igcc_energy center of wisconsin

8/9/2019 IGCC_Energy Center of Wisconsin.

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IGCC Engineering and Permitting

Issues Summaries

Clean Coal Study Group

April 2006


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Copyright 2006 Energy Center of Wisconsin.All rights reservedThis document was prepared as an account of work conducted by the Energy Center ofWisconsin (ECW) and was made possible by a grant from the Joyce Foundation. NeitherECW, participants in ECW, the organization(s) listed herein, nor any person on behalf of

any of the organizations mentioned herein:(a) makes any warranty, expressed or implied, with respect to the use of anyinformation, apparatus, method, or process disclosed in this document or that such usemay not infringe privately owned rights; or(b) assumes any liability with respect to the use of, or damages resulting from the useof, any information, apparatus, method, or process disclosed in this document.

Joe KramerSenior Project Manager

Acknowledgements

Energy Center of Wisconsin staff who contributed to this project include:

Stephen Voss

Melody Sakazaki

Joyce Foundation


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Engineering 3

Part 1 IGCC Engineering Issues Summary The purpose of this briefing paper is to summarize engineering issues associated with thecommercial application of coal-fueled integrated gasification combined cycle (IGCC)systems for electricity generation in Wisconsin.

The key questions identified by the Study Group and addressed in this paper are:

1. Is IGCC technology ready for commercial application?

2. How do the operational characteristics and construction timeframe of an IGCC

plant compare to super critical pulverized coal (SCPC)?

3. How does coal type affect IGCCs operational characteristics?

4. Does IGCCs fuel flexibility offer additional reliability benefits?

In addition to addressing these questions, this paper also provides further information oncurrent engineering efforts to improve performance and profitability.

1. Is IGCC technology ready for commercial application?

Coal-fired IGCC for energy generation is on poised for commercial application. Thecurrent round of proposed plants are expected to provide vital confirmation of predictedcapital costs that will supplement technical demonstrations of feasibility from existinggasification plants.1There is tremendous activity surrounding IGCC from major playerssuch as GE, Bechtel, Conoco Philips, Shell, the U.S. DOE, EPRI and GTI.

EPRI is spearheading an important commercialization effort known as the Coal Fleet ofTomorrow. The aim of the Coal Fleet initiative is to ensure competitive commercialofferings by 2015 to 2020.2This is being done through an industry consortium whichwill collectively address the barriers to commercialization for all advanced coal

technologies. It is significant to note that Coal Fleet is dedicating 90% of its initial effortto IGCC with the remaining 10% going to other technologies such as ultra supercriticalpulverized coal.

According to the Coal Fleet Program Summary, advanced coal technologies cannotreach commercial maturity until they have been proven in full-scale operation, underreal world conditions, for a sufficient time period to assure expectations of performanceand reliability. This is essential to convince prospective investors that costs and risks aresufficiently understood.3Towards this end, major players are designing and planning forcommercial scale demonstrations. For example, under a partnership with Bechtel, GEexpects to complete a 630MW, IGCC reference plant design by Q4 of 2006. Byproducing a standard reference plant design GE expects to be able to offer a structuredproduct, with lower capital expenditure, shorter cycle time and performance guarantees.4

1Kosstrin, Herbert M., Tomorrows Clean Coal Plants, Today, Public Power, Vol 64 No 2, March-April2006.2http://www.epri.com/portfolio/product.aspx?id=12953http://www.epriweb.com/public/corp_CoalFleet.pdf4Lowe, Edward, GEs Gasification Developments, Gasification Technologies Council, October, 2005http://www.gasification.org/


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Engineering 4

There are currently two large scale IGCC projects under serious consideration. Bothprojects have been the subject of discussion and pre-planning efforts since at least 2004.

5

GE, Bechtel and American Electric Power (AEP) are currently furthest along in theprocess with three potential locations identified in Meigs County, Ohio, Lewis County,Kentucky, and Mason County, West Virginia. All three sites are located along the Ohio

River. AEP hopes to begin construction in 2006 with completion targeted for 2010.Cinergy is also considering an IGCC plant in Indiana or Kentucky and has signed a letterof intent with GE and Bechtel for feasibility studies.

6,7,8

Gasification itself is a fairly mature process. However, most gasifiers are used to produceFischer Tropsch liquids and chemicals from coal and petroleum rather than powerthrough IGCC.9The problem being that based purely on cost of electricity (COE), IGCCis not competitive with traditional pulverized coal or natural gas. Similarly, in the future,IGCC is not expected to be the lowest cost solution without the imposition of significantadditional emissions restrictions. As additional emissions restrictions are imposed onelectricity generators, IGCC is expected to become the lowest cost solution especially ifcarbon capture and sequestration is required. The remainder of this paper will consider

technical aspects of IGCC, including advantages, challenges and ongoing developmentprojects.

2a. How do the operational characteristics of an IGCC plantcompare to super cr itical pulverized coal (SCPC)?

One significant advantage of IGCC is its relatively high efficiency, which is derived fromthe combined cycle portion of the process. IGCC is expected to yield higher electricityproduction efficiency than any other coal technology for the foreseeable future. This factalone makes IGCC attractive from an emissions standpoint. In addition to the highefficiency, the need to clean the syngas prior to combustion in a turbine results in anextremely clean exhaust stream. IGCC also results in significantly lower waterconsumption and solids production. Table 1 summarizes emissions profiles for IGCCcompared to pulverized coal. GE estimates that if super critical pulverized coal wererequired to achieve the same emissions levels as an IGCC plant, IGCC would achievecost parity.10However, the real advantage for IGCC comes in when carbon capture andsequestration (CCS) are considered.

5Gasification World Survey Results, U.S. DOE, Office of Fossil Energy, National Energy TechnologyLaboratory, 2004 http://www.netl.doe.gov/publications/brochures/pdfs/Gasification_Brochure.pdf6http://www.ge.com/stories/en/20385.html?category=Product_Business7http://www.aep.com/newsroom/newsreleases/default.asp?dbcommand=DisplayRelease&ID=11908AEP asks PJM for Transmission Interconnect Study, Platts T&D, 3/7/2005http://www.platts.com/Magazines/Platts%20T&D/News%20Archive/2005/030705_1.xml9http://www.netl.doe.gov/publications/brochures/pdfs/Gasification_Brochure.pdf10Rigdon, Robert; Schmoe, Lee, The IGCC Reference Plant, Gasification Technologies Council,October, 2005 - http://www.gasification.org/


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Engineering 5

Table 1:Comparison of emissions for IGCC versus a conventional pulverized coal plantwith emissions controls.

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IGCC Pulverized Coal

Sulfur Dioxide(lb/MBTU)

0.08 0.3

Nitrogen Oxide(lb/MBTU)

0.06 0.09

Particulate Matter(lb/MBTU)

0.06 0.3

Water Consumption(gal/MWh)

440 640

Total Solids Generated(lb/MWh)

120 250

The reason for IGCCs relative advantage in CCS is the concentration of the exhauststream. The CO2 concentration in natural gas exhaust is around 4%. For pulverized coalit increases to around 15%. For IGCC, carbon separation can be done prior to syngas

combustion where CO2concentrations can be 35-40%.12

A study conducted by MIT shows that the cost per tonne of avoided CO2emissions isdramatically lower for IGCC compared to natural gas combined cycle (NGCC) orpulverized coal. However, because of the extremely high efficiency of NGCC andresulting low CO2emissions, the actual added cost of electricity for IGCC and NGCC isquite similar. These results are summarized in Table 2. So, the ultimate economicviability of IGCC depends on two main components: increasingly stringent emissionsrequirements (particularly CO2) and high natural gas prices.13

Table 2:Cost of carbon capture from various generation technologies.14

IGCC Pulverized Coal NGCC

CO2 Created(kg/kWh)

6.64 7.66 3.37

Cost of Avoided CO2($/tonne)

18 32 41

Incremental COE(cents / kWh)

1.04 2.16 1.23

One persistent concern with IGCC systems is availability or reliability which has beendemonstrated to be a critical factor in achieving an acceptable return on investment.

15

Gasifier availability numbers for several IGCC projects are listed in Table 3. Future

11

Pashos, Kay, IGCC An Important Part of Our Future Generation Mix, Gasification TechnologiesCouncil, October, 2005 - http://www.gasification.org/12Alvey, Jennifer, The Carbon Conundrum, Fortnightly Magazine, August, 2003 -http://www.pur.com/pubs/4229.cfm13Narula, Ram, IGCC vs. SCPC: Battle of Technologies II, Gasification Technologies Conference,October 2005 - http://www.gasification.org/14David, Jeremy; Herzog, Howard, The Cost of Carbon Capture, MIT http://www.netl.doe.gov/publications/proceedings/01/carbon_seq_wksp/David-Herzog.pdf15Amick, P., et al, A Large Coal IGCC Power Plant, Bechtel Technical Paper, September, 2002http://www.bechtel.com/PDF/BIP/22008.pdf


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Engineering 6

IGCC plants are expected to address this reliability question in two ways. First, gasifierimprovements are expected to increase availability. Second, most commercialapplications are expected to include a spare gasification train. This is currentlyconsidered a necessity for achieving syngas availability of >90%.16

Table 3:Reported gasifier availability rates for several demonstration IGCC plants.17

Location Puertollano,Spain

Elcogas Nuon WabashRiver, IN

Polk PowerStation, FL

GasifierAvailability

76% 69% 82% 79% 82%

2b. How does the construction timeframe of an IGCC plantcompare to super cr itical pulverized coal (SCPC)?

There is much speculation in the literature about construction cost and timeline for IGCCand other advanced coal technologies. Unfortunately, there is little actual experience andthis is one of the key risk factors which has been identified,18and is being addressed by,

the Coal Fleet of Tomorrow initiative. The GE/Bechtel reference plant design mentionedabove is one example of what is being done to mitigate this uncertainty. However,standardization of design and streamlining of permitting processes are a common themefor major power projects across the board and IGCC will need to utilize these advanceddesign and construction techniques just to keep up.

A survey of coal technologies conducted by the World Bank found that construction of atraditional pulverized coal plant requires 38-58 months to complete. IGCC and AirFluidized Bed Combustion plants were both estimated to have similar time frames. Thestudy did find that Pressurized Fluidized Bed Combustion plants had the potential forshorter construction times (24-48 months) due to the potential for modular design andconstruction.19Alternatively, another study by the U.S. DOE concluded that IGCC and

circulating pressurized fluidized-bed combustors (CPFBC) should be expected to havelonger than average construction lead times.

20

In terms of actual on the ground experience, both the Wabash River Repoweringproject and the Polk Power Station greenfield project were completed with 2 years ofphysical construction time. The Wabash River plant was retrofitted between July of 1993

16Holt, N., Coal-based IGCC Plants Recent Operating Experience and Lessons Learned, GasificationTechnologies Conference, Washington, DC, October, 2004http://www.gasification.org/Docs/2004_Papers/22HOLT.pdf17Holt, N., Coal-based IGCC Plants Recent Operating Experience and Lessons Learned, GasificationTechnologies Conference, Washington, DC, October, 2004

http://www.gasification.org/Docs/2004_Papers/22HOLT.pdf18Nautilus Institute, IGCC in China, February 1999, -http://www.nautilus.org/archives/papers/energy/NIIGCCESENAY3.pdf19Tavoulareas, E.S., Charpentier, J.P, World Bank Technical Paper No. 286, Clean Coal Technologies forDeveloping Countries, July 1995http://www.worldbank.org/html/fpd/em/power/EA/mitigatn/thermpow.stm#top20U.S. DOE, Office of Fossil Energy, Market-Based Advanced Coal Power Systems Final Report, May1999 -http://www.fe.doe.gov/programs/powersystems/publications/MarketBasedPowerSystems/marketbased_systems_report.pdf


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Engineering 7

and November of 1995.21The Polk Power Station was constructed between November of1994 and September of 1996.

22

3. How does coal type affect IGCCs operationalcharacteristics?

Another frequently touted advantage of IGCC is fuel flexibility. The technical andeconomic performance of IGCC depends more strongly on feedstock quality thanpulverized coal.

23In the cost critical commodity market for electricity, IGCC will most

likely require optimum performance and therefore consistently high quality fuel for thegasifier. Table 4 details several IGCC plants which are currently under consideration. Thetwo plants which are furthest along in the development process are based in the OhioRiver valley with easy access to high grade coals.24

Table 4: IGCC projects currently under consideration in the U.S.Project Details

AmericanElectric Power

AEP has initiated interconnection studies with PJM for consideration of one ortwo 600MW, GE IGCC power plants. AEP is still evaluating several potential

locations in the Ohio River Valley.25Cinergy Cinergy signed a letter of intent with General Electric and Bechtel for a

feasibility study for an IGCC plant, most likely in Indiana or Kentucky. A CinergyIGCC facility probably would be in the range of 500 MW to 800 MW. Thecompany would like to have it in commercial operation around the end of thedecade.26

Mesaba EnergyProject

Excelsior Energy has plans for a 600MW ConocoPhillips E-Gas plant inMinnesota. Expected to begin operation in 2010 the project will utilize bituminousand sub-bituminous coals as well as pet coke.27

EnergyNorthwest

Energy Northwest is working on site selection for a 600MW IGCC facility inWashington state.28

Stanton Energy

Center

This is a joint development project for a 235MW IGCC plant between the DOE

and the Southern Company. The project is slated for ground breaking in 2007 andoperation in 2010.29

Indian RiverPlant

NRG Energy Inc.could put forward plans in the first half of 2006 to repower anexisting generating unit in Connecticut, Delaware, Maryland or New York withcoal gasification technology.30

21The Wabash River Coal Gasification Repowering Project, National Energy Technology Lab TopicalReport #7, November 1996http://www.netl.doe.gov/publications/others/topicals/topical7.pdf22Polk Power Station, IGCC Operation Lessons Learned, DOE Clean Coal Roundtable, July 2004http://www.climatevision.gov/pdfs/coal_roundtable/hornick.pdf23Dalton, Stu, Cost Comparison IGCC and Advanced Coal, presented at the Roundtable on Deploying

Advanced Clean Coal Plants, July 2004http://www.climatevision.gov/pdfs/coal_roundtable/dalton.pdf24Gasification World Survey Results, U.S. DOE, Office of Fossil Energy, National Energy TechnologyLaboratory, 2004 http://www.netl.doe.gov/publications/brochures/pdfs/Gasification_Brochure.pdf25http://www.platts.com/Magazines/Platts%20T&D/News%20Archive/2005/030705_1.xml26http://www.platts.com/Magazines/Platts%20T&D/News%20Archive/2005/030705_1.xml27http://www.climatevision.gov/pdfs/coal_roundtable/jorgensen.pdf28http://www.energy-northwest.com/downloads/igcc/IGCC%20Newsletter%200509.pdf29http://www.ouc.com/news/arch/20041021-cleancoal_proj.htm30http://www.snl.com/InteractiveX/article.aspx?CDID=A-2268341-13154


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Engineering 8

Table 5 summarizes the estimated heat rate and capital cost for an IGCC plant whenvarious coals are used. Due to the fact that emissions controls occur in the gas phase,prior to combustion, emissions performance is largely independent of gasifier feedstock.

Table 5:Engineering, procurement and construction cost estimates for a ConcoPhillips EGas technology using different fuels.31

Engineering, Procurementand Construction Cost

($/kW)

Approximate Heating Value(BTU/lb)

Bituminous Coal (Pitts #8) 1,140 13,100

Petroleum Coke 1,160 13,000

Bituminous Coal (Ill #6) 1,240 11,000

Sub-Bituminous Coal(Powder River Basin)

1,410 8,200

Lignite Coal 1,580 7,500

4. Does IGCCs fuel flexibili ty offer additional reliabilitybenefits?

Due to the economic sensitivity to coal type it is unlikely that IGCC plants will beoperated with a wide variety of feedstocks. In the event of a coal supply interruption,IGCC could be operated using suboptimal feedstocks. However, it does not appear thatthis would occur in such a way as to provide a competitive advantage to IGCC over othertechnologies.

However, IGCC units are fuel flexible in a secondary sense as well. The overall plantreliability and capacity factor can be substantially improved by maintaining the flexibilityto run the combined cycle power block with natural gas. When the gasifier is down formaintenance, the power block remains operational. The IGCC plant in Puertollano, Spain

and the Polk Power Station in Florida have reported power production availability of>93% by supplementing with natural gas despite gasifier availabilities of 76% and 82%respectively.32

Continuing Engineering Development and PerformanceImprovement

IGCC is an immature technology when compared to NGCC and pulverized coal. As aresult, significant performance improvements and capital cost reductions are expected forIGCC in the coming years. The rate of improvement is expected to significantly outpaceadvances in the more mature technologies against which IGCC is competing. Figure 1shows the configuration of the Wabash River Plant and provides an illustration of themajor components of an IGCC plant. Several of these components are the focus of activeresearch and development and are discussed below.

31Holt, N., Booras, G., A Summary of Recent IGCC Studies of CO2 Capture for Sequestration, TheGasification Technologies Conference, San Francisco, CA, October, 200332Holt, N., Coal-based IGCC Plants Recent Operating Experience and Lessons Learned, GasificationTechnologies Conference, Washington, DC, October, 2004http://www.gasification.org/Docs/2004_Papers/22HOLT.pdf


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Engineering 9

Figure 1:Schematic of the Wabash River Repowering Project plant.33

Coal FeedThe Wabash plant and other coal gasifiers currently use a coal and water slurry system todeliver coal to the gasifier. Significant efforts are being made to develop viable dry feedsystems. The potential advantages of a dry feed mechanism include reduced water use,reduced capital cost and reduced maintenance requirements. Methods of dry deliveryinclude lock hopper systems and solids pumps.

One of the primary challenges associated with dry feed systems is the ability to deliverthe coal at an elevated pressure. Lock hoppers accomplish this by passing the coalthrough staged load locks that enable the pressure to be increased in stages. The solidpumps are more elegant and allow continuous feed of the coal. A recent paper from

Stamet, Inc. reported the successful continuous delivery of pulverized coal at a pressureof more than 500psi. Another advantage of Stamets Posimetric dry feed pump is that itrequires significantly less make up gas than lock hopper systems, therefore reducing theamount of pure oxygen required.

33http://www.clean-energy.us/illustrations/schematic_wabash_igcc.htm


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Engineering 10

Additional development of the dry pump is currently underway with the goals ofachieving a 1000psi feed pressure and integrating a commercial scale unit at the PowerSystems Development Facility in Wilsonville, AL.34

Oxygen Plant

Gasification is done in a precisely controlled atmosphere which allows the coal (or otherfeedstock material) to react without combusting. To accomplish this, most gasifiers areoxygen blown, meaning that nearly pure oxygen is fed into the gasifier unit. Oxygenseparation from the atmosphere has typically been accomplished through a cryogenicdistillation process. Air is cooled until the various gases condense to liquids and can beseparated. This is an expensive and energy intensive process which can account for asmuch as 15% of the capital costs and reduce the overall efficiency of the IGCC plant.

The primary effort in this area is to develop an Ion Transport Membrane (ITM) systemwhich will produce oxygen for approximately 2/3 the cost of conventional cryogenicsystems. Successful integration of an ITM oxygen system is expected to improve overallplant efficiency by 2.2% and reduce the total plant capital cost by 7%.

35

The ITM development project was started in 1999 and is being led by Air Products.Phase 1 of the project has been completed and demonstrated 0.1 tons per day of oxygenproduction. Phase 2 is currently underway with the goal of demonstrating 1-5 tons perday of oxygen production. The final phase will aim to demonstrate 25-150 tons per day ofoxygen production and is scheduled to be completed in 2008. The Department ofEnergys FutureGen project (2012) is expected to require 500-2000 tons per day ofoxygen.36

Gasification

There are numerous projects underway to improve the operation of gasifiers which are

the central component of an IGCC plant. These projects range from materialsimprovements of refractory gasifier liners and metal component coatings to improvedflame monitoring equipment. Work is also underway to develop and evaluate entirelynew gasifier designs. For example, Rocketdyne has efforts underway to adapt its rocketengines for low cost, high efficiency coal gasification.

37The Power Systems

Development Facility has been in operation since 1990 and is the main facility fordemonstration of advanced coal configurations and components.38

As mentioned above, one of the important gasifier efforts focuses on improvements torefractory components. These components line and protect the inside of the gasifierchamber and are subject to harsh chemical and high temperature environments.

34Saunders, Timothy, Aldred, Derek, Successful Continuous Injection of Coal into Gasification and PFBCSystem Operating Pressures Exceeding 500psi DOE Funded Program Results, October, 2005http://www.gasification.org/Docs/2005_Papers/44SAUN%20Paper.pdf35http://www.netl.doe.gov/technologies/coalpower/gasification/projects/gas-sep/O2/o2-42469.html36Armstrong, Phillip, et al., ITM Oxygen: The New Oxygen Supply for the New IGCC Market,Gasification Technologies 2005, http://www.gasification.org/37http://www.netl.doe.gov/technologies/coalpower/gasification/projects/adv-gas/adv-design/ad42237.html38Clean Coal Today, U.S. DOE, Office of Fossil Energy, DOE/FE-0215P-41, Fall 2000http://www.netl.doe.gov/technologies/coalpower/cctc/newsletter/documents/00_fall.pdf


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Engineering 11

Improving the robustness of these refractory materials and simplifying the change outprocedures are critical to improving the up-time of IGCC units.

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Syngas Clean-up

One of the major goals for improving the IGCC process is to enable hot syngas clean-up.

The current standard process takes the syngas from its formation temperature of 2100-2700F and cools it in several stages. At the Wabash River Plant the syngas is ultimatelycooled to ambient temperature prior to desulfurization through hydrolysis. The syngas isthen reheated prior to combustion in the turbine.40

Advanced desulfurization methods use zinc and sodium based sorbents injected in the gasstream to clean the gas. This has been demonstrated at warm gas temperatures of

550F.41

Gas Turbine

According to a paper on design and integration of IGCC power plant facilities preparedby Bechtel, the gas turbine is the critical component for optimizing overall plantperformance. Critical considerations include: integration with the high pressure steamgeneration from exhaust gases, air extraction integration between the gas turbine and theair separation unit, NOx control, gas turbine power augmentation and overalloptimization of the gas turbine for use with syngas.42,43The U.S. DOE has severalprograms in place aimed at near, mid and long-term turbine development objectivesextending out to the year 2020.

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Conclusion

IGCC is ready for large scale demonstration and early adopter investment (supplementedby significant government assistance). In order to move from this stage to full

commercial viability, IGCC is dependent on four critical developments. These are: Continued technological advances to improve efficiency and reduce capital cost

Continued tightening of emissions requirements most critically carbon emissions

Continued high cost of natural gas

Successful completion of large scale demonstration facilities to provide constructionand operating experience and reduce investment risk.

39http://www.netl.doe.gov/technologies/coalpower/gasification/projects/adv-

gas/materials/materials/matAA010B.html40The Wabash River Coal Gasification Repowering Project, National Energy Technology Lab TopicalReport #7, November 1996http://www.netl.doe.gov/publications/others/topicals/topical7.pdf41http://www.netl.doe.gov/technologies/coalpower/gasification/projects/gas-clean/adv-clean/ac40674.html42Geosits, R.F., Schmoe, L.A., IGCC The Challenges of Integration, GT2005 ASME Turbo Expo2005, June 2005http://www.bechtel.com/PDF/BIP/35478.pdf43http://www.gepower.com/prod_serv/products/tech_docs/en/downloads/ger4207.pdf44http://www.netl.doe.gov/technologies/coalpower/turbines/goals.html


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Permitting 12

Part 2 IGCC Permitt ing Policy Issues Summary CleanCoal Study Group March 2006The purpose of this briefing paper is to highlight permitting issues associated with thecommercial installation of coal-fueled IGCC systems for electricity generation in

Wisconsin. The Clean Coal Study Group identified the following guiding questions aboutpolicy issues related to IGCC permitting.

1. Are there any barriers to permitting an IGCC unit in the state?

2. What, if any, policy changes might be needed to permit an IGCC unit in Wisconsin?

3. What can we learn from other states?

4. Are there regulatory options for risk-sharing given that IGCC is a newer technology?

This document is organized along the lines of these questions to directly address theneeds of the group.

1. Are there any barriers to permitting an IGCC unit in the state?IGCC facilities face many of the same permitting barriers that more-established fossilfuel combustion technologies must face. This section focuses on two barriers that areunique to, or are more pronounced with IGCC facilities. These are:

IGCC status as a pre-commercial technology for energy generation,

Lack of requirements for the strict emissions controls of which IGCC is capable.

Pre-Commercial Technology

Probably the largest hurdle for IGCC technology is the fact that it is not yet fully

commercially demonstrated for electricity generation. This situation creates a number ofdifficulties. First, state permitting agencies may not have sufficient information on thesesystems to allow routine and timely permitting. For instance, composition and properhandling and treatment of production byproducts such as gasifier slag may not be wellknown at the point of permitting. Furthermore, should CO2emissions become regulated,the permanence, efficacy and practicality of sequestration practices such as deep geologicsequestration and enhanced oil recovery require further study. This can translate intocostly delays in the permitting process. While the scant experiences with permitting forIGCC projects thus far includes some signs that environmental regulators view thesystems positively, due largely to the favorable emissions profile for the technology,

45

permitting agencies and applicants alike would benefit greatly by having dependable,

unbiased information resources and personnel to help guide their process.Another possible new-technology related permitting issue is that environmentalperformance and operational reliability may not be as consistent for IGCC facilities asthat of more-established technologies during the early stages of implementation and

45Talend, Don, On the Clean Cutting Edge: Planned Illinois plant should serve as a reference for coalgasification benefits for future coal facilities, Distributed Energy: The Journal for Onsite PowerSolutions, November/December 2005.


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Permitting 13

operation. Deployment of the first commercial scale IGCC systems using coal for energygeneration will require a period of shakedown in which the technology and operationalpractices are tuned and refined before steady-state operation begins.

The complexity and flexibility of an IGCC facility can also work against it duringpermitting. A National Association of Regulatory Utility Commissioners report describes

the licensing process for IGCC power plants as being far more complex thanconventional coal plants and calls it a major challenge in IGCC deployment.46Undercurrent requirements, IGCC power plants may require licensing as electricity generationunits, as syngas facilities, and as co-production plants. David Schwartz, of the ERORAGroup, a private developer working on the Taylorville IGCC facility in Central Illinois,concurs that the most difficult part of the permitting process is getting the facility to beviewed as one facility rather than three separate components.

47

Finally, the higher cost associated with IGCC plants relative to other advanced coaltechnologies (a cost differential that is expected to narrow as more plants are installed)can make it difficult to obtain a Certificate of Public Convenience and Necessity.Evaluation tools used by the utility commissions may not attribute sufficient value to thepositive traits of IGCC to offset these higher costs.

Lack of Incentives to Go Beyond Compliance

One of the strengths of IGCC systems for electricity generation using coal is theirpotential for emissions control including CO2capture for sequestration. Currentenvironmental permitting practices negatively affect IGCC systems in a backhanded wayby not requiring the degree of control of which this technology is uniquely suited.Therefore, evaluation of IGCC systems versus other advanced coal technologies willleave this important trait off the balance sheet, putting IGCC at a disadvantage.Incentives to go beyond compliance such as tradable emissions credits can give IGCC

systems some monetary benefit for their low emissions and make them compare morefavorably financially.

2. What, if any, policy changes might be needed to permit anIGCC unit in Wisconsin?

Based on previous research, policy changes that would simplify permitting of an IGCCunit in Wisconsin include:

An expedited process to develop a single set of standards specifically for siting andpermitting IGCC plants including co-production processes.

Development of a Memoranda of Understanding specifying compatible regional

standards to address air shed issues associated with IGCC permitting.

Set IGCC as the BACT of coal power plants

46National Association of Regulatory Utility Commissions,An Analysis of the Institutional Challenges toCommercialization and Deployment of IGCC Technology in the U.S. Electric Industry: Recommended

Policy, Regulatory, Executive and Legislative Initiatives, March 2004, DOE/NARUC Partnership forAdvanced Clean Coal Technology, prepared by Global-Change Associates.47Talend D, 2005.


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Permitting 14

An Expedited Process for Permitt ing

Currently an IGCC plant is subject to multiple permitting processes because it is treatedas both a chemical plant and a power plant. The gasifier, the gas turbine and the co-production unit operations must obtain separate and distinct operating permits, whichgreatly complicates and slows the permitting process. Therefore, state governmentdevelopment of a single set of standards specifically for siting and permitting IGCCplants, including co-production processes, would be beneficial.

In addition, although the flexibility of feedstocks for IGCC is theoretically a benefit dueto financial stability because of diversification options, it also creates complications insiting and permitting of IGCC plants. This is because permit-based requirements formaterial handling, allowable emissions and operator training varies based on thefeedstock.

Memoranda of Understanding to Address Air Shed Issues

The states could develop Memoranda of Understanding specifying compatible regional

standards to address air shed issues associated with IGCC permitting. The transitionalstate-by-state changes in the electric utility industry have resulted in a lack of regionalplanning. This lack of regional planning has resulted in short-term and incrementalinvestments in energy such as NGCC rather than in investments in systems that areeconomically sustainable in the long-term.

Setting IGCC as the BACT of Coal Power Plants

The New Source Review (NSR) process requires that a company proposing to build amajor new emissions source, or to make major modifications on an existing source, act tominimize air pollution emissions by changing the process and/or installing air pollutioncontrol equipment. Sources going through NSR in attainment areas (those not designated

by the US EPA as being in non-attainment for the criteria pollutant(s) in question) mustidentify and install the Best Available Control Technology (BACT). The BACT processincludes 5 steps: 1) identify all control technologies, 2) eliminate technically infeasibleoptions, 3) rank remaining control technologies by control effectiveness, 4) evaluate mosteffective controls and document results, and 5) select BACT. In December of 2005 theUS EPA decided that IGCC need not be considered under a Clean Air Act BACTanalysis for proposed pulverized coal-fueled electricity generating facilities. However,contrary to the federal decision, specific states including: California, New Mexico,Illinois, and Montana decided the BACT for coal plants is now IGCC. For those stateswhen a power company decides to invest in a new coal power plant they must use IGCCor a technology that is better than IGCC in terms of meeting emission standards and

requirements.

3. What can we learn from other states?

The National Association of Regulatory Utility Commissioners, the National Associationof State Energy Officials, and the Environmental Council of States developed a survey tocollect and describe different State approaches and/or incentives for improvedenvironmental performance of fossil-fuel based electricity generators. The survey dataprovides examples of regulatory options to encourage utilities to upgrade existing base-


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load generation facilities through incentives, mandates and rate cases. Policy tools thatthe report listed in states to advance the development of IGCC can be categorized as: airpollution regulations, cost recovery rules, demand-side management, and financingmechanisms.48 The main conclusions from their survey are:

More widespread and consistent incentives may encourage increased regulatory

certainty, enabling utilities to initiate widespread environmental upgrades.

Most states do not have mandated financial or regulatory incentives for base-loadenvironmental upgrades and this contributes to lack of regulatory certainty and highimplementation costs.

There are currently six IGCC plants in the United States. Two of these are under150MWe (Coolwater, Frontier) and four are 150-325MWe (Wabash, Dow, Polk,Delaware). However, both Coolwater and Dow are decommissioned. According JimFalsetti of Process Energy Systems there are currently 16 proposed IGCC projects locatedin Florida, Idaho, Illinois, Indiana, Kentucky, Minnesota, Ohio, Oklahoma, Wyoming,and Pennsylvania, ranging in size from 41 MWe to 2400 MWe. Although there are many

factors that influence the decision to invest in an IGCC plant, state policies can play arole. For the listed states the policies they have implemented include:

A. Air pollution regulations where utilities are allowed to improve cash flow byincluding pollution control equipment as construction work in progress in the ratebase (IN)

B. A cost-sharing program to reduce GHG emissions (OH)

C. A cost-recovery program (IN)

D. An environmental surcharge which provides for the current recovery of the costsof complying with the Clean Air Act and other environmental requirements (KY)

E. Loans for development of alternative energy technologies (PA)

F. Rate making treatments (IN, PA)

G. Set-asides for certain technologies such as alternative or advanced energyportfolios (PA)

H. Expedited depreciation of IGCC plants (IN)

4. Are there regulatory options for risk-sharing given that IGCCis a newer technology?

Two options for state risk-sharing in developing, installing and operating IGCC systems

are summarized below.

48National Association of Regulatory Utility Commissioners, A Survey of State Incentives EncouragingImproved Environmental Performance of Base-Load Electric Generation Facilities: Policies and RegulatoryInitiatives. Publication available at: http://www.naruc.org/displayindustryarticle.cfm?articlenbr=21611,(2004).


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State PUC Approval Process

A state PUC (or other utility ratemaking body), acting under state enabling authority,could allow sharing of the risk of investing in IGCC if it agrees to assure dedicatedrevenues to qualifying IGCC projects sufficient to cover return of capital (depreciationand amortization), cost of capital (interest and authorized return on equity), taxes, and

operating costs (e.g., operation, maintenance, fuel costs, and taxes).49In states withtraditional regulation of retail electricity sales, the state PUC could provide this revenuecertainty through utility rates, power purchase or other off-take agreements, or throughother recent innovations in finance such as currency futures, interest-rate swaps and caps,and currency swaps. For states with competitive retail electricity sales, state PUCs canassure revenues through non-bypassable wires charges and fixed capacity charges, and bycertifying (after appropriate review) that the plant qualifies for cost recovery andestablishing rate mechanisms to provide recovery of approved costs, including cost ofcapital. The certification by the state PUC occurs upfront when the decision to proceedwith the project was being made, and the prudence review by the state PUC and costrecovery occurs on an ongoing basis starting during construction, which reduces the

construction risks borne by the developer, avoids accrual of construction financingexpenses, and protects ratepayers.

Long-term Power Contract with Utility

The equity investor, whether an electric utility, municipal utility, rural electriccooperative, or independent power producer, would experience reduced risk if it couldsecure a long-term power contract with a utility (or a contract that has a comparablecredit rating). The securing of long-term power contract removes some marketuncertainties for owners of the energy generation facility, improving the likelihood thatgoals for payback will be met.

49Rosenberg, William, Dwight Alpern and Michael Walker, Deploying IGCC In this Decade With 3PartyCovenant Financing, Produced as part of the Energy Technology Innovation Project, Belfer Center forScience and International Affairs, July 2004.

igcc_energy center of wisconsin

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