According to Oil and Gas Journal (OGJ), Brazil had 12.2 billion barrels of proven oil reserves in 2008, second-largest in South America after Venezuela. The offshore Campos and Santos Basins, located on the country’s southeast coast, contain the vast majority of Brazil’s proven reserves. In 2007, Brazil produced 2.28 million barrels per day (bbl/d) of oil, of which 77 percent was crude oil. Brazil’s oil production has risen steadily in recent years, with the country’s oil production in 2007 about 5 percent (or 110,000 bbl/d) higher than 2006. EIA estimates that Brazil’s oil consumption in 2007 averaged 2.37 million bbl/d. Based on its September 2008 Short Term Energy Outlook, EIA forecasts Brazilian oil production to reach 2.41 million bbl/d in 2008 and 2.72 million bbl/d in 2009. As a result of this rising oil production, EIA estimates that Brazil will become a net oil exporter by 2009.

State-controlled Petrobras is the dominant player in Brazil’s oil sector, holding important positions in up-, mid-, and downstream activities. The company held a monopoly on oil-related activities in the country until 1997, when the government opened the sector to competition and freed oil prices from state control. The principal government agency charged with monitoring the oil sector is the National Petroleum Agency (ANP), which is responsible for issuing exploration and production licenses and ensuring compliance with relevant regulations.

Despite the opening of the sector to private actors in the late 1990s, foreign-operated oil projects are rare in Brazil. Royal Dutch Shell was the first foreign operator of crude oil production in the country, operating a single, relatively small field in the Campos Basin. In mid-2007, Devon brought its Polvo field on-stream, representing the first oil project without any Petrobras participation. Private competition in the sector is not just from foreign companies: in 2008, Brazilian oil company OGX raised $4 billion in an IPO, and the company secured interests in 21 blocks in Brazil’s ninth licensing round.

Petrobras controls over 95 percent of the crude oil production in Brazil. The largest oil-production region of the country is Rio de Janeiro state, which contains about 80 percent of Brazil’s total production. Most of Brazil’s crude oil production is offshore in very deep water and consists of mostly-heavy grades. One of Brazil’s principle marketed crude streams is Marlim, which has an API of 19.6º and a sulfur content of 0.67 percent.

Petrobras has brought numerous projects onstream in recent years, with many more planned for the near future (see table below). In 2007, the company brought online Piranema (20,000 bbl/d nameplate production capacity), Espadarte (100,000 bbl/d), the second phase of the Golfinho (100,000 bbl/d), and two floating production, storage, and offloading (FPSO) units in the Roncador field (380,000 bbl/d). In September 2008, construction of the P-53 FPSO was completed, and the vessel is scheduled for installation in the Marlin field by the end of the year. In 2009, Petrobras plans to install another FPSO in the Marlim field, P-51, with a nameplate production capacity of 180,000 bbl/d.

Shell’s Bijupira-Salema project in the Campos Basin was the first field in Brazil not operated by Petrobras. The project came on-stream in 2003 and produces about 50,000 bbl/d. Shell is also developing its BC-10 project (100,000 bbl/d), which will utilize an oil tanker currently being converted into an FPSO in Singapore. Devon brought its Polvo project (50,000 bbl/d) online in August 2007, representing the only upstream oil project without any Petrobras participation. Chevron is developing the Frade project (100,000 bbl/d), with first production expected in 2009. Finally, StatoilHydro is developing the Peregrino field in Brazil, with expected production capacity of 100,000 bbl/d.

In large part due to this sizable slate of new projects, EIA expects that Brazil’s total oil production could reach 2.72 million bbl/d in 2009. This forecast takes into account the above-mentioned projects and an estimate for decline rates at Brazil’s older, mature fields. This could make Brazil one of the largest sources of new, non-OPEC oil supply growth. However, recent experience has shown that non-OPEC supply growth has been overestimated in recent years, so there is considerable downside risk to this forecast. Such risks include larger decline rates at mature fields and delays to project schedules. In total, industry analysts estimate that spending on investments in oil and natural gas exploration and production in Brazil could amount to $72 billion by 2012.

Petrobras announced that it had discovered an estimated 5-8 billion barrels of recoverable reserves (including both oil and natural gas) in the Tupi field, located in the Santos Basin. The reserves occur in a subsalt zone that is an average of 18,000 feet total below the ocean surface. The Tupi find is the largest oil discovery since the supergiant Kashagan field in Kazakhstan. In addition, oil encountered in the subsalt zones appears to be lighter and sweeter than most of Brazil’s existing production. Following Tupi, numerous additional subsalt discoveries were announced, including Carioca, Iara, and Guara. Preliminary estimates by industry analysts of the total extent of recoverable oil and natural gas reserves in the entire subsalt reserve have approached 56 billion barrels of oil equivalent.

Tupi and the subsequent subsalt announcements immediately transformed the nature and focus of Brazil’s oil sector, and the potential impact of the subsalt discoveries upon world oil markets is vast. However, considerable challenges must still be overcome in order to bring these reserves to fruition. The full scope and nature of development of the subsalt resources is still pending the establishment of the formal contractual framework that will guide exploitation of the reserves. In addition, the difficulty of access to the reserves, considering both the large depths and pressures involved with subsalt oil production, mean that there are many technical hurdles that must be overcome. Finally, the subsalt reserves contain a high concentration of natural gas, along with oil, and proper handling this gas will require additional infrastructure and consideration. As a result, production from small pilot projects is possible in the next several years, but large-scale development of the subsalt reserves will likely not occur until well into the next decade.

Transpetro, a wholly owned subsidiary of Petrobras, operates Brazil’s crude oil transport network. The system consists of 4,000 miles of crude oil pipelines, coastal import terminals, and inland storage facilities. The overall structure of the network enables the movement of crude oil from coastal production facilities and import terminals to inland refineries and consumption centers.

According to OGJ, Brazil has 1.9 million bbl/d of crude oil refining capacity spread amongst 13 refineries. Petrobras operates 11 facilities, the largest being the 360,000-bbl/d Paulinia refinery in Sao Paulo. Petrobras also controls a dominant stake in the retail products market. According to the International Energy Agency (IEA), regular unleaded gasoline prices averaged $1.17 per liter in 2006 ($4.43 per gallon), versus $2.58 per gallon in the United States.

In February 2005, Petrobras signed an agreement with Venezuela’s state-owned Petroleos de Venezuela S.A. (PdVSA) to build a new, 200,000-bbl/d refinery in the northeastern Brazil at a cost of $5 billion. The companies expect to complete the facility, dubbed Abreu e Lima, by 2010, with each country providing half of the crude oil processed there. The facility has reportedly suffered delays due to disagreements between the two countries, but media accounts indicate that Petrobras broke ground on the facility in late 2007. Petrobras announced in 2008 that it plans to spend $40 billion over the next 5-10 years to increase Brazil’s refining capacity by 1.3 million bbl/d.

Brazil is one of the largest producers of ethanol in the world and is the largest exporter of the fuel. In 2007, Brazil produced 390,000 bbl/d of ethanol, up from 306,000 in 2006. Based on the September 2008 Short Term Energy Outlook, EIA forecasts that Brazil’s ethanol production will reach 440,000 bbl/d in 2008 and 530,000 bbl/d in 2009. Over half of all cars in the country are of the flex-fuel variety, meaning that they can run on 100 percent ethanol or an ethanol-gasoline mixture. Eight in ten new cars sold in Brazil are flex-fuel vehicles. All gasoline in Brazil contains ethanol, with blending levels varying from 20-25 percent. Ethanol in Brazil comes from sugar cane, which prospers in the country’s tropical climate.

In 2008, BP announced that it was taking a stake in an ethanol project in Edia, Goias state that would produce 115 million gallons per year (7,500 bbl/d), making it one of the largest ethanol plants in Brazil. Petrobras has also launched numerous ethanol pipeline projects, including one linking Goias with Sao Paulo.

In recent years, Brazil has sought to increase ethanol exports, especially to the United States. Media reports indicated that Brazilian ethanol exports could total 5 billion liters in 2008 (86,000 bbl/d). In 2007, Brazil exported 12,600 bbl/d of ethanol to the United States, down from 30,000 bbl/d in 2006 but well above levels seen prior to 2005. The increase in exports to the U.S. has been driven by the phase-out of methyl tertiary butyl ether (MTBE) in the United State, which effectively replaced MTBE with ethanol as an additive to gasoline. However, surging domestic demand and high domestic prices may limit export growth. In addition, Brazil’s ethanol exports face high tariffs in some markets, such as the 54 cent per gallon tariff in the United States. Besides the United States, Brazil exports ethanol to Europe, and it began exports to industrial customers in Japan in 2008.

Brazil is also reportedly looking towards growing production of biodiesel. In 2008, Petrobras announced that it planned to build three biodiesel plants in the country, with at least one plant oriented towards the export market. ANP announced a 3 percent blending requirement for domestic diesel sales in July 2008, with plans to reportedly increase this to 5 percent by 2013.