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With a performance guarantee we lock in our profits with the insurance.....therefore our stock price should reflect the profits expected!
You may be right....Time will tell. You do have a good track record.
As long as FFI process does not burn the waste....there are proccesses available that can contain the heavy metals and hazardous waste so they can be properly disposed of in a landfill with the required permits, linings to handle the toxic waste.
Does anybody think we will get news on TWR shortly? The patents have been published and it is time that NSOL do something since they own the rights to the technology....
That is an interetsing paragraph taht is worth noting....There is also alot of wastecoal in PA....free feedstock.
Shaping a Secure Energy Future for All Pennsylvanians
Beginning with Governor Rendell’s launch of the Pennsylvania Energy Harvest program in his very first months in office, we began to call for the enhanced use of Pennsylvania’s indigenous energy resources as the best way to ensure reliable, affordable and secure energy. At that time, we noted that Pennsylvania was spending approximately $30 billion per year to purchase energy resources from outside the Commonwealth, dollars that we could keep in the state to grow our economy if we developed a policy and financial environment favorable to indigenous energy resource promotion.
With the right policy and financial incentives the Commonwealth is uniquely positioned to meet its energy needs. Pennsylvania has the fourth largest coal reserves in the United States, 74 billion short tons of proven reserves --- enough coal to offset the country’s entire imported petroleum needs for the next 40 years if it were liquefied.Low-cost waste coal can be a strategic advantage for Pennsylvania by providing low-cost fuel input for energy producers. The Commonwealth also possesses tremendous renewable energy potential. According to the U.S. Department of Energy, Pennsylvania has the potential for over 5,000 megawatts of wind energy --- enough to power 1.8 million homes annually. Significant biomass, incremental, low-impact hydro and solar resources are also feasible in Pennsylvania. In the near term, it is estimated that direct biomass usage and biomass co-firing could account for the same amount of electricity generation as one nuclear power plant.
Through our Pennsylvania Energy Harvest and Pennsylvania Energy Development Authority (PEDA) programs, DEP has funded 15 biomass, landfill gas and coalmine methane recovery projects. The energy from a single coalmine methane recovery project could heat 15,000 homes; similarly, the energy value from a typical landfill gas project could heat 34,000 homes.
Governor Rendell’s Growing Greener II initiative provides significant resources to build on the success of these energy initiatives, including up to $10 million annually for PEDA, which has up to $1 billion available to provide financing to help build clean power and fuel plants. In June, PEDA awarded its first $6.5 million to finance 16 clean energy projects that will create as many as 450 permanent and construction jobs, including 327 full-time jobs.
The authority was originally established in 1982 to promote applied energy research, provide financial incentives for the deployment of clean, alternative energy projects and promote investment in Pennsylvania’s energy sector. After a period of inactivity, Governor Rendell revitalized PEDA as part of his strategy to build a clean, indigenous, diversified energy industry in the state. Today, we are funding projects that promote Pennsylvania’s indigenous energy resources, encourage energy diversity and enhance energy security.
Working with this Committee and the rest of the General Assembly, we were able to craft the historic Alternative Energy Portfolio Standard (Act 213 of 2004), or AEPS, to promote our indigenous energy resources. This act, the first of its kind in the nation to recognize the value of resources that provide a net environmental benefit, provides strong incentives for renewable energy, waste coal and coal gasification. We were also the first restructured state to include demand-side management measures, or “negawatts,” as a means to achieve portfolio standard compliance. Act 213 will ensure that approximately 5,000 megawatts of new generation that comes on line over the next 15 years will be from resources indigenous to Pennsylvania, thereby reducing our demand for natural gas in the electricity sector while improving the quality of our environment.
AEPS will help to ensure that our future electricity needs are met by clean, indigenous sources. However, one of our primary challenges is to develop indigenous alternatives for transportation fuels.
Alternative fuels such as some types of ethanol and biodiesel are alternatives that can cleanly meet some of our transportation fuel needs. The federal Energy Policy Act of 2005 will require the United States to more than double its usage of biofuels by 2012. Act 178 of 2004 amended the Alternative Fuels Incentive Grant Program to provide incentives for biofuel production and usage in Pennsylvania and we have been supportive of these efforts.
Last month, Governor Rendell took part in the opening of the first biodiesel injection refueling station on the East Coast. The station, located in Middletown, is a joint venture of Worley & Obetz, Petroleum Products Corp. and Independence Biofuels Inc. It will replace 3.2 million gallons of foreign oil, saving $6 million in imported fuel costs, and was supported by a $220,000 grant from DEP’s Energy Harvest program.
This is just the beginning of a bright future for biofuels in Pennsylvania. Through our Alternative Fuels Incentive Grant Program and other Commonwealth financial programs, we plan to assist in the deployment of biofuel projects that make use of Pennsylvania’s indigenous biomass resources.
In addition, the Governor’s newly created Renewable Agricultural Energy Council focuses on developing and expanding agricultural energy industries in Pennsylvania. Renewable agricultural energy has the potential to support and grow the agriculture industry in Pennsylvania by providing as many as 64,000 additional jobs. Renewable agricultural energy can help diversify agricultural activities and stimulate the growth of crops that strengthen the agriculture industry. Agricultural energy sources can save the average household $1,200 annually on energy bills.
The council will make recommendations to the Governor on policies, procedures, regulations and legislation that would aid in the development of renewable energy; serve as the Governor’s liaison to the ag community on issues affecting the production of renewable energy; serve as a resource to all state entities to ensure that leaders are aware of the issues surrounding renewable energy; and provide guidance and assistance to help the industry establish and develop the infrastructure necessary to deliver renewable energy sources to consumers within Pennsylvania.
Recognizing that alternative energy development represents another promising dimension to farming and offers an economic boost to agricultural communities, the Governor’s First Industries Fund has provide $1.4 million for nearly a dozen projects that include biodigesters, biofuel production, wood-fueled power plants and more. In addition, the Commonwealth Financing Authority will be providing about $22 million to stimulate early stage energy development activities and ensure capital for ventures that increase energy efficiency and promote alternative energy in the Commonwealth..
The Waste Management and Processors Inc. (WMPI) waste coal to no-sulfur diesel project in Schuylkill County demonstrates how Pennsylvania’s indigenous resources can further be deployed to meet our energy needs. This project will utilize waste anthracite coal and convert it into no-sulfur diesel fuel using a well-established technology called Fischer-Tropsch. Because the fuel input is inexpensive, at hand and abundant, WMPI will be able to produce no-sulfur diesel fuel at prices that are competitive with market rates. The plant will produce as much as 40 million gallons of clean-burning diesel annually.
This project has been very illustrative of the importance of public sector participation in promoting innovative energy solutions. Despite using well-established technology, Fischer-Tropsch coal-to-liquids technology has been used for over 50 years and producing product that is competitive with conventional diesel fuel, the financial community has been reticent to invest in innovative energy projects.
In order to make the WMPI project feasible, public sector participation has been required. Thanks to the General Assembly, WMPI received tax incentives. These incentives have been coupled with a $100 million grant and loan guarantee from the U.S. Department of Energy. Even with these valuable incentives, however, the financial community insisted that WMPI have long-term off-take contracts in place. As a result, the Rendell administration has agreed to a long-term contract to purchase diesel fuel produced by the WMPI plant and helped facilitate long-term off-take commitments for product from several other buyers, including Worley and Obetz Inc. and the Keystone Alliance --- a fuel purchase group for the trucking industry.
The financial community’s requirement for off-take contracts as a precursor to receiving financing is not unique to the WMPI project. In virtually every alternative energy project we have worked on developing, from coal gasification and liquefaction to renewable energy projects like solar and wind, long-term off-take agreements have been essential. Ensuring that Pennsylvania regulations and administrative rules associated with energy markets are favorable to long-term contracting is critical if we are going to successfully incentivize our indigenous energy resources.
Nowhere will long-term contracting ability be more essential than in encouraging one of our most promising technology solutions --- Advanced Coal Gasification and Liquefaction (ACGL). Others who have testified before this committee, including PUC Commissioner William Shane, have referred to this technology as Integrated Gasification Combined Cycle or IGCC, but we are talking about the same thing.
WMPI is an example of coal liquefaction. We have before us an historic opportunity to fundamentally transform Pennsylvania’s energy sector. Over the next five years, Pennsylvania electricity generators will need to decide whether to invest in new technology, pollution control technology or least preferably to close old power plants, in order to comply with a suite of federal air quality rules.
Our preference, of course, would be for generators to invest in the next generation of Advanced Coal Gasification and Liquefaction plants capable of producing clean electricity, synthesis gas and liquid fuels from our coal reserves. ACGL works by gasifying coal primarily into hydrogen and carbon monoxide. After gasifying the coal ACGL operators can sell the hydrogen/carbon monoxide synthesis gas directly to industrial off-takers, like chemical manufacturers. Gasified coal can also be used to generate electricity, be methanized into synthetic natural gas capable of supplementing our natural gas supply or liquefied into transportation fuels as in the case of the WMPI project. As you can see, ACGL technology is capable of using Pennsylvania coal and waste coal to address all of the energy challenges outlined above, namely constraints to natural gas and petroleum supplies that are currently leading to higher energy prices, threatening our manufacturing base, and causing financial hardship for our low and moderate income citizens.
Conclusion -- Creating a Virtuous Circle
http://www.depweb.state.pa.us/dep/cwp/view.asp?a=3&Q=482149
Alternative Fuels
In recent years, many technologies have been put forth as being alternatives to our reliance on oil and gas for transportation and heating.
Unfortunately, nearly all of these alternatives have significant environmental, social and economic impacts, making them undesirable to society at large and specifically to the communities that would host the production facilities.
Three of the most prominent "alternative fuels" technologies being promoted today are cellulosic ethanol, thermal depolymerization (TDP) and Fischer-Tropsch (F-T) gasification/liquefaction.
Cellulosic Ethanol
Cellulosic ethanol is the technology needed to turn a wide array of organic materials into ethanol. Unlike normal ethanol production, it wouldn’t be used on corn or grains. However, it can be used on corn husks, leaves and stalks (known as "stover"), trees and other crop and agricultural wastes. The same technology can be used for more dangerous types of wastes, such as municipal solid waste (household and commercial trash), sewage sludge, scrap tires, construction and demolition wood wastes and other waste streams known to be highly contaminated with toxic chemicals of various sorts.
Several companies have been seeking to build "trash-to-ethanol" plants throughout the nation, targeting at least a dozen states with over 20 proposals. This is just the beginning, but since the technology is experimental and unproven, investors have avoided funding the industry (they all want to be the "first to finance the second proposal," according to one industry leader). Now that the national Energy Bill became law in August 2005, this industry may take off, since the law includes government-subsidized loans that will enable the first plants to be financed. The nation’s leading proposal is a plan for a facility in Middletown, New York that would take trash as well as sewage sludge (possibly from New York City).
Thermal Depolymerization (TDP)
This technology has been widely promoted as "anything-to-oil" by a company called Changing World Technologies. They have a pilot test facility in Philadelphia where they have processed a variety of contaminated waste streams, including food wastes, sludges, offal, rubber, animal manures, black liquor (paper mill waste), plastics, coal, PCBs, dioxins, and asphalt. They also have a full-scale facility in Carthage, Missouri where they turn turkey guts into "oil."
Through their extensive public relations outreach, they’ve managed to get some politicians to latch onto this as a solution to dependence on foreign oil. However, many questions remain unanswered about where all of the toxic contaminants end up when their machines magically turn "anything" into "oil."
Fischer-Tropsch (F-T) Gas-to-Liquids
This technology is named after two German scientists who developed it as a means to turn coal into oil. This was used to fuel the Nazi war machine. It takes a solid fuel and gasifies, then liquefies it. This same "coal-to-oil" technology was later used in South Africa, when the Apartheid regime had a similar problem importing oil, but had large domestic coal supplies. The world’s only remaining facilities are in South Africa and they are major polluters.
An alliance between a Pennsylvania coal baron, Sasol (the South African state oil company), Bechtel and Shell has formed to bring the first coal-to-oil refinery to the U.S. It would be located in Schuylkill County in eastern Pennsylvania’s mining region, adjacent to a state prison, surrounded by three waste coal burning power plants and overshadowing a poor, white community that has a high enough population in poverty that the state classifies it as an environmental justice community. This facility is promoted as one that will turn waste coal (a fuel dirtier than normal coal, with high mercury content) into "ultra clean fuels." They also plan to produce electricity (from burning some of their gas products) and possibly hydrogen. See the company website at www.ultracleanfuels.com and find out the reality at www.ultradirtyfuels.com.
Fischer-Tropsch can be used for a wide variety of wastes. The Pennsylvania project would test process a wide range of municipal and industrial wastes as well as "biomass" (a wide category of often contaminated waste streams).
It has often been promoted as the means to reduce reliance on foreign oil, by increasing the use of coal and waste coals in the U.S. If the eastern PA project goes through, several others are likely to be built – primarily in the coal regions (target states include AK, CO, IL, IN, KY, MT, OH, western PA, VA, WV and WY). Each of these would be 10-12 times larger than the one planned for eastern PA. If they succeed at building 6-7 full-scale refineries, they would produce 20% of the diesel used in the U.S. (an amount that would more easily be avoided through conservation and efficiency tactics, such as hybrid trucks and increased use of rail for shipping). Proponents state that if all of the oil imported into the U.S. were replaced with coal-based liquid fuels, coal mining in the U.S. would nearly double.
What’s wrong with these magic machines?
In addition to being supposed "solutions" to our reliance on foreign oil and gas, these technologies are often promoted as alternatives to landfills and incinerators for a variety of waste streams. However, these expensive technologies can't help solve problems that need to be addressed "up-stream."
There's no magic technology that can make toxic metals (or radioactive contaminants) disappear. It's rare that any technology actually makes halogens (chlorine, bromine, fluorine...) into fairly benign chemicals (like salts); most tend to make these chemicals more dangerous (like converting them into dioxins and furans or releasing them as acid gases).
Promoters of these technologies tend to avoid describing the fate of toxic metals, halogens or radioactive compounds that enter their processes, making people think that they can handle contaminated wastes and have the contaminants disappear. This is typical of all who promote magic machines (including incinerators). They pretend that the only elements in waste are carbon, hydrogen and oxygen. If they admit other elements are present, it's usually to describe elements that help them market their solids wastes as soil amendment or fertilizer.
Solid waste byproducts of these processes are likely to contain contaminants from the original feedstock (possibly concentrated levels of them) and may be most appropriately placed in a landfill. However, the high cost of using these technologies demands that these solid wastes be sold as beneficial products rather than paying for their "disposal" in a landfill.
As a solution for municipal solid wastes, any technology that destroys materials necessitates the re-creation of those materials from virgin feedstocks, making the net energy flow highly undesirable. Trash incinerators would be more accurately described as waste-of-energy instead of waste-to-energy facilities.
Like incinerators, these expensive technologies compete with recycling and waste reduction efforts, since they would require long-term contracts with "put-or-pay" clauses which penalize waste reduction and recycling efforts. Incinerator companies typically rely on these types of contracts, requiring local governments to commit a certain volume of waste to the incinerator each year or pay a cash penalty.
These facilities are fairly flexible in the types of fuels/wastes they process, so there are economic incentives to use of the dirtiest possible feedstocks –like trash, tires and sewage sludge – since facilities can get paid to take such wastes, whereas they often have to pay to obtain cleaner fuels – like trees, forestry residues or organically-grown crops. Even these "ideal" fuels have impacts. The impacts on forests can be serious, especially when a constant supply of wood must be supplied from a certain area around the facility. These plants are like hungry mouths needing to be fed on a constant basis for as many decades as they'd operate. No facility is going to pay to obtain organically-grown crops, when they can use herbicide drenched, natural gas-based fertilizer grown, genetically-modified crops which are cheaper to produce. Even facilities that start with such a "clean" feedstock will be tempted over time to accept dirtier waste streams that they can get paid for, like construction and demolition wood waste, which almost always involves significant rates of contamination with toxic treated and painted woods, if not other contaminants like plastics and asbestos.
By posing as "green" solutions to waste problems, these technologies justify continued waste generation.
These technologies don't have the job creation and economic benefits that aggressive source reduction, reuse, recycling and composting programs do. The only real answers on waste lie in the zero waste movement (see www.grrn.org/zerowaste/) and for energy: conservation, efficiency, wind and solar with hydrogen (produced cleanly from water with wind and solar power) used for transportation fuels.
http://www.energyjustice.net/fuels/
The Honorable Kathleen A. McGinty
Secretary
Pennsylvania Department of Environmental Protection
Testimony - Waste Coal Incentives
Before the Senate Environmental Resources and Energy Committee
September 8, 2004
Chairman White and members of the Committee it is my privilege to be here today to discuss the administration's efforts to reclaim land and mitigate and eliminate the environmental impacts of waste coal piles while making use of this potential energy resource. I would especially like to thank Senator Stout for holding this timely hearing in his district and calling specific attention to this very important matter and opportunity.
Pennsylvania is a remarkable state with abundant natural riches, including a tremendous heritage of coal production that fueled the industrial revolution and provided hardworking residents with opportunities for a better life. Unfortunately, that legacy also left significant parts of our state scarred from past mining activities.
Travel the back roads of our Commonwealth and it's not uncommon to see refuse piles of unused coal and rock. These waste coal mixtures, commonly called gob or boney piles in the western half of Pennsylvania and culm in the eastern coal fields, are a significant problem in Pennsylvania, which has some 220,000 acres of abandoned mine lands and more than 2,200 miles of streams impaired by polluted mine drainage.
Western Pennsylvania in particular has a significant and proud coal-mining heritage, but as we will hear today from members of this Committee, other speakers and our tour of the Champion waste coal site, this part of Pennsylvania has been especially impacted by the legacy of waste coal disposal. As I will discuss further below, we look at this legacy not as a liability to be mitigated but as an opportunity to be exploited and I will outline proposals that we are developing to take advantage of this unique Pennsylvania resource.
While Pennsylvania's coal economy has indeed contributed greatly to the economic expansion of this country and its success in two world wars, it has left behind numerous scars across the landscape. According to DEP estimates, as of Dec. 2003, there were an estimated 8,529 acres of unreclaimed coal refuse piles throughout Pennsylvania. These piles include at least 258 million tons of waste coal that cause polluted mine drainage, scar the landscape and, in some cases, result in coal refuse fires which contribute to air pollution. Coal refuse piles are also used regularly as dumping piles for trash and other waste. Just one example of the magnitude of these sites is the coal refuse pile that we are going to tour, the Champion site, which, at 500 acres, is the biggest coal refuse pile east of the Mississippi River.
As you know, the department has initiated numerous programs to address the environmental impacts caused by waste coal. One of the most successful programs is the remining program, where mining companies re-mine, or remove the culm banks, screen the material, and transport the suitable refuse material to fuel nearby power generation plants. This removes much of the pyritic material left behind by past coal mining activity that contributes to acid mine drainage, one of the leading causes of stream degradation in the Commonwealth.
When the refuse is burned in the plant, alkaline material is commonly added, and the resulting coal ash -- high in alkalinity -- is then returned to the refuse sites to help reclaim those areas. This prevents any leftover pyritic material from causing acid mine drainage. The removal of the refuse piles can also result in cleaner air due to the elimination of dust sources and, in some cases, uncontrolled burning of the piles. Removing the piles also removes unregulated dumping areas, because people often access these piles through construction access roads in order to dump garbage and other waste.
The Commonwealth has analyzed coal ash and coal ash leachate (water run-off from ash) from many different sources of ash, and has determined that coal ash -- when used appropriately -- is safe to use in mine reclamation projects. This is in part due to the fact that when coal ash is placed at a mine site in an appropriate fashion, it is placed above the ground water table to prevent direct contact with water. In addition, coal ash is usually capped with topsoil -- in many cases up to a four-foot layer -- and that topsoil is then re-vegetated and graded with a three-percent slope. This ensures that rainwater will run off of the site before it comes in direct contact with the placed coal ash. Even if water permeated the topsoil, the compaction of the ash would likely prevent the permeation of water through the ash. The capping with topsoil, sloping of the ash and the compaction of the ash also prevents the rainwater from contacting the pyritic material left behind from the mining operation, so acid mine drainage is never formed.
In addition, leachate tests have shown that even when coal ash comes in contact with water, the metals and other constituents found in coal ash tend not to leach out. This is due to the fact that the chemical make-up of the alkaline coal ash binds up the metals and other constituents in the ash. In addition, the alkalinity of the coal ash prevents the development of acid, which would promote leaching (the coal ash is alkaline due to the addition of alkaline material during the combustion process).
The re-use of this material is a prime example of one of the main environmental themes of the Rendell Administration, namely viewing environmentally harmful material as a potential resource that can be re-used rather than remain as a liability. In 2003 alone, DEP issued mining permits which resulted in the removal of nearly a half-million tons of coal refuse in southwestern Pennsylvania.
Of course, government can't pursue the goal of industrial re-use alone. These efforts are a result of the advent of new boiler technology used by power generation plants called "Circulating Fluidized Beds." These plants burn coal refuse and other fuels that have far less "heating value" (BTU's, or British Thermal Units) than the types of boilers used by the large utilities to burn regular coal.
CFB's are also inherently cleaner than pulverized coal-fired boilers. For more than 30 years, the Department has collected company specific information necessary to obtain estimates for all toxic pollutants. This data demonstrates that dioxin levels were approximately four times lower and most metals, with the exception of mercury, were ten times lower per gigawatt hour than pulverized coal-fired generation. Further, CFBs could achieve very high-levels of mercury control, up to 95%, for very low relative costs should mercury standards be set at the federal level. By comparison, mercury controls on pulverized units would achieve lower-levels of control at higher costs.
Similarly, emissions of NOx and SO2 were also lower than pulverized coal-fired boilers. It should be noted that newly built pulverized coal-fired units would be able to achieve similar emissions levels for S02 due to the installation of scrubbers under Best Available Control Technology determinations. Therefore, newly constructed electric generating combusters of either waste coal or coal would emit at comparable levels because both would be employing very similar BACT for all pollutants. We have attached a comparative analysis of waste coal emissions developed by our Bureau of Air Quality, which provides more details on this matter. MS Word PDF
There are 15 plants burning coal mining refuse in CFB's located in Pennsylvania. The first of these plants came on line in Pennsylvania in 1988. According to ARIPPA, a trade organization representing 13 of the CFB plants in the Commonwealth, from 1988 through the end of 2003, coal refuse plants in Pennsylvania consumed 88.5 million tons of coal refuse, mostly from abandoned refuse piles. Approximately 19 million tons of that were burned in coal refuse plants in the southwest region of the Commonwealth. ARIPPA's records show that the plants in the Commonwealth burn an average of about 7.5 million tons of coal refuse per year, mostly from abandoned coal refuse piles.
The coal refuse that fuels these plants is removed -- or remined -- from the refuse piles under the regulation of DEP. Thanks to DEP's remining program, there have been numerous success stories in southwestern Pennsylvania in the effort to reclaim coal refuse piles. One of these examples is the scheduled removal of 60 million tons of coal refuse from over 40 different coal refuse piles in seven counties, including Allegheny, Westmoreland, Indiana, Cambria, Armstrong, Huntingdon and Somerset. These piles are scheduled to be removed and burned in the newly-constructed Reliant Energy plant, a 500-megawatt fluidized bed coal refuse-burning power plant at Seward in East Wheatfield Township, Indiana County. Reliant received $400 million in tax-exempt financing (bonds) from the Pennsylvania Department of Community and Economic Development for this project. It is estimated there is an additional 10-20 million tons to be found in piles that are still on a list to be explored and evaluated for possible use by Reliant.
While the project will result in the elimination of harmful coal refuse piles, it is also contributing to the creation of over 300 much-needed jobs throughout southwestern Pennsylvania. This underlies another major tenet of the Rendell Administration: spurring job creation and economic growth. The ability to create jobs while simultaneously cleaning up environmental scars from the past is a double-win for the Commonwealth. It's also important to note that without industry involvement, this type of success in all probability would not be happening: it's unlikely government would have the resources available to reclaim many of these coal refuse piles.
DEP also issues reclamation contracts to mine operators to reclaim refuse piles, such as the nearly 19-acre Crucible Pile in Greene County that is currently being reclaimed, and has granted funds through the Growing Greener program to various organizations to reclaim waste coal piles. For example, DEP awarded two Growing Greener grants for a total of approximately $4.6 million to the Greene County Industrial Development Authority to reclaim the Mather coal refuse pile in Greene County. That project is still under way and includes the removal of material and the capping of the area with on-site material such as top soil. That project should be completed within a year.
In addition to the environmental and economic benefits derived from the re-use of waste coal, the Commonwealth's 15 waste coal power plants generate enough electricity to power approximately 1 million homes annually. They do this with relatively low air emissions, adding to the environmental success of cleaning up waste coal piles that cause water and air pollution.
According to ARIPPA, since 1988 Pennsylvania's waste coal industry has reclaimed approximately 3,429 acres of abandoned mine lands. The Department estimates the cost of government-sponsored reclamation to be between $20,000 to $40,000 per acre. Consequently, these efforts have saved the taxpayers of this Commonwealth between $68 million and $137 million since1988, an amount equal to approximately three to six years of federal abandoned mine land appropriations to our state.
Even the residual ash from electric generation at these facilities provides a benefit for Pennsylvania as it is used to fill strip mine pits with dangerous highwalls. Similarly, because the ash is mixed with limestone, the alkaline mixture makes it effective for use to remediate the acidic drainage that pollutes streams and threatens drinking water supplies.
Using waste coal to produce energy is an innovative process that will attract new investment and help to create the jobs we critically need while ensuring the highest standards of environmental protection and public health. Pennsylvania exports more than $20 billion a year to import energy fuels--that's nearly as much as our entire state budget. Yet, indigenous energy development has a multiplier effect in the economy that may generate as much as 1.6 times more revenue than from imports. Keeping energy dollars in state clearly is an important step in retaining and generating more jobs in Pennsylvania.
The Rendell administration has recently initiated two actions to help support and promote Pennsylvania's waste coal industry. During his January budget address Governor Rendell announced that the Commonwealth would purchase ten percent of its electricity from clean, advanced energy sources, including waste coal. I am pleased to note that we recently completed this purchase, which includes 10,000 megawatt hours of waste coal -- out of a total of 100,000 megawatt hours of clean, advanced electricity.
In April Governor Rendell reestablished the dormant Pennsylvania Energy Development Authority, PEDA. As many of the members of this Committee know, PEDA was first established to encourage the development of Pennsylvania's energy resources. PEDA possesses $300 million in tax-exempt bonding authority and in the past this capability has been used to finance waste-coal power plants, notably the Ebensburg, Cambria facility. PEDA will work in concert with the Pennsylvania Economic Development Financing Authority, thereby expanding the financing capabilities of the Commonwealth. As you know, PEDFA financing was instrumental in enabling the re-powering of the Seward, Reliant power plant to utilize waste coal.
We are currently in discussions with developers seeking to deploy state-of-the-art advanced coal gasification technology, which in some cases will be able to utilize waste coal as a fuel.
Projects utilizing waste coal are also a focus of the Pennsylvania Energy Harvest Grant Program. This $5 million annual grant program provides funding to projects that improve the environment through advanced energy solutions. Last year, Energy Harvest funded two waste coal projects. The first is a joint project with the U.S. Department of Energy and CO Inc. to demonstrate the utilization of coal fines. The process, termed "Granu Flow," adds asphalt emulsion, or a similar, binder to agglomerate the coal fines. Once these fines are bound together they will be able to be utilized as fuel in waste coal power plants. Energy Harvest also provided funds to the River Hill Power Company Project in Clearfield County for preliminary environmental and fuel quality analysis for their proposed waste coal power plant. Together, Energy Harvest provided nearly $400,000 for these two projects.
In addition to the tools provided by the Commonwealth's electricity purchase PEDA, and Energy Harvest the Governor has also advocated for an Advanced Energy Portfolio Standard that would include waste coal as an eligible resource. I know this Committee has already held several hearings on this subject so I will refrain from covering the basics of portfolio standards and the Governor's proposal in general and, instead, will focus my remarks specifically on the role waste coal can play as an eligible resource.
As you know, many portfolio standards limit eligibility to renewable resources. We do not feel that this is the best approach for Pennsylvania. As I discussed earlier in my testimony, Pennsylvania's unique history and geology mean that we should take a broader view to include other resources, such as fugitive coal-mine methane and waste coal, that while not considered "traditional" renewables, still provide a net environmental benefit to the Commonwealth.
Therefore, the Governor has proposed a two-tiered portfolio standard, an Advanced Energy Portfolio Standard, which includes waste coal as an eligible resource in the second tier. The first tier would be made-up of traditional renewables, energy efficiency, energy conservation, efficiency upgrades at existing power plants, recycled energy and electricity generated from fugitive coal-mine methane. The second tier would include emissions offsets and electricity generated from fuel cells powered by non-renewable fuel, and waste coal.
Because participation in an Advanced Energy Portfolio Standard will provide economic benefits to qualifying facilities, by making power purchase contracts with those facilities more attractive to electric distribution companies and electric generation suppliers and through the sale of advanced energy credits, we believe that the qualifying facilities should be attaining the highest possible environmental standards. As such, we are proposing that qualifying facilities should meet the highest attainable emissions standards for nitrogen oxide, sulfur dioxide, particulates, and volatile organic compounds. By including an emissions standard we will ensure that our unique Pennsylvania energy resources are utilized in a way that protects the health and environmental quality of all the Commonwealth's citizens.
To clarify, this standard would not replace any facilities existing air quality permits. Facilities would still be in compliance so long as they are meeting the standards set in their current operating permits. These standards would be the requirement, essentially a higher bar, which facilities would need to meet in order to qualify for eligibility as part of the Advanced Energy Portfolio Standard.
In order for waste coal to be a meaningful part of the Advanced Energy Portfolio Standard we believe the portfolio standard targets set for the second tier should be sufficient to include both the existing power plants and to provide incentives for some new plants to be built. As was demonstrated in my testimony earlier, Pennsylvania's existing waste coal industry has and continues to provide tremendous environmental and economic benefits to the Commonwealth's citizens. However, because many of the smaller merchant facilities have power purchase agreements that will expire, in many cases, by 2013 we believe there is a need to continue to incentivize their existence and the reclamation work they are doing.
Still, as we will see later today when we visit the Champion refuse pile, there are still many areas of the state that would greatly benefit from reclamation resulting from waste coal utilization that currently have no outlet for existing abandoned waste coal piles. As such, we believe that a portfolio standard that includes waste coal should consider a target that will also incentivize new projects. We can discuss what such a target should be as we move forward in developing legislative drafts, however, for starters we believe that a second tier target of ten percent in ten years makes sense. Pennsylvania's existing and projected waste coal power plants will likely generate enough electricity to meet as much as 8% of the Commonwealth's projected electricity demand ten years from now. Thus, a ten percent overall goal would be keeping in line with the Governor's original proposal for a three percent second tier to incentivize new projects.
We believe in the view that the waste coal many individuals may see as liabilities can truly be an asset if we use our imagination for innovative solutions. The incentives that we are proposing above will provide both the policy framework and the financial tools to turn these opportunities and solutions into a reality. Again, I thank the Committee for the opportunity to present to you today. I would be happy to answer any questions that you have at this time.
COAL-TO-CLEAN FUELS AND POWER PROJECT, GILBERTON, PA, USA
The US government has long been looking for an alternative energy source to reduce reliance on the oil producing nations. A technology developed by WMPI Pty LLC (Waste Management and Processors, Inc) has been taken by the government for further research and development to sustain the country's energy demands.
Early Entry Co-Production (EECP) energy plants are being developed to change a range of hydrocarbon feedstock into electricity, heat, high quality transportation fuels and various chemicals (as opposed to current plants that produce only energy).
Following completion of the EECP research, development and testing program in 2003 by the Department of Energy (DOE), a new EECP plant is planned for Gilberton, Schuylkill County, PA.
Three DOE projects have begun with the development of an effective EECP process in mind. The multi-product facilities will co-produce transportation fuels (low sulphur clean diesel), chemicals, electric power, process heat, etc., from various waste coal and anthracite feed-stocks, and is seen as the first step on a pollution-free high energy fuel.
FINANCE
Total estimated cost of the plant is $612.5 million although the DOE sees it as a demonstration process, and therefore will underwrite the project to keep costs down. Pennsylvania State has already promised $47 million in Transferable Investment Tax Credit (TITC) for coal waste removal and ultra-clean fuels towards the project.
Finance includes $465 million in private financing - coordinated by the investment banking firm of Morgan Stanley - and $100 million in Federal participation through the US Department of Energy's Clean Coal Power Initiative (CCPI).
HISTORY BEHIND THE TECHNOLOGY
The DOE began work in August 1999 with WMPI and a project team of companies including Texaco, Nexant (a Bechtel consulting company) and SASOL to research ways to integrate gasification and liquefaction. Techno-economic feasibility tests of an EECP ran from 2001-2003 and cost $12 million. This part of the program proved to be successful.
The drive is part of the US Government's CCPI, which is estimated to be sharing a $4 billion budget with industry leaders over a ten-year period. The costs are being shared between private companies and governmental agencies. The technology is based on the gasification of waste coal residue, followed by a liquefaction process to produce sulphur-free low particle diesel.
Pennsylvania is estimated to have over 34 billion t of coal and waste coal in ground reserves, and the US as a whole 1,600 billion t. If these figures are true, the US has 811 years of coal energy remaining in reserves. After coal has been mined and sorted there is a combination of waste coal particles and silt left over. This can be used as the feedstock for the new technology.
PLANT CONSTRUCTION
It is hoped that the Gilberton project will reclaim large areas of Schuylkill County from the acres of anthracite culm piles and silt ponds that cover the area (these will provide the necessary feed-stocks). The Pennsylvania Department of Environmental Protection has suggested that there is over 250,000 acres of abandoned wasteland that were previously coalmines. This is therefore an environmental clean-up and energy production win-win situation.
WMPI Pty LLC, based in Gilberton, is currently (2005) in a position to construct the new facilities. WMPI Pty LLC's first plant will be a 5,000b/d facility built on a 75-acre site adjacent to the existing Gilberton Power Plant.
The technology and engineering team to design, engineer and construct the plant includes Nexant Inc, Shell Global Solutions US, Uhde, SASOL Technology Ltd, Linde and ChevronTexaco. The plant will take approximately three years to build. Subsequently, WMPI Pty LLC will develop, own and operate advanced world-scale coal to oil and power facilities in other locations.
CO-PRODUCTION OF ELECTRICITY AND AUTOMOTIVE FUELS
The slurry of hydrocarbons and water will be heated in a gasifier to over 2,500°F and mixed with oxygen via oxygen blown gasifiers. This gasification of the feedstock produces synthesis gas (syngas) and water. The wastewater can then be pumped back into the process and an environmentally-benign aggregate by-product resembling brown crushed glass is then removed, which can be used for the production of concrete and plaster, or as a backfill.
The syngas is put through cyclones, which get rid of some fine particles. Yellow sulphur is removed at this stage, which can be sold to pharmaceutical companies. The remaining clean syngas will then be added to a slurry phase vessel and mixed with catalysts to produce steam and paraffin, which can then be processed to produce a high-cetane, zero-percent sulphur and nitrogen, low aromatic and low particulate petroleum-based fuel. The excess tail gas will be pumped through the adjacent co-generation plant to produce electricity.
Texaco's Gasification Process (TGP) will be used for the initial stages. TGP is a non-catalytic partial oxidation process producing syngas, which contains carbon monoxide and hydrogen from organic materials. This will be followed by Sasol's slurry phase Fischer-Tropsch (F-T) process to provide the high-quality fuel and power.
The transportation fuels produced will be in the form of ultra-clean high-cetane diesel fuel from the F-T process and contain no sulphur or aromatics. The F-T naphtha can be upgraded to clean-burning reformulated gasoline. F-T naphtha is also an excellent feedstock for steam cracking for olefin production, or as onboard reforming feed for fuel-cell powered vehicles.
PROJECT REQUIREMENTS
The project needs to be sited near a mine mouth or waste heap where there is a steady supply of the raw material run-of-mine coal. The site size will be approximately 1,500 acres. The project feedstock requirements are 12,000,000t/yr (400,000,000t over the 35-year lifetime of the project) of 10,000 BTU run-of-mine coal or coal dust waste.
The plant will also require approximately 22,000,000gal/d of water and power transmission facilities sufficient for 100MW export. Transportation links are necessary to export the chemical and fuel products.
ENVIRONMENT, EMPLOYMENT AND DEPENDENCY
The high-ash coal waste is an extremely low cost feedstock. The technology also provides an environmental benefit as it reclaims the land and eliminates the potential pollution problem of acid mine drainage into groundwater and streams that could be caused by the waste. It will also reduce emissions through ultra-clean fuels and convert low-value materials such as coal refuse efficiently to clean and valuable products as well as producing clean electricity.
The Schuylkill County region, the location of the Gilberton Coal-to-Clean Fuels and Power Project, is a severely economically depressed area. The WMPI Project will create 1,000 high paying jobs during construction, more than 150 high quality permanent jobs at the project site and approx. 600 permanent offsite jobs. The success of this project will certainly reduce dependency on foreign oil and act as a key element in President Bush's plan to help America make the transition to a hydrogen fuelled society. The environmental impact assessment for the project ran from March 2003 to November 2004 and concluded that the project showed the necessary merit.
FUTURE PROJECTS
Future potential sites for this type of project have been found in other previously coal rich states such as West Virginia (which has the potential to produce between 5,000bpd and 57,000bpd), Kentucky (57,000bpd) and Illinois (57,000bpd). Obviously the Gilberton project is still only a 'pilot' scale and depending upon success future sites will be at least ten times bigger.
http://www.hydrocarbons-technology.com/projects/co_production/
OT: Soon PEIX will be close to $20/share. I hope that when FFI releases their technology news that it is exclusive rights.
I loaded up my last shares at 0.89....I was wondering if the technicals would cross over...if that happens I might have gotten in a few cents lower, but the benefit is not that great. I would hate to have experienced it running from 0.89 to $2 just because I was too cheap to pay an extra penny.
Thanks Technoman.....
If they are on the agenda....it could be for another ethonal plant such as that 300 million gallon ethonal plant!
I clicked on the Febuary 14th, 2006 NJEDA agenda and the link does not work. Is FFI on the agenda?
bid ask is now 0.94/0.98. The last 30 minutes might be good.
Now the MM have it at 0.95/0.90.......Either way..this is a good sign of things to come. The MM are sucking as many shares off the tree as possible...however fall has already fallen and there are very few leaves left....I like that analogy Tomaotoes.
It is obvious that this is artificial too. Just like yesterday, except this volume is only 18K shares traded. This is a good sign of things to come....The market makers will do this maybe until the news comes out.
Such a wide spread to stop the volume. I am disappointed with what the market makers are doing. why do they want to slow down the volume? Does anybody think the stock will turn green today?
Technoman-I want to thank you for attending that New Jersey meeting for the bond approval in FFI. It made a big difference and made the decision a nobrainer.....
...plus there was all of the other professionals who jumped on board. Mr. Devitio (the DEAL MAKER), Mr. Marcini (BOND UNDERWRITER), JACK YOUNG (DEAL MAKER with CONNECTIONS), Mr. Mucnich (THE BEST SCIENTIST AROUND), plus we have Patrick Herda...the guy who is going to surprise us all!
The charts are perfect.....I cannot wait until tommorrow!
http://stockcharts.com/def/servlet/SC.web?c=nsol
Ready to Retire? This will allow you to become an accredited investor....so you can become SUPER RICH! Even if I am rich and financially free I would still want to make money on the side....
There is a good possibility tommorrow is the day of the disclosure! It will be a fun day!
This is predictable just like what happened yesterday, the MM are taking this down on low volume. I expect to buy additional shares tommorrow so I will be happy.
Tom-not if you want to buy a couple of thousand more shares in the next day or two......Besides this appears artifical since there is no volume.....just letting it sit at 0.90/0.91
Outlook for Biomass Ethanol Production and Demand
by Joseph DiPardo
The production of ethanol from corn is a mature technology that is not likely to see significant reductions in production costs. The ability to produce ethanol from low-cost biomass will be key to making it competitive as a gasoline additive. If Department of Energy goals are met, the cost of producing ethanol could be reduced by as much as 60 cents per gallon by 2015 with cellulosic conversion technology. This paper presents a midterm forecast for biomass ethanol production under three different technology cases for the period 2000 to 2020, based on projections developed from the Energy Information Administration’s National Energy Modeling System. An overview of cellulose conversion technology and various feedstock options and a brief history of ethanol usage in the United States are also presented.
Introduction
Ethanol has been used as fuel in the United States since at least 1908. Although early efforts to sustain a U.S. ethanol program failed, oil supply disruptions in the Middle East and environmental concerns over the use of lead as a gasoline octane booster renewed interest in ethanol in the late 1970s. Ethanol production in the United States grew from 175 million gallons in 1980 to 1.4 billion gallons in 1998, with support from Federal and State ethanol tax subsidies and the mandated use of high-oxygen gasolines.
Demand for ethanol could increase further if methyl tertiary butyl ether (MTBE) is eliminated from gasoline. In March 1999, Governor Gray Davis announced a phaseout of the use of MTBE in gasoline by 2002 in California, which uses 25 percent of the global production of MTBE.1 It is unclear, however, whether the U.S. Congress will eliminate the minimum oxygen requirement in reformulated gasoline (RFG), an action that would reduce the need for ethanol. If the oxygen requirement is eliminated, ethanol will still be valuable as an octane booster and could make up some of the lost MTBE volume.
At present, extending the volume of conventional gasoline is a significant end use for ethanol, as is its use as an oxygenate. To succeed in these markets, the cost of ethanol must be close to the wholesale price of gasoline, currently made possible by the Federal ethanol subsidy; however, the subsidy is due to expire in 2007, and although the incentive has been extended in the past, in order for ethanol to compete on its own merits the cost of producing it must be reduced substantially.
The production of ethanol from corn is a mature technology that is not likely to see significant reductions in production costs. Substantial cost reductions may be possible, however, if cellulose-based feedstocks are used instead of corn. Producers are experimenting with units equipped to convert cellulose-based feedstocks, using sulfuric acid to break down cellulose and hemicellulose into fermentable sugar. Although the process is expensive at present, advances in biotechnology could decrease conversion costs substantially. If Department of Energy goals are met, the cost of producing ethanol could be reduced by as much as 60 cents per gallon by 2015.
The ability to produce ethanol from low-cost biomass will be key to making ethanol competitive with gasoline. This analysis presents a brief overview of cellulose conversion technology and various feedstock options, followed by an examination of projected ethanol costs and gasoline prices under various technological scenarios for cellulose ethanol conversion, as well as the uncertainty of oil prices. All prices quoted in this paper are in 1998 dollars unless otherwise noted. Projections are developed from the Energy Information Administration’s National Energy Modeling System.2
Background
The use of ethanol as an automobile fuel in the United States dates as far back as 1908, to the Ford Model T. Henry Ford was a supporter of home-grown renewable fuels, and his Model T could be modified to run on either gasoline or pure alcohol.3 Ethanol was used to fuel cars well into the 1920s and 1930s as several efforts were made to sustain a U.S. ethanol program. Standard Oil marketed a 25-percent ethanol by volume gasoline in the 1920s in the Baltimore area.
Ford and others continued to promote the use of ethanol, and by 1938 an alcohol plant in Atchison, Kansas, was producing 18 million gallons of ethanol a year, supplying more than 2,000 service stations in the Midwest.4 By the 1940s, however, efforts to sustain the U.S. ethanol program had failed. After World War II, there was little interest in the use of agricultural crops to produce liquid fuels. Fuels from petroleum and natural gas became available in large quantities at low cost, eliminating the economic incentives for production of liquid fuels from crops. Federal officials quickly lost interest in alcohol fuel production, and many of the wartime distilleries were dismantled. Others were converted to beverage alcohol plants.5
Interest in ethanol was renewed in the 1970s, when oil supply disruptions in the Middle East became a national security issue and America began to phase out lead (an octane booster) from gasoline. The American Oil Company and several other major oil companies began to market ethanol as a gasoline volume extender and as an octane booster.6 Ethanol was blended directly into gasoline in a mix of 10 percent ethanol and 90 percent gasoline, called gasohol. In 1978, Congress approved the National Energy Act, which included a Federal tax exemption for gasoline containing 10 percent alcohol.7 The Federal subsidy reduced the cost of ethanol to around the wholesale price of gasoline, making it economically viable as a gasoline blending component. The growth of ethanol was enhanced substantially by State tax incentives to ethanol producers. By 1980, 25 States had exempted ethanol from all or part of their gasoline excise taxes in order to promote consumption.8 Ethanol production jumped from just over 10 million gallons in 1979 to 175 million gallons in 1980.9 Federal and State tax incentives made ethanol economically attractive in the Midwest, but the difficulty and high cost of transporting ethanol precluded consumption in other markets.
Since 1980, ethanol has enjoyed considerable success. U.S. production has grown by about 12 percent per year, reaching 1.4 billion gallons in 1998 (Figure 1). U.S. gasoline consumption in 1998 was approximately 120 billion gallons. The ethanol program received a boost from Congress in 1990 with the passage of the Clean Air Act Amendments (CAAA90). Congress mandated the use of oxygenated fuels (with a minimum of 2.7 percent oxygen by volume) in specific regions of the United States during the winter months to reduce carbon monoxide. The two most common methods to increase the oxygen level of gasoline are blending with MTBE and blending with ethanol. Because ethanol has a higher oxygen content than MTBE, only about half the volume is required to produce the same oxygen level in gasoline. This allows ethanol, typically more expensive than MTBE, to compete favorably with MTBE for the wintertime oxygenate market. Unfortunately, ethanol’s high volatility, measured by Reid vapor pressure (Rvp), limits its use in hot weather, where evaporative emissions can contribute to ozone formation. Nevertheless, ethanol’s expanded role as a clean-air additive has allowed it to penetrate markets outside the Midwest (Figure 2).
Figure 1. U.S. Fuel Ethanol Production, 1980-1998
Figure 2. Regional Percentages of Total U.S. Ethanol Consumption, 1990 and 1996
Although most ethanol consumption is in conventional gasoline engines, which are limited to a 10-percent ethanol blend (E10), there is also some demand for ethanol blended in higher concentrations, such as E85 (85 percent ethanol, 15 percent gasoline). E85 vehicles are currently in use as government fleet vehicles, flexible-fuel passenger vehicles, and urban transit buses. Demand for ethanol in E85 has grown from 144,000 gallons in 1992 to 2 million gallons in 1998. Most E85 use falls under government mandates to use alternative fuels. Ethanol does not compete directly with gasoline, even at comparable costs, because its energy (Btu) content is lower than that of gasoline. It takes approximately 1.5 gallons of ethanol do deliver the same mileage as 1 gallon of gasoline.
Ethanol use is also being expanded to multi-component fuel systems. P-series fuels, created by Pure Energy Corp., are blends of ethanol, methyltetrahydrofuran (MTHF), natural gas liquids, and in some cases butane to meet cold-start requirements.10 Pure Energy is also developing a new fuel called OxyDiesel, composed of 80 percent diesel fuel, 15 percent ethanol, and 5 percent blending agent to raise cetane levels.11 The company has developed an additive system to prevent water absorption for a stable ethanol-diesel mixture that can be shipped through a pipeline.12 Currently, fuels blended with ethanol cannot be shipped in multifuel pipelines, because the moisture in pipelines and storage tanks is absorbed by the ethanol, causing it to separate from gasoline. Rather, the petroleum-based gasoline components have to be shipped separately and then blended with ethanol at a terminal as the product is loaded into trucks.
The demand for ethanol could increase if MTBE were eliminated from gasoline. MTBE (in addition to its use in high oxygen fuels) is widely used as a year-round gasoline additive for RFG to meet the legislated requirement for 2.0 percent oxygen by weight. The use of MTBE has recently been questioned, however, because traces of the additive have been found in 5 to 10 percent of the drinking water supplies in areas using RFG. In 1999, concerns about water quality resulted in the announcement of a State-wide phaseout of MTBE by the Governor of California, as well as numerous legislative proposals at both the State and Federal levels aimed at reducing or eliminating the use of MTBE in gasoline. Ethanol would be the leading candidate to replace MTBE, although it is not without its drawbacks. Compared with MTBE, ethanol use results in higher evaporative emissions of smog-forming volatile organic compounds (VOCs), requiring refiners to remove other gasoline components such as pentanes or butanes to meet the Rvp limits set by the U.S. Environmental Protection Agency (EPA).
Logistics is also an issue for ethanol use. At present, ethanol supplies come primarily from the Midwest, where the majority of ethanol is produced from corn feedstocks. Downstream Alternatives, Inc., has analyzed the logistics of supplying ethanol to California, in a study for the Renewable Fuels Association.13 The analysis found that, because of the distances involved, the only viable alternatives for transporting ethanol to California would be rail shipments or marine cargoes. Rail shipment would be required for ethanol plants that are landlocked. In addition, small plants (less than 80 millions gallons production capacity) would not be likely to ship by marine cargo, which requires large shipment volumes. Rail transit times from Midwest ethanol plants to California can range from 2 to 3 weeks, with typical costs of 14 to 17 cents per gallon, depending on the plant of origin and the market destination.
Larger ethanol plants located on the water would have the option to ship waterborne cargoes. Product would be shipped down the Mississippi via barge and then staged at a terminal in New Orleans until sufficient quantities of ethanol were accumulated for shipment. The ethanol would then be shipped south through the Panama Canal and north to California ports. The entire process would take a minimum of 34 days, and the costs would be nearly the same as the costs for rail shipments. In both cases, the ethanol would then have to be transported from a rail or marine terminal by truck to a final destination terminal before blending into gasoline. In addition, some terminals would need to make modifications to offer ethanol even if tankage were adequate to accommodate ethanol blending.
The cost of producing and transporting ethanol will continue to limit its use as a renewable fuel. Ethanol relies heavily on Federal and State subsidies to remain economically viable as a gasoline blending component. The current Federal subsidy, at 54 cents per gallon, makes it possible for ethanol to compete as a gasoline additive. Corn prices are the dominant cost factor in ethanol production, and ethanol supply is extremely sensitive to corn prices, as was seen in 1996. Ethanol production dropped sharply in mid-1996 (Figure 3), when late planting due to wet conditions resulted in short corn supplies and higher prices.14
Figure 3. Change in U.S. Corn Price and Ethanol Production From 1995 to1996
Substantial reductions in ethanol production costs may be made possible by replacing corn with less expensive cellulose-based feedstocks. Cellulosic feedstocks include agricultural wastes, grasses and woods, and other low-value biomass such as municipal waste. Although cellulosic materials are less expensive than corn, they are more costly to convert to ethanol because of the extensive processing required. Cellulase enzymes (used to convert cellulose to sugar) at $0.45 per gallon of ethanol are currently too expensive for commercial use. Current technology, however, could reduce the cost of enzymes to less than $0.10 per gallon of ethanol if a sufficient market develops.15 Advances in biotechnology could lower costs further by allowing fermentation of the nonglucose sugars produced in the hydrolysis of cellulose using genetically engineered bacteria. If Department of Energy goals are met, the cost of producing ethanol could be reduced by as much as 60 cents per gallon by 2015.16 Currently, the cost of producing ethanol from cellulose is estimated to be between $1.15 and $1.43 per gallon in 1998 dollars.17
Technology
Ethanol is produced from the fermentation of sugar by enzymes produced from specific varieties of yeast. The five major sugars are the five-carbon xylose and arabinose and the six-carbon glucose, galactose, and mannose.18 Traditional fermentation processes rely on yeasts that convert six-carbon sugars to ethanol. Glucose, the preferred form of sugar for fermentation, is contained in both carbohydrates and cellulose. Because carbohydrates are easier than cellulose to convert to glucose, the majority of ethanol currently produced in the United States is made from corn, which produces large quantities of carbohydrates.19 Also, the organisms and enzymes for carbohydrate conversion and glucose fermentation on a commercial scale are readily available.
The conversion of cellulosic biomass to ethanol parallels the corn conversion process. The cellulose must first be converted to sugars by hydrolysis and then fermented to produce ethanol (Figure 4). Cellulosic feedstocks (composed of cellulose and hemicellulose) are more difficult to convert to sugar than are carbohydrates. Two common methods for converting cellulose to sugar are dilute acid hydrolysis and concentrated acid hydrolysis, both of which use sulfuric acid. Dilute acid hydrolysis occurs in two stages to take advantage of the differences between hemicellulose and cellulose. The first stage is performed at low temperature to maximize the yield from the hemicellulose, and the second, higher temperature stage is optimized for hydrolysis of the cellulose portion of the feedstock. Concentrated acid hydrolysis uses a dilute acid pretreatment to separate the hemicellulose and cellulose. The biomass is then dried before the addition of the concentrated sulfuric acid. Water is added to dilute the acid and then heated to release the sugars, producing a gel that can be separated from residual solids. Column chromatographic is used to separate the acid from the sugars.20
Figure 4. Ethanol Production From Corn and Cellulose
Both the dilute and concentrated acid processes have several drawbacks. Dilute acid hydrolysis of cellulose tends to yield a large amount of byproducts. Concentrated acid hydrolysis forms fewer byproducts, but for economic reasons the acid must be recycled. The separation and reconcentration of the sulfuric acid adds more complexity to the process. In addition, sulfuric acid is highly corrosive and difficult to handle. The concentrated and dilute sulfuric acid processes are performed at high temperatures (100 and 220oC) which can degrade the sugars, reducing the carbon source and ultimately lowering the ethanol yield.21 Thus, the concentrated acid process has a smaller potential for cost reductions from process improvements. The National Renewable Energy Laboratory (NREL) estimates that the cumulative impact of improvements in acid recovery and sugar yield for the concentrated acid process could provide savings of 14 cents per gallon, whereas process improvements for the dilute acid technology could save around 19 cents per gallon.
A new approach under consideration is countercurrent hydrolysis. Countercurrent hydrolysis is a two stage process. In the first stage, cellulose feedstock is introduced to a horizontal co-current reactor with a conveyor. Steam is added to raise the temperature to 180oC (no acid is added at this point). After a residence time of about 8 minutes, during which some 60 percent of the hemicellulose is hydrolyzed, the feed exits the reactor. It then enters the second stage through a vertical reactor operated at 225oC. Very dilute sulfuric acid is added to the feed at this stage, where virtually all of the remaining hemicellulose and, depending on the residence time, anywhere from 60 percent to all of the cellulose is hydrolyzed. The countercurrent hydrolysis process offers more potential for cost reductions than the dilute sulfuric acid process. NREL estimates this process may allow an increase in glucose yields to 84 percent, an increase in fermentation temperature to 55oC, and an increase in fermentation yield of ethanol to 95 percent, with potential cumulative production cost savings of about 33 cents per gallon.22
The greatest potential for ethanol production from biomass, however, lies in enzymatic hydrolysis of cellulose. The enzyme cellulase, now used in the textile industry to stone wash denim and in detergents, simply replaces the sulfuric acid in the hydrolysis step. The cellulase can be used at lower temperatures, 30 to 50oC, which reduces the degradation of the sugars.23 In addition, process improvements now allow simultaneous saccharification and fermentation (SSF). In the SSF process, cellulase and fermenting yeast are combined, so that as sugars are produced, the fermentative organisms convert them to ethanol in the same step. In the long term, enzyme technology is expected to have the biggest payoff. NREL estimates that future cost reductions could be four times greater for the enzyme process than for the concentrated acid process and three time greater than for the dilute acid process.24 Achieving such cost reductions would require substantial reductions in the current cost of producing cellulase enzymes and increased yield in the conversion of nonglucose sugars to ethanol.
Once the hydrolysis of the cellulose is achieved, the resulting sugars must be fermented to produce ethanol. In addition to glucose, hydrolysis produces other six-carbon sugars from cellulose and five-carbon sugars from hemicellulose that are not readily fermented to ethanol by naturally occurring organisms. They can be converted to ethanol by genetically engineered yeasts that are currently available, but the ethanol yields are not sufficient to make the process economically attractive. It also remains to be seen whether the yeasts can be made hardy enough for production of ethanol on a commercial scale.25
The concentrated acid and dilute acid processes have been targeted for near-term deployment because of their maturity. BC International is building a facility in Louisiana that is designed to convert bagasse (sugarcane residue) into ethanol by the dilute sulfuric acid process, although its long-term plan is to convert the plant to an enzyme process. Masada Resource Group is planning to locate a municipal solid waste (MSW) to ethanol plant in New York using the concentrated acid hydrolysis process, which may be better suited than enzymes to heterogeneous cellulose sources (such as MSW). Arkenol is working to establish a commercial facility in Sacramento, California, to convert rice straw to ethanol, also using the concentrated acid hydrolysis process.26
Feedstock
A large variety of feedstocks are currently available for producing ethanol from cellulosic biomass. The materials being considered can be categorized as agricultural waste, forest residue, MSW, and energy crops. Agricultural waste available for ethanol conversion includes crop residues such as wheat straw, corn stover (leaves, stalks, and cobs), rice straw, and bagasse (sugar cane waste). Forestry waste includes underutilized wood and logging residues; rough, rotten, and salvable dead wood; and excess saplings and small trees. MSW contains some cellulosic materials, such as paper. Energy crops, developed and grown specifically for fuel, include fast-growing trees, shrubs, and grasses such as hybrid poplars, willows, and switchgrass.27
Although the choice of feedstock for ethanol conversion is largely a cost issue, feedstock selection has also focused on environmental issues. Materials normally targeted for disposal include forest thinnings collected as part of an effort to improve forest health, MSW, and certain agricultural residues, such as rice straw. Although forest residues are not large in volume, they represent an opportunity to decrease the fire hazard associated with the dead wood present in many National Forests. Small quantities of forest thinnings can be collected at relatively low cost, but collection costs rise rapidly as quantities increase.
An issue of particular concern in California is the disposal of residue from rice crops. Traditionally, rice straw has been burned, but that practice is being phased out under California law. California’s recent ban on MTBE, coupled with its forests and rice crop, provides an ideal opportunity for biomass ethanol production. BC International is developing two such projects: the Collins Pine Ethanol Project, a 23 million gallon per year plant using forest thinnings and wood wastes as feedstock, and the Gridley Ethanol Project, a 20 million gallon per year ethanol plant using rice straw as its primary feedstock.28 In addition, as mentioned above, Arkenol is working on a commercial facility in Sacramento, using rice straw as a feedstock.
Agricultural residues, in particular corn stover, represent a tremendous resource base for biomass ethanol production. Agricultural residues, in the long term, would be the sources of biomass that could support substantial growth of the ethanol industry. At conversion yields of around 60 to 100 gallons per dry ton, the available corn stover inventory would be sufficient to support 7 to 12 billion gallons of ethanol production per year,29 as compared with approximately 1.4 billion gallons of ethanol production from corn in 1998. However, the U.S. Department of Agriculture (USDA) and other appropriate entities must undertake rigorous research on the environmental effects of large-scale removal of crop residues.
The cost of agricultural residues is not nearly as sensitive to supply as is the cost of forest residues, although the availability of corn stover could be affected by a poor crop year. The relatively low rise in cost as a function of feedstock use is due to the relatively high density of material available that does not involve competition for farmland. In addition, the feedstock is located in the corn-processing belt, an area that has an established infrastructure for collecting and transporting agricultural materials. It is also located near existing grain ethanol plants, which could be expanded to produce ethanol from stover.30 Initially, locally available labor and residue collection equipment might have to be supplemented with labor and equipment brought in from other locations for residue harvesting and storage operations, if the plants involved are of sufficient scale. Eventually, however, when the local collection infrastructure has been built up, costs would come down.
Dedicated energy crops such as switchgrass, hybrid willow, and hybrid poplar are another long-term feedstock option. Switchgrass is grown on a 10-year crop rotation basis, and harvest can begin in year 1 in some locations and year 2 in others. Willows require a 22-year rotation, with the first harvest in year 4 and subsequent harvests every 3 years thereafter. Hybrid poplar requires 6 years to reach harvest age in the Pacific Northwest, 8 years in the Southeast, Southern Plains, and South Central regions, and 10 years in the Corn Belt, Lake States, Northeast and Northern Plains regions. Thus, if it were planted in the spring of 2000, switchgrass could be harvested in 2000 or 2001, willow could be harvested in 2004, and poplars could be harvested in 2006, 2008, or 2010, depending on the region.
The use of cellulosic biomass in the production of ethanol also has environmental benefits. Converting cellulose to ethanol increases the net energy balance of ethanol compared to converting corn to ethanol. The net energy balance is calculated by subtracting the energy required to produce a gallon of ethanol from the energy contained in a gallon of ethanol (approximately 76,000 Btu). Corn-based ethanol has a net energy balance of 20,000 to 25,000 Btu per gallon, whereas cellulosic ethanol has a net energy balance of more than 60,000 Btu per gallon.31 In addition, cellulosic ethanol use can reduce greenhouse gas emissions. Argonne National Laboratory estimates that a 2-percent reduction in greenhouse gas emissions per vehicle mile traveled is achieved when corn-based ethanol is used in gasohol (E10), and that a 24- to 26-percent reduction is achieved when it is used in E85. Cellulosic ethanol can produce an 8- to 10-percent reduction in greenhouse gas emissions when used in E10 and a 68- to 91-percent reduction when used in E85.32
Forecast
The National Energy Modeling System (NEMS) was used to analyze the potential for cellulose-based ethanol production under various technological scenarios, assuming either a continuation of the Federal ethanol subsidy through 2020 or expiration of the subsidy in 2008. NEMS is a computer-based modeling system of U.S. energy markets for the midterm period of 1998 to 2020. NEMS projects the production, imports, conversion, consumption, and prices of energy, subject to assumptions on macroeconomic and financial factors, world energy markets, resource availability and costs, behavioral and technological choice criteria, cost and performance characteristics of energy technologies, and demographics. The Petroleum Market Model (PMM), a submodule of NEMS, is a linear programming representation of refining. It represents the pricing of petroleum products and crude oil, product import activity, and domestic refinery operations, subject to the demand for petroleum products, the prices of raw material inputs and imported petroleum products, the costs of investment, and the domestic production of crude oil and natural gas liquids.
The PMM includes an ethanol supply function that provides the linear program with supply curves for corn- and cellulose-based ethanol, allowing the PMM to project transportation ethanol supply throughout the NEMS forecast period. The ethanol model provides prices in the form of annual price-quantity curves. The curves, derived from an ethanol production cost function, represent the prices of ethanol at which associated quantities of transportation ethanol are expected to be available for production of E85 and ethyl tertiary butyl ether (ETBE), and for blending with gasoline.
The three PMM petroleum product supply regions are derived from the Petroleum Administration for Defense Districts (PADDs) as follows: region 1 represents PADD I, region 2 is an aggregate of PADDs II, III, and IV, and region 3 represents PADD V (Figure 5). The PMM demand regions are the nine U.S. Census divisions (Figure 6). Ethanol supply regions are also aggregated by Census division. The majority of ethanol supply derived from corn33 is located in Census divisions 3 and 4, with smaller amounts in divisions 6, 8, and 9, representing current supply. Cellulosic ethanol supplies become available in 2001 in Census divisions 2 and 7 at demonstration levels, and the majority of the projected growth (beginning in 2003) is in divisions 3, 4, and 9.
Figure 5. Petroleum Administration for Defense Districts (PADDs)
Figure 6. U.S. Census Divisions
The largest growth in cellulose ethanol production is projected for Census divisions 3 and 4, the corn belt, where a tremendous supply of corn stover exists, as well as an established infrastructure for collecting and transporting agricultural materials. Census division 9 (mainly California) is projected to be the next largest producer of cellulose ethanol. It is assumed that ethanol will replace MTBE as the oxygenate for reformulated gasoline in California when the ban on MTBE takes effect in 2003, significantly increasing demand in the region. California’s vast agricultural resources could sustain a cellulose ethanol industry of about 3 billion gallons per year.34
The NEMS model was used to project potential biomass ethanol production in three different technological scenarios. The scenarios are based on the technologies described above and their associated cost savings potential. A reference case, similar to the Annual Energy Outlook 2000 (AEO2000) reference case,35 a high technology case, and a low technology case were examined. In addition, the effectiveness of the cost reductions projected by NREL was measured by the competitiveness of cellulose ethanol in the absence of the Federal subsidy.
The Federal Highway Bill of 1998 extended the current tax credit for ethanol through 2007 but stipulated reductions from the current 54 cents per gallon to 53 cents in 2001, 52 cents in 2003, and 51 cents in 2005. Although gasoline tax and tax credit provisions include “sunset” clauses that limit their duration, they have been extended historically. Therefore, a NEMS model assumption for AEO2000 was that the Federal subsidy would be extended at 51 cents per gallon through 2020.
State subsidies were also modeled in NEMS. While some ethanol-producing States do not subsidize ethanol, others offer tax incentives for gasoline blended with ethanol and for ethanol production, which vary from $0.10 to $0.40 per gallon (in nominal dollars). For modeling purposes, a volume-weighted average of $0.10 per gallon was used for corn-based ethanol in Census divisions 3 and 4.
The three technological simulations were run under two conditions to determine whether and at what price cellulose ethanol could remain competitive without the benefit of the Federal subsidy. Condition one extends the Federal subsidy at 51 cents per gallon through 2020, and condition two discontinues the subsidy in 2008.
Assumptions
Feedstock
The ethanol model uses a process costing approach to model the impacts of net feedstock production costs plus capital and operating costs associated with converting feedstock to ethanol. Corn feedstock prices were derived from USDA projections for the prices of corn and corn coproducts.36 Feedstock costs were calculated by subtracting the price of corn coproducts of wet and dry milling from the price of corn. Coproducts of wet milling were limited to corn gluten feed, corn gluten meal, and corn oil. Coproducts of dry milling consisted of distillers dried grains. USDA data were also used to vary corn and co-product prices as a function of ethanol demand. A study by Price et al.37 simulates the changes in production and consumption of major crops that would be caused by a change in corn ethanol production.
Cellulosic feedstock supply and prices are modeled in the NEMS Renewable Fuels Module.38 Biomass supply for ethanol competes with captive and noncaptive biomass markets. Captive markets pertain to users with dedicated biomass supplies who burn byproducts resulting from the manufacturing process. The noncaptive market includes the commercial, electric utility, transportation, and industrial sectors. The model calculates a supply schedule for each Census division, which defines the quantity and cost relationships of biomass resources accessible to all noncaptive consumers.
Biomass resources in the Renewable Fuels Module are an aggregation of forest products, wood wastes, crop residues, and energy crops. The forest products data were developed from U.S. Forest Service data,39 wood residue data were assembled from State and regional agency reports by Antares Group, Inc.,40 and crop residue data were developed by Oak Ridge National Laboratory.41 Separate data for energy crops were compiled from an Oak Ridge National Laboratory database42 for each model year, 2010-2020, and added to the sum from the three other categories. The maximum share of cultivated cropland that would be used for energy crops was about 10 percent. A resource-related cost adjustment factor was also imposed to treat competing uses of the resource. For example, land could be used for other fiber or food crops, or the wood could be used for construction, at alternate prices. Figure 7 illustrates the composite U.S. total supply curve in 2010 for the first 50 million dry tons of biomass.
Figure 7. U.S. Composite Biomass Supply Curve, 2010
Technology/Costs
Conversion plant process costs (capital and operating) were assumed to be independent of production quantities. Plant size was considered in the overall cost of production, but it was assumed that savings from economies of scale would be offset by increased costs for feedstock collection.43 The operating costs (exclusive of energy) and capital costs for corn feedstocks44 were assumed to be constant over time. The amount of energy required to convert corn to ethanol, taken from Wang,45 was assumed to decrease linearly over time. Prices for coal and natural gas consumed during the conversion process were provided from the NEMS Coal Market Module and Natural Gas Transmission and Distribution Module, respectively. Total corn ethanol cost in the model was computed to be approximately $1.10 per gallon in 2000. The conversion and capital cost data for cellulose, derived from Wooley et al.,46 were assumed to decrease over time at rates that varied across the technological scenarios. Wooley estimates production costs for a plant with a capacity of 2,000 tons per day (approximately 50 million gallons of ethanol) at $0.77 to $1.04 per gallon. An average of $0.91 per gallon was assumed as the initial cost for year 2000, resulting in a total cost for cellulosic ethanol production of approximately $1.29 per gallon. All costs are given in 1998 dollars.
The methods of ethanol conversion assumed for this forecast varied across technological scenarios and were chosen according to their potential for cost reduction. Cumulative cost savings as a result of process improvements were based on NREL projections for each technology,47 calculated from a base conversion cost of $0.91 per gallon. Currently, there are several projects underway to produce ethanol from cellulose using either concentrated or dilute sulfuric acid hydrolysis technology. The low technology case assumed that the technology would continue to be used throughout the forecast period, and that process improvements would provide cost savings of 16 cents per gallon of ethanol by 2015. The countercurrent hydrolysis approach was chosen for the reference case technology. The countercurrent process improves on the dilute acid process, providing potential production cost savings of 30 cents per gallon of ethanol by 2015. The most advanced conversion process, with the greatest potential for cost reduction, is the enzymatic hydrolysis process. This process was assumed for the high technology case, with production cost savings of 60 cents per gallon of ethanol by 2015. Figure 8 compares ethanol price projections in the three technology cases with motor gasoline prices in the reference, low, and high world oil price cases.
Figure 8. Ethanol and Motor Gasoline Prices at the Terminal, 2000-2020
Capacity
An important modeling consideration for the forecast of ethanol production from cellulose is the rate of capacity growth over the forecast period. Capacity expansion rates were projected using an algorithm derived from the Mansfield and Blackman statistical models of new technology market penetration. Mansfield48 investigated the factors that cause an innovation to spread through an industry. He examined the rate of substitution between time periods t and t+1 and hypothesized that the proportion of firms at time t that introduce the innovation by time t+1 is a function of: (1) the proportion of firms that have already introduced it at time t, (2) the profitability of the innovation relative to other investments, and (3) the size of the investment required to install the technology. He developed a deterministic model and fitted and tested it against data for 12 innovations in 4 industries.
Mansfield’s assumptions in functional notation are given by:
[n(t+1) - n(t)]/[N - n(t)] = f(B, S, n(t)/N) ,
where
N = the total number of firms that may adopt the innovation,
n(t) = the total number of firms that have adopted the innovation by time t,
B = profitability of the innovation relative to other investments, and
S = the size of the investment needed to install the technology.
Mansfield then takes the first nonconstant term of the Taylor’s expansion for f to rewrite the hypothesis as a differential equation:
dn(t)/dt = 2 n(t)/N [N - n(t)] ,
where the constant, 2, consists of the terms
2 = Z + a1 B + a2S.
Mansfield assumes, because of the limited number of innovations, that the coefficients of profitability and investment are constant over industries. The average payout period required by the firms to justify investments divided by the average payout period for the innovation is used as a measure of B. To measure S, he uses the average initial investment in the innovation as a percentage of the average total assets of the firms. Using these data, he obtains a least squares estimate of the parameters, resulting in the equation:
2 = Z + 0.53 B - 0.027 S (r = 0.997) ,
(0.015) (0.014)
where the constants for the four industries (Z) are: -0.57 (coal mining), -0.52 (iron and steel), -0.59 (railroads), and -0.29 (brewing).
In his followup work, Blackman49 revised the model so that the extent of substitution was defined in terms of market share captured by the new technology rather than in terms of the cumulative number of firms employing the innovation. He applied the model to describe innovations dynamics in the commercial jet engine market and in the electrical utility and automotive sectors.
Blackman’s market share formulation is given by:
N(t) = 1 / [1 + exp(-k - 2t)] ,
where
N(t) = market share of new product, and
k = constant determined by initial conditions.
In the absence of historical data, Blackman suggested the use of an Innovation Index to estimate Z. The Innovation Index measures the relative propensity toward innovation in various industrial sectors of the U.S. economy. The index is derived from input variables that reflect the extent to which resources are allocated to achieve innovation in selected industrial sectors and output variables that measure the extent to which new product and process innovation is achieved. Blackman hypothesized that a relationship might exist between the value of Z for an industrial sector and the value of the Innovation Index for that sector. The hypothesis was tested using Z values from the steel, food and kindred products, aerospace, automotive, and electrical machinery sectors. The following regression equation was obtained:
Z = 0.2221 I - 0.3165 (r = 0.92) ,
(0.0645)
where
I = the industry-specific Innovation Index.
Blackman computed the Innovation Index for 12 industrial sectors (Table 1). A positive Innovation Index indicates a strong tendency for an industry to innovate; a negative value indicates a weaker tendency for innovation.
Table 1. Innovation Index for Twelve Industrial Sectors
Blackman’s market share equation was used in NEMS to predict the rate of capacity expansion of cellulosic ethanol production. The cellulosic ethanol production capacity in year t is equal to the share of the market achieved in that year, N(t), times the total potential market for ethanol. The total ethanol market is defined as the sum of the potential gasohol market (10 percent blending of all traditional gasoline), the RFG oxygenate market, and the wintertime oxygenated gasoline market (approximately 12 billion gallons). The market penetration algorithm begins when the market share has reached 3 percent of the total market.
The constant k was determined from the initial condition; that is, at t0 = 0, the market share N(t0) = 0.03. An initial growth rate of 12 percent per year (the approximate growth rate of corn-based ethanol production) was used to reach the 3-percent market penetration threshold. The parameters I, B, and S were assumed to vary across technological scenarios. The range for I was selected around the petroleum industry index (-0.64). The profitability index B increased from the low technology to the high technology case, reflecting the reduced costs of ethanol production. Profitability also varied across Census division, being highest in Census division 9. Several factors led to this decision. It was assumed that ethanol would be the oxygenate to replace MTBE in California RFG, creating a large increase in demand (over 550 million gallons in 2003) in the high-value RFG market. Census divisions 3 and 4 supply the Midwestern gasohol market, a lower value product, and the East Coast market, where the cost of transporting ethanol would further reduce profitability. The size of investment, S, is the relative size of the investment as a fraction of the total value of the firm. The low technology case uses a 50-percent fraction, implying high risk. The reference case uses 25 percent of the firm’s value, and the high technology case uses 10 percent. The parameter values assumed for the forecast are summarized in Table 2.
Table 2. Blackman-Mansfield Parameter Values
Results Federal Subsidy Extended to 2020
Benefitting from the assumed continuation of the Federal ethanol subsidy, gasoline blending of ethanol (in gasohol and RFG) is projected to increase by 1.4 percent per year from 2000 to 2020 in the reference case (Figure 9). Total U.S. cellulose ethanol production is projected to increase by 22 percent per year, reaching 850 million gallons by 2020 (Figure 10). Because cellulosic ethanol production capacity in Census division 9 does not grow sufficiently to meet California RFG demand, supplies of ethanol from the Midwest are needed to meet demand in Census division 9.
Figure 9. Projected Motor Gasoline Blending With Ethanol, 2000-2020
In the high technology case, more rapid market penetration of cellulosic ethanol is projected, resulting in 4.0-percent annual growth in gasoline blending. Cellulose ethanol production grows by 30 percent per year, reaching 2.8 billion gallons by 2020 (Figure 10). In the low technology case, production costs limit the growth of biomass ethanol production in the Midwest; however, biomass ethanol produced in Census division 9 competes favorably with corn-based supplies from the Midwest because of the cost of transportation. U.S. production of biomass ethanol grows to 347 million gallons by 2020 in the low technology case. Production in the reference and high technology cases is limited only by assumptions on capacity expansion, indicating that ethanol from biomass is economically competitive in both cases. In the low technology case, nearly all the projected production is a result of the model requirement for ethanol blending in E85 and California RFG.
Figure 10. Projected Biomass Ethanol Production, 2000-2020
Federal Subsidy Eliminated in 2008
When the Federal ethanol subsidy is assumed to be eliminated in 2008, gasohol and RFG blending with ethanol ceases in all three technology cases. Biomass ethanol production still is projected to grow in the reference and high technology cases, however, replacing the more expensive corn ethanol to meet California RFG and E85 demand. (A NEMS model assumption for this study was that demand for E85 would remain fixed and that RFG oxygenate demand in California would be met with ethanol.) In the low technology case, the projected growth of biomass ethanol production is similar under the subsidy extension and subsidy elimination assumptions, occurring only in Census division 9 to meet the required California RFG demand. Conventional gasoline blending of ethanol is projected to resume in the high technology case by 2018, when capacity begins to exceed the required demand for ethanol in RFG and E85.
An alternative high technology case with capacity limited only by feedstock availability was also run, to determine the price at which blending of ethanol with conventional gasoline would occur without the benefit of a Federal subsidy. In this case, gasoline blending is projected to resume in 2010 in Census divisions 3 and 4 (Midwest), when the cost of cellulose ethanol drops to $0.82 per gallon. Ethanol begins to penetrate other markets in 2014, when costs fall to $0.68 per gallon.
Interestingly, the value of ethanol varies depending on how it is blended with gasoline. The marginal value of ethanol is higher in the projections when it is used as an oxygenate for RFG than when it is used as a volume extender. The projected marginal value of ethanol increases by $0.04 per gallon in Census division 3 and by $0.13 per gallon in Census division 9 when RFG blending begins in 2003 (Figure 11). Ethanol is also used as an oxygenate for wintertime fuels in areas that mandate the use of high oxygen (2.7 percent) fuels. Although ethanol is more expensive, it competes favorably with MTBE because it can provide the 2.7 percent oxygen requirement with only about 50 percent of the volume of MTBE. The NEMS model projects that ethanol will maintain its wintertime market share in high oxygen gasoline even in the absence of the Federal subsidy.
Figure 11. Marginal Value of Ethanol With and Without RFG Blending
Conclusion
Ethanol has enjoyed some success as a renewable fuel, primarily as a gasoline volume extender and also as an oxygenate for high-oxygen fuels, an oxygenate in RFG in some markets, and potentially as a fuel in flexible-fuel vehicles. A large part of its success has been the Federal ethanol subsidy. With the subsidy due to expire in 2008, however, it is not clear whether ethanol will continue to receive political support. Thus, the future of ethanol may depend on whether it can compete with crude oil on its own merits.
Ethanol costs could be reduced dramatically if efforts to produce ethanol from biomass are successful. Biomass feedstocks, including forest residue, agricultural residue, and energy crops, are abundant and relatively inexpensive, and they are expected to lower the cost of producing ethanol and provide stability to supply and price. In addition, the use of corn stover would lend continued support to the U.S. corn industry. Analysis of NREL technological goals for cellulose ethanol conversion suggests that ethanol could compete favorably with other gasoline additives without the benefit of a Federal subsidy if the goals were achieved. Enzymatic hydrolysis of cellulose appears to have the most potential for achieving the goals, but substantial reductions in the cost of producing cellulase enzymes and improvements in the fermentation of nonglucose sugars to ethanol still are needed.
The ban on MTBE in California could provide additional incentives for the development of cellulose-based ethanol. If ethanol were used to replace MTBE in Federal RFG, demand for ethanol in California would increase by more than 550 million gallons per year. California has vast biomass resources that could support the additional demand. In addition, the cost of transporting Midwest ethanol would allow cellulosic ethanol to compete favorably in the market. Ultimately, ethanol’s future in RFG could depend on whether Congress eliminates the minimum oxygen requirement included in the CAAA90. Without the minimum oxygen requirement, refiners would have more flexibility to meet RFG specifications with blending alternatives, such as alkylates, depending on an individual refinery’s configuration and market conditions. Ethanol would still be valuable as an octane booster, however, and could make up for some of the lost volume of MTBE.
Significant barriers to the success of cellulose-derived ethanol remain. For example, it may be difficult to create strains of genetically engineered yeast that are hardy enough to be used for ethanol production on a commercial scale. In addition, genetically modified organisms may have to be strictly contained. Other issues include the cost and mechanical difficulties associated with processing large amounts of wet solids. Proponents of biomass ethanol remain confident, however, that the process will succeed and low-cost ethanol will become a reality.
http://www.eia.doe.gov/oiaf/analysispaper/biomass.html
Ready for some IRANIAN WAR!
Iran Threatens Full-Scale Enrichment Work By GEORGE JAHN, Associated Press Writer
1 hour, 45 minutes ago
VIENNA, Austria - Iran threatened to retaliate Thursday in the face of almost certain referral to the U.N. Security Council for its nuclear activities, and the head of the International Atomic Energy Agency said the dispute was "reaching a critical phase."
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Ahead of a decision by the IAEA's 35-nation board, U.S. and European delegates turned to behind-the-scenes diplomacy to build the broadest possible support for reporting Iran to the council over concerns it is seeking nuclear weapons.
Cuba, Venezuela, Syria and a few other nations at odds with Washington remained opposed. India was said to be leaning toward supporting referral.
Diplomats accredited to the meeting said backing for Iran had shrunk among the U.N. nuclear watchdog's board since Russia and China swung their support behind referral at an overnight meeting with the United States, France and Britain — the other three permanent council members — that started Monday.
"There's a solid majority in favor of reporting," Gregory L. Schulte, the chief U.S. delegate to the IAEA, told The Associated Press. "There's even a more solid majority after Monday."
State Department spokesman Sean McCormack the number of nations expected to vote against referral were in the "low to single digits."
Iran remained defiant. In a last-minute warning, Tehran's chief nuclear negotiator told IAEA chief Mohamed ElBaradei that his country would severely curtail agency inspections and resume uranium enrichment if reported to the council.
Ali Larijani, in a letter made available to the AP, said referral would leave Iran no choice but "to suspend all the voluntary measures and extra cooperation" with the IAEA — shorthand for reducing IAEA monitoring to a minimum.
Furthermore, "all the peaceful nuclear activities being under voluntary suspension would be resumed without any restriction," said the letter, suggesting a resumption of work on full-scale uranium enrichment — a possible pathway to nuclear arms.
Iran has made such threats before. What was significant this time, however, was that the warnings were in the form of a formal notification to the head of the IAEA.
As Thursday's meeting adjourned, U.S. and European diplomats intensified efforts to widen support for a European draft resolution calling for Iran to be brought before the council.
ElBaradei said there was a "window of opportunity" to defuse the crisis, stressing that even if the issue is referred, the Security Council would not take up the issue before next month.
"We are reaching a critical phase but it is not a crisis," he said.
Iran, which claims its program is peaceful and aimed only at generating electricity, has repeatedly warned that such action would provoke it into doing exactly what the world wants it to renounce — starting full-scale uranium enrichment — as well as curtailing IAEA inspections.
Key members of the Security Council remained unmoved.
Grigory Berdennikov, Russia's chief IAEA delegate, reinforced Moscow's position outside the meeting, saying referral to the Security Council would send Iran "a serious signal."
Schulte agreed.
"It is time to send a clear and unequivocal message to the Iranian regime about the concerns of the international community by reporting this issue to the Security Council," he said.
Washington has waited years for international suspicions over Iran's nuclear ambitions to translate into support among board nations.
Only a simple majority is needed to approve the text, but the United States and its backers have held off pushing for earlier referral in hopes of building support for the measure. Support has grown since Jan. 10, when Iran stripped IAEA seals from enrichment equipment and announced it would restart the program.
While a broad majority of member nations support referral, a few countries that have policy disputes with Washington remain opposed — among them Cuba, Venezuela, Syria and Belarus.
"My delegation manifests its total disagreement with the proposal ... to bring it to the Security Council," said Venezuela's Gustavo Marques Marin. And Syria's Safwan Ghanem told reporters: "We will vote 'no.'"
A vote was expected Friday or Saturday. Countries opposed have the choice of voting against the text or abstaining.
Speaking for Germany, Britain and France — the three nations representing the European Union — German chief delegate Herbert Honsowitz told the meeting: "The time now has come for the Security Council to get involved."
The confidential draft resolution obtained by the AP "requests the director general to report to the Security Council" on steps Iran needs to take to dispel international suspicion it could be seeking to manufacture nuclear arms.
The draft expresses "serious concerns about Iran's nuclear program" and notes "the absence of confidence that Iran's nuclear program is exclusively for peaceful purposes."
If the board approves referral as expected, it will launch a protracted process that could end in Security Council sanctions for Tehran.
But no action is expected for weeks, if not months. Moscow and Beijing support referral only on condition that the council do nothing until at least March, when the board next meets to review the status of an IAEA inquiry into Iran's nuclear program and recommends further action.
"I am making very clear that the Security Council is not asked at this stage to take any action," ElBaradei said.
Berdennikov also told reporters that Russia "insists" no Security Council action be taken before March.
___
Associated Press Writer Palma Benczenleitner contributed to this report
Thanks Tomatoe...I looked into it briefly yesterday and have it on my watch list. That kind of volume from insiders signals good events to follow. However, which stock will move first? NSOL or JYSR! That is is the tough question....
OT: In China, to Get Rich is Glorious
By Dexter Roberts and Frederik Balfour
BusinessWeek Online
More Chinese are becoming millionaires -- and driving a fast-growing market for luxury goods
Wang Zhongjun is loaded and happy to flaunt it. He wears Prada shoes, Versace jackets, and a Piaget watch. He smokes Cohiba cigars from Cuba. He drives a white Mercedes-Benz SL600, a silver BMW Z8, and a red Ferrari 360. His art collection includes hundreds of sculptures and paintings. Value: $30 million or so. Home sweet home is a 22,000 square-foot mansion north of Beijing with antique British and French furniture, a billiard room with bar, and an indoor pool. When he tires of swimming, Wang can head to his stable (annual upkeep: $500,000) of 60 horses from Ireland, France, and Kentucky. "Entrepreneurs in China today feel much safer than before," says Wang, a 45-year-old movie producer who served in the Chinese army, studied in the U.S., and learned painting before backing internationally acclaimed films such as Kung Fu Hustle. "We are more accepted by the media, government, and society today."
That's for sure. Even though Deng Xiaoping declared that getting rich is glorious nearly three decades ago, just a few years back China's millionaires were running scared. When a Forbes Magazine survey of China's richest appeared in 1999, wags called it the "death list" after a tax crackdown targeted many who made the cut and landed some in jail.
Now China is embracing them. More than 300,000 Chinese have a net worth over $1 million, excluding property, according to Merrill Lynch & Co. And mainland millionaires control some $530 billion in assets, Boston Consulting Group estimates. "There has been a revolution in attitudes toward wealth," says Rupert Hoogewerf, who authored the 1999 list. He now runs Hurun Report, a Shanghai-based company specializing in information about China's rich, which just released a survey on millionaires' buying habits. "People don't appreciate how much cash there is running around in China today," he says.
Go to BusinessWeek Online to see the China slideshow
"DIZZY" OVER SHOES
Many people might not appreciate it, but luxury retailers sure do. Just five years ago mainland buyers accounted for 1% of global sales of luxury handbags, shoes, jewelry, perfume, and the like. Today the Chinese are the third-biggest high-end buyers on earth, with more than 12% of world sales, Goldman, Sachs & Co. reckons. Within a decade, China will likely leapfrog Japan and the U.S. to become the top luxury market, predicts Goldman analyst Jacques-Franck Dossin. "China is experiencing huge wealth creation, and there is lots of conspicuous consumption related to that," Dossin says. "People want to show they are successful."
How? By buying custom clothes, diamond-encrusted watches, pricey cars, gourmet meals, and fine wine. Zhao Hui, a chain-smoking 38-year-old restaurateur, real estate developer, and Ferrari owner from Shanghai, says he speaks no English, but he manages to pronounce "shopping" and "Tiffany" as he shows off his $50,000 Franck Muller watch. Richard Hung, a 43-year-old manager of a pharmaceutical company, has a closet filled with dozens of Armani, Gucci, and Canali suits and more than 100 pairs of Italian shoes. "I get dizzy when I look at shoes," he says. Where to wear those duds? Try Beijing's exclusive Chang An Club, where few blink at the $18,000 initiation fee. "Our members can afford it," says General Manager Antonius van Gevelt, adding that Chang An aims to keep its fees higher than rival gathering spots. The rich "want to join the most expensive club in China," he says.
Luxury marketers are happy to serve up plenty of flash and bling to keep sales rolling. Louis Vuitton, which has a dozen boutiques across the mainland, in November served up 1,500 bottles of Veuve Clicquot and platters of pâté de foie gras at the celebrity-packed launch of a new Beijing store. And fashionistas still marvel at Miuccia Prada's "skirt show" last spring, when she took over seven stories of Shanghai's art deco Peace Hotel.
CADILLAC CAFE
Pricey wheels do pretty well, too. The Rolls-Royce outlet in Beijing is one of the brand's top-selling dealerships. And Bentley Beijing has sold a half-dozen 728 stretch limos -- at $1.2 million each, the world's most expensive car -- more than any other dealership in the world. For thriftier millionaires without an extra million to drop on transportation, Cadillac, Mercedes, or BMW are eager to help. Shoppers at any of a dozen "Cadillac Experience Centers" in the mainland, for instance, can relax on a black leather sofa and enjoy a glass of Rosemount Cabernet in the "Cadillac Cafe" while browsing through photo-rich brochures that describe the brand's 102-year history. "Our whole showroom supports our brand: It's modern, sophisticated, and not your traditional luxury vehicle," says Stuart J. Pierce, who oversees the Cadillac brand at Shanghai General Motors Co.
Now the luxury goods marketers are looking far beyond Beijing and Shanghai to find China's millionaires. Cadillac plans to have 40 showrooms in China by the end of 2007, and last year dispatched a 1959 El Dorado convertible on a seven-city "heritage tour" to drum up interest nationwide. At this month's ice festival in the frigid northern city of Harbin, watchmaker Cartier has created a massive ice replica of its flagship Paris store. "Our aim is to have the second- and third-tier cities become a more important part of our business," says Daniel Chang, who oversees Cartier's sales in northern China.
Lately China's new moneyed class has gotten interested in more than fast cars, flashy threads, and extravagant timepieces. Growing numbers of mainlanders are snapping up everything from ancient scrolls and traditional ink paintings to French Impressionists. Christie's International says mainland buyers account for 20% of purchases at its Hong Kong auctions, compared with virtually none five years ago. And while most collectors prefer Chinese art, mainlanders now bid on Renoirs, Monets, and Van Goghs in New York and London, and a Shanghai businessman paid $1 million for a Picasso in a private sale. "There's tremendous potential," says Ken Yeh, deputy chairman of Christie's Asia (see BW Online, 2/6/05, "China's New Eye for Fine Art").
Even as the likes of Cartier, Christie's, and Cadillac try to separate China's millionaires from their wealth, others aim to help them preserve it. Although foreign banks are barred from marketing their offshore services inside China, they are discretely wooing mainland clients via their Hong Kong offices, figuring those who have made money abroad are fair game. And soon, banking regulations in the mainland are to be relaxed. "In the long term, China can surpass Japan as a major market for wealth management," says Kaven Leung, who oversees Citigroup's private banking efforts in China.
Diamond watches. Armani suits. Silver Bentleys. Private banks. Getting rich in today's China is indeed glorious, and spending is even better.
Go to BusinessWeek Online to see how China's new wealthy are flaunting it.
Back to the Best That Money Can Buy
I should have wired the money to purchase my last share purchase. The stock is starting to move upward again. This is exciting times and I am glad I have been able to hold on to my shares, even the rare opportunity buy majoirty of my NSOL below $0.25 back in the 2002-2003 era. That was nothing more than a gift to us all.
I am going to add my final shares within tghe next week....
The best part of the PR is that FFI will assume a leadership role in developing waste to ethonal facilities............
I thought NSOL might comment on the Presidents speech today! I wonder if this stock will now get attention since all of teh corn ethonal plants are down today!
OT: PEIX is to $18.50 and XTHN is at $5.95
Agency: Iran Document for Nuclear Weapons By GEORGE JAHN, Associated Press Writer
26 minutes ago
VIENNA, Austria - A document obtained by Iran on the nuclear black market serves no other purpose than to make an atomic bomb, the International Atomic Energy Agency said Tuesday.
The finding was made in a report prepared for presentation to the 35-nation IAEA board when it meets, starting Thursday, on whether to refer Iran to the U.N. Security Council, which has the power to impose economic and political sanctions on Iran.
The report was made available in full to The Associated Press.
http://news.yahoo.com/s/ap/20060131/ap_on_re_mi_ea/nuclear_agency_iran_5;_ylt=Ahi3lRjU6DtFgwJ37XTinC...
From that site it specificies:
Low and Stable Cash Costs Biomass feedstocks have a much lower and less volatile cost than corn and other conventional feedstocks.
Cowboy do your homework. FFI has no feed costs since their plants are being built at recyling centers which collect tons of organic material each day and will give it to FFI for free. Therefore you eliminate that $1.10-$1.30 cost for your organic source which corn ethonal producers have to pay plus there is no risk of a bad corn season. The cost is mostly with hauling and paying the collect the feedstock source. FFI is looking at producing ethonal at a cost of between 0.2 to 0.50 per gallon. The rest will be profit.
I cannot believe that FFI does not get any attention. THe fact that XTHN and PEIX are up consecutive days based on speculation. They do not have performance guarentees because they are taking a gamble on corn production. What if there are climate changes or droughts....? Then, they will have a bad year.
I may actually have to buy some more myself in the coming week of NSOL.
Nobody posted the follow up email from Patrick Herda recieved this morning!
January 30, 2006
Dear Shareholders:
I am writing to follow-up on the letter I sent earlier this weekend to bring an item of particular interest to your attention. When I managed to visit the Washington Auto Show this weekend in Washington, D.C., I was fascinated by the extensive Chevrolet exhibit on powering their vehicles with alternative fuels such as ethanol. It seems that ethanol as a fuel source is very much on Chevrolets mind! Check out the attached link and photo for more details.
Like Chevrolet, we certainly believe in the future of ethanol to revolutionize our fuel sources. That is why we continue our methodical approachwith much progress to datetoward launching Future Fuels, Inc.s first waste-to-ethanol production facility in Toms River, New Jersey.
To hear more about ethanol, be sure to tune into the CNBC special report on ethanol I mentioned in my previous letter. It is scheduled for 4:00 p.m. this Monday, January 30th.
Patrick Herda
President and CEO
Nuclear Solutions, Inc.
Anything interesting mentioned on the news report? Or is it just hype like typical news media reports are.
Is FFI being talked about in the report?