Aug 19, 2008 4:40:00 PM MSTShell Canada gets regulatory approvals for its $5 billion takeover of Duvernay Oil Corp. (Shell-Duvernay)
CALGARY _ Shell Canada Ltd., a wholly owned subsidiary of Royal Dutch Shell plc, says it has received Canadian regulatory approvals for its $5 billion deal to buy Duvernay Oil Corp. (TSX:DDV), a Calgary-based natural gas producer.Shell announced late Tuesday it had gotten approval from the Minister of Industry under the Investment Canada Act for its acquisition of Duvernay Oil/Shell said that in approving the deal, the government "determined that the transaction is likely to be of net benefit to Canada for purposes of the Investment Canada Act."The oil giant also said the Commissioner of Competition under the federal Competition Act had granted Shell Canada an advance ruling certificate that says the deal clears competition hurdles.As a result of the two rulings, Shell Canada has now received all necessary Canadian regulatory approvals to proceed with the acquisition of Duvernay.The $83 a share offer for Duvernay was announced in mid-July and expires Aug. 22.Duvernay has major natural gas properties in the Montney area of northeastern British Columbia and northwestern Alberta and generated record output of 25,584 barrels of daily oil equivalent production in the latest quarter.
August 20, 2008
Baku-Ceyhan oil pipeline to resume operations
Thomson Financial NewsBP says Baku-Ceyhan oil pipeline to resume operations
08.20.08, 6:54 AM ET
LONDON, Aug 20 (Reuters) - BP Plc said on Wednesday that testing of the Baku-Tbilisi-Ceyhan oil pipeline would begin, ahead of a move to resume full operation of the route damaged by a fire earlier this month.
Toby Odone, a BP (nyse: BP - news - people ) spokesman, added that the lifting schedule for Azeri crude at Ceyhan will be updated on Wednesday for tanker loadings to resume at the beginning of next week.
(Reporting by Alex Lawler)
08.20.08, 6:54 AM ET
LONDON, Aug 20 (Reuters) - BP Plc said on Wednesday that testing of the Baku-Tbilisi-Ceyhan oil pipeline would begin, ahead of a move to resume full operation of the route damaged by a fire earlier this month.
Toby Odone, a BP (nyse: BP - news - people ) spokesman, added that the lifting schedule for Azeri crude at Ceyhan will be updated on Wednesday for tanker loadings to resume at the beginning of next week.
(Reporting by Alex Lawler)
What is The Syncrude Project ?
http://www.cos-trust.com/
At a Glance
The Syncrude Project is a joint venture undertaking among Canadian Oil Sands Limited (36.74%); Conoco-Phillips Oil Sand Partnership II (9.03%); Imperial Oil Resources (25%); Mocal Energy Limited (5%); Murphy Oil Company Ltd. (5%); Nexen Oil Sands Partnership (7.23%); and Petro-Canada Oil and Gas (12%).
The Syncrude Project is operated and administered by Syncrude Canada Ltd. on behalf of the participants.
The Syncrude consortium was formed in 1964 with the official opening of the project and the first barrel shipped in 1978.
Located near Fort McMurray, Alberta, Syncrude operates large oil sands mines, utilities plants, bitumen extraction plants and an upgrading complex that processes bitumen into a light sweet crude oil.
The crude oil produced by Syncrude is referred to as Synthetic Crude Oil ("SCO"), which is a high quality, light sweet crude oil with no residual bottoms and low sulphur content (See Marketing section for more information).
Syncrude is one of the largest holders of Alberta's mineable oil sands leases with eight leases covering approximately 100,000 hectares.
Syncrude has proved and probable reserves of 4.9 billion barrels of SCO, which represent a lifespan of approximately 35 years at Stage 3 capacity with the potential to extend reserve life beyond the year 2050 as the leases are developed.
Syncrude has a long-term growth plan that envisions productive capacity reaching about 500,000 barrels per day of a premium quality, light sweet crude oil post 2016. Stages 1, 2 and 3 of the plan have been completed. The most recent Stage 3 expansion came on-stream in 2006 at a capital cost of about Cdn $8.55 billion, and expanded productive capacity to average approximately 350,000 barrels per day. The next expansions are referred to as the Stage 3 debottleneck and Stage 4, which have not yet been approved and are in the conceptual planning phase. The Stage 3 debottleneck will leverage and optimize the potential of Stage 3, which included pre-investment to enable further production expansion. Stage 4 currently envisions further expansion of upgrading capacity, primarily through the construction of a fourth coker, and additional mining trains on one of Syncrude's undeveloped leases.
In 2007, Syncrude shipped 111.3 million barrels of synthetic crude oil.
Syncrude is a leader in technological innovation of oil sands recovery and has pioneered many of the technologies used throughout the oil sands industry today, including low energy extraction and hydrotransport. These innovations have reduced energy requirements, thereby reducing operating costs and emissions.
Syncrude is fully committed to excellence in environment, health and safety performance in the conduct of its business and in support of a safe, reliable and profitable operation.
Syncrude is a major engine of growth for the Alberta and Canadian economies with over $4.2 billion in total spending during 2006.
More information on Syncrude Canada can be found in their sustainability report, available on Syncrude's website at www.syncrude.ca.
At a Glance
The Syncrude Project is a joint venture undertaking among Canadian Oil Sands Limited (36.74%); Conoco-Phillips Oil Sand Partnership II (9.03%); Imperial Oil Resources (25%); Mocal Energy Limited (5%); Murphy Oil Company Ltd. (5%); Nexen Oil Sands Partnership (7.23%); and Petro-Canada Oil and Gas (12%).
The Syncrude Project is operated and administered by Syncrude Canada Ltd. on behalf of the participants.
The Syncrude consortium was formed in 1964 with the official opening of the project and the first barrel shipped in 1978.
Located near Fort McMurray, Alberta, Syncrude operates large oil sands mines, utilities plants, bitumen extraction plants and an upgrading complex that processes bitumen into a light sweet crude oil.
The crude oil produced by Syncrude is referred to as Synthetic Crude Oil ("SCO"), which is a high quality, light sweet crude oil with no residual bottoms and low sulphur content (See Marketing section for more information).
Syncrude is one of the largest holders of Alberta's mineable oil sands leases with eight leases covering approximately 100,000 hectares.
Syncrude has proved and probable reserves of 4.9 billion barrels of SCO, which represent a lifespan of approximately 35 years at Stage 3 capacity with the potential to extend reserve life beyond the year 2050 as the leases are developed.
Syncrude has a long-term growth plan that envisions productive capacity reaching about 500,000 barrels per day of a premium quality, light sweet crude oil post 2016. Stages 1, 2 and 3 of the plan have been completed. The most recent Stage 3 expansion came on-stream in 2006 at a capital cost of about Cdn $8.55 billion, and expanded productive capacity to average approximately 350,000 barrels per day. The next expansions are referred to as the Stage 3 debottleneck and Stage 4, which have not yet been approved and are in the conceptual planning phase. The Stage 3 debottleneck will leverage and optimize the potential of Stage 3, which included pre-investment to enable further production expansion. Stage 4 currently envisions further expansion of upgrading capacity, primarily through the construction of a fourth coker, and additional mining trains on one of Syncrude's undeveloped leases.
In 2007, Syncrude shipped 111.3 million barrels of synthetic crude oil.
Syncrude is a leader in technological innovation of oil sands recovery and has pioneered many of the technologies used throughout the oil sands industry today, including low energy extraction and hydrotransport. These innovations have reduced energy requirements, thereby reducing operating costs and emissions.
Syncrude is fully committed to excellence in environment, health and safety performance in the conduct of its business and in support of a safe, reliable and profitable operation.
Syncrude is a major engine of growth for the Alberta and Canadian economies with over $4.2 billion in total spending during 2006.
More information on Syncrude Canada can be found in their sustainability report, available on Syncrude's website at www.syncrude.ca.
www.petroleumworld.com
www.petroleumworld.com The World, Bolivia, Brazil, Venezuela, Trinidad, Peru and Latin America's Energy, Oil & Gas Industry on the Internet
WWW.PETROLEUMWORLD.COM is a free service web site that provide real time news and information on Latin America, Bolivia, Brazil, Peru, Trinidad and Venezuela's Energy, Oil & Gas industry prepared by professionals in the area and using the latest technological advances in communication.
WWW.PETROLEUMWORLD.COM is a free service web site that provide real time news and information on Latin America, Bolivia, Brazil, Peru, Trinidad and Venezuela's Energy, Oil & Gas industry prepared by professionals in the area and using the latest technological advances in communication.
Blind faith in oil growth
http://www.chinadialogue.net/article/show/single/en/1078-Blind-faith-in-oil-growth
Blind faith in oil growth
George Monbiot
June 08, 2007
Britain's future prosperity has been hardwired to the rising use of transport fuels, without a thought for the supply drying up, writes George Monbiot. Such belief could bring the economy crashing down.
Motorised transport is a form of time travel. We mine the compressed time of other eras -- the infinitesimal rain of plankton on the ocean floor, the settlement of trees in anoxic swamps -- and use it to accelerate through our own. Every tank of fuel contains thousands of years of accretions. Our future depends on the expectation that the past will never be exhausted.
The energy white paper, or policy document, that the British government published on May 23, 2007, talks of new taxes, new markets, new research, new incentives. Anyone reading the report’s chapter on transport would be forgiven for believing that the government has the problem under control: as a result of its measures, we are likely to see a great reduction in our use of geological time.
Buried in another chapter, however, and so far missed by all journalists, there is a remarkable admission: "The majority (66%) of UK oil demand is derived from demand for transport fuels which is expected to increase modestly over the medium term." To increase? If the government is implementing all the exciting measures the transport chapter contains, how on earth could our use of fuel increase?
You won't find the answer in the white paper. It mysteriously forgets to mention that the government intends to build another 2,500 miles of trunk roads and to double the capacity of our airports by 2030. Partly to permit this growth in transport, another white paper, published on May 21, proposes a massive deregulation of planning law. There is no discussion in either paper of the implications of these programmes for energy use or climate change. There are plainly two governments of the United Kingdom, one determined to reduce our consumption of fossil fuel, the other determined to raise it.
What happens beyond the medium term is anyone’s guess. But it should be pretty obvious that more roads and more airports will mean that our rising use of transport fuel becomes hardwired -- the future health of the economy will depend on it. So the government must have examined this question. If our economic lives depend on continued growth in the consumption of transport fuels, it must first have determined that such growth is possible. Mustn't it?
I phoned four government departments -- trade and industry, transport, environment, communities and local government -- in the hope of finding this assessment. But it does not exist. No report has ever been commissioned by the British government on the issue of whether or not there is enough oil to sustain its transport programme.
Instead, both the white paper and the civil servants I spoke to referred me to a book published by the International Energy Agency (IEA), set up by the Organisation for Economic Cooperation and Development (OECD) after the 1974 oil crisis. This in itself is odd. On every other issue that might affect the United Kingdom’s security or economic growth, the government conducts its own assessments. But in this case it relies exclusively on one external source. This reliance seems even odder when you read the IEA's book and discover that it's as polemical as my columns.
Before it presents any evidence, the book dismisses people who have questioned future oil supplies as "doomsayers". It announces that it has "long maintained that none of this [the possibility that oil supplies might be reaching a peak] is a cause for concern". Though it expects the global demand for oil to rise by 70% between now and 2030, and though it anticipates that output from the world's existing oilfields will decline by about 5% a year, it is confident that new supplies will make up the difference.
It bases this assessment on the finding that "the level of remaining reserves of oil has been remarkably constant historically, in spite of the volumes extracted each successive year". As the IEA must know as well as anyone else, this is partly because the level has been forged by members of Opec, the oil producers' cartel. The quota assigned to a member of the Organisation of the Petroleum Exporting Countries reflects the size of its reserves. All members have a powerful interest in exaggerating their reserves in order to boost their quotas. The IEA admits in another report that Saudi Arabia has posted a constant level of reserves (260 billion barrels) over the past 15 years, despite the fact that it has produced over 100 billion barrels in the same period. Where has the magic oil come from?
But it is the liars of Opec on whom the agency's optimism relies. The growth in global demand will be met, it says, by a 150% increase in oil production from the Middle East by 2030. What if this oil doesn't materialise? It is a question the IEA raises then rapidly drops. "Because of the uncertainties over the respective amounts of resources and reserves, it is difficult to predict the moment of peak oil, when production might be expected to start to decline. Estimates range from today to 2050 or beyond." Isn't that reassuring?
I should point out that peak oil is not like climate change. There is no consensus among scientists about when it is likely to happen. I cannot state with confidence that the IEA's assessment is wrong. But a report published in February by the US department of energy shows how dangerous it is to rely on a single source. "Almost all forecasts are based on differing, often dramatically differing, geological assumptions ... Because of the large uncertainties, it is difficult to define an overriding geological basis for accepting or rejecting any of the forecasts."
The report then publishes a long list of estimates by senior figures in and around the oil industry of a possible date for peak oil. They vary greatly, but many are clustered between 2010 and 2020. Another report, also commissioned by the US department of energy, shows that "without timely mitigation, the economic, social, and political costs will be unprecedented". The disasters invoked by the peaking of global oil supplies can be avoided only with a "crash program" beginning 20 years before it occurs. If some of the estimates in the department of energy's report are correct, it is already too late.
The IEA believes that this crisis will be averted by opening new fields and using non-conventional oil. But these cause environmental disasters of their own. Around half the new discoveries the agency expects during the next 25 years will take place in the Arctic or in the very deep sea, between 2,000 and 4,000 metres. In either case, a major oil spill, in such slow and fragile ecosystems, would be catastrophic. Mining non-conventional oil, such as the tar sands in Canada or the kerogen shales in the US, produces far more carbon dioxide than drilling for ordinary petroleum. It also uses and pollutes great volumes of fresh water and wrecks thousands of acres of pristine land. "In the long-term future," the IEA says, "non-conventional, heavy oils may well become the norm rather than the exception." If our future growth relies on these resources, we commit ourselves to ever-growing environmental impacts.
We don't need to invoke peak oil to produce an argument for cutting our use of transport fuel. But you might have imagined that the UK government would have shown just a little curiosity about whether or not its transport programme will bring the economy crashing down.
Blind faith in oil growth
George Monbiot
June 08, 2007
Britain's future prosperity has been hardwired to the rising use of transport fuels, without a thought for the supply drying up, writes George Monbiot. Such belief could bring the economy crashing down.
Motorised transport is a form of time travel. We mine the compressed time of other eras -- the infinitesimal rain of plankton on the ocean floor, the settlement of trees in anoxic swamps -- and use it to accelerate through our own. Every tank of fuel contains thousands of years of accretions. Our future depends on the expectation that the past will never be exhausted.
The energy white paper, or policy document, that the British government published on May 23, 2007, talks of new taxes, new markets, new research, new incentives. Anyone reading the report’s chapter on transport would be forgiven for believing that the government has the problem under control: as a result of its measures, we are likely to see a great reduction in our use of geological time.
Buried in another chapter, however, and so far missed by all journalists, there is a remarkable admission: "The majority (66%) of UK oil demand is derived from demand for transport fuels which is expected to increase modestly over the medium term." To increase? If the government is implementing all the exciting measures the transport chapter contains, how on earth could our use of fuel increase?
You won't find the answer in the white paper. It mysteriously forgets to mention that the government intends to build another 2,500 miles of trunk roads and to double the capacity of our airports by 2030. Partly to permit this growth in transport, another white paper, published on May 21, proposes a massive deregulation of planning law. There is no discussion in either paper of the implications of these programmes for energy use or climate change. There are plainly two governments of the United Kingdom, one determined to reduce our consumption of fossil fuel, the other determined to raise it.
What happens beyond the medium term is anyone’s guess. But it should be pretty obvious that more roads and more airports will mean that our rising use of transport fuel becomes hardwired -- the future health of the economy will depend on it. So the government must have examined this question. If our economic lives depend on continued growth in the consumption of transport fuels, it must first have determined that such growth is possible. Mustn't it?
I phoned four government departments -- trade and industry, transport, environment, communities and local government -- in the hope of finding this assessment. But it does not exist. No report has ever been commissioned by the British government on the issue of whether or not there is enough oil to sustain its transport programme.
Instead, both the white paper and the civil servants I spoke to referred me to a book published by the International Energy Agency (IEA), set up by the Organisation for Economic Cooperation and Development (OECD) after the 1974 oil crisis. This in itself is odd. On every other issue that might affect the United Kingdom’s security or economic growth, the government conducts its own assessments. But in this case it relies exclusively on one external source. This reliance seems even odder when you read the IEA's book and discover that it's as polemical as my columns.
Before it presents any evidence, the book dismisses people who have questioned future oil supplies as "doomsayers". It announces that it has "long maintained that none of this [the possibility that oil supplies might be reaching a peak] is a cause for concern". Though it expects the global demand for oil to rise by 70% between now and 2030, and though it anticipates that output from the world's existing oilfields will decline by about 5% a year, it is confident that new supplies will make up the difference.
It bases this assessment on the finding that "the level of remaining reserves of oil has been remarkably constant historically, in spite of the volumes extracted each successive year". As the IEA must know as well as anyone else, this is partly because the level has been forged by members of Opec, the oil producers' cartel. The quota assigned to a member of the Organisation of the Petroleum Exporting Countries reflects the size of its reserves. All members have a powerful interest in exaggerating their reserves in order to boost their quotas. The IEA admits in another report that Saudi Arabia has posted a constant level of reserves (260 billion barrels) over the past 15 years, despite the fact that it has produced over 100 billion barrels in the same period. Where has the magic oil come from?
But it is the liars of Opec on whom the agency's optimism relies. The growth in global demand will be met, it says, by a 150% increase in oil production from the Middle East by 2030. What if this oil doesn't materialise? It is a question the IEA raises then rapidly drops. "Because of the uncertainties over the respective amounts of resources and reserves, it is difficult to predict the moment of peak oil, when production might be expected to start to decline. Estimates range from today to 2050 or beyond." Isn't that reassuring?
I should point out that peak oil is not like climate change. There is no consensus among scientists about when it is likely to happen. I cannot state with confidence that the IEA's assessment is wrong. But a report published in February by the US department of energy shows how dangerous it is to rely on a single source. "Almost all forecasts are based on differing, often dramatically differing, geological assumptions ... Because of the large uncertainties, it is difficult to define an overriding geological basis for accepting or rejecting any of the forecasts."
The report then publishes a long list of estimates by senior figures in and around the oil industry of a possible date for peak oil. They vary greatly, but many are clustered between 2010 and 2020. Another report, also commissioned by the US department of energy, shows that "without timely mitigation, the economic, social, and political costs will be unprecedented". The disasters invoked by the peaking of global oil supplies can be avoided only with a "crash program" beginning 20 years before it occurs. If some of the estimates in the department of energy's report are correct, it is already too late.
The IEA believes that this crisis will be averted by opening new fields and using non-conventional oil. But these cause environmental disasters of their own. Around half the new discoveries the agency expects during the next 25 years will take place in the Arctic or in the very deep sea, between 2,000 and 4,000 metres. In either case, a major oil spill, in such slow and fragile ecosystems, would be catastrophic. Mining non-conventional oil, such as the tar sands in Canada or the kerogen shales in the US, produces far more carbon dioxide than drilling for ordinary petroleum. It also uses and pollutes great volumes of fresh water and wrecks thousands of acres of pristine land. "In the long-term future," the IEA says, "non-conventional, heavy oils may well become the norm rather than the exception." If our future growth relies on these resources, we commit ourselves to ever-growing environmental impacts.
We don't need to invoke peak oil to produce an argument for cutting our use of transport fuel. But you might have imagined that the UK government would have shown just a little curiosity about whether or not its transport programme will bring the economy crashing down.
Brazilian ethanol exports?
The New European Challenge for Brazilian Ethanol Exports
Date Published: 7 Feb 2008
http://www.frost.com/prod/servlet/market-insight-top.pag?Src=RSS&docid=120514123
Date Published: 7 Feb 2008
http://www.frost.com/prod/servlet/market-insight-top.pag?Src=RSS&docid=120514123
cellulosic ethanol
I understand that there is a lot of information out there on ethanol made from corn (US) and sugar cane (Brazil). I wanted to have a post and magazine article about cellulosic ethanol because of the supply of raw materials for its production
http://www.technologyreview.com/read_article.aspx?ch=specialsections&sc=biofuels&id=18227&a=
Monday, February 26, 2007
Will Cellulosic Ethanol Take Off?
Fuel from grass and wood chips could be big in the next 10 years--if the government helps.
By Kevin Bullis
Cellulosic ethanol, a fuel produced from the stalks and stems of plants (rather than only from sugars and starches, as with corn ethanol), is starting to take root in the United States. This month, Celunol, based in Cambridge, MA, broke ground on an ethanol plant in Louisiana that will be able to produce 1.4 million gallons of the fuel each year starting in 2008. Other companies are moving forward as well with plans to build plants.
But experts from industry and environmental groups say that without loan guarantees and other incentives, the nascent industry will fail to emerge from the current demonstration phase to produce commercial-scale quantities of ethanol. And without that, it may be impossible to meet President Bush's ambitious goal of producing 35 billion gallons of renewable fuels a year by 2017.
Cellulosic ethanol is attractive because the feedstock, which includes wheat straw, corn stover, grass, and wood chips, is cheap and abundant. Converting it into ethanol requires less fossil fuel, so it can have a bigger effect than corn ethanol on reducing greenhouse-gas emissions. Also, an acre of grasses or other crops grown specifically to make ethanol could produce more than two times the number of gallons of ethanol as an acre of corn, in part because the whole plant can be used instead of just the grain. That's good news because many experts estimate that corn-ethanol producers will run out of land, in part because of competing demand for corn-based food, limiting the total production to about 15 billion gallons of fuel. (Already, corn-ethanol plants--existing and planned, combined--have a capacity of about 11 billion gallons.) The greater productivity of cellulosic sources should eventually allow them to produce as much as 150 billion gallons of ethanol by 2050, according to a report by the National Resources Defense Council (NRDC). That's the equivalent of more than two-thirds of the current gasoline consumption in the United States.
But it will take some time to reach these levels of production. Even producing enough cellulosic ethanol to meet the president's 35-billion-gallon goal will be difficult. That will require that roughly 15 billion gallons would come from non-corn-grain sources such as cellulosic ethanol (about 5 billion gallons might come from biodiesel culled from oils in crops such as soybeans). And reaching 15 billion gallons by 2017 will be a challenge. Currently, according to the ethanol industry's list of producers in the United States, none of the ethanol comes from cellulosic biomass.
Cellulosic-ethanol companies are hopeful that they can meet this goal. Colin South, the president of Mascoma Corporation, also based in Cambridge, says that if all goes well, cellulosic ethanol could supply half of the 35-billion-gallon goal by 2017. But so far Mascoma has only announced plans to build a demonstration facility with a capacity of about half a million gallons of fuel per year. That facility should be ready in 18 months, South says. But as is the case with the new Celunol plant, the facility's primary purpose would be to demonstrate that the company's technology can work at a large scale; it will not always operate at full capacity, as the system is used to test new cost-saving technologies.
Other companies are planning to build plants, but these are also relatively small. Range Fuels (formerly Kergy), based in Broomfield, CO, plans to start construction this year on a 10-million-gallon-per-year plant in Georgia, CEO Mitch Mandich says. A large corn-grain ethanol company, Abengoa Bioenergy, of St. Louis, is building a 1.3-million-gallon biomass ethanol plant in Spain. But even taken together, these plants will supply only a tiny fraction of the 15-billion-gallon target.
"That's a huge goal," says John Howe, vice president of public affairs at Celunol. "That's well beyond what any one company or a large number of companies [can do]. It will take a massive national effort to get close to that goal."
By "national effort," he partly means money for loan guarantees that will encourage financiers to fund the building of large commercial-scale plants. Company executives and cellulosic-ethanol advocates agree on the need for such government help. Iogen Corporation, in Ottawa, Canada, is a case in point. The company has been producing cellulosic ethanol since 2004 and already has an almost 700,000-gallon-per-year demonstration plant. But Iogen's plans for a 20-million-gallon commercial-scale plant are now on hold as the company awaits legislation to be passed in Canada, the United States, or Germany that will provide the financial incentives Iogen needs to build such a big operation.
Yet financing may not be the only hurdle: even if commercial plants can be built, the process may still prove too expensive to compete with corn ethanol, so further work in the lab may be necessary. (See "Redesigning Life to Make Ethanol.")
Indeed, researchers at cellulosic-ethanol companies, national labs, and academic labs are engaged in continuing R&D both in converting biomass into ethanol and in growing more-productive strains of biomass. Right now the conversion is an expensive and water-intensive multistage process. Some groups hope to genetically engineer a single organism to both break down cellulose into simpler sugars and ferment alcohols, thereby simplifying the process. Others are working to improve methods for converting biomass into ethanol using heat and catalysts--the method being used by Range Fuels. And companies such as Celunol are investigating better crops, such as the ancestors of today's sugarcane, that can produce more ethanol per acre.
Some researchers have even given up on the idea of cellulosic ethanol, turning instead to sources such as algae for biofuels. (See "Algae-Based Fuels Set to Bloom.") But Nathanael Greene, an energy-policy specialist at the NRDC, remains optimistic. Although he thinks it's unlikely that cellulosic-ethanol plants will produce more than a few billion gallons of fuel by 2017, "that would put us in the position where the cellulosic industry is really ready to start growing exponentially," he says. "Once we get over that first hump, I think the cellulosic industry will grow quite rapidly, and [it] has much greater longer-term growth potential [than corn ethanol]."
Greene cites the example of the now fast-growing corn-ethanol industry. "It took 10 years to get the first billion gallons and 10 years to get the second billion," he says. "And now we're set to go from 6 to roughly 12 billion in 18 months."
Copyright Technology Review 2007.
http://www.technologyreview.com/read_article.aspx?ch=specialsections&sc=biofuels&id=18227&a=
Monday, February 26, 2007
Will Cellulosic Ethanol Take Off?
Fuel from grass and wood chips could be big in the next 10 years--if the government helps.
By Kevin Bullis
Cellulosic ethanol, a fuel produced from the stalks and stems of plants (rather than only from sugars and starches, as with corn ethanol), is starting to take root in the United States. This month, Celunol, based in Cambridge, MA, broke ground on an ethanol plant in Louisiana that will be able to produce 1.4 million gallons of the fuel each year starting in 2008. Other companies are moving forward as well with plans to build plants.
But experts from industry and environmental groups say that without loan guarantees and other incentives, the nascent industry will fail to emerge from the current demonstration phase to produce commercial-scale quantities of ethanol. And without that, it may be impossible to meet President Bush's ambitious goal of producing 35 billion gallons of renewable fuels a year by 2017.
Cellulosic ethanol is attractive because the feedstock, which includes wheat straw, corn stover, grass, and wood chips, is cheap and abundant. Converting it into ethanol requires less fossil fuel, so it can have a bigger effect than corn ethanol on reducing greenhouse-gas emissions. Also, an acre of grasses or other crops grown specifically to make ethanol could produce more than two times the number of gallons of ethanol as an acre of corn, in part because the whole plant can be used instead of just the grain. That's good news because many experts estimate that corn-ethanol producers will run out of land, in part because of competing demand for corn-based food, limiting the total production to about 15 billion gallons of fuel. (Already, corn-ethanol plants--existing and planned, combined--have a capacity of about 11 billion gallons.) The greater productivity of cellulosic sources should eventually allow them to produce as much as 150 billion gallons of ethanol by 2050, according to a report by the National Resources Defense Council (NRDC). That's the equivalent of more than two-thirds of the current gasoline consumption in the United States.
But it will take some time to reach these levels of production. Even producing enough cellulosic ethanol to meet the president's 35-billion-gallon goal will be difficult. That will require that roughly 15 billion gallons would come from non-corn-grain sources such as cellulosic ethanol (about 5 billion gallons might come from biodiesel culled from oils in crops such as soybeans). And reaching 15 billion gallons by 2017 will be a challenge. Currently, according to the ethanol industry's list of producers in the United States, none of the ethanol comes from cellulosic biomass.
Cellulosic-ethanol companies are hopeful that they can meet this goal. Colin South, the president of Mascoma Corporation, also based in Cambridge, says that if all goes well, cellulosic ethanol could supply half of the 35-billion-gallon goal by 2017. But so far Mascoma has only announced plans to build a demonstration facility with a capacity of about half a million gallons of fuel per year. That facility should be ready in 18 months, South says. But as is the case with the new Celunol plant, the facility's primary purpose would be to demonstrate that the company's technology can work at a large scale; it will not always operate at full capacity, as the system is used to test new cost-saving technologies.
Other companies are planning to build plants, but these are also relatively small. Range Fuels (formerly Kergy), based in Broomfield, CO, plans to start construction this year on a 10-million-gallon-per-year plant in Georgia, CEO Mitch Mandich says. A large corn-grain ethanol company, Abengoa Bioenergy, of St. Louis, is building a 1.3-million-gallon biomass ethanol plant in Spain. But even taken together, these plants will supply only a tiny fraction of the 15-billion-gallon target.
"That's a huge goal," says John Howe, vice president of public affairs at Celunol. "That's well beyond what any one company or a large number of companies [can do]. It will take a massive national effort to get close to that goal."
By "national effort," he partly means money for loan guarantees that will encourage financiers to fund the building of large commercial-scale plants. Company executives and cellulosic-ethanol advocates agree on the need for such government help. Iogen Corporation, in Ottawa, Canada, is a case in point. The company has been producing cellulosic ethanol since 2004 and already has an almost 700,000-gallon-per-year demonstration plant. But Iogen's plans for a 20-million-gallon commercial-scale plant are now on hold as the company awaits legislation to be passed in Canada, the United States, or Germany that will provide the financial incentives Iogen needs to build such a big operation.
Yet financing may not be the only hurdle: even if commercial plants can be built, the process may still prove too expensive to compete with corn ethanol, so further work in the lab may be necessary. (See "Redesigning Life to Make Ethanol.")
Indeed, researchers at cellulosic-ethanol companies, national labs, and academic labs are engaged in continuing R&D both in converting biomass into ethanol and in growing more-productive strains of biomass. Right now the conversion is an expensive and water-intensive multistage process. Some groups hope to genetically engineer a single organism to both break down cellulose into simpler sugars and ferment alcohols, thereby simplifying the process. Others are working to improve methods for converting biomass into ethanol using heat and catalysts--the method being used by Range Fuels. And companies such as Celunol are investigating better crops, such as the ancestors of today's sugarcane, that can produce more ethanol per acre.
Some researchers have even given up on the idea of cellulosic ethanol, turning instead to sources such as algae for biofuels. (See "Algae-Based Fuels Set to Bloom.") But Nathanael Greene, an energy-policy specialist at the NRDC, remains optimistic. Although he thinks it's unlikely that cellulosic-ethanol plants will produce more than a few billion gallons of fuel by 2017, "that would put us in the position where the cellulosic industry is really ready to start growing exponentially," he says. "Once we get over that first hump, I think the cellulosic industry will grow quite rapidly, and [it] has much greater longer-term growth potential [than corn ethanol]."
Greene cites the example of the now fast-growing corn-ethanol industry. "It took 10 years to get the first billion gallons and 10 years to get the second billion," he says. "And now we're set to go from 6 to roughly 12 billion in 18 months."
Copyright Technology Review 2007.
The course that sparked the interest in energy and oil
This is the course and of course the professor that sparked my interest in oil and energy.
The books were a great read, but the research was better.
I did my final paper on the nationalization of Venezuelan oil companies in the 1960s.
http://www-personal.umich.edu/~twod/oil-ns/2005/
The books were a great read, but the research was better.
I did my final paper on the nationalization of Venezuelan oil companies in the 1960s.
http://www-personal.umich.edu/~twod/oil-ns/2005/
Pickens Plan?
The Pickens plan, funded by T. Boone Pickens from BP Capital states that the US is addicted to foreign oil. We've grown more dependent on importing foreign oil more than ever before.
Was Hubbert sort of right?
Pickens is convinced harnessing wind power can be the economic revival that the US currently needs.
Although I have not done enough research to openly support it, its worth a shot looking into.
http://www.pickensplan.com/theplan/
Was Hubbert sort of right?
Pickens is convinced harnessing wind power can be the economic revival that the US currently needs.
Although I have not done enough research to openly support it, its worth a shot looking into.
http://www.pickensplan.com/theplan/
What is Petroleum Coke? Is it alternative energy?
"Petroleum coke or 'pet coke' is a solid high carbon material that is produced as a by-product of the oil refining process. During the oil refining process, crude oil is distilled down into products such as kerosene, diesel fuel, jet fuel, gasoline, home oil and asphalt. Heavier products like asphalt are similar to the sediments found in wine as they both tend to fall to the bottom. Indeed, the petroleum industry often refers to these heavier by-products as 'heavy fractions' or 'bottoms'."
"In an effort to extract the more valuable, lighter fractions like gasoline, refineries run heavier sediments through a coking unit. The almost pure carbon residual is the solid by-product commonly referred to as petroleum coke. The world’s major oil refineries, including ExxonMobil, ConocoPhillips, Chevron, Shell, Valero, BP, CITGO, and Marathon, all produce varying quantities of petroleum coke."
"Petroleum coke can serve as either an energy source or carbon source. Fuel grade petroleum coke, which serves as an energy source, represents about 71 percent of the total “pet coke” production. This product is burned to produce energy used in making cement, lime, co-generation and other industrial applications. A particularly attractive feature of petroleum coke is that it produces 14,000 BTU/pound as compared to the 8,000 to 13,500 BTU/pound associated with coal and, unlike coal, has very little ash. The cement/lime industries, for instance, utilize large amounts of petroleum coke because they require higher kiln temperatures and the sulfur dioxide from the coke is absorbed into the process."
"Products that utilize petroleum coke as a carbon source include aluminum (calcined coke) and steel (metallurgical coke). "
http://www.oxbow.com/ContentPage.asp?FN=ProductsPetroleumCoke&TS=3&MS=16&oLang=
"In an effort to extract the more valuable, lighter fractions like gasoline, refineries run heavier sediments through a coking unit. The almost pure carbon residual is the solid by-product commonly referred to as petroleum coke. The world’s major oil refineries, including ExxonMobil, ConocoPhillips, Chevron, Shell, Valero, BP, CITGO, and Marathon, all produce varying quantities of petroleum coke."
"Petroleum coke can serve as either an energy source or carbon source. Fuel grade petroleum coke, which serves as an energy source, represents about 71 percent of the total “pet coke” production. This product is burned to produce energy used in making cement, lime, co-generation and other industrial applications. A particularly attractive feature of petroleum coke is that it produces 14,000 BTU/pound as compared to the 8,000 to 13,500 BTU/pound associated with coal and, unlike coal, has very little ash. The cement/lime industries, for instance, utilize large amounts of petroleum coke because they require higher kiln temperatures and the sulfur dioxide from the coke is absorbed into the process."
"Products that utilize petroleum coke as a carbon source include aluminum (calcined coke) and steel (metallurgical coke). "
http://www.oxbow.com/ContentPage.asp?FN=ProductsPetroleumCoke&TS=3&MS=16&oLang=
Offshore Infrastructure Associates Inc.
http://www.offinf.com/
What is OIA?
"(OIA) is a new venture aimed at the development and commercial implementation of renewable energy and resources, principally those related to the marine environment.
OIA's efforts are presently concentrated on the commercial implementation of Ocean Thermal Energy Conversion (OTEC), a technology that is not dependent on fossil fuels, is not vulnerable to world energy market fluctuations and is environmentally benign."
"OTEC uses the heat energy stored in the Earth's oceans to generate electricity. It will work in areas where the temperature difference between the warmer, top layer of the ocean and the colder, deep ocean water is about 20°C (36°F), in an environment that is stable enough for efficient system operation."
OTEC is the acronym for Ocean Thermal Energy Conversion. It is basically supposed to extract electricity from tropical ocean currents, only in oceans/seas with x amount of depth. There's a history to this, the US government had started to invest in this in the 1970s (OPEC crisis), but since oil prices were low enough to beat investing in this technology, the plans were thrown out the window.
Correct me if I'm wrong anybody.
http://www.offinf.com/
What is OIA?
"(OIA) is a new venture aimed at the development and commercial implementation of renewable energy and resources, principally those related to the marine environment.
OIA's efforts are presently concentrated on the commercial implementation of Ocean Thermal Energy Conversion (OTEC), a technology that is not dependent on fossil fuels, is not vulnerable to world energy market fluctuations and is environmentally benign."
"OTEC uses the heat energy stored in the Earth's oceans to generate electricity. It will work in areas where the temperature difference between the warmer, top layer of the ocean and the colder, deep ocean water is about 20°C (36°F), in an environment that is stable enough for efficient system operation."
OTEC is the acronym for Ocean Thermal Energy Conversion. It is basically supposed to extract electricity from tropical ocean currents, only in oceans/seas with x amount of depth. There's a history to this, the US government had started to invest in this in the 1970s (OPEC crisis), but since oil prices were low enough to beat investing in this technology, the plans were thrown out the window.
Correct me if I'm wrong anybody.
Where Has All the Oil Gone? WSJ Article
This is an interesting article, a must for any course that is to explore political economy of oil in the United States. Some topics that it explores is oil speculation, Cushing, contango, and backwardation.
Where Has All The Oil Gone?After Sitting on Crude, Speculators Unload It.The World's Eyes Fall on Cushing, Oklahoma
By ANN DAVIS October 6, 2007
Since summer, one of North America's most important oil towns has witnessed a disappearing act.
The mammoth storage tanks that blanket the rolling grasslands around this remote prairie town had been filled to the brim with crude oil. They aren't anymore. Since May, millions of barrels of crude have been sold off, and Cushing's inventory has fallen by nearly 35%.
Oil traders around the globe obsess about inventory. Storage levels have fallen, not just in Cushing, but in other oil depots as well. Fearful that the U.S. cushion of spare fuel could hit a low by year-end, traders drove prices to a record of nearly $84 a barrel last month. On Friday, oil closed at $81.22 on the New York Mercantile Exchange, up 33% this year.
The reasons Cushing's crude has been disappearing are surprisingly complex, and shed light on the growing involvement of speculators in the global oil market. Tanks are emptying partly because producers have been straining to keep up with demand. But investment banks and other financial firms also played a part by abruptly shifting their oil-trading strategies this summer. Even the credit crunch sparked by the subprime mortgage fiasco had an effect.
Until mid-July, unprecedented conditions in the oil market had given oil companies and speculators alike a financial incentive to sock away oil in storage tanks for sale later. Then, almost overnight, it became more lucrative to sell oil immediately, and in short order, the cushion of stored oil shrank.
The financial players who have piled en masse into commodities trading in recent years have made oil markets more unpredictable. Some are simply betting that oil prices will rise over the long term. Others are pouncing on pricing anomalies as short-term trading opportunities. Many of them move in herds.
"Factors other than supply and demand are now impacting the price," contends oil-and-gas trader Stephen Schork, who publishes the Schork Report on energy markets. "We now have to factor in how the speculators are going to affect the market, because they have different priorities in managing their portfolios."
U.S. storage tanks are being drained at a time when fears of a recession have been looming. That could make the economy more vulnerable to an oil-price spike that would lead to higher prices at the gas pump.
Investing in oil is more complicated than buying stocks or bonds or bars of gold. Most institutional investors don't want to actually own crude. To bet on it, they invest in oil futures -- agreements to buy or sell oil at a set date in the future. They usually unwind the contracts before the oil-delivery date arrives, eventually taking their profits or losses without actually handling the oil. If they leave the contracts in place, oil must be delivered to an officially designated delivery point. Cushing is the main such point in the U.S.
The price of oil for future delivery isn't the same as the price for immediate delivery. When traders figure supplies might run low, oil delivered in the future can become significantly more expensive than oil purchased on the spot market for delivery right away. Until recently, such price differentials gave oil companies and trading firms alike an incentive buy oil and store it in tanks in Cushing and elsewhere.
Although Cushing isn't located on a major highway or railroad, it's one of the world's main oil junctions. It's home to just 8,500 people -- if you count the 1,000 or so prison inmates. Downtown has one stand-alone bar, the Buckhorn. At the movie theater near City Hall, tickets cost $1.50, $2 on weekends.
About a century ago, wildcat drillers discovered oil here. By 1940, most of the wells had run dry, but a maze of pipelines and tanks had sprouted. Cushing's position as a global oil crossroads was cemented in 1983 when the New York Mercantile Exchange, or Nymex, designated it as the official delivery point for its new futures contract for light, sweet crude -- a grade preferred by gasoline refiners. This Nymex price now serves as a global benchmark. Cushing has also become an important way station for heavier Canadian crude.
These days, the steel oil tanks on the outskirts of town stretch to the horizon, covering more than nine square miles. The biggest hold 575,000 barrels. The vista is so vast "it takes two grown men and a small boy just to look at it," quips an executive with Enbridge Energy Partners LP, a tank owner.
Oil producers and traders closely follow inventory numbers from around the world in order to gauge supply and demand, which in turn allows them to make decisions about production and investment. Officially, the U.S. commercial-crude inventory stood at 321.8 million barrels on Sept. 28, but much of it is moving through pipelines or sitting at refineries waiting to be processed, says Barclays Capital analyst Paul Horsnell. While that's a little higher than in some years, it isn't a big surplus. It's only enough to feed refineries for about 21 days.
The traders and producers pay particular attention to oil levels in Cushing, which holds 5% to 10% of the total U.S. crude inventory. Cushing provides clues about what's on hand to feed America's midcontinent refineries and about oil speculation on the Nymex.
In decades past, storage was handled mostly by companies that produced and refined crude, such as the oil majors. But as global oil consumption skyrocketed this decade, transport firms such as pipeline companies bought storage tanks from oil companies and expanded hubs such as Cushing. Even some financial firms involved in oil trading got into the storage business. That gave them the means to set aside oil when the market wasn't ripe to sell it profitably, and to take a cut as middlemen.
Last year, the Vitol Group, a large oil-trading firm based in the Netherlands and Switzerland, paid $170 million to buy an oil-terminal complex in Amsterdam. Wall Street investment bank Morgan Stanley bought TransMontaigne Inc., an oil-products transportation and distribution company; it also bought a European company that manages oil tankers. In Singapore, trading firms are among the port city's largest storage providers.
Nearly three years ago, the oil market became especially attractive for investors with the means to set aside oil in storage tanks. The price of oil delivered in the future rose far above the spot price -- a market condition known as "contango." That made it profitable to store oil rather than to sell it right away.
Part of this price differential was logical -- it costs money to store oil. But the gap was accentuated by several other factors, including concerns about possible shortages linked to growing demand from China and to the potential for unrest in oil-rich nations to interrupt production. That led traders to bet that oil would get scarcer, says John Shapiro, global head of commodities for Morgan Stanley.
Nations belonging to the Organization of Petroleum Exporting Countries, which supply about 40% of the world's oil, had been pumping at nearly maximum capacity to meet higher demand. With so many wells near their limits, oil traders sharply bid up the price of future oil -- namely, oil in storage -- because they "intuitively" feared that an event might crimp that output, says Thomas Kivisto, chief executive officer of SemGroup LP, a storage and pipeline company. "The market was looking for a stable inventory above ground," he says.
In addition, investors had developed a voracious appetite for commodities, but many of them had no desire to take delivery on any oil, so they bought futures. Over the past four years, the number of oil-futures contracts outstanding tripled on the Nymex as hedge funds and other institutional investors jumped in. Many pension funds parked money in oil futures as a diversification strategy, replacing expiring contracts with new ones month after month, according a formula. The regular buying boosted confidence in long-term prices.
The gap between the spot and futures markets widened more than it had in past contango markets. This spring, the price difference between oil to be delivered soon and, say, oil four months out surpassed $6 a barrel, up from less than $2 a couple of years ago, according to OilAnalytics.net.
Storing oil became big business. Tank owners and companies that leased storage, including Wall Street giants such as Morgan Stanley, turned sizeable profits simply by sitting on tanks of oil. They would buy oil for immediate delivery and stick it in their storage tanks, then sell contracts for future delivery at a higher price. When delivery dates neared, they closed out existing contracts and sold new ones for future delivery of the same oil. The oil never budged. The maneuver was known as the oil-storage trade.
It was "effectively a free lunch," says Neil McMahon, energy analyst with research firm Sanford C. Bernstein & Co. Several gasoline refiners, he adds, made "good pocket money" just from trading around extra storage they already leased or owned.
In Cushing, most storage tanks are owned by four entities: oil giant BP PLC, and energy-transport and logistics firms Enbridge Energy Partners (an affiliate of Canada's Enbridge Inc.), Plains All American Pipeline LP, and SemGroup Energy Partners LP.
Bruce MacPhail, who manages Enbridge's U.S. oil-terminal leasing, estimates financial firms now lease 25% to 35% of the company's storage. Enbridge, which bought several Shell tank farms in 2004, has gone from having no presence in Cushing to owning just over one-third of the town's tanks. One of Enbridge's clients is Morgan Stanley, people familiar with the matter say. The investment bank recently helped Enbridge bankroll the construction of new tanks.
The Cushing tank-building boom got so heated that when property abutting the tank farms went on the block last year, terminal operator Teppco Partners LP showed up with an armored truck and edged out Enbridge in a cash auction, says Robert Felts, head of the Cushing Industrial Authority.
Plains All American Pipeline has nearly tripled its storage capacity since 2004. In recent years, it has used nearly 20% of that capacity in order to make storage trades for its own account, using a $1.2 billion line of credit to do so. Last year, the marketing unit that handles trading, among other things, contributed about half of the company's total profits before interest and taxes -- some $228 million.
"It's a little bit like finding a $20 bill in your pocket when you're doing the laundry," says Greg Armstrong, the company's chief executive officer, about the trading opportunity. "You don't throw it in the trash can."
By the end of last year, independent oil-storage firms around the world were 97% full, according to Sanford Bernstein analysts. Two tank owners in Cushing say that by this April they were turning potential customers away. Some traders even leased ocean tankers to use for storage, although that cost twice as much, or more, than land-based storage. Through it all, U.S. consumption was relatively flat. Over the summer, OPEC ministers pointed to high oil inventories in the U.S. as a reason to keep a lid on production.
This summer, however, several factors conspired to squeeze the profit out of oil-storage trades. Global oil demand kept growing, and when supplies lagged, prices for immediate delivery rose. A big Midwestern refinery suddenly began consuming a lot more of Cushing's benchmark crude, which helped lift spot prices.
Buyers began paying more to get oil right away than to take delivery in the future -- a market condition known as backwardation. The contango market had ended. It no longer paid to hold oil off the market, so investors sitting on stored oil began selling. Inventory levels in Cushing and elsewhere began to drop.
Moves by financial firms accelerated the changes. Some hedge funds had entered into agreements to sell oil at a set price in the future, but they didn't have oil sitting in storage to fulfill the contracts. With spot prices outstripping futures prices, they had to move rapidly to close out their contracts at big losses.
Separately, the subprime mortgage mess sparked a credit crunch, which made it more expensive to buy oil with borrowed money. Mr. Armstrong, chief executive of Plains, says some of his smaller customers with low credit ratings saw their borrowing costs go up 8% or more in August and September. Some traders unloaded their stored oil to cover losses on other investments.
"The credit crunch has made it very expensive to hold oil," says independent energy economist Philip Verleger.
Now that market conditions have shifted, economists worry that institutional investors will push up oil prices even more. Conditions are especially profitable now for the pension funds and others who are holding near-term oil futures. More money is pouring into this trading strategy, exerting upward pressure on prices.
It's normal for oil inventories to drift down in the fall because fuel use temporarily slows, but this year's declines have been steeper than usual. In September, after inventory drops at Cushing and rising prices on the Nymex, OPEC decided to boost production modestly. But prices kept rising, and some analysts now forecast $90 or $100 oil.
Some analysts contend that Cushing may give a distorted view of market dynamics. "The market seems to be pricing in a looming shortage," says Tim Evans, an analyst at Citigroup Inc. "But the only place in the U.S. that seems short of crude oil is one very small, but influential location -- Cushing, Oklahoma."
Write to Ann Davis at ann.davis@wsj.com2
Where Has All The Oil Gone?After Sitting on Crude, Speculators Unload It.The World's Eyes Fall on Cushing, Oklahoma
By ANN DAVIS October 6, 2007
Since summer, one of North America's most important oil towns has witnessed a disappearing act.
The mammoth storage tanks that blanket the rolling grasslands around this remote prairie town had been filled to the brim with crude oil. They aren't anymore. Since May, millions of barrels of crude have been sold off, and Cushing's inventory has fallen by nearly 35%.
Oil traders around the globe obsess about inventory. Storage levels have fallen, not just in Cushing, but in other oil depots as well. Fearful that the U.S. cushion of spare fuel could hit a low by year-end, traders drove prices to a record of nearly $84 a barrel last month. On Friday, oil closed at $81.22 on the New York Mercantile Exchange, up 33% this year.
The reasons Cushing's crude has been disappearing are surprisingly complex, and shed light on the growing involvement of speculators in the global oil market. Tanks are emptying partly because producers have been straining to keep up with demand. But investment banks and other financial firms also played a part by abruptly shifting their oil-trading strategies this summer. Even the credit crunch sparked by the subprime mortgage fiasco had an effect.
Until mid-July, unprecedented conditions in the oil market had given oil companies and speculators alike a financial incentive to sock away oil in storage tanks for sale later. Then, almost overnight, it became more lucrative to sell oil immediately, and in short order, the cushion of stored oil shrank.
The financial players who have piled en masse into commodities trading in recent years have made oil markets more unpredictable. Some are simply betting that oil prices will rise over the long term. Others are pouncing on pricing anomalies as short-term trading opportunities. Many of them move in herds.
"Factors other than supply and demand are now impacting the price," contends oil-and-gas trader Stephen Schork, who publishes the Schork Report on energy markets. "We now have to factor in how the speculators are going to affect the market, because they have different priorities in managing their portfolios."
U.S. storage tanks are being drained at a time when fears of a recession have been looming. That could make the economy more vulnerable to an oil-price spike that would lead to higher prices at the gas pump.
Investing in oil is more complicated than buying stocks or bonds or bars of gold. Most institutional investors don't want to actually own crude. To bet on it, they invest in oil futures -- agreements to buy or sell oil at a set date in the future. They usually unwind the contracts before the oil-delivery date arrives, eventually taking their profits or losses without actually handling the oil. If they leave the contracts in place, oil must be delivered to an officially designated delivery point. Cushing is the main such point in the U.S.
The price of oil for future delivery isn't the same as the price for immediate delivery. When traders figure supplies might run low, oil delivered in the future can become significantly more expensive than oil purchased on the spot market for delivery right away. Until recently, such price differentials gave oil companies and trading firms alike an incentive buy oil and store it in tanks in Cushing and elsewhere.
Although Cushing isn't located on a major highway or railroad, it's one of the world's main oil junctions. It's home to just 8,500 people -- if you count the 1,000 or so prison inmates. Downtown has one stand-alone bar, the Buckhorn. At the movie theater near City Hall, tickets cost $1.50, $2 on weekends.
About a century ago, wildcat drillers discovered oil here. By 1940, most of the wells had run dry, but a maze of pipelines and tanks had sprouted. Cushing's position as a global oil crossroads was cemented in 1983 when the New York Mercantile Exchange, or Nymex, designated it as the official delivery point for its new futures contract for light, sweet crude -- a grade preferred by gasoline refiners. This Nymex price now serves as a global benchmark. Cushing has also become an important way station for heavier Canadian crude.
These days, the steel oil tanks on the outskirts of town stretch to the horizon, covering more than nine square miles. The biggest hold 575,000 barrels. The vista is so vast "it takes two grown men and a small boy just to look at it," quips an executive with Enbridge Energy Partners LP, a tank owner.
Oil producers and traders closely follow inventory numbers from around the world in order to gauge supply and demand, which in turn allows them to make decisions about production and investment. Officially, the U.S. commercial-crude inventory stood at 321.8 million barrels on Sept. 28, but much of it is moving through pipelines or sitting at refineries waiting to be processed, says Barclays Capital analyst Paul Horsnell. While that's a little higher than in some years, it isn't a big surplus. It's only enough to feed refineries for about 21 days.
The traders and producers pay particular attention to oil levels in Cushing, which holds 5% to 10% of the total U.S. crude inventory. Cushing provides clues about what's on hand to feed America's midcontinent refineries and about oil speculation on the Nymex.
In decades past, storage was handled mostly by companies that produced and refined crude, such as the oil majors. But as global oil consumption skyrocketed this decade, transport firms such as pipeline companies bought storage tanks from oil companies and expanded hubs such as Cushing. Even some financial firms involved in oil trading got into the storage business. That gave them the means to set aside oil when the market wasn't ripe to sell it profitably, and to take a cut as middlemen.
Last year, the Vitol Group, a large oil-trading firm based in the Netherlands and Switzerland, paid $170 million to buy an oil-terminal complex in Amsterdam. Wall Street investment bank Morgan Stanley bought TransMontaigne Inc., an oil-products transportation and distribution company; it also bought a European company that manages oil tankers. In Singapore, trading firms are among the port city's largest storage providers.
Nearly three years ago, the oil market became especially attractive for investors with the means to set aside oil in storage tanks. The price of oil delivered in the future rose far above the spot price -- a market condition known as "contango." That made it profitable to store oil rather than to sell it right away.
Part of this price differential was logical -- it costs money to store oil. But the gap was accentuated by several other factors, including concerns about possible shortages linked to growing demand from China and to the potential for unrest in oil-rich nations to interrupt production. That led traders to bet that oil would get scarcer, says John Shapiro, global head of commodities for Morgan Stanley.
Nations belonging to the Organization of Petroleum Exporting Countries, which supply about 40% of the world's oil, had been pumping at nearly maximum capacity to meet higher demand. With so many wells near their limits, oil traders sharply bid up the price of future oil -- namely, oil in storage -- because they "intuitively" feared that an event might crimp that output, says Thomas Kivisto, chief executive officer of SemGroup LP, a storage and pipeline company. "The market was looking for a stable inventory above ground," he says.
In addition, investors had developed a voracious appetite for commodities, but many of them had no desire to take delivery on any oil, so they bought futures. Over the past four years, the number of oil-futures contracts outstanding tripled on the Nymex as hedge funds and other institutional investors jumped in. Many pension funds parked money in oil futures as a diversification strategy, replacing expiring contracts with new ones month after month, according a formula. The regular buying boosted confidence in long-term prices.
The gap between the spot and futures markets widened more than it had in past contango markets. This spring, the price difference between oil to be delivered soon and, say, oil four months out surpassed $6 a barrel, up from less than $2 a couple of years ago, according to OilAnalytics.net.
Storing oil became big business. Tank owners and companies that leased storage, including Wall Street giants such as Morgan Stanley, turned sizeable profits simply by sitting on tanks of oil. They would buy oil for immediate delivery and stick it in their storage tanks, then sell contracts for future delivery at a higher price. When delivery dates neared, they closed out existing contracts and sold new ones for future delivery of the same oil. The oil never budged. The maneuver was known as the oil-storage trade.
It was "effectively a free lunch," says Neil McMahon, energy analyst with research firm Sanford C. Bernstein & Co. Several gasoline refiners, he adds, made "good pocket money" just from trading around extra storage they already leased or owned.
In Cushing, most storage tanks are owned by four entities: oil giant BP PLC, and energy-transport and logistics firms Enbridge Energy Partners (an affiliate of Canada's Enbridge Inc.), Plains All American Pipeline LP, and SemGroup Energy Partners LP.
Bruce MacPhail, who manages Enbridge's U.S. oil-terminal leasing, estimates financial firms now lease 25% to 35% of the company's storage. Enbridge, which bought several Shell tank farms in 2004, has gone from having no presence in Cushing to owning just over one-third of the town's tanks. One of Enbridge's clients is Morgan Stanley, people familiar with the matter say. The investment bank recently helped Enbridge bankroll the construction of new tanks.
The Cushing tank-building boom got so heated that when property abutting the tank farms went on the block last year, terminal operator Teppco Partners LP showed up with an armored truck and edged out Enbridge in a cash auction, says Robert Felts, head of the Cushing Industrial Authority.
Plains All American Pipeline has nearly tripled its storage capacity since 2004. In recent years, it has used nearly 20% of that capacity in order to make storage trades for its own account, using a $1.2 billion line of credit to do so. Last year, the marketing unit that handles trading, among other things, contributed about half of the company's total profits before interest and taxes -- some $228 million.
"It's a little bit like finding a $20 bill in your pocket when you're doing the laundry," says Greg Armstrong, the company's chief executive officer, about the trading opportunity. "You don't throw it in the trash can."
By the end of last year, independent oil-storage firms around the world were 97% full, according to Sanford Bernstein analysts. Two tank owners in Cushing say that by this April they were turning potential customers away. Some traders even leased ocean tankers to use for storage, although that cost twice as much, or more, than land-based storage. Through it all, U.S. consumption was relatively flat. Over the summer, OPEC ministers pointed to high oil inventories in the U.S. as a reason to keep a lid on production.
This summer, however, several factors conspired to squeeze the profit out of oil-storage trades. Global oil demand kept growing, and when supplies lagged, prices for immediate delivery rose. A big Midwestern refinery suddenly began consuming a lot more of Cushing's benchmark crude, which helped lift spot prices.
Buyers began paying more to get oil right away than to take delivery in the future -- a market condition known as backwardation. The contango market had ended. It no longer paid to hold oil off the market, so investors sitting on stored oil began selling. Inventory levels in Cushing and elsewhere began to drop.
Moves by financial firms accelerated the changes. Some hedge funds had entered into agreements to sell oil at a set price in the future, but they didn't have oil sitting in storage to fulfill the contracts. With spot prices outstripping futures prices, they had to move rapidly to close out their contracts at big losses.
Separately, the subprime mortgage mess sparked a credit crunch, which made it more expensive to buy oil with borrowed money. Mr. Armstrong, chief executive of Plains, says some of his smaller customers with low credit ratings saw their borrowing costs go up 8% or more in August and September. Some traders unloaded their stored oil to cover losses on other investments.
"The credit crunch has made it very expensive to hold oil," says independent energy economist Philip Verleger.
Now that market conditions have shifted, economists worry that institutional investors will push up oil prices even more. Conditions are especially profitable now for the pension funds and others who are holding near-term oil futures. More money is pouring into this trading strategy, exerting upward pressure on prices.
It's normal for oil inventories to drift down in the fall because fuel use temporarily slows, but this year's declines have been steeper than usual. In September, after inventory drops at Cushing and rising prices on the Nymex, OPEC decided to boost production modestly. But prices kept rising, and some analysts now forecast $90 or $100 oil.
Some analysts contend that Cushing may give a distorted view of market dynamics. "The market seems to be pricing in a looming shortage," says Tim Evans, an analyst at Citigroup Inc. "But the only place in the U.S. that seems short of crude oil is one very small, but influential location -- Cushing, Oklahoma."
Write to Ann Davis at ann.davis@wsj.com2
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