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coolhand looks like this may help save our ###. can not find a date for the article...came in Email.

Breakthrough in solar photovoltaics



THE HOLY Grail of researchers in the field of solar photovoltaic (SPV) electricity is to generate it at a lower cost than that of grid electricity. The goal now seems to be within reach.

A Palo Alto (California ) start-up, named Nanosolar Inc., founded in 2002, claims that it has developed a commercial scale technology that can deliver solar electricity at 5 cents per kilowatt-hour.

Molecular self-assembly


The breakthrough has come through the application of nanotechnology to create components via molecular self-assembly, including quantum dots (10nm large nanoparticles) as well as nanotemplates with structural order extending through all three dimensions.

In addition, Nanosolar has demonstrated that the three dimensionally engineered nanotemplates can be conformally coated or solidly filled with semiconductor paint to create ultra-thin solar cells with layers that are yet another factor 100x thinner than conventional thin-film amorphous silicon solar cells.

This allows a 10x larger surface area of these structures to be used to achieve a 10x increase in efficiency for such thin layers, thus making it possible to use even less material for similarly efficient cells. Conventional inorganic semiconductors tend to require intricate processing to ensure large grains of crystallinity (in the extreme case: mono-crystallinity) so that charges can travel hundreds of nanometres without getting trapped and lost (at internal crystal boundaries).

The 3D nanocomposite architecture of the ultra-thin-absorber cells makes possible absorption of a substantial fraction of the incoming sunlight despite the ultra-thin layers since the charges need to be transported only several nanometres without much opportunity for a loss.

This means the requirements on the semiconductor material can be relaxed and low cost materials such as inorganic semiconductors of the IIb/VIa and Ib/IIIa/VIa families as well as solution-coatable organic semiconductors can be used.

Lower cost


According to the CEO, Martin Roscheisen, the conversion efficiency (percentage of incident light energy converted to electrical energy) of the Nanosolar SPV cell is above 12 per cent for its first product prototypes. He claims that the Nanosolar SPV cell costs only $ 0.36 per peak watt.

The semiconductor paint can be applied to a flexible substrate , such as a polymer sheet , through a simple web printing process, to create an array of ultra-thin solar cells.

Nanosolar has developed proprietary substrate technology that keeps the substrate cost within a smaller fraction of the overall product cost than any other state-of-the-art thin-film solar cell technology. The company has also developed a powerful new way of interconnecting individual solar cells into larger modules and large-area sheets and allows high-throughput module assembly at high yield.

The flagship product, Nanosolar SolarPly, is a 14 feet x 10 feet solar electricity module delivering 120 watts per square inch at 110V. The company is now offering solar panels at below $1 per peak watt.

The Nanosolar team, headed by CEO Martin Roscheisen (listed by Fortune in 2003 among the top ten U.S. entrepreneurs below 40 years of age), has some top-notch Indian technologists assisting it.

Among them are Dr. Siva Sivaram (ex-Intel) and Dr. Arati Prabhakar , former Director of the U.S. National Institute of Standards and Technology.

N.N. Sachitanand
 
 
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Asoil producers outside of OPEC reduce production, OPEC gains more leverage in the industry. But OPEC also understands that if they push too hard they can upset the global market, which hurts them as well, and also provides increased emphasis on alternative energy sources as that noted in this article.

Mightbe a good time to evaluatestock purchase in companies that produce innovative energy alternatives.After doing some homework that is.
 
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Rolo wrote:
I thought hydrogen cells were The Next Alternative Fuel.
Click to expand...
It's being worked. Fact is, as long as oil continues to put upward pressure on prices (and it looks like it is) it's going to spur more and more R& D inalternative energy sources.

Has to happen sometime as oil is a finite energy source. How many more oil fields can there be? Exploration is waning. Greenies aren't helping either.
 
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Rolo wrote:
I thought hydrogen cells were The Next Alternative Fuel.
Click to expand...
Chasing the hydrogen economy
Publication Date:02-February-2005
Source:Times Media Ltd
Chasing the hydrogen economy With fuel as we know it a non-renewable resource running out, General Motors is looking forward into the issue of sustainable mobility and chasing the results of hydrogen powered vehicles, writes PATRICK GEARING NOT since the Hindenberg has there been a major hydrogen disaster. But safety concerns are some of the biggest issues surrounding the future of fuel cell vehicles and their use of hydrogen as an alternative energy source.
General Motors (GM) unveiled the Sequel at the North American International Auto Show in Detroit last month as part of a strong message that the industry needs to move forward quickly with alternative fuels not only for the sake of the environment, but more for the sake of finding an alternative fuel source as world reserves of oil are depleted.

The implications are even further reaching than that. As the biggest player in automotive sales, North America is reliant on some of the world's politically unstable oil producing countries and one cannot help but wonder how important the alternative fuel race is in solving some of those issues compared to the need to sustain the world's mobility.

As Toyota launches SA's first petrol hybrid car, the Prius this week, the world's motor companies are chasing the hydrogen economy in a market that is increasingly aware of not only alternative fuel sources but also emissions.

Hybrid technology is a long way down the road with numerous commercial applications in global markets. There is now a co-operation agreement between GM and DaimlerChrysler to develop hybrid technologies, the constant goal to make the technology more affordable and therefore to penetrate a wider section of the market.

The technology is already commercially viable as proven by models such as the Prius and numerous products in North America, Europe and the Middle East. GM's philosophy on hybrid technology is simple: start with the biggest-consuming vehicles which are also the biggest emissions-producing vehicles.

As a result there are already fleets of Allison Electric Drive transit buses in use in North America that reduce emissions by up to 90% compared to a normal combustion engine. When considering the fuel consumption of a bus, the 60% improvement in fuel economy translates into a lot of litres of fuel and so the biggest effect is on the environment.

GM's strategy can be compared to a global evolution in mobility. The short-term goal is to develop diesel technology where performance and economy can be combined in as clean a way as possible with a combustion engine. The mid-term goal is hybrid technology with the ultimate goal being a hydrogen economy of fuel cell vehicles where the energy is completely renewable and the only emission is water.

It means reinventing the automobile. And a car such as the Sequel is proof that it is possible. The leaps forward in technology and car performance are quite astounding when compared to the evolution of the automobile during the last 100 years. In three years, GM has doubled the range and halved the 0-100km/h time of their fuel cell car, making it a genuine product that could hold its own on the market today. GM's goal is to design and validate a fuel cell propulsion system by 2010 that is competitive with current internal combustion systems on durability and performance, and that ultimately can be built at an affordable price, says Larry Burns, GM's vice president of research and development and planning.

That is merely five years away and the ramifications of that are enormous. No more reliance on oil producing countries, a renewable energy source that can be produced in a multitude of ways in any economy in the world, and huge improvements in efficiency, primarily from a production point of view because there are fewer moving parts. Common platforms, on which any shape of car from a four-door saloon, to a coupe, an MPV and even an SUV can be produced, are now possible. The potential for reaching previously impossible economies of scale is huge.

The exciting thing is that a vehicle like the Sequel has been achieved with technology that is available today and does not depend on science yet to be invented. But the business issues related to the technology require serious consideration. Oil producing countries have a limited economical life, as do oil companies. But there is no reason those affected cannot remain competitive. In future, oil companies could become energy companies, as there is a lot of hydrogen in petroleum products.

If hydrogen is the energy source of the future, there has to be an infrastructure to produce it. And it is that infrastructure that is the biggest stumbling block for its eventual success in the market place. Governments need to start talking seriously to the motor industry and start developing plans for the implementation of an infrastructure that supports the technology existing in fuel cell vehicles.

Safety is another major concern. Hydrogen is a volatile gas and if oil fires and associated disasters are a historical concern, the anxiety over hydrogen should be worse.

Another problem is one less considered. The marvel of hydrogen technology is that the only emission is pure water. Fantastic, but what do you do with all that water that is being exhausted onto the road? In a future economy in which hydrogen cars are the norm, the associated danger of wet roads begins to pose a problem.

We are at a stage in automotive history were we don't really know where the future lies," admits Bob Lutz, Chairman of GM North America. The development of fuel cell vehicles relies on the co-operation of world governments to work together with the automotive industry to develop infrastructure, technology and capacity. The good news is that a long-term vision for sustainable mobility is in place. The question is whether that technology is feasible in the next five years or whether it will take a little longer.

© 1999 - 2005 FuelCellWorks.com All Rights Reserved.
(http://www.fuelcellsworks.com/Supppage1998.html
 
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State-of-the-art plant reclaiming waste heaps

By TOM AVRIL

Philadelphia Inquirer

NEW FLORENCE, Pa. - Pennsylvania is littered with vast, abandoned piles of "boney" - a mixture of coal, rock and clay that chokes the life out of creeks and streams, turning them a sickly shade of yellowish-orange.

This legacy of a century of mining - more than a billion tons, by one estimate - was left behind because it wasn't worth burning to make electricity.

Not anymore.

On the banks of the Conemaugh River here, Houston-based Reliant Energy has built the Seward Power Plant, a high-tech facility specially designed to burn this "waste coal." At 521 megawatts, it is the largest such plant in the world, consuming 11,000 tons of waste coal every day.

"It's the worst of the worst fuel," said Richard Imler, general manager of the plant, which began full operation in October.

Because such plants get rid of an environmental problem, they qualify as a type of "alternative" energy under a new state law requiring that by 2020, 18 percent of electricity sold in the state must come from such sources.

Some environmentalists were aghast that the word "coal" appeared in the same legislation with solar panels, windmills and other sources considered more eco-friendly. That's because waste-coal plants, though they get rid of a source of water pollution, still pollute the air.

Others were willing to compromise, given that coal mining has long been a pillar of the state's very identity. John Hanger, president of the Harrisburg, Pa.-based nonprofit PennFuture, said waste coal is a political reality:

"There wasn't going to be a (bill) passed in Pennsylvania without it."

In Bakerton, Pa., on the west branch of the Susquehanna River, sometimes the water runs yellow. Other times it is blood red. No fish live here.

Miners dumped 1.4 million tons of waste coal along the river's banks prior to 1930. The blackish pile grew so big that it pushed the river out of its natural course.

Successive waves of immigrant miners added to the pile, which sometimes spontaneously catches fire. The Italians worked one mine, the Slovaks another, and so on. They lived in different neighborhoods in nearby Barnesboro, now part of Northern Cambria, forming what engineer Jim Panaro calls a "miniature Philadelphia."

Rain has been washing a steady diet of acidic waste into the river ever since, the result of iron pyrite and sulfur that occur naturally in coal.

Panaro, 39, who grew up in nearby St. Benedict, has been itching to get rid of the pile for most of his life.

Now it's his job.

As general manager of Robindale Energy Services Inc., Panaro supervises the daily shipment of 600 truckloads of waste coal to the Seward plant.

The fuel comes from the Bakerton pile and others like it, including a much larger, 40 million-ton heap in nearby Ebensburg.

Panaro's father helped create that one. He worked for 34 years in the mines, supporting eight children, and died of black-lung disease in 1989. He was 62.

Now Jim Panaro, the youngest of the eight, says he is closing the circle begun by miners like his father:

"He would've been amazed to see what we're able to do with what he thought was junk."

At the Seward plant, waste coal is screened to remove larger debris and then crushed.

Even after screening, it contains many impurities. It would not burn well in a traditional coal-fired power plant, where the fuel is fed continuously into the boilers and has only one chance to burn.

The solution: At Seward, enormous fans suspend the fuel in mid-air, blowing it several times through a sort of cyclical furnace so that every last bit of usable coal is burned.

"You get multiple bites at the apple," said Alan R. Metzer, the plant's technical manager.

This concept was developed in Europe in the 1980s and has been used in the United States on small plants for a few years.

Though its technology is not new, Seward has attracted attention as the world's largest such plant. And because the facility is new, the law requires state-of-the-art controls to reduce air pollution.

So as coal-fired plants go, Seward is clean, causing far less acid rain, smog and fine-particle pollution than most. According to the federal Environmental Protection Agency, waste coal generally contains more mercury, but the plant is outfitted with fabric filters that are thought to remove most of the toxic metal.

Still, the Seward plant is much dirtier than plants that burn natural gas, the primary fossil-fuel alternative. And, as with other coal-burning plants, the company must also dispose of the leftover ash.

Most of the ash will be landfilled. Because it has an alkaline content, some is being used to reclaim the acidic soil left behind when the piles of waste coal are removed.

The ash is taken back to former waste sites, mixed with the soil, and grass is planted on top. The practice has the blessing of the state Department of Environmental Protection, which for years has allowed the use of coal ash to reclaim abandoned mines.

The ash contains some toxic metals, including arsenic, but DEP officials say there is no significant leaching into groundwater.

Nathan Willcox, energy advocate for the nonprofit group PennEnvironment, is skeptical.

"We don't argue (with the fact) that they're removing one environmental problem," he said of waste-coal plants. "It's a matter of asking the tough questions of what are you doing with the ash afterward."

The state requires regular testing of the groundwater at ash-disposal sites, but testing stops once vegetation is planted on top.

Charles Norris, a Denver-based geologist who has consulted for environmental groups and industry, said testing should continue long afterward because as it ages, the ash may be more likely to release its metal components.

Besides Pennsylvania, 17 states and Washington, D.C., have laws requiring the use of a certain percentage of "renewable" energy, according to the Union of Concerned Scientists, a nonprofit advocacy group based in Cambridge, Mass. In New Jersey, 6.5 percent of energy sold in the state must be renewable by 2008.

Pennsylvania is the only one that includes waste coal in its mix. But then, Pennsylvania is the only one of the 18 states with a waste-coal problem.

State officials welcome the use of the new fuel. In a recent newspaper column, DEP secretary Kathleen McGinty labeled critics of waste coal as "anti-coal zealots."

In most cases, the companies responsible for creating the piles are long gone. Reliant Energy officials say that over the next 30 years, their Seward plant will get rid of 100 million tons - at no cost to taxpayers.

The 1.4 million-ton pile in Bakerton will be gone in four years, said Panaro, whose employer was hired by the Seward plant to deliver the fuel.

But even that won't repair all the damage wrought by a century of mining. Larger rivers in Pennsylvania have a natural pH of at least 7. Below the Bakerton pile, the pH of the Susquehanna's west branch is 2.5 - extremely acidic. Above the pile, the river is still too acidic, with a pH of 5.5, to support most life forms.

That's the fault of drainage from nearby mines, many of them abandoned and lacking a solvent mining company to pay for cleanup.

Yet Panaro, an avid sportsman, says every bit helps.

The Susquehanna shows signs of life about 10 miles south of Bakerton, near the town of Cherry Tree, where the acidity is diluted enough that hardy creatures such as catfish start to make an appearance. Smallmouth bass don't show up for a few more miles.

When the Bakerton pile is gone, he hopes, the fish will come further north.

"Every time we clean one of these piles," Panaro said, "it moves that line further upstream."

WASTE COAL ON ECO-FRIENDLY LIST

A new Pennsylvania law requires that by 2020, 18 percent of the electricity sold in the state come from renewable or environmentally beneficial sources. Eight percent must come from "tier one" sources - those that are traditionally thought of as renewable - and 10 percent from "tier two." For example:

TIER ONE:

Solar photovoltaic energy

Wind power

Low-impact hydropower

Geothermal energy

Biologically derived methane gas

Fuel cells

Coal-bed methane

TIER TWO:

Waste coal

Energy efficiency measures

Large-scale hydropower

Trash incinerators

Byproducts of pulping and wood manufacturing processes

Coal gasification

Source: Pennsylvania Senate Bill 1030.
(http://www.thestate.com/mld/thestate/news/nation/10854614.htm
 
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THE HYDROGEN ECONOMY – ENERGY AND ECONOMIC BLACK HOLE
By Alice Friedemann –

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The energy literate scoff at perpetual motion, free energy, and cold fusion, but what about the hydrogen economy? Before we invest trillions of dollars, let’s take a hydrogen car out for a spin.
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Making it
Hydrogen isn’t an energy source — it’s an energy carrier, like a battery. You have to make it and put energy into it, both of which take energy. Ninety-six percent of hydrogen is made from fossil fuels, mainly for use in oil refining and hydrogenating (partially or full) vegetable oil — the kind that gives you heart attacks [1]. In the United States, ninety percent of hydrogen is made from natural gas, with an efficiency of 72% [2], which means you’ve just lost 28% of the energy contained in the natural gas to make hydrogen (and that doesn’t count the energy it took to extract and deliver the natural gas to the hydrogen plant).

Only four percent of hydrogen is made from water via electrolysis. It’s done when the hydrogen must be extremely pure. Since most electricity comes from fossil fuels in plants that are 30% efficient, and electrolysis is 70% efficient, you end up using four units of energy to create one unit of hydrogen energy: 70% * 30% = 20% efficiency [3].

Getting hydrogen using fossil fuels as a feedstock or an energy source is a bit perverse, since the whole point is to avoid using fossil fuels. The goal is to use renewable energy to make hydrogen from water via electrolysis. When the wind is blowing, current wind turbines can perform at 30-40% efficiency, producing hydrogen at an overall 25% efficiency, or 3 units of wind energy to get 1 unit of hydrogen energy. The best solar cells available on a large scale have an efficiency of ten percent, or 9 units of energy to get 1 hydrogen unit of energy. If you use algae making hydrogen as a byproduct, the efficiency is about .1%, or more than 99 units of energy to get 1 hydrogen unit of energy [4].

No matter how you look at it, producing hydrogen from water is an energy sink. If you don’t understand this concept, please mail me ten dollars and I’ll send you back a dollar.

Hydrogen can be made from biomass, but then these problems arise: 1) biomass is very seasonal, 2) contains a lot of moisture, requiring energy to store and dry it before gasification, 3) there are limited supplies, 4) the quantities are not large or consistent enough for large-scale hydrogen production, 5) a huge amount of land would be required, because even cultivated biomass in good soil has a low yield — 10 tons of biomass per 2.4 acres, 6) the soil will be degraded from erosion and loss of fertility if stripped of biomass, 7) any energy put into the land to grow the biomass, such as fertilizer and planting/harvesting will add to the energy costs, 8) delivery costs to the central power plant, and 9) it’s not suitable for pure hydrogen production [5].

One of the main reasons for switching to hydrogen is to prevent global warming caused by fossil fuels. When hydrogen is made from natural gas, nitrogen oxides are released, which are 58 times more effective in trapping heat than carbon dioxide [6]. Coal releases large amounts of CO2 and mercury. Oil is too powerful and useful to waste on hydrogen — it’s concentrated sunshine brewed over hundreds of millions of years. A gallon of gas represents about 196,000 pounds of fossil plants, the amount in 40 acres of wheat [7].

Natural gas is too valuable to make hydrogen with. One use of natural gas is to create fertilizer (as both feedstock and energy source). This has led to a many-fold increase in crop production, allowing an additional 4 billion people to exist who otherwise wouldn’t be here [8, 9].

We also don’t have enough natural gas left to make a hydrogen economy happen. Extraction of natural gas is declining in North America [10]. It will take at least a decade to even begin replacing natural gas with imported LNG (liquified natural gas). Making LNG is so energy intensive that it would be economically and environmentally insane to use natural gas as a source of hydrogen [3].



Putting energy into hydrogen
No matter how it’s been made, hydrogen has no energy in it. Hydrogen is the lowest energy dense fuel on earth [5]. At room temperature and pressure, hydrogen takes up three thousand more times space than gasoline containing an equivalent amount of energy [3]. To put energy into hydrogen, it must be compressed or liquefied. To compress hydrogen to 10,000 psi is a multi-stage process that will lose an additional 15% of the energy contained in the hydrogen.

If you liquefy hydrogen, you will be able to get more hydrogen energy into a smaller container, but you will lose 30-40% of the energy in the process. Handling hydrogen requires extreme precautions because hydrogen is so cold — minus 423 F. Fueling is typically done mechanically with a robot arm [3].



Storage
On a vehicle you’d need to have a heavy cryogenic support system if you use liquid hydrogen. The tank is cold enough to cause plugged valves and other problems. If you add insulation to prevent this, you will increase the weight of an already very heavy storage tank [11].

Let’s assume that a hydrogen car can go 55 miles per kg [5]. A tank that can hold 3 kg of compressed gas, will go 165 miles and weigh 400 kg/882 lbs [12]. Compare that with a Honda Accord fuel tank that weighs 11 kg/25 lbs, costs $100, and holds 17 gallons of gasoline. The overall weight is 73 kg/161 lbs (8 lbs per gallon). The driving range is 493 miles at 29 mpg.

According to the National Highway Safety Traffic Administration (NHTSA), “Vehicle weight reduction is probably the most powerful technique for improving fuel economy. Each 10 percent reduction in weight improves the fuel economy of a new vehicle design by approximately eight percent”.

The more you compress hydrogen, the smaller the tank can be. But as you increase the pressure, you also have to increase the thickness of the steel wall, and hence the weight of the tank. Cost increases with pressure. At 2000 psi, it’s $400 per kg. At 8000 psi, it’s $2100 per kg [5]. And the tank will be huge — at 5000 psi, the tank could take up ten times the volume of a gasoline tank containing the same energy content.

Fuel cells are also heavy: “A metal hydride storage system that can hold 5 kg of hydrogen, including the alloy, container, and heat exchangers, would weigh approximately 300 kg (661 lbs), which would lower the fuel efficiency of the vehicle,” according to Rosa Young, a physicist and vice president of advanced materials development at Energy Conversion Devices in Troy, Michigan [12].

Fuel cells are expensive. In 2003, they cost $1 million or more. At this stage, they have low reliability, need a much less expensive catalyst than platinum, can clog and lose power if there are impurities in the hydrogen, don’t last more than 1000 hours, have yet to achieve a driving range of more than 100 miles, and can’t compete with electric hybrids like the Toyota Prius, which is already more energy efficient and lower in CO2 generation than projected fuel cells [3].

Hydrogen is the Houdini of elements. As soon as you’ve gotten it into a container, it wants to get out, and since it’s the lightest of all gases, it takes a lot of effort to keep it from escaping. Storage devices need a complex set of seals, gaskets, and valves. Liquid hydrogen tanks for vehicles boil off at 3-4% per day [3, 13].

Hydrogen also tends to make metal brittle [14]. Embrittled metal can create leaks. In a pipeline, it can cause cracking or fissuring, which can result in potentially catastrophic failure [3]. Making metal strong enough to withstand hydrogen adds weight and cost.

Leaks also become more likely as the pressure grows higher. It can leak from un-welded connections, fuel lines, and non-metal seals such as gaskets, O-rings, pipe thread compounds, and packings. A heavy-duty fuel cell engine may have thousands of seals [15]. Hydrogen has the lowest ignition point of any fuel, 20 times less than gasoline. So if there’s a leak, it can be ignited by a cell phone, a storm miles away [16], or the static from sliding on a car seat.

Leaks and the fires that might result are invisible, and because of they high hydrogen pressure, the fire is like a cutting torch with an invisible flame. Unless you walk into a hydrogen flame, sometimes the only way to know there’s a leak is poor performance.



Transport
Canister trucks ($250,000 each) can carry enough fuel for 60 cars [3, 13]. These trucks weight 40,000 kg but deliver only 400 kg of hydrogen. For a delivery distance of 150 miles, the delivery energy used is nearly 20% of the usable energy in the hydrogen delivered. At 300 miles 40%. The same size truck carrying gasoline delivers 10,000 gallons of fuel, enough to fill about 800 cars [3].

Another alternative is pipelines. The average cost of a natural gas pipeline is one million dollars per mile, and we have 200,000 miles of natural gas pipeline, which we can’t re-use because they are composed of metal that would become brittle and leak, as well as the incorrect diameter to maximize hydrogen throughput. If we were to build a similar infrastructure to deliver hydrogen it would cost $200 trillion. The major operating cost of hydrogen pipelines is compressor power and maintenance [3]. Compressors in the pipeline keep the gas moving, using hydrogen energy to push the gas forward. After 620 miles, 8% of the hydrogen has been used to move it through the pipeline [17].

At some point along the chain of making, putting energy in, storing, and delivering the hydrogen, you’ve used more energy than you get back, and this doesn’t count the energy used to make fuel cells, storage tanks, delivery systems, and vehicles [17].

The price of oil and natural gas will go up relentlessly due to geological depletion and political crises in extracting countries. Since the hydrogen infrastructure will be built using the existing oil-based infrastructure (i.e. internal combustion engine vehicles, power plants and factories, plastics, etc), the price of hydrogen will go up as well — it will never be cheaper than fossil fuels. As depletion continues, factories will be driven out of business by high fuel costs [20, 21, 22] and the parts necessary to build the extremely complex storage tanks and fuel cells might become unavailable. In a society that’s looking more and more like Terry Gilliam’s “Brazil”, hydrogen will be too leaky and explosive to handle.

The laws of physics mean the hydrogen economy will always be an energy sink. Hydrogen’s properties require you to spend more energy to do the following than you get out of it later: overcome waters’ hydrogen-oxygen bond, to move heavy cars, to prevent leaks and brittle metals, to transport hydrogen to the destination. It doesn’t matter if all of the problems are solved, or how much money is spent. You will use more energy to create, store, and transport hydrogen than you will ever get out of it.

Any diversion of declining fossil fuels to a hydrogen economy subtracts that energy from other possible uses, such as planting, harvesting, delivering, and cooking food, heating homes, and other essential activities. According to Joseph Romm “The energy and environmental problems facing the nation and the world, especially global warming, are far too serious to risk making major policy mistakes that misallocate scarce resources” [3].

When fusion can make cheap hydrogen, reliable long-lasting nanotube fuel cells exist, and light-weight leak-proof carbon-fiber polymer-lined storage tanks/pipelines can be made inexpensively, then let’s consider building the hydrogen economy infrastructure. Until then, it’s vaporware. All of the technical obstacles must be overcome for any of this to happen [18]. Meanwhile, we should stop the FreedomCAR and start setting higher CAFE standards [19].



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[1] Michael F. Jacobson Waiter, please hold the hydrogen http://sfgate.com/cgi-bin/article.cgi?f=/c/a/2004/09/08/EDGRQ8KVR31.DTL
[2] Martin I.Hoffert, et al “Advanced Technology Paths to Global Climate Stability:Energy for a Greenhouse Planet” SCIENCE VOL 298 1 November 2002
[3] Joseph J. Romm The Hype About Hydrogen: Fact & Fiction in the Race to Save the Climate
[4] Howard Hayden The Solar Fraud: Why Solar Energy Won’t Run the world
[5] D.Simbeck and E.Chang Hydrogen Supply: Cost Estimate for Hydrogen Pathways Scoping Analysis http://www.nrel.gov/docs/fy03osti/32525.pdf
[6] Union of Concerned Scientists http://www.ucsusa.org/clean_energy/renewable_energy/page.cfm?pageID=84
[7] What’s in a Gallon of Gas? http://www.discover.com/issues/apr-04/rd/discover-data/
[8] David & Marshall Fisher The Nitrogen Bomb from April 2001 Vol. 22 No. 4
[9] Vaclav Smil Scientific American Jul 1997 Global Population & the Nitrogen Cycle
[10] Julian Darley High Noon for Natural Gas: The New Energy Crisis 2004
[11] Rocks in your Gas Tank http://science.nasa.gov/headlines/y2003/17apr_zeolite.htm
[12] filler up-with hydrogen Mechanical Engineering Magazine http://www.memagazine.org/backissues/feb02/features/fillerup/fillerup.html
[13] Wade A. Amos Costs of Storing and Transporting Hydrogen National Renewable Energy Laboratory
[14] Omar A. El kebir, Andrzej Szummer Comparison of hydrogen embrittlement of stainless steels and nickel-base alloys International Journal of Hydrogen Energy Volume: 27, Issue: 7-8 July - August, 2002
[15] Fuel Cell Engine Safety http://www.avt.nrel.gov/pdfs/fcm06r0.pdf
[16] Dr. Joseph Romm Testimony For the Hearing Reviewing the Hydrogen Fuel and FreedomCAR Initiatives Submitted to the House Science Committee
[17] Ulf Bossel and Baldur Eliasson Energy and the Hydrogen Economy
[18] National Hydrogen Energy Roadmap Production, Delivery, Storage, Conversion, Applications, Public education and outreach http://www.eere.energy.gov/hydrogenandfuelcells/pdfs/national_h2_roadmap.pdf
[19] Dan Neil Rumble Seat: Toyota’s spark of genius http://www.latimes.com/la-danneil-101503-pulitzer,0,7911314.story
[20] Jul 02, 2004 Oil prices raising costs of offshoots By Associated Press http://www.tdn.com/articles/2004/07/02/biz/news03.prt
[21] May 24, 2004 Soaring energy prices dog rosy U.S. farm economy http://www.forbes.com/business/newswire/2004/05/24/rtr1382512.html
[22] March 17, 2004 Chemical Industry in Crisis: Natural Gas Prices Are Up, Factories Are Closing, And Jobs Are Vanishing http://www.washingtonpost.com/wp-dyn/articles/A64579-2004Mar16.html
 
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Forget U.S. energy independence - oil executives
Fri Feb 18, 2005 03:38 PM ET
By Deepa Babington

HOUSTON, Feb 18 (Reuters) - Holding on to hopes of an America that will one day be free from reliance on oil from the Middle East and self-sufficient in its energy needs?

Well, stop dreaming and wake up to reality, say top oil executives, who dismiss the idea of U.S. energy independence as mere political fluff.

Instead, the goal of energy independence -- among the more popular mantras thrown around during the run-up to the U.S. presidential election last year -- needs to be ditched in favor of embracing global energy interdependence, they say.

"Virtually every candidate called for American energy independence -- which is something that may sound good in a campaign, but has no grounding in reality," Dave O'Reilly, chief executive of No. 2 U.S. oil company ChevronTexaco Corp. (CVX.N: Quote, Profile, Research) , told an energy gathering earlier this week. "With the political season behind us, we can move from rhetoric to reality. We must create an energy policy that is pragmatic and holistic, and which reflects the reality of the interdependent world in which we live."

Pushing for energy independence was a key part of Democrat challenger Senator John Kerry's campaign, while President George W. Bush has said he wants to pursue energy sources that are closer to home so the country is less dependent on supplies from unstable parts of the world.

Indeed, U.S. Energy Secretary Sam Bodman has said his energy policy will focus on working toward the day when America achieves energy independence.

But oil companies, which are pushing for U.S. policies that improve access to crude supplies around the world, aren't impressed with the idea.

"There is a perception of some here in the United States that this country can achieve energy independence," Edward Galante, the head of Exxon Mobil Corp.'s (XOM.N: Quote, Profile, Research) global refining and marketing operations, said at the same gathering. "In our view, that goal is unrealistic. But more importantly, holding that view can be counterproductive.

"It can distract us from focusing on the reality -- the need to deal with U.S. interdependence in the global energy market -- an interdependence that we believe will persist in the future."

Even Abdallah Jumah, the head of Saudi Arabia's state-run oil company Saudi Aramco, threw in his support for energy interdependence at the Cambridge Energy Research Associates conference which ended on Thursday, noting that a large part of the world's proven reserves reside in the Middle East.

"It is more instructive to talk about mutual dependence, and to recognize that degree of interdependence, in all areas of trade and for all nations, will only increase in the future," Jumah said.

The remarks come as U.S. House of Representatives and Senate Republican leaders plot their strategy on how to revive a delayed energy bill this year, though it is unclear when versions of the bill will reach full-body votes.

Oil companies like ChevronTexaco add that protecting U.S. energy needs means recognizing issues not just in energy policy but also in foreign and trade policies.

For example, O'Reilly said improving security and the investment climate in West Africa, which supplies light sweet crude oil that is in high demand, should be a priority in U.S. foreign policy.


Shell, Exxon Tap Oil Sands, Gas as Reserves Dwindle (Update1)

http://www.bloomberg.com/apps/news?pid=10000087&sid=a3Iz1vRFvXuI&refer=top_world_news#

Feb. 18 (Bloomberg) -- Shell Canada Ltd. Chief Executive Officer Clive Mather says oil from his Athabasca project, where tar sands are boiled to produce crude, can cost twice as much as drilling in the North Sea. And it's worth every cent, he says.

``If we had access to unlimited conventional oil, I guess the interest in Athabasca would diminish quite quickly, but that isn't the case,'' Mather said in a Feb. 3 interview in London. ``This is high-cost oil, there's no question about that. At current prices, it's still very good business.''

A 15-year decline in oil reserves is spurring companies such as Royal Dutch/Shell Group, Exxon Mobil Corp. and ChevronTexaco Corp. to spend $76 billion in the next decade to boost supplies of oil from tar sands and diesel fuel from Qatari natural gas. Oil executives say they have no choice but to try alternatives to drilling because there is not much more crude to be found in their current fields.

``We're damn close'' to the peak in conventional oil production, Boone Pickens, who oversees more than $1 billion in energy-related investments at his Dallas hedge fund firm, said in an interview in New York Feb. 16. ``I think we're there.'' Suncor Energy Inc., the world's second-biggest oil-sands miner, is his largest holding.

New Production

Companies will produce 10.1 million barrels of oil a day by 2030 from projects in Canada and Qatar, more than Saudi Arabia does today, according to forecasts by the International Energy Agency in Paris. That's 8 percent of the world's total.

Shell is spending $13.70 per barrel at its Athabasca project in Canada, higher than drilling projects, said Mather. Oil executives say that crude prices near $45 a barrel more than offset the extra cost. Crude for March delivery today was little changed, trading at $47.68 a barrel on the New York Mercantile Exchange at 9:30 a.m. London time.

The oil industry needs to spend $3 trillion by 2030, or $105 billion a year, to meet an expected surge in demand, the IEA estimates.

``Pressure on supply will become sufficient for more money to be put into non-conventional oil,'' said Peter Odell, an oil politics and economics professor emeritus at the Erasmus University in Rotterdam. ``This is a natural development of a resource base from the lowest cost to the highest cost.''

Exxon Mobil, BP Plc, Shell, ChevronTexaco and Total SA, the five largest publicly traded oil companies, last year reported net income of about $85 billion, equal to the economic output of Venezuela, a nation of 25 million people and the third-largest member of the Organization of Petroleum Exporting Countries.

Falling Reserves, Returns

Oil-sand mining projects offer a rate of return of 13.6 percent, less than half the 33.4 percent at a deepwater Gulf of Mexico field such as BP's Mad Dog project, said Scott Mitchell, an analyst at energy consultant Wood Mackenzie in Edinburgh. West Africa's deep waters offer an 18.2 percent return, he said. The estimates are based on an average price of $21 per barrel.

Shell and BP, Europe's two largest oil companies, this month reported oil and gas reserves declined in 2004, based on U.S. rules. It was the first drop in more than six years for London- based BP, whose only investment in non-conventional oil sources is in Venezuelan heavy crude. BP acquired the stake when it bought the Veba Oel German oil-refining business from E.ON AG.

Shell Reserve Slump

Shell, based in London and The Hague, reported Feb. 3 that reserves fell in 2004 because it found enough oil to replace just 15 percent to 25 percent of what the company pumped. BP replaced 89 percent of production, the company said Feb. 8.

BP forecasts it can expand oil and gas output by 5 percent a year using existing deposits and doesn't need to turn to non- conventional projects. BP's growth comes from Russia, where it spent $7.7 billion on the TNK-BP joint venture.

``To renew our exploration business, we only need to rely on the exploration for and development of primarily conventional oil and gas resources,'' Chief Executive John Browne said on a Feb. 8 conference call.

Oil futures show crude prices will stay close to $40 a barrel until 2011 because of rising demand, spurring investment in projects once considered to be marginal. Futures contracts are a promise to deliver a commodity at a specified price at an agreed- upon date in the future.

Supply Pressure

Canada's tar sands may get $48 billion of investment by 2012, according to Canada's National Energy Board, double the amount spent in the decade ending in 2003. As part of that, Imperial Oil Ltd., controlled by Exxon, said in November it may pay $6.5 billion to double its capacity to produce oil from tar sands.

For investors, oil sands have been a better bet than the best- known oil companies. Canadian Oil Sands Trust, which invests only in the Albertan mining projects, is up 67 percent in the past year. BP shares during that time are up 34 percent in London and Exxon Mobil, based in Irving, Texas, gained 39 percent in New York.

Current spending plans show Canada's oil sands may produce 2 million barrels a day by 2015, more than Iraq today, crude worth $29.2 billion of revenue a year at oil prices of $40 a barrel.

Qatar may receive more than $28 billion of investment, to cause a 22-fold surge in the amount of fuels produced from natural gas, based on IEA estimates. Only two gas-to-liquids projects exist now, in Malaysia and South Africa, representing 35,000 barrels of daily production. The Qatari ventures are for a total of almost 800,000 barrels a day in 2011, according to the IEA. The fuels may be worth $15.5 billion a year in revenue, based on today's diesel prices.

Oil's Limits

Shell will spend as much as $6 billion in Qatar to produce diesel fuel in 2009, according to project director Andrew Brown. Projects announced by Exxon, ConocoPhillips, Marathon Oil Corp., ChevronTexaco and Sasol Ltd. will cost another $22.3 billion.

The potential for non-conventional oils may exceed the IEA forecasts. Should oil reserves be lower than expected, non- conventional oil production may be 37 million barrels a day in 2030, or 39 percent of global demand, the IEA said in an alternative to its most likely scenario in the 2004 World Energy Outlook, released in October.

Ignoring oil sands and the potential to make fuels from natural gas ``is a mistake,'' said Ian Henderson, who manages $680 million at the JP Morgan Fleming Natural Resources Fund in London. ``It's taken millions and millions of years for hydrocarbons to form, and we are running out of them.''

Henderson owns shares of Canadian Natural Resources Ltd. and Petro-Canada, a partner in Syncrude Canada Ltd., the world's largest oil-sands mining business. Both companies are based in Calgary. His investment fund is up 30 percent in the past year, compared with a 20 percent gain in the FTSE 350 Mining Index.

Making Canada's oil sands viable would ease demand for crude from Saudi Arabia and other suppliers, Odell said. Alberta's oil sands deposits contain 174.5 billion barrels of reserves, according to the Alberta Energy and Utilities Board. That total is two-thirds of Saudi Arabia's proven reserves of 262 billion barrels.

Sticky Mixture

Alberta's oil sands cover an area larger than the state of Florida, and about two tons have to be dug up, heated and processed to make a single 42-gallon barrel of oil. Suncor Energy spends C$12 ($9.62) to C$12.50 to mine and upgrade a barrel of oil. Saudi Arabia pumps a barrel of oil for about $2.

Devon Energy Corp. President John Richels, a Canadian and a lawyer by training, remembers the first time he held a handful of the oil-encrusted sand, in the early 1990s. He said he had a hard time believing the sticky mixture could be turned into smooth- flowing crude. Devon, based in Oklahoma City, is now investing C$527 million in the Jackfish oil sands project in Alberta.

``They're not particularly high-return projects,'' he said in an interview. ``We see the same kinds of returns, though, in other parts of the world.'' And given the lack of exploration and political risk, the projects pay off, he said.

`Operating Risks'

Failures are costly. A blaze at Suncor Energy in Alberta slashed output by about half, and full production won't resume for months. The lost output is worth $4.4 million a day at $40 a barrel. The company expects insurance to cover most of its losses.

``There are operating risks,'' Suncor Chief Financial Officer Ken Alley said in an interview. ``It's not unlike the refining industry where you operate with hydrocarbons, at high pressure and high temperature, and that is a risk that you design facilities to protect against. Nevertheless there is a level of residual risk.''

Oil sands projects of Shell and Suncor failed to meet their budgets and deadlines, the companies said, the result of competition for equipment and labor.

`Cost Overruns'

Syncrude Canada's project to boost capacity by 100,000 barrels a day to about 350,000 is expected to cost $6 billion by mid-2006, almost double a 2001 forecast of $3.14 billion, according to Canadian Oil Sands Trust, lead partner in the venture. Developments by Shell Canada, 78 percent-owned by Shell, and Suncor cost as much as 70 percent more than planned, the companies reported.

``The problem is the consistent, continual and predictable cost overruns,'' Pickens said. ``That can't keep happening, I don't think, but still those overruns are a concern.''

Exploiting Venezuela's heavy oil may double the reserves of non-conventional sources. Paris-based Total SA, Europe's third- largest oil company, and Statoil ASA, the biggest in Norway, are among those exploiting Venezuela's heavy oil deposits, reserves that may equal another 100 billion barrels to 270 billion, according to the U.S. Energy Department. The country already is processing 500,000 barrels a day of heavy crude.

In Qatar, the plants use a basic technology invented in the 1920s and exploited by the Nazis during World War II to make oil products from coal when embargoes cut off crude oil imports. The technology was also used in South Africa during Apartheid.

Wasted Gas

The gas-to-liquids process is wasteful, with about 45 percent of the natural gas lost in conversion, the IEA estimated.

The process consumes 10,000 cubic feet of gas to make one barrel of fuel, according to Malcolm Wells, a spokesman for Sasol Chevron Ltd., a joint venture between San Ramon, California-based ChevronTexaco and South Africa's Sasol, which is spending at least $6 billion on building plants in Qatar.

At that rate, the amount of gas used for seven barrels of diesel is equal to what is burned in the average American household in an entire year.

Project costs are escalating because of higher steel prices and increasing demand for equipment. Shell's gas-to-liquids plant will cost as much as $6 billion, 20 percent more than initially forecast, the company said.

BP just closed its gas-to-liquids pilot plant in the U.S. and is planning instead to sell natural gas to use in power plants, said Robert Wine, a BP spokesman in London.

`Isn't Cheap'

Gas-to-liquids ``isn't a cheap industry to get into,'' said Wells at Sasol Chevron. ``It requires massive investment into infrastructure and huge sources of gas.''

Qatar has the world's third-largest natural gas reserves, after Russia and Iran. Another 12 plants to make fuels from natural gas are in various stages of planning, in Nigeria, Iran, Egypt, Australia, Venezuela, Brazil and elsewhere, according to Paris-based Technip SA, Europe's largest oil-services company.

A lack of information about proven oil reserves complicates assessing when supply from the world's conventional oil fields will peak, the IEA said in its world energy outlook. The agency estimated it will occur sometime between 2013 and 2037.

``Oil won't last forever,'' said Manouchehr Takin, a senior analyst at the Centre for Global Energy Studies in London, a consulting company founded by former Saudi oil minister Sheikh Zaki Yamani.
 
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I did not quite understand this but I read they are going to add more of the lower grade crudes to the basket to lower the overall price. However, this will cause the higher grade crudes to cost more but the average price will go down. It also said that the base line price for Lightsweet will be $50 now. That may be why the $6.00 jump this week?

Not sure, just trying to learn. If the attacks keep up will quickly go somewhere else. At least this topic is of interest.

At what price will higher lightsweet hurt stocks?
 
imported post

Dr_Dubious wrote:
I did not quite understand this but I read they are going to add more of the lower grade crudes to the basket to lower the overall price. However, this will cause the higher grade crudes to cost more but the average price will go down. It also said that the base line price for Lightsweet will be $50 now. That may be why the $6.00 jump this week?
Click to expand...
I agree with you. I don't understand that logic either. I think oil jumped due to the weather up north, the weaker dollar and an apparent change in pricing strategy by the Saudis.
Click to expand...
At what price will higher lightsweet hurt stocks?
Click to expand...
I don't think it is so much how high the price of lightsweet goes up as how long the market can sustain growth at higher prices. Something else to consider is the dollar and its relationship to oil. If the dollar continues to weaken, oil will only get more expensive for us. Add to that the fact that global consumption is rising and production is falling. We all know the dynamics of supply and demand. I suspect the Saudi's are abandoning their moderate pricing strategy based on the global market and not the US market as mentioned in the article. And it actually makes sense. Still, we'll have to see how it plays out in the longer term.
Click to expand...
 
imported post

The article said if you add the poor quality crude as a higher percentage it will drop the basket price down. However since we can not use the poor crude because it costs to much to make useable the good stuff (high grade) will go up but the basket price will go down. I understand that know. It makes sense. Buy brentsweet crude contracts. Check!

The article also said that the Saudis are all most tapped out and they know they have to get all they can for what they have left. The article said that you need vegatation breaking down to replinish the removed supply. Since they are all sand the tap is running dry. The article pointed out there are no dinasours running around so it has to be vegetation.

I know in the oceans off the Philippines there have been near wars between China, Taiwan, The Phillipines, Indonesia and Singapore for moving rigs around to get at the oil off shore. Interesting post. I made me think, TY. G.
 
imported post

Yes, it looks like the tap is running dry. What will they do without oil? They have nothing else. Maybe that is why we are in Iraq? There is not that many gas pumps left. Thinking about it they were the lowest fruit to pick.

What a interesting time in history to be alive?
 
imported post

The Athabasca oil sands story
Monday, April 4, 2005
Updated at 12:19 PM EDT

For centuries; the sticky bitumen of northern Alberta was good for little more than caulking Chipewyan Indian canoes - and leading entrepreneurs astray.

The first attempt to exploit the oil sands came nearly a century ago, when oilmen tried drilling conventional wells in the area, convinced that the bitumen on the surface must be welling up from gigantic pools of crude deep in the Earth. Two dozen wells were drilled over 11 years, with zero success

Small-scale operations producing asphalt popped up in the ensuing decades, but cheper sources of the product elsewhere in the world eventually bankrupted every one of those efforts.

It was not until 1967 that the oil industry began to make a business out of bitumen, when the Great Canadian Oil Sands Project, which eventually became Suncor Energy Inc., began production.

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Swings in oil prices, particularly the collapse of the mid-1980s, left the sector's viability in continual question. In part because of shrinking opportunities for conventional exploration, interest in the oil sands grew, with tens of billions of dollar sinvested in the 1990s.

Despite a record of multibillion-dollar cost overruns, that investment has pushed production of bitumen and synthetic crude past one million barrels a day - with capital spending predicted to double that to two million barrels a day over the next five years, and perhaps to three million by the middle of the next decade.

Even with that soaring growth, there are decades, and likely centuries, of production in the oil sands. The best official estimate of oil that can be profitably extracted is 175 billion barrels - second only to the reserves of Saudi Arabia.

Oil sands projects

Shell Canada Ltd.,

Western Oil Sands Inc.,

Chevron Texaco Corp.

Athabasca Oil Sands Project - mining

Capacity: 155,000 barrels a day

Cost: $5.7-billion

Start of production: January, 2003

Canadian Natural Resources Ltd.

Horizon - Mining

Capacity: 232,000 b/d

Projected cost: $10.8-billion

Start of production: 2008

Syncrude Canada Ltd.

Stage 3 expansion - Mining

Capacity: 360,000 b/d, total

Projected cost: $7.8-billion

Start of production: 1978 for original operations

Nexen Inc., OPTI Canada Inc.

Long Lake - in situ

Capacity: 60,000 b/d

Projected cost: $3.5-billion

Start of production: 2006

Suncor Energy Inc.

Millennium, Firebag (latest expansions) - Mining and in situ

Capacity: 225,000 b/d, total

Cost or Projected cost: $3.4-billion for Millennium expansion

Start of production: 1967 for original operations

Imperial Oil Ltd.

Kearl Lake - in situ

Capacity: Up to 300,000 b/d

Projected cost: $5-billion to $8-billion

Start of production: 2009

Husky Energy Inc.

Sunrise Thermal Project - in situ

Capacity: 200,000b/d

Projected cost: Undisclosed

Start of production: 2008

Petro-Canada

MacKay River SAGD project - in situ

Capacity: 30,000b/d

Cost: $300-million

Start of production: Fall 2002

Athabasca area

At 40,000 sq. km. It is Alberta's largest and most accessible reserve of bitumen. Some of the oil sands near Fort McMurray are close to the surface and can be mined, but less than 20 per cent of the total area can be developed this way. In-situ techniques, which melt the bitumen and pump it from underground, are needed for deeper deposits.

Peace River area

The smallest of Alberta's oil sands areas at 8,000 sq. km, its deep deposits are also being recovered with in-situ methods.

Cold Lake area

At 22,000 sq. km, it is the province's second-largest reserve of bitumen. Its deep deposits are being recovered using in-situ technology.

Extraction and refining

Mining

The mining process begins with the removal of vegetation, muskeg and a thick layer of clay, silt and gravel. (The soil is saved to build the tailing ponds that will hold the sands once bitumen has been extracted.)

Oil sands are mined using shovels with buckets that hold 100 tonnes of soil, loading huge 240- to 360-tonne trucks. The mine delivers about 450,000 tonnes of oil sand a day to the ore preparation plants, with two tonnes needed to produce one barrel of synthetic oil.

Crushers and sizers in the preparation plants prepare the ore for delivery to primary extraction through pipelines after the ore has been mixed with water.

Primary extraction plants on both sides of the Athabasca River separate raw bitumen from the sand.

In secondary extraction, the bitumen is cleaned by removing fine clay particles and water. The thick bitumen is diluted with naphtha and treated to remove remaining minerals and water. It is then stored in holding tanks and delivered to the upgrader for processing.

The water, clay, sand and tailing (residual bitumen) are pumped to holding ponds where they are treated to speed up the reclamation process that will restore the landscape.

In situ

Unlike mining, in-situ production does not disturb the top soil. Instead, steam-assisted gravity drainage (SAGD) technology uses underground wells to inject steam into the oil sands deposits, melting the bitumen and allowing it to be pumped above ground. The recovered bitumen is sent by pipeline to be upgraded.

Upgrading

In upgrading, naphtha is removed and recycled back to extraction. The bitumen is heated in furnaces and sent to drums where petroleum coke is removed. Coke, which is similar to coal, is used as a fuel source for the utilities plant.

Depending on customer requirements, sulphur can be removed by hydrotreating the products. Sulphur is recovered and sold to fertilizer manufacturers.

The utilities plant provides steam, water and power for the rest of the operation. Additional steam and power is supplied through TransAlta's natural gas-fired cogeneration plant and two steam turbine generators.

Refinery-ready feedstock and diesel fuel is shipped by pipeline to customers and commercial and industrial markets throughout North America.

SOURCE: STAFF RESEARCH, SUNCOR ENERGY, REGIONAL MUNICIPALITY OF WOOD BUFFALO, OIL SANDS DISCOVERY CENTRE, NATIONAL ATLAS OF CANADA
 
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