IGCC Technology Overview & Genoa Site Feasibility EXECUTIVE SUMMARY

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1 IGCC Technology Overview & Genoa Site Feasibility September 3, 2008 Response to March 29, 2008, Vernon Electric Cooperative Resolution In response to the resolution passed at the VEC annual meeting, which states the following: Dairyland Power Cooperative should convert the Genoa pulverized coal plant to Integrated Gasification Combined Cycle (IGCC) technology in order to meet EPA emission standards. EXECUTIVE SUMMARY Dairyland has conducted a detailed and careful evaluation of gasification technology and the concept of repowering our Genoa #3 Station (G-3) with the addition of this technology. Following this evaluation, we have determined it is not technically nor logistically feasible to use this technology at the Genoa Site. Even if it were possible to implement, the economic impact and high level of uncertainty regarding this new technology would put all Vernon Electric Cooperative ratepayers and those of other member cooperatives in the Dairyland system at risk. There are six major issues which prevent Dairyland from converting the G-3 plant to a gasification facility: 1) Reliability The few existing commercial applications of gasification or IGCC technology have proved to be extremely unreliable. While several utilities have proposed IGCC projects, almost all have been put on hold or rejected by state public service commissions because of the lack of proven reliability and high cost. 2) Space Limitations There is not a sufficient area for laydown and construction of a project of this magnitude and not enough land to accommodate such a facility, which would include gasifiers, support systems, water treatment, fuel handling, and auxiliaries, on the Genoa Site. 3) Boiler and Turbine Design The existing boiler would not be amenable to conversion to synthetic gas and would have to be completely replaced. The existing boiler is also not compatible with IGCC technology which would use a Heat Recovery Steam Generator (HRSG). We do not believe an HRSG could be designed to match the supercritical pressure, temperature, and dualreheat design of the existing turbine, necessitating its replacement as well. 4) Replacement Power Costs While the existing boiler was razed and new equipment was erected, which would likely take several years, the Dairyland system would be in need of replacement electricity. This very significant capacity and energy purchase would have to be made in a very volatile market with extraordinarily unacceptable pricing risks. 5) Economic The current G-3 plant has an estimated replacement value today of over $1 billion. We estimate the cost of demolishing G-3 and replacing it with new gasification or IGCC equipment to be more than $1.5 billion. Since G-3 has 20 or more years of remaining useful life, this significant expenditure is not justified, especially since no additional energy nor air quality benefits would be gained after all of that expense. 1

2 6) Permitting Our experience is that permits for such a major project would be difficult to obtain, if even possible. Particularly given the risky nature of IGCC technology, it could literally take years to receive the necessary permits for construction. In addition to these six primary issues, there are myriad additional items which could be problematic. We have elaborated on some of these issues throughout the remainder of this document. Dairyland takes seriously our responsibility to evaluate all alternatives before launching a major project such as the environmental upgrades to the G-3 plant. The production of electricity is an incredibly complex business. In this document, we will expand on the points made above. This is fairly technical information; however, we understand the sincere desire by members to have us explore this option. Therefore, we will thoroughly explain in this document our rationale for why we have determined IGCC is not the right answer at Genoa, as we work to improve the environment and meet state and federal air pollution regulations. 2

3 BACKGROUND & TECHNOLOGY OVERVIEW G-3 BACKGROUND Genoa #3 Station (G-3) was completed in 1969 at a cost of $56 million. G-3 was named simply because it was the third generating facility to be built in Genoa, Wis. This single-unit coalfired facility has a generating capacity of about 375 megawatts (MW) or 375,000 kilowatts of electricity. On average, each MW of electrical production can power nearly 650 homes. G-3 produces over 2 billion kilowatt-hours (kwh) of electric energy each year. G-3 is extremely efficient, due mainly to a unique double reheat of the steam and supercritical steam pressures. The term supercritical is used for power plants with high operating pressures above where normal boiling occurs at a given temperature. For water at 1000 deg F, the supercritical point occurs at pressures in excess of 3,200 psi (pounds per square inch). Supercritical units can achieve thermal efficiency of more than 45%, compared with a typical subcritical plant s 30-38%. Supercritical power generation units like G-3 s feature once-through boilers designed to operate with pressures from 3,500 to 4,000 psi, versus 1,800 to 2,500 psi for conventional boilers. Higher firing temperatures and pressures translate into better efficiency, defined as more electricity generated per BTU of coal consumed. This is important to power producers and consumers, as these increased efficiencies translate into reduced fuel costs and fewer emissions for every kilowatt-hour generated. In essence, the boiler is used to convert the chemical energy in the coal to heat energy. The heat from the burning fuel causes water in the boiler to change into steam. The steam, which now contains heat energy, is sent to turbines, where it causes the turbine blades to rotate, transforming much of its energy into a mechanical form. In the case of G-3, this steam is sent back to the boiler for reheating twice prior to use in additional turbines. A shaft connects the turbines to a generator through couplings. As the turbine blades rotate, they cause the generator shaft to rotate. The generator converts the rotating mechanical energy into electrical energy. 3

4 IGCC TECHNOLOGY OVERVIEW It is important to understand both the basics of IGCC technology and concepts as well as those of G-3 before an informed decision about the use of this technology at the Genoa Site can be made. IGCC is a type of power plant that generates synthetic gas (syngas) from coal and then burns that syngas to power a gas turbine (similar to a jet engine). The heat from the gas turbine exhaust then generates steam to run a steam turbine. None of the basic technologies coal gasification, gas turbines and steam turbines are new. It is the integration of these into electric power plants that is new, and presents engineering challenges. A typical schematic is provided. IGCC technology basically consists of four processes: gasification, gas cleanup, gas turbine combined cycle operations and cryogenic air separation. The four processes must be integrated to optimize the plant. The first process is gasification. A feedstock (fuel, such as coal) can be gasified in several ways. The most common technique partially oxidizes the feedstock with pure oxygen inside a reactor. The carbon and hydrogen from the feedstock are converted into a mixture composed primarily of hydrogen and carbon monoxide. This mixture is commonly called syngas. Syngas has a heating value of 125 to 350 BTU/scf, which is three to eight times lower than that of natural gas. The syngas from the reactor must be cleaned before it can be used as a gas turbine fuel. The cleanup process typically involves removing sulfur compounds, ammonia, metals, alkalytes, ash and particulates to meet the gas turbine s fuel gas specifications. To make IGCC more economically attractive, marketable products such as methanol, ammonia, fertilizers and other chemicals can be produced from the compounds removed from the syngas. This process often further reduces the hydrogen content and therefore the heating value of the syngas. These processes need to be further evaluated based on market conditions and the cost for each specific process. 4

5 A gas turbine combined cycle is characteristic of a power producing engine or plant that employs more than one thermodynamic cycle. Since heat engines are only able to use a portion of the energy their fuel produces (usually less than 50%), the remaining heat from combustion is generally wasted. Combining two or more cycles results in improved overall efficiency. In a combined cycle gas turbine plant, a gas turbine generator produces electricity and the waste heat is used to make steam in a heat recovery steam generator (HRSG) to generate additional electricity via a steam turbine. This enhances the efficiency of electricity generation. A cryogenic air separation unit is required to provide pure oxygen to the gasification reactor, often using or being supplemented with post-compression air bleed from the gas turbine. This is a fairly complex process in itself. There are many variations in the air separation cycles which are used to make industrial gas products. Design variations arise from differences in user requirements. Process cycles are somewhat different depending upon how many products are desired (either nitrogen or oxygen, both oxygen and nitrogen, or nitrogen, oxygen and argon); required product purities; gaseous product delivery pressures; and whether one or more products will need to be produced and stored in liquid form. All cryogenic air separations consist of a similar series of steps; Filtering, compressing and cooling air Removing water vapor and carbon dioxide Cryogenic cooling (~-300 deg. F) and column distillation Variations in cryogenic air separation reflect the desired product mix (or mixes) and the priorities/ evaluation criteria of the user. Some designs minimize capital cost, some minimize energy usage, some maximize product recovery, and some allow greater operating flexibility. The two existing IGCC facilities in the U.S. are in the 250 MW net range and employ GE frame 7FA gas turbines rated at approximately 192 MW and HRSG/steam turbine combinations in the 125 MW vicinity. As much as 65 MW of the electricity generated by these plants is used to power auxiliaries. Advantages of Integrated Gasification Combined Cycle (IGCC) IGCC is an advanced technology that represents the cleanest of currently available coal technologies. Advantages of IGCC over current conventional coal-based power generation systems include: Higher efficiencies and lower emissions - Improvements in efficiency dramatically reduce emissions from coal combustion. Increasing efficiency from 35 to 40%, for example, reduces carbon dioxide emissions by over 10%. With efficiencies currently approaching 50%, IGCC power plants use less coal. Higher output - Using syngas in a gas turbine increases its output, especially when nitrogen from an oxygen blown unit is fed to the turbine. Thus a turbine rated at 170 MW, when fired on natural gas, can yield 190 MW or more on syngas. Furthermore, output is less dependent on ambient temperature than is the case with natural gas. Product flexibility - including carbon capture and hydrogen production - The gasification process in IGCC enables the production of not only electricity, but a range of chemicals, by-products for industrial use, and transport fuels. Carbon dioxide can be captured from the coal syngas (carbon monoxide and hydrogen) through a water/gas shift process - The CO2 can be captured in a concentrated stream, making it easier to convert into other products, or to sequester (for example, store underground). An added advantage in this process is that there are low additional costs for carbon capture, particularly if the plant is oxygen driven. 5

6 In addition to electricity generation, hydrogen produced from the process can potentially be used as a transport fuel, in fuel cells. Barriers to Implementing IGCC at Genoa While it is clear that IGCC technology needs to be evaluated as a potential resource in the future, as any utility looks at adding new generators on the system; Dairyland finds the following issues to be significant barriers when looking at it for renovating our existing G-3 plant. ISSUE 1 IGCC RELIABILITY IGCC technology is still in its infancy with only limited commercial applications in existence. These initial operations have proven to be extremely unreliable in comparison to existing coal technologies. While several utilities have proposed IGCC projects, several state public service commissions have rejected them because of the high cost and the lack of proven reliability. The following chart depicts availability percentages for various existing gasification type projects. These availability percentages are much lower than what we would expect out of coal-fired generators. Many experts hope that the next generation of IGCC will have availability which is more in line with current industry expectations; but the current state of the technology has not demonstrated that level of availability. Current and near-term IGCC plants must be viewed as technically feasible, but not delivering the cost or the performance to be economically attractive. A September 2004 study commissioned by the DOE found that, despite a long history of gasification, only two gasified coal plants whose primary output is for electrical generation have been built in this country. A number of studies have looked at market barriers to widespread IGCC implementation. IGCC uncertainties include lack of standard plant design, performance guarantees and high capital costs. These uncertainties call into question whether the technology is commercially viable today. IGCC veteran Stephen D. Jenkins testified in January 2007 that IGCC technology will not be ready for six to eight years, has limited performance and emissions guarantees, and that commercial-scale carbon dioxide capture and storage has not been demonstrated. The two currently operating IGCC plants in the U.S. are the Polk plant in Tampa, Florida, and Wabash River in Indiana. Although many petroleum and chemical plants employ gasification, the Polk and Wabash River plants are the only utility scale facilities to use coal to generate electrical power with combined cycle turbines. The FutureGen project, a 275 MW clean coal IGCC demonstration program of the DOE, was four years into its planning and scheduled to be constructed in Illinois when it was recently (January 2008) cancelled by the DOE because the budget estimate climbed to $1.8 billion from $1.0 billion and officials feared it would increase further. 6

7 ISSUE 2 SPACE LIMITATIONS The lack of space for the extensive chemical plant required by IGCC, and the need for a wastewater treatment plant, are the main barriers to even considering this technology at Genoa. There is inadequate area for lay down of materials and construction for a project of this magnitude and not enough land to accommodate the completed facility (including gasifiers, support systems, water treatment, fuel handling and auxiliaries) on the Genoa Site. The size of existing IGCC facilities is estimated to be approximately 100 acres or more. The size of our entire property at Genoa is 80 acres. Without even considering scale up issues to match Genoa s current output, it is doubtful that the Genoa site could support a project like this. The geographic constraints of Highway 35, the railroad tracks and the Mississippi River limit the amount of land available, along with existing plant facilities that could not be eliminated. In addition to land issues for the proposed IGCC facility, there are legitimate concerns about construction laydown and fabrication areas that are required above and beyond the footprint of the facility. It is believed that much of this construction land would need to be found off-site of the existing facility, adding to construction cost, complexity, traffic and safety concerns. ISSUE 3 G-3 BOILER AND TURBINE DESIGN The existing G-3 boiler would not be amenable to conversion to the burning of synthetic gas and would have to be completely replaced. The boiler is also not compatible with IGCC technology which would use a Heat Recovery Steam Generator (HRSG). It is doubtful that we could erect a HRSG boiler to match the supercritical pressure, temperature, and dual-reheat design of the existing turbine, necessitating replacement of the turbine as well. In addition, the existing steam turbine is far too large (~375MW) to use in a combined cycle application, rendering it useless at an IGCC plant. Typical IGCC applications have steam turbine/generator sets rated at approximately 125 MW. Therefore, the boiler and turbine at G-3 would need to be replaced in a IGCC retrofit. These issues of incompatible boiler and turbine design would force the existing building to be razed and new facilities likely put in their place. This would add to initial demolition costs and would impose extraordinary replacement power costs on the cooperative for the extended period that the facilities were unavailable. ISSUE 4 REPLACEMENT POWER COSTS It would take several years to raze the existing boiler and erect new equipment. During that time, the Dairyland system would need to buy replacement electricity to serve our cooperative members needs. With growing energy needs in the region, it would likely be virtually impossible to secure long-term replacement power for a large facility such as G-3 without simply relying on the energy market. This significant capacity and energy purchase would have to be made in a very volatile market with huge upward price risks. Recent average market pricing suggests that the energy while the G-3 facility is not operating would be approximately $87 million more expensive than if G-3 were operating. The use of average pricing does not account for the risk inherent in the wildly volatile marketplace of today. In addition to the need to replace energy during demolition and construction of the new facility, power generating capacity would need to be purchased to cover the size limitations of the facility. Currently IGCC technology has capacities in the range of 250 MW. This 125 MW shortfall needs to be replaced yearly. Using the same market assumptions, the yearly cost to cover the capacity shortfall would be approximately $11 million. These are all costs that would need to be absorbed by Dairyland s membership that would not be required without the IGCC plant. 7

8 ISSUE 5 ECONOMIC CONSIDERATIONS The current G-3 plant has a replacement value today of well over $1 billion. We estimate the cost of removing the facility and replacing it with new equipment for an IGCC retrofit to be more than $1.5 billion. Since G-3 has 20 or more years of remaining useful life this kind of significant expenditure is not justified, especially since no additional energy would be gained after all of that expense. Capital Cost vs. Efficiency IGCC has the potential to use coal in a more efficient process and with lower emissions than conventional coal power plants. The combined cycle portion of the process is attractive from a capital cost perspective compared to a conventional coal plant, but the addition of gasification, coal feeding, gas cooling, gas cleanup, and the oxygen plant result in an overall cost that is higher than a conventional coal plant. Higher efficiency than a conventional coal plant could justify higher capital costs. However, the currently demonstrated capital cost is about 30% higher and efficiency is only about 5% better than a conventional coal plant. In 2004, Indeck Energy Services testified before the Illinois State EPA that IGCC s capital costs are 30% higher. The U.S. Department of Energy (DOE) initially estimated the total capital cost for the proposed 600 MW IGCC Mesaba plant in Minnesota at $800 million, but the final cost is currently estimated at $2.155 billion or $3,593 per kw, not including carbon capture, transportation or storage. In April 2007, Minnesota s Office of Administrative Hearings, a state agency charged with conducting non-partial and balanced reviews of contentious cases, rejected the Mesaba plant, finding: Neither the project nor the IGCC technology is likely to be a least-cost resource Emissions of nitrogen oxides (NO x ) and mercury are not reduced significantly, and are not lower than currently available control technology for pulverized coal There is no guarantee of carbon sequestration The plant would cost 9-11 cents/kwh; and capturing and transporting the carbon would add at least 5 cents/kwh. Wisconsin s Public Service Commission (PSC) and Department of Natural Resources (DNR) collaborated in a task force review of IGCC technology in 2006, with a report issued in February In the study, IGCC was compared to conventional supercritical pulverized coal (SCPC) plant technology. The report was to review the costs, benefits and prospects for future use of IGCC in the state of Wisconsin. The task force investigation showed that IGCC, before considering the treatment for carbon dioxide, has a cost premium over SCPC of $5 to $7 /MWh (on about $50 energy cost) with costs primarily dependent on construction, operational reliability and heat rate. Many in the industry believe these premiums could be even more substantial. The final report of the task force additionally recognized the difficulty in estimating the construction costs, as only two IGCC plants are operating in this country and both were constructed more than 10 years ago (Polk Station in Florida and Wabash River Station in Indiana both about 250 MW). The Minnesota Department of Commerce estimated carbon dioxide sequestration costs for Mesaba at roughly $1.107 billion in 2011; and pipeline costs at $635.4 million. Carbon dioxide sequestration and storage costs are highly uncertain as none of this has been done before on a power plant scale. Continuing improvements in efficiency of SCPC plant designs is drawing into question whether IGCC will be able to claim any advantage based on environmental impact in the near future with the exception of carbon dioxide capture, and it appears now that DOE is suggesting that retrofit CO2 capture on SCPC plants may be very comparable to IGCC. 8

9 A review of data from the Department of Energy also indicates that G-3 has the lowest heat rate (best efficiency) of any utility boiler in the State of Wisconsin in recent years, making it the least attractive option for repowering to new technology from a state wide perspective. Carbon Capture and Storage Economic Risks Carbon capture and storage (CCS) is an approach to mitigate global warming by capturing carbon dioxide (CO 2 ) from large point sources such as fossil fuel power plants and storing it instead of releasing it into the atmosphere. Storage of the CO 2 is envisaged either in deep geological formations, in deep ocean masses, or in the form of mineral carbonates. After capture, the CO 2 must be transported to suitable storage sites. This is done by pipeline, which is generally the cheapest form of transport. The pipeline system that would be required largely doesn t exist today. According to the DOE, IGCC CCS is seen as too risky for private investors, and requires enormous subsidies from the federal, state and sometimes local government. Extensive research is required before a commercial-scale IGCC plant could capture, transport and store carbon dioxide. A February 2006 presentation on IGCC by Xcel Energy stated that the wild card in the IGCC cost equation is carbon dioxide capture, but no currently operating plants include carbon dioxide capture. Transport and storage costs must also be included in the total cost of electricity. It is also worth noting that ongoing research relative to CO 2 capture on conventional coal facilities suggests that the cost differential relative to IGCC facilities may not be as great as earlier estimated. Stranded Investment in Genoa G-3 has an accredited capacity of about 375 MW. The unit was commissioned in 1969, and so is about 40 years old; we expect its remaining life is on the order of about 20 more years. The installed replacement value, for a similar facility today, is well over $1 billion (375 MW x $3,000/kW). Replacing G-3 with an IGCC plant would conceivably cost on the order of $1.5 billion based on the cancelled FutureGen project, plus additional costs for the following: Razing existing facility Replacement power costs for an extended period during demolition and construction Permitting Dairyland could not justify such a retrofit to a unit with an expected additional life in the range of 20 years. Even if our Board of Directors wanted to pursue this course of action, we do not believe it would be possible to obtain financing given those circumstances. ISSUE 6 PERMITTING Dairyland Power has significant concerns about whether such an IGCC facility could be permitted at all in the current regulatory environment. Our experience is that permits for such a major project would be difficult to obtain. Particularly given the risky nature of IGCC technology, it could take several years to receive the necessary permits for construction. WE Energies recently (2002) made application to the PSC for approval to build a 600 MW IGCC plant at their Elm Road facility to complement two planned 600 MW supercritical pulverized coal plants. That application was denied by the PSC on the grounds that the technology was not sufficiently mature for commercial application at this scale and the costs not well-enough known. The decision of the Wisconsin PSC to reject IGCC is consistent with actions by regulating commissions in many other states. American Electric Power (AEP) announced about two years ago their intent to build five IGCC plants within their service territory. They drastically scaled back that initiative to only two units as they were 9

10 unable to secure authorization for rate recovery from regulatory commissions. On March 14, 2008, they cancelled those two projects as well. A special Minnesota law passed in 2003 committed Minneapolis-based Xcel Energy to buy 450 MW of power from Excelsior Energy s proposed Mesaba Energy Project. In April 2007, the Minnesota Public Utilities Commission s Administrative Law Judges recommended that the Mesaba plant be denied a Power Purchase Agreement, as it is not a least-cost resource, nor an innovative energy project as defined by Minnesota state law. In August, the state PUC affirmed this finding, arguing that the Integrated Gasification Combined Cycle (IGCC) plant is not in the public s best interest. ISSUE 7 MISCELLANEOUS ITEMS In addition to the six primary issues, the following additional items could be problematic as well. AIR EMISSIONS CHALLENGES Power plant emissions are higher during start-up procedures than in steady-state operation (some estimates indicate as much as 38% higher). Due to their inconsistent reliability, gasification plants require about 60 start-up/shut-down events every year (as opposed to two or three for pulverized coal). These additional start-up/shut-down episodes would make it difficult to comply with regulations limiting air emissions. Based on research it is uncertain that IGCC alone could ensure compliance with the Clean Air Act regulations across our system of generators. POTENTIAL FOR WASTEWATER ISSUES IGCC uses water to clean the syngas and thus creates additional water contamination and treatment issues. The DOE IGCC pilot project in Wabash River, Indiana found that elevated levels of selenium, cyanide and arsenic in the wastewater caused a permit violation, and that selenium and cyanide limits were routinely exceeded. Approaches under consideration to correct the issue include chemical precipitation, bio-remediation, reverse osmosis and evaporation. The additional cost and complexity of these potential solutions must be factored into any planned replication of this coal gasification technology. CARBON DIOXIDE CAPTURE AND STORAGE TECHNICAL RISKS As has been discussed previously, there are many economic issues associated with carbon dioxide capture and sequestration. There are many technical issues as well. Although IGCC is promoted as being capture ready, no IGCC plants are actually capturing and storing carbon dioxide in commercial quantities. A big problem for implementation in Wisconsin is that, once captured, there is no significant known geological reserve which is likely to work for carbon dioxide sequestration. To successfully sequester carbon dioxide captured from Wisconsin generating plants, pipelines will have to be built to suitable locations in other states. The technical, economic and political challenges to geologic sequestration of carbon dioxide are significant, and yet to be resolved. GASIFICATION ISSUES IGCC has been demonstrated in two U.S. commercial-scale facilities. A variety of coals have been gasified, the resulting gases have been cleaned up to allow use in combustion turbines, and electricity has been generated. However, the capital cost and performance in a number of areas has not been as attractive as planned. The troublesome areas for IGCC have included high-temperature heat recovery and hot gas cleanup. An important part of achieving an attractive heat rate is generation of high pressure and temperature steam from the high-temperature raw gas generated by gasifying coal. 10

11 The temperature of the raw gas is dependent on the gasification process and the coal. Slagging gasifiers, such as the Texaco process, typically generate gases in the 2500 to 2800 o F range. These high-temperature gases containing corrosive compounds, such as hydrogen sulfides, create a very demanding environment for the generation of high pressure and temperature steam. The reliable generation of steam under these conditions has not been demonstrated in a commercial application. Alternatives not recovering the heat in the raw gas, such as direct quenching of the gas, result in lower efficiencies. It is also attractive from an efficiency perspective to provide clean gas to the combustion turbine at an elevated temperature without cooling and reheating, hence the desire to use hot gas cleanup. Again, this demanding service has not been reliably demonstrated in a commercial application, resulting in less efficient approaches being used for current plants. COMBUSTION TURBINE ISSUES Syngas has about 25% of the heating value of natural gas meaning much more mass flow through the turbines is required. The most significant differences in the combined cycle are modifications to the combustion turbine to allow use of a 250 to 300 Btu/SCF gas. While these issues can be overcome, there is much less industry experience on these types of machines calling into question their proven reliability. 11

12 CONCLUSION Dairyland conducted a detailed and careful evaluation of gasification technology and the concept of repowering Genoa #3 Station (G-3) with this technology. As a result, we have determined that this option is not technically nor logistically feasible at the Genoa Site. Even if it were possible to implement, the economic impact and high level of uncertainty regarding this new technology would put all Vernon Electric Cooperative ratepayers and the other cooperative members of the Dairyland system at risk. However, the environmental controls Dairyland is in the process of implementing at G-3 WILL ensure we are improving air quality in our region and will remain in compliance with state and federal emission regulations while continuing to provide reliable and economic power to the region. Significant References and Additional Reading 1. Integrated Gasification Combined-Cycle Technology: Costs, Benefits, and Prospects for Future Use in Wisconsin; February 2007; A joint study of the Department of Natural Resources and the Public Service Commission of Wisconsin. 2. Tampa Electric Integrated Gasification Combined-Cycle Project Fact Sheets; 2003; Clean Coal Technology Demonstration Program, Advanced Electric Power Generation. 3. Wabash River Coal Gasification Repowering Project Fact Sheets; 2003; Clean Coal Technology Demonstration Program, Advanced Electric Power Generation. 4. Tampa Electric Polk Power Station Integrated Gasification Combined-Cycle Project Final Technical Report; August 2002; Tampa Electric Company. 5. Wabash River Coal Gasification Repowering Project Final Technical Report; August 2000; Wabash River Coal Gasification Project Joint Venture. 6. Wabash River Coal Gasification Repowering Project Project Performance Summary; January 2002; U.S. Department of Energy. 7. Wabash River Coal Gasification Repowering Project: A DOE Assessment; January 2002; U.S. Department of Energy, National Energy Technology Laboratory (NETL). 8. Practical Experience Gained During the First Twenty Years of Operation of the Great Plains Gasification Plant and Implications for Future Projects; April 2006; U.S. Department of Energy, Office of Fossil Energy. 9. Updated Cost and Performance Estimates for Clean Coal Technologies Including CO2 Capture (Report ); Technical Update March 2007; Electric Power Research Institute (EPRI). 10. Operating Experience, Risk, and Market Assessment of Clean Coal Technologies 2007 (Report ; Technical Update December 2007; Electric Power Research Institute (EPRI). 11. An Environmental Assessment of IGCC Power Systems; Presented at Nineteenth Annual Pittsburgh Coal Conference September 23-27, 2002; Jay A. Ratafia-Brown, et al., Science Applications International Corporation and Gary J. Stiegel, U.S. DOE/NETL. 12. FutureGen Fact Sheet; January 2008; U.S. Department of Energy 13. Rising Utility Construction Costs: Sources and Impacts; September 2007; The Brattle Group for The Edison Foundation. 12