The global market for ethanol faces enormous opportunities and transitional challenges over the next ten years.

In China, India, Brazil and Europe, economic and environmental security concerns are giving birth to new government targets and incentives, aimed at reducing petroleum imports and increasing the consumption and production of renewable fuels. Over the next ten years, however, investors in traditional ethanol facilities will face the inevitable prospects of increased ethanol imports, non-food crops for feedstocks, and the imminent maturation of cellulosic ethanol as a competitive ethanol fuel.
“The global market for ethanol faces enormous opportunities and transitional challenges over the next ten years. A few issues hold the key to understanding the transitional nature of these challenges and identifying the best prospects for long-term growth opportunities,“ said William Thurmond, author of Ethanol 2020: A Global Market Survey.
Thurmond’s study, which is being released today at the 23rd International Fuel Ethanol Workshop & Expo in St. Louis, Missouri, by Emerging Markets Online, provides an analysis and review of major ethanol markets, leading producers, feed stock price trends, import-export trends, government targets as well as challenges and opportunities worldwide, Solaraccess.com said.
The report reviews biofuels initiatives world-wide, including Bush’s new “20% biofuels by 2017“ re-vision of the US Renewable Fuels Standard; the European Union’s proposed “20 by 20“ program to replace 20% of transportation fuels with renewable fuels; and national biofuels target goals and programs for Brazil, China, India, the US and Europe.
“If the promises of competitive, large-scale cellulosic ethanol production are realized, and if nationalist import/export policies for biofuels are further liberalized, then the possibilities for ethanol to replace 20% of gasoline consumption in the US, China and India may be realized by the year 2020,“ noted Thurmond.
Ethanol 2020 identifies three transitional generations of biofuels emerging in the next ten years. The first generation, or 1G, according to Thurmond, is based on traditional domestic production, economics and feedstocks--generally grown and sold near geographically agricultural areas.
The second generation, or 2G, is based on the increasing transition of ethanol production facilities from traditional agricultural areas to new areas in coastal regions in order to take advantage of import, export, multi-feedstock and refinery co-location advantages.
In addition, this second phase addresses the food versus fuel debate, supported by emerging trends in increased production and consumption of non-corn and non-food fuel crops such as sorghum and switchgrass.
This is also true for biodiesel, where non-food feedstocks such as algae and jatropha produce significantly higher returns per acre, and do not compromise food supplies or stimulate higher food prices. Ethanol 2020 observes the third generation, or 3G, is based on emerging technologies and production processes such as cellulosic ethanol, biobutanol, and dimethylfuran that promise higher fuel production and investment returns per acre at lower costs.
The upside to 2G and 3G transitions, the study speculates, is they provide answers and solutions to current problems with rising feedstock costs, energy infrastructure integration issues, the food vs. fuel debate, and eventual price relief for consumers at the pump. During these transitions, new opportunities will emerge for ethanol investors, and new technological processes will improve the present production facilities of today and help alleviate concerns of ROI and stranded costs.
“As these transitions occur, we expect to see an increasing amount of cognitive dissonance and political debate between established ethanol producers, the emerging 2G/3G investors and stakeholders, policy officials and analysts,“ said Thurmond.
“Moreover, these transitional trends and technologies are likely to be critical to the success of government biofuels programs worldwide with ambitious ethanol production targets. Although growing pains will occur, the emergence of 2G and 3G ethanol will help overcome many of the present limitations of agricultural, commercial and technological ethanol production,“ he concluded.

After averting a near-term capacity crunch, crude oil producers could again start to run out of pipeline space by 2012, according to a new industry forecast.
In its annual outlook for Canadian crude oil supply, the Canadian Association of Petroleum Producers said Monday that pipeline projects currently underway will likely be enough to move the expected rise in oilsands production, but the industry needs to focus on the next round of capacity given the long lead time needed for regulatory approvals and construction.
“It’s going to be tight for the next few years, but it should be sufficient capacity,“ said Greg Stringham, association vice-president.
“The real question is if you get to 2012 and we are on the pipeline planning case, there is not going be enough capacity--we need to see what other options are out there right now and start making some decisions.“
According to the association’s “planning case,“ Canada’s crude supply will rise from 2.4 million barrels per day to nearly 5.3 million barrels of oil a day by 2020, Canada.com said.
Under a more moderate scenario, in which oilsands projects ramp up more slowly, production would reach 4.6 million barrels during the same time frame.
But supply in earlier years of the outlook is now expected to come in a little lower than previously forecast to take into account a number of oilsands projects that have been delayed in recent months due to rising costs of labor and materials.
Total oilsands production is expected to reach about 3.37 million barrels a day by 2015, down from last year’s forecast of 3.5 million barrels a day.
The expected surge in oilsands production has spurred many pipeline proposals over the past few years to link the growing output with markets, said another industry official.
“Almost all of them not only increase capacity to existing markets, but add new markets, and that sort of diversity is going to be extremely important at hopefully reducing the differential between heavy oil and conventional,“ said Dave MacInnis, president of the Canadian Energy Pipeline Association.
However, a lack of capacity is still an immediate concern, he said.
“The crunch time really is 2009,“ he said.
“We need to get moving now, because it can take a couple of years simply to move a pipeline project through the regulatory approval process and then another couple, depending on the size of the project, obviously to get it built.“
For the first time, the report also included a survey of refiners, including US operators, about the demand for western Canadian crude.
“It was really quite interesting to see that they are finally turning their attention to Canadian oil,“ said Stringham.
Canadian refineries expect demand to rise 44 per cent to nearly 1.1 million barrels a day by 2015, while U.S. refiners forecast total demand to double to 3.1 million barrels a day.
Most of the demand will come in traditional markets, but there is potential for expansion into new markets such as Quebec, the US northeast and midwest, as well as California and Asia, the report said.

The world’s first floating wind turbine could be generating electricity in the North Sea by 2009 under a research pact on Monday between Norwegian energy group Norsk Hydro and German engineering firm Siemens.
Floating wind turbines would represent a technological breakthrough for offshore power generation, which has had to rely on shallow sites for turbines installed on the seabed.
“It’s attractive to have windmills out at sea, out of sight of land, away from birds’ migration routes,“ said Alexandra Bech Gjoerv, head of Hydro’s New Energy division at a signing ceremony to develop floating wind turbine technology.
“We want to build the world’s first offshore floating windmill,“ Bech Gjoerv said. “We want to produce a lot of energy, out of sight.“
Under the plan, Hydro will combine its knowledge of floating installations, such as North Sea loading buoys for oil tankers, with Siemens’ expertise in building turbines, both on land and standing in shallow waters offshore.
Floating wind turbines are more costly than on land but could supply power both to offshore oil or gas platforms or to coastal cities, cutting emissions of greenhouse gases from fossil fuels and defusing objections that turbines are eyesores, Reuters said.
Hydro said a prototype, costing 200 million crowns ($33.64 million), could be in place in the North Sea in 2009 assuming the firm agreed funding this year. The timetable is two years’ later than hoped when Hydro unveiled a floating design in 2005.
If tests of the 5 megawatt wind turbine were successful, a small offshore wind park could be built around 2013-14. Siemens said it would spend several million euros (dollars) on the research project, on which Hydro has already spent 30 million crowns.
A Siemens unit built the first offshore wind park in 1991, with turbines standing on the seabed off Copenhagen.
“Windmills standing in waters deeper than about 30 meters become prohibitively expensive,“ said Henrik Stiesdal, chief technology officer of Siemens’ wind power unit. Hydro’s “is the most elegant and simple solution we have seen.“
Hydro’s design is an upright steel tube with a concrete base about 200 meters (660 feet) long with 80 meters jutting above the water and three blades 60 meters long.
The wind turbine is tied to the seabed by three cables to keep it steady in seas where waves can be 30 meters (100 ft) high. Hydro reckons it can work in waters 700 meters deep.
Stiesdal said other models for wind turbines at sea relied on more complex designs such as giant tripods mounted on the seabed or turbines mounted on floating boat-like structures.
Bech Gjoerv said Hydro hoped that generation costs from a floating wind turbine could be cut in the long term to 0.6 crowns ($0.109) per kilowatt hour, comparable with wind turbines on land.

The thorny problem of how to store hydrogen fuel safely for future vehicles and portable gadgets could be solved by simply storing it in nanoscopic scrolls of carbon.
Scientists in Greece say they have found a way to make so-called “carbon nanoscrolls“ store more hydrogen than any other material.
By adding impurities to rolled sheets of carbon in detailed computer simulations, they found they could control how tightly the scrolls wind up and, hence, how much hydrogen they adsorb.
This result is very promising because it provides a potential solution to one of the major problems of hydrogen storage for mobile applications, says George Froudakis at the University of Crete, who led the work.
Hydrogen has been much touted as the clean fuel of the future for electric vehicles and portable devices. But, despite holding more energy than hydrocarbon fuels, its incredibly low density makes it difficult to store in sufficient quantity to make it worthwhile, Fuelcellsworks.com said.

Under Pressure
Liquefying hydrogen by placing it under great pressure is both expensive and potentially dangerous. Even then, with a density of just one tenth that of water, it would be necessary to store four times the volume of liquid to match the energy content of gasoline.
“Most of the scientists working on this field of research believe that the solution to this problem will arise from the synthesis of new materials,“ Froudakis says.
Indeed, in 2003 the US Department of Energy (DOE) set a target of developing novel materials capable of reversibly storing enough hydrogen to make up 6% of their total weight by 2010.
The idea is to find materials with high surface areas that soak up hydrogen at much higher densities than previously possible, and without the need for extreme cooling or pressurisation.

Adding Impurities
To address this problem, Froudakis and colleagues carried out computer simulations to see how the hydrogen uptake of carbon nanoscrolls could be affected by adding quantities of different alkali metals. These impurities cause the atomic distance between the layers of a scroll to vary.
Their findings suggest that adding lithium ions should increase the uptake of hydrogen at atmospheric pressure and room temperature from 0.19% to 3.31%.
This is twice the amount that other materials have achieved. Furthermore, hydrogen uptake should increase as the temperature is reduced, the researchers say.
These are significant quantities of hydrogen, says Frantisek Svec, a researcher at Lawrence Berkeley National Laboratory, in California, US. but they still fall short of the DOE targets.
Also, as the study is only a simulation, the results will need to be confirmed experimentally. “Unfortunately, in practice, these carbon-based materials are most often much less encouraging,“ Svec says.

WM announced that it will open 60 more LFGTE facilities around the US over the next five years, resulting in 700 MW of renewable electricity.

Waste Management (WM) announced on Wednesday an initiative to expand its roster of landfill gas to energy (LFGTE) facilities, resulting in another 60 renewable energy facilities over the next five years.
Combined with its existing 103 LFGTE facilities, WM will generate more than 700 megawatts (MW) of renewable energy. Throughout the rest of 2007, WM plans to bring 10 LFGTE facilities online and begin development on an additional 10 new sites, according to Solaraccess.com.
LFGTE projects are especially valuable to utilities because they provide dependable baseload power. A typical facility will run about 95 percent of the time, making it a good fit with intermittent renewables such as wind and solar.
Landfill gas, produced when microorganisms break down organic material in the landfill, is comprised of approximately 50-60 percent methane and 40-50 percent carbon dioxide. At most landfills in the US, these greenhouse gases are simply burned off, or “flared.“
Waste Management sites that have LFGTE facilities will collect the methane and use it to fuel onsite engines or turbines, generating electricity to power surrounding homes and neighborhoods while creating a new revenue stream for the landfills. By building LFGTE facilities, Waste Management reduces greenhouse gases by offsetting the use of fossil fuel at the utility power plants.
“This initiative is a major step in Waste Management’s ongoing efforts to implement sustainable business practices across the company,“ said Paul Pabor, vice president of renewable energy at WM. “Landfill gas to energy projects provide an important contribution to the country’s renewable energy portfolio.“
The LFGTE initiative will add 230 MW of electricity generation to the grid. Waste Management’s decision to construct more facilities was due in large part to the demand for more clean energy set by state renewable portfolio standards, said Pabor.
Waste Management, which designed and operated its first LFGTE facility in the US more than 20 years ago, currently has 281 landfills in operation. The company intends to expand its waste-based renewable power generation across the country, and is exploring partnerships to develop its energy technology at other private and municipal landfills.
“Landfill gas is part of the solution,“ said Pabor. “There are a finite amount of landfills, but we do fill a niche in renewable energy. When we build out these plants in the next five yearsÉwe’ll have enough for about 700 MW, which is a good-sized fossil fuel plant.“
As part of its initiative, in 2007 Waste Management plans to commission LFGTE projects at landfills in Texas, Virginia, New York, Colorado, Massachusetts, Illinois, and Wisconsin.