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Despite many challenges, IGCC proponents believe the time is right for this promising clean coal technology to make its mark as a viable commercial generation option.
By: Brian K. Schimmoller, Managing Editor
With support from nearly every corner of the power sector, integrated gasification combined-cycle (IGCC) technology stands poised to capitalize on its ample potential. Major challenges remain to bring costs down, improve availability and reliability, and establish performance guarantees, but the confluence of concerns over natural gas supply and pricing, possible global warming, and fuel diversity have put IGCC in a favorable position for future baseload generation requirements.
The momentum is certainly there, but it must be sustained. At the Gasification Technologies Conference in Washington, D.C. this past October, David Hadley, Indiana Utility Regulatory Commissioner, strongly endorsed IGCC, but called for a greater sense of urgency. About 100 new coal-based power plants are at some stage of development, but only a few are choosing IGCC technology. “If you’re not on the drawing board soon, you might just miss this opportunity for another 20-year build cycle,” said Hadley, who cited an East African proverb to emphasize his point: “He who waits for the whole animal to appear will spear only its tail.” Rather than taking a risk by building an IGCC plant now and gaining the benefits of being an early adopter, the real risk taker might actually be the company that waits too long to choose IGCC.
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“Baseload capacity will be needed in many parts of the country starting around 2010,” said Steven Taub, Director with Cambridge Energy Research Associates. “Because technology decisions will have to be made within the next year or two to get these baseload projects moving, IGCC has a limited time window in which to make a significant impact.”
The recent upsurge in interest in IGCC can be traced, in large part, to a few coal-dependent utilities looking to position themselves as environmentally conscious early adopters. In late August 2004, AEP announced that it would build one or more commercial-scale, baseload IGCC plants as soon as 2010 as part of its future plans to mitigate the economic impacts of its emissions. AEP has since refined this announcement to say that it is seeking to build a 1,200 MW plant comprised of two 600 MW units, but the location, gasification technology and construction timeline have not yet been finalized.
Cinergy has also stepped forward to endorse IGCC. In October, Cinergy signed a letter of intent with GE Energy and Bechtel to study the feasibility of constructing a 500 to 600 MW commercial IGCC plant, likely at Cinergy’s Edwardsport, Ind., power station. This would be the first plant of its kind to be developed under an alliance GE and Bechtel formed in early October to develop a standard commercial offering for U.S. IGCC projects. Cinergy’s feasibility study is expected to be completed in May. Preliminary engineering would follow, with a final decision not expected until mid- to late-2006.
Several other IGCC plants are under active development (Table 1), although some of these will receive a measure of government funding. Booz|Allen|Hamilton recently conducted a study for the Department of Energy and the Gasification Technologies Council to assess IGCC’s market penetration under various environmental scenarios. On paper, the potential is huge, ranging from 34 GW by 2010 under conservative conditions (moderate natural gas prices, moderate technology progression, and a regulatory framework mirroring the current federal environmental framework) to 146 GW under favorable conditions (high natural gas prices, significant technology progression, and multi-pollutant legislation with a carbon constraint). These estimates, however, did not consider many of the significant uncertainties that will impact specific investment decisions in IGCC, including capital availability, performance guarantees, fuel prices, reliability, labor costs and many others.
“A couple of GW of commercial IGCC capacity online by 2010 is more realistic,” said CERA’s Taub. “We might then see a bandwagon effect, but there will probably be a time lag as other companies will first want to monitor the performance of the IGCC plants installed by the early adopters.”
The uncertainties associated with IGCC can be traced primarily to the relative scarcity of cost and performance data from operating gasification plants. This scarcity cannot be alleviated, of course, until more plants are in the ground generating power. The commercial integration efforts underway in the IGCC sector, however, are aimed at addressing some of the uncertainties. A subtle, but important facet of the emerging IGCC marketplace is the transition that is occurring from a business model based on gasification licensing to a model based on standard products. For the first-generation power sector IGCC plants developed and built in the 1990s, integration took a back seat (maybe even the bumper) to technology demonstration.
“For plants like Polk and Wabash River, the gasifier supplier simply provided a technology license to the plant owner,” said Edward Lowe, GE Energy’s General Manager for Gasification. “The customer then had to design the plant and contract separately with the suppliers for the air separation unit, the acid gas scrubber, the power island, construction, etc. Basically, the customer owned the problem if the plant didn’t work as expected - there were no guarantees or warranties.”
GE’s alliance with Bechtel, along with other similar alliances - Black & Veatch with Uhde GmbH and Fluor with ConocoPhillips - plan to address this issue by offering an integrated solution. “From various customer listening sessions, we determined that we would have to be a one-point solution for the customer from the coal pile to the grid,” said Lowe. “We realized we had to offer a turnkey contract solution, to take responsibility for a firm fixed price and to guarantee total system performance.” By teaming with Bechtel, which GE has worked with on many gasification projects, including Polk, such a turnkey offering can be made.
ConocoPhillips’ alliance with Fluor follows a similar line of thought. ConocoPhillips will provide its E-Gas gasification technology, the gasification process design package, EPC design support, proprietary equipment and start-up support, while Fluor will provide expertise related to system integration, gas purification, power generation, infrastructure development and lump sum turnkey projects. The result is a “one-stop shopping” IGCC service that includes equipment guarantees, staffing and training, availability guarantees and a fuel hedge.
Commercial deployment of IGCC has been hindered primarily by two factors: higher capital cost and poor availability/reliability. Capital cost remains about 20 percent higher than for a conventional pulverized coal plant, but the environmental benefits in the long run are expected to offset this cost premium, according to Holly Koeppel, executive vice president, AEP Utilities - East. Further, concerted engineering efforts to optimize the integrated nature of the IGCC design are expected to drive costs down $100/kW to $200/kW over the next several years.
“Capital costs are coming down as a result of lessons learned in the first generation of plants, economies of scale, and significant investments in value engineering,” said Phil Amick with ConocoPhillips. “The larger and more efficient combustion turbines available for syngas operation from Siemens Westinghouse, GE and Mitsubishi are also contributing to reducing the unit costs of the combined-cycle side of the plants.”
GE is applying its six-sigma rigor to IGCC in an effort to drive down costs and improve RAM (reliability, availability, maintainability). In developing its 600 MW standard plant design, for example, GE is using a design of experiments approach to optimize and deliver a commercial IGCC product that can accommodate a wide variety of coals with limited impact on capital cost. The idea is to identify an envelope of coals with the right mix of heating values, sulfur contents and ash contents that could produce a flat response surface for cost of electricity, which is the major metric for customer acceptance. Table 2 compares IGCC with supercritical pulverized coal (SCPC), its most likely coal competitor. While SCPC currently has an edge in capital cost and cost of electricity, the emissions advantages for IGCC - coupled with expected engineering improvements - could narrow the gap in coming years.
Click here to enlarge image
Cinergy is considering its Edwardsport, Ind., site as a possible spot for a new IGCC plant. Photo courtesy of Cinergy.
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“We anticipate landscape societal changes over the next 10 to 20 years that will result in major pressures on mercury releases, carbon emissions and water use,” said Lowe. “IGCC can potentially ease these pressures while providing reasonably priced electricity.” For example, because IGCC removes contaminants from the fuel syngas, at a volume 1/100th that of flue gas, emissions control is much less expensive.
The threat of future environmental regulations is an issue that cannot be minimized. “As we look to build a plant to operate for the next 30 to 40 years, we must consider not only current regulations, but also assess the impact of future regulations, including the potential need to operate under a carbon constraint,” said Mike Mudd, AEP Program Manager, Generation Technologies. “This does not preclude building conventional coal-fired plants, but the impact of future regulations will have to be considered in the economic evaluation of any technology.”
The possibility of a carbon constraint is paramount in the commercial deployment of IGCC. While the new batch of IGCC plants almost certainly won’t include equipment for carbon separation and sequestration, most will likely include “provisions for carbon capture,” according to Lowe. In other words, the plants will be designed so that a carbon sequestration technology retrofit would have limited capital impact on the existing plant.
IGCC plant developers may even need to consider geologic sequestration opportunities when siting a facility. According to Bill Raney, president of the West Virginia Coal Association, in an article in the Charleston Daily Mail, AEP may favor locations such as in the Ohio River Valley where the geologic formations are amenable to CO2 injection.
Driving IGCC capital costs down is not just wishful thinking. “Consider the Polk plant, for example,” said Lowe. “Most think of it as a state-of-the-art IGCC facility, but it’s based on an engineering design from the early 1990s, so it’s not truly state-of-the-art. It uses older FA gas turbine technology and, at 250 MW, is not sized to capitalize on economies of scale.” GE’s 600 MW standard IGCC plant design will benefit from the larger size and will also incorporate FB gas turbine technology. The FB is 10 percent larger than the FA, providing an immediate 10 percent capital cost reduction on a $/kW basis.
With respect to reliability, the challenges are real and significant, but not insurmountable. Eastman Chemical’s long and successful track record at its gasification facility in Tennessee provides a good measure of confidence, as does the industry’s frank acknowledgement that a learning curve will be necessary. “We are aware of the reliability and availability challenges of new technologies such as IGCC, but we are confident we have the technical expertise to address them,” said AEP’s Mudd. “Our driver is to use proven systems in the design of our plant so we can maximize its availability.”
ConocoPhillips’ Amick points to other opportunities to enhance reliability: “Advances in materials, like the refractory improvements from DOE’s Albany Research Center, could dramatically impact plant maintenance cycles and costs. The E-Gas technology alliance also offers a design configuration with a spare gasification train that increases overall annual plant availability by about 10 percent.”
To increase confidence in its standard plant design, GE is including three gasifiers - two will be operating and one will be a spare. This redundancy may not be needed as greater operating experience is gained, but initially it will be necessary to ensure customer acceptance. Further, the presence of natural gas on-site, which is used for plant start-up, should provide a further measure of comfort since it could also be used as backup fuel if necessary.
Building and operating an IGCC plant is one thing. Paying for it is another. In the near term, utility developers like AEP and Cinergy are planning to make a case for including the incrementally higher cost of IGCC in the rate base. AEP, which has targeted possible construction of an IGCC plant in seven states (Indiana, Kentucky, Michigan, Ohio, Tennessee, West Virginia, and Virginia), has initiated discussions with various regulators and lawmakers to discuss IGCC’s environmental advantages, the need for new long-term generation capacity, and possible cost-recovery assurance. In early February, AEP asked PJM Interconnection to evaluate transmission interconnection feasibility for three potential IGCC sites: Mason County, W. Va., adjacent to AEP’s Mountaineer Plant; Meigs County, Ohio; and Lewis County, Ky. All are on land currently owned by AEP and all are on the Ohio River.
“We are looking for certainty with regard to recovery of our investment,” said AEP’s Koeppel. “While this may be a departure from the traditional regulatory process, we believe that there are regulators in these states who will recognize that IGCC’s efficiency and environmental performance improvements - including the capability for future carbon capture - offer a strategic advantage that outweighs traditional least-cost considerations.”
State approval of a more expensive generation project is well within the realm of possibility. “A given project can be declared prudent even if it costs more,” said Robert P. Knickerbocker, Jr., Partner with Day, Berry & Howard. “Think back to the 1970s and the nuclear boom. Utilities were able to get regulatory rate approval - despite the fact that nuclear plants cost more and took longer to build - by emphasizing other favorable characteristics, such as lower long-term electricity costs, fuel diversity, and reduced emissions. Many of these same arguments can be made for IGCC today - the public is increasingly concerned about reliance on foreign sources of energy, environmental sensitivity remains high, and an ample supply of coal resources promises more stability in terms of electricity costs.”
Regulators, acting on behalf of ratepayers, have one over-riding concern when making rate decisions: least cost. “If IGCC is perceived to not be least cost, utilities won’t build and will lose out to a least-cost competitor,” said Indiana Commissioner Hadley. “Least cost, at least in Indiana, is followed by the words ‘reasonably possible over the life of the plant.’” That last phrase constitutes IGCC’s wiggle room, its wedge in the door. While a conventional coal plant will cost many millions less up-front than an IGCC plant, its cost rises considerably after accounting for existing and future environmental regulations.
Not all states are as enamored with IGCC. Wisconsin, for example, did not require We Energies to include IGCC in its analysis of technology options for additional capacity, in part because of IGCC’s higher costs. And even if state regulators are amenable to IGCC, they will not give utilities carte blanche when it comes to cost recovery for a $1 to $2 billion power plant. Public utility commissions, for example, could impose certain stipulations. Limits on cost overruns, limits on construction timelines, and only permitting one IGCC facility to be built until their viability is proven are possible constraints, according to Knickerbocker, as well as the traditional possibility of post-construction prudence review.
Conceptually, at least, AEP is open to such stipulations. “We would consider conditions and limitations that are reasonable for both customers and shareholders and performance criteria for cost and operations that can be reasonably managed by the company,” said Koeppel.
One interesting proposal being considered to potentially ease the financing of IGCC plants is the 3Party Covenant approach developed by the Kennedy School of Government at Harvard University. The 3Party Covenant is an arrangement between the federal government, state utility commission and equity investor that serves to lower the capital cost of IGCC by reducing the cost of debt, raising the debt-to-equity ratio, and minimizing construction financing costs. The federal government provides loan guarantees that facilitate an 80/20 debt-to-equity financing structure, the state PUC assures dedicated revenues by permitting rate recovery, and the equity investor contributes equity for 20 percent of the projects and negotiates performance guarantees to develop, construct and operate the plant.
“The rationale behind this approach is simple - debt is cheaper than equity, and government debt is cheaper than corporate bonds because there is no risk of default” said CERA’s Taub. “The federal loan guarantee would enable utilities and other project developers to access debt at about 5 percent, versus about 8 percent without the federal guarantee.” Proponents of the 3Party Covenant estimate that the capital costs for new IGCC facilities could be reduced by about 38 percent and the overall cost of energy could be reduced by about 25 percent.
Of course, the 3Party Covenant approach would require federal legislation authorizing loan guarantees for qualifying IGCC projects, which is by no means certain. Taub also isn’t convinced the 3Party Covenant approach is the best option. “An earlier draft of the energy bill, for example, included a production tax credit for IGCC facilities, which would probably be worth more money to IGCC owners than a loan guarantee, though it would be more costly for the federal government. And while a 10 percent investment tax credit probably wouldn’t be worth as much, it would have one major advantage - timing. Because an IGCC plant has a rather lengthy construction schedule, about four years, the investment tax credit would enable developers to avoid earnings dilution during construction rather than waiting until plant operation.”
The bottom line is that there is no certainty any of these support mechanisms will be enacted. The number of IGCC plants developed and built would certainly be much higher if a favorable federal provision was in place, but because IGCC is currently moving forward without support, the need for federal subsidization is debatable.
“Implementation of gasification technology, in power generation and in chemical production facilities, is going to happen in this decade,” said ConocoPhillips’ Amick. “While financial incentives for certain early projects will likely occur, our approach is to work closely with our alliance partner and clients to offer financeable, or regulatory commission approvable, installations. One size doesn’t fit all, and the widest deployment will result from a menu approach that provides options that utilities, IPPs and public power companies can all benefit from.”
In short, IGCC’s future seems bright, but while the interest from AEP, Cinergy and the various technology suppliers is favorable, it does not guarantee that the floodgates are opening on widespread commercial IGCC development. Although tight natural gas supplies have pushed natural gas prices to historically high levels - raising enthusiasm for IGCC to historically high levels as well - new natural gas resources could be opened to development and market dynamics could change, thereby dampening prices and dampening interest in IGCC.
IGCC also faces competition from supercritical steam technology. Supercritical technology is generally accepted as proven and mature, and because its efficiency and emissions performance is comparable to that of IGCC, it could be favored in certain cases. For what it’s worth, however, IGCC appears to have acquired a more environmentally friendly stigma than supercritical technology, moving it one step ahead in the public eye. p
With support from nearly every corner of the power sector, integrated gasification combined-cycle (IGCC) technology stands poised to capitalize on its ample potential. Major challenges remain to bring costs down, improve availability and reliability, and establish performance guarantees, but the confluence of concerns over natural gas supply and pricing, possible global warming, and fuel diversity have put IGCC in a favorable position for future baseload generation requirements.
The momentum is certainly there, but it must be sustained. At the Gasification Technologies Conference in Washington, D.C. this past October, David Hadley, Indiana Utility Regulatory Commissioner, strongly endorsed IGCC, but called for a greater sense of urgency. About 100 new coal-based power plants are at some stage of development, but only a few are choosing IGCC technology. “If you’re not on the drawing board soon, you might just miss this opportunity for another 20-year build cycle,” said Hadley, who cited an East African proverb to emphasize his point: “He who waits for the whole animal to appear will spear only its tail.” Rather than taking a risk by building an IGCC plant now and gaining the benefits of being an early adopter, the real risk taker might actually be the company that waits too long to choose IGCC.
“Baseload capacity will be needed in many parts of the country starting around 2010,” said Steven Taub, Director with Cambridge Energy Research Associates. “Because technology decisions will have to be made within the next year or two to get these baseload projects moving, IGCC has a limited time window in which to make a significant impact.”
The recent upsurge in interest in IGCC can be traced, in large part, to a few coal-dependent utilities looking to position themselves as environmentally conscious early adopters. In late August 2004, AEP announced that it would build one or more commercial-scale, baseload IGCC plants as soon as 2010 as part of its future plans to mitigate the economic impacts of its emissions. AEP has since refined this announcement to say that it is seeking to build a 1,200 MW plant comprised of two 600 MW units, but the location, gasification technology and construction timeline have not yet been finalized.
Cinergy has also stepped forward to endorse IGCC. In October, Cinergy signed a letter of intent with GE Energy and Bechtel to study the feasibility of constructing a 500 to 600 MW commercial IGCC plant, likely at Cinergy’s Edwardsport, Ind., power station. This would be the first plant of its kind to be developed under an alliance GE and Bechtel formed in early October to develop a standard commercial offering for U.S. IGCC projects. Cinergy’s feasibility study is expected to be completed in May. Preliminary engineering would follow, with a final decision not expected until mid- to late-2006.
Several other IGCC plants are under active development (Table 1), although some of these will receive a measure of government funding. Booz|Allen|Hamilton recently conducted a study for the Department of Energy and the Gasification Technologies Council to assess IGCC’s market penetration under various environmental scenarios. On paper, the potential is huge, ranging from 34 GW by 2010 under conservative conditions (moderate natural gas prices, moderate technology progression, and a regulatory framework mirroring the current federal environmental framework) to 146 GW under favorable conditions (high natural gas prices, significant technology progression, and multi-pollutant legislation with a carbon constraint). These estimates, however, did not consider many of the significant uncertainties that will impact specific investment decisions in IGCC, including capital availability, performance guarantees, fuel prices, reliability, labor costs and many others.
“A couple of GW of commercial IGCC capacity online by 2010 is more realistic,” said CERA’s Taub. “We might then see a bandwagon effect, but there will probably be a time lag as other companies will first want to monitor the performance of the IGCC plants installed by the early adopters.”
The uncertainties associated with IGCC can be traced primarily to the relative scarcity of cost and performance data from operating gasification plants. This scarcity cannot be alleviated, of course, until more plants are in the ground generating power. The commercial integration efforts underway in the IGCC sector, however, are aimed at addressing some of the uncertainties. A subtle, but important facet of the emerging IGCC marketplace is the transition that is occurring from a business model based on gasification licensing to a model based on standard products. For the first-generation power sector IGCC plants developed and built in the 1990s, integration took a back seat (maybe even the bumper) to technology demonstration.
“For plants like Polk and Wabash River, the gasifier supplier simply provided a technology license to the plant owner,” said Edward Lowe, GE Energy’s General Manager for Gasification. “The customer then had to design the plant and contract separately with the suppliers for the air separation unit, the acid gas scrubber, the power island, construction, etc. Basically, the customer owned the problem if the plant didn’t work as expected - there were no guarantees or warranties.”
GE’s alliance with Bechtel, along with other similar alliances - Black & Veatch with Uhde GmbH and Fluor with ConocoPhillips - plan to address this issue by offering an integrated solution. “From various customer listening sessions, we determined that we would have to be a one-point solution for the customer from the coal pile to the grid,” said Lowe. “We realized we had to offer a turnkey contract solution, to take responsibility for a firm fixed price and to guarantee total system performance.” By teaming with Bechtel, which GE has worked with on many gasification projects, including Polk, such a turnkey offering can be made.
ConocoPhillips’ alliance with Fluor follows a similar line of thought. ConocoPhillips will provide its E-Gas gasification technology, the gasification process design package, EPC design support, proprietary equipment and start-up support, while Fluor will provide expertise related to system integration, gas purification, power generation, infrastructure development and lump sum turnkey projects. The result is a “one-stop shopping” IGCC service that includes equipment guarantees, staffing and training, availability guarantees and a fuel hedge.
Commercial deployment of IGCC has been hindered primarily by two factors: higher capital cost and poor availability/reliability. Capital cost remains about 20 percent higher than for a conventional pulverized coal plant, but the environmental benefits in the long run are expected to offset this cost premium, according to Holly Koeppel, executive vice president, AEP Utilities - East. Further, concerted engineering efforts to optimize the integrated nature of the IGCC design are expected to drive costs down $100/kW to $200/kW over the next several years.
“Capital costs are coming down as a result of lessons learned in the first generation of plants, economies of scale, and significant investments in value engineering,” said Phil Amick with ConocoPhillips. “The larger and more efficient combustion turbines available for syngas operation from Siemens Westinghouse, GE and Mitsubishi are also contributing to reducing the unit costs of the combined-cycle side of the plants.”
GE is applying its six-sigma rigor to IGCC in an effort to drive down costs and improve RAM (reliability, availability, maintainability). In developing its 600 MW standard plant design, for example, GE is using a design of experiments approach to optimize and deliver a commercial IGCC product that can accommodate a wide variety of coals with limited impact on capital cost. The idea is to identify an envelope of coals with the right mix of heating values, sulfur contents and ash contents that could produce a flat response surface for cost of electricity, which is the major metric for customer acceptance. Table 2 compares IGCC with supercritical pulverized coal (SCPC), its most likely coal competitor. While SCPC currently has an edge in capital cost and cost of electricity, the emissions advantages for IGCC - coupled with expected engineering improvements - could narrow the gap in coming years.
“We anticipate landscape societal changes over the next 10 to 20 years that will result in major pressures on mercury releases, carbon emissions and water use,” said Lowe. “IGCC can potentially ease these pressures while providing reasonably priced electricity.” For example, because IGCC removes contaminants from the fuel syngas, at a volume 1/100th that of flue gas, emissions control is much less expensive.
The threat of future environmental regulations is an issue that cannot be minimized. “As we look to build a plant to operate for the next 30 to 40 years, we must consider not only current regulations, but also assess the impact of future regulations, including the potential need to operate under a carbon constraint,” said Mike Mudd, AEP Program Manager, Generation Technologies. “This does not preclude building conventional coal-fired plants, but the impact of future regulations will have to be considered in the economic evaluation of any technology.”
The possibility of a carbon constraint is paramount in the commercial deployment of IGCC. While the new batch of IGCC plants almost certainly won’t include equipment for carbon separation and sequestration, most will likely include “provisions for carbon capture,” according to Lowe. In other words, the plants will be designed so that a carbon sequestration technology retrofit would have limited capital impact on the existing plant.
IGCC plant developers may even need to consider geologic sequestration opportunities when siting a facility. According to Bill Raney, president of the West Virginia Coal Association, in an article in the Charleston Daily Mail, AEP may favor locations such as in the Ohio River Valley where the geologic formations are amenable to CO2 injection.
Driving IGCC capital costs down is not just wishful thinking. “Consider the Polk plant, for example,” said Lowe. “Most think of it as a state-of-the-art IGCC facility, but it’s based on an engineering design from the early 1990s, so it’s not truly state-of-the-art. It uses older FA gas turbine technology and, at 250 MW, is not sized to capitalize on economies of scale.” GE’s 600 MW standard IGCC plant design will benefit from the larger size and will also incorporate FB gas turbine technology. The FB is 10 percent larger than the FA, providing an immediate 10 percent capital cost reduction on a $/kW basis.
With respect to reliability, the challenges are real and significant, but not insurmountable. Eastman Chemical’s long and successful track record at its gasification facility in Tennessee provides a good measure of confidence, as does the industry’s frank acknowledgement that a learning curve will be necessary. “We are aware of the reliability and availability challenges of new technologies such as IGCC, but we are confident we have the technical expertise to address them,” said AEP’s Mudd. “Our driver is to use proven systems in the design of our plant so we can maximize its availability.”
ConocoPhillips’ Amick points to other opportunities to enhance reliability: “Advances in materials, like the refractory improvements from DOE’s Albany Research Center, could dramatically impact plant maintenance cycles and costs. The E-Gas technology alliance also offers a design configuration with a spare gasification train that increases overall annual plant availability by about 10 percent.”
To increase confidence in its standard plant design, GE is including three gasifiers - two will be operating and one will be a spare. This redundancy may not be needed as greater operating experience is gained, but initially it will be necessary to ensure customer acceptance. Further, the presence of natural gas on-site, which is used for plant start-up, should provide a further measure of comfort since it could also be used as backup fuel if necessary.
Building and operating an IGCC plant is one thing. Paying for it is another. In the near term, utility developers like AEP and Cinergy are planning to make a case for including the incrementally higher cost of IGCC in the rate base. AEP, which has targeted possible construction of an IGCC plant in seven states (Indiana, Kentucky, Michigan, Ohio, Tennessee, West Virginia, and Virginia), has initiated discussions with various regulators and lawmakers to discuss IGCC’s environmental advantages, the need for new long-term generation capacity, and possible cost-recovery assurance. In early February, AEP asked PJM Interconnection to evaluate transmission interconnection feasibility for three potential IGCC sites: Mason County, W. Va., adjacent to AEP’s Mountaineer Plant; Meigs County, Ohio; and Lewis County, Ky. All are on land currently owned by AEP and all are on the Ohio River.
“We are looking for certainty with regard to recovery of our investment,” said AEP’s Koeppel. “While this may be a departure from the traditional regulatory process, we believe that there are regulators in these states who will recognize that IGCC’s efficiency and environmental performance improvements - including the capability for future carbon capture - offer a strategic advantage that outweighs traditional least-cost considerations.”
State approval of a more expensive generation project is well within the realm of possibility. “A given project can be declared prudent even if it costs more,” said Robert P. Knickerbocker, Jr., Partner with Day, Berry & Howard. “Think back to the 1970s and the nuclear boom. Utilities were able to get regulatory rate approval - despite the fact that nuclear plants cost more and took longer to build - by emphasizing other favorable characteristics, such as lower long-term electricity costs, fuel diversity, and reduced emissions. Many of these same arguments can be made for IGCC today - the public is increasingly concerned about reliance on foreign sources of energy, environmental sensitivity remains high, and an ample supply of coal resources promises more stability in terms of electricity costs.”
Regulators, acting on behalf of ratepayers, have one over-riding concern when making rate decisions: least cost. “If IGCC is perceived to not be least cost, utilities won’t build and will lose out to a least-cost competitor,” said Indiana Commissioner Hadley. “Least cost, at least in Indiana, is followed by the words ‘reasonably possible over the life of the plant.’” That last phrase constitutes IGCC’s wiggle room, its wedge in the door. While a conventional coal plant will cost many millions less up-front than an IGCC plant, its cost rises considerably after accounting for existing and future environmental regulations.
Not all states are as enamored with IGCC. Wisconsin, for example, did not require We Energies to include IGCC in its analysis of technology options for additional capacity, in part because of IGCC’s higher costs. And even if state regulators are amenable to IGCC, they will not give utilities carte blanche when it comes to cost recovery for a $1 to $2 billion power plant. Public utility commissions, for example, could impose certain stipulations. Limits on cost overruns, limits on construction timelines, and only permitting one IGCC facility to be built until their viability is proven are possible constraints, according to Knickerbocker, as well as the traditional possibility of post-construction prudence review.
Conceptually, at least, AEP is open to such stipulations. “We would consider conditions and limitations that are reasonable for both customers and shareholders and performance criteria for cost and operations that can be reasonably managed by the company,” said Koeppel.
One interesting proposal being considered to potentially ease the financing of IGCC plants is the 3Party Covenant approach developed by the Kennedy School of Government at Harvard University. The 3Party Covenant is an arrangement between the federal government, state utility commission and equity investor that serves to lower the capital cost of IGCC by reducing the cost of debt, raising the debt-to-equity ratio, and minimizing construction financing costs. The federal government provides loan guarantees that facilitate an 80/20 debt-to-equity financing structure, the state PUC assures dedicated revenues by permitting rate recovery, and the equity investor contributes equity for 20 percent of the projects and negotiates performance guarantees to develop, construct and operate the plant.
“The rationale behind this approach is simple - debt is cheaper than equity, and government debt is cheaper than corporate bonds because there is no risk of default” said CERA’s Taub. “The federal loan guarantee would enable utilities and other project developers to access debt at about 5 percent, versus about 8 percent without the federal guarantee.” Proponents of the 3Party Covenant estimate that the capital costs for new IGCC facilities could be reduced by about 38 percent and the overall cost of energy could be reduced by about 25 percent.
Of course, the 3Party Covenant approach would require federal legislation authorizing loan guarantees for qualifying IGCC projects, which is by no means certain. Taub also isn’t convinced the 3Party Covenant approach is the best option. “An earlier draft of the energy bill, for example, included a production tax credit for IGCC facilities, which would probably be worth more money to IGCC owners than a loan guarantee, though it would be more costly for the federal government. And while a 10 percent investment tax credit probably wouldn’t be worth as much, it would have one major advantage - timing. Because an IGCC plant has a rather lengthy construction schedule, about four years, the investment tax credit would enable developers to avoid earnings dilution during construction rather than waiting until plant operation.”
The bottom line is that there is no certainty any of these support mechanisms will be enacted. The number of IGCC plants developed and built would certainly be much higher if a favorable federal provision was in place, but because IGCC is currently moving forward without support, the need for federal subsidization is debatable.
“Implementation of gasification technology, in power generation and in chemical production facilities, is going to happen in this decade,” said ConocoPhillips’ Amick. “While financial incentives for certain early projects will likely occur, our approach is to work closely with our alliance partner and clients to offer financeable, or regulatory commission approvable, installations. One size doesn’t fit all, and the widest deployment will result from a menu approach that provides options that utilities, IPPs and public power companies can all benefit from.”
In short, IGCC’s future seems bright, but while the interest from AEP, Cinergy and the various technology suppliers is favorable, it does not guarantee that the floodgates are opening on widespread commercial IGCC development. Although tight natural gas supplies have pushed natural gas prices to historically high levels - raising enthusiasm for IGCC to historically high levels as well - new natural gas resources could be opened to development and market dynamics could change, thereby dampening prices and dampening interest in IGCC.
IGCC also faces competition from supercritical steam technology. Supercritical technology is generally accepted as proven and mature, and because its efficiency and emissions performance is comparable to that of IGCC, it could be favored in certain cases. For what it’s worth, however, IGCC appears to have acquired a more environmentally friendly stigma than supercritical technology, moving it one step ahead in the public eye.
One of the advantages typically ascribed to IGCC technology is the ability to use all or a portion of the syngas from the gasifier to produce chemical by-products for use in various industries. While most of the IGCC projects on the drawing board are focused primarily on the power side of the equation, the ERORA Group, a privately held development and consulting company based in Louisville, Ky., is seriously exploring the possibility of a co-production IGCC facility.
When ERORA began developing a new minemouth power plant in south-central Illinois in 2003, they initially envisioned it as a pulverized coal plant. After evaluating some site-specific factors and conducting an initial feasibility study, however, IGCC entered the picture. “We took a hard look at IGCC in 2004, not concerned so much with the technical viability of the technology as with its commercial viability,” said David Schwartz, a Principal with ERORA. “In late 2004, we decided to go with IGCC, in part because of its environmental benefits, but also because of several perceived economic advantages related to its minemouth location, the favorable business climate in Illinois, and the opportunity to co-produce chemicals.”
The ERORA project will be a 677 MW (gross) IGCC facility, based on three gasification trains (two active, one spare) and a two-on-one combined-cycle power island. Online operation is expected around 2010, when baseload power demand will be needed in the region. ERORA will be filing its air permit application soon, after which it will focus its efforts on securing power sales agreements with interested parties. Initial discussions with various utilities, coops and municipal agencies have generated significant commercial interest, said Schwartz, who stressed that the ERORA facility would not function as a merchant power plant.
ERORA conducted a detailed economic analysis to ascertain the commercial viability of the IGCC facility with and without co-production. “In a heads-up comparison in baseload operation without co-production, we can beat a 200 to 300 MW pulverized coal plant,” said Schwartz. “At first blush, a larger scale (500 MW) PC plant would have a $3/MWh to $5/MWh advantage over the IGCC plant. However, syngas is unique in that it can be used both for power production and production of various chemicals. Combining two or more products in one plant allows you to achieve economies of scale in capital and operations, diversify your sources of revenue, take advantage of market prices, and achieve increased dispatch flexibility. When you consider this, an IGCC plant equipped for co-production can be competitive with a PC plant - and in several scenarios produces less expensive power.”
ERORA is not hanging its hopes on the possibility of federal support or tax breaks. “If the government is able to offer some form of incentive, I’m sure that would accelerate development of our project and others, but such support is not a deal-breaker for us,” said Schwartz. ERORA is aggressively pursuing the development of its planned Taylorville Energy Center, adding key players to the development team. The project stands to benefit substantially from an agreement it announced in February with Eastman Gasification Services Co. to study the feasibility of chemicals co-production. Eastman Gasification Services, a subsidiary of Eastman Chemical Co., offers more than 20 years of industry-leading coal gasification operating experience and know-how. For engineering services, ERORA turned to Burns & McDonnell Engineering Co. Inc. to act as architect/engineer for the project.
Power Engineering March, 2005
Author(s) :
Brian Schimmoller
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