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Arctic Oil Still Seen Decades Off as Producers Balk at Costs – Bloomberg

Arctic Oil Still Seen Decades Off as Producers Balk at Costs – Bloomberg.

By Mikael Holter and Niklas Magnusson  Feb 24, 2014 4:41 AM ET

Lundin Petroleum AB (LUPE), the Swedish explorer focused on Norway, said there won’t be any new oil output in the ice-filled waters of the Arctic for at least 15 years because of technical and logistical challenges.

“I don’t think we’ll see any oil production in the Arctic any time soon — probably not this decade and not the next,” Chairman Ian Lundin said in a Feb. 20 interview in Stockholm. “The commercial challenges are too big.”

The Arctic holds 30 percent of the world’s undiscovered natural gas reserves and 13 percent of its undiscovered oil, according to U.S. Geological Survey estimates. Still, exploration of the Arctic ocean floor, where 84 percent of these resources are thought to be trapped, has suffered setbacks in recent years.

Royal Dutch Shell Plc. (RDSA)Europe’s biggest oil company, in January again halted drilling plans off Alaska after a court ruled the area had been illegally opened to exploration. That followed a previous postponement after a series of technical mishaps in 2012, including the stranding of a rig.

Off the coast of Greenland, drilling has yet to resume after Cairn Energy Plc (CNE) spent $1 billion on exploration without making commercial finds in iceberg-ridden waters, while Russia’s Shtokman gas project, 600 kilometers (370 miles) from shore in the Barents Sea, has been stalled for years.

Lower Priority

As companies including Shell and Norway’s state-controlled Statoil ASA (STL) cut planned investments amid rising costs across the industry, expensive Arctic projects could get a lower priority.

“It may take a while to develop the right technology,” Lundin’s chairman said. “Investments are very, very high so it still has to be commercially justified.”

Another factor undermining the appeal of expensive exploration projects is the outlook for crude prices. Brent oil for delivery in 2016 is trading at about $97.45 a barrel, down 11 percent from the current spot price of $110.07 for the global benchmark, according to data compiled by Bloomberg from the Ice Futures Europe Exchange.

An exception to Arctic challenges is the southern part of Norway’s Barents Sea, Lundin said. While inside the Arctic circle, it benefits from a less-harsh climate and shallower and ice-free waters, and may hold 8 billion barrels of oil equivalent in undiscovered resources, more than 40 percent of the country’s total.

Dwindling Reserves

To compensate for dwindling reserves in aging North Sea fields, Norway is pushing into the Barents, which holds 54 of the 61 blocks the government has proposed issuing in its next licensing round. More than half will be in a newly opened area previously disputed with Russia.

“In the Barents Sea we’ll probably see production much sooner because there’s no technological gap,” he said. “It’s now just a matter of having the reserve base that you’re required to have to justify the investment.”

Lundin fell as much as 0.8 percent and traded 0.2 percent lower at 127.3 kronor as of 10:40 a.m. in Stockholm. That curbs the stock’s gain to 1.5 percent so far this year and gives Lundin a market value of 40.5 billion kronor ($6.2 billion.)

Some oil production has already started in Arctic waters. BP Plc (BP/)’s Prudhoe Bay field in Alaska has been producing since the 1970s, while OAO Gazprom in December became the first Russian company to extract oil from the Arctic seabed at the Prirazlomnoye field in the Pechora Sea.

Contrasting Outlooks

Eni SpA (ENI) will become the first company to produce oil in Norway’s Barents Sea when its Goliat field starts in the third quarter this year, even though the Norwegian Petroleum Directorate has said it expects delays. Statoil’s Snohvit gas field, which began output in 2007, is the only producing field in the Norwegian Barents Sea to date.

Lundin discovered as much as 145 million barrels of oil at the Gohta prospect in the Barents Sea last year. That has helped revive optimism among explorers after Statoil postponed an investment decision on its nearby Johan Castberg project because of higher costs, taxes and uncertainty about resource estimates of as much as 600 million barrels of oil.

Gohta was Norway’s first oil discovery in Permian layers with sufficient flow, and opened up a new exploration model for the area with as many as 10 new drilling targets, the Swedish explorer has said. Lundin is planning an appraisal well at Gohta in the second quarter and will drill the nearby Alta prospect in the third.

Lundin’s optimism contrasts with Statoil, which has found oil at just one of four exploration wells designed to boost crude resources for its Castberg project and make it more profitable. Still, current resources are sufficient to be developed and Gohta could even be coupled with Castberg, Lundin has said.

“There are other discoveries in the same area” as Gohta, the chairman said. “After we go through the appraisal phase we’ll hopefully be in a position where we can just press the button for development.”

To contact the reporters on this story: Niklas Magnusson in Stockholm atnmagnusson1@bloomberg.net; Mikael Holter in Oslo at mholter2@bloomberg.net

To contact the editor responsible for this story: Jonas Bergman at jbergman@bloomberg.net

Peak Oil is Real and the Majors Face Challenging Times « Breaking Energy – Energy industry news, analysis, and commentary

Peak Oil is Real and the Majors Face Challenging Times « Breaking Energy – Energy industry news, analysis, and commentary.

By  on February 18, 2014 at 9:32 AM

Surging Oil Industry Brings Opportunity To Rural California

The idea that global oil production was nearing its peak, only to plateau and then decline was a common view in the energy world for many years. The geophysicist M. King Hubbard predicted in the 1950’s that US oil production would peak in the 1970’s, a forecast that held true until technology allowed companies to economically extract oil and gas from tight geologic formations like shale.

The recent surge in US liquids output – crude plus natural gas liquids (NGLs) – quieted the peak oil community. A well-known, largely peak oil-focused website – The Oil Drum – shut down in 2013, an event some considered the death knell of the peak oil theory.

But not so fast says Steven Kopits from energy business analysis firm Douglas-Westwood. Total global oil supply growth since 2005 – 5.8 million barrels per day – came from unconventional sources, shale oil and NGLs in particular, Kopits recently told the audienceat Columbia University’s Center on Global Energy Policy.

“Not only US, but global, oil supply growth is entirely leveraged to unconventionals right now,” and the legacy, conventional system still peaked in 2005, he said. This gets a bit technical, as shale oil and liquids produced with natural gas are fed into the main crude oil stream and priced as such. But the strong degree to which increasing oil supply growth is dependent on unconventional sources is important to remember and often gets lost in the exuberance over top-line output figures.

And despite prolific incremental oil and gas production made possible by hydraulic fracturing and horizontal drilling advances, maintaining legacy production has been expensive and arguably of limited success.

Total upstream spend since 2005 has been $4 trillion, of which $350 billion was spent on US and Canadian unconventional oil and gas, with an additional $150 billion spent on LNG and GTL, according to Kopits’ presentation. About $2.5 trillion was spent on legacy crude oil production, which still accounts for about 93% of today’s total liquids supply. And despite that hefty investment, legacy oil production has declined by 1 mmb/d since 2005, said Kopits.

By comparison, between 1998 and 2005 the industry spent $1.5 trillion on upstream development and added 8.6 mmb/d to total crude production. The industry “vaporized the GDP of Italy,” with its $2.5 trillion upstream spending for oil since 2005, which barely maintained the legacy oil production system. Kopits argues this level of investment by the major oil companies appears unsustainable, and the major’s current cost structure is troublesome.

Collective oil production of the world’s largest listed oil companies has faltered, while upstream capex soared, Kopits said. Profits have suffered because costs are rising faster than revenues in a range-bound crude oil price environment. “E&P capex per barrel has been rising at 11% per year,” he said, but Brent oil prices have largely been flat. As a result, Chevron, ExxonMobil, Statoil and BP all recently put major projects on hold or cancelled them outright.

“If your costs are rising faster than your revenues, do you sell your assets? The majors have been doing this, but is it sustainable?” asked Kopits. The industry was able to maintain conventional crude oil production levels by throwing $2 trillion dollars at the system – essentially “putting it on steroids” – but now that’s run its course and capex is being curtailed, a trend that looks set to continue, in his view.

Statoil may choose between Alberta, N.L. oil projects – Business – CBC News

Statoil may choose between Alberta, N.L. oil projects – Business – CBC News.

Statoil's Leismer project began producing in 2011 and the Norwegian company has plans to expand it, but may have to prioritize Canadian projects.Statoil’s Leismer project began producing in 2011 and the Norwegian company has plans to expand it, but may have to prioritize Canadian projects. (YouTube)

Statoil might have to choose between developing properties in the Alberta oilsands and an offshore find off Newfoundland because of rising costs in the industry.

Stale Tungesvik, president of Statoil Canada, says its Norwegian parent company will decide in February which of the Canadian projects will go ahead.

“We invest more than ever, but we see that it’s much more costly to develop one barrel of oil today than it was earlier,” Tungesvik said in a briefing with reporters Monday.

He said Statoil has to prioritize which projects to develop, because the oil available is more difficult to extract.

Crude oil prices are sitting at about $100 US a barrel, but that’s the equivalent to $30 several years ago, he said.

“Today, $100 a barrel is the same as $30,” he said, adding “the easy barrels” are gone.

Tungesvik said he would prefer to go ahead with projects in bothAlberta’s oilsands and off the coast of Newfoundland and Labrador, but that may not happen.

“When that will hit us some place in Canada, I’m not sure yet. I’m still fighting for doing both, so that’s my kind of position.But there is the bigger picture. There has to be some changes,” he said.

In August, Statoil and partner Husky Energy Inc. announced a huge offshore oil discovery about 500 kilometres northeast of St. John’s.

It’s the company’s third find in the Flemish Pass Basin in the North Atlantic and promises between 300 million and 600 million barrels of recoverable oil.

It also has plans to develop the Corner oilsands in Alberta and is mulling an expansion to its Leismer property, which began production in January 2011. Both Corner and Leismer have regulatory approval to produce up to 40,000 barrels per day.

 

Enron No Lesson to Traders as EU Probes Oil-Price Manipulation – Bloomberg

Enron No Lesson to Traders as EU Probes Oil-Price Manipulation – Bloomberg.

 

EU Oil Manipulation Probe Shines Light on Platts Pricing Window – Bloomberg

EU Oil Manipulation Probe Shines Light on Platts Pricing Window – Bloomberg.

 

EU raids oil majors in ‘price fixing’ probe – Europe – Al Jazeera English

EU raids oil majors in ‘price fixing’ probe – Europe – Al Jazeera English.

 

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