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McIlvaine has just introduced two important decision making tools for both purchasers and suppliers of air pollution control systems. One is a universal application classification system. The other is: “Important Event Odds” an organized way to assess the value of market forecasts.

The universal application classification system will make the world “flat” to use the term in the well-known recent book. By identifying the location in the decision tree rather than a word description the translation difficulties are eliminated. Furthermore, decision making is classification. So a reliable classification system is contributing greatly to decision making.

You may lose a pump order to a competitor who reports lots of orders for pumps for FGD limestone systems. But if the decision tree identifies his success as pumps for the grinding circuit and the purchase is for the absorber recycle pump it becomes clear that his success is not relevant.

So the development of a universal classification system will internationalize the market and also benefit the companies with the best products and most experience. It will be particularly valuable in China where the system will eliminate any language problems.

The second tool is called “Important Event Odds”. Purchasers and suppliers must make decisions based on the likelihood of certain important events. McIlvaine has projected the market for activated carbon for power plant mercury control based on the passage of certain regulations by local and federal agencies, by the future economic growth, by the availability and price of various fuels, and by certain world security related events.

Rather than make forecasts on an “either/or” basis it is much more valuable to make them based on the odds of occurrence of each event. If one event which will shrink the market has only a one in ten chance of occurring whereas one which will increase the market has a ten to one positive odds of occurring then the forecast should reflect 90 percent of the impact of the occurrence.

Likewise the purchaser should make his decision based on the odds. Let’s say a new CAA has only a 50/50 chance of passage in 2009-10. But there are a number of other regulatory initiatives each of which has only a 50-50 chance of forcing the purchase. The combination of four such 50/50 events makes the odds four to one that the purchase will be required.

McIlvaine has introduced decision trees on FGD, DeNOx, particulate control, mercury, and CO₂. These decision trees are entirely devoted to the coal-fired power generation application. By using the branches and twigs in the decision trees, the application is precisely identified.

This decision tree labeling can be applied to steel, waste incineration, pulp and paper and all applications where air pollution control is practiced. Examples are provided for both the coal-fired power and lime industries

China is presently the largest purchaser of air pollution control equipment. In fact it represents as large a market as all the countries in which English is the first language. In the 1970s we translated all headlines into German. However the market in German speaking countries is small. So the effort was not justified. But more importantly most German technical people rapidly improved their understanding of English.

Today with the exception of China, engineers must be able to understand English to rise to management positions, obtain advanced degrees or even work in fields requiring considerable knowledge of world developments.

Those speaking English as a second language have the most difficulty with technical definitions. The best English word is “spray drier” to describe one type of FGD system. In German the best term is Halb Trocken (literally, half dry). In fact the Germans have a better approach to classification by the condition as opposed to the physical shape.

In a 1980 Envitec exhibition in Düsseldorf, McIlvaine asked that its stand be located near other “air pollution control companies”. McIlvaine was disappointed to find that its stand was located near companies making instruments and controls. But the equivalent of “air pollution control” in German is Luftreinhaltung (literally, “air cleaning”). Most would agree that the word “control” is a poor choice but it has become the industry standard.

Identifying the specific application for a pump, nozzle or even a material of construction becomes a semantic challenge. Finding the right words to describe this application in Chinese increases the challenge substantially.

The solution for all languages is the identification of the right twig in the right branch of the appropriate decision tree. Figure 1 is an example using the FGD Decision tree.

Level 1	Level 2	Level 3	Level 4	Level 5	Level 6	Level 7	Level 8	Level 9	Level 10	Level 11	Level 12
Scrub	Physical	Systems	Calcium	Wet Calcium	Subsystems	SO₂ Removal System	Absorber Tower	Spray Tower
Level 1	Level 2	Level 3	Level 4	Level 5	Level 6	Level 7	Level 8	Level 9	Level 10	Level 11	Level 12
Scrub	Physical	Systems	Calcium	Wet Calcium	Subsystems	SO₂ Removal System	Absorber Tower	Tray Tower
Level 1	Level 2	Level 3	Level 4	Level 5	Level 6	Level 7	Level 8	Level 9	Level 10	Level 11	Level 12
Scrub	Physical	Systems	Calcium	Wet Calcium	Subsystems	SO₂ Removal System	Absorber Tower	Sump

Three branches of our FGD Decision Tree show that there are options for the absorber tower design. Only a few companies can supply the large recycle pumps for spray towers. Many companies can supply the smaller pumps used with tray towers. There is no recycle pump used in the sump design.

This identification system with or without the accompanying Decision Tree will be a big step forward in helping purchasers select bidders. It will be even more useful in China where the branch names will be described in Chinese. The big advantage of the system is that the precise meaning of the branch word is irrelevant. We used “sump” to describe the Alstom FlowPac and the Chiyoda Jet Bubbling Reactor. We could have used “no spray” or “slurry pool” or some other term without changing the conveyed meaning. Likewise the exact wording in Chinese will not be critical because the whole branch design is displayed.

What is more critical is the engineering expertise to identify three major types of limestone scrubber designs. The sump scrubber has only recently become popular. By adding this segment to cover both the FlowPac and Bubbling Reactor, we are also influencing decision making. We are informing purchasers that there are now three commercial choices, not two.

The market for many products including FGD is larger in China than in Europe or the Americas. It is therefore very desirable to perfect the Decision Tree labeling system in Chinese and for the Chinese market.

The Third Asian International DeSOx, DeNOx, and Dedusting Environmental Protection Technology and Equipment Exposition will be held November 21-23 in the China World Trade Center in Beijing. Details are found at www.desox.net

We will be preparing a special website for the conference. One of the features will be the Decision Tree product classification for each product offered by each exhibitor. This means that the visitor will know precisely without any language confusion which products are being offered.

If you are going to be an exhibitor at this conference or if you just want to be able to post some of the Decision Tree product listings in Chinese on your website, please contact us.

As a supplier of air pollution control products and services you have a unique mini-orchard of decision trees which are differently arranged from the end user decision trees. But it is very desirable to label your products based on the “purchaser decision tree” format. This correct classification of your product is the first step in making a sale.

McIlvaine believes the APC business environment will be radically changed with the development of a global orchard of synergistically juxtaposed decision trees with maximum cross pollination. This whole concept is discussed at

It is logical to identify the clusters by the standard codes. NAICS has been developed by the Dept. of the Census. You can type in a key word and get the code from the following site: http://www.census.gov/epcd/www/naics.html.

The North American Industry Classification System (NAICS) has replaced the U.S. Standard Industrial Classification (SIC) system. NAICS was developed jointly by the U.S., Canada, and Mexico to provide new comparability in statistics about business activity across North America.

Most of the McIlvaine data identifies applications using the older SIC code. You can convert to the new code from SIC through the following: http://www.logisticsworld.com/sic.asp

Bin vent filter — types — pulse jet —components — elements - cartridge —media —- polyester needle felt

We have identified 18 branches and twigs ending with the media used in the dust collector. Each branch is important in the identification. A shaker collector could be used instead of a pulse jet. Bags could be used instead of cartridges. So the selection of the media is determined by these choices.

In terms of suppliers reporting experience and success it is extremely valuable to provide this level of specificity. If the media were used in a bag instead of a cartridge its performance would not be nearly as relevant.

So from the global orchard starting point we go to the Industrial cluster and then to 37410 Lime Manufacturing, shown in Figure 4.

So with these two examples we have identified applications for pulse jet filters, for cartridges, and for polyester needle felt. By contrast the kiln dust collector would not use the same media because of the high temperatures. One option for this application is shown in Figure 5.

These examples show first classifications which are already in McIlvaine Decision trees (coal-fired power) and classifications which can be derived from future decision trees (lime).

McIlvaine will be translating the power plant decision tree classifications into Chinese. The specific near term goal is to make the Desox-DeNox conference more valuable with the use of the system.

There is a further opportunity for any company to work with McIlvaine to list all its products by application using the universal decision tree classification system in both English and Chinese. To pursue this further contact Bob McIlvaine at rmcilvaine@mcilvainecompany.com (847)784-0012 ext 112.

The second new tool is “Important Event Odds”. This is being utilized in all McIlvaine Multi Client reports and in custom consulting. The best way to explain it is with a complete example. McIlvaine has a new report on mercury control at http://www.mcilvainecompany.com/brochures/newsreleases/NR1271.htm.

Forecasts of activated carbon consumption are based on the odds of certain events occurring. Here is the analysis of these events in the new report

There are many positive and negative factors which could impact sales of specific mercury reduction equipment and consumables in the fifteen years through 2023, but our conclusion is that all coal units will have mercury control by 2023. Also by that time the odds are better than 50/50 that there will be at least 20 percent more coal capacity.

Multi pollutant control is a big factor in determining which mercury technology is selected. We believe that all coal plants will have SO₂removal equipment by 2023. This will greatly influence mercury removal methods.

In the following charts we have tried to calculate the odds for each important event which can impact the total market or the share for individual technologies. These events are those which would impact the market between 2008 and 2023 and are shown in Figure 6.

Is it frivolous to include odds of unlikely events along with those which are likely? Unfortunately some environmental groups are making an impact because of concerns about very unlikely events. It is therefore valuable to illustrate that there are lots of unlikely events which could shape policy, but the odds against them should not weigh heavily.

The odds that a meteor would strike earth and do such major damage that it would interrupt a mercury program are certainly more than 20 million to l. Most doomsday scenarios of the earth being hit by something falling from space involve the large pieces, asteroids 10km or 20km across, that cause global destruction and mass extinction. This has happened at least five times in the history of the earth and completely changed life on the planet each time. However, these large objects arrive every hundred million years or so, and since the last one struck 65 million years ago, the odds that another one will not strike for a while are in our favor.

The debate over global warming is likely to continue with no major impact on a mercury control program. Regardless of the facts, we are likely to be continually bombarded with doomsday predictions. These are unlikely to persuade rate payers that a tripling of their electricity rates is justified. However, if some actual catastrophe were linked to warming, then there could be some abrupt change in public attitude. Despite the news stories which would indicate the likelihood of such a catastrophe, the odds are just as great for a warming catastrophe in the next fifteen years as they are for one from meteors.

One of the scenarios is for rapid loss of ice and rise in sea levels. Most scientists agree that any rise will be very gradual. Others even question whether there will be any rise.

“Global warming is not causing any significant retreat of polar ice caps, despite claims to the contrary in some media reports”, says James M. Taylor, senior fellow for environment policy at The Heartland Institute. “Although Arctic Sea ice last summer reached its minimum extent since satellites began measuring the ice in 1979, NASA scientists have discovered the sea ice retreated due to variable local wind patterns rather than global warming. Moreover, the ice re-formed at a record pace last fall. In the Southern Hemisphere, Antarctic Sea ice is at its greatest extent in recorded history. The majority of Antarctica is in a prolonged cold spell and has been accumulating snow and ice for decades.”

There are many aspects of global warming. One relates to the increases in CO₂ levels. Is this harmful or beneficial? Do CO₂ increases improve plant growth or do they hurt it? Do CO₂ increases cause global warming or is it the other way around? Research has shown that in most cases rate of plant growth under otherwise identical growing conditions is directly related to carbon dioxide concentration. The amount of carbon dioxide a plant requires to grow may vary from plant to plant, but tests show that most plants will stop growing when the CO₂ level decreases below 150 ppm. Even at 220 ppm, a slow-down in plant growth is significantly noticeable. Colorado State University did research on growing carnations in greenhouses. CO₂ levels to 550 ppm produced an obvious increase in yield (over 30 percent), but the greatest benefits were earlier flowering (up to two weeks) with an increased percentage of dry matter. There is a very well organized website on CO₂ science. There are detailed summaries and links to studies on various crops.

The conclusion is that nearly all agricultural crops respond to increases in the air's CO₂ content by exhibiting increases in photosynthesis and biomass production, as well as their ability to deal with various environmental stresses. http://www.co2science.org/.

You can search directly on the history of CO₂ levels and find the following: When the earth was in its infancy, some four-and-a half billion years ago, it is believed that the atmosphere was predominantly composed of carbon dioxide, which would have put its CO₂ concentration, in terms of the units most commonly used today, at something on the order of 1,000,000 ppm. Ever since, the CO₂ content of the air (in the mean) has been dropping.

By 500 million years ago, in fact, the atmosphere's CO₂ concentration is estimated to have fallen to only 20 times more than it is today, or something on the order of 7,500 ppm, and by 300 million years ago, it had declined to close to the air's current CO₂ concentration of 370 ppm, after which it rose to about five times where it now stands at 220 million years before present. Then, during the middle Eocene, some 43 million years ago, the atmospheric CO₂ concentration is estimated to have dropped to a mean value of approximately 385 while between 25 to 9 million years ago, it is believed to have varied between 180 and 290 ppm. This latter concentration range is essentially the same range over which the air's CO₂ concentration oscillated during the 100,000-year glacial cycles of the past 420,000 years.

With the inception of the industrial revolution, however, the air's CO₂ content once again began an upward surge that has now taken it to the 370 ppm level, with the promise of significantly higher values still to come. In addition to its variation over geologic time, the atmosphere's CO₂ concentration exhibits a strong seasonal variation. It declines when the terrestrial vegetation of the Northern Hemisphere awakens from the dormancy of winter and begins to grow in the spring, thereby extracting great quantities of CO₂ from the air; and it rises in the fall and winter, when much of the biomass produced over the summer dies and decomposes, releasing great quantities of CO₂ back to the atmosphere.

Will the ongoing rise in the air's CO₂ concentration lead to catastrophic global warming? Observations of historical changes in atmospheric CO₂ concentration and air temperature suggest that it is climate change that drives changes in the air's CO₂ content and not vice versa. In a study of the global warmings that signaled the demise of the last three ice ages, it was found that air temperature always rose first, followed by an increase in atmospheric CO₂ some 400 to 1000 years later. For all of the glacial inceptions of the past half-million years, air temperature consistently dropped before the air's CO₂ content did, and that the CO₂ decreases lagged the temperature decreases by several thousand years. In addition, the multiple-degree-Centigrade rapid warmings and subsequent slower coolings that occurred over the course of the start-and-stop demise of the last great ice age are typically credited with causing the minor CO₂ concentration changes that followed them. There are a number of other studies that demonstrate a complete uncoupling of atmospheric CO₂ and air temperature during periods of significant climate. Hence, there are no historical analogues for CO₂-induced climate change, but there are many examples of climate change-induced CO₂ variations.

A big potential for mercury control is at small coal plants which will need to install MACT. If natural gas prices were to fall below $4/MM/Btu, we would return to the situation of the 1990s where combined cycle plants would be the choice for new construction and smaller coal-fired plants would be retired. The odds of this occurring are now at least 1000 to l. At $3-4/MMBtu, gas is competitive with coal for electricity generation. At today’s prices the cost of gas-generated electricity is more than twice that from coal (even with all the latest air pollution control equipment). At $20/MMBtu the cost will be nearly four times that of coal. A family paying $2000/yr for electricity would be faced with paying $8000. This large difference in fuel prices would have a profound effect on energy decisions.

A front page article in The Wall Street Journal April 18, 2008 indicated that $20/MMBtu gas may be where the price is headed. Natural gas prices in the U.S. have risen 93 percent since August. On April 17 the price closed at $10.38/MMBtu. (On April 24 the price was $10.93). Gas heats 50 percent of U.S. residences and provides 20 percent of the power in the U.S.

Liquefied natural gas (LNG) arriving in Japan is priced at $20/MMBtu. Cheniere Energy Inc. just opened a new LNG terminal near the Texas-Louisiana border. However, the stock is down 70 percent from its high earlier this year because observers expect few tankers to deliver to the U.S. when they can achieve higher prices in Asia. Oil and gas generally trade at near equal values in $/MMBtu. It takes 6000 cubic feet to equal one barrel of oil. Gas is 1000 Btu/ft³. So at $10/MMBtu gas, is the equivalent now of $60/barrel. Oil is presently $114/barrel. So gas would rise to $19/MMBtu to keep its historic equality.

The article reports that some industry participants believe that gas will hold between $7/10/MMBtu based on a world increase of 30 percent in LNG. But anyone who has traveled to China recently can observe that the potential consumption in that country alone is enough to absorb much of the increase. The article points out that economists predicted that it would be a buyer’s market with purchasers holding down costs. The opposite has proved the case. Demand is high and producers can sell to the highest bidder.

The article also points out that when electricity demand is higher than supply, prices soar. Unlike other energy sources there is no storage. So we are very likely to have a repetition of the 2001 situation and a similar situation back in 1974. Within a few months utilities placed orders for 70,000 MW of coal-fired power plants. However, the shortage disappeared in a few years and many of the orders were canceled. But this time around it is not likely that there will be a sudden reversal.

As a last resort to meet demand, utilities could operate their single cycle peaking gas turbine plants. These units are only 60 percent as efficient as the combined cycle plants. This means that if they are buying gas at $20/MMBtu, it would be the equivalent impact of $33/MMBtu gas in a combined cycle plant. TXU had initiated the fast track construction of 11 coal-fired power plants in anticipation of this kind of problem. Most of those projects were canceled. Texas is heavily reliant on natural gas and is quite vulnerable along with California and others.

There are a number of factors which will determine whether there is an exorbitant carbon tax. The word “exorbitant” implies a miscalculation. This may be the most important element of risk. We could somehow stumble into a situation where a carbon tax is so punitive that it has a great negative economic impact. However, the European experience is otherwise. In fact Europeans are more positive about coal-fired power generation as a long term solution than Americans are.

The Wall Street Journal observed in an April 26, 2008 article that Polls are cruel. Voters consistently say they want to stop global warming. They also say consistently that energy prices, especially for gasoline, are too high. Excerpts from this article follow.

“So what are politicians supposed to do? The answer, apparently, is to pretend the contradiction doesn't exist. The latest episode in this long-running bipartisan ruse aired last week, when John McCain proposed a "gas tax holiday" that would suspend federal levies between Memorial Day and Labor Day. "Americans need relief right now from high gas prices," a press release put it, and the holiday will "act immediately to reduce the pain." His Arizona colleague, Jon Kyl, promptly introduced it as Senate legislation.

Most of the price of gasoline is determined by the global price of crude oil, which is spiking now due to a combination of the weak dollar and commodity speculation. The source of the problem isn't the tax. Domestic demand for gas always goes up with summer driving, but the McCain holiday doesn't affect production, and anyway, only applies over the short term.

More notably, it makes a hash out of the climate-change policies that the candidate purports to favor. In 2003, Mr. McCain and Joe Lieberman introduced the first Senate bill to mandate greenhouse-gas reductions through cap and trade. "There is no middle ground," Mr. McCain said in 2005. "You've got to have an immediate effort to reduce emissions of greenhouse gases. Anything less than that, is a fig leaf and a joke."

As honest environmentalists admit, any effective policy to reduce emissions must increase the price of carbon, encouraging cuts in consumption and creating an incentive for competing energy sources. This is justified as a necessary sacrifice to avert "dire consequences if we let the growing deluge of greenhouse gas emissions continue," as Mr. McCain said last year.

But as the gas-tax moratorium gambit shows, such purity is dumped as soon as voters start complaining about high prices. Not that the Republican is alone: Hillary Clinton, slipping into her new role as tribune of the working class, has endorsed the holiday, while Barack Obama is opposed because he believes a windfall profits tax on oil companies would provide more relief.

The evasions continue down the line. It is easy for everyone to say the U.S. needs a "Manhattan Project" for alternative energy because the phrase is meaningless. Most politicians favor a cap-and-trade regulatory policy, instead of a carbon tax, because it would shift higher emissions costs onto businesses, which would pass them on to consumers indirectly. Yet the most popular Senate bill that would create a cap-and-trade program applies only to utilities and industry. It excludes automobiles, though about one-third of annual U.S. carbon emissions come from cars and trucks.

Such contradictions are easy to paper over now, because big climate change legislation is still a way off in Congress. But it's becoming clearer all the time that whatever emerges will be so shot through with loopholes and exemptions that its effect on carbon emissions will be minimal, while still imposing economy-wide distortions.

No one could get elected, or for that matter govern on a platform that called explicitly for increased energy prices. So we get contradictions like a gas tax moratorium married to cap-and-trade carbon limits. To quote Mr. McCain, it's "a joke.” (End of WSJ excerpt).

It is instructive to review the history of natural gas power generation. The low cost of natural gas coupled with environmental pressures led to a huge building program of natural gas fired plants in the U.S. at the turn of the century.

The price of natural gas then rose substantially. The public essentially had the choice which was to utilize all this new gas-fired power generation and help reduce greenhouse gases or to switch back to the old coal plants.

The answer was that the independent gas turbine power providers went bankrupt because the public was unwilling to pay a substantial premium for cleaner energy.

One big market for activated carbon is for plants which do not install scrubbers. But it is unlikely that there will be any plants without scrubbers by 2023. Germany and Japan installed FGD on all coal-fired power plants in the 1980s. Taiwan and Korea utilize FGD on their generators. Even the new EU members are installing FGD. China has already committed to as much as 300,000 MW of FGD.

There is no logic in the long term exemption of old dirty plants from the same controls which are installed on new units. In fact logic would dictate stricter controls to compensate for the lower efficiency. A new 500-MW plant is 30 percent more efficient than an old one. Therefore to achieve the same SO₂ emissions per year, the old plant needs to meet a lower emission limit in lbs/MMBtu.

The only logic in exemption of old plants is to provide a grace period for retirement of plants which would otherwise have to install FGD. This has happened in Europe where plants had until 2007 to decide whether to retire or install FGD.

The U.S. is extremely unlikely to become the only wealthy country without stringent FGD control on all coal-fired units. The U.S. must interact with countries around the world in order to achieve its goals. Many pollutants are global. One study shows that most of the mercury deposition in the Western U.S. comes from other countries. China is being blamed for some of the SO_x and NO_x damage to mountain tops in California.

Some isolationists argue that trade tariffs should be increased due to the higher expense of environmental control in the U.S. It would be a little difficult to have to accept the reverse logic.

There is much deserved criticism of the Bush Administration, but their record is not as bad as it appears. CAIR was an expediency to at least force FGD on 70 percent of the plants in the East. The main Bush program was Clear Skies.

On July 29, 2002 the Bush Administration announced that it had sent legislation to Congress to implement the President's Clear Skies initiative. On February 24, 2002 President Bush announced the Clear Skies initiative, which proposes to set strict, mandatory emissions caps for sulfur dioxide (SO₂), nitrogen oxides (NO_x), and mercury (Hg). Clear Skies would have cut power plant emissions of these pollutants by 70 percent, eliminating 35 million more tons of these pollutants in the next decade than the current Clean Air Act.

Congress refused to pass “Clear Skies” unless carbon limits were also added. The Bush Administration could have just left the situation in limbo. But to its credit it executed an “end around” by using a court mandate to at least achieve a portion of the program.

So we had an administration which proposed more than Congress would approve and a Congress who wanted even more.

There is no longer a big utility lobby seeking to minimize mercury controls on coal-fired boilers. The utilities would support strict mercury controls in an instant if there were some certainty relative to a less than punitive carbon tax.

The conclusion is that with a McCain or Obama administration, there will be both a pro-environment administration and Congress.

McIlvaine Company tracks all the renewable projects and projects the markets for wind, solar, biomass, and other renewable technologies. The comparison of costs to coal first needs to be refined to base load generation rather than peaking.

Most peaking capacity is gas-fired. As pointed out above, the single cycle turbine uses much more gas per MW of generation than a combined cycle plant. These peaking plants at ($20/Btu gas) would have costs of six times coal. This opens the door for many renewable options. It does not mean they would be competitive for the large base load generation needs.

The comparison also needs to be refined based on quantity. Wind power may be very competitive in a situation where there is otherwise a long transmission line. Wind power supply can be expanded at a modest rate. But there is no way that wind power will provide large quantities of base loaded power at a price of less than 200 percent of coal.

Another aspect of the quantity comparison is actual electricity delivery as opposed to peak capacity. Wind turbine average generation is about 30 percent of maximum capacity due to variations in wind speed. It takes three times the wind turbine capacity to equal the baseload delivery of a coal plant.

There is a shortage of wind turbines. The industry has moved to five MW in a single turbine. But capacity is not nearly sufficient to meet demand. It will take some years for this situation to be resolved.

Solar presently has some very attractive site specific applications. There is promise of much broader application and substantial cost reductions. But it presently ranks behind wind in terms of near term promise.

Other renewable energy technologies are limited by resources (biomass) or cost, so the odds against renewable base load generation prices dropping below 200 percent of coal in the next fifteen years are at least 50 to 1.

Nuclear is the most cost competitive option to coal. However, the cost is still likely to remain higher. More importantly there are other negatives including environmental, energy security, and supply. Presently siting a nuclear plant is more difficult than a coal plant due to environmental opposition. There are also energy security aspects.

The nuclear new generation capability in the U.S. was dismantled. The world capacity growth has been modest. There are some very big hurdles to ramping up capacity to more than meet the substantial retirements. One example is the big Japanese fabricator which makes the containment vessels. It is the only company which can make the needed one piece modules. Its production is only four per year.

Alternatives are expansion of capacity or competition which would have to produce multi-piece vessels. These challenges are illustrative of the difficulty in ramping up nuclear capacity in the next 15 years.

DOE has taken these difficulties into account in its new 2008 forecast. Nuclear generating capacity in the AEO2008 reference case increases from 100.2 gigawatts in 2006 to 114.9 gigawatts in 2030. The increase includes 17 gigawatts of capacity at newly built nuclear power plants (33 percent more than in the AEO2007 reference case) and 2.7 gigawatts expected from uprates of existing plants, partially offset by 4.5 gigawatts of retirements.

The odds are conservatively 30 to 1 against nuclear playing a major role in the next fifteen years.

Mercury control will be required on coal gasifiers. But the approach is to use fixed bed carbon units and therefore these revenues are not included in this analysis.

Coal gasification has a great potential. There are, however a number of reasons it will not be the choice for the majority of new coal-fired plants. One is the need to utilize the engineering and fabrication resources to produce syngas and liquid products. With oil at over $100/barrel it will be important to national security to develop synthetic natural gas and coal-to-liquids production.

Another reason is that coal-fired power system suppliers are making their plants carbon ready and offering systems with low emissions of pollutants at prices which will be more than competitive with gasification in the short term.

Coal gasification is still a developing technology. The cancellation of government funding of Future–Gen and the slow progress in construction of other proposed coal gasification plants are indications of the slow growth.

Net additions to coal-fired generating capacity in the AEO2008 reference case total 100 gigawatts from 2006 to 2030 (as compared with 151 gigawatts in the AEO2007 reference case) including 4 gigawatts at CTL plants and 29 gigawatts at integrated gasification combined-cycle plants. Given the assumed continuation of current energy and environmental policies in the reference case, carbon capture and sequestration (CCS) technology does not come into use during the projection period.

The DOE forecast sited above projects 71,000 MW of new coal-fired plants in the years to 2030. That is an average of 3000 MW/yr. One of the biggest deterrents is lawsuits by environmental groups. Permits for new plants are routinely contested.

With the increasing resistance to high energy prices regulators will be under pressure to permit new coal plants faster. The support for the environmental groups will also be negatively impacted by cost concerns.

It is also possible that environmental groups will follow the lead of their European counterparts who are supporting the replacement of existing coal plants with new ones.

So the odds are at least five to one that the impact of environmental groups will not be paramount.

Many studies have shown the reluctance of individuals to sacrifice substantially for the abstract value of benefits in other countries and benefits which are not occurring within the lifetime of the individual. As was pointed out in the article above there is strong sentiment for environmental gains as long as it does not cost much.

So the odds are greater than five to one against the possibility that if coal plants are much less expensive than alternatives this benefit will be ignored.

As discussed under “anti-environmental administration and legislature” above the Bush Administration tried to pass Clear Skies in 2003. Now there is a bill supported by moderates on both sides of the aisle.

The Clean Air Planning Act of 2007 includes calls for CO₂ emissions to be capped at today's levels by 2012 and annually reduced to achieve levels in 2050 that are 25 percent lower than emissions were in 1990. Power plants could buy CO₂ allowances on the open market, according to lead Democratic sponsor Senator Tom Carper of Delaware. Coal-fired power plants that use cleaner fuel than the standard coal, such as coal gasification technology, would receive bonus allowances to sell. The bill would also cut SO₂ by 82 percent and NO_x by 68 percent by 2015. Mercury would be cut 90 percent by 2015. Carper introduced a similar bill last year but it stalled in committee.

The difficulties facing passage of this bill do not involve the 90 percent mercury reduction, but are centered on the CO₂. But some compromise on this issue is likely. President Bush has changed his position to one closer to the opposition.

On April 16 Bush called for major polluters like China and India to stop the growth of greenhouse gas emissions by 2025 and further called for abandonment of trade barriers on energy-related technology.

“In support of this process, and based on technology advances and strong new policy, it is now time for the U.S. to look beyond 2012,” he said. “We’ve shown that we can slow emissions growth. Today, I’m announcing a new national goal: to stop the growth of U.S. greenhouse gas emissions by 2025.”

So some compromise which sets a growth cap beyond the 15 years in the forecast would not impact the retrofit market. A new Clean Air Act would likely require each power plant to control mercury and yet would not force retirement of older plants. It would be a positive factor. The odds are ten to one or higher that there will be a new Clean Air Act in the next few years.

This new act will also probably address new source performance standards applicable to coal plants under design or planning. The efficiency may be higher than 90 percent. If systems are available for 95 percent efficiency at reasonable cost then the higher level would likely be mandated.

NSPS for particulate at 0.03 lbs/MMBtu requires efficiency of greater than 99.9 percent. So 90 percent for mercury seems low by comparison.

Senator Carper is also pushing a narrower and immediate bill which would compensate for CAMR vacatures. It would require EPA to propose a rule with 90 percent mercury reduction at every coal plant at a very early date. The odds against this becoming law instead of part of the new more encompassing ACT are at least 50 to l.

Rules limiting the emissions of fine particulate in the ambient air will impact SO_x control purchases because sulfates represent a significant portion of the ambient particulate. Therefore, indirectly the rule will impact mercury technology selection. CAIR will cause some reduction. But it is generally agreed that states will have to take additional measures in order to meet the requirements.

On March 29, 2007, EPA issued a final rule defining requirements for state plans to clean the air in 39 areas where particle pollution levels do not meet national air quality standards. Fine particles or "PM_2.5" can aggravate heart and lung diseases and have been associated with premature death and a variety of serious health problems including heart attacks, chronic bronchitis and asthma attacks. This rule will help state and tribal environmental agencies develop and implement plans that will improve air quality for millions of Americans.

States must meet the PM_2.5 standard by 2010. However, in their 2008 implementation plans, states may propose an attainment date extension for up to five years. Those areas for which EPA approves an extension must achieve clean air as soon as possible, but no later than 2015. It is therefore likely that this rule will have a positive effect on the NO_x control market.

The odds are ten to one in favor of a plant being required to install SO_x control because of this regulation in the next 15 years, if it has not already installed it for another reason. The reason that this is universally applicable is that states with non-compliance areas will sue the plants upwind. Therefore all plants will be impacted.

The U.S. Court of Appeals for the District of Columbia Circuit negated a rule known as Clean Air Mercury Rule (CAMR). That policy allows power plants that fail to meet emission targets to buy credits from plants that did, rather than having to install their own mercury emissions controls. The rule was to go into effect in 2010. The court struck down the cap-and-trade policy and the Environmental Protection Administration's plan to exempt coal- and oil-fired power plants from regulations requiring strict emissions control technology to block emissions.

New Jersey challenged the policy in federal court. Joining New Jersey in the lawsuit were California, Connecticut, Delaware, Illinois, Maine, Maryland, Massachusetts, Michigan, Minnesota, New Hampshire, New Mexico, New York, Pennsylvania, Rhode Island, Vermont and Wisconsin. The agency defended the rule, saying it represented the nation's first attempt to control such emissions and would reduce mercury emissions by 70 percent. The three-judge panel agreed with the States that the EPA did not have the authority to exempt the power plants. The court unanimously ruled that EPA's arguments were "not persuasive". The states argued that the cap-and-trade system would endanger children near some power plants that pollute but which also use credits to do it legally. "This means the EPA is going to have to go back and do a real job of regulating all the toxics coming out of these plants," said attorney James S. Pew, who argued on behalf of several environmental organizations that filed documents in the case.

What are the implications for utilities? CAMR did not have any immediate impact on controls since it relied on co-benefits for the next eight years. The states are the ones who are setting the early adoption of technology in any case. The best guess at this point is that all plants will have to meet 90 percent mercury removal or some weight equivalent to 90 percent removal from the average unit at some point in time. But since best available control technology is necessary, it will also need to be applied to the other heavy metals including cadmium, selenium, chromium etc. The TOXECON approach, wet precipitators, and certain other technologies which remove both particulate metals and gaseous phase metals in one unit will enjoy larger markets.

The ruling’s greatest impact may be the implication that all air toxics including hydrogen chloride have to be reduced under the hazardous air pollution part of the CAA. Every coal-fired power plant passes the 10 ton/yr HCl threshold. This means that best available control technology will have to be applied to make reductions. This would then mean that scrubbers would have to be installed on all units.

The reason is that in order to remove HCl you need a scrubber. It would not be cost effective to remove HCl without removing the SO₂. So the odds are ten to one that sometime within the 15 years any plant which does not have scrubbers would need to install them just because of the Toxic MACT requirements.

A rule issued nine years ago relative to regional haze will be impacting the FGD market for many years to come. Here is one example:

Portland General Electric (PGE) proposes to spend about $300 million on pollution controls at its coal-fired power plant near Boardman, OR, which is blamed for visibility impairment in the Columbia River Gorge and around Mount Hood. An analysis submitted to the Oregon Department of Environmental Quality indicated the improvements would reduce the plant's haze-causing emissions by about 75 percent. The company would simultaneously install equipment to capture at least 90 percent of the plant's mercury emissions. The changes, which PGE proposes to complete by 2013, should noticeably reduce the plant's contribution to haze around Mount Hood on the most polluted days of the year, according to the analysis. The analysis recommends new low NO_x burners with over-fire air and SNCR for NO_x control and a semi-dry FGD with pulse jet fabric filters for SO₂ and PM control.

EPA issued final regional haze regulations in 1999. The rule calls for states to establish goals and emission reduction strategies for improving visibility in all 156 Class I (large) national parks and wilderness areas. The first state plans are due (depending on several factors such as whether the area is in attainment for PM_2.5) between 2004-2008 and plans must require "uniform, reasonable progress" steps for getting to the overall goal by 2064. These goals are very long term.

EPA believes that the program to address visibility impairment must be regional in nature, therefore all fifty states are included under the rule. The rule allows nine western states to implement the recommendations of the Grand Canyon Visibility Transport Commission within the framework of a national regional haze program. The regional haze program can also be tied in with strategies to address the ozone standard, the particulate standard and the regional ozone transport problem. In fact since sulfates are the dominant source of light extinction in the eastern part of the U.S., EPA expects conditions on the worse visibility days to improve by 2010 across that area because of acid rain mandated sulfur dioxide reductions.

EPA is not specifying in the final rule what specific control measures a state must implement in its initial SIP for regional haze. A state must determine baseline visibility conditions, that is, visibility in deciviews for the 20 percent most-impaired days and for the 20 percent least-impaired days for the years 2000 through 2004. “Reasonable progress targets” will be gauged against this baseline, improving visibility on the 20 percent worst days and allowing no degradation of visibility on the 20 percent best days. A state must consider mobile sources, fire, international contributions, construction activities, stationary sources, dust from roads, etc. The long-term strategy must include enforceable emissions limitations, compliance schedules, monitoring data, criteria and procedures for a market trading plan, and other reasonable progress goals established by states which have mandatory Class I Federal areas. Reassessment and revision of the SIPs will occur every 10 years.

EPA stated that data on individual components of PM (nitrates, sulfates, elemental carbon, organic carbon, crustal material) are crucial to understanding the causes of visibility impairment at a given location and are necessary for long-term strategy development.

The regional haze rule impact on the FGD market (absent other drivers) would make a plant seven times more likely than not to install FGD control, if it is the 50 percent of the U.S. that would be considered near national parks.

A plant which triggers NSR in the future will have to meet the NSPS for mercury (this was vacated as part of CAMR), but will likely be reissued at 90 percent or greater efficiency). The Clean Air Act requires a new plant to undergo new source review if it increases its capacity. Therefore, all the plants without scrubbers and SCR have tried to avoid increases. The economic consequences were small when gas was $2/MMBtu. But at $10/MMBtu the coal plant becomes extremely lucrative to operate.

Many old coal-fired boilers have the potential to increase capacity by five percent or more. A study conducted through funding by B&W shows that the cost per KWh of a modified plant with the latest air pollution control equipment and 10 percent greater electrical generation is less than an old unmodified plant.

The difficulty in siting new plants and the rising cost of gas are both drivers which will result in capacity increases at many old plants. At least 80 percent of existing plants will install pollution control equipment to enable them to increase capacity. So at an individual plant (not subject to other rules to install NO_x and SO_x control equipment in the next fifteen years) the odds are four to one that it will install equipment to meet new source performance standards (NSPS) for the purpose of increasing capacity in a legal way.

In the original CAA there was an exemption for existing power plants which were going to retire within a few years. However, instead of just setting a grace period as did Germany, Congress wrote a confusing clause that offered permanent exemption to any plant which did not modify or try to extend the life of its plant. This clause called “New Source Review” requires any existing plant to report modifications and life extension expenditures. These plants would then face the same requirements as new plants.

The intention of the law was to give operators a few years to retire old plants. No one would have predicted that this would be extended for 38 years on plants already beyond their 20-year normal lifetime. Now we have 50-year-old plants whose life has been extended by decades.

In the 1990s EPA discovered that most if not all the utilities with older plants had not reported modifications and life extensions. These plants are liable to penalties dating from the time of the first modification or life extension. Subsequently, court opinion has set such a low bar that almost every plant was a violator within a few years of the original ACT.

During the Clinton Administration a series of lawsuits was launched. The petroleum industry was the first target. After several successful suits the remainder of the industry voluntarily settled with EPA.

Attention was then focused on the power plants. After some successful settlements it appeared that the rest of the industry would voluntarily settle. Then the Bush Administration arrived on the scene and wanted to redefine the interpretation of NSR. This should have had no effect on past violations. But the Dept. of Justice became less aggressive and only a few lawsuits did go forward.

The recent AEP settlement was significant because of its size. The First Energy settlement was significant because it was the first time a court ruled on a case. Previously all the suits were settled prior to trial. In this case the agreement for 90 percent control was higher than the agreements in previous settlements.

In 2007 American Electric Power (AEP) reached a settlement agreement with the U.S. Environmental Protection Agency (U.S. EPA).Under terms of the settlement agreement filed in the U.S. District Court for the Southern District of Ohio, AEP agreed to annual SO₂ and NO_x emissions limits for its fleet of 16 coal-fired power plants in Indiana, Kentucky, Ohio, Virginia and West Virginia.

Additionally, the company agreed to install additional emissions control equipment on two plants. AEP will pay a civil penalty of $15 million. AEP agreed to annual SO₂ and NO_x emissions limits for its fleet of 16 coal-fired power plants in Indiana, Kentucky, Ohio, Virginia and West Virginia. There are penalties should AEP fail to comply with the settlement, which requires the company reduce and cap SO₂ and NO_x emissions by more than 813,000 tons annually.

The agreement calls for a 79 percent reduction in SO₂ emissions, responsible for acid rain, from 2006 levels by 2018. In addition it requires a 69 percent cut in emissions of NO_x from 2006 levels by 2016. AEP also agreed to install SCR and FGD emissions control equipment on both generating units at its Rockport Plant in Rockport, Indiana. Unit 1 at Rockport will be retrofitted with an SCR system to reduce NO_x and a scrubber to reduce SO₂ by the end of 2017. Unit 2 at Rockport will receive the same equipment by the end of 2019.

To reduce SO₂ emissions AEP committed to complete the previously announced scrubbers for its Big Sandy and Muskingum River plants by December 31, 2015. AEP also agreed to plant-specific SO₂ emission limits for its Clinch River Plant, and it’s Kammer Plant near Moundsville, WV. Since 2004, AEP has spent nearly $2.6 billion on installation of emissions control equipment on its coal-fired plants in Kentucky, Ohio, Virginia and West Virginia as part of a larger plan to invest more than $5.1 billion by 2010 to reduce the emissions of its generating fleet. The cost of the additional environmental controls for Rockport and Clinch River agreed to in the settlement will be approximately $1.6 billion (net present value).

FirstEnergy Corp. has agreed to spend $1.1 billion to drastically cut pollution from the W.H. Sammis power plant found to be in violation of NSR regulations. Under the agreement FirstEnergy will reduce emissions by at least 90 percent by 2010 for SO₂ and NO_x. The plan calls for switching immediately to burning low-sulfur coal and installing FGD at Sammis and for cutting emissions at several other FirstEnergy plants. This agreement is important for two reasons. First it underlines the resolve of the Administration to pursue past NSR violations. Second it sets a new bar of 90 percent rather than the 70 percent in previous consent agreements.

Judge Sargus, in a 109-page opinion, said Ohio Edison's (now FirstEnergy) Sammis plant clearly went beyond routine maintenance with a series of 11 construction projects. The projects cost the company about $136.5 million and resulted in a "significant increase" in the electricity output of the plant as well as emissions of sulfur dioxide and nitrogen oxides, he wrote. FirstEnergy accounted for the $136.5 million as capital costs, not maintenance expenses. It also hired outside contractors to do most of the work instead of using in-house maintenance crews, the court said. "When coal-fired generating plants undertake activities at a unit which are not frequent, which come at a great cost, which extend the life of the unit and which require the unit to be placed out of service for a number of months, such activities can hardly be considered 'routine'," Sargus said.

The judge had this to say about EPA. "It is also evident from the record in this case that various electric utilities and industry organizations have sought within legal bounds to influence the conduct of the EPA," the judge said. "What should be unexpected and condemned, however, is an agency unwilling to enforce a clear statutory mandate set forth in an act of Congress."

An important question is to what extent this ruling is applicable to other plants built prior to 1970. The answer is that it appears to be sweeping enough to indict any plant which did enough maintenance to extend the life until 2003. The judge ruled that maintenance that results in a reduction of forced outages results in higher emissions. In other words, if availability rises, so does the capability to emit. He said that the distinction between routine maintenance and a modification to trigger compliance is hardly subtle. Routine maintenance involves no permanent improvements, is limited in expense, is usually performed by in-house employees, and is treated for accounting purposes as an expense.

In contrast, capital improvements generally involve more expense, are large in scope, often involve outside contractors, involve an increase of value to the unit, are not undertaken with regular frequency, and are treated as capital expenditures. One clue for other utilities about their fate is association with the EPRI life extension strategy. This program was cited by the government and by the judge. EPRI conferences on this subject indicated that the design life was 30 years. However, with life extension older plants can be retained for 50 to 60 years. Judge Sargus ruled for EPA on all eleven counts. This included some minor and some major expenditures.

One example is the 1993 scheduled outage on Unit l. Ohio Edison replaced three banks of horizontal reheater tubes for $2 million. It also replaced furnace ash hopper boiler tubes for another $2 million. With an additional cost for replacing super heater outlet headers the cost came to $6.1 million, so even this relatively minor project should have triggered NSR. A larger project was the replacement of the vertical tube furnace with a spiral tube furnace on Unit 5 in 1984. Low NO_x burners were also installed for a total project price of $12 million.

Another big project was the replacement of the CR 77 pulverizers with MPS pulverizers on unit 6. This was a $16 million project The court cited other decisions as support for its conclusion that “the government has proven its case by a preponderance of evidence and accordingly the court finds with respect to all eleven projects that Ohio Edison is in violation of the CAA.”

Relative to the argument that Ohio Edison did not have fair notice it cites Chevron U.S.A. v. Natural Resources Defense Council and United States v. Southern Indiana Gas and Electric Co. Relative to the definition of routine maintenance, the court cited the WEPCO rule. Routine maintenance was also explained as very narrow (de minimus) in Alabama Power Co. v. Costle.

In its summary, the court found that most of the 11 projects would result in a net increase of NO_x and SO₂ emissions. Two of the activities would result in increases in PM₁₀ emissions.

These determinations are significant because they indicate that every power plant which has operated an older plant for any length of time will trigger NSR. Thus every power plant in the country is probably guilty of triggering NSR and not reporting it.

There is a consensus that continued litigation against each utility is not the best method of resolving the situation. But in absence of a new CAA the odds are seven to one that NSR alone will cause the installation of NO_x control in the next 15 years and probably in the next seven years (2015) at an individual plant which escapes control under other rules.

It is unclear how important the “CO₂ ready concept” will be in impacting the NO_x control market. But new pulverized coal plants permits have been rejected because the plants were not deemed to be CO₂ ready. A CO₂ ready plant is one which could add a CO₂ scrubber without major modifications to existing equipment.

This document indicates that SO₂ should be no more than 10 ppm to avoid creation of salts in the CO₂ clear liquor scrubbing system.

Some plants installing scrubbers in the near future will want to make them CO₂ ready. This may mean electing wet lime systems in order to meet the future efficiency requirements. Limestone systems with dibasic acid could also meet the 10 ppm. Dry systems would probably not be able to meet this low level.

The mercury reduction needs prior to CO₂ capture have not been addressed. But the likely need for more efficient scrubbing will have a bigger impact on mercury control technology selection.

A number of states have already passed mercury rules to require 90 percent removal at some point over the next ten years. There is a likelihood that in the absence of a new CAA most other states would pass similar regulations.

In May 2008 a study showed higher prevalence of autism near coal fired plants. But since mercury travels some distance it is unlikely that this finding will be more than coincidence. However, there is an outside chance that mercury would be linked to some serious problem for which it is not now presently blamed. This could push the mercury removal efficiency requirements beyond the 90 percent.

The analysis above which shows how unlikely is the drop in price of natural gas, also supports the case that the price will average well above $9/MMBtu and may well reach $20/MMBtu. The last time oil reached the present price levels there was a sudden rush to coal. In 1974 utilities ordered more than 60,000 MW of new coal-fired plants. The rush was similar to the 1999 rush to gas.

But shortly after this 1974 rush the price of oil fell sharply and the new coal plants were delayed or canceled. No quick fall in oil prices is anticipated this time around since the price is not based on arbitrary withholding of supplies. The odds are better than five to one that the price of natural gas will stay above $9/MMBtu and the 70,000 MW of new coal-fired capacity projected by DOE will be a conservative forecast.

Changes to existing coal-fired plants could cause net reductions of CO₂ by 35 percent. Replacement of these plants with new super critical boilers and the incorporation of other technology could make a net 55 percent reduction.

Net CO₂ emissions with incremental technology additions including credits as a percent of an existing coal-fired boiler without changes are shown in Figure 7.

These are net reductions and take into account the CO₂ emissions from the whole process of oil exploration through refining and gasoline transportation as opposed to ethanol production using the coal plant waste heat. The elimination of chlor alkali plants and their resultant CO₂ contribution is included.

The CO₂ reduction costs of either retrofitting existing coal plants or the construction of new super critical plants is very low compared to renewable energy alternatives or to CO₂ capture and sequestration. Furthermore all the technology is in place.

These opportunities to reduce CO₂ net generation from coal by 55 percent by replacing an old coal plant with a super critical boiler making ethanol and hydrochloric acid is very promising. It could result in as much as 200,000 MW of new coal capacity while reducing net CO₂ emissions. So the net addition of new coal plants would be 530,000 MW under this scenario (replacement of 330,000 MW of existing plants and addition of 200,000 MW of new plants).

Great River is moving ahead with the 66 percent efficient Spiritwood plant. It is already operating the Coal Creek plant which supplies all the heat needed at Blue Flint Ethanol. Others are sure to follow.

The odds are less than one to nine that the industry will take full advantage of this opportunity, but this would still result in 60,000 MW of new capacity absent other events. The odds are that this will cause a 20 percent increase in coal capacity absent other drivers, so we have estimated the odds at two to one rather than a greater certainty that at least a 60,000 MW addition will be achieved. Based on the rush to new coal plants in Europe this is a very conservative estimate.

The DOE reference case showing 100 GW of new coal-fired capacity including 29 GW of coal gasification and 4 GW equivalent of coal-to-liquids by 2030 is based on demand increase as follows:

We believe the odds are six to one or greater that demand will meet or exceed the DOE base case.

The problems with renewables were reviewed above under “Renewable Energy Costs Fall to Less than 200 Percent of Coal”. There is presently a shortage of wind turbines and no sign that renewables can compete for base load generation in the next 15 years

This subject is covered from the negative aspect above under “Renewable Energy Costs Fall to Less than 200 Percent of Coal.” Coal plant costs are rising. There has been a 50 percent increase in the installed cost of coal-fired generation since 2006. Coal prices have also risen, so the levelized costs have risen. But the prices of alternatives have risen at least proportionally, so the odds are better than five to one coal will remain less than half the cost of alternatives.

Rate payers will not support doubling electricity costs to reduce greenhouse gases.

This is covered above from the negative aspect under “Economics are Ignored.”

If coal plants could capture CO₂ and utilize it to recover oil from the many old oil fields which need to be pressurized to recover remaining oil, then there would be no environmental resistance to their construction. The problem is that the costs are high just to capture the CO₂. The economics of transportation and sequestration are very site specific. At this time we believe that the ability to cause an additional 60,000 MW of new construction is only one in ten. Details of the CO₂ capture costs are shown at:

As explained in the other categories above, the odds are at least nine to one that all coal plants will add scrubbers before 2023. However, at least some plants which will install scrubbers in 2011-13 are already committed to use activated carbon starting this year or in the next two years.

If the scrubber selected is dry then the odds for ACI are high. But even if wet scrubbers are selected ACI may still be used for additional removal. But the odds are against this combination.

Most scrubber selections will be wet. The high sulfur coal units will almost all opt for wet scrubbers. Some of the low-sulfur coal units will also opt for wet scrubbing because of the higher efficiency.

The first choice for units burning low sulfur coal is dry scrubbing. But as in the case of LCRA the existing precipitator was efficient and the levelized cost of wet limestone was viewed to be lower than dry lime. So, on a nationwide basis the odds are one to five that any particular unit will opt for dry systems.

There is a big market for activated carbon for units which will eventually scrub. State rules already in place will create a significant ACI market. As much as 10 percent of the units in the country could use ACI as an interim measure.

There is the unlikely possibility of combining activated carbon injection and wet scrubbing. The problem with ACI followed by a particulate collector and then the scrubber is that very high removal is needed with ACI to significantly affect the combined removal efficiency.

The dry scrubber can utilize the ACI effectively. Furthermore, ash sales are not a consideration when gypsum and flyash are both being captured in the same baghouse.

There are options to remove mercury downstream of a wet scrubber. This could be a very big potential if the MACT level was higher than 90 percent. If a combination scrubber and post scrubber device could cost effectively achieve 95 percent removal or higher, then the technology could drive the regulations.

Several options to ACI would serve the same function. None is now a serious contender but the potential is there.

J-Power REACT, the Powerspan technology and some others are possible contenders to take at least a small part of the market.

With the use of additives prior to and in the scrubber the potential for 90 percent or greater mercury removal in the scrubber is high.

Biorem Inc. announced results for the first quarter ended March 31, 2008, which are summarized in Figure 8.

First quarter revenue was $3,184,000, which is up $1,415,000 or 80 percent over the comparative period in the prior year. This also represents an 8.4 percent increase over revenue in the 4^th quarter 2007 and a very encouraging trend of four continuous quarters with revenue increases. Strong revenue growth has resulted from the successful implementation of the major sales initiatives adopted in early 2007 to bring special attention separately to the municipal and industrial marketplaces and to build a very strong manufacturing representative network.

New orders in the quarter were $2,150,000 resulting in a current order backlog of $9 million. The backlog is up $1.3 million or 17 percent from March 31, 2007.

Gross profit in the quarter of $1,455,000 is up $837,000 from last year's comparative quarter resulting from increased revenue as well as improved margins on projects. This improvement has driven the gross margin up to 45.7 percent compared to the 1^st quarter 2007 of 34.9 percent.

Operating expenses were $1,219,000 which is up $265,000 or a 27.8 percent increase compared to the comparative quarter of $954,000. The largest increases are as follows:

· Sales and marketing expenses of $620,000 are up $231,000 or 59.4 percent to account for higher commissions as well as increased personnel costs.

· Research and development expenses are up $94,000 or 61.8 percent from 2007 primarily due to activity associated with an ongoing research program targeting industrial air pollution product development.

· There was an exchange gain of $102,000 in the 1^st quarter 2008 as compared to an exchange loss in the comparative period of 2007 of $14,000.

Although operating expenses were higher than last year’s first quarter, the significant increase in gross margin brought the company to a positive net earnings of $104,000 compared to a loss of $375,000 in the 1^st quarter 2007.

The company’s liquidity improved significantly in the 1^st quarter 2008. Net working capital increased by $337,000 in the three-month period. Total working capital at March 31, 2008 was $4,201,000.

Commenting on the quarterly results, Peter Bruijns, President and CEO said, “The very favorable results confirm the positive direction of the company’s sales restructuring from last year. Not only are the number of orders per quarter increasing, the average deal size is rising as the company is winning many large orders. It is also encouraging to see a healthy gross margin which is expected to continue throughout 2008.”

BIOREM^® went on to announce that, as part of an internal reorganization, the Director of Operations has departed from the company. Peter Bruijns will take responsibility for this function in the interim as the company builds best-practices and determines the most cost effective structure to deliver on the expanding business and new orders from both North America and internationally.

BIOREM recently received two orders totaling $1 million for odor control systems in the states of Florida and Texas. The projects include a large biotrickling filter project in Cape Coral, FL valued at over $800,000 and a modular biofilter order for the City of Corpus Christi, TX.

The Cape Coral installation will utilize the Mytilus^® product line. These large-scale biotrickling filter systems were introduced within the last several years to strategically expand the market size for the company. The Corpus Christi system will use the well-established Basys biofilter and is the fifth system installation for this customer. This shows the continued satisfaction that the company’s customer base has in the BIOREM^® product line.

“The biotrickling filter for Cape Coral will treat 10,000 cubic feet per minute of foul air. We have been advancing our trickling technology dramatically, which has resulted in our capability to supply state-of-the-art systems to end-users.” said Peter Bruijns, President and CEO. “The Cape Coral installation is a fast track project to be completed within six months. BIOREM^® has a history of quality performance delivered on time and this was a key factor in the selection process.

221111	Hydroelectric Power Generation	4911	Electric Services (hydroelectric power generation)
221112	Fossil Fuel Electric Power Generation	4911	Electric Services (fossil fuel power generation)
221113	Nuclear Electric Power Generation	4911	Electric Services (nuclear electric power generation)
221119	Other Electric Power Generation	4911	Electric Services (other electric power generation)
221121	Electric Bulk Power Transmission and Control	4911	Electric Services (electric power transmission and control)
221122	Electric Power Distribution

2007 NAICS	2002 NAICS	1997 NAICS	Index Entries for this Industry
327410	327410	327410	Agricultural lime manufacturing
327410	327410	327410	Calcium hydroxide (i.e., hydrated lime) manufacturing
327410	327410	327410	Calcium oxide (i.e., quicklime) manufacturing
327410	327410	327410	Dolomite, dead-burned, manufacturing
327410	327410	327410	Dolomitic lime manufacturing
327410	327410	327410	Hydrated lime (i.e., calcium hydroxide) manufacturing
327410	327410	327410	Lime production
327410	327410	327410	Quicklime (i.e., calcium oxide) manufacturing

Negative Events for Retrofit	Odds Against # to 1
Asteroid Collision	20 million
Global Warming Catastrophe	20 million
Natural gas price drops below $4/MMBtu	1,000
Carbon tax is exorbitant	100
U.S. is only wealthy country without FGD on all plants	100
Anti-environment Executive and Legislative branches	100
Renewable energy costs are below 200% of coal	50
Nuclear impact is major	30
Gasification is major	20
Additional Negative Events, New Coal-fired Power Plants	Odds Against # to 1
Environmental lobbies are completely successful	5
Economics are ignored	5
Positive Events for Retrofit	Odds for # to 1
New Clean Air Act Amendment	10
Carper Mercury Law for Oct 08 proposal	0.02
PM_2.5 NAAQS Rule	10
MACT for Toxics	10
Increase capacity	4
NSR litigation if no other law	7
Regional Haze Rule	7 (but only for about 1/3 the units)
CO₂ Ready	Affects Type
Most states pass 90% MACT rules if there is no national rule on mercury	5
Mercury link to autism or other new health risk	0.001
Positive Events for New Coal-fired Power Plants	Odds for # to 1
Gas price exceeds $9/MMBtu	5
Co-firing, ethanol, hydrochloric acid	2
High electricity demand	6
Renewables supply limits	5
Nuclear supply limit	5
Coal is less than half the cost of alternatives	50
Rate payers will not support doubling electricity costs to reduce greenhouse gases	5
Carbon Capture Economic	0.1

Events shaping mercury technology selection	Odds for # to 1
Scrubbers for any plant	9
Wet scrubber selected	3.5
Dry scrubber selected	0.2
Activated carbon used prior to scrubber installation	0.1
Activated carbon used with wet scrubber	0.02
Activated carbon used with dry scrubber	8
Mercury removed down stream of scrubber	0.05
Substitutes for ACI used	0.07
Hybrid multi pollutant device	0.07
All mercury removed in wet scrubber	2

	First quarter ended March 31
Information in table is in thousands except per share data	2008	2007
REVENUE	$3,184	$1,769
GROSS PROFIT	1,455	618
EBITDA	236	(336)
NET EARNINGS	104	(375)
BASIC EARNINGS PER SHARE	0.01	(0.03)
DILUTED EARNINGS PER SHARE	0.01	(0.03)
WEIGHTED AVERAGE COMMON SHARES	11,978	11,978