Earlier this week, India’s Mangalore Refinery and Petrochemicals (MRPL) opted to purchase Omani and Yemeni crude oil instead while Petral was also heard to have sourced July crude from outside the region.

Traders said only a few Nigerian cargoes from June have yet to clear and spot trade was seen shifting to July on Friday.

Offers for the benchmark Qua Iboe grade were reported at around dated plus $3 a barrel but most market participants assessed the grade at around 50 cents below that level and about 20 cents below levels earlier this week.

West Africa is seen as increasingly reliant on European demand for its oil, given that a more than $1 increase in the Brent/Dubai spread since the start of May has made exports to Asia less attractive.

“This leaves Europe as the core destination for Nigerian barrels, but the region already has plenty of Caspian and North Sea barrels on offer, much of which is available at discounts to Dated Brent,” said JBC Energy analysts.

NIGERIA

* Qua Iboe: Seen at around dated Brent plus $2.50 a barrel.

* Brass River: Nigeria will load an additional two tankers of Brass River oil in July, a revised shipping list showed on Friday, lifting total exports to around 1.79 million bpd.

* One of the two added cargoes – a 350,000 barrel tanker allocated to Eni – was deferred from June. The second was a 180,000 barrel Brass cargo, trading sources said.

* Bonny: A force majeure on exports declared in mid-April remains in place, Shell confirmed on Thursday.

ASIAN TENDERS

* Taiwan’s CPC was heard to have bought two cargoes of Angolan crude oil as part of its July tender. The grades were heard to be Cabinda and Nemba, although the sale prices were not immediately available.

DATABASE

For a database of oil supply and demand fundamentals upstream and downstream, Reuters subscribers can click on:

http://bond.views.session.rservices.com/ce (Reporting by Emma Farge; editing by James Jukwey)

(c) 2013 Thomson Reuters, Click For Restrictions

Featured image (c) Shutterstock/Tanawat Pontchour

Royal Dutch Shell CEO Peter Voser,
Credit: Reuters/Jerry Lampen

By Andrew Callus

LONDON, May 2 (Reuters) – Royal Dutch Shell’s 54-year old chief executive Peter Voser is to retire next year in a surprise early departure he said was driven by a desire for a change of lifestyle.

Over the past nine years the softly spoken and widely respected Swiss national has helped drive the group’s structural reorganisation and recovery from sector laggard to a leading position in the burgeoning industry of liquefied natural gas (LNG).

He took over as finance director of Europe’s top oil company in 2004 amid the board-level bloodshed that followed its shocking downgrade of reserves estimates and became CEO in 2009.

His departure comes as the company and the industry face huge new challenges.

Shell is the western world’s number two company by production behind Exxon Mobil. But, like its peers, it is struggling to replace reserves and boost production and faces a squeeze on earnings as costs rise while the price of oil threatens to fall decisively below the psychologically important $100 a barrel level.

Finance director Simon Henry said the company was well-placed for the recent fall in prices.

“We also think there are quite few players in the market, quite a few companies, who actually have bet the farm on $100-plus oil prices. We don’t,” he said.

“We’re structured around a lower oil price so it is not bad for us.”

Nevertheless, analysts say that among the world’s top oil companies, Shell spends more on exploration per barrel produced than any of its competitors. Its most high-profile exploration failure has been in Alaska, where it has spent $5 billion since 2006, and has yet to drill a single complete hole.

Meanwhile thefts, strikes and other issues dog activity in Nigeria where it is the principle international oil company operator. “We were concerned by the level of oil theft in Nigeria at the end the fourth quarter and we are even more concerned now,” Henry said.

LIFESTYLE CHANGE

Voser joined Shell in 1982. He left in 2002 to join Swiss group ABB, but was back within two years as finance director as part of an effort to stabilise the company after the reserves crisis.

He said his decision to go in the first half of 2014 was a personal one. Shell employees, investors and analysts all said they were surprised to see him go.

“After such an exciting executive career I feel it is time for a change in my lifestyle and I am looking forward to having more time available for my family and private life in the years to come,” Voser said in a statement.

Shell said it would look outside and inside the company for his replacement. A spokeswoman said Shell had looked outside for CEOs in the past. However, as with most big oil companies, new chief executives traditionally come up through the ranks.

Henry refused to be drawn on his own prospects for becoming CEO of Shell, Europe’s second-largest investor-owned company by value behind food company Nestle.

Voser has been named in media reports as a possible chairman of Roche Holding, the drug firm based in his native Switzerland and where he is already non-executive director.

A Shell insider said Voser had indicated he had no plans to take on new non-executive directorships or chairmanships.

STRONG TRADING, LIKE BP

The last of the western world’s four biggest oil companies to report results, Shell joined its peers on Thursday in delivering a first-quarter profit that topped market expectations.

Adjusted net profit on a current cost of supply basis rose to $7.5 billion from $7.3 billion a year ago, compared with expectations of around $6.5 billion.

As was the case with BP’s results on Tuesday, Shell exceeded expectations by a big margin thanks in large part to its trading activities, which were not split out from the rest of its operations.

Shell’s shares climbed 1.4 percent to 2,223 pence, making it the third-best performer among European oil stocks on Thursday.

(c) 2013 Thomson Reuters, Click For Restrictions

Image (c) R.Almeida/gCaptain.com

At the Center for Strategic and International Studies (CSIS) this morning, His Excellency Ali I. Al-Naimi, Minister of Petroleum and Mineral Resources for the Kingdom of Saudi Arabia discussed his views on the dynamic changes taking place on the global energy scene, and in particular, discussed his view on the energy “renaissance” currently underway in the United States.

By all accounts, Minister Al-Naimi came across this morning as a supporter of the current oil and gas revolution in the United States, one that is changing the dynamics of Saudi Arabian global oil trade.

“The US energy scene is witnessing a remarkable transformation,” he noted. “I welcome these new supplies into the global oil market,” supplies which he believes will bring increased stability and increased U.S. engagement within the global energy markets.

There’s been a lot of talk about the end of the United States’ reliance of foreign, and in particular Middle Eastern oil. Many oil companies predict the United States will surpass Saudi Arabia in oil production in the next few years.

He comments that Middle East oil exports to the U.S. from Saudi Arabia were higher in 2012 than at any time since US tight oil production began in 2009. “The United States is, and will remain, a major energy consumer. It will continue to meet domestic demand by utilizing a variety of sources, including from the middle east. This is simply sound economics,” commented Al-Naimi.

Secondly, Minister Al-Naimi believes that talk about energy independence on foreign oil is “naive and overly simplistic” and that it fails to recognize how interconnected the world’s energy markets are.

“If you take crude and all liquid products together, the US is currently the third largest exporter behind Saudi Arabia and Russia. We’re all part of a global market and no country is truly energy independent.”

Increasing US production does not mean the US could, or should detach itself from international affairs.

I don’t believe that is in anyone’s best interest, and I don’t think it will happen. The question is not how will the US achieve energy independence, but to what degree it will and be prepared to export its oil and gas supplies?”

Current Outlook in Saudi Arabia

Minister Al-Naimi comments that Saudi Arabia’s main mission right now is to continue to diversify their GDP away from oil revenues, and it appears they have been quite successful at meeting that goal.

“In 1973 the contribution of oil to Saudi Arabia’s GDP was 65 percent, last year it was under 30 percent,” notes Al-Naimi.

Saudi Arabia is actively pursuing investments in new mineral industries and renewable sources like solar.  Other investments include a huge investment in people, schools, and universities.  In fact, 10% of Saudi Arabia’s budget is spent on higher education and the King Abdullah scholarship program sponsors around 150,000 students worldwide to gain qualifications. Nearly half of their university students enrolled in American classroom.

“This will have a huge impact,” notes Al-Naimi, “and underlines how important the two countries are to one another.”

No plans to go up to 15 million barrels per day

While Saudi Arabia currently idles at around 9 million barrels per day, and VLCCs continue to be underutilized around the world, Prince Turki Al-Faisal mentioned in a speech at Harvard this week that Saudi Arabia had plans to achieve 15 million barrels per day of production,.  Minister Al-Naimi commented today that the Kingdom has no plans to achieve production rates that high.

“We don’t see anything like that even at 2030 or 2040.” Al-Naimi notes. “The need to build facilities or drill wells to hit 15 million is not there.  We will be lucky to go past 9 million barrels by 2020.  There is no call to go past 11 or 11.5 by 2030 or 2040 based on any projections that I’ve seen.”

Bio:
His Excellency Minister Ali Ibrahim Al-Naimi has been Minister of Petroleum and Mineral Resources for the kingdom of Saudi Arabia since August 1995. Prior to being appointed Minister, he had served as chief executive officer of Saudi Aramco for seven years. Minister Naimi has spent his career in energy exploration and production, beginning in 1947 as a foreman with Saudi Aramco, and progressing through the ranks as an assistant superintendent, superintendent and manager, before moving into the Exploration Department in 1953. He was appointed vice president of Aramco in 1975, senior vice president in 1978 and was elected as an Aramco director in 1980. He became executive vice president of Operations for Aramco in 1982, and then company president in 1984. He was named as the chief executive officer for Aramco in 1988.

Minister Al-Naimi studied at the International College and the American University in Beirut, Lebanon, from 1956 until 1963. He earned his B.Sc. in Geology from Lehigh University in Pennsylvania in 1962 and a master’s degree in Geology from Stanford University in 1963.

Tyra Southeast expansion, Image: Maersk Oil

Maersk announced today that the Danish Underground Consortium (DUC) has approved an $800 million expansion of the Tyra Southeast development in the Danish North Sea.  This plan includes a new unmanned platform, subsea pipelines, and associated well drilling services, and is expected to add reserves and resources of 50 million barrels of oil equivalent over the next 30 years to Danish production.

The DUC is the partnership between A.P. Møller – Mærsk (31.2%), Shell (36.8%), Nordsøfonden (20%) and Chevron (12.0%).

“The Danish North Sea still contains significant oil and gas resources,” commented Mark Wallace, Managing Director for Maersk Oil Danish Business Unit, the operator of the DUC. “However, the remaining oil and gas is becoming progressively more difficult to extract requiring efficient development, new technology and continued large investments. The Tyra Southeast development is an example of our efforts to maximise recovery from the Danish North Sea. The investment represents an important part of the next chapter in the Danish oil production.”

Maersk Oil has – as operator of DUC – signed a contract with Bladt Industries A/S, a Danish contractor located in Northern Jutland, to build the jacket (legs) and topside (platform). The installation is planned to take place at the end of 2014. The project schedule aims to have first oil early in 2015. After installing the platform, Maersk Oil plans to drill 12 wells during 2015-2017. Each horizontal well will be about six kilometres long.

The project has been formally approved by the Danish Energy Agency.

In China, demand for all fossil fuels is projected to expand, led by gas (+283%), oil (+73%), and coal (+34%) as nuclear and renewables surge over 1000%.

(c) BP

Unconventional tight oil and shale gas will continue to play a major role in meeting global energy demand, adds Dudley. Tight oil will account for 9% of global supplies while shale gas is expected to grow by 7% annually to reach 74 Bcf/d by 2030, accounting for 37% of the growth of the world’s natural gas supply.

Oil’s market share will continue to follow the same path it has taken over the past 40 years, slowly declining while coal, a cheap and plentiful energy resource, will be used on a greater scale to ensure China’s power generation needs are met.  Global coal demand however, is projected to fall from 71% today to 55% in 2030 as gas doubles its share and oil is unchanged.

BP attributes the decline of oil’s market share to the widespread use of fuel-efficient engines and its high cost, which is spurring further efficiency innovations.

(c) BP

Coal

After oil, coal is expected to be the slowest growing major fuel, with demand rising on average 1.2% a year to 2030. Over the period, growth flattens to just 0.5% a year after 2020. Nearly all (93%) of the net growth in demand to 2030 will come from just China and India, whose combined share of global coal consumption will rise from 57% in 2011 to 65% in 2030. India is expected to overtake the US as second largest coal consumer by 2024.

Oil and Gas Imports

“In the period to 2030, the US becomes nearly self-sufficient in energy, while China and India become increasingly import-dependent,” notes Dudley.

Oil however, is expected to be the slowest growing of the major fuels to 2030, with demand growing at an average of just 0.8% a year.  As the United States becomes less energy intensive and as domestic production increases, China is predicted to surpass the United States over the next 5 years to become the biggest net oil importer in the world.  By 2030, BP notes, the Chinese are projected to import 75 percent of their total oil consumption, a figure roughly the same as Europe’s total consumption.

Net oil imports to the US are projected to fall another 70 percent by 2030 virtually eliminating half of the US trade deficit, while Europe will be importing over 90 percent of its oil and 80 percent of its natural gas.

Russia will remain the biggest energy exporter in the world, while at the same time Saudi Arabia will regain its pole position as the biggest oil exporter in 2030.

Oil and Gas Production

According to BP, the United States will likely surpass Saudi Arabia this year as the world’s largest oil producer and will hold that title until surpassed by Saudi Arabia again in 2027.

This initial surge can be attributed to tight oil and biofuels production, and will subsequently decline post-2020 as the resource base dips and production costs rise.  During this same period, Russia and China will develop their production capabilities and are expected to reach rates of 1.4 Mb/d and 0.5 Mb/d by 2030.  China’s shale gas production is expected to hit 6 Bcf/d 2030.

Putting that in perspective, North Dakota increased its production from 100,000 bbls/day to 1 Mb/d in a 5 year period.  Currently, the United States is producing 2.1 Mb/d of tight oil (24% of US oil production) and 24 Bcf/d (37%) of natural gas from shale.

(c) BP

How much energy is left?

BP notes that every year experts have tried to come up with estimates for how much recoverable fossil fuel exists on our planet, but the number continues to rise.

Within tight oil and shale gas alone, BP notes there are estimated technically recoverable resources of 240 billion barrels of tight oil and 200 trillion cubic meters of shale gas. Asia has an estimated 57 Tcm of shale gas and 50 Bbbls of tight oil, versus 47 Tcm and 70 Bbbls respectively for North America.

However, “it’s not what’s below the ground, it’s what’s above the ground,” notes BP.

From a production standpoint of tight oil and shale gas, more than 70% of the world’s production will still be in North America by 2030 with incremental growth elsewhere around the world.  “Above ground” factors, BP notes in their Outlook, have been the catalyst for success in bringing these resources to market.

The US has the world’s largest rig fleet with over 1,800 rigs in operation according to Baker Hughes, a majority of which can drill horizontally.

BP notes, “The competitive industry that spurs continued technological innovation, land access facilitated by private ownership, deep financial markets, and favorable fiscal and regulatory terms, will support rapid production growth.”

(c) BP

Natural Gas

BP researchers conclude that natural gas will be the fastest growing fossil fuel at 2% per year, reaching 456 Bcf/d (+144) by 2030. By volume, growth is greatest in power generation (+56 Bcf/d) and industry (+54 Bcf/d).

Supported by shale gas, BP predicts North America will become a net exporter of liquefied natural gas (LNG) in 2017, with net exports approaching 8 Bcf/d by 2030.  During that same time period, China will increase their domestic production of shale gas to 6 Bcf/d, amounting to 20% of total Chinese gas production.  ”Nonetheless,” BP notes, “given the fast growth of Chinese consumption, which by 2030 will be larger than the current EU gas market, China still requires rapid import growth (11% p.a.).”

Over the next 17 years, LNG will contribute to an increasing share of global trade as production grows by 4.3% per year.  Qatar, the current world-leader in the production of liquefied natural gas, will be surpassed in the coming years as huge facilities off Australia’s northwest shelf come on line.

Demand for LNG will grow primarily from non-OECD countries and will represent 76% of the rise in gas demand and 74% of output growth. On a regional level, Africa is set to overtake the Middle East to become the largest net LNG exporter in 2028.

By 2030, LNG will represent 15.5% of global gas consumption.

Alongside the growth of LNG volumes, BP sees a diversification of trading partners for both exporters and importers. In 1990 each exporter or importer had an average of 2 partners – by 2011 that had risen to 9 and 6 respectively. Nigeria, Qatar and Trinidad & Tobago are leading export diversification, with an average of 20 trading partners in 2011.

Another indicator of increased diversification is the decline in the share of LNG accounted for by the largest importer and largest exporter – from 68% and 39% respectively in 1990 to 23% and 31% respectively in 2011.

Carbon Emissions

While the rate of growth is moderating, carbon emissions are still expected to increase by 26% from 2011 to 2030. Most of the growth will come from non-OECD countries, so that by 2030 70% of CO2 emissions are expected to come from outside the OECD. However, per capita emissions in non-OECD regions will still be less than half those in the OECD.

The Big Picture

Mr. Dudley concludes, “The energy industry is highly competitive and investment will flow to the places that possess the right resources below ground and the right conditions above it. Highlighting the “above ground” factors that have made the US and Canada engines for energy innovation can be instructive for other nations seeking to develop their domestic energy resources.”

“The overall conclusion is that increased demand can be met as long as competition is present to drive innovation, unlock resources and encourage efficiency.”

North America probably will become a net energy exporter by about 2025, after importing 35 percent of its oil in 2010, Irving, Texas-based Exxon said in an energy outlook report released today. Asia Pacific countries may import almost 40 percent of their total energy needs by 2040 as demand increases.

“After decades of relatively flat production, output of oil and other liquid fuels in North America is projected to rise by about 40 percent from 2010 to 2040,” Exxon said in the report. Meanwhile, “overall U.S. energy consumption is expected to gradually plateau and then decline by about 5 percent from 2010 to 2040.”

Technological advances have helped tap oil and gas from shale-rock formations, as well as extracting it from oil sands and deep-water prospects in North America. Monthly U.S. oil production exceeded 7 million barrels a day in November, for the first time in 20 years. The International Energy Agency said in November the U.S. is poised to surpass Saudi Arabia as a crude producer in the next decade.

U.S. liquefied natural gas exports will stay below 10 billion cubic feet a day, Bill Colton, Exxon’s vice president for corporate strategic planning, said during a presentation on the outlook at Rice University in Houston.

Emissions Price

Exxon assumes that at some point in the next 30 years governments around the world will begin putting a price on carbon emissions, Colton said. Exxon sees a possible price of $60 a ton of carbon dioxide emitted in the U.S. in 2030.

Under that circumstance, the price to burn coal to generate electricity jumps well above gas, which has about 50 percent fewer emissions, Colton said.

“Coal’s got a lot of environmental pushback, wind and solar are growing but they’re limited from a practical standpoint, nuclear is also limited from practical and political considerations,” he said. “That provides this huge opening for natural gas as sort of the fuel of choice for the future.”

More use of gas instead of coal and increased output from nuclear and renewable energy sources will reduce U.S. greenhouse-gas emissions, Exxon said. Carbon-dioxide emissions may drop more than 25 percent by 2040 to the lowest levels since the 1970s, the company said.

In December, Exxon released a broader report with its global energy outlook, boosting its long-term estimate for worldwide demand growth to 35 percent from 32 percent as expanding populations in Africa and India use more electricity.

- Edward Klump and Dan Murtaugh, Copyright 2013 Bloomberg.

With the world’s population headed toward 9.5 billion by 2060 and the rapid growth of emerging economies lifting millions of people out of poverty for the first time, world energy demand could double over the next 50 years.  This is the potential future envisioned by Shell in their latest “New Lens” scenarios, released last month.

Shell’s New Lens Scenarios, examine the economic, political and energy trends out to 2100, and underscore the critical role that government policies will likely play in shaping the future.

“The world in the future,” Shell notes, “will be defined by how people and governments meet the challenges posed by institutions, inequality, and insecurity in relation to the paradoxes of prosperity, leadership, and connectivity.”

• Which paradoxes will become more acute?
• Which will be resolved?
• Which industries, businesses, nations, and groups of people will have room to manoeuvre?
• Which will be trapped?
• How will the capabilities of capital, collaboration, and creativity develop?
• How will power and influence be distributed?

Based on potential outcomes of the above questions, the Shell Scenarios have provided critical insights into the potential trajectories of global economic, geopolitical and social trends since their inception in 1972. Shell Scenarios draw on wide-ranging expertise from inside and outside the company and have become a resource to governments, academics and think tanks around the world.

New Lens Scenarios: Mountains and Oceans. These scenarios explore two plausible future pathways, examining the implications for the pace of global economic development, types of energy used, and the growth in greenhouse gas emissions. They highlight areas of public policy likely to have the greatest influence on developing cleaner fuels and renewables, improving energy efficiencies and moderating emissions.

Scenario One: Mountains

This scenario anticipates a world of moderate economic development, with policy playing an important role in shaping the global energy system and environmental pathway. These policy measures result in more compact cities and transform the global transport network. Cleaner-burning natural gas becomes the backbone of the world’s energy system. Global demand for oil peaks in about 2035, with electricity and hydrogen dominating for cars and trucks by the end of the century. Technology to capture carbon dioxide emissions aids in reducing CO2 emissions from the power sector to zero by 2060. While greenhouse gas emissions begin to fall after 2030, they remain on trajectory to overshoot the target of limiting global temperature rise to 2 degrees Celsius.

Scenario Two: Oceans

This scenario envisions a more prosperous, but also more volatile world. The global energy system is shaped more by market forces and civil society than government policy. Both nuclear power and natural gas growth are limited outside North America by public resistance and slow adoption of policies and technologies, with oil and coal remaining significant forces in the energy system. Lacking legal and financial support, carbon catching and storage lags, capturing roughly 10% of emissions by mid-century. As a result, electricity generation takes about 30 years longer to become carbon neutral in the Oceans scenario vice Mountains. Hard to reach oil resources are developed due to high energy prices and a surge in energy demand, though oil demand plateaus around 2040. These high energy prices encourage improvements in efficiency and also solar power, with solar becoming the largest primary source of energy by the 2060s.

“By 2030 we expect demand for critical resources like water, energy, and food to have risen by 40%-50%. To meet those needs without significant environmental detriment, business as usual will not be an option – we require business unusual,” notes Royal Dutch Shell CEO Peter Voser.

Jeremy Bentham, Vice President, Shell Business Environment and Head of Shell Scenarios comments, “We are all faced with choices that produce consequences for years – and even decades – into the future. Whether we are developing new opportunities or anticipating significant threats, we base decisions on our perspectives of the future. So there is huge value in developing as rich an understanding as possible of the drivers, trends, uncertainties, choices, and cycles that will shape that unknowable future, and that may look very different through the eyes of different actors.”

While the future is impossible to predict, given the analytical rigor and track record of past Shell scenarios, it is likely that the global energy system in the future decades will closely resemble the trends predicted in these scenarios.”

Top image (c) Shell

By Emma Farge and Dmitry Zhdannikov

GENEVA, Feb 28 (Reuters) – Vitol, the world’s biggest oil trader, reported revenues that topped $300 billion for the first time in 2012, while its profit margin was under increasing pressure after slipping below 1 percent to a four-year low the previous year.

Revenues rose by 2 percent to $303 billion, despite a slight drop in traded volumes, along with a rise in energy prices, the Swiss firm said on Thursday. The figure exceeds revenues reported by U.S. No. 2 oil major Chevron.

“It was a year without the additional advantages of market structure or volatility that previous years have offered, and trading markets continue to become increasingly competitive, with additional pressure on margins,” President and Chief Executive Ian Taylor said in a statement.

The results showed the challenges that trading houses face in turning growth into profits. In their constant quest to conquer new markets and secure bigger volumes, they rarely end up generating a higher rate of return.

In 2012, furthermore, Vitol failed to repeat its whopping sales gains of 2011, when it increased volumes by 15 percent and revenue by 44 percent to $297 billion.

Like most other private commodity trading houses, Vitol does not release its profit figures publicly. But a copy of a 2011 filing obtained by Reuters showed that its profit margin and cash flow had fallen to their lowest levels in four years.

In 2011, its gross profits rose only by around $100 million to $2.438 billion, generating an overall gross margin for the year of 0.8 percent, down from 1.1 percent in 2010, 2.7 percent in 2009 and 1.2 percent in 2008, according to Reuters calculations.

Vitol, owned by some 330 employees, said 2011 net profit was $1.7 billion, up from $1.5 billion in 2010, and the second highest ever after $2.3 billion in 2009.

By comparison, Chevron’s net profit was $27 billion in 2011.

Vitol’s closest competitor, Glencore, has yet to release its revenue figures for 2012. It previously said its margins in the oil trading business were around 1 percent.

CONSTRAINED GROWTH

Vitol, like many of its peers, has stepped up efforts to acquire physical assets as it seeks to extend control over supply lines in search of higher profit margins.

The trading firm has expanded in the African fuel distribution business through a 40 percent stake in Vivo Energy and has expanded its footprint in the west African upstream sector.

“We continue to look at a variety of new investment opportunities in the midstream and downstream energy sectors, which can deliver growth and synergy with our core trading business,” Vitol said in the statement.

Taylor said he expected growth in global oil demand to be constrained in 2013 at around 1 million barrels per day (bpd) due to weakness in some European economies.

This compares with an estimate of 1.05 million bpd from the U.S. Energy Information Administration.

He estimated non-OPEC supply would grow by around 1.5 million bpd in 2013 due mostly to new production in the United States and Canada, currently enjoying a shale boom.

Vitol, alongside AtlasInvest, purchased a Swiss refinery from insolvent group Petroplus last year, increasing its presence in the European downstream market.

“The new capacity planned to come on line later in 2013 is expected to exceed the growth in demand we are forecasting, so we expect refinery margins to be somewhat lower later this year after an unexpectedly strong first quarter,” he said.

The company traded some 261 million tonnes of oil and products in 2012, down from 273 million in 2011.

(c) 2013 Thomson Reuters, Click For Restrictions

Urals exports are expected to shrink in early March, but could increase later in the month due to heavy maintenance schedules at domestic refineries, traders said on Friday. Urals supplies from the Baltic ports of Primorsk and Ust-Luga will amount to 800,000 tonnes in March 1-6, down from 1.1 million tonnes for the same period in February, a preliminary loading schedule showed.

Russian refinery runs are expected to fall by 1 million tonnes due to maintenance next month, one trader said, which should free up more crude for export from the Baltic.

“I think they will stack up more cargoes to Primorsk and Ust-Luga,” he said.

Exports from the Black Sea port of Novorossiisk will total 580,000 tonnes for March 1-6, down from 660,000 tonnes for the same period in February, according to the schedule, seen by Reuters.

February exports were boosted by shipments delayed from January when the port was forced to close several times due to storms.

A 4 percent rise in Russia’s export tax next month, to $420.6 per tonne, will also help to curb exports.

Russia’s oil export duty for March is expected to rise to the highest since May 2012 following an increase in oil prices, calculations by the Finance Ministry and Reuters showed on Friday.

In the Platts window, Shell bid for a cargo in the Baltic at dated Brent minus $1.70 a barrel, some 50 cents stronger than price indications earlier in the week, but found no sellers, traders said. In the Mediterranean, Total bought a cargo from Lukoil at dated Brent minus $1.05 a barrel, some 15 cents weaker than prices for 80,000-tonne cargoes earlier in the week.

In tender news, TNK-BP offered to sell a 140,000-tonne cargo from Novorossiisk for March 5-6 delivery.

A fire at Algeria’s Skikda refinery was extinguished, damaging its power generator which is expected to be replaced within three days, trade sources said on Friday.

The fire broke out on Thursday evening due to a fault in the electricity system during maintenance work. The flames were extinguished several hours later, the sources said oil exports from Iraq’s southern Basra terminals were restored to 2.3 million barrels per day on Friday after bad weather reduced shipments a day earlier, shipping sources said.

(Reporting by Dmitry Zhdannikov, Gleb Gorodyankin; editing by James Jukwey)

(c) 2013 Thomson Reuters, Click For Restrictions

Featured image (c) Shutterstock/billdayone

LONDON (Reuters) – A trade deal between the European Union and Singapore is unlikely to affect North Sea crude oil shipments to Asia, given that EU crude exports to Singapore already incur no taxes.

The European Union and Singapore are seeking approval for a free trade agreement (FTA) from their political authorities and envisage initialling the draft agreement in spring 2013, the European Commission said.

An existing FTA between the European Union and South Korea, in operation since July 2011, created a profitable arbitrage for North Sea traders but has also driven up prices.

Forties – the North Sea crude most often sent to South Korea – is one of the four crudes that make up the Brent oil benchmark.

Traders send about two VLCCs of Forties to South Korea every month, reducing the amount available to European refiners. This pushes up the crude’s differential to dated Brent as well as prices in the wider Brent market.

But a free trade deal with Singapore is unlikely to have the same effect, because EU crude exports to the Asian trading hub are already zero-rated for taxation purposes.

“The difference with South Korea is that it imposes duties on other crude imports, so for a South Korean buyer it makes a big difference if it doesn’t have to pay duty on crude imports from the EU,” said David Wech, an oil analyst at JBC Energy.

“If the refiner buys Middle Eastern or North African crude, it has to pay 3 percent extra and that’s a lot of money.”

Singapore tends to source its crude from close neighbours Indonesia and Brunei, said Mangesh Hirve, a director at research firm Derrick Petroleum. This works out a lot cheaper than freighting crude all the way from the North Sea. “I don’t think it would work as an arbitrage,” he said.

North Sea traders agreed that as the existing zero tax rating has so far generated few crude exports to Singapore, an FTA would make little difference.

One trader also suggested that legislators would make sure the agreement was structured in such a way that it would definitely not trigger more Forties outflows to Asia.

“It was an unforeseen side effect of the South Korean FTA; they won’t make that mistake again,” he said. “Because of (the existing zero tariff), it won’t need any special clauses, but they will check to ensure it does not lead to further distortion of the oil markets.”

JET AND DIESEL FLOWS

On the flip side, Europe is unlikely to see a major increase in imports of jet and diesel from Singapore. Although import taxes are nominally set at 4.7 percent for jet fuel and 3.5 percent for diesel, most imports do not incur these charges.

Jet fuel imports are zero-rated if they have an air-worthiness certificate, which means suitable for use in planes. “If it is EU-qualified, no tax is due and most barrels brought this way are therefore certified,” one jet fuel broker said.

Diesel is also zero-rated if it has a sulphur content of less than 2,000 ppm. As the EU uses diesel with a sulphur content of 10 ppm, diesel imports tend to meet this requirement.

“If it came in above that, it would probably be defined as a refining feedstock,” Wech said.

“But the point is that such duties aren’t paid as it is such a narrow-margin business that 3 or 4 percent is a lot of money. That would kill any arbitrage opportunity.”

In 2011, the European Union imported oil and oil products from Singapore to the value of 1.2 billion euros ($1.6 billion). This ranked Singapore 29th in terms of EU trading partners for this segment. ($1 = 0.7427 euros) (Reporting by Claire Milhench; additional reporting by Jessica Jaganathan)

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