Awl Bidness

Feb. 18 (Bloomberg) -- Oil exploration in Nigeria has slumped to the lowest in a decade after producers including Royal Dutch Shell Plc and Total SA backed away from investment until the country’s petroleum law is passed.

Just one exploration well was drilled in Nigeria in the past two years, the lowest since 1999, according to official figures released by the Petroleum Ministry. The number of wells peaked at 34 in 2002.

“Funds have not been available” for exploration, said Belema Osibodu, a spokeswoman for the Department of Petroleum Resources, in a telephone interview yesterday.

Fewer wells meant the government missed its targets to boost reserves to 40 billion barrels and output to 4 million barrels a day by 2010. Nigeria’s total crude oil and condensate reserves of about 37 billion barrels are the second-largest in Africa after Libya. The country is the continent’s biggest producer, with current oil output of about 2.1 million barrels a day, according to the state oil company.

While the government has struggled to meet its share of contributions to joint ventures, international oil companies have slowed exploration projects as they await new fiscal terms in a proposed bill before parliament, Osibodu said.

The law to reform the way the oil industry is funded and regulated, which has been in the legislature for more than two years, is expected to be passed by the current government before its tenure runs out in May, President Goodluck Jonathan said Feb. 2. Energy companies say the proposed law will hand too much profit and control to the state and make new investments in deep water oil fields unprofitable.

Armed Attacks
Exxon Mobil Corp., Shell, Chevron Corp., Total and Eni SpA run joint ventures with state-owned Nigerian National Petroleum Corp. that pump about 90 percent of the country’s oil.

Shell has been selling some of its Nigerian onshore licences to allow local producers and new investors to develop the deposits. The company plans to sell four out of a total of 34 blocks it holds in the country, Chief Financial Officer Simon Henry said Feb. 3.

“The blocks sold and for sale represent less than 10 percent of our production” in Nigeria, Henry said. “So we’re really reducing the footprint, increasing indigenous participation.”

Attacks in the south by armed groups including the Movement for the emancipation of the Niger Delta, or MEND, cut more than 28 percent of the country’s oil output between 2006 and 2009, also deterring new investment.

While the attacks decreased after thousands of fighters accepted a government amnesty in 2009, MEND refused to disarm, saying its demands weren’t met. MEND wants the region to have exclusive control of its resources, while paying tax to the central government.

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Feb. 19 (Bloomberg) -- OPEC’s oil exports fell 2 percent in December from a month earlier as Saudi Arabia, the world’s largest exporter, reported a decrease of 4.9 percent.

Total exports by the Organization of Petroleum Exporting Countries, excluding Algeria and the United Arab Emirates, fell by 387,000 barrels a day to 19.4 million barrels a day, the Joint Data Initiative website ( http://www.jodidata.org/faq.shtm ), which compiles data supplied by governments in an attempt to improve transparency, showed today.

Saudi Arabia’s exports fell to 6.05 million barrels a day in December from 6.36 million in November even as Saudi production rose to a two-year high of 8.37 million barrels a day, JODI said.

“This is a huge difference,” said John Sfakianakis, Chief Economist at Riyadh-based Banque Saudi Fransi, noting the 2.32 million barrel per day difference between what Saudi Arabia produced and its exports.

“It’s not clear if Saudi Arabia consumed the full 2.32 million barrels locally during that month, but what’s clear is that rise in local consumption is becoming eminent,” he said.

Energy demand in the kingdom will increase to more than 8 million barrels of oil equivalent a day by 2028, Hashim Yamani, president of King Abdullah City for Atomic and Renewable Energy, said at a conference in Riyadh on Jan. 23. That compared with 3.4 million barrels of oil equivalent a day last year.

Total world output fell 14 percent in December from a month earlier to 55.5 million barrels a day, the lowest since 2002, mainly due to a in non-OPEC production, particularly in Latin America.

JODI is under the supervision of the Riaydh-based International Energy Forum ( http://www.ief.org/Pages/index.aspx ) and its data goes back to 2002.

Oil ministers and energy officials from 90 countries, including members of OPEC and the IEA, will sign a charter for the Forum in Riyadh on Feb. 22, host nation Saudi Arabia said yesterday.

The agreement is aimed at finding ways to stabilize oil markets and improve the collection and dissemination of supply, demand and price data.

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Feb. 22 (Bloomberg) -- Libyan leader Muammar Qaddafi told state television he hasn’t fled the country as rebel flags flew over the second-biggest city and corpses lay on the streets of the capital after a security crackdown on protests.

“I am here in Tripoli and not in Venezuela,” the Libyan leader said in comments broadcast early today. “Don’t believe the dog news agencies,” he said, leaning out of a car to speak into a microphone while holding a white umbrella to shelter from the rain.

In Tripoli, bodies are lying outside a day after protesters were attacked by pro-Qaddafi gunmen, the opposition National Front for the Salvation of Libya said. In Benghazi, the independence flag of the constitutional monarchy overthrown by Qaddafi in 1969 flew on streets and over several buildings and there were no security forces in evidence except traffic police, witnesses said. Oil prices rose almost 10 percent.

Libya, holder of Africa’s largest oil reserves, is the latest nation to be rocked by protests...


...Crude for April delivery rose as much as 9.8 percent to $98.48, the highest in more than two years, and traded at $95.58 at 1 p.m. in London...


...Natural gas carried from Libya to Italy via Eni’s Greenstream pipeline is flowing in fits and starts and is likely to stop, possibly later today, according to two people with knowledge of the situation.

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Feb. 22 (Bloomberg) -- Robert Dudley’s second $7 billion deal this year signals a shift for BP Plc toward the world’s fastest-growing economies as exploration drilling remains closed in the U.S. after the Macondo oil spill.

Dudley, the first American chief executive officer of the London-based company, agreed yesterday to pay Reliance Industries Ltd. $7.2 billion to help explore deepwater fields in India. That follows an $8 billion share swap with OAO Rosneft to expand into Russia’s Arctic Sea in January. Last year, BP signed a deal to explore off Brazil and sealed a partnership with Cnooc Ltd. for offshore licenses in the South China Sea.

The deals are putting BP’s exploration unit closer to regions that the company predicts will generate the majority of energy demand growth for the next 20 years. Dudley is also reducing BP’s dependence on the Gulf of Mexico, where it has yet to resume drilling following the worst U.S. spill.

“The Reliance deal represents another step in reshaping BP’s portfolio,” ... “The strategy earmarked post-Macondo is clear -- a genuine focus on exploration and a shift toward resource and consumer markets.”


...Reliance gained as much as 5 percent in Mumbai trading.

$20 Billion
In India, BP will acquire a 30 percent interest in 23 blocks as well as form a venture with Reliance to market gas, the London-based company said yesterday. Future performance payments and investment could increase the size of the deal to $20 billion.

Dudley said the investment in India doesn’t mean the company will turn its back on the U.S., where the company is obliged to pay into a $20 billion fund for spill victims for the next three years.

“We’re fully committed to the U.S.,” Dudley said in a press conference yesterday. “This is part of the shift in energy demand across the globe.”

BP predicts that global energy use will rise by almost 40 percent by 2030, led by demand from emerging economies, according to the Energy Outlook 2030 report published Jan. 19...


‘Moving On’
“The game-changing moves announced with Rosneft and Reliance this year, in addition to other positive exploration access exposure, give us confidence that BP is moving on from Macondo...”

President Barack Obama halted oil and natural-gas drilling in waters deeper than 500 feet (152 meters) after BP’s well off the Louisiana coast blew out April 20, killing 11 workers and spewing crude for 87 days. While the ban was lifted Oct. 12, the U.S. has yet to issue a permit for the type of exploration stopped in the moratorium.

Reliance Chairman Mukesh Ambani said yesterday he chose BP because it is “one of the finest deepwater exploration companies in the world.” BP’s purchase, to be completed over the course of this year, is the largest foreign direct investment in India.

‘Strong Credentials’
“It’s a bold move not long after Macondo,” said Ivor Pether, who oversees $12 billion of U.K. securities at Royal London Asset Management and added to his BP holdings last year. “It’s evidence that BP still has strong credentials in deepwater.”

Like the equity swap in Russia, BP’s Reliance deal may carry some political risk, said Colin McLean, chief executive officer of SVM Asset Management Ltd. in Edinburgh, who oversees about $900 million of securities including BP shares.

Cairn Energy Plc’s agreement to sell 90 percent of its Indian production to Vedanta Resources Plc is being held up by a dispute over royalty payments to the state-owned Oil & Natural Gas Corp. The Indian government has yet to approve the purchase.

“Governments have been fearful of the majors and that’s why so many juniors have entered developing economies,” said McLean. “It needs political will and good political relationships.”

BP will pay for the India deal in cash. Dudley said yesterday the company still has $8 billion of assets to sell after $22 billion of divestitures following the spill. The potential for uncovering more crude and gas in the blocks is the part of the deal he’s most excited about, he said...

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Feb. 25 (Bloomberg) -- More than 90 million years ago, when the land mass of Pangaea began separating into the continents we now call South America and Africa, the earth may have produced a lucrative farewell gift: huge oil and gas deposits along both coastlines where they had previously been joined.

Now, Angus McCoss, exploration director and chief geologist at Tullow Oil Plc, which in 2007 discovered one of the biggest oil finds of recent years off the coast of West Africa, is betting more than $100 million that a similar bonanza awaits off South America’s eastern shore, Bloomberg Businessweek reports in its Feb. 28 issue.

Tullow and partners Royal Dutch Shell Plc and Total SA by the end of March will start drilling their first deepwater test well about 100 miles (160 kilometers) off French Guiana, a sliver of South American rainforest best known as a former penal colony. The prospect field, called Zaedyus, lies 21,000 feet (6,400 meters) below the ocean’s surface.

McCoss, who spent most of his career at Shell, aims to repeat the success of Jubilee, Tullow’s 120,000 barrel-a-day field off Ghana on the other side of the Atlantic Ocean. He’s optimistic because of evidence that Zaedyus mirrors Jubilee’s geology, formed in the Cretaceous period when the African and South American land masses began to separate.

“Tullow has proven more than once they are capable of thinking outside the box,” says Thierry Pilenko, chief executive officer of oil service provider Technip. The idea of twin basins on either side of the Atlantic is “compelling,” he said.

Bight of Benin
A glance at a map shows how South America would once have fit snugly into Africa’s Bight of Benin. Zaedyus is the first well to test the “Atlantic mirror” theory and the payoff could be huge. Computer models estimate the field may hold 700 million barrels in gross reserves, valued at more than $70 billion at today’s oil prices.

“Zaedyus is the most exciting well of the year, as bold as it gets,” says McCoss, who joined Tullow in 2006. “It’s remarkable to try to open up a new basin in 2011. There aren’t many opportunities left in the world.”

The world’s largest oil companies missed out on the Jubilee find. Tullow’s partners in Ghana are Anadarko Petroleum Corp. and private equity-backed Kosmos Energy. In French Guiana, however, Shell and Total, Europe’s largest and third-biggest oil companies, have bought shares in Tullow’s field and agreed to shoulder the majority of the $110 million cost of surveying the area and drilling the well.

McCoss says the chance of finding oil from the first test well to be drilled in French Guiana is probably about 15 percent.

‘It’s Risky’
“It’s exciting, but it’s risky,” said Yves-Louis Darricarrere, Total’s head of exploration and production. “It’s a good example of how we want to be more bold. I like to associate with those I admire.”

Geologists believe that when the Atlantic Ocean started opening between South America and Africa, organic sediment resulted in hydrocarbon deposits known as the Late Cretaceous turbidite sands. They haven’t been drilled to date because they are less visible than other types of deposits and drilling at such depths has only recently become viable.

“Integrated oil companies aren’t as comfortable with the risks of drilling these wild cat types of wells as explorer companies have been,” says Oswald Clint, an analyst at Sanford C. Bernstein. “The deep waters off French Guiana have never been explored.”

Devil’s Island
French Guiana is an overseas region of France with a population of about 230,000. Starting in the 1850s, the country began deporting convicts to a penal colony known as Devil’s Island off the coast, a practice that lasted about a century. Arianespace, the world’s biggest commercial satellite launcher, launches satellites from Kourou, near the capital Cayenne.

“We’ve been very encouraged by three-dimensional seismic we’ve shot in French Guiana,” McCoss said, referring to studies of reserves done using sound waves. “We’ve found, as we had hoped, that it is in the heart of a major turbidite sand system.”

Tullow is also a partner in the Jaguar exploratory field off nearby Guyana, scheduled for drilling later this year. Spain’s Repsol YPF SA and Canada’s CGX Energy Inc. are the other participants in that field. Exxon Mobil Corp. also holds offshore Guyanan acreage. In Suriname, a former Dutch colony that sits between Guyana and French Guiana, Murphy Oil, Repsol, Japan’s Inpex, and Tullow hold acreage.

Angola Drilling
Oil companies are preparing to test a similar theory of reserves mirroring each other across the Atlantic by drilling into so-called pre-salt formations off Angola. They may resemble structures in Brazil that scientists say could hold 124 billion barrels of oil.

Brazil’s state-controlled Petrobras’s Lula field, discovered in 2006 and formerly known as Tupi, was the biggest find in the Americas since Mexico’s Cantarell in 1976. BP, Exxon Mobil and Total are among companies that have been awarded rights to explore the Angolan pre-salt blocks.

London-based Tullow, which isn’t involved in Angola, plans to invest at least $500 million to drill about 40 exploration and appraisal wells this year

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Gazprom looks East:

March 1 (Bloomberg) -- OAO Gazprom, Russia’s gas export monopoly, won for the rights to a Siberian deposit that has enough fuel to meet Chinese demand for two decades.

The gas producer paid 22.3 billion rubles ($777 million) for assets sold by Rusia Petroleum, the operator of the Kovykta gas field, at a bankruptcy auction, said TNK-BP Chief Financial Officer Jonathan Muir. TNK-BP, BP Plc’s Russian oil venture, had sought to sell its 63 percent in Rusia Petroleum to Gazprom in 2007 for as much as $900 million.

Gazprom offered “significantly more” than the 15.1 billion-ruble starting price, said Alexander Smetanin, the external manager of the project. TNK-BP is content with the price, Chief Financial Officer Jonathan Muir said.

“It’s clear the field’s reserves are too big for the local market, the gas will have to be exported, and to China, so it had to be Gazprom,” Alexander Nazarov, a gas analyst at IFC Metropol, said by phone.

Kovykta, which holds more than 1.9 trillion cubic meters of gas, is closer to China, the world’s biggest energy consumer, than other fields targeted by Gazprom for exports. As European demand and prices have slumped, the importance of Asia as a growth market has increased.
http://www.rusiap.ru/

Beat Rosneftegaz
Gazprom beat a unit of OAO Rosneftegaz, the only other bidder, Smetanin said. Rosneftegaz holds the state’s 75 percent stake in oil producer OAO Rosneft and almost 11 percent of Gazprom. Sergei Kupriyanov, a Gazprom spokesman, declined to comment.

The east Siberian field could potentially add 6 percent to 7 percent to Gazprom’s current reserve base at “a record low valuation,” Lev Snykov and Svetlana Grizan, analysts at VTB Capital, said in a research note.

Rusia Petroleum filed for bankruptcy after TNK-BP, the Russian oil venture equally owned by BP and a group of billionaires, demanded repayment for loans to develop the field in May of last year.

TNK-BP had agreed to sell its stake in Kovykta to Gazprom in 2007 for $700 million to $900 million, after years of government threats to revoke the license over missed output targets. TNK-BP said it had nowhere to ship the required amount of gas as Gazprom, whose export monopoly was enshrined in law in 2006, blocked its plans to supply Asian markets.

The deal foundered in price disputes, and Gazprom said it wouldn’t need Kovykta for either exports or domestic use.

TNK-BP had $675 million on its balance sheet for Kovykta, Muir said when asked how much had been spent on the field.

License Application
Gazprom, as the winner of the bankrupt company’s assets, will need to apply to the Federal Subsoil Agency, to re-register the license for the field, a spokeswoman at the Natural Resources Ministry said. She declined to be identified in line with the ministry’s policy.

Gazprom aims to sign a contract with China National Petroleum Corp. by July and start its first supplies to the Asian country in 2015. Failures to agree on gas prices have held up the contract, and construction of a pipeline, for years.

Russia plans to ship some 30 billion cubic meters of gas to China by pipeline from western Siberia, with another 38 billion to 40 billion from eastern Siberia. The total would be nearly as much as China’s gas consumption in 2009, according to BP statistics.

Russia can provide China with all the gas that it needs, Deputy Prime Minister Igor Sechin said in September.

“Contracts with China could be around the corner,” VTB Capital’s Snykov and Grizan said. “Kovykta is located alongside the eastern route and we see it as potentially a major source of gas for supplies to China.”

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March 3 (Bloomberg) -- Total SA, Europe’s third-biggest oil company, agreed to buy 12 percent of OAO Novatek and join the Yamal LNG project to snap up reserves as international energy producers rush to explore Russia’s Arctic resources.

“It is a good deal that has great potential,” Prime Minister Vladimir Putin said at his residence near Moscow late yesterday after the heads of Total and Novatek signed accords.

Total is paying about $4 billion for the Novatek stake, said Chief Executive Officer Christophe de Margerie. The French explorer plans to raise its holding to 19.4 percent within three years, according to a statement.

Global oil producers are looking to Russia to boost reserves amid unrest in northern Africa and the Middle East. Russia, the world’s biggest energy producer, needs foreign expertise to develop projects in harsh, remote areas to maintain output and wants to boost liquefied natural gas output to expand in growing Asian markets and compete in Europe.

Novatek shares climbed as much as 5.9 percent to 389.97 rubles, before erasing gains to trade down 0.5 percent at 366.68 rubles at 2:53 p.m. in Moscow. Total rose as much as 2 percent to 44.22 euros in Paris.

Novatek gained more than 30 percent in the previous three months, raising the value of the stake to $4.7 billion based on yesterday’s close. That is more than the company’s market value in 2004 when Total made a failed bid to buy 25 percent.

Safe Russia
Total will gain access to equity production of 120,000 barrels of oil equivalent a day and about 1 billion barrels of proved and probable reserves, and appoint a director to Novatek’s board, the company said in a statement.

“Russia is today the go-to place for energy deals,” Chris Weafer, chief strategist at UralSib Financial Corp., said in a note today. “It has the resource base and is open for business with clearer investment rules.”

The recent upheavals in oil and gas producing countries show the need to be in Russia, de Margerie said yesterday in a meeting with President Dmitry Medvedev, according to a Russian transcript. Russia has safer conditions for investment, he said.

Putin in January praised a planned strategic alliance between BP Plc and state-run OAO Rosneft, Russia’s largest oil producer, to swap shares and explore Arctic offshore resources. TNK-BP, BP’s oil venture with a group of billionaires, is seeking to replace the U.K. company in that deal.

Major Deals
The Russian prime minister, who approves major energy deals in the country, pledged “good administrative support” for Total at a meeting with de Margerie in June.

Total will gain 20 percent of the Novatek-led Yamal LNG project, according to yesterday’s agreement. The companies aim to complete the deal in the first half, Total said.

“It is great that Total was picked,” said Alexander Nazarov, an oil and gas analyst at IFC Metropol in Moscow. “Novatek has raised its chances of implementing the project.”

Total is also working with OAO Gazprom, Russia’s gas export monopoly, to develop the Shtokman field. De Margerie in June urged Putin to keep the Arctic project on track. Delays have put its first gas in 2016 and LNG in 2017. Shtokman may start in 2018, said Pyotr Sadovnik, deputy head of the subsoil resources agency, last month.

Shtokman and Yamal won’t conflict, de Margerie said.

Main Partner
Yamal LNG aims to start producing LNG, which is gas chilled to a liquid for transport by tanker, in 2016. The project needs $20 billion of investment, and may reach output of 15 million metric tons a year in 2018, according to the documents.

Novatek, which will hold 51 percent of the project, plans to select other participants “soon,” keeping Total as the main partner, billionaire CEO Leonid Mikhelson said.

Total is buying the stock from Mikhelson, 55, and Gennady Timchenko, co-founder of energy trader Gunvor International BV. Mikhelson held 27.2 percent of Novatek, while Timchenko’s investment fund, Volga Resources SICAV SIF SA, owned almost 23.5 percent before the sale.

The two men don’t plan to significantly cut their stakes and will exercise an option to buy 9.4 percent of Novatek, Mikhelson said. Those shares used to belong to Gazprom, which now holds about 10 percent of the smaller producer.

The sale may close in April, Total said.

Total’s attempt to buy 25 percent in Novatek for $900 million failed in 2005 as the Tarko-Sale, Russia-based producer sought a higher price and decided to sell shares to the public.

“Total’s acquisition of a significant equity position in Novatek puts the independent Russian producer even more firmly on the map,” Cliff Kupchan, an analyst at Eurasia Group, said by e-mail.

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French energy giant Total SA is to buy 12% of Russia's biggest independent natural gas producer Novatek and become its core partner in the Yamal liquefied natural gas project in the Russian Arctic, in a deal worth $4 billion, Novatek's chief executive Leonid Mikhelson said on Thursday.

Novatek stock on the MICEX stock exchange rose over 4% at the opening of trade on Thursday following the announcement of the deal.

Total and Novatek signed a memorandum of intent on the deal late on March 2. Total will buy 12% of Novatek and plans to acquire another 7.4% within the next three years, and will take a 20% stake in Novatek's LNG project.

"Total will be a majority shareholder (of the Yamal LNG project)," Mikhelson said.

Overall investment in the Yamal LNG project is estimated at $20 billion, Novatek said in a statement.

Mikhelson confirmed that Novatek planned to select other participants in 2011, keeping Total as the main partner.

"I think we'll have several (partners)," he added.

Novatek will retain control of the Yamal project because it intends to exercise an option for the buyback of 23.9% of the company's shares after selling 20% of its stock in the Yamal project to Total.

Varix Enterprises Ltd., a Cyprus-based company controlled by Gazprombank, owns a 25.1% in Yamal LNG, while another 23.9% stake is owned by Cypriot Innecto Ventures Ltd., controlled by Russian businessman Gennady Timchenko and his partner Pyotr Kolbin. Timchenko is also one of Novatek's co-owners, holding a 23.49% stake.

The companies plan to develop the giant South Tambei gas field on the Yamal Peninsula. The field has Category C1+C2 reserves of 1.26 trillion cubic metres of natural gas and 51.6 million metric tonnes of gas condensate.

MOSCOW, March 3 (RIA Novosti)

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March 3 (Bloomberg) -- Statoil ASA and Eni SpA are among companies with plans to drill a record number of wells in Norway’s far north this year to help the world’s second-largest gas exporter to sustain output. So far, they’ve struck out.

All four wells drilled in the Barents and Norwegian seas this year have failed to find oil or gas, adding to two dry wells in the North Sea, the biggest number of failures to start the year since the country’s oil era began in 1966, according to government data. Oil companies plan as many as 22 wells in Norway’s Arctic this year, up from 12 last year.

Helge Lund, chief executive officer at state-controlled oil company Statoil, says the industry has been unable to “crack the code” of the Barents Sea, off Scandinavia’s northern tip. Norway, where energy production makes up about 25 percent of the economy, is pushing into the Arctic and relying more on gas because oil output has slumped 50 percent since peaking in 2000.

The Barents Sea “is extremely important for Norwegian oil production given that the mature areas are in extreme decline,” said Torbjoern Kjus, an analyst at DnB NOR ASA in Oslo. “Every dry well is a setback, but we have to keep trying where there might be resources left if we’re going to maintain Norwegian production going for as long as possible.”

Resources Cut
Explorers drilled 16 dry wells off Norway last year, part of the reason the Petroleum Directorate cut its estimate for undiscovered gas by 31 percent, or by 570 billion cubic meters. That’s equal to almost six years of production for Norway.

Norway estimates the Norwegian Sea holds 455 billion cubic meters in undiscovered gas and the Barents Sea 520 billion cubic meters. Total undiscovered gas resources may be 1.26 trillion cubic meters, the directorate said in January, down from an estimate of 1.82 trillion cubic meters last year. The country had proven gas reserves of 2 trillion cubic meters in 2009.

“It’s disappointing that we haven’t seen any results yet,” said Thina Saltvedt, an analyst at Nordea Markets in Oslo. “Norway is important for the oil market because we export a lot of the oil we produce and not least because we have a stable political situation.”

Statoil last week started work on its last well for the year in the Barents Sea, in the Skrugard area. The other four wells will be drilled by Total SA, GDF Suez SA, Dong Energy A/S and Lundin Petroleum AB. Eni also postponed two wells in the Salina and Boenna prospects until next year because of a rig delay, said Andreas Wulff, a company spokesman, by phone.

Heilo Prospect
GDF will begin drilling at the Heilo prospect in August or September with the Aker Barents rig, which will then move on to work for Dong, GDF spokesman Ulf Rosenberg said. Rocksource ASA, which owns 20 percent in Heilo, estimates the chance of a discovery at more than 50 percent and sees recoverable resources at 200 million barrels of oil equivalents, according to a statement on its website.

The Barents Sea has two developments, Statoil’s Snohvit gas field, and Eni’s Goliat, an oilfield that is scheduled to start pumping in 2013.

“A dry well is disappointing, but every new well is a new possibility,” Ola Anders Skauby, a Statoil spokesman, said by phone this week. “We still believe in the Barents Sea.”

A find at Skrugard would be positive for investments at Snohvit, Skauby said. Statoil and partners including Total, GDF, RWE AG and Hess Corp. are hoping to find more gas to enable a second liquefied natural gas plant at Melkoeya, the onshore production facility near Snohvit. An investment decision is scheduled for 2013.

Challenging Targets
The lack of discoveries is challenging targets to maintain production offshore Norway and imperiling the development of a second gas hub in the Norwegian Sea. Statoil missed production targets last year and has said a goal of keeping output in Norway at current levels until 2020 is “ambitious.”

Producers operating off Norway are investing a record amount in exploration and production this year to make bigger discoveries and prolong output from existing fields. Investments are estimated to climb 13 percent to 141.1 billion kroner ($25 billion) driven by an 11 percent increase in spending on exploration, the country’s statistics agency said today.

Appraisal wells last year around Royal Dutch Shell Plc’s Gro discovery in the Norwegian Sea have indicated resources may be at the lower end of a 10 billion to 100 billion cubic meters estimate. Total, Europe’s third-largest oil company, also reduced the size of its Victoria find in the area after more drilling in 2009.

The Norwegian Sea is also home to Shell’s Ormen Lange, Europe’s third largest gas deposit, where the company announced a dry appraisal well last month. The Petroleum Directorate and the company are assessing the field after estimated reserves at the field were cut by 24 percent last year following two appraisal wells.

Protected Waters
Det Norske Oljeselskap ASA, a Trondheim, Norway-based explorer, on Feb. 28 also reported a dry well in a prospect east of the Ormen Lange field.

Continued failure may increase pressure on the government to open up protected waters off the Lofoten and Vesteraalen islands in the Norwegian Sea. Norway is also targeting areas to the east, after signing a maritime delimitation treaty with Russia in September, settling a four-decade dispute. The treaty needs to be ratified by both parliaments. The waters along the Russian border, as well as the unexplored area around the Jan Mayen Island are described by Norway as carrying the potential to prolong petroleum output. There are no resource estimates.

The government is set to reach a decision this month on whether to start a study of the consequences of exploration off Lofoten and Vesteraalen, where 3.5 billion barrels in oil and gas is estimated to lie.

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America’s combined recoverable oil, natural gas, and coal endowment is the largest on Earth. America’s recoverable resources are far larger than those of Saudi Arabia (3rd), China (4th), and Canada (6th) combined. And that’s not including America’s immense oil shale and methane hydrates deposits.


Here’s what the Congressional Research Service ( "CRS" ) says about America’s tremendous resource base:

Oil

CRS offers a more accurate reflection of America’s substantial oil resources. While America is often depicted as possessing just 2 or 3 percent of the world’s oil - a figure which narrowly relies on America’s proven reserves of just 28 billion barrels - CRS has compiled US government estimates which show that America, the world’s third-largest oil producer, is endowed with 163 billion barrels of recoverable oil. That’s enough oil to maintain America’s current rates of production and replace imports from the Persian Gulf for more than 50 years.

Natural Gas

Further, CRS notes the 2009 assessment from the Potential Gas Committee, which estimates America’s future supply of natural gas is 2,047 trillion cubic feet (TCF) - an increase of more than 25 percent just since the Committee’s 2006 estimate. At today’s rate of use, this is enough natural gas to meet American demand for 90 years.

Coal

The report also shows that America is number one in coal resources, accounting for more than 28 percent of the world’s coal. Russia, China, and India are in a distant 2nd, 3rd, and 5th, respectively. In fact, CRS cites America’s recoverable coal reserves to be 262 billion short tons. For perspective, the US consumes just 1.2 billion short tons of coal per year. And though portions of this resource may not be accessible or economically recoverable today, these estimates could ultimately prove to be conservative. As CRS states: “...U.S. coal resource estimates do not include some potentially massive deposits of coal that exist in northwestern Alaska. These currently inaccessible coal deposits have been estimated to be more than 3,200 billion short tons of coal.”

Oil Shale

While several pilot projects are underway to prove oil shale’s future commercial viability, the Green River Formation located within Colorado, Wyoming, and Utah contains the equivalent of 6 trillion barrels of oil. The Department of Energy estimates that, of this 6 trillion, approximately 1.38 trillion barrels are potentially recoverable. That’s equivalent to more than five times the conventional oil reserves of Saudi Arabia.

Methane Hydrates

Although not yet commercially feasible, methane hydrates, according to the Department of Energy, possess energy content that is “immense ... possibly exceeding the combined energy content of all other known fossil fuels.” While estimates vary significantly, the United States Geological Survey (USGS) recently testified that: “the mean in-place gas hydrate resource for the entire United States is estimated to be 320,000 TCF of gas.” For perspective, if just 3% of this resource can be commercialized in the years ahead, at current rates of consumption, that level of supply would be enough to provide America’s natural gas for more than 400 years.

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March 4 (Bloomberg) -- Gasoline prices are setting records across Europe and exceeding $4 a gallon in California as the rise in crude oil caused by the conflict in Libya punishes companies and consumers.

Households are cutting back on travel, cinema visits and groceries in the U.K., where prices jumped to 130.68 pence a liter ($8.06 a gallon) yesterday, according to research from the Automobile Association, Britain’s largest motoring organization. Prices set records in the Netherlands and Italy today. The current average U.S. gasoline price is near a two-year high at $3.81 a gallon, according to the AAA website.

Crude oil’s rise to as high as $119 in Europe has pushed fuel costs up and put the economic recovery at risk. The impact on consumer prices may push European Central Bank President Jean-Claude Trichet to raise interest rates as soon as next month to discourage higher wages and head off the threat of an inflationary spiral.

“Rising fuel costs are negative because they push inflation up and slow the economy down,” said Philip Shaw, chief economist at Investec Securities in London. “It is essentially energy costs that have resulted in ECB putting its finger on the interest rate trigger.”

Higher fuel prices are pushing up costs for retailers such as Tesco Plc in the U.K. and Wal-Mart Stores Inc. in the U.S. and increasing concern that consumers will pare back spending.

“As we think about rising prices of gasoline, clothing, food, etc., we are concerned with the impact on the consumer confidence and spending,” Robert Hull, chief financial officer of Lowe’s Cos., the second-biggest U.S. home-improvement retailer, said on Feb. 23.

Armed Rebellion
Oil has gained 23 percent in London this year as the armed rebellion in oil producer Libya spurs prices. The jump in prices to $147 a barrel in 2008 exacerbated the recession following the global financial crisis.

Brent futures, the benchmark for Europe, traded at $116.20 a barrel today. The futures contract reached a two-year high of $119.79 on Feb. 24. In the U.S., West Texas Intermediate futures traded at $103.03 a barrel today, close to this year’s high of $103.41 also reached on Feb. 24.

In contrast to Trichet, Federal Reserve Chairman Ben S. Bernanke suggested the U.S. is unlikely to raise interest rates soon, saying this week that the surge in oil and other commodity prices probably won’t cause a permanent increase in broader inflation.

“The economy’s recovery is not firmly established, and we think monetary policy needs to be supportive,” Bernanke said. Trichet, by contrast, said yesterday that “strong vigilance is warranted” and that an increase from record low interest rates is “possible” in April.

In Germany
In Italy, gasoline prices reached 1.544 euros a liter and diesel climbed to 1.438 euros a liter ($8.17 a gallon), according to a chart published by web energy daily Quotidiano Energia. Gasoline prices in the Netherlands reached a record 1.697 euro a liter from 1.692 euro in June 2008, according to Paul van Selms, head of UnitedConsumers, a lobby group for consumers in the Netherlands.

The average price for super-grade gasoline in Germany, Europe’s largest economy, was 1.55 euros per liter today, close to the 1.58 euro record from 2008.

Drivers in California are paying more than $4 a gallon for premium grade, according to AAA.

‘Strong Echoes’
“If you go out into the country, people are down on their knees asking for lower prices,” said Luke Bosdet, a spokesman for the AA in the U.K. “The echoes of 2008 are very strong. The only thing we can hope for is an economic recovery strong enough to push up wages to absorb the costs. Until then, the lower- income driver has to leave their car in the garage.”

Oil companies such as BP Plc and Royal Dutch Shell Plc aren’t reaping a windfall from the surge in fuel prices because of weak refining margins and the risk higher costs will reduce demand, said David Hart, an analyst at Westhouse Securities Ltd.

“The price at the pump grabs headlines, but it’s not where oil companies make money,” said Hart. “It’s crude prices. But energy costs are detrimental to demand at this level.”

The price of oil is nearing the point at which it will start to hurt the world economy, said Adam Sieminski, chief energy economist at Deutsche Bank AG. An increase in the oil price to $150 a barrel would reduce global economic growth by 2.5 percentage points, returning it to recessionary territory, and there’s a 10 percent to 15 percent probability of that price being reached, he said in a report published yesterday.

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* Approval puts JV officially in China's 2011-2015 plan

* One of the few greenfield plants in the next 5 yrs

* Kuwait aims to eventually export 500,000 bpd crude to China (Adds background)

BEIJING, March 7 (Reuters) - China's top economic planning body, the National Development & Reform Commission granted final approval for the $9 billion refinery, petrochemical joint venture between Sinopec and Kuwait, two sources told Reuters.

The venture, including a 300,000 barrel-per-day refinery and a 1 million tonne-per-year ethylene complex, would make Kuwait the second OPEC nation after Saudi Arabia to have a major refining presence in the world's fastest growing major oil market.

The project, to be built in the southern coastal city of Zhanjiang and potentially one of the country's largest foreign investments, would be 50-50 owned by Sinopec Group, parent of top Asian refiner Sinopec Corp (0386.HK: Quote, Profile, Research, Stock Buzz).

But Kuwait is likely to hunt for a second or a third foreign partner for joint funding, industry officials have said.

"NDRC gave the approval last week," said one industry official with direct knowledge of the government's decision, adding that the announcement should be imminent.

China, the world's second-largest oil user after the United States, has been boosting construction in its refining sector over the last two decades to feed a robust economy now the world's second-largest.

But the industry, long dominated by oil duopoly PetroChina (0857.HK: Quote, Profile, Research, Stock Buzz) and Sinopec, increasingly favours expanding the business on its own, leaving scope only for partners equipped with resources such as OPEC exporters Kuwait and Venezuela.

Sinopec officials were not immediately available for comment. Kuwait Petroleum International's Beijing representative office also declined to comment.

Kuwait, the world's seventh-largest crude exporter, aims to eventually export 500,000 bpd of crude to China, versus last year's sales to China at just under 200,000 bpd.

The joint venture is one of the few greenfield refineries China plans to add in the five-year plan from 2011 to 2015.

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March 9 (Bloomberg) -- Exxon Mobil Corp., the world’s biggest company by market value, plans to spend $100 million a day for the next half decade on capital projects such as new oil wells and natural-gas plants.

Exxon has budgeted $34 billion for capital projects this year, a 5.6 percent increase from 2010, Chief Executive Officer Rex Tillerson said today at an analyst meeting in New York. The budget will range from $33 billion to $37 billion through 2015, according to a slide presentation prepared for the meeting.

Exxon expects to boost oil and gas production by 3 percent to 4 percent this year, the company said. Eleven new projects are scheduled to begin pumping oil or gas between now and 2013.

Exxon is spending more as the company expands its search for untapped oil and gas fields, and upgrades refining and chemical plants in Asia to supply the world’s fastest-growing energy markets. Production rose 13 percent last year, the largest annual increase since Exxon’s 1999 acquisition of Mobil Corp. Oil prices reached a 29-month high this week amid unrest in the Middle East.

“We are executing a large inventory of high-quality projects,” Tillerson said today. “Actual spending in a given year will vary depending on the pace and the progress of each project.”

About 80 percent of production from new wells between now and 2016 will consist of crude oil, the company said. Exxon’s exploration prospects range from Madagascar to Greenland to Vietnam.

Outpacing Mexico’s Reserves
The company replaced 209 percent of the oil and gas pumped from its wells last year, partly through the $34.9 billion acquisition of Fort Worth, Texas-based XTO Energy Inc. [ This is very much an example of "accentuating the positive spin" since the reserve replacement was (1) largely attributable to buying reserves and (2) was attributable to natural gas— NOT petroleum ] Exxon had proved reserves equivalent to 24.8 billion barrels at the end of December, which exceeded the crude reserves of nations such as Mexico or Algeria...

...Exxon is awaiting U.S. regulatory approval to drill two wells at its deep-water Hadrian discovery in the Gulf of Mexico, the company said. Work on Hadrian was interrupted after the fatal explosion at BP Plc’s Macondo well in April prompted the government to halt all exploration drilling in waters deeper than 500 feet (152 meters).

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March 10 (Bloomberg) -- OAO Novatek will challenge OAO Gazprom’s dominance in foreign markets after agreeing with Total SA to build an Arctic gas-export plant.

Novatek’s $20 billion development in the Yamal region is slated to be Russia’s largest plant for shipboard gas within seven years, starting earlier than Gazprom’s flagship Shtokman project. Yamal LNG got a boost last week when France’s Total agreed to take a 20 percent holding as well as to buy a $4 billion stake in Novatek.

Prime Minister Vladimir Putin, who wants Russia to export 10 percent of its gas as LNG by 2020, blessed Novatek’s plans at a ceremony near Moscow last week, calling it a “good and large- scale work.” Gazprom has delayed decisions on expanding Russia’s only LNG facility, the Sakhalin-2 project with Royal Dutch Shell Plc, and developing the Shtokman field on the Barents Sea.

“Novatek’s project is now Russia’s primary LNG project outside of Sakhalin,” said Chris Weafer, chief strategist at UralSib Financial Corp. “Total’s strategic partnership with Novatek is an acknowledgement that Shtokman is on a much slower development path with an unpredictable future.”

Total has criticized delays at Shtokman, in which it has a 25 percent stake. In June, Chief Executive Officer Christophe de Margerie urged Putin to keep the project on track and said Novatek CEO Leonid Mikhelson pledged faster progress on Yamal LNG.

Tax Breaks
Putin has pledged tax breaks for Novatek’s project. The proposal would exempt the first 250 billion cubic meters of natural gas and 20 million metric tons of condensate from the extraction tax. Gazprom hasn’t yet secured tax holidays for Shtokman.

The French explorer sees no conflict between the two projects and is trying to handle them in the best way possible, de Margerie said March 2 after the signing ceremony.

All of Yamal LNG’s planned output will “easily” find demand as it targets Europe, Asia and North America, Mikhelson said. Yamal LNG plans to produce 5 million metric tons of fuel a year for export in 2016, ramping up to a total 15 million tons a year by 2018 from three production units, or trains, according to documents distributed to reporters March 2.

Novatek has secured an agreement from Gazprom, which holds a 10 percent stake in the smaller gas producer, to export LNG from Yamal and sell the fuel as an agent.

‘Strong Foothold’
“The government has a much better chance of establishing a strong foothold in the global LNG business with Novatek’s LNG project than waiting for Shtokman,” Weafer said. Shtokman is located about 600 kilometers (373 miles) from Russia’s Barents Sea coast in stormy, iceberg-ridden waters.

Gazprom is likely to concentrate on pipeline gas to Europe and building a link to China, Weafer said.

Novatek used nuclear icebreakers to send a cargo of gas condensate from the Arctic to China last year as it weighs the costs of Asian exports. Novatek plans another trial run this year, Mikhelson said.

“There is an emerging possibility that Novatek could become a de facto competitor to Gazprom - if a small one which plays only in LNG,” Cliff Kupchan, an analyst at Eurasia Group, said in a note.

Gazprom, Total and their third partner, Statoil ASA, are considering an LNG plant with an annual capacity of 7.5 million tons for the Shtokman field. The start of gas output has been delayed by three years to 2016, with LNG a year later. Russia may push the project back further, to 2018, Pyotr Sadovnik, deputy head of the subsoil resources, said on Feb. 17.

Japanese Partners
The gas producer is also considering building an LNG plant in Vladivostok with Japanese partners.

Shtokman had planned to ship as much as 90 percent of the LNG it would produce to North America, where demand for imported gas fell last year during the financial crisis and as domestic shale-gas output surged.

Shtokman may postpone an investment decision on initial gas output beyond a planned March deadline, while seeking tax incentives, Andre Goffart, vice president of Shtokman Development AG, said on Feb. 17.

“Gazprom will probably shift its priority to the on-shore Yamal gas deposits,” Weafer said.

Gazprom plans to produce at least 310 billion cubic meters a year on the Yamal Peninsula in 2030 and build a pipeline with capacity of more than 300 billion cubic meters a year, according to its website. That compares with Russia’s output of 650 billion cubic meters last year. The largest field, Bovanenkovo, will cost about 600 billion rubles ($21 billion) to develop, the company has said.

Gazprom is likely to bring foreign partners, such as Shell, into the Yamal region as Russia makes Arctic resources a priority, Weafer said.

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America’s combined recoverable oil, natural gas, and coal endowment is the largest on Earth. America’s recoverable resources are far larger than those of Saudi Arabia (3rd), China (4th), and Canada (6th) combined. And that’s not including America’s immense oil shale and methane hydrates deposits.


Here’s what the Congressional Research Service ( "CRS" ) says about America’s tremendous resource base:

Oil

CRS offers a more accurate reflection of America’s substantial oil resources. While America is often depicted as possessing just 2 or 3 percent of the world’s oil - a figure which narrowly relies on America’s proven reserves of just 28 billion barrels - CRS has compiled US government estimates which show that America, the world’s third-largest oil producer, is endowed with 163 billion barrels of recoverable oil. That’s enough oil to maintain America’s current rates of production and replace imports from the Persian Gulf for more than 50 years.

Natural Gas

Further, CRS notes the 2009 assessment from the Potential Gas Committee, which estimates America’s future supply of natural gas is 2,047 trillion cubic feet (TCF) - an increase of more than 25 percent just since the Committee’s 2006 estimate. At today’s rate of use, this is enough natural gas to meet American demand for 90 years.

Coal

The report also shows that America is number one in coal resources, accounting for more than 28 percent of the world’s coal. Russia, China, and India are in a distant 2nd, 3rd, and 5th, respectively. In fact, CRS cites America’s recoverable coal reserves to be 262 billion short tons. For perspective, the US consumes just 1.2 billion short tons of coal per year. And though portions of this resource may not be accessible or economically recoverable today, these estimates could ultimately prove to be conservative. As CRS states: “...U.S. coal resource estimates do not include some potentially massive deposits of coal that exist in northwestern Alaska. These currently inaccessible coal deposits have been estimated to be more than 3,200 billion short tons of coal.”

Oil Shale

While several pilot projects are underway to prove oil shale’s future commercial viability, the Green River Formation located within Colorado, Wyoming, and Utah contains the equivalent of 6 trillion barrels of oil. The Department of Energy estimates that, of this 6 trillion, approximately 1.38 trillion barrels are potentially recoverable. That’s equivalent to more than five times the conventional oil reserves of Saudi Arabia.

Methane Hydrates

Although not yet commercially feasible, methane hydrates, according to the Department of Energy, possess energy content that is “immense ... possibly exceeding the combined energy content of all other known fossil fuels.” While estimates vary significantly, the United States Geological Survey (USGS) recently testified that: “the mean in-place gas hydrate resource for the entire United States is estimated to be 320,000 TCF of gas.” For perspective, if just 3% of this resource can be commercialized in the years ahead, at current rates of consumption, that level of supply would be enough to provide America’s natural gas for more than 400 years.

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The unfolding turmoil in Libya has amplified concerns about the reliability of global energy supplies in an era of political uncertainty. Is oil at $200 per barrel inescapable? Is this the beginning of the end so vigorously underscored by peak oil enthusiasts for the last several decades? The short answer is clearly "No."

Yet the question remains: What will happen to the price of crude? This, in turn, necessitates an appreciation of the "anxiety" component in current and future prices. The anxiety premium may range from $10 to $30 given current events in Libya and their spillover effects.

The good news is that such a premium is not sustainable in the long run. Prices will eventually come down due to global excess capacity—estimated at three million to five million barrels of oil per day—and even more so due to migration of demand from oil to natural gas by electric utilities and industrial markets. Natural gas holds more than a 3-to-1 price advantage over oil on an equivalent unit energy basis in the U.S. So $200 crude is unlikely given market fundamentals.

In the context of global liquids production, the civil strife in Libya represents a minor disruption (less than 2% of the total, approximately 85 million barrels of oil per day). Nor is there any evidence to suggest that even a protracted scenario of instability will result in a sustained reduction of crude supplies. Iraqi oil production dropped by 30% at the start of the second Iraq war in 2003, and then it quickly bounced back to the prewar level of two million barrels of oil per day. Currently, Iraqi oil production stands at 2.6 million barrels of oil per day, with much higher levels projected during this decade.

Fossil fuels make up about 85% of total U.S. energy demand, which is estimated at about 45 million to 50 million barrels of oil equivalent per day. Energy imports, mainly crude oil, account for 20% of the total U.S. energy requirements. This level of imports is a huge burden on the balance of payments, hence the U.S. dollar.

What is less widely recognized is the overall inefficiency of energy utilization. According to a 2007 study by National Petroleum Council, at the request of the U.S. Department of Energy, approximately 61% of energy produced is lost due to factors such as poor insulation, gas-guzzling vehicles or suboptimal power plants. On average, only one out of three reservoir barrels is recovered, which translates to an overall efficiency of only 13% for oil that is converted to a usable form. Improving energy efficiency should be a top priority, not just in our surface usage but also at the point of extraction.

Technology is reshaping every facet of our lives. The energy world is no different. This includes the resurgence of U.S. liquid production in recent years (5.5 million barrels of oil per day and trending upward), as well as conventional gas production's six-fold increase over the last two decades (to approximately 32 billion standard cubic feet of gas per day in 2010, nearly equaling U.S. liquid production). Both are attributable to recent innovations, such as highly sophisticated wells that can reach thousands of feet underground with GPS precision.

The planet is endowed with plentiful sources of natural gas and oil, conventional and unconventional. Some estimates place global unconventional gas resources at about 33,000 trillion cubic feet, or about five times the amount of proven reserves at the end of 2009. The outlook for liquids is no less promising. At current rates of global consumption, there are sufficient oil and gas supplies to last well into the next century.

What's missing is a coherent U.S. energy policy. At best, the Obama administration's approach to U.S. domestic oil and gas production can be characterized as a strategy of ambivalence, an uneasy equilibrium between desire to lessen the role of fossil fuels and the reality of their necessity in a functioning U.S. economy. Last year's Deepwater Horizon tragedy in the Gulf tilted the current administration's policies to an even more punitive posture vis-a-vis domestic energy production.

As the French philosopher Antoine de Saint-Exupéry wisely observed, "A goal without a plan is just a wish." Unfortunately for the U.S., there is not even a wish. The time to rethink and redesign our entire energy strategy is now.

The Obama administration must seriously ponder the following questions, because they relate directly to what the president likes to call "winning the future." What will be the make-up of the energy-supply pie, and how can we dramatically increase, even double, our energy efficiency? What exactly are our carbon emission goals? And how do we go from where we are today—importing about 20% of our daily energy supply—to where we want to be in 2026, perhaps even an energy exporter?

We've already entered a new energy era that is dramatically more competitive, diverse and high-tech than the past. The global consumer is king. The future energy picture for the U.S. or the planet is not constrained by the availability of supplies, either fossil or non-fossil, but by efficiency gains in generation and consumption.

This will require real leadership and the clear articulation of energy goals, costs and priorities. Ambiguity will not serve the best interests of future generations. The U.S. does not have an energy problem. It has an energy strategy problem.

Mr. Saleri, president and CEO of Quantum Reservoir Impact in Houston, was formerly head of reservoir management for Saudi Aramco.

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March 18 (Bloomberg) -- Muammar Qaddafi may expel western energy companies from Libya should he snuff out the month-old armed rebellion against his regime, draining money from the economy and hurting exporters such as Eni SpA and Repsol YPF SA.

Qaddafi, 68, took control of Ras Lanuf and Brega oil facilities and moved near Benghazi, the center of the rebellion, as the United Nations Security Council voted to establish a no- fly zone over Libya.

His threat to bring China into the energy business that Italy has enjoyed for five decades may reshape the economic map of the country holding Africa’s biggest oil reserves.

“If Qaddafi wins, Libya will look to the east for support,” said Shadi Hamid, director of research at the Brookings Institution’s Doha Center in Qatar, in a telephone interview. “Western companies won’t get back in any time soon and won’t be able to invest. The Libyan economy will be devastated for years.”

Even without outright expropriation, a Qaddafi victory may lead to Western sanctions that would roll back almost 10 years of European and U.S. investment in Libya. The 2004 reprieve from two decades of trade restrictions allowed companies such as BP Plc and Royal Dutch Shell Plc to invest in Libyan fields, boosting output to about 1.6 million barrels a day, most of which was sold to Europe.

Libya’s oil output slumped to a “trickle” by last week, according to the International Energy Agency. The conflict, which has left hundreds dead, has helped push up Brent crude prices by about 20 percent this year. Libya’s crude exports may be halted for “many months” because of damage to oil facilities and international sanctions, the IEA said this week.

Libyan Crude
Qaddafi threatened to replace western oil firms with companies from India and China in a March 2 speech and more than 10 days later discussed possible investments with the ambassadors of the two countries and Russia, state-run television reported.

Italian Foreign Minister Franco Frattini told Italian lawmakers on March 16 that “China’s reasoning is an economic one” when it comes to Libya.

Rome-based Eni, Italy’s largest oil company, France’s Total SA and Spain’s Repsol are among foreign companies that have evacuated their staff and scaled down production in Libya. More than 20 percent of the oil imported by Austria, Ireland and Italy is Libyan crude, the IEA said.

“I don’t consider relations with Libya compromised,” Eni Chief Executive Officer Paolo Scaroni told investors in London on March 16. “We maintain relations with the national oil company, which is our natural counterpart.”

Local Population
He said he asked U.S. Secretary of State Hillary Clinton, European Union Foreign Policy Chief Catherine Ashton and Frattini to ensure that gas production for the local population be excluded from any ultimate sanctions against Libya.

Libya will retain all contracts with Eni and honor existing contracts with foreign companies, Shokri Ghanem, chairman of National Oil Corp., told Italian news agency Ansa yesterday.

“We have an excellent relationship with Eni, a company that’s been working here since the 1950s and is among the most important oil producers in Libya,” he was quoted as saying.

Eni’s shares have fallen almost 10 percent since mid- February, when anti-Qaddafi protests erupted, inspired by popular revolts that led to the ouster of Tunisian President Zine El Abidine Ben Ali and Egyptian leader Hosni Mubarak this year. Repsol shares have declined 7 percent.

Security Council
United Nations Security Council veto-wielding members China and Russia have been less critical of Qaddafi than France and the U.S., whose leaders openly called on the Libyan leader to go. Chinese Foreign Ministry spokeswoman Jiang Yu told reporters yesterday that “the sovereignty and territorial integrity of Libya should be respected.”

“China is far less interested in the strategic argument and much more concerned with its economic interests in Africa,” Frattini told a parliamentary committee in Rome on March 16. “Out of this situation, great doors open for China.”

It may not be that simple, said Elizabeth Cheng, Hong Kong- based editor of China Hand, a publication of the Economist Intelligence Unit, by telephone.

“It’s a complicated issue,” she said. “I don’t think Chinese companies would be expected to make a reckless decision.” Oil companies would have to consider their relations with western companies and security in Libya, as well as Qaddafi’s ability to maintain power, she said.

Risk Management
China already has a presence in Libya. China National Petroleum Corp., the country’s biggest oil and gas producer, has evacuated all its 392 staff in Libya, the company said on Feb. 28. Risk management is being strengthened, said Zhou Jiping, who is president of PetroChina Co., the country’s biggest energy producer, and vice president of China National Petroleum, the parent company, at a Hong Kong earnings press conference yesterday.

“We will strengthen our cooperation with major resource countries and big international oil companies to share the risks,” Zhou said.

Present Libya operations are mostly engineering, he said without specifying which company he meant.

Qaddafi has kicked out foreign companies before. Three years after he came to power in a 1969 coup, Qaddafi began seizing oil fields, giving the state-owned National Oil Corp. at least 51 percent of all concessions, according to the 2010 Arab Oil and Gas Report.

A decade later, U.S. President Ronald Reagan, who called Qaddafi “the mad dog of the Middle East,” banned the import of Libyan oil and a number of exports to Libya. The U.S. bombed Tripoli in 1986 in retaliation for an attack on a Berlin discotheque that killed two U.S. servicemen.

Lockerbie Bombing
Libya came under U.S. and UN sanctions in the 1980s and 1990s over accusations of planning terrorist attacks, including the 1988 bombing of the Pan American World Airways Boeing Co. 747 over Lockerbie that killed 270 people.

The turnaround in relations with the West started in 1999, when he allowed the extradition of two Libyan suspects in the Lockerbie bombing. Qaddafi abandoned a nuclear-arms development effort after 2002 while also pledging to destroy a chemical weapons stockpile and renouncing terrorism.

The current conflict “sets everything back many years,” said Jonathan Stern, director of gas research at the Oxford Institute of Energy Studies. “There’s always a risk of expropriation. But the key thing is that Libyans struggled for 25 years under sanctions, and the lesson was that they can’t do much without outside help.”

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...Tepco will boost power supply by 20 percent before the end of April by restarting oil-fired plants to make up for the electricity shortage caused by the shutdown of the Fukushima plant, the Nikkei newspaper reported...

more...

http://noir.bloomberg.com/apps/news?pid=20601087&sid=aoVX9f15VYdA&pos=8

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March 19 (Bloomberg) -- Libya’s oil production fell to less than 400,000 barrels a day after foreign companies pulled out their staff, the chairman of the country’s state-run National Oil Corp., Shokri Ghanem, said in a televised media conference from Tripoli...

...Daily supply from Africa’s third-largest producer dropped by an estimated 195,000 barrels to 1.385 million barrels in February, from 1.58 million barrels the previous month, before slumping to a “trickle” by March 11...

more...

http://noir.bloomberg.com/apps/news?pid=20601087&sid=axMOrSuOznnw&pos=6

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Spot prices: WTI v. Henry Hub

JUNEAU, Alaska (AP) -- An Alaska plant plans to send its last scheduled shipment of liquefied natural gas to Japan this month.

The Kenai plant, owned by ConocoPhillips and Marathon Oil Corp., is closing after more than 40 years in operation. The companies, in announcing the decision last month, cited market conditions. Exports from the plant began in 1969 and all exported liquefied natural gas, or LNG, went to Japan...

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The Hague, March 23rd /PRNewswire/ — The world's largest plant to turn natural gas into cleaner-burning fuels and lubricants took a major step closer to production today when gas began flowing from a giant offshore field.

Pearl GTL will process around 3 billion barrels of oil equivalent over its lifetime from the world's largest single gas field, the North Field in the Arabian Gulf. The field stretches from Qatar’s coast and contains more than 900 trillion cubic feet of gas, equivalent to 150 billion barrels of oil, or over 10% of worldwide gas resources.*

The gas-to-liquids (GTL) plant — a joint development by Qatar Petroleum and Shell – will add almost 8% to Shell’s production worldwide — making it the company’s main engine for growth for 2012. It has a capacity of 260,000 barrels oil equivalent a day and is expected to ship its first product in 2011 and reach full production in 2012.

"We’re on the verge of starting up a project that will be a foundation for Shell’s future growth for decades to come," says Shell’s Country Chairman in Qatar, Andy Brown. "For Qatar it means another way to generate revenues from gas reserves, in addition to selling pipeline gas or liquefied natural gas. It diversifies the country’s revenue streams and provides long-term income."

The plant will produce cleaner-burning diesel and aviation fuel, oils for advanced lubricants, naphtha used to make plastics and paraffin for detergents. It will make enough diesel to fill over 160,000 cars a day and enough synthetic oil each year to make lubricants for more than 225 million cars. The products will reach customers in every major energy market through Shell’s global retail network.

In bringing Pearl to production, Shell engineers have built on more than 30 years of experience in gas-to-liquids technology. We built the world’s first commercial-scale GTL plant in Bintulu, Malaysia, in 1993. Pearl’s output of GTL products will be 10 times greater than Bintulu’s.

Safety Record

Building Shell’s biggest engineering project to date in Ras Laffan, a vast industrial zone on Qatar’s coast some 90 kilometres north of Doha, was a major feat. At the peak of construction, it involved more than 52,000 workers from over 50 nations.

Despite the massive number of workers involved and the complexity of Pearl’s construction, a strong safety culture helped Qatar and Shell achieve a record-breaking 77 million hours worked onshore without injuries leading to time off work.

Preparing for a Smooth Start-up

Getting the huge plant into full operation will take a series of carefully executed system start-ups. Pearl GTL’s control room — the nerve centre of one of the largest and most sophisticated plants ever built in the energy industry — has powered up.

The first turbines and auxiliary steam systems have begun to generate steam and electricity to power the plant. The first two oxygen separation units are up and running.

Drilling Record

Sixty kilometres offshore, natural gas from the North Field — discovered by Shell in 1971 — is now flowing from to two platforms standing in water up to 40 metres deep to feed Pearl GTL. Eleven wells were drilled for each platform in record drilling times for the field.

Two underwater 76–centimetre (30-inch) diameter pipelines are carrying the natural gas to a gas separation plant onshore that extracts natural gas liquids: ethane for industrial processes, liquefied petroleum gas (LPG) for domestic heating and cooking and condensates as a feedstock for refineries. The separation process also removes contaminants like metals and sulphur. The sulphur is turned into pellets and shipped to the nearest market to make hydrosulphuric acid, fertiliser or other valuable products.

Turning Gas into Liquid Fuel

The pure gas, or methane, that remains will then flow to the GTL section of the plant, where it will be converted in a three-stage process into a range of gas-to-liquids products using Shell proprietary technology.

Finally, the liquid hydrocarbon wax is upgraded using specially developed technology involving new catalysts into the range of products. It takes some 2,000 steps to prepare all GTL systems for production.

In Qatar, summer temperatures exceed 40°C (104°F) and rainfall is slight. Conserving water is critical. Pearl was designed to be self-sufficient in its use of water.

Pearl, the largest investment by Shell in any single project, is a fully integrated project spanning production from an offshore gas field to finished marketable products. Shell is funding 100% of the development costs under a profit- sharing agreement with the state of Qatar.

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*source: Oil and Gas Journal

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BP PLC came within 1.4 inches or less of preventing the worst offshore oil spill in U.S. history, say engineers studying the safety device that failed in last year's Gulf of Mexico disaster.

The device, known as a blowout preventer, was a massive set of valves that sat on the sea floor nearly a mile beneath the Deepwater Horizon drilling rig, which floated on the surface. It was equipped with powerful shears designed to cut through pipe and seal off the well in an emergency. Why the device failed has been one of the central mysteries of last year's disaster.

In a report released Wednesday, engineers hired by U.S. investigators say they have solved it: The force of the blowout bent the drill pipe, knocking it off-center and jamming the shears. Rather than seal the well, the blades got stuck 1.4 inches or less apart, leaving plenty of space for 4.9 million barrels of oil to leak out.

The investigators concluded the blowout preventer failed as a result of a design flaw, not because of misuse by BP or any of the other companies involved, and not because of poor maintenance. The fail-safe device, the last line of defense against a disaster, wasn't designed to handle a real-world blowout, according to investigators, who called for further study of the devices.

"They have to rethink the whole design," said Elmer P. Danenberger III, who is not involved in the investigation, but oversaw U.S. offshore drilling rules until he retired in December 2009.

The investigators' finding could be a problem for the oil industry. Drilling rigs around the world rely on blowout preventers, most of them with the same basic design as the one that failed on the Deepwater Horizon.

The report doesn't address what caused the blowout itself. That has been the subject of several other major inquiries, which all have found that a series of decisions by BP and its contractors set the disaster in motion.

Even if the device had worked, it wouldn't have saved the lives of the 11 rig workers killed in the accident. That's because no one even tried to activate the shears until after massive explosions killed the men and crippled the rig. But the device could have mostly prevented the oil spill that began when the Deepwater Horizon sank two days after the initial explosion.

Drilling critics say the report is evidence of the industry's endemic problems.

"This report calls into question whether oil-industry claims about the effectiveness of blowout preventers are just a bunch of hot air," Rep. Edward Markey (D., Mass.) said Wednesday.

The Bureau of Ocean Energy Management, Regulation and Enforcement, the offshore drilling regulator, declined to comment on the report, but pointed to new, tougher safety rules adopted in the wake of the Gulf spill. Those rules require increased testing of blowout preventers, but don't require that those tests be performed on bent or off-center pipe.

Erik Milito, head of exploration and production for the American Petroleum Institute, an industry group, said companies were still studying the report's findings, but were confident existing blowout preventers were up to the task. He added that the industry has introduced new measures to make a blowout less likely and to contain a spill should one occur.

The new study was conducted by engineers from Norwegian risk-management company Det Norske Veritas, which was hired by federal investigators to examine the blowout preventer and figure out what went wrong.

Its engineers found that when workers aboard the Deepwater Horizon first detected a problem within the well on the night of April 20, they initially activated parts of the blowout preventer meant to grab onto the pipe and cut off the flow around it, but that don't take the more extreme step of cutting the pipe entirely.

Those parts of the blowout preventer worked, but they couldn't do anything to stop the explosive natural gas that had already flowed past the blowout preventer and were racing up to the surface. Once it reached the rig, the gas ignited, setting off a massive explosion that killed the 11 workers and knocked out the rig's power, leaving survivors with no way to trigger the final fail-safe on the blowout preventer, the pipe-cutting shears known as blind-shear rams, while they were still aboard the rig.

Investigators aren't sure when, but at some point, the blind-shear rams were finally activated. That could have been done either by the rig's dead-man switch, which is meant to automatically trigger the shears when the rig loses its connection to the blowout preventer, or it could have triggered two days later when remote-controlled robots arrived on the scene. The shears activated successfully, but they didn't seal the well. The investigators found that the shears didn't work because they are designed to cut through pipe that is centered in the well. But the force of the blowout deformed the pipe, bending it and knocking it out of center, where the blades couldn't fully cut it.

The findings could be good news for BP, which has argued the disaster was at least partially attributable to the failure of the blowout preventer, which was owned and maintained by rig owner Transocean Ltd. and built by Cameron International Corp. A BP spokeswoman said: "We support efforts by regulators and the industry to make BOPs more reliable and effective."

The report could also be good news for Transocean, which said Wednesday the "findings confirm that the BOP was in proper operating condition and functioned as designed." Earlier investigations have questioned the company's maintenance of the blowout preventer. But the new study found that any maintenance flaws didn't explain the device's failure.

The report could turn attention back to Cameron, which has until recently escaped most scrutiny. The company said Wednesday the device "was designed and tested to industry standards and customer specifications."

The oil industry has long known that blowout preventers were prone to failure, especially as drilling has moved into deeper water, requiring thicker, tougher pipe. In 2004, a study commissioned by federal regulators found that only three of 14 newly built rigs had blowout preventers that could squeeze off and cut the pipe at the water pressure likely to be experiencedat the equipment's maximum water depth.

"This grim snapshot illustrates the lack of preparedness in the industry to shear and seal a well with the last line of defense against a blowout," the study said. The Wall Street Journal first reported the study's findings in a story last May.

The study singled out Cameron for relying on calculations to determine the needed strength of shear arms using "shear forces lower than required or desired in many cases."

In testimony before the presidential commission investigating the spill last year, Bill Ambrose, a Transocean executive, said blowout preventers weren't designed to cut off a flowing well.

"It is somewhat like snipping a fire hose with a pair of scissors," Mr. Ambrose said. "The blind shear ram is not designed for that particular condition."

Some experts said the report emphasized the need to avoid blowouts in the first place.

"The issue is not the BOP," said Tadeusz Patzek, chairman of the petroleum engineer department at the University of Texas, "but making sure the BOP never has to be activated in such circumstances. You don't want to rely on a single device between you and eternity."

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Pushing technological boundaries in ultradeep waters

The discovery of a giant oil accumulation in ultradeep waters off Brazil’s southeast coast is opening a new frontier for exploration and production. This presalt play, founded on the Tupi discovery in the Santos basin, contains potential recoverable reserves of 795 million m3 to 1.3 billion m3 [5 to 8 billion bbl] of oil equivalent.

Just one of several structures found beneath a thick layer of salt, the Tupi structure is pushing technological boundaries as E&P teams seek to define its geographic limits.

Geology
From a geologic perspective, this play is a product of interminably slow tectonic and depositional processes involving continental rifting, seafloor spreading, and sedimentation. These processes were associated with the split between South America and Africa during the Cretaceous breakup of Gondwana. The depositional processes created source, reservoir, and seal layers necessary to successfully produce an active petroleum system.

Technology
From a technological perspective, the viability of the presalt play is a result of operator experience gained through overcoming the challenges of constructing wells in deep and ultradeep waters off the coast of Brazil. Just as important are improvements to seismic imaging, which allow geophysicists to identify potential structures masked beneath layered evaporites that may be as thick as 2,000 m [6,560 ft].

E&P challenges
Expertise and techniques developed to exploit deepwater fields of the Campos basin have been adapted to wells in the Santos basin. Exploration models from the Santos basin presalt play, in turn, have led to significant discoveries in neighboring basins. This article discusses the geology and history of Brazil’s presalt play and describes challenges associated with exploration and production of presalt carbonate reservoirs.

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March 30 (Bloomberg) -- President Barack Obama will offer oil and gas companies new incentives to start production on undeveloped leases as part of a plan to cut U.S. dependence on imported oil, according to two administration officials.

With rising energy prices triggered by turmoil in the Middle East putting pressure on consumers and threatening the recovery, Obama plans in a speech in Washington today to lay out a blueprint to reduce U.S. oil imports by one-third in a little over a decade, the officials said, briefing reporters on condition of anonymity to preview the president’s remarks.

“We still have a lot of work to do on energy,” Obama told Democratic Party supporters at a political event last night in New York. “Let’s increase domestic oil production. Let’s also invest in solar and wind and geothermal and biofuels, and let’s make our buildings more efficient and our farms more efficient.”

The Gulf of Mexico alone may have as much as 11.6 billion barrels of untapped crude -- enough to meet U.S. demand for almost two years -- and 59.2 trillion cubic feet of natural gas, according to a U.S. Interior Department report released yesterday. Less than half the leases on federal land are active, it said.

While the officials refused to detail the incentives Obama will outline, Michael Bromwich, director of the Bureau of Ocean Energy Management, Regulation and Enforcement, which oversees drilling, said on March 17 that the administration may trim the duration of leases to accelerate development or may reward companies that step up production with lower royalty rates.

Expanded Drilling
Obama’s address today at Georgetown University comes almost a year since he announced that he would allow expanded oil and natural-gas drilling off the East Coast as part of a plan to increase domestic production while also encouraging conservation and developing alternatives.

The administration suspended drilling in waters deeper than 500 feet in May in response to the oil spill at BP Plc’s Macondo well in the Gulf of Mexico, the worst in U.S. history. The ban was lifted in October, with tougher safety, inspection and environmental-protection rules required for permits.

Obama requested the Interior Department’s report amid a rise in the cost of gasoline. Prices are up more than 20 percent this year and up 33 percent from a year ago. Regular gasoline at the pump, averaged nationwide, increased 0.3 cent to $3.587 a gallon yesterday, AAA said on its website. That’s the highest price since Oct. 2, 2008.

Crude Oil
Oil for May delivery fell as much as 47 cents to $104.32 a barrel in electronic trading on the New York Mercantile Exchange as signs of rising U.S. crude supplies stoked speculation that demand may falter.

According to the administration officials, the president will argue today that the best way to secure U.S. supplies is by increasing domestic production, encouraging production of energy-efficient vehicles and spurring the development of alternative fuels.

Obama is asking Congress for $29.5 billion for the Energy Department in the 2012 fiscal year, a 12 percent increase, to support his proposed “clean-energy standard” that envisions 80 percent of U.S. electricity coming from low-pollution sources by 2035.

Kevin Book, a managing director at the Washington policy group ClearView Energy Partners, said the administration can offer a limited number of incentives without congressional authority.

Potential Incentives
Among the options, according to Book: The administration could give companies a lower royalty rate if they produce within a certain period of time; it could propose higher rents in the future if companies don’t produce now; or it could waive fee increases for expedited permitting or refund them in response to production.

Lowering the royalties paid to the federal government for the leases “certainly would be appealing to some of the companies at today’s price point,” he said...

...the administration could streamline the process for drilling permits.

The fact there are so many leases undeveloped “tells you something about their prospects or the potential costs associated with getting the right kind of permits to drill wells...”

Lawmakers in both parties are advancing proposals to reduce energy costs.

Senate Minority Leader Mitch McConnell, a Kentucky Republican, has submitted a measure to block Environmental Protection Agency regulations to limit greenhouse gases. Letting the rules take effect “would raise energy costs for every business in America -- and lead to untold lost jobs for more American workers,” McConnell said yesterday.

Democratic Measure
Democratic Senators Robert Menendez of New Jersey and Bill Nelson of Florida have introduced legislation that would require oil and gas companies to pay an annual $4-per-acre fee for unused lands. They estimate that $874 million would be generated in 10 years.

Obama has pressed on multiple fronts to reduce U.S. oil imports...

With his 2012 re-election campaign in sight, Obama is shifting from his message on climate change “by recasting targets previously defined in terms of environmental attributes as economic and security targets, but it’s just a different route to the same place,” Book said.


more...
http://noir.bloomberg.com/apps/news?pid=20601110&sid=aSdcnsnUyUQA

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March 30 (Bloomberg) -- Petroleos Mexicanos, Latin America’s largest oil producer, said crude proved reserves dropped for a 12th consecutive year after the company faced delays bringing online new projects.

Proved reserves fell 1.4 percent to the equivalent of 13.8 billion barrels of oil in 2010, the Mexico City-based company said today in a presentation on its website.

After two years of delays, the state-owned company, which is spending about $23 billion this year, will open production projects to private companies to maximize output from older or closed fields. Pemex’s crude production dropped 1 percent to 2.576 million barrels a day last year.

Last year, Mexico’s National Hydrocarbons Commission as well as independent auditors disagreed with Pemex regarding the amount of so-called possible and probable oil-equivalent reserves at the Chicontepec development, where the company estimates it has 18.5 billion barrels of both types of oil reserves, according to a March 1 company presentation.

The commission last fall questioned Pemex’s claims of probable and possible oil and gas reserves in its northern region requiring the company to produce more evidence to back up the estimates for the Chicontepec project that represented about 58 percent of the possible reserves reported a year ago.

Chicontepec Concerns
Chicontepec is a field with small pockets of oil and low pressure spread across the states of Puebla, Hidalgo and Veracruz near the Gulf of Mexico in central and eastern Mexico.

Proved reserves are those that have a reasonable certainty of being recoverable under existing economic and political conditions with current technology.

Probable and possible reserves are unproved reserves that indicate the relative degree of uncertainty about their existence, 50 percent and 10 percent, respectively, according to the Society of Petroleum Engineers and World Petroleum Council.

Proved reserves are the only type the U.S. Securities and Exchange Commission allows oil companies to report to investors.

In 2007, Pemex forecast output of 660,000 barrels a day by 2015 for Chicontepec. Last year, Pemex cut that forecast to 150,000 barrels. Chicontepec is producing 47,000 barrels of oil a day as of last week, according to a preliminary Pemex report.

In 1938, Mexico’s President Lazaro Cardenas seized the assets of companies that later became Chevron Corp. and Exxon Mobil Corp., the world’s largest oil company. Mexico created Pemex later that year. It prohibited private and foreign companies from exploring or producing oil until October 2008 when the law was revised. Pemex is the only domestic refiner.

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