Exploration and production snapshots: Brazil
Time, capital, and opportunity
With seemingly ample natural resources, growing domestic energy needs, and a population approaching 210 million, Brazil will likely continue to play a large role in both the Latin American and global oil and gas markets. But will the country’s recent political and economic changes—and the increasing competitiveness of government-controlled oil giant, Petrobras—be enough to help its oil and gas industry overcome significant investment, development, and corruption challenges? This report explores the challenges and opportunities in Brazil’s upstream sector, discusses key indications of a shifting energy landscape, and provides an outlook of the country’s long-term potential.
Americas exploration and production (E&P) snapshots
In this series, Americas E&P Snapshots, Deloitte profiles the region’s major countries, their hydrocarbon endowments, the historical context of the industry in each country, and the new opportunities that seem to be taking shape. Each country report concludes with considerations for the future and an assessment of the country’s attractiveness for new investment in the E&P sector.
The series includes profiles of the following countries:
How we got here: Highlights from historical oil and gas development
With seemingly ample natural resources, growing domestic energy needs,1 and a population approaching 210 million,2 Brazil will likely continue to play a large role in Latin America and the world. This report explores the challenges and opportunities in Brazil’s upstream sector, discusses key signposts indicating shifts in the energy landscape, and provides an outlook of the country’s long-term potential.
Figure 1. Brazil’s energy landscape at a glance
Sources: Deloitte analysis, Agência Nacional do Petróleo, Gás Natural e Biocombustíveis3
Putting Latin America (and Brazil) in a global context
In the decade leading up to 2014, global crude prices exceeded $140 per barrel, fell to less than $40, and then plateaued well above $100 for several years. Following tremendous production growth from US shale oil and the November 2014 Organization of the Petroleum Exporting Countries (OPEC) decision not to cut production, prices fell to 13-year lows in early 2016, before partially recovering in recent months.4 During this period, production in Latin America grew less than the rest of the world on a percentage basis.5 Brazil is a notable exception, in no small part due to the discovery of the pre-salt following the 2005 Parati and 2006 Tupi exploration wells.6 The Tupi
That is not to say all of Brazil’s oil and gas comes from beneath the salt. With rapidly growing production from fields like Lula and others such as Jubarte and Baleia Azul, pre-salt production accounts for more than 40 percent of the country’s production. So while the pre-salt play represents a substantial fraction of total production, the majority of Brazil’s oil and gas is still produced from post-salt fields, including a small contribution from the onshore fields, making Brazil a substantial, and growing,
Brazil upstream in brief
Currently, Petrobras produces roughly 80 percent of the country’s oil and gas and operates virtually all the largest fields, although both large international and smaller domestic players are active (figure 2).9 Many of these large fields are in the offshore pre-salt play, which represents roughly 40 percent of the country’s production (figures 3 and 4), and the pre-salt is expected to continue growing both in absolute terms as well as relative to other existing geological plays.10
Considering the deep water, limited infrastructure, and challenging reservoir characteristics,11 as well as the company’s own financial constraints stemming from very high debt levels,12 Petrobras may not have the capacity to fully develop the resource as the primary investor and operator in a reasonable time frame. As a result, although historically various restrictions have been placed on other E&P companies operating in Brazil, with Petrobras being granted certain monopolies and dominant positions, some of these restrictions are now being moderated substantially (see Main events and milestones for more details). Increased investment in not just the upstream, but also the midstream sector could be critical for Brazil’s exploration and production sector’s long-term success. Currently, roughly 25 percent of natural gas is reinjected, largely because of a number of issues, including the lack of sufficient infrastructure connecting offshore fields to major demand centers.
Figure 3. Total Brazilian oil, condensate, and natural liquids production continues to grow despite low prices
Figure 4. High amount of reinjection and industry consumption has led to slower growth in marketable natural gas compared with total
Sources: Deloitte analysis, Agência Nacional do Petróleo, Gás Natural e Biocombustíveis14
Sources: Deloitte analysis, Agência Nacional do Petróleo, Gás Natural e Biocombustíveis15
The majors and other large independent oil companies seem particularly well suited to tackle the challenge of the pre-salt, and in fact, companies including Chevron, Shell, ExxonMobil, Total, and Statoil all have experience with major capital projects in the Gulf of Mexico sub-salt Miocene and Paleogene, or African Gulf of Guinea pre-salt, and frequently both. The latter two companies, Statoil16 and Total,17 have both farmed into pre-salt projects in Brazil. With the relaxation of Petrobras’s operatorship requirements, others will likely follow in the near term.
Nevertheless, focusing exclusively on the pre-salt may not be appropriate—more than half of current production is found elsewhere, particularly in offshore post-salt fields. At least two successful bid rounds that occurred in 2017 were under the concession regime and outside of the established pre-salt polygon region. One attracted primarily smaller domestic players and focused on marginal accumulations in mature basins. The other bid round led to 37 blocks being awarded. That round stood out because out of the 17 companies that won blocks, seven were foreign companies. It also had the highest bonus in the country’s history, $1.2 billion, for two blocks in the Campos basin.18
Petrobras has more than 50 platforms and floating production, storage, and offloading (FPSO) vessels in the Campos basin, plus dozens of others in the Santos, Espirito Santo, Sergipe, Alagoas, and Potiguar basins as well as roughly 100 onshore fields, all of which are primarily tapping into conventional resources.19 With extensive production history and existing platforms, both domestic and international operators that focus on brownfield development, enhanced oil recovery, or infrastructure-led exploration could find substantial opportunities in post-salt projects with less technical challenges.
However, both pre- and post-salt projects could still face development challenges. Few service companies can tackle the
Main events and milestones
Key plays to watch
What is the pre-salt?
Typically, oil and gas reservoirs are porous layers of sandstone or limestone containing the hydrocarbons within the pores of the rock formation. The oil and gas are contained within the reservoir via an impermeable cap rock, such as shale or in some cases salt.41 In fact, there has been an extensive history of drilling prospects under and adjacent to large salt domes found in the US Gulf Coast, both onshore and offshore. Today, many deepwater fields found in the Gulf of Mexico are producing from sub-salt sand reservoirs.42
However, the US sub-salt plays differ in many respects from Brazil’s (and West Africa’s) pre-salt reservoirs. For one, the sub-salt reservoirs are primarily limestone rather than sandstone due to different types of deposition (i.e., lacustrine, not turbidite). And they are much older—Cretaceous as opposed to Neogene and Paleogene.43 That age difference stems from the distinction between sub-salt and pre-salt. In the case of the Gulf of Mexico, the sub-salt reservoirs are found abutting or underneath salt diapirs, formed by upwardly migrating mobile salt (referred to as allochthonous). This means the reservoirs are much younger than the salt covering them. The pre-salt reservoir sediment was actually deposited before the formation of the salt layer, and therefore pre-dates it (referred to as autochthonous).44 While that distinction may seem semantic or academic, geological history is key to identifying, appraising, and exploiting petroleum systems.
Offshore pre-salt fields play an outsized role in Brazil’s exploration and production sector
Brazil’s pre-salt region includes some of the world’s largest remaining oil fields. Like much of the world’s remaining resources, the country’s fields are located offshore in deep water with challenging reservoirs. For companies with substantial offshore experience, the reward could likely outweigh the risks. Not only that, but after comparing a broad number of offshore fields across a number of basins, fiscal regimes, and technical challenges, the pre-salt fields frequently have above-average financial returns combined with an order-of-magnitude larger resource potential (figure 6).
Figure 6. Offshore pre-salt fields are both large in size and high in value
Remaining recoverable resource (millions of BOE)
(Median resource size = 250 million BOE)
Sources: Deloitte analysis, Wood Mackenzie46
Note: Data includes recoverable resource estimates and the projects’ estimated breakeven Brent prices.
Admittedly, breakeven costs and resource estimates can be volatile with shifts in basin understanding and service costs. Moreover, with many known unknowns and unknown unknowns, the full-cycle rate of return estimates should be considered highly uncertain at best; however, initial results appear promising despite the clear need for further cost and production data.
To date, more than 80 wells from 12 pre-salt fields have produced results for six months or longer. Half of those have produced for a full year continuously. Only 12 have yet to produce for two years. Factoring in shut-ins for maintenance, field expansions, as well as the underlying variability of geology, make precise estimates difficult. That uncertainty aside, the few wells that have produced sustainably have produced prolifically, including several wells that have produced in excess of 30,000 barrels of oil and 50 million cubic feet of gas per day. However, substantial variation exists in the underlying production numbers and that may ultimately determine the
Taking a generic-type well with a short ramp-up period, an extended plateau, and a 30 percent decline, the difference between
Figure 7. A top-quartile pre-salt well could produce 150% more oil than a bottom-quartile well
Figure 8. Total gas production could increase by almost 250% for a top-tier pre-salt well
Sources: Deloitte analysis, Agência Nacional do Petróleo, Gás Natural e Biocombustíveis51
Sources: Deloitte analysis, Agência Nacional do Petróleo, Gás Natural e Biocombustíveis52
Recent significant changes
Brazil seems to be undergoing significant political and economic changes spurred by the Lava Jato bribery scandal and low commodity prices including for petroleum products. These headwinds have comprised much of the international reporting of Brazil; however, in the case of its E&P sector, these recent events should not detract from the country’s long-term potential. More specifically, recent changes in Petrobras’s mandate seem to have increased its competitiveness, which has been reflected in the market.53 Additionally, the world-class prospects in the offshore pre-salt play, and potential for positive political changes all point toward improving fundamentals for the oil and gas industry, including international and domestic companies ranging from large engineering and procurement firms to small wildcatters.
However, clouds still remain. The Lava Jato investigation has involved several service and construction firms as well as a number of politicians. This may hamper the service sector’s expansion—many of the involved construction firms service the offshore oil and gas sector. They may be necessary to exploit the pre-salt not only because of their capabilities and proximity, but also because of existing local content rules. Additionally, the scandal’s impact on the political structure could have broader-reaching and longer-term impacts. The continuing investigation has the potential to uncover further graft, increasing the country’s ongoing political and, therefore, regulatory uncertainty.
In the case of local content, originally the Libra production-sharing contract awarded in 2013 stipulated that the exploration phase include 37 percent local content, while the development phase must include 55 percent through 2021 and 59 percent thereafter.54 If a number of large projects are sanctioned concurrently, local providers may have difficulty increasing capacity rapidly. Exceptions to these rules exist based on availability and cost competitiveness of Brazilian tenders; but, as Petrobras recently discovered, the exemption process can be litigious. After a court decision allowing the company to pursue international leases for a FPSO, the Brazilian shipbuilders’ association Sinaval obtained an injunction to suspend the bidding process.55
In this case, the regulator granted Petrobras authorization to exercise the waiver clause and thus import some equipment for this project.56 However, that may not hold true for all prior contracts. The regulator is currently evaluating whether to allow operators to migrate their local content requirements in the older contracts to the new, more relaxed rules in exchange for abdicating the use of the existing waiver clause.57 This could impact operator’s field development decisions going forward.
Looking to the future
Brazil’s offshore pre-salt reservoirs are still technically challenging and could require both international expertise and locally derived content. Moreover, the play is young, with room to reduce costs with new technology and economies of scale. Reduced costs will likely be important going forward, as the deep water and deeper reservoirs could prove less attractive in a lower oil price environment than at the time most of the large discoveries were made. At the same time, significant investment will likely also be needed in conventional onshore and offshore oil and gas fields, as well to offset declines as they continue to mature. This need for capital could continue to be front of mind because of the uncertainty of US shale production growth and the OPEC quota changes, with companies balancing revenue and costs as the sector expands.
By 2020, the International Energy Agency projects that Brazil will produce roughly 3.5 million barrels per day of crude oil.58 More bullishly, Wood Mackenzie projects roughly 3.6 million barrels a day,59 while the Brazilian government projects a more conservative 3.1 million.60 All three projections, of course, include various assumptions about future oil prices, amount of international investment in Brazil, and the time it could take to fully develop existing pre-salt discoveries. If you were to look to 2025 or 2030, additional assumptions would be made about yet-to-find volumes and full-cycle economics relative to other basins around the world.
With ongoing issues around financing these developments, political upheaval, and the sheer size and complexity of the pre-salt, the more conservative projections might be more plausible. Four years after awarding the Libra block to a consortium led by Petrobras—and including Shell, Total, CNPC, and CNOOC—the field has not reached first production, and it may very well not peak until almost 2030.61 Conventional production in the country declined more than 500,000 barrels per day between January 2015 and January 2016, plateauing thereafter.62 This means that a number of new fields would be needed to just keep production levels flat. Therefore, despite upcoming bidding rounds and the pre-salt’s enormous potential, it will likely take significant capital investment to grow Brazil’s production.
But with time and capital can come opportunity. Companies will likely need to spend in excess of $30 billion each year in capital and operating expenditures between now and 2020 to produce more than 3 million barrels per day.63 Considering the potential of fields such as Lula, Libra, and Jubarte, among others, that level of spend is likely to continue, if not increase dramatically, in the future. This would require not only capable operators and substantial capital investment, but also service companies that have both regional expertise and deepwater experience—and wherever possible, both. Companies capable of navigating the above-ground risks and subsurface uncertainties have an opportunity to establish a foothold in one of the world’s most prospective offshore basins.
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