The Petrobras Handbook An investor s guide to a unique oil company. The oil company FOTO

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1 Xx xxxxxxxx 2xx Petrobras xxxxxxxxxxxxxxxxxxxxxxxxxxx The Petrobras Handbook An investor s guide to a unique oil company Research Analysts Vinicius Canheu, CFA suisse.com Andre Sobreira, CFA suisse.com The oil company FOTO With over 85 thousand employees, $14bn in revenues, 2,kbd 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 6 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 $2bn 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 21, 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 25, before the discovery of the pre-salt, and lower than in 28, when the oil price hit close to $3/bbl, compared to $1/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 12-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 DISCLOSURE APPENDIX AT THE BACK OF THIS REPORT CONTAINS IMPORTANT DISCLOSURES, ANALYST CERTIFICATIONS, AND THE STATUS OF NON-US ANALYSTS. US 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 decision. Andre Sobreira, CFA 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 decision. CREDIT SUISSE SECURITIES RESEARCH & ANALYTICS BEYOND INFORMATION Client Driven Solutions, Insights, and Access

2 Table of Contents Four slides you can t forget (pages 3-7) 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 1% change in key variables for PBR. A little m ore on Upstream (pages 66-81) We provide detail and a recap of the Brazilian pre-salt, and also analyse Petrobras ten most important fields, which represent almost 7% of current production and therefore are very relevant to understanding the company. Six debates you need to know (pages 8-32) 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. A little m ore on Downstream (pages 82-95) 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 33-4) For every year since 21, 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. Understanding Gas & Power (pages 96-99) 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) 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. Petrobras financial statem ents (pages 1-17) A numerical review of PBR s financials The business plan (pages 6-65) 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. Other Brazilian oil them es (pages ) 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 213 seeing three rounds Equatorial Margin, Libra, and Onshore. Disclosures (pages ) 2

3 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 21, Petrobras has not managed to grow its oil production above the current 2,kbd 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 1% and decreased efficiency to c.7%. All of these three main reasons are being resolved now: (1) Platforms are finally coming on stream, with 213 being the highest year ever for additions (66kbd), (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 1-15% in the next two years, it would be trading at x PE and x 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: 1% m athem atics We provide simple mathematics on the impact of a 1% increase in production, a 1% depreciation of the BRL, a 1% increase in gasoline and diesel prices, and a 1% domestic-international price gap.

4 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 Revenues at $1/bbl discount to crude $1/bbl royalties $8/bbl Special Participation tax $15/bbl lifting costs $5/bbl of exploration costs and SG&A Crude Oil Production 2,kbd Crude oil import/export to adequate refinery mix 3kbd lighter oil imports 2kbd Diesel imports 2,kbd refining capacity 5kbd Gasoline imports 3kbd heavier oil exports Fuel imports to supply domestic market Other product imports 2kbd 2kbd 2kbd 2kbd 5kbd 1,kbd Other products Jet and Fuel Oil Naphtha LPG Gasoline Diesel Refined Products 2,3kbd Gasoline and diesel future growth at c.5% per year 18% 3% 18% 4% Other 5% White Flag 25% Refined products sold at a discount to international levels $5/bbl cash generation Products sold at parity / moving average to international levels Source: Petrobras, Credit Suisse Research. 4

5 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 29-1, Petrobras has not managed to grow its oil production above the current 2,kbd 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 1% and decreased efficiency to c.7%. All of these three main reasons are being resolved now: (1) Platforms are finally coming on stream, with 213 being the highest year ever for additions (66kbd net to PBR), (2) Focus is now on production, (3) Efficiencies in Campos are being resolved. The growth path is back. Petrobras production profile CS estimates Historical production Petrobras targets No growth since 21 7%+ p.a. growth until 216 1%+ p.a. growth after mnbpd Espadarte Cd. Rio de Janeiro 1kbd Polvo 9kbd Piranema 3kbd Golfinho Cd. Vitória 1kbd Roncador P-52 18kbd Roncador P-54 18kbd Marlim Leste P-53 18kbd Golfinho Cd. Vitoria 1kbd Siri Pilot Cd. Rio das Ostras 15kbd Marlim South P-51 18kbd Tupi South Cid Sao Vicente 3kbd Frade Frade FPSO 1kbd Marlim Leste Cd. Niteroi 1kbd Camarupim Cid Sao Mateus 25kbd Parque das Conchas 1kbd Source: Petrobras, Credit Suisse Research. Lula Pilot Cd. Angra dos Reis 1kbd FPSO Capixaba Cachalote/Balei a Franca 1kbd Sidon / Tiro Atlantic Zephyr 2kbd Jubarte FPSO P-57 18kbd Marlim Sul SS P-56 1kbd Baleia Azul Cid Anchieta 1kbd Lula NE Cd Paraty 12kbd Sapinhoa Pilot Cd São Paulo 12kbd Papa Terra P-63 15kbd Roncador P-55 18kbd Bauna / Piracaba Cid Itajai 8kbd Sapinhoá Norte Cid. Ilhabela 15kbd (Start-up Q3) Iracema Sul Cd. Mangaratiba 15kbd (Start-up Q4) Papa Terra P-61 & TAD (Start-up Q2) Pq. Baleias P-58 FPSO 18kbpd (Start-up Q1) Roncador module 4 P-62 18kbd (Start-up Q2) Iracema Norte Cd Itaguai 15kbd (Start-up Q3) Franco (Buzios) 2 P-75 15kbd Franco (Buzios) 1 P-74 15kbd Lula Central Cid Saquarema 15kbd Tartaruga Verde e Mestiça Pre-Salt + Libra Post-Salt Transfer of Rights e 215e 216e 217e 218e 219e 22e Lula Norte P-67 15kbd Carioca (Lapa) Cd. Caraguatatuba 1kbd Lula Sul P-66 15kbd Lula Alto Cd Marica 15kbd Franco (Buzios) 4 (Sul) P-77 15kbd Franco (Buzios) 3 (NW) P-76 15kbd Iara Horst P-7 15kbd Lula Oeste P-69 15kbd Lula Ext Sul + ToR Sul de Lula P-68 15kbd Tupi NE P-72 15kbd Entorno de Iara P-73 15kbd Iara NW P-71 15kbd Sul Pq Baleias Carcará Deepwater Espirito Santo Deepwater Sergipe I Maromba Marlim Revital I Franco (Buzios) 5 (Leste) Júpiter FPSOs already contracted Florim Libra Deepwater Sergipe II Marlilm Revitali II Espadarte III 5

6 Price increases Price increases Price increases Price increases Price increases Price increases 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. 214 bear case: 5% production growth P/E sensitivities Source: Credit Suisse Research. FX rate (BRL/USD) % % % % % % base case: 7% production growth P/E sensitivities FX rate (BRL/USD) % % % % % % bull case: 2% production growth in two years P/E sensitivities FX rate (BRL/USD) % % % % % % EV/EBITDA sensitivities FX rate (BRL/USD) % % % % % % EV/EBITDA sensitivities FX rate (BRL/USD) % % % % % % EV/EBITDA sensitivities FX rate (BRL/USD) % % % % % %

7 Four slides you can t forget #4: 1% mathematics A 1% increase in production equals 2,kbd of current oil production x 1% increase in production = 2kbd x $5/bbl cash margin per Upstream barrel x.365 = $3.6bn/ year in additional cash generation A 1% gasoline and diesel price increase equals 5kbd gasoline sold by PBR x $9/bbl price of domestic gasoline (with FX at 2.3) x 1% gasoline price increase x.365 = $1.6bn/ year in additional cash generation from gasoline 1,kbd diesel sold by PBR x $1/bbl price of domestic diesel (with FX at 2.3) x 1% diesel price increase x.365 = $3.6bn/ year in additional cash generation from diesel A 1% FX depreciation equals $8bn of revenues in USD $6bn of revenues in BRL x 1% BRL depreciation = $6bn decrease in BRL-related revenues (i) $85bn of cash costs in USD $1bn of cash costs in BRL x 1% BRL depreciation = $1bn decrease in BRL-costs (ii) (i)+(ii) = $5bn decrease in cash generation A 1% gap with international prices equals 2kbd of current diesel imports + 5kbd of current gasoline imports = 25kbd of imports x $1/bbl (equal to a 1% gap with int l prices) x.365 = $9m / year of losses PS: note current gap is around 2% Source: Credit Suisse Research. 7

8 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,kbd. 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 21-12, but in a downward trend in 213). #2: The Downstream dilemma Downstream has been one of the main responsible for a deterioration in PBR s financials since 21. 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 4% 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? 214 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 212 (and 213), 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$ #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.

9 Domestic oil production (kbd) 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,kbd. 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, 3,5 3, Growth projects: 43 new platforms from 21 to 22 2,5 2, 1,5 1, Legacy offshore production: trying to manage decline rates and increase operational efficiency 5 Onshore production Q1 6 Q1 7 Q1 8 Q1 9 Q1 1 Q1 11 Q1 12 Q1 13 Q1 14E Q1 15E Q1 16E Q1 17E Q1 18E Q1 19E Q1 2E Source: Petrobras, ANP, Credit Suisse Research. 9

10 Natural decline rate 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 28). The IEA concluded that decline rates for fields which started producing in the 199s-2s (the same period where most of Petrobras fields in Campos had first oil) are on average 1.6%-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. 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 observed post-peak decline rates by vintage (%) IEA-projected change in decline rates and RP ratios by 23 IEA observed post-peak decline rates by field type (%) 22% 2% 18% 16% 14% 12% 1% 8% 6% 4% 2% Europe Asia Pacific North America Africa World Latin America E. Europe/ Eurasia 23 Midde East 27 % Remaining reserves/ production ratio (years) 2.8% OPEC Non-OPEC World Super-giant Large 5.9% 8.8% 3.9% 3.5% Giant All fields 5.6% 4.3% 3.4% 3.4% 7.7% Newer fields showing higher decline rates 6.8% 11.2% 5.9% 6.6% 4.6% 8.3% 7.9% 14.2% 13.1% 13.3% Onshore Offshore - shelf Offshore - deepwater 7.5% 2.3% 11.6% Deepwater, large sandstone fields showing the highest decline rates 8.9% 6.6% 6.5% Carbonate 1.6% 3.4% 5.% 4.8% 14.5% Pre 197s 197s 198s 199s 2s 12.6% 1.9% 6.3% Sandstones Source: OECD/IEA, World Energy Outlook 28. Definition: Super Giant field defined as a fields with initial 2P reserves > 5bn bbls. Giant fields have initial 2P reserves between 5mmbbls and 5bn bbls, and large fields contain more than 1mmbbls of reserves. 1

11 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 25 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) 29 and 21 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 21 vintage. P-51, P-53, Cid de Vitoria and Frade explain the 29 vintage; (3) We observe a rise in decline rates in most vintages in , when PBR has not managed to grow production. More recently in 213, 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.1% 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 basin production by vintage (kbd) 2, 1,8 1,6 1,4 1,2 1, Campos decline rates by vintage over time** (%) Jan-5 Aug-5 Mar-6 Oct-6 May-7 Dec-7 Jul-8 Feb-9 Sep-9 Apr-1 Nov-1 Jun-11 Jan-12 Aug-12 Mar-13 Oct-13 4% 35% 3% 25% 2% 15% 1% 5% % 25 and before wells 26 wells 27 wells 28 wells 29 wells 21 wells and before Source: ANP data, Credit Suisse Research analysis. Note: * We define vintage as the year in which a well starts production. ** Chart shows until 21 wells 211 onwards wells were still either ramping up or with just one year of decline for us to observe proper decline trends. 11

12 Debate #1: Production growth and decline rates Vintage production: Campos basin 25 and before vintage production (kbd) 1,6 1,4 1,2 1, Average production per well (RHS) Vintage production (LHS) Jan-5 Jun-6 Nov-7 Apr-9 Sep-1 Feb-12 Jul-13 Campos basin 27 vintage production (kbd) Average production per well (RHS) Vintage production (LHS) Source: ANP data, Credit Suisse Research analysis. Decline of 13% p.a since 25 Decline of 19% p.a since 28 Jan-7 May-8 Sep-9 Jan-11 May-12 Sep Campos basin 26 vintage production (kbd) Average production per well (RHS) Vintage production (LHS) Jan-6 Apr-7 Jul-8 Oct-9 Jan-11 Apr-12 Jul-13 Campos basin 28 vintage production (kbd) Average production per well (RHS) Vintage production (LHS) Decline of 17% p.a since 27 Decline of 14% p.a since 29 Jan-8 Dec-8 Nov-9 Oct-1 Sep-11 Aug-12 Jul

13 Debate #1: Production growth and decline rates Vintage production: Campos basin 29 vintage production (kbd) Jan-9 Dec-9 Nov-1 Oct-11 Sep-12 Aug-13 Campos basin 211 vintage production (kbd) Average production per well (RHS) Vintage production (LHS) Average production per well (RHS) Decline of 28% since 212 Vintage production (LHS) Jan-11 Sep-11 May-12 Jan-13 Sep-13 Decline of 3% p.a since Campos basin 212 vintage production (kbd) Average production per well (RHS) Campos basin 21 vintage production (kbd) Average production per well (RHS) vintage apparently reached 1 peak, but not enough time for us 5 Vintage to reach decline production conclusions (LHS) Jan-12 Jun-12 Nov-12 Apr-13 Sep-13 Vintage production (LHS) Decline of 27% p.a since 211 Jan-1 Oct-1 Jul-11 Apr-12 Jan-13 Oct Campos basin 213 vintage production (kbd) Average production per well (RHS) Production still ramping-up Vintage production (LHS) Jan-13 Apr-13 Jul-13 Oct Source: ANP data, Credit Suisse Research analysis. 13

14 Debate #1: Production growth and decline rates Two other themes: Watercuts and capacity additions Watercuts in the Campos basin (%): producing more water than oil 1% 9% 8% 7% 6% 5% 4% 3% 2% 1% % % of oil + NGL % of water Watercuts above 5% for the first time end 213 Jan-5 Aug-5 Mar-6 Oct-6 May-7 Dec-7 Jul-8 Feb-9 Sep-9 Apr-1 Nov-1 Jun-11 Jan-12 Aug-12 Mar-13 Oct-13 Capacity additions: a key driver of future production growth Espadarte Cd. Rio de Janeiro 1kbd Polvo 9kbd Piranema 3kbd Golfinho Cd. Vitória 1kbd Roncador P-52 18kbd Roncador P-54 18kbd Marlim Leste P-53 18kbd Golfinho Cd. Vitoria 1kbd Siri Pilot Cd. Rio das Ostras 15kbd Marlim South P-51 18kbd Tupi South Cid Sao Vicente 3kbd Frade Frade FPSO 1kbd Marlim Leste Cd. Niteroi 1kbd Camarupim Cid Sao Mateus 25kbd Parque das Conchas 1kbd Source: ANP data, Petrobras, Credit Suisse Research. Lula Pilot Cd. Angra dos Reis 1kbd FPSO Capixaba Cachalote/Balei a Franca 1kbd Sidon / Tiro Atlantic Zephyr 2kbd Jubarte FPSO P-57 18kbd Very little additions in contributed for low growth Marlim Sul SS P-56 1kbd Baleia Azul Cid Anchieta 1kbd Lula NE Cd Paraty 12kbd Sapinhoa Pilot Cd São Paulo 12kbd Papa Terra P-63 15kbd Roncador P-55 18kbd Bauna / Piracaba Cid Itajai 8kbd Sapinhoá Norte Cid. Ilhabela 15kbd (Start-up Q3) Iracema Sul Cd. Mangaratiba 15kbd (Start-up Q4) Papa Terra P-61 & TAD (Start-up Q2) Pq. Baleias P-58 FPSO 18kbpd (Start-up Q1) Roncador module 4 P-62 18kbd (Start-up Q2) Strong additions in key for future growth Iracema Norte Cd Itaguai 15kbd (Start-up Q3) Franco (Buzios) 2 P-75 15kbd Franco (Buzios) 1 P-74 15kbd Lula Central Cid Saquarema 15kbd Tartaruga Verde e Mestiça Pre-Salt + Libra Transfer of Rights e 215e 216e 217e 218e 219e 22e Lula Norte P-67 15kbd Carioca (Lapa) Cd. Caraguatatuba 1kbd Lula Sul P-66 15kbd Lula Alto Cd Marica 15kbd Franco (Buzios) 4 (Sul) P-77 15kbd Franco (Buzios) 3 (NW) P-76 15kbd Iara Horst P-7 15kbd Lula Oeste P-69 15kbd Lula Ext Sul + ToR Sul de Lula P-68 15kbd Tupi NE P-72 15kbd Entorno de Iara P-73 15kbd Iara NW P-71 15kbd Sul Pq Baleias Carcará Deepwater Espirito Santo Deepwater Sergipe I Maromba Marlim Revital I Júpiter Post-Salt FPSOs already contracted Franco (Buzios) 5 (Leste) Florim Libra Deepwater Sergipe II Marlilm Revitali II Espadarte III 14

15 Downstream quarterly EBITDA (BRLm) Gasoline and diesel gap vs int'l (%) Debate #2: The Downstream dilemma Downstream losses in context Down 55% since end 21. 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 21 follow-on and Transfer of Rights, and lack of production growth since then. But Downstream, too, has been a key contributor. Until end 21, the business was run at a profit, with still low demand and low imports, and domestic refinery prices above international levels. Since 21, higher domestic demand and a fully utilised refinery park meant that gasoline and diesel imports soared. In addition, higher oil prices (from $7/bbl to a $1-12/bbl range), a depreciated BRL (from 1.7x to x), 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.2% below international levels, and Downstream has been a loss-making business, to the tune of $1bn/year. This has been a strong drag to Petrobras group earnings, which have fallen by 5%, precisely the $1bn 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) 1, 8, Low consumption: no need to import fuels High consumption and discount on domestic prices: PBR needs to import fuels with losses 6% 6, Diesel gap (%) 4% 4, 2% 2, F % (2,) Downstream EBITDA (4,) -2% (6,) Gasoline gap (%) -4% (8,) (1,) Jan-7 Jul-7 Jan-8 Jul-8 Jan-9 Jul-9 Jan-1 Jul-1 Jan-11 Jul-11 Jan-12 Jul-12 Jan-13 Jul-13-6% Source: Credit Suisse Research based on Petrobras, ANP and Bloomberg. 15

16 INTERNATIONAL PREMIUM (+), DISCOUNT (-) TO DOMESTIC PRICES (%) $/bbl BRL to USD DOMESTIC VS INTERNATIONAL PRICES (R$/LITER) Debate #2: The Downstream dilemma Pieces of the puzzle: The price gap Diesel Gasoline Oil prices and int l gasoline and diesel prices have rallied since Brent Diesel GoM Gasoline GoM 2 Jan-7 Jan-1 Jan-13 The Brazilian Real has depreciated strongly since 21 too Jan-7 Jan-1 Jan % 3% % Domestic diesel (R$/l) Diesel.5 Gulf (R$/l). Jan-7 Jan-9 Jan-11 Jan % 3% % Gasoline Gulf (R$/l) Domestic Gasoline. Jan-7 Jan-9 Jan-11 Jan-13 (3%) (3%) (6%) Jan-7 Jan-9 Jan-11 Jan-13 (6%) Jan-7 Jan-9 Jan-11 Jan-13 Source: Credit Suisse Research based on Petrobras, ANP and Bloomberg. 16

17 Q1 7 Q1 8 Q1 9 Q1 1 Q1 11 Q1 12 Q1 13 Q1 7 Q1 8 Q1 9 Q1 1 Q1 11 Q1 12 Q1 13 Q1 7 Q1 8 Q1 9 Q1 1 Q1 11 Q1 12 Q1 13 kbd Imports (exports), kbd Downstream quarterly net income ($m) Debate #2: The Downstream dilemma Pieces of the puzzle: Rising imports Brazil has not added a new refinery since the 198s: the sm all increm ental output is com ing from higher utilisation (today already 9%+) or debottlenecking (already done). Dem and continues to grow at 6% per year. Rising dem and im plies in higher im ports. Petrobras today on average im porting 2kbd of gasoline and diesel com bined Higher im ports coupled with a higher dom estic-international price differential im ply in a higher Downstream losses, to the tune of $1bn/ year Domestic demand Output of dom estic refineries (5) (1) Diesel Gasoline 4, 3, 2, 1, (1,) (2,) (3,) (4,) (5,) (6,) Source: Credit Suisse Research based on Petrobras, ANP and Bloomberg. 17

18 Debate #2: The Downstream dilemma Macroeconomic background: difficulty to increase prices Government primary surplus (% of GDP) 4.3% 4.6% 4.8% 4.3% 4.% 4.1% 2.% 2.8% 3.1% 2.4% Lowest result since 23 lim its relief of federal taxes 1.9% 1.3% Diesel and gasoline price composition to the final consumer: taxes are a large chunk of it (BRL/liter) % 4% % 27% 6% 14% 7% 1% 1% 6% 13% 5% 35% 57% Resale margin Distribution margin State taxes Federal Taxes Freight Anhydrous Ethanol Gasoline A Biodiesel e Inflation close to top range of target limits fuel price increase (%) 8% 7% 6% 5% 4% 3% Top range of target IPCA, 12m 2% Jan-6 Jun-7 Nov-8 Apr-1 Sep-11 Feb-13 Inflation: Fuels weight in IPCA Index A 1% increase in gasoline increases inflation by.28pp 14% 19% Gasoline 22% 25% 16% 5% Diesel 4% 1% % Food and beverages Habitation Transportation Healthcare and Personal Other Gasoline Ethanol Diesel A Diesel and GNV Source: Credit Suisse Research, Credit Suisse Economics, MME, Bloomberg, ANP, IBGE. 18

19 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 Decision taking: To build, or to import? Crude oil price Refinery capex Refinery opex Domestic gasoline/diesel prices Crude oil price 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 Domestic gasoline/ diesel prices International 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

20 IRRs (%) USDm 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 3kbd refinery has a NPV $3bn higher than importing, equivalent to a 15% relative-irr. Step 1: Decision taking: To build, or to import? Step 2: Setting the assumptions Crude oil price Refinery capex Refinery opex Capex to increase import logistics, already strained International gasoline/diesel prices Freight/cost to internalize products Key assumptions for building a new 3kbd refinery: $33/bbl capex $3/bbl opex Heavy-crude purchases at $1/bbl discount to $1/bbl Brent Key assumptions for importing 3kbd of oil products: Diesel spread to Brent of 15/bbl Import costs of $7/bbl Capex to increase import infrastructure not taken into account (conservative) as hard to gauge Conclusion: Building advantage cashflow IRRs 25% 2% 15% CS base case: building can be better than importing if the newbuild capex is right Step 3: Modeling and comparing both options 15, 1, Costs to keep im porting 5, 1% 5% % 2, 3, 4, 5, 6, 7, 8, Capex ($/bbl) (5,) (1,) Building vs import advantage Costs to build and operate a refinery (15,) 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. 2

21 IRRs (%) Age (years) Debate #2: The Downstream dilemma Single refinery economics Conclusion: A single 3kbd train with the product slate similar to the new Northeast Premium refineries (focussed on diesel, not gasoline), could yield a 6% IRR if capex is controlled and kept at $33/bbl (implying a $1bn 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 2% capex overrun from $33/bbl to $4/bbl capex would bring IRRs down from 6% to 4%. A 5% decrease on long-term pricing would bring returns down from 6% to close to zero. Partnerships: In order to enhance expertise in design and operations, PBR executed a Letter of Intent with Sinopec for the development of the Premium I refinery in Maranhão. PBR had a similar LOI with Korean GS Energy for the Premium II in Ceara, but it did not go through. In exchange for expertise and a stake in the refinery, PBR would have to guarantee export-price parity for the partners, to ensure the economics of the project work-out. Brazil is a country long-crude and short-refined products which in theory would be a good place to build a refinery. Refinery IRR sensitivity to capex at three pricing scenarios 15% 13% 1% 8% 5% 3% % (3%) (5%) CS base case Decrease in price 5% above int'l levels Increase in capex 5% below int'l levels International price levels 2, 3, 4, 5, 6, 7, 8, Capex ($/bbl) PBR current park refining costs by size ($/bbl) 3kbd refinery train base case cash-flows (USDm) ,4 4,7 2, (5) (1) (15) (2) Size (Kbd) Construction capex Maintenance capex EBITDA Free cash-flow Source: Petrobras, Credit Suisse Research. 21

22 Debate #3: Libra was better than you thought Libra basics The first pre-salt auction. In 21, 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 3% stake, and the oversight of a government company that has a 5% weight and veto power in the operating committee. Much industry and equity market skepticism surrounded the new model, especially in 213, 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 21 st. In our view, a high quality consortium (Shell and Total with a combined 4% 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 SP RJ Carcará Bem-Te-Vi Abaré Oeste Source: Credit Suisse Research, Woodmackenzie, ANP. Macunaíma Iguaçu Abaré Uruguá Carapia Dolomita Sul Carioca Gato do Mato Cernambi Lula Sapinhoá Florim Sul de Guará Lula Sul Tupi NE Tambuatá Franco Iara Entorno Jupiter Oliva Libra Resource size: 8-12bn bbls Developm ent strategy: Libra basic facts $1bn field-life spend 12 FPSOs first assessment, starting in 22 Oil com panies: Petrobras (Operator, 4%), Shell (2%), Total (2%), and the Chinese: CNPC (1%), CNOOC (1%) Bonus paym ent: R$15bn due December 213 Minim um exploratory comm itm ents: 1,547km 2 of 3D seismic that covers the full area of the block, two exploration wells and 1 extended well test Fiscal term s for the pre-salt PSC: 15% royalty 41.65% base government share of profit oil, variable according to well productivity and oil prices 5% 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 5% weight and veto power in the operating committee. Executive directors appointed with a technical, not political, profile/background. 22

23 IRRs 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 $1bn development with high 6% 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: $7/bbl opex Well productivity: 2kbd, each FPSO drains 6mmbbls of oil Developm ent schedule: FPSOs in total, gradually from Total government take on various fiscal regimes Royalties Special participation Income tax Profit oil Signature bonus 7% 4% Libra 74% 6% 85% 6% 91% 6% 96% 6% 34% 51% 59% 68% 12% 13% 7% 4% 1% 18% 21% 21% 21% 21% Concession PSC 4% (Min) PSC 6% PSC 7% PSC 8% IRR sensitivity in different oil price scenarios Break-even oil prices for 1% and 15% IRRs regimes 35% 3% Concession 1% IRR 15% IRR 14 25% 2% 15% 1% Libra PSC 4% (min) PSC 6% PSC 7% PSC 8% 43 6 Libra % % Oil price levels ($/bbl) Concession PSC 4% (Min) PSC 6% PSC 7% PSC 8% Source: Credit Suisse Research. 23

24 Oil price ($/bbl) 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 IRRs at $1/bbl for different Libra sizes and fiscal terms Production per well (kbd) Min Min Max % 37.4% 39.1% 4.2% 4.8% 41.4% 41.9% 42.3% 42.8% % 38.7% 4.2% 41.1% 41.7% 42.1% 42.6% 43.% 43.3% % 4.5% 41.7% 42.4% 42.8% 43.2% 43.5% 43.8% 44.1% % 41.7% 42.6% 43.2% 43.5% 43.8% 44.1% 44.4% 44.6% % 42.4% 43.2% 43.7% 44.% 44.3% 44.5% 44.7% 44.9% % 43.% 43.7% 44.1% 44.4% 44.6% 44.8% 45.% 45.2% % 44.% 44.5% 44.8% 45.% 45.1% 45.3% 45.4% 45.6% # FPSOs bn barrels PSC 4 (Min) 14.% 15.8% 17.1% 17.9% 18.6% 19.1% 19.5% 19.8% 2.1% PSC % 14.6% 15.8% 16.6% 17.3% 17.7% 18.1% 18.5% 18.8% PSC % 13.% 14.1% 14.9% 15.5% 16.% 16.3% 16.6% 16.9% PSC 7 9.5% 11.1% 12.2% 12.9% 13.5% 13.9% 14.3% 14.6% 14.9% PSC 8 7.4% 9.% 1.% 1.7% 11.2% 11.6% 11.9% 12.2% 12.5% PBR s Libra NPV-1 under various fiscal regimes and oil prices ($/ADR) Oil prices ($/bbl) PSC 4 (Min) (1.26) (.73) (.19) PSC 5 (1.35) (.85) (.34) PSC 6 (1.46) (.99) (.53) (.6) PSC 7 (1.57) (1.14) (.71) (.28) PSC 8 (1.68) (1.29) (.89) (.5) (.24) (.2) PBR s Libra NPV-1 under various fiscal regimes and sizes, at $1/bbl (US$/ADR) # FPSOs bn barrels PSC 4 (Min) PSC PSC PSC 7 (.4) PSC 8 (.18) (.9) Source: Credit Suisse Research, ANP. 24

25 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 1% royalty on sales, a tax on operating profit called Special Participation Tax, which varies from -4% 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 Government cashflows Sales tax (up to 9%) & Royalties (1%) Sales tax (up to 9%) & Royalties (15%) Net revenues Net revenues Opex & depreciation Cost recovery (5% ceiling) Operating profit Special participation tax (-4% of profit variable on productivity, year of production, water depth) Contractor share of excess oil Excess oil, or profit oil Government share (min 41.65% at $1/ bbl and 1-12kbd/well) Profit before tax Depreciation Income tax (34%) Income tax (34%) Oil company cashflow Oil company post-tax cashflow Source: Credit Suisse Research. 25

26 Debate #4: ToR renegotiation. Will PBR have to pay? Transfer-of-Rights basics Back to Septem ber 21. Petrobras conducted a c.$7bn 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 ). Key features of Transfer of Rights: Price: $8.5/bbl Fiscal terms: 1% royalties,.5% R&D spend Local content: Exploration 37%, Development 65% Terms: 4 years, 4 of which exploration period Renegotiation: After the declaration of commerciality, PBR and the Government will renegotiate the economics. This has been a key focus point for the equities market, which we discuss in the next slide. Valuation detail by block Area Price ($/bbl) Volume (mmbbls) Value (US$bn) Florim Franco 9. 3, South of Guará Surround Iara Transfer of rights maps and key metrics Carcará Bem-te-vi Biguá Abaré Oeste Abaré Parati Carioca Florim $9/bbl 467mn bbls NE of Tupi $8.5/bbl 428mn bbls Sapinhoá Lula Franco $9/bbl 3bn bbls Iara Júpiter Libra South of Tupi $7.9/bbl 128mn bbls Surround Iara $5.8/bbl 6mn bbls South of Tupi Northeast of Tupi Peroba (Contingent) Caramba South of Guará $7.9/bbl 319mn bbls Peroba Contingent block Transfer of Rights Libra Total $8.5/bbl 5, mmbbls $42.5bn Pre-salt concession Source: Petrobras, ANP, Credit Suisse Research. 26

27 Debate #4: ToR renegotiation. Will PBR have to pay? The renegotiation Why now? With the exploratory period of the ToR areas ending in September 214, 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. Timeline. Petrobras has to declare any commerciality by September 214 (end of the exploratory period). 1 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. Mechanism. If the revised valuation is higher than in 21, 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). Renegotiation mathematics: little to be paid ($bn) 42.5 Price paid (21) $2/bbl in oil price 2% cost inflation year delay Renegotiated price (213) +$2/ bbl in oil prices offset by a 2% inflation and a 2 year delay. Only further $4bn to be paid(on a bear case inflation can be higher than 2% and future oil prices lower due to US shale) 42.5 Price paid (21) Renegotiation timeline Signature of the ToR contract PBR to notify Gov and ANP of intention to DoC: renegotiation begins DoC deadline No set period for how long review should take Review ends and new valuation, volumes and local content are set 2 Franco FPSOs 2 Franco FPSOs 1 FPSO in Iara 1 FPSo in NE of Tupi 1 Franco FPSOs 1 FPSO in Florim End of 4-year contract Sep-1 Nov-13 Sep-14 Review Sep-5 ends 4 years exploratory period 3 years for parties to pay revised values Source: Petrobras, Credit Suisse Research. 27

28 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 21 follow-on. Of the c.$7bn 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 $7bn, only $28bn was injected in the company to recompose cash balances. Of the $28bn, minorities participated with $23bn. Before and after. With the ToR, the Government increased its stake from 4% to 49% of the total shares of Petrobras. Government participation in the voting shares increased from 58% to 7%, and from 16% to 34% in the non-voting shares. Governance discussion. Because the purchase of barrels and the follow-on were characterised as two different transactions, minorities could not vote on the barrels acquisition. In practice, minorities were effectively diluted to fund a deal that they did not had the opportunity to vote for (or against). Cash Raised in the Capitalization (R$ bn) Oil for shares: c. R$ 8bn raised from public entities, c. R$ 75bn im m ediately given back to buy oil from the governm ent in the ToR agreem ent. 45 Shareholding Structure (mn shares) Before capitalization Others BNDES* Sovereign Fund After capitalization Federal Government Total Transfer or Rights Net cash Raised 13,44 8,774 51% 7,442 3% 6% 5,62 5,73 4% 17% 42% 3,71 1% 66% 2% 8% 84% 56% 32% 5% 7% 29% 16% 27% Common Preferred Total Common Preferred Total Federal Governemt BNDES* Other Free-float Source: Petrobras, Credit Suisse. Note: Shareholding structure shown in number of local shares. Each ADR is equivalent to two shares. 28

29 R$/sh Debate #5: Different dividends, different ON-PN spread There s always a first time Petrobras has always paid sim ilar dividends to ordinary (ON) and preferred (PN) shareholders. Firstly, balance sheet has never been an impediment, so the company always distributed more than the minimum 25% payout required by law. Secondly, the earnings levels were high enough so that the 25%+ payout has always been close to 2x the book value rules that put a floor on the PN dividend. This apparent stability meant that through most of its history, the ON shares have traded at an average 13% premium vs the PNs. Better liquidity plus voting power justified that premium. But 212 (and 213) were the first tim e when dividends were different. By end 212, earnings level were low enough, one of the lowest of PBR s history. PN s book value dividend rules were higher than the ON s minimum 25% payout, so that PBR implemented different payments (PNs got R$.96/sh, ONs R$.47/sh in 212, in 213 the values were 97 and 52 cents respectivelly). This caused a major shift in the PN-ON spread. With different dividends, PNs shares started to trade at a premium to the ONs, which persists to this day. Dividends vs Interest on Equity In Brazil, companies have the choice of distributing cash to shareholders in the form of dividends, or alternatively as interest on equity (IOE). Key differences are: (1) dividends do not pass onto companies P&L, and shareholders do not pay tax on received dividends; and (2) IOE enters the P&L as a financing cost, thus decreasing the tax bill; but shareholders have to pay a 15-25% tax rate on IOE received. Historically, Petrobras has paid 88% of distributions as IOE. PBR dividend distribution rules Preferred shares (PNs): the higher of: 3% of PN book value; 5% of PN paid-in capital; 25% of net income; The ON dividend. Ordinary shares (ONs): by law, PBR is required only to distribute a minimum of 25% of net income to shareholders, but does not specify which type of shareholder. Therefore, in theory, the ON dividend could be zero if the PN dividend already consumed the full 25% of net profit. However, PBR has an explicit commitment to pay the ONs at least 25% of net profit. A dividend story: low earnings forcing different dividends Earnings per share ON dividend PN dividend Source: Bloomberg, Company data, Credit Suisse Research. Low level of earnings forced different dividend payments for the first time in Petrobras history in (2) (4) (6) (8) PN discount to ONs (R$/sh) resulting in PNs having a premium vs the ONs for the first time too. PN discount to ONs (%) (1) Nov 8 Jul 9 Mar 1 Nov 1 Jul 11 Mar 12 Nov 12 Jul 13 2% 1% % (1%) (2%) (3%) 29

30 Jan 13 Feb 13 Mar 13 Apr 13 May 13 Jun 13 Jul 13 Aug 13 Sep 13 Oct 13 Nov 13 Dec 13 Jan 14 Feb 14 Mar 14 Debate #5: Different dividends, different ON-PN spread What should the spread be? A first approach: 2 x 5cents = R$1. spread. With 212 and 213 dividends differing in around 5 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./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.. Justifying a R$1.4 spread. "R$1.4 = 2 x R$.7/ sh = 3x R$.5". Earnings and book value in 213 did not differ much from 212 s, resulting in a close to R$.5/sh differential between the ON and PN dividends. However, with a deteriorated 214 outlook, earnings will decrease, implying in a lower 214 dividend for the ONs and a differential of R$.7/sh in our view. Therefore a simple way to see a R$1.4/sh fair spread would be to assume the R$.7/sh would persist for two years, or alternatively to assume that the current R$.5/sh dividend difference will persist for three years, and not two, given a 'lost 214. R$2. = could the balance sheet force PBR to cut the ON dividend to zero? Technically, Petrobras can cut the ON dividend to zero. The company is only obliged to (1) distribute a minimum 25% of earnings as dividends, regardless if it is to ON, PN or both types of shareholders, and (2) pay the PNs the minimum 3% of book value or 5% of share capital, equivalent to the current R$.96/sh dividend. Technically, R$.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 214 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 214, 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. per year. With two years of zeroed ON dividend, the ON-PN spread could go to close to R$2.. Short-term history of the PN-ON spread (R$/sh) Different dividends and new earnings level warranted a change in the spread, with a fair value of R$1. initially The lack of a clear formula and a tough 214 could warrant a new R$ /sh spread range in our view 1..5 Very low current spread levels. (.5) (1.) Source: Bloomberg, Credit Suisse Research. 3

31 ND/EBITDA (x) ND/(ND+Equity) (%) 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 29, 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. Net debt / EBITDA (x) and Net debt / (net debt + equity) (%) Source: Company data, Credit Suisse analysis. Net debt / (ND + Equity) Net debt/ebitda % 4% 35% 3% 25% 2% 15% 1% 5% % Total debt levels, net debt levels, and cash levels ($bn) 14, 12, 1, 8, 6, 4, 2, Petrobras Enterprise Value split (Book value + Net debt) (USDm) 3, 25, 2, 15, 1, 5, Peak debt levels. Cash levels dangerously low, at same levels as in 29, prior to the capitalisation Growing book value of the enterprise until 21, via equity. Post 21, destruction of value to the shareholders Total debt levels Net debt levels Cash levels Net debt Book value

32 Borrowing costs (USDm) % of debt costs that are capitalised 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 27, 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 8-4% lower than reported since 27. 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 Petrobras earnings and impact of expensing all debt costs (USDm) 6, 5, 4, 3, 2, 1, % of debt capitalised Expensed debt Capitalised debt % 9% 8% 7% 6% 5% 4% 3% 2% 1% % Reported net income Net income if all debt was expensed in the P&L 18,432 19,994 19,948 16,982 16,85 14,491 15,54 12,866 11,48 1,87 1,912-8% -16% 9,345-22% -11% 7,16 6,977-15% -35% -4% Source: Company data, Credit Suisse analysis. 32

33 How to value Petrobras? FOTO Valuation dilem m a For every year since 21, 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 213, 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. Absolute value reference and other value guideposts: is now the time? Petrobras in 22 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. 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. Hypothetical equity issuance: at what price would you buy? 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 $1-25bn 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.x on earnings that are reasonably conservative.

34 How to value Petrobras? Valuation dilemma The value trap. For every year since 21, 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. Before it was easy to avoid the trap. We argue that up until 213, it would 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. Now it s a harder decision. Starting from 213, 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 84kbd 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, 214 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 29. PBR historical price-to-book multiples (x) 5.x 4.x 3.x 2.x 1.x.x Jan-7 Jan-8 Jan-9 Jan-1 Jan-11 Jan-12 Jan-13 Jan-14 Source: Bloomberg. Below book since late 211. Now PBR below.5x book, lowest levels ever PBR historical PE multiples (x) 16x 14x 12x 1x 8x 6x 4x 2x Close to 6x PE, almost as low as end 28 when the oil price hit $3/bbl x Jan-7 Jan-8 Jan-9 Jan-1 Jan-11 Jan-12 Jan-13 Jan-14 PBR historical EV/EBITDA multiples (x) 9x 8x 7x 6x 5x 4x High and increasing net debt levels keep 3x the EV/EBITDA multiple stable at 5-6x 2x despite a market cap that is down more than 5% since 21. Given PBR s vast 1x capex plan, there is significant debt that x does not generate EBITDA yet Jan-7 Jan-8 Jan-9 Jan-1 Jan-11 Jan-12 Jan-13 Jan-14 34

35 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 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. Three issues. Unfortunately, coming up with such a value reference is no easy job for Petrobras, for three inter-related reasons, in our view: 1. Negative cashflows for long. The first, more evident issue to built a DCF for Petrobras are negative cashflows. Petrobras has been cashflow negative since 27, and that is likely to continue into 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 the returns on those heavy-investments are also uncertain. PBR has seen declining returns since 28, and since 21 we have been below cost-ofcapital territory. Will returns ever pick-up again? 3. Will there be future dilution? A third issue derives of the first two: with uncertain returns and high capital intensity, do current shareholders face the risk of future dilution, such as happened in 21? Petrobras cashflows (USDm): very negative for very long 21,87 Cash from operations Capex Free-cashflow 25,814 22,636 28,173 29,457 29, 27,91 ROEs and ROCEs (%): falling since 28. What will future levels be? 35% 3% 25% 2% 15% 1% 5% ROE ROCE % E 216E 218E 22E 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? 7,667 61,85 52,35 43,364 37,772 22,636 25,775 (21,265) (28,325) (34,48) (41,573) (41,584) (4,44) (45,388) (41,42) (41,42) (41,42) (41,42) (41,42) (41,42) (41,42) E 215E 216E 217E 218E 219E 22E Source: Petrobras, Credit Suisse estimates. 35

36 How to value Petrobras? Arriving at an absolute value reference: Petrobras in 22 Looking at 22. One of the best ways we found to look for absolute value in Petrobras is using our Petrobras in 22 approach. The approach consists of looking at asset valuation in a normalised state in 22, 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 22, 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. 6% of the capex in Upstream (where returns are c.2%), 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. Does it make a difference? Petrobras has been trading below our $25/ADR reference since late 211. 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. Step 2: Translating asset value in 22 to equity value in 214 PBR asset value in 22, scenario 1 USDm 455,52 PBR asset value in 22, scenario 2 USDm 479,217 PBR net debt in 22 USDm (8,645) PBR equity value in 22 scenario 1 USDm 374,875 PBR equity value in 22 scenario 2 USDm 398,572 Source: Credit Suisse Research. Unit Values Comments PBR equity value in 214 scenario 1 USDm 162,69 Brought to 214 at a 15% Ke PBR equity value in 214 scenario 2 USDm 172,314 Brought to 214 at a 15% Ke PBR equity value in 214 scenario 1 USD/ADR 25 PBR equity value in 214 scenario 2 USD/ADR 26 Step 1: Arriving at an asset valuation in 22 E&P division Units Values Comments 22 Oil & Gas production kboed 5,2 22 Oil & Gas production mmbbls 1,898 Net income per boe $/boe 24 PBR 22 R&P net income and FCF USDm 45,552 Industry average $15/bbl, PBR E&P more profitable Upstream asset value (i) USDm 455,52 1% real rate, ex-growth Downstream, scenario 1 Refining asset value (ii) USDm Downstream, scenario 2 22 refining capacity kbd 2, refining capacity mmbbls 911 Global Oils average refining NI/bbl $/bbl 2.6 PBR 22 Refining net income and FCF USDm 2,37 Comments Assumes Downstream does not destroy value on the long term (net income offset by loss-making imports) Comments Doesn't assume new Premiums or Comperj2 PBR is able to restablish refining profitability Refining asset value (iii) USDm 23,697 1% real rate, ex-growth PBR asset value Comments Scenario 1 USDm 455,52 Sum of (i)+(ii) Scenario 2 USDm 479,217 Sum of (i)+(iii) 36

37 PBRa ENI CVX RDShell Total Repsol XOM Sinopec Statoil CNOOC ENI XOM Repsol Petrochina CVX BP RDShell Sinopec Statoil Total CNOOC BP Petrochina 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 22 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. $7bn: a conservative earnings estimate? At $1.5bn, Q3 13 earnings were the second worst levels in PBR history since 26 (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 213, and further FX depreciation to 2.6. This looks to us as a reasonably conservative earnings level to start from. $77bn ($12/ ADR): a conservative market 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. 7.2% dividend yield: the highest among global peers. At the current share price, Petrobras preferred shares are offering the highest yield within global oils. Writing-off $25bn of the market cap. Before the pricing formula announcement last November, PBR s market cap was c. $1bn. 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. PBRa / PETR4 now offer the highest dividend+buyback yield in Global Oils 8.% 7.% 6.% 5.% 4.% 3.% 2.% 1.%.% 7.2% 5.3% Deriving a conservative earnings estimates for PBR: $7bn (US$bn) 1.5 Q3 13 earnings 6. Q3 annualised 3. +7% production Big Oil PE on trough earnings is c. 11x, implying a PBR market cap of $77bn, already above current levels % gasoline % diesel -15% FX 214 earnings 11. Source: Bloomberg, Credit Suisse Research. 37

38 LKOH RNHS PRE OMVV SINOPEC ECOPETROL GAZP CVX NVTK SHELL ENI PETROCHINA COP BP STL XOM TOTF YPF ROSN REP PBR BG GALP CFROI (%) LKOH YPF SINOPEC GAZP OMVV ENI SHELL COP CVX STL RNHS BP TOTF PRE PETROCHINA PBR REP BG XOM GALP ECOPETROL ROSN NVTK How to value Petrobras? HOLT : Share price implying current performance into eternity HOLT s appeal. HOLT is a proprietary valuation framework of Credit Suisse s. HOLT is based 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. The chart on the bottom left shows what PBR historical CFROI performance has been (blue 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. The charts on the right compare PBR with other global oil peers. As the top-right chart 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. PBR historical, forecast, and implied CFROI (%) PBR share price implying that current business performance will be perpetuated into eternity E Global Oils implied CFROI in the current share price 2% 15% 1% 5% % (5%) (1%) (15%) PBR implied returns one of the highest amidst Global Oils 3.2% Spread: implied CFROI minus CFROI expected by the sell-side 1% 5% % (5%) (1%) (15%) (2%) (25%).3% If performance does not improve, PBR is the third most expensive oil stock globally CFROI Forecast CFROI Market implied CFROI Source: Credit Suisse HOLT. 38

39 HOLT-aggregate discount rates (%) CFROI (%) 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 1%. 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 2 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 Petrobras and Gazprom PEs over time (x) Brazil and Russia HOLT-implied discount rates* (%) Petrobras and Gazprom CFROI over time (%) Brazil Brazil s lower market-implied discount rates historically should warrant a higher PE multiple, ceteris paribus Russia Feb 1997-Jun 2-Oct 24-Feb 27-Jun 21-Oct 214-Feb 16.x 14.x 12.x 1.x 8.x 6.x 4.x 2.x 18% 16% 14% 12% 1% 8% 6% 4% 2% PBR PBR historical PE premium to GAZP. Should they trade at a similar multiple? PBR GAZP.x Jan-7 Nov-7 Sep-8 Jul-9 May-1 Mar-11 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 GAZP % E 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

40 Price increases in Price increases in Price increases in 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. Assumptions. In the exercise below, we use the following two important assumptions: (1) production growth of 7% in 214 and slightly higher 1% in 215, (2) that the debt markets will be accessible up to $2bn/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 + $1bn 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 $1-25bn in equity in scenarios where the FX goes up to 2.8x and price increases until 215 are between 5-15%, (2) even with the incremental issuance, PBR would remain geared at c.4.x 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.x 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 FX % Equity needs for PBR to keep cash levels at $25bn under different FX and price increase scenarios ($m) PEs of an issuance done at the current c.$11.5/adr share price under various FX and price increase scenarios FX % 565 8,52 15,15 2,76 25,599 29,8 5% 6,382 13,19 18,95 23,919 28,232 1% 4,243 11,229 17,14 22,238 26,664 15% 2,15 9,269 15,331 2,558 25,95 2% 7,39 13,521 18,878 23,527 FX % % % % % % % % % Source: Company data, Credit Suisse analysis. 4

41 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. 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 212 remained at c.9% levels for the past four years, despite a rise in oil price from $6/bbl to $11/bbl. This is also the same level of returns as in 22, when oil prices were at c.$3/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 9% of cash-generation for the past four years, a stark contrast to the c.6% invested in the early 2s. Even more impressive is the fact that, as a group, our universe has not managed to significantly increase production despite rising intensity. Upstream vs Downstream 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) 212 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 214, this will partially change, but a more efficient Downstream pricing policy is needed for PBR to start to be competitive on a global scale.

42 Order of Merit Returns trends All-time 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 212 remained at c.9% levels for the past four years, despite a rise in oil price from $6/bbl to $11/bbl. This is also the same level of returns as in 22, when oil prices were at c.$3/bbl. Both in Upstream and Downstream, higher prices is not translating in higher returns. Upstream vs Downstream. Comparing both charts on the right, we see two clear trends, both which are crucial to the Petrobras investment case: (1) Upstream has significantly higher returns than Downstream both for PBR and for the Industry; and (2) Petrobras performs significantly better than peers on Upstream, but lags significantly on Downstream. The Downstream drag is so significant that it brings the overall Petrobras returns below industry average, as we can see on the bottom left chart. Upstream ROGIC over time (%) 4% 35% 3% 25% 2% 15% 1% 5% % Sector Petrobras Oi price ($/bbl) Consolidated ROGIC over time (%) 18% 16% 14% 12% 1% 8% 6% 4% 2% % Sector Petrobras Oi price ($/bbl) Downstream ROGIC over time (%) 2% 15% 1% 5% % (5%) (1%) (15%) Sector Petrobras Source: Company data, Credit Suisse analysis. Note: ROGIC calculated as EBIDAX divided by Gross Invested Capital; all averages are weighted by company scale. 42

43 Chevron BG Statoil Hess BP ExxonMobil Average OMV ConocoPhillips R.D. Shell ENI Total Petrobras Marathon ExxonMobil Chevron OMV Repsol BP Statoil Hess Total Repsol Average R.D. Shell ENI Petrobras OMV Petrobras ENI Chevron Statoil Hess Average BG ExxonMobil R.D. Shell BP ConocoPhillips Total Marathon Repsol 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. Petrobras worst-in-class Downstream returns. The bottom-right chart makes 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. The need for transparent pricing. As the chart on the bottom-left shows, the 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. Upstream ROGIC rankings (%) 21% % 16% 14% 13% 13% 12% 11% 11% 11% 1% 9% 9% 8% 7% Consolidated ROGIC rankings (%) 12% 11% 11% 1% % 9% 9% 9% 9% 8% 8% 8% 7% 7% 7% Downstream ROGIC rankings (%) 11% 9% 9% 7% 7% 7% 5% 4% 3% 3% (%) (9%) Source: Company data, Credit Suisse analysis. Note: ROGIC calculated as EBIDAX divided by Gross Invested Capital; all averages are weighted by company scale. 43

44 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 212 is at all-time high levels, close to the $3bn mark. Investing most of the cash. Global oils as a group has been investing close to 9% of cash-generation for the past four years, a stark contrast to the c.6% invested in the early 2s. Here, Petrobras also stands out. The company has been investing substantially more than cash generated since 27, testimony to a huge resource base. At some point, as production ramps-up and the benefits of capex are reached, capital intensity should come down. Petrobras expects to become free-cash positive by , an assumption dependent on Downstream performance. Capex/EBIDAX over time (%) 18% 16% 14% 12% 1% 8% 6% 4% 2% % Sector Petrobras Capex/Gross Invested Capital over time (%) Aggregate segmental capex over time (US$bn) 25% 2% 15% Sector Petrobras Upstream Downstream Other % % % Source: Company data, Credit Suisse analysis. Note: all averages are weighted by company scale. 44

45 Petrobras ExxonMobil R.D.Shell Chevron Total BP Statoil Average ENI ConocoPhillips BG Hess Repsol Marathon OMV Hess BG Petrobras Chevron Statoil Average Total ConocoPhillips Marathon R.D.Shell BP ExxonMobil OMV ENI Repsol 1% 9% 9% 8% 8% 8% 8% 7% 7% 6% 6% 5% 11% 16% 15% Petrobras Hess BG Total Marathon R.D.Shell Average ConocoPhillips Chevron StatoilHydro ENI Repsol BP OMV ExxonMobil 16% 15% 95% 94% 93% 84% 84% 8% 76% 76% 73% 72% 153% 149% 135% Order of Merit Capital deployment rankings The largest capex in the industry is from Petrobras ($43bn in 212), followed by Exxon ($4bn) and Shell ($38bn), with Shell being the company with most capex hikes in the past year. With its $237bn plan for the next five years, we would expect Petrobras to keep the highest spend in the industry in the future. High E&P capital intensity. Another interesting feature of the industry that is clearly illustrated by company performance is the fact that Upstream is a much higher capital intensity business than Downstream. Petrobras, BG and Hess, thre three most-e&p focussed companies in our universe, are also the three that present the higher capital intensity, both on a capex/ebidax and Capex/GIC basis. Capex/EBIDAX rankings (%) Capex/Gross Invested Capital rankings (%) Aggregate capex rankings (US$bn) Source: Company data, Credit Suisse analysis. Note: all averages are weighted by company scale. 45

46 Petrobras Repsol ConocoPhillips Hess Marathon BG ENI OMV BP Total Average Statoil R.D.Shell ExxonMobil Chevron (9%) 1% 9% 3% 27% 27% 26% 25% 24% 21% 2% 2% 19% 17% 14% ConocoPhillips Petrobras Marathon Hess Chevron Total BP Average ExxonMobil BG R.D.Shell OMV Statoil Repsol ENI Order of Merit Balance sheet and leverage Gearing levels rem ain com fortable (for m ost) global oils, below the 2% 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. Petrobras m ost-levered balance sheet. Petrobras gearing levels have remained above those of the industry for most of the past decade. 21 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 211 to 212, only behind Conoco, and at a time most competitors delevered their balance sheets. So far in 213, gearing has continued to increase strongly, reaching 36% in Q3 13. With production set to resume growth from 214-onwards, a decrease in gearing is now dependent on the Downstream pricing mechanism. Net debt/total capital change in 212 over 211 (% points change) 6% 6% 5% 3% 1% (1%) (2%) (2%) (3%) (3%) (4%) (5%) (7%) (8%) (11%) Net debt/total capital trends (%) 35% 3% Sector Petrobras Net debt/total capital rankings (%) % 2% 15% 1% 5% % Source: Company data, Credit Suisse analysis. Note: all averages are weighted by company scale. 46

47 Petrobras Hess Marathon Chevron BP Total OMV Average Statoil ENI ExxonMobil ConocoPhillips R.D.Shell Repsol ExxonMobil BP Petrobras Chevron R.D.Shell Total Average Statoil ENI ConocoPhillips Marathon Hess BG OMV Repsol BG ExxonMobil BP R.D.Shell Chevron Petrobras Total Average Statoil ENI ConocoPhillips BG Marathon Hess Repsol OMV Production & Reserves Production overview Petrobras is big. Petrobras is the 5 th largest oil and gas producer among our 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 22, it will not take long for us to see PBR on top of that list. Petrobras is oily. Another interesting metric is the fact that PBR is the most oily 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. Oil and gas production rankings (million barrels per day) Oil production rankings and oil as % of total oil as % of total production 84% Oil production rankings (kbd, Thousands) 73% 69% 68% 61% 55% 55% 55% 55% 54% 5% 5% 49% 44% % Source: Company data, Credit Suisse analysis. Note: all averages are weighted by company scale. 47

48 Marathon Repsol Statoil Hess ENI OMV BG R.D.Shell Petrobras Average Total Chevron BP ConocoPhillips ExxonMobil Production & Reserves Production growth (poor) track-record Growing is not easy. Production growth is one of the items that always gets our 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 21! 211 was bad, 212 better (but not good). 211 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 212, 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%. Oil and gas production growth rankings (%) 19% 12% 11% 9% 7% 6% 3% 2% 1% % % -2% -3% -4% -6% Oil and gas production growth over time (YoY growth) (%) 12% Sector Petrobras 5% 3% 11% 4% 9% 4% 1% 3% 1% 1% 5% 2% % 5% -1% -1% 6% 1% % -1% -4% % 1% 1% Source: Company data, Credit Suisse analysis. Note: all averages are weighted by company scale. 48

49 Petrobras Marathon Hess BP ExxonMobil ExxonMobil R.D.Shell Petrobras BP BP Chevron Total R.D.Shell Chevron Total Average Average ConocoPhillips ENI ENI ConocoPhillips Statoil Statoil BG Marathon Petrobras BG Repsol Hess OMV OMV Marathon Repsol Hess Reserves base Oil reserves (proven SEC) rankings (mmbbls, Thousands) Oil as % of oil and gas reserves rankings (%) Gas reserves (proven SEC) rankings (bcf, Thousands) 85% 77% 75% % 57% 57% 54% 52% 52% 51% 49% 46% 45% Chevron OMV Average Total ConocoPhillips ExxonMobil ENI R.D.Shell Statoil BG Repsol Production & Reserves Petrobras is big, again. Similarly to production, Petrobras is by far the most 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 3bn bbls potential that could easily put the company in a far 1 st place position. Oily reserves, too. PBR has the most oily reserves in our universe, 85%, similar to production. This is also illustrated by the fact that Petrobras ranks close to the bottom of the list in gas reserves % 35% Source: Company data, Credit Suisse analysis. Note: all averages are weighted by company scale. 49

50 BG ExxonMobil Petrobras Marathon BP Total ConocoPhillips Average Hess OMV ENI R.D.Shell Chevron Repsol Statoil ExxonMobil Petrobras BG BP Total Chevron ConocoPhillips Average Marathon ENI R.D.Shell Repsol Hess OMV Statoil Production & Reserves Reserves life Improving reserves life in 211, stable in 212. After years of slightly decreasing reserves life from the to the level, the industry jumped back to 12.8 years of reserve life in 211, remaining at that level in 212. Petrobras strength is im pressive when it comes to resource potential: the company consistently had very high reserves life for most of the decade (c 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. Proven oil and gas reserves life rankings (Years) Industry oil and gas reserves life over time (Years) Sector Petrobras Proven oil reserves life rankings (Years) Source: Company data, Credit Suisse analysis. Note: all averages are weighted by company scale. 5

51 Repsol Marathon BG ENI Hess Chevron Average Statoil ExxonMobil Petrobras Total ConocoPhillips BP R.D.Shell OMV 192% 186% 177% 144% 142% 122% 117% 113% 15% 11% 89% 79% 75% 51% 5% BG Repsol Marathon ENI Petrobras Hess Average Statoil Chevron ExxonMobil R.D.Shell ConocoPhillips BP Total OMV 16% 137% 137% 129% 121% 114% 11% 97% 94% 93% 92% 91% 77% 61% 217% Production & Reserves Reserves replacement ratio 1% organic reserve replacem ent ratio (RRR) is hard to achieve The 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. but not for Petrobras. Contrary to the industry, Petrobras was only below 1% 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 13%+ RRRs, the same level as the more E&P-like companies such as BG and Marathon. Organic oil and gas reserve replacement ratio rankings (3-year average, %) Industry organic oil and gas reserve replacement ratio (3 year average, %) Organic oil and gas reserve replacement ratio rankings (yearly average, %) Sector Petrobras % 167% 16% 186% 165% 112% 11% 11% 11% 86% 92% 12% 78% 1% 77% 13% 71% 74% 83% 141% 128% 15% 111% 129% 91% 14% Source: Company data, Credit Suisse analysis. Note: all averages are weighted by company scale. 51

52 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 212 (c.12%) as it was in 22, when oil prices were c.$3/bbl, vs c.$11/bbl in 211. 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.$1/boe to c.$36/boe. Petrobras stands out with a best in class $41/bbl EBIDAX generation....but so has capital intensity, and this is key to a flat returns profile despite rising profitability. Upstream spends roughly 9% of cash-generated in 212, up from 5% in the beginning of the decade. PBR capital deployment has not been dissimilar to that of the industry. Upstream ROGIC over time (%) 4% 35% 3% 25% 2% 15% 1% 5% Sector Petrobras Oi price ($/bbl) Upstream EBIDAX per bbl over time (US$/boe) % Upstream Capex/EBIDAX over time (%) Sector Petrobras % Sector 73% 77% Petrobras 7% 58% 53% 6% 58% 66% 7% 64% 65% 66% 12% 8% 9% 75% 87% 91% 69% 72% Source: Company data, Credit Suisse analysis. Note: all averages are weighted by company scale

53 Petrobras Chevron OMV Average BP ENI Statoil Total R.D.Shell ExxonMobil ConocoPhillips Hess Repsol BG Marathon Statoil Chevron Petrobras Average Total R.D.Shell ENI Marathon OMV ExxonMobil BP ConocoPhillips Repsol Hess BG Petrobras Average Statoil R.D.Shell Chevron Total ENI Hess Marathon OMV BP ConocoPhillips ExxonMobil Repsol BG Upstream returns breakdown Upstream profitability High profitability. With higher cash-generation per barrel,, lower exploration 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 $1/bbl more net income in Upstream than the average oil company. Another interesting feature is PBR s oily production profile: Petrobras has the highest revenue per barrel in our universe. Upstream revenues per boe produced (US$/boe) Upstream net income per boe produced (US$/boe) Upstream EBIT per boe produced (US$/boe) Source: Company data, Credit Suisse analysis. Note: all averages are weighted by company scale. 53

54 Petrobras ConocoPhillips R.D.Shell BP Average Hess ExxonMobil OMV Marathon Chevron ENI Repsol BG Total Statoil Marathon Statoil R.D.Shell Total ExxonMobil ENI ConocoPhillips Repsol Average BG Chevron Hess OMV BP Petrobras 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 212, flat vs 211 and up from c.$6/boe in 2. 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 $18/bbl of combined royalties + special participation cash costs. This is offset by a lower corporate tax. PBR s Upstream tax rate of 35% is virtually the lowest in our universe. We note that average tax rate in the industry has been rising from c.45% in 2 to 56% in 212, significant and a sign that Governments worldwide are taking a higher toll of oil profits with rising oil prices. Upstream cash-costs per boe over time (US$/boe) Sector Petrobras Upstream cash-costs per boe rankings (excluding income taxes) (US$/boe) Upstream income tax rates rankings (%) 76% 69% 68% 64% 61% 61% 58% 56% 56% 55% % 5% 44% 38% 35% Source: Company data, Credit Suisse analysis. Note: all averages are weighted by company scale. 54

55 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 9% of cash-generated in 212, up from 5% 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 2. Upstream capex as % of Gross Invested Capital has remained relatively stable through the decade at c.1% 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 212, close to five times 2 s $4.7/boe. Higher F&D are testimony not only to cost inflation, but also to the increasingly tougher environments (deepwater, arctic, heavier oil) oil companies need to go to replace reserves. Going forward, this trend could change somewhat as shale increases its importance. Upstream capex / GIC over time (%) Upstream capex / EBIDAX over time (%) 49% Sector 73% 77% Petrobras 7% 58% 53% 6% 58% 66% 7% 64% 65% 66% Organic F&D costs over time (3-year average) (US$/boe) 12% 8% 9% 75% 87% 69% 91% 72% Sector Petrobras Sector Petrobras % 16.5% 18.1% 18.% 17.% 9.3% 1.9% 1.6% 13.5% 1.2% 1.2% 9.7% 9.9% 8.8% 9.4% 1.7% 11.9% 1.1% 12.5% 12.9% 12.9% Source: Company data, Credit Suisse analysis. Note: all averages are weighted by company scale

56 BG Hess OMV Statoil Petrobras R.D.Shell Average Chevron Total BP ENI ConocoPhillips Marathon ExxonMobil Repsol Hess OMV Total Statoil Average ConocoPhillips R.D.Shell Chevron Petrobras Marathon ExxonMobil ENI Repsol BP BG 7% 8% 8% 12% 1% 13% 11% 12% 1% 1% 8% 8% 16% 14% 18% BG Hess R.D.Shell Total Repsol Marathon Average ConocoPhillips Chevron Statoil ExxonMobil Petrobras BP ENI OMV 142% 14% 136% 115% 11% 11% 97% 89% 84% 79% 78% 72% 7% 61% 6% Upstream returns breakdown Upstream capital intensity (cont d...) Organic F&D costs over time (3-year average), with F&D split (US$/boe) Finding costs Dev costs Upstream capex / EBIDAX rankings (%) Upstream capex / GIC rankings (%) F&D costs rankings (3-year average) (US$/boe) Source: Company data, Credit Suisse analysis. Note: all averages are weighted by company scale. 56

57 ExxonMobil R.D.Shell BP Petrobras Average Total Chevron Repsol ENI OMV Statoil Crude oil refined Repsol OMV ExxonMobil R.D.Shell Petrobras Total Average BP Chevron ENI Statoil Marathon ConocoPhillips Downstream Refining overview Integration m atters. Petrobras is theoretically on a neutral Upstream vs 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. More trading. In general, the industry is selling 1.5x barrels of oil product for every barrel refined. Globally, refining throughput is at 67% of marketing barrels sold. This ratio is down for the 6 th year in a row, as majors continue to rely more on trading to supply marketing networks. Spin-off. Both marketing volumes and refining throughput fell to lowest levels in two decades as demand shrank and integrated companies continue to divest downstream assets (Conoco spin off of PSX in 212, Marathon s spin off of MPC in 211). Refinery cover ratio (Refining capacity / oil & gas production) Long Refining / Short Upstream 311% 15% 143% Short Refining / Long Upstream 11% 93% 93% 83% 8% 75% 47% 18% % % Refining capacity rankings (kbd) Crude oil refined vs oil product sold (kbd) 6, , 5, ExxonMobil 3,36 2,681 2,249 2,17 2,48 1,953 4, 3, Royal Dutch Shell Petrobras BP 2, Total Chevron 1, OMV ENI Ecopetrol Repsol YPF Statoil ConocoPhillips Hess YPF 1, 2, 3, 4, 5, 6, 7, Oil products sold Source: Company data, Credit Suisse analysis. Note: all averages are weighted by company scale. 57

58 Downstream Dark Ages in Europe, better elsewhere Dark Ages. Downstream returns peak in at the 1% level, and have been in continued decline since then. 212 returns of 3.3% are at decade-lows, skewed by Petrobras strong loss-making Downstream. Ex-Petrobras, returns remain tepid at the 5.% level. Declining profitability. The first element for a declining returns profile in Downstream is a structural profitability decline since Profitability is close to all time low levels at $1.1/bbl, barely profitable, though highly skewed by Petrobras high losses of close to $15/bbl. No capital discipline is the second element for a declining returns profile. Even with a poor returns profile, capital intensity has not decreased significantly over time. Capex was 5% of GIC in 212, similar to 1-year average. Petrobras capital intensity is close to 3x industry average at 15% of Gross Invested Capital. Excluding Petrobras, the industry invested c.6% of cashflow (EBIDA) generation in 212, below 29 s peak 123% but in line with ten-year average Petrobras Downstream ROGIC over time (%) 15% 1% 5% % (5%) (1%) Sector Petrobras Downstream Net income per barrel sold over time (US$/bbl) Downstream capex / GIC over time (%) 25% 2% Petrobras 5 Sector 15% -5 1% -1 5% % Sector Source: Company data, Credit Suisse analysis. Note: all averages are weighted by company scale. 58

59 Chevron OMV R.D.Shell ExxonMobil Statoil BP Repsol Total Hess Average ENI Petrobras Petrobras Repsol OMV Average Chevron Statoil BP Total ENI R.D.Shell Hess ExxonMobil ExxonMobil Chevron OMV BP Statoil Hess Total Repsol Average R.D. Shell ENI Petrobras 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 $15/bbl), and is by far the company that shows higher capital intensity (bottom-right, PBR invests almost three times the industry average in Downstream). This has a devastating effect on returns, with PBR ranking on the bottom of our universe (top-right chart). Opportunity? In a way, we could also see this as an opportunity. Should PBR achieve pricing parity, capital intensity will remain high, but profitability will return more in line to industry average and PBR s Downstream business can start to become competitive again. Downstream ROGIC rankings (%) 11% 9% 9% 7% 7% 7% 5% 4% 3% 3% % -9% Downstream Net income per barrel sold rankings (US$/bbl) Downstream capex / GIC rankings (%) % % % 5% 5% 6% 5% 4% 4% 2% 2% 3% Source: Company data, Credit Suisse analysis. Note: all averages are weighted by company scale. 59

60 The business plan FOTO The long-term : 23 Petrobras self-sufficient, partners exporting : this is a simple but yet effective way to see long-term trends of the Brazilian oil sector. From 22 to 23, 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 : We provide a simple view of PBR s 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 $22bn capex plan is visually better than last year's $236bn, with an optically better mix (E&P is 7% of the capex vs 62% in the last plan); (2) however, a $27bn 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 a negative, in our view; (3) a FX assumption to finance the plan of BRL/USD 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 214, 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.

61 Million bpd The business plan The long-term: 23 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 22, of which Petrobras will be responsible for 4.2mbpd. From 22 to 23, 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.mbpd by 22 and 3.7mbpd by 23. 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 Volumes Self-sufficiency: Oil production = oil products consumption Oil Products Self-sufficiency: Total throughput = Total demand Average oil production in Brazil Petrobras+Third Parties+Government 22-23: 5.2 millions bpd Petrobras average oil production in Brazil 22-23: 3.7 million bpd 3 Average demand for oil products in Brazil 22-23: 3.4 million bpd Throughput in Brazil Brazil Oil Products Demand in Brazil Petrobras Source: Petrobras. 61

62 The business plan The short-medium term: Business plan budgets over time ($bn) business plan budget split (%) $54bn $87bn $112bn $174bn $224bn $225bn $237bn $237bn $221bn A budget that is optically down 7% YoY masks a flat budget 'under implementation/bidding' ($27bn), with the inclusion of the Premium refineries a negative in our view. Another optically positive is the higher E&P mix and lower Downstream mix in the new plan vs the past. If we look at the projects under implementation, the mix barely changed from the previous plan E&P 7% Downstream 18% G&P 5% International 4% Biofuels 1% Distribution 1% Others 1% 5-year E&P plan over time: steady increase ($bn and %) 5-year Downstream budget over time ($bn and %) E&P spend E&P share $15bn 57% 58% 6% 51% $65bn $49bn $28bn $119bn 53% $142bn $148bn $154bn $128bn 7% 57% 6% 62% Downstream Downstream share $43bn $3bn $13bn $22bn 24% 25% 26% 25% $74bn $71bn 33% 31% $66bn $65bn 28% 27% $39bn 18% Source: Petrobras, Credit Suisse analysis. 62

63 The business plan In implementation vs under evaluation and financing of the plan Projects under implementation in the past three business plans ($bn and %) $29bn $27bn $27bn $19bn $17bn $14bn 25% $52bn 21% $43bn 19% $39bn 66% $138bn 71% $147bn 74% $154bn 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. $27-29bn of projects being implemented (compatible with a c.$4bn/year spend), with roughly 7% dedicated to E&P and 2% to refining. RNEST, COMPERJ and the Premium refineries remain much contested projects by investors from an economic perspective plan plan plan E&P Downstream Others Financing of the business plan ($bn and %) $27bn $27bn Both and plans have similar budget levels, but are financed differently. The 214 version counts $1bn $1bn $11bn with a much higher percentage of cash from operations, and $9bn $21bn $6bn less debt issuances (a difficult assumption to see without meaningful price increases, in our view). $165bn $182bn plan plan Net cash flow New issuance Cash Divestments / business models A 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. Source: Petrobras. 63

64 The business plan Divisional summary E&P 5-year capex summary ($bn and %) Product Development (73.1%) Total E&P RS$ billion Infrastructure and Support, 18. (11.7%) Exploration 23.4 (15.2%) Pre-Salt (concession + ToR + Libra) 82. (6%) Production Development + Exploration RS$ billion Post-Salt 53.9 (4%) E&P Petrobras US$ billion (77%) E&P Partners US$ 44.8 billion (23%) Total with Partners US$ billion (1%) Downstream capex summary ($bn and %) Gas and Power capex summary ($bn and %) Distribution.3 (1%) Corporate.3 (1%) Logistics for Ethanol.4 (1%) Petrochemical 1.4 (4%) Fleet Expansion 3.3 (9%) Logistics for Oil 1.4 (3%) Quality and Conversion 5.5 (14%) Refining Capacity Expansion 16.8 (43%) Downstream US$ 38.7 billion Operational Improvement 9.4 (24%) Projects Under Im plem entation RNEST (Pernambuco) COMPERJ 1st phase (RJ) PROMEF - 45 Vessels to transport Oil and Oil Products Projects Under Bidding Process Premium I - 1st phase (Maranhão) Premium II (Ceará) Regas LNG.1 (1%) Network 6.1 (61%) Gas, Energy and Gas-Chemical US$ 1.1 billion Energy 1.3 (13%) Projects Under Im plem entation UNF III (Mato Grosso do Sul) UNF V (Minas Gerais) Route 2: Gas pipeline and NGPU Route 3: Gas pipeline and NGPU Gas-Chemical Operational Units (Nitrogenous 2.6 (25%) Source: Petrobras. 64

65 The business plan Graça s programmes: PROCOP, PROEF, PRODESIN, INFRALOG, PRC-Poço Impact of structural programmes in PBR s net income (R$bn) R$ -9.7 billion (-41%) Impact of structural programmes in PBR s cash balances (R$bn) R$ billion (+47%) kbpd kbpd Structural programmes gains are equivalent of exports results of +293 kbpd of crude oil kbpd Net Income PROCOP Operating Costs Optimization Program PROCOP in lifting costs (R$/boe) PRODESIN Divestment Program PROEF Program to Increase Operational Efficiency of UO-BC and UO-RIO 213 Net Income without Structuring Program Cash Position 213 PROCOP in Downstream logistics (R$/bbl) PRODESIN Divestment Program INFRALOG Integrated Management of Logistics Projects PRC Poço Program to Reduce Well Costs PROCOP Operating Costs Optimization Program Cash Position without Structuring Programs PROCOP in refining costs (R$ /UEDC) % p.a. -7.2% p.a % p.a. +.12% p.a ,177 1, % p.a. -.4% p.a. 1,24 1, Gains from PROCOP reduce Lifting Cost Optimization of routine processes and resources used in the production of oil & gas. Excellence level in the management of material and spares. Adequacy of overhead. Gains from PROCOP reduce Logistic Cost Reduction in shipping costs simplification of customs procedures; optimization of fuel consumption; and implementation of new management tools. Optimization of inventory level of oil and oil products. Reduction of stored water in the logistics system. Gains from PROCOP reduce Refining Cost Integrating common and interdependent activities among refineries. Optimized use of support resources. Optimization in the consumption of energy, catalyzers and chemicals. Without PROCOP With PROCOP Source: ANP data, Credit Suisse Research analysis. 65

66 A little more on Upstream FOTO Brazilian Pre-Salt We provide a brief recap of the pre-salt, a new oil province discovered in 26 and which has been one of the major new oil frontiers globally. In 25-21, 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 5% by 22. 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 1 selected fields that represent almost 7% of Petrobras current oil production. Of the 1 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).

67 Brazilian Pre-Salt What, Where and Who What. The pre-salt has been one of the major new oil frontiers globally. In 25-21, Brazil was 62% of new deepwater discoveries globally, led by the pre-salt. Where and who. There are currently 16 major pre-salt blocks in the Santos basin, holding at least 23bn bbls of oil: 1bn bbls in 9 blocks in the concession regime (BM-S-8, 9, 1, 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 21 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 1% of the areas. 8-12bn bbls in Libra, auctioned in 213 as part of the first pre-salt auction under the new PSC terms. Shell (2%), Total (2%), CNOOC (1%) and CNPC (1%) are the partners. Campos 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. Global oil discoveries (25-21): 34bn bbls Others 49% Deepwater 51% Source: Petrobras, ANP, Credit Suisse Research. Other countries 38% Brazil 62% Santos pre-salt map, key blocks, discoveries and PBR partners BM-S-1 Petrobras (65%) BG (25%) Partex (1%) BM-S-8 Petrobras (66%) Petrogal (14%) Barra Energia (1%) QGEP (1%) Carcará BM-S-21 Caramba Bem-te-vi Biguá Abaré Oeste Carioca Abaré BM-S-9 (Sapinhoá and Carioca) Petrobras (45%) BG (3%) Repsol Sinopec (25%) BM-S-11 (Lula, Iara and Cernambi): Petrobras (65%) BG (25%) Petrogal (1%) Cernambi BM-S-1 Parati Lula Sapinhoá South of Guará Florim Iara Peroba Libra Petrobras (4%) Total (2%) Shell (2%) CNOOC (1%) CNPC (1%) Franco South of Tupi Producing units Units to start production Surround Iara NE of Tupi Júpiter Atlanta Libra Oliva BM-S-24 (Júpiter) Petrobras (8%) Petrogal (2%) Transfer of Rights Libra Pre-salt concession 67

68 Brazilian Pre-Salt Pre-salt s early history It all started in 2 and 21, when PBR and partners participated in the 2 nd and 3 rd 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 45-8% stake in 8 of them. The remaining block was BM-S-22, operated and already relinquished by Exxon. In 21, the largest 3D seismic programme at the time was hired to cover the area. In 23, 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, 3km from the coast, below a 2km salt-layer and total depth of more than 6,m. Drilling go-ahead was taken in 23, and in March 24 the Parati well in BM-S-1 was chosen as the first location, and drilling started December 24. 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 26 and found gas condensate. Parati results motivated Petrobras to drill Tupi in 26, opening up one of the world s largest exploratory frontiers to date. Petrobras share price and key pre-salt discoveries (US$/ADR) Parati Tupi Jun-6 Sep-6 Tupi Sul Carioca Caramba Jul-7 Sep-7 Dec-7 Júpiter Bem-te-vi Guará Iara Jan-8 May-8 Jun-8 Aug-8 Iguaçu Iracema Abaré W Tupi NE Apr-9 Jun-9 Sep-9 Nov-9 Key pre-salt blocks, discoveries, partners and size Block Consortium Discoveries 1 Jan-6 Jun-6 Nov-6 Apr-7 Sep-7 Feb-8 Jul-8 Dec-8 May-9 Oct-9 Mar-1 Aug-1 Jan-11 Jun-11 Nov-11 Apr-12 Sep-12 Feb-13 Jul-13 BM-S-8 Guará N Tupi OW Franco Tupi Alto PBR (66%), Petrogal (14%), QGEP (1%), Barra (1%) BM-S-9 Petrobras (45%), BG (3%), Repsol (25%) Mar-1 Apr-1 May-1 Jun-1 Iracema N Tupi SW Libra Tupi W Oct-1 Oct-1 Oct-1 Dec-1 Bem-te-vi, Biguá, Carcará Carioca NE Macunaíma Iara-Horst Guará S Biguá Abaré Jan-11 Feb-11 Mar-11 Jul-11 Nov-11 Nov-11 Declaration of Recoverable Commerciality volume Requested Extension to - ANP Sapinhoá (Guará) Dec bn bbls Carioca Dec-13 - BM-S-1 Petrobras (65%), BG (25%), PAX (1%) Parati Mar-16 - BM-S-11 Petrobras (65%), BG (25%), Petrogal (1%) Lula (Tupi) Dec-1 6.5bn bbls Cernambi (Iracema) Dec-1 1.8bn bbls Iara Dec bn bbls BM-S-21 Petrobras (8%), Petrogal (2%) Caramba Apr-15 - BM-S-24 Petrobras (8%), Petrogal (2%) Jupiter Feb-16 - ToR Petrobras (1%) 7 Blocks Sep-14 5bn bbls Libra PBR (4%), Shell (2%), Total (2%), CNOOC (1%), CNPC (1%) Libra Dec bn bbls Carioca Sela Feb-12 Franco NW Feb-12 Carcará Mar-12 Tupi NE Mar-12 Dolomita S Apr-12 Iara W Apr-12 Sul de Guará Jun-12 Franco SW Aug-12 Júpiter NE Oct-12 Carioca N Oct-12 Source: Petrobras, IPEA, Credit Suisse, Woodmac. 68

69 Brazilian Pre-Salt Importance for PBR s production profile The pre-salt will be a key part of PBR s future growth. Out of the 38 platforms Petrobras is adding in the 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 217 (35% pre-salt concession, 7% ToR), and to 5% by 22 (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. Petrobras production profile Espadarte Cd. Rio de Janeiro 1kbd Polvo 9kbd Piranema 3kbd Golfinho Cd. Vitória 1kbd Roncador P-52 18kbd Roncador P-54 18kbd CS estimates Historical production Petrobras targets Marlim Leste P-53 18kbd Golfinho Cd. Vitoria 1kbd Siri Pilot Cd. Rio das Ostras 15kbd Marlim South P-51 18kbd Source: Petrobras, Credit Suisse. Tupi South Cid Sao Vicente 3kbd Frade Frade FPSO 1kbd Marlim Leste Cd. Niteroi 1kbd Camarupim Cid Sao Mateus 25kbd Parque das Conchas 1kbd No growth since 21 Lula Pilot Cd. Angra dos Reis 1kbd FPSO Capixaba Cachalote/Balei a Franca 1kbd Sidon / Tiro Atlantic Zephyr 2kbd Jubarte FPSO P-57 18kbd Marlim Sul SS P-56 1kbd Baleia Azul Cid Anchieta 1kbd 7%+ p.a. growth until 216 Lula NE Cd Paraty 12kbd Sapinhoa Pilot Cd São Paulo 12kbd Papa Terra P-63 15kbd Roncador P-55 18kbd Bauna / Piracaba Cid Itajai 8kbd Pre-Salt (Concession) 93% Sapinhoá Norte Cid. Ilhabela 15kbd (Start-up Q3) Iracema Sul Cd. Mangaratiba 15kbd (Start-up Q4) Papa Terra P-61 & TAD (Start-up Q2) Pq. Baleias P-58 FPSO 18kbpd (Start-up Q1) Roncador module 4 P-62 18kbd (Start-up Q2) PBR production mix: pre-salt gaining share Post-Salt New Discoveries Transfer of Rights million bpd 2.75 million bpd 4.2 million bpd Iracema Norte Cd Itaguai 15kbd (Start-up Q3) 7% 58% Franco (Buzios) 2 P-75 15kbd Franco (Buzios) 1 P-74 15kbd Carioca (Lapa) Cd. Caraguatatuba 1kbd Lula Central Cid Saquarema 15kbd Tartaruga Verde e Mestiça 7% 35% 44% 31% 6% 19% 1.5 Pre-Salt + Libra Transfer of Rights Post-Salt FPSOs already contracted e 215e 216e 217e 218e 219e 22e Lula Norte P-67 15kbd Lula Sul P-66 15kbd Lula Alto Cd Marica 15kbd Franco (Buzios) 3 (NW) P-76 15kbd Iara Horst P-7 15kbd Lula Oeste P-69 15kbd 1%+ p.a. growth after 216 Franco (Buzios) 4 (Sul) P-77 15kbd Lula Ext Sul + ToR Sul de Lula P-68 15kbd Tupi NE P-72 15kbd Entorno de Iara P-73 15kbd Iara NW P-71 15kbd Sul Pq Baleias Carcará Deepwater Espirito Santo Deepwater Sergipe I Maromba Marlim Revital I Franco (Buzios) 5 (Leste) Júpiter Florim Libra Deepwater Sergipe II Marlilm Revitali II Espadarte III mnbpd 69

70 Brazilian Pre-Salt Geology & Challenges 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 CO 2 and H 2 S contents; (3) have more robust mooring systems to resist higher tensions and riser weight Ocean 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. 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 (CO 2, H 2 S) 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. m 3.m Post Salt Large Campos basin fields such as Marlim, Albacora and Roncador have high porosity/permeability sandstone reservoirs. Oil quality is heavy, c.2 o API. Some post salt reservoirs, such as Papa-Terra and BS-4, are more challenging due to even heavier oil (15 o API) and shallow reservoir both which would call for TLPs rather than FPSO development 4.m 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 15 days. Only in 213, six years after the Parati well, was PBR able to perform horizontal drilling (85 o angle) through the salt-layer 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. 6.m Pre-salt Source: Credit Suisse Research. 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 2s-3 o API. 7.m 7

71 Ten fields to remember PBR s 1 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 1 fields that are already producing that represent almost 7% of Petrobras current oil production. Of the 1 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 1-fields production, ranking of production, reserves, and play type Ten fields oil production and importance to Petrobras (production in kbd, share in %) Production Ranking (213) Field Oil % of PBR Production Production (kbd) Oil reserves Basin (mmbbl) Play type 1 Marlim Sul % 1,2 Campos Post-salt 2 Roncador % 1,297 Campos Post-salt 3 Marlim 177 9% 536 Campos Post-salt 4 Jubarte 138 7% 771 Campos Pre and Post salt 5 Marlim Leste 18 6% 268 Campos Post-salt 6 Barracuda 17 6% 278 Campos Post-salt 7 Baleia Azul 63 3% 46 Campos Pre and Post salt 1,4 1,2 1, % 6% 5% 4% 3% 2% 1% 8 Lula 63 3% 8,172 Santos Pre-salt 9 Albacora 58 3% 186 Campos Post-salt Sapinhoá 13 1% 1,797 Santos Pre-salt Source: ANP, Woodmac, Credit Suisse Research. % Jan-5 Jan-6 Jan-7 Jan-8 Jan-9 Jan-1 Jan-11 Jan-12 Jan-13 MARLIM MARLIM SUL RONCADOR MARLIM LESTE ALBACORA BALEIA AZUL BARRACUDA JUBARTE LULA SAPINHOÁ % of total 71

72 Ten fields to remember Marlim Ownership Petrobras 1% Location Campos Basin Peak Production 595 kbd (22) Oil production by platform (kbd) 6 Oil Quality 18-24º API Remaining Reserves Oil: 536mmbbls Gas: 5bcf Water Depth 65-1,5 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 22, 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 21, below Marlim reservoirs. Oil production by vintage (kbd) pre 29 Small amount of wells drilled post 28 coupled with natural decline Jan-5 Jan-6 Jan-7 Jan-8 Jan-9 Jan-1 Jan-11 Jan-12 Jan-13 Average well production by vintage (kbd) Sharp decline of most wells drilled post P-37 P-35 P-33 P-26 P-2 P-19 P-18 Jan-5 Dec-5 Nov-6 Oct-7 Sep-8 Aug-9 Jul-1 Source: ANP, Woodmac, Credit Suisse Research. Jun-11 May-12 Apr pre Jan-5 Dec-5 Nov-6 Oct-7 Sep-8 Aug-9 Jul-1 Jun-11 May-12 Apr-13 72

73 Ten fields to remember Marlim Sul Ownership Petrobras 1% Location Campos Basin Oil Quality 13-27º API Remaining Reserves Oil: 1,bn bbls Gas: 261bcf Water Depth 1,159-1,874 meters Oil production by vintage (kbd) Good productivity of new P-56 wells led to an increase in production 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 21 and aimed at exploring reserves at up to 1,5m water depth. Phase two started in 211 with the P-56 platform Pre Jan-5 Dec-5 Nov-6 Oct-7 Sep-8 Aug-9 Jul-1 Jun-11 May-12 Apr-13 Oil production by platform (kbd) P-26 and others 5 FPSO Marlim Sul Jan-5 Dec-5 Nov-6 Oct-7 Sep-8 Aug-9 Jul-1 Source: ANP, Woodmac, Credit Suisse Research. P-56 P-56 P-51 P-51 P-4 P-4 Jun-11 May-12 Apr-13 Average well production by vintage (kbd) Good productivity and slow decline of wells drilled in pre Jan-5 Dec-5 Nov-6 Oct-7 Sep-8 Aug-9 Jul-1 Jun-11 May-12 Apr-13 73

74 Ten fields to remember Marlim Leste Ownership Petrobras 1% Location Campos Basin Oil Quality 23º API Remaining Reserves Oil: 268mmbbls Gas: 98bcf Water Depth 933-2,444 meters Marlim Leste is smaller than Marlim and Marlim Sul, with c.47mmbbls of initial oil reserves, and still 27mmbbls 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 8s, but definitive units FPSO Cidade de Niteroi and P-53 only started in 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 21. Oil production by platform (kbd, LHS) and average well (RHS) Average well production Cid. De Niteroi Decline of old wells connected to Cid. de Niteroi P- 53 FPSO Cidade de Niteroi Others Jan-8 Sep-8 May-9 Jan-1 Sep-1 May-11 Jan-12 Sep-12 May Oil production (kbd, LHS) and average production per well (RHS) Average prduction per well (bbl/day) Jan-8 Sep-8 May-9 Jan-1 Sep-1 May-11 Jan-12 Sep-12 May-13 Source: ANP, Woodmac, Credit Suisse Research Total Flat number of producing wells Oil production by vintage (kbd, LHS) and number of wells (RHS) Number of wells count Pre - 29 Jan-8 Sep-8 May-9 Jan-1 Sep-1 May-11 Jan-12 Sep-12 May

75 Ten fields to remember Roncador Oil production by platform: P-55 and P-62 to come online in 213 and 214 (kbd) 4 Ownership Petrobras 1% Location Campos Basin Oil Quality 18-31º API Remaining Reserves Oil: 1,3bn bbls Gas: 338bcf Water Depth 1,7 meters P-54 Maintenance in P-54 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 213/early 214 (P-55 and P-62, both 18kbd). 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 211, and Brasil and P-52, starting 22/27; (2) With P-54 in 27 to explore the heavier oil in the Southwest, and modules 3 (P-55, Southeast) and module 4 (P-62, South/Central) upcoming P-52 Maintenance in P-52 5 FPSO Brasil Jan-5 Jan-6 Jan-7 Jan-8 Jan-9 Jan-1 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) Number of wells count (RHS) Flat number of wells, declining productivity Oil production (LHS, kbd) Number of wells count (RHS) Average production per well (LHS, kbd) Jan-5 Jan-6 Jan-7 Jan-8 Jan-9 Jan-1 Jan-11 Jan-12 Jan-13 Jan-5 Jan-6 Jan-7 Jan-8 Jan-9 Jan-1 Jan-11 Jan-12 Jan-13 Source: ANP, Woodmac, Credit Suisse Research. 75

76 Ten fields to remember Barracuda Ownership Petrobras 1% Location Campos Basin Peak Production 163 kbd (26) Oil Quality 25º API Remaining Reserves Oil: 278mmbbl Gas: 5bcf Water Depth meters With 71mmbbls of initial reserves, full production started in late 24, reaching a peak in 26. Barracuda has so far produced 6% of initial reserves. The field is facing an average 1% decline in observed production, though development drilling on the eastern flank of the field with P-48 provided a rise in production in Like many other fields in the Campos basin, there is pre-salt potential below existing post-salt reservoirs in the Nautilus discovery (made in 21). Oil production by platform (kbd) Others Maintenance in P-43 P-43 P-48 Jan-5 Dec-5 Nov-6 Oct-7 Sep-8 Aug-9 Jul-1 Jun-11 May-12 Apr-13 Oil production (kbd, LHS) and average well production (RHS) Average well production (kbd, LHS) and number of wells (RHS) Average well production (RHS, kbd) Well additions on P-48 offset declining productivity Number of wells (RHS) Oil production (LHS, kbd) Average production per well (LHS, kbd) 1 5 Jan-5 Jan-6 Jan-7 Jan-8 Jan-9 Jan-1 Jan-11 Jan-12 Jan-13 Jan-5 Jan-6 Jan-7 Jan-8 Jan-9 Jan-1 Jan-11 Jan-12 Jan-13 Source: ANP, Woodmac, Credit Suisse Research. 76

77 Ten fields to remember Albacora Ownership Petrobras 1% Location Campos Basin Peak Production 156 kbd (1999) Oil Quality 19-29º API Remaining Reserves Oil: 186mmbbl Gas: 6bcf Water Depth meters Albacora is a historically important field for Petrobras. Discovered in the mid 198 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 5mmbbls discovery in 211, which has yet to be tested. Other initiatives such as raw seawater injection are currently being tested in the field. Average well production by vintage (kbd) Low well productivity in a very mature field pre Jan-5 Dec-5 Nov-6 Oct-7 Sep-8 Aug-9 Jul-1 Jun-11 May-12 Apr-13 Oil production (kbd, LHS) and average well production (RHS) Oil production by platform (kbd) pre 29 3, Well productivity (RHS, bbls/day) 3, 2,5 2, P-5 Maintenance in P-25 and P-31, ended in June 6 1,5 6 P Jan-5 Jan-6 Jan-7 Jan-8 Jan-9 Jan-1 Jan-11 Jan-12 Jan-13 1, P-25 Others Jan-5 Jan-6 Jan-7 Jan-8 Jan-9 Jan-1 Jan-11 Jan-12 Jan-13 Source: ANP, Woodmac, Credit Suisse Research. 77

78 Ten fields to remember Parque das Baleias: Baleia Azul Ownership Petrobras 1% Location Campos Basin Oil Quality 17º (post-salt) 3º (pre-salt) Remaining Reserves Oil: 46mmbbl Gas: 14bcf Water Depth 1,338-1,348 meters Baleia Azul is a medium sized (c.4mmbbls) 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 bn bbls, in addition to the known post-salt. Baleia Azul reserves are c.6% presalt. Field production started in 212 already focused on the pre-salt, via FPSO Cid Anchieta, and P-58 to start-up soon. Post salt will be targeted in 214 with P-34. Fields within the Parque das Baleias (Whale s Park) complex ES BM-C-25 Cachalote Baleia Anã Caxareu Jubarte Baleia Azul Pirambu BM-C-25 Baleia Franca Nautilus Mangangá Argonauta C-M-61 Oil production per well (kbd) BAZ6ESS 7BAZ4ESS 6BRSA631DBE SS 7BAZ2ESS 7BAZ3ESS Total and average well production (kbd, LHS) and well-count (RHS) Sep-12 Nov-12 Jan-13 Mar-13 May-13 Jul-13 Sep-13 Nov-13 Average well production (LHS, kbd) Number of wells (RHS) Oil production (LHS, kbd) Sep-12 Nov-12 Jan-13 Mar-13 May-13 Jul-13 Sep-13 Nov-13 Source: ANP, Woodmac, Credit Suisse Research. 78

79 Ten fields to remember Parque das Baleias: Jubarte Ownership Petrobras 1% 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. 3% of total initial reserves. Postsalt development started in 22 via an EWT. A pilot project using FPSO JK (P-34) went from 26 to 212, producing from both pre and post-salt. End 21, two units started: P-57 targeting the post-salt, and FPSO Capixaba targeting the pre-salt. FPSO Cid de Anchieta started in 213, 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 213, 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) Maintenance in FPSO JK Location Campos Basin 2 FPSO JK FPSO Capixaba Jan-5 Dec-5 Nov-6 Oct-7 Sep-8 Aug-9 Jul-1 Jun-11 May-12 Apr-13 Source: ANP, Woodmac, Credit Suisse Research. Oil Quality 17º (post-salt) 3º (pre-salt) FPSO Cidade de Anchieta to produce from Jubarte, Baleia Azul and Pirambu fields Remaining Reserves Oil: 771mmbbl Gas: 2bcf Water Depth 1,245-1,347 meters P-57 Oil production (kbd, LHS) and number of wells (RHS) Average well production by vintage (kbd) Decline offset by the increasing number of producing wells pre 29 Oil production (LHS, kbd) 21 Number of wells (RHS) Jan-5 Jan-6 Jan-7 Jan-8 Jan-9 Jan-1 Jan-11 Jan-12 Jan-13 Strong decline of P-57 wells since / Jan-5 Dec-5 Nov-6 Oct-7 Sep-8 Aug-9 Jul-1 Jun-11 May-12 Apr

80 Ten fields to remember Lula (former Tupi) Ownership Petrobras: 65% BG: 25% Petrogal: 1% Location Santos Basin Oil Quality 28º API Remaining Reserves Oil: 8,172mmbbl Gas: 3,934bcf Water Depth 2,2 meters Discovered in 26, 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 2-3kbd and since 21 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). Well-by-well production (kbd) High quality wells: slow decline and high production 3BRSA496RJS 9BRSA98DRJS Scheduled maintenance, ended in June 7LL11RJS 5 9BRSA716RJS 7LL3DRJS Sep-1 Jan-11 May-11 Sep-11 Jan-12 May-12 Sep-12 Jan-13 May-13 Sep-13 Oil production, average production per well and number of producing wells (kbd) Average pruduction per well (LHS, kbd) Source: ANP, Woodmac, Credit Suisse Research. Number of wells (RHS) Oil production (LHS, kbd) Sep-1 Feb-11 Jul-11 Dec-11 May-12 Oct-12 Mar-13 Aug Oil production per FPSO (kbd) FPSO Cid. de Paraty FPSO Cid. de Angra dos Reis Sep-1 Feb-11 Jul-11 Dec-11 May-12 Oct-12 Mar-13 Aug-13 8

81 Ten fields to remember Sapinhoá (former Guará) Oil production (kbd): only one flexible riser producing so far 35 Ownership Petrobras: 45% BG: 3% Repsol: 25% Location Santos Basin Oil Quality 28-3º API Remaining Reserves Oil: 1,797mmbbl Gas: 1,29bcf Water Depth 2,141 meters Discovered in 28 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 213) and Cid de Ilhabela (due 214). 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 2kbd, the delays cost Petrobras 6kbd of production in 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 Steel Catenary Risers Flexible jumpers Buoy Mooring lines 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 Wellheads Source: ANP, Woodmac, Credit Suisse Research. 81

82 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 5% 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).

83 Refineries overview Old refineries and poor distribution infrastructure REMAN (built in 1949) Refinery capacity (kbd) LUBNOR (1966) RPCC (29) RNEST (214) RLAM (1956) REPAR (1977) REGAP (1968) REDUC (1961) REVAP (198) REPLAN (1972) RPBC (1952) RECAP (1954) REFAP (1968) Output of refined products over time (kbd) 2,5 2, 1,5 1, 5 Jan- Oct-1 Jul-3 Apr-5 Jan-7 Oct-8 Jul-1 Apr-12 Other Naphtha LPG Fuel Oil Gasoline A Diesel Source: Credit Suisse research based on Petrobras and the ANP. 83

84 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.$2bn, 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) Diesel consumption and production per region (kbd) Consumption Production Production Surplus in the Southeast Consumption Production Fastest growing regions: high expansion in disposable incom e coupled with lack of production 4 Abreu e Lima refinery to increase Northeast production capacity SE S NE MW N SE S NE MW N Source: Credit Suisse research based on the ANP. Data for

85 Refineries overview Southeast overview REGAP (1968) REDUC (1961) REVAP (198) REPLAN (1972) RPBC (1952) RECAP (1954) Diesel and gasoline production surplus in the Southeast (kbd) 2 Diesel Gasoline A Jun- Feb-2 Oct-3 Jun-5 Feb-7 Oct-8 Jun-1 Feb-12 Source: Credit Suisse research based on the ANP. Southeast: Refinery capacity and product yield (kbd) ,4 1,2 1, REPLAN REVAP REDUC RPBC REGAP RECAP Other Naphtha LPG Fuel Oil Gasoline A Diesel Southeast: Output of refined products over time (kbd) Jan- Nov-1 Sep-3 Jul-5 May-7 Mar-9 Jan-11 Nov-12 Other Naphtha LPG Fuel Oil Gasoline A Diesel 85

86 Refineries overview North and Northeast overview REMAN (built in 1949) LUBNOR (1966) RPCC (29) RNEST(214) RLAM (1956) North/Northeast: Refining capacity and product yield (kbd) Consumption of oil distillates: N/NE highest growing regions Index (2 = 1) Midwest Northeast North Southeast South Source: Credit Suisse research based on the ANP RLAM REMAN RPCC LUBNOR Other Naphtha Fuel oil Gasoline Diesel North/Northeast: Output of refined products over time (kbd) Jan- Dec-1 Nov-3 Oct-5 Sep-7 Aug-9 Jul-11 Jun-13 Diesel Gasoline A Fuel Oil Naphtha Other 86

87 Downstream demand Diesel demand driven by economic activity, Gasoline by income Diesel consumption per region (kbd) 1,2 1, Gasoline consumption per region (kbd) Diesel consumption growth among regions is more evenly distributed than gasoline, where the North-NE grow disproportionally more (income effect) Jan- Apr-2 Jul-4 Oct-6 Jan-9 Apr-11 Jan- Apr-2 Jul-4 Oct-6 Jan-9 Apr-11 South Growth in gasoline consumption is concentrated in North, Midwest and Northeast regions Source: Sindicom; Credit Suisse Research based on the ANP. North Midwest Northeast Southeast North Midwest Northeast South Southeast CAGR 5% 4% 5% 3% 4% CAGR 8% 6% 7% 5% 3% Diesel consumption x Industrial production index (22 = 1) (kbd and index ) 1,1 1, 9 8 Industrial production (index, RHS) Diesel (kbd, LHS) 9 8 Jan- Sep-1 May-3 Jan-5 Sep-6 May-8 Jan-1 Sep-11 May-13 Gasoline and Ethanol consumption vs average income in Brazil (kbd of gasoline equivalent, BRL) 1, Seasonal increase during year end due to 13rd salary income boost and vacation period Fuel consumption (kbd, LHS) Average Income (R$, RHS) 3 Jan-2 Jul-3 Jan-5 Jul-6 Jan-8 Jul-9 Jan-11 Jul ,5 2, 1,5 1, 87

88 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 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% 13% 11% 43% 37% 46% 25% 11% 43% 81% Licensing of new diesel vehicles (thousand units) 42 Light Vehicles Heavy Vehicles CAGR: 7% 58% 53% 5% 43% 32% 8% Brazil Australia China Canada USA Russia Road Rail Water & Others Consumption of diesel in the road sector (kt of oil equivalent) 123 Road-intensive transportation matrix and continental dimension puts Brazil as 3rd largest consumer in the road sector Source: Credit Suisse Research. 88

89 Downstream demand Gasoline and Ethanol are substitutes Income. 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.5% of the light vehicle fleet, a strong increase vs the 2% back in 25. In general terms, if hydrous ethanol is being sold at any price below 7% 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 , 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) Growth in Fuel demand answered by ethanol Gasoline C Hydrous Ethanol Jan- Oct-1 Jul-3 Apr-5 Jan-7 Oct-8 Jul-1 Apr-12 Source: UNICA, Bloomberg, Conab, Credit Suisse Analysis. Pressure on Gasoline C demand due to high ethanol prices at the pump Light vehicles fleet by fuel type (mn vehicles) % 75% 7% 65% 6% 55% Flex fuel and ethanol went from 21% of the fleet in 25 to c.5% in 212, and is expected to rise to 68% by the end of the decade Gasoline Fleet, LHS Ethanol fleet, LHS Max. Parity Flex fuel, LHS Net additions to flex fuel, RHS Price parity in São Paulo between Gasoline C and Ethanol (%) Gasoline more competitive Price ratio 5% Ethanol m ore com petitive 45% Jan-8 Sep-8 May-9 Jan-1 Sep-1 May-11 Jan-12 Sep

90 Italy Germany UK Japan China Canada USA Argentina Chile Uruguay Brazil Distribution Pricing overview Domestic gasoline pump prices breakdown (%) Domestic diesel pump prices breakdown (%) 18% 13% 27% Resale and distribution Anhydrous ethanol cost ICMS (state tax) 16% 4% 14% 6% Resale and distribution Biodiesel cost ICMS (state tax) CIDE, PIS/ PASEP, CONFINS (Federal taxes) 7% 35% CIDE, PIS/ PASEP, CONFINS (Federal taxes) Refinery gasoline price (Petrobras) 6% Refinery diesel price (Petrobras) Gasoline pump prices comparison across countries (US$/liter) Domestic LPG consumer price breakdown (%) Resale / Distribution margin Taxes Anhydrous ethanol Refinery price 56% 12% 5% 27% Resale and distribution ICMS (state tax) CIDE, PIS/ PASEP, CONFINS (Federal taxes) Petrobras price realisation Source: Petrobras, ANP, MME, Credit Suisse Research. 9

91 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 (2-25%) 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. LPG consumer price evolution over the years (R$/bottle) May-8 Apr-9 Mar-1 Feb-11 Jan-12 Dec-12 Nov-13 Local Taxes Federal Taxes Transportation Costs Resale Margin Distribution Margin LPG Gasoline pump price evolution over the years (R$/liter) May-8 Apr-9 Mar-1 Feb-11 Jan-12 Dec-12 Nov-13 Diesel pump price evolution over the years (R$/liter) May-8 Apr-9 Mar-1 Feb-11 Jan-12 Dec-12 Nov-13 Local taxes Federal Taxes Transportation costs Resale margin Distribution margin Anhydrous ethanol Gasoline Local taxes Federal Taxes Transportation costs Resale margin Distribution margin Biodisel Diesel Source: MME, Credit Suisse Research. 91

92 Distribution margin (R$/l) Gasoline refinery price (R$/l) Distribution margin (R$/l) Diesel refinery price (R$/l) 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). Gasoline margins vs refinery price (R$/liter) Gasoline and diesel distribution and resale margins (R$/liter) Diesel margins vs refinery price (R$/liter) Gasoline resale margins.3.25 Diesel resale margins.2 Gasoline.15 distribution margins.1 Diesel.5 distribution. margins May-8 Jan-9 Sep-9 May-1 Jan-11 Sep-11 May-12 Jan-13 Sep Gasoline Distribution margin Diesel Distribution margin May-8 Feb-9 Nov-9 Aug-1 May-11 Feb-12 Nov-12 Aug May-8 Feb-9 Nov-9 Aug-1 May-11 Feb-12 Nov-12 Aug-13. Source: MME, Credit Suisse Research. 92

93 Distribution Which region is more profitable? Gasoline distribution margins by region (R$/liter).3 N.25 Gasoline resale margins by region (R$/liter).5.45 MW N.2 SE.4 NE S.5 MW. NE May-8 Jan-9 Sep-9 May-1 Jan-11 Sep-11 May-12 Jan-13 Sep-13 Diesel distribution margins by region (R$/liter).35.3 NE.25.2 N.15 MW SE.1.5 S. May-8 Jan-9 Sep-9 May-1 Jan-11 Sep-11 May-12 Jan-13 Sep-13.3 SE.25 S.2 May-8 Jan-9 Sep-9 May-1 Jan-11 Sep-11 May-12 Jan-13 Sep-13 Diesel resale margins by region (R$/liter) N SE.23 S.21 NE.19 MW May-8 Jan-9 Sep-9 May-1 Jan-11 Sep-11 May-12 Jan-13 Sep-13 Source: MME, Credit Suisse Research. 93

94 Distribution The market share game Brazil Distribution market share 22% Other 22% 4% 4% 3% 2% 1% Market share evolution 19% 33% % Jan-9 Nov-9 Sep-1 Jul-11 May-12 Mar-13 North/ Northeast/ Mid-West 27% 4% North/Northeast/Mid-West 5% 4% 3% 14% 14% 41% 2% 1% % Jan-9 Oct-9 Jul-1 Apr-11 Jan-12 Oct-12 Jul-13 South/ Southeast 27% 21% 2% 4% 28% South/SE 3% 25% 2% 15% 1% 5% % Jan-9 Oct-9 Jul-1 Apr-11 Jan-12 Oct-12 Jul-13 Other Source: Credit Suisse research based on Sindicom. 94

95 Distribution The fight against the white flags Brazil Current share of number of Gas stations 5% White-flag 19% 39% 16% 12% 9% Other Branded White-flag WF share 38% Number of gas stations (thousands) and white flag market share 42% 41% 4% 39% North/ Northeast/ Mid-West 46% 8% 4% 2% 9% 13% North/Northeast/Mid-West 45% 49% 48% 47% 46% South/ Southeast 34% 5% 19% South/SE 34% 38% 37% 35% 34% % 7% 21% Other White-flag Branded WF share Source: Credit Suisse research based on Sindicom. 95

96 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.

97 Understanding Gas & Power A brief overview Revenues G&P and Petrobras 8.2% c. 65% of revenues Revenues of c.$12bn and EBITDA of c. $2bn Natural Gas Revenues of c. $8bn Three main markets for natural gas are: - Industrial, commercial and retail customers - Thermoelectric generation - Petrobras refineries and fertilizer plants EBITDA 91.8% c. 3% of revenues Power Revenues of c. $3.7bn Petrobras has participation in Thermopower, wind and small-scale hydroelectric plants 6,235 MW of installed capacity 7.2% 92.8% c. 5%of revenues Fertilizers Revenues of c.$6m The company is focused on the production of ammonia and urea for the Brazilian market G&P Petrobras ex-g&p Source: Petrobras, Credit Suisse research. 97

98 Understanding Gas & Power The Gas Supply Natural gas pipeline network Three main markets Sources of natural gas supply (%) Pipeline networks footprint Petrobras natural gas pipeline network has a total extension of 9,19 km Natural gas demand (%) 11% 36% 53% LNG Domestic production Imported from Bolivia Total Natural Gas supply of 75MM 3 /d LNG Pecem LNG Baía de Guanabara LNG Bahia The company invested $13bn between 26 and 212 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 22% 25% 53% Gas-fired power plants Internal consumption Local distribution companies Total Natural Gas sales of 55MM 3 /d and internal consumption of 19MM 3 /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

99 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 214 CESP, 7% CEMIG, 6% Thermo power, 19% Eletrobrás, 3% Itaipu, 6% Hydro, 63% Tractebel, 6% Biomass, 8% Wind, 2% Imports from Itaipú (Hydro), 8% Others, 29% Petrobras, 6% Copel, 4% CPFL, 2% AES Tietê, 2% Duke Energy, 2% 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. Volumes of electricity sold by Petrobras MW avg Total sales commitments 4, ,853 Bilateral merchant contracts 2,318 2, 2,24 Self-production Standby-availability 1,697 1,596 1,391 Generation volume 2, ,837 Revenues (US$ mm) 3,755 2,336 2,752 Source: ANEEL, Tractebel, Petrobras. 99

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