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 fo r 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 conc erning 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 capaci ty of the air pollution control and measurement industry to achieve substant ial reductions in emissions in a cost effective manner. Based on our thorough understanding of technology capabilities and the capacity of our industry to suppl y 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 COMPANIES2 as well as combustion controls, can achi eve 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 ra te of less than 0.2 lb/mmBtu. The industry has cost effective controls and ex tensive experience with the installation of post combustion NOx controls on a range of coals, boiler types and existing control configurations. Additionally, cost effectiv e emission reductions from the industrial sector are feasible but have not been adequately considered in the BART rule considering the quantity of visibility impa iring emissions. For industrial sources, setting an appropriate level of reduction wi th 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 provid ed 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/s3 

### 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 inThe National Air Quality and Emissions Trends Report 1
, there are a number of significant contributing pollutants to the visibility problem in Class I areas. In order to obtain sign ificant improvements in visibility, it is important to consider the components of pa rticulate matter that are contributing to visibility issues and their sources to determine where the most effective emissions reductions can be obtained. As demonstrat ed 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 ot her 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 ha s the capability to meet the proposed emission rates for the BART eligible coal-fi red units. In fact, the APC industry has the capability to achieve further SO2 and NOx emission reductions in a costeffective manner. As demonstrated in Tables A1 and A2, there are already 73 coalfired units meeting the 0.2 lb/mmBtu NO x 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 evenmore units if more current data were available as the banked SO2 and NOx allo wances 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 withou t meeting the mandated emissions limits. EPA has developed this regulation based onthe capabilities of technologies without quantifying the potential visibility benefits and the true capability of the technologies has not been adequately re presented by the chosen emission rates. The NOx emission rate limit of 0.2 lb/mmBtu can easily be obtained with either combustion or post combustioncontrols. In fact, certain coal-fired boilers are close to meeting the 0.2 lb/mmBtu emission ra te without installing any NOx controls. For this reason, averaging and purchasing credits should not be permitted as a compliance option. For sources that are af fected by both the Clean Air Interstate Rule (CAIR) and the BART guidelines, theyshould 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 indivi dual 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 with in 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 usef ul to obtaining cost effective reductions. But, it should be made difficult for sou rces 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 ex emption process, it should be at least as rigorous as the process defined in the Alte rnative 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 techno logy 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-NO x burners. Some of the other aspects of the Alternative Emission Limit program included:

• A certification was to be submitted by th e designated representative stating that the unit was unable to meet the mandatedlimit 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-assure d continuous emission monitoring data (including a specific list of data items) must be collected during the 15 month demonstration period. The CEMs data mustbe 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 requ ired. This plan required the operator to demonstrate that the air-to-fuel ratios at each burner were balanced. In some6 instances, the installation of neural ne tworks 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 sh ould 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 significan tly more efficient and are currently the best available control technologies for NO x. The majority of the low-NOx burners currently on coal-fired units were insta lled 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 eq uipment in place for over 10 years by 2013. Exemptions for existing low-NOx burn er 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 pr ovision that permits sources with first generation low-NOx burners presumptiv e 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 ma ny units that are already meeting the 0.2 lb/mmBtu NOx emission rate is becaus e it is much higher than the emission rate achievable with the best available co ntrol 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 technolo gies. For sources located within 50 km of a Class I area, the source could be requir ed to perform an ev aluation of control technologies that compare their cost effe ctiveness. 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 ev aluations from sources to determine if a source can cost effectively reduce thei r 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 St andards (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 prop osed under the 2003 Clear Skies Act, to replace the existing NSPS limits, for pulv erized coal-fired boilers was set at 0.17 lb/mmBtu. 3 Other programs have required more significant reductions for NOx including the NOx SIP Call program. The NO x 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 • SO 2

• 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 • SO 2

• 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 • SO 2

• NOx 1.2 0.15
Modified After July 9/1997 • SO 2

• 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 sect or. This experience has resulted in equipment designs that are delivering higherremoval 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 withthe majority of the 100 GW of installations taking place in the last fouryears. For particulate control devices, either electrostatic precipitat ors or fabric filt ers, 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 theyhave also completed a significant number of installations in a short period of time . As shown in Table 2, Under the NOx SIP8 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 SNCRcontrols 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 (clo se to 60%) being used in the 2001-2002 time period. The overall experience ga ined 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 polluti on 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 rulema king will require; however, with the compliance date set at 2013, the air polluti on 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.9 Control Technology Effectiveness

Due to the extensive experience the ai r pollution control (APC) industry has with the installation of air pollution co ntrol technologies for the electric power sector, improvements in remova l efficiencies have been si gnificant. 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 sh own in Figure 3, the large majority of the units (84 %) had to meet the more string ent 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 Prog ram feel short of using the full potential of commercially available equipment as th e regulation required only a 30 percent NOx reduction from 1980 baseline emissions.

Figure 3. Annual NOx Emission Rate Limits under the Acid Rain Program 4

By comparison, the cap for the NOx SI P Call was set such that the average emission rate for all units affected by the regulation would be at 0.15 lb/mmBtu10 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 1 stthrough September 30 th . 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 combustioncontrols (selective catalytic reduction, selective non-catalytic reduction, and multipo llutant 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 develo ped from the 2002 reported emissions as that was the latest year available at th e 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 emis sion rates for the year 2002. Of the one-hundred units identified in Table A1, most of them ar e regulated under the NOx SIP Call and are using some form of advanced NOx contro l technology to control their emissions.

The incentive to control emissions under the NOx SIP Call will become stronger over time, assuming electric de mand continues to grow, as sources utilize their banked emissions. As the bank of emis sion credits is reduced, additional NOx reductions will be required. Some sou rces 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 part icular 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 ef ficiencies. But, it has also been demonstrated that high removal effi ciencies are cost effective and achievable even if the inlet emission rate is relative ly low. For example, the SCR on Spurlock’s unit 2 was able to achieve an 87% NOx em ission reduction from the inlet NOx emission rate of 0.28 lb/mmBtu. The uni t is a 585 MW, tangentially fired boiler that is burning a low sulfur eastern bi tuminous 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 leve l 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 contro ls have been effectively installed on11 various boiler types burning a broad range of coals. In one example, the SCR system for the AES Somerset unit was inst alled 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, electrosta tic precipitator to control particulates and a wet FGD to control SO2. After in stalling 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 ac hieved 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) coaland 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 multip le control technologies to meet the 0.2 lb/mmBtu emission limits, several ex amples of SNCR systems that are capable of meeting emission rates le ss 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 emission s 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 Eddyston e 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 fr om 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 no t operating at those levels as the NOx SIP Call did not mandate a specific emissi on 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 onthe effects of Texas lignite on SCR catalyst life and performance. After approximat ely 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. Laborato ry tests of catalyst12 activity performed by the catalyst vendors were consistent with field test results. These results are expected to be representati ve 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 sugge st 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 th e reasons that the SNCR process works well with a range of coals is that it simply invo lves the injection of a nitrogen-containing reagent such as urea or ammonia into th e 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 ov er 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. Thro ugh reduced capital costs, SNCR trim can significantly improve the cost-effectiveness of installed systems. Wall-fired boilers with first generation combustion modifica tions 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 uni t was able to achi eve emission rates as low as 0.14 lb/mmBtu. 10

SO2 Controls

There are a number of flue gas desulfur ization 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 co nfigurations. 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 technolo gies consist of lime spray drying, duct sorbent injection and furnace sorbent in jection. 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 system s 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 co al-fired units that are meeting a 0.15 lb/mmBtu emission rate. For the units bu rning 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 efficien cy is at Tampa Electric’s Big Bend units13 1 and 2. This installation has demonstr ated 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 system s to above 95 % removal efficiencies. 13 The available options typically improve the ga s-liquid contact and FG D chemistry. The gas-liquid contact category includes option s such as elimination of wall sneakage, improved liquid distribution by installati on new spray headers and or spray nozzles, increased recycle slurry pump flow, impr oved gas distribution. The chemistry category includes a wide array of options including limestone grind size, elimination of limestone blinding, introduction of forc ed 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 sp ray 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 hi gher than average gas velocity, lower than average spray density and reduced SO2 removal capacity.

Liquid distribution rings were develo ped 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 slu rry into the spray zone to increase the spray density close to the wall. The dist ribution rings are typically placed just below each spray level. Installation experience includes spray towers that are round as well as rectangular. Small roundand rectangular towers tend to benefit the most from the liquid distribution ring s as the wall sneakage tends to be more pronounced in these configurations. Em ission 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 fo r calcium based systems. A tray provides additional SO2 removal by creating additi onal surface area obtained from liquid holdup on the tray. Significant improvem ents in SO2 removal can be achieved with the addition of perforated trays howeve r there are several factors that must be considered before they are installed. Tr ays increase the pressure drop in the flue14 gas making their applicability depend ent 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 techno logy has advanced over the last three decades, some older system designs incl ude 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 th at 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 causedby inefficiencies in the original design, holes in piping due to erosion, or brokenor 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 pr event gas sneakage. While erosion and broken pipes can be addressed with the us e 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 i ssues to consider include de termining if the scrubber can handle the added flow without creating ga s distribution problems, creating gas sneakage, reducing mist eliminator pe rformance, 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. Di basic 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 ingranular form. Organic acids work by buffering the pH at the gas liquid interfac e, 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 beside s reduced operation and maintenance costs15 is the fact that it can be installed quickl y, 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 fl uid flow, heat transfer and mass transfer processes. For scrubber work improv ement, CFD modeling can provide visual images of gas velocity, pressure, and te mperature distribution within the tower. This tool is very helpful when eval uating 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 e ssentially the first type of control device installed on electric power plants. Elec trostatic precipitators and fabric filters (baghouses) are the two primary catego ries 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 part iculate (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 operat ing 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 high ly cost effective as those emission reductions that can be achieved at a co st of less than $900/ton. Using a cost effectiveness threshold of $900/ ton or less is almost half the cost considered cost effective in a number of the more recent regulations for the electric power sector. Table 3 below describes the cost effectiv e numbers that have been the outcome of State and Federal regulations.16 Table 3. Cost Effectiveness of State an d Federal SO2 and NOx Programs ($/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 co sts of implementing the Clean Air Interstate Rule are compared under va rious assumptions. In the proposed CAIR rule, the ‘knee’ in the margin al cost curve begins to incr ease at a higher rate above $2,000/ton. The BACT determinations refl ect the application of BACT for SO2 to new sources and major modifications at exis ting sources. These decisions, which include consideration of average and incre mental cost effectiv eness, 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 rece nt State decisions for annual SO2 controls where marginal cost information was ava ilable. These include the WRAP Regional SO2 Trading Program and statewide rules th at 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 highlycost effective for NOx reductions during the ozone season. The IPM results for the projecte d cost of implementing the Clean Air Interstate Rule are compared under va rious assumptions. In the proposed CAIR rule, the ‘knee’ in the margin al cost curve begins to incr ease at a higher rate above17 above $2,000 per ton. This is also in the ra nge 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 tr ansport 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 existi ng 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 config uration, coal type and existing control configurations). Additionally, the air po llution control industry in both Germany and Japan had already installed flue ga s 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 configuratio ns. 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 emis sion control technologies that could be employed although an exhaustive list was not prepared.

SO2 Control Technologies

The following tables provide informatio n on the cost for the installation of SO2 control systems for coal-fired industrialboilers. Cost estimates were provided for 90 % removal rates (unless otherwise stat ed) for boilers burning high sulfur coal. Estimates were provided for three different boiler heat capacities including: 100, 250 and 1000 mmBtu/hr. The cost estimate s that were provided were for dry sorbent injection type systems. The follo wing estimates did not include the cost of18 installing wet flue gas desulfurization (F GD) systems as the economics favor dry systems for these smaller type applicatio ns. 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 develo ped 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 cost s may be reduced is through the supply of standardized solutions. These pre-engin eered 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 theref ore 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 ha d 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 sorben t (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, furn ace injection, dry duct injection, etc). The dry sorbents are typically delivered inbulk 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 re agent will typically be ground to fine grade (20-25 μaverage size) before being used in the control system.

For reagent storage, the storage capa city 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. Fo r 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 fu rnace sorbent injection system. The major components of the system design include: reagent storage, metering, recording and conveying system; injection la nces; flue gas conditioning system; and ID fan. The reagent is injected in the fu rnace 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 in cluded in the costestimate 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 we re 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 typi cal 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 co ntrol device (pulse-jet baghouse); waste20 discharge system; and ID fan. The ot her components of the system such as electrical controls, motors, foundation, pipi ng, 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/tron a. In order to achieve a 90% sulfur removal efficiency, sodium bicarbonate or trona would be recommended for this system. Injection of dry hydrated lime w ill achieve greater than 50% removal but in a dry form it will not achieve the same re moval efficiencies as sodium bicarbonate or trona. Sodium bicarbonate and trona ar e 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 coul d be used with hydr ated 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 we re estimated at $15/ton Power costs were estimated at $0.04/kWh Sodium bicarbonate reagen t 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; instru ment to measure flue gas temperature; round vertical duct for reagent reaction (only if does not currently exist); particulate control device (pulse-jet baghouse); wast e 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 truc ks and would last 3-5 days. Quicklime is slaked with water to form a slurry wh ich is atomized through injection nozzles in21 the duct work between the boiler and part iculate control device. Optimally, the slurry would be injected in a location th at would permit the wa ter in the slurry to evaporate before the particles encounter du ct 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 sulf ur 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 % O 2 ). 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 combusti on 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 consideredis 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 th e 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 consider ed. Another consideration is whether the combustion control will be able to meet th e 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 numbe r 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 mo nitoring of emission s 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 reductio ns 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 du e to the rigidity of the MACT program.23 

### Appendix A

Table A1. 2002 Ozone Season NOx Emissions Rates for Coal-Fired Units 16 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 0.12724 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 0.18225 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 0.09626 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&SECT ION=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 Op erating 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, “Desig n and Initial Startup Results from the New Madrid SCR Project,” ICAC NOx Forum ’00, Washington, DC.

8DOE 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?PU BLIC_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 Sympos ium, Washington, DC.27 14J. 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?fus eaction=emisscreatequeries.timeframe