http://www.platts.com/business/issues/0105/0105geb_gilliland.shtml

Global Energy Business May/June 2001 Feature

California, Competition, and Control
By Jason Makansi
...  "Risk management is one of the things Duke does really well. It's a centralized function within Duke; all business units apply risk management tools."
...California, of course, is on everyone's mind. And for good reason. The dream of a market-based electricity industry there has become a nightmare of bankrupt distributors, irate customers, rolling brownouts, out-of-control volatility, and the reappearance of the heavy hands of price caps and government ownership. And the California disease could be contagious. Other states are re-examining their competition initiatives and even rolling them back. Now it looks like Nevada's electric utilities are next in the bankruptcy queue, Montana legislators are very nervous about the financial health of their electric utilities, and the Pacific Northwest may not be far behind.
..."Most of the newly announced coal-fired units will prove not viable economically," [Gilliland ] he predicts. "Inflation for power plant equipment is running in the double digits right now, and construction labor costs are also rising significantly." Gilliland also adds that you have two choices for coal--a minemouth facility or a facility near a load center. "With one, you're constrained by the lack of transmission, and with the other, the railroads


have a stranglehold over fuel transportation."

================================================================
http://www.fetc.doe.gov/publications/press/1999/tl_global.html
U.S. Department of Energy

  Issued on November 15, 1999
          Richardson Approves Federal Funding for
       High-Tech, Ultra-Clean Coal Plant in Kentucky
  Energy Secretary Bill Richardson, Kentucky Governor Paul Patton, and Senator Mitch
  McConnell today announced that the Kentucky Pioneer Energy Project, planned for Clark
  County, KY, will become part of the federal government's Clean Coal Technology Program.

  Richardson approved the use of $78 million in Clean Coal Technology33333
  funding as the federal share of the $432 million project. The
  400-megawatt project will be one of the largest power plant projects in
  the federal Clean Coal Technology Program. The program provides federal
  matching funds for projects that demonstrate new ways to use coal while
  reducing air and other pollutants.

  "The Kentucky Pioneer Energy Project will be a showcase facility," Richardson said. "It will
  employ advanced, clean technology that will benefit the environment, provide low cost power to
  spur economic growth, and demonstrate how cities can eliminate municipal solid waste by
  mixing it with coal to produce electricity."

  "The Energy Department's participation is a major boost for the project," said Governor Patton.
  "It means that project financing will be significantly strengthened and the project will be able to
  incorporate additional high-tech innovations. Importantly for Kentucky consumers, the plant
  will produce electricity at rates that will be among the lowest in the State."

  "This public-private sector partnership we are announcing today will help move Kentucky's
  coal and electric power industries into the 21st century with some of the most sophisticated
  technology now available," said Senator McConnell. "The government's role in this project
  represents a solid investment in the energy future of Kentucky and this country."

  The federal funding is part of agreements reached this week between the Energy Department,
  Duke Energy Corp. of North Carolina, and Global Energy Inc., the Cincinnati-based parent
  company of Kentucky Pioneer Energy. Under the agreements, Global Energy will replace Duke
  Energy as the department's industrial partner in a Clean Coal Technology project that had
  encountered siting difficulties in southern Illinois.

  The Illinois project was to employ much of the same technology as the Kentucky project, and
  as part of this week's agreements, the Energy Department will approve "relocating" the project
  to eastern Kentucky. Global Energy, in turn, agreed to incorporate several unique features of
  the Illinois project into the Kentucky project, including tests of advanced fuel cell. The company
  will also provide the Energy Department with technology data from the project's design,
  construction and operation.

  Plans are to use a site near Trapp, Kentucky, originally slated for a conventional coal-fired
  power plant nearly two decades ago. When the forecasted demand for electricity failed to
  materialize in the early 1980s, construction at the East Kentucky Power Cooperative's J.K.
  Smith site was halted, leaving an excavated tract with plant foundations, an administration
  building, railroad spur and connections to the electrical grid.

  Now, the idle 300-acre tract will become the site for a new type of ultra-clean coal technology.
  Known as "integrated gasification combined cycle," the advanced process first converts coal to
  a "synthesis gas." A key advantage of the gasification step is that the synthesis gas can be
  meticulously cleaned before it is burned to generate electricity.

  In the Kentucky project, the gasification process will incorporate an added "advanced fuel
  technology" feature. Municipal solid waste will be collected and combined with coal to form
  fuel briquettes for the gasification process. Global is reviewing possible "fuel island" locations
  around the State where the briquettes will be made.

  The synthesis gas will be burned in a combustion turbine to generate electricity and exhaust
  heat will be used to boil water to drive a steam turbine. The combination of the two types of
  power generating turbines accounts for the name "combined cycle."

  Another high-tech innovation will be the use of a fuel cell in the plant's power generating
  section. Fuel cells generate electricity using an electrochemical reaction, much like a battery.
  Because no combustion is involved, fuel cells are among the cleanest power technologies now
  envisioned. In the Kentucky project, some of the synthesis gas will be directed to a
  1.25-megawatt molten carbonate fuel cell to be furnished by FuelCell Energy Inc. of Danbury,
  CT.

  When operations begin in 2002, electricity from the plant will be sold to East Kentucky Power
  Cooperative under a 20-year contract.

  The project is the fourth in the Clean Coal Technology Program to demonstrate coal gasification
  but the first to be partially fueled by municipal solid waste and to employ a fuel cell. It will also
  mean $105 million in cost savings for the taxpayer. The Illinois project had been projected to
  cost $841 million with the Energy Department's share amounting to $183 million. Under the
  new project agreement, the Energy Department's share will be capped at $78 million.

                       - End of TechLine -
===============================
http://edj.net/sinor/sfr1-00art5.html

FEDERAL FUNDING APPROVED FOR KENTUCKY PIONEER ENERGY PROJECT

In November the United States Department of Energy (DOE) announced that the Kentucky Pioneer Energy Project, planned for Clark County, Kentucky, will
become part of the federal government?s Clean Coal Technology Program.

United States Energy Secretary B. Richardson approved the use of $78 million in Clean Coal Technology funding as the federal share of the $432-million,
400-megawatt project.

"The Kentucky Pioneer Energy Project will be a showcase facility," Richardson said. "It will employ advanced, clean technology that will benefit the
environment, provide low cost power to spur economic growth, and demonstrate how cities can eliminate municipal solid waste by mixing it with coal to
produce electricity."

The federal funding is part of agreements reached between the United States Energy Department, Duke Energy Corporation of North Carolina, and Global
Energy Inc., the Cincinnati-based parent company of Kentucky Pioneer Energy. Under the agreements, Global Energy will replace Duke Energy as the
department?s industrial partner in a Clean Coal Technology project that had encountered siting difficulties in Southern Illinois.

The Illinois project was to employ much of the same technology as the Kentucky project, and as part of the agreements, the Energy Department will approve
"relocating" the project to Eastern Kentucky. Global Energy, in turn, agreed to incorporate several unique features of the Illinois project into the Kentucky
project, including tests of advanced fuel cells. The company will also provide The DOE with technology data for the project?s design, construction and
operation.

Plans are to use a site near Trapp, Kentucky, originally slated for a conventional coal-fired powerplant nearly 2 decades ago. When the forecasted demand for
electricity failed to materialize in the early 1980s, construction at the East Kentucky Power Cooperative?s J.K. Smith site was halted, leaving an excavated
tract with plant foundations, an administration building, railroad spur and connections to the electrical grid.

Now the idle 300-acre tract will become the site for a new integrated gasification combined-cycle powerplant.

In the Kentucky project, the gasification process will incorporate an added feature. Municipal solid waste will be collected and combined with coal to form fuel
briquettes for the gasification process. Global is reviewing possible "fuel island" locations around the state where the briquettes will be made.

Another high-tech innovation will be the use of a fuel cell in the plant?s power generating section. Because no combustion is involved, fuel cells are among the
cleanest power technologies now envisioned. In the Kentucky project, some of the synthesis gas will be directed to a 1.25-megawatt molten carbonate fuel cell
to be furnished by FuelCell Energy Inc. of Danbury, Connecticut.

When operations begin in 2002, electricity from the plant will be sold to East Kentucky Power Cooperative under a 20-year contract.

The project is the fourth in the Clean Coal Technology Program to demonstrate coal gasification but the first to be partially fueled by municipal solid waste and
to employ a fuel cell.
=============================
Duke Energy: Main Phone #
1-800 USE-DUKE (1-800-873-3853)
=============================
http://ens.lycos.com/ens/jul99/1999L-07-27-09.html
AmeriScan: July 27, 1999

RISING COAL USE INCREASES AIR POLLUTION

                                   Coal consumption in the U.S. has risen almost 16 percent since 1992, says a report by the
                                   Environmental Working Group and the U.S. Public Interest Research Group (USPIRG).
                                   Many older coal burning power plants were exempted from Clean Air Act standards. When
                                   Congress deregulated wholesale electricity sales in 1992, these old plants became more
                                   profitable because they compete with more recently built plants required to install pollution
                                   control equipment. The report, "Up In Smoke," looks at federal data on 446 power plants
                                   across the nation, tracks the use of coal plants since the 1992 Energy Policy Act was
                                   passed, and calculates the resulting smog and global warming pollution. Increased electrical
                                   generation at coal burning plants emitted 755,000 tons of nitrogen oxide pollution and 298
                                   million tons of carbon dioxide in 1998. By increasing coal generation, eight large utility
                                   companies, American Electric Power Company, Cinergy Corporation, Dominion Resources
                                   Inc, Duke Power Company, Edison International, The Southern Company, Tennessee Valley
                                   Authority and Associated Electric Coop each emitted as much smog pollution as one million
                                   cars. Increased smog pollution from Illinois, West Virginia, North Carolina, Missouri,
                                   Indiana and Georgia power plants each equaled that from two million cars. "This summer,
                                   tens of thousands of Americans will go to emergency rooms due to smog," said Rebecca
                                   Stanfield, clean air advocate for USPIRG. "It's time for Congress to protect public health by
                                   closing the loopholes allowing old coal plants to pollute our air."

                                                           * * *

==============================
http://energy-tech.com/cgi-bin/news_search.cgi?a=1&type=newsnumber&search=n001291

Posted on Energy-Tech.com on: 2001/12/04
Americans Favor Alternative Energy Methods to Solve Shortages

According to a new poll by the Gallup Company, Americans favor investment in the country's energy
infrastruture and the development of alternative energy sources. However, while more than 80% of the
respondents favor the creation of new power plants, the number favoring more nuclear plants has
dropped since the last poll in May. Anaylysts assume the decreased support for nuclear plants stems from
the September 11 terrorists attacks and heightened concerns over the security risks posed by nuclear
plants.

In terms of renewable energy sources, the poll found 91% of Americans in favor of developing these
sources. While the September 11 attacks helped raise concern over the countrie's dependence on
forgeign oil, a slim majority still oppose opening the Artic National Wildlife Refuge to oil exploration. 51%
are opposed to the move, compared to 57% opposed in May.

These results are based on telephone interviews with a randomly selected national sample of 512 adults,
18 years and older, conducted Nov. 8-11, 2001. For results based on this sample, one can say with 95
percent confidence that the maximum error attributable to sampling and other random effects is plus or
minus 5 percentage points. In addition to sampling error, question wording and practical difficulties in
conducting surveys can introduce error or bias into the findings of public opinion polls.

====================================
Posted on Energy-Tech.com on: 2001/11/30

http://energy-tech.com/cgi-bin/news_search.cgi?a=1&type=newsnumber&search=n001284

U.S. Carbon Dioxide Emissions Increase by 3.1 Percent in 2000

Estimated emissions of carbon dioxide in the United States and its territories, which account for more
than 80 percent of total U.S. greenhouse gas emissions, increased by 3.1 percent in 2000, rising from
1,536 million metric tons of carbon equivalent (MMTCe) in 1999 to 1,583 MMTCe in 2000, according to
Emissions of Greenhouse Gases in the United States 2000, a report released by the Energy Information
Administration (EIA). The growth in carbon dioxide emissions, 3.1 percent, was one percentage point
below the 4.1 percent growth in Gross Domestic Product (GDP). Energy-related carbon dioxide
emissions, which account for 98 percent of total carbon dioxide emissions, stood at 1,547 MMTCe, while
carbon dioxide emissions from other sources were 36 MMTCe.

The 3.1 percent growth in emissions in 2000 is the second highest growth rate for the 1990 to 2000 period,
with only the 3.4-percent growth rate in 1996 being higher, and is well above the average growth rate of
1.6 percent for the 1990 to 2000 time frame. The high growth in carbon dioxide emissions can be
attributed to a return to more normal weather, decreased hydroelectric power generation that was
replaced by fossil-fuel power generation, and strong economic growth (4.1 percent increase in GDP).

Total U.S. greenhouse gas emissions rose by 2.5 percent in 2000, increasing from 1,860 million metric
tons of carbon equivalent (MMTCe) in 1999 to 1,906 MMTCe in 2000. The 2000 growth rate of 2.5
percent was well above the average annual growth rate of 1.3 percent observed from 1990 to 2000, as
well as the 1999 growth rate of 1.3 percent.

Total estimated U.S. greenhouse gas emissions in 2000 consisted of 1,583 MMTCe of carbon dioxide (83
percent of total emissions), 177 MMTCe of methane (9 percent of total emissions), 99 MMTCe of nitrous
oxide (5 percent of total emissions), and 47 MMTCe of hydrofluorocarbons (HFCs), perfluorcarbons
(PFCs) and sulfur hexafluoride (SF6) (2 percent of total emissions). Detailed information by greenhouse
gas includes the following:

Estimated methane emissions, the second largest contributor after carbon dioxide to total greenhouse
emissions, declined by 1.6 percent, from 180 MMTCe in 1999 to 177 MMTCe in 2000. Since 1990, U.S.
methane emissions have declined by about 11 percent.

Estimated nitrous oxide emissions in 2000 fell by 0.6 percent, from 100 MMTCe in 1999 to 99 MMTCe in
2000. Nitrous oxide emissions have grown by 5.3 percent since 1990.

Emissions of human-made gases such as hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and
sulfur hexaflouride experienced a 4.5 percent increase (from 45 to 47 MMTCe) between 1999 and 2000.
However, these gases as a group have grown by 57.8 percent since 1990.

The report also contains estimates of carbon dioxide emissions from energy consumption, including
emissions from purchased electric power, on a sectoral level:

Transportation-related carbon dioxide emissions, which account for about a third of the total carbon
dioxide emissions from energy consumption, increased by 3.1 percent in 2000 to 515 MMTCe in 2000, as
a healthy economy encouraged travel and the delivery of goods.

Carbon dioxide emissions in the residential sector increased by 4.9 percent to 313 MMTCe, while
emissions in the commercial sector rose by 5.8 percent to 268 MMTCe in 2000. This growth was driven
by a return to more normal weather, higher fossil-fueled power generation and a strong economy.

Despite rapid growth of the economy (4.1 percent growth), energy-related industrial carbon dioxide
emissions in 2000 remained flat at 466 MMTCe. This constancy is due in part to slower growth in the
energy-intensive industries compared with the non-energy-intensive industries and possible efficiency
improvements.

Carbon dioxide emissions from the U.S. electric power sector in 2000, which are included in the sectoral
totals above, are estimated at 642 million metric tons carbon equivalent, 4.7 percent higher than the 1999
level. The 2000 increase is almost double the 1990-2000 average increase of 2.4 percent per year.
Contributing to the relatively large increase in 2000 was a 4.2 percent increase in fossil fuel use for
electricity generation, as well as an 11 percent reduction in electricity generation from renewable fuels,
including a 14 percent drop in hydroelectric generation.

Emissions of Greenhouse Gases in the United States 2000 was prepared by EIA pursuant to section
1605(a) of the Energy Policy Act of 1992. EIA is an independent, policy-neutral agency within the
Department of Energy that is responsible for collecting, analyzing, and disseminating energy information.

An electronic version of the report is available on EIA's Web site at
ftp://ftp.eia.doe.gov/pub/oiaf/1605/cdrom/pdf/ggrpt/057300.pdf. Printed copies of the Executive Summary
of the report will be available in November from the U.S. Government Printing Office, 202/512-1800 or
through EIA's National Energy Information Center, 202/586-8800.

==================================
http://energy-tech.com/cgi-bin/news_search.cgi?a=1&type=newsnumber&search=n001259

Posted on Energy-Tech.com on: 2001/10/03

Contracts Awarded For Commercialization Of Mercury Detection And
Removal Technologies

The EPA recently awarded contracts to four small business companies for the final development and
initial commercialization of new environmental technologies for mercury removal and monitoring.

Mercury produced by combustion sources is a major concern to the country's air quality. The Small
Business Innovation Research (SBIR) program spawns commercial ventures that improve our
environment and quality of life, create jobs, increase productivity and economic growth, and improve
international competitiveness of the country's technology industry. For this reason, ADA Technologies
Inc. of Littleton, Colo., and Sorbent Technologies Inc. of Twinsburg, Ohio, are developing new sorbents to
remove mercury from coal-fired power plants. These new materials and processes have the capacity to
remove substantially more mercury than traditional activated carbon methods at a lower cost. Apogee
Scientific Inc. of Englewood, Colo., is developing an analyzer that will give real-time monitoring
information in flue gas from coal-fired boilers. A major advantage of this new system is that it will be able
to distinguish between different types of mercury, allowing utilities to make better decisions on control
options. Frontier Geosciences of Seattle, Wash., is developing a method to remove mercury and other
toxic metals from industrial waste water. Frontier Geosciences will be working with Unocal Thailand Ltd.
to ensure quick application of this technology to the field.

===================================
http://www.pirg.org/reports/enviro/lethal/

Premature mortality: The U.S. Environmental Protection Agency (EPA) estimates that
     "soot," or "fine particulate" air pollution causes more than 40,000 premature deaths each
     year. Older-coal-burning power plants are the largest source of sulfur dioxide (SO2), a
     primary component of soot.

Human developmental and neurological damage: Mercury pollution has contaminated the
     fish in thousands of U.S. lakes and streams. Today 40 states have issued warnings against
     consuming fish due to the risk of methylmercury exposure.(4) When ingested by pregnant or
     nursing women, methylmercury can cause neurological damage, including delayed
     development in the fetus and young children. Coal-burning power plants are the largest
     known domestic industrial source of mercury.

Ranking of the States
     For each of the four pollutants under consideration, the report ranks each state according to
     total tons emitted by in-state plants in 1999 (for SO2, NOx and CO2) and estimated
     emissions from 1998 for mercury.

     The top ten states for each pollutant are:
      SO2
                     NOx
                                   Mercury
                                                  CO2
      Ohio
                     Ohio
                                   Pennsylvania
                                                  Texas
      Pennsylvania
                     Texas
                                   Texas
                                                  Indiana
      Indiana
                     Indiana
                                   Ohio
                                                  Ohio
      Florida
                     Kentucky
                                   Illinois
                                                  Florida
      Illinois
                     West Virginia
                                   Alabama
                                                  Kentucky
      Texas
                     Florida
                                   Indiana
                                                  Pennsylvania
      West Virginia
                     Illinois
                                   West Virginia
                                                  West Virginia
      Kentucky
                     North Carolina
                                   Kentucky
                                                  Illinois
      Alabama
                     Pennsylvania
                                   North Carolina
                                                  Alabama
      Georgia
                     Missouri
                                   Michigan
                                                  Georgia
 
 

     The Dirty Dozen Holding Companies
     For each of the four pollutants under consideration, the report provides a list of "Dirty Dozen"
     companies, based on the amount of pollution emitted by plants owned by company in 1999
     (for SO2, NOx and CO2) and estimated emissions from 1998 for mercury.(6) For each
     pollutant, the Dirty Dozen companies are:

      SO2
                    NOx
                                 Mercury
                                                  CO2
      Southern Company
                    Southern Company
                                 Southern Company
                                                  Southern Company
      American Electric
      Power
                    Tennessee Valley
                    Authority
                                 American Electric
                                 Power
                                                  American Electric
                                                  Power
      Tennessee Valley
      Authority
      (TVA)
                    American Electric
                    Power
                                 GPU, Inc.
                                                  Tennessee Valley
                                                  Authority
      Cinergy Corp.
                    Allegheny Power
                    System
                                 Commonwealth Edison
                                                  Texas Utilities
      Allegheny Power
      System
                    Texas Utilities
                                 Tennessee Valley
                                 Authority
                                                  Allegheny Power
                                                  System
      GPU, Inc.
                    Cinergy Corp.
                                 Texas Utilities
                                                  Cinergy Corp.
      Texas Utilities
                    Dominion
                    Resources
                                 Allegheny Power
                                 System
                                                  Entergy
      Illinova Corp.
                    PacifiCorp
                                 Dominion Resources
                                                  PacifiCorp
      Dominion
      Resources
                    Entergy
                                 Cinergy Corp.
                                                  Central and
                                                  Southwest Corp.
      Carolina Power &
      Light
                    Duke Power
                                 Central and Southwest
                                 Corp.
                                                  Dominion
                                                  Resources
      Ohio Edison
      Company
                    Carolina Power &
                    Light
                                 Carolina Power & Light
                                                  GPU, Inc.
      Duke Power
      Company
                    Central and
                    Southwest Corp.
                                 PacifiCorp
                                                  Carolina Power &
                                                  Light
 
 

     Vulnerable Populations Living Near Dirty Power Plants
     In 1997, there were 236.8 million Americans living in counties that fell wholly or partly within
     a 50 mile radius of one of the 594 dirty power plants. The health impacts of smog and soot
     pollution fall disproportionately on certain vulnerable populations, including children whose
     lungs are still undergoing development, seniors, and those who suffer from respiratory
     illnesses Of the people living in counties falling wholly or partly within 50 miles of a dirty
     power plant, 56.3 million are children under 17 years of age, 27.9 million are seniors over 65
     years of age, 13.1 million are people who suffer from asthma, and 14.7 million are people who
     suffer from either chronic emphysema or chronic bronchitis.

==============================================
http://www.icci.org/news/gov2000.html

October 24, 2000
Contact: Nick Palazzolo
217-782-7355     217/524-5136      TTD: 800-526-0844
Brian Reardon, DCCA

Governor's Coal Conference Highlights Clean Coal Initiatives

SPRINGFIELD -- The 2000 Governor?s Illinois Coal Conference convened in Springfield today, with a focus on fostering the development and deployment of clean coal-burning
technologies.

"As a state we?ve made progress in promoting clean coal technologies," Governor George H. Ryan said. "However, more must be done to find new uses for Illinois coal in ways
that are better for the environment. And that?s why we?ve brought together not only the public and private sectors, but also producers, suppliers, transporters and consumers to
discuss the issues facing Illinois? coal industry.

Panel discussions at the conference will cover such topics as coal ash management, air quality goals, and changes in the markets for Illinois Basin coal. Speakers will include
General Richard Lawson, president of the National Mining Association, and Robert E. Murray, CEO of American Coal Sales Co.

Over the last 20 years, Illinois has achieved a 35 percent reduction of sulfur dioxide emissions as the use of clean coal technology has increased. During that time, the state has
deployed $108 million in Coal Bond Funds for new commercial technology that?s lead to cleaner power plants and other coal-burning facilities.

Since 1982, Illinois has invested an additional $50 million in basic and applied clean coal research, the largest coal research commitment of any state in the nation. The Illinois
Department of Commerce and Community Affairs? (DCCA) Coal Research and Development Programs sponsor and promote the advancement of technology with special emphasis
on the removal of sulfur and other pollutants emitted during the combustion of high-sulfur Illinois coal.

The program is administered by DCCA under the technical oversight of the Illinois Clean Coal Institute, located in Carterville, Illinois.

"This year, we are enhancing our commitment to clean coal technology and research by awarding $1.6 million in grants for 13 different projects," Ryan added.

"Under the leadership of Governor Ryan, scientists working on clean coal breakthroughs will have the resources to continue and commercialize significant projects to ensure that
Illinois Coal remains a viable part of the mix for generating power in the Midwest and the nation," said DCCA director Pam McDonough.

"We have seen some positive developments in recent weeks, and the purpose of this conference is to sustain the momentum we have," McDonough added. "This afternoon, a major
energy co-operative is announcing their participation in a project that the state committed $25 million to last year. It involves a low-emission boiler system demonstration project
in Elkhart that will involve an 80 mega watt power generation station."

In addition to the state?s commitment to coal bond funding and research, Commonwealth Edison has donated $25 million to the cause as a result of the sale of its fossil fuel
generating stations. Southern Illinois University has established a Clean Coal Review Board to oversee the development and implementation of projects funded from the grant.
Seven innovative clean-coal projects last week won financial backing totaling $9.25 million from the Clean Coal Review Board for high-tech improvements at mines and electric
utilities in central and southern Illinois.

"The projects' technologies and applications are quite diverse: from coal cleaning and gasification at the mine site to new coal combustion at commercial and utility settings," said
SIUC Interim Chancellor John S. Jackson. ?This diversity demonstrates the wide range of markets that will be open to Illinois coal as clean-coal technologies gain acceptance
across the country."

A thumbnail sketch of each funded project:

     Ashworth Combuster Demonstration, Lincoln, $1 million. This project will demonstrate a break-through, three-stage, pulverized coal combustion technology. Lime or
     limestone will be added with coal in the first stage to remove a high percentage of sulfur and ash before the fuel gas enters the boiler furnace.
     Arclar Central Preparation Plant and Coal Handling System, Equality, $2 million. Funds will be used to build a preparation plant that uses state-of-the-art washing
     technologies to clean coal before it is shipped to market.
     Close-Coupled Gasification Microgeneration Power Plants, Elkhart and Coulterville, $2 million. Funds will assist in the construction of two complete facilities that use fine
     coal waste during gasificiation to generate electricity at the mine sites. The goal is to use what would otherwise be a waste product to provide energy, lowering the mines'
     operating costs and making them more competitive.
     Prairie Energy Project, Elkhart, $2 million. The project will develop a slagging furnace with low nitrous oxide emissions while producing beneficial ash. The project aims to
     boost consumption of Illinois coal and demonstrate a clean-coal technology viable for larger electric utilities.
     Installation of Advanced Fine Coal Cleaning Equipment, Pattiki Mine's preparation plant in Carmi, $1 million. The goal is to replace an inefficient fine coal air separator with
     new, advanced fine coal processing equipment. The new system will reduce the coal's sulfur dioxide emissions while improving the plant's ability to recover the
     by-product.
     Demonstration of a Coal Industrial Park for Illinois Coal Industry Enhancement, Elkhart, $250,000. Sounthern Illinois University mining engineers will study the feasibility of
     a new total-concept mine facility that would encompass environmentally friendly coal extraction, cleaning, processing and power generation at a single location.
     Marion Circulating Fluidized Bed Boiler Repowering Project, near Marion, $1 million. This electric utility will install a clean, coal-fired fluidized bed combustion system
     large enough to replace three older, coal-fired power units.

================================

http://www.icci.org/00final/malhotra.htm

FINAL TECHNICAL REPORT

                                    November 1, 1999, through October 31, 2000
 
 

Project Title:  AGRO-FGD SCRUBBER SLUDGE WALLBOARD COMPOSITES

ICCI Project Number:         99-1/2.1C-2

Principal Investigator:           Vivak M. Malhotra, Southern Illinois University at Carbondale

Project Manager:                 Dr. Ronald H. Carty, ICCI

Introduction:  About 22 million tons of flue gas desulfurization (FGD) scrubber sludge are currently produced in the U.S. every year.  Most of it is disposed in
the landfills near power plants.  In Illinois, Indiana, and Western Kentucky 6 million tons of wet scrubber sludge are currently produced.  About 7,000 MW of
additional capacity is expected to be wet scrubbed in the near future in response to the Clean Air Act Amendments of 1990; and this will further increase the
amount of wet scrubber sludge produced annually.  Currently only about five percent (5%) of wet scrubber sludge is utilized nationally.  Most of the FGD
scrubber sludge, which had found some use in Portland cement or agriculture or plaster is sulfate-rich sludge.  The wallboard industry is reluctant to use FGD
by-product gypsum because of the impurities, both organic and inorganic, and variations in the product from batch to batch.  However, for sulfite-rich scrubber
sludge the utilization is much bleaker even though some use as structural fill and as aggregates has been proposed.  Therefore, there is a strong need to develop
additional utilization strategies for wet FGD scrubber sludge.

=========================================
http://www.commoncause.org/publications/hot/chart1.htm

January 1, 1989 through June 30, 1999
Total PAC And Soft Money Contributions From Members Of The Global Climate Coalition

                                               Total:  $ 63,470,718

==========================================
http://www.retailenergy.com/articles/riskmanagement.htm
 

RISK MANAGEMENT FOR MERCHANT
                           POWERPLANT FINANCING

                           by Roger D. Feldman
                           Partner, Bingham Dana LLP

                           (originally published in the Cogeneration and Competitive Power Journal. For subscription information, call
                           (770) 925-9388)

                           The use of risk management devices has been an increasing response to merchant power plant finance
                           uncertainties. The importance of credit enhancement as an element of successful merchant plant financing
                           clearly is an evolving matter which will be affected by the maturity of systems of regulation, and the reliability of
                           power marketing backstops for projects. The basic question is: can risk management be a satisfactory surrogate
                           in the financial markets for cash flow stress elements arising from those fundamental transactional elements
                           typically singled out by the rating agencies?

                           The types of risk management being undertaken today are not necessarily disclosed by the way in which energy
                           marketing affiliates have entered off-take arrangements with their special purpose project development
                           companies. It is to be anticipated that over time there will be greater analysis of the track records of individual
                           power marketing affiliates as risk managers, and, of counter party/credit enhancers as well who assume risk and
                           seek to hedge it.

                           Certainly the experiences of the summer of 1998, highlighting the uncertainties of the risk management markets,
                           will necessitate such analysis in individual deals, particularly to the extent that power export outside of the local
                           grid is an important part of the project?s power marketing strategy. Whether private sector Transcos will
                           exacerbate the pressure on power price volatility, in an effort to maximize profit, remains to be seen.

                           The rating agencies have, of course, already taken note that effective risk management techniques will
                           distinguish the emerging merchant power plant (?MPP?) industry from the old IPPs. Standard & Poors
                           emphasizes the value to proposed project financings of in-place power marketing services, including presence of
                           in-house risk management infrastructure and quality of plant information technology, and real time data
                           acquisition abilities to track price fluctuations and load flows in volatile markets.

                           Initial specific transaction design should build on these features by taking into account the need to preserve
                           flexibility in energy transaction options with respect to transportation, sales, transmission and mode of operation,
                           as well as form of credit support. However, while sales strategies based on specific market niches tied to hedging
                           may be feasible and attractive in certain instances, S&P notes: ?as in the case for most commodity markets,
                           identifying, developing and dwelling in that ephemeral position on the kinked portion of the demand curve may
                           prove to be forever elusive.?

                           Strategies to alleviate excessive trading market risk include the fashioning of quasi-merchant plants around
                           strong industrial off takers; to establish them as split offs from utility plants selling back to utilities; to preserve
                           them as continued providers under preexisting power sales arrangements with the utility which previously
                           directed their sales or to structure other partial, long-term off-take arrangements.

                           There are limits to what risk management can achieve on individual projects. The transition of the use of risk
                           management for individual projects into a broadening of merchant plant capital markets is provided by credit
                           enhancement.

                           Increasingly larger integrated capital pools for risk assumption are seeking ways not merely to provide a credit
                           grade up tick, but to assume those specifically identified risks necessary to achieve project financeability (and
                           themselves, thereafter, backfill behind those risks through a mixture of commodity-type trading, risk spreading
                           through reinsurance, and development of appropriately priced financial products). Credit enhancers are reaching
                           into the marketplace as teammates, but perhaps ultimately as the displacers, of traditional investment banking
                           structuring activities.

                           PORTFOLIO FINANCE

                           At this intersection between fuel convergence energy projects and credit enhancement, is where the future
                           prospects for merchant plants as the building blocks of large enterprises which possibly may be corporate
                           financed. Power revenues as a type of cash flow, with which risk management markets have gotten statistically
                           comfortable as to their aggregate forward price curve profile, may be credit enhanceable to a level where
                           merchant plant securitization as well as corporate finance is possible. It becomes, of course, easier the greater
                           the diversity of project portfolio.

                           This perception of the future role of merchant plant development multiple facilities, simultaneously developed in a
                           single region like New England, could take hold in other U.S. settings, where combinations of merchant plants and
                           acquired assets are effectively creating new supply utilities to interface with the newly emergent transmission
                           utilities.

                           Certainly the vision of many transactions being fleet-financed or jointly portfolio-financed-with or without credit
                           enhancement-is the one many bankers assume will evolve into the reality of the future for merchant plants.
                           Current merchant structures are perceived as simply a product of where expertise resides right now in terms of
                           transactional capability. Domestically, it is seen as a transition stopgap while different regulatory requirements,
                           auction processes and stranded cost recovery are sorted out. Historically, project-financed projects generally
                           have been dismissed as not being subjectable to portfolio treatment like mortgages, because of their absence of
                           homogeneity, particularly where multiple sponsors, multiple power off-takers and multiple credits have been
                           involved. [The law of numbers invoked for dispersion of portfolio risk in effect has been deemed trumped by the
                           application of Murphy?s Law to each project or capital markets risks.]

                           Recently, efforts to develop a collateralized loan obligation (?CLO?) structure for merchant power plant finance
                           has received increasing attention, as one offering risk diversification for investors and greater liquidity for lenders.
                           Of course, the quality of given debt issues, rather than generic assumptions about loan portfolio performance,
                           must be in control.

                           A portfolio of properly credit enhanced merchant plants, or a single credit enhanced portfolio, may be the
                           foundation for portfolio-based issuance of securities.

                           Particularly is this true in the domestic merchant plant arena, where as we have seen, there is an emerging group
                           of transactions where the structural issues key to financing are coming into clear focus, and specific risk
                           management techniques being used to offset them in the trenches of the Northeast, and in the less settled portions
                           of the rest of the U.S. In this context, contingent equity commitment can be substituted for contributed capital.

                           The effective expansion and addition of the risk management and credit enhancement pieces to transaction and
                           capital structuring innovations is what will put merchant plant development over the top on a national basis. That
                           is why the New England trenches experience is such a useful platform for what we will be doing nationwide.
 
 

                           ABOUT THE AUTHOR

                                                        Roger D. Feldman

                           A 30-year veteran of utility and IPP finance in which he has participated in the closing of over $10 billion in
                           transactions, he is currently a NECA board member and chair of the DC Bar International Investment and
                           Finance Committee. He has chaired the American Bar Association?s Energy Finance Committee and is a board
                           member of The Journal of Project Finance, The Cogeneration and Power Marketing Letter, Cogeneration and
                           Competitive Power Journal, and the Construction Business Review.

                           Mr. Feldman is a graduate of Brown University, Yale Law School and Harvard Business School, and served as a
                           deputy administrator tothe Federal Energy Administration.

                           Bingham Dana LLP, Suite 400, 1200 19th St. NW, Washington, DC20036-2400 (202)778-6150, fax 6155.

==============================
http://www.fe.doe.gov/events/testimony/01_gee_happrops.html

                         Statement of Robert W. Gee
                      Assistant Secretary for Fossil Energy
                         U.S. Department of Energy
                                 to the
                  Subcommittee on Interior and Related Agencies
                         Committee on Appropriations
                        U.S. House of Representatives
                              March 14, 2000
...
The Clean Coal Technology Demonstration Program

A significant portion of the FY 2001 Fossil Energy budget request is offset by funding proposed for deferral or
rescission from the Clean Coal Technology Program. The budget proposes that $221.0 million be deferred
until FY 2001 and that an additional $105.0 million be rescinded.

We are proposing a deferral because some of the last projects in this program have been -- or are being --
restructured, and schedules have been delayed. The proposed rescission reflects savings from the
restructuring of a Clean Coal Technology project that originally had been proposed by a subsidiary of the
Duke Energy Corp. On November 15, 1999, Energy Secretary Richardson approved the use of $78 million in
Clean Coal Technology funding as the federal share of the $432 million Kentucky Pioneer Energy Project
planned for Clark County, Kentucky, by Global Energy Inc. This represented a $105 million cost savings
compared to the projected government cost of the Duke Energy project which had encountered siting
difficulties in southern Illinois.

===========================
http://www.hecweb.org/ccw/FINALCC1.htm

REVIEW OF THE GLOBAL ADVERSE ENVIRONMENTAL IMPACTS TO GROUND WATER AND
                    AQUATIC ECOSYSTEMS FROM COAL COMBUSTION WASTES
By

                               Donald S. Cherry, Ph.D.1, Rebecca J. Currie, Ph.D.2 and
                                           David J. Soucek, M.S.3
                                   Professor of Zoology/Aquatic Ecotoxicology,1
                                        Research Associate of Zoology,2
                                      and Research Assistant of Zoology3

                                            Biology Department
                                              Virginia Tech
                                       Blacksburg, Virginia 24061-0406

                                              Prepared for:
                              Hoosier Environmental Council and Citizens Coal Council
                                         Indianapolis, Indiana 46202

                                              March 28, 2000

EXECUTIVE SUMMARY

The United States Environmental Protection Agency (US EPA) is completing a determination under the federal Resources Conservation and Recovery Act
(RCRA) in April, 2000 that will decide if federal safeguards should be required for the disposal of waste generated from the combustion of fossil fuels. Most of
the wastes covered by this determination are coal combustion wastes (CCW) generated at power plants. A draft determination completed by EPA in April,
1999, asserted that a paucity of information exists which demonstrates dangers posed by CCW or ecological damages resulting from disposal of this waste.
Given ample data demonstrating ground water contamination around monitored CCW disposal sites, citizens are concerned that the final determination by US
EPA will allow substantial damages to occur to the environment and eventually human health as a result of lax safeguards on the disposal of CCW.

The authors of this report were asked by the Hoosier Environmental Council and Citizens Coal Council to conduct an assessment of the toxicity posed by
contamination from CCW and review studies of resulting ecological damages that may have been overlooked in the draft determination. It is our hope that this
review will provide a public record of problems caused by the lax disposal of CCW.
 

         1. We evaluated the level of toxicity exhibited by contamination at 32 CCW disposal sites and the ecological impacts from studies of
         CCW contamination on 11 fresh water aquatic communities, two salt water aquatic communities and other coastal environments.
         These sites were spread throughout America, and one additional site was in India.

The contamination in downgradient wells at coal combustion waste landfills and retention ponds as well as discharges into nearby surface waters were
evaluated. The disposal sites were located in Wisconsin, Illinois, New York, Massachusetts, Arizona, Alabama, North Dakota, and Indiana. In addition, reviews
of studies of ecological impacts at disposal sites included Belews Lake in North Carolina, the Savannah River Project (SRP) in South Carolina, the Glen Lyn
and Clinch River Plants in Virginia, the Columbus Electric Generating Station in Wisconsin, Consumer's Power J. R. Whiting Power Plant in Michigan, Northern
Indiana Public Service Company's Bailly Generating Station in Indiana, Tennessee Valley Authority's Bull Run Steam Plant and the U.S. Department of
Energy's Chestnut Ridge Y-12 Plant at Oak Ridge in Tennessee, 13 reservoirs in east Texas, River Yamuna in India, and marine environments in Sequin Bay,
Washington, Delaware's Atlantic Coast, the Netherlands' Atlantic Coast, the Gulf Coast of Mississippi, and others.
 

         2. The levels of contamination evaluated at disposal sites were extremely high.

Pollutants were found in ground water downgradient from disposal sites at grossly high concentrations relative to other contaminated environments. Sulfate
levels of 62,000 mg/L exceeded the Maximum Contaminant Levels (MCL) established by the US EPA by more than 120 times in North Dakota and Indiana.
Boron at an Illinois site surpassed the US EPA 10-day health advisory for children by nearly 350 times. Iron concentrations surpassed the MCL by 3,090 times
at a Tennesee site, 1,300 times at a North Dakota site, and 460 times in two Wisconsin sites.

Toxic trace metal concentrations in ground water and settling pond effluent at ash disposal sites were an astonishing problem at a number of sites. For example,
aluminum concentrations of 600,000 m g/L in sluice water at the Oak Ridge site in Tennessee were 6,896 times above the chronic WQC limit of 87 m g/L that
protects aquatic life. Aluminum exceeded this limit by 700 times in downgradient ground water at two sites in New York and Alabama. Arsenic, a dangerous
contaminant for human consumption, surpassed the US EPA MCL by 10 to 16 times in two Wisconsin disposal sites and 122 times in sluice water at the Oak
Ridge site. Concentrations of cadmium, one of the most toxic trace metals to aquatic life, reached 800 m g/L, 727 times beyond the chronic WQC of 1.1 m g/L in
the Bailly Power Plant's settling pond which drains into the Indiana Dunes National Lakeshore. Cadmium concentrations reached 1,226 m g/L in downgradient
ground water at a fly ash landfill site in Wisconsin, surpassing the chronic WQC by 1,114 times and the acute WQC by 314 times. Concentrations of zinc,
another trace metal highly toxic to aquatic life, reached 51,850 m g/L at this Wisconsin site surpassing the chronic WQC by 1,103 times and the acute WQC by
162 times.
 

         3. The toxicity from this contamination is extremely acute.

The toxic ramifications of heavy metal contamination from CCW are immense. The elemental concentrations of cadmium, zinc, iron and aluminum in
downgradient wells and settling pond effluent at disposal sites are up to three orders of magnitude higher than levels defined as acutely toxic in short-term
laboratory tests. For example, dissolved cadmium at 1,226 m g/L in disposal site water is sixty times more concentrated than its 48 hr LC50 value of 20 m g/L,
i.e. the lethal concentration that kills 50 percent of test organisms in 48 hrs. Extreme concentrations of zinc up to 51,850 m g/L are 741 times more toxic in water
at these disposal sites than the 48 hr LC50 values for test organisms in the laboratory. Concentrations of iron in water at these disposal sites exceed 48 hr LC50
values by 122 to 340 times. Aluminum concentrations of up to 66,000 m g/L in ground water at landfill sites exceed this laboratory acute toxicity value by 23
times, and concentrations of 600,000 m g/L of aluminum in sluice water exceed the value by 208 times. These concentrations will shock and immobilize US
EPA bioassay test organisms almost instantaneously, causing death several minutes or less thereafter.
 

         4. CCW is toxic because of the enrichment of trace metals on fly ash particles caught by electrostatic precipitators at power plants
         and the concentration of other pollutants in ash and sludge by air pollution control measures such as scrubbing.

The toxicity of fly ash occurs when ash particles become enriched with trace elements while collected in electrostatic precipitators of power plants. Trace
elements and other pollutants from the combustion of coal in the furnaces cool and condense upon the ash particle surfaces. Iron and trace metals such as
aluminum, cadmium, zinc, and selenium can regularly leach or dissolve from ash particle coatings into ground water at such high levels that their measurement
will exceed human health and aquatic life criteria by two to three orders of magnitude.

The addition of flue gas desulfurization programs at coal-fired power plants that capture much greater amounts of sulfur compounds and other air pollutants are
generating a newer form of CCW, often called scrubber sludge. Extremely high levels of sulfates, chlorides, sodium, total dissolved solids and pH are being
measured in ground water downgradient from scrubber sludge landfills.
 
 
 

         5. There are documented substantive damages from exposure to pollutants in acutely toxic levels at CCW disposal sites where
         ecological impacts have been studied.

The toxic impacts of CCW contamination have been well documented in studies of at least ten aquatic ecosystems receiving effluents and/or ground water
infiltration from CCW disposal sites. They were reported by this review's primary researcher (D. S. Cherry) at the Savannah River Project (SRP) in South
Carolina from 1973-1984. The impacts were acutely toxic upon biota in the aquatic receiving system and several years were required for any degree of
recovery.

While these original SRP studies were claimed to be an anomaly by the power industry, this review demonstrates that the SRP is not the only site where
excessive concentrations of trace elements and other pollutants from CCW as well as impacts from those pollutants have been documented. The elemental
concentrations from fly ash into McCoy Branch, Tennessee, were higher than those measured at the SRP site, and they caused an abnormally high percentage
of fish deformities in body structure and fin deterioration. In addition to these two sites, this review documents damages at other CCW disposal sites in
Tennessee, Virginia, North Carolina, Wisconsin, Michigan and Texas as well as in India and the marine environment.
 

         6. Substantive toxic impacts have occurred from much lower levels of contamination at CCW disposal sites.

Newer toxic effects reported in the past five years at the SRP by other researchers reveal insidious, chronic toxicity impacts from CCW upon aquatic life.
These include body malformations and metabolic, hormonal, and behavioral disorders that are adversely affecting the remaining hardier organisms from that
receiving system.

Selenium, a common yet alarming element associated with CCW contamination, has become known as the silent killer of trace elements to aquatic life over the
past 1.5 decades because of its ability to be concentrated up the food chain from water and sediment, to algae, insects and other similar forms, to fish. Selenium
levels have exceeded the US EPA chronic WQC level of 5 m g/L by up to 200 times in downgradient ground water at CCW disposal sites in Wisconsin, Illinois
and North Dakota.

In two east Texas reservoirs, Martin Lake and Welsh Reservoir, high selenium concentrations (2,200 to 2,700 m g/L) from fly ash settling pond discharges
owned by Texas Utilities Generating Co., caused massive fish mortalities in 1978-1979. Selenium body burdens from bioaccumulation in fish ranged from 2,000
to 9,100 ppb causing deterioration of fish blood chemistry, kidney ultrastructure and gill tissue. Several years after the discharge commenced, the fish
community structure in these reservoirs remained severely altered between the balance of plankton feeding versus predator fish, as reproductive impairment
continued. Substantial bioaccumulation of arsenic, chromium and mercury also was evident in fish found in these reservoirs. As a result, the Texas Parks and
Wildlife Department initiated a long term, trace metal monitoring program in 13 reservoirs to evaluate the impact of contamination by CCW produced from
lignite coal.

A current concern, however, is that the chronic WQC of 5 m g/L is not low enough to prevent bioaccumulation of selenium in the food chain. In 1974, Duke
Power Company began discharging fly ash into Belews Lake, North Carolina. Four years of study documented that resulting concentrations of 10 m g/L of
selenium in the water eliminated 16 of the 20 fish species found in this reservoir and rendered two of the remaining species sterile (Cumbie and Van Horne
1978; Lemly 1985). Selenium concentrations had bioacumulated by 3,975 times in the tissues of largemouth bass from the levels of selenium in the water and
tissues of prey consumed by this species. Subsequent research has concluded that waterborne selenium concentrations of 2 m g/L are hazardous to the
long-term survival of fish due to the affinity of selenium to bioaccumulate in reservoir systems (Lemly 1992).
 

         7. Arguments that high pollution levels from CCW will be attenuated by the environment before damage occurs are not borne out
         by research or monitoring. The authors of this review believe that the scope of adverse environmental impacts from CCW disposal
         practices is under-acknowledged due to an absence of monitoring measures at many disposal sites.

Certain groups are assuming without substantiation that elevated concentrations of trace elements and other pollutants from CCW will be attenuated and/or
diluted to safe levels before damage to water supplies can occur. This position ignores the fact that pollutant concentrations have risen to two to three orders of
magnitude above safe limits to protect aquatic life (US EPA WQC) in waters exiting these sites. These excessive concentrations cannot be diluted or
attenuated without polluting a ground water resource that 117-132 million people use for daily consumption. Many of these people are likely drawing ground
water from private wells near CCW disposal sites for daily consumption that is untreated and not being monitored. Even if attenuation does eventually occur,
the site studies reviewed in this report indicate that when trace metals such as selenium dissolve into surface water from CCW, damages from bioaccumulation
in living organisms occurs at minute concentrations, i.e., less than 10 m g/L in the water.

Furthermore there are many CCW disposal sites, particularly, ash ponds and lagoons at power plants, where impacts are not being examined due to the lack of
any ground or surface water monitoring programs. Even where monitoring is occuring, the number of monitoring points is often insufficient and many toxic
constituents in CCW, such as trace metals like molybdenum, strontium and thallium, various radionuclides and organic compounds are not being monitored. For
these reasons, the authors of this review believe that the scope and severity of impacts from the contamination of ground waters and aquatic ecosystems by
CCW is seriously under-acknowledged.

There are a number of ecological impact studies that should have been conducted longer in this country relative to the 12-year effort at SRP, but were not. Still,
four studies substantively document acute and chronic toxic impacts from exposure of organisms to CCW effluents and infiltration in South Carolina, North
Carolina, Tennessee and Texas. Sites where several years of research have been conducted in the mid-1970-1980's and the recent studies from 1995 to the
present at SRP have established a very important data base of toxicity from CCW that is shedding new light on the immense impact that CCW disposal is
having upon life in aquatic receiving systems.

Unfortunately most of the other field-oriented ecological studies were funded for short periods and terminated for reasons unknown. Furthermore, the
long-term impact of contamination from CCW upon human health is unknown. Until more adequate monitoring programs exist and more effort is made to look
for and study impacts, assertions of attenuation of harmful impacts from CCW disposal appear to be nothing more than an obfuscation of responsibility by those
seeking lax disposal requirements for this waste.

The US EPA's determination governing wastes from the combustion of fossil fuels needs to address the severity of the multi-directional threats that surface
waters and ground waters contaminated by CCW pose to human health, cropland irrigation, and aquatic communities in adjacent streams and other receiving
systems.
========================
 
 
 

  Clean Energy Integrated Gasification Combined Cycle Project

      Description:

      The proposed action is DOE participation, through financial assistance, in a
      cooperative agreement under the Clean Coal Technology demonstration program for
      design, construction, and operation of a demonstration plant that integrates the
      gasification of coal with an air separation unit, a combustion turbine, a heat
      recovery steam generator with existing steam turbines, and certain existing
      facilities at the Grand Tower Power Station near Carbondale, Illinois; this Station is
      owned by the Central Illinois Public Service Company (CIPS). The current nominal
      200 megawatt Station will be repowered to 477 MW of electricity. Clean Energy
      Partners, an industrial alliance between Duke Energy and Ameren Holding
      Company - a parent of CIPS - will construct, own, and operate the repowered
      Station as a merchant plant using local high sulfur coal from the Southern Illinois
      Basin.

      NEPA Schedule:

       Determination:
       Notification:
       Internal Scoping:
       Notice of Intent:
       Public Scoping:
       Preliminary Draft EIS:
       Draft EIS
       Public Distribution:
       Public Hearing:
       Preliminary Final EIS:
       Final EIS
       Draft Record of Decision:
       Approved Record of Decision:
                                        February 1999
                                        February 1999
                                        March 1999
                                        May 1999
                                        July 1999
                                        January 2000
                                        March 2000
                                        March 2000
                                        April 2000
                                        June 2000
                                        July 2000
                                        July 2000
                                        September 2000
       Estimated Cost:
                                        $ 400,000

=====================
AMEREN Contact person
Illinois
                                                     Leigh Morris
                                                     217.535.5228
========================
http://www.netl.doe.gov/coalpower/gasification/25_clean.htm
 

Clean Coal Technology
 Program
 Kentucky Pioneer Energy IGCC
 Demonstration Project

                                                  Back to Projects
         LOCATION

      Trapp, Clark County, KY
 (East Kentucky Power Cooperative's Smith
            Site)
 PROJECT OBJECTIVE
 To demonstrate and assess the reliability, availability, and maintainability of a utility-scale IGCC
 system using high-sulfur bituminous coal and municipal solid waste blend in an oxygen-blown,
 fixed-bed, slagging gasifier and the operability of a molten carbonate fuel cell fueled by coal gas.

 TECHNOLOGY/PROJECT DESCRIPTION
 The BG/L gasifier is supplied with steam, oxygen, limestone flux, and a coal and municipal waste
 blend. During gasification, the oxygen and steam react with the coal and muncipal waste blend and
 limestone flux to produce a raw coal-derived fuel gas rich in hydrogen and carbon monoxide. Raw
 fuel gas exiting the gasifier is washed and cooled. Hydrogen sulfide and other sulfur compounds
 are removed. Elemental sulfur is reclaimed and disposed of as a by-product. Tars, oils, and dust
 are recycled to the gasifier. The resulting clean, medium-Btu fuel gas fires the gas turbine. A
 small portion of the clean fuel gas is used for the molten carbonate fuel cell (MCFC). The MCFC
 is composed of a molten carbonate electrolyte sandwiched between porous anode and cathode
 plates. Fuel (desulfurized, heated medium-Btu fuel gas) and steam are fed continuously into the
 anode; CO2-enriched air are fed directly into the cathode. Chemical reactions produce direct
 electric current, which is converted to alternating current in an inverter.
 
 

 PROJECT STATUS/ACCOMPLISHMENTS
 On May 8, 1998, the DOE conditionally approved Ameren Services Company (merger of Union
 Electric Co. and Central Illinois Public Service Co.) as an equity partner and host site provider
 subject to completing specific business and teaming milestones. The new project site to be
 provided by Ameren was at their Venice Station Plant in Venice, Illinois, or near East St. Louis,
 Illinois. On April 30, 1999, Ameren Services Company withdrew from the project for economic and
 business reasons.

 In November 1999, Kentucky Pioneer Energy (KPE), LLC, a wholly owned subsidiary of Global
 Energy USA, officially became the Participant for the project.  A new host site at East Kentucky
 Power Cooperative's Smith site in Clark County, Kentucky was established.  With the
 establishment of the new site the permitting and NEPA process began.  The EIV was submitted in
 March 2000, and the public hearing was conducted in May 2000.  The draft EIS is scheduled to be
 issued in July 2001 with the Record of Decision being finalized in November 2001.  On 24  May
 2001, FERC confirmed KPE as an exempt Wholesale Generator and on 7 June 2001, the Kentucky
 Division of Air Quality issued the Air Quality Permit.  Also, the Kentucky Public Service
 commission issued a Declaratory Order of Non- Jurisdiction during this time.  Sources of the
 Municipal Solid Waste (MSW) have been identified and preliminary agreements have been
 reached to supply MSW.  Preliminary engineering to better finalize the cost has been completed.
 Closure on financing the project will occur upon completion of the NEPA process.  Final design
 and construction should begin early 2002.

 Commercial Applications
 The IGCC system being demonstrated in this project is suitable for both repowering applications
 and new power plants. The technology is expected to be adaptable to a wide variety of potential
 market applications because of several factors. First, the BGL gasification technology has
 successfully used a wide variety of U.S. coals. Also, the highly modular approach to system
 design makes the BGL-based IGCC and molten carbonate fuel cell competitive in a wide range of
 plant sizes. In addition, the high efficiency and excellent environmental performance of the system
 are competitive with or superior to other fossil-fuel-fired power generation technologies.

 The heat rate of the IGCC demonstration facility is projected to be 8,560 Btu/kWh (40%
 efficiency) and the commercial embodiment of the system has a projected heat rate of 8,035
 Btu/kWh (42.5% efficiency). The commercial version of the molten carbonate fuel cell fueled by a
 BGL gasifier is anticipated to have a heat rate of 7,379 Btu/kWh (46.2% efficiency). These
 efficiencies represent greater than 20% reduction in emissions of CO2 when compared to a
 conventional pulverized coal plant equipped with a scrubber. SO2 emissions from the IGCC
 system are expected to be less than 0.1 lb/106 Btu (99% reduction), and NOx emissions less than
 0.15 lb/106 Btu (90% reduction).

 Also, the slagging characteristic of the gasifier produces a nonleaching, glass-like slag that can
 be marketed as a usable byproduct.

 Contacts
 H.H. Graves, President
 Kentucky Pioneer Energy, LLC
 312 Walnut Street, Suite 2000
 Cincinnati, OH 45202
 (513) 621-0077
 (513) 621-5947 (fax)
 hhgraves@globalenergyinc.com
 

 Return to top of page
                                           Last Update: 10/17/01

[../../footer.html]
===========================
http://www.planetark.org/dailynewsstory.cfm?newsid=2668&newsdate=29-Jul-1999

Environmentally sound utilities seen
              bringing greater returns

                        Mail this story to a friend | Printer friendly version
              USA: July 29, 1999

              NEW YORK - Returns on investments in U.S. electric utilities
              judged environmentally efficient have outperformed those
              determined to be less environmentally friendly, a study by New
              York-based investment advisory firm Innovest Strategic Value
              Advisors shows.

              A copy of the soon-to-be released report was obtained by Reuters.

              "Companies receiving above average EcoValue 21 ratings
              outperformed companies with below average ratings by
              approximately six percent over the past year," Innovest's report
              says.

              Pacific Gas & Electric and Niagara Mohawk Power received the
              highest ratings for U.S. utilities, indicating the greatest managerial
              capacity to convert good environmental performance into
              shareholder value, the study said.

              Pacific Gas's mix of fuels includes geo-thermal, hydroelectric
              energy and some natural gas as well as dirtier burning coal, while
              Niagara Mohawk uses no coal at all.

              The companies that Innovest ranked lowest were FirstEnergy and
              Ameren , both of which burn mostly coal. FirstEnergy was worst in
              its class in terms of environmental risk management, while Ameren
              was worst in toxic emissions.

              Innovest calculates its EcoValue 21 market after determining a
              series of indicators that reflect a company's historical
              environmental risk factor, the company's capacity to minimise
              environmental damage and the potential profit from its management
              of environmental issues.

              "The correlation exists largely because eco-efficiency is an
              excellent proxy for management quality, which is the primary
              determinate of stock price performance," the report said.
===============================
 

rchive-Name: gov/us/fed/nara/fed-register/2000/apr/14/65FR20142
Posting-number: Volume 65, Issue 73, Page 20142

[Federal Register: April 14, 2000 (Volume 65, Number 73)]
[Notices]
[Page 20142-20145]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr14ap00-58]

=======================================================================

http://groups.google.com/groups?q=clean+coal+trapp&hl=en&rnum=1&selm=65FR20142%40us.govnews.org
 
 

-----------------------------------------------------------------------

DEPARTMENT OF ENERGY
 

Notice of Intent To Prepare an Environmental Impact Statement for
the Kentucky Pioneer Integrated Gasification Combined Cycle
Demonstration Project, Trapp, KY and Notice of Floodplain Involvement

AGENCY: U.S. Department of Energy.

ACTION: Notice of Intent to prepare an Environmental Impact Statement
and Notice of Floodplain Involvement.

-----------------------------------------------------------------------

SUMMARY: The U.S. Department of Energy (DOE) announces its intent to
prepare an Environmental Impact Statement (EIS) pursuant to the
National Environmental Policy Act (NEPA), the Council on Environmental
Quality (CEQ) NEPA regulations (40 CFR parts 1500-1508), and the DOE
NEPA regulations (10 CFR part 1021), to assess the potential
environmental and human health impacts of a proposed project to design,
construct, and operate a demonstration electric-power generating plant
in Trapp, Clark County, Kentucky. The proposed Integrated Gasification
Combined Cycle (IGCC) project, selected under the Clean Coal Technology
Program, would be the first commercial-scale demonstration of the fixed
bed British Gas Lurgi (BGL) gasification process in the United States.
The proposed project would also demonstrate a high-temperature molten
carbonate fuel cell and would involve the construction and operation of
a nominal 400 MWe (megawatt-electric) IGCC power station. Feed to the
BGL gasifiers would be solid fuel briquettes. The EIS will help DOE
decide whether to provide 18 percent (approximately $78M) of the
funding for the currently estimated $432 M proposed project.
    The purpose of this Notice of Intent is to inform the public about
the proposed action; announce the plans for a public scoping meeting;
invite public participation in (and explain) the EIS scoping process;
and solicit public comments for consideration in establishing the
proposed scope and content of the EIS. The EIS will evaluate the
proposed project and reasonable alternatives. Because the proposed
project may affect floodplains, the EIS will include a floodplain
assessment and a statement of findings in accordance with DOE
regulations for compliance with floodplain environmental review
requirements (10 CFR part 1022).

DATES: To ensure that all of the issues related to this proposal are
addressed, DOE invites comments on the proposed scope and content of
the EIS from all interested parties. Comments must be received by May
31, 2000, to ensure consideration. Later comments will be considered to
the extent practicable. In addition to receiving comments in writing
and by telephone, DOE will conduct a public scoping meeting in which
agencies, organizations, and the general public are invited to present
oral comments or suggestions with regard to the range of actions,
alternatives, and impacts to be considered in the EIS. The scoping
meeting will be held at Trapp Elementary School, Trapp, Kentucky on May
4, 2000, beginning at 7:00 p.m. (See Public Scoping Process). The
public is invited to an informal session at this location beginning at
4:00 p.m. to learn more about the proposed action. Displays and other
forms of information about the proposed agency action and location will
be available, and DOE personnel will be present to answer questions.

ADDRESSES: Written comments on the proposed EIS scope and requests to
participate in the public scoping meeting should be addressed to: Mr.
Roy Spears, NEPA Document Manager for the Kentucky Pioneer IGCC
Demonstration Project, National Energy Technology Laboratory, U.S.
Department of Energy, 3610 Collins Ferry Road, Morgantown, WV 26507-
0880. People who would like to otherwise participate in the public
scoping process should contact Mr. Spears directly at: telephone 304-
285-5460; toll free telephone 1-800-432-8330 (extension 5460); fax 304-
285-4403; or e-mail rspears@netl.doe.gov.

FOR FURTHER INFORMATION CONTACT: To obtain additional information about
this project or to receive a copy of the draft EIS for review when it
is issued, contact Mr. Roy Spears at the address provided above. For
general information on the DOE NEPA process, please contact Ms. Carol
M. Borgstrom, Director, Office of NEPA Policy and Assistance (EH-42),
U.S. Department of Energy, 1000 Independence Avenue, SW, Washington, DC
20585-0119; telephone 202-586-4600 or leave a message at 1-800-472-
2756.

SUPPLEMENTARY INFORMATION:

[[Page 20143]]

Background and Need for Agency Action

    Under Public Law 102-154, the U.S. Congress provided authorization
and funds to DOE for conducting cost-shared Clean Coal Technology
Program projects for the design, construction, and operation of
facilities that significantly advance the efficiency and environmental
performance of coal-using technologies and are applicable to either new
or existing facilities. The purpose of this proposed agency action,
which is known as the Kentucky Pioneer IGCC Demonstration Project, is
to establish the commercial viability of the fixed bed BGL gasification
process in the United States and the operation of a high temperature
molten carbonate fuel cell using coal derived gas. The IGCC plants have
long been recognized as being environmentally superior to conventional
coal-fired power plants while operating at significantly higher
efficiencies. The proposed project would demonstrate the improved
economic viability and process flexibility of the BGL technology and
promote fuel cells as a viable commercial source of electricity. A
slipstream of syngas would be routed to a fuel cell to produce
additional electricity in this demonstration project.
    Since the early 1970s, DOE and its predecessor agencies have
pursued research and development programs that include long-term, high-
risk activities that support the development of innovative concepts for
a wide variety of coal technologies through the proof-of-concept stage.
However, the availability of a technology at the proof-of-concept stage
is not sufficient to ensure its continued development and subsequent
commercialization. Before any technology can be considered seriously
for commercialization, it must be demonstrated. The financial risk
associated with technology demonstration is, in general, too high for
the private sector to assume in the absence of strong incentives. The
Clean Coal Technology Program is a congressionally authorized program
designed to accelerate the development of innovative technologies to
meet the Nation's near-term energy and environmental goals; to reduce
technological risk to the business community to an acceptable level;
and to provide private sector incentives required for continued
activity in innovative research and development directed at providing
solutions to long-range energy supply problems.

Proposed Action

    The proposed action is for DOE to provide, through a cooperative
agreement with Kentucky Pioneer Energy, L.L.C., financial assistance
for the design, construction, and operation of the proposed project.
The Kentucky Pioneer IGCC Demonstration Project would be designed for
at least 20 years of commercial operation, beginning with a 2-year
Clean Coal Technology demonstration, and would cost a total of
approximately $432 M; DOE's share would be approximately $78 M (18%).
    The proposed project includes the design, construction, and
operation of a new 400 MWe IGCC power plant in rural Clark County,
Kentucky. Kentucky Pioneer Energy, L.L.C. would use licensed
gasification technology to fuel an electric generating facility. The
facility would demonstrate the three following innovative technologies:
(1) Gasification of fuel briquettes; (2) use of the syngas product as a
clean fuel in combined cycle turbine generator sets; and (3) operation
of a high temperature molten carbonate fuel cell on coal derived
syngas. This project would be the first commercial scale application of
the BGL gasification technology in the United States. This would also
be the first commercial scale demonstration of a molten carbonate fuel
cell operating on coal derived gas. Construction of the proposed plant
would be expected to require approximately 30 months.
    The project consists of the following components: Briquettes and
raw material transportation, receipt, and storage; sulfur removal and
recovery; a gasification plant; a combined cycle power unit; and a fuel
cell. The IGCC facility would provide needed power capacity to the
central and eastern Kentucky areas.
    To supply the proposed plant and other potential customers with
fuel briquettes, the parent company of the applicant, Global Energy,
Inc., would construct a production facility at an off-site location.
The briquettes would be made from high-sulfur coal (at least 50%) and
refuse (municipal solid waste). The location of the briquette
manufacturing facility remains to be determined. However, sources of
low-cost high-sulfur coal, refuse availability and supporting
infrastructure would be considered by Global in siting the facility.
The EIS will consider potential environmental impacts from operation of
a briquette facility.
    The IGCC technology that Kentucky Pioneer Energy, L.L.C. would be
demonstrating consists of the following four steps: (1) Generation of
syngas by reacting fuel briquettes with steam and oxygen, creating a
high-temperature, chemically reducing atmosphere; (2) removal of
contaminants, including particulates and sulfur; (3) combustion of
clean syngas in a turbine generator to produce electricity; and (4)
recovery of residual heat in the hot exhaust gas from the gas turbine
in a heat recovery steam generator and use of the steam to produce
additional electricity in a steam turbine generator.
    The proposed project site comprises approximately 300 acres located
within a 3,120-acre tract, owned by East Kentucky Power Cooperative
(EKPC) in Clark County, Kentucky. The tract is 34 kilometers (21 miles)
southeast of the city of Lexington. The site can be reached by State
Highway 89 and accessed through a gated perimeter fence and access
road.
    The 300-acre proposed project site was previously disturbed by
preliminary construction activities when EKPC began construction of its
first-phase power station in the mid-1980s. That project was canceled
in the early 1990s when decreased demand for electric power made the
project uneconomical. EKPC completed preliminary grading, primary
foundations, fire protection piping and rail spur access infrastructure
installation before the project was cancelled.
    The Kentucky Pioneer IGCC Demonstration Project would be designed
to minimize expected or potential adverse impacts to the environment.
Advanced process technology, efficient pollution control technology,
and effective pollution prevention measures, including extensive reuse
of internal process water, would be employed to minimize impacts.

Alternatives

    Section 102(2)(C) of NEPA requires that agencies discuss the
reasonable alternatives to the proposed action in an EIS. The purpose
for agency action determines the range of reasonable alternatives. The
goals of the proposed agency action establish the limits of its
reasonable alternatives. Congress established the Clean Coal Technology
Program with a specific purpose: To demonstrate the commercial
viability of technologies that use coal in more environmentally benign
ways than conventional coal technologies. Congress also directed DOE to
pursue the goals of the legislation by means of partial funding (cost
sharing) of projects owned and controlled by non-Federal government
sponsors. This statutory requirement places DOE in a much more limited
role than if the Federal

[[Page 20144]]

government were the owner and operator of the project. In the latter
situation, DOE would be responsible for a comprehensive review of
reasonable alternatives for siting the project. However, in dealing
with an applicant, the scope of alternatives is necessarily more
restricted because the agency must focus on alternative ways to
accomplish its purpose that reflect both the application before it and
the functions the agency plays in the decision process. It is
appropriate in such cases for DOE to give substantial consideration to
the applicant's needs in establishing a project's reasonable
alternatives.
    DOE developed an overall NEPA compliance strategy for the Clean
Coal Technology Program that includes consideration of both
programmatic and project-specific environmental impacts during and
after the process of selecting a proposed project. As part of the NEPA
strategy, the EIS for the Kentucky Pioneer IGCC Demonstration Project
will tier from the Clean Coal Technology Programmatic Environmental
Impact Statement (PEIS) that DOE issued in November 1989 (DOE/EIS-
0146). Two alternatives were evaluated in the PEIS: (1) The no-action
alternative, which assumed that the Clean Coal Technology Program was
not continued and that power suppliers would continue to use
conventional coal-fired technologies with flue gas desulfurization and
nitrogen oxide controls to meet New Source Performance Standards; and
(2) the proposed action, which assumed that Clean Coal Technology
Program projects would be selected and funded, and that successfully
demonstrated technologies would undergo widespread commercialization by
the year 2010.
    The range of reasonable options to be considered in the EIS for the
proposed Kentucky Pioneer IGCC Demonstration Project is determined in
accordance with the overall NEPA strategy. The EIS also will include an
analysis of the no-action alternative, as required under NEPA. Under
the no-action alternative, DOE would not provide partial funding for
the design, construction, and operation of the project. In the absence
of DOE funding, the Kentucky Pioneer IGCC Demonstration Project
probably would not be constructed. If the proposed Kentucky Pioneer
IGCC Demonstration Project were not built, EKPC may use alternative,
less efficient sources for electric power to meet future demands of its
customers. Alternatives to the proposed project could include
purchasing power from other sources, adding generation capacity that
does not rely on the IGCC technology, or using some other current
technology. DOE will consider other reasonable alternatives that may be
suggested during the public scoping period.
    Because of DOE's limited role of providing cost-shared funding for
the proposed Kentucky Pioneer IGCC Demonstration Project, and because
of advantages associated with the proposed location, DOE does not plan
to evaluate alternative sites for the proposed project. Site selection
was governed primarily by benefits that EKPC could realize. EKPC
preferred the proposed project site because the costs would be much
higher and the environmental impacts would likely be greater for an
undisturbed area.
    Under the proposed action, project activities would include
engineering and design, permitting, fabrication and construction,
testing, and demonstration of the technology. DOE plans to complete the
EIS and issue a Record of Decision within 15 months of publication of
this Notice of Intent, assuming timely delivery of information from
Kentucky Pioneer Energy, L.L.C. that DOE needs for preparing the EIS.
Upon completion of the demonstration, the facility could continue
commercial operation.

Preliminary Identification of Environmental Issues

    The following issues have been tentatively identified for analysis
in the EIS. This list, which was developed on the basis of analyses of
similar projects and from agency concerns, and is presented to
facilitate public comment on the scope of the EIS, is neither intended
to be all-inclusive nor a predetermined set of potential impacts.
Additions to or deletions from this list may occur as a result of the
scoping process.
    The issues include:
    (1) Atmospheric resources: Potential air quality impacts resulting
from emissions during construction and operation of the Kentucky
Pioneer IGCC Demonstration Project and the briquette manufacturing
plant;
    (2) Water resources: Potential effects on surface and groundwater
resources and withdrawal of water from the Kentucky River;
    (3) Infrastructure and land use, including potential effects
resulting from the manufacture, transportation, and storage of the
briquettes required for the proposed project;
    (4) Solid waste: Pollution prevention and waste management
practices, including impacts caused by waste generation and treatment
at the proposed project and briquette manufacturing plant;
    (5) Noise: Potential impacts resulting from construction,
transportation of materials, and plant operation for the proposed
project and briquette manufacturing plant;
    (6) Construction: Impacts associated with traffic patterns and
construction related emissions;
    (7) Floodplains: Impacts associated with extension of a water
intake structure in the Kentucky River;
    (8) Community impacts, including impacts from local traffic
patterns, socioeconomic impacts on public services and infrastructure,
and environmental justice (Executive Order 12898) with respect to the
surrounding community;
    (9) Cumulative effects that result from the incremental impacts of
the proposed project when added to the other past, present, and
reasonably foreseeable future actions; and,
    (10) Visual impacts associated with plant structures.

Public Scoping Process

    To ensure that all issues related to this proposal are addressed,
DOE will conduct an open process to define the scope of the EIS. The
public scoping period will run until May 31, 2000. Interested agencies,
organizations, and the general public are encouraged to submit comments
or suggestions concerning the content of the EIS, issues and impacts to
be addressed in the EIS, and the alternatives that should be analyzed.
Scoping comments should describe specific issues or topics that the EIS
should address in order to assist DOE in identifying significant
issues. Written, e-mailed, or faxed comments should be communicated by
May 31, 2000 (see ADDRESSES).
    DOE will conduct a public scoping meeting at Trapp Elementary
School in Trapp, Kentucky on May 4, 2000, at 7 p.m. The address of
Trapp Elementary School is 11400 Irvine Road, Highway 89 South,
Winchester, Kentucky 40391. In addition, the public is invited to an
informal session at this location beginning at 4 p.m. to learn more
about the proposed action. Displays and other information about the
proposed agency action and location will be available, and DOE
personnel will be present to answer questions.
    The formal scoping meeting will begin on May 4, 2000, at 7 p.m. DOE
asks people who wish to speak at this public scoping meeting to contact
Mr. Roy Spears, either by phone, fax, computer, or in writing (see
ADDRESSES in this Notice). People who do not arrange in advance to
speak may register at the meeting (preferably at the beginning of the
meeting) and may

[[Page 20145]]

speak after previously scheduled speakers. Speakers who want more than
five minutes should indicate the length of time desired in their
request. Depending on the number of speakers, DOE may need to limit
speakers to five minutes initially, and provide additional
opportunities as time permits. Speakers may also provide written
materials to supplement their presentations. Oral and written comments
will be given equal consideration.
    DOE will begin the meeting with an overview of the proposed
Kentucky Pioneer IGCC Demonstration Project. The meeting will not be
conducted as an evidentiary hearing, and speakers will not be cross-
examined. However, speakers may be asked questions to help ensure that
DOE fully understands their comments or suggestions. A presiding
officer will establish the order of speakers and provide any additional
procedures necessary to conduct the meeting.

    Issued in Washington, DC, this 10th day of April, 2000.
David Michaels,
Assistant Secretary, Environment, Safety and Health.
[FR Doc. 00-9301 Filed 4-13-00; 8:45 am]
BILLING CODE 6450-01-P
=================================
 

http://www.kentuckyconnect.com/heraldleader/news/072301/commentarydocs/723musulin-response.htm

               Published Monday, July 23, 2001, in the Herald-Leader

               Inaccuracies undermine attack on power plant

               By Mike Musulin II

               The commentary about the Kentucky Pioneer Energy power plant at Trapp
               contained inaccurate statements reflecting a general misunderstanding
               regarding the kind of plant that will be built. The facility will be an ``integrated
               gasification combined cycle'' facility, which will convert coal and municipal solid
               waste, in the form of refuse-derived fuel pellets, into synthesis gas for use as a
               fuel in a conventional gas turbine. Syngas is a substitute for natural gas. The
               entire output of the plant will be used by East Kentucky Power Cooperative.

               Contrary to the information in the column, the plant will not incinerate garbage, it
               is not a fluidized bed process and it is not a merchant plant. The coal and pellets
               will be rail shipped to the plant. The gasification process uses steam and oxygen
               to convert the volatile material in the feedstock into hydrogen-rich syngas.

               It is not a combustion process. Gasification takes place in a closed vessel
               without a stack. Emissions from a gas turbine using syngas are much less than
               those from a traditional coal-fired power plant.

               On July 3, the Herald-Leader published a chart from the Kentucky Division for
               Air Quality showing the estimated emissions of the Kentucky Pioneer Energy
               plant and the other proposed power plants around the state. The chart clearly
               showed that the Kentucky Pioneer Energy facility will have lower emissions,
               including greenhouse gases, than the proposed coal-fired plants.

               A gasification facility does not have ash waste or gob, as the commentary
               states. Instead, the gasification process creates vitrified frit, an inert,
               non-leaching material that resembles coarse sand or aggregate. Also known as
               synthetic aggregate, it is a saleable product with a variety of uses in the
               construction and building industries. In Great Britain, synthetic aggregate has
               been used in road paving and concrete seawalls.

               At the siting analysis public hearing for the plant on June 28, officials of Global
               Energy, the parent of Kentucky Pioneer Energy, stated that plans include the
               ability to use refuse-derived fuel pellets from Kentucky sources in the future.

               However, given the volume of feedstock needed for the plant and the fact that
               municipal waste collection is spread among Kentucky's 120 counties, Kentucky
               Pioneer Energy can produce lower cost electricity by using pellets produced
               elsewhere for the majority of the feedstock.

               Gasification was selected for this project because it is an advanced technology
               that is economically and environmentally superior to any other for the beneficial
               use of coal and the elimination of waste. Kentucky Pioneer Energy will furnish
               Kentucky residents with low-cost power, high-quality jobs and a cleaner
               environment for years to come.

====================================================
http://www.kentuckyconnect.com/heraldleader/news/070801/commentarydocs/708appy-herrick.htm

               Published Sunday, July 8, 2001, in the Herald-Leader

               Trapp waste-to-energy plant will hurt, not help, Ky.

               By Will Herrick

               Kentucky has a long history of attracting out-of-state trash. In the late 1980s
               and early '90s, waste incinerators were frequently proposed, and after
               consideration, all were rejected. Little has really changed in the waste
               incineration business, and it is still in the state's interest to not burden Central
               and East Kentucky with more air and water pollution.

               The only public benefit to allowing the construction of a trash-to-energy plant
               at Trapp is to ease the cost of trash disposal in New York and New Jersey, and
               to lower the cost of electricity for folks outside Kentucky. This state doesn't lack
               for electrical production, and we have adequate landfill space for our current
               needs.

               The Trapp facility will, however, exacerbate our already serious air- and
               water-quality problems. We are in dire need of broadening our economic base,
               but is it a good trade to suffer health risks and give up diverse economic growth
               so that out-of-state trash can be burned to make electricity to export?

               There are many health issues associated with incineration. Dumping fine
               particles into the air means that folks downwind will breath them. Those
               particles are proving to cause cancers and heart problems. Kentucky is already
               facing the national limits on air pollution.

               We have one of the highest rates of heart attack in the nation. The cost of
               pushing up against those pollution limits should be very carefully considered.
               Solid waste makes strong acids when burned, not all of which are caught in the
               calcic compounds of the fluidized bed.

               The effect of acid rain and its cost to the forests of Eastern Kentucky and
               beyond should also be considered. Not all the highly toxic metal vapors like
               mercury, lead, cadmium or nickle are captured. They will enter Lexington's
               water supply in greater concentrations as the primary air transport moves up
               the Kentucky River basin and the water flows down.

               The Kentucky River is Lexington's primary source of drinking water. Metals
               like cadmium will be absorbed by tobacco plants (as well as other crops ) and
               add to the health problems already weighing down the tobacco industry. The
               ``clean coal'' contaminants don't go away, they are still in the calcic gob and in
               the air.

               The gob and the unburned fraction of the waste must be disposed of properly.
               Acid will dissolve all of the captured metals and soot right back out of the
               calcium compounds, a story all too familiar to those living around the leachate of
               mine tailings.

               For those seeking employment, it's worth looking at the chicken factories,
               where wages are so low that the jobs are not considered worth having, and
               most locals have quit taking them. Much of the incinerator operation is low-skill
               and hence low-paying. A lot of those jobs will not be worth having. Skilled
               workers need to balance the health risks of working around trash, toxic nickle
               vapors and soot against the wages being offered. I doubt that it will be the best
               job in Clark County or next door in Powell County.

               About 10 years ago, Wolfe County was chosen as the site for a large incinerator
               just above the Red River Gorge. Public reaction was sufficient to derail that
               facility, and folks here are still glad it wasn't built. It is clear that our economic
               diversification would be frustrated by having the incinerator instead of beautiful
               vistas of the Red River Gorge welcome visitors to Wolfe County. Our public
               health problems would be worse than they are.

               As one community that said no to a waste-to-energy incinerator to another:
               don't permit this facility. Ten years from now, you will be glad that you didn't.

               While local and state officials suffered much of the public's outrage, what really
               made the Wolfe County incinerator go away was pressure on the governor.
               Make phone calls, send letters and publicly demonstrate disapproval.

               If Lexington wants to keep New York's and New Jersey's toxic metals out of its
               morning coffee, if Clark and Powell counties want to spare themselves the
               burden of a waste-import facility, if Eastern Kentucky wants to preserve its air
               and water quality, and if we all want to preserve an open playing field for
               economic development, tell the governor and state legislators ``no'' to a plant in
               Trapp.

               With enough public pressure, this plant will go the way of all the rest.
 
 

               Will Herrick, a computer software writer who lives in Campton, is involved in
               environmental issues.
===========================

http://www.kentuckyconnect.com/heraldleader/news/120901/hlocaldocs/09Plant.htm
 
 

Public asked to comment on power plant

Facility near Trapp will burn combination of coal, garbage

By Lance Williams
HERALD-LEADER RICHMOND BUREAU

Federal officials will be in Central Kentucky this week to hear public comment on the potential environmental impacts of a 540-megawatt power plant in southeastern Clark County. The plant will be built on a 300-acre site near the Trapp community.

Construction of the plant, which will burn a combination of coal and municipal waste, could begin by next summer if the project receives final environmental approval by the U.S. Department of Energy.

 The $432 million project received state approval last June, but also requires federal approval to be eligible for $61 million in federal funds to aid in construction.

The public comment sessions are from 7 to 9 p.m. Monday at the public library in downtown Lexington and Tuesday at Trapp Elementary School in Winchester, said Roy Spears, the project's document manager for the Department of Energy. The plans will be available for review from 4 to 7 p.m. each day.

 Spears said the deadline for public comment on the draft environmental impact statement is Jan. 4 and construction could begin within the next five months.

 It will take approximately three years to finish the project, and up to 1,000 jobs could be created during the construction phase. Company officials have said about 120 permanent employees would run the plant.

 East Kentucky Power, an electric co-op in Winchester, has agreed to buy the plant's output for 20 years.

 Officials from Global Energy USA, which is building the plant, have said it will produce fewer emissions than traditional coal-fired plants.

 Much of the fuel will come from garbage from New York and New Jersey in the form of pellets of compacted, shredded trash. The coal that will be used will be converted to synthetic gas before it is used to turn the electric turbines.
================================================

http://www.tfhrc.gov/hnr20/recycle/waste/bfs1.htm

Table 3-2 depicts the typical chemical composition of blast furnace slag. The chemical compositions shown are in general applicable to all types of slag. The data
     presented in Table 3-2 suggest that the chemical composition of blast furnace slags produced in North America has remained relatively consistent over the years.

...

Chemical Properties

     Table 3-2 depicts the typical chemical composition of blast furnace slag. The chemical compositions shown are in general applicable to all types of slag. The data
     presented in Table 3-2 suggest that the chemical composition of blast furnace slags produced in North America has remained relatively consistent over the years.

     When ground to the proper fineness, the chemical composition and glassy (noncrystalline) nature of vitrified slags are such that when combined with water, these
     vitrified slags react to form cementitious hydration products. The magnitude of these cementitious reactions depends on the chemical composition, glass content,
     and fineness of the slag. The chemical reaction between GGBFS and water is slow, but it is greatly enhanced by the presence of calcium hydroxide, alkalies and
     gypsum (CaSO4).

                                  Table 3-2. Typical composition of blast furnace slag.(9)

                  Constituent
                                                            Percent
                                       1949a.
                                                     1957a.
                                                                  1968a.
                                                                                  1985a.
                                   Mean
                                          Range
                                                 Mean
                                                       Range
                                                              Mean
                                                                     Range
                                                                            Mean
                                                                                    Range
                Calcium Oxide (CaO)
                                    41
                                          34-48
                                                  41
                                                        31-47
                                                                39
                                                                     32-44
                                                                             39
                                                                                     34-43
               Silicon Dioxide (SiO2)
                                    36
                                          31-45
                                                  36
                                                        31-44
                                                                36
                                                                     32-40
                                                                             36
                                                                                     27-38
               Aluminum Oxide (Al2O3)
                                    13
                                          10-17
                                                  13
                                                        8-18
                                                                12
                                                                      8-20
                                                                             10
                                                                                     7-12
              Magnesium Oxide (MgO)
                                     7
                                          1-15
                                                  7
                                                        2-16
                                                                11
                                                                      2-19
                                                                             12
                                                                                     7-15
                    Iron
                 (FeO or Fe2O3)
                                    0.5
                                          0.1-1.0
                                                  0.5
                                                       0.2-0.9
                                                               0.4
                                                                     0.2-0.9
                                                                             0.5
                                                                                    0.2-1.6
                 Manganese Oxide
                    (MnO)
                                    0.8
                                          0.1-1.4
                                                  0.8
                                                       0.2-2.3
                                                               0.5
                                                                     0.2-2.0
                                                                             0.44
                                                                                    0.15-0.76
                    Sulfur
                     (S)
                                    1.5
                                          0.9-2.3
                                                  1.6
                                                       0.7-2.3
                                                               1.4
                                                                     0.6-2.3
                                                                             1.4
                                                                                    1.0-1.9
          a. Data source is the National Slag Association data: 1949 (22 sources); 1957 (29 sources); 1968 (30 sources) and 1985 (18 sources).
 
 
 

     Because of these cementitious properties, GGBFS can be used as a supplementary cementitious material either by premixing the slag with Portland cement or
     hydrated lime to produce a blended cement (during the cement production process) or by adding the slag to Portland cement concrete as a mineral admixture.

     Blast furnace slag is mildly alkaline and exhibits a pH in solution in the range of 8 to 10. Although blast furnace slag contains a small component of elemental sulfur
     (1 to 2 percent), the leachate tends to be slightly alkaline and does not present a corrosion risk to steel in pilings(10) or to steel embedded in concrete made with
     blast furnace slag cement or aggregates.(11)

     In certain situations, the leachate from blast furnace slag may be discolored (characteristic yellow/green color) and have a sulfurous odor. These properties appear
     to be associated with the presence of stagnant or slow moving water that has come in contact with the slag. The stagnant water generally exhibits high
     concentrations of calcium and sulfide, with a pH as high as 12.5.(12) When this yellow leachate is exposed to oxygen, the sulfides present react with oxygen to
     precipitate white/yellow elemental sulfur and produce calcium thiosulfate, which is a clear solution. (See references 13,14,15,16,17,18,19.) Aging of blast furnace
     slag can delay the formation of yellow leachate in poor drainage conditions but does not appear to be a preventative measure, since the discolored leachate can still
     form if stagnant water is left in contact with the slag for an extended period.(12)
 

=============================================

Commonwealth of Kentucky

Natural Resources and Environmental Protection Cabinet

Department for Environmental Protection

Division for Air Quality

803 Schenkel Lane

Frankfort, Kentucky 40601

(502) 573-3382

AIR QUALITY PERMIT

Permittee Name:

Kentucky Pioneer Energy LLC

Mailing Address:

312 Walnut Street, Suite 2000, Cincinnati, Ohio 45202

Source Name:

Kentucky Pioneer Energy LLC

Mailing Address:

312 Walnut Street, Suite 2000, Cincinnati, Ohio 45202

Source Location:

12145 Irvine Road, Trapp, Kentucky 40391

Permit Type:

Federally-Enforceable

Review Type:

PSD, Title V

Permit Number:

V-00-049

Log Number:

51152

Application

Complete Date:

January 21, 2000

KYEIS ID #:

21-049-00053

SIC Code:

4911

ORIS Code:

55266

Region:

Bluegrass

County:

Clark

Issuance Date:

June 7, 2001

Expiration Date:

June 7, 2006

___________________________________

John E. Hornback, Director

DEP7001 (1-97)

Division for Air Quality

Revised 06/22/00
 

                                                                                                Page 2
 

TABLE OF CONTENTS

SECTION

DATE

PAGE

OF ISSUANCE

SECTION A

PERMIT AUTHORIZATION

June 7, 2001

1

SECTION B

EMISSION POINTS, EMISSIONS

June 7, 2001

2

UNITS, APPLICABLE

REGULATIONS, AND

OPERATING CONDITIONS

SECTION C

INSIGNIFICANT ACTIVITIES

June 7, 2001

32

SECTION D

SOURCE EMISSION

June 7, 2001

33

LIMITATIONS AND

TESTING REQUIREMENTS

SECTION E

SOURCE CONTROL EQUIPMENT

June 7, 2001

34

OPERATING REQUIREMENTS

SECTION F

MONITORING, RECORD

June 7, 2001

35

KEEPING, AND REPORTING

REQUIREMENTS

SECTION G

GENERAL CONDITIONS

June 7, 2001

38

SECTION H

ALTERNATE OPERATING SCENARIOS June 7, 2001

44

SECTION I

COMPLIANCE SCHEDULE

June 7, 2001

44

SECTION J

ACID RAIN PERMIT

June 7, 2001

45
 

                                                                                                Page 3
 

Permit Number: V-00-049

                            Page 1 of  50

SECTION A - PERMIT AUTHORIZATION

Pursuant to a duly submitted application which was determined to be complete on January 21, 2000, the Kentucky

Division for Air Quality hereby authorizes the construction and operation of the equipment described herein in

accordance with the terms and conditions of this permit. This draft permit has been issued under the provisions of

Kentucky Revised Statutes Chapter 224 and regulations promulgated pursuant thereto.

The permittee shall not construct, reconstruct, or modify any emission units without first having submitted a complete

application and receiving a permit for the planned activity from the permitting authority, except as provided in this permit

or in the Regulation 401 KAR 50:035, Permits.

Issuance of this permit does not relieve the permittee from the responsibility of obtaining any other permits, licenses, or

approvals required by this Cabinet or any other federal, state, or local agency.

References in this permit to regulatory requirements of 401 KAR 50:035 are based on the governing regulation which

was in effect at the time the permit application was deemed complete.  For future reference to the regulatory basis for

permit conditions and for the purposes of implementation and compliance, the corresponding portions of the provisions

of new permitting regulations in 401 KAR Chapter 52 (effective January 15, 2001) shall apply
 

                                                                                                Page 4
 

Permit Number: V-00-049

                            Page 2 of  50

SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,

AND OPERATING CONDITIONS

Emissions Units: 01, 02  (GT1, GT2)

 -

Synthesis/Natural Gas-Fired Combined Cycle

Combustion Turbines

Description:

1765 MMBTU/hr maximum heat input capacity, each, 197 MW power capacity output (turbine only, does not include

heat recovery steam generator).

GE 7FA synthesis (primary) or natural (secondary/backup) gas-fired combined cycle combustion turbine equipped with

steam injection.

Construction commenced: estimated - Summer 2001
 
 

Applicable Regulations:

Regulation 401 KAR 51:017, Prevention of significant deterioration of air quality.

Regulation 401 KAR 60:005, incorporating by reference 40 CFR 60, Subpart GG, Standards of Performance for

Stationary Gas Turbines, for emissions unit with a heat input at peak load equal to or greater than 10 MMBTU/hour for

which construction commenced after October 3, 1977.

Regulation 401 KAR 59:021, New municipal solid waste incinerators.

Regulation 40 CFR 60 Subpart Eb, Standards of Performance for Large Municipal Waste Combustors for which

Construction is Commenced After September 20, 1994 or for Which Modification or Reconstruction is Commenced

After June 19, 1996.

1.

Operating Limitations:

a) Synthesis gas (mainly consists of carbon monoxide and hydrogen gas) with natural gas back-up fuel, shall be the sole

fuels fired in the turbines. [Self-imposed restriction pursuant to Regulation 401 KAR 51:017, Prevention of significant

deterioration of air quality].

b) The heat input shall not exceed 1765 MMBTU/hour at ISO standard day conditions, in accordance with Regulation

401 KAR 51:017.  The rated heat input capacity shall be calculated from the fuel usage, and corresponding fuel heating

value characteristic of the fuel to be combusted corrected to ISO standard conditions based on manufacturer's curves

or equations for correction.

c) Natural gas usage in the combustion turbine shall not exceed 7,533,600 MMBTU in the first 12 months after startup,

3,766,800 MMBTU in the second twelve months, and 1,833, 400 MMBTU/yr in any subsequent rolling 12 month

period. [This condition may be modified upon a complete analysis indicating compliance with Best Available Control

Technology and Air Quality Impact Analyses as required by Regulation 401 KAR 51:017, Prevention of significant

deterioration of air quality, and any other applicable requirements.]
 
 
 

                                                                                                Page 5
 

Permit Number: V-00-049

                            Page 3 of  50

SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,

AND OPERATING CONDITIONS (CONTINUED)

d) Pursuant to Regulation 40 CFR 60.53b, maximum synthesis gas fuel flow to the gas turbines in MMBTU/hr shall not

exceed 110% of the synthesis gas fuel flow during the most recent performance test.

e) Pursuant to Regulation 40 CFR 60.54b(a), no later than the date 6 months after the date of startup, each facility

supervisor and shift supervisor shall obtain and maintain a current provisional certification from either the American

Society of Mechanical Engineers or a State certification program.

f) Pursuant to Regulation 40 CFR 60.54b(b), no later than the date 6 months after the date of startup, each facility

supervisor and shift supervisor shall have completed full certification or shall have scheduled a full certification exam with

either the American Society of Mechanical Engineers or a State Certification program.

g) Pursuant to Regulation 40 CFR 60.54b(c), 6 months after the date of startup, no owner or operator shall allow the

facility to be operated at any time unless one of the following persons is on duty and at the facility:  A fully certified chief

facility operator, a provisionally certified chief facility operator who is scheduled to take the full certification exam

according to the schedule specified in paragraph (b) of section 60.54 of 40 CFR 60 Subpart Eb, or a fully certified shift

supervisor who is scheduled to take the full certification exam according to the schedule specified in paragraph (b) of

section 60.54 of 40 CFR 60 Subpart Eb.

h) Pursuant to Regulation 40 CFR 60.54b(e), a site-specific operating manual shall be developed prior to

commencement of normal operations, and updated annually. The manual shall include a description of the applicable

emission limits, procedures for proper operation of the gasification plant and gas turbines, startup, shutdown, and

malfunction procedures.  The manual shall include all elements of 40 CFR 60.54b(e)(1) through (11) as they relate to

the site specific operation of an IGCC power plant.  A training program shall be developed to review the operating

manual within 6 months of startup and annually. The training program shall include each person who has responsibilities

affecting the operation of the facility, including, but not limited to, chief facility operators, shift supervisors, control room

operators, and appropriate maintenance personnel.  The manual must be readily accessible and available for inspection.

i) Pursuant to 40 CFR 60.57b(b), a siting analysis shall be conducted. This analysis shall be made available to the public,

and comments accepted at the public meeting.

j) Except for periods of startup, shutdown, and malfunction, 90% full load capacity (or greater) must be maintained by

each turbine unless additional ambient impact modeling is performed demonstrating that other load scenarios result in less

impact.
 

                                                                                                Page 6
 

Permit Number: V-00-049

                            Page 4 of  50

SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,

AND OPERATING CONDITIONS (CONTINUED)

2.

Emission Limitations:

a) Pursuant to Regulations 40 CFR 60.332, and 401 KAR 51:017, nitrogen oxides emission level in the exhaust gas shall

not exceed 0.0735 lb/MMBTU based on 15 ppm by volume at 15 % oxygen, on a dry basis, during any rolling three-

hour average period when firing synthesis gas. The nitrogen oxides emission level in the exhaust gas shall not exceed

0.102 lb/MMBTU based on 25 ppm by volume at 15 % oxygen, on a dry basis, during any rolling three-hour average

period when firing natural gas. When both fuels are fired simultaneously, the allowable emissions shall be no higher than

the above limit specified for natural gas firing operations.  Additionally, the permittee shall keep records of the quantity

of each fuel used and the actual NOx/CO emissions during such periods.   The total emission from these operations,

together with the emissions from normal operations, shall not exceed the emission rates used in the permittee's air quality

analysis modeling

.

 The ppm level of nitrogen oxides (at ISO standard conditions) and lb/MMBTU shall be demonstrated

by stack test, and measured with use of a continuous emission monitor (CEM).

 b) Pursuant to Regulation 401 KAR 51:017, the carbon monoxide emission level in the exhaust gas shall not exceed

0.032 lb/MMBTU based on 15 ppm by volume at 15 % oxygen, on a dry basis, during any rolling three-hour average

period when firing synthesis gas. The carbon monoxide emission level in the exhaust gas shall not exceed 0.055

lb/MMBTU based on 25 ppm by volume at 15 % oxygen, on a dry basis, during any rolling three-hour average period

when firing natural gas. When both fuels are fired simultaneously, the allowable emissions shall be no higher than the

above limit specified for natural gas firing operations.  Additionally, the permittee shall keep records of the quantity of

each fuel used and the actual NOx/CO emissions during such periods.   The total emission from these operations,

together with the emissions from normal operations, shall not exceed the emission rates used in the permittee's air quality

analysis modeling. The ppm level of carbon monoxide and lb/MMBTU shall be demonstrated by stack test, and

measured with use of a continuous emission monitor (CEM).

c) Pursuant to Regulation 40 CFR 60.333, and 401 KAR 51:017, the sulfur dioxide emission level in the exhaust gas

shall not exceed 0.032 lb/MMBTU based on any rolling three-hour average period.  Sulfur dioxide emissions also shall

not exceed 30 ppm by volume or 20% of the potential sulfur dioxide emission concentration (80%reduction by weight

or volume) corrected to 7% oxygen (dry basis), whichever is most stringent. The level of sulfur dioxide converted to

lb/MMBTU shall be demonstrated by stack test, and measured with use of a continuous emission monitor (CEM).

d) Pursuant to Regulation 401 KAR 51:017, particulate emissions shall not exceed 0.011 lb/MMBTU.  The lb/MMBTU

level of particulate emissions shall be demonstrated by stack test, then calculated based on the emission factor derived

during the test, fuel consumption data, fuel heat input, and fuel heat content [see specific monitoring requirements].

e)  Pursuant to Regulation 401 KAR 51:017, volatile organic compound emissions shall not exceed 0.0044 lb/MMBTU.

 The lb/MMBTU level of volatile organic compound emissions shall be demonstrated by stack test, then calculated based

on the emission factor derived during the test, fuel consumption data, fuel heat input, and fuel heat content [see specific

monitoring requirements].
 

                                                                                                Page 7
 

Permit Number: V-00-049

                            Page 5 of  50

SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,

AND OPERATING CONDITIONS (CONTINUED)

f) Pursuant to Regulation 401 KAR 51:017, beryllium emissions shall not exceed 6.0E-07 lb/MMBTU.  The lb/MMBTU

level of beryllium emissions shall be demonstrated by stack test, then calculated based on the emission factor derived

during the test, fuel consumption data, fuel heat input, and fuel heat content.

g) Pursuant to Regulation 40 CFR 60.52b, emissions of cadmium shall not exceed 0.020 milligrams per dry standard

cubic meter, corrected to 7% oxygen.

h) Pursuant to Regulation 40 CFR 60.52b, emissions of lead shall not exceed 0.20 milligrams per dry standard cubic

meter, corrected to 7% oxygen.

i) Pursuant to Regulation 40 CFR 60.52b, emissions of mercury shall not exceed 0.080 milligrams per dry standard cubic

meter, corrected to 7% oxygen.

j) Pursuant to Regulation 40 CFR 60.52b, and to preclude applicability of 401 KAR 51:017, emissions of dioxins and

furans shall not exceed 0.01 nanograms per dry standard cubic meter (total mass), corrected to 7% oxygen.

k) Pursuant to Regulation 40 CFR 60.52b, emissions of hydrogen chloride shall not exceed 25 ppm by volume or 5%

of the potential hydrogen chloride emission concentration (95% reduction by weight or volume), corrected to 7% oxygen

(dry basis), whichever is less stringent.

l) Pursuant to 40 CFR 60.58b, the above emission limits shall apply at all times when syngas is fired, except during

periods of startup, shutdown, or malfunction.  Duration of startup, shutdown and malfunction periods are limited to 2

hours per occurrence

3.

Testing Requirements:

a) Pursuant to Regulation 40 CFR 60.335 (b), in conducting performance tests required by 40 CFR 60.8, the owner

or operator shall use as reference methods and procedures the test methods in Appendix A of Part 60 or other methods

or procedures as specified in 40 CFR 60.335, except as provided for in 40 CFR 60.8(b).

b) Pursuant to Regulation 401 KAR 50:045, the owner or operator shall conduct an initial performance test for nitrogen

oxides.  The initial nitrogen oxides performance test shall be performed in accordance with General Condition G(d)(5).

c) Pursuant to Regulation 401 KAR 50:045, the owner or operator shall conduct an initial test for sulfur dioxide in

accordance with General Condition G(d)(5).
 

                                                                                                Page 8
 

Permit Number: V-00-049

                            Page 6 of  50

SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,

AND OPERATING CONDITIONS (CONTINUED)

d) Pursuant to Regulation 401 KAR 50:045, the owner or operator shall conduct an initial performance test for carbon

monoxide, using a reference test method approved by the Division, in accordance with General Condition G(d)(5).

e) Pursuant to Regulation 401 KAR 50:045 and 40 CFR 60.58b, the owner or operator shall conduct an initial and

annual performance tests for particulate matter, using a reference test method approved by the Division, in accordance

with General Condition G(d)(5).

f) Pursuant to Regulation 401 KAR 50:045, the owner or operator shall conduct an initial performance test for volatile

organic compounds, using a reference test method approved by the Division, in accordance with General Condition

G(d)(5).

g) Pursuant to Regulation 401 KAR 50:045, the owner or operator shall conduct an initial performance test for beryllium,

using a reference test method approved by the Division, in accordance with General Condition G(d)(5).

h) See General Condition G(d)(6).

i) Pursuant to Regulation 40 CFR 60.52b, the owner or operator shall conduct an initial and annual performance tests

for cadmium, lead and mercury, using EPA Reference Method 29 or an alternate reference test approved by the

Division, in accordance with General Condition G(d)(5).

j) Pursuant to Regulation 40 CFR 60.52b, the owner or operator shall conduct an initial and annual performance tests

for hydrogen chloride using EPA Reference Method 26 or 26a or an alternate reference test approved by the Division,

in accordance with General Condition G(d)(5).

k) Pursuant to Regulation 40 CFR 60.52b, the owner or operator shall conduct an initial and annual performance tests

for dioxins and furans using EPA Reference Method 23 or an alternate reference test approved by the Division, in

accordance with General Condition G(d)(5). If emissions are less than 7 ng/m3, then the testing frequency can be

decreased as allowed in 40 CFR 60.58 (g)(5)(iii) upon Division approval.

4.

Specific Monitoring Requirements:

a) Pursuant to Regulation 401 KAR 50:035, Section 7(1)(c), 40 CFR 60.58b, and 40 CFR 75, the permittee shall

install, calibrate, maintain, and operate the nitrogen oxides Continuous Emissions Monitor (CEM).  The nitrogen oxides

CEM shall be used as the indicator of continuous compliance with the nitrogen oxides emission standard.  Excluding the

startup and shut down periods, if any 3-hour rolling average exceeds the nitrogen oxides emission limitation, the permittee

shall, as appropriate, initiate an investigation of the cause of the  exceedance and complete necessary control

device/process/CEM repairs or take corrective action as soon as practicable.
 

                                                                                                Page 9
 

Permit Number: V-00-049

                            Page 7 of  50

SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,

AND OPERATING CONDITIONS (CONTINUED)

b) The nitrogen oxides CEM shall be used in lieu of the water to fuel monitoring system for reporting excess emissions

in accordance with 40 CFR 60.334(c)(1).  The calibration of the water to fuel monitoring device required in 40 CFR

60.335(c)(2) will be replaced by the 40 CFR 75 certification tests of the nitrogen oxides CEM.  The CEM emission

rates for nitrogen oxides shall be corrected to ISO conditions to demonstrate compliance with the nitrogen oxides

standard established in Subsection 2.

c) Additionally, a CEM system shall be installed, calibrated, maintained, and operated for measuring oxygen levels in the

exhaust gas stacks.

d) The permittee shall comply with all of the monitoring requirements of 40 CFR 75.

e) Pursuant to Regulation 40 CFR 60.334(a), the owner or operator using water injection to control nitrogen oxide

emissions shall install and operate a continuous monitoring system to monitor and record the fuel consumption.  This

system shall be accurate to within plus or minus five (5) percent and shall be approved by the Division.

f) The nitrogen oxide and sulfur dioxide CEM shall be used in lieu of the fuel nitrogen and sulfur content monitoring

required by 40 CFR 60.334(b).

g) Pursuant to Regulation 401 KAR 50:035, Section 7(1)(c), and 40 CFR 60.58b to meet the periodic monitoring

requirement for carbon monoxide the permittee shall use a continuous emission monitor (CEM).  Excluding the startup

and shut down periods, if any 3-hour rolling average carbon monoxide value exceeds the standard, the permittee shall,

as appropriate, initiate an investigation of the cause of the exceedance and complete necessary process or CEM repairs

or take corrective action as soon as practicable.

h) Pursuant to Regulation 401 KAR 50:035, Section 7(1)(c), 40 CFR 60.58b, and 40 CFR 75, to meet the periodic

monitoring requirement for sulfur dioxide the permittee shall use a continuous emission monitor (CEM).  Excluding the

startup and shut down periods, if any rolling 3-hour average sulfur dioxide value exceeds the standard, the permittee shall,

as appropriate, initiate an investigation of the cause of the exceedance and complete necessary process or CEM repairs

or take corrective action as soon as practicable.

i) Pursuant to Regulation 40 CFR 60.58b, to meet the periodic monitoring requirement for opacity the permittee shall

use a continuous opacity monitor (COM).  Excluding the startup and shut down periods, if any 6 minute average exceeds

the standard, the permittee shall, as appropriate, initiate an investigation of the cause of the exceedance and complete

necessary process or COM repairs or take corrective action as soon as practicable.
 

                                                                                               Page 10
 

Permit Number: V-00-049

                            Page 8 of  50

SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,

AND OPERATING CONDITIONS (CONTINUED)

j) Pursuant to 40 CFR 60.13(b), the continuous monitoring systems and monitoring devices shall be installed and

operational prior to conducting the initial performance tests.  Verification of operational status shall, as a minimum, include

completion of the manufacturer's written requirements or recommendations for installation, operation, and calibration of

the device(s).

k) Pursuant to 40 CFR 60.13(c), the owner or operator of an emissions unit shall conduct a performance evaluation of

the continuous monitoring system during any performance test or within 30 days thereafter, in accordance with the

applicable performance specification in 40 CFR 60 Appendix B, for nitrogen oxides, sulfur dioxide, or carbon monoxide.

 Performance evaluations of CEM systems shall be conducted at other times as required.

l) Pursuant to 40 CFR 60.13(d)(1), the owner(s) and operator(s) of all continuous monitoring systems shall perform

appropriate calibration checks and zero and span adjustments in accordance with a written procedure at least once daily,

in accordance with requirements specified in 40 CFR 60.13(d)(1).

m) Pursuant to 40 CFR 60.13(e), except for system breakdowns, repairs, calibration checks, and zero and span

adjustments required under 40 CFR 60.13(d), all continuous monitoring systems shall be in continuous operation and

shall meet minimum frequency of operation requirements which involves one cycle of operation (sampling, analyzing, and

data recording) for each successive fifteen (15) minute period.

n) Pursuant to 40 CFR 60.13(f), all continuous monitoring systems or monitoring devices shall be installed such that

representative measurements of emissions or process parameters from the emissions unit are obtained.  Additional

procedures for location of continuous monitoring systems contained in the applicable Performance Specifications of 40

CFR 60 Appendix B shall be used.

o) Pursuant to 40 CFR 60.13(h), for the continuous monitoring systems the owner(s) or operator(s) shall reduce all data

to one-hour averages.  The one-hour averages shall be computed from four or more data points equally spaced over

each one-hour period.  Data recorded during periods of continuous monitoring system breakdowns, repairs, calibration

checks, and zero and span adjustments shall not be included in the data averages computed. An arithmetic or integrated

average of all data may be used.  The data may be recorded in reduced or nonreduced form (e.g., ppm pollutant and

percent oxygen).  All excess emissions shall be converted into units of the applicable standard using the applicable

conversion procedures specified in Subpart GG.  After conversion into units of the standard, the data may be rounded

to the same number of significant digits as used to specify the applicable emission standard.
 

                                                                                               Page 11
 

Permit Number: V-00-049

                            Page 9 of  50

SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,

AND OPERATING CONDITIONS (CONTINUED)

p) Pursuant to Regulation 401 KAR 50:035, Section 7(1)(c), for the particulate/particulate-10 periodic monitoring the

permittee shall develop the accurate emission factor during the performance test.  The permittee shall record the synthesis

gas heating value and the fuel consumption.  On a daily basis, the permittee shall calculate the emission rate for

particulate/particulate-10 using the fuel consumption, heating value of synthesis gas, and emission factor developed during

the most recent performance test. Excluding the startup and shut down periods, if any 24-hour rolling average

particulate/particulate-10 value exceeds the standard, the permittee shall, as appropriate, initiate an investigation of the

cause of the exceedance and complete necessary process repairs or take corrective action as soon as practicable.

q) Pursuant to Regulation 401 KAR 50:035, Section 7(1)(c), for the beryllium periodic monitoring the permittee shall

develop the accurate emission factor during the performance test.  The permittee shall record the synthesis gas heating

value and the fuel consumption. On a daily basis, the permittee shall calculate the emission rate for beryllium using the

fuel consumption, heating value of synthesis gas, and emission factor developed during the most recent performance test.

Excluding the startup and shut down periods, if any 24-hour rolling average beryllium value exceeds the standard, the

permittee shall, as appropriate, initiate an investigation of the cause of the exceedance and complete necessary process

repairs or take corrective action as soon as practicable.

r) Pursuant to Regulation 401 KAR 50:035, Section 7(1)(c), for the volatile organic compounds periodic monitoring the

permittee shall develop the accurate emission factor during the performance test. The permittee shall record the synthesis

gas heating value and the fuel consumption. On a daily basis, the permittee shall calculate the emission rate for volatile

organic compounds using the fuel consumption, heating value of synthesis gas, and emission factor developed during the

most recent performance test. Excluding the startup and shut down periods, if any 24-hour rolling average volatile organic

compounds value exceeds the standard, the permittee shall, as appropriate, initiate an investigation of the cause of the

exceedance and complete necessary process repairs or take corrective action as soon as practicable.

s) The permittee shall monitor the hours of operation of the emission unit on a weekly basis.

5.

Specific Record Keeping Requirements:

a) Pursuant to Regulation 401 KAR 59:005, Section 3, the owner or operator of the gas turbine shall maintain a file of

all measurements, including continuous monitoring system, monitoring device, and performance testing measurements;

all continuous monitoring system performance evaluations; all continuous monitoring system or monitoring device

calibration checks; adjustments and maintenance performed on these systems and devices; and all other information

required by Regulation 401 KAR 59:005 recorded in a permanent form suitable for inspection.
 

                                                                                               Page 12
 

Permit Number: V-00-049

                            Page 10 of  50

SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,

AND OPERATING CONDITIONS (CONTINUED)

b) Records, including those documenting the results of each compliance test and all other records and reports required

by this permit, shall be maintained for five (5) years pursuant to Regulation 401 KAR 50:035.

c) Pursuant to Regulation 401 KAR 59:005, Section 3, the owner or operator of the unit shall maintain the records of

the occurrence and duration of any startup, shutdown, or malfunction in the operation of the emissions unit, any

malfunction of the air pollution control equipment; or any period during which a continuous monitoring system or

monitoring device is inoperative.  The record shall also include the type and quantity of fuel fired and the estimated

emissions during each episode.

d) Pursuant to Regulation 401 KAR 50:035, Section 7, records of the hourly synthesis gas and/or natural gas (million

standard cubic feet) combusted shall be maintained.  Records shall be maintained to show that synthesis gas and natural

gas are the sole fuels burned in the turbine.

e) Pursuant to Regulation 401 KAR 50:035, Section 7, the permittee shall maintain a weekly log of all hours of operation

of the turbine, for any consecutive twelve (12) month period.

f) Pursuant to Regulation 401 KAR 50:035, Section 7, the permittee shall maintain a weekly log of all

particulate/particulate-10, volatile organic compounds, and beryllium calculations, emissions, and test results.

g) The owner/operator shall comply with the recordkeeping requirements of 40 CFR 60 Subpart Eb, section 60.59b.

6.

Specific Reporting Requirements:

a) Pursuant to Regulation 401 KAR 59:005, Section 3, minimum data requirements which follow shall be maintained and

furnished in the format specified by the Division. Owners or operators of facilities required to install continuous monitoring

systems shall submit for every calendar quarter a written report of excess emissions (as defined in applicable sections)

to the Division. All quarterly reports shall be postmarked by the thirtieth (30th) day following the end of each calendar

quarter and shall include the following information:

1) The magnitude of the excess emissions computed in accordance with the Regulation 401 KAR 59:005,

Section 4(8), any conversion factors used, and the date and time of commencement and completion of each time

period of excess emissions.

2) Specific identification of each period of excess emissions that occurs during startups, shutdowns, and

malfunctions of the emissions unit. The nature and cause of any malfunction (if known), the corrective action

taken or preventive measures adopted.
 

                                                                                               Page 13
 

Permit Number: V-00-049

                            Page 11 of  50

SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,

AND OPERATING CONDITIONS (CONTINUED)

3) The date and time identifying each period during which continuous monitoring system was inoperative except

for zero and span checks and the nature of the system repairs or adjustments.

4) When no excess emissions have occurred or the continuous monitoring system(s) have not been inoperative,

repaired, or adjusted, such information shall be stated in the report.

b) Pursuant to Regulation 40 CFR 60.334 (c), for the reports regarding nitrogen oxides excess emissions, in lieu of those

based on the water to fuel ratio monitoring, periods of excess emissions are defined as follows:

Nitrogen oxides: any three-hour period during which the average nitrogen oxides emission level as measured by

the continuous monitoring system, falls above the emission limitation specified in Subsection 2.

c) Pursuant to Regulation 40 CFR 60.334(c), each report of nitrogen oxides excess emissions shall include the average

nitrogen oxides emission level in lieu of water to fuel ratio, average fuel consumption, ambient conditions, gas turbine load,

and the graphs or figures developed.

d) Pursuant to 401 KAR 50:035 Section 7(1)(c), monitoring requirement with CEM for nitrogen oxides, excess

emissions are defined as any three (3) hour period during which the average emissions (arithmetic average) exceed the

applicable nitrogen oxides emission standard.  These periods of excess emissions shall be reported quarterly.

e) Pursuant to Regulation 40 CFR 60.334(c), excess emissions of sulfur dioxide are defined as any daily period during

which the sulfur dioxide emissions as indicated by continuous emission monitoring, or the sulfur content (or as otherwise

required in an approved custom fuel sulfur monitoring plan) of the fuel being fired in the gas turbine(s) exceeds the

limitations set forth in Subsection 2, Emission Limitations.  These periods of excess emissions shall be reported quarterly.

f) Pursuant to 401 KAR 50:035, Section 7(1)(c), monitoring requirement with CEM for carbon monoxide, excess

emissions are defined as any three (3) hour period during which the average emissions (arithmetic average of three

contiguous one hour periods) exceed the applicable carbon monoxide emission standard.  These periods of excess

emissions shall be reported quarterly.

g) Pursuant to 401 KAR 50:035, Section 7(1)(c), monitoring requirement with record keeping and calculations with test

data and the recorded data for particulate/particulate-10, excess emissions are defined as any 24-hour period during

which the average emissions exceed the applicable particulate/particulate-10 emission standard.  These periods of excess

emissions shall be reported quarterly.
 

                                                                                               Page 14
 

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                            Page 12 of  50

SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,

AND OPERATING CONDITIONS (CONTINUED)

h) Pursuant to 401 KAR 50:035, Section 7(1)(c), monitoring requirement with record keeping and calculations with test

data and the recorded data for volatile organic compounds, excess emissions are defined as any 24-hour period during

which the average emissions exceed the applicable volatile organic compounds emission standard.  These periods of

excess emissions shall be reported quarterly.

i) Pursuant to 401 KAR 50:035, Section 7(1)(c), monitoring requirement with record keeping and calculations with test

data and the recorded data for beryllium, excess emissions are defined as any 24-hour period during which the average

emissions exceed the applicable beryllium emission standard.  These periods of excess emissions shall be reported

quarterly.

j) Pursuant to 401 KAR 50:035, Section 7(1)(c), monitoring requirement with record keeping and calculations with test

data and the recorded data for cadmium, excess emissions are defined as any 24-hour period during which the average

emissions exceed the applicable cadmium emission standard.  These periods of excess emissions shall be reported

quarterly.

k) Pursuant to 401 KAR 50:035, Section 7(1)(c), monitoring requirement with record keeping and calculations with test

data and the recorded data for lead, excess emissions are defined as any 24-hour period during which the average

emissions exceed the applicable lead emission standard.  These periods of excess emissions shall be reported quarterly.

l) Pursuant to 401 KAR 50:035, Section 7(1)(c), monitoring requirement with record keeping and calculations with test

data and the recorded data for mercury, excess emissions are defined as any 24-hour period during which the average

emissions exceed the applicable mercury emission standard.  These periods of excess emissions shall be reported

quarterly.

m) Pursuant to 401 KAR 50:035, Section 7(1)(c), monitoring requirement with record keeping and calculations with

test data and the recorded data for hydrogen chloride, excess emissions are defined as any 24-hour period during which

the average emissions exceed the applicable hydrogen chloride emission standard.  These periods of excess emissions

shall be reported quarterly.

n) Pursuant to 401 KAR 50:035, Section 7(1)(c), monitoring requirement with record keeping and calculations with test

data and the recorded data for dioxins/furans, excess emissions are defined as any 24-hour period during which the

average emissions exceed the applicable dioxins/furans emission standard.  These periods of excess emissions shall be

reported quarterly.

o) Pursuant to Regulation 40 CFR 60.59b, The owner or operator shall submit semi-annual reports containing a summary

of collected data as outlined in 40 CFR 60.59b for all pollutants and parameters regulated under 40 CFR 60.59b.
 

                                                                                               Page 15
 

Permit Number: V-00-049

                            Page 13 of  50

SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,

AND OPERATING CONDITIONS (CONTINUED)

p) Pursuant to Regulation 40 CFR 60.59b, the owner or operator shall submit to the Division's Frankfort Regional Office

a notification of construction which shall include:

1) The intent to construct;

2) The planned initial startup date;

3) The types of fuels planned for use;

4) The unit capacity and supporting calculations, and

5) Documents associated with the siting analysis conducted in accordance with 40 CFR 60.57b(b).

A copy of the notification of the public meeting, a transcript of the public meeting, and a summary of responses to public

comments shall be accompany the notice of construction.

7.

Specific Control Equipment Operating Conditions:

a) The diluent injection control measure for nitrogen oxides emissions and, for sulfur removal, the acid gas scrubbing

system with the Claus plant and tailgas recycle, shall be operated as necessary to maintain compliance with permitted

emission limitations, in accordance with manufacturer's design specifications and/or good engineering practices.  The

permittee shall implement good combustion control and use clean, low sulfur/low ash synthesis gas as fuel.  Natural gas

may be fired in the combustion turbine during periods when the gasification system or sulfur removal and recovery system

are not operated due to maintenance, malfunction, or emergency situations. Natural gas may be fired at any time, as long

as the annual usage does not exceed the operating limits in subsection 1.c.

b) See Section E for further requirements.
 

                                                                                               Page 16
 

Permit Number: V-00-049

                            Page 14 of  50

SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE

REGULATIONS, AND OPERATING CONDITIONS (CONTINUED)

Emissions Unit: 03 (02) - Flare

Description:

Construction commenced: expected Summer 2001

Steam-assisted flare, 150 SCF/hr natural gas for pilot flame
 
 

Applicable Regulations:

Regulation 401 KAR 63:015, Flares

Regulation 401 KAR 51:017, Prevention of significant deterioration of air quality

1.

Operating Limitations:

           None.

2.

Emission Limitations:

Pursuant to Regulation 401 KAR 63:015, no person shall cause or allow the emission into the open air of particulate

matter from any flare which is greater than twenty (20) percent opacity for more than three (3) minutes in any one (1)

day.

3.

Testing Requirements:

            None.

4.

Specific Monitoring Requirements:

The permittee shall perform a qualitative visual observation of the opacity of emissions from the flare on a weekly basis

and during the occurrence of any syngas flaring and maintain a log of the observations.  If visible emissions from the flare

are perceived or believed to exceed the applicable standard, the permittee shall determine the opacity of emissions by

Reference Method 9 and initiate an inspection of the flare and the entire process making any necessary repairs.

5.

Specific Recordkeeping Requirements:

            None.

6.

Specific Reporting Requirements:

           None.

7.

Specific Control Equipment Operating Conditions:

Pursuant to Regulation 401 KAR 51:017, Prevention of significant deterioration of air quality, the permittee shall comply

with best available control technology with use of use of low ash/low sulfur natural gas fuel and good flare design.
 

                                                                                               Page 17
 

Permit Number: V-00-049

                            Page 15 of  50

SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,

AND OPERATING CONDITIONS (CONTINUED)

Emissions Unit: 04 (04) - Briquette Handling Operations

Description:

Construction commenced: expected Summer 2001

Rated capacity: 5000 tons/day

Units

Briquette delivery by rapid dump railcar (12 hours/day)

Conveyor transfer to storage area (12 hours/day)

Conveyor and transfer points (two), (continuous)

Conveyor drop of briquettes into gasifier hopper (continuous)
 
 

Applicable Regulations:

Regulation 401 KAR 63:010, Fugitive emissions, and

Regulation 401 KAR 51:017, Prevention of significant deterioration of air quality

Applicable Requirements

a) Pursuant to Regulation 401 KAR 63:010, Section 3, reasonable precautions shall be taken to prevent particulate

matter from becoming airborne.  Such reasonable precautions shall include, when applicable, but not be limited to the

following:

1.

Application and maintenance of asphalt, application of water, or suitable chemicals on roads, material

stockpiles, and other surfaces which can create airborne dusts;

2.

Installation and use of hoods, fans, and fabric filters to enclose and vent the handling of dusty materials,

or the use of water sprays or other measures to suppress the dust emissions during handling.

b)       Pursuant to Regulation 401 KAR 63:010, Section 3, discharge of visible fugitive dust emissions beyond the

property line is prohibited.

1.

Operating Limitations:

Pursuant to Regulation 401 KAR 51:017, The "rapid railcar dump and the conveyor transfer to storage area" equipment

shall be operated no more than 12 hours/day (weekly average). This limitation is required to ensure the air quality impact

is below the significant impact level and a full impact analysis will be required to increase this limit.

2.

Emission Limitations:

            None.

3.

Testing Requirements:

            None.
 

                                                                                               Page 18
 

Permit Number: V-00-049

                            Page 16 of  50

SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,

AND OPERATING CONDITIONS (CONTINUED)

4.

Specific Monitoring Requirements:

a) The permittee shall monitor/record the hours of operation of the equipment specified in the description.

b) The permittee shall monitor/record the weight of briquettes handled on a weekly basis.

5.

Specific Recordkeeping Requirements:

The permittee shall maintain records of weekly briquettes processed, the weight of materials handled, and weekly hours

of operation.  The record shall be maintained on site and made available for inspection by authorized personnel from the

Division.

6.

Specific Reporting Requirements:

            See Section F.

7.

Specific Control Equipment Operating Conditions:

Pursuant to Regulation 401 KAR 51:017, Prevention of significant deterioration of air quality, the permittee shall comply

with best available control technology with use of enclosures and good operating practices.
 

                                                                                               Page 19
 

Permit Number: V-00-049

                            Page 17 of  50

SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,

AND OPERATING CONDITIONS (CONTINUED)

Emissions Unit: 05 (05) - Vitrified Frit Handling Operations

Description:

Construction commenced: expected Summer 2001

Rated capacity: 500 tons/day

Units

Dump from gasifier to conveyor

Transfer to storage pile

Transfer point

Load into railcar (2 hours/day)
 
 

Applicable Regulations:

Regulation 401 KAR 63:010, Fugitive emissions, and

Regulation 401 KAR 51:017, Prevention of significant deterioration of air quality

Regulation 401 KAR 60:005, incorporating by reference 40 CFR 60 Subpart Eb, Standards of Performance for Large

Municipal Waste Combustors for which Construction is Commenced After September 20, 1994 or for Which

Modification or Reconstruction is Commenced After June 19, 1996

Applicable Requirements

a) Pursuant to Regulation 401 KAR 63:010, Section 3, reasonable precautions shall be taken to prevent particulate

matter from becoming airborne.  Such reasonable precautions shall include, when applicable, but not be limited to the

following:

1.  Application and maintenance of asphalt, application of water, or suitable chemicals on roads, material stockpiles, and

other surfaces which can create airborne dusts;

2.  Installation and use of hoods, fans, and fabric filters to enclose and vent the handling of dusty materials, or the use

of water sprays or other measures to suppress the dust emissions during handling.

b)  Pursuant to Regulation 401 KAR 63:010, Section 3, discharge of visible fugitive dust emissions beyond the property

line is prohibited.

1.

Operating Limitations:

Pursuant to Regulation 401 KAR 51:017, The "vitrified frit load into railcar" equipment shall be operated no more than

2 hours/day (weekly average).  This limitation is required to ensure the air quality impact is below the significant impact

level and a full impact analysis will be required to increase this limit.
 

                                                                                               Page 20
 

Permit Number: V-00-049

                            Page 18 of  50

SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,

AND OPERATING CONDITIONS (CONTINUED)

2.

Emission Limitations:

a. Pursuant to Regulation 40 CFR 60.55b, there shall be no discharge of visible emissions from conveying systems

(including transfer points) in excess of 5% of the observation period (i.e., 9 minutes per 3-hour period) as determined

by EPA Reference Method 22.

b. Pursuant to 40 CFR 60.55b(b) and (c), the emission limit listed above does not cover visible emissions discharged

inside buildings or enclosures; however the emissions limit does cover visible emissions discharged to the atmosphere

from buildings or enclosures. The limit listed in section 2.b above does not apply during maintenance of the conveying

system.

3.

Testing Requirements:

Pursuant to Regulation 40 CFR 60.55b, the owner or operator shall conduct initial and annual performance tests for

fugitive particulate emissions using EPA Reference Method 22 or an alternate reference test method approved by the

Division, in accordance with General Condition G(d)(5). The minimum observation time shall be a series of three 1-hour

observations. The observation period shall include times when the facility is transferring frit from the gasification unit to

the storage area. The average duration of visible emissions per hour shall be calculated from the three 1-hour

observations. The average shall be used to determine compliance with 40 CFR 60.55b.

4.

Specific Monitoring Requirements:

a) The permittee shall monitor/record the hours of operation of the equipment specified in the description.

b) The permittee shall monitor/record the weight of vitrified frit handled on a weekly basis.

5.

Specific Recordkeeping Requirements:

The permittee shall maintain records of weekly vitrified frit processed, the weight of materials handled, and weekly hours

of operation.  The record shall be maintained on site and made available for inspection by authorized personnel from the

Division.

6.

Specific Reporting Requirements:

           See Section F.

7.

Specific Control Equipment Operating Conditions:

Pursuant to Regulation 401 KAR 51:017, Prevention of significant deterioration of air quality, the permittee shall comply

with best available control technology with use of enclosures and good operating practices.
 

                                                                                               Page 21
 

Permit Number: V-00-049

                            Page 19 of  50

SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,

AND OPERATING CONDITIONS (CONTINUED)

Emissions Unit: 06 (06) - Limestone Material Silo Loading

Description:

Construction commenced: Expected Summer 2001

Rated capacity: 135 tons/day

Control equipment: filter

Units

Limestone transfer to silo (one hour/day, weekly average)
 
 

Applicable Regulations:

Regulation 401 KAR 59:010, New process operations, and

Regulation 401 KAR 51:017, Prevention of significant deterioration of air quality

1.

Operating Limitations:

Pursuant to Regulation 401 KAR 51:017, the "limestone transfer to silo" unit shall be operated no more than one (1)

hour/day (weekly average).  This limitation is required to ensure the air quality impact is below the significant impact level

and a full impact analysis will be required to increase this limit.

2.

Emission Limitations:

a) Pursuant to Regulation 401 KAR 51:017, and pursuant to Regulation 401 KAR 59:010, Section 3(2), particulate

matter emissions into the open air shall not exceed 0.02 lb/hour. Compliance with the allowable particulate standard may

be demonstrated by calculating particulate emissions using the following formula:

PM emissions (lbs/hour) from silo loading  = (U.S. EPA approved or AP-42 emission factor with filter efficiency factored

in: 0.001 lb/ton)(silo loading rate in tons/hr).

b) Pursuant to Regulation 401 KAR 59:010, Section 3(1)(a) visible emissions shall not equal or exceed twenty (20)

percent opacity based on a six-minute average.

3.

Testing Requirements:

           None.

4.

Specific Monitoring Requirements:

a) The permittee shall monitor/record the hours of operation of the units specified in the description.

b) The permittee shall monitor/record the weight of limestone handled on a weekly basis.
 

                                                                                               Page 22
 

Permit Number: V-00-049

                            Page 20 of  50

SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,

AND OPERATING CONDITIONS (CONTINUED)

c) The permittee shall perform a qualitative visual observation of the opacity of emissions from control equipment on a

daily basis and maintain a log of the observations.  If visible emissions from any control equipment are perceived or

believed to exceed the applicable standard, the permittee shall determine the opacity of emissions by Reference Method

9 and initiate an inspection of the control equipment making any necessary repairs.

5.

Specific Recordkeeping Requirements:

a) The permittee shall maintain records of weekly limestone processed, the weight of materials handled, and weekly hours

of operation.  The record shall be maintained on site and made available for inspection by authorized personnel from the

Division.

b) The permittee shall calculate and maintain records of such calculations to assure compliance with the hourly emission

limitations for the limestone.

6.

Specific Reporting Requirements:

            See Section F.

7.

Specific Control Equipment Operating Conditions:

Pursuant to Regulation 401 KAR 51:017, Prevention of significant deterioration of air quality, the permittee shall comply

with best available control technology with use of a high efficiency filter unit and good operating practices.
 

                                                                                               Page 23
 

Permit Number: V-00-049

                            Page 21 of  50

SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE

REGULATIONS, AND OPERATING CONDITIONS (CONTINUED)

Emissions Unit: 07 (07) - Limestone Handling Operations

Description:

Construction commenced: Expected Summer 2001

Rated capacity: 135 tons/day

Control equipment: Enclosures

Units

Transfer out of silo, (continuous)

Transfer to gasifier hopper (continuous)
 
 

Applicable Regulations:

Regulation 401 KAR 63:010, Fugitive emissions, and

Regulation 401 KAR 51:017, Prevention of significant deterioration of air quality

Applicable Requirements

a) Pursuant to Regulation 401 KAR 63:010, Section 3, reasonable precautions shall be taken to prevent particulate

matter from becoming airborne.  Such reasonable precautions shall include, when applicable, but not be limited to the

following:

1.

Application and maintenance of asphalt, application of water, or suitable chemicals on roads, material stockpiles,

and other surfaces which can create airborne dusts;

2.

Installation and use of hoods, fans, and fabric filters to enclose and vent the handling of dusty materials, or the

use of water sprays or other measures to suppress the dust emissions during handling.

b)       Pursuant to Regulation 401 KAR 63:010, Section 3, discharge of visible fugitive dust emissions beyond the

property line is prohibited.

1.

Operating Limitations:

            None.

2.

Emission Limitations:

            None.

3.

Testing Requirements:

            None.

4.

Specific Monitoring Requirements:

            None.
 

                                                                                               Page 24
 

Permit Number: V-00-049

                            Page 22 of  50

SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,

AND OPERATING CONDITIONS (CONTINUED)

5.

Specific Recordkeeping Requirements:

            None.

6.

Specific Reporting Requirements:

            See Section F.

7.

Specific Control Equipment Operating Conditions:

Pursuant to Regulation 401 KAR 51:017, Prevention of significant deterioration of air quality, particulate emissions shall

be controlled by partial enclosures.
 

                                                                                               Page 25
 

Permit Number: V-00-049

                            Page 23 of  50

SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,

AND OPERATING CONDITIONS (CONTINUED)

Emissions Unit: 08 (08) - Pet Coke Silo Loading

Description:

Construction commenced: Expected Summer 2001

Rated capacity: 60 tons/startup, 12 startups per year (initial Global estimate)

Control equipment: Filter

Pet coke transfer to silo
 
 

Applicable Regulations:

Regulation 401 KAR 59:010, New process operations, and

Regulation 401 KAR 51:017, Prevention of significant deterioration of air quality

1.

Operating Limitations:

Pursuant to Regulation 401 KAR 51:017, The pet coke silo loading units shall only be operated associated with the 12

startups per year.  This limitation is required to ensure the air quality impact is below the significant impact level and a

full impact analysis will be required to increase this limit.

2.

Emission Limitations:

a) Pursuant to Regulation 401 KAR 51:017, and pursuant to Regulation 401 KAR 59:010, Section 3(2), particulate

matter emissions into the open air shall not exceed 0.48 lb/hour. Compliance with the allowable particulate standard may

be demonstrated by calculating particulate emissions using the following formula:

PM emissions (lbs/hour) from silo loading = (U.S. EPA approved or AP-42 emission factor with filter efficiency factored

in: 0.002 lb/ton)(silo loading rate in tons/hr).

b) Pursuant to Regulation 401 KAR 59:010, Section 3(1)(a) visible emissions shall not equal or exceed twenty (20)

percent opacity based on a six-minute average.

3.

Testing Requirements:

            None.

4.

Specific Monitoring Requirements:

a) The permittee shall monitor/record the hours of operation of the units specified in the description.

b) The permittee shall monitor/record the weight of pet coke handled on a weekly basis.
 

                                                                                               Page 26
 

Permit Number: V-00-049

                            Page 24 of  50

SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,

AND OPERATING CONDITIONS (CONTINUED)

c) The permittee shall perform a qualitative visual observation of the opacity of emissions from control equipment at least

once during each material transfer event or operation and maintain a log of the observations.  If visible emissions from

any control equipment are perceived or believed to exceed the applicable standard, the permittee shall determine the

opacity of emissions by Reference Method 9 and initiate an inspection of the control equipment making any necessary

repairs.

5.

Specific Recordkeeping Requirements:

a) The permittee shall maintain records of monthly pet coke processed, the weight of materials handled, and monthly

hours of operation.  The record shall be maintained on site and made available for inspection by authorized personnel

from the Division.

b) The permittee shall calculate and maintain records of such calculations to assure compliance with the hourly emission

limitations for the pet coke.

6.

Specific Reporting Requirements:

            See Section F.

7.

Specific Control Equipment Operating Conditions:

Pursuant to Regulation 401 KAR 51:017, Prevention of significant deterioration of air quality, the permittee shall comply

with best available control technology with use of a high efficiency filter unit and good operating practices.
 

                                                                                               Page 27
 

Permit Number: V-00-049

                            Page 25 of  50

SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,

AND OPERATING CONDITIONS (CONTINUED)

Emissions Unit: 09 (09) - Pet Coke Material Handling

Description:

Construction commenced: Expected Summer 2001

Rated capacity: 240 tons/day

Control equipment: Enclosures

Units

Transfer out of silo, (continuous)

Transfer to gasifier hopper (continuous)
 
 

Applicable Regulations:

Regulation 401 KAR 63:010, Fugitive emissions, and

Regulation 401 KAR 51:017, Prevention of significant deterioration of air quality

Applicable Requirements

a) Pursuant to Regulation 401 KAR 63:010, Section 3, reasonable precautions shall be taken to prevent particulate

matter from becoming airborne.  Such reasonable precautions shall include, when applicable, but not be limited to the

following:

1.

Application and maintenance of asphalt, application of water, or suitable chemicals on roads, material stockpiles,

and other surfaces which can create airborne dusts;

2.

Installation and use of hoods, fans, and fabric filters to enclose and vent the handling of dusty materials, or the

use of water sprays or other measures to suppress the dust emissions during handling.

b)       Pursuant to Regulation 401 KAR 63:010, Section 3, discharge of visible fugitive dust emissions beyond the

property line is prohibited.

1.

Operating Limitations:

            None

2.

Emission Limitations:

            None.

3.

Testing Requirements:

            None.

4.

Specific Monitoring Requirements:

            None.
 

                                                                                               Page 28
 

Permit Number: V-00-049

                            Page 26 of  50

SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,

AND OPERATING CONDITIONS (CONTINUED)

5.

Specific Recordkeeping Requirements:

            None.

6.

Specific Reporting Requirements:

           See Section F.

7.

Specific Control Equipment Operating Conditions:

Pursuant to Regulation 401 KAR 51:017, Prevention of significant deterioration of air quality, particulate emissions shall

be controlled by partial enclosures.
 

                                                                                               Page 29
 

Permit Number: V-00-049

                            Page 27 of  50

SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,

AND OPERATING CONDITIONS (CONTINUED)

Emissions Unit: 10 (-) - Sulfur Recovery Operations and Sulfur Loading & Storage Operations

Description:

Construction commenced: Expected Summer 2001

Rated capacity: 3.1 Tons/hour

Unit

Sulfur recovery unit - 99.9 % recovery
 
 

Applicable Regulations:

Regulation 401 KAR 59:105, New process gas streams, and

Regulation 401 KAR 51:017, Prevention of significant deterioration of air quality

1.

Operating Limitations:

At all times during normal operation (non-emergency situations), the gas cleanup with specialty amine solvent scrubbing

and Claus process sulfur recovery with closed loop tailgas recycle, shall be operated in accordance with design

specifications and/or good engineering practices.

2.

Emission Limitations:

Pursuant to Regulation 401 KAR 59:105, Section 3, for sources whose combined process gas stream emission rate

totals less than two (2) tons per day of hydrogen sulfide (for example, KY Pioneer sulfur recovery process emissions

potential emissions equal 0.108 tons/year, reference application log G364 Appendix A, page 5 of 13, 11/12/1999) the

permittee shall either reduce such emissions by eighty-five (85) percent or control such emissions such that hydrogen

sulfide in the gas stream emitted into the ambient air does not exceed ten (10) grains per 100 dscf (165 ppm by volume)

at zero percent oxygen.

3.

Testing Requirements:

Pursuant to Regulation 401 KAR 59:105, Section 6, an initial performance test to demonstrate compliance with the

hydrogen sulfide emission limitation requirement in Subsection 2 shall be conducted according to Reference Method 11.

The sample shall be drawn from a point near the centroid of the gas line.  The minimum sampling time shall be ten (10)

minutes and the minimum sample volume shall be 0.01 dscm (0.35 dscf) for each sample. The arithmetic average of two

(2) samples shall constitute one (1) run.  Samples shall be taken at approximately one (1) hour intervals.
 

                                                                                               Page 30
 

Permit Number: V-00-049

                            Page 28 of  50

SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,

AND OPERATING CONDITIONS (CONTINUED)

4.

Specific Monitoring Requirements:

a) The permittee shall monitor/record the hours of operation of the units specified in the description.

b) The permittee shall monitor/record the weight of sulfur produced on a weekly basis.

c) The permittee shall monitor/record the amount of sulfur produced, and assure the calculated sulfur production rate,

as determined from weekly data, does not exceed the maximum production rate of sulfur from which resulting hydrogen

sulfide emission levels are shown to assure compliance as demonstrated during the performance test.

5.

Specific Recordkeeping Requirements:

a) The permittee shall maintain records of weekly sulfur produced, the weight of sulfur handled, and weekly hours of

operation.  The record shall be maintained on site and made available for inspection by authorized personnel from the

Division.

b) The permittee shall calculate and maintain records of such calculations to assure compliance with the hydrogen sulfide

emission limitation.  The calculations shall be performed weekly with use of the weekly sulfur production rate, based on

the weight of sulfur and hours of operation per week, emission factors as determined from the hydrogen sulfide

performance test required as specified in Subsection 3, Testing Requirements.

6.

Specific Reporting Requirements:

           See Section F.

7.

Specific Control Equipment Operating Conditions:

Pursuant to Regulation 401 KAR 51:017, Prevention of significant deterioration of air quality, the permittee shall comply

with best available control technology with use of a high efficiency filter unit and good operating practices.
 

                                                                                               Page 31
 

Permit Number: V-00-049

                            Page 29 of  50

SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,

AND OPERATING CONDITIONS (CONTINUED)

Emissions Unit: 11 (10) - Cooling Tower

Description:

Construction commenced: Expected Summer 2001

Rated capacity: 20,000 gallons/minute

Control equipment: high efficiency mist eliminators
 
 

Applicable Regulations:

Regulation 401 KAR 63:010, Fugitive emissions, and

Regulation 401 KAR 51:017, Prevention of significant deterioration of air quality

Applicable Requirements

a) Pursuant to Regulation 401 KAR 63:010, Section 3, reasonable precautions shall be taken to prevent particulate

matter from becoming airborne.

b) Pursuant to Regulation 401 KAR 63:010, Section 3, discharge of visible fugitive dust emissions beyond the property

line is prohibited.

1.

Operating Limitations:

            None.

2.

Emission Limitations:

a) Pursuant to Regulation 401 KAR 51:017, emissions of particulate matter shall not exceed 1.5 lb/hour. Compliance

with the allowable particulate standard may be demonstrated by calculating particulate emissions using the following

formula:

b) PM emissions (lbs/hour) from cooling tower = (U.S. EPA approved or AP-42 emission factor with filter efficiency

factored in: 1.25xE-6 lb/gallon)(circulation rate in gallons/hr).

3.

Testing Requirements:

            None.

4.

Specific Monitoring Requirements:

The permittee shall monitor the circulation rate on a daily basis.

5.

Specific Recordkeeping Requirements:

a) The permittee shall keep records of the circulation rate on a daily basis.

b) The permittee shall calculate and maintain records of such calculations to assure compliance with the particulate

matter emission limitation.
 

                                                                                               Page 32
 

Permit Number: V-00-049

                            Page 30 of  50

SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,

AND OPERATING CONDITIONS (CONTINUED)

6.

Specific Reporting Requirements:

            See Section F.

7.

Specific Control Equipment Operating Conditions:

Pursuant to Regulation 401 KAR 51:017, particulate emissions shall be controlled by high efficiency mist eliminators.
 

                                                                                               Page 33
 

Permit Number: V-00-049

                            Page 31 of  50

SECTION B - EMISSION POINTS, EMISSIONS UNITS, APPLICABLE REGULATIONS,

AND OPERATING CONDITIONS (CONTINUED)

Emissions Unit: 12 (11) - Wastewater Treatment

Description:

Construction commenced: Expected Summer 2001

Rated capacity: 100,000 gallons/day
 
 

Applicable Regulations:

Regulation 401 KAR 51:017, Prevention of significant deterioration of air quality

1.

Operating Limitations:

            None.

2.

Emission Limitations:

            None.

3.

Testing Requirements:

            None.

4.

Specific Monitoring Requirements:

The permittee shall monitor amount of wastewater discharged on a daily basis.

5.

Specific Recordkeeping Requirements:

a) The permittee shall maintain records of wastewater discharged on a daily basis.

b) The permittee shall maintain records of wastewater treatment design and

engineering estimates of average free-phase VOC concentrations.

6.

Specific Reporting Requirements:

            See Section F.

7.

Specific Control Equipment Operating Conditions:

Pursuant to Regulation 401 KAR 51:017, Prevention of significant deterioration of air quality, VOC emissions shall be

controlled by enclosed piping and storage of wastewater streams with flows greater than 1 liter per minute (annual

average) and VOC concentrations greater than 1% by weight (annual average).
 

                                                                                               Page 34
 

Permit Number: V-00-049

                            Page 32 of  50

SECTION C - INSIGNIFICANT ACTIVITIES

The following listed activities have been determined to be insignificant activities for this source pursuant to 401 KAR

50:035, Section 5(4).  While these activities are designated as insignificant the permittee must comply with the applicable

regulation and some minimal level of periodic monitoring may be necessary.

Description

Generally Applicable Regulation

1.

Emergency diesel electric generator

NA

2.

Fuel cell

NA
 

                                                                                               Page 35
 

Permit Number: V-00-049

                            Page 33 of  50

SECTION D - SOURCE EMISSION LIMITATIONS AND TESTING REQUIREMENTS

1.

Nitrogen oxide, carbon monoxide, sulfur dioxide, particulate, volatile organic compounds, beryllium, cadmium,

lead, mercury, hydrogen chloride, and dioxins/furans emissions, as measured by methods referenced in 401

KAR 50:015, Section 1, shall not exceed the respective limitations specified herein.

2.

Compliance with annual emissions and processing limitations imposed pursuant to 401 KAR 50:035, Section

7(1)(a), and contained in this permit, shall be based on emissions and processing rates for any twelve (12)

consecutive months.

3.

Between 18 to 24 months after startup , the permitee shall submit to the Division for Air quality a NOx BACT

determination as if it was a new source, using the data gathered on this facility, other similar facilities, and the

equipment manufacturer's research. The Division will make a determination on BACT for NOx  only, require

control equipment based on the BACT analysis, and adjust the NOx  emission limits accordingly.
 

                                                                                               Page 36
 

Permit Number: V-00-049

                            Page 34 of  50

SECTION E - SOURCE CONTROL EQUIPMENT REQUIREMENTS

Pursuant to 401 KAR 50:055, Section 2(5), at all times, including periods of startup, shutdown and malfunction, owners

and operators shall, to the extent practicable, maintain and operate any affected facility including associated air pollution

control equipment in a manner consistent with good air pollution control practice for minimizing emissions.  Determination

of whether acceptable operating and maintenance procedures are being used will be based on information available to

the division which may include, but is not limited to, monitoring results, opacity observations, review of operating and

maintenance procedures, and inspection of the source.
 

                                                                                               Page 37
 

Permit Number: V-00-049

                            Page 35 of  50

SECTION F - MONITORING, RECORD KEEPING, AND REPORTING REQUIREMENTS

1.

When continuing compliance is demonstrated by periodic testing or instrumental monitoring, the permittee shall

compile records of required monitoring information that include:

a.

Date, place as defined in this permit, and time of sampling or measurements.

b.

Analyses performance dates;

c.

Company or entity that performed analyses;

d.

Analytical techniques or methods used;

e.

Analyses results; and

f.

Operating conditions during time of sampling or measurement;

2.

Records of all required monitoring data and support information, including calibrations, maintenance records,

and original strip chart recordings, and copies of all reports required by the Division for Air Quality, shall be

retained by the permittee for a period of five years and shall be made available for inspection upon request by

any duly authorized representative of the Division for Air Quality. [401 KAR 50:035, Permits, Section 7(1)(d)2

and 401 KAR 50:035, Permits, Section 7(2)(c)]

3.

In accordance with the requirements of 401 KAR 50:035, Permits, Section 7(2)(c) the permittee shall allow the

Cabinet or authorized representatives to perform the following:

a.

Enter upon the premises where a source is located or emissions-related activity is conducted, or where

records are kept;

b.

Have access to and copy, at reasonable times, any records required by the permit:

i.

During normal office hours, and

ii.

During periods of emergency when prompt access to records is essential to proper  assessment

by the Cabinet;

c.

Inspect, at reasonable times, any  facilities, equipment (including monitoring and pollution control

equipment), practices, or operations required by the permit.  Reasonable times shall include, but are not

limited to the following:

i.

During all hours of operation at the source,

ii.

For all sources operated intermittently, during all hours of operation at the source and the hours

between 8:00 a.m. and 4:30 p.m., Monday through Friday, excluding holidays, and

iii.

During an emergency; and

d.

Sample or monitor, at reasonable times, substances or parameters to assure compliance with the permit

or any applicable requirements.  Reasonable times shall include, but are not limited to the following:

i.

During all hours of operation at the source,

ii.

For all sources operated intermittently, during all hours of operation at the source and the hours

between 8:00 a.m. and 4:30 p.m., Monday through Friday, excluding holidays, and

iii.

During an emergency.

4.

No person shall obstruct, hamper, or interfere with any Cabinet employee or authorized representative while in

the process of carrying out official duties.  Refusal of entry or access may constitute grounds for permit

revocation and assessment of civil penalties.
 

                                                                                               Page 38
 

Permit Number: V-00-049

                            Page 36 of  50

SECTION F - MONITORING, RECORD KEEPING, AND REPORTING REQUIREMENTS

(CONTINUED)

5.

Summary reports of any monitoring required by this permit, other than continuous emission or opacity monitors,

shall be submitted to the division's Frankfort Regional Office at least every six (6) months during the life of this

permit, unless otherwise stated in this permit. For emission units that were still under construction or which had

not commenced operation at the end of the 6-month period covered by the report and are subject to monitoring

requirements in this permit, the report shall indicate that no monitoring was performed during the previous six

months because the emission unit was not in operation.

The reports are due within 30 days after the end of each six-month reporting period that commences on the initial

issuance date of this permit.  The permittee may shift to semi-annual reporting on a calendar year basis upon

approval of the regional office.  If calendar year reporting is approved, the semi-annual reports are due January

30th and July 30th of each year.  Data from the continuous emission and opacity monitors shall be reported to

the Technical Services Branch in accordance with the requirements of 401 KAR 59:005, General Provisions,

Section 3(3).  All reports shall be certified by a responsible official pursuant to Section 6(1) of 401 KAR

50:035, Permits.  All deviations from permit requirements shall be clearly identified in the reports.

6.

a.

In accordance with the provisions of 401 KAR 50:055, Section 1 the owner or operator shall notify the

Division for Air Quality's Frankfort Regional Office concerning startups, shutdowns, or malfunctions as

follows:

1.

When emissions during any planned shutdowns and ensuing startups will exceed the standards

notification shall be made no later than three (3) days before the planned shutdown, or

immediately following the decision to shut down, if the shutdown is due to events which could

not have been foreseen three (3) days before the shutdown.

2.

When emissions due to malfunctions, unplanned shutdowns and ensuing startups are or may be

in excess of the standards notification shall be made as promptly as possible by telephone (or

other electronic media) and shall cause written notice upon request.

b.

In accordance with the provisions of 401 KAR 50:035, Section 7(1)(e)2, the owner or operator shall

report emission related exceedances from permit requirements including those attributed to upset

conditions (other than emission exceedances covered by general condition 6 a. above) to the Division

for Air Quality's Frankfort Regional Office within 30 days.  Other deviations from permit requirements

shall be included in the semiannual report required by general condition F.5.
 

                                                                                               Page 39
 

Permit Number: V-00-049

                            Page 37 of  50

SECTION F - MONITORING, RECORD KEEPING, AND REPORTING REQUIREMENTS

(CONTINUED)

7.

Pursuant to 401 KAR 50:035, Permits, Section 7(2)(b), the permittee shall certify compliance with the terms

and conditions contained in this permit, annually on the permit issuance anniversary date or by January 30th of

each year if calendar year reporting is approved by the regional office, by completing and returning a Compliance

Certification Form (DEP 7007CC) (or an approved alternative) to the Division for Air Quality's Frankfort

Regional Office and the U.S. EPA  in accordance with the following requirements:

a.

Identification of each term or condition of the permit that is the basis of the certification;

b.

The compliance status regarding each term or condition of the permit;

c.

Whether compliance was continuous or intermittent; and

d.

The method used for determining the compliance status for the source, currently and over the reporting

period, pursuant to 401 KAR 50:035, Section 7(1)(c),(d), and (e).

e.

For an emissions unit that was still under construction or which has not commenced operation at the end

of the 12-month period covered by the annual compliance certification, the permittee shall indicate that

the unit is under construction and that compliance with any applicable requirements will be demonstrated

within the timeframes specified in the permit.

f.

The certification shall be postmarked by the thirtieth (30) day following the applicable permit issuance

anniversary date, or by January 30th of each year if calendar year reporting is approved by the regional

office.

  Annual compliance certifications should be mailed to the following addresses:

Division for Air Quality

U.S. EPA Region IV

Frankfort Regional Office

Air Enforcement Branch

643 Teton Trail, Suite B

Atlanta Federal Center

Frankfort, KY 40601-1758

61 Forsyth St.

Atlanta, GA 30303-8960

Division for Air Quality

Central Files

803 Schenkel Lane

Frankfort, KY 40601

8.

In accordance with 401 KAR 50:035, Section 23, the permittee shall  provide the division with all information

necessary to determine its subject emissions within thirty (30) days of the date the KEIS emission report is

mailed to the permittee.

9.

Pursuant to Section VII.3 of the policy manual of the Division for Air Quality as referenced by 401 KAR 50:016,

Section 1(1), results of performance test(s) required by the permit shall be submitted to the Division by the

source or its representative within forty-five days after the completion of the fieldwork.
 

                                                                                               Page 40
 

Permit Number: V-00-049

                            Page 38 of  50

SECTION G - GENERAL CONDITIONS

(a)

General Compliance Requirements

1.

The permittee shall comply with all conditions of this permit.  A noncompliance shall be (a) violation(s) of 401

KAR 50:035, Permits, Section 7(3)(d)
 
 

and Federal Statute 42 USC 7401 through 7671q
 
 

and is grounds for

enforcement action including but not limited to the termination, revocation and reissuance, or revision of this

permit.

2.

The filing of a request by the permittee for any permit revision, revocation, reissuance, or termination, or of a

notification of a planned change or anticipated noncompliance, shall not stay any permit condition.

3.

This permit may be revised, revoked, reopened and reissued, or terminated for cause.  The permit will be

reopened for cause and revised accordingly under the following circumstances:

a.

If additional applicable requirements become applicable to the source and the remaining permit term is

three (3) years or longer.  In this case, the reopening shall be completed no later than eighteen (18)

months after promulgation of the applicable requirement.  A reopening shall not be required if compliance

with the applicable requirement is not required until after the date on which the permit is due to expire,

unless this permit or any of its terms and conditions have been extended pursuant to 401 KAR 50:035,

Section 12(2)(c);

b.

The Cabinet
 
 

or the U. S. EPA determines that the permit must be revised or revoked to assure

compliance with the applicable requirements;

c.

The Cabinet or the U. S. EPA
 
 

determines that the permit contains a material mistake or that inaccurate

statements were made in establishing the emissions standards or other terms or conditions of the permit;

d.

If any additional applicable requirements of the Acid Rain Program become applicable to the source.

Proceedings to reopen and reissue a permit shall follow the same procedures as apply to initial permit issuance

and shall affect only those parts of the permit for which cause to reopen exists.  Reopenings shall be made as

expeditiously as practicable.  Reopenings shall not be initiated before a notice of intent to reopen is provided to

the source by the division, at least thirty (30) days in advance of the date the permit is to be reopened, except

that the Division may provide a shorter time period in the case of an emergency.

4.

The permittee shall furnish to the Division, in writing, information that the division may request to determine

whether cause exists for modifying, revoking and reissuing, or terminating the permit, or to determine compliance

with the permit. [401 KAR 50:035, Permits, Section 7(2)(b)3e and 401 KAR 50:035, Permits, Section 7(3)(j)]

5.

The permittee, upon becoming aware that any relevant facts were omitted or incorrect information was submitted

in the permit application, shall promptly submit such supplementary facts or corrected information to the

permitting authority.
 

                                                                                               Page 41
 

Permit Number: V-00-049

                            Page 39 of  50

SECTION G - GENERAL CONDITIONS (CONTINUED)

6.

Any condition or portion of this permit which becomes suspended or is ruled invalid as a result of any legal or

other action shall not invalidate any other portion or condition of this permit. [401 KAR 50:035, Permits, Section

7(3)(k)]

7.

The permittee shall not use as a defense in an enforcement action the contention that it would have been

necessary to halt or reduce the permitted activity in order to maintain compliance. [401 KAR 50:035, Permits,

Section 7(3)(e)]

8.

Except as identified as state-origin requirements in this permit, all terms and conditions contained herein shall be

enforceable by the United States Environmental Protection Agency and citizens of the United States.

9.

This permit shall be subject to suspension if the permittee fails to pay all emissions fees within 90 days after the

date of notice as specified in  401 KAR 50:038, Section 3(6). [401 KAR 50:035, Permits, Section 7(3)(h)]

10.

Nothing in this permit shall alter or affect the liability of the permittee for any violation of applicable requirements

prior to or at the time of permit issuance. [401 KAR 50:035, Permits, Section 8(3)(b)]

11.

This permit shall not convey property rights or exclusive privileges. [401 KAR 50:035, Permits, Section 7 (3)(g)]

12.

Issuance of this permit does not relieve the permittee from the responsibility of obtaining any other permits,

licenses, or approvals required by the Kentucky Cabinet for Natural Resources and Environmental Protection

or any other federal, state, or local agency.

13.

Nothing in this permit shall alter or affect the authority of U.S. EPA to obtain information pursuant to Federal

Statute 42 USC 7414, Inspections, monitoring, and entry. [401 KAR 50:035, Permits, Section 7(2)(b)5]

14.

Nothing in this permit shall alter or affect the authority of U.S. EPA to impose emergency orders pursuant to

Federal Statute 42 USC 7603, Emergency orders. [401 KAR 50:035, Permits, Section 8(3)(a)]

15.

Permit Shield:  Except as provided in 401 KAR 50:035, Permits, compliance by the affected facilities listed

herein with the conditions of this permit shall be deemed to be compliance with all applicable requirements

identified in this permit as of the date of issuance of this permit.

16.

All previously issued construction and operating permits are hereby subsumed into this permit.
 

                                                                                               Page 42
 

Permit Number: V-00-049

                            Page 40 of  50

SECTION G - GENERAL CONDITIONS (CONTINUED)

(b)

Permit Expiration and Reapplication Requirements

This permit shall remain in effect for a fixed term of five (5) years following the original date of issue. Permit expiration

shall terminate the source's right to operate unless a timely and complete renewal application has been submitted to the

division at least six months prior to the expiration date of the permit.  Upon a timely and complete submittal, the

authorization to operate within the terms and conditions of this permit, including any permit shield, shall remain in effect

beyond the expiration date, until the renewal permit is issued or denied by the division. [401 KAR 50:035, Permits,

Section 12]

(c)

Permit Revisions

1.

A minor permit revision procedure may be used for permit revisions involving the use of economic incentive,

marketable permit, emission trading, and other similar approaches, to the extent that these minor permit revision

procedures are explicitly provided for in the SIP or in applicable requirements and meet the relevant

requirements of 401 KAR 50:035, Section 15.

2.

This permit is not transferable by the permittee.  Future owners and operators shall obtain a new permit from

the Division for Air Quality.  The new permit may be processed as an administrative amendment if no other

change in this permit is necessary, and provided that a written agreement containing a specific date for transfer

of permit responsibility coverage and liability between the current and new permittee has been submitted to the

permitting authority thirty (30) days in advance of the transfer.

(d)

Construction, Start-Up, and Initial Compliance Demonstration Requirements

1.

Construction of process and/or air pollution control equipment authorized by this permit shall be conducted and

completed only in compliance with the conditions of this permit.

2.

Within thirty (30) days following commencement of construction, and within fifteen (15) days following start-up,

and attainment of the maximum production rate specified in the permit application, or within fifteen (15) days

following the issuance date of this permit, whichever is later, the permittee shall furnish to the Division for Air

Quality's Frankfort Regional Office in writing, with a copy to the division's Frankfort Central Office, notification

of the following:

a.

The date when construction commenced.

b.

The date of start-up of the affected facilities listed in this permit.

c.

The date when the maximum production rate specified in the permit application was achieved.
 

                                                                                               Page 43
 

Permit Number: V-00-049

                            Page 41 of  50

SECTION G - GENERAL CONDITIONS (CONTINUED)

3.

Pursuant to 401 KAR 50:035, Permits, Section 13(1), unless construction is commenced on or before 18

months after the date of issue of this permit, or if construction is commenced and then stopped for any

consecutive period of 18 months or more, or if construction is not completed within eighteen (18) months of the

scheduled completion date, then the construction and operating authority granted by this permit for those affected

facilities for which construction was not completed shall immediately become invalid.   Extensions of the time

periods specified herein may be granted by the division upon a satisfactory request showing that an extension

is justified.

4.

Operation of the affected facilities for which construction is authorized by this permit shall not commence until

compliance with the applicable standards specified herein has been demonstrated pursuant to 401 KAR 50:055,

except as provided in Section I of this permit.

5.

This permit shall allow time for the initial start-up, operation, and compliance demonstration of the affected

facilities listed herein.  However, within sixty (60) days after achieving the maximum production rate at which the

affected facilities will be operated but not later than 180 days after initial start-up of such facilities, the permittee

shall conduct a performance demonstration on the affected facilities in accordance with 401 KAR 50:055,

General compliance requirements.  These performance tests must also be conducted in accordance with General

Conditions G(d)6 of this permit and the permittee must furnish to the Division for Air Quality's Frankfort Central

Office a written report of the results of such performance test

.

6.

Pursuant to Section VII 2.(1) of the policy manual of the Division for Air Quality as referenced by 401 KAR

50:016, Section 1.(1), at least one month prior to the date of the required performance test, the permittee shall

complete and return a Compliance Test Protocol (Form DEP 6027) to the division's Frankfort Central Office.

 Pursuant to 401 KAR 50:045, Section 5, the division shall be notified of the actual test date at least ten (10)

days prior to the test.

(e)

Acid Rain Program Requirements

If an applicable requirement of Federal Statute 42 USC 7401 through 7671q (the Clean Air Act) is more stringent than

an applicable requirement promulgated pursuant to Federal Statute 42 USC 7651 through 7651o (Title IV of the Act),

both provisions shall apply, and both shall be state and federally enforceable.

(f)

Emergency Provisions

1.

An emergency shall constitute an affirmative defense to an action brought for noncompliance with the technology-

based emission limitations if the permittee demonstrates through properly signed contemporaneous operating logs

or other relevant evidence that:
 

                                                                                               Page 44
 

Permit Number: V-00-049

                            Page 42 of  50

SECTION G - GENERAL CONDITIONS (CONTINUED)

a.

An emergency occurred and the permittee can identify the cause of the emergency;

b.

The permitted facility was at the time being properly operated;

c.

During an emergency, the permittee took all reasonable steps to minimize levels of emissions that

exceeded the emissions standards or other requirements in the permit; and,

d.

The permittee notified the division as promptly as possible and submitted written notice of the emergency

to the division within two working days after the time when emission limitations were exceeded due to

the emergency.  The notice shall meet the requirements of 401 KAR 50:035, Permits, Section 7(1)(e)2,

and include a description of the emergency, steps taken to mitigate emissions, and the corrective actions

taken.  This requirement does not relieve the source of any other local, state or federal notification

requirements.

2.

Emergency conditions listed in General Condition (f)1 above are in addition to any emergency or upset

provision(s) contained in an applicable requirement.

3.

In an enforcement proceeding, the permittee seeking to establish the occurrence of an emergency shall have the

burden of proof.  [401 KAR 50:035, Permits, Section 9(3)]

(g)

Risk Management Provisions

1.

The permittee shall comply with all applicable requirements of 40 CFR Part 68, Risk Management Plan

provisions.  If required, the permittee shall comply with the Risk Management Program and submit a Risk

Management Plan to:

RMP Reporting Center

P.O. Box 3346

Merrifield, VA, 22116-3346

2.

If requested, submit additional relevant information to the division or the U.S. EPA.

(h)

Ozone depleting substances

1.

The permittee shall comply with the standards for recycling and emissions reduction pursuant to 40 CFR 82,

Subpart F, except as provided for Motor Vehicle Air Conditioners (MVACs) in Subpart B:

a.

Persons opening appliances for maintenance, service, repair, or disposal shall comply with the required

practices contained in 40 CFR 82.156.

b.

Equipment used during the maintenance, service, repair, or disposal of appliances shall comply with the

standards for recycling and recovery equipment contained in 40 CFR 82.158.

c.

Persons performing maintenance, service, repair, or disposal of appliances shall be certified by an

approved technician certification program pursuant to 40 CFR 82.161.

d.

Persons disposing of small appliances, MVACs, and MVAC-like appliances (as defined at 40 CFR

82.152) shall comply with the recordkeeping requirements pursuant to 40 CFR 82.166.
 
 
 

                                                                                               Page 45
 

Permit Number: V-00-049

                            Page 43 of  50

SECTION G - GENERAL CONDITIONS (CONTINUED)

e.

Persons owning commercial or industrial process refrigeration equipment shall

comply with the leak repair requirements pursuant to 40 CFR 82.156.

f.

Owners/operators of appliances normally containing 50 or more pounds of refrigerant shall keep records

of refrigerant purchased and added to such appliances pursuant to 40 CFR 82.166.

2.

If the permittee performs service on motor (fleet) vehicle air conditioners containing ozone-depleting substances,

the source shall comply with all applicable requirements as specified in 40 CFR 82, Subpart B, Servicing of

Motor Vehicle Air Conditioners.
 

                                                                                               Page 46
 

Permit Number: V-00-049

                            Page 44 of  50

SECTION H ­ ALTERNATE OPERATING SCENARIOS

Not Applicable

SECTION I ­ COMPLIANCE SCHEDULE

Not Applicable
 

                                                                                               Page 47
 

Permit Number: V-00-049

                            Page 45 of  50

SECTION J ­ ACID RAIN

Commonwealth of Kentucky

Natural Resources and Environmental Protection Cabinet

Department for Environmental Protection

Division for Air Quality

803 Schenkel Lane

Frankfort, Kentucky  40601

(502) 573-3382

PHASE II ACID RAIN PERMIT

Plant Name:

                     Kentucky Pioneer Energy

Plant Location:

12145 Irvine Road, Trapp, Kentucky 40391

Owner:

                              Kentucky Pioneer Energy LLC

Mailing Address:

            312 Walnut Street, Suite 2000, Cincinnati, Ohio 45202

Region:

                            Bluegrass

County:

 Clark

ACID RAIN PERMIT CONTENTS

1)

Statement of Basis

2)

SO

2
 
 

allowances allocated under this permit and NOx
 
 

requirements for each affected unit.

3)

Comments, notes and justifications regarding permit decisions and changes made to the

permit application forms during the review process, and any additional requirements or

conditions.

4)

The permit application submitted for this source.  The owners and operators of the source

must comply with the standard requirements and special provisions set forth in the

Phase II

Application.

5)

Summary of Actions

1.  Statement of Basis:

Statutory and Regulatory Authorities:

  In accordance with KRS 224.10-100 and Titles IV and V of

the Clean Air Act, the Kentucky Natural Resources and Environmental Protection Cabinet, Division for Air

Quality issues this permit pursuant to Regulations 401 KAR 50:035, Permits, 401 KAR 50:072, Acid Rain

Permit, and Federal Regulation 40 CFR Part 76.
 

                                                                                               Page 48
 

Permit Number:

 V-00-049

     Page:

  48

of

  50

PERMIT (Conditions)

Plant Name:

 Kentucky Pioneer Energy

Affected Unit:

01 ­ GT1

2.  SO

2

 Allowance Allocations and NO

x

 Requirements for the affected unit:

Year

SO

2

 Allowances

2001

2002

2003

2004

2005

Tables 2, 3 or 4 of

40 CFR Part 73

0*

0*

0*

0*

0*

NO

x

  Requirements

NO

x

 Limits

N/A**

*

The number of allowances allocated to Phase II affected units by the U.S. EPA may change under

40 CFR part 73. In addition, the number of allowances actually held by an affected source in a unit

account may differ from the number allocated by U. S. EPA. Neither of the aforementioned

conditions necessitate a revision to the unit SO

2

 allowance allocations identified in this permit (See

40 CFR 72.84).

**

This unit currently does not have applicable NO

x

 limits set by 40 CFR, part 76

.
 

                                                                                               Page 49
 

Permit Number:

 V-00-049

     Page:

  49

of

  50

PERMIT (Conditions)

Plant Name:

 Kentucky Pioneer Energy

Affected Unit:

02 ­ GT2

SO

2

 Allowance Allocations and NO

x

 Requirements for the affected unit:

Year

SO

2

 Allowances

2001

2002

2003

2004

2005

Tables 2, 3 or 4 of

40 CFR Part 73

0*

0*

0*

0*

0*

NO

x

  Requirements

NO

x

 Limits

N/A**

*

The number of allowances allocated to Phase II affected units by the U.S. EPA may change under

40 CFR part 73. In addition, the number of allowances actually held by an affected source in a unit

account may differ from the number allocated by U. S. EPA. Neither of the aforementioned

conditions necessitate a revision to the unit SO

2

 allowance allocations identified in this permit (See

40 CFR 72.84).

**

This unit currently does not have applicable NO

x

 limits set by 40 CFR, part 76

.
 

                                                                                               Page 50
 

Permit Number:

 V-00-049

     Page:

  50

of

  50

PERMIT (Conditions)

3.  Comments, Notes, and Justifications:

The two (2) Combined Cycle Combustion Turbines, units 01 and 02 will be constructed after the

SO

2

 allocation date; therefore these units will have no SO

2

 allowances allocated by U.S. EPA and

must obtain SO

2

 allowances through other means.

The two (2) Combined Cycle Combustion Turbines, units 01 and 02 do not have applicable NO

x

limits set by 40 CFR part 76.

4.  Permit Application:

Attached

The Phase II Permit Application is a part of this permit and the source must comply with the

standard requirements and special provisions set forth in the Phase II Application.
 

5.  Summary of Actions:

Past Action:

1. Draft Phase II Permit (# A-00-007) was proposed for public comment.

Present Action:

1. Acid Rain Phase II permit # A-00-007 was included (as Section J) in Title V permit #V-

00-049 and issued as a proposed permit on June 7, 2001.

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http://www.google.com/search?q=cache:u_3_mQpBx1k:www.lanl.gov/projects/cctc/newsletter/documents/00_spr.pdf+vitrified+frit&hl=en

One of the world's pioneering commercial-scale coal gasification-based

power facilities, Wabash River's Integrated Gasification Combined-Cycle

(IGCC) plant, has successfully completed its fourth year of commercial

operation and processed over one-and-a-half million tons of coal.  A winner

of

Power

 magazine's 1996 Powerplant Award, as well as other honors,

Wabash River is one of the cleanest coal-fired facilities in the world, and has

contributed greatly to the commer-

cial potential of this advanced coal-

based power generation technology.

Gasification is already in wide use for

syngas-to-chemical production, and

under the DOE Office of Fossil En-

ergy Vision 21 initiative, coal-based

IGCC is expected to coproduce

power and high-value chemicals and

clean transportation fuels.

DOE selected Wabash River in

September 1991 as a Clean Coal

Technology (CCT) Program Round

IV demonstration project, and the

Cooperative Agreement between the industrial participants and DOE was

signed in July 1992.  Commercial operation began in December 1995.  The

Cooperative Agreement ended in January 2000 after a four-year commercial

demonstration, and the plant continues in commercial operation.

The original Participant was the Wabash River Coal Gasification Repower-

ing Project Joint Venture, formed in 1990 by Destec Energy, Inc. of Houston,

Texas and PSI Energy, Inc. of Plainfield, Indiana.  Destec owned and

operated the gasification facility, and PSI Energy owned and operated the

power generation facility.  In 1997, Houston-based Dynegy, Inc. purchased

Destec.  A final transfer took place last December when Global Energy, Inc.

purchased Dynegy's gasification assets and technology.  PSI Energy remains

the owner and operator of the generating facility.
 
 

The project is located at PSI's

Wabash River Generating Station

near West Terre Haute, Indiana.

PSI repowered a 1950s vintage steam

turbine and installed a new syngas-

fired combustion turbine while con-

tinuing to utilize locally mined

high-sulfur Indiana bituminous coal.

The repowered steam turbine pro-

duces 104 MWe that combines with

the combustion turbine generator's

192 MWe and the system's auxiliary

load of 34 MWe to yield 262 MWe

(net) to the PSI grid.

G

ASIFICATION

 P

ROCESS

The Wabash Project features the

integration of the E-GAS process

with an advanced General Electric

MS 7001 FA high-temperature gas

turbine.  The E-GAS process fea-

tures an oxygen-blown, two-stage

entrained flow gasifier capable of

operating on both coal and petroleum

coke,  with continuous slag removal.

As illustrated in the schematic,

syngas is generated from gasifica-

tion of a coal/water slurry with 95

percent oxygen in a reducing atmo-

sphere at 2,600

o

F and pressure of

400 psig.  The syngas produced from

coal comprises 45.3 percent carbon

monoxide, 34.4 percent hydrogen,

15.8 percent carbon dioxide, 1.9 per-

cent methane, and 1.9 percent nitro-

gen, and has a higher heating value of

277 Btu per standard cubic foot (dry

basis).  The ash melts and flows out

of the bottom of the vessel as a

vitrified slag (frit) by-product. Addi-

tional coal/water slurry added to the

second gasification stage undergoes

devolatilization, pyrolysis, and partial

gasification to cool the raw gas and

increase its heating value.  The syngas

flows to a heat recovery unit, produc-

ing high-pressure saturated steam

that is superheated and used to drive

a steam turbine.  Subsequently, the

particulates (char) in the raw gas are

removed with a hot/dry candle filter

and recycled to the gasifier where

the remaining carbon is converted

to syngas.  After particulate removal,

the syngas is water-scrubbed for

chloride removal and passed through

a catalyst that hydrolyzes carbonyl

sulfide to hydrogen sulfide.  The hy-

drogen sulfide is removed using

methyldiethanolamine absorber/strip-

per columns.  The syngas is then

burned in a gas turbine that produces

electricity.  Gas turbine exhaust heat

is recovered in a heat recovery steam

generator to produce steam that

drives the steam turbine to produce

more electricity.

Over its four years of operation,

the plant has demonstrated an im-

pressive record of continually in-

creasing reliability and syngas pro-

duction, with 2.7 x 10

12

 Btu in 1996,

6.2 x 10

12

 Btu in 1997, and 8.8 x 10

12

Btu in 1998.  Overall, plant availabil-

ity has increased from 56 percent in

1997 to 72 percent in 1998 and 79

percent in 1999.  Thermal efficiency

(HHV) is 39.7 percent on coal and

40.2 percent on petroleum coke com-

pared to the 33­35 percent figure for

conventional pulverized coal-fired

plants.  The greater the thermal effi-

ciency, the less coal is needed to

generate a given amount of electric-

ity, thereby reducing both fuel costs

and carbon dioxide emissions.

Emissions from Wabash River's

IGCC facility are 0.1 pounds of SO

2

and 0.15 pounds of NO

x

 per million

Btu of coal input.  This SO

2

 emission

rate is less than one-tenth the emis-

sion limit set for the year 2000 by the

acid rain provisions of the Clean Air

Act Amendments of 1990.
...
 

Fuel cell subcontract approved

for Kentucky Pioneer IGCC

Project.

  DOE has reviewed and

approved the subcontract between

Fuel Cell Energy (FCE) and Ken-

tucky Pioneer L.L.C.  FCE is plan-

ning to build and operate a 2-MWe

molten carbonate fuel cell (MCFC)

on a slipstream of clean syngas from

the 400-MWe plant.  FCE will scale

up the design of their module from an

existing 250-kW test facility.  The

FCE activity will cost about $34 mil-

lion, of which DOE will fund 50

percent.  The IGCC project is planned

for an existing power plant site in

eastern Kentucky and is currently in

the design and permitting stage.

When completed, this will be the

largest commercial-scale IGCC and

MCFC facility to operate on coal-

derived syngas.