Awl Bidness

[trysail]

http://andrewleach.ca/oilsands/on-t...-between-environmentalists-and-the-oil-price/


Rescuing The Frog

The strange relationship between environmentalists and the oil price
By Andrew Leach
February 16, 2011

Environmentalists have a very strange relationship with the price of oil. I asked around among friends, students, and online acquaintances and every one replied without question that high oil prices were a good thing if you care about the environment. Why? Well, high prices discourage consumption they said. Not only that, high prices enable alternative energy sources. Of course, both of these statements are correct, but if you look deeper into the economics of oil and gas, it is not so easy to say that you should pray for high oil prices if you care about the environment.


Supply-side economics in the energy sector are very difficult to wrap your head around. It’s far too simplistic to say that oil or gas is a finite resource (which it is, of course) or that the annual quantity of oil or gas supplied has peaked (which it may have) and so to conclude that increasing oil prices are a one-way street to environmental Utopia.


Oil, from an economics perspective, is best thought of as a series of small resources, or plays. Each play has some physical and economic characteristics, the most relevant of which are the costs to extract a barrel of oil given current technology, the quality of the oil extracted, and the fiscal regime (taxes, royalties, etc.) in which the play is located. Of course, plays have different environmental attributes as well. A light oil play in Texas is vastly different from a heavy oil play in Venezuela or an oil sands play in Northern Alberta. From a supply perspective, the finite nature of the physical resource is largely irrelevant – what you need to know is how much oil is available to the market at a given world oil price, and how much do we expect to be able to produce over the next few years given a reasonable forecast of prices and technology. This is, at a very coarse level of detail, what you see when companies or countries report reserves. The problem with using these data is that they tell you next to nothing about how much oil there is in the ground, or how much companies could produce profitably at higher (or lower) prices. So, if the world’s proven and probable reserves are 1500 billion barrels, and current production is 90 million barrels per day, this does not mean that we will “run out of oil” if we keep producing at those rates in less than 50 years. It means we will run out of oil that we know about that we can produce and deliver to market at costs of less than about $60/bbl unless technology changes.


As we run out of the $60 or $80 oil that we know about today (and we will) one of two things will happen. Either new energy sources will emerge to continue to supply those products which we derive from oil at a comparable cost, or the price of oil will be bid up (in econ 101, think of the supply curve shifting slowly to the left). As that price goes up, there will be some decline in consumption, but the increase in price will also unlock previously financially non-viable energy sources. If you live in Alberta, you need only look up Highway 63 for evidence of this, while folks elsewhere can take a trip out out to the deep water of the Gulf, the North Atlantic, or the North Sea – the fact that $70-$80 oil is now the benchmark price means that oil sands plays and deep water wells which would have been the stuff of fantasy 10 years ago represent wonderful financial opportunities today. As more of these deep water wells are drilled or oil sands plants are built, the technology will improve, and the costs will go down. Now, it’s tempting to think only about alternative energy sources which would qualify as renewable, but the market does not discriminate unless forced to by policy.

http://www.eia.gov/forecasts/aeo/images/figure_1es-lg.jpg
Source: EIA (http://www.eia.gov/forecasts/aeo/executive_summary.cfm)​

If you want an example of supply-side forces in action, look no further than natural gas. Up until 2 or 3 years ago, the North American gas market was in crisis…well, if you were a consumer at least. As recently as 2007, Us domestic natural gas production was in steep decline, prices were increasing rapidly, and imports from LNG were becoming an energy security necessity. Then, something happened. In the late 1990′s, a new technology now known as fracking was beginning to emerge and show promise. The graph above tells the story of what has happened since. North American onshore gas production has move from conventional to unconventional plays with tight and shale gas accounting for an ever increasing share of production. Natural gas is still a finite resource, but between 2008 and 2009, despite abysmal natural gas prices, US economically viable gas reserves doubled and the US has gone from peak gas to abundant gas in a matter of 10 years. Why? Because of technology and the push that technology got from high prices. In fact, North American LNG import terminals are likely to go the way of the dodo, while new export terminals are springing up on the west coast. I am not sure that this makes environmentalists happy at all.

When you think about alternative energy sources, and their ability to compete with fossil fuel sources, you have to look at them like a fossil fuel play and ask: What are the costs to deliver the same end product? What is the potential for technological improvement? How well does it fit into our energy supply chain? When it comes to substitutes for unconventional sources of oil and gas, the answers are often “much more expensive,” “high but uncertain potential for improvement,” and “we can use it if we all buy new cars and/or build new fueling stations.” If you are an environmentalist, I would humbly suggest that you start dreaming about low oil prices. A low oil price means one of two things – either we have found new, less costly ways of extracting oil which almost certainly means lower energy and GHG input per barrel (let’s hope it isn’t just due to external costs being imposed on the environment) or that we have found alternative means of getting around or heating our homes, and thus reduced the amount people are willing to pay for oil. If you are an environmentalist, I have to think that either of those sound better than oil sands and shale gas.


http://andrewleach.ca/oilsands/on-t...-between-environmentalists-and-the-oil-price/

 

[trysail]

http://www.bloomberg.com/news/2011-09-09/tullow-oil-makes-oil-discovery-offshore-french-guiana.html



Tullow Makes Oil Discovery Off French Guiana
By Eduard Gismatullin
Sep 9, 2011

Tullow Oil Plc (TLW), the U.K. explorer behind West Africa’s biggest offshore discovery in a decade, said an offshore find in French Guiana opened up a new hydrocarbon basin on the other side of the Atlantic.

The Zaedyus exploration well was drilled to test whether the Jubilee field in Ghana was mirrored in South America, the London-based company said today in a statement...

...Zaedyus is the first well to test the “Atlantic mirror” theory and Tullow’s Exploration Director Angus McCoss said the field could hold 700 million barrels in gross reserves. The well encountered 72 meters of so-called net oil pay.

“The discovery at Zaedyus has proved the extension of the Jubilee-play across the Atlantic and made an important new discovery in French Guiana,” McCoss said in today’s statement.

Jubilee, which was discovered in 2007, has potential resources of 1.8 billion barrels, according to Tullow.

The world’s largest oil companies missed out on the Jubilee find. In French Guiana, Royal Dutch Shell Plc (RDSA) and Total SA (FP), Europe’s largest and third-biggest oil companies, bought into the field...


...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.

The well found light oil, in line with expectations, and cost $200 million to drill. Tullow had delayed announcing drilling results from the “high-impact” Zaedyus well until September from August.

Tullow is the operator of the Guyane Maritime license with a 27.5 percent stake, while Shell has 45 percent, Total 25 percent and Northpet 2.5 percent.


http://www.bloomberg.com/news/2011-09-09/tullow-oil-makes-oil-discovery-offshore-french-guiana.html

 

[trysail]

http://www.bloomberg.com/news/2011-...aces-peers-as-lng-arrives-energy-markets.html


Netherlands Gas Trade Beats Peers as LNG Arrives
By Ben Farey
Sep 15, 2011

The Netherlands’ natural-gas market is growing faster than its peers, fending off competition from Germany to be mainland Europe’s largest as the country starts importing liquefied fuel for the first time.

Volumes at the Title Transfer Facility, the Dutch hub, jumped 42 percent from a year earlier in the first half of 2011, compared with a 21 percent increase in Germany and 9 percent in the U.K., Europe’s biggest market, data from Kingston Energy Consulting Ltd. show. The Netherlands handled more than 13 times as much month-ahead gas as Germany on Sept. 13, according to London Energy Brokers’ Association data.

European Union efforts to deregulate energy markets and encourage new pipelines between countries coupled with a glut that has driven buyers to favor spot markets instead of costlier oil-based contracts is boosting gas trading. The Netherlands has further enhanced its status as a hub after importing its first commercial liquefied natural gas cargo at Rotterdam’s new Gate terminal on Sept. 1.

“Two years ago when the German market was kicking off, it looked like the German hub was going to edge out” the Netherlands, Nigel Harris, a founding partner of Kingston Energy, said by telephone from Kingston, England. “Now it seems that isn’t going to happen and TTF has established itself as a pool of liquidity for forward trading.”

Dutch Hub
The Dutch hub handled more than 3,000 terawatt-hours of gas in the six months through June, according to Kingston Energy data, which include all recorded trades from exchanges and system operators as well as an estimate of the total volume of broker and unrecorded one-to-one trades. That’s enough to meet more than half the demand of the EU’s 27 member states.

Traders prefer the Netherlands because the more active market makes it easier to hedge, or protect, their bets, Jonas Nihoej, a senior trader at KIH Energy Trading GmbH in Prague, said in an interview. “It’s easy to get in and out of positions.”

Trading hubs may cover an entire nation, such as the U.K.’s National Balancing Point, or NBP, or specific pipeline connections, such as Belgium’s Zeebrugge, where the fuel can be bought and sold via brokers or exchanges. Europe’s markets evolved during the past decade, following the U.K.’s debut in 1992.

Gate LNG
The Dutch hub was established in 2003 by Nederlandse Gasunie NV, the state-owned gas transporter, and has pipeline connections to Russia and Norway as well as markets in Germany, Switzerland, France, Italy, Belgium and the U.K. Gasunie started the 12 billion cubic-meter-a-year Gate LNG terminal this year together with Royal Vopak NV to import fuel from countries such as Qatar, the world’s biggest LNG exporter.

Europe’s hubs are challenging the dominance of producers such as Russia’s OAO Gazprom and Norway’s Statoil ASA (STL), which built export pipelines stretching from northern Russia to western Europe starting in the 1960s to supply gas through multiyear contracts negotiated directly with consumers. France, Italy and Austria also have spot markets.

About 4,500 megawatt-hours of month-ahead gas was bought and sold on the TTF on Sept. 13, compared with 340 megawatt- hours for the similar contract on Germany’s NetConnect Germany GmbH, or NCG, London Energy Brokers’ Association data show.

“German hubs are still taking off,” Nihoej said. Germany uses more than twice as much gas as the Netherlands, he said.

Price Collapse
Day-ahead gas in the Netherlands dropped as low as 6.75 euros a megawatt-hour in October 2009 as the global financial crisis sapped industrial demand. It was at 25.05 euros ($34.60) yesterday, according to broker prices on Bloomberg. That’s about $10.05 a million British thermal units.

EON AG, Germany’s largest utility, and GDF Suez (GSZ) SA, Europe’s biggest gas-network operator, sought more flexible terms from producers such as Gazprom during the past two years as oil-linked contracts hurt revenue. EON said last month it may cut as many as 11,000 jobs after posting its first quarterly loss in 10 years. RWE AG (RWE), Germany’s second-largest utility, had a loss in its “midstream” gas business in the first half compared with a profit a year earlier.

“There’s been a surplus of gas at a time when markets have been liberalizing and the conditions for accessing grids, storage and customers have been improving,” Colin Lyle, chairman of the gas committee at the European Federation of Energy Traders, said in a phone interview from London. “We can expect continued growth in the traded gas markets across Europe.”

‘Extraordinary Growth’
Germany had 19 gas market areas in 2006, which were consolidated into two main trading zones by 2009. NCG is the most active. Its pipelines span 20,000 kilometers (12,400 miles), covering parts of central Germany and most of the south. The Gaspool hub covers most of the north and east.

The “extraordinary” 80 percent growth of trading in Germany last year has slowed as traders aren’t sure how the country’s regulators will reshape the market, Harris said.

Germany has the capacity to store almost 10 times as much as the TTF region, which includes Denmark, data from Gas Storage Europe, a Brussels-based industry association, show. The ability to draw on inventories helps iron out price swings.

With Germany’s power market established as Europe’s benchmark for electricity trading, it would be natural to trade German power versus German gas in a “spark spread” transaction and so avoid the TTF versus NCG price risk, Nihoej said.

The two German gas hubs will eventually merge into one, he said. “In five to 10 years NCG will be more active than TTF,” Nihoej said. “Then it will be NCG versus” the U.K.’s National Balancing Point.



http://www.bloomberg.com/news/2011-...aces-peers-as-lng-arrives-energy-markets.html

 

[trysail]

The crybabies, whingers and Monday-morning quarterbacks complain whenever somebody makes money. You never hear a peep out of 'em when some poor slob loses his shirt.


____________________

http://www.bloomberg.com/news/2011-...led-before-getting-cargo-wilhelmsen-says.html


Shipowner Mothballing New Supertanker

By Michelle Wiese Bockmann
Sep 23, 2011

A shipowner will mothball a newly built supertanker for the first time since the 1980s as a glut of the ships erodes earnings to an unprofitable $1,000 a day.

The tanker, capable of carrying 2 million barrels of crude, will be sent to a natural harbor in Malaysia, Arild Johannessen, an Oslo-based spokesman for Wilhelmsen Ship Management, which will oversee the deactivation, said by phone today. He declined to identify the ship because the details are private.

Earnings from this class of vessel, which carry about a fifth of the world’s oil, last week averaged $1,000 a day, according to Braemar Shipping Services Plc (BMS) in London, the U.K.’s second-largest publicly traded shipbroker. Some tankers were contracted speculatively and not secured against long-term charters, according to Holger Romer, spokesman for Hamburg, Germany-based Dr. Peters Group, owner of 19 supertankers.

“If you have a new ship that was ordered in ‘07 and ‘08, it was at a high price and now if you don’t have a charterer, it’s a big problem,” Romer said by phone. Dr. Peters Group owns 19 supertankers, he said.

The largest supertanker fleet in 29 years has cut earnings from the vessels by 96 percent since 2007 when they rose to a record $229,000 a day, according to data from Clarkson Research Services Ltd., a unit of Clarkson Plc, the world’s largest shipbroker.

Orders Surged
Owners ordered the most tankers in about three decades in 2007 and 2008, depressing freight rates to a 14-year low, as the fleet swelled almost three times faster than demand, Clarkson data show.

The last time new tankers were delivered straight from shipyards to anchorages, a process known in the industry as lay up, was in the 1980s, with owners sending the vessels to fjords in Norway, Eleusis Bay in Greece and the waters off Malaysia and Sri Lanka, Hong Kong-based Charles de Trenck at Transport Trackers, an adviser on shipping and trade flows, said today by e-mail.

Prices for new tankers have fallen 35 percent to about $100 million, according to EA Gibson, a London-based tanker broker. Those ordered in 2007 and 2008 require daily earnings of $55,000 to break even, the broker estimated in November.

Running costs, excluding fuel, are $10,645 a day, according to Moore Stephens International, a London accounting firm.

Cold Lay-Up
The mothballing is probably the first time in at least three decades that a new supertanker has been deactivated before trading, according to Halvor Ellefsen, a shipbroker at Galbraith’s Ltd. in London.

“More than anything else, it just shows how many ships there are,” said Ellefsen, who has been a broker since 1987. “Even if this happens on a meaningful scale, it’s hard to see it saving the tanker industry as ships that get laid up will just come back into the market when freight rates jump.”

The particular kind of mothballing for this ship is called cold lay-up, which involves anchoring the vessel in a protected area for a “long period of time,” and shutting all systems, with a minimum crew on board, according to Johannessen.

Warm lay-up means the ship can return to trading more quickly.

The supertanker, along with another of the same type already trading, will join another 15 ships already managed at anchor at Labuan, Malaysia, Johannessen said.

There are 152 supertankers contracted to be built at Asian shipyards, and 570 in the fleet trading today, according to Clarkson. A record 55 of the tankers, also known as very large crude carriers, began trading in 2010, and 41 have joined so far in 2011, Clarkson data show.

There was an overhang of 50 VLCCs, Jens Martin Jensen, chief executive officer of the management unit at Frontline Ltd., the largest supertanker operator, said on a conference call Aug. 26.


http://www.bloomberg.com/news/2011-...led-before-getting-cargo-wilhelmsen-says.html

 

[trysail]

http://oilandglory.foreignpolicy.co...onanza_along_with_its_critics_reaches_england



The shale gas bonanza -- along with its critics -- comes to England
By Steve LeVine
Thursday, September 22, 2011

The shakeup over shale gas -- a newly available fuel that has overturned assumptions about energy, climate-change and geopolitics -- has now stretched across the Atlantic to England. A drilling company backed by John Browne, the former CEO of BP, says it has discovered the gas equivalent of up to 35 billion barrels of oil. In oil, a find of 1 billion barrels is regarded as a supergiant.

Until now, the United States has been the epicenter of the shale gas disruption. This gas is locked into barely porous shale rock a mile and more beneath the surface of the Earth. Over the last few years, drillers have extracted the gas using a method called hydraulic fracturing, or fracking -- injecting a mixture of water, chemicals and sand at high pressure into the rock -- which has produced a bonanza of new supplies in the United States. Estimates are that it is sufficient to meet current U.S. consumption for a century.

Since gas emits just a third to a half the CO2 as coal, this gas glut -- to the degree it results in an accelerated shift away from coal-fired to gas-fired power plants -- could lower U.S. emissions of heat-trapping gases. As for geopolitics, the gas has already had the boomerang effect of casting doubt on Russia's economic and political leverage in Europe -- Russia supplies more than a quarter of Europe's gas, but the shale gas glut has challenged that market dominance.

All this impact has led to a search for shale gas elsewhere, especially in Europe and China.

Yet with the shale gas comes a backlash of local politics. In the U.S., drillers have been confronted with a furious protest movement of critics who say fracking contaminates drinking water supplies. In Europe, the protests have preceded any discoveries -- in the summer, for instance, France banned fracking.

Now, a U.K. company called Cuadrilla Resources says it has indications that a formation called the Bowland Shale is comparable in scale to the best U.S. finds, reports Guy Chazan at the Wall Street Journal. Cuadrilla's Dennis Carlton told Bloomberg's Ben Farey that the thickness of the gas-laden shale -- 3,000 feet in places -- is up to 10 times that of the ultra-rich Marcellus Shale that underlies New York and Pennsylvania. Cuadrilla's main investors include the hedge fund Riverstone Holdings, which is run by former BP CEO Browne.


That is just gas in place. What actually can be extracted will be much less. But the announcement caused much excitement in both directions -- from those enthused that the U.S. bonanza can be repeated on the other side of the Atlantic, and groups that wish to stop it.

As the company made its announcement in the Imperial Hotel in the city of Blackpool, a small protest was held out on the street by a group called Campaign Against Climate Change, the BBC reports. WWF, an environmental group, urged the U.K. government to call a moratorium on shale gas drilling, and instead to focus its efforts on development non-fossil fuel technologies. These critics are invigorated by two earthquakes that happened in the area in June, after which the company halted drilling.

That John Browne is the money behind this venture is ironic. In his long tenure, Browne rebranded BP into the green oil company, casting the company's name as meaning "Beyond Petroleum." His apparently successful into shale gas goes the other direction as far as critics are concerned.


http://oilandglory.foreignpolicy.co...onanza_along_with_its_critics_reaches_england

 

[trysail]

This is another in a long series of NPR stories that are long on speculation and short on facts. NPR is throwing wildly speculative numbers around with absolutely no clue what they're talking about.

The Bakken shale is a very high cost resource. The piece neglects to inform listener/readers that prevailing petroleum prices are a very large factor in the economic viability of these reserves. Yes, the hydrocarbons are there
but their economic feasibility is very much price dependent.

Rule # 1
Never believe anything from Goldman, Sachs.

Rule #2
NPR reporters know absolutely nothing about petroleum geology, very little about the petroleum industry and precious little about economics. When they cite a source such as Goldman, Sachs as the basis for a story, it is an admission of both ignorance and laziness.


__________________________
http://www.npr.org/2011/09/25/140784004/new-boom-reshapes-oil-world-rocks-north-dakota


New Boom Reshapes Oil World, Rocks North Dakota
by NPR Staff
September 25, 2011

A couple months ago, Jake Featheringill and his wife got robbed.

It wasn't serious. No one was home at the time, and no one got hurt. But for Featheringill, it was just the latest in a string of bad luck.

"We made a decision," he says. "We decided to pick up and move in about three days. Packed all our stuff up in storage. Drove 24 straight hours on I-29, and made it to Williston with no place to live."

That's Williston, ND. Population — until just a few years ago — 12,000. Jake was born there, but moved away when he was a kid. He hadn't been back since.

"We came in right through the stretch of where the Badlands is," he remembers. "And then you come into the town. So many trucks. Semi trucks and four-wheel-drive pickups — for a mile straight. You've never seen so many trucks in your life."

Those trucks were in North Dakota for one reason — the same reason Featheringill had decided to move his wife and three kids to a remote section of western North Dakota.

Oil.

A $1,200 Parking Space
Two years ago, America was importing about two thirds of its oil. Today, according to the Energy Information Administration, it imports less than half. And by 2017, investment bank Goldman Sachs predicts the US could be poised to pass Saudi Arabia and overtake Russia as the world's largest oil producer.

Places like Williston are the reason why.

"For many years, they knew that there was oil in that area, but the technology wasn't available to get it out," the town's mayor, Ward Koeser, tells weekends on All Things Considered host Guy Raz.

But in the last few years, advances in such technologies as "fracking" and horizontal drilling have made, by some estimates, as much as 11 billion barrels of oil available in the Bakken formation under North Dakota and Montana.

"There's oil companies coming from all over the country now." Koeser says.

Williston has skipped the recession entirely. Unemployment there is less than 2 percent. The population, the mayor estimates, has grown from 12,000 to 20,000 in the last four years.

"We actually have probably between 2,000 and 3,000 job openings in Williston right now," Koeser says.

Oil workers like Jake Featheringill are fueling Williston's population growth. He's working as a shophand for Baker Hughes, making enough to support his wife and three children. But with such a sudden population increase, Williston's infrastructure can't keep up.

"When we came up here, we were told housing was tough but not impossible," Featheringill says. He and his wife got lucky and borrowed an RV from a family friend. "We got lucky again and got to park the RV in a place where we were rent-free. Most of the RV spots around here run $1,000 to $1,200."

That's $1,000 a month, just for a parking space. "Is that not amazing?" Featheringill says. "And that's in a 70-mile radius. Just to park your RV."

'Boom-Town Syndrome'
"It's the old boom-town syndrome," says Charles Groat says, professor of energy and mineral resources at the University of Texas in Austin.

A small town like Williston, he says, can be burdened by a sudden oil boom.

"All the workers. And then you have roads and trucks and pipelines. And then you have all the community services that have to be provided — law enforcement, education. So it turns into a real bonanza in terms of income, but it becomes an environmental effect that people aren't used to experiencing."

In Williston, many workers forgo prices as high as $2,000 a month to rent a small apartment and instead live in "man camps," massive group-housing provided by their companies.

"Just a little room with a bed and a TV," Mayor Ward Koeser explains. "And then they have recreation areas."

The boom in Williston, Charles Groat says, is happening in spots across America. New drilling technology is also fueling boom towns in Texas, Louisiana, and Colorado. New drilling technologies mean companies can extract oil and natural gas from shale rock that was previously thought unreachable.

"Horizontal drilling — accessing a huge area of reservoir — and then the fracking process, which props opens those cracks, and allows the liquid or gas to flow to the well," Groat says. "That's what's made shale gas and shale oil such a viable resource."

But those techniques also raise environmental concerns that Groat is studying.

"There is a danger, here – the fact that we drill so many wells," he says. "If you look at the numbers of wells that have been drilled in North Dakota, just in recent times, the numbers of wells are huge, which increases the opportunity for bad things to happen environmentally or procedurally in developing the resource. We also are not dealing, of course, with the question of greenhouse gases and carbon dioxide as we continue our hydrocarbon dependence."

Global Implications
Amy Myers Jaffe of Rice University says in the next decade, new oil in the US, Canada and South America could change the center of gravity of the entire global energy supply.

"Some are now saying, in five or 10 years' time, we're a major oil-producing region, where our production is going up," she says.

The US, Jaffe says, could have 2 trillion barrels of oil waiting to be drilled. South America could hold another 2 trillion. And Canada? 2.4 trillion. That's compared to just 1.2 trillion in the Middle East and north Africa.

Jaffe says those new oil reserves, combined with growing turmoil in the Middle East, will "absolutely propel more and more investment into the energy resources in the Americas."

Russia is already feeling the growth of American energy, Jaffe says. As the U.S. produces more of its own natural gas, Europe is free to purchase liquefied natural gas the US is no longer buying.

"They're buying less natural gas from Russia," Jaffe says. "So Russia would only supply 10 percent of European natural gas demand by 2030. That means the Russians are no longer powerful."

The American energy boom, Jaffe says, could endanger many green-energy initiatives that have gained popularity in recent years. But royalties and revenue from U.S. production of oil and natural gas, she adds, could be used to invest in improving green technology.

"We don't have the commercial technology now," she says, noting the recent bankruptcy of American solar companies like Solyndra.

"The point is you can't force a technology that's not commercial. Rather than subsidize things that are not going to be competitive, we need to actually use that money to do R&D to create technologies — the same way that the industries created these technologies to produce natural gas and it turned out so commercially successful."


http://www.npr.org/2011/09/25/140784004/new-boom-reshapes-oil-world-rocks-north-dakota

 

[trysail]

http://www.bloomberg.com/news/2011-...-count-on-shell-s-bounty-from-arctic-oil.html



Alaska to BP to Conoco Count On Shell’s Bounty From Arctic Oil
By Katarzyna Klimasinska
October 1, 2011

The parking lot at the Millennium Alaskan Hotel in Anchorage was as jammed at 6:30 a.m. on a Thursday as the float-plane marina at neighboring Lake Spenard. About 170 oil executives, tribal entrepreneurs and state employees entered through a lobby adorned with stuffed polar bears and mounted moose heads.

The predawn visitors were there to hear Pete Slaiby, 53, the head of Alaska operations for Royal Dutch Shell Plc, outline the company’s plans to drill in icy Arctic seas.

They came because Shell’s good fortune may also be their own. The offshore fields the company is seeking U.S. permission to develop may contain oil valued at as much as $2.4 trillion. Drilling would set off a cascade of revenue for contractors, 54,700 jobs across the U.S. and $176 billion in federal, state and local tax revenue through 2057, according to a study Shell commissioned from consulting company Northern Economics and the University of Alaska Anchorage.

“You’re looking at decades of economic impact,” Kara Moriarty, deputy director of the Alaska Oil and Gas Association, said in an interview. Production in the Beaufort and Chukchi seas “would be a tremendous boost,” she said.

Among the winners if the Obama administration gives the required permits to The Hague-based Shell: Owners of the Trans Alaska pipeline, including BP Plc and Exxon Mobil Corp., which say they need more oil to keep it running; Statoil ASA and ConocoPhillips, which want to win approval to develop their own federal leases in the Arctic; and Noble Corp., which will supply a drilling vessel.

‘A Big Opportunity’
“This is a big opportunity,” Slaiby told the audience at the Sept. 8 meeting, showing them an animation of Shell’s spill- response plans over a breakfast of eggs and bacon.

Shell’s spending since winning Arctic leases in federal waters in 2005 is approaching $4 billion for drilling rights, engineering, government-ordered studies and research, according to the company. The Chukchi and Beaufort sea deposits may hold 25 billion barrels of oil, Shell says, citing government estimates, for a value of $2.4 trillion based on the average price of oil on the New York Mercantile Exchange this year.

Until now, the native village of Point Hope, which juts into the Chukchi Sea, and environmental groups staved off the company by contending in court and in comments to government agencies that drilling may disrupt a fragile land, putting at risk the animals that provide the Inupiats with whale blubber for fuel, pickled-flipper snacks and sealskin for the drums they beat in time to traditional dances.

White House Meetings
The delay may end soon. In August, the company won Interior Department approval for exploratory drilling in the Beaufort Sea near the North Slope towns of Deadhorse and Kaktovik. The Environmental Protection Agency issued air-quality permits on Sept. 19 for a ship Shell plans to use for drilling.

Slaiby said Shell executives met three times with White House officials, most recently on Sept. 20, to talk about Arctic drilling.

The company expects Interior Secretary Ken Salazar to uphold the Chukchi Sea lease sale by Oct. 3, and the Bureau of Ocean Energy Management, Regulation and Enforcement to give the go-ahead for the Chukchi exploration plan in December, Slaiby said at the hotel breakfast in Anchorage.

Shell says it must decide by the end of October whether to gamble that it will get all 35 permits needed and start lining up about 18 vessels and 1,200 workers to drill the first offshore wells in U.S. Arctic waters in July.

Alaska’s Republican Governor Sean Parnell has backed Shell’s plans partly as the best bet to restore the flow in the state’s largest oil pipeline to 1 million barrels a day within 10 years.

Trans Alaska Pipeline
Oil flowing through the 800-mile (1,287-kilometer) Trans Alaska Pipeline shrank to about 570,000 barrels a day this year from a record 2 million barrels in 1988, as output from onshore tracts fell. The pipeline’s owners, including BP, Exxon and ConocoPhillips (COP), say that less petroleum in the pipes allows ice to form, wax to build up and metal to corrode.

Shell, which said it expects Arctic offshore production to start after 2020, would use the pipeline to deliver its crude across the state to Valdez, the northernmost ice-free port in the U.S.

“Beaufort and Chukchi are critical for our long-term future,” Tom Barrett, president of Trans Alaska operator Alyeska Pipeline Service Co., said in an interview. Alyeska employs more than 800 workers, according to its website.

Shell said it also plans to build a connector, half the length of the Trans Alaska pipeline, across the North Slope to bring Chukchi oil to the existing line.

Tax Revenue
“It will be hugely expensive, it’s in the billions,” Slaiby said in an interview at his office in an Anchorage high- rise with a view of the Chugach Mountains, blue and shrouded in clouds.

Shell’s investments will bring $3.7 billion of tax revenue to the North Slope Borough, which borders both seas, according to the Northern Economics-University of Alaska analysis, which was released in February. Alaska’s state government would gain about $4.8 billion from property, corporate and income taxes through 2057, and the federal government would collect $161.3 billion.

U.S. approval for Shell to drill 10 Arctic offshore wells over the next two years may encourage more investment from Statoil of Stavanger, Norway, and Houston-based ConocoPhillips. Those companies also purchased Chukchi Sea leases and aren’t as far along in the process.

Statoil in Anchorage
“We’re following what’s happening with the other operators closely, and we hope that Shell is successful in drilling next year,” Lars Andreas Sunde, head of Statoil’s Anchorage office, said in an interview. “It will of course be a positive to the industry.”

Statoil opened its Anchorage office this year, as did Noble Corp. (NE), owner and manager of the Discoverer rig that Shell plans to use for the 2012 to 2013 drilling season. Shell rented the Discoverer in January to use in New Zealand this year at a rate of $155,000 a day, according to the website of Baar, Switzerland-based Noble.

Pledging to benefit local residents, Shell hired North Slope native corporations to write permit applications, engineer oil-spill response and containment and dispose of waste once exploration begins.

Waste-Management Contract
Among Shell’s Eskimo contractors is Tikigaq Corp., which provides financial support for the Inupiat villagers in Point Hope, the center of opposition to Shell’s plans.

Tikigaq’s waste-management contract with Shell, renewed every year since 2007, is more profitable than services sold to its main client, the U.S. Department of Defense, according to the corporation’s Chief Operating Officer Troy Izatt.

Because exploration hasn’t begun, Tikigaq has allotted only two workers to Shell, both based in Anchorage. One is a native of Point Hope.

“Tikigaq Corp. and its board of directors support the offshore development if it’s responsible,” Izatt said in an interview at his office, where a fur-trimmed wooden tribal mask hangs on the wall.“I always look forward to good news for Alaska, what helps all Alaskans, including natives.”


http://www.bloomberg.com/news/2011-...-count-on-shell-s-bounty-from-arctic-oil.html

 

[trysail]

As much as I wish it were accurate and reliable, there's a fair bit of exaggeration and wishful thinking in this piece. Mr. Hamm didn't get where he is by being a shy, conservative, self-effacing pessimist. To go along with that, there's a horribly telling quote (see below) from the Utopian-in-Chief who is clearly not well-informed on the subject.

_______________________



http://online.wsj.com/article/SB10001424052970204226204576602524023932438.html



How North Dakota Became Saudi Arabia

Harold Hamm, discoverer of the Bakken fields of the northern Great Plains, on America's oil future and why OPEC's days are numbered.
By STEPHEN MOORE

Harold Hamm, the Oklahoma-based founder and CEO of Continental Resources, the 14th-largest oil company in America, is a man who thinks big. He came to Washington last month to spread a needed message of economic optimism: With the right set of national energy policies, the United States could be "completely energy independent by the end of the decade. We can be the Saudi Arabia of oil and natural gas in the 21st century."

"President Obama is riding the wrong horse on energy," he adds. We can't come anywhere near the scale of energy production to achieve energy independence by pouring tax dollars into "green energy" sources like wind and solar, he argues. It has to come from oil and gas.

You'd expect an oilman to make the "drill, baby, drill" pitch. But since 2005 America truly has been in the midst of a revolution in oil and natural gas, which is the nation's fastest-growing manufacturing sector. No one is more responsible for that resurgence than Mr. Hamm. He was the original discoverer of the gigantic and prolific Bakken oil fields of Montana and North Dakota that have already helped move the U.S. into third place among world oil producers.

How much oil does Bakken have? The official estimate of the U.S. Geological Survey a few years ago was between four and five billion barrels. Mr. Hamm disagrees: "No way. We estimate that the entire field, fully developed, in Bakken is 24 billion barrels."

If he's right, that'll double America's proven oil reserves. "Bakken is almost twice as big as the oil reserve in Prudhoe Bay, Alaska," he continues. According to Department of Energy data, North Dakota is on pace to surpass California in oil production in the next few years. Mr. Hamm explains over lunch in Washington, D.C., that the more his company drills, the more oil it finds. Continental Resources has seen its "proved reserves" of oil and natural gas (mostly in North Dakota) skyrocket to 421 million barrels this summer from 118 million barrels in 2006.

"We expect our reserves and production to triple over the next five years." And for those who think this oil find is only making Mr. Hamm rich, he notes that today in America "there are 10 million royalty owners across the country" who receive payments for the oil drilled on their land. "The wealth is being widely shared."

One reason for the renaissance has been OPEC's erosion of market power. "For nearly 50 years in this country nobody looked for oil here and drilling was in steady decline. Every time the domestic industry picked itself up, the Saudis would open the taps and drown us with cheap oil," he recalls. "They had unlimited production capacity, and company after company would go bust."

Today OPEC's market share is falling and no longer dictates the world price. This is huge, Mr. Hamm says. "Finally we have an opportunity to go out and explore for oil and drill without fear of price collapse." When OPEC was at its peak in the 1990s, the U.S. imported about two-thirds of its oil. Now we import less than half of it, and about 40% of what we do import comes from Mexico and Canada. That's why Mr. Hamm thinks North America can achieve oil independence.

The other reason for America's abundant supply of oil and natural gas has been the development of new drilling techniques. "Horizontal drilling" allows rigs to reach two miles into the ground and then spread horizontally by thousands of feet. Mr. Hamm was one of the pioneers of this method in the 1990s, and it has done for the oil industry what hydraulic fracturing has done for natural gas drilling in places like the Marcellus Shale in the Northeast. Both innovations have unlocked decades worth of new sources of domestic fossil fuels that previously couldn't be extracted at affordable cost.


Mr. Hamm's rags to riches success is the quintessential "only in America" story. He was the last of 13 kids, growing up in rural Oklahoma "the son of sharecroppers who never owned land." He didn't have money to go to college, so as a teenager he went to work in the oil fields and developed a passion. "I always wanted to find oil. It was always an irresistible calling."

He became a wildcat driller and his success rate became legendary in the industry. "People started to say I have ESP," he remarks. "I was fortunate, I guess. Next year it will be 45 years in the business."

Mr. Hamm ranks 33rd on the Forbes wealth list for America, but given the massive amount of oil that he owns, much still in the ground, and the dizzying growth of Continental's output and profits (up 34% last year alone), his wealth could rise above $20 billion and he could soon be rubbing elbows with the likes of Warren Buffett.

His only beef these days is with Washington. Mr. Hamm was invited to the White House for a "giving summit" with wealthy Americans who have pledged to donate at least half their wealth to charity. (He's given tens of millions of dollars already to schools like Oklahoma State and for diabetes research.) "Bill Gates, Warren Buffett, they were all there," he recalls.

When it was Mr. Hamm's turn to talk briefly with President Obama, "I told him of the revolution in the oil and gas industry and how we have the capacity to produce enough oil to enable America to replace OPEC. I wanted to make sure he knew about this."

The president's reaction? "He turned to me and said, 'Oil and gas will be important for the next few years. But we need to go on to green and alternative energy. [Energy] Secretary [Steven] Chu has assured me that within five years, we can have a battery developed that will make a car with the equivalent of 130 miles per gallon.'" Mr. Hamm holds his head in his hands and says, "Even if you believed that, why would you want to stop oil and gas development? It was pretty disappointing."

Washington keeps "sticking a regulatory boot at our necks and then turns around and asks: 'Why aren't you creating more jobs,'" he says. He roils at the Interior Department delays of months and sometimes years to get permits for drilling. "These delays kill projects," he says. Even the Securities and Exchange Commission is now tightening the screws on the oil industry, requiring companies like Continental to report their production and federal royalties on thousands of individual leases under the Sarbanes-Oxley accounting rules. "I could go to jail because a local operator misreported the production in the field," he says.


The White House proposal to raise $40 billion of taxes on oil and gas—by excluding those industries from credits that go to all domestic manufacturers—is also a major hindrance to exploration and drilling. "That just stops the drilling," Mr. Hamm believes. "I've seen these things come about before, like [Jimmy] Carter's windfall profits tax." He says America's rig count on active wells went from 4,500 to less than 55 in a matter of months. "That was a dumb idea. Thank God, Reagan got rid of that."

A few months ago the Obama Justice Department brought charges against Continental and six other oil companies in North Dakota for causing the death of 28 migratory birds, in violation of the Migratory Bird Act. Continental's crime was killing one bird "the size of a sparrow" in its oil pits. The charges carry criminal penalties of up to six months in jail. "It's not even a rare bird. There're jillions of them," he explains. He says that "people in North Dakota are really outraged by these legal actions," which he views as "completely discriminatory" because the feds have rarely if ever prosecuted the Obama administration's beloved wind industry, which kills hundreds of thousands of birds each year.

Continental pleaded not guilty to the charges last week in federal court. For Mr. Hamm the whole incident is tantamount to harassment. "This shouldn't happen in America," he says. To him the case is further proof that Washington "is out to get us."

Mr. Hamm believes that if Mr. Obama truly wants more job creation, he should study North Dakota, the state with the lowest unemployment rate in the nation at 3.5%. He swears that number is overstated: "We can't find any unemployed people up there. The state has 18,000 unfilled jobs," Mr. Hamm insists. "And these are jobs that pay $60,000 to $80,000 a year." The economy is expanding so fast that North Dakota has a housing shortage. Thanks to the oil boom—Continental pays more than $50 million in state taxes a year—the state has a budget surplus and is considering ending income and property taxes.

It's hard to disagree with Mr. Hamm's assessment that Barack Obama has the energy story in America wrong. The government floods green energy—a niche market that supplies 2.5% of our energy needs—with billions of dollars of subsidies a year. "Wind isn't commercially feasible with natural gas prices below $6" per thousand cubic feet, notes Mr. Hamm. Right now its price is below $4. This may explain the administration's hostility to the fossil-fuel renaissance.

Mr. Hamm calculates that if Washington would allow more drilling permits for oil and natural gas on federal lands and federal waters, "I truly believe the federal government could over time raise $18 trillion in royalties." That's more than the U.S. national debt, I say. He smiles.

This estimate sounds implausibly high, but Mr. Hamm has a lifelong habit of proving skeptics wrong. And even if he's wrong by half, it's a stunning number to think about. So this America-first energy story isn't just about jobs and economic revival. It's also about repairing America's battered balance sheet. Someone should get this man in front of the congressional deficit-reduction supercommittee.


http://online.wsj.com/article/SB10001424052970204226204576602524023932438.html

 

[trysail]

Believe me, I am well aware there are folk 'round heah who don't want to hear this, but there's a simple reason for the virtual collapse of natural gas prices ( you know, the stuff they use to make the electricity that lights up the dark and that you use to heat your house and cook ).

I'll even bet you can guess what that reason is.


http://alfred.stlouisfed.org/graph/alfredgraph.png?graph_id=42961

EIA projects that the average price paid by households in the Northeast this winter (October through March) for heating oil may be the highest ever, almost $27 per MMBtu ($3.71 per gallon) or more than double the projected average cost of natural gas ($12.93 per MMBtu) delivered to households in the Northeast.

http://www.eia.gov/todayinenergy/images/2011.10.12/WinterFuels2011_p1.png

http://ir.eia.gov/ngs/ngs.gif



​

 

[trysail]

http://www.petrobras.com.br/ri/Show...==&id_canalpai=/zfwoC+leAQcwFyERVZzwQ==&ln=en


Declaration of Commerciality on the Tupi and Iracema Areas

Rio de Janeiro, December 29 2010 – Petróleo Brasileiro S.A. - Petrobras, as the operator of Block BMS-11, located in the Santos Basin, announces that it submitted today the Declaration of Commerciality of the oil and gas accumulations in the Tupi and Iracema areas to the National Petroleum Agency (ANP). In the proposal submitted to the ANP, the names suggested for these accumulations were Lula Field and Cernambi Field, respectively, for Tupi and Iracema.

The total recoverable volumes of these fields, as reported to the ANP, are:

Area
 Field
 Total Recoverable Volume

(billions of boe)
 º API
 
Tupi
 Lula
 6.5
 28
 
Iracema
 Cernambi
 1.8
 30
 
Total
 8.3

The Lula Field will be the first supergiant oil field in Brazil (recoverable volumes above 5 billion boe), while the Cernambi Field is among the top-five giant fields in Brazil.

The Final Report on the Evaluation Plan and the Development Plan (PD) for the two fields are also being submitted to the ANP together with the Declaration of Commerciality.

The Declaration of Commerciality is being made after the completion of the Exploratory Program for the area, considering that the first well was drilled in October 2006. The 11 wells drilled in these two areas and the Extended Well Test (EWT) in the Tupi area, which started in April 2009, generated the key information on which the total recoverable volume was estimated, as well as the Production Development Plans.

The exploratory success achieved in the area represents the high potential of pre-salt, which is already contributing to the growth of the Company's production curve and of its oil and gas reserves.

Block BMS-11 is operated by Petrobras, which holds 65% of the concession. BG Group, with 25% of the stakes, and Galp Energia, with a 10% interest, are the other parties to the consortium.

 

[trysail]

http://www.bloomberg.com/news/2011-10-17/bp-says-anadarko-to-pay-4b-to-settle-spill-claim.html



Anadarko to Pay $4B to Settle Spill Claim
By Kari Lundgren and Brian Swint
October 17, 2011

BP Plc (BP/), the operator of the Macondo well in the Gulf of Mexico that was the source of the worst U.S. oil spill last year, said Anadarko Petroleum Corp. (APC) will pay $4 billion to settle all claims over the disaster.

Anadarko, which had a 25 percent stake in the well, will no longer pursue allegations of gross negligence against BP. The payment will be made in a single cash sum and will be put in the $20 billion trust being used to repay claims and damages. Under the terms of the deal, Anadarko will transfer its stake in the Macondo well back to BP, the companies said in separate statements today.

The Anadarko settlement will be a boost to BP as the oil company prepares for a February trial in New Orleans to establish liability for the catastrophe. BP would face higher fines if it’s found guilty of gross negligence for the spill, which pumped almost 5 million barrels of crude into the Gulf and forced the company to write off $41 billion. Rig owner Transocean Ltd. (RIG) and Halliburton Co. (HAL), which supplied cement for Macondo, are also defendants.

“This is likely to be seen as good news for BP and will increase pressure on Transocean and Halliburton to settle ahead of the multi-district litigation,”

***​

Anadarko’s Costs
The cost of the settlement will be $5 a share after tax, with the $4 billion payment applied to third-quarter results, The Woodlands, Texas-based Anadarko said today in a filing. Anadarko said it will use cash on hand and draw on $5 billion of bank credit to pay BP within 45 days.

“Though the agreement does not provide indemnification against fines and penalties, punitive damages or certain other potential claims, we do not consider these items to represent a significant financial risk to Anadarko,” Chairman and Chief Executive Officer James T. Hackett said in the filing.

BP will withdraw claims of $6.1 billion against Anadarko, the company said.

Under the terms of the settlement, both parties agreed to drop claims against the other. Anadarko and BP have agreed to work together with respect to indemnified claims and Anadarko has the opportunity for a 12.5 percent participation in recoveries from others or insurance proceeds exceeding $1.5 billion and up to a total cap of $1 billion...

‘Clear Progress’
...BP has now reached a settlement with both partners in the Macondo well. In May, a unit of Mitsui & Co., which had a 10 percent holding in the well, agreed to pay $1.065 billion. Based on that figure analysts had expected a settlement of between $2 billion and $3 billion for Anadarko.

Weatherford International Ltd. (WFT), which provided equipment for the Macondo well, agreed to pay BP $75 million.

“The good news is that Anadarko has abandoned charges of gross negligence,”... “We’re getting a drip feed of reports suggesting it was a multi-company event.”


more...

http://www.bloomberg.com/news/2011-10-17/bp-says-anadarko-to-pay-4b-to-settle-spill-claim.html

 

[trysail]

http://www.bloomberg.com/news/2011-...eps-carbon-on-top-nathan-myhrvold.html?cmpid=



The Energy Revolution...
By Nathan Myhrvold
October 26, 2011

A remarkable thing happened in Silicon Valley during the past decade. Venture capitalists and entrepreneurs set their sights on clean energy as the Next Big Thing. They audaciously hoped to reinvent energy by harnessing the incredible innovation that had transformed information technology and biotechnology.

Some of the best venture capitalists in the business, including my friends Bill Joy and Vinod Khosla, detached from their computing roots and focused on energy startups. The result was a staggering surge of capital into clean-energy technologies. Worldwide, from 2006 to 2010, about $535 billion in venture capital, private equity and initial public offerings as well as mergers and acquisitions flowed into 4,236 clean-tech businesses, according to a recent analysis by GlobalData.

Venture-capital investing is inherently high-risk, so it shouldn’t surprise or bother anyone that many of these startups failed -- some rather spectacularly. Solyndra LLC, the solar- cell company, for example, went bankrupt even after receiving a $535 million in loan guarantees from the U.S. Energy Department. But similar failures happened during the dot-com bubble. Remember pets.com and its infamous sock-puppet TV ads?

What is worrying is that almost a decade of energy investing hasn’t produced any home runs -- no green-energy equivalents of eBay, Amazon, Google or Facebook. The modest, incremental advances we have seen don’t perceptibly move the needle on the energy problem.

That’s not to say there aren’t good companies that swear they are just about to produce their miracle; in fact, my own company has spawned a startup -- called TerraPower -- that has developed a pretty amazing set of advanced technologies for nuclear energy. Let’s hope a few of us turn out to be right.

One Real Breakthrough
In the meantime, however, a real revolution has happened in traditional energy -- one that poses a serious challenge to companies and investors betting on alternative energy. This breakthrough is arguably one of the greatest advances in energy production since the 1960s. And it came not from a Silicon Valley company, or from MIT or Stanford, but from the son of a Greek goatherd who immigrated to the U.S.

George Mitchell was born in Galveston, Texas, went to Texas A&M University and, in 1946, founded an oil-drilling and real- estate business. The company did well, and in the 1980s, Mitchell decided to take on a major technical challenge: He would try to coax gas out of a portion of the Barnett shale, which lies deep under Fort Worth and 15 counties in north- central Texas.

People told Mitchell he was wasting his money; you can’t squeeze blood from a stone, and you can’t squeeze oil or gas out of shale, which is essentially fossilized mud. Huge amounts of natural gas have formed in layers of shale, but it’s trapped within the rock and doesn’t flow toward a borehole.

The same is true of vast gas deposits that are stuck in coal beds too deep to mine, and gas that saturates spongelike sandstones and other semiporous rocks. Pulling out this “tight gas,” as drillers call it, is like trying to suck a thick milkshake through a thin cocktail straw or to breathe through a pillow.

But Mitchell was stubborn. He and his roughnecks doggedly tinkered with a variety of long-known techniques that had never been used in combination. One of these was horizontal drilling, which originated in the 19th century, was adapted for oil production by the Soviets in the 1930s and was perfected by oil drillers in the 1980s.

Cracking the Rock
A second idea was to inject fluid into the rock to fracture it into lots of pieces, thus allowing the gas and oil inside to flow more easily. In 1865, Colonel Edward Roberts, a Civil War veteran, demonstrated (and patented) the use of explosive nitroglycerin for this purpose -- which worked amazingly well, but was quite dangerous. By the 1940s, engineers had developed a gentler approach that uses high-pressure water and chemicals rather than explosions to break up the rock. It became a standard practice for some oil, gas and water wells.

A third technique that Mitchell tried was adding sand to the water to help prop open the cracks that formed in the rock. Together these approaches, collectively called hydraulic fracturing, or “fracking,” allowed drillers to inexpensively recover gas from the tight Barnett shale. Mitchell earned nothing for developing the technology, but his company went on to make a lot of money on gas leases.

A great many others in the energy industry have done the same, as the arrival of fracking unlocked enormous deposits of shale gas, tight gas and coal-bed methane across the U.S. and in other countries as well. Mitchell’s miracle has more than doubled the known reserves of natural gas.

The new resources are so vast that they would last for a century at current rates of gas consumption. And this cheap form of energy isn’t under the control of a foreign dictator, stuck in the Arctic or submerged miles below the sea -- it lies in the farmlands of New York, Pennsylvania and Texas.

The location turns out to be something of a mixed blessing; yes, these places are secure and politically stable, but they are also home to not-in-my-backyard activists who claim fracking threatens to pollute groundwater, in some cases to the point where flames will spew from people’s shower heads.

Industry experts says that is unlikely because the gas- containing rock typically lies 2 miles or more underground, in strata that are geologically isolated from groundwater. However, any form of natural-gas production can produce some environmental issues because it must be piped to the surface, and gas sometimes leaks into groundwater through breaks in the pipe, or through abandoned wells.

Another problem is that the water pumped underground for fracking gets contaminated in the process, and much of that waste comes back up and must be stored. As for the rare flaming faucet, it’s hard to tell whether fracking is to blame, because the same regions where this technique is most profitable tend to have shallower, natural deposits of gas that can contaminate groundwater without any help from industry.

Energy vs. Environment
So far, scientific evidence has not clearly linked the fracking procedure itself to groundwater contamination. But if there is anything we learned from the BP oil spill in the Gulf of Mexico last year, it is that any technology that produces energy in large quantities poses some environmental risk. So as a society, we face an interesting question: Would we rather depend for our energy on distant suppliers in the Mideast and elsewhere? Or is it better to produce the energy ourselves and accept the risk of creating some messes in our backyards?

***​

...New technologies are always risky and -- as George Mitchell found -- they almost never work perfectly from the start. So investors need an incentive to take that risk...

***​

...Not so long ago, many people believed that the cost of oil and gas would rise indefinitely, thus supporting the market for alternatives. Mitchell’s miracle has changed that calculus, much to the chagrin of the Silicon Valley venture capitalists who caught the green-energy bug.



http://www.bloomberg.com/news/2011-...eps-carbon-on-top-nathan-myhrvold.html?cmpid=

 

[trysail]

Nigeria Oil Spills Largely Due To Theft

Jon Gambrell
November 2, 2011

LAGOS, Nigeria (AP) -- Royal Dutch Shell PLC long has argued that thieves are to blame for most of the oil spills coming from pipelines in Nigeria's crude-producing southern delta. Now the company is trying to prove that claim in real time on the Internet.

Shell, the dominant oil company in Nigeria since production began there more than 50 years ago, has started posting photographs and reports on a website from every oil spill investigated by the company this year.

"Nobody else operating in the Niger Delta comes close to this level of transparency," Shell vice president Tony Attah said in a statement. "But regardless of how well we run our operations until sabotage and crude theft spills are stopped or curbed, the vast majority of oil spills will continue to blight large swathes of land and pollute rivers and farm lands."

While the majority of spills bear the telltale signs of thieves' hacksaw marks, it remains unlikely though this latest public relations move will help the image a company long demonized by environmentalists in Africa's most populous nation. Environmentalists here estimate over the last half century, enough oil has been spilled to equal one Exxon Valdez disaster per year.

Shell mentioned the website Wednesday in a statement warning that its Nigerian subsidiary faces an "unprecedented" level of oil thefts targeting its operation at Imo River, a field that spreads across Rivers and Abia states in the Niger Delta. The company shut its operation there in late August after a series of oil thefts caused oil spills, halting production at a field that produces just more than 1 million gallons of oil a day.

The company said a recent helicopter flight over the region saw thieves carting away the stolen crude in waiting river barges and trucks. Though production has stopped, the oil still can be taken from the pipelines there.

Also Wednesday, Shell announced it had lifted a production warning for its Forcados crude shipments after it shut down its Trans Forcados pipeline in early October following a "sabotage leak."

Shell pipelines and flow stations run across Nigeria's oil-rich delta region of swamps, mangroves and creeks, which is roughly the same size as South Carolina. Many areas remain remote, allowing thieves to tap into the lines to steal the easily refined crude oil produced here that makes Nigeria a top supplier to the U.S. Some of the oil is shipped out of the country, while others at crude refineries in the swamps cook it into diesel fuel.

Experts and oil companies estimate thieves take hundreds of thousands of barrels a day from fields in Nigeria. A recent United Nations report on environmental damage in one part of the delta suggested there could be "collusion" between oil thieves and government officials to allow the thefts.

While unable to stop the theft, Shell launched its oil spill website to highlight what it says causes spills in the region. Reports on the website from January to Oct. 20 of this year show the company's pipelines spilled about 500,000 gallons of oil this year -- of which just under a fifth came from operational errors or pipeline ruptures caused by Shell.

However, the largest spills -- including a Feb. 9 spill and fire that saw 184,000 gallons of oil released -- were caused by sabotage or theft, the Shell reports claim.

Each of the reports bear checklists showing them signed off by community leaders and Nigeria government officials, though Shell said it withholds the signatures and names of the officials out of security concerns.

The existence of the website came as a surprise to environmental activists, including Nnimmo Bassey, executive director of the Nigerian group Environmental Rights Action. However, Bassey cautioned that spill figures remained estimates, as Shell so far had refused to offer statistics on how much oil actually gets pumped out of its well sites.

This year's reports also don't take into account the damage done in the Niger Delta over 50 years of production, he said. Some environmentalists say as much as 550 million gallons of oil have poured into the delta during that period -- at a rate roughly comparable to one Exxon Valdez disaster per year.

"The Niger Delta is a dead environment," Bassey said. "Telling us now they are not responsible, as of now or yesterday, is not the issue. The issue is the blame and guilt that has been established historically and they need to begin to clean up the mess."


http://finance.yahoo.com/news/Shell-uses-Internet-to-show-apf-1690419542.html?x=0&.v=4

 

[trysail]

Can you spell "Marcellus Shale?"


_____________________


http://www.bloomberg.com/news/2011-...o-u-s-plunge-on-shale-gas-supply-rise-1-.html



Trinidad’s LNG Exports to U.S. Plunge on Increased Shale Gas Production
By Wael Mahdi
November 13, 2011

Trinidad and Tobago, the largest exporter of liquefied natural gas to the U.S., said exports to that country have fallen “sharply” because of rising U.S. shale gas production.

The share of Trinidad and Tobago’s LNG exports accounted for by the U.S. has plunged to 25 percent, from 75 percent three years ago, Energy Minister Kevin Ramnarine said today in an interview in Doha, Qatar. The U.S. is the largest single destination for the Caribbean producer’s exports, he said.

Trinidad and Tobago exports 15 million metric tons of the fuel a year and will continue to ship this amount even if the U.S. reduces imports, he said. The country is shifting some of the supplies previously sent to the U.S. to markets in South America, mainly Brazil, Argentina, and Chile, and also to Asia, Ramnarine said.

“There is strong demand from Asia, especially Japan, and we are getting better prices there too,” he said.

Japan increased its imports of LNG after an earthquake in March knocked out nuclear power stations in the country, Ramnarine said.

“The LNG market is very robust at the moment,” he said. The nation exports 22 percent of its output to Asia, he said.

The country has four LNG production lines and is considering building a small-scale plant to ship the fuel to smaller Caribbean Islands as demand in those nations is rising.




http://www.bloomberg.com/news/2011-...o-u-s-plunge-on-shale-gas-supply-rise-1-.html

_____________________


http://www.bloomberg.com/news/2011-...ifth-year-of-gas-declines-energy-markets.html



Shale Boom Heralds Fifth Year of Gas Declines
By Christine Buurma
December 21, 2011

Booming U.S. natural gas production from shale formations and slowing demand from households, factories and power plants are poised to send prices down for an unprecedented fifth year in 2012.

Gas may tumble 8.2 percent from its 2011 average next year, as output rises 2.8 percent to a record 67.72 billion cubic feet a day, according to the Energy Department. Demand will probably climb 1.7 percent, after a 1.8 percent increase this year, the department said in its Dec. 6 Short-Term Energy Outlook.

“It’s been practically impossible to turn off the shale- gas tap,” Adam Sieminski, chief energy economist at Deutsche Bank AG in Washington, said in a telephone interview Dec. 14. “Industrial demand has been rising, but it’s not enough.”

Natural gas has dropped 28 percent on the New York Mercantile Exchange this year, the most since 2006, as improved drilling technology and profits from selling gas liquids encouraged producers to pump record amounts of the fuel from shale formations from Texas to Pennsylvania. Futures have dropped in each of the past three years, the longest stretch of declines since the contracts began trading on the Nymex in 1991.

Gas at the Henry Hub in Erath, Louisiana, the delivery point for New York futures contracts, will slip to $3.70 per million Btu next year, the Washington-based Energy Department said in its Dec. 6 report. It would be the lowest average price since 2002, according to data compiled by Bloomberg. The average spot price for the current year is $4.03 per million Btu.

Citigroup Cuts Forecast
The January contract rose 1.2 percent to $3.164 per million British thermal units at 4:16 p.m. in electronic trading on the Nymex after settling at $3.155.

Citigroup Global Markets Inc. cut its forecast for the average 2012 natural gas price to $3.30 on Dec. 19, citing production growth and record inventories. The bank previously predicted $4.10 if a colder-than-normal winter materialized and $3.85 should temperatures stay close to the 10-year average.

Average year-to-date supply growth has climbed to a “staggering” 4.5 billion cubic feet a day, J. Marshall Adkins, an analyst at Raymond James & Associates in Houston, said in a note to clients Dec. 5.

“With that much gas supply growth, it’s a wonder why prices weren’t even lower this year” said Adkins, who lowered his 2012 price estimate to $3.50 per thousand cubic feet ($3.41 per million Btu) from $4.

Improved Technology
The drilling of longer horizontal sections of wells and fracturing of rocks in multiple locations have helped producers increase output from formations such as the Marcellus shale in the U.S. Northeast even as prices fell, Sieminski said. Production from shale deposits, where water and chemicals are pumped underground at high pressure to break apart rock and release gas, more than doubled from 2007 to 2009, according to the most recent Energy Department data.

“While our previous outlook anticipated a slow decline in gas-well completions and connections in 2012, we now believe they will come to market at about the same pace as in 2011, resulting in supply growth through 2012 and 2013,” Michael Zenker, an analyst at Barclays Capital in New York, said in a Nov. 1 note. Prices will average $3.80 per million Btu next year, down from a previous forecast of $4.55, he said.

Rising prices for gas liquids such as ethane and propane, which are byproducts of natural gas production, have also supported higher shale output, Sieminski said. The price of ethane at the Mont Belvieu hub in Texas has climbed 28 percent this year to 80 cents per gallon, according to data from Liquidity Partners, a Houston brokerage.

Rig Declines
A drop in drilling rigs and rising exports to Canada may stop the price declines in 2012, said Dan Rice, managing director of BlackRock Inc.’s global resources team in Boston, who oversees more than $5 billion in assets. Prices may average $4 next year, rising to $4.50 in the second half of 2012, he said in an interview on Dec. 14.

The number of rigs drilling for gas in the U.S. dropped two to 818 in the week ended Dec. 16, the lowest amount since Jan. 15, 2010, according to data from Baker Hughes Inc. in Houston. It was the seventh consecutive weekly decline. U.S. gas exports to Canada totaled 77.4 billion cubic feet in September, up 56 percent from a year earlier, Energy Department data show.

Production from the Haynesville shale in Louisiana has averaged 6.8 billion cubic feet a day in 2011, or 11 percent of total U.S. marketed production, Scott Hanold, an analyst at RBC Capital Markets in Minneapolis, said by phone Dec. 15. Marcellus gas is contributing about 3 billion a day, he said.

‘Incredible’ Growth
“The Haynesville shale is growing at an incredible rate and has become a meaningful part of overall supply,” he said. “The bottom line is that it’s going to be tough to absorb this supply with incremental demand growth in the short term,” said Hanold, who was the second-most accurate forecaster of natural gas prices through Sept. 30, based on a Bloomberg ranking of 23 analysts.

This winter will probably be milder than last year in the Northeast and mid-Atlantic states, limiting heating-fuel demand, Matt Rogers, president of Commodity Weather Group LLC in Bethesda, Maryland, said in a Nov. 21 revised seasonal outlook. About 51 percent of U.S. households use gas for heating, according to the Energy Department.

The period from November through March may be warmer than last year while still cooler than the 10-year average, Rogers predicted. In October he said that the coming U.S. winter may be the coldest in more than 10 years.

Record Supply
Inventories of gas reached an all-time high of 3.852 trillion cubic feet in the week ended Nov. 18, Energy Department data show. Stockpiles totaled 3.729 trillion as of Dec. 9, 10.3 percent above the five-year average and 4.3 percent higher than last year’s level for that time of year.

Consumption may rise at a slower pace in 2012 after climbing to 67.18 billion cubic feet a day, according to the Energy Department. Demand from factories, including fertilizer producers that use gas as a feedstock, may be tepid amid economic weakness, said Peter Buchanan, senior economist at CIBC World Markets Inc. in Toronto.

Industrial demand for gas may climb 0.2 percent next year after gaining 2.3 percent in 2011, the Energy Department said in the Dec. 6 Outlook.

U.S. industrial production unexpectedly dropped in November for the first time in seven months, indicating a pause in manufacturing growth, figures from the Federal Reserve on Dec. 15 showed. Output at factories, mines and utilities declined 0.2 percent after a 0.7 percent gain in October. Economists forecast a 0.1 percent advance, according to the median estimate in a Bloomberg survey.

“We’re probably going to see slower growth on the industrial-demand side,” Buchanan said in a telephone interview on Dec. 15. “The factory sector has lost a bit of momentum.”



http://www.bloomberg.com/news/2011-...ifth-year-of-gas-declines-energy-markets.html

 

[trysail]

http://www.bloomberg.com/news/2011-...king-anxiety-over-lust-for-fossil-fuels.html#



Oil Abundance in Canada Provokes Anxiety
By John Lippert and Jeremy van Loon
November 22, 2011

The helicopter swooping over once- pristine spruce forests provides a close-up view of why the province of Alberta, Canada, is among the planet’s most coveted -- and contested -- petroleum hot spots.

North of Fort McMurray, a boomtown serving tens of thousands of migrant workers, Syncrude Canada Ltd.’s oil-sands mine stretches 74 square miles.

Rivals Exxon Mobil Corp. and China Petroleum & Chemical Corp. each have bought a piece of Syncrude, one of the dozens of companies that are blasting, digging and steaming soil laden with 143 billion barrels of molasseslike crude called bitumen, Bloomberg Markets magazine reports in its January issue. Only Saudi Arabia, with 264 billion barrels, and Venezuela, with 211 billion, enjoy greater proven reserves, a BP Plc energy review found in June.

Some of the world’s biggest energy producers have poured C$123 billion (US$120 billion) into Canada’s oil sands since 1997. The Canadian Energy Research Institute, or CERI, predicts that these companies will pay another C$137 billion by 2020 to tap the Florida-sized region’s unique advantage: rising oil production taking place in a stable democracy that’s close to the massive American market.

‘Pot of Money’
Prime Minister Stephen Harper, who began his career in the Edmonton mailroom of an Exxon unit called Imperial Oil Ltd., is encouraging the boom. He wants to pump as much as possible from reserves that were valued at $14 trillion in mid-November.

Harper, 52, is creating jobs and seeking new markets for a country that now sends 99 percent of its petroleum exports to the U.S. Environmentalists, alarmed by spills, desecrated forests and rising carbon emissions, want a moratorium on oil- sands projects not yet approved as they battle to curb the use of fossil fuels.

“Oil sands are a big enough pot of money to change the landscape,” says Peter Wells, chairman of Abingdon, England- based Neftex Petroleum Consultants Ltd. “That’s why everybody’s fighting over them. The Chinese want strategic supplies. Oil companies want profits. Environmentalists want to keep Alberta looking as it was.”

The U.S. government leapt into the fray in November. The State Department announced that it was delaying a decision on TransCanada Corp. (TRP)’s proposed 1,661-mile (2,673-kilometer) pipeline from Alberta to the Gulf of Mexico. President Barack Obama, 50, pressured by environmentalists and citizens along the route, said his administration wanted to protect health, safety and natural resources on the pipeline’s path.

Avoiding the Sandhills
Four days later, TransCanada, that nation’s No. 2 pipeline company, said it would find a new route that would avoid Nebraska’s environmentally sensitive Sandhills, which shelter a shallow aquifer. The company also said Nebraskans would play a key role in determining the final course.

TransCanada had been lobbying Secretary of State Hillary Clinton for approval of the C$7 billion pipeline to Texas refineries, from where suppliers could reach new customers. The U.S. must approve the conduit because it crosses an international border.

After the November delay and TransCanada’s rerouting proposal, the department will need 12 to 18 months for its assessment, deputy spokesman Mark Toner said. That time frame would put off a decision until after the U.S. presidential election.

Chinese Investing
The delay or even death of Keystone XL won’t mean the end of the oil sands, says Jeff Rubin, former chief economist in Toronto for CIBC World Markets Inc. Instead, losing that pipeline would push more Canadian oil across the Pacific, says Rubin, author of “Why Your World is About to Get a Whole Lot Smaller: Oil and the End of Globalization” (Random House, 2009).

“Prices are higher and customers aren’t so worried about carbon in Asia,’’ he says.

TransCanada Chief Executive Officer Russ Girling says China is interested in Canada’s crude.

“The Chinese have been the single largest investor in Canadian oil sands over the last couple of years,” Girling said in a Nov. 17 interview at Bloomberg’s New York headquarters.

Harper says he’ll make increasing exports to Asia a government priority.

“This does underscore the necessity of Canada making sure that we’re able to access Asian markets,” he said on Nov. 13, referring to the U.S. delay.

Too Much to Ignore
Enbridge Inc. (ENB), Canada’s largest oil pipeline company, is pursuing its C$5.5 billion Northern Gateway to the Pacific. It has backing from Asia’s biggest refiner, China Petroleum and Chemical, known as Sinopec.

Enbridge may also extend its U.S. network from Superior, Wisconsin, to the Gulf. On Nov. 16, Enbridge bought a stake in a pipeline called Seaway. The company plans to use it to ship as many as 400,000 barrels of crude a day from Cushing, Oklahoma, to the Gulf Coast. Enbridge’s existing pipes already carry oil- sands crude across the Canadian border and don’t need additional State Department approval.

Oil-sands production is inevitable in a world hungry for fossil-based energy, says Christian O’Neill, a Bloomberg Industries analyst in Princeton, New Jersey.

“Oil is too scarce and too expensive, and there’s too much in Alberta for people to ignore,” he says

Piracy in shipping lanes near the Persian Gulf and unrest in Iraq, Libya and elsewhere have destabilized supply from members of the Organization of Petroleum Exporting Countries. Dwindling reserves plague Russia, Mexico, Norway and others with state-owned industries.

‘They Will Ship’
“Oil sands are one of the last big petroleum resources available to private capital,” O’Neill says. “One way or the other they will ship it.”

Daily oil-sands output will double to 3 million barrels by 2020 and contribute 3 percent of world supply, up from 1.7 percent today, predicts energy researcher IHS CERA in Englewood, Colorado. Neftex’s Wells says he expects that daily output of traditional, non-OPEC crude will hold steady through 2020 and then drop 17 percent to 33 million barrels during the next decade, based on the firm’s worldwide geologic studies.

Alberta’s Fort McMurray is the larger-than-life locale spawning the controversy. Located 270 miles northeast of Edmonton and sandwiched between 400-foot-tall (122-meter-tall) bluffs whose bitumen seeps into the Athabasca River, the area calls to mind Brobdingnag in Jonathan Swift’s “Gulliver’s Travels.”

Fort McMurray
Fort McMurray, with 81,000 residents, has grown so fast that 34,000 workers live in dormitories nearby. Refineries glow and mushroom-shaped steam clouds tower overhead, even during winter nights with 17 hours of darkness and minus-40-degree Fahrenheit (minus-40-degree Celsius) temperatures.

For the U.S. and Chinese companies aiming to cash in, along with France’s Total SA (FP), Japan’s Nippon Oil Exploration Ltd., the U.K.’s BP and others, the cost is soaring. Operators bid up the price to lease an acre of government land to C$3,110.85 in June, 42 percent more than in July 2010, Alberta statistics show.

North of Fort McMurray, pit mines stretch as far as a person can see. Trucks haul loads of sand that weigh 400 tons - - more than a Boeing 747. The sand is boiled and shaken in vats three stories tall to coax out bitumen. The tarlike goo is piped to an upgrader that turns it into a lighter grade by blasting it with 900-degree-Fahrenheit steam laced with hydrogen.

‘Smells Like Money’
South of town, Statoil ASA (STL), Norway’s largest energy company, aims to produce 200,000 barrels of crude a day by 2020. That would equal about one-fifth of current production, which comes mainly from in and around the North Sea. Holding up a beaker of diluted bitumen at the Alberta site, Statoil Canada President Lars Christian Bacher grins.

“It smells like money,” he says.

Bacher, a 17-year veteran of storm-lashed North Sea oil rigs, says the extraction method that Statoil and dozens of operators are using in Canada could allay environmental concerns. Instead of leveling miles of forest, Statoil drills wells in cleared patches as small as 4 acres (1.6 hectares). Then, in a process called steam-assisted gravity drainage, or SAGD, it injects steam into the wells to melt bitumen underground.

Even SAGD has drawbacks, Neftex’s Wells says. It requires 1,000 cubic feet (28 cubic meters) of natural gas and 55 gallons of fresh water for every barrel of crude. On top of that, producing gasoline from oil-sands crude spews 20 percent more carbon than refining the fuel from light crude, he says. Bacher says Statoil aims to reduce carbon emissions per barrel by 40 percent by 2025 by using less steam and natural gas.

Prolonging Dependence
All oil-sands development prolongs fossil-fuel dependence, says Nathan Lemphers, an analyst at Canadian environmental research organization Pembina Institute.

In Fort McMurray, 65 square miles (168 square kilometers) of waste ponds hold water contaminated with arsenic and mercury. The stench from sulfur residue stacked eight stories tall can reach a helicopter at 1,000 feet. Environment Canada, the government agency that protects human health and the environment, says carbon dioxide emissions from the oil sands may triple by 2020, putting the country further behind on its Copenhagen Accord commitments to slow global warming.

Lemphers’s group wants a moratorium on any oil-sands projects that haven’t been approved. He says taxes on existing operations should pay for wind and solar research.

“We’re not trying to shut oil sands down,” he says. “We want the ecosystem preserved, and we want revenue that’s generated to fund the transition to a cleaner-energy economy.”

New Markets
Canada wasn’t as big a player in the world’s energy debate a decade ago. In 2001, the U.S. petroleum benchmark called West Texas Intermediate crude cost $20 a barrel. That price made oil- sands crude prohibitively expensive by comparison, says John Stephenson, a Toronto-based portfolio manager for First Asset Investment Management Inc. By 2011, the WTI price had climbed past the $70-a-barrel threshold needed for oil sands to provide a 10 percent return to investors, says Stephenson, who manages C$2.7 billion, including C$500 million in oil-sands shares.

“Oil sands have gone from being high-cost producers to just average,” he says.

Canada is reaping the rewards. By 2020, Alberta’s annual oil-sands royalties may grow fivefold to C$28 billion, according to CERI. Oil sands helped boost Alberta’s per-capita gross domestic product to C$70,824 in 2010, 75 percent more than Quebec’s.

Pacific Pipelines
Many of Canada’s elected officials were backing Pacific pipelines even before the Obama administration’s move on Keystone XL.

“As a country, you want no more than half to two-thirds of your export base tied up with one customer,” says Ron Liepert, who oversaw the boom as Alberta’s energy minister for 21 months before becoming the province’s finance minister in October.

Liepert didn’t want to stop with Keystone XL or Northern Gateway.

“You’re looking at four or five Keystone- and Gateway-type projects,” he said in September.

Part of his goal was to make it possible for Canadians to charge more for their oil.

Today, seven major pipelines carry Alberta crude and North Dakota shale oil to the U.S. Midwest. Only a few go farther south, so supply backs up in tank farms around Cushing, where the New York Mercantile Exchange settles widely traded oil futures contracts. The Nymex contracts bundle Canada’s oil with West Texas crude. As more Canadian and North Dakota oil has landed in Cushing, the influx has pushed the WTI price lower than it would have been without the new supply.

`Third World Relationship'
On Nov. 21, WTI closed at $96.92, or $9.96 per barrel less than Brent crude, the global benchmark. WTI traded for as much as $27.88 less than Brent on Oct. 14. For the past five years, WTI averaged only $3.03 less.

“Canada is in a Third World relationship with the U.S. because we send crude to Cushing at a discount,” says Wenran Jiang, a University of Alberta political science professor.

Canada wants the higher prices it says pipelines will bring. Keystone XL was designed to move 700,000 barrels a day to the Gulf of Mexico. Turning textbook economics on its head, the increased supply would eliminate the WTI/Brent differential, says Rick George, CEO of Suncor Energy Inc., (SU) Canada’s largest oil-sands producer. Instead of jamming up with WTI crude in Cushing, the oil would flow directly to the Gulf, home to almost half of U.S. refineries. Some might be exported, especially as diesel fuel for Europe.

“We’re just one pipeline away,” George says.

Environmental Risks
TransCanada studied 14 routes before deciding on the one that traversed Nebraska’s Sandhills and the underlying Ogallala Aquifer. Nebraska Governor David Heineman said in November that most Nebraskans would support the pipeline if it’s rerouted away from the Sandhills. Residents had complained during overflowing public hearings that the path would threaten the water for people in seven states and a third of irrigated groundwater for U.S. agriculture.

“If benzene gets in the groundwater, there would be no people, livestock or crops,” says Cindy Myers, a nurse in Stuart, Nebraska, who opposes the Sandhills route.

The U.S. Environmental Protection Agency buoyed opponents’ claims by saying in June that the State Department hadn’t conducted a thorough analysis of spills and other potential hazards. Despite the rebuke, the State Department said in August that it saw few environmental risks.

White House Arrests
The State Department review was riddled with conflicts, says Steve Kretzmann, executive director of Washington environmental group Oil Change International.

“The process is a sham,” he says. Kretzmann noted that Paul Elliott, TransCanada’s chief Washington lobbyist, was deputy director for delegate selection for the Clinton campaign during her 2008 presidential bid. The State Department’s Office of Inspector General, in a Nov. 4 memo, said it would investigate to make sure the department’s handling of Keystone XL was lawful.

TransCanada declined to make Elliott available for this article. The department has met with TransCanada as well as with students and environmentalists, according to Kerri-Ann Jones, an assistant secretary of state.

Frustrated partly because Congress shelved a cap-and-trade program to limit carbon emissions, more than 1,200 protesters against Keystone XL have been arrested in demonstrations at the White House since August.

Nebraska Blowouts
Teri Taylor in Newport, Nebraska, fought against Keystone XL in her state. Pointing to a cottonwood 6 miles north, Taylor, 58, shows where the original path would cross the ranch where her mother was born.

Driving amid grass and sunflowers the height of the hood of her pickup, she recalls spreading hay alongside fences to make sure that cattle didn’t dig up sand. She says the winds of a blizzard can turn a hoof mark into a blowout: a hole as big as a house that can take 30 years to fill.

Taylor has no faith that TransCanada would restore the ranch should the company dig trenches across it.

“Do I think they give a crap about my land?” she asks. “Look at what they’re doing to Fort McMurray.”

Susan Casey-Lefkowitz, director of international programs for the Natural Resources Defense Council, says her group will still fight to kill Keystone XL -- even with a revised course.

“The State Department has to look at how a spill might affect farmland all along the route and at the economics of increasing our dependence, far into the future, of a more high- carbon form of oil,” she says.

14 Spills
TransCanada has had 14 spills from Keystone since the first phase opened in 2010, says Vern Meier, the company’s vice president of U.S. pipeline operations. In May, the equivalent of about 500 barrels gushed from a pipe in North Dakota. Meier attributes the leak to a half-inch metal fitting that blew out because the increased pressure required to move heavy crude caused excessive vibrations. He says TransCanada replaced all such fittings and redesigned its pumps.

Robert Jones, Vice President of Keystone Pipelines, says the changes would mean fewer growing pains affecting the XL.

Enbridge, which is planning Northern Gateway, spilled about 20,000 barrels into Michigan’s Kalamazoo River in 2010 from its Line 6B pipeline. Enbridge CEO Pat Daniel says corrosion in the 41-year-old conduit may have been the culprit. Because the spill occurred during a flood, fast-moving waters churned the oil and silt and mixed them together. Even with a C$700 million cleanup, Daniel says the equivalent of about 200 barrels of oil remains submerged.

Moose Hunting
“It’s not a matter of if, but when, we have a spill,” says Jackie Thomas, leader of the Saik’uz band of aboriginal Canadians, who are protesting Northern Gateway.

Hunting and fishing have sustained her people in British Columbia for 900 years, the 47-year-old grandmother says. When Enbridge said in February it would give aboriginal groups C$1 billion in annual revenue-sharing from Northern Gateway, five bands -- including Thomas’s 1,000-member Saik’uz -- said no.

“If I have to stand in front of a bulldozer, that’s what I’ll do,” Thomas says as she drives a red Chevy pickup where she keeps her .267-caliber rifle poised for moose hunting.

Northern Gateway, with an initial installment of C$10 million from Sinopec, is crucial to China’s state-owned energy giants. They’ve invested C$17 billion in Alberta’s oil and gas industry in 20 months through mid-November.

As they spend more, they’ll need a way to get the crude home. The world’s largest energy consumer will require 11 million barrels a day in 2015, up from 9.2 million in 2011, says Brynjar Eirik Bustnes, a Hong Kong-based analyst at JPMorgan Securities Ltd. As traditional wells hit capacity, imports will have to fill the gap, he says.

Unocal Deal
Beijing became increasingly interested in Alberta when the U.S. rebuffed China in 2005, Bloomberg analyst O’Neill says. American lawmakers that August blocked a bid by China’s No. 3 oil company, Cnooc Ltd. (883), for El Segundo, California-based Unocal Corp.

Cnooc is two-thirds owned by the Chinese government, which then-North Dakota Democratic Senator Byron Dorgan, among others, complained might endanger U.S. supplies. Chevron Corp., (CVX) based in San Ramon, California, bought Unocal a few months later.

Chinese companies didn’t embrace Canada immediately, Jiang says. That’s because Harper was pressuring China to improve human rights and even declined to attend the 2008 Beijing Olympics.

Harper visited China in December 2009 after what Jiang describes as goading from Canadian business leaders. Six months later, Harper welcomed President Hu Jintao to Toronto and, toning down human-rights rhetoric, described relations between the nations as a strategic partnership.

‘Driving Force’
Since then, investments by Chinese energy companies have flowed, Alberta Finance Minister Liepert says. Sinopec paid C$4.65 billion for its 9 percent Syncrude stake last year. Cnooc spent C$2.1 billion in July for oil-sands operator Opti Canada Inc.

“Shale oil and gas, and oil sands, are expected to become an important driving force of long-term supply,” Cnooc CEO Yang Hua told reporters in August.

China’s hand in the oil sands may threaten U.S. interests, says Daniel Yergin, author of The Quest: Energy, Security and the Remaking of the Modern World (Penguin, 2011).

“If a significant portion of the oil sands is sold to China, it would be a major lost opportunity for U.S. energy security,” Yergin says.

Tankers Returning?
The 8,500 people in Kitimat, British Columbia, home to salmon, white-coated Kermode bears and 300-foot-tall firs, may become firsthand witnesses to the oil-sands tug of war. The hamlet, situated 100 miles southeast of Alaska where snow-capped peaks rise from the Douglas Channel, would be the western terminus of Northern Gateway. The channel stretches 90 miles to the Pacific, making it the starting point for Asian shipments. Tankers as long as three football fields would make S-shaped turns among islands less than a mile apart.

Canada barred tankers from its western coast after the Exxon Valdez dumped 267,000 barrels in Alaska in 1989. A federal task force may overturn the ban.

“If Northern Gateway goes ahead, oil will rule our country,” says Ian McAllister, director of Pacific Wild, a group dedicated to protecting coastal waters.

As the oil-sands clashes intensify, the world is flocking to Canada. Companies from China, which has responsibility for 1.3 billion consumers, are encamping in Alberta.

“If there are more means of transporting Alberta oil to the West Coast, Chinese and other Asian investment interest will increase,” Jiang says.

Central Role
The U.S. is striving to maintain its unique ties and generous oil allotments. Even as it delays a decision on a pipeline that environmentalists hate, it plans to review a new path, ensuring that the battle over Alberta’s bounty will brew for years to come.

“Nebraskans all over now know the power of people, and the pipeline fight will not be over, even though that is the hope of our leaders,” says Myers, the nurse from Stuart who protested Keystone XL.

Across the globe, nations are clamoring for oil and Alberta is eager to oblige. With all of these forces in play, Canada’s role in shaping the planet’s energy supply and navigating its ecopolitics is just beginning.



http://www.bloomberg.com/news/2011-...king-anxiety-over-lust-for-fossil-fuels.html#

 

[trysail]

http://www.bloomberg.com/news/2011-...l-means-work-for-exxon-bp-energy-markets.html



End of Easy Mideast Oil Means Work for Exxon, BP
By Anthony DiPaola, Eduard Gismatullin and Wael Mahdi
December 6, 2011

The Middle East will need more help from international investors to keep the title of world’s biggest oil and gas producer because its remaining deposits are harder to get at.

Technology is the “key to prolonging the life span of the reservoirs, and we’ve been doing this with our partners for a long time,” Mohamed Al-Hamli, oil minister of the United Arab Emirates, said yesterday at the World Petroleum Congress in Doha, Qatar. “We are forced to go down the road of enhanced oil recovery and using more advanced technology.”

Exxon Mobil Corp., Royal Dutch Shell Plc and other international oil producers will combine with state-owned companies to spend $40 billion in 2013 on developing resources in the Middle East, up 18 percent on last year’s tally, according to Wood Mackenzie Ltd. Fields that require technology, such as steaming to extract heavy oil in Kuwait or stripping sulfur out of Abu Dhabi’s natural gas, will attract much of that spending.

Demand for energy will grow faster in the Middle East over the next two decades than any region other than Asia, according to the International Energy Agency. Rising consumption of crude oil and natural gas at home will put pressure on Saudi Arabia, the U.A.E. and other governments to keep production high enough to maintain export revenue that finances government spending.

‘Easier Oil’
Middle East countries “have definitely produced most of their cheaper and easier oil,” Iain Brown, the head of regional research at Wood Mackenzie, said in a telephone interview. “These are projects where national oil companies have greater need for support from international oil companies, because the international oil companies have had more experience of these challenging conditions.”

The increasing expense of drilling oil has helped Brent crude futures, the benchmark price for about two-thirds of the world’s oil, rise fivefold over the last decade. Brent oil for January traded as high as $109.94 a barrel today on the ICE Futures Europe exchange in London.

Executives from international and national oil companies are meeting with state officials during the four-day World Petroleum Congress this week in Qatar. The chief executive officers of BP Plc, Shell, Exxon and ConocoPhillips spoke today. BP’s Robert Dudley said the energy industry needs to add the equivalent of a large, Saudi Arabia-size producer each year to offset the decline in output capacity at existing oil fields.

Technology Transfers
“A large driver in access to new reserves throughout the region will be Middle East states’ need for technology transfers,” said Samuel Ciszuk, a consultant for KBC Asset Management U.K. “Private investment at a time when several of the countries experience sharply rising demand from their own populations for higher social spending is also an important factor.”

So-called enhanced-oil-recovery techniques to get oil from geologically challenging reservoirs and maintain production at mature fields will be a focus of international oil company investment.

Chevron Corp. plans to use steam underground to heat heavy crude in the area straddling Kuwait and Saudi Arabia’s border and make it liquid enough to pump. The project would be the largest so-called steam-flood development in the world when it is fully deployed in 2017, according to the U.S. company.

Mature Fields
Exxon and Total SA are also vying to access heavy crude deposits in mature oil fields in Kuwait, where lighter oil has already been pumped. Occidental Petroleum Corp. is producing heavy oil using enhanced recovery methods in Bahrain.

“The days of easy oil are over,” the U.A.E’s al-Hamli told reporters yesterday. “In order to maximize the potential, we have to have enhanced oil recovery.”

Another focus for investment will be natural gas, which is gaining prominence in the region as a fuel for export and domestic power generation. The IEA’s World Energy Outlook projects that gas output from the region will grow by an average 2.5 percent a year until 2035, faster than crude oil production growth of 1.7 percent a year.

Occidental together with state-run Abu Dhabi National Oil Co. is investing $10 billion to bring on stream the Shah gas field by neutralizing deadly hydrogen sulfide, which is also known as sour gas.

The Shah geology is similar to that of Kidan, a deposit Shell is exploring together with Saudi Arabian Oil Co., also known as Saudi Aramco, in the kingdom’s desert area known as the Empty Quarter. In Iraq, Shell and partners agreed last month to invest $17 billion to capture natural gas from its oil fields and reduce burn-off.

Gas-To-Liquids
Qatar became the world’s largest liquefied natural gas producer with a series of joint ventures with Exxon and other international oil companies. Shell’s $18.5 billion Pearl gas-to- liquids plant, which will use gas to produce 140,000 barrels a day of liquid fuel, will be fully operational next year.

Companies will also focus on tapping unconventional gas fields. In Oman, BP expects to spend at least $15 billion to develop so-called tight gas, locked in a hard-to-break rock that restricts the fuel’s flow.

Saudi Aramco, the world’s largest crude exporter, is looking for a foreign partner to develop shale. Unconventional gas resources will help Saudi Arabia meet rising domestic energy demand, Khalid Al-Falih, the company’s chief executive officer, said today in Doha.

“Unconventional gas will help these countries get the gas they need badly, reduce the use of oil in the power sector, and reduce the threat of reducing oil exports in the future,” to meet energy needs...



http://www.bloomberg.com/news/2011-...l-means-work-for-exxon-bp-energy-markets.html

 

[trysail]

http://www.bloomberg.com/news/2011-...sts-u-s-on-protecting-florida-or-embargo.html



Cuba Oil Drilling Tests U.S. on Protecting Florida
By Katarzyna Klimasinska
December 8, 2011

Four U.S. inspectors armed with safety glasses and notebooks will set out on a mission next month to protect Florida’s beaches from a Cuban threat.

They’ll rendezvous in Trinidad and Tobago with the Scarabeo 9, a rig headed to deep waters off Cuba to drill for oil about 70 miles (113 kilometers) south of Florida’s Key West.

Repsol YPF SA is making the Scarabeo 9 available to the U.S. inspectors before the rig starts drilling closer to Florida than the BP Plc well that failed last year in the Gulf of Mexico, causing the biggest U.S. offshore oil spill. The exploration poses an environmental, political and diplomatic challenge to the U.S. more than 50 years after cutting off relations with Cuba’s communist regime.

The Obama administration’s dilemma is “what steps to take for environmental protection and how much to honor current Cuba policy,” Dan Whittle, Cuba program director at the New York-based Environmental Defense Fund, said in an interview.

In the aftermath of the revolution that brought Fidel Castro to power, the U.S. banned exports to Cuba in 1960, withdrew diplomatic recognition, backed the failed Bay of Pigs invasion in 1961 and imposed a full trade embargo in 1962.

Now generations of animosity between the two nations limit cooperation on safety standards and cleanup precautions for the Cuba drilling planned by Madrid-based Repsol, which would be followed by state-owned companies from Malaysia to Venezuela. A conference on regional oil-spill response being held this week in Nassau, Bahamas, may provide a forum for discussions by U.S. and Cuban representatives.

Juan Jacomino, a spokesman for the Cuban Interests Section at the Swiss embassy in Washington, declined in an interview to comment on drilling off of the island nation.

Spare Parts
Repsol can use the Scarabeo 9 without violating the U.S. trade embargo because it was built at shipyards in China and Singapore, and fewer than 10 percent of its components are American, according to its owner, Eni SpA.

The sanctions would block spare parts from the U.S. for the rig’s blowout preventer, a safety device that failed in the BP spill. The restrictions also require Helix Energy Solutions Group Inc. of Houston, which provides oil-spill containment equipment for Repsol in the Gulf of Mexico, to seek a waiver to do so in Cuban waters in case of an accident.

U.S. companies seeking to do business with Cuba must ask the Commerce Department, which considers most applications “subject to a policy of denial,” the agency says on its website. The Treasury Department weighs requests to travel from the U.S. to Cuba.

Granting too few permits for spill prevention and response would keep contractors from offering the technology and services developed after the BP spill, Lee Hunt, president of the Houston-based International Association of Drilling Contractors, said in an interview.

Cuban Exiles
Approving too many licenses would undermine the embargo, enriching a regime listed by the U.S. State Department as a nation supporting terrorism along with Iran, Sudan and Syria, according to anti-Castro lawmakers such as Republican Representative Ileana Ros-Lehtinen of Florida, who heads the House Foreign Affairs Committee.

U.S. “assistance, guidance and technical advice” to Repsol, including the planned visit to Scarabeo 9, may violate the law by “helping to facilitate” the company’s work and providing the Cuban government “with a financial windfall,” Ros-Lehtinen said in a Nov. 1 letter to President Barack Obama.

Ros-Lehtinen, who immigrated from Cuba with her family at age 8, is a leader among Cuban exiles in South Florida who have opposed easing U.S. restrictions. Florida, which has been a swing state in presidential elections, also has been a bastion of opposition to oil drilling that opponents say could despoil the beaches that are a prime draw for tourists.

Florida Drilling Foes
Lawmakers such as Senator Bill Nelson, a Florida Democrat, have fought to keep drilling out of U.S. waters in the eastern Gulf of Mexico bordering Florida.

Nelson and Senator Robert Menendez, a New Jersey Democrat, introduced a bill Nov. 9 that would require foreign companies drilling in Cuban waters to pay for damage to U.S. territory without liability limits. Senator Marco Rubio, a Florida Republican, joined as a cosponsor.

Oil from BP’s spill tarred beaches 150 miles away in Florida’s northwestern Panhandle.

Now Floridians are faced with drilling under the jurisdiction of Cubans, who “don’t have the resources” to control a blowout, Jorge Pinon, an energy consultant and visiting research fellow at the Cuban Research Institute at Florida International University in Miami, said in an interview.

“If the U.S. is not willing to help” in an emergency, “the resources are going to come from Canada, Norway and the U.K., and it will take a very long time,” said Pinon, who led Amoco Corp. units in Mexico City and retired from BP in 2003, according to his biography.

Repsol’s Contract
Repsol signed a contract with Cuba in 2000, according to the company’s website, and confirmed the presence of oil with a Norwegian rig in 2004. Repsol will drill in about 5,000 feet (1.5 kilometers) to 6,000 feet of water, about the depth of BP’s Macondo well, according to Pinon.

Petroliam Nasional Bhd., or Petronas, based in Kuala Lumpur; New Delhi-based Oil & Natural Gas Corp.; Hanoi-based Vietnam Oil & Gas Group, known as PetroVietnam; Caracas-based Petroleos de Venezuela SA; and Sonangol SA of Luanda, Angola, also hold Cuban blocks, Pinon said.

U.S. officials say they are doing all they can to ensure safe drilling off Cuba.

“We are quite focused, and have been for many, many months” on “doing anything within our power to protect U.S. shores and U.S. coastline,” Tommy Beaudreau, director of the Bureau of Ocean Energy Management, an industry regulator, said in a Nov. 29 interview at Bloomberg’s Washington office.

Wild Well Control
The administration has issued some licenses to U.S. companies to respond to a spill in Cuban waters, Mark Toner, a spokesman for the State Department, said in an e-mail. He didn’t say how many have been approved, and the Commerce and Treasury departments didn’t respond to e-mailed requests for comment.

Wild Well Control Inc. of Houston is one permit recipient, according to Hunt of the drilling contractors’ trade group. The company didn’t respond to e-mails and phone calls seeking comment.

“Helix plans to build a new subsea containment cap to safeguard drilling operations in Cuba,” Cameron Wallace, a spokesman for that company said in an e-mail about its request for U.S. licenses. “The cap and associated equipment will be staged at a U.S. port near to the drilling site to minimize response time.”

Walking the Deck
In their visit to the Scarabeo 9, two inspectors from the U.S. Coast Guard and two from the Interior Department will walk the deck and check generators, the positioning system and firefighting equipment, Brian Khey, who will be on the team, said in an interview.

The Americans will watch a firefighting simulation and conduct an abandon-ship drill, according to Khey, the supervisor at the Coast Guard’s Outer Continental Shelf National Center of Expertise in Morgan City, Louisiana,

While the visitors will discuss with Repsol any deficiencies they find, they won’t have enforcement powers, Khey said. Nor will they be able to check the blowout preventer or the well casing and drilling fluid that will be used on site, according to the Interior Department.

Scarabeo 9 was built “according to the latest and most advanced international standards available at the time of her design and construction,” Rome-based Eni said in an e-mailed statement. “Health, safety and environmental protection are always a top priority.”

Eni Subsidiary
The vessel “is one of the very few units in the industry which is using a technology which is not an American one,” Pietro Franco Tali, chief executive officer of Eni’s oilfield- services subsidiary, Saipem SpA, said on an Oct. 27, 2010, conference call.

One U.S. component is the blowout preventer, made by Houston-based National Oilwell Varco Inc. The company hasn’t applied for a license to do business with Cuba and doesn’t plan to, Chief Financial Officer Clay Williams said in a phone interview.

That means rig operators will have to seek training and spare parts in Europe or Asia, according to Hunt, whose group represents 1,494 companies including Saipem.

“It’s like buying a Mercedes and being told you have to go to a Ford dealer for parts,” Hunt said in an interview.

The results of Cuba’s drilling may affect U.S. energy policy. Success would put pressure on the U.S. to open its waters surrounding Florida for exploration, Pinon said.

A serious accident off of Cuba could throw the industry out of the Gulf of Mexico, according to Brian Petty, executive vice president for governmental affairs of the drilling contractors’ group.

“A mess” in Cuban waters would lead critics of drilling to say, “Stop it, don’t let it go on anywhere,” Petty said.


http://www.bloomberg.com/news/2011-...sts-u-s-on-protecting-florida-or-embargo.html

 

[trysail]

The world proved reserves estimate of ~ 1.383 trillion barrels of petroleum includes ~143.1 billion barrels of Canadian oil sands and ~94.168 billion barrels of Venezuelan heavy oil from the Orinoco Oil Belt. Production of ~80 million barrels per day equates to ~29.2 billion barrels per year. Daily world production of ~82.1 million barrels equals ~29.96 billion barrels per year. As seen in the chart, the current derived reserve/production ratio of 46.2 years has grown over the past thirty years from under 30 years in 1980.​

http://wattsupwiththat.files.wordpress.com/2011/12/proven-world-oil-reserves-production-years-left1.jpg

Souce: BP Statistical Review of World Energy 2011
​

 

[trysail]

http://www.bloomberg.com/news/2011-...ove-4-a-gallon-as-plants-shut-morse-says.html



Gasoline May Top $4 a Gallon as Plants Shut
By Paul Burkhardt
December 23, 2011

Gasoline prices may rise above $4 a gallon next summer as refineries along the U.S. East Coast close, reducing fuel supply, said Edward Morse, New York-based head of commodities research at Citigroup Global Markets Inc.

Sunoco Inc. and ConocoPhillips have idled two plants and plan to shut a third that together can process more than 700,000 barrels a day of oil, or about 46 percent of the region’s refining capacity. That will increase the dependence on imports to meet fuel demand in the region that includes the delivery point for New York Mercantile Exchange futures contracts, the basis for national prices at the pump.

Cargoes arriving from abroad accounted for 19 percent of demand in the East Coast, or Padd 1 region, in September, Energy Department data show. Shipments from the Gulf Coast and Midwest met another 51 percent of consumption, with local refineries supplying the rest.

“We have a real supply problem ahead this summer because these refineries have not made money and they are shutting down,” Morse said yesterday in a Bloomberg TV interview with Tom Keene. “Summer gasoline is harder to make than winter gasoline, and we could see $4 as a floor price rather than a ceiling limiting demand.”

Gasoline for January delivery on the Nymex rose 1.8 percent to settle at $2.6872 a gallon on the New York Mercantile Exchange, the highest settlement price since Nov. 8. Pump prices in the U.S. averaged $3.224 a gallon yesterday, 7 percent higher than a year earlier, according to AAA data.

Summer Gasoline
Analysts at Citigroup and Barclays Capital recommended buying gasoline contracts for delivery in summer months after Sunoco announced Dec. 1 the immediate idling of its 194,000- barrel-a-day Marcus Hook refinery in Pennsylvania. ConocoPhillips stopped processing crude oil at the 190,000- barrel-a-day Trainer plant Sept. 30.

“The area could be left vulnerable to price spikes if there are ever any unplanned outages or supply disruptions,” said Tom Bentz, director with BNP Paribas Prime Brokerage Inc. in New York.

Sunoco idled Marcus Hook, moving up an earlier July deadline to find a buyer, because of “deteriorating market conditions,” the company said in a Dec. 1 statement. The July deadline remains to sell or shut the 355,000-barrel-a-day Philadelphia plant, the company said.

The three plants combined produced 315,000 barrels a day of gasoline, the Energy Department said in a report today. The shutdowns may increase regional petroleum product price volatility and may be “problematic” as supply sources shift, the report showed.

Higher Prices
The shuttered refineries, which processed mostly imported crude from Europe and West Africa, faced higher prices than their counterparts in the U.S. Midwest and Gulf Coast able to use less-expensive domestic oil. North Sea Brent increased to a record premium of $27.88 a barrel over West Texas Intermediate oil on Oct. 14.

The East Coast imported 596,000 barrels a day of gasoline in September out of 3.1 million barrels supplied daily, Energy Department data show. That’s poised to rise as suppliers seek to replace local production.

“The tanker market had already anticipated the prospect of an increase of gasoline to New York harbor,” said George Los, an analyst at Charles R. Weber Co., a Greenwich, Connecticut- based ship broker. “With the acceleration of Sunoco’s plans for the Marcus Hook idling by some eight months this is likely to boost demand, mostly for medium-range tankers.”

Prices may also rise in New York versus the Gulf Coast in order to attract more shipments from the Gulf, where about half of U.S. refining capacity is located. Reformulated 87-octane gasoline in New York was 7.75 cents a gallon above the Gulf today, according to data compiled by Bloomberg, up from 4.53 cents Nov. 30.

Colonial Pipeline
Colonial Pipeline Co., the largest pipeline linking the U.S. Gulf Coast with Northeast markets, delivers 2.35 million barrels a day of oil products from Houston to Greensboro, North Carolina. The main lines from North Carolina deliver about 1.4 million barrels a day to Linden, New Jersey.

“I would assume the Colonial line space just got a lot more valuable,” said Andy Milton, vice president of supply at Gainesville, Georgia-based Mansfield Oil Co., which supplies more than 2 billion gallons of fuel per year.

Colonial announced Dec. 21 that it plans to increase capacity on its main gasoline pipeline by 100,000 barrels a day by the first quarter of 2013.

“We foresee some significant tightness” ahead for Nymex gasoline, analysts at Barclays including Miswin Mahesh in London said in a Dec. 6 report. The analysts suggested buying the gasoline contract for August delivery and selling heating oil for the same month, according to the note.

Narrower Spread
Gasoline’s discount to heating oil narrowed to 20.35 cents from 45.37 cents Nov. 30. The spread reached 62.69 cents a gallon on Nov. 14, after diesel and heating oil inventories in the U.S. dropped to the lowest level since December 2008.

“Now is the time to look at selling heating oil and buying gasoline for the summer,” Citigroup analysts led by Seth Kleinman said in a Dec. 6 report. “The outlook for gasoline is challenging, but summer values for the spread are already extremely cheap.”

The gap between contracts for delivery in August was 13.58 cents a gallon, from 28.71 cents Nov. 30.



http://www.bloomberg.com/news/2011-...ove-4-a-gallon-as-plants-shut-morse-says.html

 

[trysail]

Dated Brent:
http://www.bloomberg.com/apps/chart?h=200&w=280&range=1y&type=gp_line&cfg=BQuoteComp_10.xml&ticks=EUCRBRDT%3AIND&img=png
http://www.bloomberg.com/apps/quote?ticker=EUCRBRDT:IND
As of 10 December 2007, Forward Dated Brent is calculated as follows: CO1 <cmdty> + Corresponding Month EFP + Average of 21 Days CFDs. Forward Dated Brent/BFOE reflects the price of North Sea Crude cargoes loading in 10-21 days from today (10-23 days on Friday). Delivery is free-on-board at the Sullom Voe terminal in the Shetland Islands, UK. Cargoes are typically 600,000 barrels. North Sea Crude is typically light, sweet oil, with gravity > 35 degrees API and sulfur content < 1 percent. The price reflects the average value of Brent contracts for differences over the 10-21 day period (10-23 days on Friday). Contracts for differences, or CFDs, are short-term swaps which represent the differential in price between Dated BFOE and a forward month cash contract, typically on a weekly basis. CFDs are traded in the OTC market and quoted by several brokerage firms. CFDs values updates up to 4 times a day between 8am and 5.30pm from Mon-Fri. The value of the cash contract is derived by adding the EFP (exchange for physical) differential for a particular month (EUCSEFP <index>) to the value of the corresponding Brent futures contract traded on the intercontinental exchange, ICE ( oil futures contract CO1 <cmdty>). This notional 'cash' contract, also called the 21-day cash BFOE contract, is set against the CFD differentials over the 10-21 day period. Forward Dated Brent/BFOE is the average of the CFDs values over this period.

Bloomberg European Urals Northwest Europe Crude Oil Differential:
http://www.bloomberg.com/apps/chart?h=200&w=280&range=1y&type=gp_line&cfg=BQuoteComp_10.xml&ticks=EUCSURNW%3AIND&img=png
http://www.bloomberg.com/apps/quote?ticker=EUCSURNW:IND
European crude oils are priced at a differential to North Sea or Mediterranean Strip. Urals NWE (cif Rotterdam) is priced as a differential to the Mediterranean Strip​

Putin’s Ambitions for Urals Seen in Rotterdam Tanks
By Jake Rudnitsky
December 29, 2011

Prime Minister Vladimir Putin has been calling for Russia, the world’s largest oil producer, to narrow the price gap (EUCSURNW) between its Urals export crude and the Brent benchmark since 2005. A $1 billion terminal in Rotterdam may help achieve that goal.

Summa Group, a shareholder in Russia’s biggest oil-export terminals, in Novorossiysk and Primorsk, is investing in a 3 million-cubic-meter facility. It will expand liquids capacity at Europe’s largest port by about 10 percent, said Summa First Vice President Alexander Vinokurov. Vitol Group, the world’s biggest independent oil trader, is a partner in the project.

The Rotterdam terminal will create a European trading hub for Urals crude, providing deliveries directly to the port and contributing supply stability. Vinokurov said that will be a key step for Urals in becoming an international benchmark, at a time when the world’s most prominent benchmark, Dated Brent (EUCRBRDT), faces declining output and supply disruptions.

“The physical market for Brent is narrowing and risks are becoming too volatile,” Mikhail Temnichenko, a vice president for the St. Petersburg International Mercantile Exchange, said Dec. 26. “Urals is the most obvious alternative benchmark, offering large, stable volumes from a variety of market participants.”

The Rotterdam terminal is evidence that competition is “heating up” as crude oil benchmarks evolve, Platts, the energy-pricing division of New York-based McGraw Hill Cos. (MHP), said in a November presentation. On Jan. 6 Platts will broaden the base for Brent pricing by extending the length of time over which cargoes are measured.

Joint Ownership
The terminal could help develop a futures market for Urals, which is necessary to become a benchmark, said Olivier Jakob, managing director at Petromatrix GmbH, a Zug, Switzerland-based oil-market researcher.

“It makes sense to create a hub in Rotterdam for Russian crude,” Jakob said by telephone yesterday. “We need to see who has access to the barrels. If it’s like Cushing with lots of participants, a market could develop in time,” he said, referring to the delivery point for New York Mercantile Exchange oil futures in Oklahoma.

The terminal’s 3 million cubic-meter capacity is nine times larger than that of an average supertanker, which would normally haul more than 2 million barrels of cargo, according to data from Redhill, England-based IHS Fairplay. Two thirds of the volume will be for crude and the rest will hold oil products, Vinokurov said.

Export Volumes
The hub may also help ensure export volumes from the Primorsk terminal, owned by Novorossiysk Commercial Sea Port (NMTP), as Russian oil pipeline operator OAO Transneft (TRNFP) works to open a new facility on the Baltic Sea, said Denis Vorchik, an analyst at UralSib Financial Corp. in Moscow. Transneft and Summa jointly own 50.1 percent of Novorossiysk, which rose 0.4 percent to 3 rubles at yesterday’s close, the highest level in a week.

“There are not many opportunities to enter the European market and given Russia is a major crude exporter to that market, it makes sense,” Mikhail Ganelin, an analyst at Troika Dialog in Moscow, said Dec. 26.

Under an “ambitious” schedule, the terminal may be commissioned by 2013 or 2014, earlier than the initially planned 2015 deadline, Vinokurov said in a Dec. 16 interview.

Russia is the biggest supplier of oil to the European Union. Urals, a blend of crudes from the Volga region and western Siberia, accounts for about 80 percent of Russia’s 5.6 million barrels a day of exports (RUCUCRUD).

Output of the crudes used to price Dated Brent, the benchmark for more than half of the world’s oil including Urals, has fallen from 1.5 million barrels a day in December 2007 to 1.1 million barrels this month, according to a Bloomberg assessment of loading schedules (LOSDBFOT).

Longer Period
Platts is considering lengthening the cargo-measuring period even further in 2015 or 2016 and may include more grades of crude into its Brent assessment, according to a Sept. 16 statement. The assessment is based on a blend of several types of crude pumped in the North Sea, including Brent, Forties, Oseberg and Ekofisk.

The Brent benchmark has required regular adjustments since production went into decline in the 1990s. Forties and Oseberg crude were added to the benchmark (EUCRBRDT) in 2002 and Ekofisk in 2007.

Very Unfair
Urals in northwest Europe has had an average discount (EUCSURNW) to Brent of $1.79 over the past two decades. Putin called the gap “very unfair” in an address when he was president in 2005. In response, the government introduced a national oil exchange and brand, calling it Russian export-blend crude oil, or Rebco.

The Russian crude traded at a 40-cent premium to Brent, its biggest ever, on Dec. 1 to Dec. 6 as the EU weighed tougher sanctions against Iran. It was at a $1.10 discount today.

Summa expects the Rotterdam facility to add stability to Urals supplies by creating accessible volumes outside Russia. This may help create a market for the Urals forward market and futures contracts, Temnichenko said by phone in Moscow.

“Urals will be more visible to traders and this could contribute to it becoming a price indicator,” Temnichenko said.

Futures contracts for Urals have been sold on the Nymex, the world’s largest energy futures marketplace, since October 2006 under Rebco name. Allan Schoenberg, a spokesman for Nymex parent CME Group Inc. (CME), said no Rebco contracts have traded in the past two years.

Reduced Deliveries
Transneft and state-controlled gas export monopoly OAO Gazprom (GAZP) have cut energy deliveries to neighboring transit countries during supply and transportation pricing disputes, disrupting shipments to Europe.

Gazprom has twice in the past six years cut gas deliveries to Ukraine on New Year’s Day. Transneft halted oil deliveries to Belarus for almost a month on Jan. 1, rerouting about 650,000 metric tons.

Transneft built the Baltic Pipeline System-2 oil link to the Gulf of Finland as Russia expands transportation capacity away from transit countries.

“This Rotterdam terminal could ensure volumes from Primorsk” in the face of competition from the new Ust-Luga crude terminal, UralSib’s Vorchik said by phone Dec. 26. Ust- Luga has been delayed for as much as three months from its expected Dec. 1 start because of engineering difficulties, Transneft said in last month.

Ust-Luga is being built by Vitol’s competitor, Gunvor Group Ltd., at the end of Transneft’s Baltic Pipeline System-2 oil link. The pipeline has a capacity of 38 million metric tons a year, or 451,000 barrels a day, while Primorsk handles about 70 million metric tons of crude a year.

Floating Pipeline
Buyers will be able to purchase Urals to be loaded in Rotterdam using a “floating pipeline” that relies on icebreaking shuttle tankers shipping crude from Primorsk on the Baltic Sea, Vinokurov said.

Urals in Rotterdam could become a benchmark with the development of forward and futures markets, Summa said in an Oct. 20 presentation.

“A case could be made for it to be a benchmark if there was a stable supply in the heart of Europe,” Vinokurov said. “We have an aggressive schedule.”

http://www.bloomberg.com/news/2011-...seen-in-rotterdam-terminal-tanks-freight.html

 

[trysail]

http://www.petrobras.com.br/publicador/arq/126/arq_126_12466.jpg​

Rio de Janeiro, December 29, 2011 – Petróleo Brasileiro S.A. – Petrobras, as operator of the consortium of Block BM-S-9, informed that it submitted today the Declaration of Commerciality for the Guará area to the National Petroleum, Natural Gas and Biofuels Agency (ANP).

The new field will be called as Sapinhoá and the estimated total recoverable volume informed was 2.1 billion barrels of oil equivalent (boe). Sapinhoá is another giant field discovered in the Brazilian pre-salt layer and one of the biggest in the country, comprised of reservoirs with good quality oil (30º API).

The consortium also submitted the final Evaluation Plan final report of the area. The Development Plan report will be submitted to the ANP in February 2012. The Declaration of Commerciality takes place following the execution of the Exploratory Evaluation Program in the area, which was conducted from the first drilled well in 2008.

Four wells were drilled in the area, including one to get data about the reservoir. In addition, four formation tests were conducted in three of the wells and a five-month extended well test (EWT) in the discovery well. The EWT confirmed the excellent productivity of the discovery well. The flow was maintained throughout the entire test period and the test showed relevant information about the carbonate reservoirs for the optimization of the development plan.

The Declaration of Commerciality for the field was anticipated by a year, considering that the deadline for the Evaluation Plan approved by the ANP was December 31, 2012.

The exploratory success obtained in the area reaffirms the high potential of the pre-salt and signals a promising outlook for the Company’s output production growth and oil and natural gas reserves increase. Petrobras is the operator of Block BM-S-9, in partnership with BG Group (30%) and Repsol Sinopec Brasil (25%).


http://www.petrobras.com.br/ri/Show...==&id_canalpai=/zfwoC+leAQcwFyERVZzwQ==&ln=en

http://images.rigzone.com/images/news/library/maps/6/4917.jpg

http://www.subseaiq.com/(X(1)S(o0vy...?project_id=274&AspxAutoDetectCookieSupport=1
​

Guara Sapinoa
Tupi Lula
Carioca
Iracema

 

[trysail]

http://blogs.wsj.com/deals/2012/01/...nese-are-digging-in-your-yard-for-natural-gas


[Words to the wise: Never trust anybody, particularly a journalist, who uses the word digging in respect of hydrocarbons. We drill for hydrocarbons. ]




January 3, 2012, 9:38 AM ET.
The French and Chinese Are Digging in Your Yard for Natural Gas
By Shira Ovide

For this week, Merger Monday is foreign shale day.

France energy giant Total S.A. and Sinopec, the Chinese oil company, both bought their way into U.S. shale assets. The U.S. shale drive, in which oil and gas producers crack open fuel-bearing rocks formations, is behind much of the corporate deal making in the U.S. in the last year.

Companies that are on the forefront of shale production, including Chesapeake Energy, are taking advantage of interest from U.S. and international energy companies and private-equity firms hoping to get in on the shale boom.

Chesapeake announced it agreed to sell a minority stake in the company to Total for $2.32 billion. Shares of Chesapeake are perking up 3.4% this morning. Also this morning, Chesapeake’s neighbor in Oklahoma City, Devon Energy, took in $2.2 billion from Sinopec, which will take a one-third stake in five of Devon’s new shale plays. Devon’s stock price is popping 4% this morning.

Throw a dart at a map, and you’re likely to hit a country that has been scooping up U.S. shale assets. Norwegian oil giant Statoil this fall agreed to buy a shale pioneer, Brigham Exploration. Anglo-Australian company BHP struck a $12.1 billion acquisition of Petrohawk Energy last summer was driven in part by Petrohawk’s ownership of shale assets. In 2010, China’s Cnooc also bought into oil-and-gas assets in the Eagle Ford Shale project in South Texas.

 

[thør]

"China will emerge as Alaska's top export customer for 2011 when final trade statistics are counted for the last two months of the year, state officials say. "

Story

 

[trysail]

Baker Hughes Horizontal Rotary Rig Count (BAKEHORZ:IND)

http://www.bloomberg.com/apps/chart?h=200&w=280&range=1y&type=gp_line&cfg=BQuoteComp_10.xml&ticks=BAKEHORZ%3AIND&img=png

​

A rotary rig rotates the drill pipe from surface to drill a new well (or sidetracking an existing one) to explore for, develop and produce oil or natural gas. The Baker Hughes Rotary Rig count includes only those rigs that are significant consumers of oilfield services and supplies and does not include cable tool rigs, very small truck mounted rigs or rigs that can operate without a permit. Non-rotary rigs may be included in the count based on how they are employed. For example, coiled tubing and workover rigs employed in drilling new wells are included in the count. To be counted as active a rig must be on location and be drilling or 'turning to the right'. A rig is considered active from the moment the well is 'spudded' until it reaches target depth or 'TD'. Rigs that are in transit from one location to another, rigging up or being used in non-drilling activities such as workovers, completions or production testing, are NOT counted as active.Miscellaneous rig counts represent geothermal rigs.

http://www.bloomberg.com/apps/quote?ticker=BAKEHORZ:IND

 

[trysail]

Three well-written and highly readable pieces that are worth reading:


Point:
http://wattsupwiththat.com/2011/12/13/the-rp-ratio/

Counterpoint:
http://wattsupwiththat.com/2012/01/03/peak-oil-the-rp-ratio-re-visited/

Peak Oil Response:
http://wattsupwiththat.com/2012/01/04/price-driven-us-energy-independence/



http://wattsupwiththat.files.wordpress.com/2012/01/image3.png

​

Eschenbach
PeakOil
Hubbert