Brazil - The next oil giant?

Brazil's oil industry has big hurdles to clear

In the past two years Brazil has discovered the largest oil deposits in the country's history and the world’s most promising fields since the discoveries made in Kashagan in Kazakhstan in 2000. This has put Brazil well on its way to becoming a major producer in the future, but technological and financial hurdles will have to be overcome first.

The finds are located in the Santos oil Basin, 300 km from the coast at Rio de Janeiro in south-eastern Brazil. The first discovery—the giant Tupi field—was made in November 2007. Potential reserves are estimated by Petróleo Brasileiro (Petrobras, the state-controlled oil company) at 5-8bn barrels of oil equivalent (boe), which would make it the largest-ever deep-water oilfield discovery. Partner company British Gas is more optimistic, estimating that the field could contain 12-13bn boe.

The Tupi discovery was followed by other large finds, including Sugar Loaf, to the south-west of Tupi, in December 2007, and the Jupiter natural-gas field, located east of Tupi, in January 2008. The three fields constitute the largest hydrocarbons discoveries in the cluster area of the Santos Basin. The government estimates reserves at Sugar Loaf could be even larger than those of Tupi, at around 33bn boe, and that the Jupiter field could have "similar dimensions" to Tupi. Other discoveries in the area include Parati, Bem te-vi, Carioca, Iara, Tupi Sul and Iati.

The president of the Agência Nacional de Petróleo (ANP, the industry regulating agency) puts total potential reserves in the Santos Basin at 80bn boe. If the new discoveries are found to be commercially viable, Brazil could become one of the world's major oil-producing and exporting countries.

On its way

Two successful wells—Caramba and Guara—have already been drilled in the Sugar Loaf field by Petrobras in association with Portuguese Galp Energy in the first case, and with BG and Spanish Repsol in the second. Projected initial production at Tupi is estimated at 100,000 barrels/day under a pilot project scheduled to start next year. In the medium term, production from Tupi alone is expected to reach around 1m b/d by 2012. With oil production averaging 1.9m b/d in 2008, the extra capacity would lift Brazil's output to levels similar to Latin America’s two main oil producers, Venezuela and Mexico, who both produce 2.5-3m b/d.

But full development of the fields will pose serious geological challenges. The onset of a sharp global economic slowdown will throw up further complications, as financing constraints hinder investment and lower oil prices bring into question the government's preference for a production-sharing (rather than concessionary) framework.

Tough conditions and high cost

The reserves are located in the so-called “pre-salt” area (below the thick salt layer and more than 4,000 km below the sea bed, under a series of layers of rock and salt). Until now, Brazil’s reserves have been found in post-salt formations—above the salt layer.

The depth of the oil reservoirs is not the main challenge, since Petrobras ranks among the world’s best-qualified companies in offshore deep-water exploration and is already exploring fields located at a similar depth. The depth and thickness of the salt formation poses more problems. Unlike drilling through rock, which can be difficult owing to its thickness but once drilled remains stable, it is tough to maintain the dimensions of the hole after drilling through salt. Another challenge is the temperature shock of the oil as it travels up to the surface.

The technology needed and the subsequent development and maintenance of the reservoirs will be expensive. The development cost of each sub-salt well is estimated at US$100-150m, and Tupi alone could require as many as 200 wells. Developing the entire Tupi area could cost around US$600bn over the life of the wells. Unexpected geological or operational issues—such as longer drilling times, and increases in the rental costs of rigs—could further raise costs. The availability of deep-water rigs could also delay Brazil's oil plans, as globally these are in short supply.

Financing hurdles

At the time of the Tupi discovery, oil prices were close to US$100/b, but since then they have fallen to around US$40/b. Weak prospects for a significant pick-up in the medium term have raised questions about whether investors will see the project as financially viable.

The drying up of international financing, significantly lower oil prices and the technological and geological challenges related to the development of the new oil finds make long-term cost calculations difficult. Because of this, Petrobras decided to delay the announcement of its five-year strategic plan by four months. It was finally made public in February 2008 and included very ambitious financial goals. The revised plan for 2009-13 is based on an average oil price of US$42/b and calls for investments of around US$174.4bn, a 55% increase from the US$112.4bn stated in its 2008-12 investment plan.

Petrobras has gone some way towards securing financing for this year’s outlays. The company has raised US$10.5bn of the US$28.6bn it needs. Of the remaining US$18.1bn, it is set to receive US$11.9bn from the Banco Nacional de Desenvolvimento Econômico e Social (BNDES, Brazil’s national development bank) in the form of a 30-year US$11.9bn loan, with an additional US$5bn bridge loan expected from a consortium of international banks. Petrobras would need to raise a further US$10bn to cover its investments in 2010.

Growing difficulties in accessing international capital markets could scupper these plans or—at the very least—sharply raise the cost of borrowing. The brief easing of credit conditions in January allowed Petrobras to issue a 10-year, US$1.5bn bond on the eurobond market. But low risk appetite on the part of foreign investors, recent currency-derivatives losses and continued uncertainty regarding the value of the Real mean that large Brazilian companies are increasingly likely to rely on local banks for credit at high premium spreads.

Strong track record

The technical and financial challenges associated with the development of Brazil’s new oil finds are unquestionably significant. But Petrobras has a strong track record in responding to domestic challenges. When onshore oil reservoirs began to dry up in the 1970s, Petrobras turned offshore. By 1974 the company had discovered the Garoupa field off the shore of Rio de Janeiro, marking the beginning of a new offshore era for Brazil's production. This was the start of the continuous successful discoveries in the Campos Basin.

In the 1980s Petrobras adopted technology used abroad to explore deep-water reservoirs in the Campos Basin. As Petrobras gradually began to acquire undersea expertise, Brazil substantially increased its output and reduced its dependence on imports. By the 1990s the company developed its own technology for deep-water reserves, and in less than ten years built itself into one of the world’s best-known producers of ultra deep-water oil.

By 2007 Brazil reached its goal of becoming self sufficient in oil. Exports doubled between 2000 and 2007 and Petrobras recently announced record monthly exports for December 2008, of 620,000 b/d. Petrobras ended 2008 producing 2.4m barrels of oil equivalent per day (boe/d).

What role for private capital?

While the role of the state oil company is not in question, the level and manner of participation by the private sector is not as clear. Brazil opened its hydrocarbons sector to private investors at the end of the 1990s. Since then, it has held annual bidding rounds that have become a model of transparency and have attracted large numbers of private participants.

But Brazil’s new oil and gas potential has raised doubts about the extent of that openness in the future, as the government debates the preferred degree of private participation. Following the Tupi discovery, the government removed 41 deepwater blocks in the sub-salt region from the ninth bidding round for the first time since it started holding international rounds in 1998. In 2008 Brasília again withheld offshore blocks from the 10th bidding round. Seven companies currently hold concessions for the development of the sub-salt: Petrobras, BG, Galp, Repsol, Shell, Exxon and Amerada Hess.

A specially created government task force is studying possible changes to the concession laws that would give Petrobras the upper hand in the development of the Tupi area. The task force is considering options such as raising taxes and royalties on private companies producing in the new areas. Under current concession contracts, private operators sell the oil they produce in exchange for a relatively low government take of between 5% and 10%. They also pay a special participation tax of 10-40% of revenue on large fields, depending on volume, location, depth and age; this level could also be raised. A more dramatic approach under consideration is to turn concession contracts into production-sharing agreements with Petrobras. This would mean that private companies would have to share their production with the government after recovering costs.

Any changes to the current contractual agreements would need congressional approval. But the final decision will be in the hands of the president, Luiz Inacio Lula da Silva, based on the suggestions made by the task force. Whichever line he takes will set the stage for hydrocarbons developments in a future oil-rich Brazil beyond the end of his presidential term in 2010. The government hopes that by engaging in a debate early on in the development of the south-eastern oil reserves, it will pre-empt a possible shift to resource nationalism.

From the Economist Intelligence Unit ViewsWire - March 19th 2009