Time for regime change
Brazil is set to change its upstream investment terms following a series of large offshore discoveries. Robert Cauclanis writes
SINCE NOVEMBER, Petrobras has announced discoveries of billions of barrels of oil and gas, in the Tupi, Jupiter and Carioca fields – in barely explored horizons beneath the country's sub-salt layer. Tupi and Jupiter each hold an estimated 5bn-8bn barrels, mostly of light crude and gas respectively. Petrobras has further drilling to do to quantify Carioca's reserves, but Agencia Nacional do Petroleo (ANP) said last month they may amount to as much as 33bn barrels.
The sub-salt oil zone is considered a new technological frontier. The reservoirs are typically over 150 km from Brazil's shoreline and lie underneath the seabed in water depths over 2,000 metres at total depths of 6,000-8,000 metres, beneath sand, rock and a salt layer that, in places, is up to 2,000 metres thick. The reservoirs are highly pressurised and extremely hot.
A new oil and gas frontier
Whatever the final reserves figures for its new sub-salt discoveries, Petrobras has found a new oil and gas frontier that is likely to increase Brazil's proved reserves – estimated at 12bn barrels of oil equivalent in 2007 – several times.
As a result, the authorities are almost certain to increase the state's take of revenues from oil sales. But it remains uncertain whether changes to operating terms would take the form of a simple increase in taxes on sub-salt production or relatively complex alterations to the petroleum law, perhaps to give Petrobras privileged access to a play that it has been instrumental in identifying and that chief executive Jose Sergio Gabrielli has claimed carries virtually no exploration risk.
Options that have been suggested by Petrobras and government officials include increasing the so-called special-participation tax – on profits from large fields (generally, those producing 80,000 barrels a day (b/d) or more) – from 40%, to 60%. ANP's director-general, Haroldo Lima, favours this solution, according to ANP sources. This approach would have the merit of simplicity: it would not require a change to the petroleum law and could be carried out by presidential decree.
The tax is applied in addition to a 10% royalty rate on all oil and gas production in Brazil and raised almost $5bn last year. In fourth-quarter 2007, according to ANP, it was generating around $25m a day – 17% of Brazil's average, gross daily revenues from crude and liquids production. The proceeds are evenly split between the federal government and local (state and municipal) governments, which have been calling for a larger share for some time.
A tax increase would be acceptable to Petrobras and other companies, which have expected terms to change for some time, according to the Brazilian Petroleum Institute, an advocacy group for private-sector oil companies operating in Brazil. Brazil is one of the few Latin American oil and gas producers not to have increased upstream taxes since the 1990s – in contrast to Venezuela, Bolivia and Ecuador.
Companies with fields that are due to come on stream soon that could be affected by changes in the tax regime include Shell, Chevron, StatoilHydro, Repsol YPF and Kerr-McGee, all of which also have additional exploration acreage. ExxonMobil, BG, Eni and Anadarko also have promising acreage to explore.
But some Petrobras officials, including Gabrielli and upstream director Guilherme Estrella, wish to see a more profound change – such as limiting the access of private-sector exploration companies to Brazil's new sub-salt play by modifying the 1997 petroleum law, which removed state-controlled Petrobras' upstream monopoly.
Energy minister Edison Lobão has said both alternatives are possible, although the time frame for implementation would differ markedly. ANP plans to propose an increase in royalties at meetings next month with the National Commission for Energy Policy. But, says David Fleischer, a politics and economics analyst based in Brasilia, changing the oil law could take years: changes would have to be approved by both houses of Congress and the president.
For now, "foreigners, including Petrobras' own partners, are very welcome to explore and discover and produce oil from underneath the salt in Brazil," Lobão said at an April conference. He also said any change in the law might only affect sub-salt acreage that has yet to be auctioned. While Petrobras holds most of the sub-salt acreage auctioned to date, other significant stakeholders include ExxonMobil, Hess, Shell, Repsol YPF, BG, Eni, and Portugal's Galp.
In 2007, the government removed sub-salt acreage from its annual concession auctions, including 41 promising blocks it had planned to offer last year. Disappointing though that may be for the majors, ANP officials have said they may not offer any new sub-salt blocks until a new regulatory framework is in place.
Many politicians, including some congressmen from the ruling Workers' Party, have argued that the country has much less need now than it once did for private-sector operators in the oil sector. Petrobras has already reached production of more than 1.8m b/d, meeting Brazil's own daily needs for crude; it plans to be exporting 350,000 b/d by 2010, but could add another 1m b/d to its production total by the end of the next decade from its sub-salt plays, Petrobras executives have suggested.
But Petrobras could benefit from spreading the risks and costs of deep-water oil development in the sub-salt province with other majors. Its first sub-salt well at Tupi cost $240m and although costs reduced substantially for the second well, it still cost $60m. The company may have to drill 50-100 wells at Tupi alone and costs for drilling rigs and offshore platforms have been rising.
"Petrobras is tempted to reserve these great riches for itself," says Adriano Pires, an energy analyst at Centro Brasileiro de Infra Estrutura, in Rio de Janeiro. "But trying to keep the private-sector companies out might greatly hinder Brazil's ability to develop them."
|Petrobras aims for quick sub-salt start-up
PETOBRAS wants to beat all expectations on how fast it can bring on stream new production from its sub-salt discoveries in the Santos basin, offshore Brazil. The company plans to begin pumping light crude from the 5bn-8bn barrels of oil equivalent (boe) Tupi discovery in the first half of 2009, reaching output of 100,000 barrels a day (b/d) by 2010 in a test-phase of what may become a 1m b/d project sometime in the next decade, according to company projections.
It also expects to start producing oil from what appears to be an even bigger discovery – Carioca, also in the Santos basin – within five years, chief executive Jose Sergio Gabrielli said at last month's Offshore Technology Conference in Houston.
The company still has not confirmed whether or not Carioca will live up to recent claims by Haroldo Lima, director-general of upstream regulator ANP, that it contains 33bn boe. But it has said that further data on the find will be available in between one and three months, following further appraisal work.
Drilling planned later this year by ExxonMobil at the nearby BM-S-22 block may help to determine whether Carioca and other nearby prospects are a contiguous oil play, as some geologists believe.
In July, Petrobras plans to provide details of its investment plans for the sub-salt province, on top of the $112bn it has already budgeted to spend between 2008 and 2012. n