blog2009

Natural gas clean and green

Claudia Cattaneo,
National Post
April 27, 2009

The emergence of immense new supplies of clean-burning natural gas from shale deposits in North America is shaking up the energy industry.

It may also end up turning the green energy debate on its head.

Among those making the case that it must impact the debate, particularly before climate change legislation is implemented, is Randy Eresman, CEO of Calgary-based EnCana Corp., one of North America's top natural gas producers from shale.

Mr. Eresman was one of several industry leaders who met last week with the U. S. energy secretary, Steven Chu, a champion of renewable energy. They explained that shale gas, while still a fossil fuel, is an extraordinary new source of clean energy in a carbon conscious world.

The change is so new and so sweeping few have caught on, he said in an interview.

"People are very quickly coming to the same conclusion that we have come
to: That natural gas is going to be abundant for a very, very, very long time, and it should be now part of the overall debate for both energy security purposes and for the benefits you get because of the lower environmental footprint," he said.

Alaska's drilling debate moves offshore

By Kim Murphy
Los Angeles Times
April 26, 2009

ANCHORAGE: Protesters call for new drilling. Days later, federal judges blocked oil and gas leases, ordering a review. (Kim Murphy / Los Angeles Times)

With the oil industry targeting Arctic waters, energy needs are weighed against a region's fragile life cycle.

Reporting from Nuiqsut, Alaska -- The year the oil companies seriously began exploring the icy waters off the Arctic National Wildlife Refuge -- where Nuiqsut whalers have hunted for as long as men have wandered on dark waters -- the villagers lost two bowhead.

The big whales had veered 30 miles from their usual migration path, and the men had no choice but to follow them through ice and mounting swells in their 20-foot boats. Hunters usually can kill the creatures with a fair amount of efficiency after they are harpooned. But this time was different.

Related Content Life on the North Slope Californians voice concerns to Obama...

The bowhead, longtime whaling captain Eli Nukapigak said, were "spooked."

One of the whales flipped and dove, with the harpoon line twisted around the propeller, dragging the boat toward the sea floor. The crew managed to leap to safety. Another boat had been towing the second whale back to camp when it was overcome in the fierce seas. The hunters had to cut the whale loose.

"That kind of disaster we don't want to see again," Nukapigak -- dressed in a parka on a recent 10-below-zero spring morning -- said of the 1985 hunt.

For the captain and others in this Inupiat Eskimo village on Alaska's North Slope, that may depend on whether the oil industry is allowed to open more of the iceberg-strewn Arctic waters to drilling.

A federal appeals court this month put the brakes on a plan to lease more than 78 million acres of the Beaufort, Chukchi and Bering seas to oil and gas developers, ordering a full environmental review before the program can proceed. But that could be little more than a speed bump in the rush to commercialize the Arctic, which global warming -- and the resulting shrinking sea ice -- has made accessible as never before.

Though the conservation community has fought successfully over the last decade to protect the Arctic National Wildlife Refuge, the remaining pristine areas of the North Slope have been going fast. In September, the Bureau of Land Management put 1.5 million acres of the National Petroleum Reserve-Alaska, with its shimmering lakes and verdant tundra, up for lease to developers.

Now the battle is moving offshore.

The coast around Prudhoe Bay is already dotted with drilling operations such as BP's Liberty project, which, when completed, will have the world's longest diagonal wells -- reaching eight miles out from facilities near shore. In contrast, the proposed Chukchi Sea leases would start 25 miles offshore and reach 200 miles out.

Obama administration officials have said they will weigh the nation's energy needs against the desire to protect crucial resources. But with active North Slope fields reaching the end of their production life, the allure of an estimated 27 billion barrels of oil and 132 trillion cubic feet of natural gas off Alaska's shores is strong.

Gov. Sarah Palin has warned that without new drilling, the 800-mile-long trans-Alaska oil pipeline could be forced to shut down in as little as 10 years, crippling America's hopes for energy independence, not to mention her state.

"The Alaska offshore is home to some of the most prolific, undeveloped hydrocarbon basins in the world -- reserves that would not only fuel Alaska's economy for decades to come, but oil and gas reserves that would also provide the nation with much-needed energy security," said Pete Slaiby, general manager of Shell Exploration and Production Co.'s Alaska operations.

The company, which had been planning the first major offshore lease development in the Beaufort Sea before it was blocked, argued its case to Interior Secretary Ken Salazar during a recent hearing in Anchorage.

The Interior Department is evaluating not only the 2007-12 offshore drilling plan struck down by the court, but also a more ambitious program rolled out in the waning hours of the Bush administration to expand leases in the Arctic Ocean, from the 74.5 million acres now being offered to 127.5 million by 2015.

Conservationists worry that a major oil spill could knock down the region's delicate house of cards: The ice pack in 2007 was at its lowest level since satellite monitoring began in 1979, putting tremendous stress on animals such as walruses, seals and polar bears that depend on the ice to hunt, rest and avoid the oil industrial zones onshore.

More than 500 spills of varying sizes occur on the North Slope each year, on average. The federal government recently estimated there was a 40% chance of a large crude spill from development in the Chukchi Sea. And though spills in open water are notoriously hard to clean up -- Prince William Sound still has oil on some of its beaches from the 1989 Exxon Valdez disaster -- one occurring amid tight chunks of broken ice would present even more problems.

"It is beyond the pale of stupidity that, in the face of everything that's happening in the Arctic, that we would launch a drilling program," said Jim Ayers, a vice president of the marine conservation group Oceana.

The Minerals Management Service, which oversees federal leases on the Outer Continental Shelf, has spent $300 million on environmental studies in the Beaufort and Chukchi seas, officials said. And the chances of a serious spill are low, regional director John Goll said.

"We are absolutely not talking about an Exxon Valdez," he said. "For us, a major spill is 1,000 barrels or more. When folks talk about 50% of [drilling operations] are going to have a spill, remember that anything that puts a sheen in the water is considered a spill. I always say, look back at the record. And it's a pretty strong record right now."

Goll also said that the government had moved to lessen the effects of offshore drilling on the bowhead whale hunt by removing some areas from leasing and limiting oil operations during certain times of the year.

In its opinion, the Washington, D.C., appellate court found that the government had failed to thoroughly weigh the environmental impact of offshore Arctic leasing, and it sent the Minerals Management Service back to the drawing board. The panel also found merit in claims that native Eskimos have a right to seek protection of animals that have been an economic and cultural resource for a millennium.

Endangered bowhead whales -- of which Eskimos may kill a varying quota of usually up to 40 a year -- form one of the backbones of native culture and diet. The hunts, elders say, teach young people a skill that encourages respect and keeps them from fleeing the barren villages that dot the Arctic coast.

There are about 10,500 bowheads, which can grow up to 60 feet long, plying the waters off Alaska's coast. A 2007 survey found nearly half that population living inside the proposed drilling area.

"It would only be a matter of time before something like Exxon Valdez would occur in our subsistence area," said Thomas Napageak Jr., 25, a whaling captain and Nuiqsut's vice mayor.

Some here also worry that the caribou that once could be hunted just outside the village now most often stay miles away. And some of them seem sick.

"This past summer, I saw a caribou that had a tumor on its right hind quarter, and it was the size of a baseball," Napageak said. "A couple months ago, I got one that had green pus on its neck and shoulders."

Even so, Nuiqsut, like other villages across the North Slope, has been lured by oil's promise of jobs and stock dividends.

A ConocoPhillips development seven miles away, on the edge of the National Petroleum Reserve-Alaska, has been a godsend for this village of run-down prefab houses, roaring snowmobiles and old whaling boats near the Colville River Delta.

While other Alaska Natives were struggling last year with soaring fuel prices and had trouble affording food, about 170 Nuiqsut families collected dividends of nearly $30,000 each from the native Kuukpik Corp., which owns land on which the project was built.

Nearly everyone in the village of 400 also collected $1,523 last month from Arctic Slope Regional Corp., which represents Alaska Natives across the North Slope.

(That is on top of the $2,069 Permanent Fund dividend check distributed to all Alaskans last year as their share of the state's invested oil wealth. The government also sweetened the deal with a $1,200 bonus to help compensate for high fuel prices.)

In exchange for the village's blessing to expand its Alpine project, ConocoPhillips has promised to build a road connecting Nuiqsut to the oil site and nearby hunting grounds.

The company also is extending a natural gas pipeline to Nuiqsut, one of the few villages in Alaska that will have gas heat, and is paying $250,000 in compensation for any impacts to hunting and fishing.

"We recognized that development is occurring and that there are benefits to be had," Kuukpik Chief Executive Lanston Chinn said.

"The reality was . . . if oil and gas development is going to proceed, what do we want out of it?"

kim.murphy@latimes.com

Can science save the oil sands?

NATHAN VANDERKLIPPE
Globe and Mail
April 24, 2009

Falling oil prices and bad PR have hammered the oil sands. Out of all that bad news may rise a new era in innovation

FORT McMURRAY, ALTA. — If Selma Guigard is right, an elusive key to reducing the oil sands' emissions could lie in the science of the super-critical molecule.

When they are subjected to a certain high temperature and pressure, substances like carbon dioxide enter a state where they are neither liquid nor gas — the super-critical state. When mixed with several other compounds, super-critical carbon dioxide is able to extract hydrocarbons from almost anything, in a process somewhat like the way some dry cleaners work.

Dr. Guigard, an associate professor of environmental engineering at the University of Alberta, is trying to prove it can do the same for the Athabasca oil sands. This is not a mere science experiment: Lab modelling has shown that her process uses virtually no water, and less than a third of the energy spent today on bitumen extraction.

That makes it not only a potentially huge step up from an environmental point of view, it could also help redraw the economics of the oil sands.

Dr. Selma Guigard, an engineering professor at the University of Alberta, has developed a method for extracting bitumen from the oil sands that uses almost no water and far less energy. (John Ulan/For The Globe and Mail)

There's only one problem. To prove the technology, Dr. Guigard needs to build a small pilot operation, and that will cost $1-million. She's spent a year banging on the doors of the energy companies that stand to gain the most from what she is developing.

They have all declined.

"The response is basically they're looking at this as still in its infancy, and so they are waiting for a little bit more research," she said.

That puts Dr. Guigard in a bind: "They want us to be further along than we can get with the funding sources that we currently have."

Talk to anyone in Calgary or Fort McMurray, and they will tell you that the story of the oil sands has been the story of technology. Were it not for the original hot-water extraction method, mining would never have become profitable decades ago. Were it not for the next step, the steam-assisted gravity drainage (SAGD) techniques developed in the 1970s that use high-pressure steam to send bitumen dripping out, the more-expansive deeper oil sands would never have been tapped.

But those are by and large yesterday's techniques and methodologies. In the past nine months, the dive in oil prices has brought more than $200-billion in spending plans crashing off books, raising profound questions about the ability of the industry to prosper in the future.

In large measure, $50 (U.S.) oil has put existing oil sands technologies on life support. In recent years, companies spent half as much of their revenue on research and development as the rest of industrial Canada — far less than even farmers and fishermen.

The lack of research has helped contribute to the vulnerability of the industry to falling oil prices. Last summer, a company building a new oil sands mine needed $90 oil to be profitable. Anyone building a new SAGD operation needed $70 oil.

Costs have begun to dip in the cooling of the boom. But if ever there was a time for someone to come up with a new way of producing the oil sands — a way that's both cheaper and less environmentally heavy footed — it's now.

Several companies are chasing ways to do exactly that, using electric currents, underground fires and petrochemical solvent cocktails to accomplish leaps in efficiency and lower greenhouse gas emissions. Many of the boldest ideas, however, belong to the oil patch outsiders. They are the upstarts — the mavericks — seeking to claim Fort McMurray's future with a new vision of how oil can flow.

But that new vision is unlikely to transform the oil sands if left to the small companies alone. Both government and industry heavyweights have been slower to embrace the need for new technology.

If they do not adapt to the future and start to invest more heavily, Canada's energy industry risks shrivelling, said Jamie Blair, a former Husky Canada executive who is now advocating for a new technological era in Alberta.

"People will talk about the oil sands being on the backburner," he said.

NEW TECHNOLOGIES

Ever since oil began its long dive last summer, a torrent of callers has been ringing Bruce McGee's phone. Every time he answers, he tells investors, energy companies and whoever else who will listen this story: He believes his company, E-T Energy Ltd., can produce oil at a profit with prices at $26 a barrel.

Mr. McGee, who is president, believes that changes everything. By his calculation, E-T's technology can be used to pump out 600 billion barrels of oil sands bitumen. That's more than triple the Alberta government's best guess at what's currently recoverable from the oil sands, and enough to satisfy total global demand for two years.

"Once we get out there and we're putting barrels on the balance sheet, we're going to have more barrels on our balance sheet than Saudi Arabia in a very short period of time," says Mr. McGee, the company's president. "We won't be second. We will be first in the world."

It could also tear apart current oil sands practices.

"If the price of oil stays at $40 a barrel, it will replace mining," predicts Craig McDonald, E-T's vice-president of operations. In coming weeks, the company will hit the road to raise $150-million to commercialize its technology.

That technology isn't much to look at — just a few well heads and large tanks sitting on a windswept field south of Fort McMurray. A series of electrodes dangle in each well. When they are turned on, they pass a current through the earth — like electricity through a stove element — and heat it up. The result: The bitumen, which is normally locked in sand as hard as rock, begins to flow — like molasses in a microwave. No huge mines needed, no greenhouse gas-spewing steam projects required.

In a place accustomed to prying bitumen from the earth using monstrous shovels and vast quantities of steam, this pilot project is a bold attempt to reshape the environmental and financial costs of the oil sands.

In other parts of Alberta, companies are using radically different techniques: Petrobank Energy and Resources Ltd. is studying how to free bitumen using underground combustion, while Laricina Energy Ltd. is mixing steam with solvents, which dramatically cuts the amount of natural gas used to extract bitumen from deeper oil sands. At universities and provincial research bodies, scientists are studying how microbes could be used in bitumen upgrading, and examining the effectiveness of new techniques inside specially modified medical CT scanners.

All of the major oil sands players maintain research divisions that pour millions of dollars into perfecting extraction processes every year. Some, like ConocoPhillips and Syncrude, are holding those budgets steady in the current downturn (Syncrude alone spends $50-million a year), while Shell has said its R&D budget will drop this year.

Others, like Imperial Oil, are ramping up: The company spent $117-million on research last year, more than double its 2006 budget. It has established a centre for oil sands innovation at the University of Alberta, and plans to build a pilot to test its own version of the solvent technology this summer.

Imperial, like many other companies, maintains that research is a crucial to its future. "Our greatest lever for profitability is technology development," said Imperial spokesman Pius Rolheiser.

R&D LAGS

Indeed, between 2004 and 2006, the most recent year Statscan has numbers, the entire industry's research spending grew by 65 per cent to $515-million.

But compared to other industries, and to their own outsized earnings, energy companies are well behind on research spending. Imperial Oil alone pulled in $3.9-billion in profit last year.

Statistics Canada's most recent figures on R&D spending as a percentage of revenue, from 2006, show the national average among all industries is 2 per cent. Pharmaceutical companies spent 6.7 per cent; the agriculture industry 1.6 per cent; forestry and logging 4.4 per cent; fishing, hunting and trapping 5.8 per cent. Oil and gas companies spent 0.9 per cent.

And not all of the spending is going toward finding new extraction methods. Substantial sums are being spent on improving tailings technology and perfecting extraction processes currently in place.

Those who have experience in the oil sands charge that the companies that work there are not open enough to new thinking.

"They've gotten so complacent and so fixed in the way they've done business up there," said Paul Verhesen, the president of construction firm Clark Builders, which has done work in the oil sands. "They'll spend $1,000 to save $1 as opposed to being innovative, being creative, being willing to look at options."

For many years, there was little incentive to spend on research. Rising oil prices made existing technologies abundantly profitable, masking a need for change. Instead of searching out better extraction technology, energy companies focused more attention on geological innovation: Finding better ways to discover and measure how much petroleum is beneath the surface.

And compared with industries like biotechnology, which spend heavily to grow and develop, the energy industry is mature, "so they don't spend as much" on technology, said Peter Tertzakian, the chief energy economist for Calgary-based ARC Financial.

What's needed, he said, is for the industry to undergo a "renaissance" that requires a boost in spending.

Part of the responsibility also lies with government, which has, in the past, been integral to pushing the oil sands forward. The Alberta Oil Sands Technology and Research Authority, or AOSTRA, was created by the Alberta government in 1974 to help lower the cost of oil sands development. It succeeded in laying the foundations for the SAGD technology that is in use today.

The Alberta and Saskatchewan governments are both spending money on provincial research bodies that are looking for new solutions. Most notably, Alberta is spending $2-billion over the next 12 years to help develop carbon capture and storage technology.

But less is being spent on the extraction technologies that are most critical to oil sands economics and environmental footprint. In its heyday in the mid-1980s, AOSTRA received more than $70-million in annual funding. Its best current counterpart, the Alberta Energy Research Institute, received $44-million last year, and its executive director, Eddy Isaacs, said the problems that need solving today — cost concerns intermingled with environmental and greenhouse gas issues — are far more complex. Mr. Isaacs said his budget needs to be more than doubled, "at the very least."

There is, however, growing hope that Alberta's sudden decline in fortunes has brought an appetite for change rushing back to the oil patch. And it is coming in expected places.

A NEW SURGE OF INNOVATION?

Take Jamie Blair, for example, a man whose pedigree easily ranks among the best in Alberta. Mr. Blair served as chief operations officer for one of Calgary's biggest conventional oil firms, Husky Oil. His father, the late Bob Blair, founded and led Nova Corp., the Alberta icon that almost single-handedly built a petrochemicals industry in the province. His grandfather, Sid Blair, helped develop the pioneering hot-water extraction process in the 1920s, a critical development that used hot water to lift bitumen from mined oil sands and opened the way for the first Athabasca oil sands mine decades later.

Mr. Blair still has a copy of the thesis statement on that process that his grandfather co-authored. What bothers him is that it's not a historical document: Hot-water separation remains an integral part of modern oil sands mines, many decades after it was first commercialized.

Advances in recent years have helped cut in half the temperature at which the process is done — lowering its energy requirements — but "the work that [Sid Blair] was doing in a lab up at the University of Alberta a million years ago is still the technology of today," he said. "And the upgrading technologies, again, haven't made leaps forward."

Mr. Blair himself is helping fund some research at the University of Calgary that is experimenting with microbes in hopes of making "quantum" savings in the energy required to process bitumen.

But he accuses industry of being afflicted with a "syndrome of 'you can't change the technology.'" He points to the business of natural gas as an example of what's possible. In the past decade, that industry has found itself suddenly able to tap enormous new bodies of natural gas after the development of new drilling and rock-fracturing technologies enabled it to access shale gas, which had previously been considered uneconomic.

The results have been dramatic. In one shale alone, the Barnett in Texas, the U.S. Geological Survey estimated technically recoverable reserves of three trillion cubic feet in 1996. By 2008, the best estimate was 55 trillion cubic feet — a stunning 18-fold increase in what could be economically extracted from one area, thanks almost entirely to technological advance.

The oil sands is in dire need of such a makeover, Mr. Blair said — but has been hampered from trying to change by the past decade's steady surge in crude prices.

"We've seen oil price increases make the old technology seem very practical," he said. "But particularly in today's environment, where oil prices have now retreated dramatically and the challenge is now on cost and efficiency, it puts a harder perspective on things."

"And are people going to rise to the challenge? Yes."

They have in the past, and there are examples where they are today. In 1982, Imperial Oil patented the revolutionary steam-assisted gravity drainage technology now used in most new projects. The result: Industry suddenly gained access to a huge new resource of deep bitumen deposits, all without using the gaping open-pit mines that have drawn such environmental ire.

More recently, Shell has experimented with electrical extraction — using a different method from E-T — and produced 100,000 barrels of oil at a test site near Peace River, although that technology is not yet commercially ready.

Yet early stage efforts remain a bet fraught with risks.

E-T has stumbled in its attempts to apply the technology to the oil sands (it has worked dozens of times in environmental remediation applications). In its second major test, it managed to produce oil from only one of four wells. Its problems ranged from electrical cables that were accidentally severed by surface equipment, to the design of its electrodes. In total, E-T has produced less than 3,000 barrels of oil.

Yet the potential prize for success is huge. E-T's technology, for example, could help open up carbonate oil, a huge hydrocarbon resource that is so tricky to produce that virtually no one has tried. And Petrobank believes its process, which uses a controlled underground burn to intensely heat oil sands and make them flow, can be used in a huge variety of heavy oil fields around the world. Like E-T's process, it requires virtually no water and uses dramatically less energy.

"We are breaking new ground in the industry," said Chris Bloomer, Petrobank's chief operating officer for heavy oil.

He knows doubters think it won't work. He remembers when skeptics said steam-based extraction wouldn't work, either. They believed gravity would have no force in the reservoir, and the oil simply would not flow out. They were wrong then, and he believes they're wrong now.

Will the rest of the industry agree?

Mr. Blair is optimistic that low oil prices are cracking old resistance to change. The way he sees it, companies have two choices: Wait for oil prices to jump high enough that oil sands projects are economic again, or "get there first by being the first on the block to implement newer and more efficient technology."

"It seems like an easy choice to me," he said. "But it takes leadership. It takes innovators."

California rule could hit oil sands producers

SHAWN MCCARTHY
Globe and Mail
April 25, 2009

OTTAWA -- Canadian oil companies face an effective U.S. tax on their greenhouse gas emissions if climate change regulations adopted by California this week are copied by other American jurisdictions.

On Thursday night, the California Air Resources Board adopted the world's first low-carbon fuel standard, which sets a threshold for total carbon dioxide emitted in the production and consumption of all fuels sold in the state.

Although Canadian oil is not currently exported to California, the industry is worried because some 13 states and the government in Washington have proposed similar regulations.

"The main concern we have is not California, it's the influence they have on others," said Rick Hyndman, vice-president at the Canadian Association of Petroleum Producers in Calgary.

The California standard is the latest U.S. attack on the oil sands' environmental performance. A 2005 federal law prohibited U.S. agencies from using fuel that derives from unconventional sources, though there is debate whether that includes oil sands.

The Obama administration has backed similar low-carbon regulations at a national level, though Canadian officials remain hopeful those rules could be more accommodating to oil sands producers.

Mr. Hyndman and representatives of the Canadian and Alberta governments attended a hearing in Sacramento on Thursday, urging the board to drop provisions that they claim discriminate against Canadian oil sands and other crudes that aren't currently refined or marketed in California.

If other states, or Washington, adopt regulations that penalize oil sands crudes, it will cut into producers' revenues, Mr. Hyndman said. They would be forced to divert Canadian exports to markets that do not have such standards, or to invest in expensive abatement technology, beyond what Canadian federal and provincial rules are demanding.

Simon Mui, a San Francisco-based scientist with the National Resources Defense Council, a U.S. environmental group, said the Canadians are wrong in arguing that the regulations discriminate against the oil sands projects. He said the regulations assess fuel sources by their carbon content, regardless of origin.

"They are lobbying for a solution that would unfairly disadvantage low-carbon intensity alternative and renewable fuels and leave themselves off the hook," Mr. Mui said. "They're effectively looking for an exemption from the rule."

---

New California fuel rule may violate NAFTA -lawyer

By Scott Haggett
Reuters
Fri, 24 Apr 22:52

CALGARY, Alberta, April 24 (Reuters) - California's new low-carbon fuel rules may be a violation of NAFTA and World Trade Organization provisions because they would unfairly limit exports of crude from Canada's oil sands to the state, a prominent Canadian trade lawyer said on Friday.

California adopted a first-ever rule on Thursday requiring refineries, producers and importers of motor fuels sold in the state to reduce the "carbon intensity" of their products by 10 percent by 2020, with greater cuts thereafter.

The measures to slash such emissions would force refiners to consider the carbon footprint of the fuels they produce, a potential blow to synthetic crude upgraded from Alberta's oil sands, whose production emits more carbon-dioxide than conventional oil.

However, the state may have no business imposing such rules on oil produced in other countries, a Canadian lawyer said, and the provisions may violate international trade treaties.

"There's definitely a NAFTA case and a WTO case. There's no doubt in my mind about it," said Simon Potter, a partner at the McCarthy Tetrault law firm whose practice includes trade and competition law. "This is California deciding they are going to treat oil differently depending on ... where it comes from. It's an obvious violation of the requirement for national treatment."

NAFTA provisions guarantee that companies and products from Canada, the United States and Mexico are not discriminated against on the basis of nationality or origin.

"Once you get across the border, you have to be treated like everybody else," said Potter, a former president of the Canadian Bar Association. "To the extent that these measures make oil from one part of the world that they consider dirty more expensive than identical oil from another part of the world they consider clean, they've got a discriminatory treatment issue."

Canadian trade officials could not be immediately reached for comment on whether they have concerns about the new rule.

While little or no oil sands crude is currently exported to California, the Alberta government said it considers the provision a threat because the state is a potential market. Also, other U.S. states are considering similar regulations.

"Does it have a possibility of a negative effect on Alberta's bitumen future? I would suggest I'd be very naive if I thought anything other than 'yes' is the proper answer to that," Alberta Energy Minister Mel Knight said on Friday in Houston.

(Additional reporting by Bruce Nichols; editing by Rob Wilson)

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See also:

Oil sands brace for American green fuel regulation

Miliband's coal decision is cynical and meaningless

COMMENT: Britain's 2009 Budget was released on April 22. It contained a funding provision for at least two, perhaps up to four, large scale Carbon Capture and Storage (CCS) projects. Accompanying the budget was an announcement by Britain's Environment Minister, Ed Miliband, that all new coal-fired generation plants must be equipped with CCS, initially to capture a quarter of the carbon emissions, and by 2025, to capture all carbon. George Monbiot is critical of the plan.

George Monbiot
The Guardian
April 23, 2009

If coal plants go ahead on the condition that their emissions will one day be abated through carbon capture and storage technology, then emissions are a certainty

It's simple: there should be no new coal burning without 100% carbon capture and storage (CCS) to bury carbon dioxide emissions underground where they cannot influence the climate.

This is a very different matter from Ed Miliband's proposal in the House of Commons today that energy companies must "demonstrate CCS on a substantial proportion of any new coal-fired power station." The figures he has just proposed (400MW of gross capacity) suggest that only around one-quarter to one-fifth of total emissions from a new plant will be captured.

These partly abated coal plants, in other words, would still be much worse than unabated gas plants.

Miliband went on to insist that "when the technology is proven [we will make a] commitment that CCS will be fitted on the entire plant."

So the big "if" about CCS has magically been turned into a "when".

If Miliband is sure that full-scale CCS is viable, two questions arise:

1. Why has he just announced four demonstration projects to test whether it is viable or not?

2. Why not go ahead with full CCS right now?

Of course, there is no "when". As Alastair Darling told the House of Commons in May 2007:

"It is true to say that the technology to capture, transport and store the carbon exists, but it has not actually been joined up on a commercial basis yet … these things might never become available."

It might work. It might not. As anyone seeking to develop and commercialise a new technology knows, it is likely to be beset by a host of unforeseeable difficulties, which will almost certainly delay it and possibly derail it.

As Miliband says:

"I have had representations that from day one there should be 100% CCS on new coal, but I believe that this does not appreciate the need that still exists to demonstrate the technology before full-scale commercial deployment is possible."

So here's the difficulty for the government. It will approve a new generation of coal-burning power stations, starting with Kingsnorth in Kent, on the basis that they will one day reduce their emissions by means of a technology that has not yet been demonstrated. What happens if the CCS demonstrations show that it doesn't work on the scale Miliband envisages, or not, at least, when he predicts? The only means the government will then have of cutting emissions from the coal-burning plants it approves today is to shut them down, wholly or partially. Two factors mean that this is likely to be politically impossible:

1. The government has to decide now what our future energy mix will be. All large-scale electricity generation - whether from fossil fuel, nuclear or renewables - takes years to plan, develop and bring onstream. If, say, the government decides that in 2020 one-fifth of our power will come from coal, and then discovers in 2020 that coal emissions cannot be abated by CCS, it will not be able to shut those power stations down without massive consequences for electricity supply. The choice will be a stark one: either it will have to abandon its carbon targets or it will have to subject the country to electricity rationing and rolling black-outs. It's not hard to guess which way it would jump.

2. Both Labour and the Conservatives have long colluded with the power generation industry. The Guardian's new revelations about this relationship are just the latest in a long line. The power sector is a formidable industrial lobby group, which no government appears prepared to confront.

Miliband can make extravagant promises today about retrofitting 100% CCS to all new coal-burning power stations by 2020 and preventing them from operating without it. But he probably won't be in office then, and almost certainly won't be in his current role. Perhaps, as a private citizen, he intends to march into the Kingsnorth power plant and demand that it shuts down, but he can expect to be bludgeoned by the police if he does, just like the rest of us.

The government's announcement, in other words, is cynical and meaningless. It cannot enforce the decision it has just made, and it knows that no one else will. If coal plants go ahead on the condition that their emissions will one day be abated through CCS, the emissions will be a certainty. The abatement will not.

monbiot.com

Clean coal push marks reversal of UK energy policy

John Vidal
guardian.co.uk
23 April 2009

Decision not to allow any new coal-powered plants to be built in Britain without carbon capture represents a major victory for the new Department for Energy and Climate Change and green pressure groups

This video from E.ON shows how CO2 could theoretically be captured from coal-power plants in Kent, piped to the North Sea and buried in disused oil and gas fields Link to this video

No new coal-fired power stations will be built in Britain from now on unless they capture and bury at least 25% of greenhouse gases immediately and 100% by 2025, the climate change secretary, Ed Miliband, announced today.

In a reversal of energy policy which represents a major victory for the new Department for Energy and Climate Change and green pressure groups, the government will direct the building of four energy "clusters", generating a total of 2.5GW of electricity, on the east coast of Britain.

Each cluster will have at least one major new coal-fired power station able to collect carbon emissions and transport them out to sea, where they will be buried in redundant oil or gas fields.

The new power stations, the first to be built in over 30 years, are not expected to come onstream until 2015. They will be sited in the Thames Gateway, on the rivers Humber and Tees and in the Firth of Forth in Scotland, with a possible fifth on Merseyside. The government envisages oil and coal companies linking to reduce emissions from coal-powered electricity generation by up to 60% by 2025.

Demanding carbon capture and storage (CCS) on all new coal plants is expected to cost around £1bn for each plant and increase energy bills. Government and energy companies are in talks over how these will be funded but it is expected to come from a levy on all fossil fuel electricity generation in Britain. This could put 2%, or roughly £8 per household a year, on a consumer's electricity bills by 2020. Other funding alternatives being considered are to pay the energy companies according to how much carbon they store underground.

Earlier today, Ed Miliband said that Britain planned to lead the world in clean coal technology. This is expected to become a global industry in the next 50 years as countries commit to reducing carbon emissions to combat global warming. Coal is the dirtiest of fossil fuels but provides at least one-third of the world's electricity.

"There is a massive gain we can benefit from by being in the front of this revolution. We need to signal a move away from the building of unabated coal-fired power stations because it is right for our country to drive us towards a low-carbon [economy]. The change starts now," he said.

Environmental groups found themselves in the unusual position of joining the Confederation of British Industry (CBI) in hailing a government initiative.

"At last Ed Miliband is demonstrating welcome signs of climate leadership in the face of resistance from Whitehall officials and cabinet colleagues. He is the first minister to throw down the gauntlet to the energy companies and demand they start taking climate change seriously," said John Sauven, Greenpeace UK's director.

"This time last year energy issues were being decided by tired ministers in thrall to regressive civil servants. Now we see hints of real climate leadership."

But he added: "Very significant questions remain unanswered, with environmentalists concerned that emissions from coal could still be undermining Britain's climate efforts for years to come. For every tonne of carbon captured and buried from new coal plants before the 2020s, the government seems happy to see three tonnes released into the atmosphere. Until there is a cast-iron guarantee that new coal plants won't be allowed to pump out massive amounts of CO2 from day one, our campaign continues."

The announcement will have the effect of delaying a decision on the go-ahead for a major new coal-fired power station at Kingsnorth in Kent for at least another year, but it is not expected to stop major climate change protests over coming months.

Miliband said it was technically not possible to insist on 100% carbon capture and storage immediately. "Some people will say that Britain needs 100% carbon capture and storage from day one, but this is not practical, affordable or right. The technology must be shown to work on a large scale. If it leads to no new coal-fired power stations going ahead it would be a dramatic failure of leadership. 2025 is a practical."

Environmentalists have run a two-year campaign against new highly polluting coal plants, with attention focusing on E.ON's plans to build the new plant at Kingsnorth. The German utility submitted plans for a normal "unabated" plant, and came within weeks of being given permission by energy secretary John Hutton.

The announcement follows this week's budget which pledged £1.4bn towards home energy saving and other climate change reduction initiatives.

Alaska crude headed for U.S. Gulf Coast - Exxon

By Bruce Nichols
Reuters
April 22, 2009

HOUSTON - A supertanker cargo of Alaska North Slope crude ASW- is headed for the Louisiana Offshore Oil Port, an unusual destination for crude from Alaska, a spokesman for Exxon Mobil's (XOM.N) shipping affiliate confirmed Wednesday.

The Alaska crude is similar in gravity and sulfur content to some Gulf Coast grades of oil, but there could be nonmarket reasons for the voyage, including retiring the vessel from the Alaska trade. It is the last single-hull ship on that service.

Traders said the cargo is being sold for $1.25 a barrel over West Texas Intermediate CLc1, well above the discount of $3 to $5 for which recent ANS cargoes have sold on the West Coast. According to a maritime database, it is due to arrive later this week.

A LOOP spokeswoman declined comment. The spokesman for SeaRiver Maritime Inc, a wholly owned affiliate of Exxon Mobil, declined to comment on the price reported by traders.

Alaska crude once flowed regularly to the United States, traveling by tanker to Panama, crossing the Isthmus of Panama by pipeline and then being tankered to U.S. refineries. Supertankers are too big to transit the canal.

But Alaska oil has flowed almost exclusively to the U.S. West Coast in recent years.

The very large crude carrier SeaRiver Long Beach is a sister ship to the Exxon Valdez, which in 1989 ran aground and leaked millions of gallons oil in Alaska's Prince William Sound in one of the world's largest oil spills.

An official of the Washington State Department of Ecology said the 985-foot-long (300-meter-long) SeaRiver Long Beach was to stop hauling crude from Alaska to the U.S. West Coast by January 2010.

Although it exceeds current regulatory standards for that voyage, the SeaRiver Long Beach is the last single-hull tanker on that service. Double-hull tankers have been adopted to minimize the risk of spills.

Spokesman Ray Botto of SeaRiver Maritime declined to say what the ship's future holds after its latest voyage from Valdez to the LOOP around Cape Horn.

Editing by Jim Marshall
b.nichols@thomsonreuters.com;
+1 713 210 8510;

The Exxon Valdez was renamed Exxon Mediterranean, then SeaRiver Mediterranean, then Mediterranean - and continued carrying oil as an Exxon vessel until 2008. Hong Kong Bloom Shipping Ltd. purchased the ship, refitted it as an ore carrier, and renamed it Dong Fang Ocean. (Wikipedia)

Oil sands brace for American green fuel regulation

SHAWN MCCARTHY
Globe and Mail
April 22, 2009

OTTAWA — Federal and Alberta officials will make a last-ditch effort in California on Thursday to head off a regulation that would target oil sands emission levels and create a new barrier to the export of the unconventional oil.

Despite significant opposition, California's Air Resources Board is expected to approve on Thursday North America's first low-carbon fuel standard, a system that is expected to be a model for the U.S. federal government, 13 American states and several Canadian provinces that have proposed similar regulations.

The California board's regulations would require Canadian oil sands producers to dramatically reduce their emissions before their product could be sold in the state, or to purchase expensive credits from alternative energy producers, like those who make ethanol from non-food feedstocks.

While California does not currently consume oil from the oil sands, the largest state in the union is a potentially lucrative market for American refiners that do handle Alberta-based bitumen and upgraded synthetic crude.

As well, Calgary-based Enbridge Inc. is planning to build a pipeline to deliver oil-sands product to the West Coast, aimed at markets in Asia and California.

Under the low-carbon fuel standard, refiners and petroleum marketers will be required to track their supplies back to the wellhead.

This means marketers will have to provide an assessment of the carbon intensity of the fuel, based on guidelines being produced by staff at the Air Resources Board.

In a letter to California Governor Arnold Schwarzenegger that was filed with the board, federal Natural Resources Minister Lisa Raitt complained that the proposed rules appear to single out oil sands producers for punitive treatment.

“We are concerned that crude oil derived from Canada's oil sands may be discriminated against as a high [carbon-intensity] crude oil, while other crude oils with similar upstream emissions are not singled out,” Ms. Raitt wrote in a letter sent Tuesday.

“This could be perceived as creating an unfair trade barrier between our two countries.”

As part of the state's overall climate change plan, Mr. Schwarzenegger signed an executive order requiring the board to establish a low-carbon fuel standard in order to reduce emissions from the state's motor vehicle fleet by 10 per cent by 2020.

The California regulations would also be a setback for the corn-based ethanol industry, as the board's staff has concluded many sources of conventional ethanol is little better than gasoline when it comes to emissions. Ethanol producers are fighting back, claiming the regulator's methodology is flawed when it comes to determining the emissions that result from land-use practices.

Canadian oil industry officials are furious that the regulators have establish two standards: one for crudes that are already used in the California market and are included in a state-wide carbon intensity average, and another for crude types that are not now sold in the state and will have to fall below that average or face penalties.

The Alberta Energy Department, which has sent an official to intervene in today's hearing, wants to ensure the regulations aren't designed in a way that favours imported oil from Mexico and Venezuela, which can cause as much greenhouse gas emissions as Alberta crude. “We want to make sure that all sources are assessed on a full-life-cycle basis, from well to wheels,” Alberta Energy spokesman Jason Chance said Wednesday.

Several studies have concluded that the oil sands crude result in 20 per cent to 30 per cent higher emissions than fuel derived from conventional light oil, but the industry and Canadian governments argue the oil sands should be compared with other heavy oil sources, which make up an increasing share of the North American consumption.

Ms. Raitt argued California should take into account Canada and Alberta's efforts to reduce greenhouse gas emissions, including from oil sands facilities.

Simon Miu, a San Francisco-based scientist with the Natural Resources Defense Council, said it is critical the regulations penalize fuels that have a heavy carbon content as a way of encouraging low-carbon alternatives.

Mr. Miu recently concluded a study of oil sands emissions that concluded there is a wide disparity among oil sands projects. He said Canadian Natural Resources' Primrose in-site project produced 161 kilograms of carbon dioxide per barrel, while Petro-Canada's McKay River project emits only 34 kilograms per barrel.

Shawn McCarthy is The Globe's Global Energy Reporter

Safety lapses at record level

By Dina O'Meara
Calgary Herald
April 21, 2009

High commodity prices sparked fevered activity in Canada's oilpatch in 2008, sometimes with tragic results, said Canada's federal energy regulator.

Two people died and three were seriously injured while working in the oil and gas industry last year, the National Energy Board (NEB) said in its annual report tabled in Ottawa on Monday.

The fatalities and injuries were included in 58 reportable incidents in the energy industry, the highest number in the board's history and up from 49 the previous year, it noted. The fevered levels of activity in the oil and gas sector certainly contributed to the lower safety results, one agency representative said.

"In 2008, we had the highest levels of construction activity that we've seen in any number of years," said Ken Paulson, technical leader of operations. "Two major pipeline projects across the Prairies with three pipelines being installed is a very, very busy year."

TransCanada Corp. started construction of its 3,456-kilometre Keystone pipeline from Hardisty, Alta., to two points in the U. S. Midwest last year, and Enbridge Inc. launched Southern Lights and Alberta Clipper.

One fatality, an electrocution, was related to one of the Enbridge projects, while the second death involved a single-vehicle rollover.

Paulson suggested the higher number of reportable incidents, ones resulting in damages to people, places or the environment, also were the result of the board working more closely with industry in improving reporting, rather than simply the activity levels.

"What we're trying to do is encourage people to tell us what's going on so we can use that information to hone our compliance programs," he said.

The board completed 216 compliance activities, including inspections, audits and meeting with companies, compared with 99 in 2007.

Last year, there were a total of 26 hazardous occurrences, up slightly from the number of hazardous occurrences in 2007. The increase can be linked to a corresponding increase in activity and hours worked, the board said.

The regulatory agency also presided over a record number of hearings in 2008.

The biggest challenge facing the agency this year will be keeping up with all the new infrastructure associated with the oilsands.

domeara@theherald.canwest.com

© Copyright (c) The Calgary Herald

GE: Energy Business the Savior, But Even That’s Got Headwinds

By Keith Johnson
Wall Street Journal
April 17, 2009

General Electric’s first-quarter earnings were as dire as expected, with a 9% drop in sales and a 35% fall in profit. Once again, the single bright spot was the energy business—but even there, good news was mixed with bad.

The energy unit showed the best growth in the GE empire: Revenue rose 7% to $8.2 billion and profit jumped 19% to $1.3 billion. The energy business showed “great performance” in a quarter that will “be indicative of the total year,” chief financial officer Keith Sherin said in a conference call. GE shares fell 1.5% in early trading.

GE is pinning a lot of hopes on global stimulus spending on new infrastructure, especially in the energy business. Of a global total of about $2 trillion, GE said it sees the opportunity to snag at least $100 billion in deals, with a focus on the U.S., China, Western Europe, and the Middle East.

The question is when that stimulus money will really offset the fallout from the financial crunch. GE’s wind orders fell 8% in the first quarter, Mr. Sherin said. And while the company touted a recent wind farm deal with Invenergy as a sign that “U.S. wind projects [are] being executed,” the deal was announced last year and was just pushed back to 2009.

Still, the energy revolution is about more than wind farms—GE says it sees business opportunities of $500 million for each million-person city that adopts a smart power grid. Next week, chief executive Jeff Immelt said, GE will announce a deal for smart grid rollout in a “big city.”

Pipe Down: Alaska May Get a Gas Pipeline, Just Not the Big One

By Russell Gold
Wall Street Journal
April 17, 2009

Just a couple days after Alaska Gov. Sarah Palin talked up natural gas, while apparently moderating her stance on global warming, she received an unexpected present from her state legislature.

Gas, please (AP)

Juneau is buzzing about a last-minute addition to the state’s capital budget giving Gov. Palin funds to push ahead on a small pipeline to bring gas from the North Slope down to Fairbanks and Anchorage, where most Alaskans live.

Alaska is in a pickle. There’s a lot of natural gas on the North Slope, but very few people live up there. There’s some gas in Cook Inlet, near the population centers, but that is running out.

The big oil producers on the North SlopeBP and ConocoPhillips in particularare backing a plan to build a very large pipeline to move the gas all the way down to the Lower 48 states. But plans for this $30 billion project are stalled for many reasons, not least because gas prices are low and expected to stay that way for some time.

Meanwhile neither the BP/Conoco pipeline nor a competing proposal from TransCanada are moving forward quickly and the two projects can’t find common ground to join forces.

Against this backdrop, it seems at times that Alaskans will never be able to use their world-class gas deposits to, say, heat their homes, something that is kind of important up there.

But if the legislature revives plans for a bullet pipeline, it would be a victory for Gov. Palinand a setback for the companies that want to pursue the giant pipeline.

Alaskans want the jobs a giant pipeline would create and the revenue developing gas reserves would mean for the dwindling annual checks Alaskans receive. But they need more gas within a decade, or it could get awfully cold up there.

Californians voice concerns to Obama administration over offshore drilling

By Maria L. La Ganga
Los Angeles Times
April 17, 2009

Those opposed to offshore drilling of oil and gas protest outside a public meeting in San Francisco. The meeting wrapped up at two-week listening tour by the Obama administration. (Justin Sullivan / Getty Images)

During a public comment session in San Francisco, environmental activists decry expansion of oil and gas drilling, which could be allowed after Bush lifted a ban on new leases off the nation's coast.

Reporting from San Francisco -- For all his green talk en route to the White House, President Barack Obama remains a cipher on one of the most critical environmental and economic issues facing California: whether to expand drilling for oil and gas off the coast for the first time in a generation.

In four crowded meetings from Atlantic City to Anchorage, the administration has elicited heated comment from all sides on the future of the outer continental shelf, wrapping up a two-week listening tour Thursday in eco-friendly San Francisco.

"How green is Obama? I would say on energy in general, extremely green and visionary and smart," said Warner Chabot, chief executive of the California League of Conservation Voters. "On the issue of offshore oil drilling, there's a big, giant question mark."

Nine months ago, then-President Bush lifted a long-standing White House ban on new oil and gas leases off the nation's coastlines. On Sept. 30, the congressional moratorium on offshore leasing expired.

In the waning months of Bush's tenure, his administration ordered a five-year plan for awarding offshore drilling leases, including opening up 130 million acres off the California coast.

Shortly after Obama took office, Interior Secretary Ken Salazar extended the public comment period. The big question now is what the new administration will do.

"We're all waiting to see if he changes the plan," said Alison J. Dettmer, deputy director of energy for the California Coastal Commission. "We want him to change the plan. We all hope that he will -- and remove all the leases in California."

Salazar did little Thursday to fill in the blanks. At a news conference during the all-day hearing, the former Colorado senator said that oil and gas production "has to be something that is on the table for consideration."

"Does that mean we will rubber stamp what President Bush and his administration did with respect to the five-year plan?" he asked. "I expect that the answer to that is no. We will have a different plan, a new way forward that is a comprehensive energy plan."

Although environmental activists promised that Thursday's hearing at UC San Francisco's Mission Bay campus would be attended by a "giant oil rig, dolphin/jellyfish costumes, thousands of activists with signs, live music, surfboards, beach balls," the actual turnout was not nearly on that scale.

Yes, there were some jellyfish of human proportions, a band playing surf music and activists in full-body polar bear and sea turtle suits. A big banner beseeched, "Salazar: Save Polar Bears Now!"

But there were also empty seats in the auditorium, which seats fewer than 500.

"I am kind of disappointed that there wasn't more turnout," said Tim Lyons, a member of the Fremont-based California Coastkeeper Alliance who was decked out as a furry brown sea otter.

Even without the promised cast of thousands, representatives from the oil and gas industry were outnumbered and often booed. Salazar even went out of his way to demand that the audience applaud Joe Sparano, president of the Western States Petroleum Assn., for showing up.

Sparano acknowledged that offshore drilling in California is "an emotional issue," but he said that there is "factual information" to prove why "gaining access to additional domestic supplies even here in California is important."

The United States imports between 60% and 65% "of every drop of oil we use every day," he said. And the 10 billion barrels of oil available in California's offshore leases "would allow us to replace California's foreign imports for 35 years."

But a phalanx of elected officials -- including Sen. Barbara Boxer (D-Calif.), Oregon Gov. Ted Kulongoski and the mayor of Fort Bragg, Calif. -- condemned any plan to open up the California coast.

They talked in economic terms about coastal jobs, tourism and fishing. They talked in aesthetic terms about the beauty of the 1,150 or so miles of sand and sea. They praised the ocean's biodiversity.

Lt. Gov. John Garamendi even invoked a higher power, describing the coast as "a spiritual thing for Californians."

They repeatedly recalled the 1969 oil rig blowout off Santa Barbara, a disaster that spilled more than 200,000 gallons of crude and gave birth to the modern conservation movement.

"Our beautiful coastline and our coastal economy," Boxer said, "are too precious to risk."

maria.laganga@latimes.com

TransCanada, Shell's plan for LNG rejected

Shaun Polczer
Calgary Herald
April 14, 2009

CALGARY - Plans by Calgary-based TransCanada Corp. and Shell to build a floating liquefied natural gas( LNG)terminal in the water off New York City were dealt a potentially fatal blow Monday after the United States'Commerce Department rejected the project.

TransCanada and Shell had hoped to build the$700-million Broadwater facility in the water of Long Island Sound in a bid to level off price spikes and open a new avenue for natural gas supplies into the lucrative Northeastern U. S. market.

Traditional gas sources from Canada and the Gulf Coast are expected to decline even as energy use in the area is expected to surge through 2025.

But in its ruling, the department said "the record does not establish that the national interest furthered by the project outweighs the project's adverse coastal effects. Separately, the record does not establish that the project is necessary in the interest of national security."

The rejection comes despite unanimous approval from the Federal Energy Regulatory Commission and U. S. Coast Guard over the objections of both the state governments of New York and Connecticut. Monday's ruling means Broadwater will have no recourse but to appeal to the U. S. courts to overturn the ruling, which Connecticut Gov. Jodi Rell described as a"knockout blow" for the project.

"This misguided project is now down for the count," she said in a statement posted on her website. "The ruling means we can turn our attention to . . . policies that will meet our needs for power without devastating treasured natural resources."

The decision comes almost a year to the day after New York Gov. David Paterson stood on a Long Island beach to officially proclaim the state's opposition to the proposal. "This is an extremely important victory for the health and future of the Long Island Sound and the State of New York."

TransCanada spokespeople referred media requests to the New York offices of the Broadwaterconsortium, whichinturn said it hasn't decided whether to appeal the decision.

"We are disappointed in the commerce secretary's ruling," said John Hritcko, Broadwater's senior vice-president. "We believe the region will need additional natural gas to ensure a reliable supply of energy, help reduce price spikes and meet air quality and climate change goals."

spolczer@theherald.canwest.com

© Copyright (c) The Calgary Herald

CN plans 'pipeline on rail' to tar sands

CN RAIL LINE TO THE OIL SANDS (cn.ca, Andrew Barr, National Post)

Diane Francis
Financial Post
Wednesday, April 09, 2009

CN could gear up its capacity to ship by rail up to four million barrels a day of oil at less cost and more quickly, bypassing the need to finance huge pipelines.

Canadian National Railway Co. has developed a transformative strategy it calls the "Pipeline on Rail" that can move oil-sands production quickly and cheaply to markets in North America or Asia.

Currently, pipelines charge $17.95 per barrel to ship oil from Alberta to the U.S. Gulf Coast. Estimates are that the increase in pipeline capacity to four million barrels a day from the oil sands to the Gulf of Mexico would cost about $25-billion to build and take years to complete.

CN could gear up its capacity to ship by rail up to four million barrels a day of oil at less cost and more quickly, bypassing the need to finance huge pipelines. By the end of this year, the company will be shipping 10,000 barrels daily from producers whose reserves are now stranded.

"Not enough pipeline capacity exists today to move bitumen [gooey oil-sands production], diluted bitumen [called dilbit] or synthetic crude," Jim Foote, CN's executive vice-president of sales and marketing, said in an interview this week. "We can get their products today to market using the concept of a pipeline on rail and move it directly either into the U.S. or to the West Coast [for shipment to Asia], which creates the flexibility. It means smaller producers are not just tied to a refinery down in Texas."

Mr. Foote, an American from Chicago, is excited about the concept, which may, once volumes build, eventually replace freight tonnage lost in the manufacturing and forestry sectors during this severe recession.

CN recently acquired the Athabasca Northern Railway linking Edmonton to Fort McMurray, Alta., to cash in on the oil-sands action. The railway will deliver the oil-sands production through the use of insulated and heatable railcars or by reducing its viscosity by mixing it with condensates or diluents.

The "scaleability" of the concept - up to millions of barrels per day - means that the railway can ramp up production cheaply and quickly to provide immediate cash flow to producers which otherwise will have to wait years for completion of upgraders and/or pipelines.

"That's the beauty of having the rail system. It's scaleable, can go in any direction they want to go - to the West Coast ports of Prince Rupert, Kitimat or Vancouver, or down to the Gulf coast - where the capacity is already in place and where they are used to refining heavy crude," he said.

The cost of a pipeline expansion from Edmonton to Kitimat, B.C., is estimated at $4-billion to handle nearly 600,000 barrels per day of bitumen and diluent. But producers will have to sign on, and take the pricing risk, for 20 years and wait years to get it built.

CN estimates it could ship and have the capacity to handle 2.6 million barrels a day of oil products to the West Coast if 20,000 railcars were added to its fleet.

For instance, CN's current volume of coal shipments is equivalent to transporting 624,000 barrels per day and represents only 5% of CN's business. CN moves about 130 trains a day in Western Canada alone. To add 10% of the potential oil-sands production of four million daily to the company's operations, or 400,000 barrels daily, would be equivalent to between four to six new trains a day.

The rail option also circumvents the problem, for Canadian producers, of reliance on monopoly markets in the United States, and on the fickleness of environmental politics south of the border.

"As the oil-sands issues have developed recently, and prices come down, and a lot of the upgrader facilities have gone away, the need for some way to get the smaller and medium-sized players into the marketplace is becoming critical," Mr. Foote said.

"The number I have seen for constructing a pipeline to serve the West Coast is $4-billion. Our rail network is already in place to get to all the West Coast ports. Any terminal facilities needed would have to be put in place whether customers used pipeline or rail. CN's service is scaleable, meaning capacity can be matched with production," Mr. Foote added.

"Our target is to be moving 10,000 barrels a day by the end of this year. We already move a lot of petroleum products. Our capabilities to handle this product are clearly not an issue and we handle a lot more products that are much more environmentally risky than this would be. Diluted or moved in a car that can be heated is similar to how we ship asphalt today."

Rail's other benefit is speed.

"We can take this to any port, any place the customer wants it to go, with a minimum capital investment," he said. "We can get a railcar to the Gulf Coast in eight days but in a pipeline it could take 50 days to get there."

The rail cars can go full in both directions to lower costs, taking bitumen down and bringing condensates back, thus lowering costs.

CN is going to test its concept shortly with producers. Immediate beneficiaries will be projects now being developed by Japanese, French and American partnerships, which are located along CN's line between Edmonton and Fort McMurray.