# Control Technologies to Reduce

Conventional and Hazardous Air

Pollutants from Coal-Fired Power Plants

March 31, 2011

### This Page Intentionally Blank

## Control Technologies to Reduce

Conventional and Hazardous Air Pollutants

from Coal-Fired Power Plants

Prepared For:

Northeast States for Coordinated Air Use Management

89 South Street, Suite 602 Boston, MA 02111

Prepared By:

James E. Staudt, Ph.D. Andover Technology Partners

M.J. Bradley & Associates LLC

March 31, 2011

©2011 by Andover Technology Partners

All Rights Reserved

## Table of Contents

Executive Summary .................................

................................................... .................................... 1

Introduction ......................................

................................................... ............................................ 5

Transport Rule ....................................

................................................... ................................. 5

Air Toxics Rule ...................................

................................................... ................................. 7

Overview of Air Pollution Control Technologies ....

................................................... .................... 8

Methods for Controlling SO 2 

### Emissions......................................... ................................................ 8

Lower Sulfur Coal..................................

................................................... .............................. 9

Flue Gas Desulfurization (FGD) or “Scrubbing” .....

................................................... ......... 10

Wet Scrubbers .....................................

................................................... ............................... 10

Dry Scrubbers .....................................

................................................... ............................... 11

Upgrades to Existing Wet FGD Systems ..............

................................................... ............. 12

Dry Sorbent Injection (DSI)........................

................................................... ....................... 13

Methods for Controlling NOx Emissions .............

................................................... ..................... 14

Combustion Controls ...............................

................................................... .......................... 15

Post-Combustion NOx Controls ......................

................................................... .................. 16

Methods for Controlling Hazardous Air Pollutant Emi ssions ............................................ .......... 18

Control of Mercury Emissions ......................

................................................... ..................... 18

Acid Gas Control Methods ..........................

................................................... ...................... 21

PM Emissions Control ..............................

................................................... ......................... 23

Control of Dioxins and Furans .....................

................................................... ...................... 25

Labor Availability ................................

................................................... ...................................... 26

Conclusion ........................................

................................................... ......................................... 27

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## Executive Summary

To implement requirements adopted by Congress in th e federal Clean Air Act (CAA), the U.S. Environmental Protection Agency (EPA) is developing new rules to reduce air pollution from fossil fuel power plants. Power plants that burn coal will bear a large responsibility for reducing their emission s further, as the majority of air pollutants from the electric generation sector come from coal combusti on.

The major rules addressing power plant pollution th at EPA recently proposed are the Clean Air Transpor t Rule (Transport Rule), and the National Emission St andards for Hazardous Air Pollutants from Electric Utility Steam Generating Units (Air Toxics Rule). The Transport Rule will address the long-range interstate transport of sulfur dioxide (SO 2 ) and nitrogen oxides (NOx) in the eastern United S tates. Both these types of pollutants contribute to formation o f small particles (“fine particulates”) in the atmo sphere that can be transported long distances into downwin d states. These small particles can be inhaled dee p into the lungs, causing serious adverse health impa cts. Nitrogen oxides also contribute to the format ion and long-range transport of ground-level ozone, ano ther pollutant with significant health impacts. Th e Air Toxics Rule will address emissions of hazardous air pollutants (HAPs) such as mercury, lead, arsen ic, along with acid gases such as hydrogen chloride and hydrogen fluoride and organic air toxics (e.g., dioxins and furans). HAPs are chemical pollutants that are known or suspected to cause cancer or othe r serious health effects, such as reproductive proble ms or birth defects, and that adversely affect the

environment.

These regulations will require coal-fired power pla nts that have not yet installed pollution control equipment to do so and, in some cases, will require plants with existing control equipment to improve performance.

Over the last several decades, state and federal cl ean air rules to address acid rain and ground-level smog led to power plant owners successfully deploying a range of advanced pollution control systems at hundreds of facilities across the country, providin g valuable experience with the installation and ope ration of these technologies. In addition, many states ad opted mercury reduction requirements in the absence of federal rules, leading to new controls and signific ant reductions of this air toxic from a number of c oal power plants over the past several years. This has provided industry with a working knowledge of a su ite of air pollution control devices and techniques tha t can comply with EPA’s proposed Transport Rule and

Air Toxics Rule.

This report provides an overview of well-establishe d, commercially available emission control technologies for SO 2 and NOx, and HAPs, such as mercury, chromium, lead and arsenic; acid gases, such as hydrogen chloride and hydrogen fluoride; dioxins and furans; and other toxic air emissions.

The key findings of the report include:

 The electric power sector has a range of available technology options as well as experience in their installation and operation that will enabl e the sector to comply with the Transport

Rule and the Air Toxics Rule.

o The electric power sector has long and successful e xperience installing many of the required pollution control systems.

### 2 | P a g e o The first flue gas desulfurization (scrubber) syste m was installed in 1968 and more than 40 years later, the plant is still in operation and undergoing a performance upgrade.

o To reduce SO 2 emissions, about 60 percent of the nation’s coal f leet has already installed scrubber controls, the most capital intensive of th e pollution control systems used by coal-fired power plants.

o About half of the nation’s coal fleet has already i nstalled advanced post-combustion NOx controls, with the first large-scale coal-fired sel ective catalytic reduction (SCR) system on a new boiler in the U.S. placed in service in 19 93 and the first retrofit in the U.S. placed in service in 1995.

 Modern pollution control systems are capable of dra matically reducing air pollution emissions from coal-fired power plants.

o Although scrubbers installed in the 1970s and 1980s typically obtained 80-90 percent

SO 2 removal, innovation has led to modern systems now capable of achieving 98 percent or greater removal.

o SCR can achieve greater than 90 percent NOx removal

.

o Coal-fired power plants, equipped with baghouse sys tems, report greater than 90 percent removal of mercury and other heavy metals.

 Pollution controls that significantly reduce mercur y emissions from coal-fired power plants have already been installed, demonstrated, and in o peration at a significant number of facilities in the United States. This experience d emonstrates the feasibility of achieving the mercury emissions limits in the proposed Air Toxics Rule.

o In 2001, under cooperative agreements with the Depa rtment of Energy, several coal plant operators started full-scale testing of activated c arbon injection (ACI) systems for mercury control.

o Since 2003, many states have led the way on mercury control regulations by enacting statewide mercury limits for coal power plants that require mercury capture rates ranging from 80 to 95 percent. Power plants in a number of these states have already installed and are now successfully operating mercury controls that provide the level of mercury reductions sought in EPA’s proposed Air Toxics Rule

.

o At present, about 25 units representing approximate ly 7,500 MW are using commercial technologies for mercury control. In addition, the Institute of Clean Air Companies (ICAC), a national association of companies providi ng pollution control systems for power plants and other stationary sources, has repo rted about 55,000 MW of new bookings.

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 A wide variety of pollution control technology solu tions are available to cost-effectively control air pollution emissions from coal-fired power plant s, and many technologies can reduce more than one type of pollutant.

o A variety of pollution control solutions are availa ble for different plant configurations.

o The air pollutants targeted by the Transport Rule a nd the Air Toxics Rule are captured to some degree by existing air pollution controls, and , in many cases, technologies to control one pollutant have the co-benefit of also controlling other pollutants. For example, scrubbers, which are designed to control S O 2 , are also effective at controlling particulate matter, mercury, and hydrogen chloride.

o Dry sorbent injection (DSI) has emerged as a potent ial control option for smaller, coalfired generating units seeking to cost-effectively control SO 2 and acid gas emissions.

o As highlighted below in Table ES-1, because of thes e “co-benefits,” in many cases it may not be necessary to add separate control technologi es for some pollutants.



### Table ES

- 1. **Control Technology Emission Reduction Effect**

SO 2 NOx Mercury (Hg) HCl PM Dioxins/ Furans

Combustion Controls N Y C N N Y

SNCR N Y N N N N

SCR N Y C N N C

Particulate Matter Controls N N C N Y C

Low Sulfur Fuel Y C N C N N

Wet Scrubber Y N C Y C N

Dry Scrubber Y N C Y C* N

DSI Y C C Y N C

ACI N N Y N N Y

**N = Technology has little or no emission reduction effect**  **Y = Technology reduces emissions C = Technology is normally used for other pollutant**  **s, but has a co-benefit emission reduction effect** *** When used in combination with a downstream partic ulate matter control device, such as a baghouse** 

 The electric power sector has a demonstrated abilit y to install a substantial number of controls in a short period of time, and therefore s hould be able to comply with the timelines of the proposed EPA air rules.

o Between 2001 and 2005, the electric industry succes sfully installed more than 96 gigawatts (GW) of SCR systems in response to NOx requirements.

o In response to the Clean Air Interstate Rule (CAIR) , about 60 GW of scrubbers and an additional 20 GW of SCR were brought on line from 2 008 through 2010. Notably, most companies were “early movers,” initiating the insta llation process before EPA finalized

its rules.

### 4 | P a g e o Available technologies that are less resource and t ime-intensive will provide additional compliance flexibility. For example, DSI and dry s crubbing technology design and installation times are approximately 12 and 24 mont hs, respectively.



###  The electric power sector has access to a skilled w orkforce to install these proven control technologies.



### o In November 2010, ICAC sent a letter to U.S. Senato r Thomas Carper confirming the nation’s air pollution control equipment companies repeatedly ha ve successfully met more stringent NOx, SO 2 and mercury emission limits with timely installatio ns of effective controls and are well prepared to meet new EPA requirements.



### o Also in November 2010, the Building and Constructio n Division of the AFL-CIO sent a letter to Senator Carper indicating that “[t]here i s no evidence to suggest that the availability of skilled manpower will constrain pol lution control technology development.”



### o Actual installation of pollution control equipment far exceeded EPA’s earlier estimate of industry capability that it made during the Clean A ir Interstate Rule (CAIR) rulemaking.



### o In response to CAIR, boilermakers increased their m embership by 35 percent in only two years (between 1999 and 2001) to meet peak labor de mand.

In summary, a range of available and proven polluti on control technologies exists to meet the requirements of EPA’s proposed Transport Rule and A ir Toxics Rule. In many cases, these technologies, some of which have been operating for decades, have a long track record of effective performance at many coal-fired power plants in the U.S.

The electric power sector has shown that it is capa ble of planning for and installing pollution contro ls on a large portion of the nation’s fossil fuel generatin g capacity in a relatively short period of time. S uppliers have demonstrated the ability to provide pollution control equipment in a timely manner, and the skill ed

labor needed to install it should be available to m eet the challenge as well. Examples of successful pollution control retrofits are provided throughout this report.

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## Introduction

The U.S. Environmental Protection Agency (EPA) is c urrently developing two major air quality rules under the Clean Air Act (“CAA” or “the Act”) to red uce air pollution from power plants: (1) the Transport Rule, and (2) the Air Toxics Rule. These regulations will require certain power plants that have not installed pollution control equipment to do so and others to improve their performance. The discussion that follows provides an overview of the se regulations, including a discussion of the sourc es regulated by the rules and the air pollutants the r ules address. Both rules are being developed in re sponse to court decisions overturning prior EPA regulatory programs and have long been anticipated by the electric power sector.



### Transport Rule

The Transport Rule—proposed by EPA in July 2010—is designed to reduce the interstate transport of harmful air pollution from power plants in the east ern U.S. as required by the CAA. The “good neighbo r” provisions of the Act require states to prohibit ai r pollution emissions that “contribute significantl y” to a downwind state’s air quality problems. 1 For example, EPA found that power plants in West Virginia significantly affect the air quality status of coun ties in Ohio, Indiana, Pennsylvania, Kentucky, and Michigan—hindering these states from achieving or m aintaining federal air quality standards. 2

In keeping with the purpose of the “good neighbor” provisions in the Act, the Transport Rule will assi st states and cities across the eastern U.S. in comply ing with the national, health-based fine particulat e, or
PM 2.5 , and 8-hour ozone standards by limiting SO 2 and NOx emissions from power plants in the region. Fine particulates can be inhaled deep into the lung s, and have been linked to increased hospital admissions and emergency room visits for various re spiratory or cardiovascular diseases, respiratory illness and symptoms, lung function changes, and in creased risk of premature death. Ground-level ozon e is a respiratory irritant that adversely affects bo th people with respiratory disease and healthy chil dren and adults. Exposure to ozone through inhalation can r esult in reduced lung function and inflamed airways

, aggravating asthma or other lung diseases. As with fine particulate matter, ozone exposure is also li nked to increased risk of premature death.

The Transport Rule will replace the earlier Clean A ir Interstate Rule (CAIR) that EPA had issued in

March 2005. 3 Under CAIR, EPA limited NOx and SO 2 emissions from 28 states and the District of Columbia, and directed each state to file a plan fo r meeting those limits, or emission caps. In July 2008, however, the U.S. Court of Appeals for the District of Columbia Circuit struck down CAIR after finding

several flaws in the rule. 4 In a subsequent ruling, the court determined that CAIR could remain in place until EPA developed a replacement program. 5

Table 1

. **The Clean Air Transport Rule**

Regulated Pollutants Affected Sources Compliance Da tes Regulatory Mechanism **Sulfur dioxide (SO 2**  **)**

**Nitrogen oxides (NOx) Fossil fuel-fired power**  **plants 25 MW and larger**

**in 31 eastern states and**

**DC Phase 1: 2012** 

**Phase 2: 2014 EPA’s preferred approach** 

**would allow intrastate trading among covered**  **power plants with some limited interstate trading** 

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EPA’s proposed emissions caps for SO 2 and NOx are summarized in the following figures. EPA notes in the proposed rule that additional ozone season (May 1 to September 30) NOx reductions will likely be

needed to attain the national ozone standards. 6 Therefore, the agency plans to propose a new tran sport rule in 2011, to become final in 2012, to reflect t he revised National Ambient Air Quality Standards (NAAQS) for ozone when they are promulgated. While the Transport Rule only proposes to require reductions from the power sector, EPA notes, “it is possible that reductions from other source categor ies could be needed to address interstate transport req uirements related to any new NAAQS.” 7

EPA estimates that the proposed rule would yield $1 20 billion to $290 billion in annual health and welfare benefits in 2014, 8 which exceed the estimated $2.8 billion in annual costs that EPA estimates power plants will incur to comply with the rule by a factor of more than 30. 9 To meet the new requirements, EPA expects plants will employ a wide range of strategies, including operating already

**Clean Air Transport Rule: Proposed SO 2**  **Emissions Caps**

**EPA’s proposed Transport Rule would establish two i ndependent trading programs for SO**  **2 : (1) group 1 states; and (2) group 2**  **states (see maps below). SO 2**  **emissions from group 1 states would be capped at 3 .1 million tons per year beginning in 2012 and**  **1.7 million tons per year beginning in 2014. The 2 012 cap represents a 13 percent reduction below 200**  **9 emissions levels. SO 2**  **emissions from group 2 states would be capped at 0. 8 million tons beginning in 2012. The 2012 cap for**  **group 2 states represents a 29 percent reduction below 2009 emissions levels.** 

**0.0 0.5**  **1.0 1.5**  **2.0 2.5** 

**2000 2001 2002 2003 2004 2005 2006 2007 2008 2009** 2012 **proposed cap** SO 2**million tons** Group 2 states

**0.0 0.5**  **1.0 1.5**  **2.0 2.5** 

**2000 2001 2002 2003 2004 2005 2006 2007 2008 2009** 2012 **proposed cap** SO 2**million tons** Group 2 states

**0.0 2.0**  **4.0 6.0**  **8.0**

**2000 2001 2002 2003 2004 2005 2006 2007 2008 2009**

2012

2014 **proposed phase 1 cap**

**proposed phase 2 cap** SO 2**million tons** Group 1 states

**0.0 2.0**  **4.0 6.0**  **8.0**

**2000 2001 2002 2003 2004 2005 2006 2007 2008 2009**

2012

2014 **proposed phase 1 cap**

**proposed phase 2 cap** SO 2**million tons** Group 1 states **0.0 0.4**  **0.8 1.2**  **1.6 2.0** 

**2000 2001 2002 2003 2004 2005 2006 2007 2008 2009** 2012 Ozone

Season NOx

**proposed cap** Ozone season states**million tons**

**0.0 0.4**  **0.8 1.2**  **1.6 2.0** 

**2000 2001 2002 2003 2004 2005 2006 2007 2008 2009** 2012 Ozone

Season NOx

**proposed cap** Ozone season states**million tons**

**0.0 1.0**  **2.0 3.0**  **4.0 5.0** 

**2000 2001 2002 2003 2004 2005 2006 2007 2008 2009** 2012 Annual NOx

**proposed cap million tons**  annual states

**0.0 1.0**  **2.0 3.0**  **4.0 5.0** 

**2000 2001 2002 2003 2004 2005 2006 2007 2008 2009** 2012 Annual NOx

**proposed cap million tons**  annual states **Clean Air Transport Rule: Proposed NOx Emissions Ca ps** 

**EPA’s proposed Transport Rule would establish two N Ox programs: (1) an annual NOx program, and (2) an**  **ozone season (summer time) NOx program (see map below). Annual**  **NOx emissions would be capped at 1.4 million tons p er year beginning in**  **2012. The 2012 cap represents a 10 percent increas e over 2009 emissions levels. Ozone season NOx emi**  **ssions would be capped at 0.6 million tons beginning in 2012. The**  **ozone season cap represents a 15 percent increase o ver 2009 emissions levels.** 

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installed pollution control equipment more frequent ly, using low sulfur coal, or installing new contro l equipment.



### Air Toxics Rule

The U.S. EPA’s proposed Air Toxics Rule will establ ish, for the first time, federal limits on hazardou s air pollutant (HAP) emissions from coal- and oil-fired power plants. The HAPs covered include mercury, lead, arsenic, hydrogen chloride, hydrogen fluoride , dioxins/furans, and other toxic substances identi fied by Congress in the 1990 amendments of the CAA. The rule establishes “maximum achievable control technology” (MACT) limits for many of these.

The U.S. EPA’s prior effort to regulate HAP emissio ns from power plants was overturned by court challenges. On February 8, 2008, a federal court h eld that EPA violated the CAA when it sought to regulate mercury-emitting power plants through the Clean Air Mercury Rule (CAMR), an interstate capand-trade program issued by EPA in March 2005. 10 The court concluded that EPA violated the CAA by failing to make a specific health-based finding to remove electric generating units from regulation un der

CAA section 112. a

On March 16, 2011, EPA proposed its replacement for CAMR that would establish numerical MACT emission limits for existing and new coal-fired ele ctric power plants that would cover mercury, partic ulate matter (as the surrogate for non-mercury toxic meta ls), and hydrogen chloride (as the surrogate for to xic acid gases). The proposed rule would also establis h work practice standards for organic air toxics (e .g., dioxins and furans). 11 EPA projects the proposed rule will reduce mercur y emissions from covered power plants by 91 percent, acid gas emissions by 91 perc ent, and SO 2 emissions by 55 percent. 12 The projected mercury reductions are in the range of what a numbe r of states already require for coal-fired power plants. 13 A consent decree with public health and environme ntal groups requires EPA to finalize the standards by November 16, 2011. Table 2 summarizes elements of the proposed Air Toxics Rule.

EPA estimates that the Air Toxics Rule would yield $140 billion in annual health and welfare benefits in

2016. 14 The estimated annual cost of the program is $10.9 billion. 15 EPA emphasizes that the proposed rule would cut emissions of pollutants that are of particular concern for children. Mercury and lead can adversely affect developing brains–including effect s on IQ, learning, and memory.

Table 2

. **The Air Toxics Rule**

Regulated Pollutants Affected Sources Compliance Da tes Regulatory Mechanism **Mercury**

**Non-mercury metals, such as arsenic,**  **chromium, cadmium,**

**and nickel**

**Organic HAPs (e.g., dioxins/furans)** 

**Acid gases (HCl, HF) Coal- and oil-fired power**  **plants 25 MW and larger Early 2015** 

Note: **EPA can grant a one year extension for a source** 

**to install controls Numerical emission limits**  **for mercury, other toxic metals, and acid gases;**  **work practice standards for organic air toxics (e.g.,**  **dioxins/furans)**

a “ EPA’s removal of these [electric generating units] from the section 112 list violates the CAA because section 112(c)(9) requires EPA to make specific findings be fore removing a source listed under section 112; EP A concedes it never made such findings. Because coal-fired [e lectric generating units] are listed sources under section 112, regulation of existing coal-fired [electric generat ing units’] mercury emissions under section 111 is prohibited, effectively invalidating CAMR’s regulatory approach .” New Jersey v. EPA, 517 F.3d 574 (D.C. Cir. 2008 ).

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## Overview of Air Pollution Control Technologies

There are a wide range of technologies available fo r controlling air pollution emissions from coal-fir ed power plants. The most appropriate combination of control technologies will vary from plant-to-plant depending on the type and size of the electric gene rating unit, age, fuel characteristics, and the boi ler design.

Many of the air pollutants targeted by the proposed Transport Rule and the Air Toxics Rule are capture d to some degree by existing air pollution control de vices. Table 3 summarizes the various pollutants a nd the technologies that are currently being applied o r may be applied in the future to control them. In many cases, technologies designed to control one polluta nt will also control others. These “co-benefits” m ay or may not be adequate to achieve compliance with the Transport Rule or the Air Toxics Rule. As a result

, in some cases, it may be necessary to add separate control technologies for some pollutants.

Table 3. **Control Technology Emission Reduction Effect**

SO 2 NOx Mercury (Hg) HCl PM Dioxins/ Furans

Combustion Controls N Y C N N Y

Selective Non

- Cata lytic Reduction (SNCR) N Y N N N N

Selective Catalytic Reduction (SCR) N Y C N N C

Particulate Matter Controls (i

. e. , ESP or baghouse) N N C N Y C

Lower Sulfur Fuel Y C N C N N

Dry Scrubber Y N C Y C* N

Wet Scrubber Y N C Y C N

Dry Sorbent Injection (DSI) Y C C Y N C
Activated Carbon Injection (ACI) N N Y N N Y

**N = Technology has little or no emission reduction effect**  **Y = Technology reduces emissions C = Technology is normally used for other pollutant**  **s, but has a co-benefit emission reduction effect** *** When used in combination with a downstream partic ulate matter control device, such as a baghouse** 



## Methods for Controlling SO 2 

## Emissions

SO 2 is a highly reactive gas linked to a number of adv erse effects on the human respiratory system. In 2008, power plants accounted for 66 percent of the national SO 2 emissions inventory, 16 with the vast majority of this contribution (more than 98 percent ) coming from coal-fired power plants. 17

There are two basic options for controlling SO 2 emissions from coal-fired power plants, which is f ormed from the oxidation of sulfur in the fuel: (1) switc hing to lower sulfur fuels; and (2) SO 2 capture, including Flue Gas Desulfurization (FGD), or more commonly re ferred to as “scrubbing.” Table 4 shows the various methods for controlling SO 2 emissions. These methods include those that have been widely used on power plants, such as low sulfur coal and scrubb ing, as well as less costly technologies that may b e more attractive for smaller boilers, such as dry so rbent injection (DSI).

### 9 | P a g e Table 4. **SO 2**  **Emissions Control Methods**

Methods of C ontrol

Lower Sulfur Fuel **Method – Lower sulfur fuel reduces SO 2**  **formation Reagent – None**  **Typical fuel types – Powder River Basin coal and lo wer sulfur bituminous coal**  **Capital Cost – Low Co-benefits – May reduce NOx, HCl, and HF emissions**  Dry Sorbent Injection **Method – Dry Sorbent Injection captures SO 2**  **at moderate rates, downstream PM control device captures dry product**  **Reagent – Trona, sodium bicarbonate, hydrated lime Typical Fuel Types – Most often solid fuels (i.e.,**  **coals – lignite, sub-bituminous,**

**bituminous) Capital Costs- Low to moderate**  **Co-benefits – NOx and HCl and HF reduction, Hg redu ction, removal of chlorine,**  **a precursor to dioxins/furans** Dry Scrubber with F abric

Filter **Method – Reagent + water react to capture acid gase s and dry product captured** 
**in downstream fabric filter Reagent – Hydrated lime**  **Typical Fuel Types – Coal Capital Costs – High**  **Co-benefits – High SO 2**  **and Hg capture (esp. bituminous coals), high PM an d** 

**HCl capture**

Wet Scrubber **Method – Reagent + water react to capture acid gase s**  **Reagent – Limestone, lime, caustic soda Typical Fuel Types – Coal, petroleum coke, high su**  **lfur fuel oil Capital Costs – High**  **Co-benefits –Highest SO 2**  **capture, high oxidized Hg and high HCl capture, PM capture**  Wet Scrubber Upgrades **Method – Upgrade older scrubbers to provide perform ance approaching those of** 

**new scrubbers Reagent – Limestone, lime, etc.**  **Typical Fuel Types – Coal, petroleum coke, high su lfur fuel oil**  **Capital Costs – Low to moderate**

**Co-benefits – Same as wet scrubber**

Co

- benefit Methods of Control

None **SO 2**  **is a key pollutant that often is the major driver in emission control technology** 

**selection**



### Lower Sulfur Coal

Changing to lower sulfur coal was the most widely u sed approach for compliance with the Acid Rain Program (Title IV of the 1990 Clean Air Act Amendme nts). Certain coal types are naturally low in sulfur, such as sub-bituminous coal mined in the Po wder River Basin (PRB) of Montana and Wyoming. b

Some facilities cannot burn 100 percent PRB coal wi thout substantial modifications to the boiler or fu el handling systems. These facilities can blend PRB o r another lower sulfur coal with a bituminous coal to
reduce emissions. Facilities that are not able to burn lower sulfur coals or facilities needing great er SO 2 emissions reductions may need some form of flue gas treatment.

b Coal is classified into four general categories, o r “ranks.” They range from lignite through sub-bit uminous and

bituminous to anthracite. Sub-bituminous and bitum inous coals are the most widely used coal types, an d the SO 2 emissions from burning these fuels can vary by a fa ctor of 10 or more, depending upon the fuel sulfur content and the heating value of the fuel. Lignite fuels have low heating values, making them uneconomical to tra nsport, and are generally limited in use to mine-mouth plants. Ant hracite coal is used in very few power plants.

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Co-benefits of low sulfur coal – PRB coal is relatively low in nitrogen, which res ults in lower NOx emissions. It is also very low in chlorine, so hyd rogen chloride (HCl) emissions are low for PRB coal

.



### Flue Gas Desulfurization (FGD) or “Scrubbing”

As EPA and states have further limited SO 2 emissions, an increasing number of coal-fired powe r plants have installed FGD systems. FGD controls enable a plant operator to use a wider variety of coals whil e maintaining low SO 2 emissions. There are two basic forms of FGD – wet and dry. As shown in Table 5, nearly two-thirds of the coal-fired power plant cap acity in the United States is scrubbed or is projec ted to be scrubbed in the near future. Most plant operato rs have opted for wet FGD systems, particularly on larger coal-fired power plants. In response to the Clean Air Interstate Rule, coal-fired power plants added about 60 gigawatts (GW) of scrubbers in the three y ear period from 2008 through 2010. 18

Table 5. **Coal-Fired Power Plant Scrubbers 19** 

Scrubber Type Sum of Capacity ( % ) # Boilers Average Capacity (MW)
**FGD (wet) 170 GW (52%) 371 457 FGD (dry) 22 GW (7%) 114 196** 
Total Scrubbed 19 2 GW (59%) 485 396 **No scrubber 134 GW (41%) 788 171**

Total 326 GW 1,273 256



### Wet Scrubbers

Wet scrubbers are capable of high rates of SO 2 removal. In a wet FGD system, a lime or limestone slurry

reacts with the SO 2 in the flue gas within a large absorber vessel to capture the SO 2 , as shown in Figure 1. 20 Wet FGD systems may use lime or limestone. Lime is more reactive and offers the potential for higher reductions with somewhat lower capital cost; however, lime is also the more expensive reagent. As a result, limestone-forced oxidation (LSFO) wet scrubber technology is the most widely used form of wet FGD and is more widely used on coal-fired power plants than every other form of FG D combined. State-of-the-art LSFO systems are capabl e of providing very high levels of SO 2 removal – on the order of 98 percent or more

.

The first wet scrubber system in the U.S. was desig ned by Black & Veatch and installed in 1968 at the Lawrence Energy Center in Kansas. More than 40 years later, the system is still in operation, and the facility is undertaking a major upgrade to improve the system’s performance. The facility is also adding a pulse jet fabric filter. 21

In the absorber, the gas is cooled to below the saturation temperature, resulting in a wet gas and high rates of capture. Modern wet scrubbers typically h ave SO 2 removal rates of over 95 percent and can be in the range of 98 percent to 99 percent. 22 The reacted Figure 1

**.** Wet Flue Gas Desulfurization
**Image courtesy of Babcock and Wilcox Company**

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limestone and SO 2 form a gypsum by-product that is often sold for th e manufacturing of wallboard.

Because a wet FGD system operates at low temperatur es, it is usually the last pollution control device before the stack. The wet FGD absorber is typicall y located downstream of the PM control device (most often an electrostatic precipitator though many pow er plants have baghouses) and immediately upstream of the stack. Wet FGD is frequently used to treat the exhaust gas of multiple boilers with the gases being emitted through a common stack. A single absorber can handle the equivalent of 1,000 megawatts (MW) of flue gas.

Wet scrubber retrofits are capital intensive due to the amount of equipment needed, and recent

installations for the Clean Air Interstate Rule hav e been reported to have an average cost of $390/kW. 23 EPA estimates a capital cost of about $500/kW ($200 7) for a wet scrubber (limestone forced oxidation)

on a 500 MW coal unit. 24 There can be, however, a significant variation in costs depending upon the size of the unit and the specifics of the site. General ly, smaller boilers (under 300 MW) have been shown to be significantly more expensive to retrofit with we t scrubbers (capital cost normalized to a $/KW basi s) than larger boilers due to economies of scale. The economies of scale become less significant as boil er size increases. 25 As a result, wet scrubbers are a less attractive alternative for controlling SO 2 on small units. Companies can sometimes offset the cost of installing wet scrubber technology by switching to less expensive high sulfur coal supplies. Because of th e high capital costs of the technology, wet scrubbe rs are generally only installed on power plants where the owner expects to operate the plant for an exten ded number of years.

Due to their complexity and the size of the equipme nt, EPA estimates that the total time needed to complete the design, installation, and testing of a wet FGD system at a typical 500 MW power plant wit h one FGD unit is 27 months, and longer if multiple b oilers or multiple absorbers are necessary. Actual installation times will vary based upon the specifi cs of the plant, the need to schedule outages with FGD hook up, and other factors.

Co-benefits of wet FGD – FGDs have been shown to be effective at removing other pollutants including pa rticulate matter, mercury, and hydrochloric acid. For this r eason, facilities that are equipped with wet or dry FGD sy stems may
avoid the need to install additional controls for h azardous air pollutants.



### Dry Scrubbers

Dry scrubber technology (dry FGD) injects hydrated lime and water (either separately or together as a slurry) i nto a large

vessel to react with the SO 2 in the flue gas. Figure 2 shows a schematic of a dry scrubber.

The term “dry” refers to the fact that, although wa ter is added to the flue gas, the amount of water added is only just enough to maintain the gas above the saturation (dew point ) temperature. In most cases, the reaction products and any unreacted lime from the dry FGD process are capture d in a downstream fabric filter (baghouse), which helps pr ovide additional capture of SO 2 . Modern dry FGD systems typically provide SO 2 capture rates of 90 percent or more. Figure 2 **. Dry Flue Gas Desulfurization**
**Image courtesy of Babcock and Wilcox Company**

### 12 | P a g e

Historically, dry FGDs have been used primarily on low sulfur coals because the reagent, lime, is more expensive than reagents used in wet FGD systems. A lso, because the systems are designed to maintain the flue gas temperatures above the dew point, this limits the amount of SO 2 that can be treated by a spray dryer. Another form of dry FGD, circulating dry sc rubber systems (CDS), inject the water and lime separately, and have been shown to achieve high SO 2 removal rates in excess of 95 percent on higher sulfur coals. Lime is more costly than limestone, the most commonly used reagent for wet scrubber
systems.

Dry FGD systems tend to be less expensive than wet FGD systems because they are less complex and generally smaller in size. They also use less wate r. The lower reagent cost of wet FGD and the abili ty to burn lower cost, higher sulfur coals make wet FGD m ore attractive for large facilities. EPA estimates a capital cost of about $420/kW ($2007) for a dry scr ubber (lime spray dryer) on a 500 MW coal unit. 26
The Turbosorp system installed at the AES Greenidge plant in New York cost $229/KW ($2005). 27
Depending upon the specifics of the facility to be retrofit, the cost could be higher in some cases.

Dry FGD systems are less complex and generally requ ire less time to design and install than wet FGD systems. The Institute to Clean Air Companies (ICA C) estimates that dry scrubbers can be installed in a time frame of 24 months. 28

Co-benefits of Dry FGD – Dry FGD pollutant co-benefits include greatly en hanced capture of hazardous air pollutants, especially PM, mercury and HCl (as discussed later in the report).



### Upgrades to Existing Wet FGD Systems

Modern wet FGD systems are capable of SO 2 removal rates in the range of 98 percent or more.

Limestone wet scrubber removal efficiencies have im proved dramatically since the 1970s as shown in Figure 3. 29 As a result, there are opportunities to improve s crubber performance from many existing

scrubbers that were built in the 1970s and 1980s. An advantage of this approach is that substantial S O 2 reductions are possible at a far lower cost than in stalling a new scrubber and in a much shorter perio d of time. Each scrubber upgrade is unique, so cost and schedule will vary. Depending upon the scope of a scrubber upgrade, a scrubber upgrade could be imple mented in under a year as opposed to three to four years for a new scrubber installation. All key are as of many older FGD systems (absorber, reagent preparation, and dewatering) can benefit from moder n upgrades. Because each system is unique, an 

# Case Study: Dry Scrubber

In Massachusetts, First Light’s Mt. Tom Power Plant , a 146 MW coal-fired unit that went into service i n 1960, installed state-of-the-art pollution control equipment in 2009 to meet state and federal
environmental regulations. In December 2009, the p lant installed a circulating dry scrubber to reduce SO 2 and mercury emissions during a routine outage. A p recipitator and baghouse were also installed to rem ove particulate matter emissions. Total project costs were $55 million, or $377/kW. The project has redu ced the plant's SO 2 emissions by approximately 70 percent, with the pl ant’s 2009 SO 2 emission rate of 0.73 lbs

SO 2 /mmBtu dropping to 0.22 lbs SO 2 /mmBtu in 2010.

Source: U.S. Environmental Protection Agency, Clean Air Mar kets-Data and Maps; http://camddataandmaps.epa.gov/gdm/index.cfm?fuseac tion=emissions.wizard (accessed March 17, 2011).

### 13 | P a g e

effective FGD system-wide upgrade process is most s uccessful after an extensive system review and diagnostics.

There have been numerous examples of FGD upgrades o ver the last several years that have improved SO 2 removal efficiencies. For example, the Fayette Sta tion Unit 3, a 470 MW tangentially-fired coal unit in Texas, completed an upgrade to its 1988-vintage scr ubber in 2010. The plant’s control efficiency was increased from about 84 percent to 99 percent, high er than the guaranteed SO 2 removal efficiency of 95.5

percent. 30 In Kentucky, E.On’s Trimble County Generating Station Unit 1, a 550 MW tangentially-fired coal boiler, completed a scrubber upgrade in 2006. Its scrubber, installed in the 1980s, was originally designed for 90 percent removal efficiency. The scrubber system is now able to achieve over 99 percent SO 2 removal efficiency. 31 In Indiana, NiSource upgraded the scrubbers at

Schahfer Units 17 and 18 in 2009. 32 The scrubber upgrades increased SO 2 removal efficiency from 91 percent to 97 percent. 33



### Dry Sorbent Injection (DSI)

DSI is the injection of dry sorbent reagents that r eact with SO 2 and other acid gases, with a downstream PM control device to capture the reaction products.

The most common DSI reagent in use is Trona, a natu rally occurring mixture of sodium carbonate and

sodium bicarbonate mined in some western states. O ther reagents have also been used, such as sodium bicarbonate and hydrated lime. Sodium bicarbonate is capable of higher SO 2 removal efficiencies than

Trona because it is more reactive. Trona can achie ve varying levels of SO 2 reductions, from a range of 30-60 percent when injected upstream of an ESP, or up to 90 percent when injected upstream of a fabric filter. Fabric filters allow greater contact betwe en the gas and the injected sorbent than ESPs, enab ling better removal for any given reagent treatment rate . The level of removal will vary depending upon th e circumstances of the facility and the injection sys tem.

DSI equipment is relatively simple and inexpensive when compared to a scrubber and can be installed typically within 12 months. 34 Unlike scrubbers that require additional reaction chambers to be installed, in DSI the reaction occurs in the existing ductwork and air pollution control equipment. The basic injection system with storage silo costs around $20 /kW; however, in some cases additional storage and material handling may be necessary that will add co st. But, even with the additional equipment, the capital cost of a DSI system will be substantially less than that of a full wet or dry scrubber, which can cost as high as $400/kW. Reagents used in DSI are more costly than those used in wet or dry scrubbers

, and the reagent is not as efficiently utilized, whi ch can contribute to a higher cost of control in te rms of dollars per ton of SO 2 reduced. Figure 3. Historical Trends in Limestone Wet Scrub ber SO 2 Removal Efficiency of Limestone Wet Scrubbing Syste ms

### 14 | P a g e

Co-benefits of DSI – DSI has been shown to be very effective in the capt ure of the acid gases, HCl and HF. DSI has been shown to enhance mercury capture for facilities that burn bituminous coal by removin g sulfur trioxide (SO 3 ) that is detrimental to mercury capture through AC I. In the case of PRB coals, the impact on mercury capture might be negative. Injec tion of Trona or sodium bicarbonate can also remove NOx in the range of 10-20 percent, although NOx rem oval is generally not a principal objective of DSI. 35
If DSI is installed at a point in the gas stream th at is upstream of the dioxins/furans formation temperature, it is expected to remove the precursor chlorine that leads to their production.



## Methods for Controlling NOx Emissions

Nitrogen oxides (NOx) are an acid rain precursor an d a contributor to the formation of ground-level ozone, which is a major component of smog. In 2008 , power plants accounted for 18 percent of the national NOx emissions inventory. Most of the NOx formed during the combustion process is the result of two oxidation mechanisms: (1) reaction of nitrog en in the combustion air with excess oxygen at elevated temperatures, referred to as thermal NOx; and (2) oxidation of nitrogen that is chemically bo und in the coal, referred to as fuel NOx. Controlling NOx emissions is achieved by controlling the format ion of NOx through combustion controls or by reducing N Ox after it has formed through post-combustion controls. Table 6 summarizes key NOx control techn ologies. 

# Case Study: Dry Sorbent Injection

Conectiv Energy installed a DSI Trona system at Edg e Moor Units 3-4 to comply with Delaware’s multipollutant emissions control rule. The project was several years in planning and operated from 2009 to mid2010. The emission rates went from 1.2 lbs SO 2 /mmBtu to 0.37 lbs SO 2 /mmBtu with the use of Trona.
Since the purchase of the facility by Calpine in mi d-2010, coal is no longer burned thus eliminating t he need for the Trona system. In New York, NRG installed a Trona system at its Dunkirk (530 MW) and Huntley stations (380 MW). This project is the first of it s kind in the U.S. in which Trona and powder-activa ted carbon (PAC) are simultaneously injected into the f lue gases to control both SO 2 and mercury emissions.
The DSI system included several Trona storage and i njection systems with equipment buildings, 6000 fee t of
transport piping, Trona railcar unloading and trans fer systems, and associated bulk storage silos.

Performance tests indicate that emissions of SO 2 have been reduced by over 55 percent, mercury leve ls
have been reduced by over 90 percent, and particula te levels have been reduced to less than 0.010 lbs/mmBtu.

Source: Pietro, J. and Streit, G. (NRG Energy). “NRG Dunki rk and Huntley Environmental Retrofit Project.” Pre sented to Air & Waste
Management Association – Niagara Frontier Section, September 23, 2010.

### 15 | P a g e Table 6. **NOx Emissions Control Methods**

Methods of C ontrol

Combustion Controls **Method – Reduce NOx formation in the combustion pro cess itself for**  **levels of reduction that vary by application Reagent – None**  **Typical fuel types – All fuels Capital Cost – Low to moderate**  **Co-benefits – Potential impacts on Hg, CO and precu rsors of** 

**dioxins/furans**

Selective Non

- Catalytic

Reduction **Method – Reagent injected into furnace reacts with and reduces NOx at** 
**moderate removal rates of about 30% Regent – Urea or ammonia**  **Typical Fuel Types – Most often solid or liquid fue ls**  **Capital Costs- Low**

**Co-benefits - None** Selective Catalytic

Reduction **Method – Reagent reacts with NOx across catalyst be d and reduces**  **NOx at high rates of about 90% Reagent – Ammonia (or urea that is converted to amm**  **onia) Typical Fuel Types – Any fuel**  **Capital Costs – High Co-benefits – Oxidation of Hg for easier downstream**  **capture in a wet scrubber, reduction of dioxins/furans** 

Co

- benefit Meth ods of Control

Low Sulfur Coal **Conversion to PRB coal for SO 2**  **reduction will also reduce NOx due to lower fuel nitrogen in PRB coal**  Dry Sorbent Injection **DSI with Trona can provide NOx reduction of about 1 0-15%** 



### Combustion Controls

Combustion controls minimize the formation of NOx w ithin the furnace and are frequently the first choice for NOx control because they are usually low er in cost than post-combustion controls. For most forms of combustion control, once installed there i s little ongoing cost because there are no reagents or catalysts to purchase. Combustion controls reside within the furnace itself, not in the exhaust gas s tream, and include such methods as low NOx burners (LNB), over-fire air (OFA), and separated over-fire air (SOFA). Reburning technology is another combustion control option, but it chemically reduces NOx formed in the primary combustion zone. Reburning t echnology may also utilize natural gas.

Most utilities have already achieved substantial re ductions in NOx emissions from implementation of combustion controls, sometimes in combination with post-combustion controls. There are some facilitie s that can still benefit from combustion controls, bu t these are generally the smaller units where utili ties have not yet invested in NOx controls.

The capital cost of these combustion controls will vary; however, the capital cost is generally far le ss than that of more costly post-combustion control options , such as Selective Catalytic Reduction (SCR). The capital costs of combustion controls could be anywh ere from about $10/kW to several times that, but generally fall below $50/kW. Except for gas reburn ing, there is little or no increase in operating or fuel

costs.

Co-benefits of Combustion NOx Controls – Combustion controls may enhance mercury capture at coalfired power plants because they can increase the le vel of carbon in the fly ash. While higher carbon in the

### 16 | P a g e

fly ash is generally viewed negatively because it i s the result of incomplete combustion, it does prov ide a real benefit in enhancing mercury capture. Combust ion controls can also have a positive impact on CO emissions and on concentrations of organic precurso rs to dioxins/furans.



### Post-Combustion NOx Controls

There are limits to the level of NOx control that c an be achieved with combustion controls alone. Therefore, post-combustion controls are necessary t o achieve very low emissions of NOx. Combustion NOx controls and post-combustion NOx controls can, and often are, used in combination. About half of the nation’s coal fleet has already installed advan ced post-combustion NOx controls (Table 7).

Table 7. **Coal-Fired Power Plant Post-Combustion NOx Contro ls**  **36**

Control Type Sum of Capacity (% ) # Boilers Av erage Capacity (MW)
**SCR 129 GW (40%) 259 499 SNCR 29 GW (9%) 172 166** 

Total Post

- Combustion NOx 1 58 GW (49%) 431 366 **No Post-Combustion NOx 842 GW (51%) 842 198**

Total 32 4 GW 1,273 255



### Selective Catalytic Reduction (SCR)

SCR technology, which has been in use at coal-fired power plants for more than 15 years in the United States, is a post-combustion NOx control system tha t is capable of achieving greater than 90 percent removal efficiency. 37 The first large-scale coal-fired selective cataly tic reduction (SCR) system on a new boiler in the U.S. was placed in service in 1993 in New Jersey, and the first retrofit in the U.S. wen t into service in 1995 at a power plant in New Hampshire. 38 About 130 GW of the total coal-fired generating capacity in the U.S. is now equipped with SCR, and more SCRs are planned for existing units. Between 2001 and 2005, the electric industry installed more than 96 GW of SCR systems in response to the NOx SIP Call. Coal plant operators installed an additi onal 20 GW of SCR from 2008 through 2010 in respons e to the Clean Air Interstate Rule. 39

SCR utilizes ammonia as a reagent that reacts with NOx on the surface of a catalyst. The SCR catalyst reactor is installed at a point where the temperatu re is in the range of about 600°F-700°F, normally placing it after the economizer and before the air- preheater of the boiler. The SCR catalyst must periodically be replaced. Typically, companies wil l replace a layer of catalyst every two to three ye ars. Multiple layers of catalysts are used to increase t he reaction surface and control efficiency (Figure 4).

SCR system capital costs will vary over a wide rang e depending upon the difficulty of the retrofit. S ome retrofits have been reported to cost under $100/kW, while others have been reported to cost over $200/kW. 40 Operating costs include ammonia reagent, periodic catalyst replacement, parasitic power, and fixed operating costs.



### The EPA estimates that the total time needed to complete the design, insta llation, and testing at a facility with one SCR unit is about 21 months, and longer for plants that have multiple units to be

retrofitted with SCR. 41

### 17 | P a g e

Selective Non-Catalytic Reduction (SNCR)

SNCR is another post-combustion NOx control technol ogy. It typically achieves in the range of 25-30 percent NOx reduction on units equipped with low NO x burners. SNCR reduces NOx by reacting urea or ammonia with the NOx at temperatures around 1,800°F -2,000°F. Therefore, the urea or ammonia is injected into the furnace post-combustion zone itse lf and, like SCR, reduces the NOx to nitrogen and

water.

The capital cost of SNCR is typically much less tha n that of SCR, falling in the range of about $10- $20/KW, or about $4 million or less for a 200 MW pl ant. The operating cost of SNCR is primarily the cost of the ammonia or urea reagent. SNCR is most commonly applied to smaller boilers. This is partl y because the economics of SCR are more challenging for small boilers. Furthermore, when emissions regulations allow averaging or trading of NOx emissions among units under a common cap, installing an SCR on a large boiler allows utilities to over-control the large unit and use less costly technology, such as SNCR or combustion controls,

for NOx control on smaller units.

SNCR systems are relatively simple systems that can be installed in a period of about 12

months.



### Hybrid SNCR/SCR

SNCR and SCR may be combined in a “hybrid” manner. In this case, a small layer of catalyst is installed in ductwork

downstream of the SNCR system. With the downstream catalyst, the SNCR sys tem can be operated in a manner that provides higher NOx removal rates while using the SCR cataly st to mitigate the undesirable ammonia slip from th e SNCR system. Although some NOx reduction occurs ac ross the SCR catalyst, its function is primarily as a means to reduce ammonia slip to an acceptable lev el. This approach has been demonstrated at the Greenidge power plant in upstate New York, but has not been widely adopted. 42 For some smaller boilers

that can accommodate the needed ductwork modificati ons necessary for “hybrid” SNCR/SCR, this may be an attractive technology for reducing NOx emissi ons beyond what SNCR is able to achieve.

The hybrid SNCR/SCR system installed at Greenidge w as part of a multi-pollutant control system designed to demonstrate a combination of controls t hat could meet strict emissions standards at smalle r coal-fired power plants. 43 The multi-pollutant control system was installed on AES Greenidge Unit 4, a 107 MW, 1953-vintage tangentially-fired boiler. Th e facility fires high sulfur eastern U.S. bituminou s coal. The multi-pollutant control system consists of a hybrid SNCR/SCR technology to control NOx, a circulating fluidized bed dry scrubbing technology to control SO 2 , mercury, SO 3 , hydrogen chloride, and Figure 4 **. Selective Catalytic Reduction (Retrofit Installat ion)**  **Image courtesy of Babcock and Wilcox Company**

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particulate matter, and an activated carbon injecti on system to control mercury emissions. Total capi tal cost of the system was $349/kW (2005$), about 40 pe rcent less than the estimated cost of full SCR and wet scrubbers—$114/kW for the hybrid SNCR/SCR syste m, $229/kW for the circulating dry scrubber system and $6/kW for the activated carbon injection system. The plant has achieved 95 percent SO 2 control, 98 percent mercury removal, and 95 percent SO 3 and HCl removal. 44

Co-benefits of post-combustion NOx controls – SNCR has no known co-benefit effects on other pollutants. SCR, on the other hand, has the co-ben efit effect of enhancing oxidation of elemental mercury, especially for bituminous coals. The effe ct of mercury oxidation is to enhance mercury captu re in a downstream wet FGD because the resulting ionic mercury is extremely water soluble. Several field and pilot studies conducted in the U.S. have found increases in oxidized ionic mercury with the use of

SCR controls. 45,46,47,48 For example, testing conducted at the Mount Storm coal-fired power plant in West Virginia evaluated the effect of the unit’s SCR sys tem on mercury speciation and capture. 49 The facility fires a medium sulfur bituminous coal. The test pr ogram found that the presence of an SCR catalyst ca n significantly affect the mercury speciation profile . Measurements showed that the SCR catalyst improv ed the mercury oxidation to levels greater than 95 per cent, almost all of which was captured by the downstream wet FGD system. In the absence of the S CR catalyst, the extent of oxidation at the inlet o f the FGD system was only about 64 percent. This eff ect, however, is much reduced with PRB coals because halogen content in PRB coals is low. SCR ca talyst can also mitigate emissions of dioxins and

furans. 50,51



## Methods for Controlling Hazardous Air Pollutant Emi ssions

HAPs from power plants include mercury, acid gases (HCl and HF), heavy metals (nickel, chromium, arsenic, selenium, cadmium, and others), and organi c HAPs (dioxins and furans). Many HAPs emitted by power plants are captured to some degree by existin g air pollution control technologies. However, EPA ’s proposed Air Toxics Rule will establish emissions s tandards that will require additional controls be installed. For each of these HAPs, the potential m ethods for capture are discussed below.



### Control of Mercury Emissions Mercury is found within coal, with its concentratio n varying widely by coal type and even within coal types. The mercury is released during combustion a nd becomes entrained in a power plant’s flue gas in one of three forms; particle-bound mercury, gaseous elemental mercury, and gaseous ionic mercury. Table 8 lists available methods to control mercury emissions for coal units.

### 19 | P a g e Table 8. **Mercury Emissions Control Methods**

Methods of C ontrol

Activated Carbon Injection (ACI) **Method – Activated carbon adsorbs gaseous Hg, conve rting to particle**  **Hg that is captured in downstream PM control device Reagent – Powdered Activated Carbon**  **Typical Fuel Types – Any fuel, but downstream PM co ntrol needed**  **Capital Costs – Low Co-benefits – Some capture of dioxins/furans**  Halogen Addition **Method – Halogen (bromine) addition to flue gas inc reases oxidized Hg**  **that is easier to capture in a downstream scrubber or in PM** 

**control device Reagent – Halogen containing additive**  **Capital Costs – Negligible**

**Co-benefits – None**

Co

- benefit Methods of Control PM Controls (ESP, FF, multicyclone) **Method – Captures particle-bound mercury**

Dry Sorb ent Injection **Method – Increases co-benefit and ACI Hg capture by removing SO**  **3, which suppresses mercury capture**  Dry Scrubber with F abric

Filter **Method – Hg captured in downstream fabric filter**

Wet Scrubber **Method – Oxidized mercury captured in wet scrubber** NOx Catalyst **Method – Catalyst in SCR increases oxidation of Hg that is more**  **effectively captured in downstream wet scrubber**



### Activated Carbon Injection (ACI) Mercury is often captured using injection of powder ed activated carbon (activated carbon injection – ACI) and capture of the injected carbon on a downst ream PM capture device (ESP or a baghouse). An ACI system is relatively simple and inexpensive, co nsisting of storage equipment, pneumatic conveying system, and injection hardware (“injection lances”) . Under cooperative agreements with the U.S. Department of Energy, several coal plant operators conducted full-scale testing of ACI systems in 2001

. 52

ACI has been used to capture mercury by effectively converting some of the gaseous ionic and elemental mercury to a particle-bound mercury that is capture d in a downstream particulate matter control device

, such as an ESP or fabric filter. ACI is very effec tive at removing mercury except if high sulfur coal s are used, or if SO 3 is injected for flue gas conditioning for ESPs, or if the facility has a hot-side ESP and no downstream air pollution controls. SO 3 interferes with mercury capture by ACI; however, u pstream capture of SO 3 by DSI, if one is in place, should enable ACI to b e more effective at capturing mercury. Fortunately, most of the installed capacity of boil ers firing high sulfur fuels is scrubbed and may no t need

ACI.

Since 2003, many states have led the way on mercury control regulations by enacting statewide mercury limits for power plants that require mercury captur e rates ranging from 80 to 95 percent. 53 At present, about 25 units representing about 7,500 MW are usin g commercial ACI technologies for mercury control. In addition, about 55,000 MW of new bookings are re ported by the Institute of Clean Air Companies (ICAC), a national association of companies providi ng pollution control systems for power plants and other stationary sources. 54

ACI systems cost in the range of $5/kW and can be i nstalled in about 12 months or less, assuming a baghouse is installed. PSEG’s Bridgeport Harbor Ge nerating Station completed the construction and

### 20 | P a g e

installation of a baghouse and ACI system in under 2 years. The final connection of the controls was completed during a six to eight week outage.

Co-benefits of ACI – ACI co-benefits include the reduction of dioxins an d furans.



### Halogen Addition

For applications where there is inadequate halogen for conversion of elemental mercury to ionic mercur y, such as some western coals, the addition of halogen will increase mercury conversion to the ionic form and will permit higher capture efficiency through c o-benefit capture or by ACI. Addition of halogen t o PRB coals or to activated carbon injected for mercu ry capture has been shown to make mercury capture from PRB fired boilers with halogen addition genera lly high. 55



### Co-Benefit Methods for Mercury Capture

Of the three mercury forms previously mentioned, pa rticle-bound mercury is the species more readily captured as a co-benefit in existing emission contr ol devices, such as fabric filters (also called “baghouses”) or electrostatic precipitators (ESPs). Ionic mercury has the advantage that it is extrem ely water soluble and is relatively easy to capture in a wet FGD/scrubber. Ionic mercury is also prone to adsorption onto fly ash or other material, and may thereby become particle-bound mercury that is captured by an ESP or fabric filter. Elemental mer cury is less water soluble and less prone to adsorp tion, thus remains in the vapor phase where it is not typ ically captured by control devices unless first con verted to another form of mercury more readily captured.

Fabric filters generally provide much higher co-ben efit mercury capture than ESPs. Bituminous coalfired boilers with fabric filters can have high rat es of mercury capture based on data collected by th e U.S. EPA during its Information Collection Request (ICR) supporting the development of the Air Toxics

Rule. 56 

# Case Study: ACI Controls

In response to a 2006 Minnesota state mercury law, Xcel Energy agreed to install an ACI system on the 900 MW Unit 3 at its Sherburne County plant (Sherco 3). The unit, which burns low sulfur western coal
from Montana and Wyoming, already had a dry scrubbe r operating to reduce SO 2 emissions. Once it has
been tuned to the unit’s operational specifications , the ACI system is expected to reduce the plant’s
mercury emissions by about 90 percent. The system was completed in December 2009 for a total capital cost of $3.1 million, or $3.46/kW. Wisconsin Powe r and Light installed ACI controls at its Edgewater
Generating Station. The system was operational in the first quarter of 2008. Edgewater Unit 5 is a 3 80 MW plant that fires PRB coal and is configured with a cold-side ESP for particulate control. The tota l
installed costs of the Edgewater Unit 5 ACI system was approximately $8/kW, or approximately $3.04

million.

Source: Southern Minnesota Municipal Power Agency. “Sherco 3: Environmental Controls.” August 2010, http://www.smmpa.com/upload/Sherco%203%20brochure%2 02010.pdf (accessed March 17, 2011).

Starns, T., Martin, C., Mooney, J., and Jaeckels, J . “Commercial Operating Experience on an Activated Carbon Injection System, Paper #08-A-170-Mega-AWMA.” Power Plant Air Pollutant Con trol MEGA Symposium. Baltimore, MD. August 25-28, 2 008.

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Wet scrubbers with SCR controls upstream have been shown to be very effective in removing oxidized (ionic) mercury. Therefore, when a wet scrubber is present, it is beneficial to take measures to incr ease the oxidation of mercury upstream of the wet scrubb er. Catalysts in SCR systems promote oxidation of mercury, and SCR controls upstream of a wet FGD sys tem have been shown to provide high mercury capture in the range of 90 percent when burning bit uminous coals. 57 The precise level of oxidation and capture will vary under different conditions. In a study by the Southern Company, five of its plants with SCR and scrubbers captured an average of 87 percent of mercury over a period of several months. 58

Co-benefit capture rates of mercury in ESPs, fabric filters, scrubbers, or other devices for bituminou s coals are generally greater than that for PRB coals . This is because the higher halogen content (e.g.

, chlorine) found in eastern coals promotes formation of oxidized mercury. 59



### Acid Gas Control Methods

Strong acids, such as hydrogen chloride (HCl) and h ydrogen fluoride (HF), result from the inherent halogen content in the coal that is released during combustion to form acids as the flue gas cools. A s with mercury content, the concentration of halogens in t he coal varies widely by coal type and even within coal types. Chlorine is of greatest concern because it is usually present in higher concentrations than ot her halogens in U.S. coals. The U.S. EPA’s proposed Ai r Toxics Rule for power plants sets a numerical

emission limit for HCl. The HCl limit also functio ns as a surrogate limit for the other acid gases, w hich are not given their own individual emission limits under the proposed rule.

Table 9 shows HCl emission control methods for coal boilers. In principle, wet and dry SO 2 scrubbers can be used for the control of HCl and HF on power plant boilers; however, these are not likely to be necessary because lower cost methods exist. For th ose facilities with wet or dry scrubbers for SO 2 control, these units will likely provide the co-ben efit of HCl capture. For those units that are unsc rubbed, these will likely be adequately controlled through retrofit with DSI systems, and a fabric filter.

### 22 | P a g e Table 9. **HCl Emissions Control Methods**

Methods of C ontrol Dry Sorbent Injection **Method – Dry sorbent captures HCl, downstream PM co ntrol device**  **captures dry product Regent – Trona, sodium bicarbonate, hydrated lime**  **Typical Fuel Types – Most often solid fuels with PM control**  **Capital Costs – Low to moderate**

**Co-benefits – NOx and SO 2**  **reduction, Hg reduction, removal of chlorine precursor leading to lower dioxins/furans formation**  Dry Scrubber with fabric

filter **Method – Reagent + water react to capture acid gas and dry product**  **captured in downstream fabric filter Reagent – Hydrated lime**  **Typical Fuel Types – Solid fuels Capital Costs – High**  **Co-benefits – High Hg capture (esp. bituminous coal ), high SO**  **2 capture,**  **high PM capture**

Wet Scrubber **Method – Reagent + water react to capture acid gas Reagent – Limestone, lime, caustic soda**  **Typical Fuel Types – Solid fuels Capital Costs – High**  **Co-benefits – Highest SO 2**  **capture, high oxidized Hg capture, some PM capture** 

Co

- benefit Methods of Control Wet or Dry Scrubbers **Method – SO 2**  **scrubber has high HCl removal efficiency** Coal Change **Low sulfur PRB coal is also low in chlorine content**



### Dry Sorbent Injection

Data from DSI commercial projects or pilot testing has indicated that acid gases can be very effective ly captured by DSI using Trona, sodium bicarbonate, or hydrated lime. Although DSI is a technology that has not yet seen the wide deployment of other techn ologies for acid gas controls, like wet or dry scrubbers, data suggest that DSI is an effective te chnology for controlling emissions of acid gases, including HCl and HF. For example, as shown in Tab le 10, HCl capture rates of 98 percent have been

measured at Mirant’s Potomac River station with sor bent injection upstream of the air preheater. 60
Testing of DSI systems has shown that HCl capture i s consistently well above the SO 2 capture rate, and that capture rate of HCl on an ESP was in the mid t o upper 90 percent range with SO 2 capture in the 60 percent range. With fabric filters, similar HCl ca pture efficiencies are possible but at lower sorben t

treatment rates. 61 Hydrated lime has also been shown in pilot tests to potentially achieve substantial HCl removal at low capital cost. 62

Table 10 **. HCl and HF Capture at Mirant Potomac River Stati on** 

Trona Injection Sodium Bicarbonate Injection HCl (%) **98.8 97.8**  HF (%) **78.4 88.0** 

DSI may be sufficiently effective in removing acid gases in combination with the existing PM control device. In some cases, however, it may be necessar y to modify the existing PM control device or to

install a new PM control device. If a fabric filte r is installed for PM control, this will also facil itate capture of acid gases with DSI, and mercury and dio xins/furans with ACI. Such an approach will be far

### 23 | P a g e

less expensive than installing a wet scrubber. As indicated above, DSI equipment is relatively simple and inexpensive when compared to a scrubber and can be installed typically within 12 months.



### PM Emissions Control

Toxic metals other than mercury are normally in the particle form and are therefore controlled through particulate matter controls, such as ESPs and fabri c filters. The proposed Air Toxics Rule for power plants sets numerical PM emission limits as a surro gate for non-mercury toxic metal emission limits. Table 11 lists PM emission control methods for pulv erized coal units.

Table 11. **PM Emissions Control Methods**

Methods of C ontrol

ESP **Method – Electrostatic capture of PM, high capture efficiency**  **Reagent – None Typical Fuel Types – Solid fuels**  **Capital Costs – High Co-benefits – Capture particle-bound mercury**  Baghouse **Method – Filtration of PM, highest capture efficien cy**  **Reagent – None Typical Fuel Types – Gaseous fuels**  **Capital Costs – High Co-benefits – High capture of mercury and other HAP**  **s** Co

- benefit Methods of Control Scrubber (wet or dry) **Method – Captures PM**



### Electrostatic Precipitator

An electrostatic precipitator (ESP) uses an electri cal charge to separate the particles in the flue ga s stream
under the influence of an electric field. More than 70 percent of existing coal-fired power p lants are reported to have installed ESPs. 63

In brief, an ESP works by imparting a positive or n egative charge to particles in the flue gas stream. The particles are then attracted to an oppositely charg ed plate or tube and removed from the collection su rface to a hopper by vibrating or rapping the collection surface. An ESP can be installed at one of two

locations. Most ESPs are installed downstream of t he air heater, where the temperature of the flue ga s is

between 130 ° C-180 ° C (270 ° F-350 ° F). 64 An ESP installed downstream of the air heater is known as a “cold-side” ESP. An ESP installed upstream of the air heater, where flue gas temperatures are significantly higher, is known as a “hot-side” ESP.

The effectiveness of an ESP depends in part on the electrical resistivity of the particles in the flue gas. Coal with a moderate to high amount of sulfur produ ces particles that are more readily controlled. Lo w sulfur coal produces a high resistivity fly ash tha t is more difficult to control. The effectiveness of an ESP also varies depending on particle size. An ESP can capture greater than 99 percent of total PM, while capturing 80 to 95 percent of PM 2.5

. 65

Depending upon the particular ESP and the applicabl e MACT standards, there may not be any need for further controls; however, many ESPs are decades ol d and were built for compliance with less stringent emission standards in mind. As a result, these fac ilities may need to make one or both of the followi ng modifications to comply with new MACT standards:

### 24 | P a g e

• Upgrade of existing ESP – The existing ESP could be upgraded through addition of new electric fields, use of new high frequency transformer recti fier technology, or other changes. The applicability of this option will depend upon the c ondition and performance of the existing ESP.

• Replacement of ESP with fabric filter – A fabric fi lter may be installed in place of the existing ESP. In some cases, the existing ESP casing and su pport structure could be utilized for the baghouse. A booster fan is likely to be necessary because of the increased pressure drop across

the fabric filter.

In recent years, there has been more focus on fabri c filters for PM control than ESPs because of the P M capture advantages of fabric filters. As a result, there is not a great deal of available information on recent cost or installation time for ESPs. In gene ral, however, an ESP will likely cost somewhat more and

take more time to construct than a fabric filter bu ilt for the same gas flow rate because ESPs are somewhat more complex to build than a fabric filter system.



### Fabric Filter or Baghouse

A fabric filter, more commonly known as a baghouse, traps particles in the flue gas before they exit t he stack. Baghouses are made of woven or felted mater ial in the shape of a cylindrical bag or a flat, supported envelope. The system includes a dust col lection hopper and a cleaning mechanism for periodi c removal of the collected particles.

According to EPA, a fabric filter on a coal-fired p ower plant can capture up to 99.9 percent of total particulate emissions and 99.0 to 99.8 percent of P M 2.5

. 66 Thirty-five percent of coal-fired power plants in

the U.S. have installed fabric filters. 67

A full baghouse retrofit would generally cost somew hat more than the addition of a downstream polishin g baghouse (discussed later); however, because the ma terial and erection of the baghouse is only a porti on of the total retrofit cost of any baghouse, most of the costs are the same (ductwork, booster fans, da mpers, electrical system modifications, etc.). Increasing the fabric filter size by 50 percent (equivalent t o a change in air to cloth ratio of 6.0 to 4.0) would y ield much less than a 50 percent impact to project cost over the cost of retrofitting a polishing baghouse, perhaps in the range of 15-20 percent. A fabric f ilter retrofit (full or polishing) would typically be ach ievable in 12-24 months from design to completion, depending upon the complexity of the ductwork neces sary. For example, in 2009, the Reid Gardner generating station in Nevada completed the installa tion of three new pulse-jet baghouses in 17 months. The retrofit required the replacement of the plant’ s existing mechanical separators. 68

Rather than replacing an ESP with a fabric filter, a power plant with an existing ESP has the option o f installing a downstream polishing baghouse (downstr eam of the existing ESP). This will capture particulate matter that escapes the ESP. Retrofit of a downstream polishing fabric filter will requir e addition of ductwork, a booster fan, and the fabric filter system. Costs will vary by application, particularly by the amount of ductwork needed. For example, the polishing fabric filter installed on three 90 MW boilers at Presque Isle Power Plant in Michig an cost about $125/KW (2005$). This project, however, had very long duct runs for each of the bo ilers and significant redundancy. 69 For a project on a single larger unit without the long duct runs, one would expect a lower cost.

Co-benefits of PM controls – PM controls, especially fabric filters, permit high er co-benefit mercury capture. Also, capture of other toxic pollutants t hrough DSI is improved with a fabric filter. This is true

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with any situation where sorbent is used to capture a pollutant because a fabric filter permits captur e on the filter cake in addition to capture in-flight wh ile ESPs permit only in-flight capture.



### Control of Dioxins and Furans

Under the Air Toxics Rule, EPA has proposed a “work practice” standard for organic HAPs, including emissions of dioxins and furans, from coal-fired po wer plants. Power plant operators would be require d to perform an annual tune-up, rather than meeting a specific emissions limit. EPA has proposed a work practice standard because it found that most organi c HAP emissions from coal power plants are below

current detection levels of EPA test methods. Ther efore, it concluded that it is impractical to relia bly measure emissions of organic HAPs. While EPA is no t proposing numerical emission limits for organic HAPs, for completeness, we discuss below experience in controlling emissions of dioxins and furans from incinerators that may have relevance for co-be nefits with coal power plant controls.

Emissions of dioxins and furans result from: (1) th eir presence in the fuel being combusted; (2) the thermal breakdown and molecular rearrangement of pr ecursor ring compounds, chlorinated aromatic hydrocarbons; or (3) from reactions on fly ash invo lving carbon, oxygen, hydrogen, chorine, and a transition metal catalyst. Because dioxins and fur ans are generally not expected to be present in coa l, the

second and third mechanisms are of most interest. In both of these mechanisms, formation occurs in th e post-combustion zone at temperatures over 500°C (93 0°F) for the second mechanism or around 250- 300°C (480-575°F) for the third mechanism. 70 Once formed, dioxins and furans are difficult to destroy through combustion. Therefore, it is best to preve nt their formation, or alternatively, capture them once formed.

While emissions of dioxins and furans have long bee n a source of concern for municipal and other waste incinerators, their emissions have not generally be en controlled from power plants. Emissions of diox ins and furans are generally expected to be lower in co al combustion than in municipal waste combustion because of the relatively lower chlorine levels and the higher sulfur levels of coal. 50 Sulfur has been shown to impede dioxins and furans formation. 50,70,71 Table 12 lists the technologies for control of dioxins and furans and EPA’s previously proposed in stitutional, commercial, and industrial boiler limi ts for pulverized coal units.

The extensive experience with control of dioxins an d furans at incinerators has provided insights that may be relevant for power plants, while recognizing the important differences between power plants and

incinerators. Because dioxins and furans are forme d from organic precursors, one way to avoid their formation is to have complete combustion of organic s; hence, combustion controls or oxidation catalyst s can contribute to their lower formation. 70 SCR has also been shown to mitigate emissions of dioxins and

furans. 50,51 Data indicate that capture of chlorine prior to t he dioxins formation temperature will reduce dioxins/furans formation from municipal waste combu stors. 58 Therefore, dry sorbent injection upstream of the air preheater of a coal boiler may be a mean s of reducing dioxins/furans formation.

Injection of activated carbon is a means that has b een used to capture dioxins and furans emitted by municipal waste incinerators, 50, 70 and has demonstrated over 95 percent capture of di oxins at a hazardous

waste incinerator. 72 Currently, there are not enough available data to form a definitive conclusion about how effective ACI will be at dioxins/furans capture from power plants because of the different conditi ons. The information available, however, suggests that i t is likely to be useful in reducing dioxins and fu rans in the event other methods are not adequate in prev enting their formation.

### 26 | P a g e Table 12. **Dioxins and Furans Emission Control Methods**

Methods of C ontrol

Activated Carbon Injection (ACI) **Method – Activated carbon adsorbs gaseous dioxins/f urans, and is**  **captured in downstream PM control device Reagent – Powdered Activated Carbon**  **Typical Fuel Types – Any fuel, but downstream PM co ntrol needed**  **Capital Costs – Low Co-benefits – Capture of Hg** 

Co

- benefit Methods of Control

Combustion Controls **Method – Destruction of organic dioxins/furans prec ursors**  Dry Sorbent Injection **Method – Captures precursor chlorine prior to dioxi ns/furans formation**  CO or NOx Catalyst **Method – Catalyst increases oxidation of organic di oxins/furans** 

**precursors**



## Labor Availability

The installation of air pollution control equipment requires the effort of engineers, managers, and sk illed laborers, and past history has shown that the indus try has substantial capacity to install the necessa ry controls. Between 2008 and 2010, coal-fired power plants added approximately 60 GW of FGD controls

and almost 20 GW of SCR controls with a total of 80 GW of FGD controls installed under CAIR Phase 1. Between 2001 and 2005, the electric power industry successfully installed more than 96 GW of SCR systems in response to the NOx SIP Call.

Based on a retrospective study of actual retrofit e xperience, it was determined that EPA and industry dramatically underestimated the ability of the air pollution control industry to support the utility i ndustry in responding to CAIR. The study offered several r easons for why EPA and industry underestimated the capabilities of the labor market: (1) boilermakers will work overtime during periods of high demand; ( 2) boilermakers frequently travel to different locatio ns for work, supplementing local available labor; ( 3) boilermakers work in fields other than power, such as refining/petrochemical, shipbuilding, metals industries and other construction trades, and worke rs can shift industry sectors with appropriate trai ning; and (4) new workers will enter the field—for exampl e, in advance of the NOx SIP Call, boilermakers increased their ranks by 35 percent, mostly by addi ng new members. 73

In November 2010, the Institute of Clean Air Compan ies (ICAC), an association that represents most of the suppliers of air pollution control technology, sent a letter to U.S. Senator Thomas Carper confirm ing the nation’s air pollution control equipment compan ies repeatedly have successfully met more stringent NOx, SO 2 , and mercury emission limits with timely installat ions of effective controls and are well prepared to meet new EPA requirements. In its lett er, the industry association stated, “based on a hi story of successes, we are now even more resolute that la bor availability will in no way constrain the indus try’s ability to fully and timely comply with the propose d interstate Transport Rule and upcoming utility MACT rules. Contrary to any concerns or rhetoric p ointing to labor shortages, we would hope that effo rts that clean the air also put Americans back to work. ” 74 Also in November 2010, the Building and Construction Trades Department of the AFL-CIO issue d a letter concluding that “[t]here is no evidence to suggest that the availability of skilled manpower w ill constrain pollution control technology development.” 75

The electric industry has long been aware that EPA would be regulating HAPs and other pollutants from coal-fired power plants. As a result, many compani es started planning their compliance strategies bef ore EPA even proposed its Air Toxics Rule in March 2011 . For example, companies have been evaluating

### 27 | P a g e

control technology options and establishing capital budgets. 76 Similar advance planning occurred after the proposed CAIR rule was released in December 200 3. In 2004, when EPA was still working to finalize the rule, companies placed orders for more than 20 GW of FGD controls (wet and dry scrubbers). 77 Southern Company, for example, had begun planning its FGD installations in 2003, well in

advance of the final rule. 78



## Conclusion

EPA’s clean air rules—the Transport Rule and the Ai r Toxics Rule—address one of the nation’s largest sources of toxic air pollution, providing important human health protections to millions of people throughout the country. Additionally, thousands of construction and engineering jobs will be created as companies invest in modern control technologies. 79

The electric power sector has several decades of ex perience controlling air pollution emissions from c oalfired power plants, which should serve the industry well as it prepares to comply with the Transport R ule and the Air Toxics Rule. Many companies have alrea dy moved ahead with the upgrades necessary to comply with these future standards, demonstrating t hat better environmental performance is both technically and economically feasible.

In most cases, the required pollution control techn ologies are commercially available and have a long track record of effective performance at many coal- fired power plants in the U.S., with some operating successfully for decades. The electric power secto r has demonstrated that it is capable of installing pollution controls on a large portion of the nation ’s generating fleet in a relatively short period of time. Also, suppliers have demonstrated the ability to de liver pollution control equipment in a timely manne r, and the skilled labor needed to install it should b e available to meet the challenge as well.

### 28 | P a g e



## Endnotes

1 Clean Air Act, section 110(a)(2)(D), often referre d to as the “good neighbor” provision of the Act, r equires upwind states to prohibit certain emissions because of the ir impact on air quality in downwind states.

2 U.S. Environmental Protection Agency. Federal Imp lementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone. Federal Register / V ol. 75, No. 147 / Monday, August 2, 2010.

3 U.S. Environmental Protection Agency. Rule To Red uce Interstate Transport of Fine Particulate Matter and Ozone (Clean Air Interstate Rule); Revisions to Acid Rain Program; Revisions to the NOx SIP Call; Final Rule

. Federal Register / Vol. 70, No. 91 / Thursday, May 12, 2005.

4 North Carolina v. EPA , 531 F.3d 896 (D.C. Cir. 2008).

5 North Carolina v. EPA , 550 F.3d 1176 (D.C. Cir. 2008).

6 U.S. Environmental Protection Agency. Federal Imp lementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone. Federal Register / V ol. 75, No. 147 / Monday, August 2, 2010.

7 U.S. Environmental Protection Agency. Federal Imp lementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone, Page 45213. Federal Register / Vol. 75, No. 147 / Monday, August 2, 201 0.

8 U.S. Environmental Protection Agency. Federal Imp lementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone, Page 45344. Federal Register / Vol. 75, No. 147 / Monday, August 2, 201 0.

9 U.S. Environmental Protection Agency. Fact Sheet: Proposed Transport Rule Would Reduce Interstate Tr ansport of Ozone and Fine Particle Pollution. July 6, 2010, http://www.epa.gov/airtransport/pdfs/FactsheetTR7- 6- 10.pdf (accessed March 17, 2011).

10 New Jersey v. EPA , 517 F.3d 574 (D.C. Cir. 2008).

11 U.S. Environmental Protection Agency. Reducing Ai r Toxics from Power Plants: Regulatory Actions. Mar ch 16, 2011, http://www.epa.gov/airquality/powerplanttoxic s/actions.html (accessed March 16, 2011).

12 U.S. Environmental Protection Agency. Fact Sheet: Power Plant Mercury and Air Toxics Standards; Overv iew of Proposed Rule and Impacts. March 16, 2011, http://www.epa.gov/airquality/powerplanttoxics/pdfs /overviewfactsheet.pdf (accessed March 17, 2011).

13 National Association of Clean Air Agencies (NACAA) . “State/Local Mercury/Toxics Program for Utilities .” April 6, 2010 (updated February 8, 2011), http://ww w.4cleanair.org/index.asp.

14 U.S. Environmental Protection Agency. Fact Sheet: Proposed Mercury and Air Toxics Standards. March 16 , 2011, http://www.epa.gov/airquality/powerplanttoxics/pdfs /proposalfactsheet.pdf.

15 U.S. Environmental Protection Agency. Fact Sheet: Proposed Mercury and Air Toxics Standards. March 1 6, 2011, http://www.epa.gov/airquality/powerplanttoxic s/pdfs/proposalfactsheet.pdf.

16 U.S. Environmental Protection Agency. National Emi ssions Inventory (NEI) Air Pollutant Emissions Tren ds Data (1970 - 2008 Average annual emissions, all criteria pollutants in MS Excel). June 2009, http://www.epa.gov/ttnchie1/trends/ (accessed March 29, 2011).

17 U.S. Environmental Protection Agency. Clean Air Ma rkets: Emission and Compliance Data (Table 1). Dece mber 20, 2010, http://www.epa.gov/airmarkt/progress/ARP0 9_1.html (accessed March 29, 2011).

18 Institute of Clean Air Companies. Letter to Senato r Thomas Carper, U.S. Senate. November 3, 2010, http://www.icac.com/files/public/ICAC_Carper_Respon se_110310.pdf (accessed March 17, 2011).

19 This is developed from US EPA NEEDS 4.10 database.

20 Srivastava, R. “Controlling SO 2 Emissions: A Review of Technologies.” U.S. Environ mental Protection Agency.

EPA-600/R-00-093. October 2000.

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### 29 | P a g e 22 U.S. Department of Energy, Energy Information Admi nistration, Form 767 data.

23 Wall, Darryl, Healy, Edward, Huggins, John. Imple mentation Strategies for Southern Company FGD Proje cts. (Undated).

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25 Sharp, G.W. “Update: What’s that Scrubber Going to Cost?” POWER Magazine. March 1, 2009, http://www.powermag.com/issues/features/Update-What s-That-Scrubber-Going-to-Cost_1743.html (accessed March 17, 2011).

26 U.S. Environmental Protection Agency. Documentatio n for EPA Base Case v.4.10: Chapter 5. http://www.epa.gov/airmarkt/progsregs/epa-ipm/BaseC asev410.html (accessed March 24, 2011).

27 Roll, D., Connell, D., and Huber, W. “Results from the First Year of Operation of a Circulating Fluid ized Bed Dry Scrubber with High-Sulfur Coal at AES Greenidge Uni t 4.” Electric Power Conference & Exhibition. Baltimore, MD. May 8, 2008.

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31 Erickson, C., Jasinski, M., and VanGansbeke, L. “W et Flue Gas Desulfurization (WFGD) Upgrade at the T rimble County Generation Station Unit 1.” EPRI-DOE-EPA-AWM A Combined Power Plant Air Pollutant Control MEGA Symposium. Baltimore, MD. August 28-31, 2006.

32 Indiana Utility Regulatory Commission. Cause No. 4 3188. Filed Testimony of Barbara A. Smith - On Beha lf of the Indiana Office of Utility Consumer Counselor. F iled April 5, 2007.

33 Indiana Utility Regulatory Commission. Cause No. 4 3188. Proposed Order, Submitted by: Northern Indian a Public Service Co. – Electric. Filed July 6, 2007.

34 Institute of Clean Air Companies (ICAC). Letter to Senator Thomas Carper, U.S. Senate. November 3, 20 10, http://www.icac.com/files/public/ICAC_Carper_Respon se_110310.pdf (accessed March 17, 2011).

35 Atwell, M. and Wood, M. “Sodium Sorbents for Dry I njection Control of SO 2 and SO 3 .” 2009, http://www.solvair.us/static/wma/pdf/1/6/2/9/5/SOLV AirAPC.pdf (accessed March 17, 2011).

36 This is developed from the U.S. EPA NEEDS 4.10 dat abase.

37 LePree, J. “SCR: New and Improved.” Chemical Engin eering. July 1, 2010, http://www.che.com/environmental_health_and_safety/ environmental_mgmt/air_pollution_control/SCRNew-and-Improved_5803.html (accessed March 17, 2011 ).

38 Cichanowicz, J.E. and Muzio, L.J. “Twenty-Five Yea rs of SCR Evolution: Implications for US Applicatio n and Operation.” Proceedings of the EPRI/EPA/DOE MEGA Sy mposium. Chicago, IL. August 2001, http://www.ferco.com/Files/P117.pdf (accessed March 17, 2011).

39 Institute of Clean Air Companies (ICAC). Letter to Senator Thomas Carper, U.S. Senate. November 3, 20 10, http://www.icac.com/files/public/ICAC_Carper_Respon se_110310.pdf (accessed March 17, 2011).

40 Marano, M. and Sharp, G. “Estimating SCR Installat ion Costs.” POWER Magazine. February 15, 2006, http://www.powermag.com/issues/cover_stories/Estima ting-SCR-installation-costs_506.html (accessed March 17, 2011).

41 U.S. Environmental Protection Agency. “Engineering and Economic Factors Affecting the Installation of Control Technologies for Multipollutant Strategies.” EPA-60 0/R-02/073. October 2002.

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46 Laudal, D.L., Thompson, J.S., Pavlish, J.H., Brick ett, L., Chu, P., Srivastava, R.K., Lee, C.W., and Kilgroe, J.D. “Evaluation of Mercury Speciation at Power Plants U sing SCR and SCR NOx Control Technologies.” 3rd International Air Quality Conference. Arlington, VA . September 9-12, 2001.

47 Chu, P., Laudal, D., Brickett, L., and Lee, C.W. “ Power Plant Evaluation of the Effect of SCR Technol ogy on Mercury.” EPRI-DOE-EPA Combined Air Pollution Contr ol MEGA Symposium. Washington, DC. May 19-22, 2003.

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### 31 | P a g e 57 U.S. Environmental Protection Agency, Air Pollutio n Prevention and Control Division, National Risk Management Research Laboratory, Office of Research and Development. “Control of Mercury Emissions from Coal Fired Electric Utility Boilers: An Update .” Research Triangle Park, NC. February 18, 2005, http://www.epa.gov/ttn/atw/utility/ord_whtpaper_hgc ontroltech_oar-2002-0056-6141.pdf (accessed March 17, 2011).

58 Tyree, C. and Allen, J. “Determining AQCS Mercury Removal Co-Benefits.” POWER Magazine. July 1, 2010, http://www.powermag.com/issues/cover_stories/Determ ining-AQCS-Mercury-Removal-Co-Benefits_2825.html (accessed March 17, 2011).

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60 Kong, Y., de la Hoz, J.M., Atwell, M., Wood, M., a nd Lindsay, T. “Dry Sorbent Injection of Sodium Bic arbonate

for SO 2 Mitigation.” Power-Gen International 2008. Orlando , FL. December 2-4, 2008.

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### 32 | P a g e 73 Staudt, J. “Availability of Resources for Clean Ai r Projects.” Andover Technology Partners, North And over, MA.

October 2010.

74 Institute of Clean Air Companies (ICAC). Letter to Senator Thomas Carper, U.S. Senate. November 3, 20 10, http://www.icac.com/files/public/ICAC_Carper_Respon se_110310.pdf (accessed March 17, 2011).

75 Building and Construction Trades Department, Ameri can Federation of Labor–Congress of Industrial Organizations (AFL-CIO). Letter to Senator Thomas C arper, U.S. Senate. November 5, 2010, http://www.supportcleanair.com/resources/letters/fi le/11-11-10-AFL-Letter-To-Sen-Carper.pdf (accessed March 19, 2011).

76 See, for example: (1) NRG. Fourth Quarter and Ful l-Year 2010 Results Presentation. February 22, 2011 ; and (2) Southern Company Mercury Research Center establishe d in December 2005: http://mercuryresearchcenter.com.

77 Staudt, J. “Availability of Resources for Clean Ai r Projects.” Andover Technology Partners, North And over, MA.

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78 Institute of Clean Air Companies (ICAC). Letter to Senator Thomas Carper, U.S. Senate. November 3, 20 10, http://www.icac.com/files/public/ICAC_Carper_Respon se_110310.pdf (accessed March 17, 2011).

79 Ceres. New Jobs-Cleaner Air: Employment Effects U nder Planned Changes to the EPA’s Air Pollution Rul es. February 2011.