July 15, 2004

Honorable Michael Leavitt, Administrator

U.S. Environmental Protection Agency

EPA Docket Center (Air Docket)

Mail Code: B102

1200 Pennsylvania Avenue, NW

Washington, DC 20460

Attention Docket ID No. OAR–2002–0076.

Dear Administrator Leavitt:

The Institute of Clean Air Companies (ICAC) is the national trade

association of companies that supply air pollution control and monitoring

technology. Our members include nearly eighty leading suppliers of air pollution

control and monitoring technologies for stationary sources. These companies

operate and provide environmental solutions for affected industries as well as

employment opportunities across the U.S.

The Institute congratulates EPA’s efforts to propose a much-needed rule that

provides for the reduction of sulfur dioxide (SO2), nitrogen oxides (NOx), particulate

matter (PM), and volatile organic compounds (VOC) emissions from electric

generating and industrial facilities in order to improve visibility in national parks

and wilderness areas. The Institute has a few observations concerning the proposed

Regional Haze Regulations and Guidelines for Best Available Control Technology

(BART) Determinations specifically concerning control technology performance,

commercial availability, cost, and the availability of construction resources for

control equipment construction.

The Institute recommends that EPA pursue a regulatory framework that

fully encompasses the capability and capacity of the air pollution control and

measurement industry to achieve substantial reductions in emissions in a cost

effective manner. Based on our thorough understanding of technology capabilities

and the capacity of our industry to supply these technologies, we believe that the

proposed emission reduction levels for SO2 and NOx are achievable and that more

can be done. The current suite of best available NOx technologies, post combustion

1660 L Street NW

Suite 1100

Washington, DC 20036-5603

Telephone 202.457.0911

Fax 202.331.1388

David C. Foerter, Executive Director

Email: dfoerter@icac.com

Chad S. Whiteman, Deputy Director

Email: cwhiteman@icac.com

INSTITUTE OF

CLEAN

AIR

COMPANIES
2

as well as combustion controls, can achieve significantly lower emission rates than

the proposed 0.2 lb/mmBtu. In 2002 ozone season, the air pollution control industry

had 100 units achieving a NOx emission rate of less than 0.2 lb/mmBtu. The

industry has cost effective controls and extensive experience with the installation of

post combustion NOx controls on a range of coals, boiler types and existing control

configurations. Additionally, cost effective emission reductions from the industrial

sector are feasible but have not been adequately considered in the BART rule

considering the quantity of visibility impairing emissions. For industrial sources,

setting an appropriate level of reduction with some flexibility such as providing the

option of meeting an emission rate limit or percent reduction is one way to assure

significant emission reductions. Finally, one of the most glaring omissions is the

lack of focus on direct PM emissions as total carbon makes up the largest portion of

particulate. To that end, ICAC has provided comments on policy strategies as well

as technology capabilities that support the development of BART guidance with

greater benefits.

We look forward to working with EPA on this important issue and invite you

and your staff to contact me if you have any questions.

Sincerely,

David C. Foerter

Executive Director, ICAC

Enclosure a/s
3

Discussion Outline

• General Comments

• Electric Generating Units

− Control Technology Effectiveness

 NOx Controls

 SO2 Controls

• Retrofits

• Upgrades

 PM Controls

− Cost Effective Control Technologies

− Control Technology Experience

 NOx Control Installations

 SO2 Control Installations

• Industrial Units

− SO2 Controls

− NOx Controls

− VOC Controls

General Comments

Stationary Source Contribution to Regional Haze

As demonstrated in The National Air Quality and Emissions Trends Report1,

there are a number of significant contributing pollutants to the visibility problem in

Class I areas. In order to obtain significant improvements in visibility, it is

important to consider the components of particulate matter that are contributing to

visibility issues and their sources to determine where the most effective emissions

reductions can be obtained. As demonstrated in Figure 1; nitrates, sulfates, and

ammonium make up a significant portion of the fine particle matter. Putting aside

the ‘total carbon’ portion of PM, the other important components of PM consist of

nitrates and sulfates. The atmospheric chemistry that forms these components is

often complex and site specific; however, it is known that electric power plants

contribute greater than 30 % of the total national NOx emissions and almost 70% of

the SO2 emissions in the U.S. For this reason, EPA has identified more than 300

BART eligible electric power units as they are responsible for a significant portion

of the national SO2 and NOx emiss ions. Additional cost effective reductions can

also be obtained from the industrial sector even though their emissions inventories

are not as well documented.
4

Proposed Emission Limits and Exemption Criteria

The air pollution control industry has the capability to meet the proposed

emission rates for the BART eligible coal-fired units. In fact, the APC industry has

the capability to achieve further SO2 and NOx emission reductions in a cost

effective manner. As demonstrated in Tables A1 and A2, there are already 73 coalfired units meeting the 0.2 lb/mmBtu NOx emission rate and close to 40 units

meeting the 0.15 lb/mmBtu SO2 emission rate on an annual basis. These lists

reflect year 2002 data and would include even more units if more current data were

available as the banked SO2 and NOx allowances become fewer each year thus

requiring additional reductions.

Due to the availability of control technologies to cost effectively reduce SO2

and NOx emissions from coal-fired boilers, BART eligible sources should not be

allowed to opt out of the program without meeting the mandated emissions limits.

EPA has developed this regulation based on the capabilities of technologies without

quantifying the potential visibility benefits and the true capability of the

technologies has not been adequately represented by the chosen emission rates.

The NOx emission rate limit of 0.2 lb/mmBtu can easily be obtained with either

combustion or post combustion controls. In fact, certain coal-fired boilers are close

to meeting the 0.2 lb/mmBtu emission rate without installing any NOx controls.

For this reason, averaging and purchasing credits should not be permitted as a

compliance option. For sources that are affected by both the Clean Air Interstate

Rule (CAIR) and the BART guidelines, they should be required to meet the BART

emission rate limit of 0.2 lb/mmBtu instead of being exempted by buying emission

credits to satisfy both the CAIR and BART rules.
5

One of the other reasons that sources should not be permitted to opt out of

the program is due to the local effects individual sources can have on visibility. The

combustion controls installed on coal-fired units for the Acid Rain Program were

done so to help reduce NOx emissions and ultimately reduce acid deposition. Acid

deposition problems are more of a regional transport problem that can be address

by regional cap and trade programs. The environmental objectives of the Acid Rain

Program and BART guidance are completely different. The BART guidance has

been developed because emissions from individual combustion sources are

significantly contributing to local visibility problems in national parks and

wilderness areas. EPA has identified 50 km as a sensitive corridor around these

Class I areas due to the effects that sources in the vicinity of national parks have on

visibility. For this reason, sources within this 50 km area should not have the

option to opt out if they are found to be BART eligible (e.g. began construction

between 1962 – 1977 and emit greater than 250 tons of the identified pollutants).

If EPA makes increases the required level of reduction for NOx or SO2

emissions, then some flexibility may be useful to obtaining cost effective reductions.

But, it should be made difficult for sources to justify being exempted as the current

suite of best available technologies can readily meet and go beyond the mandated

limits. For example, state-of-the-art NOx controls that would be considered for a

LAER determination would likely require advanced low-NOx burners in conjunction

with SCR or SNCR. If EPA provides an exemption process, it should be at least as

rigorous as the process defined in the Alternative Emission Limit provisions of the

Title IV Acid Rain Program (Part 76.10).2 Under this program, sources were

required to install the best retrofit technology and if they were not able to meet the

specified limit after three months of operation, they could petition EPA for a less

stringent limit. In the early 1990s when the regulation was developed, the best

available technology was defined as low-NOx burners. Some of the other aspects of

the Alternative Emission Limit program included:

• A certification was to be submitted by the designated representative stating that

the unit was unable to meet the mandated limit with hourly emissions data to

support the statement.

• Units that submitted a petition had to demonstrate, over a 15 month period, that

the control technology was operated in accordance with the control vendor

specifications and procedures.

• Unit operating data and quality-assured continuous emission monitoring data

(including a specific list of data items) must be collected during the 15 month

demonstration period. The CEMs data must be collected in accordance with the

monitoring provisions of Title IV Part 75 in order to demonstrate the inability of

the specific unit to meet the applicable emission limitation on an annual average

basis.

• A certification submitted by the designated representative describing the reason

or reasons why the unit cannot achieve the applicable emission limitation.

• A demonstration period plan was also required. This plan required the operator

to demonstrate that the air-to-fuel ratios at each burner were balanced. In some
6

instances, the installation of neural networks were required so that computer

controls balanced the operating conditions of each burner.

For any exemption program, whether based on the AEL provisions or through the

use of the CALPUFF model, the source should be required to perform a field

demonstration that SNCR trim and compact SCR would not cost effectively achieve

the required emission rate.

Post combustion controls (e.g. SCR and SNCR) as well as advanced (or second

generation) low-NOx burners are significantly more efficient and are currently the

best available control technologies for NOx. The majority of the low-NOx burners

currently on coal-fired units were installed to meet the compliance deadline for the

start of Phase I and II of the Acid Rain Program in 1995 and 2000, respectively.

Units that installed their low-NOx burners for Phase I of the Acid Rain Program

will have had their air pollution control equipment in place for almost 20 years by

the time the BART rule is implemented in 2013. Even the units that installed lowNOx burners by 2000 will have had their equipment in place for over 10 years by

2013. Exemptions for existing low-NOx burner equipment that is not meeting the

0.2 lb/mmBtu emission rate should not be given as technology performance has

significantly improved since 1995 and will continue to improve out to 2013. For

these reasons, EPA should remove the provision that permits sources with first

generation low-NOx burners presumptive NOx emission rate and mandate that

BART eligible sources meet the 0.2 lb/mmBtu or lower emission rate.

One of the reasons why there are so many units that are already meeting the

0.2 lb/mmBtu NOx emission rate is because it is much higher than the emission

rate achievable with the best available control equipment. In fact a number of units

are already meeting 0.2 lb/mmBtu or are very close to it doing so with technologies

that are no longer best available technologies. For sources located within 50 km of

a Class I area, the source could be required to perform an evaluation of control

technologies that compare their cost effectiveness. A number of the large power

companies have completed these types of evaluations and have a good

understanding of the cost of the various control scenarios for their units. States

may want to request cost effectiveness evaluations from sources to determine if a

source can cost effectively reduce their emissions. Because a larger number of

sources outside of the NOx SIP Call region have not been required to install many

advanced NOx controls, cost effective reductions can be achieved.

As proposed in the 2004 Amendments to the BART Guidelines, ICAC agrees

that the current New Source Performance Standards (NSPS) limits do not represent

the best control for existing sources. The 1980 BART Guidelines refer to the NSPS

limits for SO2 which have not changed since they were first adopted in 1971. As

shown in Table 1, even the NSPS limits that were promulgated in 1997 are not

representative of what the best available retrofit technology can achieve. Just by

comparison, the NOx emission rate proposed under the 2003 Clear Skies Act, to

replace the existing NSPS limits, for pulverized coal-fired boilers was set at 0.1
7

lb/mmBtu.3 Other programs have required more significant reductions for NOx

including the NOx SIP Call program. The NOx SIP Call also set a cap level, back in

1997, that equated to an emission level of 0.15 lb/mmBtu. Further discussion of the

potential emission reductions achieved for retrofit control installations is provided

below.

Table 1. NSPS for SO2 and NOx - Title I, Part A, Section 111

Unit built

or modified on

or after

Pollutant

Emission

limit

(lb/mmBtu)

Aug. 17, 1971 • SO2

• NOx derived from lignite

• NOx derived from anthracite, bituminous, or subbituminous coals

• NOx derived from ND, SD or MT lignite and burned in cyclone boilers

1.2

0.6

0.7

0.8

Sept. 18, 1978 • SO2

• NOx derived from subbituminous coals

• NOx derived from anthracite or bituminous coals

• NOx derived from ND, SD or MT lignite and burned in slag tap furnaces

1.2

0.5

0.6

0.8

Modified After

July 9/1997 • SO2

• NOx

1.2

0.15

Modified After

July 9/1997 • SO2

• NOx

1.2

1.6 lb/MWh

Electric Generating Units

The air pollution control (APC) industry has extensive experience both in the

United States and worldwide with the installation of air pollution control

technologies for the electric power sector. This experience has resulted in

equipment designs that are delivering higher removal efficiencies while providing a

high level of equipment reliability. Over the last three decades in the US, vendors

and power plant operators have gained experience with the control of SO2 from

coal-fired power plants through the installation and operation of over 100 GW of

flue gas desulfurization (FGD) systems. For SCR and SNCR systems in the US, a

few installations were in place in the mid-1990s with the majority of the 100 GW of

installations taking place in the last four years. For particulate control devices,

either electrostatic precipitators or fabric filters, the air pollution control industry

has even more experience as all units that began construction after 1977 were

affected by the NSPS rules that required some form of control to be installed at the

time of the boiler construction.

Not only has the air pollution control industry installed a significant number

of advanced control technologies, but they have also completed a significant number

of installations in a short period of time. As shown in Table 2, Under the NOx SIP
8

Call requirements, the air pollution control

industry started-up 63 GW of SCR,

approximately 111 units, from 2001 through

2003. The industry also installed 70 SNCR

controls on approximately 14 GW of fossil fuelfired units. The rapid deployment of

technologies demonstrates that the industry

has adequate labor and material resources to

complete a large number of control

installations in a short period of time. In

regard to the skilled labor required to complete

these NOx retrofits, it is estimated by the

National Association of Construction

Boilermaker Employers (NACBE) that these

control installations contributed 38 million union boilermaker man-hours between

2000-2004, with an estimated 22 million (close to 60%) being used in the 2001-2002

time period. The overall experience gained from the post combustion control

installations, including both SCR and SNCR, equates to almost ten years of

operational and installation experience on coal-fired power plants in the U.S. alone.

This experience has given the air pollution control industry the credibility that

significant control numbers of control installations can be completed in a short

period of time when necessary. EPA has yet to estimate the number of expected

control installations that this rulemaking will require; however, with the

compliance date set at 2013, the air pollution control industry does not anticipate

any problems with the supply of material resources or skilled labor for the

completion of control technologies.

Outside of the US, there is also

extensive experience with the

installation of SO2 and NOx controls

on coal-fired units. It is estimated

that over 125 GW of FGD

installations and close to 90 GW of

SCR installations have been

completed in Japan and Europe.

Figure 2 exemplifies that Germany

has installed a large numbers of SCR

systems over a short period of time as

97 of their 137 units were installed

during two consecutive years (1989-

1990).4 This pattern of installations demonstrates that the air pollution control

industry is able to quickly respond to environmental regulations that require a

surge of control installations in a short period of time.
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Control Technology Effectiveness

Due to the extensive experience the air pollution control (APC) industry has

with the installation of air pollution control technologies for the electric power

sector, improvements in removal efficiencies have been significant. This experience

has resulted in improved designs that have reduced the size of the equipment,

reduced operation and maintenance costs, and increased equipment reliability.

NOx Controls

A good example demonstrating the improved performance of control

technologies can be seen with the development of technologies to control NOx

emissions. Under the national Acid Rain program developed under the 1990 Clean

Air Act, coal-fired units were required to meet an annual average emission limit of

between 0.40 - 0.86 lb/mmBtu depending on the boiler type (e.g. tangentially-fired,

cyclone, dry bottom wall-fired, etc.). As shown in Figure 3, the large majority of the

units (84 %) had to meet the more stringent emission rates of between 0.42 - 0.50

lb/mmBtu. First generation combustion controls such as low-NOx-burners and

over-fire air were the control technologies employed to meet these limits. SCR units

were already operating in both Japan and Germany and were demonstrating higher

removal efficiencies but the Acid Rain Program feel short of using the full potential

of commercially available equipment as the regulation required only a 30 percent

NOx reduction from 1980 baseline emissions.

Figure 3. Annual NOx Emission Rate Limits under the Acid Rain Program4

By comparison, the cap for the NOx SIP Call was set such that the average

emission rate for all units affected by the regulation would be at 0.15 lb/mmBtu
10

across twenty-one eastern states and the District of Columbia. The NOx SIP Call

program is an ozone season cap-n-trade program that runs from May 1st through

September 30th. This program has allowed for the installation of a suite of

advanced combustion technologies (e.g. low-NOx burners and other combustion

modifications) as well as post combustion controls (selective catalytic reduction,

selective non-catalytic reduction, and multipollutant controls). As seen in Table A1,

there are one-hundred coal-fired units that achieved a NOx emission rate of less

than 0.2 lb/mmBtu and fifty-nine coal-fired units achieved an emission rate of less

than 0.15 lb/mmBtu during the 2002 ozone season. Seventy-three of these units

listed in Table A1 achieved an emission limit of less than 0.2 lb/mmBtu on an

annual basis. These tables were developed from the 2002 reported emissions as

that was the latest year available at the time the comments were due. The number

of units achieving these low emission rates will increase in the year 2003 due to the

number of additional post combustion controls installed for the NOx SIP Call.

These are the reported emission rates for the year 2002. Of the one-hundred units

identified in Table A1, most of them are regulated under the NOx SIP Call and are

using some form of advanced NOx control technology to control their emissions.

The incentive to control emissions under the NOx SIP Call will become

stronger over time, assuming electric demand continues to grow, as sources utilize

their banked emissions. As the bank of emission credits is reduced, additional NOx

reductions will be required. Some sources will be required to install control

technologies while those with controls will have an incentive to operate their control

technologies at their highest efficiency so they can sell the emission credits that

they offset.

The emission rate achieved from a particular unit depends on several factors

including coal type and boiler configuration. Post combustion controls, such as SCR

and SNCR, have been broadly applied to power generating units fired with Power

River Basin (PRB) coals and bituminous coals. In general, the higher the inlet

emission rate, the easier it is to achieve higher removal efficiencies. But, it has also

been demonstrated that high removal efficiencies are cost effective and achievable

even if the inlet emission rate is relatively low. For example, the SCR on Spurlock’s

unit 2 was able to achieve an 87% NOx emission reduction from the inlet NOx

emission rate of 0.28 lb/mmBtu. The unit is a 585 MW, tangentially fired boiler

that is burning a low sulfur eastern bituminous coal; has a hot-side ESP for

particulate control; and has a wet flue gas desulfurization (FGD) for SO2 control.

The guarantee requested by the plant was for an equivalent emission reduction of

82 % but the unit was able to achieve an 87 % emission reduction down to a NOx

emission rate of 0.03 lb/mmBtu. In the 2002 ozone season, the Spurlock unit

operated at a higher emission level of 0.062 lb/mmBtu, as the regulatory

requirements have only provided an economic incentive to go that low.5

A few more examples of NOx control installations will be provided to

demonstrate that post combustion controls have been effectively installed on
11

various boiler types burning a broad range of coals. In one example, the SCR

system for the AES Somerset unit was installed and designed to achieve a greater

than 90% NOx reduction down below 0.05 lb/mmBtu NOx. The unit is a 675 MW,

dry bottom wall-fired boiler that is burning a high sulfur eastern bituminous coal

and has an inlet NOx emission rate of 0.55 lb/mmBTu. The unit was already

equipped with low-NOx burners, electrostatic precipitator to control particulates

and a wet FGD to control SO2. After installing the SCR equipment, emission tests

demonstrated that the SCR was able to achieve a greater than 90% NOx reduction

to a NOx emission rate below 0.05 lb/mmBtu.6 In another example, the SCR for

AECI’s New Madrid Station unit 2 has achieved a 93% NOx reduction from a

baseline emission rate of 1.5 lb/mmBtu. The unit is a opposed wall cyclone unit that

burns 100% powder river basin (PRB) coal and has a cold side ESP to control

particulates.7 Post combustion controls have been installed on over 200 coal-fired

units in the U.S. alone accounting providing the air pollution control industry to

tackle a myriad of specific design issues.

To demonstrate the availability of multiple control technologies to meet the

0.2 lb/mmBtu emission limits, several examples of SNCR systems that are capable

of meeting emission rates less than 0.2 lb/mmBtu will be discussed. NRG Somerset

unit 5, Exelon’s Eddystone Units 1 & 2, and Duke Energy’s Allen Unit 1 were

provided with guarantees for NOx emissions less than 0.2 lb/mmBtu. The existing

control configurations at these plants varied once again demonstrating that SNCR

is compatible with other controls. The Somerset unit has gas reburn and over-fire

air as their NOx control and the Eddystone and Allen units have low-NOx burners

with over-fire air. The units range in size from 165 – 300 MW in capacity. The

guarantees for these four units range from 0.14-0.18 lb/mmBtu and were tested to

demonstrate their ability to achieve those rates. In the emissions data provided

from the 2002 ozone season, these units are not operating at those levels as the NOx

SIP Call did not mandate a specific emission rate but allows companies to adjust

their control strategy according to the market.

Lignite coal burning units have yet to install post combustion NOx controls

on their units as environmental regulations have not yet required them to do so. In

the U.S. today, 35 power-generation units, with an installed capacity of 15-

gigawatts (GW), burn lignite.8 Lignite units account for less than three percent of

the coal-fired population in the U.S. Nevertheless, some tests have been performed

on lignite coals and have demonstrated the effectiveness of post combustion controls

to remove NOx from these types of units. Tests were performed on TXU Energy’s

Martin Lake Unit 3 to get a better understanding of how SCR catalyst works on

Texas-lignite-fired units. An in-situ mini SCR reactor was used for long term tests

on two types of catalyst to collect data on the effects of Texas lignite on SCR catalyst

life and performance. After approximately 8000 hours of exposure to economizer

outlet flue gas at typical SCR velocities of 15-20 ft./sec. (4.6-6.1 m/sec), both

honeycomb and plate-type catalyst samples were shown, by field test, to have

relative activities (K/K0) in the range of 0.70 to 0.75. Laboratory tests of catalyst
12

activity performed by the catalyst vendors were consistent with field test results.

These results are expected to be representative of the first layer of a full-scale SCR

reactor system. Erosion of the catalyst samples was not significant enough to affect

catalyst performance. Test results suggest that applying SCR catalyst technology

(using even a high-dust design) to Texas-lignite-fired power generating units may

be a practical approach for NOx control.9

In addition to SCR controls, a full scale test was conducted with SNCR on a

lignite coal unit with success. One of the reasons that the SNCR process works well

with a range of coals is that it simply involves the injection of a nitrogen-containing

reagent such as urea or ammonia into the combustion products at an appropriate

temperature. In the EPRI study, a full-scale SNCR demonstration showed that a

single level reagent injection system could provide NOx reductions over a broad

range of boiler loads from 40% - 100% of the boiler maximum continuous rating and

offer a potential capital cost savings over more complex multi-level SNCR systems.

This type of simple SNCR system is called a SNCR trim system as it represents a

single level of reagent injection. Through reduced capital costs, SNCR trim can

significantly improve the cost-effectiveness of installed systems. Wall-fired boilers

with first generation combustion modifications and firing lignite can achieve NOx

emission levels on the order of 0.20 to 0.25 lb/MBtu. With the addition of a single

injection level SNCR, AEP’s 710 MW Perky unit was able to achieve emission rates

as low as 0.14 lb/mmBtu.10

SO2 Controls

There are a number of flue gas desulfurization technologies that have been

developed over the last thirty years. The lessons learned from over 100 GW of

installation experience on coal-fired units has produced a fleet of high efficiency

designs for all ranges of coals and boiler configurations. For coal-fired power plants,

most flue gas desulfurization technologies can be classified as either wet or dry

systems. The primary wet scrubber technologies consist of limestone forced

oxidation, limestone inhibited oxidation, magnesium lime (or lime), and seawater

systems. The primary dry scrubber technologies consist of lime spray drying, duct

sorbent injection and furnace sorbent injection. Wet systems produce a slurry

waste and saturate the flue gas while dry systems produce a dry waste and do not

saturate the flue gas stream. Wet systems are typically employed in high sulfur

coal applications, greater than 2% sulfur, while dry systems tend to be installed in

low to medium sulfur coal applications. The removal efficiency for both systems has

steadily increased over the years with new wet scrubbers typically achieving over

95% removal and dry scrubbers achieving over 90% removal.

As shown in Table A2, there are 38 coal-fired units that are meeting a 0.15

lb/mmBtu emission rate. For the units burning high sulfur coals, they are able to

achieve a 95% or greater percent removal of SO2. One example of a unit that has

achieved greater than 95 % removal efficiency is at Tampa Electric’s Big Bend units
13

1 and 2. This installation has demonstrated that removal rates greater than 98 %

are possible with the addition of adipic acid to the sorbent which enhances it’s

reactivity.11 Centralia’s wet FGD systems on units 1 and 2 achieved emission

reductions of greater than 95 % on a blended high sulfur coal.12

Flue Gas Desulfurization Upgrades

Several options are available to further reduce SO2 emissions and improve

the reliability of existing FGD systems to above 95 % removal efficiencies.13 The

available options typically improve the gas-liquid contact and FGD chemistry. The

gas-liquid contact category includes options such as elimination of wall sneakage,

improved liquid distribution by installation new spray headers and or spray nozzles,

increased recycle slurry pump flow, improved gas distribution. The chemistry

category includes a wide array of options including limestone grind size, elimination

of limestone blinding, introduction of forced oxidation, optimizations of operating

pH and use of performance additives. Some of the upgrade options are more

effective than others.

Liquid Distribution Rings

In general, open spray towers provide good gas-liquid contact but inherent in

any design is a region of lower slurry spray density close to the absorber walls. A

reduction in spray density is a result of recycle slurry being captured by the

absorber walls and a limitation in nozzle placement in the wall region. The region

close to the wall is characterized by a higher than average gas velocity, lower than

average spray density and reduced SO2 removal capacity.

Liquid distribution rings were developed to reintroduce slurry running down

the absorber walls to reduce the flue gas sneakage. The liquid distribution rings

are sloped downwards to re-inject wall slurry into the spray zone to increase the

spray density close to the wall. The distribution rings are typically placed just

below each spray level. Installation experience includes spray towers that are

round as well as rectangular. Small round and rectangular towers tend to benefit

the most from the liquid distribution rings as the wall sneakage tends to be more

pronounced in these configurations. Emission reduction improvements from 30 to

60 % have been achieved in certain applications.14

Perforated Trays

Perforated trays have been applied successfully in lime and limestone-based

scrubbers and is a proven contact device for calcium based systems. A tray provides

additional SO2 removal by creating additional surface area obtained from liquid

holdup on the tray. Significant improvements in SO2 removal can be achieved with

the addition of perforated trays however there are several factors that must be

considered before they are installed. Trays increase the pressure drop in the flue
14

gas making their applicability dependent on the available fan capacity.

Additionally, scrubber chemistry needs to be carefully monitored as plugging and

scaling on the trays can occur. Trays do have the advantage of being useful where

space is limited and can correct a skewed gas distribution profile.

Absorber Tower Redesign

As the flue gas desulfurization technology has advanced over the last three

decades, some older system designs include aspects that make them inefficient

compared to today’s designs. Systems with cross flow horizontal designs, top entry

with side exit and annulus spray section designs, and high pressure cone spray

nozzle designs are examples of systems that may have the potential for rebuilds.

Incomplete spray coverage is sometimes encountered in the recycle spray

header of older FGD systems. This results in poor gas-liquid contact and reduces

the scrubbers efficiency. This can be caused by inefficiencies in the original design,

holes in piping due to erosion, or broken or missing spray nozzles. A spray header

redesign can be done to assure that there is sufficient spray coverage for a

particular spray nozzle design and to prevent gas sneakage. While erosion and

broken pipes can be addressed with the use of corrosion resistant materials such as

alloy, stainless steel, and rubber lined piping.

Some older FGD systems are designed to bypass a portion of the flue gas.

This bypassed gas, typically between 5 – 15 % of the flue gas flow, is mixed with the

treated gas upstream of the stack to achieve some degree of stack gas reheat to

improve gas buoyancy and reduce moisture condensation. Eliminating the bypass

and treating all of the flue gas would provide a significant reduction in SO2

emissions. Before doing this however, there are several issues that must be

considered. Some of the issues to consider include determining if the scrubber can

handle the added flow without creating gas distribution problems, creating gas

sneakage, reducing mist eliminator performance, causing slurry recirculation

problems, and affecting the lining of the stack under a wet environment.

Performance Additives

Organic acids have the ability to significantly enhance the performance of

lime and limestone wet FGD systems. Dibasic acids such as adipic acid are

commonly used as performance additives. The additives are typically supplied in a

liquid form but may also be available in granular form. Organic acids work by

buffering the pH at the gas liquid interface, reducing the back pressure of SO2 and

lowering the liquid-film resistance to mass transfer. This essentially increases the

absorption capacity of the scrubbing slurry which has the benefit of reducing the

power consumption with savings both from the spray pumps as well and reduced

pressure drop. Other advantages besides reduced operation and maintenance costs
15

is the fact that it can be installed quickly, serve multiple absorbers, and requires a

small footprint.

Computational Fluid Dynamics Studies

Computational fluid dynamics (CFD) modeling is a method of obtaining

solutions to complex equations involving fluid flow, heat transfer and mass transfer

processes. For scrubber work improvement, CFD modeling can provide visual

images of gas velocity, pressure, and temperature distribution within the tower.

This tool is very helpful when evaluating gas-liquid interactions and solid

deposition problems.

PM Controls

Particulate control devices were are the most obvious control area that has

not been appropriately addressed in the Regional Haze rule. According to EPA’s Air

Trends Report, electric power plants emit over 500,000 tons of direct particulate

matter. Particulate control devices are essentially the first type of control device

installed on electric power plants. Electrostatic precipitators and fabric filters

(baghouses) are the two primary categories of particulate control devices.

Baghouses often are capable of 99.9 percent removal efficiencies, and commonly can

reduce power plant emissions to below 0.03 lb/MMBtu, and often to below 0.01

lb/MMBtu. Electrostatic precipitators have overall (mass) collection efficiencies that

can exceed 99.9 percent, and efficiencies in excess of 99.5 percent are common.

Considerable reductions of primary particulate (both coarse and fine) can be

achieved with the installation of PM controls. Since most power plants already

have some form of PM control, upgrades of existing equipment and conversions from

ESPs to FF are the primary type of PM installations taking place in today’s market.

Additionally, EPA did not address emission of SO3 from power plants. This

has become an increase area of concern for power companies as States have set

emission standards for SO3 in the operating permits for power plants. A number of

control technologies have been developed to address this pollutant and are able to

achieve a high level of removal.

Cost Effective Control Technologies

For the BART rule, EPA has defined highly cost effective as those emission

reductions that can be achieved at a cost of less than $900/ton. Using a cost

effectiveness threshold of $900/ton or less is almost half the cost considered cost

effective in a number of the more recent regulations for the electric power sector.

Table 3 below describes the cost effective numbers that have been the outcome of

State and Federal regulations.
16

Table 3. Cost Effectiveness of State and Federal SO2 and NOx Programs ($/ton)

Regulation 2010 2015

NOx SIP Call

(ozone season

controls)

$1,000 (average cost)

$2,200 (marginal cost)

$1,500 (average cost)

$2,600 (marginal cost)

Clean Air

Interstate Rule

(projected cost)

$800 (average cost)

$1,200 – 2,160 (marginal

cost)

$700 (average cost)

$1,500 - $2,000 (marginal

cost)

Wisconsin Rules $1,800

NOx

Texas Rules $1,400 - $3,000

Clean Air

Interstate Rule

(projected cost)

$700 (average cost)

$700 – 900 (marginal

cost)

$800 (average cost)

$1,000 – 1,100 (marginal

cost)

BACT

determinations

$500 – 2,100

Wisconsin Rules $1,400

North Carolina

Rule

$800

SO2

WRAP Rule $1,100 – 2,200

Cost Effectiveness of SO2 Emission Reductions

The IPM results for the projected costs of implementing the Clean Air

Interstate Rule are compared under various assumptions. In the proposed CAIR

rule, the ‘knee’ in the marginal cost curve begins to increase at a higher rate above

$2,000/ton. The BACT determinations reflect the application of BACT for SO2 to

new sources and major modifications at existing sources. These decisions, which

include consideration of average and incremental cost effectiveness, reflect the

application of best available controls in attainment and unclassified areas. These

decisions do not reflect the application of lowest achievable emission rate, which is

required in nonattainment areas and which does not directly consider cost in any

form. The marginal cost per ton of recent State decisions for annual SO2 controls

where marginal cost information was available. These include the WRAP Regional

SO2 Trading Program and statewide rules that have required significant reductions

of SO2 in North Carolina and Wisconsin.

Cost Effectiveness of NOx Emission Reductions

In developing the NOx SIP Call, EPA determined that an average cost

effectiveness of $2,500/ton (in 1999 dollars, from original $2,000/ton in 1990

dollars), or less, was highly cost effective for NOx reductions during the ozone

season. The IPM results for the projected cost of implementing the Clean Air

Interstate Rule are compared under various assumptions. In the proposed CAIR

rule, the ‘knee’ in the marginal cost curve begins to increase at a higher rate above
17

above $2,000 per ton. This is also in the range of the cost effectiveness numbers for

the Wisconsin and Texas NOx rules.

Control Technology Experience

NOx Control Installations

The air pollution control industry has significant experience both in the

United States and abroad with the installation of control technologies on both

electric power and industrial boilers. In a three-year period, our industry recently

started-up more than 63 GW of selective catalytic reduction systems for NOx control

on 111 coal-fired units to address regional transport issues in the eastern part of the

US. By the end of this year, there will be a post combustion NOx control retrofit on

nearly one-third of the existing coal-fired capacity in the U.S. This has given the

control vendors considerable experience designing systems for almost every

conceivable configuration (e.g. boiler configuration, coal type and existing control

configurations). Additionally, the air pollution control industry in both Germany

and Japan had already installed flue gas desulfurization (FGD) systems and post

combustion NOx controls on all their coal-fired plants by the late 1980’s.

SO2 Control Installations

For SO2 control, there are currently about 100 GW of installed FGD systems

on coal-fired power plants in the U.S. This accounts for approximately one-third of

the coal-fired electric generating capacity with post combustion SO2 controls. This

experience list also includes control installations on various boiler configurations,

coal types, and other control configurations. Not only have control vendors gained

experience in constructing these technologies, but power companies have also

gained valuable experience operating these controls over the last 30 years.

Industrial Units

With potentially 26 different industrial categories that have units which are

potentially BART eligible, the options for emissions control are numerous. Below is

a summary of some of the types of emission control technologies that could be

employed although an exhaustive list was not prepared.

SO2 Control Technologies

The following tables provide information on the cost for the installation of

SO2 control systems for coal-fired industrial boilers. Cost estimates were provided

for 90 % removal rates (unless otherwise stated) for boilers burning high sulfur coal.

Estimates were provided for three different boiler heat capacities including: 100,

250 and 1000 mmBtu/hr. The cost estimates that were provided were for dry

sorbent injection type systems. The following estimates did not include the cost of
18

installing wet flue gas desulfurization (FGD) systems as the economics favor dry

systems for these smaller type applications. In general, wet FGD systems have

higher capital costs compared to the dry systems making them less favorable for

smaller industrial applications.

If larger retrofit markets are developed in response to regulations, the

manufacturing capacity for these controls will increase. Increased demand will

create provide incentives for the development of innovative technologies at lower

costs. One of the ways in which the costs may be reduced is through the supply of

standardized solutions. These pre-engineered systems will likely serve the smaller

size boilers (e.g. 100 and 250 mmBtu/hr) that were considered in these estimates.

They will emphasize a modular design and maximize fabrication off-site making

them more of a off-the-shelf type technology. The modular design decreases onsite

fabrication reducing labor costs and therefore the overall cost of the project. In

cases where onsite fabrication is required, labor costs will be more than the cost of

the actual equipment.

For the operation and maintenance cost information given in the tables

below, it was assumed that the boilers had an 85% capacity factor. The cost of

water, mixed with the sorbent, was not calculated but estimated by consumption.

The power costs need to run pumps and other electrical equipment were assumed to

be $0.04 kWh while the cost of reagent was assumed to be $50/ton or as noted.

Waste disposal costs for the spent sorbent (land filling costs) are typically between

$9-15/ton depending on the location of the site and quantity of waste.

Sorbents

A variety of sorbents are available for use in acid gas scrubbing systems (wet

limestone, wet lime, spray dryer absorber, furnace injection, dry duct injection, etc).

The dry sorbents are typically delivered in bulk by rail car, hopper or pneumatic

truck in either a coarse or fine grade. The smaller the size of the scrubbing system,

the more likely the scrubber will not have a grinding system. For these types of

smaller systems, the reagent will likely be delivered pre-ground in a pneumatic

truck. If delivered in coarse grade, the reagent will typically be ground to fine grade

(20-25 μ average size) before being used in the control system.

For reagent storage, the storage capacity on site ranged from three to

fourteen days. A 3-5 day storage capacity may be used when the sorbent is received

in a tanker truck in a wet slurry. For dry sorbents, the maximum size storage

capacity considered would be fourteen days. In some cases, a fourteen day capacity

would be considered excessive and a seven day capacity would be used.
19

Below are some typical sorbent cost estimates:

Sodium bicarbonate (dry) $225/ton, delivered to plant site

Trona (dry) $70/ton FOB in Wyoming

Hydrated lime (dry) $70-100/ton, delivered to plant site

Pre-ground limestone (dry) $28-50/ton

Coarse quicklime (dry) $50-80/ton

Pre-slurried hydrated lime (wet) $50-100/dry ton

Furnace Sorbent Injection

The estimates in Table 4 are for a furnace sorbent injection system. The

major components of the system design include: reagent storage, metering,

recording and conveying system; injection lances; flue gas conditioning system; and

ID fan. The reagent is injected in the furnace at the location providing the optimum

temperature. The injection ports also act as over-fire air ports which improve the

boilers combustion. The other components of the system such as electrical controls,

motors, piping, insulation, etc. are included in the cost estimate as well.

The typical sorbent injected into the furnace would be dry powdered

limestone. The limestone would typically be injected at a 3:1 calcium to sulfur ratio.

This type of system would have a removal efficiency of 70% sulfur.

Table 4. Furnace Sorbent Injection System Estimate

1000

mmBtu

Boiler

250

mmBtu

Boiler

100

mmBtu

Boiler

Capital Cost ($) 4,600,000 2,400,000 1,700,000 Capital Costs Installation Cost ($) 1,100,000 600,000 450,000

Reagent ($/yr) 3,000,000 750,000 300,000

Water - - -

Power ($/yr) 148,000 40,000 16,000

Waste Disposal ($/yr) 450,000 112,500 45,000

Parts & Labor ($/yr) 50,000 25,000 25,000

Operating

Costs

Total O&M Cost ($/yr) 3,648,000 927,500 386,000

Waste disposal costs were estimated at $15/ton

Power costs were estimated at $0.04/kWh

Limestone reagent was estimated at $50/ton

Total O&M costs include reagent, power, waste disposal, parts & labor

Dry Sorbent Injection

The estimates in Table 5 are for a typical dry sorbent injection system. The

major components of the system design include: reagent storage (14 days),

metering, recording and conveying system; injection nozzles; reagent reaction

chamber (venturi reactor); particulate control device (pulse-jet baghouse); waste
20

discharge system; and ID fan. The other components of the system such as

electrical controls, motors, foundation, piping, insulation, etc. are included in the

cost estimate as well.

The typical sorbent used for a dry sorbent injection system would be either

hydrated lime or sodium bicarbonate/trona. In order to achieve a 90% sulfur

removal efficiency, sodium bicarbonate or trona would be recommended for this

system. Injection of dry hydrated lime will achieve greater than 50% removal but in

a dry form it will not achieve the same removal efficiencies as sodium bicarbonate

or trona. Sodium bicarbonate and trona are relatively expensive reagents, therefore

cost estimates were not provided for the 1,000 mmBtu/hr case as the operating costs

would be prohibitive. This system could be used with hydrated lime for the 1,000

mmBtu/hr boiler but with a lower removal efficiency.

Table 5. Dry Sorbent Injection System Estimate

1000

mmBtu

Boiler

250

mmBtu

Boiler

100

mmBtu

Boiler

Capital Cost ($) - 1,350,000 850,000 Capital Costs Installation Cost ($) - 1,200,000 550,000

Reagent ($/yr) - 2,610,000 1,035,000

Water (gpm) - - -

Power ($/yr) - 89,700 37,500

Waste Disposal ($/yr) - 575,000 127,000

Parts & Labor - 24,000 17,000

Operating

Costs

Total O&M Cost ($/yr) - 3,298,700 1,216,500

Waste disposal costs were estimated at $15/ton

Power costs were estimated at $0.04/kWh

Sodium bicarbonate reagent was estimated at $225/ton

Total O&M costs include cost of reagent, power, waste disposal, parts & labor

Wet Sorbent Injection

The estimates in Table 6 are for a wet sorbent injection system. The major

components of this system include: reagent storage, metering, recording and

conveying system; injection nozzles; instrument to measure flue gas temperature;

round vertical duct for reagent reaction (only if does not currently exist); particulate

control device (pulse-jet baghouse); waste discharge system. The other components

of the system such as electrical controls, motors, piping, insulation, etc. are included

in the cost estimate as well.

Hydrated lime [Ca(OH)2] would be used in this system as the sorbent and

would be able to achieve a 50-70% sulfur removal efficiency. The reagent would

likely be delivered in 5000 gallon tanker trucks and would last 3-5 days. Quicklime

is slaked with water to form a slurry which is atomized through injection nozzles in
21

the duct work between the boiler and particulate control device. Optimally, the

slurry would be injected in a location that would permit the water in the slurry to

evaporate before the particles encounter duct walls or bends. In addition, the

optimum injection location would be approximately forty degrees Fahrenheit above

the saturation temperature of the flue gas. The lime would typically be injected at a

1.25 to 1.75 calcium to sulfur ratio based SO2 removal.

Table 6. Wet Sorbent Injection System Estimate

1000 mmBtu

Boiler

250

mmBtu

Boiler

100

mmBtu

Boiler

Capital Cost 2,625,000 712,500 560,000 Capital Costs Installation Cost 1,125,000 237,500 140,000

Reagent ($/yr) 800,000

(1,350,000)*

200,000

(345,000)*

80,000

(135,000)*

Water (gpm) 56 10 3

Power ($/yr) - - -

Waste Disposal

($/yr)

414,000

(576,000)*

103,500

(144,000)*

41,400

(57,600)*

Parts & Labor 1 man on

daylight shift - -

Operating Costs

Total O&M Cost

($/yr)

2,000,000

(2,650,000)*

600,000

(775,000)*

300,000

(450,000)*

Waste disposal costs were estimated at $9/ton

Hydrated lime reagent was estimated at $50/ton

Total O&M costs include costs for complete system (reagent, water, power, parts &

labor, etc)

*based on higher sulfur content in flue gas (0.255 lb/hr SO2)

NOx Control Technologies

Emission Rates

NOx emissions regulations are continually being tightened across the country

for nearly all combustion processes including industrial boilers, process heaters,

refinery furnaces, etc. As an example, BACT regulations have required refineries in

CA to reduce NOx emission to less than 0.033 lb/mmBtu (27 ppm at 3 % O2).15

Similarly, south Texas has implemented regulations for the refining and

petrochemical furnaces requiring emission rate to get down to 0.12 lb/mmBtu but

are expected to be limited to 0.01 lb/mmBtu for furnaces greater than 100

mmBtu/hr in the near future.
22

Combustion vs. Post Combustion Controls

For industrial applications, careful consideration should be given to the

choice between combustion and post combustion controls. For units that do not yet

have any combustion controls, a post combustion control might be the better option.

One of the issues that must be considered is the effect the control technology may

have on the boiler efficiency. In some industrial applications, the efficiency of the

process is very important and tied to the overall productivity of the process.

Advanced low-NOx burners (LNB) are affective at reducing NOx but in general,

low-NOx burners reduce the efficiency of the boiler. Post combustion controls also

require energy but the incremental difference in fuel costs that would be lost due to

the decreased efficiency must be considered. Another consideration is whether the

combustion control will be able to meet the stringent emission rates that are being

promulgated by States.

Post combustion controls provide total fuel flexibility which is significant due

to the rising energy costs. Industrial users tend to buy more fuel on the spot

market which means that they will use a wider variety of fuels with differing

properties. Technologies like SCR and SNCR are able to deliver a high level of

emission reduction regardless of the type of fuels (oil, coals and residual fuels). The

post combustion controls are so flexible because they can simply adjust the reagent

injection rate or they can add additional layers of catalyst to meet changing NOx

levels come from the boiler. Combustion controls are less flexible when it comes to

switching fuels as there is a limited number of changes that can be made without

affecting the combustion process.

In a number of industrial applications, monitoring of emissions is performed

on an infrequent basis. More frequent monitoring of emissions would be beneficial

to control system regardless of whether it were a combustion or post combustion

control technology.

VOC Control Technologies

In many cases, the emission reductions required through the NESHAP rules

will provide some level of control but do not directly address the criteria pollutants

that the BART provisions were designed to address. With that in mind, there is an

opportunity for increased cobenefit control due to current statutory requirements.

For instance, the Industrial Boiler MACT is projected to require the installation of

venturi scrubbers to control certain HAP emissions. A small amount of SO2 will be

removed with a venturi scrubber but with the design of a control system that would

allow for the application of a sorbent such as lime or limestone, a much higher level

of SO2 control could be achieved while continuing to reduce the required HAP

emissions. There are numerous other examples under the MACT rules where the

best available controls were not used due to the rigidity of the MACT program.
23

Appendix A

Table A1. 2002 Ozone Season NOx Emissions Rates for Coal-Fired Units16

State Facility Name ORIS

Code

Unit ID NOx Rate

(lb/mmBtu)

FL Northside 667 1A 0.046

FL Northside 667 2A 0.060

WV Mountaineer (1301) 6264 1 0.062

KY H L Spurlock 6041 2 0.062

MS Red Hills Generation Facility 55076 AA002 0.082

FL Polk 7242 **1 0.083

KY Paradise 1378 1 0.083

PA Montour 3149 1 0.087

PA Montour 3149 2 0.095

GA Bowen 703 2BLR 0.097

MS Red Hills Generation Facility 55076 AA001 0.098

NC Roxboro 2712 4B 0.099

NC Roxboro 2712 4A 0.099

KY Paradise 1378 2 0.100

MO Labadie 2103 1 0.100

MO Labadie 2103 4 0.102

MD Herbert a Wagner 1554 3 0.104

GA Hammond 708 4 0.105

MO Rush Island 6155 1 0.105

MO Hawthorn 2079 5A 0.106

MO Labadie 2103 3 0.108

GA Bowen 703 1BLR 0.108

IL Newton 6017 2 0.108

PA Mt. Carmel Cogeneration 10343 SG-101 0.109

OH Bay Shore 2878 1 0.113

MO Rush Island 6155 2 0.115

IL Joliet 29 384 71 0.116

WV John E Amos 3935 3 0.117

IL Joliet 29 384 72 0.118

MO Labadie 2103 2 0.119

NH Merrimack 2364 1 0.120

MI Shiras 1843 3 0.121

IL Joppa Steam 887 5 0.122

IL Joppa Steam 887 6 0.122

TN Allen 3393 3 0.124

IL Joliet 29 384 81 0.124

TX Gibbons Creek Steam Electric

Station

6136 1 0.126

MD Brandon Shores 602 2 0.127

IL Joliet 29 384 82 0.127
24

IL Waukegan 883 8 0.127

OH Miami Fort 2832 8 0.128

IL Baldwin 889 3 0.128

TN Allen 3393 2 0.129

IL Joppa Steam 887 2 0.130

IL Joppa Steam 887 1 0.131

IL Joppa Steam 887 3 0.131

IL Joppa Steam 887 4 0.132

IL Waukegan 883 7 0.133

TX W A Parish 3470 WAP7 0.138

IL Will County 884 4 0.140

IN Gibson 6113 3 0.141

AL Gorgas 8 10 0.143

MI St. Clair 1743 6 0.143

IL Newton 6017 1 0.146

NY AES Somerset (Kintigh ) 6082 1 0.147

IA Milton L Kapp 1048 2 0.148

MI Wyandotte 1866 8 0.149

PA Westwood 50611 31 0.149

TX Big Brown 3497 1 0.150

WI Columbia 8023 1 0.153

TX Monticello 6147 1 0.153

TX Martin Lake 6146 3 0.155

MI J H Campbell 1710 1 0.156

MD Brandon Shores 602 1 0.158

TX W A Parish 3470 WAP8 0.161

LA Big Cajun 2 6055 2B3 0.161

TX Welsh Power Plant 6139 1 0.166

FL Curtis H. Stanton Energy

Center

564 2 0.166

IL Wood River 898 4 0.167

TX Big Brown 3497 2 0.169

TX W A Parish 3470 WAP5 0.169

GA Scherer 6257 3 0.169

TX Martin Lake 6146 2 0.170

IL Will County 884 3 0.170

WY Neil Simpson II 7504 1 0.171

TX Twin Oaks Power, LP 7030 U2 0.172

TX Welsh Power Plant 6139 3 0.174

TX Coleto Creek 6178 1 0.177

MI Belle River 6034 2 0.177

IL Wood River 898 5 0.177

TX W A Parish 3470 WAP6 0.179

IA Burlington (IA) 1104 1 0.180

NY WPS Empire State, Inc- 50202 1 0.182
25

Niagara Falls

MI Trenton Channel 1745 9A 0.182

TX Monticello 6147 3 0.183

TX J T Deely 6181 1 0.185

MI B C Cobb 1695 5 0.185

NH Merrimack 2364 2 0.185

TX J T Deely 6181 2 0.186

NE Lon D Wright Power Plant 2240 8 0.188

TX H W Pirkey Power Plant 7902 1 0.188

WI South Oak Creek 4041 5 0.188

MI St. Clair 1743 7 0.189

WI South Oak Creek 4041 6 0.190

MI River Rouge 1740 2 0.190

IL Crawford 867 8 0.190

TX J K Spruce 7097 **1 0.193

MO Meramec 2104 4 0.196

IL Crawford 867 7 0.197

TX Twin Oaks Power, LP 7030 U1 0.198

Table A2. 2002 Annual SO2 Emission Rates for Coal-Fired Units

State Facility Name ORIS

Code Unit ID

SO2 Emission

Rate

(lb/mmBtu)

AZ Navajo Generating Station 4941 2 0.035

AZ Navajo Generating Station 4941 1 0.039

UT Bonanza 7790 1-Jan 0.044

AZ Navajo Generating Station 4941 3 0.047

NV Reid Gardner 2324 2 0.047

VA Southampton Power Station 10774 2 0.049

VA Southampton Power Station 10774 1 0.049

UT Intermountain 6481 2SGA 0.050

UT Intermountain 6481 1SGA 0.050

VA Altavista Power Station 10773 1 0.053

VA Altavista Power Station 10773 2 0.053

NV Reid Gardner 2324 3 0.054

VA Clover Power Station 7213 2 0.063

VA Clover Power Station 7213 1 0.065

CO Rawhide Energy Station 6761 101 0.074

UT Hunter (Emery) 6165 3 0.083

NV Reid Gardner 2324 4 0.088

CO Craig 6021 C3 0.092

TX Sam Seymour 6179 3 0.095

IA Muscatine 1167 9 0.096
26

GA Yates 728 Y1BR 0.098

PA Conemaugh 3118 2 0.099

MT Colstrip 6076 3 0.100

MT Colstrip 6076 4 0.102

NV Reid Gardner 2324 1 0.104

SC Cope Station 7210 COP1 0.110

PA Conemaugh 3118 1 0.112

WA Centralia 3845 BW22 0.114

KS Holcomb 108 SGU1 0.125

NV North Valmy 8224 2 0.127

WV Harrison Power Station 3944 1 0.127

WV Harrison Power Station 3944 3 0.127

WV Harrison Power Station 3944 2 0.127

CO Hayden 525 H1 0.132

CO Hayden 525 H2 0.133

MI Shiras 1843 3 0.134

AZ Cholla 113 2 0.134

NM Prewitt Escalante Generating

Station

87 1 0.139

 

1 U.S. EPA, The National Air Quality and Emissions Trends Report: 2003 Special Studies Edition,

http://www.epa.gov/air/airtrends/aqtrnd03

2 CAA, Title IV, Alternative Emission Limitation Provisions for NOx,

http://frwebgate.access.gpo.gov/cgi-bin/getcfr.cgi?TITLE=40&PART=76&SECTION=10&YEAR=2000&TYPE=TEXT

3 Clear Skies Act 2003, February 27, 2003, http://www.epa.gov/air/clearskies/Air_005.pdf 4 “OTC NOx Budget Program 1999-2002 Progress Report,” March, 2003, USEPA and Ozone

Transport Commission EPA 430-R-03-900. http://www.epa.gov/airmarkets/otc/otcreport.pdf

5 J. Buschmann, D. Borio, M. Cohen, “Early Operating Experience of the Spurlock SCR System,”

ICAC Forum ’03: Multipollutant Emission Controls & Strategies, Nashville, TN.

6 W. Nischt, J. Hines, K. Robinson, “Selective Catalytic Reduction Retrofit of a 675 MW Boiler at

AES Somerset,” ICAC NOx Forum ’00, Washington, DC.

7 J. Cochran, D. Hellard, V. Rummenhohl, “Design and Initial Startup Results from the New Madrid

SCR Project,” ICAC NOx Forum ’00, Washington, DC.

8 DOE Press Release, June 24, 2004, ”More Electricity, Lower Emissions from Lignite Plants Are

Goals of New Clean Coal Power Initiative Project,”

http://www.energy.gov/engine/content.do?PUBLIC_ID=16062&BT_CODE=PR_PRESSRELEASES&

TT_CODE=PRESSRELEASE

9 Electric Power Research Institute, December 2003, “Impacts of Texas Lignite Coal on SCR Catalyst

Life and Performance: Field Data from TXU's Martin Lake Plant,” http://www.epri.com. 10 EPRI, April 2004, “Evaluation of an SNCR Trim System on a 710 MW Opposed Wall Design CoalFired Utility Boiler,” www.epri.com. 11 J. Smolenski, J. Murphy, and I. Brodsky, 1999, “Tampa Electri Compay Phase II FGD System Big

Bend Station Units 1 & 2 Advanced Design – Low cost, “ MEGA Symposium, Palo Alto, CA.

12 M. Miller, L. Webster, P. Rader, C. Bussell, May 19-22, 2003, “Centralia WFGD System: State-ofthe-Art SO2 Compliance," MEGA Symposium, Washington, DC.

13 G. Miller, M. Cook, G. Betenson, May 19-22, 2003, “Improving the Performance of Older FGD

Systems,” MEGA Symposium, Washington, DC.
27

 14 J. Dopatka, N. Ford, K. Jiajanpong, May 19-22, 2003, “Opportunities to Achieve Improved WFGD

Performance and Economics,” MEGA Symposium, Washington, DC.

15 M. Rini, N. Kuck, “NOx Control Technologies for Refining and Petrochemical Furnace

Applications: A Discussion of Available Technologies.”

16 Acid Rain Program and NOx SIP Call Data, USEPA Emissions Query Wizard,

http://cfpub.epa.gov/gdm/index.cfm?fuseaction=emisscreatequeries.timeframe