Future of Coal in Illinois: Case study Fisk 19 Amy Hee Kim, Jon Handy, and Kendrick Sands

Introduction

Recently, people have become much aware of the environmental impact of energy

generation in our country. Despite the fact that burning coal has proven to be a very

useful source of electricity over the last 100 years, it has also released large amounts of

gases into the atmosphere, most of which can be directly linked to global warming.

However, despite greenhouse gas emissions and substantial investment in alternative

energy sources, coal will remain a large source of electricity generation for the next 100

years, largely because of its easy availability and cheap price. Consequently, continued

development and testing of new coal technologies that can reduce coal’s negative

environmental impact is essential. It is important to note, though, that while continued

development and implementation is important, due to the large expense attributed with

such new technologies it is crucial to make sure that government policy be created and

implemented in such a way as to make the new technologies more economical. As a way

to fully understand just how feasible the implementation of new “Greener” technology is

it is important to analyze the costs and benefits of various options regarding specific

power plants that are likely to, in the future, be faced with the decision of upgrading their

facilities. In this study, we have concentrated our efforts to describe the future of coal in

Illinois and used FISK Unit 19, a Chicago-based plant, as a case study.

Background

Despite the increased awareness of renewable energy sources, currently more than

five hundred 500MW coal-fired power plants produce over 50% of the United States’

electricity need; the largest number of which can be found in the upper Great Lakes and

Southeastern states each power plant having an average age of 35 years. The typical plant

uses an air blown pulverized coal combustion method with an average efficiency of 33%

and emits an annual 3 million tons of CO2 over its 30-year lifespan. Consequently, coal

power generation accounts for roughly 34% of U.S. greenhouse-gas emissions. In general,

only a third of currently operating coal plants have a method of desulfurization installed,

less than 10% of them have post combustion NOx control, and only about 25% of

mercury is removed after combustion. Most of the country’s coal plants can be well

modeled by the power plants in Illinois, which practice very similar burning methods as

well as cleaning methods. In this study we analyze the potential scenarios facing Fisk

Unit 19 and use these results to better model and understand the decisions facing other

similar plants across Illinois.1,2

Fisk 19 is one of two coal power plants located within the city limits of Chicago,

and was first built in 1903, acting as the first power plant in the U.S. to operate entirely

on steam turbines. Unit 19, the grandfather of 18 prior plants, was built in 1959, and

currently generates 363MW of electricity a year, which is mainly used to stabilize

Chicago’s electric grid during peak hours. Despite the fact that over 32 billion tones of

coal is mined every year in Illinois, Unit 19 uses 7000 tones of Wyoming Powder River

Basin (PRB) coal daily in its pulverized coal combustion boilers to generate electricity

with a 35% efficiency rate, one that is significantly less than newer facilities. The

production process begins when coal is removed from the loading barge and sent to one

of eight mills where it is pulverized and air-blown into one of the two furnaces. As the

coal is burned heat generated from the furnaces creates steam that generates electricity by

driving two Allis-Chalmers turbines. An end result of the combustion process is a

mixture of bottom ash and fly ash found on the furnace floors, which can be collected and

used as a soil stabilizer as well as an additive to cement. After the “Cleaner Air Act” was

passed, Fisk did install SO2 scrubbers that reduced the SO2 emissions below the cap-and-

trade limit, however after electricity generation, over 4 million tons of CO2, 130 tons of

soot, and 279 pounds of mercury (even after some degree of mercury capture in the stack)

are still released into the air.

1 www.lib.niu.edu 2 “The Illinois Coal Industry”, June 2006. Report of the Department of Commerce and Economic Opportunity, Office of Coal Development

It is important to note that one of the reasons why Fisk 19 operates, even though it

does not produce significant amount of electricity, is due to its “Black Start Capability.”

The plant has the capacity to restore power to the nuclear plants in its vicinity in the case

of complete grid failure during blackouts without relying on external energy sources, an

ability that not all power plants have.

Coal power generation

Coal-fired boiler technology has developed rapidly over the last century. Today

most coal power plants in America use pulverized fuel boilers (PF).3 In a typical PF

boiler, coal is ground into fine particles before being injected with air through a number

of burners into the bottom of a combustion chamber. The particles are burnt in

suspension which releases heat that is transferred to water tubes in the walls of the

combustion chamber. This process generates steam at both high pressure and temperature

which is fed into a turbine and generator set to produce electricity. PF boilers are defined

as “sub-critical” if the steam is generated at a pressure below the critical pressure of

221.2 bar. At high pressures, there is no distinct water and steam phase transition, and the

boiler is defined as “supercritical”. Supercritical PF boilers have 5% increase in

efficiency compared to sub-critical PF. Majority of American power plants, mainly due to

its old age, are sub-critical, therefore, in order to improve PF plant efficiency it is

important to continue developing ultra supercritical boiler technologies.

Efficiency of a power plant is not only dependent on the combustion method but

also on the type of coal used for combustion. Coal type and quality impact the technology

choice, generating efficiency, capital cost, performance, and the cost-of-energy. The

energy, carbon, moisture, ash, and sulfur contents as well as ash characteristics, all pay an

important role in the value and selection of coal. As shown in figure 1 the transportation

cost and technology cost of these different types of coal must be taken into consideration

when deciding which coal type to rely on because each type can drastically affect plant

performance. For example, bituminous coal, which has high sulfur contents, reduces the

3 “Post-combustion decarbonisation processes” D.W. Bailey and P.H.M. Feron, Oil & Gas Science and Technology 60(2005) No.3, pp 461-474.

Figure 1. Typical properties of characteristic US coal types 4

generating efficiency due to the added energy consumption and operating cost required to

remove the sulfur oxides from the flue gas. If coal types with lower energy content and

higher moisture content like sub-bituminous PRB coal are used, then there will be an

increase in capital cost and a reduction in generating efficiency because more coal must

be used in order to generate and equivalent amount of energy. However, despite the loss

of heat, one of the main advantages of using PRB coal instead of Illinois #6 coal (type of

Bituminous coal) is the coal’s significantly lower price.

For our research we have concentrated on Fisk Unit 19, a plant that uses

pulverized fuel boilers at sub-critical pressure to burn Wyoming Powder River Basin sub-

bituminous coal. For our purposes we have only considered cases where Fisk will

continue to use PRB coal, due to the high expense of switching to another fuel type

which will be shown later in the paper.

Carbon Capture and Storage

A major step in improving the quality of energy production is the reduction of

greenhouse gas emissions. For a typical air-blown PC combustion unit retrofit includes

the an additional processing unit placed on the flue-gas system’s back end to separate and

capture CO2 and to dry and compress the CO2 to a supercritical fluid which is ready for 4 “Cost and performance of fossil fuel power plants with CO2 capture and storage” E.S. Rubin, C. Chen, and A.B. Rao Energy Policy Coal has proven to be a very useful source of electricity generation for the last 100 years 35 (2007), pp 4444-4454

transport and sequestration. It is important to note that many other similar technologies

have been developed but large portions of these are still in relatively early stages of R&D.

Currently, coal power plants wishing to reduce CO2 emissions will probably do so by

using chemical absorption, a method most commonly known as wet-scrubbing. The

process is relatively simple: the flue gas will transfer through a chemical solvent, usually

alkano-amines, packed in a tower and reacts with absorption liquid. By taking advantage

of the exothermic and reversible nature of the chemical reaction, concentrated CO2 can be

easily captured separated from other components of the air. The most common and

currently commercially available solvent is mono-ethanol amine (MEA) that can be

mixed with corrosion inhibitors. It needs to be emphasized that there is a significant drop

in efficiency of the plant when carbon scrubbers are installed; for example, once CO2

scrubbers are installed, Fisk will go from operating at 35% efficiency down to 25%

efficiency.

Currently, much research is being done to make the scrubbing process more

efficient: different types of solvents are being used such as ammonia instead of MEA;

different chemical additives are being used to increase the CO2 concentration after

scrubbing; and the temperature conditions of the solvents are being optimized so that

scrubbing can commence at an environmentally friendly temperature and pressure. Other

post-combustion methods include the membrane process, which requires the flue gas to

be compressed to high pressure, and the adsorption of CO2 using zeolites or activated

carbon, which can later be heated to capture only the CO2.

A few coal plants in Canada are being built using oxy-fuel combustion.5 Oxy-fuel

combustion was developed to eliminate the need to capture carbon dioxide from flue gas

at a low concentration and low partial pressure, a consequence of the flue gas’ large

quantity of nitrogen. By burning the coal in a high O2 environment (produced in an air

separation unit) instead of normal air, the CO2 concentration in the flue gas is increased

(up to 98%) which makes it easier to recover and compress the CO2. This method is

sometimes called “zero emission,” but it is important to note that some fraction of the

CO2 generated during combustion will inevitably end up in the condensed water requiring

5 “Oxyfuel boiler design in a lignite-fired power plant”, E. Kakaras, A. Koumanakos, A. Doukelis, D. Giannakopoulos, and I. Vorrias Fuel 86 (2007) pp. 2144-2150.

the water to be appropriately treated or disposed of. It is important to note that the reason

why technologies such as these are so expensive is the separating of O2 and N2, a difficult

process that consumes much of the energy.

Another method that might be observed at plant trying to reduce emissions is the

chemical looping combustion method. When used as a solid oxygen carrier that reacts

with the fuel in the fluidized bed combustor, metal oxides produce solid metal particles

and a mixture of carbon dioxide and water vapor. The water vapor can be condensed

leaving only the CO2 to be sequestered. The solid metal particles can be circulated to

another fluidized bed where they react with air (producing heat which can then be used to

generate electricity) and regenerating metal oxide particles that can again be circulated to

the bed combustor.

An interesting case study in Brazil showed that microalgae could be used for bio-

fixation of carbon dioxide.6 Studies show that plants, by installing large tanks of

microalgae ponds nearby, may created an environment that successfully lowers its CO2

emissions due to the fact that nearby algae source consume most of the CO2 to sustain

their photosynthetic processes. However, studies also show that depending on the

concentration of CO2 as well as other characteristics of the plant emissions the growing

conditions of the microalgae may differ (Maximum growth attained with 12% CO2.)

Despite recent advancement in CO2 capture technologies these new techniques

still require a large amount of funding and much work is to be done to ensure their

efficiency and sustainability.7 More studies must be conducted to evaluate each plant’s

“capture-readiness” to determine which plant can be retrofitted for carbon dioxide

capture and still operate efficiently. Along with the development of new combustion

methods, the development of new carbon capture methods should be continued;

especially since these methods can also reduce the greenhouse gases emitted by

transportation methods. In our case, we will only consider using MEA wet-scrubbing

technology as an option to reduce CO2 emission since it is at the most advanced stage of

development and the only currently available commercial method. In our study, we did 6 “Isolation and selection of microalgae from coal fired thermoelectric power plant for biofixation of carbon dioxide”, M.G. de Morais and J.A.V. Costa, Energy Conservation and Management 48(2007), pp 2169-2173. 7 “Comparison of CO2 removal systems for fossil-fueled power plant processes”, G. Gottlicher and R. Pruscheck, Energy Conservation Management 38(1997), pp S172-S178.

not include the process of sequestration due to its large unknown stability and safety. We

only considered capture of CO2.

IGCC

Energy experts believe that in the near future integrated gasification combined

cycle (IGCC) power plants will replace our aging coal power plants. All IGCC plants use

similar processes: the coal, mainly bituminous and/or petroleum coke, is pulverized and

gasified with oxygen to produce a synthetic gas called syngas, which is then also mixed

with hydrogen and carbon monoxide. Next, the pollutants, mainly sulfur and mercury, are

removed from the syngas. Electricity is then generated using combined cycle technology,

a technology similar to modern natural gas fired combined-cycle power plants. In the

combined-cycle, a gas turbine-generator burns the syngas to create the heat used to create

steam that powers a steam turbine generator. The fact that the IGCC method both

captures CO2 and produces hydrogen that can be sold for additional revenue make is a

very economical option (The IGCC plant process is summarized in figure 1-2.)

Figure 1-2. Summary of processes involved in IGCC plants8

8 www.futuregenalliance.org

Ultimately, IGCC plants have significantly lower SOx, NOx, and particulate

emissions, they emit approximately 20% less CO2 emission, use 20~40% less water than

modern coal plants, and it is estimated that IGCC plants will operate at higher

efficiencies (upward of 60%.) However, it is important to note that these plants are much

more capital intensive than their PF counterparts, and still require a great deal of R&D.

Until recently there have only been four IGCC demonstration plants completed, all

requiring significant financial support from Department of Energy (DOE). Only two of

these units are currently generating electricity: Wabash River Power Station in Indiana

and Polk Power Station in Tempa, Florida. All previous IGCC power plants have

required significant post construction adjustments, and the plant in Nevada was

eventually shut down due to its complications. A recent analysis shows that operating the

Polk Power Station is very similar to operating a petroleum refinery, a plant that requires

continuous attention to avert, solve, and prevent the problems that can periodically arise.

In this sense, the operation of an IGCC unit is significantly different from the operation

of a PF unit, and requires a different operational philosophy and strategy.

In December 2007, the DOE selected Mattoon Illinois as the home of the new

“FutureGen” IGCC power plant, an experimental plant that was to be built as a way to

increase IGCC plant efficiency and as well as combine newly developed technology into

one unit. FutureGen, an alliance of a dozen big power and coal companies and the

government, got together and decided to build the first IGCC plant to generate electricity

while capturing and permanently storing carbon dioxide deep beneath the earth. The

original intentions were that the plant would integrate advancing technologies for coal

gasification, electricity generation, emissions control, CO2 capture and storage, and

hydrogen production, and would use all these technologies to test the technical and

commercial viability of complete IGCC integration. The 275MW plant was estimated to

cost $1.8 billion dollars, which caused the DOE to cancel this project in January 2008

dealing a possible major blow to the Illinois economy (Illinois #6 would have been the

main sour of fuel for the plant and it would have created 100s of construction jobs.) As of

May 2008, the DOE unveiled a new blueprint for spending $1.3 billion on multiple clean

coal power plants, including IGCC as well as various other plant types (mainly PF), that

would add the capability to capture carbon emissions and permanently store them. The

rational is that it is wiser to spread taxpayer money around several smaller projects

through the entire country rather than localizing the entire budget to one plant. They

believe that by spreading the budget to multiple power plants the technology becomes

commercialized rather than being solely experimental, and as a result the capture and

sequestration of carbon emissions will double when the technologies are spread. As of

right now, the fate of Mattoon IGCC plant is still being debated in the Senate and the

fight will most likely continue until 2009, when the new president enters the Whitehouse.

But, it is important to note that there is still a great need of R&D required to optimize the

IGCC process combined with carbon capture and storage. Without further research, the

technology might not become commercially available in the near future.9

In addition our study of Fisk 19 remaining the same we will the consider building

of a new Fisk Unit 20, an IGCC plant using Illinois #6 coal with carbon capture.

However, due to the fact that much of the technology is still being research we have had

to assume that IGCC research funding will continue as is and it is important to note that

all calculations regarding construction and operation cost are under the assumption that

IGCC technology becomes mature in the next few years.

Policy Regarding GHG Emissions

Policy Assumptions

The general trend regarding a baseline for greenhouse gasses (GHG’s) has been

1990 levels. This standard is present on the national and local levels of government, as

well as internationally, where it can be seen in the Kyoto Protocol, which requires a 5%

reduction below these 1990 levels by 2012. The methods for reduction are more

complicated and incorporate a variety of instruments that cross national borders and set a

priority on industrialized rather then industrializing or developing nations. Furthermore,

a significant portion of these industrialized nations appears unable to meet the 2012

deadline. The U.S. opted out of this treaty because of competitive advantage issues but

since then, the individual states have taken the lead on GHG reduction.

9 “Mounting costs slow the push for clean coal”, Matthew L. Wald, The New York Times May 30, 2008

Ultimately, although it is apparent that, because of the scope of climate change, an

international solution must reach a consensus before it becomes effective (likewise for

any U.S. Policy as well), there must also exist a national policy. However, while this is in

the process of being created, many of the states are already begun to implement policy

similar to that of Kyoto Protocol. The first of such initiatives was the Global Warming

Solutions Act of California enacted by Governor Schwarzenegger in 2006 that caps

California’s GHG emissions at 1990 levels by 2020. Following suit Oregon, Hawaii,

Washington, New York, Maine, Vermont, New Hampshire, Rhode Island, New Jersey

and Connecticut set a target of a ten percent reduction of GHG emissions from 1990

levels by 2020. Other states have set less ambitious goals that establish 2005 or 2000 as

the baseline for emission levels and require similar reductions by 2020 of these levels.

These targets are illustrated in figure 2-1. The difficulty of states in achieving these

goals independently is obvious and has required the forming of regional agreements.

Figure 2-110 GHG emission targets for individual states

10 Image from Pew Center on Global Climate Change “Learning from State Action on Climate Change.” December 2007 Update p. 14

These regional agreements represent the need of a national policy and operate in

many respects as test cases for what the national policy will be. The regional agreements

have various differences in benchmark years, methods of reduction, emphasis on

renewable/alternative sources of energy and enforcement capabilities, but there are a few

similarities to note. (Figure 2-2 summarizes these regional agreements.) The majority of

states, as well as regional organizations, have adopted 1990 as the benchmark year and

developed renewable portfolio standards that set minimum renewable energy

requirements on electricity generating companies. There is also a consensus among

states that a cap-and-trade system for carbon dioxide emissions would be the most

effective method of reduction. Congress has attempted to make a national program;

however, it has become clear that the executive branch heavily influences environmental

policy for the U.S. Since we are nearing a presidential election it is worth considering the

prospective candidates proposals.

Figure 2-211 Summary of regional initiatives across America

11 Image from Pew Center on Global Climate Change “Learning from State Action on Climate Change”, December 2007 Update, p.4

The reduction of GHG emissions to prevent climate change has become a

significant issue in this election and the candidates have responded with structured plans

on how to address the problem. Candidates from both political parties are strongly in

favor of implementing cap-and-trade of CO2 emission, similar to European standards,

instead of tax on emission. Senator Obama (and Senator Clinton), the democratic

candidate, proposes using the 1990 benchmark to reduce carbon dioxide emissions 80%

by 2050. The Republican Candidate, Senator McCain, also uses the 1990 benchmark but

propose reaching it by 2020 and by having a 60% reduction of these levels by 2050. As

illustrated by these proposed policies, whether a democrat or republican is president in

the next election, reducing GHG emissions based on the 1990 level will be a priority.

Specific Illinois Standards

The National policy is likely to compliment the Illinois GHG emission’s

reduction standard. Governor Blagojevich established the Illinois Climate Change

Advisory Group as part of the Illinois Environmental Protection Agency (IEPA) in 2006

with executive order 2006-11 to explore methods of GHG emission reduction. This

group has suggested a Cap and Trade program on the state level be implemented. The

program is to start in 2011 and reach 1990 levels by 2020 in accordance with the

Governors targets. There are some complications when applying this policy to the coal

burning sector of the electricity generating industry of Illinois.

The problems arise when considering how these standards will be implemented.

Midwest Generation, a subsidiary of Edison International is responsible for Fisk, and five

other coal power plants totaling 91% of coal for energy consumption in Illinois. Since

Midwest Generation was founded in 1999 it would be difficult to apply this standard to

them unless the specific coal plants are targeted. This also has potential of inefficiency

when considering the cost of carbon dioxide scrubbers as will be discussed later in the

paper. We will then assume that each plant, including Fisk, will have to meet their 1990

carbon dioxide levels that we can calculate from the amount of coal consumed by the

plant.

We will also assume that there will be gradual increase from 2011 to 2020 of the

GHG emission targets. If the 1990 levels are the target, [254,400 tons] and there is a time

frame of 9 years, we subtract the current consumption [2,555,000 ton] from 1990 levels

and get the amount to be reduced by 9 years [2,300,600]. This amounts to a 255,623 ton

reduction for nine years; or a 10% reduction from current consumption. As outlined

earlier, the various carbon dioxide capture methods are efficient in capturing a large

amount of these admissions and we will compare these benefits against the costs of

upgrading the plant.

Policy Recommendations

There are lessons to be learned from previous environmental initiatives that

should be applied to the future Cap and Trade policy. The policy should allow for a

degree of innovation by Midwest Generation and the specific coal plants as is allowed

under the current SO2 cap and trade program. This innovation should not be confused

with loopholes that have become apparent in the SO2 system as well as the European

experience with carbon trading. Avoiding these problems will maximize program

efficiency as well as minimize the effects of global climate change.

In the European carbon trading system, the initial distribution of permits resulted

in an artificially low price of carbon and saturation of the market. By learning from this

experience, a standard price should be guaranteed for a ton of carbon abated. The

structure of the trading should also mirror that of the European Carbon Exchange and the

activities of the U.S. closely connected with it. Because climate change is a global

concern, there should be global coordination of industrialized, as well as industrializing,

nations.

Specific to Illinois there are a few policy modifications that should be taken into

account that are illuminated by the SO2 trading system. When SO2 limitations were first

established some plants were shut down because of the natural life of the power plant was

expired. Credits were then distributed based on a business as usual scenario for the

expired power plant even though it wasn’t operating and thus wasn’t abating any

emissions. Midwest Generation would have a similar incentive in the event of a tax on

GHG emissions, closing one of the two coal plants in Chicago to keep the other emitting

at a business as usual rate. By holding each power plant to its 1990 rates of GHG

emissions this incentive would be avoided. Along the same lines, if a plant has already

decreased coal consumption by 1990 or the plant was built after 1990 then a separate

standard should be applied based on the average reduction of coal plants, most likely a

ten percent reduction per annum to a set standard that allows for a limit on CO2 emission

per Mega Watt Generated. This would assure that the policy would not be avoided or

ineffective in its objectives. As the cost benefit analysis will show, the reduction of GHG

emissions in Illinois is a viable strategy. We chose the Fisk generating station to show

that this policy will work even for coal plants that are subjected to the most stringent of

regulations. By providing economic incentives for electricity generating companies to

incorporate the externalities that arise due to GHG emissions, there is a greater chance

the policy will succeed.

Cost Benefit Analysis

By way of a benefit-cost analysis we are able to see which scenario, under certain

circumstances, is the most beneficial; that is to say which scenario has the highest net

revenue. In order to do such a study it is necessary to make certain assumptions due to

either a lack of obtainable data or the added difficulty of calculating results that are

neither significant nor beneficial to our study. In order to calculate the emission levels of

the 500 MW IGCC Plant we have had to maintain that a 363 MW PC plant sustains

energy production by using 7000 tons of coal each day12 and that this ratio of coal to

energy output is constant across plants, that is to say that there is no existence of

economies of scale. We have also had to assume that operating costs across plants are

similar, and consequently that these costs add nothing to the net-benefit of the model. We

have had to assume that SO2 trading produces insignificant revenue for all plants, and

that all emissions of trace elements have little or no external costs. Finally, we have had

to assume that all plant action aimed at reducing CO2 emissions will begin in the year

2010, two years after implementation of emissions reduction policy, and that the

12 Delaney, George. Personal interview. 5 May 2008.

European market price for Coal, currently $41.20 accurately prices the externalities of

CO2 emissions.13

The first scenario that Fisk Unit 19 faces, and perhaps the easiest from a logistics

standpoint, is to stay just the way they are: they will continue to use Wyoming Powder

River Basin Coal (PRB) and freely emit CO2. The costs faced from such a scenario is that

they will continue to pay coal fees, they will continue to pay transportation fees to ship

the coal to the plant, and they will continue to impose an external cost upon society by

freely emitting CO2. Each of these costs can be found in Figure 3-1. It is important to

note that the difference between the costs of a PF plant like Fisk Unit 19 without

considering the social impact of CO2 is substantially less than the cost of a plant

operating when adding the additional externality prices. One might ask why then do coal

plants continue to operate as they do if the costs to society are so high? The answer is that,

by the definition of externality, these costs don’t appear on company budget sheets

because these costs are someone else’s costs. Coal plants, as do all firms, act in such a

way as to maximize their revenue, and do not consider social costs, until government

policy, or some other regulating force, is placed in such a way that “internalizes” these

social costs. After summing the annual operating costs as well as the annual social costs

Figure 3-1 Case scenarios of Fisk remaining the same with two different coal types 13 PointCarbon.Com. 20 May 2008 <www.pointcarbon.com>

and discounting them at a 7% discount rate over a 30-year period (the estimated coal

plant lifetime) the total cost upon Fisk Unit 19 and society is just under $3 Billion.

The second scenario Fisk Unit 19 faces is to switch coal sources and begin to use

coal from its home state of Illinois. Illinois is home to large veins of a coal labeled

Illinois #6 coal. This coal is a bituminous coal that burns much hotter than PRB coal and,

consequently, much less is needed to fuel a plant. However, what bituminous coals gain

in high energy density they lose in “environmental friendliness,” due to their large CO2

density. By using Illinois #6 coal Fisk 19 will be able to produce 363MW of electricity at

a cost of only 5357 tons of coal per day, and will not have to pay the substantial

transportation fees to import it from Wyoming. Much to the downfall of Illinois coal

producers though, the cost of extracting Illinois #6 coal is much higher than that of PRB

coal and consequently is sold at a price of $27.46 /t coal14, just over ten dollars more than

Wyoming PRB, including transport costs. By adding an the additional social costs from

burning carbon dense coal the total discounted cost of energy production jumps to over

$3 billion! These results can all be found on figure 3-1.

Fisk’s third option is to shut down unit 19 and rebuild unit 20, an IGCC plant with

carbon capture, in its place. By relying heavily on a study done by the Massachusetts’s

Institute of Technology, labeled “The Future of Coal,” the total cost of building and

operating a 500MW IGCC plant, discounted over 30 years totals to just over $1billion

without including any sort of social cost.15 This is substantially higher than both the PRB-

burning plant and the Illinois #6-burning plant at a ratio of nearly 2:1. In all fairness

though, certain underlying facts must be brought to light in order to accurately assess this

price. This number is based on the production costs of a 500 MW plant instead of a

363MW plant, so if the city of Chicago wanted to strictly maintain its current level of

energy production it would lower the amount of energy produced at the Crawford Plant

(Chicago’s Second power plant) by 137MW. By totaling the cost per megawatt of

electricity produced at Crawford (assumed to be the same as that at Fisk) and discounting 14 Edward S. Rubin, Chao Chen, Anand B. Rao, Cost and performance of fossil fuel power plants with CO2 capture and storage, Energy Policy Volume 35, Issue 9, , September 2007, Pages 4444-4454. 15 Katzer, James, Executive Director. The Future of Coal. Massachusetts Institute of Technology. Massachusetts Institute of Technology, 2007. 1-175. 25 May 2008.

it over 30 years the price of building and running the IGCC plant shrinks to just over

$600,000,000 which, though still larger than the cost of the PRB Plant and the Illinois #6

plant without including social costs, but is drastically lower than both plant when social

costs are included. These results can all be found on figure 3-2.

Figure 3-2 Case Scenario for building Fisk unit 20, and IGCC plant with carbon

capture

With rising concerns about global warming and with increasing knowledge of the

consequences of excessive CO2 emissions, it is likely that the state of Illinois as well as

all of the United States will begin to see more legislative action restricting CO2 emissions.

To elucidate the effects of emissions policy upon the cost of plant operations we have

decided to calculate the total costs of operation over the next 30 years under the plan

proposed by Illinois Governor Blagojevich. Under his policy Fisk Unit 19 will have to

reduce it’s emission to 1990 levels by 2020. In 1990 Fisk Unit 19 emitted close to

475,000t CO2 compared to today in which they emit approximately 4,740,000 t. In order

to meet these requirements Fisk would have to reduce emissions by 427,325 t CO2 each

year until 2020. Under the assumption that Fisk will begin reducing its emissions starting

2010, they will have to either cut an additional 10% of emissions each year until 2020

and then maintain emission levels or purchase CO2 permits (1 permit per ton) for emitted

CO2. Were to Fisk to continue to freely emit CO2, under Blagojevich’s policy they would

have to purchase 427,325 permits initially and add an additional 427,325 yearly until

2020, after which they will be purchasing an annual 4,273,250 permits per year. At a

price of $41.20/permit the total discounted costs of Fisk Unit 19 would be

$1,320,540,976.51. These results can be found on figure 3-3.

Fisk Purchasing only Permits:

Fisk 1990 Coal Usage: 254,400 t/yr 1990 Co2 Level 472,662 t Co2

Fisk 2008 Coal Usage 2,555,000 t/yr

2008 Co2 Level 4,745,912.5 t Co2

Required C02 Reduction by 2020: 4,273,250.5 t Co2

Initial 10% Decrease 427,325.5 t Co2

Total Discounted

Costs over 30 years: $1,320,540,976.51 Figure 3-3 Cost of permits if Fisk were to only buy permits

As mentioned earlier in the paper there exists multiple ways to lower CO2

emissions, so it is quite possible that Fisk may decide that they will update the facility

with CO2 scrubbers. CO2 scrubbers initially cost an estimated $921/KW for a total fixed

cost of $334,323,000; however, these scrubbers also need energy to be run and use

approximately 30% parasitic power from the plant. As a result, Fisk must purchase an

added 766,500 tones of PRB coal per year in order to keep power levels at 363MW.

Taking this into considering, the price of scrubbers jumps from $334 million to a 30 year

discounted price of $500 million, a substantial increase. However, to be fair, under the

assumption that a cap and trade program exists Fisk 19 will be able to sell CO2 permits

for a length of time and will actually regain some of the cost. As the policy states Fisk,

beginning in 2010 will be able to emit a certain amount of CO2 that is decreasing by 10%

of the difference between 2008 levels and 1990 levels. It is true that at 2020, Fisk is

required to only emit 472,662 t/ CO2 annually, and that even with the scrubbers installed

they will have to purchase approximately 452,791 permits annually, however from 2010

until 2018 they will be scrubbing enough CO2 from the air that they are under their

emission requirements. By being able to sell permits for these extra CO2 tones not

emitted Fisk is able to earn $439,693,977 discounted over nine years. It is important to

note though that despite these earnings the combination of later permit purchases as well

as the fixed/upkeep costs of the scrubbers would cause Fisk to lose just over $150 million

over thirty years over and above the costs of running without any sort of regulation.

These results can be found on figure 3-4.

Figure 3-4 Cost of Fisk if CO2 scrubbers installed along with purchasing permits

The CO2 emission target for both cases are the same represented in blue in the plot

below and the actual emission allowed for both cases are represented in red and green. As

you can see if a scrubber were installed instead of just purchasing permits, Fisk 19 will be

actually be able to reduce the carbon emission and nearly meet the emission target by

2019.

Fisk 1990 Coal Usage 254,400 t/yr 1990 Co2 Level 472,662 t Co2 Fisk 2008 Coal Usage 2,555,000 t/yr 2008 Co2 Level 4,745,912.5 t CO2

4273250.5 t CO2 Required Co2 Reduction by 2020 Initial 10% Decrease 427325.05 t CO2 Initial Scrubber Cost $921/kW At 363Mw $334,323,000.00 Additional coal needed at .30PP 766500 Cost of Coal $13,283,445.00 Discounted Value over 30 yrs $164,834,816.10 Total Profit From installing Scrubbers: Profit From Permits $348,091,149.34 Minus Scrubber Costs $499,157,816.10 Total ProfIt: -151,066,666.76

However, the cost of both scenarios differs from the actual emission. For the first case, to

“stay as is” and purchase permits to meet the allowed target, the total cost of permit will

increase every year until 2019 and eventually stabilize. For the second case, to install

carbon scrubbers, the plant will be able to sell the permits until 2019 making profit until

the 2020 target is met, and afterwards the required permit purchase cost will stabilize and

a very small value. (Once the scrubber is installed it will be able to reduce 85% of its

emission immediately.) As shown in the plot below, installing CO2 scrubbers will cost

much less money in the long run (despite its initial capitol requirement for installation).

Were Fisk to revamp its facilities and become an IGCC plant it would sequester

90% of its CO2 emissions and be able to actually sell permits. The estimated CO2

emissions after sequestration equate to approx. 494,383.12 t/yr, a number less than the

1990 emissions level for a 500MW PF plant, and so the IGCC plant would be able to sell

nearly 4,500,000 permits annually. Assuming there is no shortage of buyers, at a price of

$41.20/permit an IGCC plant would be able to bring in an annual amount of

$183,317,257.60 which totals to a value of $2,274,791,399.00 discounted over 30 years.

The analysis shows that though an IGCC plant has a much higher total cost when

compared to a PF plant, when proper policy exists an IGCC plant is not only able to sell

permits it can sell enough permits to fully pay for production and operation, but have

almost $300,000,000 left over in unspent revenue! These results can be found on figure

3-5.

Figure 3-5 Case scenario if Fisk unit 20, an IGCC plant with carbon capture

While it is clear that under certain policies an IGCC plant becomes a much more

economical option the costs and benefits of each scenario is highly dependent upon what

the “actual” pricing of CO2 Emissions. There are many estimates claiming that the price

of CO2 ranges from $0 to $9.016 to $36.45,17 in fact some estimate that by next year the

purchasing price of a CO2 permit will be up to $100 per permit! The results found by

using different permit-pricing options can be found in figures 3-6 and 3-7. This was done

to show that the economical benefit of each option, greatly depends on the policy the

government decides on.

16 carbonfund.org. 20 May 2008 <www.carbonfund.org> 17 myclimate.org. 20 May 2008 <www.myclimate.org>

IGCC Co2 Emissions (kg/hr) 51198 kg/hr Equates to: 1354.5 t/day Yearly IGCC Emissions 494,383.12 t/yr IGCC Co2 Capture (@ 90%) 460782 kg/hr Equates to: 12190.3 t/day Yearly IGCC Capture 4,449,448.1 t/yr

Permits available for Sale 4,449,448 permits/yr Valued at: $183,317,257.60

30 yr discounted Value: $2,274,791,399.00

Figure 3-6 Cost of Scenario 1, reducing carbon emission sole by purchasing permits,

at various discount values and different permit prices

Figure 3-7 Cost of Scenario 2, reducing carbon emission by installing scrubbers as

well as purchasing permits, at various discount values and different permit prices

Conclusion

In this study, we have shown that if Fisk 19, used as a representation of a typical

coal power plant in the state, were to continue its operation under the to-be applied

carbon cap-and-trade system, it would be more economical to install a CO2 scrubber than

to keep the operation as is and purchase permits to meet to cap limit. Also, we have

shown that IGCC plant may cost more initially in the long run, over 30 years, it would be

more economical under the cap-and-trade system. In conclusion, it has been shown that

in order for the IGCC type coal facility to become an economically viable option certain

government policy must be in place to provide the proper incentive to invest the large

amount of capital compared to continue using PF power plants. In this particular study

we have used Governor Blagojevich’s plan however there is more than one possible

method to ensure proper emission levels. It is clear though that if a cap and trade policy is

efficiently set up, under certain permit prices the IGCC plant not only becomes viable but

it also become highly profitable. As shown, under certain scenarios, the monetary

benefits of creating IGCC power plants are very high and surpass the costs by almost

$300 Million. If these results can be generalized across the Unites States the IGCC Plant

will change from the concept plant that it currently is to a major energy producing type

that is used nation wide. We must make sure though, that because the future of coal is

bright, that we continue to make it brighter by researching and developing cleaner

methods of energy production.