(Aker Solutions, 5.Oct.2018) — Aker Solutions has signed a contract with Petrobras to provide a subsea production system and related services for the Mero 1 project within the Mero field development, one of the largest oil discoveries in Brazil’s pre-salt area.
The subsea production system will consist of 12 vertical subsea trees designed for Brazil’s pre-salt, four subsea distribution units, three topside master control stations for the Mero 1 Guanabara FPSO and spare parts. The order also includes installation and commissioning support services.
“We’re pleased to become a key supplier to Petrobras and its partners for the first full production project of this major development,” said Luis Araujo, chief executive officer of Aker Solutions. “We have an extensive local workforce and over 40 years’ experience in Brazil and look forward to continuing to play an important role in the development of the country’s pre-salt resources,” he added.
Aker Solutions’ subsea manufacturing facility in São José dos Pinhais and its subsea services base in Rio das Ostras will carry out the work.
The work has already started and deliveries are scheduled for 2020. Installations are scheduled between 2020 and 2023.
The subsea production system will be hooked up to the first full-scale floating production, storage and offloading (FPSO) vessel for Mero, known as the Guanabara FPSO. The FPSO is scheduled to come on stream in 2021 and will have capacity to process up to 180,000 barrels of oil a day and 12 million cubic meters of gas a day.
The ultra-deepwater Mero field is located in the northwestern area of the original Libra block, which is about 180 kilometers south of Rio de Janeiro. First oil was produced in November last year.
Petrobras is the operator of the consortium developing the Libra area. Shell, Total, CNPC and CNOOC Limited are partners. Pre-Sal Petróleo S.A (PPSA) manages the Production Sharing Contract.
The companies are not disclosing the value of the contract. The order will be booked in the third quarter of 2018.
(OffshoreEnergyToday, 13.Sep.2018) — French oil major Total has exercised its option to acquire a 25 percent working interest in the Orinduik block offshore Guyana after a competent persons report identified potential for almost three billion barrels of oil equivalent.
Eco Atlantic, a partner in the Tullow-operated Orinduik block, said on Thursday that Total E&P Activités Pétrolières, a wholly-owned subsidiary of Total, exercised its option to acquire a 25% working interest in the block from Eco Atlantic.
Total decided to exercise the option following a competent persons report (CPR) announced on Tuesday. According to the CPR, the Orinduik block could potentially hold 2,9 billion barrels of oil equivalent of P50 (best estimate) reserves identified across a total of 10 leads.
Eco added that the option was exercised before delivery of the final 3D seismic data due to be delivered to Total, which would have triggered a 120-day exercise window for the option.
The option does not effect Tullow which will remain the operator and hold down its 60 percent of working interest. Following the option exercise and the receipt of all requisite regulatory approvals, Total will hold 25 percent while Eco’s interest will decrease from 40 to 15 percent.
In accordance with the terms of the option, Total will pay a fee of $12.5m to the company on receipt of all requisite approvals for the transfer of the 25 percent interest. Eco added that the payment would provide adequate funding to meet Eco’s share of the costs to drill at least two wells on the block as well as recover the costs of the completed 3D seismic survey.
Gil Holzman, CEO of Eco, said: “We are absolutely delighted that Total, one of the world’s largest oil companies, has so quickly chosen to exercise its option to acquire a 25 percent stake in our Orinduik Block to gain further exposure to offshore Guyana, currently one of the most exciting exploration areas globally.
“With Tullow as operator and the technical contribution that both Total and Eco now bring to the project, we look forward to working with these two world-class players in further progressing the exciting exploration of the Orinduik Block.”
Colin Kinley, COO of Eco, added: “Total entering the blocks four months earlier than anticipated is welcomed as they add significant technical horsepower to the interpretation and now bring them into the planning for drilling. Tullow announced last week drilling is anticipated early the third quarter of 2019.”
(Reuters, 5.Sep.2018) — Tullow Oil plans to drill its first well in the much-watched Guyana offshore basin in the third quarter of next year in its Orinduik licence bordering discoveries by Exxon, a spokesman said on Wednesday.
Exxon and U.S. partner Hess Corp have said that more than 4 billion barrels of oil equivalent could be recovered from the Stabroek block off Guyana, which is part of one of the world’s biggest oil discoveries in the past decade.
Tullow owns 60 percent and Eco Atlantic Oil and Gas 40 percent in Orinduik. Total has an option to buy 25 percent from Eco.
“Hammerhead-1 is located approximately 7 km from the Orinduik licence boundary … Hammerhead-1 found material oil in turbidite channel systems,” the Tullow spokesman said of a recent Exxon discovery in the Stabroek block.
“Our 3D seismic (data), which includes Hammerhead, shows that these channel systems extend up-dip (?) into the Orinduik licence. We will now pick the well location for our first well on this licence and remain on track for drilling that well in the third quarter of 2019.”
Tullow also has a 37.5 percent stake in the Kanuku licence offshore Guyana alongside Repsol and Total. It also owns stakes in two blocks off Guyana’s neighbour Suriname, where its partners are Ratio, Equinor and Noble.
(Reporting by Shadia Nasralla; Editing by David Goodman and Mark Potter)
(AP) — As the United States plans new defences against the more powerful storms and higher tides expected from climate change, one project stands out: an ambitious proposal to build a nearly 60-mile ‘spine’ of concrete seawalls, earthen barriers, floating gates and steel levees on the Texas Gulf Coast.
Like other oceanfront projects, this one would protect homes, delicate ecosystems and vital infrastructure, but it also has another priority – to shield some of the crown jewels of the petroleum industry, which is blamed for contributing to global warming and now wants the federal government to build safeguards against the consequences of it.
The plan is focused on a stretch of coastline that runs from the Louisiana border to industrial enclaves south of Houston that are home to one of the world’s largest concentrations of petrochemical facilities, including most of Texas’ 30 refineries, which represent 30 per cent of the nation’s refining capacity.
Texas is seeking at least US$12 billion for the full coastal spine, with nearly all of it coming from public funds. Last month, the government fast-tracked an initial US$3.9 billion for three separate, smaller storm barrier projects that would specifically protect oil facilities.
That followed Hurricane Harvey, which roared ashore a year ago, last August 25, and swamped Houston and parts of the coast, temporarily knocking out a quarter of the area’s oil refining capacity and causing average gasolene prices to jump 28 US cents a gallon nationwide. Many Republicans argue that the Texas oil projects belong at the top of Washington’s spending list.
“Our overall economy, not only in Texas, but in the entire country, is so much at risk from a high storm surge,” said Matt Sebesta, a Republican who as Brazoria County judge oversees a swathe of Gulf Coast.
But the idea of taxpayers around the country paying to protect refineries worth billions, and in a state where top politicians still dispute climate change’s validity, doesn’t sit well with some.
“The oil and gas industry is getting a free ride,” said Brandt Mannchen, a member of the Sierra Club’s executive committee in Houston. “You don’t hear the industry making a peep about paying for any of this and why should they? There’s all this push like, ‘Please, Senator Cornyn; Please, Senator Cruz, we need money for this and that’.”
Normally outspoken critics of federal spending, Texas Senators John Cornyn and Ted Cruz both backed using taxpayer funds to fortify the oil facilities’ protections and the Texas coast. Cruz called it “a tremendous step forward”.
Federal, state and local money is also bolstering defences elsewhere, including on New York’s Staten Island, around Atlantic City, New Jersey, and in other communities hammered by superstorm Sandy in 2012.
Construction in Texas could begin in several months on the three sections of storm barrier. While plans are still being finalised, some dirt levees will be raised to about 17 feet high, and six miles of 19-foot-tall floodwalls would be built or strengthened around Port Arthur, a Texas-Louisiana border locale of pungent chemical smells and towering knots of steel pipes.
The town of 55,000 includes the Saudi-controlled Motiva oil refinery, the nation’s largest, as well as refineries owned by oil giants Valero Energy Corp and Total SA. There are also almost a dozen petrochemical facilities.
“You’re looking at a lot of people, a lot of homes, but really a lot of industry,” said Steve Sherrill, an Army Corps of Engineers resident engineer in Port Arthur, as he peered over a Gulf tributary lined with chunks of granite and metal gates, much of which is set to be reinforced.
The second barrier project features around 25 miles of new levees and seawalls in nearby Orange County, where Chevron, DuPont and other companies have facilities. The third would extend and heighten seawalls around Freeport, home to a Phillips 66 export terminal for liquefied natural gas and nearby refinery, as well as several chemical facilities.
The proposals approved for funding originally called for building more protections along larger swathes of the Texas coast, but they were scaled back and now deliberately focus on refineries.
“That was one of the main reasons we looked at some of those areas,” said Tony Williams, environmental review coordinator for the Texas Land Commissioner’s Office.
Oil and chemical companies also pushed for more protection for surrounding communities to shield their workforces, but “not every property can be protected,” said Sheri Willey, deputy chief of project management for the Army Corps of Engineers’ upper Texas district.
“Our regulations tell us what benefits we need to include, and they have to be national economic benefits,” Willey said.
Once work is complete on the three sections, they could eventually be integrated into a larger coastal spine system. In some places along Texas’ 370-mile Gulf Coast, 18 feet is lost annually to erosion, threatening to suck more wetlands, roads and buildings into rising seas.
Protecting a wide expanse will be expensive. After Harvey, a special Texas commission prepared a report seeking US$61 billion from Congress to “future proof” the state against such natural disasters, without mentioning climate change, which scientists say will cause heavier rains and stronger storms.
Texas has not tapped its own rainy day fund of around US$11 billion. According to federal rules, 35 per cent of funds spent by the Army Corps of Engineers must be matched by local jurisdictions, and the GOP-controlled state legislature could help cover such costs. But such spending may be tough for many conservatives to swallow.
Texas “should be funding things like this itself,” said Chris Edwards, an economist at the libertarian Cato Institute. “Texans are proud of their conservatism, but, unfortunately, when decisions get made in Washington, that frugality goes out the door.”
State officials counter that protecting the oil facilities is a matter of national security.
“The effects of the next devastating storm could be felt nationwide,” said Representative Randy Weber, a fiercely conservative Republican from suburban Houston, who has nonetheless authored legislation backing the coastal spine.
Major oil companies did not respond to messages seeking comment on funding for the projects. But Suzanne Lemieux, midstream group manager for the American Petroleum Institute, said the industry already pays into programmes such as the federal Harbor Maintenance Trust Fund and the Waterways Trust Fund, only to see Congress divert that money elsewhere.
“Do we want to pay again when we’ve already paid a tax without it getting used? I’d say the answer is no,” she said.
Phillips 66 and other energy firms spent money last year lobbying Congress on storm-related funding post-Harvey, campaign finance records show, and Houston’s Lyondell Chemical Company PAC lobbied for building a coastal spine.
“The coastal spine benefits more than just our industry,” Bob Patel, CEO of LyondellBasell, one of the world’s largest plastics, chemicals and refining companies, said in March. “It really needs to be a regional effort.”
(Energy Analytics Institute, Piero Stewart, 17.Aug.2018) – Venezuelan opposition leader Maria Corina Machado tours the Jusepin petroleum region in Venezuela.
Depredadores. Arrasaron con todo. Jusepín, un campo petrolero que fue referencia mundial por su alta productividad y sede del núcleo Monagas de la Universidad de Oriente; hoy parece Casas Muertas, le cayó la peste… pic.twitter.com/cgHh9zyEIz
(Argus, 9.Aug.2018) – Venezuela’s state-owned PdV and its joint ventures fell short of officially targeted crude production by more than 125,000 b/d in July, according to an internal PdV upstream report obtained by Argus.
The steepest shortfalls were registered in the Orinoco heavy oil belt — long touted by the Opec country as the driver of ambitious growth plans — and PdV’s western division around Lake Maracaibo.
The monthly report indicates that July production averaged 1,526,600 b/d, compared with a target of 1,651,700 b/d, with operations by PdV and its joint ventures both explicitly missing their targets.
The report data does not include annual or monthly comparisons. Venezuela’s official June production, according to Opec’s latest Monthly Oil Market Report, was 1.531mn b/d. The average of secondary sources, including Argus, was 1.340mn b/d.
PdV officials tell Argus that the production data in the monthly internal report are systematically inflated, mainly by the company’s eastern and western divisions. “They play with the storage tanks and what they report is not reality,” one senior executive says. Actual July national production was around 1.25mn b/d, the officials say.
Despite its shortcomings, the report sheds light on field-by-field and divisional performance trends, acknowledging that neither PdV nor its joint ventures with foreign companies has been able to check Venezuela’s precipitous decline in output. Among the factors fueling the trend are scant maintenance, reservoir mismanagement, skilled labor flight and a lack of critical naphtha and light crude for transport and blending.
The Orinoco oil belt produced 843,200 b/d of crude in July, compared with a targeted 908,200 b/d, the report indicates. Of the belt’s four producing blocks, Carabobo accounted for 375,000 b/d, 23,500 b/d short of its target. PetroMonagas, a PdV joint venture with Russia’s state-controlled Rosneft, accounted for 119,700 b/d or 32pc of the block’s total reported output. That’s followed by Sinovensa, a PdV joint venture with China’s state-owned CNPC, with 91,800 b/d or 24pc.
In the Orinoco’s Junin block, July output averaged 191,800 b/d, off target by 16,500 b/d. The top producer with 71,600 b/d was PetroCedeno, in which France´s Total and Norway´s Equinor are PdV´s minority partners. The joint venture´s production missed its target by 12,200 b/d, well in excess of any other project in the block, the report indicates. PetroCedeno has an official capacity in excess of 200,000 b/d.
Other Junin block projects, including PetroMiranda with Rosneft and PetroJunin with Italy´s Eni, also missed their July goals. PetroUrica and PetroMacareo, PdV nominal joint ventures with CNPC and PetroVietnam, respectively, showed zero real and targeted output.
In the Ayacucho block, PdV´s PetroPiar joint venture with Chevron produced 123,300 b/d, off target by 12,400 b/d, the report says. The project has official capacity of 190,000 b/d.
In PdV´s eastern division, which hosts the legacy Furrial complex, July production averaged 326,300 b/d, just 9,500 b/d short of its target.
The western division, in contrast, produced 319,200 b/d, missing its target by 44,600 b/d. The shortfall came mainly from shallow-water operations in Lake Maracaibo and on its eastern coast.
The report indicates that 1,191 wells stopped producing in July, accounting for 333,200 b/d of lost output. The western division accounted for more than two-thirds of the number of deactivated wells, but the Orinoco accounted for some 80pc of the lost output, reflecting its higher well productivity.
The western division also accounted for 70pc of 1,114 well reactivations in July. These added a total of 183,300 b/d of production, mostly from the Orinoco.
PdV is reactivating the western division wells on its own and with small contractors, unrelated to the company’s vaunted plan to reactivate more than 23,000 wells nationwide, a PdV official says.
(UPI, Daniel J. Graeber, 18.Jul.2018) – A renewable energy division of French supermajor Total said Wednesday it was moving forward with new solar power developments in Brazil.
Total in September paid about $275 million to acquire a 23 percent stake in renewable energy company Eren, naming the new entity Total Eren. The renewable energy division announced Wednesday it was financing and building a combined 140 megawatts of nominal power in Brazil, roughly enough power for at least 100,000 homes.
Of the three projects either in the finance or construction phase, a project dubbed BJL 11 is the company’s first ever in Brazil. With close to 78,000 panels, the French company said it could generate enough power for 23,000 homes.
The move into Brazilian renewables follows the formation of a strategic partnership between Total and Petróleo Brasileiro, known commonly as Petrobras. The 2016 partnership reinforced operations at oil fields off the Brazilian coast, thermal plants and infrastructure associated with liquefied natural gas.
Last week, Petrobras signed a memorandum of understanding to examine solar and wind energy segments in the Brazilian market with Total Eren.
“The recently announced agreement with Petrobras and Total, two major players in the energy sector, makes me very much enthusiastic about future growth prospects in renewables in the country,” Fabienne Demol, the global head of business development of Total Eren, said in a statement.
Petrobas has 104 MW of wind power and 1.1 MW of solar power already in its portfolio in the Brazilian market.
Brazil generates about three quarters of its electricity from renewable energy resources. According to the U.S. Commerce Department, it’s the best renewable energy market in Latin America.
(Maritime Herald, 9.Jul.2018) – The oil spill that occurred this Friday, July 6 in two tanks of the secondary recovery plant of the Jusepín Operational Complex of Pdvsa, demonstrates the safety failures of the Venezuelan state industry.
This is what the biologist, Alejandro Álvarez Iragorry, considers that what happened for the second time in this Pdvsa facility, located in the northwest area of Maturín, is another sign that “PDVSA seems to be operating at the operational minimums “.
For PDVSA, ” oily waters to the river ” fell ; According to the minister, they were ” oil fluids ” and the regional executive defined it as ” a spill of oil “, which led the authorities to suspend for an indefinite period the pumping of water to 80% of the population of Maturin, since seven of the 10 parishes in the capital of Monaco are supplied by the Guarapiche River .
Álvarez Iragorry, who is also a doctor in Ecology and coordinator of the Clima 21 Coalition, points out that the lack of information is a norm, not only in this accident but in others that have occurred since the one that occurred on February 4, 2012, also in the Operational Complex of Jusepín, considered one of the most serious in the Venezuelan oil industry.
“I am very concerned because, from the safety point of view, there is a greater chance of a major accident. Since the spill that occurred in the Guarapiche River six years ago, there have been about four more spills, that although they were not originated by PDVSA, some of them like Trinidad and Tobago, when entering Venezuelan marine waters are their responsibility and not they have responded as it should be, “the expert mentions.
For the biologist, without accurate information, you can not alert or recommend the citizens with enough details to take the forecasts as to what happens in these types of cases.
In addition, the contingency plans of PDVSA in each of the spill cases have questioned the capacity to respond. Several photos are remembered of how in 2012, those who were manually blocking the passage of oil in the Guarapiche River did not have uniforms or safety equipment.
Álvarez Iragorry emphasizes this to emphasize that if you add the lack of information, “when everything becomes opaque, you have no idea what is happening.”
Damage and environmental impact
Although it is early to evaluate the environmental impact in the Guarapiche River, which already suffered the effects of the first spill in 2012 when it is estimated that for 21 hours 100 thousand barrels of oil were poured into its bed, a new spill of course that causes a immediate damage in the flow.
The first is the one that affects citizens who are left without water supply indefinitely. The biologist believes that the Maturineses are the ones who must demand an answer from the rulers and authorities. “A healthy river will give healthy water if it is not healthy it will not give healthy water”.
The damage it causes in the river is also direct because it affects the vegetation, the soil and the species that inhabit one of the longest rivers that Monagas has and that crosses the municipalities Cedeño, Maturín and Bolívar.
The Guarapiche has mangroves that were severely contaminated six years ago. The amount of oil that fell in its waters was so great that it travelled 75 kilometres until reaching the French, Cuatro Bocas and Colorad pipes, which are the connection of the Guarapiche with the San Juan River and from there to the Caribbean Sea.
Just to take into account an effect of what happened six years ago, the journalist David González in a work published by the newspaper El Nacional made a tour of the river and this was part of what he said:
The tour lasts almost two hours after which the visitor will feel that he accessed a disaster area. At the foot of the mangroves a black strip protruding half a meter from the water: it looks like a large skirting board at the base of a very long plant wall. As the tide drops, more stems and more roots are exposed and you can see how deep the oil adhered. A fact can illustrate that only a part of the mangroves is visible: if a rod of two and a half meters is put into the water, the riverbed will not be touched yet. A similar landscape can be observed while navigating an approximate distance of 20 kilometres through the pipes adjacent to the San Juan River.
After the spill, this July 6 little is what is known, because as happened in 2012 the secrecy of Pdvsa remains.
For Álvarez Iragorry, the authorities speak of up to three terms to define the spill, which accounts for the lack of seriousness with which things are carried out, which could try to minimize the impact of those events.
“In case of being some type of residual hydrocarbon, here, in this case, we do not have information about it, it is an even more toxic material. In any case, there is an impact because it does not matter if it is any other waste or water contaminated with hydrocarbon because there is an impact, “he said.
(Financial Times, Benedict Mander, 25.Jun.2018) – The collapse of the Argentine peso and the government’s struggle to tackle soaring inflation are causing disquiet among companies developing Vaca Muerta, one of the world’s largest deposits of shale oil and gas.
In his drive to liberalise Argentina’s energy markets, President Mauricio Macri phased out consumer subsidies and increased tariffs. Local oil prices rose and late last year converged with those of international crude, providing an important stimulus for companies in Vaca Muerta, Argentina’s star investment attraction.
But the government has now capped the price at which companies producing oil in Argentina can sell to refineries, along with the price of petrol at the pump, to shield consumers from rising global oil prices and prevent inflation soaring even further.
Companies now must sell at prices considerably below the international level, which on Thursday was above $77 a barrel for Brent crude, the global benchmark. This, as well as the devaluation of the peso, is hitting profitability and forcing companies to reassess their plans in Vaca Muerta.
“Suddenly from moving in the right direction, it feels like the country is taking a step back,” said Anuj Sharma, chief executive of Phoenix Global Resources, a mid-sized oil company investing in Vaca Muerta. “If there’s one thing markets hate, it is uncertainty. It makes planning very difficult.” He added that it was hard to plan more than 3-5 months ahead.
As little as four years ago, the state oil company YPF estimated that the break-even oil price for wells in Vaca Muerta to be economically viable was about $80 a barrel. Wood Mackenzie, the energy consultants, now estimates the break-even price to be $56 a barrel. After the first well began producing commercially in 2013, Vaca Muerta is now producing 120,000 barrels a day, or more than 10 per cent of national production.
“Just 5 years ago Vaca Muerta was a dream. Now it is starting to become a reality. It is at an inflection point where you can actually make money drilling it,” said one senior executive whose company is investing in Vaca Muerta.
“You can argue that at $67-68 a barrel you can make more than the break-even price, but you are not obliged to drill Vaca Muerta. Elsewhere you get 75 or even higher if oil prices go up . . . if there’s no [price] visibility, it’s very hard to deploy billions into Vaca Muerta.”
With Javier Iguacel replacing Juan José Aranguren as energy minister as part of a shake-up last week, the government’s plans remain unclear. Mr Aranguren, a former executive at Royal Dutch Shell, was widely applauded by the private sector for increasing the tariffs that consumers pay for electricity and natural gas, which enabled the government to cut subsidies in its effort to rein in the fiscal deficit. But he is unpopular with voters.
How Mr Iguacel, a petroleum engineer who also has a private sector background, proceeds depends on a precarious political scenario for Mr Macri, who is seeking re-election next year. Tariff hikes — as well as a $50bn bailout from the IMF in response to the currency crisis — was one of the main motives for trade unions on Monday holding their third national strike since Mr Macri took power.
Freezing prices at petrol pumps may go some way to keeping voters happy, even if it is debatable what impact it might have on inflation, which is running at more than 25 per cent annually. But international companies are not keen on effectively financing Mr Macri’s “gradualist” economic reform programme, which seeks to cushion the impact of austerity on poorer Argentines.
“If prices remain uncoupled, that would be negative. Without doubt, investment would fall, production too, and we would have to import more,” said Daniel Gerold, an energy consultant in Buenos Aires. “If it becomes clear that prices do not follow clear rules or the law is not respected, even if costs are low in Vaca Muerta, investments are not going to come.”
Nevertheless, analysts are broadly optimistic about the prospects for Vaca Muerta, which has seen a sharp fall in costs in recent years, while production has jumped dramatically. Argentina might even have an oversupply of natural gas this summer, when demand is lower, said Amanda Kupchella, an analyst at Wood Mackenzie.
“There are a lot of things that just come with the territory in Argentina — like price controls, working with unions and so on. They are things that operators are used to dealing with,” said Ms Kupchella. “Productivity in Vaca Muerta is so good that it doesn’t seem to be keeping [investors] away . . . wells just seem to be getting better and better.”
Alejandro Bulgheroni, chairman of Pan American Energy Group, expects that in 2-3 years it will be as cheap to drill wells in Vaca Muerta as it is in the US.
“Let’s hope this is resolved and that we return to international prices,” said Mr Bulgheroni. Although it was a “difficult moment”, he recognised that under this government, negotiations had always ended in mutual agreements, with no impositions. “We have lived through much worse times.”
(Energy Analytics Institute, Jared Yamin, 16.Jun.2018) – Russian oil giant Gazprom remains attracted to the hydrocarbon opportunity set in Bolivia in South America.
A working meeting between Gazprom Management Committee Chairman Alexey Miller and Bolivia’s President Evo Morales was held at Gazprom’s office in Moscow where various agreements were signed with the aim to expand cooperation between Gazprom and Bolivia in the petroleum sector.
Land-locked Bolivia is the third-largest hydrocarbon producer in South America, extracting over 20 billion cubic meters of natural gas per year. Bolivia’s gas production is initially destined for the domestic market, while excess gas supply is exported primarily to Argentina and Brazil.
Miller expressed appreciation for the ongoing implementation of joint projects in Bolivia and discussed the opportunities to increase output at Bolivia’s Incahuasi natural gas field. The Russian official placed emphasis on joint plans for geological exploration in the promising Vitiacua oil and gas block, reported Gazprom in an official statement on its website.
A summary of the signed agreements follows:
Gazprom Management Committee Deputy Chairman Vitaly Markelov and Yacimientos Petroliferos Fiscales Bolivianos (YPFB) Vice President for Contract Management and Supervision Luis Poma signed a strategic cooperation agreement that envisions joint efforts in a wide range of areas including but not limited to the following: geological exploration, gas production and hydrocarbon transportation across Bolivia, development of the national gas and oil transportation infrastructure and NGV market, exchange of experience and personnel training, and sci-tech collaboration.
Gazprom EP International B.V. Managing Director Andrey Fick and Luis Poma also signed a term sheet related to the contract for exploration and production in the Vitiacua oil and gas block that will allow the companies to start drafting the main design documentation.
Finally, Bolivia’s Hydrocarbons and Energy Minister Luis Alberto Sanchez and Alexey Tyupanov, the CEO of EXIAR — the Russian Agency for Export Credit and Investment Insurance, which was established in late 2011, becoming Russia’s first export credit agency — signed an agreement to secure financing for supplies of gas-fueled machinery and equipment produced by Russian manufacturers.
GAZPROM IN BOLIVIA
In Bolivia, Gazprom International B.V., a company that participates in hydrocarbon prospecting, exploration and development projects outside Russia, represents Gazprom’s interests in projects in the country.
Gazprom in partnership with France’s Total S.A. (operator, WI 50%), Tecpetrol S.A. (WI 20%), and YPFB (WI 10%) develops the promising Ipati and Aquio oil- and gas-bearing blocks, within which the Incahuasi field is located. Gazprom (WI 50%) and Total (WI 50%) also implement a hydrocarbon exploration project in the Azero block.
In 2016, Gazprom, Bolivia’s Ministry of Hydrocarbons and Energy, and YPFB established the means for implementing Bolivia-based projects for hydrocarbon exploration, production, and transportation, and updated the general scheme for development of the country’s gas industry through 2040. Gazprom and YPFB also cooperate in personnel training and retraining.
Finally, in 2016, Gazprom and YPFB signed an agreement to explore the promising La Ceiba, Vitiacua and Madidi blocks. The La Ceiba and Vitiacua blocks are situated in the Chaco oil- and gas-bearing basin in the southern part of Bolivia (Tarija and Chuquisaca departments).
(Reuters, Marc Frank, 30.Apr.2018) — French energy firm Total SA and German industrial giant Siemens AG hope to sign a deal soon with Cuba to build a 600 megawatt gas-fired power plant on the island, according to diplomats and businessmen with knowledge of the talks.
The two are leading a consortium that has been in negotiations with Communist-run Cuba since last year when they won a tender for the project, said the sources, who did not identify the other members
“Total, with some international partners, is looking at a LNG power project in Cuba, one of several countries where Total is exploring similar LNG potentials,” the company said in a statement to Reuters.
A Siemens spokesman in Germany was not immediately available for comment.
The sources cautioned that many details of the project were under negotiation and that the combination of U.S. sanctions and Cuban bureaucracy meant there was no guarantee the agreement would be finalized, though they were hopeful.
The potential deal is the latest example of companies from the European Union moving to take advantage of Cuba opening to foreign investment.
“The EU has become Cuba’s first trade partner and was already the first in investment and development cooperation,” the European Union’s top diplomat Federica Mogherini said in January while visiting the country.
Siemens signed a letter of intent with the Cuban power authority in 2016 to help modernize the grid.
“With this important agreement … we will assist and support Cuba on the development of a sustainable and modern electricity system,” Willi Meixner, head of Siemens Power and Gas division, said at the time.
In the Matanzas Bay project, 124 kilometers (77 miles) east of Havana, Total would obtain the liquid gas from abroad, and then store, process and supply it to the plant, which would be built by Siemens, the sources said.
The project would mean less dependence on oil and less pollution, Jorge Pinon, a Cuban energy expert at the University of Texas in Austin, said.
“It could be the best decision that the Cuban government has made toward an energy policy able to react to changes in price, geopolitical events and or supply-demand disruptions,” he said.
Cuba was left in the lurch when its sole oil supplier, the Soviet Union, collapsed in 1991. More recently it has been scrambling to find alternative oil supplies as ally Venezuela’s economy and oil production implode.
Cuba’s total generating capacity is around 6,000 megawatts and demand is increasing due to growing tourism, digitalization and a new private sector.
Around 95 percent of electricity in Cuba is generated by fossil fuels. The government has begun a program to generate 24 percent with renewable sources by 2030.
Total and Siemens have engaged in commerce with the Caribbean island nation for decades.
Total was the first foreign company to drill for oil just off shore in the 1990s after the Soviet Union collapsed. The company failed to find a commercially viable field.
It also has a joint venture with Cuban state oil monopoly Cubapetroleo (CUPET), Elf Gas Cuba, which for 20 years has packed a liquid propane and butane gas mix into cylinders and distributes them for use by households and businesses in eastern Cuba.
The Cuban state power authority, Union Electrica, and CUPET did not respond to a request for comment. (Reporting by Marc Frank Editing by Daniel Flynn and Susan Thomas)
(Energy Analytics Institute, Pietro D. Pitts, 24.May.2018) – Venezuela’s reserves-to-production or R/P ratio was a remarkable 342 times in 2016 based on reserves of 300.9 billion barrels and production of 2.41 million barrels per day (MMb/d), according to BP’s Statistical Review of World Energy.
Today, in a best-case scenario, Venezuela’s R/P ratio could reach 550 times assuming no decline in reserves but a 38% drop in production to 1.5 MMb/d. Stated another way, Venezuela has enough reserves to last for 550 years, up 61% from 2016. In a presumed worst case scenario, if reserves were to declined for numerous reasons by 10% to 271 billion barrels with the same production of 1.5 MMb/d, Venezuela would still have enough reserves to last for 495 years, up 45% from 2016.
When compared to a Reuters’ peer group (comprised of Exxon, BP, Chevron, Total, Eni, Shell, and Equinor, the former Statoil – see chart above) with a combined R/P ratio of 80, Venezuela’s R/P ratio is still a whopping 7x higher than the seven-company peer group.
For what it’s worth, we know reserves are worth nothing in the ground unless they are produced. Maybe it’s correct and better to focus on reserve quality versus quantity but that still doesn’t drive me from my most important point in the case of Venezuela, a country with a lot of potential, but many more wasted opportunities.
Just think what will happen to Venezuela’s R/P ratio as the denominator approaches zero.
(Energy Analytics Institute, Piero Stewart, 22.Apr.2018) – Patrick Pouyanne, the Chief Executive Officer of French major Total, announced production at one of its oil fields in Venezuela was down to 80,000 barrels per day (b/d) from 120,000 b/d.
Pouyanne made the comments during an oil summit in Paris, reported Oil Price. He added that production in Venezuela was down due to a lack of capital and staff contributions from its partner PDVSA.
(Reuters, David Alire Garcia & Marianna Parraga, 27.Mar.2018) — Mexico awarded just under half of the 35 shallow-water blocks it tendered on Tuesday, in an auction muddied by the promises of the presidential frontrunner to review contracts awarded under a historic energy opening if he wins the July 1 election.
The country’s oil regulator awarded 16 blocks in the Gulf of Mexico to firms including Spain’s Repsol, France’s Total, Italy’s Eni, Britain’s Premier Oil and Mexico’s state-run Pemex, which was the biggest winner overall.
A final, competitive round of bidding in the Southeast Basins improved what started as a patchy showing, with little interest in fields believed to contain high amounts of natural gas.
About $8.6 billion in investment is expected from the projects to be developed in the awarded blocks, Mexico’s Energy Minister Pedro Joaquin Coldwell said, with early production starting in 2022 and a production potential of 280,000 barrels per day (bpd).
Andres Manuel Lopez Obrador, who has a comfortable lead in most polls, said that if he wins the July vote, he would review more than 90 contracts signed since Mexico passed legislation in 2013 ending Pemex’s 75-year monopoly, looking for signs of corruption.
Running for office for a third time, Lopez Obrador has also said he would hold a referendum on the future of the reform, and ask President Enrique Pena Nieto to cancel two auctions planned for the second half of the year.
Mexico’s next president takes office in December.
Despite the political uncertainty, Tim Davis, the group exploration manager for Premier Oil, said he was bullish about the future of the oil and gas opening.
“I think you could see a slowdown (if Lopez Obrador wins). But … I think they will see the benefits,” of the investment that’s coming in and the invigoration of new ideas and new companies arriving.
Repsol and Premier Oil individually claimed two areas each in the shallow-water fields offered in the Burgos basin, where less than a third of blocks were awarded. Premier won another block in a consortium with DEA Deutsche Erdoel and Sapura Energy.
Consortia made up of state-run Pemex, Mexico’s Citla Energy, Spain’s Cepsa, Britain’s Capricorn Energy and Germany’s DEA Deutsche Erdoel posted winning bids for four blocks in the Tampico-Misantla-Veracruz basin further south along the Gulf. There, around a third of blocks were awarded.
In the final Southeast Basins tender, competition was higher, and the oil regulator awarded all eight of the shallow-water blocks it tendered to consortia including Total, Eni, Royal Dutch Shell and Pemex.
“This is very high percentage (of awarded blocks),” said Coldwell.
Mexico’s government collected $124 million in cash payments from the auction, below the $525 million collected in a January deepwater auction.
The Southeast Basins areas are located in a portion of the Gulf where many of the companies that won blocks on Tuesday had already secured areas in earlier shallow and deepwater bidding rounds.
By securing neighboring blocks in the Gulf, companies are able to build clusters in order to reduce infrastructure costs.
Mexico’s Deputy Secretary for Hydrocarbons Aldo Flores blamed the weaker early interest on the quantity of natural gas areas in the auction, saying companies were more interested in finding crude.
“This will continue to be a challenge for us given the abundance of natural gas in Texas at very low prices,” Flores told Reuters on the sidelines of the auction in Mexico City.
Mexico is also competing for private companies’ interest with Brazil, which is holding its own auction this week, with another scheduled in June.
Brazil holds its own election in October, with the most likely leftist contender in the presidential race, Ciro Ferreira Gomes, warning he would expropriate energy assets bought by investors if he wins.
(Reporting by David Alire Garcia, Adriana Barrera and Marianna Parraga; Writing by Gabriel Stargardter Editing by Frank Jack Daniel, Susan Thomas and Diane Craft)
(CaribbeanLife, Bert Wilkinson, 31.Jan.2018) — Now that Guyana’s oil and gas basin has been deemed as one of the hottest and most exciting prospects in the world, Shell Oil has to be regretting its decision to withdraw as an investment partner with United States giant ExxonMobil, which has so far drilled six successful wells offshore Guyana worth about 3.2 billion barrels of oil, officials said Monday, Jan. 29.
Minister of Natural Resources Raphael Trotman said Exxon’s mid 2015 “world class” oil and gas find has clearly taken away all the fears and apprehensions about wasting investor dollars exploring offshore Guyana and Shell is one company which has missed out on the chance to cash in on one of the world’s largest oil finds in more than a decade. Exxon plans to begin producing about 120,000 barrels of oil daily in early 2020. This will make Guyana the largest producer in the Caribbean Community. The others are Trinidad, Suriname and Barbados.
“Shell was with Exxon on the Stabroek block and pulled out. They now maybe rue the day that they ever did that. Now, Shell has signaled that it wants to come back to Guyana,” Trotman noted, saying that all the major oil and gas companies in the world are either vying for their own offshore blocs or buying into smaller companies which have deep water concessions near Exxon’s highly successful offshore fields.
Exxon spokeswoman Kimberly Brasington Monday confirmed that Shell was the original partner with Exxon in the six million acre-plus concession area after Exxon had signed its exploration agreement with Guyana back in 1999 “but chose to pull out. They made the decision not to take the risk. We therefore had to go out there and look for new partners in Hess Oil and Nexen (of China). Yes that was indeed the case,” she said.
Geology and Mines Commissioner Newell Dennison said Shell pulled out about a decade ago and has been sending signals about coming back into the basin but he has seen no paper work regarding this so far.
Exxon and its partners plan to drill 17 wells in the first phase of their offshore venture and up to 40 others ion phase two. The company has already filed paperwork for permission to begin preparations for phase two of its offshore operations and has begun public consultations about this phase.
Spain’s Repsol, Tullow Oil of the United Kingdom, Chevron, Brazil’s Petrobras, Eni of Italy, TOTAL of France and British Petroleum are among big oil players all vying for participation in the country’s fledgling oil and gas sector.
“These companies are only expressing interest because ExxonMobil has de-risked the basin. Zero from zero is nothing. If you have oil and no one is troubling it, then it is worth zero. The oil may be worth a lot, but only if it is produced. We are moving to production, but it took ExxonMobil to find what others have been looking for,” Trotman said.
(Energy Analytics Institute, Piero Stewart, 11.Mar.2017) – PDVSA said that the start of the Jusepin 200 gas processing plant will allow its affiliate PDVSA Gas to reduce gas flaring by 100 million cubic feet per day (MMcf/d), announced Venezuela’s oil ministry in a twitter post.
The compression plant, located in the NIF Complex (Hato El Limón), is comprised of four compression trains with capacity to handle 200 MMcf/d of gas at a level of 60 pounds per square inch gage (PSIG).
(Petrobras, 10.Mar.2017) – Petrobras understands that the content disclosed to the market on the Strategic Alliance with Total on 10/24/2016, 12/21/2016 and 3/1/2017, includes the relevant information about this partnership, informing the values that refer to the purchase and sale contracts that were signed between the two companies and to the credit line negotiated. It should be noted that the contracts signed were based on internal and external economic-financial assessments, as well as fairness opinion issued by independent institutions.
In relation to the internal memo disclosed exclusively to the workforce, Petrobras considered that its content is not a matter of relevant information that could impact an investor’s decision in respect to the Company’s securities, since the main partnership elements were already included in the releases disclosed to the market.
It is important to note that the potential additional gains mentioned in the internal memo depends on synergy gains from the technological cooperation in the future, involving research components, exchange of knowledge and expertise, which may or may not materialize, so that they did not present sufficient certainty to be disclosed to the market, due to the preliminary level of discussions in progress and the low maturity of their estimates.
(Petrobras, 7.Mar.2017) – Petrobras clarified that the R$ 500 million amount mentioned in the article published by the newspaper O Estado de S. Paulo and mentioned by President Pedro Parente in an internal communication to the company’s work force, represents a preliminary estimate of potential gains that may result from the Strategic Alliance signed between Petrobras and Total.
The synergy between the companies, where Petrobras brings in technical knowledge from the operation of pre-salt layer fields in Brazil, and Total brings in its experience in the operation of deep water fields in the Western African coast and in carbonate reservoirs, might facilitate production optimization in the future as a consequence of an increase in the recovery factor in carbonate reservoirs and resulting increase in volume produced.
As such, the aforementioned amount has not been recorded in the global value of the Strategic Alliance announced to the market on 10/24/2016, 12/21/2016, and 03/01/2017, in the amount of $2.2 billion, since materialization of the foreseen synergies will depend on the progress of technical discussions and development plans to be jointly prepared.
(Petrobras, 1.Mar.2017) – Petrobras and Total signed the sales contracts for the assets in the Strategic Alliance, as set out in the Master Agreement signed on the 21st of December, 2016.
The contracts signed yesterday form a Strategic Alliance between both companies creating new partnerships in the Upstream and Downstream segments, and they reinforce technical cooperation in operations, research and technology. This alliance should allow both companies to bring together their internationally recognized expertise in all segments of the oil and gas value chain in Brazil and abroad.
Through these contracts:
– Petrobras will transfer 22.5% of the rights to Total in the concession area called Iara (comprising Sururu, Berbigão and Oeste de Atapu fields, which are subject to unitization agreements with the area called Entorno de Iara, a transfer of rights area in which Petrobras holds a 100% stake), in the Block BM-S-11. Petrobras will continue as operator and hold the largest stake, with 42.5%. The partnership with Total will allow Petrobras to reduce its investment and will benefit from technological solutions for its development that will be jointly studied by Petrobras and Total, maximizing profitability and the volume of oil to be recovered. BG E&P Brasil, a subsidiary of Royal Dutch Shell plc, with 25%, and Petrogal Brasil, with 10%, are also part of the consortium.
– Petrobras will transfer 35% of the rights to Total, along with its operation, in the Lapa field concession area, in Block BM-S-9. Petrobras will keep 10%. The Lapa field is in the production phase and came onstream in December 2016. Total, as the new operator of this field, will benefit the Consortium by incorporating valuable experience in deepwater projects for the next phases of the challenging Lapa project, which has distinct characteristics from other operating pre-salt fields. BG E&P Brasil, a subsidiary of Royal Dutch Shell plc, with 30%, and Repsol-Sinopec Brasil, with 25%, are also part of this consortium.
– Sale of Petrobras’ 50% stake to Total in Termobahia, which includes two cogeneration plants, Rômulo de Almeida and Celso Furtado, located in Bahia. Both plants are connected to the regasification terminal located in São Francisco do Conde, Bahia, where Total will take the regasification capacity to supply gas to the thermoelectric plants. This initiative constitutes an innovative partnership in the Brazilian thermal market.
The above contracts are in addition to other agreements already entered into on the 21st of December, namely: (i) Letter granting Petrobras the option to purchase a 20% stake in block 2 of the Perdido Foldbelt area, in the Mexican sector of the Gulf of Mexico, only taking on future obligations in proportion to its stake (ii) Letter of intent for joint exploration studies in the exploratory areas of the Equatorial Margin and the Santos Basin; and (iii) Technological partnership agreement in digital petrophysics, geological processing and subsea production systems.
The deal includes Total paying $2,225 million to Petrobras, made up of $1,675 million in cash for assets and services, a $400 million line of credit that could be triggered by Petrobras for part of their investment in the Iara development fields and $150 million for contingent payments.
After signing the contracts, Pedro Parente, CEO of Petrobras and Patrick Pouyanné, Chairman and CEO of Total, have declared: “We are delighted today to see our Strategic Alliance becoming reality. These new partnerships together with a reinforced technological cooperation should create significant synergies and values, mutualizing our operational excellence and further reducing costs on our joint projects for the benefit of both companies”
The deal is subject to the approval of the relevant regulatory entities, the potential exercise of preemptive rights by current Iara partners in addition to other preceding conditions.
For Petrobras, this Strategic Alliance is an important part of the Petrobras 2017-2021 Business and Management Plan. It increases information, experience, and technology sharing, which strengthens corporate governance, and improves the company’s financeability through mitigation of risks, cash inflows, and the release of investments.
For Total, these new partnerships with Petrobras reinforce Total’s position in Brazil through the access to new fields in the Santos Basin while entering a promising gas value chain.
Total and Petrobras
Currently, Petrobras and Total jointly participate in 19 Exploration and Production consortiums worldwide. In Brazil, the companies are partners in the development of the giant Libra field, which is the first Production Sharing Contract in the Brazilian pre-salt Santos basin. Outside Brazil, Petrobras and Total are partners in the Chinook field in the US Gulf of Mexico, in the deep-water Akpo field in Nigeria and in the gas fields of San Alberto and San Antonio/Itau in Bolivia, as well as in the Bolivia-Brazil gas pipeline.
(Petrobras, 21.Dec.2016) – Petrobras signed a Master Agreement with the French company Total, in connection with the Strategic Alliance established in the Memorandum of Understanding signed on 10/24/2016, as previously announced to the market.
Entering into strategic partnerships is an important part of Petrobras’ 2017-2021 Business and Management Plan, as it contributes to mitigating risks, strengthening corporate governance and sharing information, experiences and technologies, in addition to improving the Company’s financial viability through cash inflows and the release of investments.
Petrobras and Total have strong similarities in the upstream segment, sharing a relevant common base of E&P assets and the search for technological development in similar themes.
The companies jointly participate in 19 consortiums worldwide in exploration and production in key projects such as the Libra area, which is the first production sharing contract in the Brazilian pre-salt in Santos Basin, besides exploration areas in Equatorial Margin, Espírito Santo Basin and Pelotas Basin. In addition, both companies are partners in the Brazil-Bolívia gas pipeline.
With this new agreement, both companies will strongly reinforce their technological cooperation in the areas of geoscience, subsea systems and joint studies in areas of mutual interest, aiming to reduce investment risks and increase the probability of exploratory success over the next years. The companies will also become partners in the Iara and Lapa fields, in the pre-salt Santos Basin, and in two thermal plants, sharing the use of the regasification terminal infrastructure in the state of Bahia.
The companies also undertake to expand their joint activities outside Brazil, with Petrobras having the option of taking a stake in the Perdido Foldbelt area in the Mexican portion of the Gulf of Mexico.
The transaction has a global estimated value of $2.2 billion including cash, contingent payments and the carry of investments in production development of common assets to both companies, to be paid by Total to Petrobras and its subsidiaries as appropriate.
The signing of the relevant Sale and Purchase Agreements (SPA) related to the assets from this Master Agreement is subject to internal and external control and regulatory approvals, including the Brazilian Federal Accounting Court (TCU), potential preemptive rights from the current partners of Iara, plus other precedent conditions. The companies have a mutual commitment to make all the necessary efforts to sign all contracts within 60 days.
The main terms and conditions of this Agreement are as follows:
– the sale of a 22.5% interest to Total, in the Iara area (Sururu, Berbigão and Oeste de Atapu fields) in Block BM-S-11. Petrobras will remain the operator and will keep the largest stake in that consortium, with a 42.5% interest.
– the sale of 35% interest to Total in Lapa field in Block BM-S-9, with transfer of the operation to Total. Petrobras will have a 10% interest in this concession.
– Petrobras’ option to take a 20% participation in block 2 of the Perdido Foldbelt area in the Mexican portion of the Gulf of Mexico, acquired by Total in partnership with Exxon in the round of bidding held by the Mexican government on 12/05/2016.
– shared use of the Bahia regasification terminal, with a capacity of 14 million m3/day.
– partnership, with Total holding a 50% stake, in the thermal plants Rômulo de Almeida and Celso Furtado, located in Bahia, with energy generation capacity of 322 MW.
– joint studies in the exploratory areas in the Equatorial Margin and in the southern area of Santos Basin, taking advantage of the existing synergy between the two companies, since each has outstanding geological knowledge of the oil basins located on both sides of the Atlantic.
– technological partnership agreement in geological processing and subsea engineering, in which the companies have complementary knowledge, which can boost the gains from the application of new technologies in the partnership areas.
The information below refers to the concessions established in the Agreement:
Concessions in Upstream
In the Iara concession, Petrobras holds a 65% interest and is the operator. Shell, with 25%, and Galp with 10%, are partners in this area, which is part of Block BMS-11. The reservoirs of this concession have higher complexity and are in the production development phase. The partnership with Total in this area will bring benefits such as the release of investments and new technological solutions for its development, maximizing profitability and the volume of oil to be recovered.
The limits of this consortium extend into the Entorno de Iara area, from the Transfer of Rights agreement, in which Petrobras holds a 100% interest. The fields Berbigão, Sururu and Oeste de Atapu must enter into Individualization Production Agreements (unitization) with this area of the Transfer of Rights.
In the Lapa field, Petrobras holds a 45% interest and is the operator. Shell, with 30%, and Repsol with 25%, are partners in this field, which is part of BM-S-9 block. The development of the Lapa field is at an advanced stage, with the recent start of production, as announced on 12/20/2016, and presents geological characteristics and oil quality different from other pre-salt fields. Total, as future operator of this field, will bring benefits to the consortium, by incorporating its experience and knowledge in the continuity of its development plan.
The technological partnerships in the Iara and Lapa areas will develop and apply certain subsea technologies in a pioneering manner in Brazil. The efforts to reduce risks and increase the probability and the success in exploration will rely on a 4D seismic application in the context of carbonate reservoirs, with specific studies on CO2 migration and geomechanical studies, in addition to the development of a methodology for the construction of models to support investment decisions.
Gas & Energy Concessions
In the case of the G&E area, Petrobras and Total are forming an innovative partnership in the Brazilian thermal market. The initiative is aligned with the strategies of Petrobras for the Gas and Energy segment in the 2017-2021 Business and Management Plan, which establishes the restructuring of the Energy Businesses and maximizes the value generated in the gas chain. This vision considers a regulatory evolution, that is already under discussion with Brazilian federal authorities, forecasting an improvement of the procurement rules, access to the pipeline network and LNG regasification terminals.
The partnership with Total includes two thermal plants (Rômulo Almeida and Celso Furtado), connected to the Regasification Terminal located in São Francisco do Conde, in Bahia.
(Energy Analytics Institute, Pietro D. Pitts, 14.Sep.2016) – On a brief taxi ride from Punto Fijo’s Josefa Camejo International Airport to the main highway that crosses this city and connects to one of the many refining complex entrances here, a scrawny dog with mange can be seen emerging from an endless pile of discarded trash.
In this small refining town broken beer bottles, dirty diapers, and discarded personal items cling to trees and bushes as far as the eye can see in either direction along the short stretch of highway that separates the two massive refineries here: Amuay and Cardón. The refineries comprise the lion’s share of the processing capacity at PDVSA’s 971,000 barrel-a-day Paraguana Refining Complex, also commonly known as the CRP by its Spanish acronym. The CRP refineries combined with three others spread across this country have produced cumulative financial losses of $53 billion in the last eight years. Definitely not chump change.
Venezuela is home to a wealth of natural resources from gold to iron ore and holds the world’s eighth-largest natural gas reserves and the largest crude oil reserves, according to BP’s Statistical Review of World Energy. Yet, images of the immediate surroundings of the CRP paint a different financial storyboard about the well-being of Venezuela’s all important oil sector – which generates 96 percent of the country’s foreign export earnings.
Despite Venezuela’s claim to fame in terms of the size of its oil reserves, the South American country has been reduced to importing refined products because its refineries can’t meet local demand. The country’s refining sector is in a virtual state of emergency due to low processing rates, numerous unplanned plant stoppages, as well as accidents and injuries that state oil company Petróleos de Venezuela S.A. prefers to not report, according to oil union officials here. All summed up, PDVSA’s refining sector – especially within Venezuela – is a financial drain on the company as operating losses continue to mount year after year.
Venezuela – a founding member of the Organization of Petroleum Exporting Countries or OPEC — is engulfed in an economic crisis that started way before oil prices began their long downward trend. Political uncertainty, an ongoing threat of asset expropriations as well as currency and price controls have only helped to starve the capital-intense oil sector here of necessary foreign investments. PDVSA, as the Caracas-based company is known, continues to lack the necessary cash to properly revive the country’s oil sector in its majority partnership role, while local Venezuelan oil companies are few and in between and often lack the financial firepower of many of their international peers.
Many Venezuelan-based economists from Datanálisis President Luis Vicente León to Ecoanalitica Director Asdrubal Oliveros blame part of the economic crisis on the failure by former populist Venezuelan President Hugo Chávez to divert financial resources to the country’s private sector importers and the all-important upstream, midstream and downstream sectors during his tenure from 1999-2013 amid robust oil prices. In general, PDVSA’s problems mirror Venezuela’s economic crisis. The country’s economy has not fared any better under the presidential tenure of Nicolas Maduro, the man hand-picked by Chávez to succeed him prior to his untimely death in 2013. By most people’s accounts, considering the scarcities here of everything from milk to basic medicines, widespread looting, and runaway crime, things are much worst.
Oil-dependent Venezuela continues to rely heavily on its exploration and production or upstream sector to generate the bulk of its petroleum sector revenues. However, Venezuela’s oil output appears to be on an unstoppable decline, reaching 2,095,000 barrels per day in July of 2016 compared to 2,361,000 barrels per day in 2014, according to Organization of Petroleum Exporting Country’s Monthly Oil Market Report, citing secondary sources. Data from direct communications is just slightly more optimistic. Nevertheless, the downward continues.
Oil workers in red work overalls can be seen everywhere in the streets of Punto Fijo, either hailing taxis or waiting in the shade of trees for public transportation. Due to the ongoing economic crisis that has also affected Venezuela’s transportation industry – like countless other industries here – many cars and taxis in these parts and others in this resource-rich country don’t have air conditioning and/or visually lack some part or another such as a rearview or side mirror, working locks, a speedometer or a functioning trunk. The market for used tires, or anything used, is booming in Venezuela as new tire imports have come to a virtual halt.
Inside the CRP complex – physically off limits to visitors without permission from PDVSA but very visible through the wired fences — the scene within is arguably not much better, as years of under-investment on maintenance, upgrades and safety protocols by the state oil company have unfortunately left the refineries and the grounds similarly forsaken. Against a backdrop of a country in the midst of an ongoing political crisis, many refinery workers here say a combination of 12-16 hours work days, a lack of employee benefits and arguably the lowest salaries for refinery workers anywhere in the world (in dollar terms) has also taken a toll on them as well as their colleagues.
Whether the refineries or the workers are in worst condition, is a judgment call, but at first glance they both appear to be on their last legs.
In the last eight years, PDVSA’s refining, trade and supply division accumulated net losses in each of the consecutive years since 2008, which was the last time the division reported a positive gain from its combined operations in Venezuela. All tallied, the division accumulated losses of $53 billion during 2008-2015, according to data compiled from PDVSA’s financial reports.
“With a cash crunch they have focused all efforts in the upstream where you make the money,” said Francisco J. Monaldi, Ph.D. and Fellow in Latin American Energy Policy & Lecturer in Energy Economics at Rice University’s Baker Institute for Public Policy in an e-mailed response to questions. “The lack of human resources adds to the lack of investment to generate the operational difficulties.”
Refining sector stoppages and costly repairs are generating large production and economic losses for PDVSA, said oil union representative Larry López during a late afternoon sit down chat at a run-down restaurant just two blocks from the Amuay refinery.
Venezuela doesn’t need refineries to be a major exporting country, former PDVSA President Rafael Ramírez told me in 2014 during a company-sponsored media trip to visit the CRP on the anniversary of the deadly explosion at Amuay that left at least 48 people dead. To this day, it is unclear if those comments justify the lack of attention that has been given to the country’s refining sector even now under the leadership of Stanford-trained Eulogio Del Pino.
Venezuela’s Information Ministry, the clearing house for questions for all of the country’s ministries, and media officials with PDVSA and the Venezuelan Oil Ministry did not reply to emails seeking comment on the company’s refining sector strategy or general comments for this article. Venezuela’s newly elected Petroleum Chamber President was also unavailable to comment on this article.
“Our refineries have always produced products to cover demand in the domestic market as well as the Caribbean. To export to the US and Europe we really don’t need to have refineries,” said Carlos Rossi, president of Caracas-based consulting firm EnergyNomics and formerly an economist with the Venezuelan Hydrocarbons Association or AVHI, in an interview in Caracas.
“Because the refineries have been seen as a low priority, PDVSA has focused more attention on the Faja,” said Rossi referring to the Hugo Chávez Oil Belt, formerly known as the Orinoco Heavy Oil Belt, home to one of the largest non-conventional oil deposits in the world.
PDVSA’s total hydrocarbon workforce mushroomed during 2000-2015 as the company stressed more importance on political affiliation and less on university or technical experience, said Eddie Ramírez, the director of Gente del Petróleo and a former PDVSA employee, in a phone interview from Caracas. At year-end 2015, PDVSA employed 114,259 direct hydrocarbon sector workers, up from just 42,267 when Chávez rose to power in 1999, according to PDVSA data.
PDVSA’s refining sector, which employed 9,391 workers in 2015, represented just 8.2 percent of the company’s total workforce in that year. In 2010, just 3,584 workers were employed in the refining sector, which represented a mere 3.8 percent of PDVSA’s total workforce.
Given PDVSA’s cash problems and its inability to generate positive free cash flow, the company’s plans to build six new multi-billion dollar upgraders, boost oil production and refining capacity to 6,000,000 barrels per day and 1,800,000 barrels per day respectively by 2019 seem to be optimistic and represent a major challenge for the state oil company.
PDVSA owns six refineries in Venezuela, which the company reports are strategically located to supply refined products to its major consumers. The refineries – which had a total combined processing capacity of 1,303,000 barrels per day, as of year-end 2015 – produce a product slate including but limited to: 91 and 95 grade gasolines, jet and diesel fuel, light naphtha, liquefied petroleum gas, solvents and residuals.
Due to a combination of problems, the six refineries were just processing a combined 616,000 barrels per day in August 2016, translating into an average utilization for PDVSA’s domestic refineries of 47.3 percent, said Ivan Freites, an oil union official with the United Federation of Venezuelan Oil Workers or FUTPV, which represents a large portion of PDVSA’s workers, during an interview in Punto Fijo.
Two refineries are located in Venezuela’s western Falcon state including: Amuay, with a 645,000 barrel-a-day processing capacity; Cardón, with a 310,000 barrel-a-day capacity; while the smaller Bajo Grande is located in Zulia state, with a 16,000 barrel-a-day capacity. Together, the three refineries make up the CRP, according to PDVSA’s annual report for 2015, with a product slate destined 55 percent for the domestic market and 45 percent for the export market.
More centrally located is the El Palito refinery in Carabobo state with a 140,000 barrel-a-day capacity while the remaining two refineries located in Venezuela’s eastern Anzoátegui state include Puerto La Cruz, with an 187,000 barrel-a-day capacity and the smaller San Roque, with a 5,000 barrel-a-day capacity.
In 2015, Venezuela’s domestic refining sector reported average utilization rates of 66.2 percent, according to PDVSA’s operational and financial data from last year. This compares to an average utilization rate of 70.6 percent in 2014 and an average utilization rate of 72.8 percent during 2011-2014.
The CRP has suffered much more deterioration and lower utilization rates than the other refineries. Average utilization rates at the complex reached just 60.5 percent in 2015, down compared to 72 percent in 2011 and an average 67.7 percent during 2011-2014, according to PDVSA data, which differs to what oil union officials report.
“Average utilization rates at the CRP were just 53 percent in 2015,” said Freites, a stocky, long-time oil union official. “The complex is damaged to the point that it almost makes better sense to build new refineries than to fix the incalculable problems that exist.”
In contrast, average utilization rates at El Palito reached 71.4 percent in 2015, down from 90.7 percent in 2011 and an average 89.5 percent during 2011-2014 while at Puerto La Cruz rates reached 93.2 percent in 2015, up from 88 percent in 2011 and an average 88.6 percent during 2011-2014, according to PDVSA.
Figures reported by PDVSA are always overly positive and extremely optimistic, said Freites, 53, during an early happy hour brunch which included Venezuelan ‘tequeños’, a special mix here of fried cornmeal with cheese on the inside accompanied with another popular import here: whisky.
From oil towns in Midland, Texas to Maracaibo to Monagas and Punto Fijo in Venezuela, oil men have at least one thing in common: their love for food and the typical companions Grants, Chivas, and the rest of the supporting cast. However, the economic crisis here has forced many oilmen to settle for whatever is available at the kitchen table. With bottled water sometimes unavailable, Johnnie Walker becomes a name to trust.
PDVSA data differs significantly from that provided by oil union officials here and other international agencies due to the opaque operating and reporting nature of the state oil company. A quick comparison of Venezuela’s production figures as reported by PDVSA and Venezuela’s Oil Ministry as compared to figures reported by OPEC in its monthly reports or even BP in its yearly statistical review serve to prove the point.
Cash-strapped PDVSA recently reiterated plans to boost its domestic refining capacity to 1,800,000 barrels per day by 2019 but has not detailed plans for its existing refineries – which continue to process at less than optimal levels – and has been quiet about plans to build new refining capacity. Only the Puerto La Cruz refinery is known to be undergoing a deep conversion process aimed at boosting its ability to process heavier Venezuelan crudes, according to PDVSA.
Recent agreements signed by PDVSA with authorities from the governments of Aruba, Venezuela and Citgo Aruba related to the restart of a 209,000 barrel-per-day refinery located in San Nicolas, Aruba point to potential issues PDVSA may have building new refineries or even six planned new upgraders, a special type of refinery, due to financial constraints whereby at first glance it appears easier to buy refining capacity than build it from scratch.
It is not a priority to build refineries since it is much better to invest in upstream activities to maximize your limited resources, said Monaldi, also the founding director and a professor at the Center for Energy and the Environment at IESA in Venezuela. New refineries are not great moneymakers and require low capital cost to make any money, he said.
Just a handful of streets separate the Amuay refinery from the Las Piedras fishing neighborhood. Not far away, rusted out American gas-guzzlers like the Ford Maverick and even the Ford F-1, seemly pulled straight off the set of the 1970’s U.S. television show Sanford and Son, can be seen littering the narrow streets here as well as the ones behind Cardón refinery in the neighborhood that bears its name, Punta Cardón. Residents of the latter neighborhood, basically live under the constant flare of gas and whatever else might come from the refinery that is practically in their backyards.
All of PDVSA’s Venezuelan refineries seem to suffer from some type of operational deficiency. At any given time and sometimes at the same various units from different refineries are down for unplanned repairs ranging from the Amuay flexicoker, alkylation, and catalytic units; the Cardón distillation units; the three Puerto La Cruz atmospheric distillation units to the El Palito FCC unit, thus, drastically reducing domestic processing capacity and output, said Frietes. On a number of occasions in the past two years complete operations at PDVSA’s principal refineries have been halted due to operational issues.
Reduced utilization rates at the CRP have created shortages of oil derivatives including unfinished oils, lubricants, finished motor gasoline and special naphthas. As a result, Venezuela is importing more derivatives such as products for gasoline as well as light oils from the U.S. and even far off countries such as Russia and Algeria to mix with its heavy and extra-heavy crude oils produced in the Faja, even as it continues to offer oil to regional neighbors ranging from Cuba to Nicaragua under attractive financing terms.
Despite the need to import oil and products, Venezuelan oil exports continued to member countries belonging to regional initiatives ranging from the Cuba-Venezuela Cooperation Agreement (CIC) to PetroCaribe but declined 6.6 percent to 185,000 barrels per day in 2015 compared to 198,000 barrels per day in 2014, according to PDVSA data. The volumes in 2015 were down 27.3 percent compared to 255,000 barrels per day supplied to member countries in 2009.
“PDVSA continues to give away oil while in Venezuela inventories of gasoline, gasoil, diesel, LPG and lubricants are insufficient to cover domestic demand,” said Freites, a stern critic of PDVSA.
Operating deficiencies in Venezuela have created export opportunities for refiners along the North American Gulf Coast. U.S. net imports of oil and refined products from Venezuela ranging from distillate fuel oil to MTBE (oxygenate) averaged 751,000 barrels a day in the 12-month period ended June 2016 compared to 711,000 barrels a day in the same year-ago period, according to data posted to the U.S.-based Energy Information Administration’s website. However, U.S. net imports of the same products from Venezuela averaged 1,590,000 barrels-a-day in the 12-month period ended June 2001 in the early years of the Chávez government.
Productivity at the CRP is down due to the increase in workers and the decline in output, said a former PDVSA refinery safety manager who worked for 29-years at the company. He didn’t want to reveal his name since he still does contract work for PDVSA in Punto Fijo and feared retaliation from the company. Oil workers must be oil workers and not politically divided like today as it is affecting the productivity of the employees and the company, he said during an interview at a small building in downtown Punto Fijo which serves as the local office of the FUTPV.
“It is still politically hard to justify massive Imports. But the economics are very clear. In the long run, if you can sustain international market prices in the domestic market you may be able to open the downstream to private investment,” said Monaldi.
Grade school kids and university students blend into the scenery of an oil town gone bust. Many will never reach PDVSA’s professional ranks unless they have connections within the company and/or support the socialist ideas, or at least those expressed by Maduro and his government. More than anything, PDVSA refinery workers in faded red work overalls dominate the landscape in Punto Fijo and the surrounding towns seemingly unaffected by hot weather, strong wind gusts and refineries constantly emitting gas and other substances into the air. What has affected them is the continued economic crisis and low wages, many say here.
Under the sweltering sun, improvisations are the order of the day at the CRP for many refining workers frequently forced to scramble to solve recurring small problems turned into major ones due to the lack of basic replacement parts. The practice of using emergency stapling techniques to fix routine vapor leaks at processing units, or product leaks along pipelines, is commonplace nowadays, says Freites, who is the spokesperson for many refining and oil union workers not willing to go on record due to fear of retaliation or work dismissal from PDVSA.
Similar scenes are said to resonate at the Puerto La Cruz and El Palito refineries, said José Bodas, another oil union official, in a telephone interview from Carabobo state.
PDVSA is using stapling methods to fix pipeline and unit leaks instead of properly fixing or repairing them due to a lack of funds to procure the necessary replacement parts, said the former PDVSA safety manager. PDVSA is more reactive than preventative and is conducting more corrective maintenance than preventative maintenance due to the lack of financial resources. It’s not necessarily a money thing but just the way PDVSA works today, he said.
Lackluster security measures to protect the PDVSA refineries and workers have allowed crime incidents to edge up within the complexes’ gates. Stolen work bags and purses, missing clothing and other personal items and car break-ins are daily work hazards beyond those related to working in a domestic refining sector where accidents, sadly enough, are more the norm than in many other countries with refining operations. In the country with the highest murder rate in the world, according to the website WorldAtlas.com, not even the confines of the refinery complex are safe enough to shield workers from the realities on the streets in Punto Fijo, Ciudad Ojeda, Anaco and other major oil and gas towns across Venezuela.
Safety is no longer a priority for PDVSA as funds are being spent haphazardly on non-necessary projects, said the former PDVSA safety manager with his salt-and-pepper mustache and Italian surname. He says many current PDVSA bosses only respond to accidents when they are officially reported by the media.
On its part, PDVSA claims there were just 154 total injuries at the CRP, El Palito and Puerto La Cruz refineries in 2015. This compares to 173 in 2014, 276 in 2012, and 298 in 2010, according to PDVSA data in its social and environmental statements on its website. Still, union officials here say the numbers don’t reflect the real case scenario since a lot of accidents and injuries go undocumented.
As the sun falls over the horizon, workers use their mobile phones in some areas of the CRP seemly unaware of the work hazards. Thieves that regularly enter the complex via the various gate openings to rob copper, bronze, nickel as well as other materials and equipment, also rob workers of their mobile phones whenever possible. The resale market for mobile phone parts is big in Venezuela amid an economic crisis that has impacted not just food importers, but the telecommunications and airline industries as well, among others.
The multiplier effect on this town and surrounding communities can visibly be seen in the fishing regions of Punto Fijo from Las Piedras to Los Taques where white and blue collar oil workers in the good ole days would be seen almost everywhere eating and taking in the sun with family and coworkers or clients. That’s not the scene here anymore. Local mayors have for years promised money to fishing communities and fishermen in the region but many, like other family members, remain unemployed. Many have turned to crime to rob and steal things they can resell to get basics like food or medicines for their families.
“Whatever was taken over from the transnational companies doesn’t work here,” said Jaime Antonio Diaz, 44, during an interview at a lightless restaurant in Los Taques. “If the Fourth Republic was bad, then the Fifth Republic is the worst,” he said as a stray cat entered the premise through an entrance door kept open to let in fresh air and natural light.
Diaz’s comments refer to the two most recent republics in Venezuela. The Fourth Republic was the period in Venezuelan history marked by the Punto Fijo Pact in 1958 for the acceptance of democratic elections in that year. Nationalization of Venezuela’s oil industry was a point frequently criticized by Chávez as a one of many failures of the Fourth Republic. The Fifth Republic Movement (MVR by its Spanish acronym) was a leftist political party founded in the late 1990s by then-presidential candidate Chávez. It was later dissolved in 2007 to give way to Chávez’s new political party the United Socialist Party of Venezuela (PSUV).
From refinery workers fleeing low pay and increased worksite accidents to unemployed fishermen and engineers driving taxis, Punto Fijo is going through what many say is one of its worst periods in decades.
Within visible distance of the dirt roads of Los Taques nearly 30 or more towering wind power turbines can be seen off the immediate horizon on the return trip from Los Taques to Punto Fijo. Despite the strong winds here, the turbines are not operational and have yet to generate power for commercial or domestic usage, according to Freites, owing to corrupt deals between Venezuelan government officials and the company that supplied the towers. Venezuela – which has long suffered from a natural gas deficit in its industrialized western Zulia state – has plans to use non-associated natural gas production from the Cardón IV offshore project as well as power generated by these turbines to reduce the need to import costly diesel fuel. From the look of things here, it is quite obvious the latter is not something PDVSA officials want to openly talk or brag about. However, it’s safe to assume somebody made a killing on the turbine deal.
While the wind turbine project – like others envisioned in this small country with a population close to 31 million – looks good on paper in the boardroom, the corruption here more often than not turns the project into a financial bonus for some individuals at the costs of local jobs and wasted resources for a country teetering on the brink of financial default.
One thing continues to thrive here: the contraband of fuels. Contraband of cheap Venezuelan gasoline continues to nearby Colombia, Guyana, Trinidad and Tobago and Aruba despite efforts to deter it and a decision by this government to boost gasoline prices in February of 2016 to 6 bolivars a liter from 9.7 centavos. While demand for gasoline has declined in Venezuela due to economic crisis and a higher cost for gasoline, its elevated price is still quite low compared to nearby markets; thus, making it still very attractive for trade internationally.
Large fishing boats – refitted by the Venezuelan military and now under the control of military officers that pose as fishermen – continue to leave the pier near Las Piedras with domestic fuel. These so-called ‘gasoil mafias’ continue to exchange Venezuelan refined products on the high seas in international waters in seemingly another way the military is kept happy and loyal by Maduro and company, according to Rossi, author of the book ‘The Completion of the Oil Era: The Economic Impact (Energy Policies, Politics and Prices).’
Barefoot grade school kids with just shorts on, play baseball on the dirt roads and side streets in numerous poor communities in and around Punto Fijo. Using broomsticks and makeshift baseballs, they can be seen enjoying their game despite the extreme poverty they live in and not having gloves. Despite being a Latin American country, baseball, not soccer is the sport of choice here and seen here as the way to rise out of poverty, at least for many males. On the other side, females here dream of being Ms. Venezuela or Ms. World.
“This government only saves itself by changing the model,” said León, referring to what the Maduro government needs to do to stay in power.
Whether the model change comes tomorrow, next year or in 2019, Venezuela’s hydrocarbon sector is in need of drastic changes. However drastic and radical these changes may have to be, investors will continue to keep Venezuela on their radar screens, hoping for a chance to invest in the country with one of the largest resource bases on the planet. However, from the looks of things, with foreign diplomats and oil men continuing to get kidnapped here, Venezuela is not yet ready for the massive return of foreign companies or better yet the foreign companies aren’t ready to return under the existing circumstances.
The recently announced departure of Schlumberger, the world’s largest oilfield services company, should serve as a reminder to potential investors about the condition of the oil sector here which still contends with a massive brain drain of national and international talent from companies from Halliburton to Total, Chevron, Statoil and a host of smaller companies lacking the deep pockets to survive without quarterly or sometimes monthly cash flow.
“The low wages continue to produce brain drain and that makes worse the operational problems,” said Monaldi.
Top Venezuelan officials and PDVSA executives blame the economic and petroleum sector crisis here on an economic war waged they say by opposition leaders with the backing of persons and institutions from Bogotá, Miami, Washington and even Madrid. The open denial of internal problems created by widespread mismanagement, errored financial and economic decisions as well as a number of actions including asset expropriations have handcuffed the country’s private sector and brought the all-important petroleum sector to a near halt. That hasn’t stopped other countries from stepping in to fill the void when and where it is possible. Case in point: Algeria just started to supply oil to Cuba amid mounting issues at PDVSA.
The Amuay explosion on August 25, 2012, as regrettable as it was, was an early wake-up call about what PDVSA had (and has) become after more than a decade of so-called socialism. Amid continued corruption at PDVSA and a hydrocarbon sector where funds mysteriously disappear, the financial and economic dreams of a handful or more have smashed the hopes of many in Punto Fijo and all across this major oil producing South American country.
“A lot of people here are changing sides due to the mismanagement of resources by the Chávez and now the Maduro government,” said Ali, a 50-year old taxi driver of an old Toyota Corolla, who requested his last name not be used in this article for fear of retaliation from PDVSA or government officials.
Ali’s sentiment resonates across all parts of this country from many petroleum engineers and other professionals that have left the industry to drive a taxi, wait tables or do anything where the wages are better.
“The sad part of all this is that we could have another August 25th,” said Freites.
(Editing by Peter Wilson)
(Energy Analytics Institute, Jared Yamin, 9.May.2016) – France’s Total plans to boost natural gas production by 6.7 million cubic meters per day at Aquio Incahuasi.
The French company also plans to take part in the second phase of activities at the field whereby it plans to boost output there by another 6.7 million cubic meters per day, reported the daily newspaper La Razón, citing Bolivia’s Hydrocarbon Minister Luis Alberto Sánchez.
(Petrobras, 24.Mar.2015) – The Libra consortium has finished drilling extension well 3-BRSA-1267-RJS/3-BRSA-1267A-RJS (3-RJS-735/735A). The drilling results confirmed the presence of a hydrocarbon column approximately 200 meters deep in reservoirs with good permeability and porosity characteristics.
Informally known as C1, the well is located in the central part of the Libra block, in Santos Basin, around 220 km offshore from the city of Rio de Janeiro.
The final depth reached was 5,780 m, including a water depth of 2,160 m. This is the second well successfully drilled by the Libra consortium, and is 18 km from the first well, called 3-RJS-731.
The hydrocarbon and CO2 bearing intervals were calculated through electrical profiles and fluid samples, which are being characterized through laboratory analysis.
The consortium will continue with the exploration plan by drilling new wells in order to evaluate the Libra area, which covers around 1,550 km2.
The Libra consortium is composed of Petrobras (Operator, 40% WI), Shell (20% WI), Total (20% WI), CNPC (10% WI) and CNOOC (10% WI), as well as Brazilian state-owned company Pré-Sal Petróleo S.A. (PPSA), which is the contract manager.