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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.