Petroleo Brasileiro SA, the world’s biggest producer of oil in ultra-deep waters, is showing signs of a production rebound as suppliers accelerate equipment deliveries.
Petrobras, as the state-controlled oil producer is known, has received four of seven offshore production units slated to arrive this year and the rest are on schedule. Last year, the company installed one of three planned offshore production units amid delays that contributed to its first yearly output decline since 2004 and the first quarterly loss in 13 years.
Production rose to a six-month high in June after Petrobras started pumping from a second vessel at Lula, Brazil’s second-largest discovery. Domestic output is expected to increase by 9 percent in 2014 and surpass a 2011 peak, Bank of America Corp. said in a Aug. 1 note to clients. Additional oil sales will ease reliance on debt markets to finance $237 billion in investments through 2017, Petrobras Chief Financial Officer Almir Barbassa said Aug. 12 on a conference call.
“From an operational standpoint this is a turning point,” Gianna Bern, president of risk-management adviser Brookshire Advisory and Research, said by telephone from Chicago. “This is some of the toughest work in the industry; getting even one of these up and running is a feat in itself.”
Petrobras has lost 23 percent for investors this year in U.S. dollar terms, the worst performance by an oil company with a market value of more than $50 billion, according to data compiled by Bloomberg. ConocoPhillips, returning 19 percent, and BG Group Plc, yielding 16 percent, are the biggest winners.
Petrobras rose 5.2 percent to close at 17.83 reais in Sao Paulo.
Increased output by the Rio de Janeiro-based company will help compensate for losses at the company’s refining division that subsidizes imported gasoline as part of a government policy to control inflation. The government controls the makeup of Petrobras’s board through a majority of voting shares.
A weaker Brazilian currency and rising fuel prices abroad have widened the subsidy on imported gasoline to about 25 percent from about 9 percent in the second quarter, said Auro Rozenbaum, an analyst at Banco Bradesco SA in Sao Paulo.
The company plans to eventually bring domestic fuel prices in line with international prices to eliminate the losses, Barbassa said on an Aug. 12 conference call.
Petrobras “always” asks for price increases and the government will study the request, Energy Minister Edison Lobao said Aug. 13. There are no guarantees it will be granted, he said.
West Texas Intermediate crude jumped 16 percent on the New York Mercantile Exchange this year to $106.85 a barrel yesterday. WTI crude for September delivery increased 48 cents to $107.33 a barrel on the New York Mercantile Exchange today. It was the highest settlement since Aug. 1.
Petrobras will increase fuel imports in the second half to compensate for maintenance related shutdowns at two plants and an expected increase in demand, Jose Cosenza, Petrobras’s head of refining, said on the Aug. 12 call.
“Petrobras’s operations and its cash generation are likely to deteriorate fast in light of Brazil’s weaker currency; its commitment to a Atlas-like capex program and the limited scope for fuel price increases,” BTG Pactual analyst Gustavo Gattass said in a note to clients dated Aug 12.
Brazil’s real was the worst-performing emerging market currency in the second quarter after losing 9.4 percent against the U.S. dollar.
It will be “challenging” for Petrobras to meet this year’s target, Gattass said. Petrobras’s first-half output fell 3 percent from the prior year to the lowest for the period since 2009. That includes the June rebound.
Petrobras maintains its target of 2 million barrels a day on average this year with strong growth in the fourth quarter as new platforms increase production, the company said yesterday in an e-mailed reply to questions. Pre-salt fields will represent 42 percent of output in 2017 and 50 percent in 2020, it said. The company is constantly looking to reduce decline rates of about 10 percent a year at older fields in the Campos Basin, it said.
The company needs to deploy similar numbers of floating, production storage and offloading units, known as FPSOs, in 2016 and 2017 to meet its plan to pump 4.2 million barrels of crude daily in Brazil in 2020 at a time manufacturers are struggling to complete global FPSO orders.
“There has been tightness in the market for FPSOs,” T.J. Conway, a research and advisory manager at New York-based Energy Intelligence Group, said by telephone from Washington. “This is a critical year to test Petrobras and the Brazilian sector in general to deliver on these very difficult plans.”
Petrobras is looking to replicate the Lula success at other fields trapped beneath a layer of salt as deep as two miles below the Atlantic seabed, known as pre-salt deposits. Ultra-deep fields are in waters at least 300 meters (984 feet) deep. Petrobras’s first FPSO at Lula reached capacity ahead of schedule and with fewer wells than planned because individual wells pumped more than expected.
Of the 35 production vessels Petrobras plans to install through 2020, 22 are targeted for pre-salt fields near Lula in the Santos Basin in an effort to maximize output at the country’s most productive oil region.
Seven of Brazil’s 10 most productive wells in June were located in the pre-salt, and three of the five biggest gushers were at Lula, according to the country’s oil regulator. Petrobras plans to pump half of its crude from the pre-salt in 2020, up from 7 percent last year, as it deploys the vessels almost 300 kilometers (186 miles) off the coast of Rio and Sao Paulo states.
Petrobras is also drilling deeper at the Campos Basin to tap pre-salt fields it didn’t know existed when it first developed the region in the 1980s and 1990s. While the pre-salt layer of Campos doesn’t hold as much oil as the deeper Santos region, it is cheaper to extract the fuel because Petrobras can use existing platforms and pipelines to get the fuel to consumers.
Pre-salt oil was formed when the South American and African continents began separating more the 100 million years ago. The repeated flooding and evaporation of salt water in what is now the South Atlantic created a layer of the mineral as thick as 2,000 meters that blankets the largest crude discoveries in the Western Hemisphere since Mexico found Cantarell in 1976.
Petrobras’s advances in the pre-salt, where the company conducted extensive production tests to confirm flow rates, contrasts sharply with the production collapse at OGX Petroleo & Gas Participacoes, the explorer controlled by entrepreneur Eike Batista that started commercial output at its first field two years after the discovery.
Rio-based OGX planned to produce at levels similar to pre-salt wells in an under-explored section of the Campos Basin where Batista’s team found oil at more than 80 percent of the wells drilled.
The exploration successes pushed the market value of OGX to a high of 75 billion reais ($32.3 billion) in 2012. Then Batista tried and failed to extract the oil. At the first project, flow rates faded after a few months because the region’s geology hindered the flow of oil, prompting OGX to announce Aug. 1 it would abandon fields it previously declared commercial. The company is now worth two billion reais in Sao Paulo trading. OGX didn’t reply to an e-mail seeking comment.
At Petrobras, “their approach is very conservative with very long-term tests; it ensures we’re not going to get bad geologic surprises,” Cleveland Jones, a geology professor at Rio de Janeiro State University, said in a phone interview. “There’s not going to be an OGX type of thing.”