RESPONSE TO SIGNIFICANT PUBLIC COMMENTS ON

THE PROPOSED CLEAN AIR MERCURY RULE

Received in response to:

Proposed National Emission Standards for Hazardous Air Pollutants; and, in

the Alternative, Proposed Standards of Performance for New and Existing

Stationary Sources: Electric Utility Steam Generating Units

(69 FR 4652; January 30, 2004)

Supplemental Notice for the Proposed National Emission Standards for

Hazardous Air Pollutants; and, in the Alternative, Proposed Standards of

Performance for New and Existing Stationary Sources: Electric Utility Steam

Generating Units

(69 FR 12398; March 16, 2004)

Proposed National Emission Standards for Hazardous Air Pollutants; and, in

the Alternative, Proposed Standards of Performance for New and Existing

Stationary Sources, Electric Utility Steam Generating Units: Notice of Data

Availability

(69 FR 69864; December 1, 2004)

Docket Number OAR-2002-0056

1.0 INTRODUCTION AND BACKGROUND

2.0 APPLICABILITY AND SUBCATEGORIZATION

US Environmental Protection Agency 

Emissions Standards Division

Office of Air Quality Planning and Standards

Research Triangle Park, North Carolina 27711

15 March 2005
i

General Outline

1.0 INTRODUCTION AND BACKGROUND

2.0 APPLICABILITY AND SUBCATEGORIZATION

3.0 PERFORMANCE STANDARDS FOR COAL-FIRED ELECTRIC UTILITY

STEAM GENERATING UNITS

4.0 PERFORMANCE STANDARDS FOR OIL-FIRED ELECTRIC UTILITY STEAM

GENERATING UNITS

5.0 MERCURY CAP-AND-TRADE PROGRAM

6.0 MERCURY EMISSIONS MONITORING

7.0 IMPACT ESTIMATES

8.0 COMPLIANCE WITH EXECUTIVE ORDERS AND STATUTES

9.0 NODA

10.0 OTHER

Appendix A LIST OF COMMENTERS
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1.0 INTRODUCTION AND BACKGROUND

The purpose of this document is to provide EPA’s responses to public comments received

on the notice of proposed rulemaking (NPR), “Proposed National Emission Standards for

Hazardous Air Pollutants; and, in the Alternative, Proposed Standards of Performance for New

and Existing Stationary Sources: Electric Utility Steam Generating Units” (Clean Air Mercury

Rule; CAMR) (69 FR 4652; January 30, 2004); on the supplemental notice of proposed

rulemaking (SNPR), “Supplemental Notice for the Proposed National Emission Standards for

Hazardous Air Pollutants; and, in the Alternative, Proposed Standards of Performance for New

and Existing Stationary Sources: Electric Utility Steam Generating Units” (69 FR 12398; March

16, 2004); and on the notice of data availability (NODA), “Proposed National Emission Standards

for Hazardous Air Pollutants; and, in the Alternative, Proposed Standards of Performance for

New and Existing Stationary Sources, Electric Utility Steam Generating Units: Notice of Data

Availability” (69 FR 69864; December 1, 2004).

The opportunity for written and oral public comment on the proposed rulemaking was

announced with the NPR, the SNPR, and the NODA. Concurrent public hearings on the NPR

were held on February 25 and 26, 2004, in Chicago, IL, Philadelphia, PA, and Research Triangle

Park, NC. A public hearing on the SNPR was held on March 31, 2004, in Denver, CO. No

public hearing was held on the NODA. The period for public comment on the NPR closed on

March 30, 2004, but was extended to April 30, 2004, upon publication of the SNPR. Following

numerous requests for an extension, the public comment period was reopened on May 1, 2004,

and extended to June 29, 2004. The public comment period on the NODA closed on January 3,

2005. In addition, a telephone hotline was established for use by the public in providing

comments.

EPA received approximately 500,000 comments on this proposed rulemaking, including

numerous mass-mailings and approximately 5,000 “unique” comments. A listing of the

commenters is provided in Appendix A to this document. A complete set of the public comments

received (including the transcripts of the public hearings and telephone hotline calls) is available as

part of eDocket OAR-2002-0056. This docket can be accessed at www.epa.gov/edocket or

through the U.S. EPA Docket Center, 1301 Constitution Avenue, NW, Washington, D.C., 20004

in the Public Reading Room, Room B102, EPA West Building, 8:30 a.m. through 4:30 p.m.,

Monday through Friday.

A summary of the public comments received and EPA’s responses is contained in the

subsequent chapters of this document. In this document, EPA has followed the following three

criteria:

! Detailed responses are provided only for those comments deemed to be significant. Other

comments may be summarized and general responses provided.

! Comments determined to be “late public comments” on the NODA (i.e., received after the

close of the public comment period for the NODA) are neither summarized in this

document nor are responses provided. Comments received between June 30, 2004
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(following the June 29, 2004, end of the public comment period on the NPR and SNPR)

and November 30, 2004 (prior to the December 1, 2004, opening of the public comment

period on the NODA) were considered in the decisions on the final rule because the

comment period was reopened on December 1, 2004, if only on a limited number of

issues. Responses are not provided to comments received after the close of the public

comment period on the NODA on January 3, 2005, because there was insufficient time for

adequate analyses of these comments.

! Comments received on the proposed Clean Air Act (CAA) section 112(d) maximum

achievable control technology (MACT) approach and on the proposed approach to

institute a cap-and-trade rulemaking under the authority of CAA section 112(n)(1)(A)

have neither been summarized nor responded to in this document. We have taken this

approach because these two proposed regulatory approaches, which were two of the three

regulatory approaches proposed, were not selected for promulgation. Some commenters

on CAA section 112(d) discussed alternative measures of what the proper emissions

standards would be under a MACT, or criticized EPA’s methodology for estimating those

standards. To the extent these commenters have stated, or believe, that EPA should have

performed additional MACT calculations, and compared these revised calculations with

the emissions reductions achieved under CAA sections 110(a)(2)(D) and 111 before

revising its 2000 CAA section 112(n) determination or promulgating CAMR, EPA

disagrees. In assessing the effects of Hg emissions from U.S. utilities, EPA identified, to

the extent possible given limits in data and modeling capability, all utility-attributable Hg

emissions that deposit in the U.S. or otherwise affect U.S. public health. EPA used this

information – what would happen if Hg emissions form U.S. utilities were eliminated

completely – to identify the effects, and any remaining risks, of today’s regulatory actions. 

Because EPA has concluded the effects and benefits of emissions reductions beyond those

achieved through the Clean Air Interstate Rule (CAIR) and CAMR are small, and would

not justify different decisions than those reached today, EPA has, therefore, not relied

upon comparison between the emissions standards under a MACT and emissions after the

actions adopted today.
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2.0 APPLICABILITY AND SUBCATEGORIZATION

2.1 APPLICABILITY

2.1.1 Definitions

Comment:

One commenter (OAR-2002-0056-2922) stated that EPA uses the terms “coal-fired

electric utility steam generating unit,” “integrated gasification combined cycle electric utility steam

generating unit,” and “oil-fired electric utility steam generating unit” to define applicability in the

proposed rules. However those terms are not defined anywhere in the proposed revisions (or the

existing 40 CFR 60). EPA should add definitions for those units that are consistent with the

definitions in proposed 40 CFR 60 Subpart UUUUU and with the public comments on those

definitions.

Response:

EPA has provided the additional definitions, as appropriate, as suggested by the

commenter.

Comment:

One commenter (OAR-2002-0056-2922) stated that EPA proposes to incorporate Hg and

Ni standards into 40 CFR 60 subpart Da through section 60.45a(a) and (b) and section 60.46a,

respectively. As revisions to the NSPS, applicability of those limits to new units is limited to units

that commenced construction after the proposal date of January 30, 2004. EPA proposes to

reflect that limited applicability only by means of parenthetical statements in the compliance

provisions in 40 CFR 60 Subpart Da 60.48a(m) and (n). The commenters do not believe that

EPA’s approach is sufficient to make applicability clear. Instead, EPA should follow the

approach it took with promulgation of a new output-based NOx standard and also include a clear

statement of applicability in the provisions setting out the new standards.

Response:

EPA has clarified the applicability language as suggested by the commenter.

Comment:

Several commenters (OAR-2002-0056-2922, -2634, -2718) identified a number of

instances where the definitions do not reflect the proposed regulatory provisions. For example,

the provisions for regulation of “oil-fired” units apply to any unit combusting oil. Because some

coal-fired units combust oil for start-up, the definitions of “coal-fired” and “oil-fired” should be

revised to make clear that units that combust both coal and oil are not “oil-fired,” and that any

unit regulated as a coal-fired unit is not subject to the “oil-fired” unit limits. Those revisions
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would be consistent with EPA’s statements in the preamble regarding applicability.

Several commenters (OAR-2002-0056-2634, -2718, -2922) stated that under the

proposed rule, units combusting “natural gas at greater than or equal to 98 percent” of the unit’s

annual fuel consumption are not affected units under this proposal. Because other provisions in

the rule state that they apply to “coal-fired” units, the definition of “coal-fired” should be revised

to reflect the 98 percent or more exclusion for combustion of natural gas.

Response:

EPA has clarified the definitions. It was EPA’s intention that the definition of a “coalfired” boiler would be the governing definition. That is, if a unit burned coal, in any amount,

then it would be classified as a “coal-fired” boiler and subject to the Hg regulation. A unit that

is designed to burn oil is more likely to be able physically and actually to combust natural gas

interchangeably than is a unit designed to burn coal. Units continue to be exempt from the

emission limits during periods of startup, shutdown, and malfunction. Therefore, coal-fired

units that combust natural gas during such periods would, during these periods, be exempt from

the regulations.

Comment:

Several commenters (OAR-2002-0056-2634, -2718, -2922) noted that the rule would

include several exclusions related to combustion of “natural gas,” which is not defined. Section

63.10042 should be revised to include a definition of natural gas. EPA should also consider

whether combustion of synthetic gaseous fuels that are not derived from coal (e.g., digester gas

and landfill gas) also should be eligible for the 98 percent exclusion. The commenters believe that

they should be.

Response:

EPA will add the definition of natural gas as suggested by the commenters. However, the

other synthetic gases noted by the commenters are not “fossil fuels” under the definitions in 40

CFR 60.41a and, therefore, units firing these fuels would not be subject to this regulation unless

such firing was in combination with the firing of coal.

Comment:

One commenter (OAR-2002-0056-3449) stated that a definition of startup should be

added to the rule.

Response:

“Startup” is already defined in the General Provisions at 40 CFR 60.2.

2.1.2 Industrial Boilers
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Comment:

One commenter (OAR-2002-0056-2331) agreed with EPA’s position that the rule should

apply to only electric utility steam generating facilities (EGU). The commenter added that

non-EGU should not be included under the proposed rule. The commenter also stated that Hg

emissions from industrial boilers are insignificant in comparison with those from EGU.

Response:

EPA concurs that industrial boilers should not be included in the same source category

as electric utility steam generating units.

2.1.3 Cogeneration Units

Comment:

One commenter (OAR-2002-0056-2277) believed that consistent with Acid Rain

regulations, the proposed definition of “electric utility steam generating unit” seems intended to

exclude units that are primarily designed to provide power to industrial facilities. The commenter

believed the definition seems intended to create two categories that are regulated, typical

electricity generating utilities, and co-generation units that supply more than one-third of its

potential electric output capacity and more than 25 megawatts-electric (MWe) output to any

utility power distribution system for sale. The commenter noted that, however, as written, the

first category seems overly broad and could be read to include the industrial units that are

intentionally excluded from the second category (those that supply less than one-third of the units

potential electric output capacity or less than 25 MWe output to any utility power distribution

system for sale). The commenter further noted that, as written, the second category does not

create an exemption from the first category, although it seems intended to create this exemption. 

To clarify that the regulation applies only to units that produce more than one-third of their power

for sale, the commenter suggested the definition be changed as follows:

Electric utility steam generating unit means any fossil fuel-fired combustion unit of

more than 25 MWe that serves a generator that produces more than one third of

its potential electric output capacity and more than 25 MWe of its electricity for

sale. A unit that co-generates steam and electricity and supplies more than

one-third of its potential electric output capacity and more than 25 MWe output to

any utility power distribution system for sale is also considered an electric utility

steam generating unit.

The commenter noted that, alternately the regulation could be changed as follows to show that

the second category exempts units from the first category:

Electric utility steam generating unit means any fossil fuel-fired combustion unit of more

than 25 MWe that serves a. generator that produces electricity far sale. A unit that

co-generates steam and electricity and supplies less than one-third of its potential electric
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output capacity or less than 25 MWe output to any utility power distribution systems for

sale is not an electric utility steam generating unit.

Response:

EPA believes that the definition provided in revised subpart Da clearly defines two

categories of new sources – utility units and non-utility units (which could include industrial

boilers, combustion turbines, etc.). That is, a joint condition must be met in order to be

classified as a Utility Unit – the unit must provide more than one-third of its potential electric

output capacity and more than 25 MWe electrical output to any utility power distribution system

for sale. Further, the boiler itself must be capable of combusting more than 73 MW (250 million

Btu/hr) heat input (which equates to 25 MWe on an output basis). The Agency’s historical

interpretation of the subpart Da definition has been that a boiler meeting the capacity definition

(i.e., greater than 250 million Btu/hr) but connected to an electrical generator with a generation

capacity of 25 MWe or less would still be classified as an “electric utility steam generating unit”

under subpart Da. However, one or more new boilers with heat input capacities less than 250

million Btu/hr connected to an electrical generator with a generation capacity of greater than 25

MWe would not be considered Utility Units because they individually do not meet the definition

(they would be considered industrial boilers). EPA acknowledges that there are differences in

definitions between the NSPS program and the Acid Rain and other trading programs (e.g.,

CAIR) that result from the underlying statutory mandates.

With regard to the amount of power sold to the grid and the “trigger” beyond which a

unit is considered a Utility Unit for the purposes of this rulemaking, again there are definitional

differences that have developed from the statutory mandates. EPA believes that new sources

have the foreknowledge of the rules in effect and, thus, should be expected to be able to

determine up-front whether they want to be considered a Utility Unit or an industrial boiler (i.e.,

do they plan on selling, or is it likely that they will sell, more than one-third of their power in the

future). Therefore, EPA considers a new cogeneration unit to be subject to the subpart Da Hg

emission limit if it ever exceeds the definitional threshold. Existing units, discussed further

elsewhere in this document, are brought into the program at its inception rather than at their

start-up. Therefore, EPA is using an annual average threshold for existing units, noting that if

the threshold is ever met for a given year, then the unit will be considered a Utility Unit from

there on out.

Comment:

Several commenters (OAR-2002-0056-2085, -2206, -2906, -2922, -3525) recommended

that the final rule allow cogeneration (or combined heat and power; CHP) units above 25 MWe to

supply up to 25 MWe electrical output or up to one-third of their potential electrical output

capacity to a utility power distribution system for sale on a net annual basis as is done in the Acid

Rain program. This would likely minimize the possibility of non-utility units being classified as

utility units based upon unique situations of relatively short duration or of unrepresentative

operating history (e.g., if power was generally used exclusively at the plant at which it was

generated, but was sold to the grid when the production facility was down for maintenance). In
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the event that a unit were classified as a Utility Unit and had to meet a more stringent standard,

the EPA should provide a reasonable period of time for the unit to come into compliance. Two

commenters (OAR-2002-0056-2206, -2906) stated that this requirement stands in contrast to

EPA’s proposed CAIR, where the definition for a Utility Unit is based on a historical annual

average (69 FR 4610). The commenter stated that to prevent these undesirable consequences,

and to prevent conflicts and confusion with the definition of a Utility Unit in the CAIR, EPA

should base the Utility Unit definition on a net annualized average and not “during any portion of

the year.”

One commenter (OAR-2002-0056-2085) stated that EPA created a new opportunity for

misunderstanding by proposing in the rule that a cogeneration unit that meets the definition of a

Utility Unit during any portion of a year would be subject to the proposed rule (69 Fed. Reg.

4657). The commenter believed that EPA should not adopt its proposed approach to

cogeneration units that may operate as “electric utility steam generation units” on a short-term or

temporary basis. According to the commenter, the proposed approach will create complicated

and unnecessary issues in implementation. The commenter asked is a “year” a calendar year or a

12-month rolling average? The commenter also asked how long does a cogeneration unit need to

meet the “electric utility steam generation unit” definition to qualify - one day, one hour, or one

minute? The commenter believed that EPA will not gain a material improvement in environmental

conditions by creating these implementation problems (caused by a unit being classified as an

“electric utility steam generation unit” on a short-term or temporary basis). According to the

commenter, the Industrial Boiler MACT rule has Hg limits for boilers of the size involved here

(40 CFR Part 63 Subpart DDDDD, Table 1). The commenter noted that for coal-fired electric

utility units, the principal environmental benefit is the Hg limit. The commenter believed these

cogeneration units should be subject only to the Industrial Boiler MACT (40 CFR Part 63

Subpart DDDDD).

Three commenters (OAR-2002-0056-2206, -2906, -3525) stated that in the preamble,

EPA, absent rationale, states that any CHP unit that meets the definition of a Utility Unit during

any portion of the year would become subject to the rule. The commenters stated that requiring a

CHP unit to stay below the Utility Unit definition on an instantaneous basis provides a

disincentive for facilities to invest in new CHP capacity or to maximize the output and efficiency

of their current CHP and energy-producing network of units. The commenters encouraged EPA

to confirm that for purposes of its proposed definitions of “electric utility steam generating unit”

and “cogeneration unit,” all sales of electricity will be measured on a “net” annual basis, as is done

in the Acid Rain program. The commenters stated that in determining that “net” basis, EPA’s

accounting should take account of the specific situation of major facilities with a number of

cogeneration units. The commenters stated that at such plants, some units may be over the size

threshold, while others may be below it. Yet, according to the commenters, the electricity from

all those units will be pooled before it is either used in the plant or sold to the grid. In that case,

the commenters believed EPA’s accounting rules should provide for determining when the

threshold conditions have been met by looking at all the electricity generated by all the

cogeneration units, whether they were subject to the SIP call or not. The commenters asserted

that no other approach would be administratively feasible. In addition, the commenters pointed

out that, in some cases, contractual arrangements may exist between the cogeneration facility and
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the local electric utility wherein all generated power is considered sold to the utility and all

electricity used on the site is purchased from the utility. According to the commenters, in reality,

only a small portion of the generated power really enters the grid from the cogeneration facility,

and only that “net” sales of power should be considered when determining applicability with the

EGU definition. Subject to these qualifications, the commenters supported the cogeneration unit

threshold being used for consideration as an EGU, specifically, a unit serving a generator with a

nameplate capacity of greater than 25 MW and supplying more than one-third of its potential

electric output capacity and more than 25 MW to any utility power distribution system for sale. 

The commenters stated however, it would provide additional clarity and prevent confusion if it

was specifically stated that units associated with generators of 25 MWe capacity or less were not

affected sources under this subpart; and any cogeneration units not supplying both more than

one-third of their potential electric output capacity and more than 25 MWe to any utility power

distribution system for sale were not affected sources under this subpart. The commenters

recommended that EPA include this additional clarifying language in the final rule.

Two commenters (OAR-2002-0056-2206, -2906) stated that requiring a cogeneration unit

to stay below the Utility Unit definition on an instantaneous basis would create a large

disincentive for facilities to invest in new CHP capacity, or to maximize the output and efficiency

of their current cogeneration and energy-producing network of units. According to the

commenters, cogeneration units are inherently more efficient than traditional Utility Units (in

many cases twice as efficient), and often provide distributed key power to the grid during

transient or short-term periods of peak power demand. The commenters stated that in order to

prevent being included within the Utility Unit definition, many cogeneration units will likely

establish tight restrictions on exporting excess power to the grid, or eliminate export all together.

According to the commenters, this would have the perverse effect of reduced cogeneration unit

power output, reduced overall grid efficiency and reduced industrial steam and electricity

generation efficiency.

Response:

EPA believes that its historic interpretation of the subpart Da definition of an “electric

utility steam generating unit” has been that meeting the criteria (i.e., more than one-third of its

potential electric output capacity and more than 25 MW net-electrical output to any utility power

distribution system for sale) at any time subjects the source to subsequent compliance with the

appropriate standard. Subpart Da is applicable to each new electric utility steam generating

unit otherwise meeting the definition. Thus, there is no more basis for considering a group of

cogeneration units for the purpose of determining applicability with the rule than there is

currently for considering a group of non-cogeneration boilers. 

Comment:

One commenter (OAR-2002-0056-3525) stated that in both the proposed rule and

preamble (69 FR 4696 and 69 FR 4762), EPA applies the 18 CFR 292.205 efficiency

methodology to cogeneration facilities (implied to be limited to solid-fuel fired facilities because

gas-fired units are not included in the rule applicability). The commenter submitted that this
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proposed emission rate calculation for cogeneration units appears to unfairly penalize them for

sales of any electric power less than the full generation capacity. According to the commenter,

such a penalty is contrary to the Bush Administration’s stated intent to advance the application of

cogeneration facilities and thereby improve the nation’s energy efficiency and achieve greenhouse

gas emission intensity reductions. The commenter strongly encouraged EPA to reconsider this

approach. The commenter believed a much more equitable and workable approach would be to

provide cogeneration facilities with the ability to use input-based emission limits and calculations. 

The commenter stated that in that way, the boiler, fuels, and emissions controls will determine

compliance without the apparent emission rate being unfairly skewed by the portion of electricity

sold to the grid. According to the commenter, this method also follows from past EPA practice in

establishing emissions standards. The commenter submitted that EPA should establish emissions

standards that encourage installation and operation of highly efficient cogeneration facilities, and

recognize their inherent variability in design and operating profiles versus typical single use

electric utility units.

Response:

The approach EPA has taken with regard to crediting the steam generated beyond that

necessary to generate electric power in a cogeneration system is consistent with that taken

during the earlier revision of the subpart Da NOx emission limits. We believe that consistency is

appropriate for this application.

Comment:

Two commenters (OAR-2002-0056-2906, -3525) supported EPA’s decision not to set

emission limits for utility units that burn 98 percent or more of natural gas. The commenters

noted that historically, EPA has not drawn a distinction among natural gas and other refinery or

process gases, but rather has determined to define and regulate them as simply “gaseous fuels.” 

The commenters noted that although most commercial gas-fired utility units burn natural gas,

many CHP units located at petroleum refineries or petrochemical facilities also burn some amount

of refinery fuel gas or other process gas that is being produced and consumed onsite for energy

production. Commenter OAR-2002-0056-2906 noted that in the Industrial Boiler MACT, EPA

included not only natural gas but also process gas and refinery gas in the same subcategory. In

other words, in that rule EPA did not draw a distinction among natural gas and other refinery or

process gases, but rather defined and regulated them as simply “gaseous fuel.” The commenter

stated that this same issue exists for Utility Units under the proposed rule, and in particular

cogeneration units that meet EPA’s definition of a Utility Unit. The commenter believed that

most readers would conclude that this rule and its emission limits do not apply to CHP-type or

other utility units that burn 98 percent or more of natural gas, including other gaseous fuels. The

commenters stated that, however, it would help clarify matters if the rule specifically stated that

this exemption applies not just to natural gas, but also to other gaseous fuels such as process and

refinery gases, as well as other non-residual fuel oil fuels, in keeping with EPA’s approach in the

Industrial Boiler MACT.

Response:
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EPA believes that a reasonable interpretation of its exclusion provision for natural gasfired units would include other gaseous fossil fuels. However, EPA has clarified in the final rule

to indicate that only units that combust coal, in any amount, or any coal-derived fuel are subject

to the rule.

2.1.4 Combined Heat and Power Units

Comment:

Several commenters (OAR-2002-0056-2066, -2206, -2833, -3530) stated that the final

NSPS utility rule should not extend its mandates to either current or future CHP systems. The

commenters stated that in virtually all cases, CHP units are a source of highly efficient power with

correspondingly low emissions. According to the commenters, because cogeneration units are

generally twice as efficient (i.e.; more output per unit of input) as non-CHP Utility Units, they

consume less coal and oil, and have significantly less emissions than fossil-fuel burning non-CHP

Utility Units. The commenters asserted that, for this reason, encouraging CHP units should be

part of EPA’s strategy toward reducing harmful emissions from the electricity generating sector.

The commenters stated that the Agency should not, therefore, seek to impose additional

regulation on these units. The commenters added that hundreds of industrial facilities depend on

the economic efficiencies of CHP. The commenters stated that in fact, the President’s National

Energy Policy recommends the increased use of CHP systems to improve energy efficiency and

decrease air emissions (See National Energy Policy, Report of the National Energy Policy

Development Group, May 2001, pp. 4-11 and 6-18). The commenters also stated that however,

industrial units should be given the opportunity to voluntarily opt-in to the benefits of the

cap-and-trade program. The commenters stated that any opt-in provision should be drafted to

encourage participation and recognize cost-effective emission reductions tailored to the unique

attributes of manufacturing facilities.

Two commenters (OAR-2002-0056-2066, -2206) stated that CHP units currently

represent only about 3 percent of the electric generating capacity covered by Agency’s proposal. 

According to the commenters, CHP units are generally twice as efficient when compared to their

utility counterparts, and about two-thirds of all CHP units burn natural gas and have extremely

low NOx emission rates. The commenter stated that although individual CHP emission rates will

vary, the average gas-fired CHP emission rates are only 15 to 25 percent of that emitted by a

typical utility. The commenter added that even CHP units using coal or oil as a fuel source are

still much more efficient than a utility using the same fuels. The commenter further stated that

CHP units are usually only a small part of a much larger industrial facility or complex. According

to commenter OAR-2002-0056-2206, including CHP units in this rule may require them to install

flue gas desulfurization (FGD) or selective catalytic reduction (SCR) control technology by 2010

or purchase credits. The commenter stated that these costs will be a significant disincentive to

building these environmentally superior forms of electricity generation and could significantly

impair continued reliance on this type of environmentally wise technology. The commenter

asserted that including these units into this rulemaking would layer another set of regulations on

the entire facility, thus further complicating on-going compliance efforts, and, because there are

relatively little emissions coming from such units, not significantly reduce the amount of Hg. The
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commenter added that EPA is proposing that compliance with its new standards will be based on

emissions attributable to combustion for electricity generation, and not from steam production

(See e.g., 69 FR at 4,668 and 4,696). For these reasons, the commenters believed that CHP units

should be exempted from inclusion in this rulemaking. According to the commenters, inclusion of

traditional CHP facilities would provide negligible environment benefit while discouraging

application of these ultra-efficient power and steam generators both now and in the future.

Response:

EPA sees no reason to exclude cogeneration or CHP units that otherwise meet the

definition of “electric utility steam generating unit” from the final rule, as units meeting the

definition would, like other similarly sized but non-cogeneration units, be emitters of Hg.

2.1.3 Other

Comment:

One commenter (OAR-2002-0056-2835) stated that for any regulatory program for Hg

and Ni emissions, EPA should clarify that compliance with the regulatory requirements qualifies

as a pollution control project. The commenter stated that regardless of whether EPA implements

a regulatory program under CAA section 112(d), section 112(n)(1)(A), or section 111, the

regulation should provide that projects and/or activities undertaken by electric utilities to comply

with the obligations of a Hg regulatory program do not trigger the requirements of New Source

Review (NSR) or Prevention of Significant Deterioration (PSD). The commenter further stated

that as a matter of policy, an affected source should not trigger additional regulatory requirements

when undertaking efforts to comply with a set of new regulations, particularly where the new

rules lead to reductions in HAP.

The commenter noted that the proposed emission guidelines for oil-fired units already

include a provision in Section 60.4010(b) which states that “[p]hysical or operational changes

made to an existing electric utility steam generating unit solely to comply with an emission

guideline are not considered a modification or reconstruction and would not subject an existing

electric utility steam generating unit to the requirements of subpart Da (see Section 60.40a of

subpart Da).” The commenter recommended that this provision be expanded to include the

requirements imposed by the NSR and PSD programs. Furthermore, the commenter urged EPA

to include this expanded provision in any regulatory program for all electric utilities (i.e., the

MACT standard or a cap-and-trade program). The commenter stated that by making the rule

explicit that such projects would not trigger the NSR and PSD programs, EPA avoids the

situation where State permitting agencies have to second guess whether implementation projects

and activities are indeed pollution control projects.

Response:

NSR and PSD are only triggered through emission increases. Compliance with the

promulgated rule would not result in emission increases and, thus, would not trigger NSR or
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PSD.

2.2 SUBCATEGORIZATION

The proposed NSPS includes Hg emission limits for new coal-fired units subcategorized

by coal rank (bituminous, subbituminous, lignite, waste coal, integrated gasification combined

cycle [IGCC]). The rationale for subcategorization under section 111 is the same as was

described in the January 30, 2004, proposed section 112 standards. Therefore, many commenters

only addressed subcategorization in the context of section 112; it is presumed that their

comments, when not otherwise explicitly stated, also pertain to the proposed

section 111 standards.

2.2.1 Support for Subcategorization

Comment:

One commenter (OAR-2002-0056-2915) pointed out that under CAA section 111, EPA

has previously subcategorized coal-fired utility units based on the sulfur levels in the coals they

burn. The commenter noted that this subcategorization approach was approved by the U.S.

Court of Appeals for the District of Columbia Circuit in Sierra Club v. Costle, 657 F.2d 298 (D.C.

Cir. 1981). The commenter stated that in approving EPA’s NSPS regulations, the Court

recognized that CAA section 111 allowed EPA “to distinguish among classes, types and sizes

within categories.” The commenter noted that the Court explained that “[o]n the basis of this

language alone, it would seem presumptively reasonable for EPA to set different...standards for

utility plants that burn coal of varying sulfur content.” Thus, the Court found that EPA could

create subcategories based on the type of fuel an EGU burns.

One commenter (OAR-2002-0056-2862) stated that in establishing a new source NSPS

for Hg, EPA should subcategorize coal-fired power plants based on the rank of coal fired. The

commenter stated that pursuant to CAA section 111(b)(2), EPA has the authority to distinguish

among classes, types, and sizes within categories of new sources for the purpose of establishing

NSPS standards. (42 U.S.C. section 7411(2)) The commenter stated that it supports EPA’s

proposed subcategorization of coal-fired power plants based on coal rank and also referred to the

Circuit Court case (Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981)).

Several commenters (OAR-2002-0056-2067, -2161, -2247, -2264, -2332, -2365, -2375,

-2634, -2721, -2725, -2835, -2891, -2897, -2898, -2900, -2907, -2911, -2915, -2918, -2948, -

3198, -3200, -3398, -3440, -3469, -3514, -3537, -3539, -4139, -4191) supported EPA’s use of

subcategories. Two commenters (OAR-2002-0056-2375, -2918) supported EPA’s decision to

subcategorize bituminous, subbituminous, and lignite-burning affected units and stated that EPA’s

subcategorization based on coal rank is proper under section 111, which gives EPA broad

authority to subcategorize as it deems appropriate. The commenter also stated that the CAA, as

interpreted by the D.C. circuit and the legislative history, make clear that EPA has broad authority

to distinguish among classes, types, and sizes of sources to account for differences in the

effectiveness of control technology. One commenter (OAR-2002-0056-2375) stated that EPA’s
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approach to the subcategorization of electric utility steam generating units is generally appropriate

and consistent with the CAA and believes that subcategorization of coal-fired and oil-fired units

into two subcategories is warranted based on their distinct emissions profiles and their typical uses

as base-load and peaking units, respectively. The commenter also supported EPA’s proposal to

subcategorize coal-fired units by coal rank, in part, to account for the significant impact coal rank

can have on overall plant design, the design process and the operation of pollution controls.

According to several commenters (OAR-2002-0056-2067, -2365, -2375, -2725, -2898,

-3198, -3514), subcategorization by coal rank is amply supported by the differences in Hg

speciation that in turn impact the effectiveness of control technology. One commenter

(OAR-2002-0056-2891) notes that cooperatives are users of all three general coal ranks and, in

relation to the rest of the industry, are heavy users of subbituminous and lignite coals. The

commenter stated that because it is much more difficult and expensive to reduce Hg emissions

from these when compared to eastern bituminous coal, a single standard for Hg emission limits for

all coal-fired power plants would be impossible, as a practical matter, for some lignite and

subbituminous coal burning plants to meet. The commenter believed that it is imperative that in

the final rule, the use of any specific coal type or rank must not be advantaged or disadvantaged.

One commenter (OAR-2002-0056-2897) stated that concerns that subcategorization

causes an increase in allowable Hg emissions are unjustified in that under a cap-and-trade system,

the emissions cannot exceed the cap, and under a MACT system the average floor effectively sets

the emission level. The commenter believed that subcategorization does not necessarily raise

emissions but merely ensures that the compliance burden is evenly distributed. The commenter

also stated that concerns that subcategorization may result in more complex permitting are

overstated and can be resolved. The commenter indicated that permitting is a relatively minor

issue compared with the disruption to the nation’s energy system and fuel switching, including

switching to gas, that will occur if bituminous and subbituminous coals are not subcategorized

separately.

One commenter (OAR-2002-0056-2375) supported EPA’s subcategorization of IGCC

units based on the distinct processes that such units employ (i.e., they are the only units that do

not combust coal in the unit during operation).

One commenter (OAR-2002-0056-2948) supported EPA’s decision to subcategorize

electric utility steam generating units and stated that EPA should place oil-fired units in a different

category than coal-fired units because emissions from those plants differ markedly.

One commenter (OAR-2002-0056-2721) agreed with EPA’s proposed five subcategories

- four based on coal ranks and one for process type - and disagreed with the option to combine

subbituminous with bituminous coals for the purposes of Hg regulations. The commenter did not

agree that a five-category program places a burden on the Utility Unit for tracking burn rates from

various coal sources on a monthly or annual basis. The commenter asserted the practical

implications of this co-categorization would be significant. The commenter stated that the

differences in the Hg emission levels on subbituminous and bituminous coals are great and have

been well documented and published in the ICR data. The commenter noted that these coals are
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currently blended for sulfur compliance. The commenter stated that because of the significant

higher sulfur content in the bituminous coal, the reverse scenario of blending bituminous coal with

subbituminous coal for Hg compliance would be detrimental to the SO2 compliance of the facility.

Several commenters (OAR-2002-0056-2260, -2560, -2725, -3440) supported EPA’s

proposal to use subcategories in setting emissions limits and providing allocations to adequately

address differences in abilities to control Hg based on coal chemistry that varies with coal rank. 

One commenter (OAR-2002-0056-2560) stated that their coal-fired facilities have different boiler

configurations and fuel firing abilities, and that this is typical for the industry. The commenter

further stated that a key consideration in Hg removal from coal is the presence or lack of

halogens. The commenter supported subcategorization in that it recognizes the technological

challenges presented by the lack of halogens in Powder River Basin (PRB) subbituminous coals.

One commenter (OAR-2002-0056-2725) believes that subcategorization should include at

least three categories: lignite, subbituminous, and bituminous coals. The commenter stated all

these coal ranks behave differently when burned, releasing significantly different levels of Hg that

may require different controls. The commenter adds that Hg control costs for lignite and

subbituminous coals may be higher at plants that already have particulate matter (PM) and sulfur

dioxide (SO2) controls than the control costs for plants burning bituminous coal. The commenter

stated that any regulation of Hg that includes a one-size-fits-all standard would unfair. The

commenter stated that lignite and subbituminous coals are fundamentally different from

bituminous coal.

Several commenters (OAR-2002-0056-2830, -3543, -3406) supported the separate

treatment of lignite through the subcategorization process.

One commenter (OAR-2002-0056-3208) believed it is important for EPA to recognize the

relative disadvantage at which it now places PRB subbituminous coal due to the preponderance of

elemental Hg in its content. The commenter submits that PRB coal now will be placed at risk in

contravention of previous environmental policies that encouraged its use. According to the

commenter, these factors should motivate EPA to recognize the need for subcategorization of

coals in determining MACT for Hg removal.

In supporting EPA’s decision to create separate subcategories for bituminous and

subbituminous coals, one commenter (OAR-2002-0056-2897) stated that bituminous coals are

more likely to be used in a plant equipped with wet flue gas desulfurization (wet FGD) for SO2

control and selective catalytic reduction (SCR) for nitrogen oxides (NOx) control and are,

therefore, more likely to benefit from “co-benefit” capture in these systems, whereas a

subbituminous coal is more likely to be burned in a plant with a dry scrubber, which has shown no

quantifiable Hg capture in testing to date. The commenter also stated that supra fuel switching is

not a viable solution and failing to subcategorize between bituminous and subbituminous would

create regional disparities.

Several commenters (OAR-2002-0056-1969, -2161, -2535, -2661, -2843, -2867, -2891,

-2897, -3539) supported separate subcategories stating that there are significant differences
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between the two coals, subsequent speciation of the Hg in the flue gases, and differences in

achievable emission reductions. One commenter (OAR-2002-0056-2661) stated that if coal ranks

were combined into a single category, rural electric consumers would be negatively impacted. 

The commenter stated that if a single standard for Hg emission limits were set for all coal-fired

power plants, based on bituminous rank coals, it would be impossible, as a practical matter, for

some lignite and subbituminous coal burning plants to meet that standard. One commenter

(OAR-2002-0056-2891) stated that cooperatives are users of all three general coal ranks and, in

relation to the rest of the industry, are heavy users of subbituminous and lignite coals and would

be disadvantaged under a single emission limit.

One commenter (OAR-2002-0056-2948) stated that EPA should subcategorize units

based on differences between coal ranks. The commenter did not believe, however, that EPA

should place units burning coals of more than one rank in a separate subcategory because large

differences exist in the way plants burn coals of more than one rank.

One commenter (OAR-2002-0056-2067) agreed with EPA that there is no demonstrated

justification to create a separate category for circulating fluidized bed (CFB) units.

Response:

EPA concurs with the commenters.

2.2.2 No Subcategorization

Comment:

Many commenters (OAR-2002-0056-2575, -2823, -2878, -2920, -3459) doubt the

legality of EPA’s use of subcategorization by coal rank. One commenter (OAR-2002-0056-2920)

stated that EPA’s proposal to subcategorize by coal rank is unlawful, arbitrary, and capricious for

the following reasons:

(1) EPA provides no reason to believe that just because some plants are located near

mine mouths (e.g., lignite plants), they are of a different class, type, or size than other

units;

(2) EPA argues that the characteristics of the coal rank to be burned was the driving

factor in how a unit was designed, but does not say what those design differences are and

does not claim that any such differences are so great that plants designed to burn different

ranks of coal are different classes, types, or sizes of a unit;

(3) EPA admits that many plants burn two or more different ranks of coal;

(4) EPA admits that its basis for subcategorization was to ensure that standards are

achievable for all sources through the use of certain technologies. According to the

commenter, this argument has been found unlawful (Cement Kiln Recycling Coalition v.
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EPA);

(5) EPA appears not to have seriously considered alternative subcategorization

approaches or no subcategorization.

One commenter (OAR-2002-0056-2878) stated that EPA fails to provide any technical

rationale to justify why coal rank should define the allowable emissions a unit can emit when

technology is available that enables all plants to meet high levels of Hg control regardless of coal

rank. According to the commenter, EPA’s rationale is based on a misguided claim that boilers are

specifically designed for a specific rank of fuel. Yet, according to the commenter, units burn more

than one rank of coal in the same boiler. In support, the commenter cited the Stanton study which

showed that high levels of Hg reduction can be achieved with currently available technology,

regardless of coal rank. According to the commenter, the Stanton study was used as the basis for

Iowa’s recent permit for a new unit burning subbituminous coal from the PRB that requires

83 percent reduction using activated carbon injection (ACI) or other sorbent injection.

According to one commenter (OAR-2002-0056-2823), 11 State Attorneys General

contend that EPA’s proposed subcategorization by coal rank is unlawful because:

(1) EPA applied the scheme inconsistently (i.e., EPA cannot insist that emission

standards be set for specific subcategories and then reject standards that are so tailored

because they are not appropriate for every unit in the category as a whole);

(2) EPA’s scheme does not accurately reflect industry practices as it applies to the

subcategorization scheme because there are units that burn more than one rank of coal;

and

(3) The proposed scheme does not serve to protect health and the environment in that

EPA admits that it elected to subcategorize by coal rank so as to produce a standards

achievable by all units, ensuring that units continue to operate rather than on protecting

human health and the environment.

One commenter (OAR-2002-0056-2575) argued that subcategorization can only be done

on three criteria: class, type, and size of sources and the factor that coal rank is one of the

characteristics of a coal-fired boiler does not mean it can be used for subcategorization. The

commenter stated that EPA’s reliance on coal rank is misplaced because many coal-fired units

blend or fire two or more ranks of coal in the same boiler and EPA itself states that coal blending

is possible and not uncommon. The commenter stated that EPA also claims (with no support)

that fuel switching would require significant modification or retooling of a unit. The commenter

cited case law to support its contention that EPA’s subcategorization is not permitted. The

commenter stated that EPA’s justification for rejecting a no subcategorization option is factually

and legally indefensible. That is, EPA based its subcategorization on two principles:

(1) plants were largely designed based on coal rank to be burned and fuel switching

would be problematic, and
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(2) the type of coal rank to be burned is based on economic issues, including availability

withing the area.

The commenter stated that, as stated above, reliance on coal rank is factually wrong and fuel

switching is a common practice.

According to one commenter (OAR-2002-0056-3459), EPA’s proposed subcategories are

contrary to law, without rational basis, arbitrary and capricious, and an abuse of discretion. The

commenter stated that EPA proposes subcategorization by coal rank, based on the arguments that

combustion technologies are coal-rank specific and that many utilities are dependent on particular

mines and, therefore, particular ranks of coal. According to the commenter, these arguments are

not supported by the facts:

(1) Utilities regularly burn more than one rank of coal together and there is no significant

technical difference in the boilers receiving various ranks of coal.

(2) EPA’s reliance on American Society for Testing and Materials (ASTM) methods to

determine coal rank is so technically problematic that it erodes EPA’s rationale for

subcategorization by coal rank. Coal rank is not an easily discernible and always clear

characteristic of coal and EPA itself acknowledges some overlap.

(3) Individual mines can produce different ranks of coal. EPA’s justification that many

utilities are dependent on particular mines and therefore particular ranks of coal is not

supported.

(4) EPA acknowledges that coals of varying ranks have similar combustion and handling

properties, and operators have learned to handle these blends but then ignores it.

(5) EPA’s assumptions also differ from real world experience where many units switched

to low-sulfur coal to satisfy the acid rain program requirements, demonstrating that units

are capable of burning a mix of coal ranks.

(6) Even if different ranks do have different properties, coal treatment technology may

allow one coal rank to act in ways that make it more like a coal of a different rank. EPA

acknowledges that a key consideration in subcategorization decisions is whether different

units have differences in the feasibility in the application of control technology. However,

available evidence shows that units burning different ranks of coal are equally amenable to

Hg pollution controls. Both high and low rank coals (such as bituminous and

subbituminous) coal can be controlled by the same control technology

(7) Although EPA has only spurious rationale for subcategorization of existing units;

there is no rationale for new units. These can be designed to provide optimum

performance when firing all coal ranks.

Response:
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EPA continues to believe that it has the statutory authority to subcategorize based on

coal rank and process type, as appropriate for a given standard. As initially structured, subpart

Da subcategorized based on the sulfur content of the coal (essentially based on coal rank) for

SO2 emission limits and based on coal rank for NOx emission limits. This approach was selected

because of the differences in the relative ability of the respective control technologies to effect

emission reductions on the various coal ranks. Although EPA has subsequently changed the

format of the NOx emission limits and has recently proposed to establish common SO2 emission

limits regardless of coal rank (70 FR 9706), we believe that the conditions existing at proposal

of the previous standards (e.g., the inability of the technologies to control SO2 and NOx equally

from all coal ranks) equally apply now for Hg and justify the use of subcategorization by coal

rank for the Hg emission limits. This does not indicate, however, that at some point in the

future, the performance of control technologies on Hg emissions will not advance to the point

that the rank of coal being fired is irrelevant to the level of Hg control achieved (similar to the

point reached by controls for SO2 and NOx emissions). At that time, EPA may adjust the

approach to Hg controls appropriately.

Comment:

Many commenters (OAR-2002-0056-1471, -1611, -1682, -1686, -1687, -1773, -1861,

-2108, -2160, -2243, -2334, -2415, -2441, -2819, -2833, -2878, -2887, -2889, -2924, -3199,

-3435, -3437, -3440, -3449) opposed the use of subcategories based on fuel types. One

commenter (OAR-2002-0056-3199) recommended that EPA establish fuel-neutral limits that

account for the high variability in coal, combustion processes, and control system performance

under different types of firing conditions. Several commenters (OAR-2002-0056-1471, -1611,

-1773, -1861, -2108) believe that subcategorization by coal rank is not warranted or is otherwise

questionable because a unit can burn bituminous or subbituminous coal with no change to the

boiler. They argued that a fuel-neutral rule would provide an incentive for plants to blend the two

ranks of coal and point to the industrial boiler MACT which was fuel neutral. These commenters

stated that subcategorization by coal rank simply guarantees the continuing use of Hg-heavy fuel. 

In opposing subcategorization, two commenters (OAR-2002-0056-2243, -2878) stated that the

percent removal requirement should be the same for all fuel ranks and unit configurations. One

commenter (OAR-2002-0056-2878) recommended a single performance standard to reduce

emissions by 90 percent in 2007 and stated that this can be achieved by ACI with an electrostatic

precipitator (ESP) and a retrofit fabric filter or a fabric filter alone.

Several commenters (OAR-2002-0056-1682, -1686, -1687, -2108) oppose

subcategorization by coal rank because plants burning western, subbituminous, or lignite coal

remain uncontrolled while plants burning eastern bituminous coal must have one or more controls. 

The commenters stated that this is inconsistent with the CAA’s fuel neutrality and harms the

economies of States with eastern coal. According to the commenters, Illinois has seen a

25 percent increase in Hg emissions due to a switch to subbituminous coals. They stated that this

impact has not been reflected in the EPA analyses. One commenter (OAR-2002-0056-2160)

stated that Illinois, Indiana, Ohio, and West Virginia oppose subcategorization by coal rank and

prefer limits that are fuel neutral. The commenter stated that the more stringent limits for

bituminous coal will result in fuel switching with severe economic impacts on States that produce
2-17

bituminous coal and negligible emission reductions due to switching to subbituminous coal as the

low cost compliance strategy for Hg. One commenter (OAR-2002-0056-2819) supported a

single fuel-neutral limit that would not be any less stringent than the rules proposed by New

Jersey and promulgated by Massachusetts. According to the commenter, compliance can be

achieved through currently available technologies: for a cyclone boiler, SCR can be used in

conjunction with FGD or ACI and a particulate control device, and, for a tangential boiler,

compliance can be achieved through an appropriate PM control device that collects fly ash if

needed or by ACI with a particulate control device when fly ash re-injection systems are used. 

Two commenters (OAR-2002-0056-2924, -3449) oppose subcategorization on the grounds that

the higher limit for subbituminous coal could encourage operators to switch and blend fuels

resulting in an increase in Hg emissions. One commenter (OAR-2002-0056-2924) stated that as a

result, they would continue to be impacted by Hg emissions from other areas and that

differentiation should be based on the type of unit (which would not discriminate against fuel

type), not the rank of coal.

One commenter (OAR-2002-0056-3449) stated that subbituminous coals or blends of

subbituminous and bituminous coals can frequently be burned in units previously burning only

bituminous coal without extensive retrofit. According to this commenter, combustion of waste

coal or anthracite coals also results in similar emissions; thus, separate limits for bituminous,

subbituminous, and waste coal is questionable. One commenter (OAR-2002-0056-2889) stated

that if EPA had used a sufficiently long averaging time (which it did not attempt to address), it

would obviate the need to consider variability of coal Hg content, allowing a coal-neutral rule. 

The commenter stated that another difficulty with the subcategorization scheme is the inaccuracy

typically encountered in determining the amount of different ranks of coal in a blend, which is

typically done in a bulldozer. One commenter (OAR-2002-0056-2887) stated that practical

reasons for limiting the number of subcategories is the reduced regulatory burden and increased

plant flexibility in fuel procurement and management strategies. One commenter

(OAR-2002-0056-2819) stated that EPA’s analyses supporting subcategorization are severely

flawed because of the limited amount of stack test data collected and analyzed to date. The

commenter stated that as more data is collected (primarily at the State level), it is evident that

factors other than coal rank are more important in determining Hg speciation and the ability of

commercially available control technologies to reduce emissions from coal-fired boilers. 

According to the commenter, important factors that affect Hg speciation and control effectiveness

include: the combustion efficiency of the utility boiler, and the combination of control. One

commenter (OAR-2002-0056-3437) stated that subcategorization creates a competitive

advantage for western coal that is not justified and is inconsistent with other Federal programs

such as the NOx SIP Call and the proposed Clean Air Interstate Rule (CAIR; originally titled at

proposal the Interstate Air Quality Rule, IAQR), which are fuel neutral. One commenter

(OAR-2002-0056-3435) stated that the variability of the Hg and chlorine (Cl) content of coal

within a rank, the ability of a unit to burn more than one rank of coal, and the magnitude of the

difference in emission limits diminishes the merit of subcategorization by coal rank, particularly

for bituminous and subbituminous units.

One commenter (OAR-2002-0056-2944) disagreed with the proposal to subcategorize

based on coal ranks. The commenter stated that coal rank is a continuous variable, a function of
2-18

degree, not one of kind, stretching from before peat on the one end to past anthracite on the

other. The commenter noted that these classifications grade into each other and in many cases

can be subject to dispute and added that, as noted in the proposed rules, the ASTM classification

of coal rank has overlapping attributes.

One commenter (OAR-2002-0056-2944) noted that U.S. boilers commonly fire mixes of

coals of different ranks, citing information from the ICR that although around 215 utility boilers

burned only subbituminous coals, nearly as many burned both combinations of subbituminous and

bituminous. The commenter added that about 25 percent of the boilers that burned lignite burned

other coal ranks as well. The commenter further stated that over the last two decades a very

significant number of U.S. plants converted their boilers from burning high-sulfur bituminous

coals to low-sulfur subbituminous coals to reduce their SO2 emissions. According to the

commenter, obviously, there is nothing particularly unique about coal rank that should lead to

subcategorization and dramatically different Hg emission limits. The commenter observed that

U.S. coal-fired boilers burn combinations of many carbonaceous fuels: in addition to lignite,

subbituminous, and bituminous coals they burn anthracite, petroleum coke, waste subbituminous,

waste bituminous, waste anthracite, biomass, and waste tires. The commenter asked is it logical,

or practical to have separate emission standard determinations for each. The commenter further

asked how can compliance be fairly determined at the over 20 percent of plants that burn multiple

fuels simultaneously.

The commenter continued that the three primary coal-fired boiler fuel types contain Hg

relative to their heating value at about the same degree. The commenter stated that each coal

rank has about 70 percent of its deliveries with Hg contents measured between 4 and 14 pounds

of Hg per trillion British thermal units (lb/TBtu). The commenter added that median Hg contents

of each coal rank are also similar at 7, 5 and 8 lb Hg/T Btu for bituminous, subbituminous, and

lignite respectively. (The commenter further noted that although subbituminous coals contain less

Hg than bituminous coals, they ended up being allowed to emit nearly three times as much in the

currently-proposed regulations.) The commenter stated that there is nothing obvious about the

Hg content of coals of different ranks that justifies subcategorization.

Response:

EPA believes that there are sufficient differences in the design and operation of utility

boilers utilizing the different coal ranks to justify subcategorization by major coal rank. As

documented in the record, utility boilers vary in size depending on the rank of coal burned (i.e.,

boilers designed to fire lignite coal are larger than those designed to fire subbituminous coal

which, in turn, are larger than those designed to fire bituminous coal). Boilers designed to burn

one fuel (e.g., lignite) can not randomly or arbitrarily change fuels without extensive testing and

tuning of both the boiler and the control device. Further, if a different rank of coal is burned in

a boiler designed for another rank, either in total or through blending, the practice is only done

with ranks that have similar characteristics to those for which the boiler was originally designed. 

That is, the ASTM classification system is structured on a continuum based on a number of

characteristics (e.g., heat content or Btu value, fixed carbon, volatile matter, agglomerating vs.

non-agglomerating) and provides basic information regarding combustion characteristics. 
2-19

Because more than one characteristic is used, the possibility exists for numerous situations

where a coal could be “classified” in one rank based on one characteristic but in another rank

based on another characteristic. Ranking is based on an evaluation of all characteristics. 

Therefore, it is possible that (for example) a non-agglomerating subbituminous coal with a

heating value of 8,300 Btu/lb (ASTM classification III.3–“Subbituminous C coal”) could be

co-fired with, or substituted for, a non-agglomerating lignite coal with heating value of

8,300 Btu/lb (ASTM classification IV.1--“Lignite A coal”). This does not, however, mean that it

is possible for a boiler designed to burn the Lignite A coal to burn an agglomerating coal with a

heating value of 13,000 Btu/lb (e.g., ASTM classification II.5–“High volatile C bituminous

coal”). Further, it does not mean that the substituted coal would exhibit the same

“controllability” with respect to emissions reductions as the original coal, regardless of its

compatibility with the boiler. The fact that a number of Utility Units co-fire different ranks of

coal does not negate the overall differences in the ranks that preclude universal coal rank

switching, particularly when the design coal ranks are not adjacent on the ASTM classification

continuum.

Although other classification approaches have been suggested (e.g., based on the

geologic age of the coal; see OAR-2002-0056-5411), the ASTM classification system remains

the one most recognized and utilized by the industry and the one which the EPA believes is most

suitable for use as a basis for subcategorization. EPA further believes that, at this time, coal

rank is an appropriate and justifiable basis on which to subcategorize for the purposes of this

rule. We address elsewhere in this document comments related to the appropriate emission level

for each subcategory.

2.2.3 Single Subcategory for Bituminous and Subbituminous

Comment:

Many commenters (OAR-2002-0056-1675, -1677, -1762, -1848, -1852, -1853, -2160,

-2269, -2660, -2826, -2860, -2871, -2878, -2875, -2889, -2904, -2905, -2908, -2937, -2944,

-3205, -3324, -3366, -3394, -3406, -3435, -3449, -3560) opposed subcategorization and setting

different limits for bituminous and subbituminous coal ranks. Some commenters

(OAR-2002-0056-1675, -2160, -2871, -2889, -3324, -3394) stated that such subcategorization

discriminates against bituminous coal and could result in increased emissions as plants switch to

subbituminous coal to take advantage of the lax limit, rather than install Hg controls. Two

commenters (OAR-2002-0056-2871, -2889) stated that the final rule should address the lax

requirement for subbituminous coal by requiring a stricter limit for subbituminous coal (i.e.,

80 percent). One commenter (OAR-2002-0056-3406) stated that the rationale for

subcategorization presumably is that Hg emissions from subbituminous coal are more difficult to

control. The commenter believed, however, this is almost certainly a short-term problem in light

of the progress that has been and is being made with respect to the development of Hg controls

for this coal rank and that development of these needed controls for subbituminous coal actually

will be stalled if strict control standards are not promulgated. Another commenter

(OAR-2002-0056-2160) stated that when Hg-specific control technologies are commercialized,

there will be no differentiation in their performance for different ranks of coal, which they say, is
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supported by preliminary data which indicates that there are no removal differences between

bituminous and subbituminous coals using the compact hybrid particulate collector (COHPAC)

technology.

Two commenters (OAR-2002-0056-2878, -3205) cited the paper, “Mercury Air Pollution: 

The Case for Rigorous MACT Standards for Subbituminous Coal,” to support their contention

that there is no technical justification for the separate subcategories. The commenters stated that

the technology is available that can achieve 90 percent reduction at the same costs for both ranks

of coal using ACI and an ESP and COHPAC baghouse for particulate collection and nearly all the

western plants are already equipped with either an ESP or baghouse. According to the

commenters, subcategorizing these two ranks of coal also may result in plants switching or

locking into using the dirtier western subbituminous coal because of the more lenient limits. The

commenters also stated that separate limits would be difficult to implement and enforce because

many plants burn both ranks of coal, some coals cannot be classified as either rank under the

ASTM standard, and the amounts vary from month to month and year to year. One commenter

(OAR-2002-0056-3205) stated that the proposed Roundup power plant provides a perfect

example of the implementation issues that arise with EPA’s proposed subcategorization. A

review of 300 samples from various points across the nearby basin from which the plant’s coal

would come could not be classified as bituminous or subbituminous by ASTM standards.

One commenter (OAR-2002-0056-3205) stated that EPA fails to provide an adequate

rationale to justify weaker standards for units burning subbituminous coal. In opposing separate

subcategories for units burning bituminous and subbituminous coal, one commenter

(OAR-2002-0056-3406) explained that companies are increasingly attempting to capture subtle

changes in fuel price and viewing fuel supply as a compliance option, with the result that many

companies use various blends of coal to optimize their emission performance. The commenter

believed that the use of subcategories may significantly limit the flexibility to manage a facility’s

operational conditions and fuel choice; in the context of a competitive market for supplying

electric generation, operational flexibility and fuel choice are of paramount importance. One

commenter (OAR-2002-0056-3435) stated that the variability of the Hg and Cl content of coal

within a rank, the ability of a unit to burn more than one rank of coal, and the magnitude of the

difference in emission limits diminishes the merit of subcategorization by coal rank, particularly

for bituminous and subbituminous units.

One commenter (OAR-2002-0056-3449) opposed subcategorization by coal rank stating

that subcategorization results in more blending of subbituminous coal at existing bituminous units. 

The commenter stated that coal blending is becoming more common and can result in Hg

emission reductions (30 to 40 percent subbituminous coal with about 60 to 70 percent bituminous

coal reduced Hg emissions by about 35 percent at one plant). According to the commenter, this

is because subbituminous coal has less Hg and the combination of blend characteristics and

existing controls for bituminous coal maintains the efficiency of Hg control for the blend. The

commenter stated that this contradicts EPA’s assumption that it is harder to control Hg from

subbituminous coal. According to the commenter, it may be that the lack of control systems,

especially for NOx, will cause lower Hg removal at some subbituminous plants.
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One commenter (OAR-2002-0056-2860) favored a single category for bituminous and

subbituminous coal stating that a fuel-neutral standard would facilitate compliance by simplifying

recordkeeping and reporting for the type of fuel burned. The commenter also stated that it was

not clear in the ICR database how EPA determined which sources are considered in each

subcategory because a number of sources identified one fuel as primary yet tested another fuel.

Two commenters (OAR-2002-0056-1848, -1853) opposed subcategorization for

subbituminous coal as unnecessary and potentially illegal, stating that the decision is at odds with

the FACA workgroup as evidenced in October 30, 2002, memorandum.

Some commenters (OAR-2002-0056-2826, -3560) stated that because of the CAA and

rules relevant to SO2, several Midwest utilities switched to low sulfur western subbituminous

coal, thereby increasing the amount of Hg that was emitted. Yet, under the proposed Hg rules,

power plants burning low-sulfur western coal will be subject to less strict Hg emissions limits than

plants that burn bituminous and coal refuse. Those power plants that switched to lower sulfur

coal will benefit from the less stringent Hg standard, even though these plants are emitting more

Hg. The commenter stated that they should not be penalized for making the choice to continue to

burn coal refuse and bituminous coal, rather than switching to low-sulfur western coal, especially

when it has in place on both units all the technology considered sufficient for compliance.

According to one commenter (OAR-2002-0056-2905), Wisconsin recently completed a

Hg rule that is reasonable, achievable, and cost effective and urges EPA to promulgate a more

stringent rule, particularly for subbituminous coal. According to the commenter, Wisconsin,

where many utilities rely heavily on western subbituminous coal, requires a 40 percent reduction

by 2010, 75 percent by 2015, and 80 percent by 2018.

One commenter (OAR-2002-0056-3435) recommended a single subcategory for existing

units burning bituminous and subbituminous coal with separate subcategories for lignite, coal

refuse-fired, and IGCC units. The commenter stated that according to EPA, an estimated

23 percent of the coal-fired utilities burn two or more ranks of coal in the same boiler. Because

the proposed rule does not prohibit a utility from fuel switching, the commenter stated that a unit

could switch to a lower rank coal and increase emissions by as much as 190 percent. The

commenter argued that combining bituminous and subbituminous units in one category would

preserve flexibility for fuel blending and switching without affecting the applicable emission

standard. Although fuel switching is not an option due to design limitations, the commenter

stated that there are plants that are capable of burning both ranks of coal. According to the

commenter, if other coal ranks such as lignite are given a separate limit, the use of lower rank coal

should be subject to approval, considering either the operation of the facility or other

environmental impacts, such as NOx or SO2 reductions. Another commenter

(OAR-2002-0056-3406) recommended a single standard for existing pulverized coal units burning

bituminous and subbituminous coal.

Response:

As noted above, EPA believes that subcategorization by coal rank, including for
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bituminous and subbituminous ranks, is appropriate in this case. The ability of some units to

burn more than one rank of coal does not override the overall appropriateness of the approach. 

We will address later in this document the respective emission limits for the various coal ranks. 

Further, we believe that the regulatory approach being taken (e.g., cap-and-trade) will address

the monitoring and recordkeeping concerns raised.

Comment:

One commenter (OAR-2002-0056-1852) sought clarification on how EPA will calculate a

Hg emission standard, based upon the proposed subcategories, for coals that have undergone

pre-combustion. According to the commenter, pre-combustion technology alters a fuel’s

chemical and physical properties so that the end resulting fuel does not resemble the initial

feedstock.

Response:

Under the approach being taken for the final rule (i.e., cap-and-trade), units will be

assigned Hg allocations. Compliance with the allocated Hg emissions “cap” may then be

accomplished by any means the owner/operator chooses.

Comment:

One commenter (OAR-2002-0056-2269) recommended combining subbituminous coal

and western bituminous coal into a single subcategory because:

(1) The similar low sulfur, low Hg, low Cl, and high calcium content of western

bituminous and subbituminous coal is consistent with similar Hg flue gas speciation (and

consequently, similar emission control performance);

(2) Combining them into a single class simplifies equitable development and enforcement

of rules; and

(3) The amount of Hg in western bituminous coal is only 5 percent of the total Hg in coal

burned in the U.S., so this change would have a negligible effect on emission reductions.

They recommended that the same limits as proposed for subbituminous coal also apply to western

bituminous coals at new and existing plants. The commenter believed that the proximity of

subbituminous and bituminous coals in the west will cause market impacts and complicated

oversight if limits are specified by rank. The commenter stated, for example, both kinds of coal

may be produced from a single mine or a single county or region. And, where the ASTM rank

parameter is near the subbituminous/bituminous threshold, the commenter stated that regulators

will need to consider complicated scientific factors as well as the impact of the sampling method

on moisture content to know which rank is which. The commenter also recommended that State

Hg budgets should be revised to reflect coal origin, where the algorithm used for plants burning

subbituminous coal is also used for plants burning western bituminous coal and adjusted in
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proportion to their fractional share of western bituminous coal as needed.

Response:

As noted above, although EPA recognizes that the ASTM classification system may not

be perfect and, in fact, has occurrences of overlap, it remains the most widely accepted system

and, therefore, is appropriate for use in subcategorizing for the purpose of this rule.

2.2.4 Lignite

Comment:

To recognize the differences in lignite coals, several commenters (OAR-2002-0056-1803,

-2054, -2422, -2844, -2867, -2915, -3327, -3440, -3463, -3469, -3510, -3543, -4191, -4891)

stated their support for creation of a subcategory for units burning Gulf Coast lignite separate

from units burning Fort Union lignite. One commenter (OAR-2002-0056-3543) supported a

separate subcategory for Gulf Coast lignite because the current rule structure could force

generators to switch coal ranks, primarily from lignite and subbituminous to bituminous coal. 

According to the commenter, Gulf Coast lignite is substantially different from other lignite coals

and, because it is an important fuel source, should remain viable. The commenter stated that

under a cap and trade approach, the subcategorization should be used to determine allocations for

State Hg budgets. According to some commenters (OAR-2002-0056-2054, -2422, -3510,

-4191), the higher Hg content of Gulf Coast lignite and higher Hg emissions from units burning

Gulf Coast lignite versus Fort Union lignite for similarly controlled boilers justifies separate

subcategories and higher emission limits for units burning Gulf Coast lignite. Several commenters

(OAR-2002-0056-2915, -3463, -3478, -4191) stated that inaccurate analytical methods (method

ASTM D 3684 for coals with high ash and moisture content) used during EPA’s Hg ICR coal

sampling gave erroneously low Hg content readings for Gulf Coast lignite in comparison to more

accurate analytical methods. Using a new analyzer and ASTM D 6414 method, the commenter

stated that Hg in fuel averaged a six-fold increase over the other method. A commenter (3478)

stated that they believe that all high ash coals may have a higher Hg content in the coal than the

ICR data reveals and if this is the case, and the stack emissions are also higher, then EPA has

proposed a much more stringent standard than a 70 percent reduction. The commenter further

discusses the problems with the test methods used to analyze for Hg and Cl in these samples and

stated that the allowance allocations must be based on a baseline adjustment factor of at least 3

for lignite plants to meet the targets.

Several commenters (OAR-2002-0056-2915, -3463, -4191) stated that if EPA does not

establish a separate subcategory for Gulf Coast lignite with a higher emission standard, they

should offer an alternative percent reduction option.

Response:

EPA continues to believe that there is insufficient evidence available to justify separate

subcategories for Gulf Coast and Fort Union lignites. The reanalysis of the data in support of
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the revised new-source NSPS Hg emission limits, discussed later in this document, incorporated

data from units firing both types of lignite, further lessening the necessity of additional

subcategorization. EPA will continue to evaluate the Hg emission data that becomes available,

including that generated through the studies on emerging Hg control technologies by the U.S.

Department of Energy (DOE), and reassess the issue of further subcategorizing lignites during

the normal NSPS review cycle.

Comment:

Although one commenter (OAR-2002-0056-3406) supported the separate treatment of

lignite through the subcategorization process, the commenter adds that a great deal of research

and development is focused on controlling Hg emissions from lignite coal, and strict control

standards will certainly further fuel these development efforts.

Response:

EPA concurs with this comment and believes that the regulatory approach being taken

will further serve to advance the development of improved Hg control technologies.

2.2.5 Integrated Gasification Combined Cycle (IGCC)

Comment:

One commenter (OAR-2002-0056-2948) opposed including IGCC units in this rulemaking

because those units differ fundamentally from electric steam generating units.

Response:

EPA agrees that IGCC units differ fundamentally from other types of coal-fired electric

utility steam generating units in their mode of combustion and operation. However, they remain

“fossil-fired electric utility steam generating units” under the subpart Da definitions of “fossil

fuel” and “electric utility steam generating unit” (see 40 CFR 60.41a) currently included in

subpart Da and, therefore, are included within this rule.

2.2.6 Coal Refuse

Comment:

According to one commenter (OAR-2002-0056-2160), waste coals are insignificant in the

overall fuel mix; there is no value in regulating them separately, which creates unnecessary

complexity.

One commenter (OAR-2002-0056-2162) stated that waste coal-fired plants should not be

subject to the proposed Hg rules.
2-25

Response:

Although insignificant in the overall mix of fuels used in Utility Units, coal refuse-fired

units are typically utilized in fluidized bed combustors (FBC), a type of boiler not in general use

for other coal ranks. For this reason, coupled with the fact that their emission characteristics

are dissimilar from other coal ranks, EPA is considering coal refuse as a separate subcategory

for purposes of this rule.

Comment:

According to one commenter (OAR-2002-0056-2920), EPA must regulate plants burning

waste coal refuse, including culm, gob, and subbituminous coal refuse, as incineration units under

CAA section 129. According to the commenter, it is not relevant whether a unit recovers energy

from the combustion of waste (coal refuse-burning plants do not fall into the exception for

specific energy recovery units under section 129(g)(1)). The commenter stated that EPA’s failure

to regulate coal refuse-burning power plants as incinerators under section 129 contravenes the

CAA.

Response:

Coal refuse is a recognized subcategory under subpart Da (see 40 CFR 60.41b); this

revision of the rule merely continues to consider “coal refuse” as a subcategory of “fossil fuelfired electric utility steam generating units.”

Comment:

One commenter (OAR-2002-0056-2842) noted that EPA proposed to include all waste

coal units in a single subcategory, regardless of the rank of waste coal burned and stated that EPA

must establish separate waste coal subcategories based on coal rank or otherwise adjust the waste

coal emission limits to reflect the control and other issues that would be expected to be associated

with subbituminous or lignite waste coals. The commenter also stated that EPA must modify the

limits to account for the possibility that the units used to develop the limits might burn any rank of

waste coal from any source, which, depending upon the Hg content and control issues of the Hg

in the coal, would require adjustments to the limits. According to the commenter, waste coal

units have the same issues EPA identified for conventional units regarding coal rank. The

commenter also stated that EPA has based the limits on data from only two units, both of which

fired waste bituminous coals, and ignored the fact that waste subbituminous and lignite coals can

be expected to have the same issues concerning emissions controllability as the coal ranks from

which the waste coal is derived. The commenter also stated that EPA must take the same

considerations into account to the extent that it considers a rule under CAA section 111.

Response:

As the commenter noted, EPA used the only coal refuse data available in establishing the

proposed NSPS emission limits. No additional coal refuse emission data were provided during
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the public comment period; therefore, EPA has no additional data upon which to base any

further subcategorization of the “coal refuse” subcategory. As discussed later in this document,

EPA is, however, reassessing the approach taken to develop the new source NSPS limits.

Comment:

One commenter (OAR-2002-0056-3525) stated that waste-fuel combustion is a variable

process, because the waste varies from mine site to mine site. According to the commenter,

existing CFB plants are among the newest of the boiler fleet in this country, most having been

built to meet best available control technology (BACT) requirements within the last 15 years. 

According to the commenter, all of the units with which he is aware have current Hg removal

rates of 96 to 99 percent. The commenter stated that using more restrictive input limits on these

units appears to be punishing facilities that made early investment in technology. The commenter

stated that the variability of Hg content in the fuel is greater than that of regular coal and that

carbon injection and other Hg removal methods currently under study are not directly adaptable

to CFB design operations. The commenter stated that if variability of fuel quality justifies the

proposed limit for bituminous coal, then at least a similar limit seems reasonable for a unit

combusting waste products from bituminous coal mining processes. The commenter asserted that

assignment of less than 20 percent of that value to units that currently meet BACT is overly

restrictive and discriminatory, as well as arbitrary and capricious. The commenter submits that

similarly, emission limits for firing of other rank coal wastes should be at least the level of limits

applied to those other respective coal ranks.

Response:

EPA disagrees that the limits proposed for coal refuse-fired units is arbitrary and

capricious given that the limits are based on data from such units and were not extrapolated

from non-coal refuse-fired units. As discussed later in this document, EPA is, however,

reassessing the approach taken to develop the new source NSPS limits.

Comment:

According to one commenter (OAR-2002-0056-2162), EPA may only regulate waste

coal-fired sources as part of the broader category of electric utility steam generating units, rather

than as a distinct subcategory subject to a unique emission limitation. The commenter pointed out

that EPA has developed a unique, and unduly stringent, Hg emission control level applicable only

to waste coal-fired units without making a finding that emissions from waste coal-fired sources

would pose a hazard to public health, or that the regulation of such units is “appropriate and

necessary.” According to the commenter, EPA’s finding that it is “appropriate and necessary” to

regulate Hg emissions for electric utility steam generating units applied generally to all coal-fired

sources in that source category and that it is inconsistent, therefore, for EPA to distinguish waste

coal-fired sources under the proposed rule as a separate and distinct source category subject to

unduly stringent emission limitations. The commenter stated that any determination to regulate

Hg emissions from waste coal plants–as sources that are “reasonably anticipated to cause adverse

health effects”–only can be justified under EPA’s statutory mandate, if at all, if waste coal sources
2-27

are members of the broader source category of electric utility steam generating units. 

Accordingly, in order for the Agency to appropriately regulate waste coal plants, it must not

distinguish between waste coal plants and other coal-fired electric utility steam generating units in

establishing proposed emission limits. For these reasons, if the Agency regulates waste coal fired

sources under the Proposed Mercury Rules, the commenter argued that the Hg emission levels

applied to waste coal-fired sources must be consistent with those applied to conventional

coal-fired sources, such as sources firing bituminous coal.

Response:

As noted earlier, EPA believes that it has the statutory authority to subcategorize “fossil

fuel-fired electric utility steam generating units” for purposes of regulation under CAA

section 111. Further, based on the subcategorization, EPA proposed a unique Hg emissions

limit for each of the subcategories and does not believe that any are “unduly stringent” as the

commenter asserts, given that each was based on the data available. As discussed later in this

document, EPA is, however, reassessing the approach taken to develop the new source NSPS

limits.

2.2.7 Fluidized Bed Combustors

Comment:

Several commenters (OAR-2002-0056-2375, -2911, -2918, -2948, -3537) supported a

subcategory for FBC units. Three commenters (OAR-2002-0056-2375, -2918, -3537) stated that

EPA should create a subcategory for FBC units to subsume the proposed subcategory for units

that combust waste coal because FBC units use a fundamentally distinct process for fuel

combustion that implicates differences in design, construction, and equipment. According to the

commenters, such differences are sufficient to establish that FBC units constitute a different

“class” or “type” of utility steam generating unit. Both commenters stated that subcategorization

is further warranted because the FBC unit process and design differences have significant

implications for Hg removal efficiency. One commenter (OAR-2002-0056-2918) provided a list

of the main differences between FBC units and conventional boilers and stated that these

differences are important for the higher Hg removal efficiencies of FBC units and such differences

should make FBC units a distinct subcategory. The commenter offered examples of when EPA

has created subcategories among sources due to the performance of control technology (i.e., steel

pickling and phosphoric acid manufacturing MACT).

Two commenters (OAR-2002-0056-3445, -3556) supported EPA’s proposed

subcategories based on coal rank but feel additional subcategorization, specifically a separate

category for FBC units, is appropriate because FBC units use a fundamentally different

combustion process than pulverized-coal units, making them a different type of source.

Response:

EPA agrees that FBC units operate and are designed differently than conventional
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pulverized coal (PC) boilers. However, with the exception of FBC units firing coal refuse, there

was no clear indication from the available data that such units impacted on the ultimate Hg

control effected. That is, in some cases, FBC units had higher removal rates than most with

respect to their Hg emissions; in other cases, FBC units had lower removal rates than most. 

Therefore, EPA concluded that it was the coal rank, rather than the process type (e.g., FBC, PC)

that should govern in any determination relating to subcategorization.

2.2.8 Fuel Switching and Impacts on U.S. Coal Supply

Comment:

Many comments were received regarding fuel switching and the impacts of the proposed

rule on fuel switching. Several commenters (OAR-2002-0056-1969, -2067, -2260, -2834, -2897,

-3198) agreed with EPA that fuel switching is not practicable to meet the proposed Hg emission

limits. One commenter (OAR-2002-0056-2260) stated that furthermore, there exists no one fuel

in sufficient quantities and availability that can be used by all utilities. The commenter’s boilers

were designed to burn western subbituminous/bituminous coals and cannot switch to burn eastern

bituminous coals. Eastern coals also have higher levels of sulfur and would overload their

scrubber control units. The commenter’s remote location in southeastern Arizona also makes it

impossible to transport coals from regions other than the west. Additionally, the commenter’s

units are limited in the amount of natural gas that can be burned because of severe constraints on

the natural gas supply in the region.

One commenter (OAR-2002-0056-1969) stated that EPA has appropriately concluded

that fuel switching is not a compliance option which is consistent with the CAA and favors the

development of consistent standards that do not create regional inequities or favor one fuel type

over another.

One commenter (OAR-2002-0056-2945) stated that any fuel switching or shift in coal

utilization away from bituminous coal due to the proposed rules would have a drastic adverse

impact on mining employment and on electric power generation.

One commenter (OAR-2002-0056-2891) stated that cooperatives believe that fuel

switching is not a reasonable or practical alternative for many units to meet the new emission

limits and that in many cases, plants may have no option but to shut down.

Response:

Modeling done in support of EPA’s proposed rules does not indicate that a significant

amount of fuel switching will be undertaken by the utility sector to comply with the proposed

rules. Some companies may chose to change fuels to effect compliance with either the CAIR or

CAMR, or both. Further, EPA believes that some sources have extremely limited options (in

some cases, no options) with regard to other coals or fuels that could be fired at a given Utility

Unit. Therefore, EPA proposed emission limits that would be achievable for such units that

would not require fuel switching.
2-29

Comment:

Some commenters were concerned over the impacts of the rule on bituminous coal. One

commenter (OAR-2002-0056-3445) stated that in addition to coal-fired power plants which burn

bituminous coal, they also own and operate bituminous coal mining and terminal operations. The

commenter stated that any Hg regulation must treat all coals fairly. The commenter added that

providing an advantage to coal from one region over coal from other regions encourages fuel

switching as a compliance strategy and could limit the diversity of fuels available for electrical

generation. The commenter stated that it is critical to the nation’s security that all forms of coal

continue to be available for electrical generation.

One commenter (OAR-2002-0056-2845) stated that any rule must not favor one rank of

coal over another and that, although fuel switching appears to be an acceptable control option, it

will severely reduce employment in the bituminous coal sector.

One commenter (OAR-2002-0056-2692) stated that the proposed rules threaten the future

of the Appalachian coal industry. The commenter stated that industry and elected representatives

from western States have for some time pushed EPA for a rule that would advantage western

coal. According to the commenter, EPA responded to these concerns by publishing rules on

January 30, 2004, that provide a major disadvantage to eastern coal. The commenter stated that

specifically, the rules as proposed require sharp cuts in Hg emissions from eastern bituminous

coals, but require far smaller cuts from the subbituminous and lignite coals of the west. 

According to the commenter, this difference in treatment is so great that it will certainly produce

an illogical result: utilities will be encouraged to burn more western coal, despite the fact that it

has higher levels of Hg. The commenter stated that the result will be more pollution and less

eastern coal jobs.

One commenter (OAR-2002-0056-3469) stated that the Hg rule and the CAIR will further

concentrate U.S. coal supply among Wyoming Southern PRB subbituminous coal producers and

delay emission control technology retrofits and further erode production from the Illinois Basin as

well as niche coal and lignite production regions, including certain Indian reservations.

One commenter (OAR-2002-0056-2661) stated that EPA’s generalities of Hg emissions in

coal, as a one size fits all, implies a greater burden for subbituminous coal users. The commenter

noted that substantial reductions in SO2 and NOx were achieved by the conversion to low sulfur

coal - subbituminous coals. The commenter stated that units that have borne the economic

burden for fuel switching should not bear a disproportionate burden of Hg emission reduction

strategy now. Further, the commenter did not believe it is in the best interest of the U.S. energy

policy to favor limited coal choices based on any emission threshold currently established by EPA. 

According to the commenter, EPA’s policy would continue to hamper U.S. energy needs and

reliance on foreign and other inappropriate sources of fuel for U.S. consumer energy needs.

One commenter (OAR-2002-0056-3531) expressed concern with the discriminating

impact the proposed rule will have on Ohio and other eastern bituminous coals. The commenter

stated the current rule proposals may allow sources burning western coal to continue to do so
2-30

without installing any control technologies. The commenter stated that essentially, the cost of all

Hg reductions under the current proposal would be borne entirely by sources burning eastern

coals, such as in Ohio. According to the commenter, there is no valid technical or economic

justification for such discrimination. The commenter stated that Hg reductions must be based on

an examination of the best-controlled sources in each fuel subcategory and a valid determination

of the level of control that can be achieved within each subcategory. The commenter concluded

that EPA must revise the rules to not favor regional fuel usage and, instead, require reductions

for all sources based on available technical data. One commenter (OAR-2002-0056-2870)

encouraged EPA to adopt approaches to control Hg emissions from power plants that will ensure

a level playing field among all coal ranks and will promote an equitable strategy to address

interstate pollutant transport. The commenter claimed the rule creates an uneven playing field

that would harm the bituminous coal industry and its coal miners. One commenter

(OAR-2002-0056-2937) recognized that although difficult regulatory decisions must be made, the

commenter felt that good science, coupled with a sense of fairness can produce a rule that yields

Hg reduction in a way that does not compromise the viability of bituminous coal producing

regions.

Response:

EPA’s modeling has shown little significant coal switching as a result of the proposed

CAMR and CAIR actions. We believe that this rebuts the commenter’s suggestions that one or

another coal rank is “advantaged” or “disadvantaged” with respect to other coal ranks. EPA’s

responses to comments on the allocation adjustment factors are found elsewhere in this

document.

Comment:

Many commenters (OAR-2002-0056-1625, -1673, -1768, -1802, -2020, -2066, -3478,

-3513, -3517, -3530) expressed concern over the impacts of the proposed rule on the nation’s

energy supply. Several commenters (OAR-2002-0056-1673, -1768, -3478) believed that the Hg

levels set by this rulemaking should not result in the loss of viability of any fuel type, such as

lignite, considering the severe impact this would have on local communities, jobs and the nation’s

energy security from the loss of this significant domestic fuel supply for electric generation.

One commenter (OAR-2002-0056-3513) stated that the nation’s largest energy supply

will be unduly impacted if EPA fails to adequately consider the vital role that coal-based

electricity plays in America’s current and future economic prosperity; the demand for electricity is

growing and other fuels–such as natural gas–cannot meet this growing demand.

One commenter (OAR-2002-0056-3517) stated that coal represents our single largest

domestic reserve of fossil fuel, representing 95 percent of the reserves (as compared to crude oil

at 2 percent and natural gas at 3 percent). The commenter asserted that coal is electricity,

accounting for 87 percent of the use of coal in the nation, and is responsible for 50 percent of

total electricity generated in the U.S. The commenter believed it is incumbent upon EPA to

promulgate responsible and achievable standards so as to not impact the reliability and cost of
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electric service.

Several commenters (OAR-2002-0056-1768, -3530) stated that the final rule must be

consistent with the need for reliable and affordable electric power, including affordable use of all

coal ranks and options for efficient on-site power generation such as CHP. The commenter stated

that the final rule must facilitate–not discourage–the availability of an adequate and diverse fuel

supply for the future, including coal, natural gas, nuclear energy, hydroelectric, and renewable

sources. According to several commenters (OAR-2002-0056-1768, -2066), the final rule must

not aggravate the already precarious natural gas supply which is currently inadequate. One

commenter (OAR-2002-0056-2066) stated that these actions will inhibit, if not totally eliminate,

plans for any new coal-fired base load electric generation, and this forgone option will

undoubtedly be replaced by additional natural gas-fired generation.

Should EPA proceed with the rulemaking, one commenter (OAR-2002-0056-2847) urged

the agency to adopt sufficient subcategories of expected reductions so as to limit the potential for

economic disruption in the coal, transportation, and utility industry sectors.

Although supporting full use of categories and subcategories to adequately address

differences in abilities to reduce Hg based on such things as coal chemistry that varies with coal

rank, one commenter (OAR-2002-0056-3200) stated that it is imperative that no fuel type be

afforded an unfair market advantage and that overly aggressive mandatory reductions in Hg

emissions be avoided that would lead to loss of fuel diversity, higher energy prices and a strain on

electric reliability, all of which are inconsistent with sound energy policies.

Several commenters (OAR-2002-0056-1675, -2160, -2660, -2875, -2904, -2908, -2937,

-3324, -3366, -3560) stated that limits that favor one coal over another may have considerable

economic impacts due to the higher control costs affecting coal producers, utilities, and

customers. According to two commenters (OAR-2002-0056-2875, -2937), a significant loss of

employment would occur in the Appalachian areas of their State and would be devastating to an

area already suffering from excessively high unemployment rates.

Several commenters (OAR-2002-0056-1675, -1677, -1762, -2944) stated that

subbituminous coal, which is primarily produced in the West, will receive favorable treatment at

the expense of eastern bituminous coal that will make bituminous coal virtually non-competitive

with western subbituminous coal. One commenter (OAR-2002-0056-2944) stated that

subcategorization will result in regional disparities and inconsistences in the industry which EPA

stated that it intended to avoid.

One commenter (OAR-2002-0056-1852) opposed EPA’s proposal to subcategorize

stating that the widely varying proposed emission rates for coal subcategories could cause

disruption to coal supplies and fuel blends in order for utilities to comply with the Hg standard.

Response:

As noted above, EPA’s modeling has shown little significant coal switching as a result of
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the proposed CAMR and CAIR actions. We believe that this rebuts the commenter’s suggestions

that one or another coal rank is “advantaged” or “disadvantaged” with respect to other coal

ranks. Further, we do not believe that the final rules will have a negative impact on the nation’s

energy security, employment rates, or energy reliability. Responses to comments on the

allocation adjustment factors are found elsewhere in this document.

Comment:

One commenter (OAR-2002-0056-3198) stated that these regulations will have a

tremendous impact on the mining industry in Wyoming and on the state as a whole and it is

critical that EPA adequately address the unique chemistry of Wyoming coal.

Response:

EPA believes that it has adequately addressed the commenter’s concerns in the rule

through the finalizing of two emission limits for subbituminous coals, depending on the type of

FGD unit used and the allocation factors used in the trading program.

Comment:

According to one commenter (OAR-2002-0056-3254), Illinois Hg emissions have risen

about 28 percent while burning western coal. The commenter stated that Illinois coal Hg content

is 1/3 that of western coal and that EPA should not allow western coal to be burned.

Response:

EPA does not feel that it is in the best interest of the country to prohibit the use of some

ranks of coal when those coals can be adequately controlled to limit Hg emissions.

Comment:

One commenter (OAR-2002-0056-3525) encouraged EPA to reduce Hg emissions

without undermining fuel diversity. The commenter believed that flexibility will more likely be

achieved through EPA’s market-based, cap-and-trade, approach to controlling Hg emissions than

through the MACT approach. The commenter stated that the tight time frame for reductions in

the Hg MACT approach could leave utilities with no real choice but to install a significant

quantity of additional gas fired generation facilities and thereby switch fuels as a primary means of

compliance. The commenter stated that market-based mechanisms, like the successful

cap-and-trade program under the acid rain program, will dramatically increase the

cost-effectiveness of any program. The commenter supported an approach of imposing Hg

emissions reductions to a level commensurate with co-benefits achieved through the SO2 and NOx

emissions reductions of the proposed CAIR. The commenter stated this will help mitigate the

costs of compliance, which will be borne by all electricity consumers. According to the

commenter, when establishing emission limits, the inherent fuel quality differences and the varying

capability of emission control devices to capture Hg between coal ranks needs to be considered
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and properly accommodated. The commenter urged EPA to establish a rule that does not

preferentially disadvantage a particular fuel or fuel type so that fuel diversity of the electrical

generation sector is not artificially restricted.

Response:

EPA concurs with the commenter’s belief that a cap-and-trade approach will better serve

to protect the environment while at the same time allowing the industry to maintain fuel

diversity.

2.2.9 Other Subcategorization Approaches

Comment:

One commenter (OAR-2002-0056-2422) suggested the following subcategorization

approach: hot stack, wet stack, and saturated stack configurations. According to the commenter,

this approach recognizes that many hot-stack eastern units fired with bituminous coals are not

cost-effective candidates for capital-intensive control technology retrofits. The commenter

believed that EPA should provide emission-based exemptions for relatively small Hg-emitting

units to mitigate the substantial risks of plant closures among older and smaller units.

One commenter (OAR-2002-0056-2634) stated in addition to subcategorization by coal

rank, further subcategorization could be warranted, based on pollution control process

configuration and coal chemistry, due to its impact on Hg speciation and its ability to be

controlled by present technology.

Response:

EPA believes that cost-effective emission reduction approaches are available for

“hot-stack” units, particularly when the CAMR is taken in concert with the CAIR. EPA

analyzed the commenter’s suggested subcategorization approach but believes subcategorization

based on coal rank is more easily implemented and more adequately addresses the coal

chemistry issue.

Comment:

One commenter (OAR-2002-0056-2267) believed that EPA should create a subcategory

for small municipal generators under the MACT approach.

Response:

EPA sees no justification for creating such a subcategory. Such units are constructed

and operated in a manner similar to other “electric utility steam generating units” and, as such,

are sources of Hg emissions. Coal-fired municipal units otherwise meeting the definition would

be subject to the final rule.
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2.2.10 New Units

Comment:

Several commenters (OAR-2002-0056-1969, -2067, -2634, -2721, -2843, -3403, -3514,

-3537) supported the proposal to use the same coal subcategories for new plants as for existing

plants. However, one commenter (OAR-2002-0056-2067) stated that the EPA ICR reference

data should be supplemented with more recent and representative power plants and coal sources. 

The commenter stated that Hg removal data used to set the standards for the best performing

utility units must be accurate and represent the variations of coal within each coal rank. The

commenter stated that standards for new power plants should be adopted to encourage the

construction of cleaner coal plants and maintain a diverse mix of fuel.

One commenter (OAR-2002-0056-1969) stated that the historical fuel mix is indicative of

regional and economic conditions and fuel needs and according to the commenter, selection of

other subcategorization methodologies for new units could affect their future market conditions

and an ongoing need for a diversified electrical generation fuel mix.

One commenter (OAR-2002-0056-2721) believed that without subcategorization, the

location of new units will be biased geographically near the fuel types that provide for the ease of

compliance. According to the commenter, this unfair siting advantage will place strenuous

hardships on the electrical supply chain of the country and place economic hardship in areas of the

western U.S. where typically the low Cl content of coal resides.

One commenter (OAR-2002-0056-3435) recommended a single subcategory for new units

burning bituminous and subbituminous coal. The commenter stated that the difference in the

limits for new bituminous and subbituminous coal would allow a 233 percent increase in

emissions.

Response:

EPA continues to believe that new sources should be subcategorized in the same manner

as existing units.

Comment:

One commenter (OAR-2002-0056-3459) stated that, although EPA has only spurious

rationale for subcategorization of existing units, there is no rationale for new units. The

commenter stated that these can be designed to provide optimum performance when firing all coal

ranks and that EPA must reject subcategorization and establish a single limit for new units. 

According to the commenter, the effect of EPA’s proposal is to make the standards less stringent

by subcategorizing according to the rank of coal. The commenter stated that the words of a

statute must be read in their context and with a view to their place in the overall statutory scheme

and that Congressional intent was to use subcategorization sparingly; the same reasons the NOx

NSPS was fuel neutral (improvements in control technologies were available on all utility boilers)
2-35

applies here.

Response:

EPA believes that the proposed requirement for new units to comply with an output-based

emission limit will ensure that they are designed to achieve optimum performance. However,

units designed to burn bituminous coals will still not be able to burn lignite coals (for example)

and, thus, the need for subcategorization remains. As noted earlier, EPA concurs that

advancements in Hg control technologies may lead to more “fuel neutral” formats; however,

that time has not come.

Comment:

One commenter (OAR-2002-0056-3537) contends that IGCC units use fundamentally

different processes than conventional boilers and should be placed in their own new unit

subcategory.

Response:

EPA concurs that new IGCC units should continue to be subcategorized separately from

other coal-fired units.

Comment:

One commenter (OAR-2002-0056-2862) stated that in establishing a new source NSPS

for Hg, EPA should also subcategorize coal-fired power plants based on the process type. The

commenter believed that it is vital that EPA further consider the performance of representative

boiler types and variations in Hg content.

Response:

EPA does not believe that there is any additional justification for subcategorizing new

units by process type than there is for existing units.

2.2.11 Coal Blends

Comment:

Two commenters (OAR-2002-0056-2535, -3435) favored a subcategory for units burning

a blend of subbituminous and bituminous coals. One commenter (OAR-2002-0056-2535)

believed that blends of subbituminous and bituminous coals should not be categorized under

subbituminous coal. The commenter stated that EPA incorrectly set the limit for subbituminous

coal by mis-classifying blended fuel units as subbituminous units, resulting in a erroneously higher

number of plants classified as subbituminous plants. The commenter cited certain plants named by

EPA as being subbituminous plants (e.g., Craig, La Cygne, Lawrence, Newton, and Presque Isle)
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as potentially burning blends of subbituminous and bituminous coal. For each of the plants

identified as burning subbituminous coal, the Energy Information Administration (EIA) database

was reviewed by the commenter to determine which mine the coal was shipped from in 1999. 

According to the commenter, EPA’s Table 2 summary of the coal supply data as reported to the

EIA for these plants, shows these plants categorized as subbituminous plants, but may instead be

plants that burn a blend of bituminous and subbituminous coals. The commenter further stated

that neither the EIA data nor the ICR data differentiates as to what coals were delivered to which

unit within a facility, so the shipments listed above are for the plant as a whole for 1999. The

commenter was unable to find any clear documentation as to what rank of coal was being burned

during the EPA ICR tests. The commenter stated that unless EPA is able to accurately determine

what coals were burned during the test, the assumption must be made that it was a subbituminous/

bituminous blend and the plant must be placed in the “blend” category. The commenter further

stated as unsound the suggestion that any plant that burned over 90 percent subbituminous coal

should still be classified as a subbituminous unit and that the remaining blend be considered a

deminimus amount. The commenter stated that there needs to be a better evaluation of blended

coals, and how these different ranks of coals interact relative to the species of Hg that is emitted.

Response:

As noted above, EPA does not believe that a subcategory based on blended use of

bituminous and subbituminous coals is warranted. EPA relied on the facilities to provide

accurate information regarding the rank of fuel burned and, in some cases, errors were

corrected. It is true that some units noted by the commenter received shipments of multiple

ranks of coal during the reporting period, they reported burning only one rank of coal during

their emission test program and, therefore, have been classified as being in that subcategory. 

However, as noted later in this document, EPA has reevaluated the basis for the new source

NSPS limits for the final rule.

Comment:

Commenter OAR-2002-0056-3459 states that EPA’s proposed case-by-case alternative

for units burning a blend of coals is unlawful. EPA must establish emission standards for each

subcategory of sources that emit HAP and those standards are to be based on the best performing

units within the subcategory. However, EPA does not propose a uniform standard for units

burning a blend of coals and does not base the standard, such as it is, on the best performing units. 

Even though EPA effectively creates a subcategory for units burning a blend of coals, it makes no

effort to establish standards for that subcategory.

Response:

The approach being taken for blended coals is consistent with the procedures already inplace in 40 CFR 60, subpart Da.

2.2.12 Other
2-37

Comment:

One commenter (OAR-2002-0056-2897) agreed with EPA’s decision to subcategorize by

coal rank and to differentiate between bituminous and subbituminous coals. The commenter also

stated that the ICR data used to support the claim that PRB coal is compliant must be questioned. 

The commenter agreed with EPA’s determination that the overlap in coal classification properties

does not compromise its ability to subcategorize by coal rank and overlap only occurs in a very

limited number of cases and it remains true that coal rank is a significant factor that distinguishes

the design and operational characteristics of different boilers.

Response:

EPA has reanalyzed the data used to support the Hg emission limit for subbituminous

coals. Discussion of this reanalysis is contained elsewhere in this document.

Comment:

Not all commenters (OAR-2002-0056-2661, -2692, -2870, -2937, -2944, -3208, -3469,

-3531, -4139) agreed with EPA’s use of subcategories. One commenter (OAR-2002-0056-2944)

stated that the combustion processes involved in IGCC systems, FBC, and PC boilers are

themselves fundamentally different in their mechanical operation and the resulting processes offer

distinctly different possibilities for limiting Hg emissions. The commenter added that in actual

practice each of these combustion types produces significantly different relative Hg emissions. 

According to the commenter, because the differences between these classes of coal combustors is

a matter of kind, rather than one of degree, it is logical to determine separate emission limits for

them. The commenter believed that because the combustion process, opportunities for limiting

emissions, and typical emission results of cyclone boilers and stoker boilers are very similar to

those of PC boilers, it makes regulatory sense to combine them into the class of pulverized

boilers.

Response:

As noted above, EPA concurs that IGCC units should be subcategorized separately but

disagrees with the commenters with regard to FBC units.

Comment:

One commenter (OAR-2002-0056-4139) suggested that the logic used in establishing the

subcategories needs to be reassessed.

Response:

EPA has reviewed its analysis leading to the proposed subcategories and continues to

believe that the subcategories proposed continue to be appropriate.
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Comment:

In addition to demonstrating the efficacy of ACI, one commenter (OAR-2002-0056-3208)

and other participants in research funded in part by the U.S. Department of Energy’s National

Energy Technology Laboratory stated that they are exploring the potential use of oxidizing

agents, enhanced sorbents, and coal blending as potential pathways to achieving significant

reductions in Hg emissions from use of PRB coals. On this basis, the commenter urges EPA to

adopt a separate subcategory for PRB coals within a subbituminous coal category.

One commenter (OAR-2002-0056-4139) agreed that the importance of coal ranks may

diminish and that EPA should review its limits by coal rank periodically and make them more

stringent if appropriate due to improving Hg control technology.

Response:

EPA stands by its decision with regard to subcategorization. Further, EPA believes that

the research noted by commenter -3208 supports more limited, rather than broader,

subcategorization scenarios (i.e., fewer, perhaps none, rather than more subcategories) when the

rule is reviewed in the future as suggested by commenter -4139.

Comment:

According to some commenters (OAR-2002-0056-2364, -2430), EPA’s straw proposals

of August 2001 and December 2001 contained subcategorization possibilities calling for

90 percent control, have defensible MACT floors, are cost effective, have timely implementation,

and are preferable to EPA’s proposals.

Response:

The “straw proposals” noted by the commenters were extremely preliminary in nature

and were never the basis for any proposal options. The data upon which the straw proposals

were based were subsequently determined to be in error with regard to levels of Hg control

achieved by existing controls. Further analysis of the available data also indicated that the

subcategories used at proposal were appropriate.

2.3 GENERAL COMMENTS

Comment:

One commenter (OAR-2002-0056-2485), also noted that many sources of natural gas

contain high levels of Hg and should be included in this subpart.

Response:

EPA received no data or information during the public comment period to indicate that
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its determination that regulation of natural gas-fired Utility Units was neither necessary nor

appropriate was in error. Therefore, EPA stands by that decision.
RESPONSE TO SIGNIFICANT PUBLIC COMMENTS ON

THE PROPOSED CLEAN AIR MERCURY RULE

Received in response to:

Proposed National Emission Standards for Hazardous Air Pollutants; and, in

the Alternative, Proposed Standards of Performance for New and Existing

Stationary Sources: Electric Utility Steam Generating Units

(69 FR 4652; January 30, 2004)

Supplemental Notice for the Proposed National Emission Standards for

Hazardous Air Pollutants; and, in the Alternative, Proposed Standards of

Performance for New and Existing Stationary Sources: Electric Utility Steam

Generating Units

(69 FR 12398; March 16, 2004)

Proposed National Emission Standards for Hazardous Air Pollutants; and, in

the Alternative, Proposed Standards of Performance for New and Existing

Stationary Sources, Electric Utility Steam Generating Units: Notice of Data

Availability

(69 FR 69864; December 1, 2004)

Docket Number OAR-2002-0056

3.0 PERFORMANCE STANDARDS FOR COAL-FIRED

ELECTRIC UTILITY STEAM GENERATING UNITS

US Environmental Protection Agency 

Emissions Standards Division

Office of Air Quality Planning and Standards

Research Triangle Park, North Carolina 27711

15 March 2005
i

General Outline

1.0 INTRODUCTION AND BACKGROUND

2.0 APPLICABILITY AND SUBCATEGORIZATION

3.0 PERFORMANCE STANDARDS FOR COAL-FIRED ELECTRIC

UTILITY STEAM GENERATING UNITS

4.0 PERFORMANCE STANDARDS FOR OIL-FIRED ELECTRIC

UTILITY STEAM GENERATING UNITS

5.0 MERCURY CAP-AND-TRADE PROGRAM

6.0 MERCURY EMISSIONS MONITORING

7.0 IMPACT ESTIMATES

8.0 COMPLIANCE WITH EXECUTIVE ORDERS AND STATUTES

9.0 NODA

10.0 OTHER

Appendix A LIST OF COMMENTERS
3.0 PERFORMANCE STANDARDS FOR COAL-FIRED

ELECTRIC UTILITY STEAM GENERATING UNITS

3.1 MERCURY CONTROL TECHNOLOGIES

Comment:

According to one commenter (OAR-2002-0056-2946), although there may be no single

technology to meet the needs of all plants, a wide set of solutions are available for each

subcategory. The commenter listed 10 control measures ranging from coal washing to switching

to renewable resources.

Response: 

EPA concurs that there are a number of technologies that may be used by utility units to

reduce Hg emissions.

3.1.1 Availability of Mercury-Specific Control Technologies

3.1.1.1 Current Commercial Availability

Comment:

Several commenters (OAR-2002-0056-1826, -2020, -2160, -2578, -2929, -2948, -3445,

-3463, -3478, -3537) stated that there are no commercially available control technologies

specifically designed for Hg emission control from coal-fired power plants. Commenters

acknowledged that existing control technologies used to control PM, SO2, or NOx emissions

reduce Hg emissions under selected conditions and significant research is being conducting by the

public and private sectors on new Hg control technologies. Although significant research is

underway by the private and public sectors, before commercial availability is achieved, additional

development is need to provide for new technologies that account for variability in coal content,

combustion processes, and control system performance under different kinds of firing conditions.

One commenter (OAR-2002-0056-1814) stated that Hg is a naturally-occurring chemical

that is emitted in trace amounts when coal is combusted. The low concentrations of Hg in coal

make capture of Hg from power plants very difficult and subject to a great deal of variability. 

Technologies are not currently available that are specifically designed for control of Hg at the low

concentrations emitted by power plants

One commenter (OAR-2002-0056-2861) stated that technology is not ready to support a

regulatory program. The low concentration of Hg that occurs naturally in coal makes the capture

of Hg from the flue gas of coal-fired power plants very difficult and subject to a great deal of

uncertainty and variability. According to the commenter, there currently are no commercially

available technologies that are specifically designed to control the very low concentrations of Hg
3-2

emitted by coal-fired power plants. The commenter stated that although some of the technologies

being investigated have shown some promise, there are still many unanswered questions regarding

the level of reduction that can reliably be achieved, the variables that will affect performance, and

the impacts on overall plant operation and maintenance.

One commenter (OAR-2002-0056-2899) stated that for a technology to be deemed

commercially available, it must be able to control Hg emissions from power plants burning

different coal ranks and having different boiler types and configurations; a few isolated tests or

demonstrations are not sufficient to conclude that a technology is commercially available. A

technology needs to be installed in full-scale applications at a number of sites and operated over

extended periods of time before it can be viewed as commercially available, and a technology is

not commercially available just because a vendor is willing to sell it. The commenter points out

that commercial availability requires that most of the key engineering questions about the

technology need to have been previously resolved. The commenter added that a technology is not

commercially available if one installs it knowing that many problems will need to be resolved as

part of the installation and operation.

Response:

EPA concurs with the commenters and believes that Hg-specific control technologies are

not yet commercially available.

Comment:

One commenter (OAR-2002-0056-3469) stated that lack of control and monitoring

technology impedes speedy compliance. The issues relating to the state of science on Hg are

compounded by a lack of technology to reliably measure or control Hg emissions, particularly

from lignite-fired units, to justify the level of emission reductions proposed by EPA. As stated by

the Department of Energy (DOE), "Today, there is no commercially available technology that can

consistently and cost-effectively capture Hg from coal-based power plants."

Response:

EPA concurs that Hg-specific control technologies are not currently available. However,

we disagree with respect to Hg monitoring technologies and believe that such systems will be

available by the time compliance with the regulation is required.

Comment:

One commenter (OAR-2002-0056-3454) stated that the rapid development of Hg control

technologies over the last several years has produced a number of technologies that are available

for the implementation of a national Hg control regulation for coal- and oil-fired power plants. A

large number of laboratory tests and full-scale demonstrations have been conducted that provide

information on the effectiveness of controls for various coal ranks and control configurations. 

Despite the current lack of a national control requirement for Hg, a number of options are
3-3

commercially available while others are still in the development and testing phases.

One commenter (OAR-2002-0056-3210) stated that the EPA understates the availability

of Hg control technology because it failed to acknowledge the DOE/National Energy Technology

Laboratory Mercury Control Technology Research Program on coal-fired power plants. 

Response:

EPA disagrees with the commenters about the availability of Hg-specific control

technologies at the present time. EPA is fully aware of the DOE research program cited by the

commenter. The limited, but increasing, number of tests have not yet brought the technologies to

the level of demonstration that we feel necessary to be considered "commercially available" and

the basis for a national standard.

Comment:

One commenter (OAR-2002-0056-2247) stated that sorbent injection technologies should

be considered available for Hg. Permits have been issued that will rely on sorbent injection

technologies such as ACI (MidAmerican Energy, Council Bluffs Unit 4, PSD permit issued by

Iowa; and Wisconsin Public Service Corporation, Weston Unit 4, issued by Wisconsin). These

show that Hg removal technologies capable of achieving more than 80 percent control are

available.

Many commenters stated that EPA failed to consider Hg control technologies and

methods that are currently available and cost effective. EPA must consider the costs and 

environmental effects of these technologies, such as ACI and other sorbent injection systems, coal

washing, and selective catalytic reduction (SCR). New units can design these into their control

systems without retrofit problems. EPA should also consider technologies required in consent

decrees, case-by-case MACT and BACT analyses, State regulations, and permit data.

Response:

As noted earlier, EPA does not believe that Hg-specific control technologies, including

ACI, are commercially available for nationwide application to the coal-fired utility industry. 

Installation of such technologies on a limited number of units (e.g., the two cited) is possible and

will serve to advance the technologies such that they are widely for use in compliance with the

phase II cap.

3.1.1.2 Mercury Control Technology Development Time

Comment:

Many commenters (OAR-2002-0056-1471, -1608, -1636, -1667, -1773, -1777, -1791,

-1806, -1817, -1987, -2064, -2233, -2887, -2946, -3454, -3538) disagreed with the EPA’s

conclusion that Hg-specific controls for electric utility power plants will not be commercially
3-4

available on a wide scale until 2010 or later. Other commenters agreed with EPA’s time estimate

on the availability of Hg-specific controls (OAR-2002-0056-1969, -3537, -3565). Arguments

stated by various commenters disagreeing with EPA’s assessment included the following. 

Mercury control technologies are available now. The EPA disregarded studies on emerging Hg

control technologies. The EPA’s own numbers and other studies indicate that coal-fired plants

can achieve 90 percent reduction regardless of the type of plant or coal. Field testing of ACI has

shown 90 percent capture of Hg. Units equipped with scrubbers and fabric filters can obtain near

90 percent. Studies indicate that the cost of these controls would be comparable to those for

other pollutants and EPA disregards these studies and emerging state of the art Hg control

technologies. The EPA did not provide a detailed analysis of the current available technologies.

Outside of the U.S., the Berrenrath 275 MWe and the Wachtberg 166 MWe plants in Germany

operate on carbon injection technology to control Hg. What is contradictory in EPA’s analysis is

that they used ACI in their cost modeling exercises with the integrated planning model (IPM) but

failed to recognize this technology in setting the level of Hg reductions for the emission limits.

Several commenters (OAR-2002-0056-2873, -3449), although agreeing that ACI

technology currently is not commercially available, stated that this technology will be available

before 2010. One commenter (OAR-2002-0056-3449) stated that ACI can be developed and

widely implemented within the next 6 years. A second commenter stated that ACI can be

developed and widely implemented by 2008 to 2009.

Response:

EPA disagrees with the commenter’s assessment regarding the time that it will take for

ACI, or other Hg-specific control technologies, to become commercially available. We do not

believe that these technologies are available now for wide-spread usage. We have been

following the studies of such technologies closely and have discussed their degree of

development with vendors, the industry, and the DOE. No utility unit has operated a Hg-specific

control technology full-scale for longer than a month or so. Further, the technologies have not

been fully evaluated on all coal ranks (e.g., Gulf Coast lignite), even under short-term

conditions. In addition, other aspects of the use of Hg-specific control technologies (e.g.,

balance of plant, waste issues, other atmospheric concerns) have not been fully addressed. 

Studies continue to (1) evaluate the impact on the coal-fired facility as a whole of both ACI and

enhanced ACI (e.g., corrosion); (2) assess the impact on the fly ash of the ACI or enhanced ACI

with regard to its reuse and disposal; and (3) study the other atmospheric emissions that may

result from use of ACI or enhanced ACI (e.g., brominated dioxins emitted either directly or

formed following emission to the atmosphere). Based on these tests, on-going studies, and

discussions, we do not believe that the technologies have consistently demonstrated an ability to

reduce Hg emissions by 90 percent (or any other level) for an extended period of time on all coal

ranks and all boiler types. Use of sorbent injection technologies for Hg removal on European

facilities is informative but does not serve to prove the technologies on U.S. facilities. We

believe that the cap-and-trade approach selected for the final regulation is the best method for

encouraging the continued development of these technologies. Use of sorbent injection in the

IPM model served to estimate the impact of these Hg-specific control technologies in the outyears of the cap-and-trade program and was based on EPA’s projections that such technologies
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would be available after 2010.

Comment:

One commenter (OAR-2002-0056-2929) stated that the reliable, cost-effective control

technologies designed specifically for capturing Hg have not yet been fully developed or tested.

EPRI, DOE, and EPA have conducted extensive research and development (R&D) programs over

the past decade with the objective of developing cost-effective methods for reducing power plant

Hg emissions. Mercury control technology capable of achieving high removal rates (i.e., greater

than 80 percent) across the entire industry is not available. Full-scale demonstrations of Hg

control technologies at individual power plants are just getting underway. It will take at least 2 or

3 years to complete these initial demonstrations and evaluate the potential effectiveness of

possible new control technologies. And then, several more years will be needed before these

technologies can be considered "commercially available."

One commenter (OAR-2002-0056-2160) stated that programs for testing new

technologies such as ACI have been conducted for only short run times as opposed to the long

running times needed to validate a technology for deployment in a power plant.

Response:

EPA concurs with this assessment of the level of demonstration of Hg-specific control

technologies.

3.1.2 Mercury Control Technology Transfer from Other Industrial Sectors

Comment:

One commenter (OAR-2002-0056-3454) stated that the air pollution control industry

already has considerable experience with the implementation of Hg controls for other industrial

sectors. Sorbent injection has been commercially proven to augment the removal of Hg in

waste-to-energy plants. Experience controlling Hg emissions has been gained in more than 60

U.S. and 120 international waste-to-energy plants which burn municipal or industrial waste or

sewage sludge. For the past two decades, sorbent injection upstream of a fabric filter has been

successfully used for removing Hg from flue gases from these facilities. Other reagents used

include activated carbon, lignite coke, sulfur-containing chemicals, or combinations of these

compounds. The Hg control experience gained from the municipal and industrial waste

combustors demonstrates that the air pollution control industry has been able to control Hg in the

past and is able to apply their expertise to the electric power sector.

Response:

EPA disagrees that experience gained through use of Hg-specific control technologies on

municipal waste combustors (MWC) is directly transferrable to coal-fired utility units. As noted

in the proposal preamble, this results from differences in the level of Hg emissions (e.g., Hg
3-6

emissions from a controlled MWC unit are roughly the same level as uncontrolled Hg emissions

from a coal-fired utility unit) and differences in the species of Hg emitted (e.g., because of the Cl

content of the waste stream, Hg emissions from MWC units are primarily in the oxidized form). 

Mercury-specific control experience in the MWC industry was the basis for initiating testing on

coal-fired utility units but not as the basis for direct transfer of results.

Comment:

Several commenters (OAR-2002-0056-2867, -3478) stated that experience with

application of Hg control technologies on waste incinerators cannot be applied to electric utility

power plants because of process differences and differences in the fuel assays. Waste incinerators

operate at much lower temperatures which are not as much of a hindrance to the Hg removal

process as the higher temperatures that are typical of utility power plant systems. The waste

incinerator fuel is also higher in Cl, a constituent that is associated with higher fractions of the

soluble and removable form of Hg.

One commenter (OAR-2002-0056-2850) stated that although electric utilities that burn

coal have measurable Hg emissions, the concentration of Hg from utilities might typically run only

1/10th that of the control limit established for incinerators. The commenter stated that this low

concentration makes further Hg reductions in electric utility boiler flue gas difficult and

complicates the transfer of control technologies established for other industries such as MWC to

the utility sector.

Response:

EPA concurs with the commenters’ assessment.

Comment:

One commenter (OR-2002-0056-4139) disagreed with the proposal preamble discussion

of the differences between solid and medical waste incinerators and coal-fired utility units. The

EPA stated that greater Hg reductions are achieved from the incinerators compared to utility units

because of waste separation techniques. This is false because the Hg reductions are from inlet and

outlet tests, independent from waste stream separation. Also, EPA’s description of Hg spikes is

highly unlikely. Mercury reductions of 80 to 90 percent are achieved even after good waste

separation.

Response:

EPA’s discussion in the proposal preamble relating to waste separation indicated that

this is but one of several methods by which MWC units may achieve high levels of Hg reduction.

3.1.3 Pre-Combustion Technologies

Comment:
3-7

One commenter (OAR-2002-0056-3454) stated that with the implementation of a national

program, multiple control options including pre-combustion, combustion and post combustion

technologies will contribute to meeting the required emission reductions. Coal cleaning as well as

coal switching are examples of options that have the potential to reduce Hg emissions prior to fuel

combustion.

Response:

EPA concurs with this comment.

Comment:

One commenter (OAR-2002-0056-1817) stated that the EPA dismisses switching to lower

Hg coal and any other pre-combustion controls but has no problem presenting DOE’s variability

analysis that assumes all plants can switch to higher Hg coal. However, KFx Corporation is

currently constructing a facility for pre-combustion treatment of subbituminous coal (70 to 90

percent Hg removal).

Response:

EPA has not "dismissed" the use of fuel switching, lower-Hg coal, or any pre-combustion

control technologies as compliance options. However, EPA believes that a regulation that

requires a facility to switch fuels to achieve compliance results is an "unachievable" standard. 

We acknowledge, that some utilities will choose to switch fuels and, in fact, our IPM modeling

predicts some minimal amount of fuel switching. Technologies such as that developed by KFx

Corporation could be used at the discretion of the utility. With regard to the DOE variability

analysis, EPA presented their analysis as being yet another approach to handling variability and

sought comment. EPA used its own variability analysis.

Comment:

One commenter (OAR-2002-0056-1952) stated that studies have shown pre-combustion

beneficiation of western coal, including lignite, can provide Hg reductions of up to 70 percent. 

Coal as-mined contains rock and minerals, and the commenter asserts that much of the Hg in coal

is typically associated with these non-fuel impurities. Removal of these impurities using proven,

commercial coal cleaning technology will result in greater than 60 percent Hg reduction in many

western coals. The commenter has investigated coals from the Southwest, Northern Great Plains,

the Rocky Mountains, Gulf Basin, PRB, and Western Canada and states that, with the exception

of the PRB, Hg reductions were substantial using simple gravity separation. The commenter

stated that coal cleaning provided only a 25 percent reduction of Hg in PRB coal. 

Pre-combustion Hg removal should be investigated by EPA as a preferred technology for western

coal; it is economical, it is proven technology, and it reduces other key pollutants such as ash,

sulfur, arsenic, and NOx. The commenter also stated that regulations that don’t encourage

economical pre-combustion Hg reduction will actually increase the pollution from coal-fired

plants in two ways. First, there will be a disincentive to provide cleaner-burning coal fuels. Coal
3-8

buyers will be attracted to cheaper, dirtier fuels. The commenter stated that if post-combustion

clean-up is the only technology recognized by EPA, power plants will have higher emissions of

pollutants per megawatt-hour (MWh) produced, than if policy encourages burning cleaner coal. 

The commenter asserts that although we may have lower Hg emissions, we’ll have more solid

waste, SO2, NOx, CO2, and arsenic. Second, natural gas prices are unlikely to return to levels

where they can provide low-cost, low-emissions electricity for the U.S. market. The commenter

states that if we are to reduce emissions from the production of electricity, we must implement the

most cost-effective technology available. The commenter notes that some utility clients report

that post-combustion Hg removal could add $8 to $12 per ton to the cost of using coal. The

commenter states that those costs will be directly absorbed by U.S. industry, impacting American

products and services from aluminum to computer server farms.

One commenter (OAR-2002-0056-3478) stated that fuel processing technologies are

being developed to remove Hg and sulfur from the coal before it reaches the plant. Washing coal

is one method that has been used on the higher rank coals for some time. Processes are being

developed for low rank coals such as lignite that have the potential of reducing, or perhaps

eliminating, the requirement for post combustion equipment. Some technologies incorporate

novel ways of physical screening while others involve heat and pressure to drive off pollutants. 

Additional work will be required on coal treatment processes to complete the economics of these

processes. Also, in fuel processing, it may not be practical to treat all of the coal going to a plant

because of the large amount of tonnage involved. The commenter believes the economics of coal

treatment systems would be greatly enhanced if it were possible to treat only a fraction of the total

tonnage consumed by a unit.

Response:

Utility units are free to utilize any means available, including pre-combustion treatments,

to achieve compliance with the standards.

3.1.4 Combustion Technologies

Comment:

One commenter (OAR-2002-0056-2922) stated that the single Hg combustion technology

that has been investigated to control Hg has been demonstrated only on a pilot scale without

full-scale applications. A Hg control combustion practice has been investigated by GE-EER on a

pilot-scale combustor that is several orders of magnitude smaller than a utility boiler. Essentially,

the technique achieves high loss on ignition (LOI) by combusting the fuel initially at low oxygen

concentrations to promote the formation of carbon in the boiler and the fly ash. GE-EER

primarily evaluated the Hg removal potential for low-rank coals such as PRB and lignite. The

vendor claims Hg removal rates of up to 40 percent for low-rank coals, although its own data

seem to indicate that only 25 percent removals were actually achieved. This technology goes

against the trend in the utility industry whereby burner manufacturers for years have been trying to

minimize LOI to address the concern of the utility industry that high carbon levels make it

impossible to sell fly ash as an additive to cement. Although the GE-EER "in-situ" carbon
3-9

formation concept for Hg removal results looks interesting, it is far from being a commercial

process. At this stage of development it is impossible to evaluate its true costs. For example,

costs cannot be evaluated without knowing the extent to which this technology would result in

lost income from the inability to sell fly ash with high LOI levels and increased disposal costs of

up to $30 to $40 per ton for fly ash. Finally, this technology might cause the radiant and

convective boiler section tubes to be blanketed with carbon, decreasing boiler efficiency and

increasing the cost of electric production.

Response:

EPA is not mandating use of any technology to achieve compliance with the final rule. 

The industry is free to use any means, including the one cited by the commenter, to achieve

compliance with the standards.

Comment:

One commenter (OAR-2002-0056-2889) stated that EPA did not adequately consider

low-NOx burners as a Hg control technology. The EPA wrongly characterized this system as

poor tuning (69 FR 12402). Low-NOx burners result in higher levels of unburned carbon in coal

ash, and are a mature technology required in the Northeast for years to achieve the NOx RACT. 

In Massachusetts, units at the Salem Harbor and Mt. Tom Station power plants are averaging 83

to 87 percent Hg capture in coal using low-NOx burners and ESP units. The EPA should

recognize the possible role of low NOx burners in helping reduce Hg emissions.

One commenter (OAR-2002-0056-3449) stated that the best Hg control technology for

existing coal-fired power plants is use of fabric filters with low-NOx burners. Rather than

injecting carbon like ACI, the low-NOX burners tend to generate carbon that is caught by the bags

and then may absorb Hg. Controls in use today at power plants in New Jersey to reduce

emissions of SO2 and PM have achieved Hg reductions of 90 percent or more (scrubbers and

fabric filters with low-NOx burners and SCR for NOx). 

Response:

EPA’s description of "poorly tuned coal burners" in the supplemental notice did not refer

to properly installed and operated low-NOx burners as the commenter states. Rather, the

discussion was directed at any type of burner that had not been properly maintained and

operated. Low-NOx burners are in wide-spread use in the coal-fired utility sector and could be a

part of any utility’s compliance strategy. EPA notes, however, that use of low-NOx burners on

low-rank coals is unlikely to result in significant Hg capture due to the low levels of chlorine in

the coal.

3.1.5 Post-Combustion Technologies

3.1.5.1 General Comments on Hg Control Performance
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Comment:

Many commenters stated that coal plants can achieve greater than 90 percent Hg control

using existing technology which is available at many plants (e.g., scrubbers, fabric filters, and

SCR) or by ACI. ACI is commercially available today and technology transfer from MWC units

is clearly feasible. Municipal waste combustors with fabric filters and ACI have achieved 99

percent Hg control; DOE analyses show that retrofitting a coal-fired boiler with ACI and fabric

filter also can achieve 90 percent control with low capital and operating costs.

Many commenters also stated that the emission reductions used by EPA are much too low

compared to what is technically achievable and cost effective. Based on currently available

control technology, existing units should be able to meet at least 80 percent Hg efficiency for

subbituminous coal and a minimum of 90 percent for bituminous coal.

Response:

EPA agrees that some coal-fired units have exhibited greater than 90 percent Hg

reductions in the limited test data available. However, not all units have been able to achieve

this level of control, even with similar control technologies installed. As noted earlier, EPA

disagrees with the commenter’s assessment regarding the commercial availability of Hg-specific

control technologies and on the ability to transfer the technology from the MWC industry.

Comment:

One commenter (OAR-2002-0056-3210) stated that based on the ICR III data, the best

reductions for Hg and sulfur an be achieved with wet scrubbers and fabric filters or spray dryer

absorbers with fabric filters. Analysis of the data showed that in the 8 states surrounding New

York, fabric filters achieved the best control of Hg, followed by an ESP with wet scrubbers. 

Municipal waste combustors in New York using ACI with fabric filters achieve 90 percent Hg

reduction while combustors with ACI and an ESP achieve at least 85 percent reduction.

Response:

EPA is charged with establishing a standard that is achievable nationwide, not just in

one sector of the nation. As noted elsewhere in this document, EPA has reanalyzed the available

data and revised the new-source NSPS limits based, in part, on the control technologies

suggested by the commenter.

Comment:

One commenter (OAR-2002-0056-4209) agrees that optimizing controls for NOx and SO2

can reduce Hg from 60 to over 90 percent.

Response:
3-11

EPA agrees that existing controls can be optimized for Hg removal and believes that the

approach taken for the final rule will provide the greatest incentive to induce early applications

of such optimization.

Comment:

One commenter (OAR-2002-0056-2661) stated that there are inherent problems in a Hg

control philosophy based on Hg control technologies that require converting elemental Hg to a

form potentially more harmful to human health for the purpose of Hg emission control efficiency. 

It doesn’t make sense to require the formation of a potentially more harmful species of Hg in

order to remove it from the flue gas stream.

Response:

EPA has no information to indicate that oxidized Hg is any more harmful to human

health than is the elemental form, particularly at the concentrations found in the atmosphere

(i.e., the levels found in the atmosphere are significantly lower than those expected from a Hg

spill in a confined space). Oxidized Hg would tend to deposit closer to the emission source than

elemental Hg, but elemental Hg is ultimately transformed to oxidized Hg forms in the

atmosphere and subsequently deposited. Oxidizing the elemental form enhances the ability of

many control technologies to remove significant levels of Hg from the exhaust-gas stream. EPA

believes that the rule will reduce the risks from Hg, rather than increase them.

Comment:

One commenter (OAR-2002-0056-2422) stated that the EPA paper, "Control of Mercury

Emissions from Coal-Fired Electric Utility Boilers," presents a narrow and misleading view of the

Hg capture performance of conventional SO2 and particulate control technologies. If the purpose

of the paper was to communicate what is and is not known about Hg control, the paper should

have discussed the limitations of the data from which conclusions were drawn, the variability and

uncertainty of the results in that data, the performance that can be expected over a range of coal

ranks, the confidence intervals for those estimates, and what EPA is doing to improve the state of

knowledge on the effectiveness of conventional as well as advanced control systems.

Response:

The referenced paper was written in late 2003 and was based on data available at that

time on Hg capture performance of conventional SO2 and particulate control technologies. The

paper was intended to provide a brief overview of the state of Hg controls for Hg emissions from

coal-fired utility boilers and it was not intended to provide a detailed statistical analysis of the

available data. Such analyses of Information Collection Request (ICR) data have been

conducted by EPA and are in the docket. The paper does briefly discuss results obtained from

the ICR data. However, that data represented a wide range of combinations of boilers, coal

types, and air pollution control configurations. As mentioned in the referenced paper, and

elsewhere, the ability to capture Hg in the PM or SO2 control device is highly dependent upon
3-12

the form (elemental, oxidized, or particulate-bound) of the Hg. The form of Hg in the flue gas is

dependent upon the type of coal being burned, the combustion conditions, and the installed air

pollution control configuration. The paper does discuss the variability resulting from

interactions of these many combinations. For example, on page 7, the final paragraph of the

referenced paper notes that the "ICR data reflected that average Hg captures ranged from

29 percent for on PC-fired ESP plus flue gas desulfurization (FGD) unit burning subbituminous

coal to 98 percent in a PC-fired FF plus FGD unit burning bituminous coals."

Comment:

One commenter (OAR-2002-0056-2843) stated that implementation of the proposed

standards would require new plants to comply with levels of Hg emissions that are inconsistent

with available demonstrated technology. The commenter stated that there are no creditworthy

suppliers of Hg control technology in a position to provide guarantees of performance consistent

with the levels required under the rulemaking. Absent such technology guarantees of

performance, the commenter submits that only a small portion of the available coal resources in

the U.S., particularly those in the PRB in Montana and Wyoming, are known to have Hg content

sufficiently low as to permit operation in conjunction with commercially available air pollution

control device technologies, such as fabric filters, to meet the requirements of the rulemaking. The

commenter cites for example, only about 8 percent of PRB subbituminous coal reserves would

qualify as "compliance coal" if the "new source" criteria proposed by the EPA is adopted.

Response:

As noted later in this document, EPA has reanalyzed its new-source NSPS limits.

3.1.5.2 Fabric Filter Hg Control Performance

Comment:

One commenter (OAR-2002-0056-2359) stated that fabric filter technology exists today

that can reduce Hg emissions by 72 percent on average for subbituminous coal and up to 92

percent for bituminous coal. Activated carbon injection is very cost effective and in the early

stages of full scale commercialization. The combination of ACI and fabric filters essentially

eliminate problems with carbon contamination of fly ash and would allow for the beneficial reuse

of ash in concrete and other products.

Response:

As noted above, EPA disagrees on the degree of commercial availability level of ACI. In

addition, as noted later in this document, EPA has reanalyzed its new-source NSPS limits. EPA

agrees that the use of a supplemental fabric filter with ACI will allow for the beneficial reuse of

fly ash.

3.1.5.3 ESP Hg Control Performance
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Comment:

One commenter (OAR-2002-0056-2259) stated that the his company installed in 2001 a

pilot-scale wet ESP at FirstEnergy’s Penn Power’s Bruce Mansfield Plant located in

Shippingport, PA. The ESP uses a slipstream of flue gas from the exhaust of the FGD system on

boiler unit No.2, which has a rated capacity of 835 MW and burns 3 percent sulfur coal. The

plant installed the pilot ESP to test for PM2.5 and S03 mist removal as a potential control

technology to reduce visible emissions. Further Hg testing was performed during 2003 under an

award from DOE’s National Energy Technology Laboratory. The tests confirm that wet ESP

technology can collect PM2.5 and sulfuric acid (SO3) mist as well as Hg at very high levels. 

Particulate and oxidized Hg species were collected with greater than 70 percent efficiency while

elemental Hg can be partially oxidized, in the range of 18 percent to 44 percent. Successful

development of the Plasma-ESP technology will also allow for high removal efficiency of

elemental Hg within the wet ESP. Therefore, wet ESP technology should be given consideration

as another control technique that offers the co-benefits of capturing PM2.5 and SO3 with little

pressure drop (< 1 inch water column), low power consumption (1 kW/MW). and no additional

real estate if mounted on top of the FGD system or retrofitted within a dry ESP.

One commenter (OAR-2002-0056-1842) stated that the Croll Reynolds’ Plasma Enhanced

ESP technology (PEESPTM) is to be installed at Southern Company’s Miller plant. In this pilot,

a 5,000 actual cubic foot per minute (acfm) wet ESP will be installed after a dry ESP to test for

PM2.5 and SO3 and Hg removal under a EPRI funded contract. It will operate in an unsaturated

flue gas environment and will incorporate the PEESPTM technology, which at lab scale has

demonstrated up to 79 percent elemental Hg control. Buzz Reynolds says that successful

demonstration of the Hybrid dry-wet ESP with PEESPTM could offer plants burning low sulfur

coals a cost-effective option to that of injecting activated carbon followed by fabric filter. Croll

Reynolds claims that the wet ESP approach adds less than one-half inch pressure drop, requires

no additional real estate if retrofitted into the last field of the dry ESP, operates at low power

(1 kW/l MW), has no impact on the dry ESP fly ash, and minimizes the handling of the waste

by-product by concentrating the Hg in the WESP slurry, which is then treated in a recycle system

where the Hg is precipitated out of the water. The Hg by-product is in a much more

concentrated, compact form for easier disposal and handling.

Response:

EPA is not mandating use of any technology to achieve compliance with the final rule. 

The industry is free to use any means, including the one cited by the commenters, to achieve

compliance with the standards.

Comment:

One commenter (OAR-2002-0056-2889) stated that a statement by DOE in a Hg control

technology R&D fact sheet wrongly dismisses the high Hg capture efficiency achieved at Brayton

Point as an "unusual ESP configuration." A more appropriate reaction is that an ESP can be used

with ACI to achieve high Hg removal rates. Salem Harbor’s 90 percent Hg removal rate is also
3-14

portrayed as unusual even though the State has other units with similar particulate-bound Hg

fractions. DOE’s characterization only serves to promote as lenient a control level as possible

rather than building on the strong successes their funding helped document.

Response:

EPA concurs that ESP units may be used with ACI under the proper conditions to effect

Hg removal.

3.1.5.4 Wet Scrubber Hg Control Performance

Comment:

One commenter (OAR-2002-0056-3478) stated that enhancing gas phase oxidation

systems warrant further investigation to reduce Hg. The term "gas phase oxidation systems"

refers to the process of improving the ability of a scrubber to capture Hg by using a technology to

oxidize the Hg. Compounds that are water-soluble are "scrubbed" or removed from the flue gas

into the scrubbing liquid and removed with the scrubber sludge. Thus, an existing FGD system

has the ability to remove the fraction of the Hg that is oxidized.

Response:

Systems such as the one the commenter describes are included in the DOE program and,

if proved successful, would be available as compliance options by industry should they so

choose.

3.1.5.5 Sorbent Injection for Hg Control

Comment:

Several commenters (OAR-2002-0056-2871, -2889) stated that ACI is commercially

available and widely recognized as a viable control for Hg. It has been demonstrated with pilot

and full-scale demonstration projects on coal and has been used for over 10 years on other large

combustion projects. States are now requiring it on new coal-fired units for Hg control. The

EPA’s failure to consider this technology is inconsistent with its past approaches for developing

Hg limit for combustion sources and EPA provides no justification for the change. In previous

standards, EPA has not required technologies to be in long-term us to be considered

"commercially available" and to be evaluated as a potential control method. For example, EPA

proposed NSPS and emission guidelines for MWC units that require ACI even though it had been

tested at only two facilities (and went beyond the floor because lower emissions were achievable

at low costs). The EPA also evaluated ACI for hazardous waste and medical waste incinerators,

even though the technology was rarely used. Sorbent injection technologies such as ACI have

been demonstrated to achieve significant Hg reductions at coal-fired power plants regardless of

coal type; Hg control above 90 percent is feasible at costs similar to those for NOx removal

(Mercury Emissions from Coal Fired Power Plants, NESCAUM, October 2003). State and local
3-15

agencies are using these studies to establish permit limits for new boilers. Wisconsin is preparing

to permit a coal-fired unit using subbituminous coal at 83 percent control efficiency for Hg

(Wisconsin Public Service Company Weston Unit 4). Iowa has issued a permit for a facility using

subbituminous coal requiring 1.7 lb Hg/TBtu (equivalent to an 83 percent control efficiency for

operation with coal from the source with the highest average Hg content (MidAmerican Energy

Company Council Bluffs Energy Center). One of these units has commenced construction under

that permit. Therefore, the technology is in commercial use and must be considered in the

development of performance standards.

One commenter (OAR-2002-0056-3454) stated that Hg specific control technologies such

as sorbent injection systems have been demonstrated at full-scale. Multi-pollutant control

approaches as well as other Hg specific technologies have also demonstrated significant progress

and will provide additional low cost, innovative approaches to Hg control. A number of these

technologies, including sorbent injection systems as well as SCR coupled with wet FGD, have

achieved removal rates greater than 90 percent under certain circumstances.

One commenter (OAR-2002-0056-3449) disagreed that there are no commercially

available control technologies specifically designed for reducing Hg emissions as the EPA stated

in the rationale for the proposed subpart Da standards (p. 4691). Activated carbon injection is

commercially available today for Hg control. Ten years of experience with ACI on MWC

incinerators in New Jersey show that technology transfer is feasible. Some of these incinerators

achieve 99 percent Hg control with fabric filters. The EPA is mistaken to discount ACI because it

has only been pilot tested or short term demonstration tested at full scale units, and has not been

in long term use at any coal units. It will be used long term if required. The NESCAUM report

on full-scale demonstration of ACI shows that 90 percent Hg removal is feasible with costs

comparable to NOx removal. A recently issued Iowa permit requires ACI from a proposed

bituminous coal plant. DOE pilot studies show up to 95 percent control for both bituminous and

subbituminous control with fabric filter and ACI. National Energy and Gas Transmission

Company’s Carneys Point and Logan Township boilers are each equipped with low-NOx burners,

SCR, dry scrubber, and fabric filter which reduce Hg emissions by more than 90 percent.

One commenter (OAR-2002-0056-3205) stated sorbent injection is available for the

control of Hg emissions. Activated carbon injection has been used successfully on MWC units for

the past 7 to 8 years and the technology has been successfully demonstrated in several full-scale

tests, including the recent year-long test at Gaston. Vendors such as ADA-ES have indicated that

ACI is available now for utility units. The commenter also refers to an Iowa permit requiring ACI

at a new MidAmerican Energy Council Bluffs plant. Xcel also proposes to use ACI at a new unit

at the Comanche plant. The commenter referred to the definition of available technology in

EPA’s new source review workshop manual ..."a technology is considered available if it can be

obtained by the applicant through commercial channels or is otherwise available within the

common sense meaning of the term." Activated carbon injection has clearly reached the

commercial availability stage for utility units.

One commenter (OAR-2002-0056-2819) stated that ACI is one of several commercially

available, cost effective technologies for coal-fired boilers. Activated carbon injection systems are
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commercially available and have been install on MWC units. Others include wet ESP, fly ash

injection systems, SCR, wet and dry FGD system, and fabric filters. West ESP and fly ash

injection systems are already in use on coal-fired boilers in the U.S., Europe, and Japan. This data

was presented to EPA. Wet ESP, fly ash injection systems, SCR, wet and dry FGD systems, and

fabric filters have been commercially available and installed on coal and oil-fired utility boilers for

many years.

Several commenters (OAR-2002-0056-2873, -3210) stated that full-scale demonstration

projects have been conducted and are on-going at many U.S. coal-fired power plants to test the

effectiveness of ACI with conventional PM controls for control of Hg emissions. According to

the commenters, these full-scale ACI demonstrations so far have demonstrated at least 50 percent

Hg removal and those with pre-halogenated sorbents have observed as much as 95 percent. The

E.C. Gaston plant burning low sulfur bituminous coal achieved 90 percent removal using carbon

injection with a hotside ESP and COHPAC fabric filter. The Brayton Point plant burning low

sulfur bituminous coal achieved 90 percent with carbon injection and a coldside ESP. The

Pleasant Prairie plant burning subbituminous coal achieved 65 percent using ACI with a coldside

ESP. Gaston showed that a high removal rate using significantly less ACI can be achieved with

the COHPAC system in comparison to other conventional controls. The controls apply to

bituminous and subbituminous coal.

One commenter (OAR-2002-0056-2575) stated that the EPA improperly rejected ACI or

sorbent injection systems as viable Hg control technologies. Much research shows that these

systems are highly effective (80 to 90 percent Hg removal). EPA claims that carbon-based and

sorbent injection control systems are not currently available on a commercial basis. However, in a

separate discussion of certain carbon-based injection system, the EPA repeatedly describes them

as commercially available. The EPA also rejects injection-based systems because they have not

been installed except on a demonstration basis and no long-term data are available to indicate

performance on all representative coal ranks. EPA’s refusal is a direct violation of the CAA

goals. The legislative history clearly shows that Congress intended the statute to be

technology-forcing. EPA’s agreement that it cannot force the industry to implement specific

controls until the industry has fully implemented the same controls is circular logic and destroys

any incentive for industry to develop better controls.

One commenter (OAR-2002-0056-2199) stated that a 90 percent Hg reduction using ACI

is feasible based on a 2002 technical report by the Massachusetts Department of Environmental

Protection. Also, DOE tests at an Alabama plant found that ACI achieved 90 percent Hg

reduction at a very low cost (0.05 cents/KWh). Preliminary tests with ACI by EPRI achieved 90

percent with eastern coal ranks and 60 to 70 percent with western coal ranks at costs from

0.2-0.3 cents/KWh.

Response:

As noted earlier, EPA disagrees with the commenters about the availability of Hgspecific control technologies at the present time. The limited, but increasing, number of tests

have not yet brought the technologies to the level of demonstration that we feel necessary to be
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considered "commercially available" and the basis for a national standard for this industry. We

do not believe that these technologies are available now for wide-spread usage. We have been

following the studies of such technologies closely and have discussed their degree of

development with vendors, the industry, and the DOE. No utility unit has operated a Hg-specific

control technology full-scale for longer than a month or so. Based on these tests and

discussions, we do not believe that the technologies have demonstrated an ability to reduce Hg

emissions by 90 percent (or any other level) for an extended period of time on all coal ranks and

all boiler types. We believe that the cap-and-trade approach selected for the final regulation is

the best method for encouraging the continued development of these technologies.

Comment:

One commenter (OAR-2002-0056-1842) stated that sodium tetrasulfide (Na2S4)

technology can remove elemental as well as ionic (oxidized) forms of Hg. Other advantages

include: the fact that it results in an inert, stable reaction product (cinnabar). Sodium tetrasulfide

is a liquid, and, thus, is easier and safer to handle and inject than powdered activated carbon and is

less abrasive than activated carbon. Both full scale and pilot plant tests have demonstrated that

the Na2S4 process is both a technologically and an economically effective approach to controlling

Hg emissions on MWC units. Pilot plant and short-term tests have verified that the Na2S4

technology alone or in combination with activated carbon technologies can achieve a controlled

Hg emission rate approaching the expected regulatory requirements for coal-fired boilers. Longer

test programs are planned to optimize the flue gas temperature regime and Na2S4 dose rate. 

Because the efficiency of the Na2S4 process is influenced by mass transfer rates, the technology

may be most effective on facilities equipped with fabric filters and wet FGD systems due to the

additional retention and contact time.

Response:

EPA is not mandating use of any technology to achieve compliance with the final rule. 

The industry is free to use any means, including the one cited by the commenter, to achieve

compliance with the standards.

Comment:

Several commenters (OAR-2002-0056-2887, -2946) stated that in the proposal notice (69

FR 4674) the EPA presented a misleading characterization of conclusions from the NESCAUM

October 2003 report "Mercury Emissions from Coal Fired Power Plants." The NESCAUM

analyses show that commercially available control technologies, as well as rapidly emerging

technologies, are capable of achieving greater than 90 percent Hg control. Activated carbon

injection has been used on MWC units for 5 to 10 years, are routinely achieving greater than 90

percent Hg control, and has been successfully demonstrated on coal-fired electric utility

generating units by DOE. The commenters requested that the EPA correct the preamble

statements to reflect the actual conclusions of the report.

Response:
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As noted elsewhere, EPA disagrees with the commenter on the availability and level of

Hg reduction achievable by ACI. We apologize for any misleading characterization of the

NESCAUM report in the proposal preamble.

Comment:

One commenter (OAR-2002-0056-3478) stated that ACI is not a one-size-fits all control

technology; it is highly dependent upon boiler exhaust temperatures, and works best at

temperatures below 300 F. Because the commenter’s coal-fired boilers experience exhaust

temperatures in excess of 350 F to over 400 F, the overall removal efficiency of vapor phase

Hg by ACI would be significantly decreased. The commenter states that to achieve a desired

removal rate with the higher back-end temperatures will require significantly more activated

carbon to be injected. The commenter adds that recent pilot scale testing indicates that ACI may

not be effective at all at temperatures of 400 F or above.

Response:

EPA is aware of the concerns expressed by the commenter. It is concerns such as these

that factor into the Agency’s decision that ACI is not yet a commercially available technology

ready for universal, wide-spread usage.

Comment:

One commenter (OAR-2002-0056-3478) stated that ACI is already used in water and

wastewater applications, and it is not clear that a new significant demand in production for use in

ACI controls at coal-fired power plants could be met. The commenter added that the added

demand will increase the price of activated carbon, changing the cost effectiveness of this

technology.

Response:

EPA also has concerns about the short-term availability of activated carbons suitable for

wide-spread usage by the coal-fired utility industry.

3.1.5.6 Other Hg Control Technologies

Comment:

One commenter (OAR-2002-0056-1842) listed a number of Hg control technologies

under various stages of development that should be considered by the EPA as Hg control options. 

These included the following. Powerspan has a 50 MWe commercial demonstration unit of

electro-catalytic oxidation (ECO) technology at the FirstEnergy R.E. Burger plant. The Mitsui BF

activated coke system is used in full-scale installations on combustion sources in Japan. The

Kentucky Utilities Ghent generating station is the host of a 5 MW slipstream demonstration of the

Airborne process being developed by Babcock & Wilcox and US Filter HPD systems. The EPRI
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and Apogee Scientific have been developing a Hg control technology called MerCAP (Mercury

Control via Amalgamation Process). ADA Technologies, Inc. and CH2M-Hill are developing a

new family of Hg sorbents, called Amended SilicatesJ. Nooter Eriksen and EnviroScrub are

offering the Pahlman technology with multi-pollutant control capabilities including Hg removal.

One commenter (OAR-2002-0056-5316) stated that the Toxecon IIJ technology is

applicable to 715 coal-fired plants while the new high temperature sorbents cover another 82

plants. The industry can reach a 70 percent Hg removal rate by 2010 and 90 percent by 2014

with this technology. The Toxecon IIJ system can be rapidly deployed because it takes

advantage of the existing ESP. It is cost effective because the new chemically-enhanced AC

sorbent has low injection rates. In addition, the plant can continue to sell 90 percent of its fly ash

for use in concrete.

Response:

EPA is aware of these technologies and aware that none are in full-scale application. 

We believe that the final rule’s cap-and-trade approach, with declining caps and market rewards

for reductions will provide the impetus necessary to bring these technologies to full development.

3.1.5.7 Impact of Coal Chlorine Content on Hg Control Performance

Comment:

One commenter (OAR-2002-0056-2422) stated that the best performing technologies for

Hg removal are fabric filters (with or without scrubbing) and wet scrubbers with (cold- or

hot-side) ESP units. The Hg removal capability of these technologies is found to be correlated

with coal Cl content. The performance of these control technologies is substantially reduced and

highly variable when firing coals with low Cl content. Thus, there is not have a high level of

confidence that the best performing technologies will reduce Hg emissions to a significant degree

when units fire coals of relatively low Cl content. The performance of other emission control

technologies does not appear to be sensitive to Cl content.

Response:

EPA has based its emission limits on the performance of technologies within each of the

subcategories and, thus, feels the situation noted by the commenter has been addressed.

Comment:

One commenter (OAR-2002-0056-1842) stated that the addition of a chloride prescrubber before a SO2 wet scrubber should ensure 90 percent Hg removal and even more. A

number of European waste-to-energy plants utilize this technology and achieve 90 percent

removal (combination of pre-scrubber and scrubber). There is no reason this technology needs to

be modified for coal-fired power plant use. The chloride pre-scrubber levels the playing field for

those burning PRB coal. No matter how small the Cl content of the coal, the pre-scrubber
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captures it as hydrochloric acid and then builds the concentration to the needed level. The

chloride scrubber by itself should provide all the oxidation necessary. But if higher oxidation is

still desired, you can deposit some of the salts or the acid back on the coal feed belt. So the

concern that low sulfur, low Cl coals will make it more difficult to remove Hg is eliminated with

this scheme.

Response:

EPA is not mandating use of any technology to achieve compliance with the final rule. 

The industry is free to use any means, including the one cited by the commenter, to achieve

compliance with the standards.

Comment:

One commenter (OAR-2002-0056-3517) stated that EPA has hypothesized that Hg

removal rates are influenced by the amount of Cl that is contained in the coal. The commenter

notes that although western bituminous coals are low in Hg content relative to other coals, they

are also very low in Cl. The commenter adds that there is evidence that these coals perform very

well with current technology in reducing Hg, despite the low Cl content. According to the

commenter, a case in point is the Intermountain Plant in Utah, which burns a low Hg, low Cl Utah

bituminous coal; it is possible that the Cl content may be a surrogate for other factors that

influence Hg reduction performance.

Response:

EPA believes that the Cl content is but one of many factors that may impact on Hg

removal from coal-fired utility units. The performance of western bituminous coals noted by the

commenter is one factor that lead EPA to subcategorize all bituminous coals together.

Comment:

One commenter (OAR-2002-0056-2944) stated that the different average Cl levels of the

different coal ranks was used as the justification to support proposing different emission limits and

allocation weightings. However, based on the commenter’s analysis, Cl is found to be of little

importance. The utility industry is already removing about 30 percent of the estimated 75 tons of

Hg coming into its plants annually with the fuel. The commenter further stated that according to

ICR flue gas measurements, this Hg is primarily removed at bituminous coal plants as soluble

oxidized Hg (due to coal Cl) in existing SO2 scrubbers and as absorbed oxidized and elemental Hg

on unburned carbon captured in the plants’ particulate collectors (due not to higher Cl in

bituminous coal, but due to their higher unburned carbon levels, which result from less-reactive fly

ash). (The commenter notes however, that only 20 percent of U.S. boilers have scrubbers.) The

commenter states that as indicated in the second Hg-content plot (see OAR-2002-0056-2944), if

all the bituminous coals are adjusted for a 30 percent (post-combustion) reduction in their Hg

levels, and subbituminous coals see no corresponding reduction, the Hg (emission) distributions

for these two fuels, which encompass over 95 percent of U.S. coal use, are amazingly identical.
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Therefore, when considering coal Hg, Cl, and fly ash together, without any specifically-added Hg

control technology, subbituminous coals are currently not at any disadvantage relative to

bituminous coals with respect to Hg emission limits.

Response:

EPA is not alone in its belief that the Cl content of coal is a factor in the level of Hg

removal achievable. It is also realized that the level of unburned carbon in the exhaust gas is

also a contributing factor. We believe that the final rule does not disadvantage any coal rank.

3.1.5.8 Impact of SCR for NOx Control on Hg Control Performance

Comment:

Several commenters (OAR-2002-0056-1969, -2830) disagreed with EPA’s statement in

the proposal preamble that although no full-scale lignite-fired SCR-equipped unit has been tested

for Hg removal it is possible that greater Hg removal would result when an SCR unit was applied

to a lignite-fired unit. The commenters stated that testing of a pilot-scale SCR reactor at Coyote

Station (a nominal 420 MWe lignite-fired generating facility that is located near Beulah, North

Dakota) showed that the SCR technology is ineffective in oxidizing Hg and that the saltation of

calcium and sodium ash deposits foul the catalyst rendering the SCR technology ineffective for

NOx control. The installation was in conjunction with a study entitled "Impact of SCR Catalyst

on Mercury Oxidation in Lignite-Fired Combustion Systems" that conducted by the Energy and

Environmental Research Center located in Grand Forks, North Dakota.

One commenter (OAR-2002-0056-3514) stated that currently, no technology has been

shown to be effective in capturing Hg from lignite coals. Lignite and other low-rank western

coals face additional obstacles that do not affect other ranks of coals, specifically higher ash,

lower Cl, and higher elemental Hg content. According to the commenter, these factors make it

impossible, at least currently, to attain the removal percentages being achieved with other coals. 

The commenter noted that EPA refers to SCR, intended for NOx reduction, as an option that

could also significantly increase the oxidation of Hg in the flue gas to improve capture. The

commenter stated that although this may have been shown to work for certain coal ranks, it has

been shown that the SCR blinds almost immediately in lignite applications in recent large scale

testing conducted by the University of North Dakota Energy and Environmental Research Center. 

Thus, in establishing Hg removal goals and limits, the commenter believes EPA must consider that

SCR is not a viable option for lignite.

Response:

EPA still believes that SCR installations on lignite-fired units will, with further

development, provide improved Hg removal. Any improvement will provide yet another means

for such units to effect compliance with the final rule. However, the use of SCR units on lignitefired units was not included in the analyses that led to the final emission limits for this

subcategory.
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3.1.6 Analysis of ICR Hg Emission Data

Comment:

Many commenters (OAR-2002-0056-1675, -1677, -1680, -1692, -1762, -2160, -2422,

-2535, -2818, -2876, -3198, -3478, -3534, -3565) stated that the ICR Part III data are not

appropriate for establishing any regulatory standard because of the deficiencies in the quantity,

quality, and accuracy of this data set. Reasons cited by commenters include the following. The

ICR emissions data fail to meet generally accepted limits of experimental accuracy and precision. 

The data set includes estimates of negative Hg removal, incomplete data, failure to close the

material balance in the overall accounting for Hg input and output, and low precision. The

80-plant ICR sample data provide an unrepresentative snapshot of emissions from a limited

number of facilities because the data include emissions from the use of a limited number of fuel

types over a limited period of time. The wide variability of coals and process conditions is not

accounted for in the ICR sample data. The units chosen by EPA for Hg emissions sampling in the

ICR program are unrepresentative of the coal-fired power plants in the U.S. The companies that

performed the tests had inadequate experience with the required test methodology. The data are

affected by a bias in testing conditions, because the testing was done during high-load and

steady-state operations. The data were gathered using a test method that is very different from

what is proposed for compliance demonstration under the rule and no effort has been made to

translate the proposed standards that were developed from the data to the basis of the test

methods proposed for compliance demonstration. The reported coal rank used to classify some

of the units tested was incorrect or did not accurately reflect the blending of coals from different

ranks. The selection of the units chosen by the EPA for testing is skewed toward wet- and dryscrubbed units which are more likely to show lower emissions than the majority of plants, which

are inscribed. 

In contrast, Commenter OAR-2002-0056-5535 stated that EPA’s ICR III dataset is more

than adequate to support establishment of stringent standards. The industry commenters

opposing the ICR data set identify nothing in the language of the CAA that requires that the

dataset comprehensively account for emissions information from the industry as a whole, provided

the data allow EPA to make a reasonable estimate of performance of the top 12 percent of units. 

(Sierra Club v. EPA, 167 F.3d 658, 662 (D.C. Cir. 1999). The D.C. Circuit has further observed

that EPA typically has wide latitude in determining the extent of data-gathering necessary to solve

a problem. (Cement Kiln Recycling Coalition v. EPA, 255 F.3d 855, 867 (D.C. Cir. 2001)

("CKRC") (quoting Sierra Club, 167 F.3d at 662)). It is only when the model or dataset chosen

bears "no rational relationship to the reality it purports to represent" that a court will interfere

with the agency’s exercise of its discretion. (Columbia Falls Aluminum Co. v. EPA, 139 F.3d

914,923 (D.C. Cir. 1998)). Putting aside the legal requirements, EPA also thoroughly debunked

the factual basis underlying the industry claims that the ICR database is too weak to use for

standard-setting. Industry stakeholders first raised this issue in 2001 during the Utility Working

Group process. At that time, EPA presented their analysis of both the coal sampling data and the

emissions testing data. With respect to the fuel analyses, EPA concluded that the "data are

sufficient to use in the development of MACT standards." For the emissions tests, the agency

undertook what they described as an "[e]xtensive quality assurance effort." After examining
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individual test data, excluding invalid data and examining data points for potential outliers, EPA

found no reason to exclude any of the complete datasets as outliers. As with the fuel analyses,

EPA concluded the "[ s ] tack test analyses data are sufficient to use in the development of

MACT standards."

Response:

EPA believes that the data are adequate with which to establish appropriate emission

limits for the industry. EPA agrees with some of the comments made but not with the

conclusions. For example, EPA made no attempt to conduct a material balance around the

utility unit, this not being necessary to establish an emission standard. Units showing negative

removals are, obviously, not among the better controlled units and, thus, were not used in

establishing the emission limit. The 80 units tested, although seemingly limited in number,

represent a larger data set than available for other CAA section 111 or section 112 regulatory

efforts. The matrix of unit types to be tested was subject to public notice and comment prior to

being sent to the industry. The resulting mix and number of units is a compromise between the

greater number of units that could have been tested as inferred by the commenters and the cost

of such testing. EPA reported the rank of coal used during the testing based on what the

companies involved provided to EPA. EPA did not specify the load to be maintained during

testing but concurs that testing of this type is generally undertaken during periods of steady-state

operation to minimize the problems associated with evaluating test results obtained during

periods of fluctuating operation. However, we feel that the incorporation of variability in the

analyses adequately addresses this issue. The testing runs were conducted sequentially, so

source variation in emissions is present from run to run. Therefore, no measurement of

sampling precision is possible as this would have required the use of paired sampling trains at

all sites. The test contractors utilized by the industry are among those regularly employed in

such activities and, thus, are familiar with both the industry as well as the various EPA

Reference Methods. The Ontario-Hydro method used, although requiring attention to the details

of the procedures, utilizes much of the same sampling equipment as does other EPA Reference

Methods more widely utilized by the test contractors. Further, attention to the details of the test

methodology is not, or should not be, anything different from such contractor’s performance of

any emissions test. The proposed continuous Hg measurements are for gaseous Hg only; most of

the Hg measured through the Ontario-Hydro method was also determined to be gaseous. EPA

performed some comparisons of the data obtained through manual vs. continuous monitoring for

those sites at which the continuous monitors were evaluated and believes that the 12-month

rolling average format chosen adequately reflects an appropriate translation of the data.

Comment:

One commenter (OAR-2002-0056-2535) retested in 2003 some of the power plants

burning Wyoming PRB coal included in the ICR Part III data sets. The re-testing methods used

at these plants were consistent with the methodologies and protocols used in the EPA ICR III

testing. Irrespective of the distribution of the Hg species at the APCD inlet, the outlet stream

contains mostly elemental Hg. Both the ICR and the newly acquired data are directionally

consistent but have significant variation due to coal Hg content and operational variability. This
3-24

corroborates the earlier observations that data variability is an issue. Hence, any regulatory

standards or guidelines must account for the variability, specifically in the case of subbituminous

coal due to its higher fraction of elemental Hg exiting the furnace.

Response:

EPA concurs that variability must be accounted for in any emission limits. We believe

that the final emission limits adequately address the commenter’s concerns.

Comment:

One commenter (OAR-2002-0056-3560) stated the ICR data collection effort appears to

have been done on a dry basis. This introduces minor error when the actual testing is done

including moisture on an as-received basis, but the impact on the regulation in lb/MWh may be

more significant. This issue has not been addressed by EPA.

Response:

EPA provided the data on a dry basis for consistency and ease of use of the data because

some data were reported by the companies on a wet basis and some on a dry basis. We do not

believe that this will have a significant impact on the rulemaking.

Comment:

One commenter (OAR-2002-0056-2422) stated that based on the commenter’s analysis of

the ICR Part III data, no statistically significant differences can be detected in the Hg removal

performance among the three configurations of fabric filter controls alone or combined with wet

or dry scrubbers. Similarly, no statistically significant differences can be detected in the Hg

removal performance among cold- and hot-side ESPs combined with wet scrubbers.

Response:

EPA concurs with the comment.

Comment: 

One commenter (OAR-2002-0056-5564) provided additional information on the ICR fuel

sampling to show that the amount of Hg was significantly understated in Gulf Coast lignites

because of the test method (ASTM D3684) used in the analyses. When the analytical lab

switched to ASTM D 6414, the Hg levels essentially tripled. Method 3684, which most Gulf

Coast lignite plants used, is not accurate for lignite with high levels of Hg.

Response:

EPA is aware of the issue but believes that the value is limited in that the final emission
3-25

limits were based on Hg emissions to the atmosphere rather than on any calculation based on

the Hg content of the coal being used. EPA reserves the right to revisit this issue during normal

reviews of the NSPS but believes that the revised Hg emission limits adequately address the

commenter’s concerns.

3.1.7 Cross-Media Impacts

Comment:

Two commenters (OAR-2002-0056-2008, -3478 ) stated that the implementation of ACI

Hg controls could potentially impact the sale of combustion byproducts, eliminating an income

stream for utility companies and increasing expenses for permanent ash disposal. One of the

commenters (OAR-2002-0056-2008) stated that the largest market segment for coal combustion

by-product (e.g, fly ash) use is the construction materials market. Fly ash is used as a replacement

for Portland cement in concrete production and other cementitious based applications. The

commenter stated that the severe detrimental influence exhibited by activated carbon on airentrained concrete was shown in a presentation provided at the American Coal Council Mercury

and Multi-Emission Compliance: Strategies and Tactics for New and Existing Coal Plants

Symposium, Irving, Texas, March 24-25, 2004. The reported findings indicated that the addition

of activated carbon in amounts of less than one percent could render fly ash unusable for concrete

applications. The laboratory findings are consistent with reports from large-scale demonstration

projects such as the one conducted by ADA-ES at WE Energies’ Pleasant Prairie Power Plant. In

that study, powdered activated carbon was used as the Hg sorbent. Although the activated

carbon removed Hg from the flue gas stream during the test program, it also contaminated the fly

ash, darkening the light-colored material and making it unusable for air entrained concrete. The

commenter stated that the ACI process would not only cause the plant to lose a source of revenue

through lost fly ash sales, but lead to additional disposal cost. The commenter reported that these

combined issues were estimated to be valued at $5,000,000 per year (R. Peatier; Mercury removal

standards are coming; Where’s the technology?, Power, May 2003 p 40).

Response:

EPA agrees that the use of ACI can impact on the usability and disposal of fly ashes from

coal-fired utility units. However, we believe that means are available that minimize this impact

(e.g., use of a polishing fabric filter following an ESP; the ESP to capture the majority of the

"clean" fly ash for re-use and the fabric filter to capture the activated carbon injected between

the two units). Further, sorbents are under development and testing that do not cause the same

degradation with air-entrained concretes that are posed by activated carbon.

3.2 EMISSIONS LIMITATIONS

3.2.1 General

Comment:
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One commenter (OAR-2002-0056-2443) stated that establishing nationwide emission

limits is not justifiable given the wide variability in coal properties (e.g., Hg content, Cl content),

plant operating practices, and the uncertainty about the chemistry of Hg speciation and its control.

Response:

EPA believes that its use of subcategories in establishing the final emission limits

adequately addresses the commenter’s concern.

Comment:

One commenter (OAR-2002-0056-2422) stated that the EPA’s proposed new source

standards are not based on the "best controlled similar source" using a worst-case operating

scenario. New coal-fired units are not uniform in design; coal properties and other factors can

significantly affect plant designs. Current bituminous PC plant designs typically incorporate a wet

scrubber for SO2 control, an ESP or fabric filter for particulate control, and an SCR for NOx

reduction. New plants designed for PRB coal will likely be dry scrubbed, have a fabric filter, and

some advanced form of NOx control such as SCR. As noted previously, dry scrubbed plants with

fabric filters obtain virtually no Hg reduction. An SCR or other form of NOx control may aid in

the reduction of Hg, but there are no data in EPA’s ICR database on which to base a sound

decision on the effectiveness of NOx controls in reducing Hg emissions from either eastern or

western coals.

Response:

EPA concurs with the commenter’s concerns but believes that because the final emission

limits were based on the performance or permitted levels of current controls within each

subcategory, the commenter’s concerns have been addressed adequately.

Comment:

One commenter (OAR-2002-0056-2843) recommended that no standard be promulgated

unless existing control technology can be demonstrated to be able to attain and sustain the

standard over a wide range of coals and for a long period of time. The commenter stated that this

is true whether the emission reduction is to be accomplished by a requirement under either CAA

section 111 or section 112. The commenter believes that unless achievable control technology is

available at the outset, the construction of new coal-fired facilities will be improbable. Further,

the commenter believes that no demonstrated technology exists that is capable of affecting the

levels of emissions reduction which would be required under either of EPA’s proposed

rulemaking. Therefore imposition of either proposed approach would make it extremely difficult,

if not impossible, to construct new coal-fired plants. The commenter specifically cites that the

latest DOE solicitation for a full-scale demonstration of Hg reduction technologies on a scrubbed

unit burning PRB coal will not be concluded until 2005. The first such tests being conducted at

the commenter’s Holcomb 1 unit will not be concluded until late summer 2004.
3-27

Response:

As noted above, EPA concurs with the commenter’s concerns but believes that because

the final emission limits were based on the performance or permitted levels of current controls

within each subcategory, the commenter’s concerns have been addressed adequately. Further,

as noted later in this document, EPA has reanalyzed the data and revised the NSPS emission

limit for new sources.

Comment:

One commenter (OAR-2002-0056-2916) stated that CAA section 111(a)(1) requires that

the level of emissions reductions for a new source must reflect a level of performance of a

technology that has been put to practice in a number of commercial applications using a number

of coal ranks in order to meet the test of being "adequately demonstrated." The commenter stated

that there are currently no commercially available technologies that are designed to control Hg

from coal-fired power plants to the levels proposed. The EPA must reconsider and revise the

proposed NSPS limits in light of the wide range of uncertainty concerning the performance and

future availability of commercial Hg control technology. In order to support the emissions levels

and time frames set forth in the proposed rulemaking, the commenter believes that the EPA and

DOE must make certain that sufficient funds are provided to complete the required R&D to fully

develop and commercially demonstrate advanced Hg control technologies. The commenter stated

that Hg emission reductions that are required before the technology has been fully developed will

lead to significantly increased costs, to likely fuel switching from coal to natural gas, and to

possible disruption of the nation’s electricity supply.

Response:

EPA might argue the commenter’s discussion of what section 111(a)(1) requires but

agrees with the commenter that Hg-specific control technologies are not yet commercially

available. Further, as noted later in this document, EPA has reanalyzed the data and revised the

NSPS emission limit for new sources.

Comment:

One commenter (OAR-2002-0056-2331) stated that to reduce the possibility of overly

stringent source limits and resultant fuel switching, the EPA should set the new source standards

on demonstrated, commercially viable technologies as provided in CAA section 111(a). The

EPA’s proposal to set standards based on "emerging" pollution control technology introduces

unnecessary uncertainty in the viability of all fuel sources for future generation of electricity.

Response:

As noted later in this document, EPA has reanalyzed the data and revised the NSPS

emission limit for new sources. We do not believe that the final emission limits have been based

on "emerging" technology but, rather, that the format of the standards selected will allow for the
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full development of such technologies.

Comment:

One commenter (OAR-2002-0056-1852) stated that utilities should be allowed the

greatest flexibility in switching and blending fuels to meet an emissions standard. Therefore, it is

important that the final rule be designed to allow for inclusion of pre-combustion controls as a

viable compliance strategy. For many electric generating facilities, pre-combustion Hg removal

can be more cost-effective than post-combustion removal, as pre-combustion methods control the

Hg while it is in a more concentrated and contained form, permitting significant savings in waste

disposal volumes and costs. For older facilities in particular, for which retrofits would be

extremely costly, using fuel that has been cleaned and upgraded on a pre-combustion basis offers

the most cost-effective compliance method.

One commenter (OAR-2002-0056-1760) stated the final rule should incorporate pollution

prevention strategies to remove Hg prior to release to the air.

Response:

EPA believes that pre-combustion removal of Hg is a viable option available to the

industry under the final rules.

Comment:

One commenter (OAR-2002-0056-2331) stated that EPA must ensure that any new

source emission limits are economically attainable for electric utilities and will not lead to facilities

switching to natural gas for base load electrical generation.

Some commenters (OAR-2002-0056-1692, -1768) stated that Hg standards must be

technically achievable for all types of coal-based electric generation sources.

Response:

EPA believes that its final rule is founded on the cost requirements of section 111, is

technically achievable for all types of coal-based electric generation sources, and will not lead

to fuel switching. Note, however, that utilities are free to comply with the final emission limits in

any manner they choose.

Comment:

One commenter (OAR-2002-0056-2843) stated that circulating fluidized bed technology

sources behave quite differently than pulverized coal sources and should not be used to determine

either emission limit levels or allowance allocations.

Response:
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As noted earlier, with the exception of coal refuse-fired units (which is a result of the

coal rank rather than of the boiler type), the data did not suggest that FBC units (including CFB

units) emitted Hg any differently than other boiler types and, therefore, no subcategory

specifically for FBC units was established.

3.2.2 Regulated Pollutants

Comment:

One commenter (OAR-2002-0056-2219) stated that the proposed rules fail to address

speciation of Hg. Mercury takes different forms (ionic, elemental, particulate) depending on the

rank of coal burned. Although ionic and particulate Hg can be controlled by existing technology,

additional controls are needed for elemental Hg. This is particularly important in the case of a

cap-and-trade program.

One commenter (OAR-2002-0056-2067) stated that there is a lack of effective removal

technology for elemental Hg, which is prevalent in Wyoming PRB coal. Without existing

technology, it is unfair to the purported neutral treatment of coal ranks to require removal of

elemental Hg (which is more prevalent in subbituminous coal) before 2010. This is especially true

for those power plant units that have existing scrubbers in place.

Response:

The rank of coal burned impacts the relative amounts of each of the three primary

species of Hg emitted; all coals emit some of each species. The final rule is based on the

performance and permitted levels of existing technologies for new sources. For existing sources,

adequate time is provided before the Phase II cap is in place to allow for the development of the

promising Hg-specific control technologies that will effectively capture the elemental Hg.

3.2.3 Format of Standards

3.2.3.1 General

Comment:

One commenter (OAR-2002-0056-3449) objected to the format of the proposed standard

because the EPA failed to select a format that best addresses variability. It is wrong for a

contaminant where variability of the concentration of the contaminant in a fuel is an important

consideration. The appropriate format was used in the MWC standards and the NSPS for SO2

emissions from coal-fired plants. Both of these rules have a combination standard (X micrograms

per cubic meter or W percent control for the MWC units) and Y lb/Btu or Z percent control for

the NSPS. This format allows the concentration limit to be based on the average level of the

constituent because the percent reduction limit can be used for situations with the constituent

level is much higher. The logical way to structure a combination standard is to base the lb/TBtu

(or lb/MWh) on the median case and to base the percent reduction on the worst coal case. This
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ensures that real reductions occur for the median coal and the worst case coal can still be burned

with good control.

One commenter (OAR-2002-0056-3406) stated that because of variations in plant design

and the coal ranks used, the commenter recommended that the standard for all plants be a

combination of a reduction in emission rate or an emission rate, whichever is less restrictive (e.g.,

X percent reduction or Y lb/TBtu). The commenter stated that this is consistent with the

approach used in Connecticut and proposed in other States.

Response:

EPA disagrees that a percent reduction format, or a combination format that includes

percent reduction, is appropriate for this rulemaking because of the difficulty in determining

where the percent reduction should be assessed. Further, EPA has proposed to eliminate the

percent reduction portion of the subpart Da emission limits for SO2 emissions from coal-fired

power plants.

3.2.3.2 Percent Reduction Format

Comment: 

Many commenters (OAR-2002-0056-2054, -2067, -2068, -2160, -2224, -2422, -2634,

-2661, -2827, -2867, -2922, -3200, -3403, -3514, -3432, -3565, -4891) recommended that the

EPA add a "percent reduction" alternative for emission limit standards, based on the Hg in the

coal supplied to the boiler and the Hg in the stack. Affected units would have the option of

meeting an emissions rate limit or a removal efficiency requirement. Reasons for adopting a

percent reduction format include such an approach is appropriate given the variability between

and among units and the differences in coal characteristics among coal within a given rank. This

would allow units to burn higher Hg content coals by removing Hg to the greatest extent possible. 

In addition to providing a realistic option for units that would result in significant Hg reductions,

this approach ensures that existing coal reserves remain a viable fuel source. Such an option

would insure that one coal is not favored over another.

One commenter (OAR-2002-0056-2160) recommended that standards should have an

alternative standard to emission limits based on a percent reduction from the raw coal as mined. 

This alternative would provide some relief for coals with unusually high Hg content while still

achieving meaningful emission reduction.

According to Commenter OAR-2002-0056-5535, industry's suggested alternative

percent-reduction format is inappropriate because unit operators can control pollutant input

levels. In the MACT standards for the brick and structural clay products and clay ceramics

manufacturing industries, EPA allowed units to meet either an emissions rate or a percent

reduction standard for hydrogen fluoride (HF) and hydrogen chloride (HCl), but did not provide

the alternative approach for PM (a surrogate for HAP metals). EPA’s reasons for declining to

provide an alternative, percent-reduction standard for PM are equally applicable here: EPA
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decided not to finalize a percent reduction alternative because "a percent reduction standard

rewards those facilities that have high inlet PM loadings...[a situation different] from the percent

reduction standards for HF and HCl because facilities do not typically have options for reducing

the uncontrolled levels of HF and HCl." In other words, a percent reduction alternative is

appropriate when the input levels of the HAP in question are outside the control of the operator. 

When, as here, there are options available to reduce input levels of the HAP being regulated,

however, a percent reduction standard has the perverse effect of rewarding those operators who

do not take prophylactic steps to reduce input levels. For the coal-fired electric generating

industry, as we demonstrated in our initial comments, there are a variety of pre-combustion

techniquesBsuch as coal washingBthat reduce input levels of Hg and other HAP from all coal

types. Allowing an alternative percent reduction approach would reward operators who do not

use such techniques and approaches.

Response:

EPA continues to believe that a percent reduction format is not appropriate for this

rulemaking. As noted in the proposal preamble, in order to accommodate pre-combustion Hg

control technologies, a percent reduction format would require tracking the Hg concentrations

in the coal basically from the mine to the stack, and not just before and after the control

device(s) and could be difficult to implement. We believe that this would require an inordinate,

and possibly unworkable, recordkeeping effort. We believe that the subcategorization approach

and revised emission limits being finalized will address the commenter’s concerns.

Comment:

One commenter (OAR-2002-0056-2243) stated that the Hg limits should be set as a

minimum percent removal in place of a specific emission limit. This is consistent with EPA’s

earlier efforts at SO2 control.

Response:

As noted earlier, EPA has proposed to eliminate the percent reduction portion of the

subpart Da emission limits for SO2 emissions from coal-fired power plants and does not believe

that a percent reduction format is appropriate for this rulemaking.

Comment:

One commenter (OAR-2002-0056-3288) supported an emission rate limit rather than a

percent reduction requirement. A percent reduction format will likely result in higher overall

emissions which would end up being more costly for consumers and would create a bias against

cost effective, environmentally-preferable subbituminous coal. An emissions limit will result in the

highest level of overall reduction at a lower cost to consumers, avoid massive disruptions to the

coal industry, and encourage continued development of effective pre-combustion technologies.

Response:
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EPA concurs that an emission rate limit is more appropriate than an emission reduction

requirement.

3.2.3.3 Output-based Format

Comment:

One commenter (OAR-2002-0056-3435) recommended that the EPA establish

input-based standards for Hg control. Although the output format promotes energy efficiency,

this is not the purpose of a standard for protection of public health and the environment. The

EPA makes an economic argument for an output-based format (69 FR 4699) which contradicts

the purpose of promoting efficiency through emission standards. The output-based limit uses an

assumed efficiency and will be based on output energy. Using output energy (gross or net) can

introduce error in representing actual emissions because of the variability in assuming efficiency

and the introduction of other variabilities inherent to the standard, especially compared to heat

input determinations. Mercury is present in the gas in such trace amounts that the most stringent

measurement standard of the emission rate should be used. A lb/TBtu standard has less error than

a lb/MWh standard and will better represent emission levels. Because heat input is already

required for the Acid Rain Program, this format is already standard and places no additional

burden on the plants.

Response:

EPA believes that an output-based standard is consistent with the intent of section 111

and will serve to protect the public health and the environment, as well as promote energy

efficiency. Further, EPA has revised, or is in the process of revising, subpart Da to place the

emission limits for PM, NOx, and SO2 in an output-based format.

Comment:

One commenter (OAR-2002-0056-2161) recommended that the EPA provide the

maximum encouragement for energy efficiency by promulgating a standard based upon

lb/MWh-net instead of lb/MWh-gross. The true efficiency of a coal-fired unit is based upon how

much of its energy is available after reduction by internal station power consumption, measured as

MWh-net. Therefore, if EPA’s goal is to help encourage increased energy efficiency with the Hg

standard, the most effective way to do this is to utilize the net production.

One commenter (OAR-2002-0056-3449) recommended changing the proposed format for

the output based standards from lb/MWh "gross" to lb/MWh "net" to encourage efficiency. A net

standard, like the one in their State, should lead to lower emissions from electricity productions.

Response:

EPA agrees with the commenters that using the "net" output would more adequately

address energy losses within the utility station. However, our intent is to encourage existing
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units to utilize the output-based format also. Therefore, we believe that the lb/MWh-gross

format is more appropriate for this rulemaking because implementation on existing units could

require significant and costly additional monitoring and reporting systems because the energy

output that is used for internal components (and not sent to the grid) cannot be accounted for by

simply installing another meter. EPA agrees that new units could accommodate the lb/MWh-net

format but we do not want to institute a dual set of formats for the same industry and the

implementation and compliance problems that would result.

Comment:

Two commenters (OAR-2002-0056-3406, -5445) supported the use of an output-based

standard because this approach rewards efficiency and allows the market to make decisions about

fuel choices rather than favoring one type of generation over another. The commenters also

supported the proposed use of gross, as opposed to net, plant energy output. Commenter OAR2002-0056-3406 stated that gross energy output is the amount of energy generated before internal

energy consumption and losses are considered. Net electricity generation is the amount of energy

that is delivered to the energy grid after taking into account internal consumption losses. The

commenter notes that those losses can be significant, and can actually increase with the operation

of emission controls such as SCR and scrubber units. The commenter concluded that the use of

net plant energy output would penalize a power plant that installed additional control equipment,

which the commenter takes to be contrary to the intent of the rule.

One commenter (OAR-2002-0056-1969) stated that EPA has suggested that the

output-based standard be calculated on gross rather than net energy output basis. According to

the commenter, a net energy output based standard is certainly the most comprehensive and is

able to capture energy efficiency improvements for the entire plant. The commenter states,

however, that EPA is correct in concluding that calculation of emissions on a net energy output

basis is a more complex task. The commenter asserts that although that concern may not be the

sole reason to exclude a net energy output standard, a gross energy based standard is able to

capture most efficiency improvement projects and is less burdensome to administer. The

commenter supports an output-based standard based on a gross energy output basis.

Response:

EPA concurs with the commenters. However, we note that a practice of overall energy

efficiency would also look to utilizing more efficient equipment on the SCR and scrubber units,

although we do not believe that use of lb/MWh-net is appropriate here.

Comment:

Two commenters (OAR-2002-0056-1969, -2850) supported the option of either an

input-based or a gross output-based standard for existing units as long as the mathematical

relationship between the two standards is equitable. The output-based standard offers a

regulatory incentive to improve unit efficiency. Any output-based standard should give

consideration to average unit efficiency subcategorized for unit type so that differences in installed
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design can be reflected when establishing Hg control stringency. An output-based standard

should not be periodically revised for existing units because doing so would discourage energy

efficiency as a compliance option for existing sources.

Response:

EPA believes that the conversions used in developing the final emission limits are

equitable and appropriate. However, EPA does not believe that it is appropriate to average unit

efficiency subcategory-by-subcategory at this time.

Comment:

One commenter (OAR-2002-0056-4132) objected to using an output-based emission limit

format for old or new sources. Output-based emission standards are not desirable. First, they

draw in complexities like gross electrical output, net electrical output, and disassociated

monitoring systems. Secondly, they deal poorly with systems that choose to use steam for a

variety of auxiliary functions, because they may have a corresponding loss of electrical output. 

Thirdly, for facilities involved with some level of cogeneration, complex and unnecessary

accounting regimes are required. Input-based emission standards work well, and should be

available to all emission units.

Response:

EPA disagrees with the commenter. Although output-based formats do require different

considerations than input-based formats, all formats involve a certain amount of complexity. 

The final rule addresses the issues related to cogeneration units in a manner similar to that done

under subpart Da for NOx emissions from such units. EPA continues to believe that outputbased emission limits encourage energy efficiency, are consistent with other Agency actions on

subpart Da, and are appropriate for this rulemaking.

Comment:

One commenter (OAR-2002-0056-3210) disagreed with the method EPA used to convent

input-based limits to output-based limits. The commenters stated that the EPA should establish

output emission limits for Hg using actual emission data, not a calculated value from a heat inputbased standard.

Response:

The conversion used by EPA was based on that used in the subpart Da NOx revisions,

which were based on data received from new facilities.

Comment: 

Several commenters (OAR-2002-0056-3210, -1474, -2721, -3437, 3459) disagreed with
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the power plant efficiency values EPA used to convent input-based limits to output-based limits. 

The commenters stated that the plant percent efficiencies used by the EPA are too low.

 One commenter (OAR-2002-0056-3437) used the 1999 National Electric Data System to

estimate the efficiency of the 69 coal-fired units greater than 25 MW that are potentially affected

by the proposed rule. The average efficiency is 34 percent for existing units. The commenter

provided data showing that new units can achieve efficiencies significantly greater than 35 percent

with IGCC units operating at 42 to 47 percent efficiency and certain pulverized units achieving

40 percent efficiency.

Several commenters opposed the use of 35 percent efficiency as the baseline efficiency for

new units. One commenter (OAR-2002-0056-1474) stated that the baseline efficiency should be

set at 35 percent to move power plants toward higher efficiencies. Commenter OAR-2002-0056-

2721 disagreed that 35 percent efficiency is an appropriate baseline for all new units. The

commenter stated this may be a good assumption for higher quality fuels but not for the low rank

fuels. According to Commenter OAR-2002-0056-3459, EPA used a 35 percent baseline

efficiency for new units and did not provide any support for their assumption. The commenter

stated that the EIA assumes that a new scrubbed coal plant with SCR will have an efficiency of 38

to 40 percent. For new IGCC units, the EIA assumes 42.5 percent efficiency.

Response:

EPA is unclear about the reference to "69 coal-fired units...that are potentially affected

by the proposed rule." Only new units would be impacted under the section 111 approach. EPA

used data from the EIA (OAR-2002-0056-0017) that provided average coal-fired power plant

efficiencies over the period 1935 to 1996 for all boilers and fuels. The 35 percent value chosen

is higher than that achieved in all but 2 of those years.

3.2.4 Numerical Emission Limits

3.2.4.1 General

Comment:

Several commenters (OAR-2002-0056-2843, -2897, -2911, -3324) stated concerns that

the proposed emission limits for new sources are unjustifiably stringent citing general reasons

including the control technologies needed to comply with the standards have not been adequately

demonstrated, the controls are too costly to implement, and the standards would prevent the use

of much of the coal resources in the U.S.

Many commenters (OAR-2002-0056-1692, -1804, -2068, -2224, -2243, -2264, -2365,

-2431, -2661, -2835, -2891, -2898, -2907, -2948, -3200, -3403, -3432, -3514, -3517, -3560)

stated concerns that the proposed emission limits would adversely impact the construction of new

coal-fired power plants in the U.S. Reasons cited by the commenters include the following. The

proposed Hg emission standards are at levels that are not be achievable with currently available
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technology except for the lowest Hg content coals. This would preclude the ability of new units

to combust coal from many seams that have high Hg content levels. The proposed limits fail to

account for variability in the Hg content from coals mined from a given seam. Also, no vendors

of control technology are willing to guarantee Hg removal at the rates needed to achieve the

proposed emission levels. No company would make a large capital investment in a new plant if

performance guarantees to meet required environmental standards were not available. Financial

institutions will be very wary of participating in projects that are given emission limits that cannot

be guaranteed by equipment suppliers and whose limits will be difficult to verify. Additionally, if

facilities are forced to use alternative coal sources, it could dramatically increase the cost of the

fuel and decrease the economic viability of the units, also impacting the decision to construct the

unit.

Several commenters (OAR-2002-0056-1952, -2331, -2560, -2725, -2833, -2897, -3200,

-3257) stated concerns that the proposed emission limits would require base load electric utility

generating units to switch to firing natural gas to ensure compliance with the standards. 

Commenters stated that forced fuel switching from coal is unacceptable as a national energy

policy. It would adversely impact natural gas supplies and costs to other natural gas users. It is

important that EPA set emission rates that maintain coal as a major fuel source option in a

diversified national energy program.

One commenter (OAR-2002-0056-2210) stated that the EPA’s proposed limits for new

sources, under either a MACT or cap-and-trade (NSPS) approach, are unduly stringent and

would preclude the use of many U.S. coalsBbituminous, subbituminous and lignite. Unrealistic

new source limits could present an insurmountable barrier to the construction of new, low-cost

coal powered generation, conflicting with the Administration’s energy policies favoring the

development of all forms of domestic energy. The proposed emission limits for new plants need

to reflect the emission performance that can be expected from different coal ranks at plants

equipped with state-of-the-art emission controls, and must ensure that all U.S. coals may be

utilized at such new plants. The U.S. can ill afford to create artificial barriers to the development

and use of its largest domestic, fossil energy resource.

One commenter (OAR-2002-0056-2160) stated that any revised rules should be fuel

neutral (equitable for all geographic regions and coal ranks), reduction requirements should be

based on reasonable estimates of when technology will be available to meet the limits (and

consider economic and time constraints), and take into account the effect of the inherent

variability of coals with respect to Hg content, combustion characteristics, and control system

performance.

Several commenters (OAR-2002-0056-1175, -1658, -1781, -1783, -1848, -1861, -1863,

-2333, -2924) stated that the EPA’s proposed limits are more stringent than those recommended

by industry as part of the workgroup recommendations. The proposed limits do not reflect the

level of control that is technically achievable.

Response:
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As stated in the preamble, EPA has re-analyzed the data collected in the 1999 ICR and

examined the Hg limits issued in recently issued permits to establish new source NSPS Hg

emissions limits for five subcategories of Utility Units. Based on these findings, EPA believes

that the revised new-source NSPS Hg emission limits are reflective of the level of Hg control that

is currently technically achievable for these subcategories.

Comment:

Several commenters (OAR-2002-0056-2871, -2889) stated that the proposed limits are

flawed because EPA failed to consider all available technologies. Activated carbon injection is

commercially available and widely recognized as a viable control for Hg. It has been

demonstrated with pilot and full-scale demonstration projects on coal and has been used for over

10 years on other large combustion projects. States are now requiring it on new coal-fired units

for Hg control. EPA’s failure to consider this technology is inconsistent with its past approaches

for developing Hg limit for combustion sources and EPA provides no justification for the change.

One commenter (OAR-2002-0056-2108) stated there is not adequate justification for not

examining more control technologies/options in setting the emission limits for new sources.

Response:

EPA disagrees with the commenters. As noted earlier, EPA does not believe that ACI, or

any other Hg-specific control technology, has been adequately demonstrated under the criteria

of section 111 to be considered viable control options for new sources under this rulemaking. 

However, we do believe that the cap-and-trade approach being taken will allow such

technologies the necessary time to be fully proven for widespread commercial installation.

Comment:

One commenter (OAR-2002-0056-2422) stated that the EPA’s proposed limits for new

sources must be revised to fully account for variability in the performance of the "best

performing" unit, regardless of whether it imposes an emissions limit or a "cap-and-trade"

program. Also, the proposed emission limits for new plants need to reflect the emission

performance that can be expected from different coal ranks at plants equipped with state-of-theart emission controls, and must ensure that all U.S. coals may be utilized at such new plants. The

U.S. can ill afford to create artificial barriers to the development and use of its largest domestic

energy resource.

Response:

Although use of the "best performing unit" is not applicable under CAA section 111, EPA

believes that the reanalysis noted earlier adequately addresses the concerns related to

variability, use of different coal ranks, and emission controls noted by the commenters.

Comment:
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One commenter (OAR-2002-0056- 2441) stated that the EPA ignored their workgroup

position on limits for existing and new sources that would allow the use of all coals. The

proposed limits for western subbituminous and lignite coal are substantially less stringent that the

limits recommended by the industry workgroup participants, the proposed limit for eastern

bituminous coal is 9 percent more stringent. More than half of eastern bituminous coal would

require greater than 75 percent removal to meet the limit (beyond EPA’s estimate of 50 to

70 percent) removal capability for current technologies). In contrast, the proposed limit for

western subbituminous coal gives PRB coal a free ride in that most of 62 percent of these coals

could meet the limit without any controls. This would encourage cherry picking of western coal

that could be sold without the need to reduce emissions. This preferential treatment would invite

massive fuel switching to western coal and, thus, a massive shift of coal production from eastern

to western states. This would have a disastrous economic impact on coal mining. For existing

sources, 84 to 100 percent of the bituminous coal mined in eastern states could not be used under

the NSPS limits, even at 80 percent removal.

Response:

EPA believes that the emission limits developed through the reanalysis of the data will

address the concerns noted by the commenter and provide equitable treatment for all coal ranks.

Comment:

One commenter (OAR-2002-0056-2068) stated that the EPA should set a separate

emission limit for fluidized-bed combustors.

Response:

As noted earlier in this document, EPA does not believe that the data justify a separate

subcategory for FBC units and, thus, no separate emission limit has been established for FBC

units utilized in the bituminous, subbituminous, and lignite subcategories.

Comment:

One commenter (OAR-2002-0056-2913) stated that the proposed limits based on the use

of wet limestone scrubbers for Hg control do not include an allowance for the Hg content of the

limestone used as the sorbent material.

Response:

Because the emission limits established are based on Hg testing conducted at the stack

(i.e., following any limestone injection into the wet- or dry-scrubber), EPA believes that any Hg

contained in the limestone has been accounted for in the revised emission limits.

Comment:
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One commenter (OAR-2002-0056-2108) stated that new units should be required to

reduce Hg emissions by 90 percent regardless of fuel type.

One commenter (OAR-2002-0056-3449) recommended that emissions limits for all new

units (regardless of the rank of coal) be determined on a case-by-case basis and be no higher than

the proposed limit for new bituminous coal units, along with a 90 percent control option to

address high Hg coals.

Response:

As noted earlier, EPA does not believe that a percent reduction format, or combination

format including percent reduction, is appropriate for this rulemaking. Further, EPA believes

that it is consistent with the criteria of CAA section 111 to establish the emission limits for each

subcategory based on information available for each subcategory which is the procedure

followed for this rulemaking. Nor does EPA believe that CAA section 111 allows for a case-bycase determination of new-source NSPS emission limits as suggested by the commenter.

Comment:

Commenter OAR-2002-0056-2922 stated that it is not clear why such a strange mix of

units is required throughout the proposed rules. The commenter found lb/TBtu, 10-6 lb/MWh,

ounces, tons, MMBtu, etc. For example, it does not make sense for the State allocations to be

done in factional tons while the unit allocations are in ounces. Why not use ounces for both?

Response:

EPA agrees with the commenter and has standardized the units of measure as much as

possible in the final rules.

3.2.4.2 Approach to Setting New-source Limits

Comment:

Two commenters (OAR-2002-0056-2422, -2862) stated that the EPA proposed the same

numerical limits for new source MACT under CAA section 112 and the alternative NSPS under

CAA section 111. Under section 112, the new source MACT limit should "not be less stringent

than the emission control that is achieved in practice by the best controlled similar source." Under

section 111, NSPS should "reflect the degree of emission limitation and the percentage reduction

achievable through application of the best technological system of continuous emission reduction

(taking into consideration the cost of achieving such emission reduction, any nonair quality health

and environmental impact and energy requirements)." Limits under both sections of the CAA

begin with an assessment of what limit is achievable in practice with the best available controls,

but the NSPS goes on to consider cost, energy use and non-air impacts. Accordingly, it is

inappropriate and inconsistent with the CAA for the EPA to establish an NSPS requirement based

on an analysis undertaken pursuant to the requirements of CAA section 112.
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Response:

EPA agrees with the commenters who indicated that the new-source NSPS limits were not

established in a manner consistent with the requirements of CAA section 111. We have,

therefore, re-analyzed the information collection request (ICR) data collected in 1999, and

examined the Hg limits in recently issued permits. Based on this refined analysis, we have

arrived at the following new-source NSPS Hg emission limits for the five subcategories:

Bituminous units: 0.0026 ng/J (21 x 10-6 lb/MWh);

Subbituminous units:

- wet FGD units 0.0055 ng/J (42 x 10-6 lb/MWh);

- dry FGD units: 0.0103 ng/J (78 x 10-6 lb/MWh);

Lignite units: 0.0183 ng/J (145 x 10-6 lb/MWh);

Coal refuse units: 0.00017 ng/J (1.4 x 10-6 lb/MWh);

IGCC units: 0.0025 ng/J (20 x 10-6 lb/MWh).

Documentation for this re-analysis may be found in the e-docket (OAR-2002-0056).

To establish the revised new-source limits, EPA re-examined the 1999 ICR data which

includes an estimate of the Hg removal efficiency for the suite of emission controls in use on

each unit tested. The EPA focused primarily on the 1999 ICR data because it is the only test

data for a large number of Utility Units employing a variety of control technologies currently

available to the Agency and because there is very limited permit data for new or projected

facilities from which to determine existing Hg emission limits. (The EPA has historically relied

on permit data in establishing new-source NSPS limits because it believes that such limits

reasonably reflect the actual performance of the unit.) We analyzed the performance of

currently installed control technologies in the respective subcategories in an effort to identify a

best adequately demonstrated system of emission reduction, also referred to as a best

demonstrated control technology (BDT), for each subcategory. To do this, we determined the

combination of control technologies that a new unit would install under the current NSPS to

comply with the emissions standards for PM, SO2, and NOx. Based on the available data, units

using these combinations of controls had the highest reported control efficiency for Hg

emissions. Thus, we determined that BDT for each subcategory of units is a combination of

controls that would generally be installed to control PM and SO2 under the NSPS. For

bituminous units, BDT is a combination of a fabric filter and a FGD (wet or dry) system. For

subbituminous units, BDT was determined to be dependent on water availability. For

subbituminous units located in the western U.S. that may face potential water restriction and,

thus, do not have the option of using a wet FGD system for SO2 control, BDT is a combination

of either a fabric filter with a spray dryer absorber (SDA) system or an ESP with a SDA system. 

For subbituminous units that do not face such potential water restrictions, BDT is a fabric filter

in combination with a wet FGD system. For lignite units, BDT is either a fabric filter and SDA

system or an ESP with a wet FGD system.

To determine the appropriate achievable Hg emission level for each coal type, a

statistical analysis was conducted. Specifically, the Hg emissions limitation achievable for each
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coal type was determined based on the highest reported annual average Hg fuel content for the

coal rank being controlled by the statistically-calculated control efficiency for the BDT

determined for that fuel type. The control efficiency for BDT was calculated by determining the

90th percentile confidence level using the one-sided z-statistics test (i.e., the Hg removal

efficiency, using BDT, estimated to be achieved 90 percent of the time). The data used consisted

of stack emission measurements (pounds Hg per trillion Btu, lb Hg/TBtu) for each unit, the

average fuel Hg content for the fuel being burned by that unit during the test (parts per million,

ppm), and the highest average annual fuel Hg content reported for any unit in the coal rank. 

Because the Hg emissions from any control system is a linear function of the inlet Hg (i.e., Hg

fuel content), assuming a constant control efficiency, the reported highest annual average inlet

Hg was adjusted to determine the potential maximum Hg emissions that would be emitted if BDT

was employed. The calculated 90th percentile confidence limit control reduction for each

subcategory, based on the calculated highest annual average uncontrolled Hg emissions, in lb

Hg/TBtu, for the subcategory was determined to be the new source emission limit. Finally, the

new source limit for IGCC units and its justification remains unchanged from the limit proposed

in January 2004 (69 FR 4652).

EPA also evaluated recent, available permit Hg levels for comparison with the limits

presented above. EPA does not believe that the use of permit Hg limits is appropriate for

independently establishing new-source NSPS emission limits because of the limited number of

permits issued with Hg emission levels and the limited experience of both State permitting

authorities and the industry itself with establishing appropriate permit conditions. However,

comparison of the available permit limits with those developed by EPA is a valid "reality check"

on the appropriateness of EPA’s limits. Available permits on bituminous-fired units have Hg

emission limits ranging from approximately 20 x 10-6 lb/MWh to 39 x 10-6 lb/MWh; those for

subbituminous-fired units range from 11 x 10-6 lb/MWh to 126 x 10-6 lb/MWh. Considering the

limited number of permits and the limited experience in developing appropriate Hg limits for

those permits, EPA believes that its final new-source NSPS Hg emission limits are in reasonable

agreement with these permits. Insufficient permit information is available to do a similar

comparison for lignite- and coal refuse-fired units but we have used the same analytic procedure

for these subcategories.

Further, EPA concurs with those commenters who indicated that we had overstated the

variability in the context of the proposed CAA section 111 NSPS limits by using both a rigorous

statistical analysis and a 12-month rolling average for compliance. Therefore, for the final rule,

while we have retained the 12-month rolling average for compliance, we have used the annual

average fuel Hg content in the ICR data to establish the NSPS limits. Given the favorable

comparison with the available permit data, we believe that variability has been adequately

addressed. Documentation for the new-source limits is provided in "Statistical Analysis of

Mercury Test Data to Determine BDT for Mercury" (OAR-2002-0056-6192).

3.2.4.3 Bituminous Coal-fired Units

Comment:
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Two commenters (OAR-2002-0056-2160, -3199) stated that in the supplemental notice,

the EPA stated that 50 to 70 percent Hg removal technologies may be commercially available

after 2010 which could address emissions from bituminous coal. The proposed emission limits

would require about 94 percent reduction from the average bituminous coal. This is higher than

EPA’s assessment of the Hg-specific control technologies which would be available at the time of

implementation. The standards should be based on the emission reduction that is achievable at the

time of implementation. Reductions should be based on realistic estimates of when technology

will be available and include consideration of the economic and time constraints in meeting the

limits.

One commenter (OAR-2002-0056-3445) stated that the control level required of new

sources under either of EPA’s proposed regulatory approaches would make it nearly impossible

to build new bituminous coal-fired power plants.

One commenter (OAR-2002-0056-2862) stated EPA’s proposed emission limit for new

bituminous units contradicts the Agency’s findings about achievable Hg reductions and would

prevent the use of many coals. If the Hg emission standard for new bituminous coal units is set at

the proposed 0.6 lb/TBtu emission rate, coals from many regions of the country could not be used

in new coal-fired plants because Hg removal in excess of 90 percent would be required. This

would eliminate billions of tons of coal from the nation’s energy supply. The commenter included

an analysis that the commenter stated demonstrated that the majority of bituminous coal supplies

available to utilities in the Midwest would be unable to achieve the proposed emission standard.

The bituminous coals used in the analysis represent typical coals (coals from West Virginia,

Pennsylvania, Kentucky, Illinois and Colorado) that a new unit in the Midwest would burn.

Response:

As noted above, EPA has reanalyzed the data and revised the new-source NSPS Hg

emission limits which should address the commenter’s concerns.

Comment:

One commenter (OAR-2002-0056-2064) stated that the proposed limits for bituminous

coal are above the levels that are technically achievable and cost effective. For bituminous coal,

proposed limit would require a 77 percent reduction but this is well below the average 90 percent

control demonstrated by fabric filters. This State recently permitted a plant for 90 percent

removal for bituminous coal using a fabric filter and wet FGD. These controls are applicable to

existing and new units.

Response:

As noted elsewhere, EPA has reanalyzed the data and revised the new-source NSPS Hg

emission limits based on the use of current technologies.

3.2.4.4 Subbituminous Coal-fired Units
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Comment:

One commenter (OAR-2002-0056-2535) stated that the Wyoming PRB subbituminous

coal, which is the most widely used subbituminous coal, should not be used to establish Hg

emission limits for all subbituminous coal-fired plants. Instead, Colorado, Montana, and New

Mexico subbituminous coals should be used. These coals are typically higher in caloric (Btu)

content, and resemble a bituminous coal. Wyoming PRB coal grades out as a Subbituminous C

coal, while most other western subbituminous coals grade out as Subbituminous A (according to

ASTM standards). For the proposed limit, an analysis by the National Mining Association

estimates that 41 percent of subbituminous coals would not be able to meet the limit with any

degree of confidence due to the high variability in Hg content of the coal.

Response:

EPA has used the data and information available, including permit information, to revise

the new-source NSPS Hg emission limits for all of the subcategories, including subbituminous. 

We believe that these revised limits will accurately reflect the level of control expected in each

subcategory. EPA does not understand why PRB coal should be excluded from this analysis,

particularly given the fact (acknowledged by the commenter) that it is the most widely used

subbituminous coal.

Comment:

One commenter (OAR-2002-0056-3437) opposed the proposed emission limit for

subbituminous coal. The proposed limit would require little or no control at some power plants in

Indiana that use subbituminous coal or a blend of bituminous and subbituminous coal. This

disparity also can cause bituminous units to switch to subbituminous coal or a blend of the two,

which would increase Hg emissions above 1999 levels.

One commenter (OAR-2002-0056-3449) stated that the proposed limit for subbituminous

coal-fired units is three times higher that the proposed limit for bituminous coal. The proposed

limit is so high that it would result in little, if any, Hg reductions. The ICR data shows that the

proposed limit is about the average Hg content of subbituminous coal, assuming all Hg in the coal

is emitted. With co-benefits of existing controls, over 80 percent of subbituminous coal is likely

to be burned without any additional control. About two-thirds of the subbituminous coals have

Hg content less than 5.8 lb/TBtu (the proposed limit). Assuming a 30 percent co-benefit of

minimal existing controls, this results in equivalent Hg content of more than about 8.3 lb/TBtu for

which added control would be needed. Only about 15 percent of subbituminous coal is above this

level. And, when long term averaging is considered, even fewer subbituminous coal-burning units

are likely to required controls. Even if no units switch from bituminous to subbituminous coal,

Western states will obtain little or no Hg reduction. If widespread switches to subbituminous coal

occur, the East will have much higher Hg emissions than EPA projects.

Response:
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EPA has used the data and information available, including permit information, to revise

the new-source NSPS Hg emission limits for all of the subcategories, including subbituminous. 

We believe that these revised limits will accurately reflect the level of control expected in each

subcategory.

Comment:

Several commenters (OAR-2002-0056-2064, -2198) stated that the proposed limits for

subbituminous coal-fired units are too high. In Wisconsin, only one plant in the State (the largest

unit with the highest emission rate) would be required to reduce emissions at all; this plant would

need to reduce emissions by 40 percent. Plants firing subbituminous coal should be capable of

achieving 50 to 83 percent removal from fuel input based on use of a fabric filter alone. One

State recently permitted one coal-fired plant at 83 percent removal for subbituminous coal

(1.70 lb/Btu) using a fabric filter (dry FGD system) with sorbent injection. This control

equipment is applicable to existing and new units.

Response:

As noted above, EPA has used the data and information available, including permit

information, to revise the new-source NSPS Hg emission limits for all of the subcategories,

including subbituminous. We believe that these revised limits will accurately reflect the level of

control expected in each subcategory. Further, it has also been noted that EPA does not believe

that ACI is a commercially available technology upon which a CAA section 111 standard can be

established.

Comment:

One commenter (OAR-2002-0056-2535) stated that the AES Hawaii power plant should

not be used to set the subbituminous emission limit for two reasons. First, the plant is an FBC

unit, which relies on a fundamentally different combustion process and is not representative of the

type of plant that burns subbituminous coal in the 48 contiguous States. Second, the plant burns

Indonesian subbituminous coal, which is also not representative of the subbituminous coal burned

in the 48 contiguous States. In addition to the coal not being representative, EPA must recognize

that coal is our largest reserve of domestic fossil fuel, and should not be using a foreign coal to set

a domestic standard. This goes against EPA’s stated principle of not considering fuel switching as

a viable method for setting a MACT floor. Use of Indonesian coal to set the MACT floor will

result in more domestic coal being displaced from use in domestic coal-fired power plants.

Response:

The AES Hawaii facility was one of nine subbituminous-fired units used in establishing

the revised new source NSPS emission limits. EPA did not feel that it would be appropriate to

exclude this unit from the reanalysis because (1) at least one new subbituminous-fired unit has

received a permit based on the use of FBC technology in Utah (and, thus, FBC technology is

representative of the type of plant that could burn subbituminous coal in the contiguous 48
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States), and (2) Indonesian coal was reported to be used by at least two other utility units in

1999 (and, thus, could be used by other units in the U.S.).

Comment:

One commenter (OAR-2002-0056-3437) requested that EPA examine the recent State

MACT/BACT decisions that have required ACI. In particular, Iowa set a case-by-case MACT

limit equal to 1.7 lb/TBtu based on ACI with 83 percent control efficiency using PRB coal.

Response:

As noted earlier, EPA does not believe that Hg-specific control technologies, including

ACI, are commercially available for nationwide application to the coal-fired utility industry. 

Installation of such technologies on a limited number of units (e.g., the one cited) is possible and

will serve to advance the technologies such that they are widely for use in compliance with the

phase II cap.

3.2.4.5 Lignite-fired Units

Comment:

One commenter (OAR-2002-0056-3469) supported the proposed limits. The commenter

stated that despite flaws in the ICR data used to determine the emission limits, they supported the

emission limits for existing units of 9.2 lb/TBtu for Fort Union lignite-fired units.

Another commenter (OAR-2002-0056-2115) supported the proposed limit for lignite

because it is the same level that would be required under the Clear Skies proposal. An

unattainable Hg limit would result in a practical ban on lignite as fuel. Texas mines over

40 million tons of lignite coal per year for use as power plant fuel.

Response:

EPA concurs that the standards must be achievable by all coal ranks.

Comment:

One commenter (OAR-2002-0056-3514) stated that currently, no technology has been

shown to be effective in capturing Hg from lignite coals. Although EPA has proposed for lignite

more reasonable emission limits, it still has not been shown that these levels can be met. Lignite

and other low-rank western coals face additional obstacles that do not affect other coals, namely

higher ash, lower Cl and higher elemental Hg content. Accordingly, these factors make it

impossible, at least currently, to attain the removal percentages being achieved with other coals.

One commenter (OAR-2002-0056-2054) stated that the EPA has not proposed standards

for new lignite-fired units on a level of performance that is "achievable" by a unit that is "similar"
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to most new lignite-fired units. The commenter stated that the highest Hg removal rate of any

lignite-fired plant in the ICR data was 21 percent, and the plant that achieved this removal rate,

Stanton Station, is a relatively small, older plant that is definitely not "similar" to a new

lignite-fired unit. According to the commenter, the agency did not base its new unit standard on

performance, but rather on the lowest Hg coal; the result of this basis is to eliminate the vast

majority of lignite reserves from any new units. The commenter asserts that the choice of best

performing unit should comply with the direction given by the DC Circuit Court in National Lime

Association v. EPA, 627_F.2d 416, 431n. 46(1980). The commenter stated that this best

performing unit is based, according to the court, on a level of performance that can be achieved

"under the most adverse circumstance which can reasonably be expected to occur." Therefore,

the "best controlled" source must be taken into account to predict emissions from any reasonable

situation, including different lignites.

Response:

As noted above, EPA has revised the new-source NSPS Hg emission limits based on a

reanalysis of the available information, including permits. We believe that the revised emission

limits address the commenters’ concerns.

Comment:

One commenter (OAR-2002-0056-3478) requested that any emission limits for lignitefired power plants include Gulf Coast lignite as a separate subcategory. Based upon their

evaluation of the tested units, the commenter requested that EPA set any limit for Gulf Coast

lignite-fired units at a rate no less than 28 lb/TBtu. The commenter stated that if EPA does not

establish a separate subcategory for Gulf Coast lignite with a higher standard, then a percent

reduction option and/or a "safety net" must be offered so that units in Texas, Louisiana, and

Mississippi can continue to utilize locally mined lignite as fuel.

Two commenters (OAR-2002-0056-2915, -3463) stated that Gulf Coast lignite cannot

achieve the reductions required to meet the proposed standard for lignite Because it was set with

units firing North Dakota lignite. One commenter (OAR-2002-0056-2915) stated that coal-fired

utility units already face emissions control requirements that are duplicative, contradictory, costly,

and complex, and create enormous uncertainty for future investment and that adding Hg

emissions regulations will create even greater challenges for coal-fired utility units, and this is

especially true for Gulf Coast lignite because its unique physical composition makes reductions in

Hg emissions from utility units firing it very difficult to achieve and more difficult to achieve than

for non-lignite coal-fired utility units.

One commenter (OAR-2002-0056-4891) added that the proposed Hg rule rules should be

revised to better recognize the high concentration and type of Hg present in Gulf Coast lignite and

the difficulties associated with controlling its Hg emissions as compared to Hg emissions from

other coal ranks. The commenter stated that without significant changes to the proposed Hg rule

to lessen compliance costs, it is likely that most Gulf Coast lignite mines and some Gulf Coast

lignite-fired power plants will ultimately be forced to close. According to the commenter, power
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grid stability would be compromised without the generation capacity provided by Gulf Coast

lignite-fired power plants, resulting in the potential for frequent and sustained power outages that

would undermine economic stability and prospects for economic growth.

One commenter (OAR-2002-0056-3478) believed the Hg content in Gulf Coast lignite is

higher than the ICR data indicate, a more accurate analytical method for Cl in coal demonstrates

that the Cl content in Gulf Coast lignite is much lower. The commenter also believed this revised

information on Cl content may explain why lignite combustion results in a significant percentage

of elemental Hg being emitted.

One commenter (OAR-2002-0056-2929) expressed concern that facilities burning Texas

lignite will be unable to comply with the proposed Hg emission limits because the best performing

lignite units all fire cleaner-burning North Dakota lignite.

Response:

As noted elsewhere, EPA does not see a basis at this time for further subcategorizing

lignite coals.

Comment:

Several commenters expressed concern over the impacts resulting from the stringent rules

for lignite coals. The commenters (OAR-202-0056-1692, -2915, -3510, -3543, -4891) were

concerned that stringent rules for lignite coal would result in fuel switching and have negative

impacts on lignite-burning units. One commenter (OAR-2002-0056-2915) stated that EPA must

ensure that the Hg rule does not disadvantage coal, especially Gulf Coast lignite, because doing so

would aggravate the already precarious natural gas supply and price situation. The commenter

stated that if the Hg rule was to even slightly decrease the dependence on coal, the natural gas

supply and the price problems would increase. According to the commenter, it is estimated that

forced replacement of coal with natural gas as fuel in electric generation would increase the

demand for natural gas by about 35 percent and would increase natural gas prices by about

33 percent. According to one commenter (OAR-2002-0056-3510), natural gas is not available to

utilities in the winter when it is apportioned to residential users. One commenter

(OAR-2002-0056-1692) stated that the proposed lignite limit of 9.2 lb/Btu is so stringent that it

would preclude many southern lignite coals from future use and would promote the use of natural

gas, especially in smaller plants, where the high cost of controls may not be justified given the

anticipated life of the plant. According to another commenter (OAR-2002-0056-3543), the

current rule structure could cause generators to switch coal ranks, primarily from lignite and

subbituminous to bituminous coal with resultant economic impacts. Without a higher limit for

Gulf Coast lignite, commenters (OAR-2002-0056-3510, -4891) stated that their State economies

will suffer because lignite is an important fuel in their State. One commenter

(OAR-2002-0056-2915) stated that utility units designed to burn lignite cannot easily, quickly, or

cheaply switch to burn other fuel types. According to the commenter, lignite’s low heat content

and its other properties would require time consuming and expensive alterations to allow them to

burn non-lignite fuels. The commenter further stated that lignite-fired utility units are often
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parties to long-term contracts to purchase the lignite; therefore, even if such utility units could no

longer burn lignite, they would still be required to purchase it pursuant to any such long-term

contracts. The commenter also added that Gulf Coast lignite-fired utility units in Texas are

located on the property from which the lignite is mined and that for many such units, rail lines that

could be used to transport other types of fuel to the site would have to be constructed.

Response:

As noted elsewhere, EPA has reanalyzed the new-source NSPS limits and believes that

the emission limit being finalized is achievable and appropriate.

Comment:

Several comments addressed the control of Hg from lignite-fired units. Three commenters

(OAR-2002-0056-3327, -3469, -4191) expressed concern regarding the availability of proven

control measures. According to one commenter (OAR-2002-0056-3469), the lack of availability

on the market of proven cost-effective control and monitoring equipment will make compliance

with the proposed regulations difficult for utilities, particularly those burning lignite. The

commenter supported proposals which give utilities flexibility in how they implement controls and

comply with the regulations and which provide incentives to comply as quickly as practical and

make the most cost-effective investments that provide the largest emissions reductions. Thus, the

commenter supported EPA’s proposal to allow utilities to use facility-wide averaging,

system-wide averaging, and use 12-month rolling averages to calculate emissions and demonstrate

compliance. One commenter (OAR-2002-0056-3327) was concerned that despite the progress

made in their State and efforts to continue identifying new technologies to control emissions from

coal-fired power plants, the imposition of the proposed requirements will force the closure of

lignite-fired power plants prior to the time that effective emissions control technology can be

developed and made commercially available.

One commenter (OAR-2002-0056-3478) cited lignite properties in addition to monitoring

technology as the main hindrance to pollution control companies providing a Hg removal

guarantee. Citing the high degree of elemental Hg remaining in flue gases of lignite as well as

lignite’s tendency to have relatively high total Hg content, the commenter believed they have valid

concerns that Hg control for lignite-fired boilers will be more difficult and costly than for

bituminous coal-fired boilers. According to the commenter, coal analysis from one mine indicated

that a 59 - 76 percent reduction in Hg emissions would be required. The commenter also reports

that similarly, if they examine the 70 percent lignite/30 percent PRB data, a weighted average

limit of 8.18 lbs/TBtu would have to be met. According to the commenter, one pollution control

company does have experience with an ACI system supplier that have given guarantees of

50 percent removal for PRB coals at a carbon consumption rate equivalent to an expenditure of

~$5M per year and subject to very specific restrictions and very limited liability, but no such

guarantees to date have been given for lignite-fired plants. The commenter further stated that the

PRB guarantees to date have been predicated upon availability of necessary quantities of suitable

activated carbon, total amount of Hg entering the system, and averaging period allowed to meet

guarantees. According to the commenter, Hg control technologies are highly coal and
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boiler/AQCS configuration dependent, not to mention the issues with test accuracy when

measuring Hg with a concentration six orders of magnitude less than SO2. The commenter stated

that it will only be after multiple demonstrations have been completed before all the anomalies are

sorted out in order for suppliers to take on the risk of Hg removal guarantees.

Response:

EPA believes that the regulatory approach being taken will address the commenters’

concerns, particularly with regard to the flexibility afforded to a company. The flexibility

afforded by the cap-and-trade approach will preclude any concerns about having to arbitrarily

close coal-fired utility units and provide the time necessary to fully develop the emerging Hgspecific control technologies. Further, EPA believes that reliable, cost-effective Hg monitoring

systems are available and will be further refined by the time utilities must be in compliance with

the revised standards.

Comment:

One commenter (OAR-2002-0056-3478) stated that regulations to control SO2 and NOx

will require the installation of pollution controls that will also capture the forms of Hg that tend to

deposit nearby. The commenter stated that, based on testing of SCR performance for Hg cobenefits on a lignite facility in North Dakota, SCR will not provide much, if any, Hg co-benefit

reduction. According to the commenter, SCR technology is ineffective in oxidizing Hg and that

the saltation of calcium and sodium ash deposits fouls the catalyst rendering the SCR technology

ineffective for NOx control.

Response:

EPA believes that the cap-and-trade approach being taken will address the commenter’s

concerns. For the new-source NSPS Hg emission limits, EPA has not assumed any removal

contribution by SCR units on lignite coal.

Comment:

One commenter (OAR-2002-0056-4891) stated that, given the lack of scientific evidence

linking health impacts to Gulf Coast lignite-fired power plant Hg emissions and its insignificant

contribution to Hg emissions relative to other sources and the global Hg emissions pool, there is

no present justification for a regulation with as significant an economic impact as the proposed Hg

rule.

Response:

EPA sees no basis for excluding Gulf Coast lignite from the revised standards.

Comment:
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One commenter (OAR-2002-0056-3398) stated that North Dakota lignite has a lower Cl

content than subbituminous or bituminous coal and that Hg control from lignite is much more

difficult, warranting a higher emission limit.

Response:

EPA concurs that lignite coal exhibits unique combustion and control characteristics

and, as such, has placed lignite in a separate subcategory.

Comment:

Commenter OAR-2002-0056-5535 disagreed that the best-performing lignite units fire

North Dakota lignite and that North Dakota lignite is significantly different from other lignite. 

First, the commenter’s analysis of the best-performing units indicates that TXU’s TNP-One unit,

which burns Texas lignite coal, is the best-performing lignite unit. The commenter used EPA’s

methodology to estimate Hg emissions for every coal shipment fired by TNP-One. When these

estimates are averaged, the average annual emission rate is 1.29 lb/TBtu B the best performance

of any lignite-fired unit. Second, although it is true that Texas lignite has a higher ash content

than North Dakota lignite and that facilities firing Texas lignite are among the biggest Hg emitters

in the U.S., none of these facilities has opted to participate in any of the DOE-sponsored

emissions tests aimed at evaluating Hg control technologies. The Monticello plant, which fires

Texas lignite, is scheduled to be tested during the Phase II DOE tests (mid-2005), but the test

plan excludes the most promising technology for lower ranks coals B halogenated activated

carbon sorbents. Consequently, it will not be possible to compare Monticello’s performance with

that of North Dakota facilities, which have been tested with these sorbents, achieving Hg emission

reductions in excess of 90 percent. In addition, the commenter noted that one facility firing Texas

lignite B the Big Brown plant B has been operating a COHPAC baghouse for a number of years. 

This small add-on fabric filter is the key component of EPRI’s patented TOXECON process,

whereby activated carbon is injected upstream of the COHPAC. Tests of this configuration on

low sulfur bituminous coal resulted in Hg capture averaging 86 percent over a 19-week period. 

Use of a COHPAC with a halogenated sorbent could result in very high Hg capture B even with

Texas lignite B but, unfortunately, the test will not include this configuration. If EPA were to

establish a more lenient standard for Texas lignites, it would have harmful environmental and

health consequences. One outcome of a more lenient standard for these facilities is that they will

continue to emit Hg in huge amounts. A second potential outcome of a higher emission rate B if

EPA adopts its ill-advised trading scheme B is that these facilities might decide to reduce their Hg

emissions using the most promising technologies, and then to bank and sell a large number of Hg

allowances, thereby allowing other polluters to avoid controls. Thus, convincing EPA that they

are unable to control their Hg emissions (in the absence of any data substantiating that assertion)

is clearly in the financial interest of these companies and against the interests of public health and

welfare.

Response:

As noted earlier, EPA continues to believe that placing lignite in a separate subcategory
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is warranted but that further subcategorization into Fort Union and Gulf Coast lignites is not

necessary. The revised new-source NSPS Hg limits incorporate data from both types of lignite

and, thus, are believed to be representative and appropriate. Further, as noted earlier, EPA

does not believe that Hg-specific control technologies are currently available for use as the basis

of a national Hg standard. We believe that the declining cap under the cap-and-trade approach

being finalized will ensure both development of the emerging Hg-specific control technologies

and continued Hg emission reductions by all utility units in the most efficient manner.

3.2.4.6 Coal Refuse-fired Units

Comment:

One commenter (OAR-2002-0056-2068) requested that the EPA not set emission limits

for new and existing coal refuse-fired plants so as to ensure that any limit is achievable and takes

into account the wide variability within this important fuel supply.

Response:

The current subpart Db emission limits for PM, SO2, and NOx, are applicable to coal

refuse-fired units (with an existing definition of "coal refuse") and EPA sees no basis to exclude

such units from the Hg emission limits. EPA believes that the revised new-source NSPS Hg

emission limits for these sources are achievable and appropriate.

Comment:

Three commenters (OAR-2002-0056-1766, -2162, -5495) opposed the proposed emission

limits for coal refuse-fired units. The proposed limits are more than five times more stringent, on

a lb/TBtu basis, than the proposed limits for the next most stringently-regulated coal-fired source

category. The EPA selected this proposed standard based upon limited data from only two waste

coal-fired sources. Such an insignificant amount of data is an insufficient basis upon which to

promulgate emission limits. Also, the EPA did not appropriately consider the variability inherent

in the waste coal fuel source. Specifically, the characteristics of waste coal vary to a much greater

extent than other coal ranks. Finally, the commenters stated that in addition to being inequitable

and based on inadequate data, the proposed emission limit for waste coal-fired sources may not be

achievable. Commenter OAR-2002-0056-5495 thought the measured emissions from the test

data used to set the limit were abnormally low due to a variety of factors.

Response:

The revised emission limits (as noted earlier) for coal refuse-fired units are based on

data from units within the coal refuse subcategory. EPA believes that the stringency of the limits

accurately reflects the performance on Hg emissions of controls used on such units. No data

were provided during the public comment period that refuted the relative levels of control

achievable by coal refuse-fired units as evidenced by the Hg emission limits established in the

rule. Further, EPA did consider the variability inherent in the fuel source in arriving at the final
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emission limits. EPA disagrees with the commenters regarding the level of variability found in

coal refuse related to other coal ranks. Some constituents (e.g., ash, Btu content) do exhibit

wider variability, as would be expected given the nature of the fuel source. However, other

constituents (e.g., sulfur, Hg) exhibit similar or less variability than do other coal ranks.

Comment:

One commenter (OAR-2002-0056-2261) stated that the emissions limits for coal

refuse-fired units must be consistent with the current levels of Hg emissions from each of these

sources to ensure that all coal refuse-fired sources could comply with such levels, notwithstanding

the inherently variable characteristics of the waste coal source. The commenter recommended

that any such limit should be reflective of a 90 percent reduction in Hg, based upon the Hg

content in the coal refuse prior to combustion, as measured by inlet and outlet concentrations

evaluated during biennial performance testing. The commenter stated that such a limit would be

consistent with the effective Hg control achieved by coal refuse sources.

Response:

EPA sees no basis for providing coal refuse-fired units a different compliance approach

than for other subcategories. Therefore, the 12-month rolling average and continuous

monitoring requirements have been maintained in the revised standards. The revised standards

are believed reflective of the expected performance of coal refuse-fired units.

Comment:

One commenter (OAR-2002-0056-3560) stated that the EPA did not gather information

concerning a non-CFB unit that burns coal refuse. Therefore, the proposed Hg emission limit for

coal-refuse units cannot be justifiably applied to a cyclone unit burning at least 25 percent coal

refuse and the rest of the fuel input is essentially bituminous coal.

One commenter (OAR-2002-0056-2826) points out that their member electric cooperative

burns Illinois basin bituminous waste coal. Along with their electric cooperative, the commenter

believes that EPA’s data from units burning waste coals and the EPA’s related analysis are neither

complete nor representative of the emission characteristics of this coal rank. The commenter adds

that there is apparently no information in the EPA database for a cyclone unit, such as their

member cooperative’s Unit 4, which burns a coal waste product as a significant portion of its fuel

input. The commenter respectfully requests that EPA address the above issues as it finalizes its

proposed rule.

One commenter (OAR-2002-0056-2261) observed that the proposed rules establish Hg

emission rates based on rank of coal, including waste coal, being burned. The commenter does

not believe that the rates for existing and new units are reflective of either new or existing

technology used to burn waste coal. According to the commenter, EPA must consider:

(1) the difference and variation in the chemical quality of waste coal from different coal
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fields in different parts of the country;

(2) the technology used to clean the coal producing the waste coal;

(3) the percent SO2 reduction required at the different waste coal plants and its impact on

heat input and Hg emissions; and

(4) NOx controls being implemented.

Response:

Such data as noted by the commenters (e.g., non-CFB units burning coal refuse; data on

coal refuse from different parts of the country) were not made available to EPA during the

public comment period. Units co-firing coal refuse and other coal ranks would be subject to the

provisions applicable to units that blend coal ranks. EPA believes that future units constructed

to combust coal refuse will be similar in nature to existing units and, thus, that the final emission

limits are reflective of units that will combust coal refuse.

3.2.4.7 IGCC Units

Comment:

One commenter (OAR-2002-0056-2721) stated there has not been a full-scale

demonstration of sorbent bed technology on IGCC units with lignite or subbituminous coal. The

commenter noted that the process addressed by EPA in the preamble for the proposed rule is for

an industrial facility firing bituminous coal and producing a synthetic gas (syngas) that is cooled to

about 100 F. According to the commenter, not all IGCC units have a gas stream with a

temperature that low. The commenter stated that sorbent beds do not work when temperatures

are several hundred degrees. The commenter believes there is no justifiable basis to use this

technology for setting. performance standards.

Response:

EPA agrees with the commenter that no IGCC unit utilizing syngas produced from

subbituminous or lignite coals has been operated with a carbon bed for Hg removal. However,

IGCC units have been operated on subbituminous and lignite coals in the U.S. 

(OAR-2002-0056-5684). Application of the carbon bed to IGCC units burning such coals would

not present any additional technical obstacles. EPA also concurs that the optimal temperature

for carbon bed utilization is around 100 F. However, EPA disagrees with the commenter’s

inference that this temperature is not found in some IGCC applications. The DOE conducted a

feasibility study to evaluate the cost of removal of Hg from IGCC units (OAR-2002-0056-5685). 

This study found that the optimal location for the carbon bed was between the fuel gas

cooling/knockout unit and the acid gas removal unit (and prior to the combustion turbine), a

location likely to be found in any new IGCC installation. This location affords temperatures

close to the optimal 100 F. Therefore, EPA believes that carbon bed technologies are
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appropriate for use on new IGCC installations.

Comment:

One commenter (OAR-2002-0056-3459) stated that ACI should be the basis of the

standard for IGCC units. DOE has concluded Hg controls are available and applicable to IGCC

units. The technology is already commercially demonstrated to remove greater than 90 percent

Hg removal and was specifically applicable to gasification systems using high-temperature

slagging gasifiers and bituminous coal, which includes both of the IGCC plants currently in

operation. EPA must establish emission limits that reflect at least 90 percent reduction in Hg

emissions from IGCC units. Based on commenter’s analysis, the rate should be 0.49 lb/TBtu or

3.9 x 10-6 lb/MWh (output-based standard based on 42.5 percent efficiency and conversion factor

for mass/1012 Btu to mass/MWh at 42.5 percent efficiency is 8 x 10-6 TBtu/MWh).

Two commenters (OAR-2002-0056-1852, -2160) opposed separate limits for new or

existing IGCC units. According to one commenter (OAR-2002-0056-2160), Hg capture from

syngas has been proven to be readily available and inexpensive at the Eastman Chemical coal

gasification plant in Kingsport, TN. There is no reason to establish separate and overly lenient

limits for the two existing U.S. plants or for any new plants.

Response:

The existing units will be covered under the cap-and-trade portion of the final CAA

section 111 rulemaking and, thus, will be subject to their respective State’s Hg budget. Any new

units would be subject to the more restrictive new source NSPS Hg emission limit which is based

on the use of a carbon bed as at the Tennessee facility.

Comment:

One commenter (OAR-2002-0056-4139) stated that the WEST Associates statistical

model should not have been applied in developing the emission limits for IGCC units. Both Cl

and Hg would be removed separately from the coal as part of the coal gasification process. 

Therefore, Cl and Hg could not interact as they are not present at the same quantitative levels as

in the combustion process of coal-fired boilers. This leads to an artificially high limit for new

sources.

Response:

Analysis of variability is appropriate for IGCC units. It is true that Hg and Cl would be

removed separately in an IGCC process; however, based on information available to EPA

(OAR-2002-0056-5685), the Hg would likely be removed prior to the removal of the Cl, and,

thus, the Hg-Cl interaction presumed in the current statistical analysis would still be valid.

3.2.4.8 Blended Fuel-fired Units
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Comment:

One commenter (OAR-2002-0056-2198) stated that the proposed limits for

subbituminous coal are less stringent than those for bituminous coal. A unit that previously

burned bituminous coal could choose to blend or switch to subbituminous coal and emit more Hg

proportional to the ratio of subbituminous to bituminous coal. Because many units can burn

either of the two ranks of coal, this commenter does not support this approach. The EPA should

require sources that burn a blend of coal to be subject to the more stringent limit regardless of the

coal or coal mixture being burned at any time.

One commenter (OAR-2002-0056-2889) stated the proposed rule would allow units that

blends coal ranks to average the standards for those coal. Facilities must compute the weighted

average limit based on the proportion of energy input (Btu) contributed by each coal rank burned

during the compliance period. However, the rule does not specify how this is to be done. 

Because blending is typically done with a bulldozer, the quantity of each fuel is not determined

with any precision. To avoid inaccuracies inherent in computing a limit for blended coal, the rule

should require the facility to meet the most stringent standard of the fuels combusted.

One commenter (OAR-2002-0056-3449) stated that limits for blended coals should not be

prorated. Under the proposal, 50/50 blending of subbituminous coal with bituminous coal would

increase allowable emissions for a facility previously burning only bituminous coal by almost

2 times. This type of coal blending is already popular for reducing SO2 and NOx emissions; the

additional benefit of lower Hg emissions coupled with a higher limit would further increase the

incentive. The fact that coal blending provides the benefit of a higher limit is a clear rationale that

EPA should adopt one limit for subbituminous and bituminous coal. At the very least, the lowest

applicable standard should apply to blended coal, not a prorated higher standard. The

commenter’s experience demonstrates that blended coal does not need a higher limit. Blending

should be encouraged to reduce emissions, not increase allowable emissions.

Response:

EPA believes that it is appropriate to use the prorated approach as this is consistent with

that already included in subpart Da.

Comment:

One commenter (OAR-2002-0056-2247) disagreed with EPA’s description of the

importance of coal rank at units such that fuel switching will not occur. Given the demands of

further NOx and SO2 reductions, fuel switching will continue, the EPA’s proposal to proportion

the Hg emissions limit between subbituminous and bituminous (or between subbituminous and

lignite) will result in emissions increases for the unit that switches. Rather than apportioning the

limit between the percent of fuel burned, the limit should apply for the fuel used in the majority. 

Thus, any facility using up to 50 percent bituminous coal with subbituminous coal should meet a

limit for bituminous coal. Because subbituminous coal has lower overall Hg content and

bituminous appears to have sufficient Cl or oxidize Hg for downstream capture, a unit blending
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coal should not have difficulty meeting the limit.

Response:

EPA believes that it is appropriate to use the prorated approach as this is consistent with

that already included in subpart Da.

Comment:

One commenter (OAR-2002-0056-2897) believed blending of different coal ranks can also

be readily accommodated under a rule that includes subcategorization. Of the two options

presented, the commenter recommended that the EPA proceed with a weighted average standard,

as this will be less susceptible to "gaming."

One commenter (OAR-2002-0056-2922) supported EPA’s decision to utilize a blended

emissions limit rather than attempt to establish a separate subcategory for blended fuel units, or to

classify a unit based on the predominant coal it combusts.

One commenter (OAR-2002-0056-2900) urged EPA to retain the five subcategories

identified in the proposal. The commenter stated that the failure to do so would have an

immediate impact on the balance of coal ranks burned in the U.S. and would jeopardize the

nation’s fuel diversity. For the same reasons, the commenter supported the Agency’s proposed

approach of addressing units burning blended coal by weighting the applicable Hg limit according

to the amounts of the different coals that are burned.

One commenter (OAR-2002-0056-2922) supported EPA’s decision to utilize a blended

emissions limit rather than attempt to establish a separate subcategory for blended fuel units, or to

classify a unit based on the predominant coal it combusts.

Response:

EPA concurs with the weighted average approach endorsed by the commenters.

Comment:

One commenter (OAR-2002-0056-2900) supported the EPA’s proposed approach for a

unit burning a blend of coals and a supplemental fuel that the supplemental fuel would not be

taken into account for purposes of determining the unit-specific emission limit that the unit must

meet. However, the supplemental fuel’s heat input and Hg emissions would be considered in

determining the unit’s compliance with the emission limit. The commenter requested that the

regulatory text clearly reflects EPA’s preamble language on this issue. In addition, the

commenter requested that EPA clarify that units burning a single coal rank and a supplemental

fuel would be treated the same as units burning a coal blend and a supplemental fuel. That is, the

supplemental fuel would not be considered in determining the emission limit to which the unit is

subject. The commenter explains the unit would be subject to the emission limit for the coal rank
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it is combusting; however, for compliance purposes, the heat input and Hg emissions from the

supplemental fuel would be taken into account.

 Response:

EPA believes that the final regulatory language is clear.

Comment:

One commenter (OAR-2002-0056-3517) pointed out that there has been little in-depth

study of plants that burn coal blends, and how that might impact or benefit Hg removal. The

commenter stated that a case in point is the Valmont Plant in Colorado which burns a blend of

low Hg, low Cl bituminous and subbituminous coal, both of which are mined in Colorado. 

According to the commenter, although it is recognized that these coals are low in Hg, there is still

significant Hg reduction that occurs. The commenter request that EPA seek further information

on coal blending as a potential option in addressing Hg reductions between the close of the

comment period and the issuance of the final rule. The commenter stated they would like to

retain the option to provide additional information on this topic as it becomes available.

Response:

The impact of intentional coal blending for the purpose of Hg removal is being

investigated under the DOE Hg research program. EPA believes that this approach is yet

another option that facilities may have in achieving compliance with the final emission limits.

Comment:

Two commenters (OAR-2002-0056-1848, -2108) expressed concern about compliance

burden on sources that blend coal and the State agencies that regulate them. According to the

commenters, there are no industry-wide blending procedures and the lack of specificity will lead

to an inaccurate accounting of emissions.

Response:

EPA believes that the States are familiar with the weighted average approach being used

in the final rule as it is currently a part of subpart Da for other pollutants.

3.2.4.9 Cogeneration Units

Comment:

One commenter (OAR-2002-0056-2906) stated that the proposed emission rate

calculation for cogeneration units appears to unfairly penalize these units for sales of any electric

power less than the full generation capacity, contrary to the EPA’s stated intent to advance the

application of cogeneration facilities and thereby improve the nation’s energy efficiency and
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achieve greenhouse gas emission intensity reductions. In both the proposed rule and preamble,

EPA applies the 18 CFR 292.205 efficiency methodology to cogeneration facilities (implied to be

limited to solid fuel-fired facilities because gas-fired units are not included in the rule applicability)

(69 FR 4696 and 69 FR 4762). Application of that methodology appears to penalize those

cogeneration facilities that sell only a portion of their total net electricity generation output to the

grid. Irrespective of the comments relating to the need for annual net sales of electricity to the

grid, the EPA approach would restrict the total output of energy in the denominator to only that

electricity sold to the grid plus one-half of the net steam output of the unit, assuming that any

energy input that is not utilized through electricity sales is used as steam output (69 FR 4762). 

However, this penalizes a facility for using any electricity generated in the cogeneration facility

within the manufacturing facility. Many cogeneration facilities are located within manufacturing

plants that use most, or all of the generated electricity. The cogeneration unit only sells to the

grid the excess power on an as-available basis in order to maintain optimum overall system

efficiency. For example, the methodology in the proposed rule was applied to a typical coal-fired

cogeneration facility. At a constant Hg lb/hr emission rate, constant heat input to the boiler, and

constant electricity generation rate, the calculated emission rate on a lb/MWh basis would vary

with the quantity of electricity sold to the grid. For this example, the lb/MWh calculated emission

rate would be 70 percent higher when selling 25 MWe to the grid than when selling 100 percent

of generated electricity to the grid. This equation unfairly penalizes cogeneration facilities. The

EPA needs to provide full consideration of the complexities of cogeneration units when trying to

develop and utilize output based emission limits. An equitable and workable solution would be to

follow past EPA practice in establishing emissions standards and allow cogeneration facilities the

ability to use input based emission limits and calculations. With this approach, the boiler, fuels,

and emissions controls will determine compliance without the apparent emission rate being

unfairly skewed by the portion of electricity sold to the grid. The EPA should establish emissions

standards that encourage installation and operation of highly efficient cogeneration facilities, and

recognize their inherent variability in design and operating profiles versus typical single use

electric utility units.

Response:

The commenter appears to believe that, for a cogeneration unit classified as a utility

generating unit, reducing the percentage of electricity sold to the grid increases the emission

rate for regulatory purposes. The commenter provided no calculations to support this

contention, but, in any event, we believe the comment to be incorrect. If a unit’s entire rated

output is sold to the grid, the unit would be charged with emissions equivalent to full load. If the

unit sells half of its rated output to the grid and the other half is used internally (either as steam

or as electricity), the unit would be charged only 75 percent of its entire emissions output (all of

the emissions from the 50 percent sold to the grid plus half of the emissions from the remaining

energy used internally, or 25 percent, which totals 75 percent.

The boiler emits Hg for all the coal burned, whether the output is sold or used internally. 

EPA’s proposed rule was formulated to be consistent with State implementation plan (SIP) rules

for NOx emissions under the provisions of the Acid Rain program and with the revised NOx

emissions limits under subpart Da.
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Comment:

One commenter (OAR-2002-0056-2913) stated that the proposed output-based limits

should be modified to take into account the Hg emissions resulting from the combustion of fuel

for co-generating steam for uses other than electricity production.

Response:

The commenter implies that no emissions limit exists for fuel burned to produce steam

not used for electricity sold to the grid. This assertion is incorrect. Emissions from fuel used for

cogenerating steam are generated at the same time as those emissions resulting from fuel used

for electricity generation. However, for purposes of determining the "output" from the unit,

credit for the steam is given a 50 percent credit, versus 100 percent credit for electricity. As

stated earlier, this policy is consistent with SIP rules for NOx emissions under the provisions of

the Acid Rain program and with the revised NOx emissions limits under subpart Da.

3.2.5 Emissions Limit Averaging Period

Comment:

Many commenters (OAR-2002-0056-1803, -1969, -2067, -2365, -2535, -2634, -2661,

-2721, -2827, -2867, -2900, -2918, -2922, -3403, -3432, -3444, -3463, -3478, -3509, -3513,

-3514, -3539, -4891) supported EPA’s proposal to determine compliance with emissions

standards based on a 12-month averaging period. Reasons cited by the commenters included:

(1) the large variability in coal Hg content. plant operations, and control technology

performance;

(2) Hg is not an acute health hazard and concerns about Hg arise from long-term chronic

exposure; and

(3) the compliance period would provide greater certainty that units will consistently meet

the limits, particularly given that operational and material-related variability beyond the control of

the owner/operator can impact emission levels.

Response:

EPA concurs with this comment.

Comment:

Several commenters (OAR-2002-0056-1969, -2260, -2721, -2830, -2835, -2850, -2918,

-3449) supported using a 12-month averaging period but disagreed with using the proposed

averaging method for computing the 12-month average based on averaging monthly average. 

Instead, the commenters recommended that the averaging method be revised to a simple average
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of all valid hourly data from the previous 12 months. The commenters stated that this revision

would equally weight all valid data over the 12-month period. The proposed rolling monthly

average calculation method would place disproportionate weighting on hour values in months that

include extended periods of lower loads, load following, or other operational variances.

Response:

To address the commenters' concerns, the final rule requires the 12-month rolling

averages to be computed on a weighted basis. The rule requires valid Hg emissions data to be

obtained for at least 75 percent of the unit operating hours in each month in which the unit

operates. For each operating month, a monthly average Hg emission rate is calculated, which

weights all of the hours of valid data equally. However, when the 12-month rolling average is

calculated, each monthly average Hg emission rate is weighted according to the number of valid

hours of data collected in that month. This ensures that the Hg emission rate for a month with

few unit operating hours is not counted the same as the emission rate for a month in which the

unit is in continuous operation. For any month in which less than 75 percent of the Hg emission

data is captured, the rule requires a substitute Hg emission rate to be reported, and in the

rolling average, the substitute emission rate is weighted according to the number of unit

operating hours in that month.

Comment:

One commenter (OAR-2002-0056-3210) objected to the 12-month average compliance

determination because it further weakens the proposed standards. The purpose of the 12-month

average is to adjust for variability in the process, fuel source, etc. However, variability is already

overstated in the proposed emission limits resulting in many units being able to avoid controls. 

The 12-month average would be acceptable if the proposed standards were significantly more

stringent.

Response:

EPA disagrees that the 12-month rolling average format weakens the standards. 

Further, as noted above, the new-source emission limits have been revised which may also

address the comment.

Comment:

Two commenters (OAR-2002-0056-2835, -2922) noted that 40 CFR 60.50a(h)(1), which

covers calculation of mass Hg emissions from Hg CEMS and Method 324, calls for calculating

the "arithmetic average of all weekly emission rates for [Hg] for the 12 successive calendar

months." Subsequent subsections refer to calculation of Hg mass emissions "over a month" from

CEMS and over the "emission rate period" from Method 324. It is not clear why 40 CFR

60.50a(h)(1) refers to calculation of weekly rates or how those rates fit into the more specific

calculations. The EPA needs to correct this discrepancy. 
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Response:

Proposed Method 324 has been renamed as appendix K to 40 CFR part 75 and the

method and regulatory text has been clarified.

Comment:

One commenter (OAR-2002-0056-2889) stated that a correction is needed is 40 CFR

60.45a(a). This section refers to a 12-month rolling average and conflicts with 40 CFR

60.45(a)(5) which refers to a monthly limit.

Response:

The commenter is correct in that the compliance monitoring period is based on a

12-month rolling average. However, in order to arrive at this average, monthly averages must

be established on a continuous basis. Thus, EPA believes that 40 CFR 60.45(a)(5) is correct as

stated.

3.2.6 Emissions Averaging

Comment:

Several commenters (OAR-2002-0056-2634, -2830, -2835) requested that the EPA

include facility-wide averaging in the section 111 Emission Guidelines for existing sources as an

additional compliance alternative. States should be encouraged to allow such flexible compliance

alternatives if states decline to adopt a section 111 trading program, if that option is selected by

the EPA. By including this type of flexibility mechanism, the EPA will ensure that those facilities

located in States opting out of the trading program will retain some degree of flexibility when

complying with the requirements of the Emission Guidelines. Similarly, facility-wide emissions

averaging provides a flexible compliance alternative to a cap-and-trade program in the event that

neither cap-and-trade option can be authorized under the statute. Varying operational modes or

combination of systems, e.g., wet/dry scrubber, ESP or fabric filter, could be employed to provide

the greatest potential to economically reduce Hg emissions to meet compliance requirements.

Response:

States and Tribes are free to allocate their Hg budgets as they see fit, whether they

participate in the nationwide trading program or not, as long as the reductions are achieved

from coal-fired Utility Units. We believe that this will address the commenter’s concerns.

Comment:

Several commenters (OAR-2002-0056-2900, -3432) supported allowing facilities with

both industrial boiler units and coal-fired utility units to opt the industrial boiler units into the

electric utility rule for purposes of meeting the emissions standard. The commenter believes a
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final rule should allow affected facilities with both industrial boilers and coal-fired utility units the

compliance flexibility to meet one Hg emission limit through facility-wide emissions averaging.

Response:

Industrial boilers that do not meet the definition of an "electric utility steam generating

unit" under either 40 CFR part 60, subpart Da or HHHH will not be subject to the final rule. 

Therefore, facility-wide emissions averaging between such units and Utility Units will not be

allowed.

Comment:

One commenter (OAR-2002-0056-2922) supported EPA’s proposal to allow emissions

averaging as a compliance option for two or more coal-fired units, including blended coal units,

that are located at a single contiguous. However, the commenter suggested the following

clarifications to provide for smooth implementation of averaging plans. First, one situation under

which sources might wish to utilize averaging is where two or more units utilize a common stack. 

Common stack monitoring is allowed under the general provisions as long as the "monitoring is

sufficient to demonstrate compliance with the relevant standard." However, the proposed rules

do not make clear under what provision such units should report and whether EPA expects

sources to submit averaging plans for such units. The EPA should revise the rule to address that

point.

One commenter (OAR-2002-0056-3398) recommended extension of emissions averaging

to all units under common control within a State to add flexibility.

Two commenters (OAR-2002-0056-1608, -2922) recommended that a Multi-Source

Averaging Plan (MAP) to meet the Hg emission standards be based on the existing CAA Title IV

NOx program. Although this approach for Hg averaging would benefit larger utility systems, it is

of far less benefit to small systems. Instead, it could be altered to allow averaging among different

owners and operators. The CAA Title V permit program could serve to ensure multi-source

compliance after a MAP is approved by EPA. Additionally, the MAP approach could be

extended across state lines as appropriate, as is done in the CAA Title IV NOx program.

Response:

EPA believes that the cap-and-trade approach being finalized will adequately address

the comment.

3.3 VARIABILITY

Comment

EPA used a similar variability methodology to calculate the new-source NSPS limits as it

did to select the MACT floor limits; the only difference is that it did not apply the inter-variability
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analysis. Thus, several of the commenters’ concerns also apply to the selection of new source

NSPS limits.

Many commenters explained that EPA improperly used a short-term worst-case analysis

to develop a long-term standard (12-month rolling average). EPA chose the 12-month rolling

average emission limit format and then applied the industry’s variability method to account for

coal composition. The EPA’s own variability analysis explained that it was inappropriate to apply

its variability analysis where a long-term compliance period is allowed. Commenter OAR-2002-

0056-2878 stated that, given the long-term format, there is no need for the industry’s variability

analysis; the 12-month averaging time provides more than enough buffer to address the worst

foreseeable circumstances.

Commenter OAR-2002-0056-3459 stated that although EPA acknowledged that one

method for dealing with variability was the length of the compliance period, EPA did not assess

that option. Instead, EPA added an annual averaging time on top of is inflated variability

approach and attempted to justify this double counting by stating that Hg poses a chronic and not

acute health risk. Whether or not this justification is warranted, EPA neglected the effect of using

a long-term standard on the stringency of the standard. And because EPA proposed to determine

compliance using a long-term average, the compliance status of the unit will be unaffected by

short-term fluctuations in the coal characteristics of coal shipments and control equipment.

Commenter OAR-2002-0056-2920 stated that EPA must specifically explain why the 12-

month averaging period is necessary and appropriate.

After applying the industry’s variability analysis, EPA calculated the emission rate over the

full range of coal compositions presumed to be used and sorted those emissions to obtain a

cumulative frequency distribution and selected limits based on the 97.5 percentile (compared to

the 95 percent in the WEST analysis). Many commenters (e.g., OAR-2002-0056-2920) noted

that EPA provided no rationale for selection of the 97.5 percentile. This violates the CAA, is

inconsistent with EPA’s own guidance and past practices, and improperly results in emission

limits that are many times higher than appropriate or allowed under State permits. Commenter

OAR-2002-0056-3459 recommended that EPA use the mean calculated emissions from annual

coal data rather than the 97.5 percent upper confidence limit of the mean. The arithmetic mean is

consistent with the 12-month rolling average and consistent with EPA policy.

Commenter OAR-2002-0056-3449 criticized EPA’s failures to consider data on

management of Hg variability from operating facilities.

Two commenters (OAR-2002-0056-2920, -3449) criticized in detail EPA’s equations

based on coal Cl content. EPA has not established a valid statistical relationship between Hg

removal and coal Cl content.

State (e.g., OAR-2002-0056-2660, -2823, -2889, -3210, -3449) and environmental group

(e.g., OAR-2002-0056-3459) commenters asserted that EPA has not established a valid statistical

relationship between Hg removal and coal Cl content. Analyses conducted by WEST and DOE
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demonstrate that there is indeed a valid correlation, particularly with respect to units equipped

with a fabric filter/spray dryer combination. To the extent coal rank is indicative of Cl content,

coal rank may be an important factor with respect to the Hg removal fraction as the New Jersey

Department of Environmental Protection suggests. However, the New Jersey Department of

Environmental Protection incorrectly asserts that EPA should have used raw data rather than

average Cl concentrations to develop its Equation (5). EPA's approach properly relies on average

values because they provide less uncertainty as compared to raw data alone. 

Commenter OAR-2002-0056-5498 provided detailed supplemental comments that address

criticisms of EPA/DOE’s variability analysis. Their comments explain why EPA’s analysis is both

consistent with the CAA as interpreted by the D.C. Circuit and scientifically sound.

One commenter (OAR-2002-0056-2835) stated that the variability factors used by the

EPA in the proposal are appropriate.

Response:

EPA continues to believe that accounting for variability is required in the establishment

of national emission standards. However, EPA concurs with those commenters who indicated

that we had overstated the variability by using both a rigorous statistical analysis and a 12-

month rolling average for compliance. Our revised analysis of the data and new-source

selection procedures are described elsewhere in this document. We believe that this adequately

addresses the variability.

3.4 COAL ANALYSIS

Comment:

One commenter (OAR-2002-0056-3546) stated that the proposed rule does not specify

protocols for determining rank classification of the coal burned in a unit. The EPA needs to

propose a methodology for establishing and reporting coal rank classification for determining

which of the emission limits is applicable to a given unit. The commenter asked if coal ranks will

be based on coal samples taken at the mine or upon delivery point at the power plant, and who is

ultimately accountable for conducting the ASTM coal rank tests; the supplier or the power plant

owner/operator.

Response:

It is the owner/operator that is ultimately responsible for compliance with the final rules. 

How he/she chooses to comply, however, is not specified. EPA believes that facilities are

currently contracting for a certain rank of coal with specific properties best suited for the given

boiler and, thus, are well aware of the rank of coal being utilized. EPA believes that reliance on

the ASTM coal rank classification scheme is appropriate for this rule as it is a commonly

accepted means of ranking coals.
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Comment:

One commenter (OAR-2002-0056-1969) stated that the proposed rule does not specify

fuel measurement/sampling method required to determine the Btu input contributed by each coal

rank. The commenter recommended that EPA should make it clear that sources can use

procedures already in place at the source for recording fuel type and monitoring fuel

consumption.

Response:

The final rule does not require fuel measurement or sampling. Further, there are no

specifications for fuel consumption monitoring procedures so the facility may continue to use

procedures already in place.

3.5 NOTIFICATION, RECORDKEEPING, AND REPORTING

3.5.1 Recordkeeping

Comment:

One commenter (OAR-2002-0056-3543) stated that regardless of the approach taken, the

requirements for emissions testing and recordkeeping must be sufficient to provide data for

development of TMDL. These requirements will provide a rich source of data and should not be

weakened.

Response:

EPA has not weakened its monitoring or recordkeeping requirements.

Comment:

Several commenters (OAR-2002-0056-2634, -2718, -2922) stated that the preamble

indicates that sources will be required to maintain monthly records of types of fuel burned, total

fuel usage, and fuel heating value, but these requirements do not appear in the proposed rule. 

EPA should add a provision for recording those values consistent with existing company

practices.

Response:

EPA believes that the final rule addresses the commenter’s concerns.

3.5.2 Notifications and Reporting

Comment:
3-66

Several commenters (OAR-2002-0056-2634, -2718, -2922) stated that section

63.10030(e) states that a "Notification of Compliance Status" must be submitted for each

"performance test" or "initial compliance demonstration" as specified in section 63.10007. 

Section 63.10007, however, only covers performance testing for "oil-fired" units. Initial

compliance demonstrations for coal-fired units are addressed in section 63.10009. If EPA intends

a "Notification of Compliance Status" to be submitted by coal-fired units following the first

12-month period, a reference to section 63.10009 should be added. If EPA does not intend for

coal-fired units to submit that notice, the reference to the "initial compliance demonstration"

should be removed or clarified.

Several commenters (OAR-2002-0056-2634, -2718, -2922) stated that section

63.10030(a) requires compliance with many notices in the general provisions, including the

"Notification of Compliance Status" in section 63.9(h). That requirement is confusing given that

section 63.10030(e) sets out requirements for "Notification of Compliance Status" that are

narrower than those in section 63.9(h) (e.g., section 63.10030(e) only requires compliance with

section 63.9(h)(2)(ii)). EPA should review these provisions and address the inconsistencies and

overlapping requirements to better explain to sources what is required in each applicable notice or

report. Section 63.10030(a) also requires compliance with section 63.6(h)(4) and (5). However,

according to Table 4, those provisions, which relate to opacity and visible emissions observations

are not applicable. As a result, they should be removed from section 63.10030(a).

Response:

Part 60 does not have a requirement for a Notification of Compliance Status. The

proposed amendments to subpart Da require for Hg and Ni emissions that the performance test

data from the initial and subsequent performance test and from the performance evaluation of

continuous monitors be submitted to the Administrator. Subpart Da also requires semiannual

reports indicating whether: (1) The required continuous monitoring system calibration, span,

and drift checks or other periodic audits have or have not been performed as specified. (2) The

data used to show compliance was or was not obtained in accordance with approved methods

and procedures of this part and is representative of plant performance. (3) The minimum data

requirements have or have not been met: or, the minimum data requirements have not been met

for errors that were unavoidable. (4) Compliance with the standards has or has not been

achieved during the reporting period. Therefore, subpart Da with the proposed amendments

would require that performance tests and semiannual compliance reports be submitted for both

oil- and coal-fired units. Regarding the reference to the requirement to comply with section

63.6(h)(4) and (5), 63.6 (h) deals with compliance with opacity and visible emission standards. 

Section 60.48a in subpart Da with the proposed amendments does not have any compliance

provisions for opacity and visible emission standards. Therefore this comment does not apply to

the part 60 standards.

Comment:

Several commenters (OAR-2002-0056-2634, -2718, -2922) stated that section

63.10009(d)(4) requires reporting of the 12-month rolling average Hg emissions rate in the "first
3-67

semi-annual compliance report." If the initial semi-annual report will be submitted before

12 months of data have been collected, as section 63.10031 requires, it is not possible to report a

12-month rolling average. EPA should remove this requirement and clarify how and when results

are to be reported (e.g., first in the initial "Notification of Compliance Status" and thereafter in the

next semi-annual report).

Response:

This comment does apply to reporting of compliance with the Hg emission limit. 

Compliance cannot be determined until 12 months of data are available. This has been

addressed in MACT standards with emission rates that are 12-month rolling averages, such as

subpart SSSS (the NESHAP for Surface Coating of Metal Coil, see 68 FR 12591, March 17,

2003 for correction notice) as follows for new affected sources: (1) The initial compliance

period begins immediately upon start-up or by (data of publication of the final rule in the FR)

and ends on the last day of the 12th month following the compliance date. If the compliance

date falls on any day other than the first day of a month, then the initial compliance period

extends through that month plus the next 12 months. (2) The first semiannual reporting period

begins 1 day after the end of the initial compliance period described in (1) that applies to your

affected source and ends 6 months later.

Comment:

Several commenters (OAR-2002-0056-2634, -2718, -2922) stated that table 2 in the

proposed rule would require each coal-fired unit subject to a limit in section 63.9990 must

demonstrate "initial compliance" by establishing "a site specific [Hg] limit according to the

procedures in section 63.10009 and reporting the limit in your notification of compliance status." 

This articulation of the initial compliance demonstration is not consistent with the rules. Many

units do not establish site-specific limits, and it is not clear how simply reporting a limit establishes

compliance. Section 63.10009 does not call for reporting of a limit, but rather calculation of a

12-month rolling average. Also, there is no requirement in section 63.10030(e), addressing

"notification of compliance status," to report the applicable limit

Response:

This does not apply to the proposed amendments to subpart Da. The Hg compliance

provisions added as paragraph (m) to Section 60.48a specify how Hg emissions will be

calculated using data measured as specified in Section 60.49a. There is no mention of

establishing a site-specific Hg limit.

3.6 COMPLIANCE DATES

Comment

One commenter (OAR-2002-0056-3449) disagreed with the EPA’s preamble statement

that overly ambitious Hg mandates in the near term could actually hamper innovation toward

more cost effective and less costly technologies (69 FR 4687). It is more likely that EPA’s
3-68

minimal reductions over the next decade would hamper innovation and improvement of public

health. The sooner ACI with fabric filters or other control combinations are required, the sooner

costs will drop. The costs are reasonably now and much less than the costs of Hg poisoning.

Response:

EPA stands by its position that Hg-specific control technologies are not yet commercially

available and that the regulatory approach being finalized is the best approach to both effect

significant SO2, NOx, AND Hg emission reductions while also encouraging the further

development of the emerging Hg-specific technologies.

Comment:

One commenter (OAR-2002-0056-1969) stated the concern that the monitoring and

recording technology has not evolved to the level of reliability necessary to collect continuous Hg

emissions data for compliance purposes and to report those results consistent with EPA’s

proposed requirements.

Response:

EPA believes that the monitoring and recording technology is available and reliable at

this time sufficient to show compliance with the final emission limits. However, further

developments are sure to ensue in the coming years such that the commenter’s concerns will be

alleviated.

Comment:

Several commenters (OAR-2002-0056-2634, -2718, -2922) stated that under proposed

compliance date provisions are confusing and conflicting. Under 40 CFR 63.9983(a) and

63.10008(d), new units must (1) install and operate monitors, and (2) comply with the "emissions

limitations and work practice standards" upon the later of publication of the final rule, or startup. 

Under Section 63.10005, sources then have 180 days after the date for compliance with

"emissions limitations and work practice standards" in Section 63.9983, to complete all

performance tests, selection of operating parameters, and monitoring equipment performance

evaluations. Under Section 63.9983(b) and 63.10008(d), existing units must (1) install and

operate monitors, and (2) comply with "emissions limitations" by 3 years after the final rule is

published. Section 63.10005 states that performance tests, operating limits and monitoring

equipment performance evaluations also must be conducted by the compliance date in Section 

63.9983 (i.e., 3 years from publication of the final rule), but done so according to the applicable

provisions in section 63.7(a)(2), which (unlike section 63.9983) allows 180 days from the

compliance date for performance testing (i.e., 3 years and 180 days after publication). For both

new units and existing units, however, section 63.10009(d) states that "compliance monitoring"

must begin on the "effective date of this subpart." For new units, the requirement to "comply"

with "emissions limitations and work practice standards" on the date of publication of the final

rule and 180 days before the deadline for performance testing, Section 63.10005 makes no sense. 
3-69

Sources cannot be expected to comply without a performance test or monitoring system in place

to establish compliance. For existing units, the rules also are in conflict as to whether an

additional 180 days is allowed for performance testing, selection of operating parameters, and

monitoring equipment performance evaluations. If the additional 180 days is provided, the

deadline for compliance must also be extended. Moreover, for Hg, these provisions also fail to

recognize that sources cannot establish compliance with the Hg emissions limitation until

12 months after the monitoring system evaluation has been completed and the required 12 months

of compliance data have been collected. For both new and existing units, the requirement to

begin "compliance monitoring" on the effective date of the rule, also makes no sense. It conflicts

with the provisions in section 63.9983 establishing "publication" (not the effective date) as the

triggering point, ignores the fact that some new units may not even have started-up, and ignores

the additional 180 days that are supposed to be provided under section 63.10005. The EPA

should follow the model in Part 75 and establish a deadline for applicability of the subpart and

then a single deadline for installation, operation, and evaluation of monitoring systems and for

performance testing and selection of operating parameters. For new units, the deadline for

applicability of the rule would be the later of publication or unit startup. For existing units, the

applicability date would be 3 years after the date of publication of the rule. The deadline for

installation, operation, and certification of monitoring systems and for performance testing and

selection of operating parameters (i.e., the point when "compliance monitoring" is begun) would

be 180 days later. The deadlines for establishing compliance with the Hg standard should be the

end of the initial 12-month compliance period. At the time of the demonstration of compliance

for the initial 12-month period, sources would be deemed to be in compliance for the prior

12 months. As a result, they would at that time have met the statutory deadline for compliance.

Response:

Although the commenters cited concerns with the proposed MACT standard, which is not

being finalized, EPA believes that their concerns may also have been valid for the proposed

subpart Da revisions. Section 60.8 Performance tests of the General Provisions to part 60

requires that within 60 days after achieving the maximum production rate at which the affected

facility will be operated, but not later than 180 days after initial startup of such facility... the

owner or operator of such facility shall conduct performance test(s) and furnish the

Administrator a written report of the results of such performance test(s). Therefore, a new

facility has 180 days after initial startup or date of publication of the final rule to complete and

report the results of the initial performance test. The timing of the initial compliance period and

required reporting should be as follows: (1) The initial compliance period begins upon

submitting the report of the initial performance test to the Administrator, but no later than 180

days after start-up or (data of publication of the final rule in the FR) and ends on the last day of

the 12th month following the compliance date. If the compliance date falls on any day other

than the first day of a month, then the initial compliance period extends through that month plus

the next 12 months. (2) The first semiannual reporting period begins 1 day after the end of the

initial compliance period described in (1) that applies to your affected source and ends 6 months

later.
RESPONSE TO SIGNIFICANT PUBLIC COMMENTS ON

THE PROPOSED CLEAN AIR MERCURY RULE

Received in response to:

Proposed National Emission Standards for Hazardous Air Pollutants; and, in

the Alternative, Proposed Standards of Performance for New and Existing

Stationary Sources: Electric Utility Steam Generating Units

(69 FR 4652; January 30, 2004)

Supplemental Notice for the Proposed National Emission Standards for

Hazardous Air Pollutants; and, in the Alternative, Proposed Standards of

Performance for New and Existing Stationary Sources: Electric Utility Steam

Generating Units

(69 FR 12398; March 16, 2004)

Proposed National Emission Standards for Hazardous Air Pollutants; and, in

the Alternative, Proposed Standards of Performance for New and Existing

Stationary Sources, Electric Utility Steam Generating Units: Notice of Data

Availability

(69 FR 69864; December 1, 2004)

Docket Number OAR-2002-0056

4.0 PERFORMANCE STANDARDS FOR OIL-FIRED ELECTRIC

UTILITY STEAM GENERATING UNITS

US Environmental Protection Agency 

Emissions Standards Division

Office of Air Quality Planning and Standards

Research Triangle Park, North Carolina 27711

15 March 2005
i

General Outline

1.0 INTRODUCTION AND BACKGROUND

2.0 APPLICABILITY AND SUBCATEGORIZATION

3.0 PERFORMANCE STANDARDS FOR COAL-FIRED ELECTRIC

UTILITY STEAM GENERATING UNITS

4.0 PERFORMANCE STANDARDS FOR OIL-FIRED ELECTRIC

UTILITY STEAM GENERATING UNITS

5.0 MERCURY CAP-AND-TRADE PROGRAM

6.0 MERCURY EMISSIONS MONITORING

7.0 IMPACT ESTIMATES

8.0 COMPLIANCE WITH EXECUTIVE ORDERS AND STATUTES

9.0 NODA

10.0 OTHER

Appendix A LIST OF COMMENTERS
4-i

4.0 PERFORMANCE STANDARDS FOR OIL-FIRED ELECTRIC

UTILITY STEAM GENERATING UNITS

4.1 NEED FOR REGULATION

Comment:

One commenter (OAR-2002-0056-2046) questioned the threshold decision to regulate

nickel (Ni) emissions from oil-fired units at all. According to the commenter, based on what it

termed conservative assumptions (i.e., assumptions that overstate the risk), EPA concluded in its

1998 Report to Congress on the emission of hazardous air pollutants (HAP) from oil-fired units

that Ni emissions from these units were responsible for one excess cancer case every 5 years.

According to the commenter, the Agency concluded in the same report that only 11 units in the

country contributed to an excess maximum individual risk of cancer of one-in-a-million, but only

barely so. The commenter provided updated information indicating that many of these units have

changed their operations so as to drastically limit their oil use, or have shut down entirely. 

Moreover, the commenter added that there is information to suggest that EPA’s assumptions

regarding the toxicity of Ni emissions from oil-fired units were overly conservative. The

commenter recommended that EPA re-evaluate its conclusion that these emissions warrant

regulation at all.

One commenter (OAR-2002-0056-2828) stated that EPA should not set a MACT

standard for Ni emissions from electric utility steam generating units because the cost/benefit ratio

of the proposed MACT is exorbitant and EPA’s risk assessment is extremely over-conservative

and greatly overstates risks which are not significant. The commenter stated that EPA assumed

that Ni emissions from electric generating units are 50 percent Ni subsulfide although a more

realistic estimate based on data that became available to EPA after the Report To Congress was

issued indicates that the level of Ni subsulfide in electric utility emissions is far lower than even 10

percent, and may actually be 0 percent.

The commenter noted that in the proposed rulemaking, EPA asked for comment on the

finding in the Utility RTC that only 11 of 137 oil-fired utility units considered in the Utility RTC

posed an inhalation risk to human health of greater than one in one million. The commenter noted

that this estimate is for the year 1990, for which it is estimated that a population of 110,000

would be exposed to a risk greater than one-in-one-million. The commenter further noted that in

2010, after imposition of the requirements of the Clean Air Act (CAA), EPA estimates that the

population at risk decreases to 11,000 because several of the 11 units have already been

converted to natural gas, are burning more gas or are shut down. According to the commenter,

EPA did not specify which of the 11 units these are although it seems reasonable that the number

of power plants would be substantially less than 11.

Regarding the cost-benefit calculation, the commenter stated that a cost benefit calculation

using EPA’s numbers shows a cost-benefit ratio of $2.08 billion dollars per avoided cancer case,

clearly exorbitant and unjustifiable. According to the commenter, using more reasonable numbers
4-ii

for the percent of emissions that are Ni subsulfide would result in even higher cost per avoided

cancer.

One commenter (OAR-2002-0056-2504) stated that the scientific risk data does not

support the need for regulating Ni.

One commenter (OAR-2002-0056-2891) stated that risks posed by Ni emissions from

oil-fired generators are negligible and do not justify a finding that the regulation of such units is

appropriate and necessary. 

One commenter (OAR-2002-0056-3402) submitted that there is a serious question as to

whether Ni emissions from oil-fired units should initially have been or should now be regulated at

all, in light of evidence relating to the decreasing use of oil generation and the toxicity of Ni

emissions. The commenter recommended that EPA re-evaluate its conclusion that these

emissions warrant regulation at all.

One commenter (OAR-2002-0056-2850) supported exempting Ni emissions from oil-fired

plants as there is no public health justification for developing regulations. According to the

commenter, any actions taken by their industry that could raise the cost of electricity to

consumers should bring commensurate health and environmental benefits.

One commenter (OAR-2002-0056-2452) noted that the power generation industry has

changed significantly since EPA’s 1998 Report to Congress. The commenter stated that updated

data on the nation’s oil-fired units and their operating characteristics are important to developing

a sound final rule.

Response:

Based on the comments received, EPA has reexamined the available information relating

to both the number of oil-fired units and the combinations of fuels fired in such units. Based on

that reexamination, EPA believes that Ni emissions from oil-fired Utility Units have been

substantially reduced since the 1998 Utility Report to Congress through a combination of unit

closures and fuel switching. In addition to the information provided by the commenters, EPA

analyzed the latest information provided by the U.S. Department of Energy, Energy Information

Administration (DOE/EIA), particularly with regard to the 11 plants identified as causing the

greatest risk. The 11 oil-fired plants identified in the Utility Study as having a cancer maximum

individual risk of greater than 10-6 based on Ni emissions were comprised of 42 individual units. 

Of those 42 units, 12 units have permanently ceased operation or are out of service. (OAR2002-0056-2046 at pp. 12 - 13; OAR-2002-0056-5998). In addition, 6 of the original 42 units

have reported to the U.S. Department of Energy (DOE) that their fuel mix now includes natural

gas. Earlier reports did not show these units as using natural gas as a fuel. (OAR-2002-0056-

5998). The use of natural gas as a part of their fuel mix would decrease the Ni emissions from

these 6 units. Similarly, another 5 units report using a mix of natural gas and distillate oil

(rather than residual oil) in 2003. (OAR-2002-0056-5998). Since distillate oil contains less Ni

than the residual oil previously burned by these units, it is reasonable to assume that these units
4-iii

currently emit less Ni than was previously the case. Another 2 units now fire a residual

oil/natural gas mixture and have limited their residual oil use through permit restrictions to no

greater than 10 percent of the fuel consumption between April 1 and November 15, with natural

gas being used for at least 90 percent of total fuel consumption. (OAR-2002-0056-2046 at p.

13). Finally, five units have effectively eliminated their mercury emissions since the Utility

Study by switching to burning natural gas exclusively. (OAR-2002-0056-2046 at pp. 12 - 13;

OAR-2002-0056-5998). Taken as a whole, these changes mean that 30 of the original 42 units

identified in the Utility Study have taken steps to effectively reduce or actually eliminate their Ni

emissions. Of the original 11 plants identified in the Utility Study, only 2, both in Hawaii, have

units for which actions that will result in reduced Ni emissions do not appear to have been taken. 

(“Analysis of operating oil-fired electric utility steam generating units,” OAR-2002-0056-6178). 

In addition to the closure of the 12 units identified as being of potential concern in the Utility

Study, there has been a steady decrease in the number of oil-fired Utility Units generally over

the past decade and this trend is likely to continue. In fact, the latest DOE/EIA projections

(OAR-2002-0056-5999) estimate no new utility oil-fired generating capacity and decreasing

existing oil-fired generating capacity through 2025, with an additional 29.2 gigawatts of

combined oil- and natural gas-fired existing capacity being retired by 2025. Based on the

foregoing, EPA concludes that it is not appropriate to regulate oil-fired Utility Units under

section 112 because we do not anticipate that the remaining level of utility Ni emissions will

result in hazards to public health.

4.2 OTHER

Because EPA, in the final rule, is not taking final action on the proposal to regulate Ni

emissions from oil-fired units, we are not providing responses to the remaining comments

received on the proposal to regulate such emissions.
RESPONSE TO SIGNIFICANT PUBLIC COMMENTS ON

THE PROPOSED CLEAN AIR MERCURY RULE

Received in response to:

Proposed National Emission Standards for Hazardous Air Pollutants; and, in

the Alternative, Proposed Standards of Performance for New and Existing

Stationary Sources: Electric Utility Steam Generating Units

(69 FR 4652; January 30, 2004)

Supplemental Notice for the Proposed National Emission Standards for

Hazardous Air Pollutants; and, in the Alternative, Proposed Standards of

Performance for New and Existing Stationary Sources: Electric Utility Steam

Generating Units

(69 FR 12398; March 16, 2004)

Proposed National Emission Standards for Hazardous Air Pollutants; and, in

the Alternative, Proposed Standards of Performance for New and Existing

Stationary Sources, Electric Utility Steam Generating Units: Notice of Data

Availability

(69 FR 69864; December 1, 2004)

Docket Number OAR-2002-0056

5.0 MERCURY CAP-AND-TRADE PROGRAM

US Environmental Protection Agency 

Emissions Standards Division

Office of Air Quality Planning and Standards

Research Triangle Park, North Carolina 27711

15 March 2005
i

General Outline

1.0 INTRODUCTION AND BACKGROUND

2.0 APPLICABILITY AND SUBCATEGORIZATION

3.0 PERFORMANCE STANDARDS FOR COAL-FIRED ELECTRIC UTILITY

STEAM GENERATING UNITS

4.0 PERFORMANCE STANDARDS FOR OIL-FIRED ELECTRIC UTILITY STEAM

GENERATING UNITS

5.0 MERCURY CAP-AND-TRADE PROGRAM

6.0 MERCURY EMISSIONS MONITORING

7.0 IMPACT ESTIMATES

8.0 COMPLIANCE WITH EXECUTIVE ORDERS AND STATUTES

9.0 NODA

10.0 OTHER

Appendix A LIST OF COMMENTERS
ii

5.0 MERCURY CAP-AND-TRADE PROGRAM

5.1 GENERAL

5.1.1 Support cap and trade

Comment:

Many commenters (OAR-2002-0056-1046, -1475, -1482, -1483, -1608, -1623, -1625,

-1673, -1692, -1768, -1790, -1802 -1826, -1834, -1859, -1889, -1900, -1955, -1961, -1969,

-2042, -2115, -2117, -2119, -2123, -2135, -2162 -2172, -2204, -2221, -2224, -2228, -2229,

-2232, -2243, -2260, -2323, -2346, -2356, -2375, -2428, -2431, -2597, -2610, -2613, -2718,

-2729, -2826, -2833, -2835, -2841, -2844, -2845, -2850, -2861, -2883, -2895, -2897, -2899,

-2900, -2904, -2906, -2907, -2911, -2915, -2918, -2929, -2948, -3199, -3208, -3211, -3431,

-3432, -3440, -3443, -3445, -3454, -3463, -3469, -3478, -3516, -3517, -3521, -3522, -3530,

-3531, -3537, -3539, -3546, -3556, -3565, -4103, -4132, -4385, -4454) supported the

cap-and-trade option for controlling mercury emissions from coal-fired power plants.

One commenter (OAR-2002-0056-2906) also supported the cap-and-trade approach to

controlling nickel emissions from oil-fired power plants.

Many commenters (OAR-2002-0056-1623, -1625, -1673, -1692, -1768, -1826, -1859,

-1961, -1969, -2162, -2243, -2375, -2431, -2718, -2833, -2835, -2841, -2844, -2861, -2883,

-2897, -2899, -2900, -2906, -2907, -2915, -2929, -3208, -3432, -3443, -3463, -3478, -3507,

-3521, -3522, -3531, -3537, -3546, -3565) supported a cap-and-trade approach as being the most

cost effective way of achieving substantial emission reductions from the electric power sector.

Many commenters (OAR-2002-0056-1046, -1475, -1482, -1483, -1623, -1834, -1889,

-1900, -1955, -2117, -2115, -2117, -2135, -2224, -2323, -2346, -2718, -2841, -2904, -2906,

-2929, -3199, -3211, -3443, -3516, -3531, -3539, -3546) cited larger emission reductions from

cap and trade than from the traditional MACT approach as a reason they supported cap and trade.

Several of these commenters (OAR-2002-0056-1955, -2718, -3546) noted that greater

environmental benefits would be achieved because of greater compliance within the regulated

community and commenter 1955 cited the compliance rate of 99.93 percent with the Acid Rain

Program for SO2 in 2001.

Several commenters (OAR-2002-0056-4103, -4385, -2610, -2613, -2729, -2841)

submitted that emission trading helps companies avoid potential problems that could reduce

power reliability while improving the environment by providing faster and efficient emission

reductions.

One of these commenters (OAR-2002-0056-2841) noted cap and trade would not result in

increased demand for or pressure on natural gas prices because companies will be able to over

control units that are most economic to control and leave smaller, lower emitting units on-line.
iii

Several commenters (OAR-2002-0056-1834, -1889, -2117, -2123, -2323, -2907) stated

that a nationwide cap-and-trade would reduce mercury emissions by almost 70 percent from 2001

levels, achieving the MACT goal by 2010 and capping emissions at 15 tons in 2018. The

commenters noted that MACT would only reduce these emissions from coal-fired power plants by

29 percent from 2001 levels by 2007.

Several commenters (OAR-2002-0056-1623, -1768, -1859, -2162, -2375, -2597, -2833,

-2835, -2844, -2850, -2900, -2907, -3432, -3440, -3522, -3531, -3537) believed cap and trade

offers a flexible, market-based approach.

One commenter (OAR-2002-0056-3432) noted that compliance flexibility is especially

important to small generating systems.

Several commenters (OAR-2002-0056-2597, -2845, -2897, -2906, -3431) believed that

cap and trade will have less impact on fuel diversity and natural gas availability than the MACT

approach.

One of these commenters (OAR-2002-0056-2845) noted fuel switching to meet the acid

rain requirements resulted in the loss of many jobs. Several commenters (OAR-2002-0056-2224,

-2597, -2900, -2904, -3530, -3537) submitted that cap and trade will spur technological

innovations by electric generators seeking to create emission credits that can be sold and reducing

emissions early in the process.

Several commenters (OAR-2002-0056-2900, -3537) added that cap and trade would

result in a certain, fixed cap on emissions from affected sources and would create incentives for

emissions reductions beyond those required by current regulations.

One commenter (OAR-2002-0056-1608) believed that a regulatory approach can work if

it’s designed around the following principles: 1) regulatory certainty that will allow our industry

to make financially sound compliance and planning decisions regarding capital investments in

environmental and energy technologies, 2) that EPA should set reasonable reduction targets and

time lines, and provide maximum flexibility to minimize costs to achieve desired air quality

objectives cost effectively through the use of flexible, market-based mechanisms such as emissions

trading, and finally 3) to protect fuel diversity to preserve and assure the continued supply of

reliable, affordable electricity to meet our nation’s growing energy needs.

One commenter (OAR-2002-0056-3516) stated that criticism of the cap-and-trade option,

in the mercury context, was inappropriate. The commenter noted a recent study from the

Brookhaven National Laboratory (BNL) observed that, “A Cap and Trade program has the

potential to be protective of human health while being more economically efficient than limiting

releases from all power plants to a fraction of their current release rates.” [Assessing the Mercury

Health Risks Associated with Coal-Fired Power Plants: Impacts of Local Depositions

[PDF-866MB] presented by Terry Sullivan, BNL at

http://www.netl.doe.gov/coalpower/environment/mercury/ .] The commenter noted further the

BNL researchers challenged the alternative of a plant-by-plant approach to mercury control based
iv

upon risk considerations as follows: “The prediction that risks resulting from Hg emissions from

coal-fired power plants are small for the general population and the fact that the risks are borne by

a small fraction of the population suggests that placing reduction in mercury emission goals on a

plant by plant basis will do little to improve human health. Therefore, a cap and trade approach

appears to be acceptable from a risk standpoint.”

Several Texas State representatives and local officials (OAR-2002-0056-2119, -2204,

-2221, -2228, -2232, -2356, -2428) endorsed the cap and trade approach. They noted that Texas

is the largest coal consumer (using over 40 million tons of lignite/yr) and the 5th largest coal

producer; coal mining is an important part of the economy ($17 billion/yr). The commenters

stated that mercury is difficult to remove from lignite and there are no commercially demonstrated

technologies to remove the elemental mercury emitted from lignite. The commenters submitted

that any regulations must not displace lignite coal in the fuel mix in favor of more costly natural

gas.

Concerning the regulatory mechanism used for a mercury control program, one

commenter (OAR-2002-0056-3454) recommended including flexible mechanisms in the

regulation that would encourage innovation while providing a clear goal with meaningful

reductions. Examples cited by the commenter of these types of mechanisms included early

reduction incentives, market based approaches, capital recovery programs, plant wide averaging,

safety valves or other approaches. The commenter stated these types of incentives combined with

concrete goals would encourage technology innovation and reduce impacts on generation mix.

Many commenters (4,457 citizens, 3 public interest groups, 18 states, 1 tribe) generally

supported the more flexible cap and trade approach because it would result in lower emissions for

less cost than fixed emission reductions. The commenters stated this would be a reasonable

approach because the health risk is unproven (claims about the harmful effects of mercury on

women and children are exaggerated and misleading), there is no demonstrated technology to

meet the limits (particularly if additional emission reductions were required), or raise electric rates

as much. The commenters believed emissions trading could help companies avoid potential

reliability problems while improving the environment by encouraging earlier reductions through

new technology.

Many commenters (OAR-2002-0056-1673, -1955, -2224, -2833, -2844, -2861, -2883

-2897, -2900, -2907, -2918, -3211, -3445, -3478, -3522, -3530, -3537, -3546, -4454, -4891)

cited the success of the Acid Rain Program as illustrating the advantages of the cap-and-trade

system. One commenter (OAR-2002-0056-2897) agreed that “[t]he challenge in creating an

environmental market is often to design the predecessor regulatory system that will create proper

incentives to produce the technological developments that are preconditions for a transition to a

market.” The commenter stated that the Acid Rain Program achieved that success with clear

emission caps, the establishment of allowances that were traded as financial instruments, a

national market program, the lack of any restrictions on the instruments, and a program design

that rewarded the innovator and the environmental investor.
v

Another commenter (OAR-2002-0056-2883) stated that as EPA’s acid rain program has

shown, a well-constructed cap-and-trade program can achieve significant emission reductions

with lower cost than other regulatory approaches. The commenter believed a cap-and-trade

program provides individual units maximum flexibility to achieve an emissions cap.

Several commenters (OAR-2002-0056-2883, -3530) pointed out it also encourages the

development and installation of individual control technologies and rewards early reductions or

additional reductions through the use of a banking system. For these reasons, the commenters

favored a cap-and-trade approach over a MACT approach for regulating mercury.

One commenter (OAR-2002-0056-2835) contrasted the Acid Rain Program and NOx SIP

Call to command and control type of regulations that would limit compliance flexibility and might

impose regulatory constraints that not only unnecessarily increase compliance costs, but also pose

real reliability concerns. The commenter believed an emissions trading framework is an effective

regulatory mechanism to ensure that reliable power can be delivered to customers while installing

the requisite emission controls.

According to another commenter (OAR-2002-0056-3522), especially given the substantial

variability in emissions of mercury from plant to plant, the uncertainty about the levels of existing

mercury emissions from power plants and the lack of commercially proven technology to control

mercury emissions from the commenter’s sub--bituminous and western bituminous coal-fired

generation, a cap and trade program would be the best option.

One commenter (OAR-2002-0056-4454) submitted the following policy justifications for

cap and trade, in addition to the compliance successes and operational flexibilities realized

through the Acid Rain Program: (a) additional time needed to manufacture, install and calibrate

emission control equipment; and (b) additional time needed to develop accurate continuous

monitoring technology, and more time to manufacture, install and calibrate it.

One commenter (OAR-2002-0056-2897) believed that a cap-and-trade approach would be

far more effective than a conventional “command and control” regulatory MACT at promoting

the development of dedicated maximum achievable control technologies. According to the

commenter, as the existing fleet is not equipped with dedicated mercury control technologies, the

MACT methodology, which is based on the performance of existing units, cannot promote the

development of dedicated control technologies. The commenter stated that, however, a national

cap-and-trade approach, which includes limits that decrease with time, would provide incentive

for the development of effective and affordable technology. Thus, the commenter encouraged a

design feature with decreasing allowances over time to increase the value of the allowances as

commodities. The commenter believed this should help to create the market forces to

commercialize technology.

One commenter (OAR-2002-0056-2835) believed the power sector is well suited to a

cap-and-trade regulatory framework. Given the relatively small number of emissions sources to be

regulated, the administrative burdens of the program should be minimal. The commenter also

believed a cap-and-trade program for mercury would not thwart the achievement of the Act’s
vi

goals to protect human health and the environment. One important reason was that mercury is a

“global” pollutant for which there does not appear, in most cases, to be a pressing need to require

minimum reductions at each and every affected EGU.

One commenter (OAR-2002-0056-3454) stated that past experience with technology

development for other pollutants (SO2, NOx, and PM) as well as other source categories such as

mobile sources, suggests that delaying the regulation of mercury emissions from power plants

would serve to delay the development of innovative control technologies. The commenter

believed that research and development efforts would be unlikely to be sustained at a vigorous

level in the absence of regulatory or other drivers capable of creating a viable market for advanced

control technologies. The commenter submitted that larger markets provide more incentives for

the development of technologies as well as foster competition between vendors that produces

more innovative and cost effective solutions for affected sources.

One commenter (OAR-2002-0056-2819) stated that if EPA decides to pursue trading and

banking despite the lack of legal authority, any trading and banking program should be used to

supplement rather than supplant other CAA requirements. At a minimum, EPA must adopt an

initial set of regulations under section 112. The commenter suggested that any additional

regulations adopted under section 111 using trading and banking should allow only for achieving

compliance with a cap that is more stringent that the MACT standards.

One commenter (OAR-2002-0056-2181) stated cap and trade programs work best when a

clear, enforceable emissions cap is established, based upon the appropriate environmental or

public health goal. The cap is then accompanied by an emissions trading system that allows

competitive markets–not regulators–to determine the lowest cost method to elicit the reductions

necessary to accomplish the goal. The commenter believed trading programs are distorted when

they are skewed to favor a particular fuel source, encourage a specific technology choice or

protect a particular vintage or business segment. The commenter concluded that such market

distortions are merely a subtle way of returning to more traditional command and control

regulatory regimes and will reduce the cost-minimizing function of the trading program, hinder

progress toward air quality improvements, or both.

Response:

EPA is finalizing a cap-and-trade program under section 111 and is finalizing caps and

timing that are integrated with the Clean Air Interstate Rule (CAIR). See final rule preamble for

further discussion.

5.1.2 Oppose Cap and Trade

Comment:

Many commenters specifically stated that EPA should abandon the cap-and-trade

approach. The commenters believed that while a cap-and-trade program may be effective and

appropriate for nontoxic pollutants, it is not permitted by section 112(d) for HAP. Many
vii

commenters submitted that cap-and-trade approaches fall short of what is technologically feasible

and needed to protect human health and the environment. A trading scheme would allow dirty

plants to continue to emit high levels of mercury by purchasing credits from cleaner plants and not

installing controls, which would further endanger the health of surrounding communities. with hot

spots.

One commenter (OAR-2002-0056-3449) opposed a cap and trade approach for mercury

except as a supplement to more stringent MACT standards. The commenter stated mercury

emissions remaining after compliance with a cap and trade program would cause unaccpetable

adverse health effects; hot spots would remain.

One commenter (OAR-2002-0056-2067) stated that cap and trade is inappropriate

because it encourages the development of mercury “hot spots,” i.e., the commenter claimed that

some individual power plant units might continue to emit mercury under a cap and trade

approach, causing localized mercury deposition. The commenter stated that, alternatively, the

MACT approach would require the installation of control technology on all power plants and

would bring the balance of the industry to the same emissions level as those utilities that have

been industry leaders for decades. Similarly, another commenter (OAR-2002-0056-2359) noted

that the purpose of standards under section 112 is to raise the control performance of all sources

to the level of the top 12 percent. The commenter submitted that trading would be in direct

contrast to this purpose as utilities would trade for credits rather than install controls. The

commenter believes that all existing units must be required to meet limits. The commenter

concluded that allowing trading would invite legal challenges that would further delay MACT

promulgation and implementation.

Many Indian tribes and organizations strongly opposed cap and trade due to the deferral

of mercury controls, the inadequate level of control, and lack of measures to prevent hot spots. 

Waters they depend on for fishing are contaminated by mercury deposition from local, regional,

and international deposition. In many cases, Indian lands are largely wetlands which are more

susceptible to methylmercury formation or otherwise sensitive to mercury contamination due to

site-specific factors.

Several Indian tribes (OAR-2002-0056-1327, -2010, -2110, -2118, -2173, -3311, -3549,

-3550, -3551) opposed cap and trade because unlike the Federal government, states do not have

trust responsibilities for tribes and tribes have no formal role in rulemakings. The commenters

believed state-run programs would be inefficient, ineffective, and not in the best interest of health

and the environment.

One commenter (OAR-2002-0056-3469) believed the best method for the EPA to reach

its goals for SO2, NOx and mercury emissions reductions and to prevent penalizing Indian country

coal and already clean plants, would be to require all power plants producing more than 50 MW

in the nation that are not scrubbed, to install emission control equipment that meets the latest

standards. The commenter stated this approach was preferred to cap and trade programs.
viii

One commenter (OAR-2002-0056-2519) noted that during the summer of 2002 EPA

initiated the two-year process under the Clean Air Act Advisory Committee’s Mercury Working

Group, seeking stakeholder input to develop the merury emissions control program. That process

considered various technical, policy and legal issues associated with setting the MACT standard. 

The commenter submitted that at no time during those deliberations was there any suggestion to

utilize a cap-and-trade program in lieu of MACT standards. Accordingly, there was no

opportunity to fully assess and debate various issues associated with such a mercury emissions

control approach.

One commenter (OAR-2002-0056-3449) submitted that emission trading is not

appropriate for HAP and that the current Acid Rain and NOx SIP call programs are not good

models for advancing trading of criteria pollutants or mercury. The commenter claimed some

components have proven problematic. Unrestricted banking has been shown to be inappropriate

in the SO2 trading program; the 2000 cap has yet to be met because of banking. The commenter

stated that if it is met anytime soon, it will be because of NSR settlements. The commenter

believes banking would also prevent achievement of the 15 tpy mercury cap in 2018 for at least a

decade.

Several commenters (OAR-2002-0056-2364, -3435) claimed the mercury emission

reductions under the section 111 cap-and-trade approach would be too little too late. One

commenter (OAR-2002-0056-2364) found this proposal inadequate because: the cap is too high

and EPA provided no justification for it (installation of MACT controls should reduce emissions

to about 7.5 tpy), the 2030 compliance date for reaching the cap is too long and ignored

attainment dates for the 8-hr ozone and PM2.5 rules (the commenter recommends a compliance

date between 2012 to 2015), and would not protect areas from localized hot spots. The second

commenter (OAR-2002-0056-3435) stated it is inappropriate and a dangerous precedent to treat

a listed HAP outside the 112 framework.

Several commenters (OAR-2002-0056-2695, -2814, -4190) submitted questions regarding

the cap and trade program: (1) How does EPA intend to provide accountability for the system? 

(2) What are the potential risks to endangered species and other flora and fauna? (3) How will the

risk assessment and cost benefit analysis include tribal values, unique exposure pathways, and

consumption levels? (4) Given that mercury is transported over large areas and has local impacts,

is it environmentally safe to trade allowances? (5) What rule provisions will prevent plants from

buying allowances to increase emissions regardless of the affects on surrounding communities? (6)

How will EPA (or how could tribes) measure the reduction of human and environmental

exposure? (7) What is the potential for creating hot spots? (8) How will the program protect

Indian resources used in traditional, cultural, and subsistence practices?

Several commenters (OAR-2002-0056-2871, -2889) contended that comparisons to the

acid rain trading program are inappropriate because of the nature of the pollutants. The

commenters stated that the acid rain program focuses on pollutants with welfare effects while

mercury is a neurotoxin with serious health effects. Similarly, one commenter

(OAR-2002-0056-2243) stated that although NOx and SO2 trading programs are a success, the

commenter did not support this approach with mercury. According to the commenter, trading
ix

ounces of mercury did not appear to be a reasonable approach. The commenter was concerned

with the ability to accurately monitor and tabulate emissions. Also, the commenter stated that a

trading program for hazardous air pollutants could not be viewed as a preferred control strategy.

One commenter (OAR-2002-0056-3561), a Maine Congressman attached testimony from

Maine officials and residents opposing the proposal in a state public hearing. [Note: attached

testimony is not in docket].

One commenter (OAR-2002-0056-2836) consisting of US Senators and Congressmen

contended that EPA’s weak proposal under CAA section 111 would not result in major

reductions of mercury for at least 10 years beyond the time frame required for MACT standards. 

The commenter claimed this would result in more pollution and health risk and would fail to

encourage new technology. The commenter noted that EPA’s own modeling showed that Clear

Skies legislation, which calls for essentially the same mercury reduction on the same schedule as

the section 111 approach, would exempt almost 200 of the oldest and dirtiest coal-fired plants

from installing advanced pollution controls for decades. It also showed that the section 111

approach would achieve at best a 58 percent reduction in mercury emissions by 2020, well below

the 69 percent goal for 2018. The commenter stated that in addition, the Energy Information

Administration predicts that the plants would reduce mercury emissions by only 40 percent by

2025. The commenter stated in addition, the section 111 cap and trade approach would fail to

protect local populations from hot spots. The commenter submitted that EPA has instead

committed to evaluate the health risks that remain without committing to prevent or eliminate

those risks.

One commenter (OAR-2002-0056-2951) believed in the recent debate over the desirability

of a “Cap and Trade” system for utility mercury, too much concentration has been placed on the

desirability of the Trading; yet the key to maximizing social welfare is dramatically reducing and

accelerating the proposed Cap. The commenter stated that it may be comforting for economists

to recognize that, given that MACT law is eventually followed and the utility emission limits are

set at some real semblance of “the average of the best-performing 12 percent,” the loss of the

efficiencies of trading will not be that great. According to the commenter, the primary reason for

this is simply that if the average required mercury reduction is truly in the neighborhood of

80 percent to 90 percent, then there will not be much over compliance from which to draw

tradable allowances. The commenter stated that mercury is, indeed, an air toxic and common

sense dictates that if it can be limited cost-effectively to a high degree–and it can–then it deserves

to be. The commenter believed emission allowance trading is just not designed for accelerated

compliance with 80+percent reduction requirements. The commenter added that further, because

of the nature of the likely control methods to be predominately used in complying with strict

emissions limits–lower-mercury coals and sorbent injection into existing particulate collectors–the

ability to trade emission allowances would yield only minimal economic gains. The commenter

stated that coal-mercury rationalization and sorbent injection are not capital-intensive control

methods: their costs vary directly with their use. The commenter noted that economic benefits of

trading are maximized when great disparities in marginal compliance costs among units exist. The

commenter believed this is simply not turning out to be the case with utility mercury. The

commenter stated that even in the high-cost compliance cases, like units with hot-side ESPs or
x

those that sell their fly ash for concrete, technological advances are reducing the compliance costs

considerably. (See the Sorbent Technologies’ presentations on the e-Docket at

OAR-2002-0056-1461 and OAR-2002-0056-1463.) The commenter believed that efficiency

analogies with the SO2-allowance-trading experience are simply not there.

One commenter (OAR-2002-0056-3398) opposed interstate trading of mercury emissions

because of the potential for hot spots.

Response:

EPA is finalizing a cap-and-trade program under section 111 and is finalizing caps and

timing that are integrated with the CAIR. See final rule preamble for further discussion.

5.2 LEGAL AUTHORITY FOR CAP AND TRADE

Commenter:

One commenter (OAR-2002-0056-3531) stated that by implementing the program

nationally and requiring EPA’s CAMD group to oversee the implementation, the rules will not

add any regulatory or cost burden to the states.

One commenter (OAR-2002-0056-3478) stated that a cap and trade program would have

to be set up in an equitable manner. The commenter also stated that it would be imperative that

the allowance allocation system be transparent and provide certainty for the units complying with

the cap and trade program. For this reason, the commenter did not support the cap and trade

approach under section 111. The commenter believed that this method would allow individual

states to determine whether, among other things, to 1) let its electric generators participate in a

national cap and trade program; 2) allocate all, some, or none of its budgeted allowances to the

generators; 3) auction the allowances back to the generators; 4) withhold allowances from a given

generator or 5) let its generators buy and sell allowances out of state. According to the

commenter, in addition to being a major enforcement and oversight challenge for EPA, the

resulting patchwork of conflicting programs could create even greater challenges to electric

generators, endanger the stability of the grid, increase costs to consumers, and ultimately delay

reductions in utility mercury emissions.

Several commenters (OAR-2002-0056-2046, -2247, -2871, -2887, -2889, -4139) feared a

cap-and-trade program under section 111(d) would require states to develop and submit a

SIP-like plan for approval to regulate existing facilities which would result in a patchwork of

varying regulations and limits. The commenters claimed the section 111 approach would be

time-consuming, duplicative, and inconsistent. One commenter (OAR-2002-0056-4139) stated

also, there are no assurances that EPA would consider depostion from an upwind state when

reviewing the “SIP-like” control requirements. Therefore, the section 111(d) approach would not

protect the commenter from upwind states.
xi

Several commenters (OAR-2002-0056-1763, -4177) asserted EPA’s section 111 proposal

is unworkable because EPA can only promulgate regulations that establish a procedure for states

to follow in establishing NSPS for existing sources. This could result in states developing their

own mercury plans rather than following a consistent approach. This does not comport with the

national multi-pollutant framework. One commenter (OAR-2002-0056-4177) added that it would

be an administrative nightmare and many states would opt out making it useless. This approach

would prolong implementation, create uncertainty, and make an uneven playing field.

Several commenters (OAR-2002-0056-2414, -3351) stated that the CAA section 111

cap-and-trade alternative is not an option for toxic air pollutants. One commenter

(OAR-2002-0056-2414) submitted that section 111 is designed only to address emissions of

non-hazardous air pollutants from new sources. In addition, the original intent of the Act

demands across the board reductions. By definition, a trading program does not require

reductions from all sources. The second commenter (OAR-2002-0056-3351) stated that section

111 was designed to address criteria pollutants like SO2 and NOx.

One commenter (OAR-2002-0056-2521) stated that many stakeholders have charged, and

the Administration has itself acknowledged, that there are substantial questions as to the legality

of the EPA regulatory proposal to regulate mercury under a cap-and-trade system, whether under

section 111 or 112 of the Clean Air Act. According to the commenter, the mere fact that these

and other legal questions were being raised, regardless of how they are eventually resolved, meant

substantial delay and uncertainty in terms of putting stable standards in place. The commenter was

concerned that if the courts resolve the legal questions contrary to EPA’s position, the Agency

would have to propose a stricter standard-but only after a period of continued uncertainty.

Response:

EPA is finalizing a cap-and-trade program under section 111 and is finalizing caps and

timing that are integrated with the CAIR. See final rule preamble for further discussion.

Comment:

Several commenters (OAR-2002-0056-1673, -2172, -2224, -2899, -2922, -2929, -3537)

believed that EPA has the legal authority under CAA section 111(d) to establish a cap-and-trade

program to control mercury emissions from utility units.

One commenter (OAR-2002-0056-3537) submitted that EPA’s proposal to revise its

“necessary” finding made in December 2000 is supportable under the administrative record. The

commenter believed EPA’s justification that another viable statutory mechanism exists to

adequately address mercury (and nickel) emissions from coal (and oil-fired) Utility Units–CAA

§111–is legally justifiable. The commenter also believed EPA’s interpretation of

§112(n)(1)(A)–that just because it is appropriate to regulate Utility Units, EPA is not compelled

to regulate them under §112 if other authorities in the CAA exist to adequately address health

hazards that occur as a result of HAP emissions–is a reasonable interpretation of the term

“necessary” in §112(n)(1)(A). The commenter stated that if EPA withdraws its determination
xii

that regulation under §112 is necessary, then EPA should not be required to go through a formal

de-listing procedure to remove Utility Units from the §112(c) list. The commenter submitted

EPA’s interpretation of the phrase best system of control, coupled with the definition of standard

performance in §111(a) to allow a cap and trade program is reasonable in the context of

establishing NSPS for mercury pursuant to CAA §111. The commenter believed EPA’s analysis

of the use of §§111(b) and (d) to establish NSPS for new and existing coal-fired Utility Units for

mercury emissions is reasonable in the context of establishing a cap and trade program pursuant to

§111. The commenter stated in summary, although it may not be the best approach, especially

from an efficiency standpoint, a cap-and-trade program established pursuant to §111 is a viable

and appropriate statutory mechanism by which to regulate mercury emissions from new and

existing coal-fired Utility Units. However, should EPA proceed forward to establish a cap and

trade program pursuant to §111, the commenter believed that the general approach outlined by

the commenter in section 3.24 (in OAR-2002-0056-3537) would be a much improved version of

EPA’s proposed cap and trade system in the currently proposed Mercury Rule.

Similarly, another commenter (OAR-2002-0056-2899) believed that CAA section

112(n)(1)(A) provides EPA with broad authority to craft regulations to address any public health

concerns it identifies. The commenter stated that section 112(n)(1)(A) does not require EPA to

regulate under §112(c) and (d); instead, the provision provides generally that EPA shall regulate

under this section if the Administrator finds that regulation is appropriate and necessary. The

commenter stated the most consistent reading of §112(n)(1)(A) is that Congress intended EPA to

consider a variety of control options to address whatever heath concerns were identified in the

Report to Congress and then to promulgate rules based on the best of those options. The

commenter added that the limited legislative history of §112(n)(1)(A) supports a broad grant of

authority. The commenter stated this legislative history indicates that EPA has broad discretion

to establish regulatory standards, should it find such standards necessary to protect public health.

One commenter (OAR-2002-0056-2224) stated that it should be emphasized that CAA

section 111(d)(1) itself does not independently mandate that standards of performance for existing

sources impose a source-specific requirement for continuous emission reduction. According to the

commenter, thus, a state plan incorporating a standard of performance that employs a

cap-and-trade mechanism would not conflict with the statutory requirements of section 111(d)(1).

Moreover, the commenter believed that the emissions cap and allowance-holding requirement in

EPA’s proposed section 111(d) trading program arguably would have the effect of imposing a

“continuous emissions reduction” requirement on affected electric generating units (EGUs).

According to the commenter, specifically, the proposed section 111(d)(1) cap-and-trade program

would establish a permanent cap on mercury emissions and require affected sources to hold

allowances that correspond to the level of mercury emissions from those sources at all times.

Response:

EPA is finalizing a cap-and-trade program under section 111 and is finalizing caps and

timing that are integrated with the CAIR. See final rule preamble for further discussion.

Comment:
xiii

Many commenters (OAR-2002-0056-2108, -2219. -2695, -2823, -2871, -2887, -2889,

-3205, -3457, -4117) did not believe that mercury emissions trading is legal under either section

111 or 112(d) of the Clean Air Act.

The public interest group comprehensive comments (OAR-2002-0056-3459) stated that

the proposed cap and trade program is not permitted under section 111. The commenter claimed

judicial decisions limit pollution trading under the CAA and do not authorize EPA’s proposed

approach as follow: (1) EPA’s attempt to permit even limited emission trading under CAA section

111 has been rejected by the U.S. Court of Appeals (ASARCO v. EPA, 578 F.2d 319 (DC Cir.

1978). For new and modified sources, EPA may allow some form of intra-source trading to avoid

the application of PSD permit requirements but the offsetting changes must be within the same

source (Alabama Power Co. v. Costle, 636 F.2d 323, DC Cir 1980). And, while Congress added

provisions for trading programs in several parts of the CAA as part of the 1990 amendments, it

did not do so for section 111. (2) The legislative history of CAA section 111 indicates a

Congressional desire for uniform national standards, not a tradeable system of allowances. 

Congress’s manifested intent that every individual source meet the same standard is fundamentally

inconsistent with a cap-and-trade program in which some plants would be able to emit more than

would be allowed by a technology-based standard because they have traded with other plants. 

And, nothing in the legislative history suggests that the “best system” be interpreted so broadly. 

To the contrary, the best system is consistently understood to be the best system that an individual

plant could implement and the legislative history of the 1990 amendments reaffirms that the best

system applies to individual plants and not to a novel regulatory system. While Congress reverted

to the 1970 definition of “standard of performance” to provide plants more flexibility, this clearly

was intended to apply within the constraint of a command and control system.

One commenter (OAR-2002-0056-2823) comprised of eleven State Attorney Generals

stated that mercury emissions trading is illegal and inappropriate under either section 111 or

112(d) Act because mercury emissions may be deposited in close proximity to power plants

resulting in “hot spots.” The commenter submitted the following supporting information: 

(1) EPA’s own report recognizes that buying allowances cannot address a hot spot if the cap does

not require sufficient reductions to minimize or prevent local impacts. EPA’s plan to evaluate the

protectiveness of the program after 2018 provides no assurance that hot spots will be adequately

dealt with. (2) EPA’s proposed trading program does not address mercury “hot spots.” It is well

documented that mercury must be controlled at a local level and a national cap and trade

approach by itself will not address local issues. Recent studies show considerable hot spots and

that up to 95 percent of the mecury can be of the reactive form that is deposited locally (Florida

Everglades, New Hampshire data). EPA has also ignored it’s own policy statements that trading

may be inappropriate for highly toxic pollutants like mercury. (3) The trading program as

proposed does not include adequate restrictions, such as temporal restrictions on the use of

allowances. EPA has ignored its own policy guidance on how to design a cap and trade program

so as to address localized hot spots. Also, EPA’s provision for unlimited flexibility, such as the

proposed safety valve, undermines any potential for a trading program to address hot spots.

(4) Other regulatory standards and level of required reductions are inadequate to address localized

impact. EPA fails to recognize that the acid rain program has certain “backstops” that are not in

the mercury proposal. (See pages 55-61).
xiv

One commenter (OAR-2002-0056-2108) noted that CAA sections 111(b) and 112(d)

require a performance standard or an emissions standard. The trading program does not require a

source to achieve any particular level of control.

Another commenter (OAR-2002-0056-2219) pointed out that according to EPA guidance

(Environmental Incentive Performance), trading programs must be able to quantify the pollutant

reduction. The commenter claimed it is not possible to quantify mercury emissions because

baseline levels are not well established. Also, some ecosystems are more sensitive to mercury

deposition and accumulation than others, making the need for accurate measurement imperative. 

The commenter believed a trading program should not be allowed because it conflicts with EPA

guidance. One commenter (OAR-2002-0056-2887) also strongly opposed the removal of coal

and oil-fired units from the list of source categories in CAA section 112(c). The commenter felt

this action would be entirely inconsistent with the air toxics program since these units comprise

one of the largest sources of HAP in the country. One commenter (OAR-2002-0056-3205)

stated that if EPA rescinds its December 2000 finding that it is necessary and appropriate to

regulate HAP from coal fired utility units, the requirement for case-by-case MACT determinations

for new units required by section 112(g) would no longer apply. The commenter would be

adversely affected because the state (Montana) would likely rescind its MACT limit for the

proposed new Roundup power plant . The commenter concluded that although EPA has

proposed a cap-and-trade program, if it rescinds the December 2000 regulatory finding, the

commenter agreed with Environmental Defense that the program is unlawful.

Response:

EPA is finalizing a cap-and-trade program under section 111 and is finalizing caps and

timing that are integrated with the CAIR. See final rule preamble for further discussion.

Comment:

Several commenters (OAR-2002-0056-2897, -3556, -3565) believed a nationwide

cap-and-trade program under CAA section 112 would create a more efficient regulatory structure

than a similar program under CAA section 111. One commenter (OAR-2002-0056-2897) stated

the 111 approach recognizes the inherent cost-effectiveness of emission trading compared to

traditional command-and-control regulation; however, the commenter stated the practical

problems with section 111 are evident. In the commenter’s view, the 111(d) approach, while well

intended would not be a market-based approach and would result in extended delays in achieving

its intended purpose. The commenter believed the 111(d) program inherently withdraws the

incentive offered to the early innovator and the early investor. The commenter added that under

111, it will take years to have any understanding of the final approved plans, and the careful

investor will withhold investment until it can better understand which states are in, which states

are out, and which states will reward investment. The commenter stated this would only result in

delays in commercializing of remediation technology. The commenter added that lack of a

national allowance system would only create further investment delays. According to the

commenter, it appeared likely the 111(d) approach already lacks state support. For example, the

commenter noted the Northeast OTC “does not support a cap-and-trade for Mercury (Hg)
xv

beyond a facility’s borders. The OTC supports a bubble concept for mercury at a given facility.” 

The commenter also noted that eleven of the 12 OTC states voted to oppose any cap-and-trade

program for mercury, with Virginia abstaining. The commenter concluded that if the purpose of

this rulemaking is to get the international ball rolling then the 112(n)(1)(a) approach offers the

most likely manner of expediting commercialized remediation technology.

A second commenter (OAR-2002-0056-3556) believed that the Clean Air Act provides

EPA with broad discretion as to how it chooses to regulate EGUs for HAPs emissions. The

commenter’s preference and recommendation was that the Agency do so under the provisions of

CAA section 112(n)(1)(A). The commenter believed that this section would provide EPA with

the discretion it requires, yet would create a program with a uniform format that is national in

scope. The commenter strongly believed that a Federally operated, national emissions trading

program is essential if this effort is to achieve the desired emissions reduction in the quickest and

most economical manner.

Response:

EPA is finalizing a cap-and-trade program under section 111 and is finalizing caps and

timing that are integrated with the CAIR. See final rule preamble for further discussion.

5.3 NATIONWIDE CAP AND COMPLIANCE DATES

5.3.1 Timing of Compliance Dates

Comment:

Several commenters (OAR-2002-0056-1625, -1673, -1768, -1814, -2117) expressed

concern over the proposed mercury rule and the Interstate Air Quality Rule (IAQR). One

commenter (OAR-2002-0056-1625) stated that a potential timing issue would be the possible

requirement of mercury reductions to take place in 2008, 2 years before the SOx and NOx

reductions of the Interstate Air Quality proposal. The commenter submitted that EPA must

harmonize the mercury compliance dates with the deadlines for the SOx and NOx reductions. For

an effective multi-pollutant control strategy that best mirrors the advantages of Clear Skies,

another commenter (OAR-2002-0056-1673) stated that EPA must coordinate and harmonize the

mercury rule and IAQR as much as possible. In setting reduction targets and compliance

deadlines for individual pollutants, several commenters (OAR-2002-0056-1673, -1768) stated

that EPA should fully consider the co-benefits that pollution controls such as SO2 scrubbers and

SCR controls will have for reduction of other pollutants. The commenters believed that aligning

reduction targets and compliance deadlines would allow companies to address SO2, NOx, and

mercury in one integrated step, rather than two. The commenters submitted this would promote

the efficient utilization of resources and better ensure timely compliance. The commenters added

therefore, it is critical for the Phase I compliance dates under both rules to be set for 2010. The

commenters believed that, as in Clear Skies, the Phase I mercury reduction targets should be set

at the co-benefit level resulting from Phase I of the IAQR. Failure to align these deadlines and
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reduction targets would not only increase compliance costs substantially, but could actually

impede the early installation of the most effective control technologies.

Another commenter (OAR-2002-0056-1814) stated that EPA has taken the innovative

approach of proposing the IAQR rules at the same time as the mercury rules. The commenter

also stated that this is important because controls that would be required under the IAQR will

achieve significant reductions in mercury emissions, through co-benefits of the control devices.

The commenter believed setting the Phase I target at the level of co-benefits of SO2 and NOx

control is appropriate considering the low concentrations emitted from power plants and the

difficulty of achieving mercury reductions.

Response:

EPA is finalizing a cap-and-trade program under section 111 and is finalizing caps and

timing that are integrated with the CAIR. See final rule preamble for further discussion.

Comment:

One commenter (OAR-2002-0056-3431) stated that the small and medium-sized units that

risk shutdown if unit-specific controls were mandated are not expendable; they provide a valuable

electric service reliability benefit to the national grid. The commenter added that specifically, they

provide operating reserves, load balancing capability, regulation, and voltage support. The

commenter believed based on the current demands on the grid, it is critical this reliability support

not be ignored, particularly when EPA can achieve the same or better aggregate reduction of

mercury emissions utilizing a mandated cap and trade program. Similarly, one commenter

(OAR-2002-0056-2431) argued that an unreasonably accelerated compliance schedule for a

MACT standard could lead to reliability problems and outages for equipment installation when

this rule and the IAQR rule are considered. The commenter also noted that new control

technologies are 2-3 years from completing demonstration.

Response:

EPA is finalizing a cap-and-trade program under section 111 and is finalizing caps and

timing that are integrated with the CAIR. See final rule preamble for further discussion.

Comment:

Many commenters (OAR-2002-0056-1768, -2042, -2123, -2224, -2833, -2844, -2906,

-2907, -3443, -3537) stated that the cap-and-trade approach to mercury control should be

adopted in conjunction with the proposed interstate air quality rules. One commenter

(OAR-2002-0056-2906) supported an approach of imposing mercury emission reductions to a

level commensurate with co-benefits achieved through the SO2 and NOx emissions reductions of

the CAIR. The commenter noted however, those reductions must be made in an equitable fashion

between coal ranks, recognizing the inherent difference in trace metal concentration, and the

differing ability of SO2 and NOx emission control systems to remove mercury from those different
xvii

coal ranks, with consideration of chlorine content impact. The commenter believed this approach

would help to mitigate the costs of compliance, which would be borne by all electricity

consumers.

Similarly, one commenter (OAR-2002-0056-1768) stated that the final rule should, to the

greatest extent possible, rely on SO2 and NOx control technologies to meet mercury reduction

obligations. One commenter (OAR-2002-0056-2224) stated EPA’s proposed cap-and-trade

option would be the best way to ensure the mercury co-benefits reductions can be realized by

achieving significant, cost-effective reductions for all three pollutants at the same time. The

commenter stated that working within a rigorous MACT-regulatory context instead of a

cap-and-trade framework would afford EPA and industry much less flexibility in terms of timing

of compliance. The commenter noted that the statute allows, at most, three years for meeting the

MACT emissions limits. The commenter also pointed out that although a compliance extension

would be possible, CAA section 112(i)(3)(B) provides only a one-year extension in cases where

“such addition period is necessary.” The commenter added that furthermore, the CAA only

authorizes longer extensions in time through a “Presidential Exemption.” According to the

commenter, this statutory provision has never been used and does not authorize an extension of

the compliance deadline unless the following two criteria have been met: 1) that “‘the technology

to implement such standard is not available,” and 2) that a compliance extension “is in national

security interests of the United States.” According to the commenter, it was far from clear

whether both criteria could ever be satisfied, which only exacerbates the lack of regulatory

certainty for the power sector.

Response:

EPA is finalizing a cap-and-trade program under section 111 and is finalizing caps and

timing that are integrated with the CAIR. See final rule preamble for further discussion.

Comment: One commenter (OAR-2002-0056-1768) supported the concept of

multi-emissions regulation, but was concerned over the economic and technological feasibility of

the basic time frames and levels of reductions under the trading options. The commenter

encouraged the EPA to incorporate provisions to lengthen the time frames and levels should

achievement not be possible in the proposed rules.

Response:

EPA is finalizing a cap-and-trade program under section 111and is finalizing caps and

timing that is integrated with the Clean Air Interstate Rule. See final rule preamble for further

discussion.

Comment:

Several commenters (OAR-2002-0056-2160, -2375, -2818, -2833, -2835, -2844, -2867,

-2899, -3531) stated that the compliance dates for emission controls for mercury should be

coordinated with the compliance dates for controls for sulfur dioxide and nitrogen oxides under
xviii

the proposed Interstate Air Quality Rule. The commenters submitted that if EPA harmonizes the

mercury rule deadline with the IAQR Phase I deadline, sources will be able to coordinate their

planning and avoid wasteful investments in pollution controls and maximize the mercury removal

co-benefits from SO2 and NOx controls. One commenter (OAR-2002-0056-2818) pointed out

that given EPA’s determination that the coordinated regulation of mercury, sulfur dioxide and

nitrogen oxides allows mercury reductions to be achieved in a cost effective manner due to the

co-benefit of mercury removal to be derived form controls for sulfur dioxide and nitrogen oxides,

it would be reasonable and in the national interest to have the mercury compliance deadlines

match those under the proposed Interstate Air Quality Rule.

Several commenters (OAR-2002-0056-2915, -4132) expressed concern that the deadlines

for having emissions controls installed and operational in the mercury rule and in the CAIR may

not be the same. One commenter (OAR-2002-0056-2915) stated that after EPA lengthens the

compliance deadlines in the mercury rule compared to the proposed compliance deadlines, EPA

would need to establish CAIR compliance deadlines such that they are synchronized with such

lengthened compliance dates in the mercury rule to allow electric generators to develop

cost-effective planning strategies that allow them to take advantage of co-benefit mercury

emissions reductions that can be achieved through SO2 and NOx control technologies. The

commenters claimed that failure to synchronize these deadlines could affect electric rates and

reliability.

Several commenters (OAR-2002-0056-2830, -2850, -3443) stated that the first phase of

the CAIR and the first phase compliance date for mercury under a cap and trade scheme should be

delayed. Several commenters (OAR-2002-0056-2830, -2850) noted that 2010 was established as

the date for first phase compliance for SO2 and NOx under the Clear Skies legislation. Two years

have elapsed since Clear Skies was proposed. The commenters recommended that the first phase

of the CAIR and the first phase compliance date for mercury under a cap and trade scheme should

be delayed 2 years, i.e., from 2010 to 2012. One commenter (OAR-2002-0056-3443) stated that

in their comments on the CAIR, they noted the likely scheduling problems associated with

fabricating the control equipment and obtaining requisite permits for waste disposal. For these

reasons, the commenter recommended that the CAIR schedules be adjusted to make the first

phase effective in 2011 and the second phase in 2016. Consistent with these earlier comments,

the commenter would expect the timing of Phase I under both rules be linked such that if the

CAIR schedule is adjusted, the mercury schedule would follow suit. The commenter stated that

synergy between the two rules will facilitate the reduction of emissions of multiple pollutants

(SO2, NOx, and Hg) in a cost-effective manner. If Phase I of the CAIR is delayed, the commenter

believed the onset of the mercury program should also be delayed and sources be allowed to earn

early reduction credits in the interim prior to the onset. The commenter submitted that this is an

environmentally preferable approach since early reductions would be achieved while still ensuring

that the two rules are implemented in tandem.

One commenter (OAR-2002-0056-2521) stated that the Clean Air Planning Act proposes

a 24-ton cap in 2009 on mercury emissions from the industry sector, and the Northeast States for

Coordinated Air Use Management (NESCAUM) equates the commenter’s recommendation to

the Working Group with a 13.1-ton cap in 2008. In light of its view that these targets are
xix

achievable, the commenter anticipated no need for a one-year extension (from 2008 to 2009) for

the implementation of the 34-ton cap that EPA proposed.

Response:

EPA is finalizing a cap-and-trade program under section 111 and is finalizing caps and

timing that are integrated with the CAIR. See final rule preamble for further discussion.

Comment:

Several commenters (OAR-2002-0056-2833, -3440, -3530) stated that in the final rule,

EPA must not tighten the standards or compliance deadlines set forth in the proposed rule. The

commenters submitted that the reduction requirements in the proposed rule are extremely

aggressive and will be very difficult for many companies to meet. One commenter

(OAR-2002-0056-3440) noted the first phase is proposed to take effect in 2010, leaving

companies only 5 years to make decisions on the type of control and to set about procuring

contracts for labor and materials. The commenter stated this is particularly concerning for the

Texas lignite units, the majority of which are fitted with sulfur dioxide controls already and have

no demonstrated control technology available for mercury removal. Given that national

applicability of this rule, Texas utilities will not be the only ones involved in this process. The

commenter was concerned about the effect on labor and material costs to the electric generators

as a result of such a shortened timeframe. All of the commenters believed it is important for the

deadlines and emission reduction levels to be tied to the practicability of hundreds of units to

acquire labor, materials and permits and control technologies (many at the same time) in order to

install controls without sacrificing reliable and low-cost electric generation. Several commenters

(2833, 3530) believed EPA should provide for time extensions for companies to comply with the

standards if they can demonstrate reasonable concern for grid reliability or security problems,

technological infeasibility or financial hardship. One commenter (OAR-2002-0056-2833) stated

that EPA should determine whether and when reliable, cost-effective control technologies to

capture mercury emissions will be fully developed and tested or made commercially available on a

wide-enough scale to reduce mercury emissions.

Many commenters (OAR-2002-0056-2067, -2332, -2375, -2441, -2551, -2899, -2915,

-2929, -3510, -3531) expressed concern that the proposed compliance schedule might not allow

sufficient time to install the control technologies that will be needed to meet the CAIR and

mercury program mandates, especially for reductions required by 2010. Several commenters

(OAR-2002-0056-2899, -2915) observed that EPA predicts, based on the CAIR proposal, that

almost 80 GW of capacity would install either flue gas desulfurization or selective catalytic

reduction to reduce SO2 and NOx, respectively, between 2005 and 2010. The commenters also

noted that EPA assumes that companies will not begin construction activities until 2007 when the

states and EPA finalize requirements, leaving just parts of three years (2007, 2008 and 2009) to

install control technologies on hundreds of generating units.

These commenters (OAR-2002-0056-2899, -2915) stated simultaneous installations of

controls under the CAIR and mercury programs at hundreds of units would stress labor,
xx

materials, and state and local permitting agencies. The commenters explained that the process for

a single installation would involve a complicated engineering review, negotiation of contracts with

vendors, obtaining permits from local and state authorities, and engaging contractors, materials

and machinery at the site for construction. The commenters added that all this would be done in

an environment of limited availability of expert labor, especially for boilermakers; in addition to a

shortage of boilermakers, there could be a shortage of electricians, pipefitters and ironworkers. 

The commenters also stated that installations take the plant off-line for weeks, and such outages

must be coordinated within the company and throughout the region with other types of outages in

order to avoid stretching the generation capacity too thin and exposing the grid to upset and

potential blackouts.

One commenter (OAR-2002-0056-2899) noted EPA assumes that the CAIR installations

can be done hundreds of times concurrently, in less time than electric companies believe possible.

According to the commenter, installing one scrubber requires approximately 48-54 months: about

12 months to select the appropriate technology and establish design criteria; 12-18 months for

engineering and design; and 24-30 months (depending on weather) for construction and startup.

The commenter added that the permitting process can take years, especially for a new landfill. The

commenter submitted that these time constraints would most likely be longer with hundreds of

affected sources installing control equipment within the same time frame. The commenter added

that the demand for labor for complying with the industrial boiler MACT program will further

strain the labor supply.

The commenter (OAR-2002-0056-2899) noted that the Utility Air Regulatory Group

(UARG) concluded that the probability is high that the boilermaker labor pool will not be

sufficient to install all of the necessary control technology by 2010; that is, 1) EPA has

optimistically assumed that all of the boilermakers who would be available for work on electric

utility environmental retrofit projects would be fully utilized, 40 hours a week for 50 weeks a

year, and 2) alternative electricity demand growth projections of the Energy Information

Administration (EIA) would require 15 percent greater retrofits.

One commenter (OAR-2002-0056-2661) stated that rural electric cooperatives generally

have systems that are smaller with fewer units than the average utility and, therefore, would have

an even more difficult time competing for limited resources and equipment. Also, the commenter

noted that the time needed by cooperatives to obtain financing from the Department of

Agriculture Rural Utility Services would not support a three or four-year compliance schedule,

which is key to providing safe, affordable, and reliable energy needs of our member-owners. The

commenter believed installation of any mercury control requirements must coincide and be

integrated with existing and new SO2, NOx and particulate control measures required over the

next decade.

One commenter (OAR-2002-0056-2067) stated that financing arrangements can pose

significant obstacles to a relatively short compliance period, especially for public power entities.

One commenter (OAR-2002-0056-2441) stated mercury-specific controls do not exist yet

on a commercially available basis and new regulations must provide adequate time for the
xxi

commercial development of control technologies capable of meeting emission reduction targets. 

Similarly several commenters OAR-2002-0056-2915, -3510) submitted that demonstrated control

technology does not exist to reduce mercury emissions from Gulf Coast lignite-fired power plants. 

Commenter OAR-2002-0056-2915 noted that the majority of Gulf Coast lignite-fired EGUs are

fitted with SO2 controls already.

One commenter (OAR-2002-0056-2929) stated that in its CAIR comments, the

commenter suggested that EPA take into consideration the difficulty for some companies to meet

the 2010 targets and provide a regulatory fix to this almost inevitable problem. The commenter

submitted the same regulatory considerations should be provided for a mercury cap-and-trade

program that relies on supposed CAIR co-benefits.

One commenter (OAR-2002-0056-2422) favored the longer time frames for compliance

that are available under cap-and-trade alternatives. The commenter believed that with the absence

of commercially demonstrated technologies for controlling mercury emissions from coal-fired

power plants, a longer compliance timetable such as 2018 would provide needed time for the

testing, demonstration and commercialization of Activated Carbon Injection and similarly

promising mercury control technologies.

Response:

EPA is finalizing a cap-and-trade program under section 111 and is finalizing caps and

timing that are integrated with the CAIR. See final rule preamble for further discussion. EPA

believes its timeframe is appropriately addresses the time needed to install controls and the

concerns about financing controls. See final rule preamble for further discussion.

Comment:

Many commenters stated that the compliance time frame for the cap and trade program

(2018) is too long. The commenters noted that banking provisions extend the compliance date

for 14 years or more. This would be counter to Clean Air Act requirements and also is at odds

with settlement agreement. These commenters supported an earlier time frame using the existing

provisions of the Clean Air Act for extensions under section 112(i) to allow time to install

controls or longer, using the Presidential exemption provision. One commenter

(OAR-2002-0056-2064) added that DOE is expected to have cost effective mercury control

available by 2010. EPA’s mercury rule should at least be consistent with that timing. One

commenter, OAR-2002-0056-2094, also believed reductions should occur by 2010 and the Clean

Air Act has provisions to accomodate this timeframe. Several commenters

(OAR-2002-0056-2094, -2108) also explained that compliance is needed by 2010 for states to

have TMDLs in place by 2015 to address impaired waters as required under the CWA. Another

commenter suggested that mercury controls should be in place at the same time as control for

other pollutants.

One commenter (OAR-2002-0056-2247) asserted the final mercury cap must be in place

sooner than 2018. The commenter concluded that the availability of labor is not a real constraint
xxii

as suggested by EPA in its rationale for the proposed effective dates of the caps. The commenter

noted that EPA’s own analysis shows that recent power plant activity due to the NOx SIP call has

increased the labor supply and other EPA analyses show that there is sufficient boilermaker labor

to meet the IAQR needs. This analysis did not take into account any increase in number of

boilermakers as a result of new demand. The commenter stated that the effective date for mercury

should be the same as the IAQR- an interim cap in 2010 and a final cap in 2015. This would not

change the costs for a significant portion of the units and would force control technology

development at a slightly aggressive date. The commenter believed an earlier date would not

seriously compromise a plant’s ability to plan and execute mercury reduction requirements. An

earlier deadline would also help to make technology available sooner to developing countries like

China. The commenter submitted this would better address concerns about mercury from global

sources if we could offer cost effective methods and deploy it sooner.

Response:

EPA is finalizing a cap-and-trade program under section 111 and is finalizing caps and

timing that are integrated with the CAIR. See final rule preamble for further discussion. EPA

believes its timeframe is appropriately addresses the time needed to install controls and the

concerns about financing controls. See final rule preamble for further discussion.

Comment:

Several commenters (OAR-2002-0056-1673, -2243, -2830, -2850, -2879, -2922, -3463,

-3469, -3539, -3548) supported EPA’s efforts to coordinate the mercury emissions reduction

program with the sulfur dioxide and nitrogen oxides reductions proposed under the IAQR rule. 

One commenter (OAR-2002-0056-2850) noted that keeping the timing of mercury rule control

requirements compatible with the IAQR should assure that cobenefits from SO2 and NOx cap and

trade methodology are not sub-optimized due to accelerated mercury control timing requirements. 

Another commenter stated that a multi-phased and balanced national cap and trade program

would take advantage of the co-benefits derived from implementation of the IAQR while

providing time for the full development and installation of mercury-specific control equipment.

Several commenters (OAR-2002-0056-2862, -3463) stated that compliance deadlines for

UMRR should be set to match the deadlines that are established for compliance with the phases of

the IAQR cap-and-trade program. One commenter (OAR-2002-0056-2826) noted EPA’s

proposed IAQR requires compliance with Phase I SO2 and NO, emission reductions by 2010 and

compliance with Phase II SO2 and NO, emission reductions by 2015. EPA’s MACT option

specifies a 2008 compliance deadline, while EPA’s Cap and Trade options under section 112 or

section 111 specify a 2010 Phase I compliance deadline. The section 111 and 112 Cap and Trade

Options also include a Phase II compliance date of 2018. One commenter

(OAR-2002-0056-3436) noted that these deadlines should be adjusted if the IAQR timeline is

adjusted. However, the commenter recommended that, if anything, the deadlines be pushed

further back into the future in order to allow time for the development of mercury control and

monitoring technologies for emissions from coal-fired power plants. Similarly another commenter

(OAR-2002-0056-3469) recommended that the compliance time frames proposed under the
xxiii

UMRR and IAQR be consistent and adjusted to reflect the two years which have passed since

Clear Skies was first proposed. The commenter stated that this would set the first phase

compliance date for a cap and trade program at 2012. An additional commenter

(OAR-2002-0056-3548) also strongly supported EPA’s efforts to coordinate the schedules of the

proposed IAQR and mercury rules, as many of the controls expected to be needed for the IAQR

may also address emissions of mercury.

One commenter (OAR-2002-0056-1673) submitted that to ensure a broad range of

compliance options, the cap-and-trade program under the UMRR and IAQR should be consistent

with previous trading rules.

One commenter (OAR-2002-0056-2243) stated that in a cap and trade environment,

addressing mercury, NOx, and SO2 simultaneously will insure that adequate allowances will be

available for either existing unit expansion and/or new project construction.

Several commenters (OAR-2002-0056-1889, -2323, -2346) stated that the cap-and-trade

program can be coordinated with the timing of SO2 and NOx controls proposed under the IAQR

and should be a nation-wide program. The commenters also stated that this coordination will

enable power generators to take full advantage of the way SCR and scrubber systems can help

reduce mercury emissions while also reducing SO2 and NOx. Several of the commenters

(OAR-2002-0056-1889, -2323) believed this allowance allocation system should mirror the

methodology used in the successful acid rain control program.

One commenter (OAR-2002-0056-2346) supported a multi-pollutant, market-based

approach and believed that with some enhancements, the IAQR could be a vital, cost-effective air

regulatory program for the United States. The commenter stated that the proposed cap-and-trade

program is superior to the MACT program because 1) Cap-and-trade would reduce mercury

emissions by almost 70 percent from 2001 levels, achieving the MACT goal by 2010 and capping

emissions at 15 tons in 2018. The MACT would only reduce these emissions from coal fired

power plants by 29 percent from 2001 levels by 2007; 2) There is no commercially available

mercury control technology for coal fired power plants. Therefore, it would be impossible for the

industry to comply with the MACT timetable of 2007; and 3) The cap-and-trade program can be

coordinated with the timing of SO2 and NOx controls proposed under the IAQR and should be a

nation-wide program.

One commenter (OAR-2002-0056-3830) has publicly supported the Clear Skies Initiative

and supports a coordinated approach to utility emission reductions that would provide a

“systems” approach, thus reducing uncertainty and cost. The commenter believed EPA’s intent to

coordinate the development of the proposed Mercury and CAIR rules would provide a more

cost-effective approach to developing emission control systems. The commenter supported, in

concept, the cap and trade as it would allow time for the development of potentially cost-effective

control technologies and would offer a more reasonable implementation schedule.

One commenter (OAR-2002-0056-2911) has been an advocate for a multi-pollutant

approach to address the need for the electric generation industry to make further reductions in the
xxiv

emissions of SO2, NOx and mercury. The commenter believed that a comprehensive program

would produce those reductions faster and more cost-effectively than the traditional regulatory

approach. The commenter stated that EPA is to be commended for its efforts to craft a

regulatory framework to implement such a program. However, the commenter believed that a

multi-pollutant approach would be best implemented through legislation. The commenter stated

that EPA faces many obstacles as it moves to implement a multi-pollutant program for EGUs,

within the existing framework of the Clean Air Act–particularly with respect to keeping the

schedules of the CAIR and the proposed mercury rule in synch.

One commenter (OAR-2002-0056-2850) stated that it is crucial that any regulatory

requirements result in a level playing field for all affected sources. The commenter added that

compliance timeframes must be flexible and harmonized with the Clean Air Interstate Rule

(CAIR) to ensure continued reliability, to feasibly allow capital investment, and to recognize that

there are no currently available commercial technologies designed exclusively for mercury control

from electric utilities.

Response:

EPA is finalizing a cap-and-trade program under section 111 and is finalizing caps and

timing that are integrated with the CAIR. See final rule preamble for further discussion.

5.3.2 Level of Reduction Required by Caps

Comment:

One commenter (OAR-2002-0056-1768) stated that deeper mercury reductions beyond

the co-benefits associated with SO2 and NOx caps should be based on the progress of technology

development and a clear demonstration of a health benefit. Also, emerging scientific research

suggested to the commenter that reducing mercury emissions from the U.S. power generating

sector does little to reduce the amount of mercury deposition in the United States or the levels of

methyl-mercury in fish. The commenter submitted that forcing all power plants to install

expensive anti-pollution devices would not necessarily ensure reductions in methylated mercury

levels in local environments. The commenter asserted that the final rules must address the

scientific uncertainties and complexities of mercury pollution in addition to providing flexibility

and weighing known costs against unknown benefits of regulation.

Response:

EPA is finalizing a cap-and-trade program under section 111, and establishing a first

phase cap of 38 tons and a second phase cap of 15 tons. See preamble for further rationale for

the 15 ton cap.

Comment: One commenter (OAR-2002-0056-1611) submitted that the NC Clean

Smokestacks Act will reduce emissions far more than the President’s proposal and should be used

as the national model rule.
xxv

Response:

EPA is finalizing a cap-and-trade program under section 111, and establishing a first

phase cap of 38 tons and a second phase cap of 15 tons. See preamble for further discussion.

Comment:

Several commenters (OAR-2002-0056-2660, -2838, -2871, -2887, -2889, -3437, -3449,

-4117) submitted that the proposed mercury standards under the cap and trade options are too

weak and the implementation time frame is too long.

One commenter (OAR-2002-0056-3449) stated that trading only makes sense if the caps

are set at well below the standards that otherwise would have been set. Commenter

OAR-2002-0056-3449 believed a defensible MACT standard should result in emissions in the

5-10 tpy range by a set deadline, which would be a much greater reduction than the 15 tpy actual

in 2018 that EPA proposed.

One commenter (OAR-2002-0056-3437) was concerned that EPA is using projections to

estimate future emissions and reductions. The proposed Phase II cap would be 15 tons in 2018

based on a percentage reduction rather than an estimate of possible emissions based on possibly

faulty projections. The commenter submitted that EPA should determine a reasonable percentage

reduction for both Phase I and Phase II and should not use unknow co-benefits for establishing a

budget. Several commenters (OAR-2002-0056-2871, -2889, -2660, -2838, -2887, -4117) also

pointed out that the Phase I cap (34 ton/yr cap in 2010) does not require any mercury specific

controls beyond the incidental reductions expected from the IAQR. The commenters added,

while the proposal cites a 15 ton/yr final cap in 2018, the impacts analysis shows the final cap

would not be achieved. The commenters noted that EPA acknowledged that emissions could be

as high as 22 tons when banking, trading, and resultant delays are considered. One Commenter

(OAR-2002-0056-2887) also pointed out that the section 111 proposal is totally dependent on the

IAQR. The commenters asked, what if the IAQR is not finalized or promulgation is delayed? 

The commenters believed it is questionable that the interim cap would be enforceable. Another

commenter (OAR-2002-0056-2660) added that that IAQR does not extend to the 15 western

states so it is possible there would be no mercury reduction ever from any western power plants

and that the limits for subbituminous coal are so lax that there probably will not be any mercury

reduction within the state either. The commenter asserted the proposed limits would not achieve

the needed reductions.

One commenter (OAR-2002-0056-2887) and several states also opposed the section 111

proposal because the deadlines are extremely protracted given the seriousness of mercury

pollution and its toxicity. The commenters pointed out that the settlement agreement calls for

final HAP standards by March 2005, with compliance by December 2007 (with extensions if

justified). The proposal postpones compliance until 2018 and beyond due to banking and trading

provisions. The commenters submitted this delay is inappropriate, irresponsible, and

unacceptable. It is also counter to CAA requirements and the settlement agreement. The
xxvi

commenters believed feasible controls are certainly available now. The commenters pointed out

that for example, Massachusetts rules require 85 percent control by 2008 and 95 percent in 2012.

Response:

EPA is finalizing a cap-and-trade program under section 111, and establishing a first

phase cap of 38 tons and a second phase cap of 15 tons. See preamble for further rationale.

Comment:

One commenter (OAR-2002-0056-4177) opposed the cap and trade approach but stated

that if EPA proceeds with it, the cap should be about 7 tons/yr (same as an appropriate MACT

standard), with a final compliance date as close as possible to the 2007 date required by section

112 and the court settlement agreement.

Several commenters (OAR-2002-0056-0501, -2569) specifically stated that a more

ambitious cap and trade program might be effective in reducing emissions with minimal costs to

industry. One commenter (OAR-2002-0056-2569) recommended increasing the phase I

reduction to 20 tons by 2009 and the phase 2 reduction to 45 tons by 2015. The commenter

believed these reductions ccould be made easily on those plants with configurations compatible

with existing control technology.

One commenter (OAR-2002-0056-3444) submitted that the calculation of achievable caps

in 2010 and 2018 would require operating data of Utility Units during the baseline period.

Response:

EPA is finalizing a cap-and-trade program under section 111, and establishing a first

phase cap of 38 tons and a second phase cap of 15 tons. See preamble for further rationale.

Comment:

Several commenters (OAR-2002-0056-2519, -3543) submitted that the extent of

co-benefits reductions of SO2 and NOx controls is unknown under the cap and trade program. 

One commenter (OAR-2002-0056-2519) noted that the EPA proposal solicits comments on what

level should be selected for Phase I mercury emissions cap. The proposal states that EPA expects

mercury emission reductions under the Phase I cap would result via “co-benefits” (resulting from

actions designed to achieve SO2 and NOx emission controls by retrofitting SO2 scrubbers and

SCR) in areas covered by the proposed Interstate Air Quality Rule (IAQR region) of 29 Eastern

sates and D.C. EPA suggested setting a Phase I cap of around 34 tons, the level anticipated via

co-benefits from sources located throughout the country. The commenter stated however, similar

estimates by WEST Associates and the U. S. Department of Energy range from 36.5 tons to

42 tons. The commenter believed that with the 1999 baseline mercury emissions of 48 tons,

setting a Phase I cap “too high” will create a credibility problem while picking a cap that is “too

low” may not be achievable with co-benefits alone.
xxvii

The commenter submitted it is not possible to accurately predict how much mercury

emission reductions will occur via co-benefits in the IAQR region. First, because the proposed

mercury cap-and-trade program does not impose any geographic limitation on mercury trading,

there is no assurance which plants will reduce emissions, and which will rely on buying credits

from the market. For example, some of the reductions would occur at plants located outside the

IAQR region, and hence, the reductions from the IAQR region would be less than estimated.

Second, many, if not most sources in the IAQR region could shift their fuel (where the

infrastructure exists) from current use of bituminous coal to sub-bituminous coal (not only for

mercury reduction purposes but also to reduce SO2 emission reductions for achieving PM2.5

standards). The commenter added it is well known that mercury reductions expected via

co-benefits from sub-bituminous coal are much lower than in the case of bituminous coal.

Therefore, not knowing which plants might switch fuel or which plants will elect to buy credits,

there is no way anyone can accurately predict what level of mercury emission reductions would

occur via co-benefits. The commenter stated thus, it is not possible to set a Phase I mercury

emissions cap that relies exclusively on co-benefits in the IAQR region.

The commenter also stated that finally, EPA has not provided state-by-state mercury

budgets for Phase I starting in 2010, primarily due to the fact that EPA has not specified a Phase I

cap. It was unclear to the commenter whether EPA expects mercury emission reductions during

Phase I (via co-benefits) from sources located outside the IAQR region. The commenter noted

that as sources outside the IAQR region are not expected to install scrubbers and SCR to attain

PM2.5 standards, no mercury emission reductions via co-benefits can be expected to occur at

sources outside the IAQR region in the near term. Accordingly, if the Phase I cap is set beyond

the co-benefits level, sources outside the IAQR region will have to either install scrubbers and

SCR or other mercury specific control measures sooner than their counterparts would have to do

in the IAQR region. The commenter points out that such a scenario could result in unfair

competitive advantages for sources in the IAQR region. Accordingly, there is considerable

uncertainty on the compliance obligations under Phase I for sources located in regions outside the

IAQR region.

Response:

EPA is finalizing a cap-and-trade program under section 111, and establishing a first

phase cap of 38 tons and a second phase cap of 15 tons. See final preamble for further

rationale. EPA is establishing a firm cap for the first phase and provided State and Tribal

emissions budgets. For further discussion of state emision budgets see final rule preamble

(section IV.C.4) and Technical Support Document for CAMR Notice of Final Rulemaking, State

and Tribal Emissions Budgets, EPA, March 2005.

Comment:

Many commenters (OAR-2002-0056-1608, -1768, -1859, -1969, -2224, -2375, -2818,

-2830, -2833, -2835, -2850, -2861, -2895, -2898, -2907, -2918, -3327, -3444, -3463, -3469,

-3530, -3546, -4891) supported setting the phase I mercury cap at a level that’s commensurate
xxviii

with the co-benefit reductions anticipated to be achieved through implementation of SO2 and NOx

reductions under the transport rule.

Several commenters (OAR-2002-0056-1969, -2830, -3463, -3469) asserted that tying the

proposed 2010 mercury reductions to co-benefits will allow reliable data on the mercury content

of lignite and mercury emissions to be collected, co-benefits to be evaluated, and will provide

additional time to research and develop effective control and monitoring technology. Thus, the

commenters recommended against setting a hard cap and recommended that the cap simply be the

level which co-benefits can deliver.

Commenters OAR-2002-0056-3463 and OAR-2002-0056-3469 stated that if a soft cap

approach is adopted, banking of allowances should not be permitted in Phase I. One commenter

(OAR-2002-0056-3463) added that a non-numeric cap such as this is also appropriate because

mercury removal as a co-benefit of SO2 and NOx control technology is unproven. According to

the commenter, EPA has acknowledged that currently-available control equipment cannot achieve

consistent levels of mercury removal in the elemental phase. The commenter stated that since

current control equipment cannot effectively remove mercury in the elemental phase, EPA should

not put a cap on emissions levels from lignite-fired units. According to the commenter, with no

known control method for elemental mercury, a specific limit on lignite emissions levels would

force lignite operations to buy allowances or switch fuel–either of which would effectively put the

Texas Gulf Coast Lignite industry out of business.

One commenter (OAR-2002-0056-2224) stated that EPA does not propose a specific

level of mercury control for Phase I of the cap-and-trade program under either option. The

commenter noted that rather, EPA proposes to set the mercury emissions cap at the level that can

be achieved through the installation of controls that are necessary to meet the Phase I emission

caps in the proposed IAQR. The commenter asserted that setting the mercury missions cap at this

level fully realizes the mercury “co-benefit” reductions associated with the controls required under

the IAQR. According to the commenter, a more stringent emissions cap—that is one that does

not correspond to the controls for NOx and SO2–would present significant compliance and

reliability concerns to the power industry given that control technologies for mercury are not yet

commercially available. The commenter was still evaluating the appropriate level for setting a

“co-benefit” emission cap. The commenter stated that EPA should be guided by best available

data from technical analyses developed by DOE and other entities that suggest that a 34-ton cap

level may be overly optimistic. The commenter noted that when setting the Phase I mercury cap,

EPA should consider that the IAQR only covers the Eastern United States.

One commenter (OAR-2002-0056-2918) stated that the amount of mercury emissions

reduction that will be achieved as co-benefits has a particularly significant impact in the western

U.S. According to the commenter, two-thirds of the western units are already scrubbed to

remove SO2. The commenter added however, that scrubber technology is not as effective in

mercury capture in the western U.S. because coals burned there emit a relatively higher

proportion of elemental mercury compared to oxidized mercury due to their lower chlorine

content.
xxix

In an analysis included in the docket (OAR-2002-0056-1912), commenter

OAR-2002-0056-2918 examined EPA’s NATEMIS files and the applicable data sets from EPA’s

1999 Information Collection Request (ICR) supporting this rulemaking, and estimated the

maximum co-benefits achievable by the application of pollution controls to coal-fired units to

meet proposed CSA reduction targets for SO2 and NOx. The commenter submitted that this

analysis indicates a co-benefits cap of 36.5 tons under the best of circumstances. The commenter

believed that in all likelihood, co-benefit mercury emission reductions will be less, and the Phase I

cap should be set at a higher level. Consequently, if the 2010 cap is to truly reflect co-benefits,

then it was the commenter’s view that it should be at minimum of 36.5 tons. One commenter

(OAR-2002-0056-3522) proposed that the Phase I cap be set at no less than 36.5 tons as

commenter OAR-2002-0056-2918 recommended, and that this cap be accompanied by an

effective safety valve. This commenter added that others, such as the Department of Energy,

estimated even higher emissions, depending, for example, on whether one assumes that the use of

SCR reduces emissions of mercury along with emissions of NOx.

One commenter (OAR-2002-0056-2900) also stated that EPA has suggested that the

appropriate mercury cap for Phase I is 34 tons and noted that Department of Energy and West

Associates data suggest that a higher level likely is more realistic. First, the commenter did not

believe that EPA had taken into account many units that recently have switched or are in the

process of switching to sub-bituminous, low sulfur coal. The commenter stated that as a result of

such fuel switching, the reductions EPA has anticipated due to the co-benefits of SO2 and NOx

controls and based on the proposed MACT standards would not be as great. Second, the

commenter believed EPA needs to re-evaluate the overall expected mercury co-benefits of

compliance with Phase I of the CAIR.

Response:

EPA is finalizing a cap-and-trade program under section 111, and establishing a first

phase cap of 38 tons and a second phase cap of 15 tons. EPA is establishing a firm cap of

38 tons based on EPA’s modeling of projected CAIR Hg co-benefits. See final preamble for

further rationale.

Comment:

Several commenters (OAR-2002-0056-2375, -2903) suggested to avoid basing the Phase

I cap on as-yet-unknown Interstate Air Quality Rule (IAQR) co-benefits, EPA should promulgate

a final rule stating that the Phase I cap will be at least 34 tpy and no greater than 38 tpy. The

commenters continued that based on emissions data that will be available to EPA in 2008, EPA

should determine in 2009 what the Phase I cap should be in 2010. The commenters concluded

that if EPA determines that co-benefits have resulted in emissions (i) below 34 tpy, EPA will set a

34 tpy Phase I cap; (ii) between 34 tpy and 38 tpy, EPA will set the cap at the specific level; (iii)

greater than 38 tpy, EPA will set a 38 tpy Phase I cap.

Response:
xxx

EPA is finalizing a cap-and-trade program under section 111, and establishing a first

phase cap of 38 tons and a second phase cap of 15 tons. EPA is establishing a firm cap of

38 tons based on EPA’s modeling of projected CAIR Hg co-benefits. EPA believes it is

important to establish the cap level in the final rulemaking to provide affected sources with

certainty and time for compliance planning. See final preamble for further rationale.

Comment:

Similarly one commenter (OAR-2002-0056-3443) recommended the imposition of a

Phase I cap of 34 tons per year if the cap and trade program allows for early reduction credits

starting in 2008. The commenter noted that early reduction incentives would offer facilities the

opportunity to minimize compliance risks and the ability to deliver low-cost, reliable electrical

power by accumulating a small buffer of allowances prior to the Phase I start date. Equally

important, early reductions would be environmentally beneficial since they would help reduce

mercury emissions prior to the Phase I deadline. Alternatively, in the absence of early reduction

incentives, the commenter recommended that the Phase I cap be established at the higher end of

the CAIR emission levels, i.e., at 38 tons, to account for variability in mercury emissions data. 

The commenter noted that these recommendations for a Phase I cap were based on the use of

heat input adjustment multipliers proposed by EPA (1:1.25:3.0). The commenter believed any

further adjustment to these multipliers should be accompanied by a commensurate adjustment of

the cap.

Response:

EPA is finalizing a cap-and-trade program under section 111, and establishing a first

phase cap of 38 tons and a second phase cap of 15 tons. EPA is establishing a firm cap of

38 tons based on EPA’s modeling of projected CAIR Hg co-benefits. See final preamble for

further rationale. As discussed in comment responses below, section 5.8.3, EPA is not including

early reduction credits for Hg in the final rulemaking.

Comment:

Several commenters (OAR-2002-0056-1768, -2833, -3530) stated that many groups are

calling for a more stringent mercury cap than the level of reductions achieved through

“co-benefits” of SO2 and NOx reductions on a faster timetable, under which many plants would be

forced to invest over a very short time period in expensive technologies that may not be fully

proven for every application nor achieve desired results. The commenters believe that many

generators may choose not to “gamble” with their ratepayers’ or investors’ dollars and instead

choose to prematurely retire existing coal-fired capacity, thereby exacerbating utility demand for

natural gas. 

One commenter (OAR-2002-0056-2835) agreed with EPA that it is unrealistic to establish

a mercury cap based on the reductions possibly achievable through activated carbon injection

(ACI) and other such breakthrough technologies (e.g., chemical systems to enhance mercury

removal efficiencies for wet scrubbers). The commenter believed that these technologies have not
xxxi

been adequately demonstrated on full-scale power plants and thus do not currently provide a

reliable means to achieve mercury reductions below the levels achievable through SO2 scrubbers

and selective catalytic reduction (SCR) systems for NOx. For these reasons, the commenter

supported EPA setting the Phase I mercury cap at levels that can be achieved through installation

of such conventional SO2 and NOx control technologies. The commenter submitted that under

this approach, the emissions cap would match actual projected mercury emissions instead of

hypothetical best mercury performance through unproven mercury control technologies that are

not yet demonstrated. The commenter believes this approach is consistent with the requirement in

CAA section 111(d) that the standard of performance be based on the best system of emission

reduction that has been adequately demonstrated. The commenter also noted that when setting

the Phase I mercury cap, EPA needs to address that the transport rule only covers the eastern

states and the very minimal co-benefit mercury reductions achievable in the west, even if the

transport rule is expanded to the entire continental United States. Moreover, the commenter also

recommended that the Phase I cap for mercury reflect the use of banked SO2 and NOx allowances

to meet Phase I of the transport rule.

Response:

EPA is finalizing a cap-and-trade program under section 111, and establishing a first

phase cap of 38 tons and a second phase cap of 15 tons. EPA is establishing a firm cap of

38 tons based on EPA’s modeling of projected CAIR Hg co-benefits. See final preamble for

further rationale. 

Commenter:

One commenter (OAR-2002-0056-2861) believed that any regulation of mercury

emissions from coal-fired power plants that goes beyond the level of co-benefit reductions would

be premature. The commenter submitted that mercury-specific control technologies to achieve

reliable reductions in mercury emissions from power plants are not commercially available, as

EPA acknowledged in its proposal. The commenter noted that while EPA’s response to that

problem is to develop a cap based on “co-benefits” of SO2 and NOx controls beginning in 2010,

the problem remains that establishing any hard cap in 2010 would be inconsistent with a

“co-benefits” philosophy. The commenter claimed the performance of SO2 and NOx controls

relative to their ability to consistently and reliably remove mercury is still largely unknown. The

commenter asserted therefore, since it is impossible at this time to predict with reasonable

certainty either the SO2 and NOx controls that will be installed to comply with EPA’s CAIR or

their effectiveness at removing mercury, any attempt by EPA to set a hard emissions cap in 2010

at any level and call it a co-benefit is nothing more than a guess, with the utility industry and its

customers holding the risk. If EPA guessed on the low side and set a cap below what co-benefits

would actually turn out to be as a result of CAIR implementation (the 34 ton number that has

surfaced as a possible level that EPA may be considering for a 2010 co-benefits cap by all

accounts is well below even the most aggressive estimate of what co-benefits might turn out to be

in 2010), the industry would be faced with having to install controls specifically to remove

mercury, controls that by 2010 EPA acknowledges will not be ready for deployment in support of
xxxii

a regulatory requirement. The commenter stated that promulgating such a regulatory requirement

would seem an archetype of arbitrary and capricious agency action.

Commenter OAR-2002-0056-2861 stated that utilities and others are investigating ways

to make the performance of SO2 and NOx controls more predictable and consistent, but at this

time there is no way to know with any certainty how much reduction can be reliably achieved at a

particular unit over an extended period of time. The commenter asserted not only would this

uncertainty create problems for assuring compliance at a given unit, but also it would have serious

impacts on the ability to create a robust and effective emissions trading market. The commenter

submitted utilities will be reluctant to sell allowances if they are unsure whether they can actually

achieve the reductions necessary to free up excess allowances.

In light of concerns over technology availability and performance and the likely adverse

impacts on the efficient operation of a cap and trade program, commenter 2861 recommended

that no hard cap on mercury emissions be set for either 2010 or 2018 at this time. The

commenter suggested instead, any final rule should specify that reductions in mercury emissions

will be measured to quantify the co-benefit performance of controls that will be required under

separate federal or state programs including the CAIR, Regional Haze, or state requirements such

as North Carolina’s Clean Smokestacks Act. The commenter stated that to assure that co-benefit

mercury reductions are maximized, EPA could specify that each unit equipped with a wet or dry

SO2 flue gas desulfurization (FGD) system would develop an operational plan to quantify mercury

reductions and to develop operational parameters to optimize mercury removal performance to

the extent practical, without adverse impact on boiler performance or SO2 and NOx removal. The

commenter added the rule could also specify that the question of whether to require reductions

beyond co-benefits would be revisited by 2013 after several years of operating data are collected

and analyzed. These data would provide better information about the actual co-benefit level of

reductions that can be achieved and will inform an assessment of whether further reductions

beyond co-benefits are warranted. The commenter believed this approach would provide several

years to gather data on mercury speciation, mercury removal associated with FGD and SCR

systems, and advances in mercury control technology for both elemental and non-elemental

mercury.

Response:

EPA is finalizing a cap-and-trade program under section 111, and establishing a first

phase cap of 38 tons and a second phase cap of 15 tons. EPA is establishing a firm cap of

38 tons based on EPA’s modeling of projected CAIR Hg co-benefits. EPA believes it is

important to establish the cap level in the final rulemaking to provide affected sources with

certainty and time for compliance planning. See final preamble for further rationale.

Comment: One commenter (OAR-2002-0056-2895) noted that the exact level of mercury

reduction that will be realized as a result of the IAQR is uncertain and hence the level of a

co-benefit cap is not known. The commenter submitted that estimates of a co-benefit cap range

from 34 to 42 tons. The commenter suggested that one possible approach to establishing a

co-benefits cap would be to implement required mercury monitoring (source testing or
xxxiii

monitoring) in the beginning of 2008. By mid 2009, the EPA would have more mercury emission

data that could be used to estimate a more informed level for a co-benefit cap. The commenter

stated the December 2004 final rule can establish a co-benefit level range with the final number

being established in mid 2009.

One commenter (OAR-2002-0056-2907) supported a Phase I program based on a true

co-benefits approach, which must take into account the fact that it is more difficult to remove

elemental mercury from sub-bituminous and lignite coals than it is to remove oxidized mercury

from bituminous coal. The commenter noted there is considerable uncertainty regarding the

appropriate co-benefits level. Unless EPA can establish the co-benefits cap with certainty, the

commenter encouraged the Agency to consider alternatives to a hard 2010 cap on mercury

emissions. The commenter’s alternatives included (1) deferring a 2010 cap as proposed by EEl; or

(2) creating another mechanism to provide industry with adequate relief in the event actual

mercury emissions exceed the projected co-benefits emissions level.

One commenter (OAR-2002-0056-3543) stated EPA’s rationale for setting Phase I

mercury cap at a level that can be achieved through FGD and SCR was inconsistent with the

preamble rationale which stated that uncertainty exists in the level of reduction that may be

achieved through FGD and SCR on different boiler types burning different ranks of coal.

One commenter (OAR-2002-0056-2430) stated EPA’s proposal discussed mercury

reductions in 2010 as a co-benefit of the controls required by the IAQR. However, no method for

quantifying the mercury reduction was discussed, making it impossible to evaluate expected 2010

reductions under the trading program with 2010 under the MACT proposal.

Response:

EPA is finalizing a cap-and-trade program under section 111, and establishing a first

phase cap of 38 tons and a second phase cap of 15 tons. EPA is establishing a firm cap of

38 tons based on EPA’s modeling of projected CAIR Hg co-benefits. EPA believes it is

important to establish the cap level in the final rulemaking to provide affected sources with

certainty and time for compliance planning. See final preamble for further rationale.

Comment:

Several commenters (OAR-2002-0056-2521, -2634, -3543) recommended setting a Phase

I hard cap. One commenter (OAR-2002-0056-2521) noted that EPA’s current proposal includes

the following: 1) depending on which of the proposed approaches the Agency adopts, a 34-ton

limit or cap on mercury emissions in 2008 to 2010 (a 29 percent reduction from 1999 levels), and

a 15-ton cap in 2018 (a 69 percent reduction), and 2) no limit on trading. The commenter then

noted that these are the corresponding provisions of the Clean Air Planning Act: 1) a 24-ton cap

on mercury emissions in 2009 (a 50 percent reduction from 1999 levels) and a 10-ton cap in 2013

(a 79 percent reduction), and 2) trading of mercury allowances after imposition of a reduction

requirement on each facility (of 50 percent in 2009, and 70 percent in 2013, calculated with

reference to the quantity of mercury in the coal).
xxxiv

The commenter also stated that during the course of the Working Group’s proceedings,

the commenter made specific recommendations (letter to Mr. John Paul, co-chair of the Working

Group, dated March 28, 2003) regarding subcategories of coal-fired units and emission rates for

each subcategory. (According to the commenter, they noted in their March 28 submission that

they supported a combined standard that allows the opportunity to meet either a specified

emission rate or control efficiency; however, they included only emission rate recommendations at

that time in light of the fact that the IPM model-which EPA had intended to use to model the

stakeholder recommendations cannot be run with control efficiencies.)

The commenter stated that although their recommendations were rate-based and they did

not translate those recommendations into total mass emissions from the industry sector, the

Northeast States for Coordinated Air Use Management (NESCAUM) has since done an analysis

that translates the recommendations of all of the stakeholder groups that participated in the

Working Group into tons of emissions from the industry. According to NESCAUM, the

commenter’s rate-based recommendations equate to total industry emissions of 13.1 tons of

mercury per year, with an implementation date of 2008. Although the commenter was not

advocating MACT standards that equate to a highly specific industry-sector tonnage limit, they

adopted that calculation for the purposes of having a common metric with which to compare the

proposed EPA, Clean Air Planning Act, and commenter’s approaches to limiting mercury

emissions.

One commenter (OAR-2002-0056-3543) recommended strengthening Phase I by

establishing a hard cap at a level designed to eliminate most of the ionic mercury emissions from

affected units.

One commenter (OAR-2002-0056-2634) stated that if EPA ultimately decides to establish

a numerical cap for 2010 as well as 2018, the commenter supported the position being proposed

in WEST’s comments, whereas the 2010 cap would be set at 36.5 tons with enhanced safety

valves available in 2010 and 2018.

Response:

EPA is finalizing a cap-and-trade program under section 111, and establishing a first

phase cap of 38 tons and a second phase cap of 15 tons. EPA is establishing a firm cap of

38 tons based on EPA’s modeling of projected CAIR Hg co-benefits. EPA believes it is

important to establish the cap level in the final rulemaking to provide affected sources with

certainty and time for compliance planning. See final preamble for further rationale.

Comment: One commenter (OAR-2002-0056-2835) noted that questions have been raised

regarding the timing and stringency of the Phase II mercury cap. These questions appear to stem

from the concern that the Phase II compliance deadline for mercury (2018) is three years after the

Phase II compliance deadline for SO2 and NOx (2015) under the transport rule. The commenter

acknowledged that this mismatch in compliance deadlines may enable many electric utilities to

bank significant amounts of mercury allowances between 2015 and 2018, and these banked

allowances may delay achievement of the Phase II mercury cap for many years after 2018.
xxxv

Furthermore, the commenter acknowledged these concerns, if substantiated, may justify the need

for adopting an interim cap in 2015 that is more stringent than the co-benefit cap set in 2010. 

Under this approach, EPA might defer the imposition of a numeric cap in 2010, preclude banking

of pre-2015 allowances in most cases, and require electric utilities to monitor mercury emissions

during the initial phase of the program (e.g., 2008 to 2014). The commenter submitted that

another approach might be to maintain the co-benefit cap in Phase I (2010-2014), but set it at a

slightly higher level to address the many uncertainties inherent during the initial compliance

period. Generally speaking, these uncertainties relate to the baseline emissions levels for all

affected coal-fired utility units and co-benefit mercury levels projected in 2010 as a result of the

transport rule. The program would then: 

• Establish an interim cap that would apply during the 2015-2017 period. The control level

of the interim cap would be set to reflect, in part, the additional co-benefit mercury

reductions achieved under Phase II of the transport rule. 

• End with final cap of 15 tons in 2018, as initially proposed by EPA under both

cap-and-trade options.

One commenter (OAR-2002-0056-2224) was still evaluating the need and appropriateness

of setting an interim mercury cap that would be slightly more stringent than the Phase I cap and

might be imposed between the Phase I and Phase II compliance deadlines. The commenter was

not opposed to the imposition of such an interim cap if additional mercury reductions are

appropriate and necessary prior to 2018 and if the timing and reduction levels of the interim cap

levels are done correctly.

One commenter (OAR-2002-0056-2725) noted that in setting an interim milestone, EPA

should remember that much of the industry will spend significant dollars and resources over the

next ten years reducing emissions of SO2 and NOx under the Interstate Air Quality Rule (IAQR)

or other programs, and these efforts should result in significant mercury reductions. The

commenter believed that EPA should ensure that any interim milestone is consistent with the

co-benefits expected from other control systems installed pursuant to the IAQR. The commenter

stated that, as with the final milestone, EPA should recognize the mercury emission reductions

arising in the West under other regulatory programs such as Regional Haze.

Several commenters (OAR-2002-0056-2850, -2883, -3443, -3478, -4891) supported the

establishment of an interim cap of 24 tons of mercury in 2015 when IAQR Phase II controls are in

place. Commenter OAR-2002-0056-2850 stated that this is consistent with the utility industry’s

commitment to ensuring that the 15-ton cap is met in 2018. Commenter OAR-2002-0056-3478

added that establishing a “hard cap” in 2015 would also limit the amount of mercury allowances

that could be banked by 2018 and, therefore, attain the final goal of 15 tons earlier. Commenter

OAR-2002-0056-3443 stated they can support the establishment of an intermediate cap in 2015 if

early reductions can be banked starting in 2008. The commenter believed banking encourages

earlier or greater reductions than are required from sources, stimulates the market and provides

flexibility in achieving emissions reduction goals. The commenter submitted that these advantages

notwithstanding, banking can also result in the use of allowances in a particular year that exceed
xxxvi

the state’s trading program budget. Thus, an excessive accumulation of banked allowances could

result in a situation where actual emissions in 2018 are significantly above the Phase II cap of

15 tons per year. To prevent the accumulation of excess allowances, the commenter could

support the establishment of an intermediate mercury cap of 24 tons in 2015 and a onetime

discounting (as described in the following comment ) in 2018.

Response:

EPA is finalizing a cap-and-trade program under section 111, and establishing a first

phase cap of 38 tons and a second phase cap of 15 tons. EPA is establishing a firm cap of

38 tons based on EPA’s modeling of projected CAIR Hg co-benefits. EPA believes it is

important to establish the cap level in the final rulemaking to provide affected sources with

certainty and time for compliance planning. See final preamble for further rationale.

Comment:

One commenter (OAR-2002-0056-2898) stated the 2018 cap level is too stringent given

today’s state of development of mercury control technologies. The commenter believed it is

speculative that controls would be advanced to the point of being capable of controlling mercury

emissions nation-wide to levels proposed for 2018. The commenter noted control technology for

mercury removal is in the developmental stage. The commenter noted further that the proposed

2018 cap of 15 tons would require technologies that can remove elemental mercury. Since, these

technologies are not proven at this time, the commenter submitted that EPA should include

provisions in the rule to revisit the long-term cap if technology does not develop that will allow

regulated sources to meet this cap. The commenter believed the U.S. economical impact must be

weighed against any human health and environmental benefit that would result in the additional

reductions.

One commenter (OAR-2002-0056-2907) also had concerns with the proposed Phase II

cap of 15 tons. This commenter also believed the cap will require significant reductions in

mercury that do not appear to be attainable with current technology. The commenter

acknowledged there is considerable ongoing research investigating new technologies to reduce

mercury emissions and lower the costs of control, the commenter believed it is premature to set a

cap based on the presumption that cost effective controls will be available by 2018. For this

reason, the commenter supported a robust “safety valve” to ensure that the mercury emissions

reductions required by the Phase II cap are achievable. The commenter stated WEST Associates

is filing comments containing such a safety valve.

Several commenters (OAR-2002-0056-3463, -3469) challenged the legal basis for EPA’s

proposed cap of 15 tons starting in 2018. The commenters claimed the proposal is based on

unproven mercury control technology with no associated cost estimates. One commenter

(OAR-2002-0056-3463) stated that lignite-fired facilities cannot meet this cap limitation with

currently available control technology. The commenter stated that EPA cannot use untested

technologies to set emissions requirements. The commenter believed insufficient data exists to

establish reliable and attainable mercury emissions limit at this time. The commenter urged EPA
xxxvii

to postpone setting a cap for Phase II until reliable data is collected, IAQR-related co-benefit

emission reductions are evaluated, and control technology for mercury is developed. One

commenter (OAR-2002-0056-3469) stated that given the high level of elemental mercury in

lignite and the difficulty of capture it poses, lignite will be put at a disadvantage and utilities will

have to purchase excessive amounts of allowances, if available, in order to comply. Both

commenters recommended that EPA should establish a Phase II cap based upon the following:

data resulting from Phase I, sound science, verifiable public health benefits, proven mercury

control technologies, coal type differentiation, amount of contribution to global mercury levels,

and equitable treatment of lignite in connection with the cap-and-trade program.

One commenter (OAR-2002-0056-2918) stated that in the NPR, EPA proposed a Phase 2

cap of 15 tons, which reflects approximately a 70 percent reduction from current emissions. The

commenter noted the NPR indicates that this cap is based on the modeling used to support the

CSA. The NPR specifically states that this modeling “suggests that, assuming technologies such

as Activated Carbon Injection (ACI) become available, such a cap (15 tons) will create an

incentive for certain plants to install these newer technologies.” However, the commenter, in the

analysis referred to in the discussion concerning the Proposed Phase 1 cap

(OAR-2002-0056-1912), calculated the resulting emissions based on the assumption that a total

of 875 units–288,874 MW or ~88 pecent of total generation–were retrofitted with ACI. The

commenter’s analysis indicated that the resulting mercury emissions would be 19 tons, which is

4 tons higher than the proposed Phase II cap. The commenter concluded that consequently, given

the Phase 2 cap is based on the underlying assumptions about the availability of ACI as suggested

by CSA modeling, the Phase 2 (2018) cap should in fact be 19 tons.

Several commenters (OAR-2002-0056-2835, -3443, -4891) accepted a final 15-ton cap to

become effective in 2018. One commenter (OAR-2002-0056-2835) stated that although

ambitious, the level of control may be achievable based on the incremental co-benefit reductions

expected from Phase II of the transport rule. The commenter believed that in addition, it is

reasonable to expect that additional mercury reductions can be cost-effectively achieved in 2018

through the application of ACI and/or other emerging technologies that are expected to become

commercially available for deployment after 2010. To address the issue of excessive

accumulation of banked allowances, one commenter (OAR-2002-0056-3443) recommended that

allowances could be discounted in 2018 by a preset percentage of the owner’s banked allowances. 

Reducing the banked allowances in 2018 would ensure that actual mercury emissions from the

sector as a whole are near the 15 tons per year level during subsequent years. The commenter

emphasized that this discounting must be applied one-time only. No further discounting should be

applied to allowances earned after 2018 as otherwise the incentives to create banked allowances

would be dampened. The commenter believed, therefore, this discounting mechanism should not

discourage the overall banking program.

Several commenters (OAR-2002-0056-2364, -3446, -3455) recommended a tighter Phase

II cap. Modeling by ICF conducted for one commenter (OAR-2002-0056-3446) found that

incremental changes in the timing and stringency of a mercury cap have modest cost implications. 

The added costs of a Phase II cap at 10 tons in 2015 (instead of 15 tons in 2018) would be about

the same as the cost saving for moving the Phase I cap from 26 to 34 tons. The commenter
xxxviii

summarized that on a percentage basis, the incremental environmental benefits from a tighter

Phase II cap would exceed the incremental costs.

One commenter (OAR-2002-0056-2364) believed that the emission limits which reduce

emissions to 34 tons per year are too high and that additional reduction is needed. The

commenter recommended reducing emissions to 5 tons/yr and requested an IPM run to determine

the optimal time frame for reaching this lower emission level.

One commenter (OAR-2002-0056-3455) believed EPA should consider enhancing the

NOx and SO2 controls to achieve more mercury reduction. The commenter believed more

stringent limits are technologically possible and recommends limits resulting in 85-90 percent. 

The commenter submitted that even considering the variability in coals, a national mercury

emission cap of 5-10 tons per year is achievable. The commenter stated this is consistent with

STAPPA/ALAPCO’s recommendation to the working group of a standard reducing emissions to

less than 7.5 tons per year and with EPA’s straw proposal for a 24 ton cap in 2008 and a final cap

of 7.5 tons in 2012. The commenter noted that based on control technologies currently in

commercial use or proposed in permit applications, states such as Connecticut, Massachusetts,

New Jersey, and Wisconsin have or will adopt limits that represent control efficiencies of 80 to

90 percent or more. The commenter stated these levels can be achieved using the controls

required for NOx and SO2 reductions under the IAQR if the equipment maximizes mercury

control. Tuning for optimal mercury removal, absorbent improvements, and other enhancements

for multiple emissions control would be effective measures to improve mercury removal.

Response:

EPA is finalizing a cap-and-trade program under section 111, and establishing a first

phase cap of 38 tons and a second phase cap of 15 tons. See preamble for further rationale for

the 15 ton cap.

Comment:

Many commenters (OAR-2002-0056-2634, -2819, -2861, -2867, -2876 -2911, -2922,

-2929, -2945, -2948, -3521, -3556, -3565) believed that EPA should modify its cap-and-trade

proposal. One commenter (OAR-2002-0056-2819) recommended that the trading/banking

program be based on recommendations issued by STAPPA/ALAPCO and OTC. The

STAPPA/ALAPCO analysis recommended a 15-20 ton interim cap by 2008 and a 5-10 ton cap by

2013. The OTC recommended a 15 ton interim cap by 2008, a 10 tons maximum cap for 2012,

and a 5 ton cap for 2015. The commenter noted that both of these are more stringent and timely

than EPA’s proposal and would ensure installation of the best controls nationwide.

One commenter (OAR-2002-0056-2945) specifically supported a multi-phase approach to

a national cap and trade program as a means of overcoming the multitude of problems associated

with the EPA data, the industry’s limited experience with mercury control technology, and the

need to maintain affordable electricity generation while developing the necessary experience to

reduce mercury emissions in the most cost effective manner. The commenter stated that the
xxxix

Bituminous Coal Coalition’s proposed multi-phase approach and timetable is superior to any EPA

MACT proposal since it ultimately results in a much lower cap (15 tons) than does the MACT

proposal

One commenter (OAR-2002-0056-2922) recommended that a mercury cap-and-trade

program be implemented in three phases. In Phase 1, there should not be a numeric cap on

mercury emissions. Instead, mercury emission reductions would be those resulting from

coal-fired power plants’ installing new control equipment to comply with the requirements of

EPA’s proposed Clean Air Interstate Rule (CAIR), assuming that EPA promulgates that rule. 

Mercury trading would not occur during Phase 1. Mercury allowances would not be issued and

banking of mercury allowances would not occur. Coal-fired units would install and certify

mercury monitors in 2008 and begin to monitor mercury emissions in 2009. The commenter

stated that the main reason a numeric cap should not be established in Phase 1 is because there is

no way to predict the level of mercury reductions that will be a result from utilities’ efforts to

meet the CAIR requirements. The commenter noted that not setting a numeric limit would avoid

excess banking of allowances if the cap was set too high, and conversely, compliance problems if

the cap was set below the level of mercury reductions actually achieved from complying with the

CAIR. Phase 2 would begin in 2015 with a cap of 24 tons of mercury emissions per year. In

Phase 2, mercury allowances would be allocated and mercury trading could occur. Allowances

should be allocated on the basis of heat input. The commenter suggested heat input multipliers of

1.0 for bituminous units, 1.5 for sub-bituminous units and 3.0 for lignite units. Phase 3 would

begin in 2018 with a cap of 15 tons per year.

Several commenters (OAR-2002-0056-2634, -2861, -2867, -2911, -2929, -2948, -3521,

-3556, -3565) supported and recommended the three phase approach recommended by

commenter OAR-2002-0056-2922. The commenters also cited advantages to this approach. 

Several commenters (OAR-2002-0056-2911, -3556) stated that beginning in 2008, the industry

would begin a comprehensive emissions measurement program for mercury from EGUs. 

Similarly, commenter OAR-2002-0056-3565 expressed a willingness to perform continuous

monitoring of mercury emissions using Method 324 beginning in 2008. This measurement

program would provide EPA, the states, the industry and the public with detailed information

regarding the mercury emissions from each coal-fired EGU.

Several commenters (OAR-2002-0056-2911, -3556) submitted that the primary

advantages of this proposal are that it acknowledges that there are significant unknowns regarding

mercury emissions from EGUs, allows the opportunity to resolve those unknowns, and affords the

opportunity for control technology to catch up with the final goals proposed by EPA–primarily

through advancements in reducing the emissions of elemental mercury.

One commenter (OAR-2002-0056-3565) stated that, as a practical matter, there is no way

to predict what equipment the utilities will install to meet the CAIR requirements. The

commenter added that there is currently much uncertainty as to the amount of mercury reduction

that can be achieved by SCR and scrubbers. The commenter stated that the limited data from

testing mercury on units with SCR and/or scrubbers has been very varied and inconsistent. The

commenter further added that there is also some evidence that some ionic mercury reduces to
xl

elemental mercury and is reemitted in some scrubbers. One of the commenter’s 1999 ICR stack

test sites clearly produced data, which indicated such reemissions were occurring. The

commenter believed estimating the amount of mercury co-benefits which will occur in year 2010

is just a guess, therefore, the most straightforward approach is to not set a tons limit for Phase I.

One commenter (OAR-2002-0056-2634) stated that the three phase approach provides

greater certainty to the utilities as it accurately addresses the true level of “co-benefits” and it

provides sufficient time, between 2008 (when monitoring would begin) and 2015 for utilities to

plan for installation of mercury specific controls. The commenter added it is also environmentally

beneficial in that it would reduce the total mercury emissions between 2010 and 2018, and would

result in actual 2018 emissions being very close to 15 tons through reduced banking.

One commenter (OAR-2002-0056-2861) stated that the three phase approach would

achieve several objectives: First, it would eliminate the guesswork that would be involved in

setting a co-benefit cap in 2010. Second, it would eliminate the potential that the lack of

demonstrated mercury specific removal technology, combined with the difficulty in installing all of

the SO2 and NOx controls that would be required under CAIR by 2010, could make it impossible

for the industry either to meet a specific mercury emissions cap in 2010 or to have an effective

mercury trading program in 2010. The commenter submitted that while concerns remain that the

2015 and 2018 targets are still ahead of technology development, the approach would provide

more time for the technologies that will be needed to reduce emissions beyond co-benefits to be

developed, demonstrated and deployed. The commenter concluded that last, the proposal to

move the first cap to 2015 would address concerns that have been expressed that too much

banking may occur if utilities are allowed to start banking any reductions below their 2010

allocations. The commenter stated a 2015 cap that sets an emissions cap below co-benefits would

make it more difficult to bank reductions for the period from 2015 to 2018. However, the

commenter recommended that limited banking be allowed prior to 2015 if the utility can

demonstrate that controls have been installed to reduce mercury beyond co-benefits, for example,

if a company installs a demonstration technology to specifically remove mercury. The commenter

suggested that will promote early reductions and help development of technologies needed to

meet both the 2015 and 2018 caps.

One commenter (OAR-2002-0056-2867) applauded EPA’s recognition that

mercury-specific control technologies will not be commercially ready for application in the 2010

time frame. The commenter noted that several technologies are in various stages of pilot testing,

but none have been demonstrated on a commercial scale for any extended periods of time. The

commenter stated that those that have pilot-tested have shown a substantial degree of variability. 

It was anticipated by the commenter that in the post-2010 period and by the 2018 Phase 2

compliance deadline, the performance of existing technologies would be well demonstrated, and

innovative mercury-specific technologies would have matured and be ripe for commercial use. 

The commenter submitted that the commitment to advance mercury control technology for

readiness in the future is demonstrated by the pace of industry research activities and

demonstration plans. Active commitment of funds by EPRI, DOE, and several utility companies

including AEP, further attest to the commitment of the industry to further development and

demonstration.
xli

Response:

EPA is finalizing a cap-and-trade program under section 111, and establishing a first

phase cap of 38 tons and a second phase cap of 15 tons. EPA examined a three-phase approach

but conclude its two-phase approach was appropriate. See preamble for further rationale and

Chapter 7 of Final CAMR Regulatory Impact Analysis.

Comment:

Commenter OAR-2002-0056-2867 cited the following advantages of the recommended

three phase approach:

• Would provide assurances (through the required monitoring programs) that emission

reductions are being steadily phased in toward successful achievement of the ultimate

15-ton cap

• Monitoring capabilities and technologies would have attained the needed level of

performance improvement to provide consistent demonstrations of compliance and

accurate future allowance allocations under the cap-and-trade program.

• Banking would be limited in the earlier phase, thus ensuring that the 2018 emissions would

closely track the ultimate 15 Ton cap. The 3-phase plan would achieve greater mercury

reductions in the 2010-2018 period compared to EPA’s proposed two-phase plan (a

cumulative total of 242 Tons of allowances under a 3-phase plan, versus a cumulative

total of 272 Tons of allowances under the 2-phase plan as proposed) 

• The interim compliance date would more closely approximate the schedule for

implementing demonstrated mercury specific newer technologies that would be elemental

mercury specific (the predominant form of mercury expected after the co-benefits based

reductions that principally remove the ionic form).

Consistent with the 3-phased approach recommended by commenter

OAR-2002-0056-2922 as described above, one commenter (OAR-2002-0056-2876) proposed

that a phased, national cap and trade program (under section 112 of the CM) be implemented to

reduce power plant mercury emissions. The commenter favored a phased approach because it

would not be possible to predict with adequate confidence the co-benefit reductions that would be

achieved through the industry’s actions to meet CAIR requirements. In addition, the commenter

believed a phased approach would allow for the time that is required for the commercialization of

mercury-specific control technologies that will be needed for future reductions. However, a key

distinction between the commenter’s proposed alternatives and the 3-phased approach described

above is that the commenter did not believe that EPA has data that are sufficient to support

setting an interim (2015) cap, or emissions allocation factors at this time. As noted above, EPA

should determine emissions allocation factors by coal type and set an interim cap in 2012; this

interim cap should become effective in 2015. The commenter stated the cap and associated

factors should be based on a co-benefits analysis of the monitoring data collected in the
xlii

2008-2012 period, and an assessment of commercial availability and performance characteristics

of mercury control technologies for different coal types. The analysis performed during this

period would allow for the implementation of an interim cap that would be achievable (and thus

would not promote fuel switching - to natural gas, for example), and avoid emissions allocations

among coal ranks that would place certain coal ranks at a market disadvantage.

Response:

EPA is finalizing a cap-and-trade program under section 111, and establishing a first

phase cap of 38 tons and a second phase cap of 15 tons. EPA examined a three-phase approach

but conclude its two-phase approach was appropriate. EPA believes it is important to establish

the cap levels in the final rulemaking to provide affected sources with certainty and time for

compliance planning. See preamble for further rationale and Chapter 7 of Final CAMR

Regulatory Impact Analysis.

Comment:

One commenter (OAR-2002-0056-4894) provided a memo that summarized the results of

an EPMM model run simulating the impacts of the EEl’s proposed alternative Mercury Cap and

Trade program (Alt Hg Option). Under this option, there would be no hard mercury cap until

2015. However, early reduction credits could be earned and banked during the period 2010-2014

if mercury emissions were to be consciously reduced through early application of control

technology. Phase I of the mercury cap would start in 2015 and be set to 24 tons. Phase II would

start in 2018 when the cap is lowered to 15 tons.

The commenter attached the standard summary tables for this case as an Excel file. This

memo highlighted the key results, primarily though comparison with results from EPA’s proposed

Mercury Cap and Trade Rule (Hg Rule), which has a cap of 34 tons starting in 2010, reduced to

15 tons in 2018. The commenter ran both scenarios with identical assumptions except for the

timing and level of the mercury caps.

The Alt Hg Option and the Hg Rule results presented by the commenter both were

simulated with an assumption that there would be gradual improvement in activated carbon

injection (ACI) mercury control technology: a 2.5 percent annual reduction in the current estimate

of the variable costs only of ACI-based technology. The summary tables for this specific version

of the Hg Rule scenario were also attached to the memo.

Response:

EPA is finalizing a cap-and-trade program under section 111, and establishing a first

phase cap of 38 tons and a second phase cap of 15 tons. EPA believes it is important to

establish a firm cap of 38 tons in 2010 based on EPA’s modeling of projected CAIR Hg

co-benefits. See final preamble for further rationale. As discussed in comment responses below,

section 5.8.3, EPA is not including early reduction credits for Hg in the final rulemaking. 
xliii

Comment:

Several commenters (OAR-2002-0056-2880, -2889) urged EPA to adopt the mercury cap

levels and reduction timeframes in the Multi-Pollutant Strategy Position of the Ozone Transport

Commission (January 27, 2004) and STAPPA/ALAPCO’s Principles for a Multi-pollutant

Strategy for Power Plants (May 7, 2002 with March 12, 2004 analysis of those principles). The

OTC calls for stepwise reductions in mercury emissions: 15 tons/yr in 2008, 10 tons/yr in 2012,

5 tons/yr in 2015 and performance standards for individual units by 2012. These reductions are

technically and economically feasible in that timeframe.

Response:

EPA is finalizing a cap-and-trade program under section 111, and establishing a first

phase cap of 38 tons and a second phase cap of 15 tons. See final preamble for further

rationale.

Comment:

One commenter (OAR-2002-0056-3546) was generally supportive of the proposed targets

and compliance deadlines for reducing mercury proposed under the cap-and-trade options. 

However, the commenter urged EPA to further examine these targets and deadlines–which are

very ambitious–to ensure that the proposed two-phased mercury control program is technically

and economically feasible and consistent with the objectives to ensure adequate supplies of

reasonably priced power. Moreover, the commenter submitted that given the stringency of the

proposed reduction requirements, the adoption of an emissions trading program is essential to

ensure these objectives are realized and that mercury reduction obligations can be achieved at the

lowest possible cost.

Response:

EPA is finalizing a cap-and-trade program under section 111, and establishing a first

phase cap of 38 tons and a second phase cap of 15 tons. See final preamble for further

rationale.

Comment:

One commenter (OAR-2002-0056-2359) stated EPA’s weak proposals do not provide

incentive for advancing mercury removal technology in conjunction with SOx, NOx, and PM. The

commenter pointed out that DOE is expected to have cost effective mercury control technology

available by 2010; EPA’s mercury rules should at least be consistent with that timing.

Response:
xliv

EPA is finalizing a cap-and-trade program under section 111, and establishing a first

phase cap of 38 tons and a second phase cap of 15 tons. EPA believes this cap levels and timing

encourage technology development. See final preamble for further rationale.

Comment: One commenter (OAR-2002-0056-3210) opposed EPA’s rationale in the

supplemental notice for 6 years to adequately conduct a commercial demonstration of mercury

controls. The commenter claimed EPA is attempting to selectively develop time lines to justify

cap and trade. The commenter noted the 6 year time line includes a pre-award period greater than

12 months, each full-scale demonstration taking another 12 months and inflates the operating and

reporting timeline by including the time to prepare a report on the project. The commenter

believes a realistic time line is 3-4 years, especially in light of all the full scale demonstration

projects already completed or underway. The commenter stated the goal of the DOE/NETL

Mercury Control Technology Research Program is for technology for bituminous coal to be

available by 2005 and lignite and sub-bitumihnous coal by 2007 and advanced mercury controls

for all coal types by 2010. Widespread commercial deployment could begin in 2008 for

bituminous and 2011 for lignite and sub-bituminous coal.

Response:

EPA is finalizing a cap-and-trade program under section 111, and establishing a first

phase cap of 38 tons and a second phase cap of 15 tons. EPA believes this cap levels and timing

are consistent with its understanding of technology development. See final preamble for further

rationale and see Control of Emissions from Coal-Fired Electric Utility Boilers: An Update,

EPA/Office of Research and Development, March 2005, in docket.

Comment: Several commenters (OAR-2002-0056-2054, -2422, -2718, -2922, -3198,

-3469) recommended that EPA should implement a phased-in approach to the mercury

cap-and-trade program that recognizes the differences in available technology solutions between

the various fuel subcategories. Several of the commenters (OAR-2002-0056-2054, -2422, -3198)

claimed adequate technical data do not exist at this time to provide a reasoned basis for the

allocation of allowances among coal types for purposes of an initial reduction in 2010.

One commenter (OAR-2002-0056-2054) believed the mercury data collected as part of

EPA’s 1999 Information Collection Request (ICR) is inadequate and inherently flawed. The

commenter proposed that EPA acknowledge these data problems and implement mercury

regulations that are designed to rectify the situation, while maintaining a reasonable level of

environmental control over mercury emissions. Several commenters (OAR-2002-0056-2054,

-2422) encouraged initial reliance on the “co-benefit” mercury reductions achieved by the sulfur

and nitrogen oxides reductions required by EPA’s proposed Interstate Air Quality Rule (IAQR). 

One commenter (OAR-2002-0056-2422) noted that EPA’s mercury co-benefit reduction

estimates associated with the IAQR are comparable to those resulting from implementation of the

agency’s MACT proposal. The commenter noted EPA estimates that compliance with the IAQR

will result in an overall level of 34 tons of mercury emissions from the electric generating sector in

2010, due to the installation of 49 Gigawatts (GW) of scrubbers and 24 GW of SCR capacity by

2010.
xlv

Several commenters (OAR-2002-0056-2054, -2422, -3198) stated EPA should implement

a phased approach to the determination of mercury emission allowance allocations under any form

of an emissions trading rule. The commenters submitted a phased approach should be designed

with the following milestones:

• 2008-Require installation and initial testing and operation of mercury emission monitoring

equipment on affected units;

• 2009-11-Collect and analyze monitor data to determine mercury emissions and reductions

achieved by IAQR emission reductions in 2010;

• 2012-Determine prospective emission allocations by coal type for an interim 2015

emissions cap, based on results of the 2009-11 co-benefits analysis, and an assessment of

the expected future commercial availability and performance characteristics of mercury

control technologies for different coal types;

• 2015-Affected plants meet an interim emissions cap determined by EPA in 2012; banking

and trading of allowances commences;

• 2018-Final emissions cap of 15 tons is imposed.

Several commenters (OAR-2002-0056-2054, -2422) recognized that the development of

mercury-specific control technologies may, or may not, reduce the need for specific emission

allowance allocations by coal type at some point in time. The commenters stated the proposed

2009-2011 analysis of the efficacy of co-benefit control reductions, coupled with an assessment of

mercury-specific control technologies, would facilitate a determination of the appropriateness of

coal-specific emission allowance allocations to meet an interim 2015 and a final 2018 cap.

Under the commenters’ (OAR-2002-0056-2054, -2422, -3198) phased approach, no

mercury allowances would be assigned until 2015, for purposes of meeting an interim cap, and no

banking or trading of allowances could occur prior to that date. One commenter

(OAR-2002-0056-2244) strongly opposed use of the agency’s proposed MACT floor values for

any allocation of mercury emission allowances. The commenter asserted these floor values were

not statistically defensible, and were inappropriate for any regulatory purpose. One commenter

(OAR-2002-0056-2054) believed that with this proposal, the total mercury emissions would

decrease and be equal to or less than the emission levels under the currently proposed regulatory

alternatives. The commenter stated in addition, the additional data collection would insure a just

and verifiable regulatory program based on sound science. The commenter also stated that finally,

the limited time for banking allowances (3 years) would insure that the maximum mercury

reductions would be achieved in a relatively short time.

Another commenter (OAR-2002-0056-2922) also recommended that a mercury

cap-and-trade program be implemented in three phases. This commenter’s recommendation as

described in the following paragraphs was identical to the recommendation of the above

commenters (OAR-2002-0056-2054, -2422, -3198) with the exception of the Phase 2 (interim)
xlvi

cap. The commenter submitted that in Phase 1, there should not be a numeric cap on mercury

emissions. Instead, mercury emission reductions would be those resulting from coal-fired power

plants’ installing new control equipment to comply with the requirements of EPA’s proposed

Clean Air Interstate Rule (CAIR), assuming that EPA promulgates that rule. Mercury trading

would not occur during Phase 1. The commenter stated mercury allowances would not be issued

and banking of mercury allowances would not occur.

Under the commenter’s (OAR-2002-0056-2922) approach, coal-fired units would install

and certify mercury monitors in 2008 and begin to monitor mercury emissions in 2009. The

commenter stated the main reason a numeric cap should not be established in Phase 1 is because

there is no way to predict the level of mercury reductions that would be a result from utilities’

efforts to meet the CAIR requirements. The commenter believed not setting a numeric limit

would avoid excess banking of allowances if the cap were set too high, and conversely,

compliance problems if the cap were set below the level of mercury reductions actually achieved

from complying with the CAIR. Phase 2 would begin in 2015 with a cap of 24 tons of mercury

emissions per year. The commenter submitted that in Phase 2, mercury allowances would be

allocated and mercury trading could occur. According to the commenter, allowances should be

allocated on the basis of heat input. The commenter suggested heat input multipliers of 1.0 for

bituminous units, 1.5 for sub-bituminous units and 3.0 for lignite units. Phase 3 would begin in

2018 with a cap of 15 tons per year. The commenter asserted that the main problems with EPA’s

cap-and-trade proposal center on the overly stringent limits on new units and the emissions

monitoring and compliance requirements.

One commenter (OAR-2002-0056-2718) supported the consensus industry position that

EPA implement a three-Phase trading program and proposed a variation of the approaches

described above. According to the commenter, EPA should initially set a Phase I nationwide cap

to begin in 2010 at 34 tpy but, based on monitoring data collected in 2008, reevaluate whether the

cap appropriately captures the Agency’s intent to require co-benefits reductions only in the first

phase. The commenter noted that several different studies of co-benefits have indicated a Phase I

range of removal from 34 tpy to 42 tpy–a significant range of uncertainty that could be addressed

through a monitoring program in 2008. The commenter proposed an interim Phase II cap of

24 tpy in 2015 and a Phase III cap of 15 tpy in 2018. The commenter urged EPA to implement

flexible cap-and-trade mechanisms that would enable affected sources to achieve the proposed

reductions as cost-effectively as possible. 

Response:

EPA is finalizing a cap-and-trade program under section 111, and establishing a first

phase cap of 38 tons and a second phase cap of 15 tons. EPA is establishing a firm cap of 38

tons based on EPA’s modeling of projected CAIR Hg co-benefits. EPA believes it is important

to establish the cap levels in the final rulemaking to provide affected sources with certainty and

time for compliance planning. EPA examined a three-phase approach but conclude its

two-phase approach was appropriate. See final preamble for further rationale and Chapter 7 of

Final CAMR Regulatory Impact Analysis. For discussion of coal adjustment factors used in

determining allocations see responses in section 5.6.1 below.
xlvii

Comment:

One commenter (OAR-2002-0056-2243) believed that in general, the grandfathering of

elevated NOx and SO2 emissions should be eliminated. The commenter viewed this as an unfair

competitive advantage to existing generators in a supposedly competitive electric market.

Response:

EPA is finalizing a cap-and-trade program under section 111, and establishing a first

phase cap of 38 tons and a second phase cap of 15 tons. See final preamble for further

rationale.

Comment:

One commenters council (OAR-2002-0056-2906) reminded EPA that it is much more

cost effective to reduce emissions from large utility units than from smaller industrial size steam

boilers. The Council supported the EPA approach of focusing on the more cost effective larger

units as in the proposed Clean Air Interstate Rule (CAIR), formerly known as the Interstate Air

Quality Rule (69 FR 4566, January 30, 2004 and 69 FR 32684, June 10, 2004) to achieve the

required emissions reductions rather than on higher cost industrial size units.

Response:

The final CAMR will require Hg reductions from coal-fired power plants. See final

preamble for further rationale.

Comment:

One commenter (OAR-2002-0056-3469) noted that EPA’s determination of the necessity

to regulate Mercury emissions from EGU’s is based in part on a report by the National Academy

of Sciences (NAS). However this report stated that “based on estimates of methylmercury

exposures in the U.S. populations... the risk of adverse effects from current methylmercury

exposures in the majority of the population is low.” Methylmercury is typically found in fish. The

commenter further noted that EPA itself has acknowledged that concentrations of methylmercury

in fish come from a variety of sources including global natural and manmade sources. According

to the Electric Power Research Institute, of the 5,500 tons of mercury emissions estimated to

occur globally, only 150 tons originate in the U.S. In the 1997 Mercury Study Report to

Congress, the EPA estimated that U.S. EGU’s “account for roughly 1 percent of total global

emissions” (approximately 48 tons) and emissions of mercury from lignite-fired plants is less than

10 percent of that 1 percent. The report went on to say that “the relationship between mercury

emissions reductions from Utility Units and methylmercury concentrations cannot be calculated

with confidence.” The commenter submitted that computer models run by U.S. EPA and EPRI

predict that cutting mercury emissions from power plants by 50 percent will only reduce mercury

levels in U.S. waters by an average of 3 percent and this level of reduction will translate into a

reduction of less than 1 percent in exposure to mercury via fish consumption.
xlviii

The commenter believed the EPA is faced with a dilemma. On the one hand the science

does not yet point to a direct link between U.S. EGU mercury emissions and methylmercury

concentrations in fish nor does science show how reductions in EGU mercury emissions will alter

these concentrations and lower health risks. On the other hand, the public has been led to believe

that mothers and unborn children are at risk to exposure of damaging levels of mercury due to

consuming fish and that this mercury emanates from U.S. power plants. It is asking for action to

be taken to control mercury emissions from power plants.

The commenter stated that given the state of the available information, it would thus

appear prudent on the part of EPA to proceed slowly, implementing cost-effective regulations

that do not destabilize energy markets, such as forcing fuel switching or inhibiting the

construction of new coal-fired generation, or imposing unintended social or economic costs, such

as raising energy prices and closing mines and power plants in rural areas. (These consequences

are discussed in detail in the comments submitted by CEED and are incorporated in the

commenter’s comments by reference). The commenter submitted that a measured approach will

allow the EPA to evaluate the effectiveness of the regulations in reducing health risks and to

modify future regulations in light of these results. To demonstrate it is a good steward of the

public’s health and resources, EPA must be able to conclusively demonstrate that the regulations

have resulted in lower health risks. The commenter concluded that as such a phased approach to

regulation is called for.

Response:

EPA is finalizing a cap-and-trade program under section 111, and establishing a first

phase cap of 38 tons and a second phase cap of 15 tons. See final preamble for further

rationale.

Comment:

One commenter (OAR-2002-0056-1842) offered the following “mercury escalating

payment proposal.” According to the commenter, the high mercury emitters would pay the low

mercury emitters’ amounts which would rise each year. The commenter submitted that if

90 percent of the mercury could be removed for a rate increase of one percent, the vast majority

would support the expenditure. If a modest rate increase would achieve 80 percent reduction

while a huge increase would be needed for 90 percent reduction then the vast majority would

support the 80 percent removal. So there would be relatively little controversy over how much

should be spent. The commenter believed the controversy would be over cost vs. performance. 

The commenter noted environmentalists say 90 percent of the mercury can be eliminated at a cost

of a few thousand dollars/lb. Utilities say that even at $35,000/lb you may not be able to remove

90 percent.

The commenter stated that at the end of the year each utility who emits mercury at greater

than the average rate pays into a fund and each utility under the average receives those payments. 

The amount per pound would rise each year. The commenter submitted it would likely start low,
xlix

e.g., $5,000 lb in 2007 and rise at $10,000/lb per year until industry-wide emissions are reduced

to 5 tons/yr.

The commenter submitted that if the environmentalists are right and most mercury can be

removed for a few thousand dollars/lb, then utilities would soon invest in removal technology

rather than pay into the fund. To ensure that this does happen the rule could contain a proviso

that if mercury is not reduced to some level (e.g. 25 tons in 2010 and 5 tons in 2015) then a tax

would kick in. The commenter suggested this tax/lb would be greater for those with higher than

average emissions. The funds from this tax would be earmarked for mercury development.

The commenter believed setting the cost/lb would be critical. The commenter noted that

interestingly both sides in the argument would have to contradict themselves. Environmentalists

would say that instead of a few thousand dollars/lb it could be very costly. Utilities would say that

the payment costs should be set lower and will have to base this on the claim that mercury can be

removed cheaply.

The commenter admitted that the truth of the matter is that setting the costs would be

tricky. At $19,000/lb average cost it would appear that a $25,000/lb top payment would be

sufficient. But the commenter submits that given the incremental cost structure above, utilities

would stop at 75 percent efficiency. The commenter suggested it might be best to set $85,000/lb

as the payment in 2015. According to the commenter, this would result in more than 80 percent

removal.

The commenter explained the steep escalation for the final percent is based on increasing

carbon usage from 2 Lbs/MMacf to 10 lbs/MMacf to 30 lbs/MMacf. The commenter did not

believe carbon would be used at the high usage rates. The commenter believed this escalating

payment system will stimulate all sorts of developments. The commenter submitted one of the

main attractions of this approach would be the accelerated use of better technology. The

commenter pointed to chloride pre-scrubbers, biomass gasification including PVC for injection as

a reburn fuel, additives other than carbon, acid condensation, etc. The commenter stated all

would promise to remove 90 percent of the mercury at less than $10,000/lb.

Escalating Payment Scenario Would Also Solve Monitoring Problem. The commenter

submitted the EPA proposal to ignore particulate mercury was not a good idea. The commenter

noted that three percent error is maybe acceptable for emission reporting but if you are trading

allowances at $35,000 or as per above $85,000/lb (NOTE: The $85,000/lb figure is based on an

example application of the mercury escalating payment proposal given in the comment), you are

talking about a variance of $100 million to $200 million. Furthermore, there is no assurance that

three percent is the right number. The commenter pointed out the RJM concept is to condense

acid mist on fine particulate in order to create acid deposition sites. Under the EPA scheme all

the mercury could then be discharged and not counted. The commenter also pointed out there is

a 10 times differential between fine particulate emissions from old precipitators and new ones.

According to the commenter, no trading system will stand for this amount of inaccuracy. 

So the commenter proposed an “audit system.” EPA can protect against abuses but put the
l

burden on the utilities to report accurately. The commenter submitted that because of the

financial consequences utilities will demand a measurement system which provides the highest

possible accuracy. EPA has already proposed allowing better QC/QA rather than mandating

specific instrumentation. The commenter believed this is the route to take.

Investors Will Supply the Capital and Take the Risks. The commenter stated most experts

agree that mercury technology lacks the certainty of SO2 removal. But they would also agree that

there are many probable routes to economic mercury removal. The commenter submitted the

problem is that utilities do not have the mind set of traders. So why not pass the risk to the

investment community. The commenter pointed out the maximum cost per pound in any future

year is now known. The investor would agree to receive some percentage of this amount. In

return he would finance the control technology used to make the reductions.

The commenter believes there is a big upside profit potential and a limit on downside risk. 

In a worst case scenario the investor would lose his investment but does not face additional

penalties. The investor says that if the system works he wants the lion share of the cost

difference. If it doesn’t work the utility just makes the payments they would have made without

the investment.

The commenter raised the question, How does a proposal such as this meet the criteria of

individual action by each state? One way would be to add a clause that each state that volunteers

to enter this plan would have the option to drop out when mercury limits reach the budgeted

amount in the state. The commenter believes in practice no state would do so.

The commenter submitted the reason would be if the state reached this threshold, utilities

in the state would be net recipients rather than payers. So opting out would increase electricity

rates.

The commenter stated another reason no state would drop out is that this plan would

encourage cost effective mercury reductions beyond the 90 percent. The commenter stated, e.g.,

the national average drops to five tons in 2015. At that time the payment price of $85,000/lb

would no longer escalate, but the payment would continue at that price. The commenter

submitted that in future years, new technology that costs less than $85,000/lb would be

implemented. The commenter believed that eventually mercury might be reduced by 95 percent

instead of 90 percent. The beauty is that the cost would be a maximum of $85,000/lb for the last

increment and on the average only a fraction of that. The commenter stated that their analysis

showed that the cost for very high mercury reduction will be only 1 to 2 mils/kWh.

The commenter (OAR-2002-0056-1842) stated that the Particulate Inter-Utility escalating

payment plan would provide a cost effective solution to the particulate and toxic metal problems.

The commenter submitted that higher emitting utilities would pay lower emitting utilities an

amount starting at $400/ton in 2007 and amounts in future years which escalate at $400/ton until

national averages drop below 0.05 lbs/MM/btu. According to the commenter, an analysis showed

that within a few years, payments would be more than the annual cost of efficient particulate
li

control equipment. The analysis also showed the substantial reduction in toxic metals which

would accompany the particulate reduction.

Response:

EPA is finalizing a cap-and-trade program under section 111 that it believes is

appropriate and cost-effective.

5.4 HOT SPOTS

Comment:

A trading scheme would allow dirty plants to continue to emit high levels of mercury by

purchasing credits from cleaner plants and not installing controls, which would further endanger

the health of surrounding communities. with hot spots. For example, one commenter

(OAR-2002-0056-2355) stated that low income immigrant populations who eat fish from local

waters are at risk as are Boston residents who suffer from asthma. The commenters believed this

approach is inappropriate for such a toxic pollutant and is inconsistent with EPA’s own findings

as well as other Federal agencies such as FDA and NAS. Another commenter

(OAR-2002-0056-4139) submitted information suggesting that localized deposition impacts do

occur. The commenter attached a copy of the USGS briefing. The commenter stated that the

data suggest that monitored mercury wet deposition is directly related to the quantity of mercury

emissions within 50 km.

One commenter (OAR-2002-0056-4177) opposed a cap and trade approach under section

111 or 112. The commenter submitted that State ambient monitoring shows that mercury

emissions create hot spots downwind of sources. The commenter believed a national trading

program would doom certain areas of the country to unacceptably high concentrations. Given the

current concentrations in the Northeast, the commenter felt Maine would likely continue to be

located in a hot spot.

The commenter (OAR-2002-0056-3449) stated mercury emissions remaining after

compliance with a cap and trade program would cause unacceptable adverse health effects; hot

spots would remain. The commenter noted that EPA’s rationale stressed that the health risks

associated with mercury emissions from power plants are uniquely global, rather than local . 

According to the commenter, this dismisses the importance of local impacts from heightened

deposition near power plants and the regional impacts from overlapping deposition pattern. The

commenter submitted that in general, regions with the highest deposition are the same regions

where local and regional sources make significant contributions to the total mercury load. It was

clear to the commenter that mercury emitted from coal-burning power plants is deposited much

more in some areas than other. The commenter submitted that a cap and trade approach would

exacerbate the regional impacts. The commenter noted that about 30 percent of generating

capacity has shorter stacks that tend to result in more local deposition. These are typically

smaller, older plants that would not likely be controlled under a cap and trade program. The

commenter believed regional and local impacts could increase in regions where these plants are
lii

prevalent. The commenter stated large hot spots exist now across areas too big to be called

“spots.” These include entire regions, especially in the Northeast and Great Lakes. The

commenter claimed this is confirmed by deposition monitoring data collected by states and the by

widespread fish advisories. The commenter concluded that marginal regional decreases would not

solve the regional or local problems. In some cases, emissions may increase if plants increase coal

use.

One commenter (OAR-2002-0056-3435) stated EPA should abandon cap and trade

because of its weakness in control of a HAP and concern for possible hot spot problems. The

commenter submitted that recent studies (New Jersey Mercury Task Force Reports, Mercury

Emissions from Coal-fired Power Plants by NESCAUM, and Integrating Atmospheric Mercury

Deposition with Aquatic Cycling in South Florida have shown that mercury is deposited much

closer to the source of emissions than NOx or SO2 emissions and poses a much greater health and

environmental impact. The commenter noted that Georgia already has areas of high mercury

concentrations in the southern part of the state where physical and chemical conditions favor

metethylation and bioaccumulation of mercury. The commenter believed utility units within these

airsheds must reduce emissions to the maximum extent possible. The commenter asserted that

any aspect of a program that would allow less than maximum control is unacceptable.

Several commenters (OAR-2002-0056-2817, -2819) supported MACT standards under

CAA section 112(d) to address mercury hot spots associated with emissions of oxidized mercury

from coal-fired boilers. One of the commenters (OAR-2002-0056-2817) contended that while

science may not be conclusive on some aspects, EPA should err on the side of public health and

adopt more stringent limits. The commenter cited potential legal concerns, the hazardous nature

of mercury and the potential for hot spots as reasons EPA should abandon the cap and trade

approach. The commenter believed cap and trade may be appropriate for regional pollutants such

as SO2 and NOx, but not for HAP.

One commenter (OAR-2002-0056-3210) stated that EPA’s conclusions about the benefits

of a cap and trade program for mercury do not reflect current science, environmental

considerations, engineering, or economics. The commenter noted the Utility RTC concluded that

the Great Lakes, Ohio River Valley, the Northeast, and scattered areas in the South are predicted

to have the highest annual deposition rates. The commenter also noted that recent studies show

that US sources are the main contributors. The commenter believed the cap and trade program

would promote hot spots and allow continuation of regional concentrations. The commenter

stated that regional concentrations could be reduced much sooner through appropriate MACT

standards.

One commenter (OAR-2002-0056-2878) opposed cap and trade and cited several

scientific and policy concerns including lack of safeguards to protect the public health and secure

additional needed reductions, toxicity of mercury and tendency to bioaccumulate in the food

chain, potential for hot spots, and environmental justice. According to the commenter, an initial

analysis showed that the top 33 percent of the largest plants have stack heights about twice as tall

as the bottom 33 percent lowest emitters. Short stacks could contribute to more local deposition. 
liii

The commenter submitted that to the extent that trading shifts emissions from larger to smaller

plants, the maximum local deposition would be about 4 times higher for each pound of mercury.

Several commenters (OAR-2002-0056-2219, -3526) opposed the cap and trade approach

because it would have disproportionate impacts on the Great Waters, including the Great Lakes

region and worsen existing hot spots and may cause new ones. One commenter

(OAR-2002-0056-2219) stated that not requiring controls on all facilities would further

contaminate important food supplies for sensitive populations already impacted by the largest

concentration of coal-fired power plants in the U.S. According to the commenter, except for the

Everglades, the Great Lakes have the highest mercury deposition rate in the world. According to

an EPA mass balance study, 86 percent of mercury deposited to Lake Michigan comes from

atmospheric sources–30 percent of these emissions are from local sources near Chicago and the

number of potential local sources of mercury is increasing. The commenter claimed that the

health of women, children, and other sensitive populations will be at further risk. The other

commenter (OAR-2002-0056-3526) stated that cap and trade is inconsistent with EPA’s prior

determination that it would protect the Great Waters through faithful enactment of section 112

without a cap-and-trade approach (63 FR 14090, March 24, 1998). The commenter noted that a

cap and trade approach would not guarantee that units responsible for mercury and other HAP

pollution to the Great Waters would have to adopt mercury controls. section 112(m) of the CAA

prohibits EPA from adopting a program to control HAP that does not assure adequate safeguards

for the Great Waters. The commenter asserted the cap and trade program can not address the

adverse impacts that units currently have on the Great Waters and could result in even more harm. 

The commenter stated that if EPA does adopt a cap and trade program, it must explain how this

approach fulfills its nondiscretionary duties to protect the Great Waters.

One commenter (OAR-2002-0056-2219) opposed the cap and trade approach because

scientific understanding of the percentage of mercury that is converted to methylmercury (the

form that most readily enters the food chain) is limited. The commenter noted that results of the

Florida Everglades study showed that reducing emissions on a regional basis, facility by facility,

would achieve reductions in the ecosystem, but it is not a one-to-one correlation. In this study, a

99 percent reduction in emissions from incinerators yielded a 60 percent reduction of mercury in

fish tissues. The commenter stated it is not clear that a cap and trade program would achieve the

significant local reductions needed to improve the ecosystem. The commenter believed if all

facilities reduced emissions, then local and national emissions would also be reduced. The

commenter also stated that mercury emissions must be addressed on a facility-by-facility approach

since the most toxic form of mercury (reactive gas phase mercury or RGM) is deposited locally. 

According to the commenter, trading schemes would create regional areas of higher mercury

releases that would further damage food sources and human health–particularly in the Great

Lakes area where there is a high percentage of subsistence fishing.

According to the commenter (OAR-2002-0056-3437), The 2003 results of the EPA

Office of Water study, “Draft Mercury REMSAD Deposition Modeling Results” reinforced their

concerns. This modeling showed that at mercury hot spots, local emission sources within a state

can be the dominant source of deposition, commonly accounting for 50-80 percent of the mercury

deposition. According to the commenter, in state sources contributed more than 50 percent of
liv

the pollution to sites in the top 8 worst hot spot states (Michigan, Maryland, Florida, Illinois,

South Carolina, North Carolina, Pennsylvania, and Texas).

Response:

EPA has addressed the hot spots issue in the revision Federal Register notice and in the

Effectiveness TSD.

Comment:

Many commenters (OAR-2002-0056-1625, -1627, -1673, -1790, -1859, -1969, -2251,

-2332, -2431, -2547, -2560, -2578, -2725, -2830, -2833, -2835, -2841, -2850, -2861, -2862,

-2897, -2900, -2907, -2915, -2918, -2922, -2929, -2948, -3353, -3444, -3463, -3478, -3513,

-3530, -3537, -3539, -3546, -4891) believed that a mercury cap-and-trade program will not create

hot spots. Many of these commenters (OAR-2002-0056-1625, -1790, -2251, -2547, -2560,

-2725, -2833, -2835, -2897, -2900, -2915, -2922, -2948, -3353, -3463, -3513, -3539) cited

review of recent studies as directly refuting that claim.

Several commenters (OAR-2002-0056-1625, -2915) stated there are several facts that

suggest that localized effects will not occur with a mercury emissions trading program. The

commenters pointed out that mercury emissions from utilities in the U.S. represent only a portion

of emissions–less than 10 percent of total North American emissions and about one percent of

total global mercury emissions. Regulations or legislation will make this small contribution even

smaller. According to the commenters, a recent study by EPRI found that reducing power plant

generation mercury emissions will produce minimal benefits–a 47 percent cut would yield less

than a one percent drop in exposure. The commenters submitted that even drastic reductions in

utility mercury emissions will have a minimal effect on state fish advisories. Furthermore, most

power plant mercury emissions are of the elemental form soon after release and therefore enter

the global pool instead of depositing nearby. The commenters cited a recent study by

Brookhaven National Laboratory that found only 4 to 7 percent of mercury is deposited locally. 

Another fact presented by the commenters is that regulations to control SO2 and NOx will require

the installation of pollution controls that will also capture the forms of mercury that tend to

deposit nearby. This is because the species of mercury that are deposited locally-oxidized and

particulate mercury-are controlled by the same equipment that controls fine particles, SO2 and

NOx.

Another commenter (OAR-2002-0056-3478) stated that current research indicates that

North American anthropogenic sources were calculated to contribute only from 25 to 32 percent

of the total mercury deposition over the continental U.S. The commenter stated that the amount

of local deposition of mercury is in part a function of the speciation of the mercury emitted from

the source. The commenter further stated that mercury is typically emitted both in its elemental

form and as oxidized mercury. According to the commenter, elemental mercury tends to enter the

global mercury cycle, and may be retained in the atmosphere for up to one year before deposition,

creating the possibility that it will travel around the earth several times before deposition. 

Similarly, one commenter (OAR-2002-0056-1859) agreed that no hot spots should occur,
lv

particularly as it pertains to units in the west and to facilities that burn sub-bituminous coals. The

commenter noted that sub-bituminous coals are typically low in SO2 and mercury and when

combusted, produce primarily elemental mercury which tends to not deposit near the source.

One commenter (OAR-2002-0056-2431) cited modeling by EPA, DOE, the Brookhaven

National Laboratory, and EPRI and concluded that emissions trading would not create hot spots. 

The commenter claimed that studies of the acid rain program trading program demonstrated that

trading did not significantly change where emissions actually occurred when compared to a

command and control approach. The commenter stated trading would not cause local impacts

because most emissions become elemental soon after release and enter the global pool instead of

depositing nearby. Also new SO2 and NOx rules will require controls that also capture the forms

of mercury that tend to deposit nearby. The commenter further submitted that overall emissions

would still decline even if some utilities did not install controls because of the cap. The

commenter stated that emissions trading also creates economic incentives which bring about the

greatest reduction from the highest emitting sources. The commenter concluded thus, hot spots

would not occur.

One commenter (OAR-2002-0056-3513) pointed out that EPRI modeling has indicated

that mercury should be studied on a global scale–not a local or even national one. EPRI’s analysis

showed that the majority of mercury emitted from coal-fired units is in the elemental form which

does not deposit locally, but enters the global pool and circulates in the atmosphere for six months

to a year on average. The soluble forms of mercury are more likely to deposit nearby. The

commenter submitted however, if the proposed rule is enacted along the same timeline as the

Interstate Air Quality Rule, most units will be required to install SCR’s and/or scrubbers which

will capture most soluble forms of mercury.

One commenter (OAR-2002-0056-2835) stated that the acid rain program has cost

effectively achieved a 41 percent reduction in SO2 emissions from 1980 through 2002 (despite a

significant increase in electric generation) and done so without any evidence of local “hot spots”

occurring. The commenter also pointed out that the NOx SIP Call rule has adopted an interstate

cap-and-trade program that has achieved significant reductions in NOx emissions from the power

sector.

Several commenters (OAR-2002-0056-2251, -2833, -2948, -3530) submitted that as

“proof” of the “hot spot” theory, some groups have cited a study of mercury in the Florida

Everglades. According to the commenters, many claims about this study contain erroneous,

unsubstantiated assertions that it “proves” controls on local sources would result in a fairly rapid

decline of mercury in the regional environment. The commenters asserted the study does not

prove such assertion because:

• The mercury reductions in south Florida were from municipal and medical waste

incinerators, not from power plants. The mercury emissions from these incinerators are

generally in a water-soluble form.
lvi

• Many studies have shown that the characteristics of the water body, not the amount of

atmospheric deposition, dictate the eventual levels of mercury in fish. The Everglades is a

unique ecological and climatological system, strikingly different from other U.S.

waterbodies; it should not be considered representative of water bodies in other states, or

even of other parts of Florida. Before states decide to take action beyond the federal

mercury rules, they should assess their state’s actual situation.

• The claim that changes in mercury emissions will result in rapid changes in the amount of

methylmercury found in fish is not supported by the study’s data or findings. Despite

decreases in mercury emissions from incinerators, data measurements and long-range

transport modeling indicate that the amount of mercury being deposited in the Everglades

overall has changed little. Modeling of mercury transport conducted by EPA and EPRI

has led to the conclusion that over 60 percent of mercury deposited in Florida originates

outside the state.

• Extensive measurements around power plants have failed to show local increase in

mercury at ground level or in nearby waterways. EPA reached this conclusion in its 1997

Mercury Study Report to Congress, and this finding has been supported by recent studies

at a large power plant in Maryland.

The commenters concluded that clearly, the Florida Everglades study does not support applying

the “hot spot” theory to other states, or even other parts of Florida.

Regarding the South Florida Report, another commenter (OAR-2002-0056-3444) had

several comments. The commenter referenced several commenters that suggested that this

Report demonstrated the existence of “hot spots” and further demonstrated that limiting mercury

releases from coal-fired power plants (CFPPs) would cause rapid decreases in mercury

concentrations in the local/regional environment. The commenter submitted that neither

conclusion followed from the Florida report. While the commenter acknowledged an extensive

and valuable body of research has been conducted in south Florida, the commenter found two

major problems with how the results have been interpreted (both in the report itself and by

others). First, to what degree has the relationship between local mercury emissions reductions

(known to have decreased dramatically between the late 1980s and the early 1990s) and

decreasing levels of mercury in biota (documented to have occurred between the early 1990s and

the present, but not to the same degree everywhere in south Florida) been established, or put

another way, how much of the latter was caused by the former? Second, to the extent we know

this relationship, to what degree does it apply to CFPPs in other parts of the country?

The commenter stated that relative to the first issue, while there is an evolving weight of

evidence that there is some relationship between local mercury emissions reductions and local

biotic response, the degree of the relationship has not been, nor can it be, definitively quantified

for the time period addressed by the Florida study. First, the commenter noted there is no

deposition record spanning the time before and after the emission reductions. Inferences from

sediment cores are, at best suggestive, and at worst inconsistent. Second, the commenter

submitted that while aquatic model hindcasting (currently being conducted) suggests a link
lvii

between deposition and response in aquatic biota, it cannot allocate the share of deposition

changes coming from other source changes and the share of the biotic response coming from

non-depositional ecosystem changes (e.g., hydrological, sulfate, phosphorous, DOC, etc.). To the

extent that U.S. emissions reductions, European emissions reductions, and other worldwide

emissions changes were affecting the changes in deposition at the same time (also a study in

progress), it would moderate the degree that local emissions changes were having on deposition

changes. The commenter also stated that similarly, to the extent hydrological and other

ecosystem changes were also affecting biotic mercury levels, it would moderate the role of

deposition changes. Finally, the commenter believed atmospheric modeling conducted as part of

the Florida Study was flawed in several ways. The modeling erroneously assumed that mercury

deposition in waterways comes only from local sources. The commenter noted that modeling by

EPA and EPRI has shown that more than 90 percent of the mercury that currently deposits in

south Florida originates outside the United States. The commenter conceded that in the late

1980s it is likely that the local contribution was somewhat higher than today, it could not have

been 100 percent. The commenter summarized, the magnitude of the connection between local

mercury emissions reductions in south Florida and local biotic response is tempered by the

contributions from other mercury emissions changes worldwide and other ecosystem changes

affecting the biotic response.

Relative to the issue of extrapolation, the commenter stated there are numerous arguments

why the results cannot be extrapolated to CFPPs in other areas of the country. The commenter

submitted that whatever relationship that may exist is unique to the type of emissions, the

climatology, and the type of ecosystem that exists in south Florida. First, as demonstrated above,

we don’t know the magnitude of the connection between local mercury emissions and local biotic

responses. Second, municipal and medical waste incinerators–not power plants–are the source of

industrial mercury emissions in south Florida that are referenced in the Florida report. 

Incinerators produce far higher percentages of ionic mercury–the form of mercury that is

water-soluble and more readily deposited–than coal-fired power plants and have far shorter stack

heights resulting in the potential for higher amounts of mercury being deposited near these

sources. Third, there is evidence that ionic mercury emissions from CFPPs rapidly converts to

elemental mercury–the form of mercury having a long atmospheric residence time–a phenomena

not observed in incinerators, which suggest that the link between emissions and local deposition

would be even less for CFPPs. Fourth, the climatology of south Florida is unique to the U.S. with

daily, deep convective thunderstorms that converge over the Everglades in the summer. Fifth, the

Everglades are not representative of U.S. waterways because they are in a subtropical zone with

no distinct seasons and high rainfall in the summer, contain shallow water with very low flow

rates, and with bottom sediments that differ from those in other locations. Other waterbodies also

have different levels of acidity, biological activity, dissolved oxygen, and turbidity. The

commenter asserted that all of these differences could dramatically affect mercury cycling and

uptake by biological organisms and make extrapolation of the Florida results to other areas of the

country inappropriate. The commenter pointed out that in Minnesota, for example, mercury

emissions also have declined dramatically from 1990 to 2000 (about 68 percent–Minnesota

Pollution Control Agency, March 2004), yet mercury in fish of that area has not changed

significantly in the last 15 years. The commenter summarized, the extrapolation of the Florida
lviii

mercury emissions to deposition or deposition to biotic response relationships, to other sources

and areas of the country is inappropriate.

The commenter stated, accordingly, the Report cannot justify a conclusion by EPA that

coal-fired power plants create local “hot spots” nor can the results be extrapolated to CFPPs in

other parts of the country. The commenter added that the Report itself recognizes its limited

focus and is replete with assumptions, caveats, cautions and recommendations for further work,

none of which is mentioned in the references or citations above. More detailed comments

regarding the Report are summarized as follows:

• The analysis upon which the Report relies is a work-in-progress, and therefore the

conclusions are at least premature. The Report expressly recommends that further

information be obtained and provides seven specific cautions when interpreting the results.

• Any claim that cost-effective control strategies have substantially reduced mercury

concentrations in south Florida’s fish and wading birds is premature. A research project in

excess of $300,000 has been designed specifically to shed light on this assertion, that is, to

elucidate between competing hypotheses for explaining the observed reduction of mercury

in south Florida’s biota.

• Not all ecosystems are created equal. Mercury may be accumulated up the food chain

differently in other ecosystems than in the Everglades. To the extent decreases in local

reactive mercury emissions result in local declines in concentrations in fish and wildlife

might be true in the area of study (central Everglades), there are substantial differences in

responses even across the Everglades ecosystem. There is also evidence of a general

decline in mercury in biota in areas that are remote from local sources.

• While it may be true that total quantities of mercury emitted from CFPPs are substantially

larger than that of incinerators on a world-wide basis, the form of mercury emitted from

coal plants is more in a form (non-reactive) not readily deposited on a local scale. In

addition, recent research indicates that any reactive mercury that is emitted from coal-fired

power plants is largely transformed to the non-reactive form before deposition can occur. 

Furthermore, a press release from the Resources Committee, US Congress, states that

U.S. coal-fired power plants emit only 1 percent of the total global mercury emissions,

citing peer-reviewed research published in Atmospheric Environment, 2003. In addition,

emissions measurements analyses show that the data quality varies widely between

different sources and geographically.

• The Report describes impressive reductions in mercury emissions achieved by municipal

waste incinerators and by the closing of numerous small medical waste incinerators. 

These reductions and the implied reductions in mercury inputs to the Everglades

ecosystem must be considered in the context of the high percentage of reactive mercury

emitted from these facilities, 75 percent and 95 percent, respectively.
lix

• The Report does not support the idea that the Lake Annie (sediment core) data shows a

peak in deposition coinciding with the peak in emissions, followed by a rapid decline

consistent with emission reductions from the Dade and Broward County incinerators

150 miles away. The implication that emissions from the Dade and Broward County

incinerators affected mercury accumulation in the Lake Annie cores is not supported. 

Researchers have postulated that mercury reduction effects can be seen 60 miles from an

emission source. However, prevailing winds from Dade and Broward counties are

unlikely to cause consistent depositional impacts in an area northwest of Lake

Okeechobee. In addition, the magnitude of decrease (assuming it has been corrected for

focusing and rainfall) was small and should have been noted as evidence for local sources

not playing much of a role.

• A modern and retrospective study of mercury in feathers from wading birds is cited as

following the pattern of mercury emissions from 1920 to 2002. However, a modern and

retrospective study of mercury content in hair of raccoons (Porcella et al., 2004) failed to

demonstrate a significant difference over the last 50 years in south Florida. However, a

large difference existed between sites (up to a factor of 20) for raccoon hair mercury in

both modern and historic samples. The difference between the wading bird data and the

raccoon data may be due to a broader sampling area for raccoons (across the entire south

Florida peninsula), compared to feather collections from specific rookeries.

• The idea that reductions in mercury deposition will be more dramatic closer to Broward

and Dade counties where the majority of emissions reductions from incinerators occurred

is also not supported. Specifically, the Florida Atmospheric Mercury Study (referred to in

comment g) results do not bear this out.

• Finally, the South Florida Report characterizes mercury as a “now well-understood

neurotoxin.” This is certainly arguable since major studies of neurological effects of

prenatal mercury exposure in children are not in agreement. No one seriously disputes the

fact that, at high levels of exposure and in laboratory settings, mercury is toxic to the

brain. However, setting an exposure limit for regulatory purposes should use the best data

available from the most realistic and broadly generalisable studies.

One commenter (OAR-2002-0056-2251) claimed that new research from Michigan, a

state with significant coal-based electricity generation, further discredits the “hot spot” theory. A

March 2004 study conducted for the EPRI by Atmospheric and Environmental Research, Inc.

found that “Mercury emissions from Michigan coal-fired power plants are calculated to contribute

between 0.5 and 1.5 percent to total mercury deposition over each of the Great Lakes and about

2 percent statewide”. The commenter enclosed a copy of this study, Modeling Deposition of

Atmospheric Mercury in Michigan and the Great Lakes Region.

Several commenters (OAR-2002-0056-2251, -2833, -3530) also noted that according to

the rule’s preamble, EPA “does not expect any local or regional hot spots” if it selects the cap and

trade approach and will consider using trading ratios to address regional differences if they occur. 

The preamble also made it clear that states will have the ability to address any remaining local
lx

health-based concerns if the EPA selects the section 111 cap and trade option. The commenters

pointed out that indeed, the Clean Air Act provides states with discretion to enact more stringent

air quality regulations than required by the Act, with the exception of certain limitations for

automotive emissions. States would be free to develop specific mercury control strategies to

supplement the final federal rule, regardless of its form or level of stringency.

Several commenters (OAR-2002-0056-2830, -3463) believed that mercury allowance

trading will not cause adverse local environmental or health impacts because most power plant

mercury emissions become elemental mercury soon after release and enter the global pool instead

of depositing near the power plant from which it originates. Commenter OAR-2002-0056-3463

stated that elemental mercury is not as likely to be deposited locally as is particulate and oxidized

mercury. According to the commenter, a comparison of “Wet Deposition” data to “Total

Mercury Concentration” data from the National Atmospheric Deposition Program/Mercury

Deposition Network documents strongly supports the conclusion that deposition is more a

function of precipitation than proximity to emission sources. The commenter also pointed out

that the proposed IAQR rules to control SO2 and NOx will require the installation of pollution

controls that also will capture the forms of mercury that tend to deposit nearby.

One commenter (OAR-2002-0056-3353) stated that based on the known science of

mercury transport, transformation, and health effects, the Agency proposal to control mercury by

a cap and trade program is appropriate and health protective. The commenter presented extensive

information on the science of mercury (see section 6 of e-docket item OAR-2002-0056-3353)

supporting the commenter’s belief that a cap and trade approach will not endanger public health

or result in hot spots of mercury health risk. The commenter stated that it will, on the other hand,

encourage the continuing development of low cost mercury controls. As the program proceeds

and experience is gained with various control options, the commenter believed the cost of control

will be explicitly identified.

One commenter (OAR-2002-0056-2431) supported the cap and trade approach because

mercury exposure does not present a public health concern warranting stricter regulation under a

MACT standard. According to the commenter, recent research by the CDC indicated that people

are not being exposed to unsafe mercury levels and the recent Seychelles Child Development

Study assessments at 9 years of age show no detectable adverse effects. The commenter also

pointed out that in the December 2000 regulatory finding, EPA was unable to quantify the

connection between utility mercury emissions and mercury in fish, citing only a “plausible link.”

One commenter (OAR-2002-0056-2578) claimed to have performed an extensive

modeling exercise with state-of-the-art tools and data to explore projected deposition patterns

under both regulatory proposals. The commenter’s analysis showed that:

• The highest levels of mercury deposition anywhere in the continental United States are

brought about primarily by non-utility sources (even after accounting for MACT rules on

those non-utility sources).
lxi

• The Cap & Trade proposal would produce larger and more widespread reductions in

mercury deposition compared to current emissions than would the MACT proposal,

particularly in regions with the highest deposition currently.

The commenter also cited increasing evidence from laboratory, pilot-scale, and full-scale

measurements that the divalent form of mercury may convert to the far less soluble elemental

form within power plant plumes and that this apparently rapid and complete conversion would

reduce local scale deposition from power plants significantly, if it is found to hold for a wide

range of such sources. To verify these preliminary results, the commenter undertook a field

program at two power plants using a combination of aircraft measurements, surface observations,

in-plant measurements, and coal sampling. At both power plants from the stack to downwind

sampling locations, the commenter reported a significant increase in the elemental mercury

concentration and a corresponding decrease in the divalent mercury concentration. According to

the commenter, these initial demonstrations of the significance of a potential reduction reaction

may imply that utility power plant mercury emissions contribute less to downwind wet deposition

than has been assumed previously.

One commenter (OAR-2002-0056-2862) stated that while there is evidence in the

literature regarding apparent linkages between incinerator mercury emissions and enhanced

mercury deposition near these sources, extensive modeling work, as well as detailed flue gas

chemistry measurements, did not support a similar linkage for coal-fired power plants. Indeed,

preliminary results from the EPRI I U.S. DOE -funded plume chemistry work that is currently

underway and discussed in EPRI’s comments on these proposed rules, strongly reinforced EPA’s

assertion that the cap and trade program is unlikely to produce so-called areas of enhanced

mercury deposition near coal-fired power plants. Based on these conclusions, the commenter

asserted that EPA should not require units in “sensitive” areas to surrender more allowances than

units in other areas deemed less sensitive (e.g., requiring some units to surrender two allowances

for an ounce of mercury emissions rather than the standard one allowance). Commenter

OAR-2002-0056-2948 also stated that EPA should not require units in “sensitive” areas to

surrender more allowances than other areas deemed less sensitive because this would significantly

and unnecessarily complicate the trading program and would lower the cap. The commenter

added that EPA’s proposal did not describe how such “sensitive” areas would be defined, and

only a very small portion of mercury emissions from coal-fired power plants deposit within 50

kilometers in any event. The commenter stated that adoption of this proposal will only add a

great deal of complexity to the program.

Similarly, one commenter (OAR-2002-0056-2861) stated there is no basis for any

provision in EPA’s mercury rule to require the surrender of more than one allowance per ounce of

mercury emissions related to the alleged issue of mercury sensitive areas or “hot spots.” The

commenter submitted neither EPA nor anyone else has made any demonstration of a linkage

between power plants in a given area and elevated mercury deposition or exposure in that area. 

The commenter added that by nature of the cap and trade program and by nature of how power

plants operate, there is no concern that the mercury cap and trade program would create such

“hot spots.” The commenter noted the cap and trade program at the proposed levels would

achieve a significant overall reduction in mercury emissions across the nation. The commenter
lxii

believed the larger, higher emitting sources are the sources that will be controlled. Requiring the

surrender of more than one allowance in certain areas would greatly complicate and confuse the

trading program and would result in a lowering of the emissions cap. The commenter stated this

also would affect the cost of compliance that was used to establish the performance standard that

is the basis of EPA’s cap and trade program. The commenter believed such a provision should

not be allowed without a clearly demonstrated need and that demonstration would be extremely

subjective as it relates to the definition and identification of “sensitive” areas and the sources

whose emissions would be deemed to impact those areas and therefore required to surrender

additional allowances. The commenter concluded that there is simply no credible way to make

such determinations, and in fact EPRI studies of mercury deposition and exposure suggest that

such a program would not be justified.

One commenter (OAR-2002-0056-3537) submitted that a mercury cap and trade program

would not increase local mercury deposition in waterbodies close to regulated Utility Units and

create hot spots. The commenter stated in fact, EPA’s analysis showed that, if anything, a cap

and trade program would help to protect against potential hot spots rather than aggravate them. 

The commenter noted that EPA’s modeling suggested that large coal-fired Utility Units, which

are those units that tend to have relatively high mercury emissions, are likely to have larger local

deposition footprints than medium and smaller sized coal-fired Utility Units. However, the

commenter submitted that the trading of allowances will probably lead to the over control of

mercury emissions at the larger Utility Units and the selling of allowances to smaller Utility Units. 

Why? According to the commenter it would make more economic sense (due to economies of

scale) for a utility to allocate pollution prevention capital expenditures to its larger, generally more

efficient facilities than to smaller, generally less efficient plants. Several other commenters

(OAR-2002-0056-1969, -2841, -2861) stated that the most cost-effective reductions will be made

first at the larger, higher emitting sources.

The commenter (OAR-2002-0056-3537) submitted second, the types of mercury that are

deposited locally–ionic and particulate mercury–are controlled somewhat by the same type of

equipment that will be used to comply with the CAIR (i.e., FGD and SCR). These types of

mercury are more likely to be deposited locally than elemental mercury, which is emitted in a

gaseous form, is not soluble in water, has a relatively long life in the atmosphere and which

remains uncontrolled by FGD and SCR. The commenter stated that as utilities invest in

equipment to comply with not only the CAIR but also with new national ambient air quality

standards for PM2.5 and ozone, a co-benefit in mercury control will be achieved. Those

co-benefits will be the increased control of ionic and particulate mercury, decreasing even further

the extremely small amount of mercury now deposited locally by Utility Units. The commenter

claimed, therefore, a mercury cap and trade program would lead to increased control on the forms

of mercury most likely to be involved in potential hot spots.

The commenter pointed out that modeling conducted by the Electric Power Research

Institute (EPRI) has demonstrated that mercury must be studied and understood on a global scale

rather than a national one. The commenter stated that U.S. utility mercury emissions account for

only 1 percent of total yearly mercury emissions worldwide. A recent report indicated that the

amount of mercury released to the air from the earth’s surface each year is estimated to be
lxiii

between 2700-6000 tons, with another 2,000-3,000 tons emitted by human activities, yielding a

total amount of mercury that enters the atmosphere each year of 4700-9000 tons. The

non-anthropogenic fraction is due to volcanic action, natural weathering and re-entrainment of

crustal material and the re-emission of mercury associated with past man-made emissions since

the Industrial Revolution. The commenter noted that by comparison, a number of sources

estimate current emissions of mercury from U.S. utilities to be approximately 48 tons per year,

which is less than 8 percent of the mercury deposited in the U.S. The commenter stated that a

2003 study by EPRI indicated that if ionic mercury emissions from coal-fired power plants were

reduced by 10 percent, mercury deposition in the U.S. would decrease by only 0.75 percent. If

elemental mercury emissions from coal-fired power plants were reduced by 10 percent, the

resultant drop in mercury deposition in the U.S. would only be 0.03 percent.

Finally, the commenter stated EPA noted that States retain the power under the CAA to

adopt stricter regulations to address any local hot spots or other problems. Given the 70 percent

emission reduction proposed in EPA’s cap and trade systems, the Agency noted that it expects no

local regional hot spots. The commenter noted however, it also stated that it plans to continue

monitoring mercury emissions and the operation of the trading system through its administration

of the MATS, to ensure that localized hot spots do not materialize. Accordingly, the commenter

believed it is clear that EPA imposition of a mercury cap and trade program, would, if anything,

reduce the potential for localized hot spots around affected Utility Units. EPRI provides an

extensive discussion on the hotspot issue in their comments and the commenter respectfully

referred EPA to this discussion as further evidence that hot spots will not be a concern under a

mercury cap and trade program.

One commenter (OAR-2002-0056-3546) submitted that EPRI’s most recent research has

shown that the highest level of mercury deposition anywhere in the continental United States are

brought about by non-utility sources. According to the commenter, EPRI’s analysis further

demonstrated that the Cap-and-Trade proposal would produce larger and more widespread

reduction in mercury deposition than would the MACT proposal.

The commenter stated that it is well understood that mercury is a global pollutant. 

According to the commenter, EPRI model results showed that approximately 75 percent of the

mercury that deposits in the United States originates from sources outside the U.S. For areas in

the west, the contribution of global emissions to mercury deposition may be as high as

100 percent. The commenter stated that mercury emissions from coal-fired power plants mercury

deposition will not increase in any area as a result of a cap-and-trade program. The commenter

noted that modeling work performed by the Electric Power Research Institute predicts that

reducing total mercury emissions from coal-fired power plants from present day levels to 15 tons

annually will reduce mercury deposition in the United States by 6.9 percent–from 165.4 tons to

153.9 tons per year. The reduction in deposition in western states would be substantially less

since mercury deposition from global sources can be as high as 100 percent.

The commenter claimed that cap-and-trade programs promote economically efficient

decisions to reduce emissions from power plants. According to the commenter, Units with the

highest mercury emissions would be among the first to be controlled since the cost per pound of
lxiv

mercury controlled would the lowest at these units. The commenter noted that this economic

behavior has previously been demonstrated in utilities compliance with EPA’s Acid Rain

requirements and the NOx SIP call. On a source-by-source basis, the opportunity to trade has led

many of the largest SO2 and NOx emitters to clean up the most, such that trading has had an effect

of cooling potential hot-spots, not creating them.

Response:

EPA has addressed the hot spots issue in the revision Federal Register notice and in the

Effectiveness TSD.

Comment:

Several commenters (OAR-2002-0056-2560, -2897) stated that if hot spots did occur,

focused local investigations and some simple constraints would be the best available practice for

the accurate identification of contributing localized mercury deposition sources. Commenter

OAR-2002-0056-2560 offered as an example, based on the presentation by Opto-Forensics

Technologies at the 2004 Electric Utility Environmental Conference in Tucson, Arizona the

solution to fish tissue mercury level reductions may well lie in the monitoring and control of

mercury emission from municipal landfill vents and not in the reduction of local EGU emissions.

Commenter OAR-2002-0056-2897 offered as another example, EGUs in the immediate

vicinity of vulnerable ecosystems could be prohibited from trading, or minimal levels of mercury

reductions at all facilities could be required. The commenter stated this would still allow trading

to achieve the greatest reductions where it is cheapest and to incentivize the development of

control technology. The commenter asserts that in the unlikely event that hot spots are a serious

concern, they can be readily addressed and should not be a basis for giving up the significant

benefits offered by a cap-and-trade approach to mercury regulation on a national basis.

Response:

EPA has addressed the hot spots issue in the revision Federal Register notice and in the

Effectiveness TSD.

Comment:

One commenter (OAR-2002-0056-2922) stated that EPA should not require units in

“sensitive” areas to surrender more allowances than units in other areas deemed less “sensitive”

(e.g., requiring some units to surrender two allowances for each ounce of mercury emissions

rather than the standard one allowance per ounce). The commenter submitted that hot spots have

not resulted in the Title IV Acid Rain Program, and, as discussed above, no reason exists to

believe they will occur in this program. Moreover, requiring different areas to surrender different

numbers of allowances would complicate the trading program and result in a lowering of the cap,

contrary to EPA’s regulatory determinations.
lxv

Response:

EPA has addressed the hot spots issue in the revision Federal Register notice and in the

Effectiveness TSD.

Comment:

Several commenters (OAR-2002-0056-1625, -1673, -2547, -2725, -2850, -2929, -3478)

pointed out that under a cap-and-trade program, the larger emitters will be the first to be

controlled. For example, several commenters (OAR-2002-0056-1625, -2929, -3478) stated that

the economics of trading will help to minimize local deposition. The trading of allowances almost

always involves large coal-based power plants controlling their emissions more than required and

selling allowances to smaller plants. Thus, economies of scale of pollution control investment will

favor investment at the larger plants and will produce reductions in emissions at the plants of

greatest interest. One commenter (OAR-2002-0056-2725) stated that this is doubly true with

mercury; because ionic mercury, the form of mercury that is most likely to be deposited near the

plant, is also the easiest and least expensive to control, a mercury trading program would result in

emissions reductions at exactly those plants most likely to be responsible for “hot spots. One

commenter (2929) noted that the CAIR proposal and other pending state and federal regulations

would require the installation of pollution controls that also would capture the forms of mercury

that tend to deposit nearby.

Response:

EPA has addressed the hot spots issue in the revision Federal Register notice and in the

Effectiveness TSD.

Comment:

One commenter (OAR-2002-0056-1627) stated that what has emerged from monitoring

actual mercury deposition is a far different picture than predicted by many of the early computer

models which predicted the presence of hot spots. The commenter submitted that actual data

demonstrates that power plants do not significantly affect deposition. The commenter believed

hot spots should now be seen to simply be artifacts of the first generation of computer models

rather than real occurrences.

Response:

EPA has addressed the hot spots issue in the revision Federal Register notice and in the

Effectiveness TSD.

Comment:

Many commenters (OAR-2002-0056-2173, -2227, -2380, -2415, -2575, -2660, -2817,

-2838, -2871, -2880, -2887, -2889, -2878, -2924, -3202, -3413 -3448, -3452, -4177) believed
lxvi

mercury trading may lead to hot spots. One commenter (OAR-2002-0056-2173) noted that

concerns about trading are recognized in the regulatory finding, including that the lakes regions of

the Upper Midwest may be more sensitive to mercury deposition. The commenter submitted that

a recent New Hampshire study suggested that local deposition is very much a concern. However,

EPA then claims in the preamble that it does not expect any local or regional hot spots and

provides no support or anecdotal arguments in support. The commenter states that hot sports are

a real concern in the midwest because of the use of western sub-bituminous coal. It is more

difficult and costly to reduce mercury emissions from this coal type than from eastern bituminous

coal. Thus, the commenter believed that utilities would be more likely to purchase emission

credits from utilities burning eastern coal that have installed controls. The commenter asserted

that the result would be that Tribal lands and the entire lakes area of the upper midwest (which is

particularly sensitive to mercury deposition and most needing of reductions) may experience little

or no benefit. Another commenter (OAR-2002-0056-2227) also noted that EPA’s own data show

that mercury hot spots exist and are associated with local sources of air pollution.

An alliance of many commenters (OAR-2002-0056-2575) stated that data collected by the

North American Commission for Environmental Cooperation show that there are 244 locations in

North American where the amount of mercury contamination is greater than that which occurs

naturally in the environment. The commenter also provided several examples of the impact of

local sources on mercury deposition. and the resulting effects on wildlilfe. The commenter

claimed a cap and trade program would only continue and exacerbate mercury deposition and

increase the number of hot spots. The result would be concentration of pollution in certain areas

and merely a reallocation of pollution rather than reduction or even an increase.

One commenter (OAR-2002-0056-2838) submitted that in-state and regional sources of

mercury in the Southeast contribute to high levels of deposition; four of the top 10 most severe

hot spots are in Southeastern states. The commenter believed the cap and trade program has

great potential to exacerbate mercury contamination at many sites by allowing large plants to

continue emitting; studies show that this mercury would be deposited in-state or within the

Southeast region. The commenter stated that according to EPA’s Mercury REMSAP Deposition

Modeling Results, coastal regions along the Gulf of Mexico and southern Atlantic will require

more than 75 percent reduction in air deposition rates to meet EPA’s CWA requirements for

methyl mercury.

Another commenter (OAR-2002-0056-2878) stated that recent modeling suggests that at

mercury hot spots, pollution sources within a state can account for large portions of that

deposition. The commenter claimed that at hot spots across the US, local sources often account

for 50 to 80 percent of the mercury deposition. The commenter also submitted that in-state

sources contribute more than 50 percent of the pollution to sites in the top 8 worst hot spot states

(Draft Mercury Deposition Modeling Results, EPA:OW, 2003). The commenter stated that data

from the Florida Everglades study showed that local reductions of mercury yielded reductions in

mercury pollution. The mercury deposition research in the Florida Everglades, Wisconsin, and

southern Ontario also indicated that the majority of mercury converted into methylmercury is

from recent deposition, rather than cycling from the sediment, suggesting that reducing mercury
lxvii

emissions from all coal-fired plants is a critical need for reducing exposure and improving

damaged ecosystems.

One commenter (OAR-2002-0056-2380, -3413) also stated that earlier modeling showed

that local hot spots are the primary sources of mercury deposition within a state, contributing

more than 50 percent of the pollution to sites in the top 8 worst hot spot states. The commenter

submitted that EPA should include provisions in the rule to address hot spots before they occur.

Many of the commenters (OAR-2002-0056-2660, -2817, -2871, -2880, -2887, -2889,

-2924, -3202, -3448, -3452, -4177) referred to the recent Florida study (Integrating Atmospheric

Mercury Deposition with Aquatic Cycling in South Florida, November 2003), which showed that

sources of mercury can have significant local impacts. This report stated that the drastic

reductions in mercury concentrations in fish and birds in the Everglades were directly linked to

installation of mercury controls by industries in South Flordia. One commenter

(OAR-2002-0056-2819) noted that EPA has already reported that deposition of oxidized mercury

can be expected to occur within 50 kilometers of the source; evidence of the existence of hot

spots has already been documented in the Evers report (Assessing the Potential Impacts of

Methymercury on the Common Loon in Southern New Hampshire) and the Florida Everglades

report. The commenter stated that additional evidence of the existence of mercury hot spots can

be found on the University of Michigan website at

http://www.personal.umich.edu/~kalwali/mich+ohio.html . This website shows color coded maps

that distinguish the relative hot spots associated with mercury emissions from local sources from

mercury emissions due to longer range transport (regional sources). The commenter asserted

that EPA cannot dismiss these concerns.

One commenter (OAR-2002-0056-2819) submitted recent stack test data showing that

72-94 percent of the mercury emitted by coal-fired boilers is emitted as oxidized mercury. These

tests (2003) used the Ontario Hydro method to determine the amount of total mercury and the

total amount by species. According to the test data, 2003 annual emissions of oxidized mercury

from Merrimack Station units 1 and 2 were 32 pounds and 77 pounds, respectively. Annual

emissions of oxidized mercury from Schiller Station units 4, 5, and 6 were 7 pounds. The

commenter believed that emissions of this magnitude have the potential to cause local hot spots

which can not be remedied solely with a cap and trade program. The commenter submitted that

stringent plant-specific MACT limits are needed to address local hot spots. Also, the commenter

pointed out that EPA’s prediction that small and mid-size units like Schiller and Merrimack

Station would likely purchase credits rather than install controls (see 69 FR 4702) confirmed that

the cap and trade would not address localized deposition in their state. The commenter believed

that the only sure method for addressing hot spots would be to reduce emissions at their source

through strict MACT standards. The commenter concluded that it was also a good reason that

more stringent limits should apply to all units regardless of size.

One commenter (OAR-2002-0056-2887) contended that EPA has not considered local

deposition that can disproportionately affect sensitive ecosystems. The commenter claimed

sources that purchase allowances in effect emit uncontrolled levels of all three species of mercury

- gaseous elemental, reactive gaseous (RGM), and particulate. The commenter stated trading can
lxviii

worsen existing hot spots and may create new ones near powerplants because the RGM (which

can be as high as 70 percent of the total mercury emitted from a bituminuous plant) has relatively

short travel distances (up to 50-100 kilometers) and short residence times in the atmosphere (1-2

days), tending to deposit locally near the source. The commenter also noted that recent field

studies showed that mercury newly deposited to a zone of methylation in a waterbody is more

readily converted to methylmercury. The commenter claimed that, in addition to local impacts,

the Northeast is affected by long-range transport of elemental mercury because areas with high

ozone levels oxidize elemental mercury and therefore increase mercury deposition throughout the

airshed. Further, the commenter cited a report by the New Jersey Mercury Task force which

examined local emissions, models, and results, and stated that about half of the mercury deposited

in New Jersey comes from relatively nearby sources. One commenter (OAR-2002-0056-4177)

cited the NESCAUM Deposition Study which concluded that 47 percent of mercury deposition in

the Northeast came from sources within the region, 30 percent from sources outside the region,

and 23 percent from the global reservoir. One commenter (OAR-2002-0056-3202) asked EPA to

establish more rigorous national standards so downwind states can meet Clean Water Act

requirements. One commenter (OAR-2002-0056-3452) submitted a REMAP assessment of

mercury in sediments of selected lakes in New Hampshire and Vermont which showed the

disproportionate impact of airborne mercury from a power plant and municipal waste combustor.

Response:

EPA has addressed the hot spots issue in the revision Federal Register notice and in the

Effectiveness TSD.

Comment:

Several commenters (OAR-2002-0056-1596, -2330, -2819, -2823, -2871, -2889, -3449,

-3499) noted that in the proposal, EPA indicated that hot spots could be addressed through the

adoption of more stringent state or local standards. The commenters disagreed and cited their

recent survey that showed about half of the state agencies have restrictions on their ability to

adopt programs more stringent that those of the federal government. In addition, hot spots can be

created across state lines, so that a downwind state is dependent on stricter controls that may be

installed by utilities in an upwind state. One commenter (OAR-2002-0056-2819) added that their

state relies upon adoption of a strict federal standard under section 112 to establish state limits to

meet an annual cap and relying on states to adopt meaningful controls creates an economic

disadvantage compared to lax states. One commenter (OAR-2002-0056-3449) asked what these

related Federal and State programs are that are supposed to address local risks?

Response:

EPA has addressed the hot spots issue in the revision Federal Register notice and in the

Effectiveness TSD.

Comment:
lxix

Many U.S. Congressmen (OAR-2002-0056-3293) felt that the rule could be strengthened

by addressing hot spots now rather than later. The commenters suggested that adding regional

emissions trading areas for States with high mercury or setting a level of emissions above which

no plant could emit would help protect the public health.

Many state legislators, governors, and local officials called on EPA to strengthen the

proposed standards as they are not protective of public health and do not adequately address hot

spots. The commenters pointed out that available technology can achieve reductions of 80 or

90 percent. The commenters also pointed out that the emission reductions fall well short of the

cuts that could be achieved by 2007 under section 112. One Texas representative stated that no

state emits more mercury pollution from its power plants than Texas and no state faces a greater

risk from cap and trade than Texas, which could see no emission reduction at all.

Response:

EPA has addressed the hot spots issue in the revision Federal Register notice and in the

Effectiveness TSD.

Comment:

One commenter (OAR-2002-0056-3543) supported the cap and trade program but

pointed out that data on hot spots appears scant. The commenter stated that while EPA states it

intends to collect data and study the effectiveness of the rule in Phase I and II in order to make

any necessary adjustments, it presented no clear strategy for collecting and analyzing information,

no solid data on which to formulate a baseline for this analysis, and no strategy for changing the

regulatory approach if it aggravates hot spots.

Similarly, one commenter (OAR-2002-0056-2219) disagreed with EPA’s suggestion to

evaluate mercury hot spots formed as a result of the cap and trade program. As described in the

preamble, EPA would evaluate whether emissions remaining after compliance with the cap and

trade program cause a health program. The commenter believed this would be problematic

because conducting an evaluation in 2018 after the implementation of the program would be too

late; the mercury accumulation would have already occurred and people would be exposed then

on. In addition, EPA does not have a good “on time” track record.

Response:

EPA has addressed the hot spots issue in the revision Federal Register notice and in the

Effectiveness TSD.

Comment:

One commenter (OAR-2002-0056-3210) disputed EPA’s rationale that the economics of

a cap and trade program would lead to better control of bituminous coal sources since these

sources emit more oxidized mercury and may deposit mercury locally. The commenter noted that
lxx

EPA believes reducing oxidized mercury would reduce local hot spots. The commenter asserted

that this rationale ignores current science on the atmospheric chemistry of mercury and the

regional concentration component of the mercury deposition problem. The commenter submitted

that uncontrolled sources of elemental mercury will continue to contribute to regional mercury

deposition, especially in the summer during high ozone season. The commenter cited several

studies and reports indicating that areas with elevated ozone levels can expect increased mercury

deposition. The commenter concluded that mercury deposition is a year round local hot spot

issue and a seasonal widespread regional deposition issue.

Similarly, one commenter (OAR-2002-0056-3437) submitted information confirming that

mercury deposition of local waterbodies will continue as emissions actually increase under the

lenient MACT limits or a cap and trade approach. While the commenter was generally supportive

of a cap and trade approach , the commenter believed it must be designed to assure no hot spots. 

The commenter provided evidence from deposition monitoring that showed a correspondence

between mercury deposition values and mercury emissions from sources within a 50 km radius;

mercury deposition rates were highest at the monitor where nearby emissions were the highest. 

Given the concern about mercury deposition in the Great Lakes and the Grand Calumet

watershed, the current mercury load in the region, and the potential for hot spots, the commenter

was very concerned about any approach that would allow emissions to increase above 1999

levels.

Response:

EPA has addressed the hot spots issue in the revision Federal Register notice and in the

Effectiveness TSD.

5.4.1 Trading Constraints to Address Hot Spots

Comment:

Several commenters (OAR-2002-0056-2911, -3556) stated that mercury deposition is an

issue that is global in scale and that U.S. EGUs represent about 1 percent of the global emissions. 

The commenters stated that EPA acknowledges that it cannot determine what the contribution of

EGU mercury emissions is to concentrations in fish. The commenters further stated that EPA

also acknowledges that it cannot determine how much the concentrations in fish will decrease, if

at all, once EGU mercury emissions are reduced. The commenters noted that the concentration

of mercury in fish is the pathway of exposure to humans. The commenters also pointed out that

EPRI has submitted detailed comments addressing the issue of mercury “hot spots” and the lack

of relevance to EGU mercury emissions. Consequently, the commenters could see no scientific

justification to regional allocations and trading. In order to have a viable and robust trading

program, the commenter 3556 believed it must be national in scope.

One commenter (OAR-2002-0056-4139) stated that any cap and trade program should be

contained to a geographic area.
lxxi

Response:

EPA has addressed the hot spots issue in the revision Federal Register notice and in the

Effectiveness TSD.

Comment:

One commenter (OAR-2002-0056-2064) opposed trading under CAA section 111 on a

national scale. The commenter believes if trading is allowed under section 111, it should be

limited to a regional or contiguous basis because of interstate deposition problems with mercury. 

Similarly, one commenter (OAR-2002-0056-3437) suggested that EPA should consider if

geographic or other constraints on trading are needed to prevent hot spots. The commenter

recommended establishing reduction targests to assure that all plants reduce emissions to some

degree. The commenter submitted a cap and trade program must contain a backstop to ensure

that no individual plant could emit more mercury than in 1999. The commenter believed the rule

also must assure that states retain the ability to address local hot spots.

Response:

EPA has addressed the hot spots issue in the revision Federal Register notice and in the

Effectiveness TSD.

Comment:

Several commenters (OAR-2002-0056-3437, -3443) responded to EPA’s request for

comments on whether it would be appropriate to adjust the geographic scope of the trading

program by introducing trading ratios to address regional differences. (See Fed. Reg. 4651,

4701.) One commenter (OAR-2002-0056-3437) understood that geographical constraints would

be one possible approach to prevent hot spots. But the commenter believed this approach could

add much complexity to the trading program and might not provide the desired result. The

commenter stated a preferable approach would be a stringent limit to allocate allowances and the

flexibility to impose more stringent local requirements. The commenter cautioned that EPA

should be very clear about trading ratios so that industry will have clear direction to plan for

compliance and states will be aware of any responsibilities that will be imposed on them.

One commenter (OAR-2002-0056-3443) did not support such adjustments to the

geographic scope because they would hamper the effectiveness of the trading program by

interfering with the market. More importantly, the commenter saw no need for such adjustments

because EPA’s analysis in the preamble leads to the conclusion that “hot spots” would not be a

problem under a cap and trade program. (See 69 Fed. Reg. 4,651, 4,702-03.)

The commenter presumed that the main reason for making such geographic adjustments

would be to address the potential for localized impacts. In regard to the issue of localized

impacts, the commenter has been monitoring mercury in sediments and fish in the reservoirs on

the Tennessee River and its tributaries for over 30 years. The commenter stated that these studies
lxxii

show that mercury levels in the sediment for both mainstream and tributary reservoirs in the entire

Tennessee Valley region have declined substantially since 1973. Likewise, the commenter stated

that although mercury levels in fish tissue in the reservoirs along the Tennessee River have varied,

these levels indicate a constant or declining trend despite an increase in coal-fired generation on

the commenter’s system during this period. (The commenter attached a letter dated November

19, 2003, from the commenter to EPA on Mercury in Sediment and Fish in the TVA Reservoirs.)

The commenter submitted that although the study identified areas with elevated mercury, none of

these elevated levels were attributable to emissions from the commenter’s coal-fired units. 

Rather, the elevated levels were the result of industrial activity, such as waste water discharges

form the chlor-alkoli industry.

Response:

EPA has addressed the hot spots issue in the revision Federal Register notice and in the

Effectiveness TSD.

Comment:

One commenter (OAR-2002-0056-2247) stated that while they viewed a cap and trade

program as the preferred policy approach, the cap must be lower and the trading properly

constrained. The commenter suggested an additional control option. To insure reductions from

western coal users and to prevent drift of emissions from eastern to western states, the commenter

submitted that EPA should combine a lower cap with some form of a zonal trading plan that

would achieve reductions in both the eastern and western areas of the U.S.

The commenter claimed that up to 90 percent of the mercury entering their waters comes

from atmospheric sources outside the state. Their TMDL studies showed that a reduction in the

range of 50 percent in atmospheric deposition would be needed to meet their projected water

quality standard. EPA’s deposition modeling predicted only a 5 percent reduction in certain areas

of the state. The commenter believed the proposed cap of 15 tons is so loose that utility boilers in

the commenter’s state and those to the sourth and west would do little to control mercury

emissions. The IPM modeling showed that utility boilers in the commenter’s state and similar

boilers west of the Mississippi burning Powder River Basis or lignite coal would reduce emissions

by only 35 percent as a co-benefit of controlling SO2 and NOx. These states, including utilities in

the commenter’s state, are predicted to purchase credits from eastern utilities rather than control

releases. Even the 5 percent reduction EPA predicted for the commenter’s state may not occur

because modeling did not account for banking or the cost-based safety valve. The commenter

believed the 15 ton final cap would not address the commenter’s problem–it seemed to shift the

cost of SO2 and NOx controls at eastern boilers to western states burning PRB coal. Their

analysis showed that tighter MACT standards or a lower cap are justified.

The commenter submitted that the drawback of a cap and trade program is that it reduces

mercury where it is most cost effective, but does not address specific geographic needs. The

commenter needs reductions from coal-fired plants to the south and west of the state. The

commenter suggested trading zones with separate mercury caps and limiting trading between the
lxxiii

zones. The commenter believed this would avoid relying on bituminous coal-fired boilers for

nearly all the reductions.

Response:

EPA has addressed the hot spots issue in the revision Federal Register notice and in the

Effectiveness TSD.

Comment:

One commenter (OAR-2002-0056-2860) recommended a maximum allowable emission

rate to address hot spots. The commenter asserted that EPA should provide options and support

for identifying and mitigating potential hot spots.

Response:

EPA has addressed the hot spots issue in the revision Federal Register notice and in the

Effectiveness TSD.

Comment:

One commenter (OAR-2002-0056-1825) objected to a provision in the cap and trade

program that would allow utilities in a State to avoid any additional mercury reduction even if

studies confirm that hot spots are the result of emissions from local utilities.

Response:

EPA has addressed the hot spots issue in the revision Federal Register notice and in the

Effectiveness TSD.

Comment:

One commenter (OAR-2002-0056-3448) stated that delaying 70 percent of the emission

reduction until about 2030 in the proposed CAA section 111 rule would perpetuate local and

regional hot spots for 25 years and forever for the many areas affected by plants that will not

install controls at all under a cap and trade system. The commenter believed proposals to adjust

trading to attempt to address hot spots are likely to fail based on perceptions they would

complicate and reduce the efficiency of a cap and trade program.

Response:

EPA has addressed the hot spots issue in the revision Federal Register notice and in the

Effectiveness TSD.

Comment:
lxxiv

One commenter (OAR-2002-0056-4139) stated that budgets need to be lowered to

protect certain areas.

Response:

EPA has addressed the hot spots issue in the revision Federal Register notice and in the

Effectiveness TSD.

Comment:

One commenter (OAR-2002-0056-2173) stated that given the serious concern about hot

spots, if EPA adopts a cap and trade approach, it must take all appropriate actions to ensure they

do not result. The commenter recommended the following actions: (1) require excess “offsets”

(the offset ratio should be adjusted based on the ability of mercury reductions at one source to

reduce deposition in the area of the other source to ensure that any reductions at units generating

credits would have an equivalent environmental effect in the area of the unit purchasing the unit);

(2) limit trades to a regional or basin-wide area; (3) limit amount of credits that can be purchased

to meet limits; and (4) create a natural resources damage fund to compensate tribes, states, and

other resource trustees for damage caused by hot spots by assessing a surcharge on credits that

are traded.

Response:

EPA has addressed the hot spots issue in the revision Federal Register notice and in the

Effectiveness TSD.

Comment:

Several commenters (OAR-2002-0056-1671, -2108) stated that if EPA retains the

cap-and-trade program, credits should be available only to plants that demonstrate through

modeling that deposition is not occurring in local watersheds or land (i.e., hot spots).

Response:

EPA has addressed the hot spots issue in the revision Federal Register notice and in the

Effectiveness TSD.

Comment:

One commenter (OAR-2002-0056-2160) suggested that maximum emission limits should

be established for individual plants to avoid hot spots. The commenter noted that capping

maximum emissions from a given plant has ample precedent in existing SO2 and NOx rules.

Response:
lxxv

EPA has addressed the hot spots issue in the revision Federal Register notice and in the

Effectiveness TSD.

Comment:

Several commenters (OAR-2002-0056-2835, -2878) addressed the evaluation of control

requirements after implementation of the cap-and-trade program. One commenter

(OAR-2002-0056-2835) agreed with the EPA proposal to evaluate after the implementation of

the control requirements in 2010 and 2018 whether the mercury cap adequately protects public

health and, if necessary, take further regulatory actions to address any health risks not fully

addressed by the cap-and-trade regulatory program.

The second commenter (OAR-2002-0056-2878) cited several scientific and policy

concerns including lack of safeguards to protect the public health and secure additional needed

reductions, toxicity of mercury and tendency to bioaccumulate in the food chain, potential for hot

spots, and environmental justice. The commenter asserted that EPA’s response to these concerns

(reevaluate effects of cap and trade on local hot spots after implementation in 2018) would leave

communities at risk for another 14 years or longer.

Response:

EPA has addressed the hot spots issue in the revision Federal Register notice and in the

Effectiveness TSD.

Comment:

If EPA pursues regulation under CAA section 111, one commenter

(OAR-2002-0056-2430) recommended that it include some type of risk and environmental health

assessment including an evaluation of the effects of mercury deposition. The commenter noted

that residual risk requirements under CAA section 112 address risk to public health and the

environment, while CAA section 111 does not. The commenter asserts that the disassociation of

CAA regulations from public health and the environment is unacceptable public policy and sets a

bad precedent.

Response:

EPA has addressed the hot spots issue in the revision Federal Register notice and in the

Effectiveness TSD.

5.5 APPLICABILITY

5.5.1 Affected Units

Comment:
lxxvi

One commenter (OAR-2002-0056-2862) stated the program threshold should be based on

size of unit (m 25 MW). The commenter noted the current program threshold is consistent with

the m 25 MW level set for EPA’s Acid Rain program. The commenter believes this is an

appropriate threshold. Including units based a size definition creates a fair and consistent

regulatory program.

One commenter (OAR-2002-0056-2721) supported the proposed minimum level of

generation of a fossil fuel fired combustion unit that serves a generator of 25 MW that produces

electricity for sale would be affected by the proposed mercury regulations.

A second commenter (OAR-2002-0056-2913) stated the proposed CAA section 111

cap-and-trade provisions of the proposal expand upon the CAA section 112 definition of electric

utility steam generating unit by including combustion units less than 25 MW if they serve a

generator greater than 25 MW. The commenter stated that CAA section 112 defines an electric

utility steam generating unit as a 25 MW combustion units, but the proposed CAA section 111

cap-and-trade rule presumably would apply to combustion units, regardless of size, serving

25 MW generators (see 60.4104 (a)). It appeared to the commenter as though the Agency is

attempting to expand the number of electric utility units to which this rule would apply beyond

that authorized by statute. Furthermore, the potential exists for some electric utility units to be

regulated by two different and conflicting regulations (i.e. the industrial/commercial/ institutional

boilers and process heater MACT standards which are nearing final promulgation and these

electric utility steam generating unit MACT standards). The commenter believed this is contrary

to both statutory intent and expressed EPA policy. The commenter did not believe that this is the

Agency’s intent and this “inconsistency” between CAA section 112 definition and CAA section

111 applicability is merely an oversight on EPA’s part.

The commenter recommended that, if the Agency ultimately decides that the best way to

adopt a cap-and-trade rule is under CAA section 111, then this situation can be rectified in one of

two ways: 1) Rewrite 40 CFR 60.4104(a) as applying to “Any fossil fuel fired combustion unit of

more than 25 megawatts that serves a generator that produces electricity for sale.”; or 2) state, in

the applicability section, that any unit covered in 40 CFR Part 63, Subpart DDDDD (i.e. the

industrial/commercial/ institutional boilers and process heater MACT standards), is not covered

under this subpart.

Response:

For purposes of model trading rule, an affected unit is defined as a coal-fire boiler or

IGCC that serves a generator with nameplate capacity of more than 25 MWe producing

electricity for sale (see regulatory text of final rule, §60.4104, for full definition). The definition

also provides an exception for cogeneration units serving at any time a generator with

nameplate capacity of more than 25 MWe and supplying in any calendar year more than

one-third of the unit’s potential electric output capacity or 219,000 MWh, whichever is greater,

to any utility power distribution system for sale (see regulatory text of final rule, §60.4104, for

full definition).
lxxvii

As discussed in the final rule preamble (section IV.D.3), the approach of using a 25 MWe

cut-off is consistent with existing SO2 and NOx cap-and-trade programs like the NOx SIP call and

the Acid Rain Program and the final Clean Air Interstate Rule. In addition, the Agency’s

historical interpretation of the subpart Da definition has been that a boiler meeting the capacity

definition (i.e., greater than 250 million Btu/hr) but connected to an electrical generator with a

generation capacity of 25 MWe or less would still be classified as an “electric utility steam

generating unit” under subpart Da. EPA acknowledges that there are differences in definitions

between the NSPS program and the Acid Rain and other trading programs (e.g., CAIR) that

result from the underlying statutory mandates. From implementation standpoint, EPA maintains

that is important for the applicability definition under the Hg modeling trading rule to be

consistent with other cap-and-trade rules, especially the recently finalized CAIR.

Comment:

One commenter (OAR-2002-0056-2066) stated that combined heat and power (CHP)

units currently represent only about 3 percent of the electric generating capacity covered by

Agency’s proposal. According to the commenter, CHP units are generally twice as efficient when

compared to their utility counterparts, and about 2/3 of all CHP units burn natural gas and have

extremely low NOx emission rates. The commenter stated that while individual CHP emission

rates will vary, the average gas-fired CHP emission rates are only 15-25 percent of that emitted by

a typical utility. The commenter added that even CHP units using coal or oil as a fuel source are

still much more efficient than a utility using the same fuels. The commenter further stated that

CHP units are usually only a small part of a much larger industrial facility or complex. The

commenter asserted that including these units into this rulemaking would layer another set of

regulations on the entire facility, thus further complicating on-going compliance efforts. For these

reasons, the commenter believed that CHP units should be exempted from inclusion in this

rulemaking. According to the commenter, inclusion of traditional CHP facilities would provide

negligible environment benefit while discouraging application of these ultra-efficient power and

steam generators both now and in the future.

The commenter (OAR-2002-0056-2206) noted that EPA is proposing to establish a cap

and trade program for regulated utility units that is similar to the current cap and trade for this

sector under the Title IV program and the Agency’s proposed rule relating to interstate air quality

(69 FR 4652). The commenter further noted that as part of EPA’s proposal, EPA would include

some cogeneration units as electric utility units and make them subject to the rule. The

commenter did not support this approach toward cogeneration units. Instead, the commenter

suggested that EPA should exclude all cogeneration units. The commenter offered that EPA

could include them in its planned study to see if unregulated units are causing adverse health

effects.

Response:

As discussed in the final rule preamble (section IV.D.3), EPA believes it is important to

include in the CAMR program all units, including congeration units, that are substantially in the

business of selling electricity. As discussed above, the applicability definition under the Hg
lxxviii

modeling trading rule is consistent with other cap-and-trade rules, especially the recently

finalized CAIR.

Comment:

For CHP units, the commenter (OAR-2002-0056-3525) believed that EPA should define a

“utility unit” as only those units that meet the definition on a net annual basis. The commenter

pointed out that in the preamble, EPA, absent rationale, states that any CHP unit that meets the

definition of a utility unit during any portion of the year would become subject to the rule. The

commenter stated that requiring a CHP unit to stay below the utility unit definition on an

instantaneous basis provides a disincentive for facilities to invest in new CHP capacity or to

maximize the output and efficiency of their current CHP and energy-producing network of units.

The commenter encouraged EPA to confirm that for purposes of its proposed definitions

of “EGU” and “cogeneration unit,” all sales of electricity will be measured on a “net” basis, as is

done in the acid rain program. The commenter stated that in determining that “net” basis, EPA’s

accounting should take account of the specific situation of major facilities with a number of

cogeneration units. The commenter stated that at such plants, some units may be over the size

threshold, while others may be below it. Yet, according to the commenter, the electricity from all

those units will be pooled before it is either used in the plant or sold to the grid. In that case, the

commenter believed EPA’s accounting rules should provide for determining when the threshold

conditions have been met by looking at all the electricity generated by all the cogeneration units,

whether they were subject to the SIP call or not. The commenter asserted that no other approach

would be administratively feasible.

The commenter stated an annual average should be used to determine whether

cogeneration units sold more than one third of their potential electric output to the grid and more

than 25 MW on a net annual average basis and thus were defined as EGUs. According to the

commenter, a shorter averaging time could often result in classifying units as EGUs based on a

short and unrepresentative operating history-for example, if power was generally used exclusively

at the plant at which it was generated, but was sold to the grid when the production facility was

down for maintenance.

The commenter pointed out in addition, in some cases, contractual arrangements may exist

between the cogeneration facility and the local electric utility wherein all generated power is

considered sold to the utility and all electricity used on the site is purchased from the utility. 

According to the commenter, in reality, only a small portion of the generated power really enters

the grid from the cogeneration facility, and only that “net” sales of power should be considered

when determining applicability with the EGU definition.

Subject to these qualifications, the commenter supported the cogeneration unit threshold

being used for consideration as an EGU, specifically, a unit serving a generator with a nameplate

capacity of >25 MW and supplying more than 1/3 of its potential electric output capacity and

more than 25 MW to any utility power distribution system for sale. The commenter stated

however, it would provide additional clarity and prevent confusion if it was specifically stated that
lxxix

units associated with generators of 25 MWe capacity or less were not affected sources under this

subpart; and any cogeneration units not supplying both more than one-third of their potential

electric output capacity and more than 25 MWe to any utility power distribution system for sale

were not affected sources under this subpart. The commenter recommended that EPA include

this additional clarifying language in the final rule.

Another commenter (OAR-2002-0056-2906) stated that for cogeneration units, EPA

should define as an electric utility steam generating unit (utility unit) only those units that meet the

definition of a utility unit on a net annualized basis. The commenter noted that in the preamble,

EPA states that any cogeneration unit that meets the definition of a Utility Unit during any portion

of the year would become subject to the rule (69 FR 4657). The commenter stated that EPA

provides no rationale for this requirement. The commenter further stated that this requirement

stands in contrast to EPA’s proposed CAIR, where the definition for a Utility Unit is based on a

historical annual average (69 FR 4610).

The commenter stated that requiring a cogeneration unit to stay below the Utility Unit

definition on an instantaneous basis would create a large disincentive for facilities to invest in new

CHP capacity, or to maximize the output and efficiency of their current cogeneration and

energy-producing network of units. According to the commenter, cogeneration units are

inherently more efficient than traditional Utility Units (in many cases twice as efficient), and often

provide distributed key power to the grid during transient or short-term periods of peak power

demand. The commenter stated that in order to prevent being included within the Utility Unit

definition, many cogeneration units will likely establish tight restrictions on exporting excess

power to the grid, or eliminate export all together. According to the commenter, this would have

the perverse effect of reduced cogeneration unit power output, reduced overall grid efficiency and

reduced industrial steam and electricity generation efficiency.

The commenter stated that to prevent these undesirable consequences, and to prevent

conflicts and confusion with the definition of a Utility Unit in the CAIR under which some of

these units may choose to opt into the CAIR regulation, EPA should base the Utility Unit

definition on a net annualized average and not “during any portion of the year.”

Response:

As discussed in the final rule preamble (section IV.D.3), EPA confirms that, for purposes

of applying the one-third potential electric output criteria in the CAMR program and the model

cap-and-trade rules, the only electricity that counts as a sale is electricity produced by a unit

that actually flows to a utility power distribution system from the unit. Electricity that is

produced by the unit and used on-site by the electricity-consuming component of the facility will

not count, including cogenerated electricity that is simultaneously purchased by the utility and

sold back to such facility under purchase and sale agreements under the Public Utilities

Regulatory Policy Act of 1978 (PURPA). However, electric purchases and sales that are not

simultaneous will not be netted; the one-third potential electric output criteria will be applied on

a gross basis, except for simultaneous purchase and sales. This is consistent with the approach

taken in the Acid Rain Program.
lxxx

Comment:

One commenter (OAR-2002-0056-2906) requested that EPA confirm that, for purposes

of its proposed definitions of “Utility Unit” and “cogeneration unit,” all sales of electricity will be

measured on a “net” basis, as is done in the acid rain program. According to the commenter, in

determining that “net” basis, EPA’s accounting rules should take into account the specific

situation of major facilities with a number of cogeneration units. The commenter pointed out that

at such plants, some units may be over the size threshold for inclusion in the rule, while others

may be below it. The commenter added that, yet, the electricity from all those units will be pooled

together before it is either used in the plant, or sold to the grid. The commenter stated that, in

other words, there will be no way to determine the particular use of the electricity generated by

the large units subject to the rule. The commenter believed that in that case, EPA’s accounting

rules should provide for determining when the threshold conditions have been met by looking at

all the electricity generated by all the cogeneration units. According to the commenter, no other

approach would be administratively feasible.

The commenter pointed out that in many cases contractual arrangements may exist

between the cogeneration facility and the local electric utility wherein all generated power is

considered sold to the utility and all electricity used on the site is purchased from the utility. 

According to the commenter, in reality, only a small portion of generated power really enters the

grid from the cogeneration facility, and only that “net” sales of power should be considered when

determining applicability with the Utility Unit definition.

The commenter stated that an annual average should be used to determine whether

cogeneration units sold more than one third of their potential electric output to the grid and more

than 25 MWe on a net annual average basis and thus were defined as Utility Units. According to

the commenter, a shorter averaging time could often result in classifying units as Utility Units

based on a short and unrepresentative operating history–for example, if power was generally used

exclusively at the plant at which it was generated, but was sold to the grid when the production

facility was down for maintenance.

Subject to these qualifications, the commenter supported the cogeneration unit threshold

being used for consideration as an Utility Unit, specifically, a unit serving a generator with a

nameplate capacity of greater than 25 MWe and supplying more than one-third of its potential

electric output capacity and more than 25 MWe to any utility power distribution system for sale.

The commenter stated that, however, it would provide additional clarity and prevent confusion if

it was specifically stated that units associated with generators of 25 MWe capacity or less were

not affected sources under this subpart; and any cogeneration units not supplying both more than

one-third of their potential electric output capacity and more than 25 MWe to any utility power

distribution system for sale were not affected sources under this subpart. The commenter

recommended that EPA include this additional clarifying language in the final rule. 

Response:
lxxxi

As discussed in the final rule preamble (section IV.D.3), EPA is finalizing to determine

whether a unit is affected by the CAMR on an individual-unit basis. This unit-based approach is

consistent with both the Acid Rain Program and the NOx SIP Call. EPA considers this approach

to be feasible based on experience from these existing programs, including for sources with

multiple cogeneration units. EPA is unaware of any instances of cogeneration unit owners being

unable to determine how to apply the one-third potential electric output capacity criteria where

there are multiple cogeneration units at a source.

In a case where there are multiple cogeneration units with only one connection to a

utility power distribution system, the electricity supplied to the utility distribution system can be

apportioned among the units in order to apply the one-third potential electric output capacity

criteria. A reasonable basis for such apportionment must be developed based on the particular

circumstances. The most accurate way of apportioning the electricity supplied to the utility

power distribution system seems to be apportionment based on the amount of electricity

produced by each unit during the relevant period of time.

The commenters concerns about “net sales” are addressed in the previous response.

Comment:

One commenter (OAR-2002-0056-3469) stated that the tribes support the EPA in their

efforts to improve air quality. However, tribes needed protections to ensure their future energy

projects and the economic benefits derived from current mining operations are not jeopardized. 

The tribes supported the exemption of all new power plants developed by the tribes or developed

on tribal land from being required to hold allowances for SO2, NOx or mercury emissions, as long

as these new power plants meet New Source Performance Standards (NSPS) and all other

relevant permitting requirements at the date of initial operation. These power plants would

adhere to the monitoring requirements specified in the rules ensuring that these NSPS

requirements are met over time.

Comment: One commenter (OAR-2002-0056-2850) supported exemption of new units

from the Hg program that are constructed with Best Available Control Technology for Hg. The

commenter stated that if a new unit exemption is not implemented, credits should be purchased

from the new Hg allowance market or buyout mechanism.

Response:

In the final CAMR, new sources will be covered under the Hg cap of the trading

program, and will be required to hold allowances equal to their emissions. EPA maintains that

is essential to include new sources under the cap to ensure that environmental goal of reducing

mercury emission is achieved. With new sources under the cap, the environmental goal

continues to be achieved despite future growth in the electric power sector, as older coal-fired

generation is retired and replaced new coal-fired generation.

Comment:
lxxxii

One commenter (OAR-2002-0056-2162) stated that waste coal-fired plants should not be subject

to the proposed mercury rules.

Response:

As discussed in the final rule preamble (section IV.D.3), EPA points out that coal refuse

is already subject to other Utility Unit programs, such as the Acid Rain program, the NSPS

program (40 CFR part 60, subpart Da), and the CAIR program. Consequently, EPA rejects the

commenter’s request to not be included in the CAMR program.

5.5.2 25 lb Exclusion

Comment:

Several commenters (OAR-2002-0056-2161, -2267, -2375, -2634, -2830, -2913, -2922,

-2948) supported the provision excluding units that emit less than 25 pounds of mercury per year

from the cap-and-trade program.

One commenter (OAR-2002-0056-2161) suggested that EPA require these emitters to

conduct compliance testing annually to verify the level of their emissions and report the results to

EPA. As a result EPA would be able to monitor the national emissions profile of this group of

sources and change the way they participate in the mercury cap and trade program if their

emissions profile changes significantly.

One commenter (OAR-2002-0056-2267) requested that EPA consider extending the

exemption to the Phase I cap as well. The commenter stated that controls on low emitting units

are not highly cost-effective. EPA has acknowledged that expected new mercury-specific control

technologies may not practically apply to these units. Moreover, emissions from such units do not

contribute significantly to over-all mercury emissions. The commenter noted that EPA’s data

indicates that these units (numbered at 396) currently account for less than 5 percent of total

mercury emissions. The commenter believed EPA should exclude these units because the

cost-savings would be substantial for such units without affecting the ability to achieve the

proposed caps. In the event low emitting units are excluded from the Phase I and/or II cap, the

commenter would support provisions that would allow such units (as well as non-affected units)

to opt-in to the cap-and-trade program at their discretion as in the NOx Budget Trading Program.

One commenter (OAR-2002-0056-2375) stated that EPA has authority to promulgate

such an exemption based on its inherent de minimis authority. The commenter noted sources of

emissions below this level comprise less than 4 percent of current U.S. power plant emissions.

The commenter believed exempting them from the rule would not jeopardize the caps. The

commenter stated that moreover, the exemption is warranted because pollution controls required

for Phase II may not be feasible for sources with low emissions.

Several commenters (OAR-2002-0056-2634, -2922, -2948) added that since these units

do not significantly contribute to total domestic emissions, the 2010 and 2018 caps should remain
lxxxiii

unchanged and be applicable to the units remaining in the program, even if these sources are

excluded from the program.

One commenter (OAR-2002-0056-2914) stated that requiring low emitting units to

participate in the proposed cap-and-trade program would provide very little benefit in comparison

to the costs needed to become effective trading partners. The commenter also stated that low

emitting units, especially those already equipped with MACT standard setting technology should

only be required to demonstrate that the installed pollution controls are operating properly,

monitor operating parameters and emissions, keep records of their operating parameters and

emissions, report their emissions, and nothing more. The commenter submitted suggested

regulatory language to implement and exemption for low emitting units.

One commenter (OAR-2002-0056-2560) supported the exclusion of coal-fired electric

generating units (EGUs) that emit less than 25 pounds of mercury per year. According to the

commenter, these units account for a very small proportion of mercury emissions.

One commenter (OAR-2002-0056-2883) urged the EPA to consider the implications of

both proposed rules on smaller emitters and urges the EPA to provide a de minimus exemption

from the rule for de minimus emitters.

One commenter (OAR-2002-0056-3445) noted that EPA has expressed concern about

units with low mercury emissions rates (e.g., less than 25 pounds/year) and has asked for

comment on excluding these units (69 FR 4999). The commenter believed EPA should exclude

these units. The commenter stated that excluding them will provide an incentive to reduce

emissions to below the 25-pound/year level through pollution prevention or innovative

technology. The commenter believed that this clearly is an environmental benefit. The

commenter further suggested that if the agency excludes these units in a cap-and-trade program,

the overall mercury emissions cap should not be reduced by the amounts that these sources emit

(i.e., the 2018 cap should remain 15 tons even if these sources are excluded from the program).

One commenter (OAR-2002-0056-2891) stated that EPA should include an exclusion–or

at a minimum, reduced requirements–for small emitting units where additional emission controls

cannot be economically justified. The commenter believed equipping smaller units with state of

the art emission controls is not economically viable and equipping larger units that already emit

relatively small amounts of mercury is not cost effective. According to the commenter, excluding

these units from any additional mercury controls, or phasing in requirements for these units would

be more cost effective while not resulting in any significant detriment to mercury reduction goals.

One commenter (OAR-2002-0056-2867) supported exempting units with mercury

emissions less than 25 pounds per year. The commenter recommended, however, that EPA

should re-allocate the allowances to controlled units in proportion to their annual heat input. If

these allowances are reallocated, the commenter believed it would be incumbent on these

exempted, low-emitting units to monitor emissions using infrequent measurement methods.
lxxxiv

One commenter (OAR-2002-0056-3445) noted that EPA has expressed concern about

units with low mercury emissions rates (e.g., less than 25 pounds/year) and has asked for

comment on excluding these units (69 FR 4999). The commenter believed EPA should exclude

these units. The commenter stated that excluding them will provide an incentive to reduce

emissions to below the 25-pound/year level through pollution prevention or innovative

technology. The commenter believed that this clearly is an environmental benefit. The

commenter further suggested that if the agency excludes these units in a cap-and-trade program,

the overall mercury emissions cap should not be reduced by the amounts that these sources emit

(i.e., the 2018 cap should remain 15 tons even if these sources are excluded from the program).

One commenter (OAR-2002-0056-2172) strongly supported exempting from the final rule

those units that emit less than 25 lbs. of mercury per year. The commenter believed that EPA has

ample legal authority to provide such an exemption, which would provide important regulatory

relief for small units that may not be able to comply, particularly with the Phase II cap.

One commenter (OAR-2002-0056-2850) supported a proposal to exempt units whose

mercury emissions are under 25 pounds per year. The commenter added that would involve less

than a 10 percent shift in the tonnage cap but would exclude coal units for which mercury control

retrofit would be the least cost effective.

Response:

As discussed in the final rule preamble (section IV.D.3.iv), the low-emitter exclusion was

proposed to address small business entities. Small business entities, however, are not

necessarily small emission emitters. Of the 396 units with estimated Hg emissions under 25 lb in

1999, most (about 95 percent) are not owned by small entities and a significant amount (about

10 percent) are large-capacity units (greater than 250 MW). In addition, removing low-emitters

from the trading program could increase costs, because a significant amount of the 396 units are

large-capacity units that might be expected to be net seller of allowances because they are

already achieving emission reductions. Therefore, EPA maintains that the low-emitter exclusion

may not be the best way to address small entity burden. For today’s final CAMR, EPA is not

finalizing a low-emitter exclusion and EPA recommends States address small business entities

through the allocation process. For example, States could provide a minimum Phase II

allocation for small entities (e.g., allocation based on projected 2010 unit emissions). EPA also

maintains that the cap-and-trade program and other program aspects minimize the burden for

small business entities. These program aspects include the 25 MWe size cut-off.

Comment:

Several commenters (OAR-2002-0056-2260, -2365, -2661, -2891) believed EPA should

include an exclusion–or at a minimum, reduced requirements–for small emitting units where

additional emission controls cannot be economically justified. The commenters stated equipping

smaller units with state of the art emission controls is not economically viable and equipping

larger units that already emit relatively small amounts of mercury is not cost effective. The

commenters added that excluding these units from any additional mercury controls, or phasing
lxxxv

requirements for these units would be more cost effective and not detrimental to mercury

reduction goals.

One commenter (OAR-2002-0056-2267) believed that EPA must limit the

disproportionate impact of the proposed rules on low emitting units. The commenter noted the

low emitting units emit relatively smaller amounts of emissions and controls on such units are less

cost-effective than for larger units. The commenter stated imposing controls on the low emitting

units will not significantly contribute to reductions required to meet the proposed caps or to the

overall reductions achieved under the MACT approach if it is adopted. The commenter stated that

for these reasons, EPA should provide appropriate relief for the low emitting units under the

proposed cap-and trade or MACT programs.

One commenter (OAR-2002-0056-3514) supported EPA’s conclusion that the control

technologies currently being researched will not be practical at units emitting less than 25 tons per

year, and suggested that exemption apply regardless of which implementation option EPA selects

for the final rule.

One commenter (OAR-2002-0056-1969) stated that EPA is correct in its concern that

new, mercury specific control technologies that are expected to be developed prior to the Phase II

cap deadline may not practicably apply to units with low annual mercury emissions. The

commenter suggested that electric generating units emitting less than 25 pounds per year be

excluded from the Phase II cap.

Response:

As discussed above and in the final rule preamble (section IV.D.3.iv), EPA is not

finalizing a low-emitter exclusion and EPA recommends States address small business entities

through the allocation process.

Comment:

One commenter (OAR-2002-0056-3437) stated that the 25 lb/yr exemption should not be

included. The commenter noted that in the SNPR, the applicability is limited to EGU greater than

25 MW with no low-emitting exception. The only exception is for retired units.

One commenter (OAR-2002-0056-3459) stated in public interest group comprehensive

comments that if EPA proceeds with its illegal trading program, it must reject program elements

that permit increased pollution. In response to EPA’s request for comments, the commenter

stated utility units emitting less than 25 pounds of mercury should not be exempted from the 2018

cap. The commenter asserted that the record documents the origin of this provision and shows

that EPA did no analysis of impacts or costs. The commenter stated that the language comes

directly from the Small Business Administration (SBA), which is concerned about small units

having difficulty making the reductions, but EPA offers no evidence that this is true. The

commenter stated that EPA’s memo identifying such units indicates that only about 60 (of 396)

are standalone units; all others are boilers part of a multi-boiler facility where boilers are likely tied
lxxxvi

into a common ductwork for pollution control. The commenter added that because EPA is

proposing to allow facilities to bubble their emissions, units other than the one or two small units

can be controlled to a greater extent to compensate for the lower emitting small units. The

commenter stated that his would help mitigate any concerns about control costs for small units. 

Thus, the commenter asserted that the proposal to exempt them is arbitrary and capricious.

Response:

As discussed above and in the final rule preamble (section IV.D.3.iv), EPA is not

finalizing a low-emitter exclusion and EPA recommends States address small business entities

through the allocation process.

Comment:

One commenter (OAR-2002-0056-2911) recommended that EPA follow its concerns

about the ability of smaller units to implement mercury-specific control technologies. The

commenter recommended that units emitting less than 50 pounds of mercury per year be exempt

from mercury-specific control requirements.

One commenter (OAR-2002-0056-3556) recommended that EPA follow its concerns

about the ability of smaller units to implement mercury-specific control technologies. The

commenter recommended that units emitting less than 50 pounds of mercury per year be exempt

from mercury-specific control requirements.

One commenter (OAR-2002-0056-3556) recommended that EPA follow its concerns

about the ability of smaller units to implement mercury-specific control technologies. The

commenter recommended that units emitting less than 50 pounds of mercury per year be exempt

from mercury-specific control requirements.

One commenter (OAR-2002-0056-3556) recommended that EPA follow its concerns

about the ability of smaller units to implement mercury-specific control technologies. The

commenter recommended that units emitting less than 50 pounds of mercury per year be exempt

from mercury-specific control requirements.

 One commenter (OAR-2002-0056-3432) stated that like other small rural electric

generating and transmission (G & T) cooperatives, they have a number of small coal-fired boilers. 

The commenter stated that installing and operating emission controls on small units is not

economically viable, and the amount of mercury emissions attributable to these small units is not

significant. The commenter supported exempting units with mercury emissions less than

50 pounds/year from the control program and re-allocating the exempt unit allowances to units in

the program in proportion to their annual heat input. The commenter acknowledged that

exempted units would need to demonstrate that their emissions do not rise above the exempted

level, however, less sophisticated and cost-effective monitoring methods should be allowed.
lxxxvii

One commenter (OAR-2002-0056-2422) noted that EPA has requested comment on the

basis for excluding certain small coal-fired units from emission controls in the context of an

emission trading program. The commenter encouraged EPA to exclude at least these 396 small

units emitting less than 25 pounds of mercury annually due to the lack of cost-effective mercury

controls available for retrofit installations, and the likelihood that emissions from these units are

not contributing measurably to any domestic public health problems. According to the

commenter, indeed, a higher cutoff limit for a small unit exclusion could be justified for the

reasons that EPA has identified regarding the prospective retrofit of mercury control technologies

in a Phase II trading program. For these reasons, the commenter urged EPA to establish a

minimum emission threshold for exclusion that will avoid the need to control emissions at small

electric generating units whose emissions do not measurably impact global mercury budgets.

According to the commenter, if confronted with plant- or unit-specific emission limits, such units

likely would be retired rather than retrofitted with costly control technologies.

Response:

As discussed above and in the final rule preamble (section IV.D.3.iv), EPA is not

finalizing a low-emitter exclusion and EPA recommends States address small business entities

through the allocation process.

Comment:

One commenter (OAR-2002-0056-2861) stated that EPA has asked for comment on

excluding units that emit less than 25 pounds of mercury per year from the Phase II mercury cap. 

According to the commenter, as noted, these units make up a small percentage of the total

mercury emissions from U.S. coal-fired power plants (5 percent by EPA’s estimate). The

commenter believed an exclusion for low emitting units is appropriate, both for all phases of a cap

and trade program and for a MACT program. However, rather than exclude units based on their

mercury emissions as EPA has proposed, the commenter recommended the exclusion be based on

a unit’s size, with a cutoff in the range of 100 to 140 MW. The commenter believed a MW size

cutoff would provide a more definite exclusion than use of mercury emissions. The commenter

stated that currently, there is great uncertainty and variability in estimations of mercury emissions

from power plants. The commenter submitted that specifying unit size as the parameter for

determining the exclusion will provide greater regulatory certainty and will meet similar objectives

as EPA identified for considering a 25-pound exclusion.

The commenter has reviewed the estimated mercury emissions from the commenter’s

coal-fired power plants for 2002 based on information provided in their annual TRI report. The

commenter operates 31 coal-fired boilers burning Eastern bituminous coal. These boilers range in

size from 38 to 1120 MW. For 2002, the 13 boilers of 100 MW or less in size accounted for only

5 percent of the commenter’s estimated coal-fired boiler mercury emissions, and each of those

boilers had calculated emissions less than 25 pounds. The commenter suggested a broader

analysis of all power plants in the nation may show that a unit rating as high as 140 MW would

account for 5 percent or less of total mercury emissions. According to the commenter, as

suggested in EPA’s proposal, the cost of emissions monitoring and administration for these units
lxxxviii

with low emissions is excessive and would result in very little actual reduction in emissions. The

commenter added that requiring sources to incur the cost of monitoring simply to demonstrate

that they qualify for the exclusion when there is a surrogate metric, megawatts, which will yield

very similar results is not cost effective and is not good public policy.

The commenter stated that if EPA does exclude low emitting units under a cap and trade

program, the cap for the remaining, non-excluded units should not be reduced to offset the

emissions from the excluded units. The commenter noted that the proposed 15 ton cap on

mercury has no specific regulatory or scientific basis and therefore EPA is not required to offset

the insignificant amount of emissions from small sources as if there were a “hard cap” on the

allowable mercury emissions. The commenter submitted that reducing the 15 ton cap would

simply shift an additional burden onto the regulated units, and would tend to drive up the cost of

allowances by locking up 5 percent of the total allowances that would otherwise be available for

trading.

The commenter noted that in its MACT proposal, EPA proposed that low-emitting units

be excluded only from monitoring requirements for low-emitting units. Consistent with their

position on the cap and trade program, the commenter believed these low-emitting units (units

rated below a specified MW rating as they have proposed, or units below 25 pounds of mercury

as EPA has proposed) should be excluded from all MACT requirements.

Response:

As discussed above and in the final rule preamble (section IV.D.3.iv), EPA is not

finalizing a low-emitter exclusion and EPA recommends States address small business entities

through the allocation process. The CAMR cap-and-trade program includes a 25 MWe size

cut-off which EPA believes is appropriate.

Comment:

One commenter (OAR-2002-0056-2661) proposed that smaller emitting units be allowed

to be bubble with other larger sources within the larger system-wide average for a utility or group

of utilities. The commenter believed that greater emission controls would be realized at large

emitting units and make control schemes more cost effective to implement.

Response:

As discussed above and in the final rule preamble (section IV.D.3.iv), EPA is not

finalizing a low-emitter exclusion and EPA recommends States address small business entities

through the allocation process. EPA also notes that the cap-and-trae program allows for the

commenter’s proposal.

Comment:
lxxxix

One commenter (OAR-2002-0056-3509) stated that to the extent that the final Utility

Mercury Rule does require controls of small municipal generators via allowance trading or other

requirements, EPA should provide these units with other compliance flexibility options to reduce

the cost of such compliance.

One commenter (OAR-2002-0056-3509) strongly urged the EPA to exclude the smallest

emitting units (units with less than 25 pounds annual emissions) from mercury controls under

either the MACT or the cap-and-trade approach, because these small units emit a relatively

insignificant level of mercury; because these units will suffer drastic, disproportionate and costly

impacts from the rule; because the technology to comply is unproven for these small units; and

because the continued operation of these units is critical to the basic energy needs of local

communities in Michigan. The commenter urged EPA to adopt this exclusion for small emitters

for both existing affected units and new affected units, including those that blend coal and

non-coal fuels in their generation mix (and who measure emissions using EPA’s suggested mass

balancing approach).

One commenter (OAR-2002-0056-3509) stated that the rule’s requirements for utility unit

mercury controls, under either the MACT or trading approach, will disproportionately impact the

smallest units and systems. Based on information derived from EPA’s Mercury Information

Collection Request, Toxic Release Inventory reporting, and stack testing for mercury emissions,

the commenter estimated that the units they own and operate are emitting less than 25 pounds of

mercury annually each. The commenter stated this places them in the category of units that EPA

refers to as “small emitters.” The commenter pointed out that it is important that the Utility

Mercury Rule considers and helps mitigate small entity impacts for several economic and

environmental reasons, including:

• Diseconomies of Scale–The capital costs for emissions control at small-sized utility units is

disproportionately high due to inefficiencies in mercury removal, space constraints for

control technology retrofits, and the fact that small units have fewer rate base customers

upon which to spread these costs.

• Less Bang for the Buck–The commenter stated that as EPA has acknowledged, smaller

utility units contribute a relatively insignificant level of mercury in the context of the

industry-wide contribution of mercury emissions.

• Unproven Technologies–The commenter was not able to provide any technical

information on whether these small units could reduce mercury emissions to the low levels

proposed by the EPA either under the MACT approach or the cap-and-trade

approach–because mercury control technologies are generally untested and unproven for

these sizes and types of units. The commenter emphasized EPA’s own recognition that

“the new, mercury-specific control technologies that we expect to be developed prior to

the [2018] Phase II cap deadline may not practicably apply to such units period.” 

Proposed Rule at 4699. The commenter also noted that the current DOE/EPRI/EPA

effort to test the availability and effectiveness of mercury control technologies for

coal-fired utility units involves primarily larger-sized units (See
xc

http://www.netl.doe.gov/coalpower/environment/ ). The commenter added that nor do

these DOE demonstration studies, or other available studies, show whether mercury

control technologies are effective, let alone cost-effective, at the smallest sized coal-fired

units. To the commenter’s knowledge, no large scale field testing for activated carbon

technology have been conducted for units <80 MW. The commenter added that these

technologies are untested for the smallest utility units.

• More Limited Access to Capital–Smaller utility systems generally have less capital to

invest in pollution control than larger, investor-owned systems, due to statutory inability

to borrow from the private capital markets, statutory debt ceilings, limited bonding

capacity, borrowing limitations related to fiscal strain posed by other, non-environmental

factors, and other limitations.

• Limited Ability to Average Emissions–Public power systems have much less flexibility in

trading under the proposed Utility Mercury Rule because municipalities typically do not

own multiple utility units that can utilize system-wide averaging of emissions for

cap-and-trade compliance purposes. Likewise, the commenter did not own units that are

large enough to enable the application of control technology that could likely produce

mercury trading credits.

• Important Role of Public Power to Communities–Michigan public power communities

play an important role in the competitive utility industry, and provide valuable services to

local citizens. Pollution controls should not disproportionately impact smaller entities and

thereby impose a competitive disadvantage on municipalities.

The commenter stated that for all these reasons, EPA should take into account the

disproportionate adverse impacts of the Utility Mercury Rule on small systems and units. 

Moreover, the commenter emphasized that the ability of these small electric systems to purchase

mercury allowances on the market is not a sufficient solution, by itself, to the major economic

challenges that will face these communities under the Utility Mercury Rule. The commenter

stated that there are substantial transaction costs to allowance trading, as recognized by the D.C.

Circuit Court of Appeals. See Michigan v. EPA, 213 F.3d 663, 676 and n.3 (D.C. Cir. 2000) (“A

glance at EPA’s regulations for allowance trading will convince any doubter that transaction costs

can safely be expected to be substantial.”) The commenter further stated that in addition, the

Utility Mercury Rule’s trading market may never generate sufficient excess allowances to alleviate

any of this burden on small electric systems and units. The commenter believed that without

consideration of the particular challenges and needs of small electric units, the long-term

economic viability of these systems will be subject to the vagaries of an uncertain and potentially

scarce allowance market.

One commenter (OAR-2002-0056-3509) encouraged EPA to consider allowing small

municipal generators (with capacities of less than 25 megawatts) that are located at a common

facility with larger units (>25MW), to have the voluntary option to “opt-in” the smaller, less than

25 MW units, to the Utility Mercury Rule. The commenter added that most importantly, EPA

should provide options for mercury compliance optimization at electric generating facilities where
xci

there are units that are considered Industrial Boiler MACT units that are operated in common

with proposed Utility Mercury Rule units. The commenter added that the current situation is

particularly difficult for those public power systems, like some of those commenting here, who

have both >25MW and <25MW electric generating units located in a common facility. The

commenter noted that in one case, these different sized units are located on a common steam

header. The commenter stated that however, under EPA’s Industrial Boiler MACT and proposed

Utility Mercury Rule, these systems will be unable to average emissions facility-wide, or enjoy the

compliance optimization and flexibility necessary to be able to comply cost-effectively.

The commenter noted that EPA specifically requests comments in the Proposed Rule

(4657) on how to consider units subject to different EPA mercury rules at the same facility. The

commenter emphasized that this is a problem, and encourages EPA to allow small, <25MW

EGUs located at a common, contiguous facility with other EGUs subject to the Utility Mercury

Rule, to be able to opt-in to the Utility Mercury Rule, either to claim the “small emitter”

exclusion, or to be able to average and trade allowances among their common units.

Response:

As discussed above and in the final rule preamble (section IV.D.3.iv), EPA is not

finalizing a low-emitter exclusion and EPA recommends States address small business entities

through the allocation process.

Comment: One commenter (OAR-2002-0056-4456) supported a small emitter exemption

that would apply to either a cap/trade-based or MACT -based Hg emissions regulatory system. 

However, the commenters suggested that EPA can best achieve its objectives by crafting an

exemption that is facility or source based, as opposed to one that is solely unit based.

The commenters stated that EPA’s notice styles the proposed small emitter exemption as

one applying on a unit basis. The commenters stated that, however, EPA’s data shows that

creating a unit-based Hg exemption does not isolate a class of small utility emitters. The

commenters noted that many units covered by EPA’s suggested unit-based exemption are smaller

units at very large multiple-unit electric generating facilities. The commenters stated that,

conversely, EPA’s data shows that many units that may emit more than 25 pounds of Hg per year

are single units at small electric generating facilities. According to the commenters, thus, a

unit-based proposal does not correctly identify the universe of small utility Hg emitters.

The commenters proposed that EPA adopt a final rule that exempts from Hg regulation all

utility units at common-source plant facilities that emit, on a facility-wide basis, less than a

threshold amount of Hg per year. For the threshold amount, the commenters suggested that EPA

convert the Clear Skies unit-based exemption (50 pounds or less per unit) to a facility-based

exemption so that the total projected exempt emissions (6.9 percent of the total) remains the

same. The commenters stated that EPA’s 1999 ICR plant emission data base shows this cut-off,

on a facility basis, is approximately 95 pounds (or less) of Hg facility emissions per year.
xcii

According to the commenters, alternatively, EPA could convert the 25 pound unit-based

exemption referenced in EPA’s Notice to a facility-based exemption so that the total exempt

emissions (3.9 percent of the total) remains the same. The commenters stated that EPA’s 1999

ICR plant emission data base shows this cut-off, on a facility basis, is approximately 62 pounds

(or less) of Hg facility emissions per year.

The commenters suggested EPA adopt the following procedures to implement a facility-based

small emitter exemption:

• Initial Identification of Exempt Facilities. EPA would identify potentially qualifying

facilities (i.e., all utility units at facilities emitting less than the annual utility facility Hg

threshold) from its 1999 ICR plant data base.

• Utility Election. Owners of qualifying facilities identified by EPA could, at their election,

have units at their facilities designated as exempt or, in the alternative, designated as

non-exempt covered utility units.

• Post-Election Actions. Under cap and trade, qualifying units that a facility owner elects

for exempt status would receive no allowance allocations. Consistent with the approach

taken in the Chairman’s Mark bill, remaining affected units would be allocated allowances

(e.g., if a 15 ton Phase II Hg cap is in place, allowances equal to 15 Hg tons would be

allocated to non-exempt affected units). (See, S. 1844, §§471,473). Under MACT,

qualifying units that a utility elects for exempt status would initially be exempt from

MACT Hg regulations.

• Monitoring. Facility owners electing exempt status would be required to monitor their

facility Hg emissions in a cost-effective manner. Hastings and Grand Island suggest that

exempt facilities utilize EPA-approved ASTM Hg sampling and Hg emission testing

procedures at frequencies selected by facility owners, but no less than quarterly. Annual

Hg emissions would be calculated from this data, using the same procedures EPA utilized

to estimate the unit-specific 1999 Hg emissions referenced in its Notice (49 F.R. at 4699).

• Excess Emissions. If an exempt facility exceeded the exemption Hg emission threshold in

any year, the facility owner, under the cap-and-trade proposal, would have to obtain Hg

allowances equal to its excess emissions (Hg emitted (pounds) threshold Hg amount

(pounds) = excess Hg emissions). Under MACT, the facility owners could pay an

appropriate fine, or if the problem became a persistent one, the facility would lose its

exempt status and become subject to the applicable governing MACT standards for

non-exempt units.

• New Units. Any new utility units built at exempt facilities would be subject to otherwise

applicable Hg emission regulations, but pre-existing facility units would remain exempt if

the exemption threshold is not exceeded for the pre-existing facility units.

Both EPA and Congress have expressed concerns about small Hg emitters. These

concerns are driven by the huge costs that Hg controls will impose on impacted utilities and the
xciii

cost/benefit considerations of imposing these huge costs on very small Hg emitters. The

commenters suggested that the correct cost/benefit calculus results in exempting facilities, many

of which are publicly-owned or co-ops, where overall facility emissions are low. According to the

commenters, EPA can achieve its national Hg reduction objectives without subjecting facilities

that contribute only a tiny fraction of national Hg emissions to extraordinarily expensive

regulations.

Response:

As discussed above and in the final rule preamble (section IV.D.3.iv), EPA is not

finalizing a low-emitter exclusion and EPA recommends States address small business entities

through the allocation process.

Comment:

One commenter (OAR-2002-0056-2162) supported the promulgation of an exemption

from the proposed mercury rules for electric utility steam generating units emitting less than 25

pounds of mercury per year.

The commenter noted that in its preambles to the Proposed Mercury Rules, the Agency

solicits comment on a proposed exemption from the Phase II requirements of the proposed

mercury cap-and-trade rule for units emitting less than 25 pounds of mercury per year. The

commenter noted that the Agency’s basis for the proposed exemption from the requirements is

that low emitting sources would be disproportionately impacted by the costs of complying with

requirements under the proposed MACT standard. The commenter stated that the available

information clearly justifies this concern. According to the commenter, while the Agency

estimates that 396 of the 1,124 units operational in 1999 (35.4 percent of total operating units)

would meet the 25 pound exemption, these units in the aggregate would contribute less than

5 percent of total mercury emissions. The commenter added that, further, according to the

Agency’s data, exemption of these units from the Phase II cap would not interfere with the overall

ability of affected sources to comply with the 15 ton cap. The commenter stated that, accordingly,

proposed 25 lb/year exemption, a substantial number of sources would be forced to absorb

significant expense without achieving any appreciable environmental benefit.

The commenter stated that, likewise, the Agency expressed concern that the mercury

specific control technologies currently under development may not apply to low-emitting units,

and therefore those units would be unable to further reduce mercury emissions in accordance with

cap-and-trade requirements. The commenter stated that with respect to their facilities, the units

already are subjected to the best commercially available mercury control technology. According to

the commenter, these low emitting sources could not reasonably further reduce mercury emissions

in response to any cap-and-trade or other mercury control regulation.

In addition to its position that waste coal-fired sources should be exempt from the

Proposed Mercury Rules, the commenter also supported the proposed exemption of sources

emitting less than 25 pounds of mercury per year from the Proposed Mercury Rules, for the
xciv

reasons articulated by the Agency in its preamble. The commenter believed that the de minimis

nature of these sources supports the implementation of a wholesale exemption from the proposed

MACT-based emission limitations or the proposed cap-and-trade program, whichever is finally

promulgated by the Agency. The commenter stated that, specifically, the Agency’s rationale for

exempting such sources from the Phase II mercury cap-and-trade program also would support an

exemption from MACT requirements. According to the commenter, to the extent that low

emitting sources would be unable to further control mercury emissions as required under the

Phase II cap due to the unavailability of effective add-on mercury controls, such sources likewise

would be unable to meet the proposed MACT standards. The commenter further stated that the

regulation of such low emitting sources would be inconsistent with the Agency’s mandate to

consider the necessity and benefit of regulation for specific affected sources.

According to the commenter, to the extent that the Agency does promulgate an exemption

for sources emitting less than 25 pounds per year of mercury, the exemption should be absolute,

and should not result in the imposition of monitoring, testing or record keeping requirements

upon these de minimis sources. The commenter stated that such an approach would be consistent

with other MACT standards developed by the Agency, pursuant to which certain de minimis

sources within a regulated source category may be completely exempted from all requirements of

the relevant MACT regulation.

Response:

As discussed above and in the final rule preamble (section IV.D.3.iv), EPA is not

finalizing a low-emitter exclusion and EPA recommends States address small business entities

through the allocation process.

5.5.3 Opt-ins

Comment:

Several commenters (OAR-2002-0056-2900, -3432, -2105) supported allowing facilities

with both industrial boiler units and coal-fired utility units to opt the industrial boiler units into the

electric utility rule for purposes of meeting the emissions standard. The commenter believes a final

rule should allow affected facilities with both industrial boilers and coal-fired utility units the

compliance flexibility to meet one Hg emission limit through facility-wide emissions averaging.

One commenter (OAR-2002-0056-2105) recommended that any emission-trading

program for Utility Steam Generating Units be promulgated with an “opt-in” provision so that

other sources and industries with verifiable and surplus mercury emission reductions could

generate and trade them as viable emission reduction credits under this rulemaking. The

commenter was aware of the many obstacles and potential legal challenges, however in this

instance, the commenter felt it was imperative that more, faster, and cost-effective reductions are

made as soon as practicable. The commenter believed that providing an “opt-in” provision for

any and all sources would encourage the maximum reduction in emissions in the shortest amount

of time, in the most cost effective manner and with the least amount of social cost in the form of
xcv

elevated energy costs to the public. A second commenter (OAR-2002-0056-1756) asked if the

rule will allow other types of sources (non-utility combustion or non-combustion mercury) to

participate in trading or offsets in cap and trade program?

One commenter (OAR-2002-0056-3432) believed that if, in the final rule, the EPA does

not allow sources to opt-in industrial boiler (IB) unit(s) into the Utility Mercury MACT, or if the

final rule does allow the flexibility of opt-in and sources choose not to opt-in IB unit(s) due to

their own unique situations, these sources should not be faced with expensive additional

monitoring or apportionment methods for the determination of the contribution of mercury

emissions from IB unit(s). For those sources with the “common stack” situation, the commenter

stated that the EPA should allow the source the flexibility to monitor the mercury concentration in

the common stack and to apply this concentration to the IB(s) flue gas duct. According to the

commenter, utilizing the EPA approved volumetric flow measurements for the common stack and

for the IB(s) flue gas duct, the source would then be able to calculate mercury mass emissions for

the common stack and for the IB(s) duct. With these parameters, electric utility steam generating

units (EUSGU) and IB(s) mercury mass emissions can be determined by simple subtraction.

Response:

Under the final CAMR, EPA is requiring States and Tribes to meet emissions budgets

and to achieve those emissions reductions from coal-fired power generation sources. EPA is not

allowing States or Tribes to opt-in other sources into the cap-and-trade program to meet its

emission budget. EPA feels strongly that any cap and trade program needs to have strong

monitoring and reporting requirements, which are difficult to enforce and implement for other

source categories. Given that other stationary sources (e.g., boilers) are already complying with

MACT Hg standards, cost-effective reductions from other source categories are not likely.

To address the issues associated with monitoring units at a common stack where one is

affected and the other not EPA provides alternative monitoring methodology. This alternatives

can possibly include: measuring Hg for the affected unit in the duct; doing a proportional

distribution based on fuel; using a conservative mass balance to determine the proportion of Hg

in the flue gas that each unit is contributing.

Comment:

Commenter (OAR-2002-0056-3530, -2833) stated that the utility mercury reductions rule

(UMRR) should not extend its mandates to either current or future combined-heat-and-power

systems (CHP). The commenter stated that in virtually all cases, CHP units are a source of highly

efficient power with correspondingly low emissions. The commenter added that hundreds of

industrial facilities depend on the economic efficiencies of CHP. The commenter stated that in

fact, the President’s National Energy Policy recommends the increased use of CHP systems to

improve energy efficiency and decrease air emissions. The commenter also stated that however,

industrial units should be given the opportunity to voluntarily opt-in to the benefits of the

cap-and-trade program. The commenter stated that any opt-in provision should be drafted to
xcvi

encourage participation and recognize cost-effective emission reductions tailored to the unique

attributes of manufacturing facilities.

Response:

As already discussed in responses above, EPA maintains that certain cogeneration units

should be included in the CAMR program and that opt-in will not be allowed.

5.6 STATE EMISSION BUDGETS

5.6.1 Coal Adjustment Factors

Comment:

Many commenters (OAR-2002-0056-1803, -2721, -2830, -2915, -3440, -3463, -3469,

-3478, -3515, -3565, -4191, -4891) supported the proposed allocation ratios of 1, 1.25 and 3 for

bituminous, sub-bituminous and lignite coals. One commenter (4891) stated that the proposed

ratios should be adopted to apply to both the interim and Phase II caps. Several commenters

(OAR-2002-0056-2915, -3440, -3463, -3478) noted that lignite units receive a 3:1 heat input

based allocation of allowances with respect to bituminous units. This ratio is to account for the

higher mercury content and lower energy content in lignite versus other coal types. The

commenters stated that such an allocation is critical to the continued use of lignite given its higher

mercury content with a higher elemental content that is harder to control, its lower heat content

and the current lack of demonstrated mercury control technology for lignite coals. One

commenter (OAR-2002-0056-3478) also stated that these baseline adjustment ratios were agreed

upon by the industry in the Clear Skies Initiative negotiations.

One commenter (OAR-2002-0056-3478) added that not only does the higher mercury

content, mercury speciation, lower heat content and lack of demonstrated mercury control

technology for lignite support at least an adjustment factor of 3 (with sub-bituminous held at

1.25), but the variability in the existing data supports this as well. According to the commenter,

in the preamble to this proposed rule, EPA stated: “Variability is inherent whenever measurements

are made or whenever mechanical processes operate. Variability in emission test data may arise

from one or more of the following areas: (1) The emission test method(s); (2) the analytical

method(s); (3) the design of the unit and control device(s); (4) the operation of the unit and

control device(s); (5) the amount of the constituent being tested in the fuel; and, (6) composition

of the constituents in the fuel and/or stack gases.” The commenter also stated that these baseline

adjustment ratios were agreed upon by the industry in the Clear Skies Initiative negotiations.

The commenter believed that although the EPA made these comments in regards to

setting the Maximum Achievable Control Technology (MACT) standard, it also would apply to

setting an appropriate cap for mercury in a cap and trade system. The commenter has noticed in

reviewing the 1999 Information Collection Request (ICR) data, considerable variability in all

these parameters, especially with lignite. According to the commenter, ICR Part III test runs

across the scrubber on Monticello Unit 3 indicated that mercury increased on one run and was
xcvii

reduced by 48 percent on another run. The commenter also stated that the tests on both Big

Brown Unit 1 and Monticello Unit 1 both indicated that mercury was increasing across the

baghouse. The commenter stated that, therefore, there was a great deal of variability in the stack

test method at their plants. The commenter has seen variability not only in the mercury content of

the coal from mine to mine, but also seam to seam and even noticed seasonal variability. The

commenter could not explain whether the seasonal variability was an actual phenomenon or some

type of laboratory analysis difference. According to the commenter, the lignite mercury analysis

performed for Part II of EPA’s 1999 Information Collection Request showed the same seasonal

trend for the samples from all four plants.

Several Texas State representatives and local officials (OAR-2002-0056-2119, -2204,

-2221, -2228, -2232, -2356, -2428) endorsed the cap and trade approach and supported the

allocations for lignite.

Several of the commenters (OAR-2002-0056-2830, -3469) requested that any adjustment

to the proposed factors which might occur during the rulemaking process not reduce the

allocations to lignite and thus disadvantage it in the market.

One commenter (OAR-2002-0056-2331) opposed EPA’s proposal to use the maximum

achievable control technology (MACT) emission rate criteria for different grades of coal as the

basis for allocating Mercury allowances. The commenter recommended that the EPA adopt the

CAA section 111 approach and maintain the compromise criteria of the December 15, 2003

proposal that were based on baseline heat input and adjustment factors for different grades of

coal. The commenter believed this would not only be a more equitable interregional solution for

allocating mercury allowances but would also not result in excessive fuel switching from coal to

natural gas.

One commenter (OAR-2002-0056-2634) would support and prefer a well designed Cap

and Trade program if the allocation methodology were modified to achieve a more fair and

equitable allowance distribution and thus reduce the number of large winners and losers. In an

effort to achieve a more equitable mercury allowance distribution, however, the commenter

proposed three (3) allocation methodology options.

OPTION 1: The commenter Mercury Allocation Methodology using unit specific 1999

Elemental Mercury Emissions.

The commenter submitted that this methodology would achieve the major goals of:

• Being coal neutral. Does not utilize any coal category adjustment factors.

• Reducing the number of large winners and losers. 

The commenter felt that the methodology proposed above utilizing the individual

elemental mercury emissions would be the most equitable way of allocating mercury allowances.
xcviii

However, the commenter recognized that the methodology proposed in the NPR may not be

substantially modified without seeking additional comments from interested stakeholders.

Therefore, the commenter proposed two alternate allocation methodologies that would

apply to those units having high (90 percent plus) elemental mercury emissions.

OPTION 2: The commenter Mercury Allocation Methodology using adjusted HI factors for

units that have 1999 elemental mercury emissions above 90 percent.

OPTION 3: The commenter Mercury Allocation Methodology using a set aside of 10 percent

of the 2010 and 2018 allowances.

The commenter stated that at a minimum, the modified allocation under Options 1, 2, or 3,

or under some other similar method, would need to be applied to units that presently have Spray

Dryer Absorbers (SDA) for SO2 control and Fabric Filters for particulate control and have

mercury emissions that are above 90 percent elemental. The commenter believed that this

adjustment for these units would be necessary and justifiable because the SO2 control (SDA) is

located upstream of the Fabric Filter. The commenter stated SDA tends to remove most of the

gases that would potentially oxidize some of the mercury to a form to be removed in the Fabric

Filter. The commenter stated further that units whose emissions are above 90 percent elemental

have already achieved the maximum removal that these units are capable of achieving without the

addition of advanced mercury control technology. This technology is envisioned as necessary for

past 2018 compliance, but it is not intended for the 2010-2018 period when co-benefits are

envisioned.

One commenter (OAR-2002-0056-2879) believed EPA’s data are inadequate both

quantitatively and qualitatively to produce supportable unit MACT emissions rates or, under a

trading regime, supportable or equitable allowance allocations, and has detailed those deficiencies

in Attachment A (See docket item OAR-2002-0056-2879).

If EPA proceeds with a cap and trade option, one commenter (OAR-2002-0056-2264)

recognized and supported the need for adjustments in the allocations to recognize differences

between bituminous and sub-bituminous coals. The commenter believed that EPA should develop

better data and information on which to quantify the mercury adjustment factors.

One commenter (OAR-2002-0056-2944) believed the currently-proposed mercury

emission limits, along with the similarly-weighted allowance distribution systems that were

proposed, clearly look politically-derived to particularly favor some business interests at the

expense of others. The commenter stated that the Environmental Protection Agency should

adamantly reject regulatory schemes which so blatantly appear to sacrifice the nation’s health to

special interests.

One commenter (OAR-2002-0056-3522) stated that allowances should be allocated to

sources in accordance with the emission factors developed as a result of WEST Associates’

analysis and described more fully in the WEST Associates’ comments. However, the commenter
xcix

could accept the allowance allocation factors endorsed in the comments of the Edison Electric

Institute.

One commenter (OAR-2002-0056-2835) submitted that while commenter members have

varying viewpoints on the different possible methodologies, all of the commenter’s members

agreed that allowances should be allocated in a manner that reflects coal chemistry, mercury

variability in the combustion fuel, and mercury removal efficiencies of available pollution control

technologies.

One of the commenters (OAR-2002-0056-2725) stated that many questions remain

regarding both the impacts of various coal types and the controls effective in mitigating each

type’s specific impacts. The commenter noted that the National Mining Association, recognizing

that more data is needed to fully answer these questions, is recommending that the EPA hold off

on assigning allocations among coal types until more complete information can be gathered and

assessed. The commenter believed this suggestion has real merit and would be supportive of such

a measured approach.

The commenter stated that should EPA determine that it must go forward with setting

allocations on the front end through its proposed mercury trading program, the commenter urged

the Agency to assure that those allocations are as equitable as possible. The commenter noted

EPA has proposed a range of allocation options for mercury allowances, ranging from the

allocation scheme proposed in the Clear Skies Act ( i.e. allocate in the proportion of 1:1.25:3 for

bituminous, sub- bituminous coal and lignite) to a scheme based on the mercury MACT proposal. 

In light of the problems with controlling mercury from sub-bituminous coal, the commenter

believed that the Clear Skies approach provides too few allowances for Western sub-bituminous

coal and suggested that EPA find compromise allowance allocation ratios that are more consistent

with the science of mercury control.

One commenter (OAR-2002-0056-3463) stated that the EPA should allocate emission

allowances for mercury to each affected unit directly in keeping with the Acid Rain Program. 

Similarly one commenter (OAR-2002-0056-2826) advocated that the cap-and-trade program’s

allowance allotment be based upon “heat input”–as with the Subpart H, NOx credit program-and

not on rank of coal.

One commenter (OAR-2002-0056-2160) stated that a cap and trade program should not

include fuel adjustment factors.

One commenter (OAR-2002-0056-2452) submitted that within a section 112 or section

111 cap-and-trade context, they did not believe that it is appropriate for EPA to adjust allocations

to the states or generating units based on coal-type adjustment factor (the commenter noted that

EPA’s currently proposed methodology applies adjustment factors to coal unit baseline heat input

data with an adjustment of 1.0 for bituminous coal, 1.25 for sub-bituminous and 3.0 for lignite). 

The commenter believed that rather, a single allocation emission rate standard, applied to baseline

generating unit heat input (without adjustment for coal-type) should be the basis for state and unit

level allocations. The commenter asserted that under a cap-and-trade regime, there would be no
c

need for EPA to address differences in coal-types as part of its allocation system. Units that were

harder to control would have the option to go to the market to support their compliance needs. 

The commenter submitted that a single allocation standard has worked well for the NOx SIP Call

(e.g. 0.15 Ib NOx/mmBtu) and companies have had the flexibility to choose the optimum mix of

controls and allowance purchases for compliance at their generating units. The commenter

believed a single allocation standard would also be more competitively neutral versus EPA’s

proposed allocation system that effectively “subsidizes” states and units with lower rank coals,

particularly lignite. The commenter stated that it is quite possible that as mercury control

technology evolves, that cost effective, high removal efficiency control technologies for lower

rank coals will be developed. The commenter pointed out that in this case, EPA’s proposal to

provide lower rank coals with larger emission allocations would provide these units with a

windfall relative to higher rank coals. Also, by lowering the compliance burden on lower rank

coals, EPA would be potentially creating a self-fulfilling prophecy where highly effective control

technology for lower rank coals would be under-developed versus what would be the case if all

units received emission allocations based on the same standard.

One commenter (OAR-2002-0056-3431) stated that regulations for the control of

mercury from utilities must not favor one coal type over another. The commenter believed the

cap-and-trade proposal with adjustment factors for different coal ranks (i.e., types) affecting

allocations and the MACT proposal with different emissions standards for different coal types,

both inappropriately favor particular coal types. The commenter stated that these regulations

should not unduly disadvantage generators based upon their coal type (i.e. bituminous,

sub-bituminous and lignite). The commenter believed a regulatory approach that does not favor

one coal type over another would be more efficient, cost-effective and equitable. According to

the commenter, under the successful Acid Rain program, the allocation methodology did not

favor one type of coal over another for sulfur content, but let the market set demand for a

particular coal.

The commenter noted that EPA solicited comment on whether it should use the proposed

MACT emission rates proposed in the Notice of Proposed Rulemaking as the basis for

allocations. The commenter specifically opposed this approach since it would penalize plants that

burn bituminous coal even more than the allocation approach proposed in the rule. The

commenter also stated that the MACT proposal would disadvantage both producers and users of

bituminous coal and would force the use of non-bituminous coal through blending. The

commenter believed such blending would favor Western coals over Eastern coals and, at a

minimum, increase transportation and coal costs for those who blend. The commenter added that

blending of coals also would result in higher emissions rates as the proposal requires a monthly

unit-specific weighted mercury emissions limit based on the proportion of energy output (in Btu)

contributed by each coal type burned during the compliance period and each coal type’s

applicable emissions limit. According to the commenter, as sub-bituminous coal has a higher

emission rate under the MACT proposal than bituminous coal, any blending of sub-bituminous

coal with bituminous coal would result in a higher emission rate.

One commenter (OAR-2002-0056-3443) did not support the use of heat input adjustment

multipliers and was against any further tinkering of the multipliers proposed by EPA. See 69 FR
ci

12397 and 12406 (1.0:1.25:3.00). The commenter submitted that heat input adjustment factors

would favor non-bituminous coals by allowing higher mercury emissions per TBTU. The

commenter believed this approach was not equitable nor environmentally sound since it would

allow units to have higher emissions based entirely on fuel choice. The commenter noted that

previous EPA cap and trade programs did not make such skewing adjustments favoring one coal

rank over another. In fact, EPA’s Acid Rain program was designed to prevent the market from

bestowing preferential treatment on a particular coal rank. The commenter believed EPA’s

proposed factors were already generous to non-bituminous units in accounting for the higher

emissions of non-elemental mercury from bituminous units. Pertinently, the intermediate and final

cap of 24 and 15 tons per year respectively, would require reductions from bituminous units not

only of most non-elemental mercury but also of the elemental kind. The commenter asserted that

accordingly, further skewing of the ratios in favor of the non-bituminous units would essentially

absolve these units of any control of elemental mercury.

One commenter (OAR-2002-0056-3437) questioned the allocation methodology. The

commenter noted the baseline heat input would be the average of the 3 highest heat inputs during

1998-2002. The was consistent with the NOx trading program. The commenter also noted

however, EPA proposed to adjust the heat input based on the coal rank. This would not be

consistent with the NOx or Acid Rain programs. The commenter noted further that EPA claimed

this would level the playing field based on the different mercury removal efficiencies with the

control used to control PM, SO2 and NOx. It was not clear to the commenter how this would

affect fuel switching, control options, or actual emissions. The commenter submitted that EPA

must provide information on how allocations would be distributed using different methodologies

so that more detailed comments can be filed. Absent any comparisons, the commenter believed

emission rates should be used to determine allocations and budgets that would address any

differences in coal types.

One commenter (OAR-2002-0056-3437) disagreed with the method for calculating state

and unit budgets. The commenter believed the rule should not be structured to provide an

advantage to one type fuel over another. The commenter suggested EPA should do like in the

NOx SIP Call; use an emission rate to determine allocations and budgets. This would avoid the

need to adjust the heat input . The commenter stated the emission rates would address the

differences in the ability to control mercury from different types of coal.

Many commenters (OAR-2002-0056-1854, -1969, -2067, -2160, -2180, -2375, -2519,

-2535, -2560, -2597, -2634, -2661, -2718, -2725, -2835, -2850, -2861, -2862, -2867, -2879,

-2895, -2897, -2900, -2903, -2918, -3406, -3521, -3537, -3546, -4132) requested changes in the

mercury allocation adjustment factors. Many of these commenters (OAR-2002-0056-1969,

-2375, -2519, -2560, -2597, -2661, -2718, -2725, -2850, -2862, -2867, -2897, -2903, -3198,

-3521, -3546) supported a change in EPA’s proposed mercury allocation adjustment factors to

1.0 for bituminous units, 1.5 for sub-bituminous units and 3.0 for lignite units. One of these

commenters (OAR-2002-0056-3546) submitted that allowances should be allocated in a manner

that reflects coal chemistry and mercury variability between coals. The commenter noted that

chlorine in coal plays a major role in the type of mercury that is emitted. Higher chlorine levels

result in a greater percentage of oxidized mercury and lower amounts of chlorine in coal result in
cii

more elemental mercury. The commenter stated that sub-bituminous and western bituminous

coals tend to be very low in both mercury and chlorine content compared with the concentrations

found in eastern bituminous coals. Data from the 1999 Information Collection Rule showed that

western plants emit lower concentrations of total mercury than eastern plants and that elemental

mercury is the form of mercury primarily emitted. The commenter noted that elemental mercury

is the form of mercury that is the most difficult to control. Ionic mercury can be readily captured

in existing particulate controls and flue gas desulfurization systems. The commenter stated that

EPA’s proposed mercury MACT floor limit for sub-bituminous coal recognizes the technical

challenge of controlling elemental mercury. However, according to the commenter, the proposed

allocation adjustment factors for the various coal ranks did not adequately reflect the differences

in coal chemistry and mercury variability between sub-bituminous and eastern bituminous coals. 

The commenter believed that the proposed 1.25 allocation adjustment factor for sub-bituminous

and western bituminous coals needed to be increased to at least 1.5.

The commenter (OAR-2002-0056-3546) stated that the proposed allocation adjustment

factors also do not differentiate between western bituminous coal and eastern bituminous coal;

both coal types receive the same adjustment factor. The commenter claimed that this would treat

EGU’s that burn western bituminous coal unfairly because the physical, chemical and emission

characteristics of western bituminous coals are substantially more similar to western bituminous

coal than eastern bituminous coal. The commenter submitted there are often times subtle

differences between the physical properties of western bituminous and sub-bituminous coals. 

While these physical tests determine whether a coal is bituminous or sub-bituminous, it does not

reflect that both ranks of western coal have low mercury and chlorine concentrations, and thus

similar mercury emission characteristics. The commenter supported an adjustment to the coal

rank multiplies that would combine western bituminous coal with sub-bituminous coal.

Another of the commenters (OAR-2002-0056-2850) noted EPA is suggesting a 1.0, 1.25

and 3.0 relative allocation of mercury allowances to bituminous, sub-bituminous and lignite coals

respectively, based on heat input. The commenter stated that, in effect, sub-bituminous coal units

incur a relatively more aggressive control requirement than would be applied under the EPA

proposed MACT levels and it would be expected that utilities burning sub-bituminous coals

would find it most economic to buy credits from bituminous coal units that face lower mercury

compliance costs. According to the commenter, a ratio for allocation of 1, 1.5 and 3 would be

more equitable and should be considered by EPA as an alternative.

One of the commenters (OAR-2002-0056-3537) stated that although there are no

commercially available control technologies specifically designed today for reducing mercury

emissions and monitoring data from Utility Units of mercury emissions is sparse, there is some

available data. The commenter noted that such data indicates that the three types of mercury

emitted in flue gas–particulate, ionic and elemental–vary according to the three most common

ranks of coal–bituminous, sub-bituminous and lignite being combusted in the Utility Unit. The

commenter also noted that generally speaking, the lower the coal rank, from bituminous to

sub-bituminous to lignite coals, the more difficult it is to control mercury. The commenter stated

that differences in elemental constituents in coal is just one variable affecting the ability to control

mercury emissions, since mercury speciation dictates the level of control that can be achieved
ciii

using existing air pollution control equipment. The relationship between coal chemistry and

mercury speciation is not totally understood. The commenter pointed out it is known, however,

that chloride content, sulfur content and ash characteristics can all affect mercury speciation. In

conclusion, the commenter stated that conventional pollution control technologies will be least

effective on units combusting lignite and most effective on those that burn bituminous coals, with

sub-bituminous units falling somewhere between the other two coal ranks.

The commenter (OAR-2002-0056-3537) stated therefore, any cap and trade program

which uses heat input as the basis for allocation must, to be equitable, contain adjustment factors

to account for the varying coal ranks that will be combusted across the industry, and the

associated differences between coal ranks related to the difficulty in controlling mercury

emissions. The commenter noted that EPA proposed heat input adjustment factors of 1.0 for

bituminous units, 1.25 for sub-bituminous units and 3.0 for lignite Utility Units. The commenter

believed that the heat input factor for sub-bituminous coal is too low relative to the other coal

ranks and should be increased to 1.50, which, based on the available data, would better represent

the relative difficulties of controlling mercury emissions from the three coal ranks.

One of the commenters (OAR-2002-0056-2375) stated that the method of allocating

mercury trading credits among affected sources can be established in a manner that would provide

protections against potential fuel-switching or creating an unequal playing field between

subcategories of coal users. Studies by WEST Associates (WEST) and the commenter showed

that the multiplier for sub-bituminous units should be at least 1.5 to account for the difficulty of

controlling mercury emissions from western coal. The commenter submitted that the vast

majority of coal-fired generators in the U.S. have agreed to compromise multipliers of 1.0, 1.5,

and 3.0 for bituminous, sub-bituminous, and lignite, respectively. The commenter supported

these multipliers both as representing a reasonable compromise and as having a sound technical

basis, although a higher multiplier for sub-bituminous could be justified based on the available

data.

One of the commenters (OAR-2002-0056-2519) noted that WEST Associates, of which

the commenter is a member, was submitting detailed comments on several issues associated with

the C & T program, and the commenter endorsed those comments by reference. Specifically,

those issues relate to the multipliers used for different coal types in calculating the allowance

allocations.

Another of the commenters (OAR-2002-0056-1969) expressed concern that EPA’s

proposed coal heat input adjustment factors of 1.0 for bituminous coal, 1.25 for sub-bituminous

coal, and 3.0 for lignite are not equitable for the purpose of allocating future mercury allowances. 

According to the commenter, EPA has not adequately considered the fuel-specific impacts of the

co-benefit level mercury emissions reductions. The commenter believed that as a result,

allowances would not be equitably allocated among the coal ranks. The commenter stated that

specifically, the optimum level of co-benefits would occur when all particulate and oxidized

mercury have been removed from the flue gas with only elemental mercury remaining. According

to the commenter, Table 1 (see docket) estimated the elemental portion of each coal rank based

on the 1999 ICR data. Table 2 (see docket) projected the annual emissions in tons per year on
civ

the basis of EPA’s proposed 1:1.25:3 coal heat input adjustment factors. The commenter noted

that the relative margin between the ICR -based 1999 mercury emission and the EPA proposal

was considerably smaller for sub-bituminous coal as compared to the other fuels. The commenter

asserted that more equitable heat input adjustment factors would be 1.0 for bituminous, 1.5 for

sub-bituminous and 3.0 for lignite (See Table 3 in docket).

One of the commenters (OAR-2002-0056-2661) stated there is an understood

industry-wide and regulatory concern that sub-bituminous coal users are at a disadvantage to

meet mercury reduction requirements because of the unique coal chemistry involved in burning

this fuel type. The commenter submitted this inherent difference should be reflected in the heat

input adjustment factor or multiplier for subbituminous coal ranks. As proposed, the commenter

supported a 1.5 or higher adjustment factor for users of the differing coal types, specifically for

sub-bituminous coals. The commenter agreed with EPA’s assertion that the same percentage of

non-elemental mercury first be reduced at a proportional rate across the board between the variety

of coal ranks.

Another of the commenters (OAR-2002-0056-2718) supported The Allocation Of

Mercury Allowances Based On Reasonable Multipliers. The commenter agreed with industry

consensus, with some refinements given the commenter’s unique situation, that for Phases I and

II, the multipliers that most appropriately reflect the mercury reductions that would be achieved as

co-benefits of CAIR NOx and SO2 reductions are 1.0, 1.5 and 3.0 for bituminous, sub-bituminous

and lignite, respectively. For Phase III, no multipliers–or, put differently, multipliers of 1.0, 1.0,

and 1.0–would be appropriate. Given that mercury reductions are a nationwide, rather than

regional, concern, the commenter believed that EPA’s final rule should equitably distribute the

burden of mercury reductions among regulated utilities and coal producers nationwide.

Another of the commenters (OAR-2002-0056-2560) stated that at an absolute minimum

the commenter supported a 1.5 or higher heat input adjustment factor for boilers burning

sub-bituminous coals as compared to bituminous coals. The commenter added that where

sub-bituminous and bituminous coals are blended for firing, the heat input adjustment factor

should reflect the percent of blend.

Another of the commenters (OAR-2002-0056-2903) stated that mercury trading credits

should be allocated among affected sources in a manner that recognizes the differences in control

opportunities and costs among coal types and preserves fuel diversity, yet avoids unintended fuel

switching and, when all factors are considered, still preserves a balance among subcategories of

coal users. The commenter believed that the appropriate multipliers, taking such considerations

into account, should be 1.0 for bituminous, 1.5 for sub-bituminous and 3.0 for lignite. The

commenter noted that the majority of coal-fired generators in the U.S. have now agreed to

support such multipliers.

One of the commenters (OAR-2002-0056-2597) noted that a major issue embedded in the

model cap-and-trade program concerns how mercury allowances would be allocated among the

different subcategories of coal types. The commenter stated that in order for the model program

to work most efficiently and cost-effectively, it is critical that no coal type is unduly disadvantaged
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based on the allowance allocation scheme adopted by EPA. The commenter believed the most

equitable allocation method uses adjustment factors of 1.0 for bituminous, 1.5 for sub-bituminous

and 3.0 for lignite.

One commenter (OAR-2002-0056-2895) stated that while the proposed allowance

allocation factors do reflect the difficulty in controlling for mercury amongst the different coal

ranks, the commenter believed that the proposed factors of 1.0 for bituminous coal, 1.25 for

sub-bituminous coal, and 3.0 for lignite need to be revised. The commenter believed that the

multipliers developed by WEST Associates based on its technical analysis of coal chemistry and

mercury variability between coals are more reflective of the difficulty in controlling for mercury

amongst the different coal ranks. These multipliers are 1.0 for bituminous coal, 1.8 for

sub-bituminous coal, and 3.6 for lignite. The commenter was also aware that a large number of

companies in the industry were supporting adjustment factors of 1.0 for bituminous coal, 1.5 for

sub-bituminous coal, and 3.0 for lignite. If the WEST Associate numbers are not selected as the

multipliers in the final rule, the commenter recommended the use of the aforementioned

multipliers (1.0, 1.5, 3.0) supported by much of the industry.

One commenter (OAR-2002-0056-2835) supported minor adjustments to allocation

methodology for mercury allowances based on type of fuel burned. The commenter agreed with

EPA’s decision to allocate mercury allowances based on the ability to control mercury from the

three major types of coal: bituminous, sub bituminous, and lignite. Furthermore, the commenter

believed that the adjustment factors selected for the mercury allocations should represent an

equitable sharing of the burden among coal types to achieve the required mercury reductions. 

The specific mercury allocation position outlined below reflected a compromise position among

the commenter members, which collectively have burned a diverse mix of coal types including

eastern and western bituminous and sub-bituminous coals and lignite.

The commenter stated that initial mercury reductions would be achieved through the

imposition of the SO2 and NOx controls required by the CAIR. These reductions are referred to

as mercury co-benefit reductions. The commenter also stated however, additional reductions

would be required beyond projected mercury co-benefit levels, particularly during the later years

of the mercury control program. The commenter submitted this additional mercury reduction

burden for each coal type could be measured in several ways. These included percent reduction

(pounds reduced divided by current pounds emitted for each coal type), equal reduction on a Btu

basis (pounds reduced divided by total coal type Btu), or cost of required reductions on a Btu

basis (dollar cost of reductions divided by total coal type Btu).

The commenter believed costs on a Btu-basis may be the best measure of the “fairness” of

a given set of allocation factors. The commenter has examined the range of removal costs for the

various coal types. The commenter’s analysis indicated that existing pollution control

technologies can, on average, achieve the following $/pound removal rates: $20,000/ pound for

lignite, $25-$30,000/pound for bituminous, and $30-$40,000/pound for sub-bituminous. Another

relevant factor examined by the commenter was the incremental mercury reductions estimated to

be necessary after mercury co-benefit reductions have been achieved through implementation of
cvi

the CAIR controls. Finally, the commenter considered variations in the form of mercury and level

within each coal type as well as the National Energy Technology Lab’s data on coal use by type.

The commenter noted that the considerations noted above indicated that the proposed

allocation factors of 1.0 (bituminous), 1.25 (sub-bituminous), and 3.0 (lignite), although

directionally sound, fall far short of equitably allocating the mercury control obligation among

coal types. Among other things, EPA’s proposed factors failed to reflect adequately the difficulty

in removing elemental mercury from those units burning sub-bituminous coal and over-allocate

mercury allowances to those units burning lignite. The commenter submitted furthermore, these

considerations noted above weighed in favor of EPA making the following changes in the

proposed mercury adjustment factors. The commenter believed that adjustment factors should

represent an equitable sharing of the burden among coal types for necessary mercury reductions

when the cost of required reductions on a Btu-basis is evaluated for each coal type. The

commenter stated that these factors would not achieve equality among the coal types with respect

to cost per Btu, but would be much more equitable than the proposed factors. The commenter

believed that these allocation factors should be used for each phase of a cap-and-trade program:

Coal Type Proposed Adjustment Factor Revised Adjustment Factor

Bituminous 1 1

Sub-Bituminous 1.25 1.5

Lignite 3 2.5

Several commenters (OAR-2002-0056-2898, -2907) supported allowance adjustment

factors as proposed by WEST Associates in Table 2 of WEST’s multivariable analysis. The

commenters stated these allocation factors are: Bituminous 1.0; Sub-bituminous 1.8; and Lignite

3.6. One of the commenters (OAR-2002-0056-2907) stated they supported these allocation

factors in light of the difficulty associated with controlling sub-bituminous coal. The commenter

believed these allocation factors would be more consistent with the science of mercury and

control technology.

One commentor (OAR-2002-0056-2180) noted that the proposed allowance adjustment

factors for determining allowance allocations to units are 1.0 for bituminous coal, 1.25 for

sub-bituminous coal, and 3.0 for lignite, and that these factors appeared to originate from the

proposed Clear Skies legislation. The commenter stated that, however, the adjustment factors in

the proposed legislation have not been scrutinized for scientific accuracy. The commenter noted

that the proposed rule’s preamble states that the proposed adjustment factors “are considered to

be directionally correct based on test data currently available” and the factors “are intended to

equitably distribute allowances to the affected industry.” The commenter stated that, however,

there is no information in either the rule’s preamble or in the mercury rulemaking docket that

scientifically justifies the proposed adjustment factors. The commenter noted that the preamble

indicates that EPA may apportion allowances based on proposed MACT emission limits. 

According to the commenter, the proposed MACT emission limits suggested that the
cvii

sub-bituminous allowance adjustment factor is set too low. The commenter stated that the ratio

of the sub-bituminous proposed MACT limit to the bituminous proposed MACT limit was 2.9,

while the ratio of the sub-bituminous to the bituminous proposed adjustment factors was only

1.25. According to the commenter, the apportionment process based on MACT limits could be a

step in the right direction, as MACT limits in the proposal are based on coal subcategories

reflecting coal rank, and the proposed MACT limits are based on EPA’s analysis of data. The

commenter stated that, however, without knowing what the final MACT limits would be, how the

limits were scientifically justified, and how the limits would be translated into the equivalent

adjustment factors for allocating allowances, it would not be possible to specifically support the

proposed alternate apportionment approach at this time. The commenter’s coal capacity

consisted of about two-thirds sub-bituminous and one-third bituminous coal. Therefore, the

commenter had a direct interest in having appropriate and scientifically justified adjustment factors

reflecting the various coal ranks. The commenter asserted that the final mercury trading rule

should include a complete scientific analysis and explanation of the final adjustment factors that

are adopted. The commenter offered that one alternative to consider would be to set adjustment

factors based on the ratio of remaining emission levels for each coal type after application of

co-benefit controls. According to the commenter, remaining emission levels for this purpose

would consist of elemental mercury emissions (assuming minimal emission reduction with

co-benefit controls) plus non-elemental mercury emissions (representing the percentage of

non-elemental mercury not captured by co-benefit controls).

One commenter (OAR-2002-0056-4132) cautioned that EPA should be careful not to

manipulate mercury allowances to simulate a technology-based standard. The commenter noted

that EPA has garnered significant praise over the economic successes of cap and trade programs

implemented relative to SO2 and NOx. Critical to the success of these programs was the fact that

there were strong economic incentives for all affected emitters to develop a low-cost solution to

reducing their emissions.

The commenter noted that in these proposals EPA is considering an unusual allocation of

mercury allowances at paragraph 60.4142. Sub-bituminous coal users may receive 25 percent

more mercury allowances per mmBtu than bituminous coal users. Lignite coal users may receive

200 percent more mercury allowances per mmBtu than bituminous users. (The mechanism for this

unusual allocation are coal-specific annual heat input multipliers 1.0, 1.25, and 3.0). The

commenter believed this artificial manipulation of a cap and trade program had the potential to

create several adverse outcomes:

• It appeared to provide special subsidies to the coals that emit the highest amount of

mercury per mmBtu.

• It allocated large lignite and sub-bituminous coal users mercury allowances equal to or

exceeding their current mercury emissions. As a result they would have little incentive to

make capital improvements to reduce mercury emissions. Theoretically, they may

backslide and emit more mercury in the future than in the base year.
cviii

• Bituminous coal users were essentially shorted in their allocations of mercury allowances.

This would cause higher levels of mercury control with higher incremental control costs

than would possibly be experienced in the traditional, unmanipulated allocation program.

• The allocation of mercury allowances to the sub-bituminous and lignite coal users would

have the potential to incentives use of these types of coal. This would not be a desirable

outcome, since mercury emissions from these coal types do not respond well to existing

air pollution controls.

The commenter stated that the remedy for the above outcomes would be to do away with the use

of any “annual heat input multipliers.” The commenter suggested that alternatively the annual

heat input multipliers should be reduced in magnitude and at the very least, they should not be

made larger.

One commenter (OAR-2002-0056-2897) stated that any cap-and-trade approach must

include allocation factors that address the need for subcategorization. The commenter believed

the factors proposed by the EPA (1.0 for bituminous, 1.25 for subbituminous and 3.0 for lignite)

did not adequately address this issue. The commenter stated that these factors were based on

EPA’s analysis of the ICR data, which has been shown to be inappropriate for any regulatory

purpose. According to the commenter, even the EPA states that these factors are only

“directionally correct”, this was a completely inadequate basis for setting a regulatory standard.

The commenter urged the EPA to thoroughly reassess the proposed allocation factors.

The commenter pointed out as the first phase reduction targets were based on EPA’s

estimates of actual reductions achieved through co-benefits and as it was widely acknowledged

that sub-bituminous coals obtain lower co-benefit reductions than bituminous coals it would be

essential that the EPA adopt appropriate allocation factors. The commenter stated that without

appropriate allocation factors sub-bituminous users who could not achieve significant co-benefit

reductions would be forced to buy allowances from bituminous users who can. According to the

commenter, this would obviously result in wealth transfer from users of sub-bituminous to users

of bituminous coals and promote fuel switching. The commenter asserted that claims that the

incorporation of any allocation factors will result in wealth transfer from bituminous users to

sub-bituminous users were clearly false and ignored the reality of lower co-benefit reductions for

sub-bituminous coals.

The commenter noted that other industry commentators are proposing factors of 1.0 for

bituminous, 1.5 for sub-bituminous and 3.0 for lignite based upon the relative proportions of

elemental mercury produced by the three different coal ranks. The commenter believed given the

limitations in the ICR database, basing the factors on the relative proportions of elemental

mercury would likely be a more robust approach. According to the commenter, because the

amount of elemental mercury produced effectively reflects the difficulty of control, these factors

are, in the long term, more likely to result in an even distribution of the compliance burden

between coal ranks. The commenter stated that, however, because plant configuration also

affects mercury capture and as sub-bituminous coal is typically burned in plant configurations that

produce little co-benefit capture, e.g. plants with dry scrubbers, a sub-bituminous factor based
cix

purely on elemental mercury content will be inadequate to avoid fuel switching. The commenter

asserted that in order to account for differences in plant configuration allocation factors of 1.0 for

bituminous, 1.9 for sub-bituminous and 2.95 for lignite, as proposed by the industry majority

during the CAAAC process, appear to be the most appropriate. The commenter stated that these

factors have been calculated from the floors developed by industry majority consensus position,

which included representatives from the unions, all major coal producing regions and a large

proportion of the electric utility industry.

One commenter (OAR-2002-0056-2634) noted that the adjustment factors are supposed

to account for the difference in coal chemistry among the different types of coal ranks. The

commenter pointed out that some of the major differences among coals is the amount of elemental

mercury and the chlorine content.

According to the commenter, bituminous coals are generally high in chlorine content

which tends to oxidize the elemental mercury and thus facilitate its removal with add on

SO2/NOx/PM emission control equipment. Sub-bituminous coals, however, have little or no

chlorine content and thus mercury oxidation is correspondingly less. The commenter stated it is

much more difficult to remove the elemental portion of the mercury in flue gas for sub-bituminous

coals regardless of control technology, including the addition of activated carbon which is the

most promising technology but is yet unproven. The commenter submitted that because

sub-bituminous coals typically have a much higher percentage of elemental mercury, the

adjustment factors should proportionally provide sub-bituminous coal users with a higher

allocation.

The commenter stated that given this fact, it follows that the adjustment factor for

sub-bituminous coal should be considerably higher than what is proposed in the NPR. The

commenter believed the ratio that would result from the proposed MACT floor contained in the

section 112 MACT portion of the NPR appeared to be the most reasonable. These factors would

be 1.0 for bituminous, 2.9 for subbituminous, and 4.6 for lignite. The commenter noted ICR III

speciation data showed that the average ratio of elemental mercury between sub-bituminous and

bituminous coals is 2.3. The commenter stated that this analysis supported the 2.9 adjustment

factor for sub-bituminous coals because it demonstrated and considered the inherent difficulties of

controlling elemental mercury; however, a multiplier of 2.3 for sub-bituminous could be justifiable

and defensible.

One commenter (OAR-2002-0056-3406) noted that EPA proposed to allocate allowances

to bituminous coal-burning units on the basis of 1.0 times their overall heat input, and to

sub-bituminous units on the basis of 1.25 times their heat input. The commenter recommended

against distinguishing between bituminous and sub-bituminous units for these purposes. In view of

the efforts underway to develop mercury control technologies for sub-bituminous coal, and the

role of stringent standards in driving technology development, the commenter believed that

bituminous and sub-bituminous units should be treated the same for allocation purposes.

Similarly, the commenter believed that constraint should be exercised in applying adjustment

factors to lignite.
cx

One commenter (OAR-2002-0056-1854) believed that a properly implemented cap and

trade program could reduce the overall cost of mercury control for coal-fired electric generating

units. The commenter supported the cap and trade baseline heat input adjustment factors that are

listed in this proposed rule on page 12445, i.e., 1 for bituminous, 1.25 for sub-bituminous and

3 for lignite coals. The commenter noted that these factors resulted from a carefully crafted

agreement reached in the Clear Skies Initiative. However, the commenter stated that with their

increasing knowledge of the mercury content of lignite and the inability to control it with proven

technology, they did have concerns that a factor of 3 for lignite may still be very restrictive.

One commenter (OAR-2002-0056-2067) stated that it is dependent on Wyoming Powder

River Basin (PRB) subbituminous coal to fuel its primary generating resource. According to the

commenter, PRB coal accounts for nearly 40 percent of the coal used for generating electricity in

the United States. The commenter supported the use of multipliers for the coal ranks based on

sound scientific data and noted that the EPA ICR data is a starting point but should not be the

exclusive source of such data. According to the commenter data collected by the Subbituminous

Energy Coalition (SEC), through the Western Research Institute in Laramie, Wyoming, provided

a more recent set of test data that should be considered. The commenter recommended that at a

minimum, the appropriate multiplier for sub-bituminous coal should be 1.5.

One commenter (OAR-2002-0056-2861) noted that EPA has proposed to apply an

adjustment factor to the baseline heat input used to allocate allowances depending on the coal

rank consumed during the baseline period. The commenter stated that the proposed factors of

1.25 for sub-bituminous and 3.0 for lignite would provide additional allowances to those coal

ranks, leaving fewer allowances for bituminous coal users. The commenter submited that EPA

has proposed those factors for distributing the allocations for 2018 and presumably for 2010 as

well. The stated basis for the factors was that boilers that burn sub-bituminous or lignite coals

presumably emit more mercury in the elemental form which is more difficult to capture with SO2

and NOx technologies. The commenter believed that the use of adjustment factors provides a

significant advantage to sub-bituminous and lignite coals. The commenter asked that EPA

re-evaluate the technical basis for adjustment factors and at a minimum to reject any request to

make those factors higher than what the Agency has proposed.

The commenter did not support the 1.5 adjustment factor for sub-bituminous coal being

proposed by UARG and the Edison Electric Institute (EEI). The commenter claimed that neither

UARG nor EEI have provided a sufficient technical justification for the higher factor. The

commenter noted that those arguing for the higher allocation adjustment factor are assuming that

sub-bituminous coals will achieve no control of elemental mercury. The commenter believed that

while that assumption may be somewhat appropriate if considering the level of reduction

associated with the co-benefits of SO2 and NOx control, the analysis is entirely inappropriate when

considering allocations of mercury at either a 24 ton or a 15 ton cap level.

The commenter submitted that in order for the industry to meet either a 24 ton or 15 ton

emissions cap, it would be necessary for utilities across the nation to take broad actions to install

technologies that are under development to control both elemental and non-elemental mercury,

with an overall 80 percent reduction requirement from the total mercury in coal. The commenter
cxi

stated that the advanced technologies that are under development are intended to be applicable to

a wide range of coals, including bituminous, sub-bituminous, and lignite. The commenter believed

factors other than coal rank may be more important to the ability to reduce mercury emissions. 

For example, a facility that is equipped with a baghouse may be able to achieve substantial

elemental mercury reduction through use of carbon injection.

The commenter claimed that even using heat input alone to distribute either a 24 ton or

15 ton cap would provide a significant advantage to sub-bituminous coal users. The commenter

noted that sub-bituminous coal has the lowest average mercury content of the coal ranks, as

documented by EPA data from the mercury ICR. The commenter stated that using an adjustment

factor of 1.0 (using unadjusted heat inputs to allocate allowances) would actually provide nearly a

50 percent bonus to sub-bituminous coals compared to the allocations if all coal ranks were

expected to achieve the same percent reduction. The commenter claimed that EPA’s proposed

adjustment factor of 1.25 for sub-bituminous coal amounts to an allocation windfall bonus of

nearly 90 percent. The commenter also claimed that for lignite coal, the proposed adjustment

factor of 3.0 would be equivalent to an allocation windfall bonus of nearly 150 percent.

The commenter asserted that additional allocations for sub-bituminous and lignite coal

would mean that bituminous coal users would be required to make proportionally greater

reductions, or purchase more allowances than would otherwise be required. The commenter

submitted that EPA has not provided a technical basis to justify this subsidization of

sub-bituminous and lignite users by bituminous users, but has simply declared that the factors are

“directionally correct.” The commenter submited moreover, EPA has not indicated why it is

necessary to give this advantage to sub-bituminous and lignite coal producers and to punish

bituminous coal producers. The commenter stated EPA must provide a compelling justification

for such economic policy choices and impacts. The commenter believed the fact that the Clear

Skies legislation included adjustment factors for sub-bituminous and lignite coal was not a

justification for EPA to include them in a mercury rule. The commenter submitted that unlike

Congress, EPA must provide adequate technical justification for its rule, which in the case of its

proposed adjustment factors it has failed to provide. Without a reasonable technical basis, the

commenter believed the adjustment factors were arbitrary and should not be used for establishing

a regulatory control program. The commenter submitted that providing these bonus allocations

would be an energy and economic policy decision that would provide an advantage for states that

have historically produced and/or used certain coal supplies. The commenter also submitted it is

not a decision based on future environmental control requirements and effectiveness. The

commenter predicted the consequences for states that have used bituminous coal exclusively, and

those states engaged in the mining of bituminous coals, are millions of dollars for additional

controls or allowance purchases, limited ability for development of new coal facilities due to a

shortage of allowances for bituminous users, and lost jobs and income for industry and coal

miners.

While the commenter believed that the use of adjustment factors would not be warranted,

if EPA finalizes a cap and trade program beginning in 2010 which includes adjustment factors for

sub bituminous and lignite coals, the commenter recommended that both adjustment factors be

gradually eliminated on a sliding scale through 2018 to reflect the fact that advanced technologies
cxii

and the stringent cap will require control of all species of mercury. Under the alternate proposal

that the commenter and UARG are recommending (co-benefits with no cap in 2010, followed by

a two-phase cap and trade program beginning in 2015), the commenter recommended no

adjustment factors be included. In any case, the commenter was not aware of any credible

analysis that would support the adjustment factors higher than those that EPA has proposed as

some groups are advocating, and EPA should reject those suggestions.

One commenter (OAR-2002-0056-2879) stated that allowance allocations under a trading

program must be done equitably. The commenter believed that an allowance allocation using the

proposed MACT emissions rates would simply convert the form of the advantage conferred on

sub-bituminous coal from coal switching to a transfer of allowances, with hundreds of millions of

dollars flowing each year from bituminous coal users to sub-bituminous coal users in the form of

excess allowances. The EPA should propose a supportable and equitable allowance allocation

scheme that does not overtly favor one coal rank over another. (Note See detailed explanation in

docket item.)

One commenter (OAR-2002-0056-2535) believed that if EPA’s proposed mercury

adjustment factors (1.0; 1.25; 3.0) were used in conjunction with EPA’s assumed 34-ton

co-benefit level in 2010, a corresponding mercury emission limit could be calculated. Using the

assumptions described, the corresponding mercury emission limit would be in the ballpark of

2.6 lb Hg/TBtu (bituminous coal), 3.2 lb Hg/TBtu (sub-bituminous coal), and 7.8 lb Hg/TBtu

(lignite coal). This calculation showed that EPA’s proposed mercury adjustment factors represent

a dramatically different regulatory scheme than that proposed under the MACT program

(2 lb Hg/TBtu (bituminous coal), 5.8 lb Hg/TBtu (sub-bituminous coal), and 9.2 lb Hg/TBtu

(lignite coal)), as there was relatively little “subcategorization” in the proposed adjustment factors

between bituminous and sub-bituminous coal. The commenter pointed out there are dramatic

differences between Wyoming sub-bituminous coal and other sub-bituminous coals. These

differences include higher mercury content than the EPA’s “average” sub-bituminous coal

mercury content of 5.74 lb Hg/TBtu, and lower capture rates than some other sub-bituminous

coals largely based on the high elemental to total mercury ratio in the coal (evidenced by the lack

of Wyoming PRB plants among the top performing units). EPA stated in the allocation

memorandum cited above that “These adjustment factors are considered to be directionally

correct based on the test data currently available.” The commenter asserted the allocation process

is critically important to the coal industry, regardless of coal rank. “Directionally correct” would

not be a sufficient basis on which to set adjustment factors that are so crucial to understanding

market implications. For this reason, the commenter would support EPA taking the necessary

time to determine the accuracy and validity of the data prior to setting the adjustment factors. 

This approach would allow EPA to better understand the current state of control technology, and

how different coal ranks behave with that technology. If EPA opts not to go this direction, then

the commenter would be forced to support the mercury adjustment factors based upon EPA’s

proposed MACT emission floor numbers–those being 1.0 for bituminous; 2.9 for sub-bituminous;

and 4.6 for lignite.

One commenter (OAR-2002-0056-3198) stated that any allocation factors must address

the need for sub-categorization, and the factors currently proposed by the EPA (1.0, 1.25 and
cxiii

3.0) did not adequately address this issue. The commenter stated that these factors were based on

EPA’s analysis of the ICR data and would be inappropriate for any regulatory purpose. The

commenter pointed out that EPA stated that their analysis is only “directionally correct,” which is

an insufficient basis for setting a standard of this significant importance. The commenter urged

the EPA to thoroughly reassess the proposed allocation factors. The commenter asserted that

there is no rush to judgment in setting these factors, and EPA can take the appropriate time to

obtain and analyze the proper factors. Absent this process and EPA moves forward to set the

factors at this time, the commenter believed that factors should be set somewhere in the range of

the proposed EPA MACT emission limits for mercury.

One commenter (OAR-2002-0056-2918) asserted the rulemaking must take into

consideration both coal chemistry (primarily the chlorine content) and mercury variability between

coals both as a total concentration and elemental fraction. The commenter submitted that doing

so would result in a regulatory approach that addresses both the environmental impacts of

near-field deposition of oxidized mercury and the long-range atmospheric transport of elemental

mercury.

The commenter noted that the NPR recognized distinctions in coal chemistry by proposing

to use allocation adjustment factors for each coal rank. These allocation factors are intended to

compensate for differences in the efficacy of mercury control based on coal type.

The commenter stated that they undertook extensive technical work to determine the most

appropriate manner to address mercury variability in developing a mercury MACT floor. The

commenter suggested using this work as the basis to develop mercury allocation factors under a

cap and trade program that would reflect actual mercury variability. The commenter believed that

the relative difference between the proposed mercury MACT floor levels for each coal rank

would be a good surrogate for weighting the allocations of future mercury emission credits

between units burning these coal types, i.e., the cap and trade multipliers should reflect coal

chemistry to the same extent as the proposed MACT limits.

The commenter noted that the proposed MACT floors contained in the section 112

MACT portion of the NPR would produce the following allocation factors for various coal ranks:

bituminous–1.0; sub-bituminous and western bituminous–2.9; and lignite–4.6. While the

commenter supported these allocation adjustment factors, the commenter was concerned that

there may be inadequate basis for these derived factors. Alternatively, the commenter suggested,

based on its technical analysis, using the following allowance multipliers: bituminous–1.0;

sub-bituminous and western bituminous–1.8; and lignite–3.6.

One commenter (OAR-2002-0056-2918) wanted to bring to EPA’s attention that there

are member facilities (the commenter is a coalition of utilities) that, because of the high

percentage of elemental mercury emitted by their coal (90-99 percent), would not receive

adequate allowance allocations under any set of multipliers. According to the commenter, some

of these facilities already have SO2/NOx/PM controls, but they would receive considerably fewer

allowances than needed to operate based on ICR data for their 1999 emissions. This would be

true even in 2010 with a cap set at the level of co-benefits achieved through installation of control
cxiv

technology at sources covered under the CAIR. The commenter claimed that these member

sources would therefore be forced to purchase allowances in Phase I. For the facilities that would

have to purchase allowances, the commenter recommended that an additional allocation

adjustment factor be applied that promotes equitable allowance distribution, particularly in Phase I

of the cap and trade program.

One commenter (OAR-2002-0056-2900) believed that EPA’s proposed adjustment

factors are directionally correct but requested that the Agency re-evaluate the appropriate levels

for the adjustment factors in light of the data submitted by other groups that have analyzed this

issue.

One commenter (OAR-2002-0056-3437) noted that in the SNPR, EPA continued the

methodology for basing allocations on the unit’s proportionate share of the baseline heat input to

total heat input. The commenter pointed out that this way would not use an emissions rate, but

would simply divide the toal cap among individual units based on heat input. The commenter

questioned how this would affect actual reductions? The commenter also questioned whether this

could lead to some units being uncontrolled and allowing allowances to be transferred to other

units so that even more units would be uncontrolled? The commenter stated that EPA proposed

an alternative method that would use the proposed MACT limit and the proportionate share of

heat input to establish unit allowances. In both cases the state budget would be the sum of the

unit’s allowances. The commenter supported using an emission rate that would reflect cost

effective control and would more effectively limit individual units and result in more units having

to control emissions. The commenter believed the allocation budgets should be based on an

emisson rate that reflected adequate and reasonable reductions of mercury similar to that in the

NOx SIP call. The commenter submitted that EPA needs to provide comparisons of the final

allocations based on the proposed methods.

One commenter (OAR-2002-0056-2181) believed the Rule’s proposed allocation method

for determining individual State budgets was flawed because it would adopt two market-distorting

foundations. First, it would base the allocation on historic heat input; thus rewarding those States

with the most inefficient fleet of electric generating capacity. Second, by subcategorizing the

allocation formula based upon fuel sources and granting more allowances to higher cost-of

control coal types, the proposed rule also would reward some sources at the expense of other

sources. The commenter claimed that these proposed subcategorizations were based on

expectations of mercury control costs that are not well documented and would defeat the

cost-minimization function of the trading program. Neither of these two foundations would

establish the fundamental signals that will lead to a dynamic trading program that would allow

markets to work in the most cost effective manner. The commenter pointed out that the negative

response from States to this skewing of the allocation system highlighted the problem of trying to

prejudge the compliance response. The commenter submitted that the most equitable and

effective choice would be to treat all sources equally in the allocation program and allow the

market to determine the least-cost approach to reducing emissions. As an alternative, the

commenter recommended that EPA should structure the State budgets on an output basis

(lb/MWhr) without regard to subcategories of fuel. This method would be the best approach for

establishing a trading program that provides the broadest flexibility and insures neutrality among
cxv

vintage or technology choices. Indeed, output-based allocation would put into practice many of

the goals set forth by the enlibra principles promoted by Administrator Leavitt. The commenter

noted that specifically, these principles stated that, “A clean and safe environment will best be

achieved when government actions are focused on outcomes, not programs and processes, and

when innovative approaches to achieving desired outcomes are rewarded.” An output-based

allocation method that rewards efficiency and lower emissions would be one such innovative

approach. The commenter strongly urged the EPA to follow this approach in determination of

the State budgets as the most equitable, and to signal support for this approach with the States in

determination of the generator allocations.

One commenter (OAR-2002-0056-2843) believed that an allowance allocation budget

established at this time would almost certainly unfairly discriminate among coal types and among

installed APCD technologies. The commenter submitted that postponement of an equitable

allocation determination until near the implementation of Phase 2 could eliminate most of the

uncertainty and inequities associated with pre-mature determination.

Response:

EPA is finalizing coal adjustment factors for the purpose of establishing state emission

budgets of 1.0 for bituminous coals, 1.25 for subbituminous coals, and 3.0 for lignite coals. To

develop allocation ratios, EPA balanced a number of factors, including: (1) data on mercury

capture by control figuration and coal type, (2) data on coal characteristics impacting Hg

capture, and (3) Hg emissions by capacity. EPA believes the allocation adjustment ratios

recognize that subbituminous and lignite coals have the lowest mercury capture with existing

technologies, represent more emissions per capacity, and in the case of lignite also have higher

mercury coal content. These adjustment factors are considered to be appropriate numbers based

on the test data currently available. For further discussion see final rule preamble (section

IV.C.4) and Technical Support Document for the Clean Air Mercury Rule Notice of Final

Rulemaking, State and Tribal Emissions Budgets, EPA, March 2005.

5.6.2 Methodology for Determining Budgets

Comment:

One commenter (OAR-2002-0056-3449) stated that estimating national mercury

emissions based on sampling of coal from all coal-fired units and testing about 80 units is

appropriate. However, these tests were too limited for allocations to specific states or plants. 

The commenter submitted that testing at more than 80 units would be needed to allocation of

allowances.

Response:

EPA is finalizing a formula to be used to develop budgets for each state and Tribes for

2010 and 2018. That formula is, in essence, the sum of the hypothetical allocations to each

affected Utility Unit in the State or Tribe, and that allocation, in turn, is based on the
cxvi

proportionate share of their baseline heat input to total heat input of all affected units. For

purposes of this hypothetical allocation of the allowances, each unit’s baseline heat input is

adjusted to reflect the ranks of coal combusted by the unit during the baseline period. The

commenter is incorrect in the assumption that emissions data was used to develop the budget

allocations. Rather, reported heat input from affected units was used to develop the allocation. 

For further discussion see final rule preamble (section IV.C.4) and Technical Support

Document for the Clean Air Mercury Rule Notice of Final Rulemaking, State and Tribal

Emissions Budgets, EPA, March 2005.

Comment:

One commenter (OAR-2002-0056-4139) stated that the proposed budget is too high and would

not provide for adequate reductions in Phase I. The commenter claimed EPA has exaggerated the

Phase 2 reduction as well ; it would not occur by 2018. The commenter submitted the budget

allocation for Michigan would not reach the national average reduction even in 2018–only

63 percent of it. The budgets were established by fuel types burned. However, the commenter

believed the focus must be on needed mercury reductions. The commenter asserted the method

for budget allocations must be changed to ensure public health protection.

One commenter (OAR-2002-0056-3976) submitted that the 2018 mecury allowances

cause 7 of the top 10 plants and all of the top 5 to be in Texas. The commenter stated this placed

an undue mercury allocation on Texas of 59,391 ounces per year compared to 5077 for New

York and 0 for California.

Response:

EPA maintains that it is appropriate to base emission budgets on baseline heat input that

is adjusted to reflect the ranks of coal combusted by the unit during the baseline period. It

should also be noted that these allocation adjustment factors should not impact the achievement

of the specific environmental goal or impact the overall efficiency of the cap-and-trade program. 

Allowance allocation decisions in a cap-and-trade program raise essentially distributional

issues, as economic forces are expected to result in economically least cost and environmentally

similar outcomes regardless of the manner in which allowances are initially distributed. 

Comment:

One commenter (OAR-2002-0056-2452) noted that EPA has requested public comment

on an appropriate mercury cap level for 2010-2017. The commenter requested that before EPA

goes final with its proposed cap level for this time period, that the proposed cap level, state

budgets, and unit-level allocations be published for public comment in a supplemental notice of

proposed rulemaking (SNPR) in the Federal Register. As per the commenter’s recommendation

on state mercury budgets and unit allocations, all unit level allocations and state budgets could be

published for comment based on the commenter’s recommendation of a single mercury emission

standard for all coal-fired units applied to baseline heat input (without adjustment for fuel type).
cxvii

Another commenter (OAR-2002-0056-2108) noted that the proposal did not contain any

State budgets for 2010, nor did it indicate when such budgets would be promulgated. According

to the commenter, this is a critical piece of the program.

Response:

As discussed above, EPA maintains that it is appropriate to use coal adjustment factors

for the purpose of establishing state emission budgets. EPA also maintains that the commenter

has been supplied with appropriate notice and comment for the 2010-2017 emission budgets

because EPA has noticed the unit allocations used to derive those budgets in the supplemental

notice of proposed rulemaking. The final rulemaking includes State and Tribal emissions

budgets for 2010-2017 and 2018 and after.

Comment:

One commenter (OAR-2002-0056-4891) noted that EPA has proposed a budget allowance for

Texas of 1.837 tons per year for 2018 and thereafter. The commenter supported a proposed

mercury emissions budget allowance for Texas of no less than EPA’s proposal. 

Response:

EPA has used the same methodology to determine state emission budgets as the proposed

rulemaking. EPA has made some adjustments to the unit-level allocation data for the final

rulemaking which as resulted in some state budgets changing for the final rulemaking. For

discussion of final rule State and Tribal Budgets see Technical Support Document for the Clean

Air Mercury Rule Notice of Final Rulemaking, State and Tribal Emissions Budgets, EPA, March

2005.

Comment:

One commenter (OAR-2002-0056-3432) observed that industrial boilers are already

subject to a MACT rule which the EPA issued as final on February 26, 2004. The commenter

noted with considerable interest that in the March 16, 2004 SNPR, in th units allocation table

(69 FR 12435), the EPA includes Alma Bl, B2, and B3 in the listing of units with “Phase II Hg

allocation(ounces).” The commenter stated that these are the same units that the EPA has

otherwise identified as industrial boilers (or IBs) since they serve generators less than 25 MWe. 

The commenter found the inclusion of these units in the units allocation table confusing since the

commenter found no explanation in the SNPR for a deviation from the prescribed definition of

these combustion units. The commenter stated that EPA needs to clarify the listing of their Alma

IB units.

Response:

The commenter did provide EPA with specific nameplate capacity data to determine

whether they are not affected units under this program. Therefore, EPA has included they in the
cxviii

unit-level allocations used to determine state emission budgets for the final rule. EPA notes that

these hypothetical unit allocations to not determine applicability to the program. Rather,

applicability is determined by whether a unit meets the definition of affected unit (see regulatory

text of final rule, §60.4104, for full definition). If the commenter’s units are determined to be

unaffected units, EPA maintains that removal from the list of hypothetical unit allocations will

not significant impact the state emission budget for Wisconsin.

Comment:

According to one commenter (OAR-2002-0056-3443), state budgets should be in

perpetuity. A shifting state budget would make long-term planning difficult for utilities and would

add significantly to the administrative burden of the rule. The commenter stated it would also

discourage repowering or retirement of uncontrolled units.

Response:

EPA has established permanent state Hg emission budgets for the first (2010-2017) and

second (2018 and after) phase of the program.

5.6.3 Baseline Data Used in Emission Budgets

Comment:

One commenter (OAR-2002-0056-2922) suggests that, in reference to the calculation of

the baseline heat input, EPA must take steps to ensure that the heat input data for non-Title IV

units are accurate. The commenter noted that in its proposal, some of the heat input data that

EPA provided for non-Title IV units were incorrect.

Several commenters (OAR-2002-0056-2162, -3565) believed EPA must take steps to

ensure that the heat-input data are correct so that accurate baselines can be established. One

commenter (OAR-2002-0056-3565) stated that EPA should publish all heat input data and any

other data it intends to use and clearly describe the methodology by which it intends to calculate

both a unit’s baseline and the allowances to be allocated to the unit. The commenter cannot

exactly duplicate and match the proposed allowance allocation for its units with the allowances

listed in the proposed rule. The commenter stated that enough data and information should be

clearly provided to allow all affected sources the ability to calculate and check their individual

allocations.

One commenter (OAR-2002-0056-2891) stated that EPA must address errors and

omissions in its ICR database and provide a mechanism for correction of mercury unit allocations. 

According to the commenter, for a number of reasons, information reported to EPA and reflected

in its ICR database regarding gulf coast lignite was seriously flawed. The commenter added that

appropriate information regarding waste coal and its use in Southern Illinois was not reflected in

the database. The commenter further stated that in addition, changes in generating unit
cxix

operational circumstances have occurred since 1999. For these and other reasons, the commenter

recommended that a petition process be put in place to facilitate needed unit allocation changes.

One commenter (OAR-2002-0056-2162) noted that in its preamble to the Proposed

Mercury Rules, the Agency specified that baseline heat input would be determined for each

affected unit by determining the average of the three annual highest heat input values for the

period from 1998 to 2002. However, based upon a review of the Agency’s revised unit

allocations, it appeared to the commenter that the Agency has established allocations for many of

the commenter facilities based upon only one year of heat input data.

The commenter believed that the Agency’s methodology for establishing unit allocations

under the proposed cap-and-trade approach may rely exclusively on data collected in accordance

with 40 CFR Part 75 monitoring standards. Although Acid Rain Program data may be the best

available data for many electric utility steam generating units, the majority of the commenter’s

facilities have been exempted from the program, including its monitoring provisions, since the

program’s inception. The commenter’s facilities generally began to monitor emissions in

accordance with Part 75 requirements during 2002, pursuant to implementation of the NOx SIP

Call Rule. In fact, EPA has accepted monitoring data collected by the commenter’s facilities

under 40 CFR Part 60 for purposes of all other federal allocation programs, including even the

initial allocation under the NOx SIP Call Rule.

Notwithstanding the availability of more complete historic heat input data for the

commenter’s facilities (which the Agency utilized in the context of the NOx SIP Call), the Agency

utilized only one year of heat input in establishing a baseline value for the commenter’s facilities. 

In fact, while the Agency identified both 2002 and 1999 heat input data for most the commenter’s

facilities, the Agency only utilized the 1999 data, even where the 2002 data demonstrated a higher

heat input. This would pose a significant disadvantage to the commenter’s facilities, which do not

have the benefit of averaging the three highest years of heat input, and inexplicably have been

limited to 1999 heat input data. The commenter submitted further, to the extent that the Agency

has relied on heat input data that reflected an aberrational operating condition, the baseline heat

input value may be inappropriately low.

For these reasons, the commenter requested an opportunity to submit complete and

accurate heat input data for the years 1998 through 2002, from which the Agency could

determine appropriate baseline heat input values, and mercury allocations, for the commenter’s

facilities.

Response:

EPA is finalizing a formula to be used to develop budgets for each state and Tribes for

2010 and 2018. That formula is, in essence, the sum of the hypothetical allocations to each

affected Utility Unit in the State or Tribe, and that allocation, in turn, is based on the

proportionate share of their baseline heat input to total heat input of all affected units. For

purposes of this hypothetical allocation of the allowances, each unit’s baseline heat input is

adjusted to reflect the ranks of coal combusted by the unit during the baseline period.
cxx

Commenters indicated inaccurate data in the hypothetical unit allocations used to

determine the emission budgets, but have not pointed to specific errors or provided corrected

data. Thus, EPA is unable to address the commenters claim’s. EPA believes that its

methodology for determining the state emission budgets is accurately described in its emission

budget technical support document and in the companion spreadsheet file, both in the

rulemaking docket (see Technical Support Document for the Clean Air Mercury Rule Notice of

Final Rulemaking, State and Tribal Emissions Budgets, EPA, March 2005 and electronic

spreadsheet file: Final CAMR Unit Hg Allocations.xls, which contains the unit level allocations).

The use of one years worth of data was done for non-Acid Rain units, because this was

the only available data. Non-Acid Rain units in the Hg ICR inventory do not uniformly report

annual heat input to EPA’s Clean Air Market Division (some OTC NOx Budget Program units

may have reported ozone season heat input for 1999-2002). Baseline heat input information was

collected by the Hg ICR for 1999. The fuel use and heat content data from the ICR were used to

calculate 1999 annual heat input, and this single year was used as the baseline heat input (see

Budget TSD for more discussion).

With regard to commenter’s request to submit more appropriate data for 1998-2002,

EPA notes that it requested at proposal for commenters to submit such data. For commenters

who submitted such data, EPA adjusted hypothetical unit allocations accordingly. In most

instances, corrections to baseline heat input data at the unit level allocation are not likely to

result in significant changes to the overall State or Tribal emissions budgets. Under the model

trading rule, EPA notes that States and Tribes have the authority to allocate at the unit level and

commenters can submit corrected baseline heat input to the State or Tribe prior to the allocation

process.

Comment:

Several commenters (OAR-2002-0056-2915, -3478, -4191) supported the 1999 coal type

use as the basis for the adjustment of the baseline for establishing plant mercury allocations. 

Commenter OAR-2002-0056-3478 stated that this is the year upon which the 48-ton electric

utility mercury emissions were based. Several of the commenters (OAR-2002-0056-2915, -4191)

believed using 1999 as the fuel baseline is needed to provide certainty. The commenters added,

1999 is the only year for which EPA already has data for all the coal-fired EGUs throughout the

country.

Several commenters (OAR-2002-0056-2180, -2816, -2900, -2948, -3537, -3546, -3556,

-3565) stated that basing plant mercury allocations on the coal rank used in 1999 would not

reflect coal type switches that have occurred since the coal rank year. One commenter

(OAR-2002-0056-2180) pointed out that, therefore, units that have switched coal type since 1999

would not receive an appropriate or relevant allocation of allowances for future operation, as the

allowance adjustment factor would be based on historical coal type, not the current coal type. 

The commenter was a joint owner of two coal units that have switched coal rank since 1999 and

stated that they would be adversely affected by the proposed method for determining the

allowance adjustment factor and mercury allowances. The units represented about two-thirds of
cxxi

the commenter’s total coal capacity. These units switched coal rank from bituminous coal to

sub-bituminous coal to comply with the NOx SIP Call. According to the commenter, using

sub-bituminous coal in these units reduced the NOx emission rate by about 50 percent. The

commenter stated that switching coal type was not simply a matter of ordering a different type of

coal. The commenter emphasized that to use sub-bituminous coal at its units, they made

significant and necessary investments to the units’ systems for coal transportation, coal handling,

dust suppression, fire protection, particulate emissions control, and ash handling. The commenter

stated that the coal switch qualified as a pollution control project under New Source Review

regulations, and the decision to switch coal type came about long before the mercury cap and

trade rule was proposed. The commenter asserted that the mercury trading rule’s application of

allowance adjustment factors should be revised to reflect coal type switches that have occurred

since the baseline coal rank year, and especially for coal type switches that were done towards

complying with Clean Air Act requirements and where the decision to switch coal type occurred

prior to the proposed mercury rule. The commenter stated that for such situations, the final rule

should enable the use of the adjustment factor for currently used coal. According to the

commenter, this recommended revision would not affect the total number of national mercury

allowances, only the allocation of the allowances among affected units, and would only have a

very minor change in allowances allocated to other affected units. Another commenter

(OAR-2002-0056-2948) suggested that EPA should permit units that had a significant change in

their coal-type usage since 1999 to provide EPA with that information before allocations are

finalized.

A third commenter (OAR-2002-0056-3537) stated that in anticipation of new regulatory

requirements, two Utility Units co-owned by the commenter switched from eastern bituminous to

western sub-bituminous coal to lower NOx emissions. In 2001, the decision was made by the

Corporation (and the other co-owners) to switch to sub-bituminous coal, in anticipation of

imminent new regulatory requirements for Georgia. According to the commenter even though the

units in question were originally designed to burn this type of coal, some engineering and design

work was needed to facilitate the switch. This was started in late 2001 and construction began in

early 2002, in order to fully implement the switch in 2004. The commenter stated the units began

to operate fully on sub-bituminous coal at the beginning of 2004. The commenter noted if EPA

uses the coal type used by each unit in 1999, however, to determine the adjustment factor, then no

adjustment to these units’ baseline will be made. Further, when Georgia (under CAA section 111)

or EPA (under CAA section112) allocates back to these units from Georgia’s mercury trading

program budget, likely that same multiplier (i.e., 1.0) instead of the higher ratio for subbituminous

coal would be used. The commenter submitted that the result would be a lower allocation of

mercury allowances to such units than would otherwise occur had those units been given credit

for the fuel that is actually being burned. The commenter believed that such units will be

“short-changed,” since they would not receive the amount of mercury allowances needed for the

coal they are now burning–coal whose mercury emissions are by their very nature harder to

control than the type combusted in 1999. The commenter claimed that such units would

automatically be at a distinct competitive disadvantage vis-a-vis other units, who were fortunate

enough not to have switched to a lower ranked coal since 1999. The commenter asserted that the

result would be patently inequitable, in essence punishing the affected units for taking steps to

comply with an important State and federal program for the control of a criteria pollutant, by
cxxii

failing to allocate to them the allowances that correspond to actual coal usage. The commenter

believed EPA should not allow these units to be so unfairly prejudiced. EPA should correct this

inequity for those Utility Units that switched fuels for environmentally beneficial reasons, by

allowing a unit that switched to a lower ranked coal for reasons other than the Mercury Rule to

use the year the Mercury Rule is finalized as the year to determine the adjustment ratio to be used,

both when computing State budgets and when allocating mercury allowances to units within the

State. The commenter suggested alternatively, EPA could allow owners of those few units in this

position to petition it (or the relevant State) for use of a different adjustment ratio that matches

the real-world coal use at such units.

Several other commenters (OAR-2002-0056-2911, -3546, -3556) cited circumstances

leading to fuel switches that would be inequitable to the Utility Unit. One of these commenters

(OAR-2002-0056-3546) believed EPA should permit units that had a significant change in their

coal-type usage in connection with mine closures or environmental purposes to provide EPA with

that information before allocations are finalized so that EPA could use the adjustment factors that

more accurately reflect the coal actually being used at a unit.

The other commenters (OAR-2002-0056-2911, -3556) stated that allocations of

allowances based on the 1999 fuel blend would be detrimental to those units that have increased

the percentage of western fuel burned, as mercury from western coal is harder to remove,

therefore a larger allocation is necessary to prevent fuel bias. The commenter recommended that

more recent and representative data be used to allocate allowances. The commenter believed this

would ensure that allocations to the states, with units that have switched to western coal, would

be done in a manner that would not to create a competitive disadvantage due to an inappropriate

allocation of allowances.

One of these commenters (OAR-2002-0056-2911) included a graph showing the

substantial changes to fuel blends that have occurred since 1999 due to the lower cost and

compliance with the Acid Rain provisions of the Clean Air Act.

One commenter (OAR-2002-0056-3565) had seven units located at three different plants,

which burned bituminous coal in 1999 but switched to sub-bituminous coal in 2000, which they

continue to burn today. The commenter stated that these seven units should receive the higher

heat input allocation factor 1.25 for sub-bituminous units and not the 1.0 factor for bituminous

units. The commenter strongly urged EPA to use the year 2003, or even 2004, to determine

coal-type usage.

One commenter (OAR-2002-0056-2816) noted that EPA proposed to use 1999

Information Collection Request (ICR) data to determine the coal-type usage patterns of units

subject to regulation. The commenter stated that these data are important because they determine

the factors that will be used to adjust heat input based on coal type. The commenter submitted

that using 1999 data to determine coal usage patterns would result in incorrect information

regarding coal use by a majority of the commenter’s units, as well as the units of other companies

that switched from high sulfur bituminous coals to low sulfur sub-bituminous coal during and after

1999 in order to comply with requirements for reducing SO2 emissions for Phase II of the Title IV
cxxiii

Acid Rain Program. The commenter submitted that incorrect identification of the coals actually

being used by these units would result in significant penalty in allocating allowances to any such

unit. The commenter submitted that to more fairly and accurately represent the coal-type usage

pattern for such units, EPA should implement one of the following proposals:

• EPA should permit companies with units that had a significant change in their coal-type

usage during or after 1999 to provide that information to EPA before allocations are

finalized. EPA should revise its coal type usage data for those units and use the

adjustment factors that accurately reflect the coal actually being used at such units. EPA

could limit manipulation of the factors by restricting coal-type usage data to an annual

period before December 31, 2004; or

• Rather than using the ICR data to set allowance allocations, EPA should use the most

recent publicly available fuel data (2004) such as that provided to the Department of

Energy on Forms 423 or 906. These data specify the type of fuel used at each coal-fired

power generating facility on a current basis.

One commenter (OAR-2002-0056-2900) noted the proposed 2018 allowance allocations

are based on the coal burned at the affected units during the baseline period, which is the average

of the three years of highest heat input from 1998-2002. EPA proposed it would use this same

methodology to set 2010 allowance allocations. The commenter stated that subsequent to the

proposed baseline period of 1998-2002, many coal-fired EUSGUs have switched or are in the

process of switching from the use of bituminous coal to sub-bituminous coal to meet the

requirements of other programs. The commenter believed EPA must allow such units the option

of establishing a different baseline for allowance allocations. According to the commenter, failure

to do so would result in a highly inequitable system that severely penalizes units that recently have

switched to lower sulfur coal.

For units that switched or partially switched from bituminous to sub-bituminous coal

following the proposed baseline period of 1998-2002, the commenter urged EPA to consider an

adjustment when establishing the 2010 cap and to revise the proposed 2018 allocations. The

commenter suggested this could be accomplished by allowing units to choose an alternative

three-year baseline that encompasses the switch. For units that only partially switched to

sub-bituminous coals, the heat input could be proportioned to reflect the amount of

sub-bituminous and bituminous coal burned during the revised baseline period when any blending

occurred, similar to the MACT provision allowing mercury emissions to be weighted

proportionally by fuel type when blending.

The commenter understood that, if EPA establishes a cap in 2010, then the Phase I

allowance allocations would be included in the final rule. The commenter noted that this would

not allow units that have switched to sub-bituminous coal to select an alternative baseline period. 

Therefore, for Phase I, the commenter proposed that EPA deal with any additional allowance

allocations to alternative baseline units through the establishment of an allowance set-aside. For

Phase II, the commenter proposed that EPA revise the allowance allocations once units have

submitted their alternative baseline to EPA. The commenter further recommended that alternative
cxxiv

baseline units be required to use the lower heat input from the 1998-2002 time period or the

alternative baseline period. Specifically, units would demonstrate an alternative baseline for

purposes of determining the coal type on which their Phase II allowance allocations should be

based and their eligibility for the Phase I alternative baseline allowance set-aside. However, for

determining heat input, the commenter recommended the unit would be required to use the lower

of the baseline selected by EPA from the 1998-2002 time frame (EPA used the average of the

highest three years of heat input from the 1998-2002 time frame in determining the proposed

Phase II allowance allocations for the SNPR) or the alternative baseline. The commenter believed

this requirement would prevent units from gaming the system.

The commenter did not have a specific recommendation as to the size of the alternative

baseline allowance set-aside that would be appropriate for Phase I but believed that EPA could

readily determine this information by sending out a request and reopening the comment period on

this narrow issue to determine which units have switched to sub-bituminous coal or are in the

process of switching. The commenter submitted the responses would provide EPA with a

reasonable estimate of the amount of allowances needed for the set-aside.

Response:

EPA agrees with commenters that 1999 coal type is appropriate for the use as the basis

for the adjustment of the baseline for establishing plant mercury allocations. 1999 is the only

year for which EPA already has data for all the coal-fired power plants throughout the country,

is the year upon which the 48-ton electric utility mercury emissions estimate was based, and the

emissions EPA examine in developing its coal adjustment factors.

EPA is finalizing a formula to be used to develop budgets for each state and Tribes for

2010 and 2018. That formula is, in essence, the sum of the hypothetical allocations to each

affected Utility Unit in the State or Tribe, and that allocation, in turn, is based on the

proportionate share of their baseline heat input to total heat input of all affected units. For

purposes of this hypothetical allocation of the allowances, each unit’s baseline heat input is

adjusted to reflect the ranks of coal combusted by the unit during the baseline period. 

Commenters did not provide data that indicated how coal switching since 1999 would impact, if

at all, the state emissions budgets.

Under the model trading rule, EPA notes that States and Tribes have the authority to

allocate at the unit level and they can use a different baseline year for coal type used to

determine unit level allocations. 

Comment:

One commenter (OAR-2002-0056-3431, -3400) stated that upon review of Appendix B to

the Preamble (Unit Allocations) and EPA’s April 5, 2004 memorandum to the Docket titled

“Revisions to Unit Level Allocations and State Emissions Budgets for the Proposed Mercury

Trading Rulemaking” it appeared that the commenter’s Warrior Run allocation (21 ounces) was

incorrect and should be greater. (The commenter noted that Warrior Run was a 180 MW
cxxv

coal-fired power plant located in Maryland.) The commenter noted that in the April 5, 2004

memo, EPA stated that the figures in the spreadsheet that accompanied the memo would replace

the hypothetical unit allocations in Appendix B and the state emission budgets in the regulatory

text of the Supplemental Rulemaking. The commenter stated that if they are interpreting the

spreadsheet correctly, EPA’s spreadsheet showed zero (0) heat input for the plant trom 1998 to

2001 and 15,587,456 mmBtu in 2002. The correct heat input (mmBtu) at Warrior Run trom coal

was as follows:

1999 2000 2001 2002 2003

1,128,625 14,890,200 15,495,345 15,222,786 15,579,265

The commenter stated that start-up operations commenced in 1999, explaining the low

heat input for that year. The commenter believed that because EPA did not record any heat input

for 1999 to 2001, the baseline data that EPA used to calculate the commenter’s allocation was

probably incorrect. The commenter requested that EPA verify its heat input information for

Warrior Run and update the information and calculations used to calculate Warrior Run’s

allocations and Maryland’s state emissions budgets.

The commenter observed that as provided for in the Supplemental Notice of Proposed

Rulemaking, the other plants’ allowance allocations were based on their proportion of the total

state’s heat input. The commenter stated for example, the combined heat input for the three units

at Dickerson Station was approximately 11 percent of the total Maryland heat input, and the

station was allocated 647 allowances which was 11 percent of the total Maryland 2018 mercury

allocation. Based on the commenter’s heat input figures above, Warrior Run’s heat input was

approximately 5 percent of the total Maryland heat input and therefore the commenter should

receive roughly 5percent of the total Maryland budget, or approximately 296 allowances. The

commenter stated that however, the allocation for Warrior Run in the April 2004 memo was only

21 allowances–0.35 percent of the total Maryland budget instead of the 5percent that should have

been provided.

The allocation issue was of great concern to independent power producers (IPPs) such as

the commenter. The commenter stated that passing through increased costs to comply with new

environmental regulation in rates could rectify shortfalls in allowance allocations for power plants

owned by traditional utilities; however, IPPs would not have this luxury and must absorb such

increased costs against the plant’s bottom line.

Response:

EPA updated the heat input data for 1 plant based on commenter input. EPA data was

missing heat input for the AES Warrior Run plant in Maryland for the years 1998-2001. The

data submitted by the commenter is highlighted in the heat input data spreadsheet available in

the docket (see electronic spreadsheet file: Final CAMR Unit Hg Allocations.xls, which contains

the unit level allocations).
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5.6.4 Tribal Emission Budgets

Comment:

Several commenters (OAR-2002-0056-2010, -2118, -2380, -3413, -3469, -3549, -3550,

-3551) opposed cap and trade, but stated that if EPA adopts this approach the rule must make

provisions for tribal allowances.

One commenter (OAR-2002-0056-3469) stated that in the event a cap-and-trade program

is implemented by the EPA to reduce SO2, NOx or mercury, future tribal energy development

projects and existing power plants burning Indian country coal that has a higher sulfur content

than SPRB coal, i.e., more than 1.2lb SO2/mmBtu, will be allocated allowances (a) as ultimately

determined by EPA for NOx and mercury and (b) as currently scheduled under Title IV for SO2 or

otherwise under a separate CAIR program, depending on its structure. These new projects and

plants would be permitted to use these allowances according to the following formula:

• 1 allowance for 2 tons of SO2-effective immediately through 12/31/05

• 1 allowance for 3 tons of SO2-effective 1/1/06 forward

• 1 allowance for 2 tons of NOx-effective with CAIR implementation

• 1 allowance for 2 ounces of Mercury-effective with CAIR and Mercury Rule

implementation

The commenter noted that the SO2 formula above would only apply to noncompliance

coal (i.e. greater than 1.21b SO2/mmBtu). The commenter believed the accelerated schedules for

the SO2 formulae above are justified given that the mere announcement of the CAIR proposal is

having real and immediate impacts on the Title IV SO2 allowance market with real and current

impacts on Indian country coal. (Allowance prices have already increased by 80 percent largely

due to announcement of the proposal). The commenter submitted that granting these preferential

allowance ratios will have no negative impact on national emissions. SO2 emissions at plants

using Indian country coal will not increase emissions nationally as these plants are already

scrubbed and compliant with NSPS. The commenter also noted the SO2 ratio is based upon the

greater amount of sulfur content in Montana Indian country coal when compared to SPRB coal.

EPA intends to increase the market price of Title IV allowances by reducing available supply, thus

providing economic justification for power plants to retrofit emission control technology. The

commenter stated that by intertwining the CAIR with Title IV, the proposal would increase SO2

costs for all plants across the country, not just in the 29 states and D.C. The commenter believed

that volatility in the SO2 allowance market could drive changes in fuel choices at clean plants

using Indian coal, or could even cause plants to shut down, depriving the tribes of coal sales

royalty and tax revenues, employment, and other economic benefits they currently rely on to

sustain their nations.

Response:
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EPA has provided budgets to tribes in the final rule that have existing sources on their

land. Requirements for new tribal sources under CAMR are discussed in the preamble.

EPA understands and is sympathetic to the economic situation of the specific tribe’s

comments. EPA staff and officials have met with one of the commenters regarding their

concerns regarding the CAIR rulemaking, and considered the comments and proposals put forth

by the commenters. EPA’s analysis of the Crow tribe’s economic situation, and discussions with

the commenters, suggest that the Tribe should not experience adverse economic impacts as a

result of the NOx caps under CAIR. Rising SO2 prices, however, may lead to the erosion of the

competitive advantage currently held by coal from Absaloka mine, and could potentially force

the mine to shut down. However, the erosion of this competitive advantage is not a direct effect

of CAIR, as the price advantage held by Absaloka coal is likely to disappear under title IV alone. 

The EPA has determined that we can not implement the commenters recommendation for

the following reasons: The proposed Hg allowance retirement ratios would undermine both the

environmental certainty and economic stability of the cap-and-trade program. If EPA were to

allow power plants burning Indian country coal, and future tribal energy development projects

to retire allowances at a less than one to one ratio, the certainty of the cap level, and the

resulting knowledge of the value of an allowance would be jeopardized. This lack of certainty

about the cap is unacceptable for a cap and trade program, which function most successfully

when environmental and economic certainty have been established. 

Comment:

Several commenters (OAR-2002-0056-2380, -3413, -3457) noted that Tribal

organizations opposed cap and trade, but asked EPA to include these provisions. Commenter

OAR-2002-0056-2380 suggested: (1) Tribes should be included where they are omitted. 

(2) Restrict trading. EPA should set an appropriate ceiling for the number of credits any source

may hold and use at a given time. (3) Require a higher trading ratio for facilities with high

emissions to encourage sooner installation of controls. It should cost more to buy credits than to

not install controls. Commenter OAR-2002-0056-3457 recommended that any allowance system

forbid trading and require allowances to expire or be discounted over time.

Response:

In the final rule, EPA has established Hg emission budgets for tribes with existing

sources. Requirements for new tribal sources under CAMR are discussed in the preamble. EPA

believes that a cap-and-trade program for Hg will provide for an efficient means of achieving

the necessary level of emissions reductions. Allowing for trading maximizes the

cost-effectiveness of emissions reductions. Sources that can reduce emissions most cheaply will

do so, and sell any remaining allowances to sources that cannot. Sources have an incentive to

endeavor to reduce their emissions below their allowance allocation; if they can do so

cost-effectively, they may then sell their excess allowances on the market. In practice, the

sources that can reduce emissions cost-effectively under a cap-and-trade program are the

largest (and frequently high emitting) sources.
cxxviii

Comment:

Several commenters (OAR-2002-0056-2380, -3413) noted that the tribal authority rule

allows tribes to adopt parts of air programs without being subject to deadlines or other

requirements imposed on states. The commenters submitted the proposed rule should include a

mechanism for tribes to enter the cap-and-trade program if and when they want. At minimum,

tribes need allocations for plants already located on Indian land or planning to do so. The

commenters also submitted that in absence of adequate resources for a tribe to enter the program

(i.e., inability to develop and implement a tribal implementation plan), EPA should develop a

Federal Implementation Plan for them.

Response:

EPA has provided budgets to tribes in the final rule that have existing sources on their

land. The requirements of tribes under CAMR are discussed in the preamble.

Comment:

One commenter (OAR-2002-0056-3469) stated that if CAA provisions do not permit an

exemption for new plants in Indian country, the EPA should make available to developers or new

consumers of Indian country energy a pool of SO2, NOx and mercury allowances equal to

5 percent of all allocations at set prices. The commenter suggested that these prices would be

established as follows:

• 50 percent of the mercury price modeled by EPA;

• Average SO2 allowance price 2000-2003; and

• 50 percent of the NOx price modeled by EPA.

Response:

EPA has allocated allowances to States and tribes on the basis of heat input and coal

type. States have the authority to determine how to allocate allowances to sources within the

State. Allocations to States and tribes are discussed in section IV of the preamble. 

Comment:

Several commenters (OAR-2002-0056-1961, -3469) recommended that new Tribal plants

be exempted from the requirement to purchase allowances as long as they have NSPS Subpart Da

technology operational when they initiate operations and they adhere to monitoring and reporting

requirements, demonstrating continuous compliance. One commenter (OAR-2002-0056-3469)

submitted given that lignite units and the small number of new plants that could be built by the

Tribes will contribute a minute amount of mercury to the global pool, exempting new plants will

not materially affect any caps adopted by the EPA. One commenter (OAR-2002-0056-1961)
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added that if EPA does not exempt them, EPA should make an energy pool available for mercury

allowances equal to 5 percent of all allocations at set prices (50 percent of mercury prices

modeled by EPA). This will help tribes who have developed their coal reserves.

Response:

In the final CAMR, new sources will be covered under the Hg cap of the trading

program, and will be required to hold allowances equal to their emissions. EPA maintains that

is essential to include new sources under the cap to ensure that environmental goal of reducing

mercury emission is achieved. With new sources under the cap, the environmental goal

continues to be achieved despite future growth in the electric power sector, as older coal-fired

generation is retired and replaced new coal-fired generation. Requirements of new tribal

sources under CAMR are discussed in the preamble.

5.7 ALLOCATION METHODOLOGY

5.7.1 Allocation Mechanisms

Comment:

One commenter (OAR-2002-0056-2860) recommended that a parallel allowance

allocation methodology similar to that used under the IAQR should be used. The commenter

believed this would promote consistency among programs.

Response:

EPA agrees with commenter and has provided an example unit allocation methodology

for the Hg model trading rule as consistent as possible to the CAIR NOx allocation methodology.

Comment:

One commenter (OAR-2002-0056-1608) believed that in order to establish consistency

across the country, the EPA should develop the model trading rules in a way that maximizes

appeal to all of the states affected. The commenter however urged the EPA to assure that any

allocation methodology developed for mercury allowances under a trading program does not

penalize sources that are already achieving co-benefit reductions through the operations of

existing control equipment.

Response:

EPA believes its example allocation methodology should appeal to all states. EPA also

maintains that coal adjustment factors for existing units address commenters concerns with

regard to co-benefit reductions.

Comment:
cxxx

Several commenters (OAR-2002-0056-2830, -2835, -2915, -3440, -3469, -3478, -3546,

-4191, -4891) stated that allowances should be allocated only to affected EGUs. Four of the

commenters (OAR-2002-0056-2915, -3440, -3478, -4191) explicitly stated that mercury

allowances under the mercury rule should be allocated to coal-fired EGUs only.

Response:

The final CAMR requires reductions from coal-fired power plants and as such States can

only allocate to these affected units.

Comment:

One commenter (OAR-2002-0056-2180) stated that allowance allocations should be

periodically updated to reflect changes in capacity utilization (capacity factor), unit retirements,

commencement of operation of new units, and changes in coal rank. The commenter suggested

that an appropriate first update might be when Phase II of the cap comes into effect, with at least

a three-year lead time for beginning the updated allocation. Thereafter, allowances could be

allocated only for specific future periods, e.g. 5 to10 years.

Response:

Under its example allocation methodology, EPA has finalized for the model rule a

“modified output” approach. This example method involves input-based allocations for existing

coal units (with different ratios based on coal type), with updating to take into account new

generation on a modified-output basis. It also utilizes a new source set-aside for new units that

have not yet established baseline data to be used for updating.

Under the EPA example method, existing units as a group will not update their heat

input. This will eliminate the potential for a generation subsidy (and efficiency loss) as well as

any potential incentive for less efficient existing units to generate more. This methodology will

also be easier to implement because it will not require the updating of existing units’ baseline

data. Retired units will continue to receive allowances indefinitely, thereby creating an incentive

to retire less efficient units instead of continuing to operate them in order to maintain the

allowance allocations. Moreover, new units as a group will only update their heat input

numbers once–for the initial 5-year baseline period after they start operating. This will reduce

any potential generation subsidy and be easier to implement, because it will not require the

collection and processing of data needed for regular updating. See preamble for further

discussion of example methodology.

This methodology is offered simply as an example, and individual States retain full

latitude to make their own choices regarding what type of allocation method to adopt for Hg

allowances and are not bound in any way to adopt the EPA’s example.

Comment:
cxxxi

Several commenters (OAR-2002-0056-2862, -2911, -2922, -2948, -3546, -3556, -3565)

supported permanent mercury allowance allocations. One commenter (OAR-2002-0056-2948)

believed permanent allocations of mercury allowances would provide units with the greatest

amount of certainty, would provide units with an incentive to improve energy efficiency, and

would require fewer resources to administer than an updated allocation system. Several

commenters (OAR-2002-0056-2911, -3556) believed that such a system would provide units with

certainty regarding their allowances, facilitating planning for the implementation of controls and

turnover of the generating fleet - all of which would work towards the reduction of mercury

emissions while maintaining the reliability of the power supply and the integrity of the grid.

One commenter (OAR-2002-0056-2862) stated that a permanent allowance allocation

would provide certainty and aid in planning. The commenter added that a necessary part of a

permanent allocation scheme would be to include a new source set aside. The commenter

believed a permanent allocation approach coupled with a new source set aside would be less

complicated than EPA’s proposed updating approach and would provide units with the greatest

amount of certainty while providing a mechanism for new sources to receive allowances.

The commenter (OAR-2002-0056-2721) supported free distribution of allowances that

are permanently assigned to the affected unit. The commenter stated that allowing a periodically

(5 years in EPA example) allocation methodology that would incorporate new units would cause

uncertainty in planning for environmental compliance strategies. The commenter believed that

allowances should be issued on a heat-input basis using the established baseline.

Response:

As discussed in the final rule preamble, under its example allocation methodology, EPA

has finalized for the model rule a “modified output” approach. This example method involves

input-based allocations for existing coal units (with different ratios based on coal type), with

updating to take into account new generation on a modified-output basis. It also utilizes a new

source set-aside for new units that have not yet established baseline data to be used for

updating. EPA is offering States flexibility regarding allocation of allowances to sources. This

includes the flexibility to create new source set-asides and/or to issue allowances on a permanent

basis. As discussed in the preamble, EPA does not believe these flexibilities impact the total cost

or environmental benefits of the overall rule.

The commenter is also inconsistent in supporting a new source set-aside while

condemning programs that adjust allowance allocations periodically. A new source set-aside

(where unused allowances are returned to existing sources) effectively adjusts allocations

periodically.

Comment:

One commenter (OAR-2002-0056-2721) recommended that the allocations of allowances

are based on the baseline heat input.
cxxxii

Response:

As discussed in the final rule preamble, under its example allocation methodology, EPA

has finalized for the model rule a “modified output” approach. This example method involves

heat input-based allocations for existing coal units (with different ratios based on coal type),

with updating to take into account new generation on a modified-output basis. It also utilizes a

new source set-aside for new units that have not yet established baseline data to be used for

updating. EPA is offering States flexibility regarding allocation of allowances to sources.

Comment:

One commenter (OAR-2002-0056-2181) agreed with EPA that there are significant

benefits associated with an allocation method that allows for updating and felt that the rolling

annual updating system, determining allocation for a single control period six years in advance,

would be a reasonable time period (given the approximate amount of time required to permit and

construct a coal-fired power plant) and one that the commenter would encourage States to adopt. 

The commenter submitted however, that the updating approach has one major flaw in that the

initial allocation baseline does not change over time. This means that existing plants would

continue to receive allowances in future years, even if they are shut down. On the other hand,

new plants would receive allocations forever based on their initial years of operation, which could

be significantly less than their ultimate operating levels due to operation and competitive

limitations. The commenter believed strongly that an updating mechanism with responsive

adjustments that would reflect the actual operation both in the near term and future years is the

appropriate method that EPA should adopt.

Response:

Under the EPA example method, existing units as a group will not update their heat

input. This will eliminate the potential for a generation subsidy (and efficiency loss) as well as

any potential incentive for less efficient existing units to generate more. This methodology will

also be easier to implement because it will not require the updating of existing units’ baseline

data. Retired units will continue to receive allowances indefinitely, thereby creating an incentive

to retire less efficient units instead of continuing to operate them in order to maintain the

allowance allocations. Moreover, new units as a group will only update their heat input

numbers once–for the initial 5-year baseline period after they start operating. This will reduce

any potential generation subsidy and be easier to implement, because it will not require the

collection and processing of data needed for regular updating. See preamble for further

discussion of example methodology.

Comment:

One commenter (OAR-2002-0056-2547) supported EPA’s requirement that all states

adopt the “hypothetical” hybrid allowance allocation approach it describes in the preamble of the

Supplemental Rule. The commenter submitted that since many facilities are exploring the use of

Powder River Basin coals to meet reduced SO2 emission requirements of the proposed CAIR
cxxxiii

rule, the mercury allocation method should be structured so as not to disadvantage units that

switch to this higher mercury content fuel after promulgation of the mercury rule. The

commenter believed options to consider would be not using adjustment factors at all, or if a

facility switches fuels between the three listed fuel types–bituminous, sub-bituminous, and lignite,

that the facility notify the state agency requesting additional allowances be allocated (or forfeiting

allowances where appropriate) based upon the difference between the average heat inputs

calculated in 60.4142(a)(1)(i)(A-C) for the fuel type for which the allocations were initially

determined and for the new fuel type. The commenter stated this should be done in the spirit of

promoting multi-pollutant emission reduction, and to aid in achieving the goals of the CAIR.

Response:

As discussed in the final rule preamble under EPA’s example allocation methodology,

EPA is finalizing that if states want to have allocations reflect the difficulty of controlling Hg,

they might consider multiplying the baseline heat input data by ratios based on coal type, similar

to the methodology used to establish the State Hg budgets in today’s final rulemaking. In

today’s rulemaking for the purposes of establishing State budgets, EPA is using the coal

adjustment factors of 1.0 for bituminous coals, 1.25 for subbituminous coals and 3.0 for lignite

coals. In this example allocation methodology for States, EPA is also using these adjustment

factors. EPA is offering States flexibility regarding allocation of allowances to sources. This

includes the flexibility to not use coal adjustment factors.

Commenter:

The commenter (OAR-2002-0056-2181) believed that in its discussions of allowance

allocation methodology, the EPA argued, “allowance allocation decisions in a cap and trade

program largely reflect distributional issues, as economic forces would be expected to result in

economically efficient and environmentally similar outcomes.” The commenter disagreed with

this conclusion, and believed that allocation choices could have a significant impact on economic

and environmental outcomes. The commenter claimed that several studies supported this position

and discussed the potential economic “co-benefits” of an output allocation standard. For

example, a study by the Northeast-Midwest Institute concluded that an output-based allocation

standard could “advance an array of innovative technologies that would offer enormous potential

to improve efficiency and enhance the environment.” Likewise, a policy report by the Pew Center

for Climate Change concluded that an output-based allocation standard “could significantly affect

the ability of new, highly efficient generation technologies to enter the market.” Conversely, the

Report also concluded that input allocation would “put new investments in clean technologies at a

competitive disadvantage.”

The commenter noted that the allocation approach recommended by the EPA would be a

hybrid approach that would include some of the desirable components but would be lacking in

other areas. EPA first recommended that existing sources follow an input-based system with

different allocation ratios based on coal-type. Next, it recommended accommodating new sources

through updates to the allocation on a modified output basis, without differentiating between coal

types. The commenter welcomed the second approach that EPA selected for new sources as a
cxxxiv

step towards a full output-based allocation system. The commenter believed that output-based

allocation would be the appropriate method for all sources, new and existing. While the

commenter appreciated that the hybrid is an attempt to introduce a compromise approach, the

commenter believed the result would perpetuate a disturbing trend toward developing two sets of

environmental rules within the nation’s power sector - one for existing power sources and one for

new sources. Such a two tiered system not only would create inequities among competitors, it

would send market signals that may, in the long run, lead to unintended consequences to market

structures within the power sector such as favoring existing generators over new entrants and

regulated utilities over independent producers.

Several commenters (OAR-2002-0056-3437, -4139) recommended that allowances be set

based on energy output. Commenter OAR-2002-0056-3437 stated that would reward and

encourage efficiency. Similarly, Commenter OAR-2002-0056-4139 submitted an energy output

model would reward conservation and renewable energy sources and encourage cleaner

technology development.

Response:

As discussed in the final rule preamble, under its example allocation methodology, EPA

has finalized for the model rule a “modified output” approach. This example method involves

heat input-based allocations for existing coal units (with different ratios based on coal type),

with updating to take into account new generation on a modified-output basis. It also utilizes a

new source set-aside for new units that have not yet established baseline data to be used for

updating.

The EPA believes that allocating to existing units based on a baseline of historic heat

input data (rather than output data) is desirable, because accurate protocols currently exist for

monitoring this data and reporting it to EPA, and several years of certified data are available

for most of the affected sources. EPA expects that any problems with standardizing and

collecting output data, to the extent that they exist, can be resolved in time for their use for new

unit calculations. Given that units keep track of electricity output for commercial purposes, this

is not likely to be a significant problem.

EPA is giving States flexibility with regards to the allocations of the its Hg budgets to

sources. EPA notes that its example “modified output” allocations approach incorporates key

aspects of an output based updating system and provides incentives for efficient new units. 

Additionally, EPA reiterates that use of output based allocation methodologies, if not updated,

do not provide incentives for behavior or for new generation. They only provide a one-time

transfer amongst existing sources.

Comment:

One commenter (OAR-2002-0056-3443) stated that the model rule lays out a rational

program for periodic redistribution to individual sources. The commenter suggested that the

initial allocation period be extended from 5 to 8 years since that would align with the 2018 Phase
cxxxv

II compliance date. This would avoid an unnecessary reallocation prior to the 2018 Phase II

compliance date. The commenter noted that the model rule proposed that allocations after the

initial allocation period be on an annual basis using the original baseline heat inputs for existing

units. For new units, these allocations would be based on the average of the high three year heat

inputs (calculated from generation and an 8000 Btu/kwh heat rate). The commenter believed that

a proposal with an 8-year initial allocation would provide a sufficient planning horizon for

responding to changes in allocations. In the same vein, the commenter supported EPA’s proposal

to make allocations in perpetuity to retired units as it would provide owners an incentive to retire

higher-emitting sources, creating a multi-pollutant (SO2, NOx and Hg) reduction benefit.

Another commenter (OAR-2002-0056-3444) stated to ensure that companies are able to

recover investments made in control equipment and use of clean technologies, the commenter

believed the initial allocation of allowances should be fixed for the existing sources for the period

from 2010 until 2020. The commenter stated that the certainty associated with control equipment

and construction investment decisions rely on a source’s ability to realize anticipated allowance

excesses to generate revenue required for those investments. The commenter maintained that by

allocating on a 10-year basis EPA will maintain a minimal level of certainty in Utility Unit

investments and also provide a mechanism for mercury allowances to encourage new coal fired

Utility Unit entrants. The commenter believed that maintaining fuel flexibility is key to the

security and reliability of the electrical grid and national energy supply.

One commenter (OAR-2002-0056-4132) stated that EPA must provide allocations, which

align with the long-term nature of the emission control system investments. The commenter

submitted the strategic and financial planning process involved with the industry installing billions

of dollars of new pollution control equipment would be very complex. The commenter added that

forecasting the value of emission allowances (sale or purchase) would be difficult. The

commenter believed that if there is no certainty in the number of allowances provided in later

years, the economic analysis for such projects becomes speculative.

The commenter strongly encouraged that EPA allocate mercury emission allowances for a

time period that would align with the economic considerations of the air pollution control

equipment required for this air quality improvement. The commenter submitted a perpetual

allocation consistent with the current Clean Air Act SO2 allocation would be appropriate and

necessary for utilities to determine the proper investment strategy. The commenter also submitted

that early reduction credits should be awarded and could be allocated for a lesser time period. 

The commenter also believed the cap and trade system should not be subject to flow control. The

commenter stated flow control would greatly reduce incentives for early reductions and hinder

economic analysis.

Response:

As discussed in the final rule preamble, under its example allocation methodology, EPA

has finalized for the model rule a “modified output” approach. Under the example method,

allocations are made from the State’s Hg budget for the first five control periods (2010 through

2014) of the model cap-and-trade program for existing sources on the basis of historic baseline
cxxxvi

heat input. The allowances for 2015 and later will be allocated from the State’s Hg budget

annually, six years in advance, taking into account output data from new units with established

baselines (modified by the heat input conversion factor to yield heat input numbers). EPA

believes this 5 year period provides enough certainty and planning time horizon.

Comment:

One commenter (OAR-2002-0056-2267) noted that EPA discussed whether allocations

should be based on baseline heat input or baseline generating output under the cap-and-trade

approach. 69 FR 12408. The commenter objected to a strict output-based allocation method. 

The commenter submitted that the smaller boilers and generators owned and operated by

municipalities generally are less efficient in terms of energy output per heat input than the large

boilers and generators operated by the large utilities. The commenter believed municipal power

generators would be placed at an additional competitive disadvantage by the budgets being set on

this basis. Adding this to the disadvantage of a smaller customer base over which to spread the

emission control costs, municipal power generators would face multiple competitive

disadvantages relative to large electric utilities.

Ensuring that new units have fair access to allowances was a concern for the commenter

(OAR-2002-0056-2068). In concert with the EPA’s “example methodology,” the commenter

suggested allocations be determined according to the baseline heat input of affected units. As

outlined in the Supplemental Notice, initial allocations for existing sources should be made for the

first five control periods at the start of the program on the basis of heat input and take into

consideration coal type. After the first five years, the budget should be distributed on an annual

basis, taking into account data from new units. The baseline heat input for units should be

determined by averaging the three highest heat input years out of a five-year period, and

allowances should be reallocated after each subsequent five-year period.

Response:

As discussed in the final rule preamble, under its example allocation methodology, EPA

has finalized for the model rule a “modified output” approach. This example method involves

heat input-based allocations for existing coal units (with different ratios based on coal type),

with updating to take into account new generation on a modified-output basis. It also utilizes a

new source set-aside for new units that have not yet established baseline data to be used for

updating. 

Comment:

One commenter (OAR-2002-0056-2862) stated that allocations to retired units should be

permanent. The commenter noted that EPA’s definition of the baseline for calculating cap and

trade emission allowances does not address the issue of how to treat units retired since the

1998-2002 proposed baseline period (69 FR 4703 and proposed 40 CFR 60.4105 of the SNPR).

The commenter submitted that treatment of retired units is, however, very important. The

commenter’s position was that units retired since the baseline period should receive budget
cxxxvii

allowances. The commenter believed if allocations were not made to retired units, the rule

effectively would discourage utility system modernization and penalize environmental

improvement efforts.

The commenter stated ideally, EPA’s rules should provide incentives for utilities to retire

existing coal-fired generating plants and replace them with plants that are more efficient and

equipped with state-of-the-art environmental controls. At a minimum, utilities that retire units

that were operating during the baseline period should not be penalized. The commenter explained

this means that owners should be allowed to hold allowances for retired units that were operating

during the baseline period, and be able to apply those allowances as eligible emission currency in

the cap-and-trade program. The commenter concluded that a permanent allocation system would

ensure that retired units retain their allowances.

One commenter (OAR-2002-0056-4139) stated that future allocations should be set at

less than the shutdown facility if that facility is replaced. The replacement facility should meet a

new source limit to emit less mercury than the shutdown plant it replaced. The commenter

submitted that if permitting and construction is not begun in a specified reasonable time, there

should be a decrease over time in the allocation for the shut down declining to zero. The

commenter added the overall state budget should also be decreased as described.

Response:

As discussed in the final rule preamble, under its example allocation methodology, EPA

is finalizing January 1, 2001 as the cut-off on-line date for considering units as existing units.

Under the EPA example method, existing units as a group will not update their heat input. This

will eliminate the potential for a generation subsidy (and efficiency loss) as well as any potential

incentive for less efficient existing units to generate more. This methodology will also be easier

to implement because it will not require the updating of existing units’ baseline data. Retired

units will continue to receive allowances indefinitely, thereby creating an incentive to retire less

efficient units instead of continuing to operate them in order to maintain the allowance

allocations.

Comment:

One commenter (OAR-2002-0056-2519) encouraged EPA to incorporate a provision to

update allowance allocations to reflect changes in electricity generation. The commenter offered

for example, the West is one of the fastest growing regions of the country, and the increasing

population growth will mean increased electricity demand. In order to keep coal as a viable

option for such new generation, the allowance allocation should be updated periodically to match

increases and shifts in power generation at existing sources and new sources. Toward that end

the commenter recommended that the allowance allocation should be updated every five years.

Response:
cxxxviii

As discussed in the final rule preamble, under its example allocation methodology, EPA

has finalized for the model rule a “modified output” approach. This example method involves

heat input-based allocations for existing coal units (with different ratios based on coal type),

with updating to take into account new generation on a modified-output basis. It also utilizes a

new source set-aside for new units that have not yet established baseline data to be used for

updating.

Comment:

One commenter (OAR-2002-0056-2267) requested that EPA make a change to the rule to

allocate additional allowances to the entities in recognition of the their foresight and progressive

in investment in hydroelectric power (or other green power) when cheaper energy choices could

have been made. As it stood, the commenter’s municipality ultimately would be penalized, rather

than rewarded, for its early focus on reducing emissions from its power generation system. To

address this situation, the commenter requested that the budget allocation be based on potential or

projected heat input rate for entities such as the commenters. By granting this request, EPA

would ensure that the commenter’s and other similar entities have enough allowances to provide

reliable power generation at an affordable price. As an alternative solution, the commenter

requested that EPA provide in its model trading program rules for the use of a different time

period to calculate baseline heat input for situations described above. The commenter cited

precedence under the Clean Air Act for substitution of baseline data when a baseline period is not

representative of normal source operation. See 40 CFR 52.21(21)(ii) (NSR rules). The

commenter stated EPA has recognized that it should have discretion to allow the use of a different

time period upon a determination that it is more representative of normal source operation. The

commenter recommended that EPA should exercise similar discretion in this case.

Response:

State are required to achieve the mercury reduction requirements by reducing Hg

emissions from coal-fired power plants. States are welcome to use set-asides (size determined by

the State) for new units and any special policy objectives - such as promoting energy efficiency

or renewables. The States, rather than this regulation can decide the best way to incorporate

renewable incentives.

5.7.2 Baseline Period for Allocations

Comment:

One commenter (OAR-2002-0056-3478) supported the use of the average of the highest

three-year heat inputs achieved during the five-year period of 1998 to 2002 as the baseline for

establishing plant mercury allocations.

Several commenters (OAR-2002-0056-2867, -2922, -2948, -3437, -3565) noted the

proposed calculation of the baseline heat input by “using the average of the three highest heat

inputs of the period 1998 to 2002" and suggested using a more current period. Two of the
cxxxix

commenters (OAR-2002-0056-2922, -2948) suggested using the average of the three highest heat

inputs of the period 1999 to 2003. These commenters believed this approach would use a period

that would be closer in time to the commencement of the trading program under EPA’s proposal

and still would avoid opportunities to affect the baseline through prospective actions. One of the

commenters (OAR-2002-0056-3565) strongly urged EPA to use the average of the three highest

heat inputs of the period 1998 to 2002.

One commenter (OAR-2002-0056-2867) recommended that EPA consider using the

average heat-input of the highest of three years from the period which begins six years prior to the

implementation of the cap (2004 if the cap takes effect in 2010 as proposed or 2009 if the cap

takes effect in 2015 under the commenter’s recommended program) to account for growth in

electricity demand, changes in the generation fleet, the inherent variability in heat input levels for

individual units, and for weather and demand induced variability.

One commenter (OAR-2002-0056-3437) noted that EPA did not mention updating the

baseline heat input based on more recent years of operation. The commenter stated that the rule

would use the same baseline throughout time. The commenter believed this would help in having

to track annual operating data, but it was not clear to the commenter if this would increase or

decrease a unit’s allowances if the heat input data was update. The commenter noted EPA says

this is preferable because it would eliminate a potential generation subsidy and an incentive for

less efficient generation. The commenter stated that EPA should use an output based emission

rate to address efficient generation and a system that would use updated heat input to more

accurately reflect industry changes.

Response:

For existing units under the model trading rule, EPA is using the average of the highest

three-year heat inputs achieved during the five-year period of 2000 to 2004 as the baseline for

establishing plant mercury allocations. EPA proposed January 1, 2001, cut-off on-line date for

considering units as existing units. The cut-off on-line date was selected so that any unit meeting

the cut-off date would have at least five years of operating data, i.e., data for 2000 through

2004. EPA is concerned with ensuring that particular units are not disadvantaged in their

allocations by having insufficient operating data on which to base the allocations. EPA believes

that a 5-year window, starting from commencement of operation, gives units adequate time to

collect sufficient data to provide a fair assessment of their operations.

As discussed in the final rule preamble, under its example allocation methodology, EPA

has finalized for the model rule a “modified output” approach. This example method involves

heat input-based allocations for existing coal units (with different ratios based on coal type),

with updating to take into account new generation on a modified-output basis. It also utilizes a

new source set-aside for new units that have not yet established baseline data to be used for

updating.

The EPA believes that allocating to existing units based on a baseline of historic heat

input data (rather than output data) is desirable, because accurate protocols currently exist for
cxl

monitoring this data and reporting it to EPA, and several years of certified data are available

for most of the affected sources. Under the EPA example method, existing units as a group will

not update their heat input. This will eliminate the potential for a generation subsidy (and

efficiency loss) as well as any potential incentive for less efficient existing units to generate

more. This methodology will also be easier to implement because it will not require the updating

of existing units’ baseline data. Retired units will continue to receive allowances indefinitely,

thereby creating an incentive to retire less efficient units instead of continuing to operate them in

order to maintain the allowance allocations.

Comment:

One commenter (OAR-2002-0056-2267) requested that EPA provide in its model trading

program rules for the use of a different time period to calculate baseline heat input for situations

where to allocate additional allowances to the entities in recognition of their foresight and

progressive investment in hydroelectric power (or other green power) such as Boiler #9. The

commenter stated there is precedence under the Clean Air Act for substitution of baseline data

when a baseline period is not representative of normal source operation. See 40 CFR 2.21(21)(ii)

(NSR rules). The commenter noted that EPA has recognized that it should have discretion to

allow the use of a different time period upon a determination that it is more representative of

normal source operation. The commenter urged that EPA should exercise similar discretion in

this case.

Response:

For existing units under the model trading rule, EPA is using the average of the highest

three-year heat inputs achieved during the five-year period of 2000 to 2004 as the baseline for

establishing plant mercury allocations. EPA proposed January 1, 2001, cut-off on-line date for

considering units as existing units. The cut-off on-line date was selected so that any unit meeting

the cut-off date would have at least five years of operating data, i.e., data for 2000 through

2004. EPA is concerned with ensuring that particular units are not disadvantaged in their

allocations by having insufficient operating data on which to base the allocations. EPA believes

that a 5-year window, starting from commencement of operation, gives units adequate time to

collect sufficient data to provide a fair assessment of their operations.

States are required to achieve the mercury reduction requirements by reducing Hg

emissions from coal-fired power plants. States are welcome to use set-asides (size determined by

the State) for new units and any special policy objectives–such as promoting energy efficiency or

renewables. The States, rather than this regulation can decide the best way to incorporate

renewable incentives.

Comment:

One commenter (OAR-2002-0056-2918) understood that in the event that EGUs, burning

a mixture of coal ranks, the MACT compliance limit will be adjusted based on pro-rata heat input

calculation of each of the coal ranks in the mix of coal burned. Consistent with such an
cxli

adjustment, the commenter recommended that EPA adopt a provision making each EGU

responsible for obtaining periodic ASTM laboratory test data on coal burned by the EGU for each

compliance period.

Similarly, if EPA adopts a cap and trade program, the commenter recommended that EGU

owners be provided an opportunity to submit more recent coal rank data obtained by ASTM

laboratory test methods for the coal burned during a time period that reflects more contemporary

usage. The commenter stated that such coal rank data should be used by EPA in allocating Hg

emission trading credits for the future year period(s) designated in the proposed cap and trade

rule.

Whether EPA adopts Hg MACT emissions limits, or alternatively a Hg cap and trade

program, the commenter stated that their recommendation will provide EGU owners the

opportunity to adjust their Hg compliance requirements based on current coals burned. The

commenter noted that coal fired EGUs do change coal suppliers and coal ranks over time because

of changing market conditions and regulatory requirements. As such the commenter believed their

proposal would add additional equity to EPA’s Hg compliance requirements for EGUs.

Response:

As discussed in the final rule preamble, under its example allocation methodology, EPA

has finalized for the model rule a “modified output” approach. This example method involves

heat input-based allocations for existing coal units (with different ratios based on coal type),

with updating to take into account new generation on a modified-output basis. It also utilizes a

new source set-aside for new units that have not yet established baseline data to be used for

updating.

For existing units under the model trading rule, EPA is using the average of the highest

three-year heat inputs achieved during the five-year period of 2000 to 2004 as the baseline for

establishing plant mercury allocations. EPA proposed January 1, 2001, cut-off on-line date for

considering units as existing units. The cut-off on-line date was selected so that any unit meeting

the cut-off date would have at least five years of operating data, i.e., data for 2000 through

2004. EPA is concerned with ensuring that particular units are not disadvantaged in their

allocations by having insufficient operating data on which to base the allocations. EPA believes

that a 5-year window, starting from commencement of operation, gives units adequate time to

collect sufficient data to provide a fair assessment of their operations.

The EPA believes that allocating to existing units based on a baseline of historic heat

input data (rather than output data) is desirable, because accurate protocols currently exist for

monitoring this data and reporting it to EPA, and several years of certified data are available

for most of the affected sources. Under the EPA example method, existing units as a group will

not update their heat input. This will eliminate the potential for a generation subsidy (and

efficiency loss) as well as any potential incentive for less efficient existing units to generate

more. This methodology will also be easier to implement because it will not require the updating

of existing units’ baseline data.
cxlii

5.7.3 New Units

Comment:

One commenter (OAR-2002-0056-3437) did not support EPA’s proposed alternative of

using the lower of the NSPS for the different coal types or a rate based on the proposed 2018 cap

rather than using a single emission rate for new units. The commenter stated that while this

approach may address the differences between coal types and new and existing units, the

commenter would still be concerned that using different information based on coal type could lead

to fuel switching and the possibility of not achieving the desired reductions.

One commenter (OAR-2002-0056-3543) understood that new sources would be required

to hold allowances equivalent to the product of their NSPS and baseline heat input. The

commenter stated however, EPA is unclear what will be proposed as the baseline for new sources.

One commenter (OAR-2002-0056-3543) found the proposal unclear regarding how new

sources would be treated under a cap and trade approach. The commenter noted new sources

would be required to comply with the NSPS for mercury and be required to hold allowances. The

commenter asked would new sources be given an allocation or is this up to the discretion of the

states?

Response:

As discussed in the final rule preamble, under its example allocation methodology, EPA

is finalizing the approach that new units will begin receiving allowances from the set-aside for

the control period immediately following the control period in which the new unit commences

commercial operation, based on the unit’s emissions for the preceding control period. Thus, a

source will be required to hold allowances during its start-up year, but will not receive an

allocation for that year. States will allocate allowances from the set-aside to all new units in any

given year as a group. If there are more allowances requested than in the set-aside, allowances

will be distributed on a pro-rata basis. Allowance allocations for a given new unit in following

years will continue to be based on the prior year’s emissions until the new unit establishes a

baseline, is treated as an existing unit, and is allocated allowances through the State’s updating

process. This will enable new units to have a good sense of the amount of allowances they will

likely receive - in proportion to their emissions for the previous year. This methodology will not

provide allowances to a unit in its first year of operation; however it is a methodology that is

straightforward, reasonable to implement, and predictable.

Although EPA is offering an example allocation method with accompanying regulatory

language, EPA reiterates that it recognizes States’ flexibility in choosing their Hg allocations

method.

Comment:
cxliii

Many commenters (OAR-2002-0056-2067, -2422, -2818, -2911, -2915, -2922, -3198,

-3443, -3444, -3514, -3519) believed that the cap-and-trade program should have a set aside for

new sources. Several of these commenters (OAR-2002-0056-2818, -2911, -2915, -3198) noted

that a modest set aside would be consistent with the Acid Rain Program.

Several commenters (OAR-2002-0056-2818, -3198) submitted that this will ensure that

new units operating in compliance with the NSPS will have legitimate access to allowances. One

commenter (OAR-2002-0056-2915) stated that new unit development is critical to the continued

use and development of Gulf Coast lignite for electric generation in Texas.

Commenter OAR-2002-0056-2911 suggested that once the size of the permanent

allocation pool is determined, a small percentage of those allocations, 2 percent for example, can

be set aside for new units each year. The commenter further suggested that any unused

allocations would be returned to the pool for the other affected units. According to the

commenter, similar concepts have been successfully incorporated into the trading program used

for the NOx SIP Call.

Several commenters (OAR-2002-0056-3443, -3519) submitted that the model rule

proposal for a two percent new source set-aside was reasonable. One commenter

(OAR-2002-0056-3443) believed this would be sufficient to prevent any inhibition to entry of

new units in the market. The commenter asserted that redistribution of unused allowances from

the set-aside to existing units is a critical piece of this proposal. The commenter believed the

model rule should require that this redistribution be completed in time for existing sources to use

them in the same budget year.

One commenter (OAR-2002-0056-3519) believed that new units should be defined as

EGUs starting operation after the date of final rule adoption. One commenter

(OAR-2002-0056-2922) stated that if EPA chooses a “cap-and-trade” program, it must ensure

that new facilities have reasonable access to mercury emission allowances.

Similarly, one commenter (OAR-2002-0056-2067) stated that the proposed Cap and

Trade alternative must give economic access to allocations to new power plants to allow for

effective planning for construction of new units to meet growth and to replace retiring units. The

commenter asserted that the Cap and Trade mechanism should not create obstacles to retiring

older units or to adding new generation to ensure adequate security and reliability.

One commenter (OAR-2002-0056-3444) stated the cap and trade program should provide

new unit set asides for new units operating prior to 2010.

One commenter (OAR-2002-0056-2725) stated that the West is one of the fastest

growing regions in the country, and new coal plants are vital to affordable energy prices in the

future and will be essential to continued growth in the economy. The commenter noted the

DOE’s Energy Information Administration projects a significant increase in construction of new

coal-based power plants; the DOE/EIA Annual Energy Outlook 2004 with projections to 2025

forecasts the addition of 112 Gigawatts of new coal generating capacity. According to the
cxliv

commenter, if these new plants were to be prevented from being constructed because of new

mercury regulations, the only alternative for this needed capacity would be natural gas. The

commenter stated that due to physical and regulatory constraints, the supply of natural gas is not

able to affordably meet its demand.

Over the next several years, the commenter expected several new, clean coal units to

come on line in the West, and submitted that EPA should not burden these new units with overly

stringent emission control requirements. Thus, the commenter supported adopting the allocation

of mercury allowances for new units under the trading approach consistent with Senator Inhofe’s

approach to Clear Skies.

Many commenters (OAR-2002-0056-2042, -2375, -2422, -2519, -2862, -2907, -2815,

-2922, -3440, -3478, -3556, -3565, -4191, -4891) stated there should be a modest mercury

allowance set-aside for new units. Many of the commenters (OAR-2002-0056-2375, -2422,

-2519, -2915, -3440, -3478, -3556, -3565, -4191, -4891) suggested the new unit set aside should

be consistent with the 2 percent set aside for new facilities in Title IV Acid Rain Program. 

Several commenters (OAR-2002-0056-2915, -3440, -3478, -4191) believed new unit

development would be critical to the continued use and development of lignite for electric

generation in Texas. One commenter (OAR-2002-0056-3556)stated that any unused allocations

would be returned to the pool for the other affected units. The commenter also stated that similar

concepts have been successfully incorporated into the trading program used for the NOx SIP Call. 

Similarly, a second commenter (OAR-2002-0056-2375) suggested the unused portion of the set

aside should be returned to existing sources on a pro rata basis. One commenter

(OAR-2002-0056-2907) stated that as we enter a new era where demand is beginning to exceed

supply, new generation becomes essential. The commenter added, new coal generation is cleaner

and more efficient than existing plants. The commenter believed that EPA should use an approach

similar to that used in the Clear Skies Act to allocate mercury allowances to new units under a

mercury cap and trade program. One commenter (OAR-2002-0056-3565) believed that new

units should also be able to acquire mercury allowances from the allowance market.

One commenter (OAR-2002-0056-2422) noted that under a cap-and-trade approach, EPA

has proposed NSPS emission limits equivalent to the NSPS proposed under the 112(d)

regulations. The commenter believed the limit was set at a level that could not be achieved by the

best performing units, and should be adjusted upward. The commenter was concerned that a

cap-and-trade program would add another significant burden to new units if they are not allocated

emission allowances. New units would be left to pursue allowances on the open market, with no

guarantee of access. The commenter stated that EPA should reconsider how it will ensure that

new units operating in compliance with the NSPS will have legitimate access to allowances. The

commenter suggested that this could be achieved, for example, by requiring a modest set-aside of

allowances from existing units, similar to the approach taken in the Title IV acid rain program.

One commenter (OAR-2002-0056-4891) stated that as proposed, the mercury rule would

discourage the development of new power plants given that it would require new sources to

procure allowances from the same pool of allowances applicable to existing sources. The

commenter submitted that jeopardizing the ability to develop new power plants would ultimately
cxlv

put an untenable strain on the ability to meet the ever-increasing demand for affordable electricity

in Texas and throughout the U.S. The commenter believed that to avoid this clearly undesirable

result and ensure the continued development of new plants, new power plants should either be

exempted from the requirement to obtain allowances, or be provided an allowance set-aside

specifically for new units comparable to the 2 percent set-aside for new facilities in the Title IV,

Acid Rain Program.

One commenter (OAR-2002-0056-4891) submitted that only existing facilities subject to

the mercury rule should receive allowances. The commenter noted that as proposed, the mercury

rule would discourage the development of new power plants given that it would require new

sources to procure allowances. Jeopardizing the ability to develop new power plants would

ultimately put an untenable strain on the ability to meet the ever-increasing demand for affordable

electricity in Texas and throughout the U.S. To avoid this clearly undesirable result and ensure

the continued development of new plants, the commenter stated new power plants should be

exempted from the requirement to obtain allowances.

One commenter (OAR-2002-0056-2243) was concerned with how allowance programs

are being developed. According to the commenter, when new projects were primarily gas-fired,

the availability of an adequate allowance pool for new sources was not as important as it is today.

The commenter pointed out that as coal-fired projects are conceived, the availability of access

into the allowance market is critical. The commenter added that encouraging new project

development is vital from both an economic and environmental point of view.

Response:

As discussed in the final rule preamble, the example allocation methodology includes a

new source set-aside equal to 5 percent of the State’s emission budget for the years 2010 to 2014

and 3 percent of the State’s emission budget for the subsequent years. This is a change from the

SNPR were EPA proposed a level 2 percent set aside for all years.

One commenter pointed to EIA forecasts for coal to grow by 112 gigawatts (GW) by

2025 and EPA economic modeling projects growth in coal by 2020. In order to estimate the

need for allocations for new units, EPA considered projected growth in coal generation and the

resulting Hg emissions portion of the Hg national cap. EPA believes the final new source

set-aside provides for that growth.

Because States have flexibility in choosing their Hg allocations method, individual States

using a version of the example method may want to adjust this initial five year set-aside amount

to a number higher or lower than 5 percent to the extent that they expect to have more or less

new generation going on-line during the 2001 to 2013 period. They may also want to adjust the

subsequent set-aside amount to a number higher or lower than 2 percent to the extent that they

expect more or less new generation going on-line after 2004. States may also want to set this

percentage a little higher than the expected need, because, in the event that the amount of the

set-aside exceeds the need for new unit allowances, the State may want to provide that any
cxlvi

unused set-aside allowances will be redistributed to existing units in proportion to their existing

allocations.

Comment:

One commenter (OAR-2002-0056-2830) believed the heat rate conversion factor of

8,000 Btu/kWh was too low for Fort Union lignite fired EGUs. The commenter stated that heat

rates for units utilizing Fort Union lignite have improved over time. According to the commenter,

the recent historical heat rate for existing Fort Union lignite-fired boilers is just under 11,000

Btu/gross kWhr. The commenter recommended that a heat rate conversion factor of 9,700

Btu/gross MWhr be employed for new lignite-fired units (69 FR 12409).

One commenter (OAR-2002-0056-2841) stated that the rule should not discourage new

coal units. The commenter noted that new units undergoing permitting and/or under construction

would not have the ability to establish a baseline heat input until going into commercial operation. 

The commenter also noted EPA has proposed an alternative to address the issue of no baseline by

suggesting that the updated allocation for such units be adjusted by calculating the heat input for

such units by multiplying the unit’s output by a heat rate conversion factor of 8000 btu/kWh. 

EPA suggested that the 8000 btu/kWh rate represents a midpoint between expected heat rates for

new pulverized coal plants and new integrated gasification combined cycle (IGCC) coal plants. 

The stated purpose for such an approach is to create level benefits for new units based on their

output and encouraging efficiency. In principle, the commenter agreed with the approach selected

by EPA to address units that will not have an established baseline. However, the commenter

believed the selected conversion rate of 8000 btu/kWh rate cannot be supported and would

unduly penalize new units.

The commenter stated the range of heat rates for IGCC units can be anywhere from

8400 btu/kWh to 9500 btu/kWh. Accordingly, the commenter did not believe the midpoint

between IGCC and supercritical was appropriately established at 8000 btu/kWh. Given the

current state of IGCC technology and the range of heat rates, the commenter did not believe that

EPA should try to establish any presumed incentive for IGCC. Instead, EPA should only utilize a

rate that provides incentive to proven technology such as construction of a supercritical

pulverized coal boiler that can be supported by Public Utility Commissions. The commenter

recommended a conversion factor of 8900 btu/kWh that would provide the incentive to build

supercritical units, while not penalizing companies through the utilization of an unrealistic and

unsupportable conversion factor. Similarly, the commenter believed the conversion factor should

not have the unintended consequence of encouraging the further utilization of natural gas for the

production of electricity.

Similarly, one commenter submitted that the model rule’s use of an 8000 Btu/kWh

assumed heat rate for calculating allowance allocations appeared to be a mistake. The cmmenter

noted that the model rule states that 8000 Btu/kWh represents the “mid-point” between the heat

rate expected of new conventional coal and IGCC units. However, in the supplemental CAIR the

same 8000 Btu/kWh is used as the “mid-point between gas fired combined cycle units and

conventional coal units. The commenter agreed the 8000 Btu/kWh mid-point is reasonable for
cxlvii

CAIR. However, the commenter pointed out that existing IGCC units have heat rates in the mid

8000s and conventional coal units have heat rates in the mid to lower 9000s. Consequently, the

commenter believed 9000 Btu/kWh is the more appropriate mid-point for the mercury model rule.

The commenter also had concerns about using the midpoint approach at all since it would

clearly favor IGCC technology over conventional coal technology. The commenter encouraged

EPA to consider a separate heat rate for IGCC and conventional coal units. The commenter

pointed out that the DOE clean coal roadmap goals for 2010 indicate that 9000 Btu/kWh for

conventional coal and 8000 Btu/kWh for IGCC would be reasonable heat rates.

The commenter (OAR-2002-0056-2721) submitted that the new unit mercury allocation

utilizing the modified heat output basis again places low rank fuels at a distinct disadvantage. The

commenter noted that the modified heat output based procedure would take the three highest of

the first five years of gross output and multiply it by a conversion factor of 8,000 btu/kWH. The

commenter stated that this would place a plant efficiency incentive on new units so that the low

rank coals would be unfairly punished. The commenter noted that EPA is requesting comment

on the appropriateness of 8,000 btu/kWH. The commenter strongly encouraged EPA to establish

a subcategory for heat rate conversion factor for low rank coals nearer 9,700 btu/kWH.

One commenter (OAR-2002-0056-2834) believed the proposed heat rate conversion

factor of 8,000 Btu/kWh is to low for Fort Union lignite-fired EGUs. The commenter stated that

heat rates for units utilizing Fort Union lignite have improved over time. According to the

commenter the recent historical heat rate for existing Fort Union lignite-fired boilers is just under

11,000 Btu/gross kWh.

Response:

As discussed in the final rule preamble, under the example allocation methodology,

allowances will be allocated to new units with an appropriate baseline on a “modified output”

basis. The new unit’s modified output will be calculated by multiplying its gross output by a heat

rate conversion factor of 8,000 Btu per kilowatt-hour (Btu/kWh). The 8,000 Btu/kWh value for

the conversion factor is an average of heat-rates for new pulverized coal plants and new IGCC

coal plants (based upon assumptions in EPA’s economic modeling analysis). See documentation

for the Integrated Planning Model (IPM) at http://www.epa.gov/airmarkets/epa-ipm). A single

conversion rate will create consistent and level incentives for efficient generation, rather than

favoring new units with higher heat rates.

EPA maintains that providing each new source an equal amount of allowances per MWh

of output is an equitable approach. Because electricity output is the ultimate product being

produced by electric generating unit, a single conversion factor based on output ensures that all

sources will be treated equally. Higher conversion factors for less efficient technologies will

effectively provide greater amounts of allowances (and thus a greater subsidy) to such less

efficient units for each MWh they generate. This will serve to provide greater relative incentives

to build new less efficient technologies rather than efficient technology. It should also be noted
cxlviii

that, since all allocations are proportionally reduced after a new source is integrated into the

market, higher conversion factors also lower allocations to existing sources.

Comment:

One commenter (OAR-2002-0056-3437) submitted that if EPA decides to include a new

source set aside, states should be in charge of managing it and should be able to use some of it to

encourage energy efficiency. The commenter felt it would be more equitable to use a

methodology that allows all new units to receive some allowances to reduce the amount that may

need to be purchased. The commenter believed this is especially important if sources are allowed

to request up to 5 years of allowances. The commenter suggested that one option would be to

increase the discount factor (0.90) to 0.80 or 0.75 or more. The commenter noted it is difficult to

estimate the actual number of new units and the amount of allowances needed, but this is

somewhat resolved by redistributing unallocated allowances back to existing units.

Regarding the allocation methodology, one commenter (OAR-2002-0056-3437) noted

that EPA did not provide any basis for a discount factor of 0.90 to arrive at a final allocation.

One commenter (OAR-2002-0056-3437) commented on EPA’s proposed alternative where new

units would simply apply at the end of the year for allowances based on actual emissions. The

commenter submitted that this is not a good alternative because sources would be uncertain about

the actual amount of emissions and available allowances. The commenter believed that this could

lead to a flurry of activity to try and buy allowances in a short time or risk noncompliance.

Response:

The example allocation methodology for the final rule does include these discount

factors. As discussed in the final rule preamble, under its example allocation methodology, EPA

is finalizing the approach that new units will begin receiving allowances from the set-aside for

the control period immediately following the control period in which the new unit commences

commercial operation, based on the unit’s emissions for the preceding control period. Thus, a

source will be required to hold allowances during its start-up year, but will not receive an

allocation for that year. States will allocate allowances from the set-aside to all new units in any

given year as a group. If there are more allowances requested than in the set-aside, allowances

will be distributed on a pro-rata basis. Allowance allocations for a given new unit in following

years will continue to be based on the prior year’s emissions until the new unit establishes a

baseline, is treated as an existing unit, and is allocated allowances through the State’s updating

process. This will enable new units to have a good sense of the amount of allowances they will

likely receive–in proportion to their emissions for the previous year. This methodology will not

provide allowances to a unit in its first year of operation; however, it is a methodology that is

straightforward, reasonable to implement, and predictable.

Although EPA is offering an example allocation method with accompanying regulatory

language, EPA reiterates that it recognizes States’ flexibility in choosing their Hg allocations

method.
cxlix

Comment:

One commenter (OAR-2002-0056-2181) stated that the proposal provides credit for the

thermal output of new CHP facilities. The commenter believed this is a very important and

beneficial provision that will help encourage the application of CHP. The commenter believed,

however, the same credit should apply to existing CHP facilities. The commenter stated that the

program should provide the maximum encouragement to CHP as a means of reducing energy

consumption and emissions from the power and steam generation sectors. The commenter

submitted that continued and increasing use of CHP can help reduce the cost of the program as

well as producing significant coincident benefits for regulated and non-regulated pollutant

reductions.

Response:

As discussed in the final rule preamble, under the example allocation methodology,

existing units as a group will not update their heat input. This will eliminate the potential for a

generation subsidy (and efficiency loss) as well as any potential incentive for less efficient

existing units to generate more. This methodology will also be easier to implement because it

will not require the updating of existing units’ baseline data. Retired units will continue to

receive allowances indefinitely, thereby creating an incentive to retire less efficient units instead

of continuing to operate them in order to maintain the allowance allocations.

Comment:

One commenter (OAR-2002-0056-2913) stated that their newest, cleanest and most

efficient electric utility steam generating unit was currently under construction, which because the

unit commenced construction prior to January 30, 2004, it was classified as an existing unit as

provided for in rule §63.9982(b). The commenter submitted however, if a cap-and-trade program

were promulgated as proposed this unit’s mercury allowances would be allocated according to

new unit criteria (i.e. a design output basis in lb/GWh) and only after it operated for five years.

According to the commenter, its newest unit would be allocated mercury allowances

based on the unit’s heat input which, for the first five years of operation, would be converted to

gross electrical output using a predetermined conversion factor of 8,000 Btu/kWh. The

commenter stated that 8,000 Btu/kWh is not applicable under any cogenerating circumstances and

is extremely aggressive under best case conditions and leaves no allowance for equipment

degradation due to low load conditions, equipment degradation or non-optimal process

operations. The commenter further stated that any heat input used for co-generation purposes

would only be converted at one-half of the actual rate and that mercury allowances would then be

allocated based on these artificially low heat input conversion rates; these allowances would be

reduced further by an additional 10 percent before being allocated for use. Beyond the penalties

already imposed on this unit (i.e. no allowance for mercury content in the limestone used for SO2

control purposes as discussed above) the commenter claimed they will be further penalized by this

allocation process and questions the appropriateness of applying what is in essence a new source

limit/allocation process to an existing unit.
cl

While the commenter believed the set-aside allocation process as currently proposed was

flawed, they expressed a much larger concern. According to the commenter, under the allocation

process proposed in §60.4142(c)(4)(iii) and (iv), there was a distinct possibility that they would

not be allocated enough mercury allowances to operate its newest unit regardless of the amount

of the proposed set-aside, due to the fact that a large new electric utility steam generating unit

could potentially require and be granted the entire amount of allowances set-aside. The

commenter stated that they would then be faced with the possibility of not being able to achieve

“... the maximum degree of reductions ...” on its own even though it would use the very

technology EPA relied upon in setting the EGU MACT standard in the first place. The

commenter did not believe this is what Congress envisioned when it passed CAA section 112 into

law. While the list of compliance measures, processes, methods, systems or techniques delineated

in CAA section 112(d)(2)(A)-(E) is, admittedly, not all inclusive, the commenter argued they

would essentially be prevented from using any of them to achieve compliance with the MACT

standard under a cap-and-trade program not “funded” with sufficient set-aside allowances.

As a remedy, the commenter offered that one way to treat all existing units equitably

would be to allocate mercury allowances to all existing units whether or not they operated during

the initial baseline period and whether or not they operated for five years or more. The

commenter stated that one could look to §60.4142(c)(3) for guidance on what EPA believed was

appropriate for initial mercury allowance allocations for units that have not operated for five years

or more. To implement the stated policy consistent with the approach outlined in §60.4142(c)(3),

the commenter offered suggested modifications to §60.4142.

Response:

The example allocation methodology for the final rule addresses the commenter’s

concerns about new units. As discussed in responses above, the example allocation methodology

includes: a new sources set-aside, allowance allocations for a given new unit based on the prior

year’s emissions until the new unit establishes a baseline, and no inclusion of discount factors.

Comment:

The commenter (OAR-2002-0056-4891) added that with the exemption option, new

power plants should be exempted from the requirement to purchase allowances as long as they

have NSPS Subpart Da technology operational when they initiate operations, and they adhere to

monitoring and reporting requirements to demonstrate continuous compliance. By the same

token, facilities that are not subject to the UMRR should not be able to receive credits and

thereby receive windfall gains on the allowance trading markets.

Response:

In the final CAMR, new sources will be covered under the Hg cap of the trading

program, and will be required to hold allowances equal to their emissions. EPA maintains that

is essential to include new sources under the cap to ensure that environmental goal of reducing

mercury emission is achieved. With new sources under the cap, the environmental goal
cli

continues to be achieved despite future growth in the electric power sector, as older coal-fired

generation is retired and replaced new coal-fired generation

Comment:

Several commenters (OAR-2002-0056-2834, -2898) submitted that Springerville Units 3

and 4 should receive allocations in the same manner as other “existing units.” The commenters

stated that the Springerville Generating Station was recently permitted for the addition of two

new 400 MW net coal-fired units. The permit for the addition of Springerville Units 3 and 4 was

received on April 29, 2002, and construction of the phased project began on October 22, 2003,

with Unit 3 scheduled for completion in 2006 and Unit 4 at a later date. Two other Units already

exist at the site, Springerville Units 1 and 2.

The commenters stated that units such as Springerville 3 and 4 should receive allocations

in the same manner as other “existing units” since construction commenced on or before January

30, 2004. The Springerville units 3 and 4 are “existing units” for the purpose of determining the

applicability of the proposed rule. The commenters noted that under either section 111 or 112, an

“existing unit” is one for which construction, modification, or reconstruction commenced on or

before January 30, 2004 (69 FR 4662 and 69 FR 4690). The commenters stated that Units 3 and

4, however, are not listed as part of those existing units receiving mercury allowances under a

Cap and Trade program. Under the proposed rule (69 FR 12446), units that “commence

operation on or after January 1, 2000" receive allocations according to a different approach,

regardless of whether they are “new” or “existing units.” The commenters felt that, since

construction of Springerville Units 3 and 4 commenced on or before January 30, 2004, these units

should receive allocations in the same manner as other “existing units.” Commenter 2898 added

that due to the fact that there is no historical heat input for these units, the “baseline heat input”

(prior to multiplying by the adjustment factors) should be calculated using the maximum potential

heat input for the units and a capacity factor of 90 percent. The commenter noted that units of

this nature are invariably intended to provide base load power, and the allocation methodology

must recognize this fact.

Response:

Under the example allocation methodology, a new unit is defined as a unit commencing

operation after January 1, 2001. For purposes of allocating emissions, EPA believes that

existing units need five years of heat input data to establishes it baseline heat input. This is

consistent with the overall allocation approach, under which new unit establishes a baseline

after 5 years of operation, is treated as an existing unit, and is allocated allowances through the

State’s updating process.

5.7.4 Auctions

Comment:
clii

Many commenters (OAR-2002-0056-1834, -1969, -2117, -2161, -2180, -2267, -2375,

-2721, -2830, -2835, -2850, -2867, -2891, -2898, -2911, -2922, -2948, -3443, -3445, -3543,

-3546 -3556, -3565) opposed the auctioning of mercury allowances. One commenter

(OAR-2002-0056-3565) believed states do not have that authority and allowances should be

allocated free. A second commenter (OAR-2002-0056-2891) stated that EPA had no regulatory

“taxing” authority under section 112 or section 111 to mandate the auctioning of mercury

allowances, and the auctioning of allowances would be poor public policy because it would

increase the cost of an already expensive proposal. The commenter further stated that a mercury

cap-and-trade program could be constructed in many ways to help ensure an equitable and

cost-effective program. The commenter noted that EPA requested comment on whether it could

and should impose an auction program under either a section 112(n) or section 111(d) Federal

Implementation Program cap-and-trade program, at 12408. The commenter stated that in short,

it is neither legal nor appropriate for EPA to implement any auction program of mercury

allowances.

Commenter OAR-2002-0056-2891 stated that first, EPA had no legal authority under the

CAA to auction or require the auctioning of mercury allowances under either proposed

cap-and-trade programs and conspicuously cited no legal authority in the proposal. According to

the commenter, the only auctioning of allowances the EPA has authority to conduct is specifically

delineated by an act of Congress in the 1990 CAA Amendments, section 416, under “acid rain”

control. The commenter stated that even under section 416, the auction proceeds are

redistributed to the original allowance holders. The commenter further stated that auction

proceeds would be effectively a tax on those required to purchase mercury allowances. The

commenter believed that EPA’s contention, at 12408 col. 2, that it might have regulatory

authority to collect taxes and deposit the proceeds in “general revenues” under the Miscellaneous

Receipts Act was unfounded.

The commenter added that the policy goals EPA claimed an auction would achieve can be

accomplished by less draconian and more legal means. The commenter stated that for example, a

“new source set aside” provision alternatively suggested by EPA, at 12408-12409, could be

constructed to accomplish the same objectives without unnecessarily driving up the costs of what

will be an already expensive program.

One commenter (OAR-2002-0056-2922) opposed auctions or any other method of forced

sale of allowances.

Several commenters (OAR-2002-0056-2161, -2948) opposed auctions, but stated that if

EPA decided to permit auctions, auctions should not be for the initial allocations of allowances,

but only for a very small percentage of allowances each year as in the Title IV program. One

commenter (OAR-2002-0056-2161) noted that the infrastructure for an allowance program is

already in place as a result of the Acid Rain Amendments, and it should be relatively simple to add

mercury allowances to the program already in existence.

Several commenters (OAR-2002-0056-2180, -2267, -2835, -2898, -3445) supported an

allocation system and opposed an auction. One commenter (OAR-2002-0056-2898)
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recommended that mercury allowances be allocated to sources by EPA. Several commenters

(OAR-2002-0056-2267, -2835, -3443, -3445) stated that mercury emissions would be controlled

at substantial cost, and to pay for allowances in addition to the mercury controls would add

substantial cost with no added environmental benefit. One of these commenters

(OAR-2002-0056-3445) did not believe that additional reductions would occur from sources

seeking to reduce the cost of allowances; it was not anticipated that additional reductions will be

possible, based on the available and developing control technologies.

Commenter OAR-2002-0056-2267 submitted that allocating allowances for free would

provide assistance to the entities incurring most of the costs of complying with the necessary

mercury reductions, lessening the financial impact of the program on these sources. One

commenter (OAR-2002-0056-2180) submitted that affected units will pay twice, once to reduce

emissions and second to pay for allowances they need to operate. Commenter

OAR-2002-0056-2835 suggested that if any allowances are withheld from affected EGUs for

auction, proceeds from auction sales should be remitted to the original holders from which the

allowances were withheld. Commenter OAR-2002-0056-3443 submitted that auctioning

allowances would increase the price of electricity due to the increased stringency of the emission

standard resulting from the requirement to purchase allowances and invest in control equipment. 

The commenter stated that well-documented studies show clearly that affordable electricity is a

key element in public health policy. The commenter felt that placing a tax on electricity could

undermine the health-benefits sought to be gained by this rulemaking.

Several commenters (OAR-2002-0056-2991, -3556) believed that if states were allowed

to sell allowances at auction (or otherwise) rather than allocate them without charge, it would

substantially change the cost analyses for the standard of performance that EPA has conducted. 

The commenters added that it would add to the variability of the implementation of the trading

program, hindering the development of a robust program.

One commenter (OAR-2002-0056-3543) believed auctions would not be necessary under

an open market free trade system. The commenter submitted that the use of a safety valve

mechanism, or capping allowance prices, may dictate decisions to install controls instead of the

market price for an allowance. This would be counter to the idea that decisions to control

emissions are driven by the cost effectiveness of controls compared to purchase of allowances. 

The commenter believed the safety valve mechanism also may hamper EPA’s ability to assess

penalties for noncompliance.

One commenter (OAR-2002-0056-3546) stated that requiring controlled sources to both

reduce emissions and pay for allowances to cover their remaining emissions would impose

significant costs on emitting sources. These additional allowance costs would be unnecessarily

burdensome and costly to fossil fuel-fired generation. In contrast, the commenter believed

allocating allowances to regulated sources would lessen the financial impact of this very costly

control program.

Several commenters (OAR-2002-0056-1969, -2830, -2850) disagreed with EPA’s

proposal to have an annual auction for mercury allocations under a cap-and-trade approach. 
cliv

According to the commenters, considering the uncertainty of the availability of mercury controls

and monitors, the risk to the existing coal-fired electric generating units would be high. The

commenters believed that, to alleviate some of the risk, the mercury caps should be fully and

permanently allocated to the existing electric generating units as is done under the Title IV sulfur

dioxide program. The commenters stated that new units would be better able to minimize risks

since they would be able to design systems and select fuels to minimize mercury emissions, which

is something that many existing units cannot do. The commenters asserted that if EPA decides to

allocate allowances to new units, it should not be done at the expense of existing units. The

commenters suggested that if EPA decides to implement an auction, EPA should manage that

auction program at the national level rather than having it managed by the individual states.

One commenter (OAR-2002-0056-2721) noted that allowance auctions would be the

responsibility of the individual state. The permanent allowance system would not take into

account new units, unless there was a new unit set aside. The commenter would be concerned

with the quantity of the set-aside as it is difficult to anticipate the rate of new units coming

on-line. An additional concern would be that the set aside would not be available for existing

sources.

One commenter (OAR-2002-0056-2861) opposed giving states the option of distributing

allocations through an auction. The commenter submitted this is not a necessary element of an

environmental control program. The commenter added that auctioning allowances would not

produce any additional reduction in emissions. It would simply increase the cost of the regulatory

program to companies and ultimately to consumers by requiring regulated entities to pay for every

ton emitted. The commenter stated that auctioning of mercury allowances would simply not be

an economically efficient policy. The commenter added, as UARG has argued in its comments, a

state does not have the authority to auction allowances because to do so would fundamentally

change the cost analysis that EPA used to establish the mercury performance standard.

One commenter (OAR-2002-0056-3437) stated that, although EPA proposes it, the

auction allowance work would fall to the states. While it may be beneficial to have a pool of

revenue available, there could be resource issues with establishing and implementing an auction

program. The commenter asserted that if EPA includes auctions, this must be voluntary and not a

requirement.

Response:

For States participating in the EPA-administered CAMR cap-and-trade program, States

have the flexibility to determine their own methods for allocating Hg allowances to their sources. 

Specifically, such States will have flexibility concerning the cost of the allowance distribution,

the frequency of allocations, the basis for distributing the allowances, and the use and size of

allowance set-asides.

As discussed in the final preamble, although there are some clear potential benefits to

using auctions for allocating allowances, EPA believes the decision regarding utilizing auctions

rightly belongs to the States and Tribes. EPA is not requiring, restricting, or barring State use
clv

of auctions for allocating allowances. An example of an approach where CAMR allowances

could be distributed to sources through a combination of an auction and a free allocation is

provided in the preamble.

5.8 OTHER TRADING MECHANISMS

5.8.1 Banking

Comment:

Several commenters (OAR-2002-0056-1673, -1859, -2375, -2547, -2718, -2862, -2867,

-2883, -2900, -2922, -2948, -3509, -3565) stated there should be no restrictions on banking of

emission allowances. Several commenters (OAR-2002-0056-2547, -2718) supported a provision

for unrestricted banking as a way to encourage early emissions reductions, stimulate the trading

market, encourage efficient pollution control, and provide flexibility to affected sources in meeting

environmental objectives. One commenter (OAR-2002-0056-2900) noted that, like the Acid Rain

Program, the Mercury Budget Trading Program proposed unlimited banking without the flow

control provisions of the NOx Budget Trading Program. The commenter supported unlimited

banking of allowances allocated to sources under each phase of the Program and did not see any

advantage to a flow control provision. Commenter OAR-2002-0056-2862 also believed there

should not be any restrictions such as flow control. This commenter stated that because mercury

is a chemical that bio-accumulates in the environment, and because the behavior of mercury

emissions are not exacerbated by seasonal weather conditions (such as the proclivity for ozone

formation development during hot, humid summer months), any reduction in mercury in advance

of a compliance date would result in a net environmental gain.

Response:

EPA has finalized that banking will be allowed without restriction after the start of the

Hg cap-and-trade program in 2010.

Commenter (OAR-2002-0056-2375) submitted that a mercury cap-and-trade program

should include provisions for early reduction credits (ERC) and banking of mercury credits. The

commenter supported unrestricted banking of all ERCs and Phase I and II excess credits without

discount, except the banking of Phase I credits should be restricted if EPA determines in 2009

that IAQR reduction co-benefits result in emissions less than 34 tpy and EPA sets the cap at

34 tpy. Sources would be permitted to use vintage Phase I credits during Phase I without

discount and vintage Phase II credits during Phase II without discount.

Response:

EPA has finalized that banking will be allowed without restriction after the start of the

Hg cap-and-trade program in 2010. Given that the 2010 cap is set at a level that represents Hg

co-benefit reductions under CAIR, EPA did not propose, and is not finalizing, an early reduction

credit provision, because the cap-level does not require the installation of Hg specific controls. 
clvi

Under CAIR, Acid Rain Program sources will be able to bank SO2 allowances from additional

reductions before 2010 that may also result in ancillary Hg emission reductions.

One commenter (OAR-2002-0056-3443) recommended in view of the environmental

benefits fostered by a program that allows allowances to be banked in advance of the deadline for

a cap, that early reduction credits should be allowed for calendar years 2008 and 2009. The

commenter has long held that early reduction programs be made part of all cap and trade

programs. The commenter believed that early reduction programs work to promote clean air

sooner by encouraging the early installation of new technologies. The commenter installed

state-of-the-art scrubbers in advance of the statutory deadlines under the successful Title IV

program. Likewise, the commenter installed the nation’s first SCRs burning high sulfur coal in

advance of the NOx SIP Call. For a mercury cap and trade program, the commenter asserted that

the utility industry needs banking of early reduction credits because of the uncertainty in its ability

to control mercury emissions over the long term. The commenter noted that as the preamble

acknowledges, a banked allowance is one less ounce of mercury emitted in a given year. Thus, an

early emissions banking program has the advantage of achieving reductions in advance of the

2010 compliance date for a Phase I cap.

The commenter recommended an early emission banking program would be based on the

mass of reductions produced from the installation of an emissions control device on an individual

unit basis, as was done in the NOx SIP Call. In addition to providing environmental

improvements, the commenter believed this program also provides an opportunity to address

important monitoring issues since utilities choosing to participate in the program would have to

start monitoring for mercury in 2008 for units in this early reduction program. The commenter

stated credit would be earned on an individual unit basis at levels below their Phase I allocation.

The commenter estimated that on a yearly basis, they might earn three to six percent of their

Phase I allocation level. The commenter noted this is a small amount, given that the current best

mercury emission monitoring method (the Ontario Hydro Method) has a 10 percent accuracy

level.

Given the limited experience industry has had with mercury CEMs or equivalent methods,

the commenter believed several monitoring issues would have to be resolved prior to the onset of

monitoring. For example, substitution of missing data is just one of the many issues that the

commenter felt need to be addressed. The commenter submitted an early banking program,

starting in 2008, would allow EPA to address these issues prior to the imposition of the first cap

in 2010.

The commenter submitted that excessive bank accumulations could be minimized by

discounting the banked allowances in 2018 by a certain pre-set percentage. The commenter

believed the interim cap and the discounting of allowances would ensure that actual emissions in

2018 are close to the Phase II cap of 15 tons per year. The commenter stated that this approach

provides the flexibility of building some allowances prior to program initiation in 2010 to hedge

against the uncertainty in the estimate of achievable mercury reductions. This approach would

also be environmentally preferable because it would encourage earlier reductions and then in 2018

permanently retire allowances.
clvii

Response:

Given that the 2010 cap is set at a level that represents Hg co-benefit reductions under

CAIR, EPA did not propose, and is not finalizing, an early reduction credit provision, because

the 2010 cap-level for CAMR does not require the installation of Hg specific controls. Under

CAIR, Acid Rain Program sources will be able to bank SO2 allowances from additional

reductions before 2010 that may also result in ancillary Hg emission reductions. EPA has

finalized that banking will be allowed without restriction after the start of the Hg cap-and-trade

program in 2010. The ability of affected sources to bank Hg allowances starting in 2010 will

promote earlier reductions than would otherwise be achieved in the program, and help to

stimulate the Hg allowance market.

Comment:

One commenter OAR-2002-0056-3445 stated that they are already installing equipment to

make significant reductions in NOx and SO2 emissions. The commenter added that they and their

customers have made a substantial investment in the NOx and SO2 control technologies, one that

the commenter believed will have a substantial level of mercury reduction co-benefits. The

commenter added that this equipment will be operational as much as five years before EPA’s

proposed initial compliance deadline, resulting in less overall mercury emissions to the

environment.

The commenter believed that banking should be allowed, so the credits that the

commenter earns by acting early may be used to offset later emissions or as a reserve in the event

of equipment failure. A significant amount of the commenter’s generation comes from nuclear

power, which emits no mercury. The commenter pointed out that if any of those nuclear units

experienced an unexpected outage, generation must be made up from the fossil plants, which

could result in unanticipated mercury emissions. With limits as tight as the proposed 15-ton cap

in 2018, the commenter believed that banked emissions credits should be available to offset the

unexpected mercury emissions from such an event.

The commenter stated that banking would encourage companies to install and operate

pollution control equipment early, at significant operating cost, so that the banked allowances

could be used when additional equipment could not be installed in the limited time available. The

commenter added that banking also encourages companies to operate pollution control equipment

to achieve maximum emissions reductions, accumulating a pool of allowances that can be used as

a reserve in case of the unforeseen loss of a non-emitting or controlled unit, during periods of

necessary but unexpected maintenance, and in the event that some controls do not perform as

designed.

The commenter stated that utilities like them that have a significant number of

non-mercury emitting generation units (e.g., nuclear and gas) must plan for fluctuations in their

operations, based on long-term maintenance and refueling cycles. The commenter added that

these plans impact the plants’ year-to-year operations and the commenter’s overall emissions. 

The commenter further added that weather is also a factor in plant operations. According to the
clviii

commenter, an extremely hot summer or cold winter could result in a significant emissions

increase relative to the original plan, which would be based on “normal weather assumptions” for

that period. The commenter stated that banking would provide a cost-effective mechanism for

dealing with the expected year-to-year emissions fluctuations while ensuring long-term

compliance.

Response:

EPA has finalized that banking will be allowed without restriction after the start of the

Hg cap-and-trade program in 2010.

Several commenters (OAR-2002-0056-1596, -2071, -2064, -2094, -2359, -3398, -4139)

stated that banking should not be allowed or should be restricted. One commenter

(OAR-2002-0056-2359) opposed EPA’s proposal to allow units to bank early emission credits

with no restrictions to be used in meeting reductions under CAA section 111. If banking and

trading were allowed, the proposed 15-ton final cap in 2018 would increase to 22 tons or only a

54 percent reduction. The commenter believed that the banking of emission credits should be

restricted and that at a minimum, credits should expire by a final compliance date. Commenter

OAR-2002-0056-3398 rejected banking prior to the 2018 compliance date because it would

extend the timeframe for meaningful reductions and may further contribute to hot spots. One

commenter (OAR-2002-0056-4139) did not support banking of allowances without restrictions. 

The commenter believed the availability of banked allowances should be decreased either through

time-generated reductions (i.e., allowances expire after a definite time period) or by requiring the

use of older banked allowances on an increasing ratio based on age (i.e., 1 to 1.5 or 1 to 2). One

commenter (OAR-2002-0056-1596) stated that any banking of allowances must include an extra

reduction for each transaction for environmental improvement. For example, when 100 units are

retired, an additional 5 units should be retired. 

Response:

Banking would achieve greater cumulative reductions early in the program than would

be required by the final cap, and will not increase cumulative emissions over the entire length of

the program. Banking has several additional advantages, including the potential to encourage

earlier or greater reductions from sources, stimulate the market and encourage efficiency, and

provide flexibility in achieving emissions reduction goals (e.g., by allowing for periodic

increased generation activity that may occur in response to interruptions of power supply from

non-Hg emitting sources).

5.8.2 Safety Valve Provision

Comment:

Many State Attorney Generals (OAR-2002-0056-2823) stated there is no legal or policy

basis for establishing a “safety valve,” which would set a maximum cost for mercury emission

allowances. The commenters asserted EPA lacks both authority and a policy basis for adopting a
clix

safety valve. The commenters believed the safety valve would provide incentive to deter emission

reductions and should be withdrawn. The commenters noted that even if authority existed, EPA

presented no legal or technical basis for the proposed price of $2,187.50. The commenters stated

the provision is also unnecessary for a market-based program and would undermine its

purpose–to use market incentives to achieve timely reductions.

Response:

EPA is not finalizing a safety valve provision in CAMR. EPA maintains that the safety

valve mechanism is not necessary to address market volatility associated with the Hg reduction

requirements. This issue is discussed in detail in section IV of today’s preamble.

Comment:

Similarly, several states (OAR-2002-0056-3437, -3449, -4139) did not support the safety

valve provision. One commenter (OAR-2002-0056-3437) stated safety valves have not been

needed in the Acid Rain or NOx programs, and they would require EPA to speculate about too

many uncertainties, such as the allowance price. One commenter (OAR-2002-0056-3449)

submitted the safety valve provision to avoid controls if the cost is greater than $35,000/lb is

inappropriate and arbitrary. The commenter noted the dollar value was not linked to the

environmental cost which result from excess mercury emissions. The commenter believed that it

appeared to be linked to EPA’s arbitrary notion of what level of cap is supported by the proposed

rule. The commenter also believed costs of control over $100,000/lb were justified based on the

economic loss of fish, sports fishing industry, and the lifetime economic loss of brain damaged

people due to in utero exposure.

Response:

EPA is not finalizing a safety valve provision in CAMR. EPA maintains that the safety

valve mechanism is not necessary to address market volatility associated with the Hg reduction

requirements. This issue is discussed in detail in section IV of today’s preamble.

One commenter (OAR-2002-0056-4139) submitted that allowing sources to purchase

allowances under a safety valve price guarantee may discourage companies from seeking more

cost effective means to control mercury. The commenter pointed out this could inhibit

advancement of new technologies because sources would control only to a set dollar amount

regardless of advances in control technology.

Response:

EPA is not finalizing a safety valve provision in CAMR. EPA maintains that the safety

valve mechanism is not necessary to address market volatility associated with the Hg reduction

requirements. This issue is discussed in detail in section IV of today’s preamble. 

Comment:
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Public interest group comprehensive comments (OAR-2002-0056-3459) stated that the

safety valve provision should be discarded because it would permit pollution levels to remain

artificially high and because EPA expects it to be used to avoid pollution controls. Even though

purchased safety valve allowances would be deducted from the next year’s allocation, there does

not seem to be any limit on using the provision to borrow again year after year and avoiding

controls indefinitely. The commenters noted that EPA’s own IPM modeling showed it is bad

environmental policy that would increase emissions in the years 2023-2030 beyond the cap of

15 tpy (to 22 tpy). It also would have the potential to delay controls if the price were cheaper

than controls. The commenters observed that EPA did not even address the possibility of local

problems resulting from the safety valve provision. It also would create a huge paradox

associated with the continual borrowing of future allowances without ever reconciling the

borrowed allowances from future compliance periods. As written, the commenters submitted the

proposed provision would allow a plant to comply by purchasing allowances into the future.

Response:

EPA is not finalizing a safety valve provision in CAMR. EPA maintains that the safety

valve mechanism is not necessary to address market volatility associated with the Hg reduction

requirements. This issue is discussed in detail in section IV of today’s preamble.

Comment:

One commenter (OAR-2002-0056-2897) expressed concern about the proposed safety

valve mechanism and suggested that this concept be revisited, as it seemed to undermine the

market value concept of Title IV. The commenter noted that the concept suggests that there

would be unlimited allowances available at a fixed and arbitrary price unrelated to market

conditions and that these allowances could be borrowed against ad finitum into the future. The

commenter questioned whether this truly incentivizes commercialization of technology.

Response:

EPA is not finalizing a safety valve provision in CAMR. EPA maintains that the safety

valve mechanism is not necessary to address market volatility associated with the Hg reduction

requirements. This issue is discussed in detail in section IV of today’s preamble.

Comment:

The commenter (OAR-2002-0056-2897) stated that borrowing of future allowances may

be acceptable if there will be only minor noncompliance issues in the years immediately following

initial implementation. The commenter asserted that, however, this could not be guaranteed and

continued borrowing of out year allowances would be extremely problematic. The commenter

stated that an alternative approach may be to allow utilities to purchase off-system reductions

from outside the electricity-generating sector, if their control costs exceed the safety valve value. 

According to the commenter, this would eliminate the risk that utilities face from excessive

control costs while continuing to reduce the mercury emitted to the environment. The commenter
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believed over time, the depletion of these off-system reductions would help incentivize mercury

control technology.

Response:

EPA is not finalizing a safety valve provision in CAMR. EPA maintains that the safety

valve mechanism is not necessary to address market volatility associated with the Hg reduction

requirements. This issue is discussed in detail in section IV of today’s preamble. 

Comment:

Several commenters (OAR-2002-0056-2180, -2375, -2519, -2547, -2718, -2721, -2830,

-2835, -2850, -2861, -2922, -2948, -3509, -3522, -3565, -4891) supported the establishing of a

safety valve. Several commenters (OAR-2002-0056-2375, -2718, -2903, -3522) supported an

enhanced, appropriately designed safety valve provision because it could solve critical problems of

implementing the trading program while ensuring compliance with and the integrity of the Phase I

and II caps. Specifically, the commenters supported a Phase I safety valve set at $15,000/lb. and

a Phase II safety valve set at $35,000/lb. However, the commenters objected to EPA’s proposal

to deposit safety valve funds into the general treasury and to deduct safety valve allowances from

future years. The commenters proposed that safety valve funds should go into a Mercury

Reduction Fund (MRF) and be used to fund the development of innovative technologies and/or

purchase additional off-utility system mercury reductions. The commenters proposed that

because the MRF could yield net mercury reduction benefits, there would be no need to

confiscate safety valve credits from future years.

Response:

EPA is not finalizing a safety valve provision in CAMR. EPA maintains that the safety

valve mechanism is not necessary to address market volatility associated with the Hg reduction

requirements. This issue is discussed in detail in section IV of today’s preamble. Further, it

should be noted that under section 111 where state plans have been approved, funds from the

sale of safety valve allowances would have been collected by the States, not EPA.

Comment:

One commenter (OAR-2002-0056-4891) stated the safety valve provision is intended to

and would, in fact, minimize some of the uncertainty and unanticipated market volatility that may

be associated with the cost of mercury rule compliance. The price of allowances would be capped

such that, if the allowance price exceeds the “safety-valve” amount, sources would be authorized

to borrow allowances from following years to have access to more allowances available at that

price. The commenter submitted that perhaps the primary benefit of this provision is that it would

render the cost of complying with the mercury rule requirements somewhat predictable and

limited, though extremely costly.

Response:
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EPA is not finalizing a safety valve provision in CAMR. EPA maintains that the safety

valve mechanism is not necessary to address market volatility associated with the Hg reduction

requirements. This issue is discussed in detail in section IV of today’s preamble. 

Comment:

One commenter (OAR-2002-0056-2835) emphasized that the success of a safety valve

mechanism would depend on the design of the state allocation system–i.e., the availability of

undistributed allowances from which the sources could borrow–and highlighted the need for

consistent allocation methods across the various state programs. 

Response:

EPA is not finalizing a safety valve provision in CAMR. EPA maintains that the safety

valve mechanism is not necessary to address market volatility associated with the Hg reduction

requirements. This issue is discussed in detail in section IV of today’s preamble.

Comment:

One commenter (OAR-2002-0056-3431) noted that EPA has proposed a safety valve

provision that sets the maximum cost purchasers must pay for mercury emission allowances. The

commenter observed that EPA proposed a price of $2,187.50 for a mercury allowance (one

ounce); this price would be adjusted annually for inflation. The commenter stated that safety

valve allowances could be used to cover any shortfall between reported emissions and the

allowances needed to cover those emissions. The commenter observed that as proposed,

allowances purchased by a power plant through the safety valve mechanism would come out of

the budget for future years from the state within which the power plant is located and, in EPA’s

example, would be taken out of the pool of allowances available for units that have been

generating for at least five years. The commenter stated that this would result in reduced future

allocations for all plants in that state. According to the commenter, it would be unwarranted and

inequitable for other plants in the state to be penalized as a consequence of another plant taking

advantage of the safety valve mechanism. The commenter stated that this potentially is an

especially problematic issue for plants in states that have a small number of coal-fired power

plants. To address this problem, the commenter suggested that the mechanism be revised to have

the “borrowed” safety valve allowances come out of the overall nationwide budget, not individual

state budgets. The commenter also suggested that alternatively, the mechanism could be changed

to allow plants to use future year allowances for compliance in an earlier compliance year, at no

charge, but on a discounted basis. According to the commenter, this would eliminate the problem

of penalizing plants for the use of the safety valve mechanism by other plants in its state, while

making sure there isn’t excess “borrowing” of future years’ allowances through the discount

provision.

Response:
clxiii

EPA is not finalizing a safety valve provision in CAMR. EPA maintains that the safety

valve mechanism is not necessary to address market volatility associated with the Hg reduction

requirements. This issue is discussed in detail in section IV of today’s preamble.

Comment:

One commenter (OAR-2002-0056-2634) believed that the EPA’s safety valve provision is

not a true safety valve in that it requires the confiscation of future years’ allowances. The

commenter stated that the purpose of the safety valve is to ensure reliability in the electrical

system by providing units a means of compliance even if technology does not develop at the rate

currently anticipated. The commenter believed confiscation of future years allowances would

only exacerbate the problem. The commenter suggested that if EPA ultimately decides that the

safety valve provision will include borrowing of future years allowances, allowances should be

borrowed from the general pool and not against an individual units account. If the safety valve

were triggered, it would not be the result of any business decisions made at a unit level, rather it

would be a reflection of the state of technology across the industry. Therefore, the cost burden

should also be spread across the industry. 

Response:

EPA is not finalizing a safety valve provision in CAMR. EPA maintains that the safety

valve mechanism is not necessary to address market volatility associated with the Hg reduction

requirements. This issue is discussed in detail in section IV of today’s preamble.

Comment:

One commenter (OAR-2002-0056-1969) was unclear how a safety valve will be an

effective tool to minimize unanticipated market volatility if the future year cap is reduced by the

borrowed amount. The commenter stated that it certainly could alleviate compliance concerns at

the point in time when the safety valve is triggered, but also noted that, on the other hand,

triggering the safety valve in multiple years could compound future compliance requirements

unless industry were able to effectively reduce future mercury emissions within a reasonable time

frame.

Similarly, one commenter (OAR-2002-0056-2850) supported the safety valve if it does

not involve replacement of credits from future allocations. The commenter believed an interim

phase buyout price of $10,000 per pound mercury should be considered, shifting to EPA’s

proposed $35,000 per pound value at the final phase of the program (2018). The commenter

stated that the price cap is critical considering that there is no commercially demonstrated control

technology. The commenter suggested that the pay back component be eliminated, since that

only serves to make future year compliance all the more difficult while emerging technology is

commercialized.
clxiv

One commenter (OAR-2002-0056-2861) suggested that some restriction is needed on the

use of the safety valve to assure that borrowed allowances do not affect the future allocations of

sources that met compliance without the need to borrow.

One commenter (OAR-2002-0056-2180) suggested that proceeds from the safety valve

should be returned to other allowance holders or held in escrow until the user of the safety valve

can return the borrowed allowances.

Several commenters (OAR-2002-0056-2948, -3565) requested EPA to modify their

proposal to enable a unit to borrow from its own future-year allowance account (resulting in

fewer allowances available to that unit in future years). Commenter OAR-2002-0056-2948 stated

this would avoid a situation where units that did not borrow allowances are forced to bear part of

the burden of a reduced number of available allowances in future years. Commenter

OAR-2002-0056-3565 recommended that the unit borrowing from its own future-year allowance

still pay EPA the $2,187.50 per allowance for the privilege to borrow against future years. The

commenter believed the unit should not be borrowing from the general pool of allowances

available to all units within the state as EPA has proposed. The commenter stated that this would

result in fewer allowances available for allocation in future years, not just to the units that

borrowed allowances, but to all units. The commenter noted that EPA also proposes that funds

received from the purchase of safety valve allowances be deposited in the United States Treasury. 

The commenter requested that these funds instead be provided to the United States Department

of Energy to assist in the development of innovative mercury emissions control projects, such as

Powerspan’s Electro Catalytic Oxidation technology.

Response:

EPA is not finalizing a safety valve provision in CAMR. EPA maintains that the safety

valve mechanism is not necessary to address market volatility associated with the Hg reduction

requirements. This issue is discussed in detail in section IV of today’s preamble.

Comment:

One commenter (OAR-2002-0056-3443) stated that EPA has asked for comments on the

need for a safety valve mechanism under which the price of allowances is effectively capped. See

69 FR 12397 and 12410. The commenter can support the inclusion of such a mechanism in the

trading rule but contended that an early reduction credit program would be a more effective tool

for dampening the market volatility that could result from implementation of a cap and trade

program. The commenter believed an early reduction program would be a better policy and

market tool since it would grant credit for reductions made early rather than grant credit for the

promise of greater future reductions. The commenter noted early reduction allowance programs

have been part of previous cap and trade programs, and are better suited to dampen market

volatility by making emission credits available ahead of compliance deadlines. The commenter

pointed out that the safety valve mechanism, by contrast, would attempt to artificially restrain the

market price of allowances. The market price of an emission allowance obtained via a safety

valve provision could vary greatly depending on the final source of that emission allowance,
clxv

creating situations in which the safety valve would have little effect on dampening market

volatility or facilitating compliance decisions.

Response:

EPA is not finalizing a safety valve provision in CAMR. EPA maintains that the safety

valve mechanism is not necessary to address market volatility associated with the Hg reduction

requirements. This issue is discussed in detail in section IV of today’s preamble. See the

discussion of early reduction credits in following section.

Comment:

One commenter (OAR-2002-0056-1842) offered the following “variable mercury safety

valve plan,” based on the mercury cap and trade proposal.

Proposition: Variable mercury safety valve allowance pricing should be included in the

proposed mercury and cap and trade rule.

Purpose: To eliminate the impasse over feasability. This impasse is largely based on the

question of mercury technology performance. Variable pricing eliminates the need

to address this question.

Proposition

Specifics: Present proposals call for absolute diminishing caps with a fixed safety valve price

approach. This should be changed to single cap target (5 to 10 tpy) with safety

valve allowance prices which start low but increase yearly. The result is that the

achievement of the target is probable but the maximum cost is predictable.

Background: Much of the debate centers on the amount of mercury removal which should be

achieved in various years. The differences are not about the goal but about the cost

of obtaining the goal. Power plants in the U.S. presently emit 48 tons (96,000 lb)

of mercury/yr. Environmentalists contend that 90 percent of the mercury can be

removed with known technology and are calling for a five ton mercury cap in

2007. Power plant owners believe there is no reliable technology available and are

questioning whether a 26 ton cap in 2010 is too onerous. However, both agree

that by 2018 it is necessary to remove between 70-90 percent of the mercury.

Mercury is bio-accumulative. Therefore mercury removed in earlier years will

benefit those living in 2018. Since there is broad agreement to reduce mercury

exposure in 2018, there must be agreement that cost effective earlier reduction of

mercury is also desirable. The problem is that there is great disagreement on what

will be cost effective when.

The proposed rule attempts to allay power plant concerns about cost through a

“safety valve” provision. A 34 ton cap is proposed for 2010. 68,000 pounds of
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mercury allowances would be allocated to the 300,000 MW of generating

capacity. The average 300 MW plant would have an allowance of 68 pounds.

Should he emit more than 68 lbs in 2010 he can buy allowances on the open

market. If he cannot buy allowances on the open market for less he can buy them

from EPA for $35,000/lb. The average 300 MW plant emits 96 lbs/yr of mercury.

Therefore the worst case scenario is a 2010 cost of 28 lbs x $35,000 = $980,000.

Impasse

Analysis: There is no supplier with deep pockets guaranteeing to remove 90 percent of the

mercury at $5,000/lb of mercury in 2007. So while environmentalists claim that

this can be done utilities can justifiably ask: what if we install lots of equipment

which does not work and then still end up not meeting the limits? They argue that

by 2018 solutions will be available at a reasonable cost. So let’s wait.

Argument over an unknown is fatal to any progress. Since the cost of removal at

any point in time is not certain, progress can only be made by eliminating the

relevance of this “unknown.” Variable safety valve allowance pricing does

precisely this.

Proposition

Details: The safety valve concept is undeniably a positive addition. Environmentalists who

anticipate allowances selling for $5,000/lb will not object to a $35,000 safety valve

price. Utilities which anticipate much higher costs are relieved that there is a cost

ceiling. But this high priced safety valve which is only applicable at a 34 ton cap in

2010 does little to break the impasse. However, the basic idea can be exploited to

completely eliminate the Impasse.

The plan entails a fixed cap with variable price allowances. Under this proposal the

ultimate cap, whether it is 5 tons or 10 tons, would be utilized from the first date

of promulgation. This means that the average 300 MW utility would have an

allowance of 10 to 20 pounds from some date starting in 2006 through 2010. The

plant would buy allowances for yearly emissions above this figure. However, if the

allowances exceeded some price, e.g. $1,000-5,000 in the first year, they could be

purchased for that amount from EPA. This price would rise each year. So for

example the price could start at $1,000/lb in 2007 and rise to $7,000/lb in 2010. A

2018 price of $25,000/lb instead of the proposal of $35,000 could be set.

This mechanism favors all parties. Environmentalists who are confident that 90

percent removal will be achieved at $5,000 lb would back a variable price at this

amount at the earliest time they can negotiate. Utilities who are already

anticipating spending up to $35,000/lb in 2018 will see themselves much better off

under this provision. Suppliers will be spurred to massive R and D programs

because they can target specific years when they are confident their technology will

be more cost effective than the safety valve price. The public will be better off

because the private sector will shoulder the development costs. EPA and DOE

will be relieved that the burdens are transferred elsewhere.
clxvii

Summary: The fixed cap/variable safety valve allowance prices for mercury would eliminate

the impasse in Clear Skies passage and would result in a very cost effective

solution to the mercury removal problem. Since many suppliers believe they have

solutions which will remove mercury at low cost, but who do not see any market

until 2018, this provision would trigger immediate development of technology. In

the past, government funded development of air pollution control technology has

proven to be expensive and not as productive as private funding. Revenues

generated by the safety valve option could be funneled directly to mercury

technology development. So this provision will be an important addition to the

proposed legislation.

The commenter then offered an example of how the variable mercury safety valve plan

would work for a 300 MW plant.

Response:

EPA is not finalizing a safety valve provision in CAMR. EPA maintains that the safety

valve mechanism is not necessary to address market volatility associated with the Hg reduction

requirements. This issue is discussed in detail in section IV of today’s preamble.

Comment:

One commenter (OAR-2002-0056-2918) believed that an enhanced, appropriately

designed “Safety Valve” provision could resolve several critical problems related to

implementation of a mercury cap and trade program for the coal-fired power plant industry. The

commenter stated a properly designed safety valve mechanism could ensure compliance with, and

the integrity of, the Phase I (2010) and Phase II (2018) mercury emission caps while providing the

flexibility to address the current uncertainty about mercury emissions and their control.

The commenter proposed that EPA enhance the safety valve provision and design it to

address the following critical cap and trade implementation issues:

• Significant uncertainty exists over the accuracy of EPA’s ICR and NATEMIS national

emissions database inventories, as well as the accuracy of EPA’s 34-ton co-benefits-based

Phase I mercury emissions cap. Therefore, the coal-fired power plant industry sees

significant uncertainty whether sufficient mercury allowances will be available for

compliance after the co-benefit controls are installed under EPA’s proposed CAIR.

• In addition to the potential Phase I shortfall of mercury allowances, the compliance issue is

exacerbated for one or more coal ranks if EPA’s allowance multipliers are not set

appropriately.

• EPA’s proposed confiscation of future year “borrowed” mercury allowances in its safety

valve proposal presents serious potential system reliability and future compliance

problems. As currently understood by industry, if significant advancements in mercury
clxviii

control technology do not develop at a commercial level by Phase II (2018), the

confiscation of future year allowances will simply “dig the hole deeper.”

• Finally, the safety valve needs to materially contribute to actual achievement of the Phase

II 15 ton/yr mercury emissions cap. The commenter prepared a “Hg Co-Benefits and

CSA Phase I and II Analysis” that demonstrated (based on EPA’s ICR II and NATEMIS

national emissions inventory data) that after application of co-benefit control technology

required to meet the CSA requirements, and with the application of all feasible ACI

mercury control (assuming it becomes commercially available), national mercury emissions

from power plants would remain at about 19 tons/year by Phase II.

The commenter believed that a safety valve must be properly designed to maximize

mercury emission reductions, while enabling the operators of coal-fired power plants to comply

with the Phase I and Phase II caps at an acceptable cost. The commenter submitted that a

properly designed safety valve could also accelerate the development of commercially available

mercury control technologies necessary to achieve the proposed Phase II 15 ton/year cap. The

commenter stated that the aforementioned co-benefits analysis was performed principally with the

use of EPA’s IPM modeling assumptions about the effectiveness of mercury control technologies,

including ACI.

The commenter recommended that EPA revise its proposed safety valve provision to

include the following design elements for both Phase I and Phase II of the mercury cap and trade

program:

• Allow a lower $/lb mercury safety valve fee for compliance during Phase I (2010-2017). 

The safety valve fee during Phase I could be set at $15,000 per pound. Covered facilities

would pay the fee in lieu of using mercury allowances for compliance in the event that the

mercury allowance price exceeds $15,000 per pound.

• Allow payment of EPA’s currently proposed $35,000/lb fee during Phase II, in lieu of

using mercury allowances for compliance in the event that the allowance market price

exceeds $35,000 per pound.

• Do not confiscate future year mercury allowances under either the Phase I cap, or under

the Phase II cap. Facilities paying the fee would not be allowed to use any Phase I or

Phase II “banked” emission credits. This feature would ensure that banked emissions must

be used, or placed on the market (likely at a price lower than the fee), before compliance is

allowed by payment of the safety valve fee, to preserve the integrity of the mercury caps

to the maximum extent possible.

• Establish a Mercurv Reduction Fund from the safety valve fees collected, and disburse the

funds (with no more than a 5percent administrative cost) to achieve mercury reductions

and advancing mercury control technologies, by contracting for and funding: (1) Project

proposals to make mercury reductions from other mercury emissions sources “off the

utility system”; and, (2) Project proposals that demonstrate advanced mercury control
clxix

technologies, including commercial level generating unit demonstrations (i.e., units at

25MW to 750MW capacity).

• Conduct a mercury cap and trade program “reasonable progress” review at years 2015,

2018, and 2021 to assess the actual mercury emissions reduction progress occurring from

electric generating units (EGUs) under the cap and trade program, compared with the

Phase I and Phase II mercury caps. The purpose of a “reasonable progress” review would

be to determine whether any program adjustments need to be promulgated by rule

revision, to ensure that the mercury reduction caps are achieved–given the state of

development of mercury emission reduction technologies, and the reliability of the national

electric supply grid system.

The commenter stated that the safety valve proposal would guarantee a maximum price at

which regulated sources would be able to purchase mercury allowances for Phase I and Phase II,

market pressures notwithstanding. The safety valve also would minimize unanticipated allowance

market volatility by ensuring that the price for allowances would not exceed a fixed ceiling. 

According to the commenter, EPA thereby would provide industry with reliable market

information for strategic compliance planning. Even more importantly, in the event that it proved

more costly and difficult to achieve the Phase I and Phase II mercury emissions reduction targets

than is now projected, the marginal cost of the mercury control program could not exceed

$15,000 per pound in Phase I and $35,000 per pound in Phase II. The commenter stated that this

would protect consumers from unanticipated and unjustifiable costs. For these reasons, the

commenter supported the creation of a safety valve mechanism for both Phase I and Phase II of

the proposed mercury cap and trade program to ensure that emissions reductions will be achieved,

but that control costs would not exceed a predetermined level.

The commenter further supported the creation of a Mercury Reduction Fund as an

effective means for maximizing the economic efficiency of achieving the Phase I and Phase II

mercury reduction caps. First, safety valve funds could be used to stimulate the development of

innovative control technologies, by providing capital to potential innovators that is otherwise

unavailable due to the scale of the required investment, the delay in return, or the degree of risk

involved. Second, the fund could act as a safety net or relief valve by making it easy for sources

with limited or no emissions control capability to obtain needed reductions from off-line sources

that can reduce emissions more efficiently.

The commenter pointed out that a safety valve fund could enhance compliance with

emissions standards in several ways. The commenter continued that the fund also would promote

regulatory certainty by guaranteeing a cap on removal costs. This would help owners and

operators of regulated sources better plan for the future. The commenter submitted that the fund

also would enable EPA to target sources for cost-effective emissions reductions that EPA

otherwise would lack the statutory authority to regulate. Armed with safety valve funds, the

commenter believed EPA could act as a market participant and procure additional reductions

from any entity willing to be paid in return.
clxx

The commenter added that a safety valve fund could also significantly benefit the

environment. For example, if the safety valve were set at an appropriate marginal control cost

level as described above, regulated sources would be discouraged from paying into the fund to

cover emissions. Rather, sources would be encouraged to develop innovative ways to reduce

emissions more efficiently. Further, the commenter stated a safety valve fund would encourage

the aggregation of capital for larger, strategic investments by reducing associated transaction

costs. The commenter suggested EPA could then use the capital at its disposal to invest in a

variety of technological innovations, including low-risk, low-return investments as well as

higher-risk and potentially higher-return investments.

In conclusion, the commenter urged EPA to establish Phase I and Phase II safety valve

fees at appropriate marginal cost level (as proposed above) that would be high enough to

discourage sources from choosing payment into the fund as their means of control, but low

enough so sources that could not obtain controls for a reasonable cost would not be penalized. 

The commenter further recommended that EPA use safety valve proceeds to purchase additional

cost-effective off-utility (EGU) sector reductions, not to purchase or confiscate mercury

allowances from future years. By implementing the recommended safety valve provision, the

commenter believed EPA could prevent delay in important air quality achievements. Moreover,

the commenter supported the use of any excess safety valve funds to provide capital for the

development of better, more efficient mercury controls.

Response:

EPA is not finalizing a safety valve provision in CAMR. EPA maintains that the safety

valve mechanism is not necessary to address market volatility associated with the Hg reduction

requirements. This issue is discussed in detail in section IV of today’s preamble.

Comment:

One commenter supported the proposed safety valve price level as a means of capping the

overall economic impact of controlling mercury emissions. The commenter submitted the price

cap would be critical considering that there is no commercially demonstrated control technology. 

The commenter agreed that EPA’s cap-and-trade program would effectively address alleged

mercury hot spots and concluded that most cost-effective reductions will be made at the larger,

higher emitting sources. The commenter also agreed the remaining uncontrolled emissions would

be largely elemental mercury that is not as likely to be deposited locally as is the particulate and

oxidized mercury. (69 FR 4703.)

However, the commenter was unclear how a safety valve would be an effective tool to

minimize unanticipated market volatility if the future year cap were reduced by the borrowed

amount. The commenter believed that while it may alleviate compliance concerns, at some point

in time triggering the safety valve in multiple years could compound future compliance

requirements unless industry were able to effectively reduce future mercury emissions within a

reasonable time frame.
clxxi

The commenter recommended that if the safety valve is triggered, the annual allocations to

the plant withdrawing from the safety valve pool should be decreased at a rate of 0.5 ounces for

every ounce of mercury it purchased under the safety valve. (69 FR 4704.)

Response:

EPA is not finalizing a safety valve provision in CAMR. EPA maintains that the safety

valve mechanism is not necessary to address market volatility associated with the Hg reduction

requirements. This issue is discussed in detail in section IV of today’s preamble.

5.8.3 Early Reduction Credits and Incentive Pools

Comment:

One commenter (OAR-2002-0056-3531) further suggested, if the EPA were to create an

early reduction credit program, significant reductions prior to 2010 would still be achieved by

units coming on line early to earn the ERCs. The commenter concluded that as a result, early

mercury reductions will be achieved while still allowing for a reasonable cost effective installation

schedule.

Response:

The first phase Hg cap is set at a level that requires no additional installation of controls

relative to CAIR, because it is set at a level that represents projected cobenefit mercury

reductions that will occur as a result of NOx and SO2 control technologies installed under CAIR. 

Acid Rain Program units and SIP call units can bank excess NOx and SO2 reductions achieved

prior to 2010 for use under CAIR. Further, EPA is finalizing that banking be allowed without

restriction from the start of the Hg cap-and-trade program. Banking of allowances will provide

flexibility to sources, encourage earlier or greater reductions than required, stimulate the

market, and encourage efficiency.

Comment:

One commenter (OAR-2002-0056-3444) stated that the proposed initial compliance date

of 2010 creates a large uncertainty in the ability of the Electric Generating Industry to achieve the

reductions required by the initial mercury cap. To assist the industry and the EPA in achieving

these target reductions the commenter believed it would be necessary to implement an Early

Reduction Credit (ERC) program to create incentives for coal fired Utility Units to install controls

well before the 2010 target date. The commenter submitted that to effectively achieve early

mercury reductions the following elements should be part of the proposed ERC program: 1)

Installation of controls must be accomplished prior to 2009; 2) Continuous Mercury Emissions

Monitoring Systems must be installed with a minimum demonstrated data availability of

90 percent; 3) Installed control efficiency must meet or exceed the co-benefit removal efficiency

target for the type of coal being combusted; 4) ERC’s allocated to sources must be used prior to

the 2018 final budget compliance date.
clxxii

Response:

The first phase Hg cap is set at a level that requires no additional installation of controls

relative to CAIR, because it is set at a level that represents projected cobenefit mercury

reductions that will occur as a result of NOx and SO2 control technologies installed under CAIR.

Acid Rain Program units and SIP call units can bank excess NOx and SO2 reductions achieved

prior to 2010 for use under CAIR, and sources will be allowed to bank starting at beginning of

the first phase of the Hg cap-and-trade program.

Comment:

One commenter (OAR-2002-0056-4891) added emissions reductions credits should be

provided to facilities subject to the rule for commissioning projects that achieve mercury

emissions reductions from other mercury emission sources.

Response:

The ability to accurately measure emissions reductions, and thus guarantee the value of

an allowance, is essential to a successful cap-and-trade program. Allowing credit to be used in

the Hg cap-and-trade program for utilities from off-sector reductions that may not have

adequate Hg emissions monitoring, would jeopardize the certainty behind the value of an

allowance, and thus the functioning of the trading program.

Comment:

One commenter (OAR-2002-0056-3446) recommended that EPA develop a technology

incentive pool, a mechanism in which allowances from the first compliance period would be

distributed early to plants that deploy advanced mercury control technology. This would spread

the risks of technology development and help build confidence in the performance and cost of

advanced control technologies. The commenter stated that an IPM modeling run found a

2.6 ton/yr incentive pool (with a 26-ton Phase I cap and a 15-ton Phase II cap) would achieve a

total penetration of 31 GW of ACI in 2010 and 48 GW of ACI in 2015–11 and 5 GW of ACI

penetration more than a program with no technology incentive pool. The commenter added that

this added technology penetration would be achieved at an incremental net present value cost of

$400 million or 0.6 percent of total 3-pollutant compliance costs.

Response:

While the proposed technology incentive pool has merit for the potential to stimulate

earlier adoption of Hg control technology, EPA believes that the market forces at work under the

Hg cap-and-trade program will act to promote the development of Hg control technology, and

the technology incentive pool is not necessary. 

Comment: Several commenters (OAR-2002-0056-2181, 2519) noted the EPA has

indicated that it is examining a possible incentive within the cap and trade program that would
clxxiii

provide and set aside allowances that would be used to develop so called “technology incentive

pools.” EPA appears particularly concerned with providing a technology assist for the

development and deployment of activated carbon injection (ACI) systems. The commenters had

serious concerns about applying such a system in the context of a cap and trade program because

it would conflict with the goal of a system that allows market forces to set the cost of compliance. 

The commenters stated that in a trading program, an appropriately set cap should be the signal

that will drive the appropriate economic response, which may include any number of market

driven reactions, such as new technology investments, fuel choices or efficiency standards. One

of the primary advantages of the cap and trade approach is the ability to drive the development of

new technology solutions that are not foreseen in the program design. The commenters believed

that any technology set-aside within the context of a trading program would tend to predetermine

an economic outcome, generally at the expense of alternative choices that may provide consumers

with lower cost solutions, a more aggressive environmental benefit, or both. The commenters

submitted that this has been well documented in earlier cap and trade programs in which new and

lower cost solutions that were not expected or predicted during the program design period

successfully evolved and were deployed. The future success of the program should not be

constrained by trying to anticipate future technology or market solutions. The commenters stated

the program will find the right answers if it is designed to treat all sources equally and reward

efficiency and low emissions.

Response:

While the proposed technology incentive pool has merit for the potential to stimulate

earlier adoption of Hg control technology, EPA believes that the market forces at work under the

Hg cap-and-trade program will act to promote the development of Hg control technology, and

the technology incentive pool is not necessary. 

Comment:

Many commenters (OAR-2002-0056-1608, -1673, -1814, -2163, -2180, -2224, -2375,

-2718, -2725, -2835, -2843, -2845, -2850, -2861, -2862, -2900, -2907, -2922, -2948, -2951,

-3431, -3444, -3521, -4132) suggested that EPA should provide for early reduction credits. One

commenter (OAR-2002-0056-2180) stated that to encourage development and implementation of

technologies that reduce mercury emissions, and to help insure a workable cap and trade program,

there should be a crediting program for early mercury reductions. One commenter

(OAR-2002-0056-2725) believed that early reductions reduce the overall mercury loading in the

environment and, to the extent power plant reductions will have a positive impact on public

health, achieve those benefits earlier. In particular, for the proposed trading program, the

commenter supported setting the “baseline” from which reductions will be measured at an earlier

date and protecting the ability to bank allowances throughout the program.

Response:

EPA is not finalizing an early reduction program. The first phase Hg cap is set at a level

that requires no additional installation of controls relative to CAIR, because it is set at a level
clxxiv

that represents projected cobenefit mercury reductions that will occur as a result of NOx and SO2

control technologies installed under CAIR. Acid Rain Program units and SIP call units can

bank excess NOx and SO2 reductions achieved prior to 2010 for use under CAIR, and sources

will be allowed to bank starting at beginning of the first phase of the Hg cap-and-trade program. 

EPA believes that the cap-and-trade program, by relying on market forces, will provide

incentives for the development of mercury control technologies.

Comment:

Several commenters (OAR-2002-0056-2862, -2922) supported the creation of an early

reduction credit feature as part of the mercury trading program to aid in the development of

mercury emissions control technologies. One commenter (OAR-2002-0056-2922) stated that

EPA should create a small reserve of early reduction credits for units that install mercury-specific

control technology by 2014. The commenters (OAR-2002-0056-2862, -2922) submitted that

EPA should limit the program to mercury-specific controls; no credits should be given for the

installation of scrubbers, SCRs, or other controls designed primarily to reduce emissions of NOx,

SO2, or other non-mercury emissions. The commenters believed EPA should award credits only

for reductions of mercury emissions that result from mercury-specific controls that go beyond the

reductions achieved as co-benefits from NOx or SO2 controls.

Response:

EPA is not finalizing an early reduction program. EPA believes that the cap-and-trade

program, by relying on market forces, will provide incentives for the development of mercury

control technologies. Additionally, the ability of sources to bank allowances starting at the

beginning of the Hg cap-and-trade program, will provide flexibility to sources, encourage

earlier or greater reductions than required, stimulate the market, and encourage efficiency.

Comment:

Commenter OAR-2002-0056-2861 stated that under the recommended alternate cap and

trade proposal (first cap and allocations begin in 2015), the commenter recommended an early

reduction credit program that provides credit only for reductions attributed to technologies

designed specifically to capture mercury. The utility would provide a demonstration of the

removal efficiency and would be provided credit for the difference between actual mercury

emissions and emissions that would have occurred without the use of the technology. The

commenter suggested the operating permit would specify conditions to verify control technology

performance.

If EPA establishes a cap and trade program that begins in 2010, then commenter

OAR-2002-0056-2861 believed an early reduction credit program would be even more important

and should include credit for reductions achieved as a co-benefit of SO2 and NOx controls. The

commenter suggested that in order to earn early reduction credits, EPA would need to require

only that the facility install appropriate monitoring technology to quantify emissions and the level

of mercury removal resulting from the installation of emission controls for SO2 and NOx or
clxxv

demonstration technologies specifically aimed at removing mercury. The commenter noted that

the level of “co-benefits” associated with SO2 and NOx controls is uncertain and variable, and

utilities will need to work with the technologies to develop ways to enhance their removal

efficiencies. The commenter submitted that compliance by 2010 will also be very difficult, and

providing an early reduction credit program will help facilitate compliance while preserving the

nation’s fuel diversity. Early reduction credits would provide an incentive for companies to install

and operate emissions controls and achieve reductions sooner than they otherwise would. The

commenter suggested that if EPA has concerns that too many early reduction credits would be

banked, it can create a “Compliance Supplement Pool” similar to the program used in the NOx

SIP Call, thus limiting the number of allowances that could be earned through early reductions.

Response:

EPA is not finalizing an early reduction program. The first phase Hg cap is set at a level

that requires no additional installation of controls relative to CAIR, because it is set at a level

that represents projected cobenefit mercury reductions that will occur as a result of NOx and SO2

control technologies installed under CAIR. Acid Rain Program units and SIP call units can

bank excess NOx and SO2 reductions achieved prior to 2010 for use under CAIR, and sources

will be allowed to bank starting at beginning of the first phase of the Hg cap-and-trade program.

Comment:

Several other commenters (OAR-2002-0056-1608, -2850, -3521) also stated that EPA

should provide early reduction credits for mercury-specific add-on controls. Several of these

commenters (OAR-2002-0056-2907, -3521) stated early reduction credits should be awarded

units that implement mercury-specific controls prior to 2015. Several of these commenters

(OAR-2002-0056-2907, -2850) also supported early reduction credits for coal plant closures. 

Similarly, one commenter (OAR-2002-0056-4132) stated that EPA must provide early reduction

credits for plants shutting down. The commenter noted that the economic burden of this mercury

initiative may force the shutdown of some of the oldest EGUS. If these units shutdown, yielding

early reductions in mercury emissions, it is important that early reduction credits be provided. 

The commenter emphasized that the final regulations should expressly and properly acknowledge

this approach to early reductions.

Response:

EPA is not finalizing an early reduction program. EPA believes that the cap-and-trade

program, by relying on market forces, will provide incentives for the development of mercury

control technologies. Additionally, the ability of sources to bank allowances starting at the

beginning of the Hg cap-and-trade program, will provide flexibility to sources, encourage

earlier or greater reductions than required, stimulate the market, and encourage efficiency. 

Further, EPA is not projecting that any additional coal-fired capacity will be uneconomic to

maintain relative to CAIR under the combination of CAIR and CAMR.

Comment:
clxxvi

One commenter (OAR-2002-0056-1673) stated that the IAQR and mercury rules should

provide utilities with the incentive to undertake early reduction measures, such as year round

operation of SCRs currently operated during the ozone season. This would provide immediate

NOx and mercury reduction benefits. Another commenter (OAR-2002-0056-1814) submitted that

early reduction credits would provide an incentive for companies to install and operate emissions

controls and achieve these co-benefits earlier. The commenter believes these credits are also

important in aiding companies in meeting very aggressive schedules for installation of equipment. 

A third commenter (OAR-2002-0056-2845) stated that credits for early reductions could be

coupled with additional early SO2 reductions in the CAIR proposal. The commenter believed the

proposed rule should provide credit for reductions achieved from the installation and/or

modification of emission or combustion control technologies like early installation and operation

of scrubbers, SCR, and ACI. The commenter stated that credit should not be available for

reductions required under federal regulations.

Response:

EPA is not finalizing an early reduction program. The first phase Hg cap is set at a level

that requires no additional installation of controls relative to CAIR, because it is set at a level

that represents projected cobenefit mercury reductions that will occur as a result of NOx and SO2

control technologies installed under CAIR. Acid Rain Program units and SIP call units can

bank excess NOx and SO2 reductions achieved prior to 2010 for use under CAIR, and sources

will be allowed to bank starting at beginning of the first phase of the Hg cap-and-trade program. 

See the CAIR preamble for discussion of early reduction credits under that rule. 

Comment:

Several commenters (OAR-2002-0056-2224, -2835) noted that an early reduction credit

system is consistent with the concept of “banking” surplus reductions under a market-based,

cap-and-trade regulatory approach. Commenter OAR-2002-0056-2224 noted that in order to

facilitate this action, details pertaining to the baseline, measurement, deadline and time line

mechanisms would need to be sorted out in the final rule. Commenter OAR-2002-0056-2835

believed that an early reduction credit would not compromise the environmental integrity of the

trading program because only a small number of sources would be able to take advantage of this

feature. According to the commenters, from a policy perspective, early mercury reductions

should be encouraged because they deliver an important environment benefit in advance of the

regulatory control program. The commenters further added that credit should only be granted

where a facility can demonstrate that the reductions are real and quantifiable. The commenter

also added that any early reduction credit scheme should not penalize a facility for such reductions

by reducing the allocations the facility would receive under the trading program.

Response:

EPA is not finalizing an early reduction program. The first phase Hg cap is set at a level

that requires no additional installation of controls relative to CAIR, because it is set at a level
clxxvii

that represents projected cobenefit mercury reductions that will occur as a result of NOx and SO2

control technologies installed under CAIR.

Comment:

One commenter (OAR-2002-0056-2163) noted that cost-effective implementation of any

new technology requires experience with full-scale installations over extended periods of

operation. The commenter stated there are always forward-thinking utilities who are interested in

early adoption of new pollution control strategies. The commenter believed these utilities should

be offered incentives to promote this early adoption strategy and to encourage the refinement and

deployment of control technology options. Such incentives could include bankable and/or salable

emissions credits. The commenter strongly encouraged EPA to work with these early adopters to

creatively develop a strategy that offers broad incentives for early implementation.

Response:

EPA believes that the market forces at work under the Hg cap-and-trade program will

provide incentives for the development of Hg control technology. This incentive will be further

strengthened by the ability of sources to bank allowances from excess mercury reductions

starting at the beginning of the Hg cap-and-trade program.

Several commenters (OAR-2002-0056-2375, -2718) proposed that sources be able to earn

ERCs before the Phase I deadline in 2010. To address concerns that such a provision may

jeopardize the integrity of the Phase I and Phase II caps, commenter OAR-2002-0056-2375

submitted that ERCs should be discounted at a 2-to-1 ratio upon registration into the mercury

bank. Sources would be permitted to use ERCs without discount during Phase I and Phase II. 

The commenter (OAR-2002-0056-2375) asserted that an ERC program is supportable on public

policy grounds. The commenter believed an ERC provision in the final rule would encourage

sources not yet equipped with mercury controls to install and operate them before the January

2010 deadline, where feasible, so that greater reductions would be achieved earlier. The

commenter’s proposal that ERCs be discounted at a 2-to-1 rate upon registration in the mercury

bank would achieve added benefits by ensuring that sources would be permitted to emit only one

ounce of mercury after Phase I takes effect for every two ounces of mercury reduced prior to

January 2010. The commenter believed in addition, an ERC provision would provide sources with

much-needed compliance flexibility for meeting the Phase I deadline. Similarly, commenter 2718

proposed that affected sources that implement mercury CEMs monitoring be permitted to earn

ERCs at a 2-to-1 ratio such that one credit would issue for every two ounces of mercury

emissions reduced from the source’s baseline. Sources using other methods, such as stack testing

or look-up tables, would be subject to a 3-to-1 issuance ratio.

Response:

EPA is not finalizing an early reduction program. EPA believes that the cap-and-trade

program, by relying on market forces, will provide incentives for the development of mercury

control technologies. Additionally, the ability of sources to bank allowances starting at the
clxxviii

beginning of the Hg cap-and-trade program, will provide flexibility to sources, encourage

earlier or greater reductions than required, stimulate the market, and encourage efficiency.

One commenter (OAR-2002-0056-2907) participated in programs to voluntarily reduce

emissions from its facilities prior to adoption of mandatory programs. The commenter believed

EPA should not penalize the commenter’s efforts and the efforts of similar proactive companies

by reducing mercury allowance allocations to companies that make emission reductions prior to

the compliance dates required by this rule. Instead, EPA should encourage and support early

reductions by not restricting the banking of allowances created by early reduction programs. The

commenter believed all reductions completed prior to the compliance date should be credited

toward meeting the proposed cap.

Response:

EPA is not finalizing an early reduction program. The first phase Hg cap is set at a level

that requires no additional installation of controls relative to CAIR, because it is set at a level

that represents projected cobenefit mercury reductions that will occur as a result of NOx and SO2

control technologies installed under CAIR. Acid Rain Program units and SIP call units can

bank excess NOx and SO2 reductions achieved prior to 2010 for use under CAIR, and sources

will be allowed to bank starting at beginning of the first phase of the Hg cap-and-trade program. 

See the CAIR preamble for discussion of early reduction credits under that rule. 

Comment:

One commenter (OAR-2002-0056-2900) noted that Phase I of the Program is scheduled

to begin in 2010, to coincide with the first phase of the CAIR. In addition, EPA proposes to set

the Phase I mercury cap according to the co-benefits achieved from the SO2 and NOx reductions

mandated by the CAIR. However, it is not clear to the commenter what that level should be and,

if EPA is mistaken in the level of the Phase I mercury cap, it is possible that coal-fired EGUs will

not meet the cap even with the installation of stringent SO2 and NOx controls on each affected

unit. To alleviate this potential problem, the commenter recommended that EPA allow coal-fired

EGUs to generate early reduction credits that could be used during Phase 1. Specifically, the

commenter recommended that EPA grant mercury early reduction credits to sources that

demonstrate that their mercury emissions are below the amount they are allocated under Phase 1. 

The commenter also recommended sources should be allowed to generate early reduction credits

beginning with adoption of the Program until the start of Phase I, unless the units are retired or

repowered. They would not be eligible for early reduction credits until they have met the

Program’s initial certification procedures for mercury monitoring.

Response:

EPA is not finalizing an early reduction program. The first phase Hg cap is set at a level

that requires no additional installation of controls relative to CAIR, because it is set at a level

that represents projected cobenefit mercury reductions that will occur as a result of NOx and SO2

control technologies installed under CAIR. Acid Rain Program units and SIP call units can
clxxix

bank excess NOx and SO2 reductions achieved prior to 2010 for use under CAIR, and sources

will be allowed to bank starting at beginning of the first phase of the Hg cap-and-trade program. 

See the CAIR preamble for discussion of early reduction credits under that rule.

Comment:

To ensure that such early reduction credits would not simply expand the Phase I cap and

indefinitely put off achievement of the Phase II cap, the commenter (OAR-2002-0056-2900)

suggested that such early reduction credits expire in 2014, although the commenter advocated

unlimited banking for mercury allowances that are allocated to affected sources under each phase

of the program. The commenter believed that early reduction credits would help sources make

the transition to the Program. They also would improve the robustness of the market and would

offer EUSGUs an incentive to achieve reductions earlier than otherwise required. Finally, the

commenter believed early reduction credits will help avoid the need for sources to use the safety

valve that the Agency is proposing.

Response:

EPA is not finalizing an early reduction program. The first phase Hg cap is set at a level

that requires no additional installation of controls relative to CAIR, because it is set at a level

that represents projected cobenefit mercury reductions that will occur as a result of NOx and SO2

control technologies installed under CAIR. Additionally, the ability of sources to bank

allowances starting at the beginning of the Hg cap-and-trade program, will provide flexibility to

sources, encourage earlier or greater reductions than required, stimulate the market, and

encourage efficiency. 

Comment:

One commenter (OAR-2002-0056-2951) stated that to maximize the social benefits from

utility mercury emission limitations, the regulatory scheme needs the earliest possible compliance

date. The commenter called this the “Average Control Date.” The commenter added that just as

important, to minimize social costs we need the earliest possible date that utilities can get credit

for making technology-based mercury reductions. The commenter called this the “Mercury Credit

Date.”

The commenter stated that on their own, utilities have no incentives to reduce any

mercury emissions one minute before they have to. The commenter added that indeed, top utility

executives could be sued by their shareholders if they spent any money on mercury reductions any

earlier than required; that money should theoretically go to the shareholders.

The commenter stated that nationally, it is obviously advantageous to have orderly

mercury technology implementation, rather than the inefficiencies resulting from all of the utilities

and their subcontractors competing to have controls in place on all 1,100 boilers at the same date. 

The commenter believed, however, that social benefits are lost with any delay. The commenter

stated that, consequently, utilities should be able to make mercury reductions at some of their
clxxx

units early, ahead of the Average Control Date, and get credit that they can trade off by beginning

reductions at an equivalent amount of their units late. According to the commenter, as net

mercury emissions would be the same, society should be largely indifferent to such “banking.” 

The commenter believed if the tougher, more-costly sites come last, society even gains a bit.

The commenter suggested that to maximize the benefits of such flexibility, the temporal

trade-off period should be designed to be as wide as possible (and it need not necessarily be

symmetrical). The commenter stated that in particular, it should begin at the earliest conceivable

“Mercury Credit Date” because any early technology-adopters benefit everyone else by leading

the industry down the learning curve, resulting in lower total costs for everyone. The commenter

added that unfortunately, however, any early adopters would inevitably see higher costs and

greater risks than those who wait until the last minute, and they would be unable to capture the

social benefits of their pioneering, thus creating a classical market failure.

The commenter stated that consequently, there should be special incentives for early

technology-based mercury-reductions. The commenter added that for example, early

technology-driven mercury reductions could receive extra credit, perhaps at 2X, for banking

purposes. The commenter stressed that the positive social externalities of early technology

adopters are very real and very significant and efforts should be made to encourage them in

constructing any utility mercury regulatory framework.

The commenter further stated that there are no positive externalities with early switches to

lower-Hg-coal or for scrubbing co-benefit-based-reductions or other

non-innovative-technology-based Hg reductions. According to the commenter, while these types

of reductions could conceivably be banked, they might be difficult to substantiate or result in

zero-sum losses in unobserved parts of the system. The commenter believed they should not be

advantaged.

Response:

EPA believes that the cap-and-trade program, by relying on market forces, will provide

incentives for the development of mercury control technologies. Additionally, the ability of

sources to bank allowances starting at the beginning of the Hg cap-and-trade program, will

provide flexibility to sources, encourage earlier or greater reductions than required, stimulate

the market, and encourage efficiency. Therefore, EPA does not believe it is necessary to add

any additional provisions to the rule to promote technology adoption.

One commenter (OAR-2002-0056-2843) stated that if a cap-and-trade program is

promulgated, two essential elements must be preserved if new coal-fired units are to remain viable

resources for the future. First, because compliance with either emission rates or reductions

necessary under a “cap-and-trade” environment are uncertain at best, there must be a reliable and

readily available source of allowances available for purchase at a pre-determined price. The

commenter suggested that early reduction credits might be an available resource for these

allowances. Second, the commenter believed there should be a reservation of allowances for
clxxxi

allocation to new units. These should be available on a first-come, first-served basis until

exhausted.

Response:

EPA is not finalizing an early reduction program. The first phase Hg cap is set at a level

that requires no additional installation of controls relative to CAIR, because it is set at a level

that represents projected cobenefit mercury reductions that will occur as a result of NOx and SO2

control technologies installed under CAIR. Additionally, the ability of sources to bank

allowances starting at the beginning of the Hg cap-and-trade program, will provide flexibility to

sources, encourage earlier or greater reductions than required, stimulate the market, and

encourage efficiency.

Under the Hg cap-and-trade program, States determine how to allocate allowances to

sources. EPA provides an example allocation methodology in the model rule, which provides for

a new source set-aside.

Comment:

One commenter (OAR-2002-0056-2850) achieved about 17 percent reduction in mercury

stack emissions in 2000 compared to 1990 levels through optimizing fuel sourcing and plant

operation. The commenter’s coal units are also over 70 percent wet scrubbed for particulate and

sulfur dioxide removal, which combined with other voluntary mercury reduction activities has

reduced base line emissions relative to 1990 and compared to other utility units. Consequently,

the commenter stated that an equitable allocation of mercury reduction requirement stringency,

either through unit specific requirements or cap and trade program allowance allocation

methodology would be important for assuring reasonable credit for early action. The commenter

supported an equitable cap-and-trade approach as the preferred option for regulating electric

power sector mercury emissions, as that provides the most flexibility for achieving compliance

using new and often unproven technology.

Response:

EPA agrees with the commenter about the advantages of using cap-and-trade for

achieving mercury emissions reductions from the power sector. Under the Hg cap-and-trade

program, States have the authority to allocate allowances to sources. EPA’s example allocation

methodology is outlined in the preamble. EPA is not finalizing an early reduction credit

provisions. See the comments above regarding this issue.

Comment:

One commenter (OAR-2002-0056-3431) believed the market will send the proper signals

to influence early reductions that will drop mercury emissions at a sharp and steady rate as the

first phase compliance deadline approaches. The commenter stated that credit for such early

reductions can be patterned after the provisions of the NOx SIP Call and NOx budget rules and
clxxxii

could be granted for reductions in total mercury in coal from as-fired analyses and consumption

information. The commenter added that such information could be verified with annual stack

testing prior to installation of Hg Continuous Emission Monitoring Systems (CEMS). According

to the commenter ERCs are a “win-win” for EPA, industry, and the environment; the opportunity

to receive ERCs improves environmental performance, reduces cumulative compliance costs and

provides flexibility to deal with uncertainty in the trading market.

Response:

EPA is not finalizing an early reduction program. The first phase Hg cap is set at a level

that requires no additional installation of controls relative to CAIR, because it is set at a level

that represents projected cobenefit mercury reductions that will occur as a result of NOx and SO2

control technologies installed under CAIR. Additionally, the ability of sources to bank

allowances starting at the beginning of the Hg cap-and-trade program, will provide flexibility to

sources, encourage earlier or greater reductions than required, stimulate the market, and

encourage efficiency.

Comment:

One commenter (OAR-2002-0056-2067) stated that the proposed alternative

Cap-and-Trade approach would rely heavily on achieving mercury reductions through the

co-benefits of future installation of scrubbers to meet SO2 and NOx. The commenter added that

however, the Cap-and-Trade proposal failed to take into account that there are existing Utility

Units that have already achieved this Phase I reduction, and are currently operating with

significantly lower mercury emissions than the industry as a whole. The commenter asserted that

instead, Cap and Trade would subject these plants, such as the commenter’s primary generating

resource (which has been controlling mercury emissions for nearly 25 years), to the same cap as

the majority of Utility Units and provide allocations based on the assumption that existing

scrubbers do not exist, creating an unrealistically low emissions level. The commenter stated that

Cap and Trade would fail to give appropriate credit to power plants that already are reducing

mercury emissions, and that indeed, it would create a greater burden on scrubbed plants because it

would effectively require scrubbed plants to achieve the same level of reductions as unscrubbed

plants. The commenter stated that this is a significant issue in the western United States where it

has been estimated that up to two-thirds of Utility Units are presently scrubbed. According to the

commenter, this approach imposes a disproportionately high burden on power plants that are

already scrubbed, such as the commenter’s primary generating resource, and is a fundamental flaw

of Cap and Trade that is avoided under MACT.

The commenter stated that, in the event EPA selects the Cap-and-Trade approach to

regulating mercury, key modifications would be necessary to make Cap and Trade workable. 

According to the commenter, the net effect is that while Cap and Trade is designed to achieve a

total reduction of 70 percent from current levels, units that have existing scrubbers will be

required to achieve this 70 percent reduction on top of existing reductions of nearly 70 percent. 

The commenter stated that it is fundamentally unfair for the EPA to give credit for mercury

reductions to utilities that install scrubbers for SO2 and NOx in the future, while not providing the
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same credit to those who installed the technology and have been reducing emissions for 25 years. 

The commenter asserted that in the event EPA adopts a Cap and Trade approach, EPA should

address this fundamental unfairness that would penalize utilities that have taken early steps to

reduce emissions. The commenter recommended that, at a minimum, Utility Units that have

existing scrubbers should be exempt from mercury reduction requirements through Phase I, and

should only be subjected to additional requirements in Phase II when the future co-benefits have

been recognized, and the next level of control is required.

Response:

EPA is not finalizing an early reduction program. The first phase Hg cap is set at a level

that requires no additional installation of controls relative to CAIR, because it is set at a level

that represents projected cobenefit mercury reductions that will occur as a result of NOx and SO2

control technologies installed under CAIR. Acid Rain Program units can bank excess SO2

reductions achieved prior to 2010 for use under CAIR, and sources will be allowed to bank

starting at beginning of the first phase of the Hg cap-and-trade program. See the CAIR

preamble for discussion of early reduction credits under that rule.

Comment:

One commenter (OAR-2002-0056-3469) recommended that EPA should implement a vigorous

research and development program to develop economically viable technology solutions–and

allow work on existing programs to be concluded–for all fuel sub-categories.

Response:

EPA’s Office of Research and Development currently participates in a program with

Department of Energy and industry representatives to assess mercury control technology

options. See the revised ORD White Paper on Hg control technology, available in the docket.

Comment:

One commenter (OAR-2002-0056-4891) recommended that EPA provide an option that

allows entities subject to the cap-and-trade program to “earn” emissions reduction credits for

commissioning or funding projects that result in the reduction of mercury emissions from other

mercury emissions point sources (e.g., fuel combustion; waste incineration; industrial processes;

and metal ore roasting, refining, and processing).

Response:

The ability to accurately measure emissions reductions, and thus guarantee the value of

an allowance, is essential to a successful cap-and-trade program. Allowing credit to be used in

the Hg cap-and-trade program for utilities from off-sector reductions that may not have

adequate Hg emissions monitoring, would jeopardize the certainty behind the value of an

allowance, and thus the functioning of the trading program.
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5.8.4 Other Model Trading Rule Requirements

Comment:

One commenter (OAR-2002-0056- 4139) supported the need for two primary types of

accounts-compliance accounts and general accounts. Compliance accounts would be created for

each Mercury Budget source with one or more Mercury Budget units upon receipt of the account

certificate of representation form. General accounts would be created for any organization or

individual upon receipt of a general account information form.

Response:

Today’s final rule contains provisions for the establishment of compliance accounts and

general accounts.

Comment:

One commenter (OAR-2002-0056-2287) suggested that the cap and trade system be open

to all interested parties, including communities and environmental groups so that they could also

bid for credits to use as they please.

Response:

Under the final rule, States are given the authority to allocate Hg allowances as they see

fit. However, individuals and groups that are not affected sources are allowed to hold Hg

allowances by establishing a general account.

Comment:

One commenter (OAR-2002-0056-3509) stated that to the extent that the final Utility

Mercury Rule does require controls of small municipal generators via allowance trading or other

requirements, EPA should provide these units with other compliance flexibility options to reduce

the cost of such compliance. Specifically, the commenter supported several of the proposals

made by EPA, including for facility-wide emissions averaging, measurement of emissions using

12-month rolling averages, the ability to bank mercury allowances without restriction, and the

ability to use “safety valve” allowances when the price of allowances exceed a reasonable cost

threshold.

Response:

EPA is finalizing a number of provisions as part of the cap-and-trade program in order

to provide flexibility to sources. Under the final rule, compliance will be assessed at the facility

level, and on a 12-month rolling average basis. Additionally, EPA is finalizing that banking be

allowed without restriction, beginning at the start of the first phase of the program. EPA is not
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finalizing a safety valve provision, for reasons discussed in the preamble, and section 5.8.2 of

this document.

Comment:

One commenter (OAR-2002-0056-2181) believed there were several key components of

the proposed rules that could set broad precedents within the electric power sector beyond just

the control of mercury, specifically in regard to the design of trading programs and allowance

allocation systems.

Response:

EPA believes that the final design of the Hg Budget Trading Program will result in an

efficient and effective program.

Comment:

One commenter (OAR-2002-0056-2067) expressed significant concern regarding what

entity actually receives the allocations in the Cap and Trade approach. The commenter stated that

if a Cap and Trade alternative is selected, it is important that emission allowances be awarded to

the owners of Utility Units, not the operators of such units. As a relatively small wholesale power

producer, the commenter is not able to economically construct, own and operate its own baseload

facilities. Rather, the commenter is a joint owner with other utilities in its primary generating

resource and would expect to utilize the same type of arrangement for any future baseload coal

additions to its resource portfolio. The commenter asserted that allowances should be allotted to

the unit owners on the basis of their ownership interest and should not be awarded to the

operators of the unit(s).

Response:

Hg allowances will be allocated by States to Hg Budget sources. Each Hg Budget source

affected under the Hg cap-and-trade program is required to have 1 Hg designated

representative, with regard to all matters under the trading program concerning the source or

any Hg Budget unit at the source. This representative shall be selected by an agreement binding

on the owners and operators of the source and all Hg Budget units at the source.

Comment:

One commenter (OAR-2002-0056-3537) stated that CAA §408(i) sets out an approach

regarding the holding and distribution of Title IV SO2 allowances and the proceeds of transactions

involving allowances, where there are multiple holders of a legal or equitable title to or a

leasehold interest in an affected unit. That provision in pertinent part provides that: “No permit

shall be issued under this section to an affected unit until the designated representative of the

owners or operators has filed a Certificate of Representation with regard to matters under this

subchapter, including the holding and distribution of allowances and the proceeds of transactions
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involving allowances. Where there are multiple holders of a legal or equitable title to, or a

leasehold interest in such unit, or where a utility or industrial customer purchases power from an

affected unit (or units) under life-of-the-unit, firm power contractual arrangements, the certificate

shall state (1) that allowances, and the proceeds of transactions involving allowances will be

deemed to be held or distributed in proportion to each holder’s legal, equitable, leasehold or

contractual reservation or entitlement, or (2) if such multiple holders have expressly provided for

a different distribution of allowances by contract, that allowances and the proceeds of transactions

involving allowances, will be deemed to be held or distributed in accordance with the contract. A

passive lessor, or a person who has an equitable interest through such lessor, whose rental

payments are not based, either directly or indirectly, upon the revenues or income from the

affected unit shall not be deemed to be a holder of a legal, equitable, leasehold, or contractual

interest for the purpose of holding or distributing allowances as provided in this subsection,

during either the term of such leasehold or thereafter, unless expressly provided for in the

leasehold agreement.” CAA §408(I).

The commenter submitted that clearly, when enacting Title IV of the CAAA, Congress

considered how allowances should be distributed to multiple owners of an affected unit. It

concluded that allowance allocations (or the proceeds from auctions) should track the ownership

interest in affected units, absent an agreement between the parties to the contrary. The

commenter believed there is nothing in the proposed mercury rule that would justify following a

different approach to the ultimate distribution of mercury allowances under EPA’s current

proposal. The commenter suggested, therefore, when proposing and promulgating regulatory

language to implement the requirements of the mercury cap and trade rule, EPA should encourage

States that promulgate cap and trade rules pursuant to CAA section 111 to use the approach

followed in CAA §408(i) as the method for allocating allowances among multiple owners of a

Utility Unit. The commenter also suggested that should EPA promulgate a cap and trade

program under CAA §112, then EPA should, as part of its method for allocating allowances,

follow the approach set forth in CAA §408(I).

Response:

Regarding the commenter’s concerns about rules and guidance on allocations, the model

trading rules already include provisions analogous to section 408(i) of the Clean Air Act.

Comment:

One commenter (OAR-2002-0056-2898) opposed EPA’s proposal to confiscate future

year allowances in the event a source does not have enough allowances to offset emissions. 

Rather, the commenter proposed that a fee be assessed for each pound of mercury that a source

exceeds its available allowances. The commenter suggested this source of revenue would fund

mercury control technology research and demonstration projects. The commenter added also,

these monies could be used to achieve off-utility system mercury reductions.

Response:
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EPA is finalizing that three Hg allowances for each ounce of emissions would be

deducted from a source’s compliance account for the following control period, in the event that

an affected source does not hold sufficient Hg allowances to offset emissions for the season. 

EPA believes that it is important to set up this automatic offset deduction because it is ensures

that non-compliance with the Hg emission limitations of this rule is a more expensive option

than controlling emissions. EPA required the same offset deduction of three to one in the NOx

SIP call. The automatic offset provisions do not limit the ability of the permitting authority or

EPA to take enforcement action under State law or the CAA.

Comment:

One commenter (OAR-2002-0056-3478) did not see the benefit to having a 3-to-l offset

for allowance shortages. The commenter believed the 1-to-1 offset penalty and deduction from

the next year’s subaccount in Acid Rain provides adequate control for shortages.

Response:

EPA is finalizing that three Hg allowances for each ounce of emissions would be

deducted from a source’s compliance account for the following control period, in the event that

an affected source does not hold sufficient Hg allowances to offset emissions for the season. 

EPA believes that it is important to set up this automatic offset deduction because it is ensures

that non-compliance with the Hg emission limitations of this rule is a more expensive option

than controlling emissions. EPA required the same offset deduction of three to one in the NOx

SIP call. The automatic offset provisions do not limit the ability of the permitting authority or

EPA to take enforcement action under State law or the CAA.

Comment:

One commenter (OAR-2002-0056-4132) noted that EPA has proposed that the Mercury

Budget Trading Program utilize source-wide compliance rather than unit-by-unit compliance. 

The commenter noted in particular, EPA proposed that sources would be allocated allowances

rather than individual units and, accordingly compliance would be source-wide rather than

unit-by-unit. The commenter strongly supported this concept. This would simplify the

administrative activities associated with ensuring that each unit account has sufficient allowances

by the end of the allowance transfer deadline.

Response:

EPA is finalizing that compliance with CAMR be assessed at the facility level.

Comment:

One commenter noted that EPA proposes to require compliance on a facility-wide basis

rather than on a unit-by-unit basis. Each facility would have a “compliance” account, which would

need to hold enough allowances to cover mercury emissions for an entire facility. The commenter
clxxxviii

believed this makes practical sense from a technology perspective, and simplifies program

accounting requirements.

Response:

EPA concurs, and is finalizing that compliance with CAMR be assessed at the facility

level.

Comment:

One commenter (OAR-2002-0056-4239) recommended using serial numbers of some

mechanism for tracking and reporting mercury emissions. The commenter stated the program

must be transparent to all entities. The commenter believed serial numbers encourage

transparency and benefits derived for tax and accounting purposes.

Response:

Under CAMR, each Hg allowance will be assigned a serial number for the purpose of

tracking allowances.

Comment: Several commenters (OAR-2002-0056-2634, -2830, -2835) requested that the

EPA include facility-wide averaging in the section 111 Emission Guidelines for existing sources as

an additional compliance alternative. States should be encouraged to allow such flexible

compliance alternatives if states decline to adopt a section 111 trading program, if that option is

selected by the EPA. By including this type of flexibility mechanism, the EPA will ensure that

those facilities located in States opting out of the trading program will retain some degree of

flexibility when complying with the requirements of the Emission Guidelines. Similarly,

facility-wide emissions averaging provides a flexible compliance alternative to a cap-and-trade

program in the event that neither cap-and-trade option can be authorized under the statute.

Varying operational modes or combination of systems, e.g., wet/dry scrubber, ESP or fabric filter,

could be employed to provide the greatest potential to economically reduce Hg emissions to meet

compliance requirements.

Response:

As discussed in the final preamble, States must submit a demonstration that it will meet

ist assigned emissions budget through reductions from coal-fired power plants. There are no

restrictions on states using facility-wide averaging.

5.8.5 Title V Permits

Comment:

One commenter (OAR-2002-0056-4139) stated that a Title V permit incorporates

applicable requirements that are created under other authorities, but does not directly establish
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specific standards unless explicitly provided by the CAA (such as periodic monitoring). In the

case of mercury budget program requirements, the proposed rule appeared to require permitting

authorities to directly create mercury permit requirements in Title V permits. The commenter

questioned what authority under the CAA allows the mercury budget rule to change Title V

program requirements and allow Title V to directly create mercury program permitting

requirements? 

One commenter (OAR-2002-0056-4139) submitted the proposed general permit

requirement in 40 CFR 60.4120 specified that the Mercury Budget portion of the Title V permit is

to be administered according to the permit authority’s Title V operating permits regulations. 

However, the proposed rule did not comport with existing permit content requirements

particularly for monitoring requirements. The commenter stated that the Title V permit must

directly identify the applicable limits or operational restrictions and what monitoring,

recordkeeping, and reporting requirements will be used to demonstrate compliance. The

commenter pointed out the proposed Mercury Budget permit portion does not include that same

level of detail.

One commenter (OAR-2002-0056-4139) noted the proposed general permit requirement

in 40 CFR 60.4120 specifies that the Mercury Budget portion of the Title V permit is to be

administered according to the permit authority’s Title V operating permits regulations. The

commenter submitted, however, the proposed rule did not comport with the Title V schedule

requirements for revising a permit to include new requirements. The proposed general permit

requirement in 40 CFR 60.4121 specified that the Mercury Budget permit application must be

submitted 18 months before January 1, 2010, (or the date the Mercury Budget unit commences

operation for new units). The commenter stated, however, 40 CFR 70.6(f) of the Title V

operating permits rules does not require that the source submit an application to revise a Title V

permit for new promulgated requirements. The permitting authority must reopen the permit for

cause if there are 3 or more years remaining before the current Title V permit expires.

One commenter (OAR-2002-0056-4139) noted the proposed rule did not comport with

the Title V permit renewal schedule. The proposed general permit requirement in 40 CFR

60.4121 (c) specified that the Mercury Budget authorized account representative must submit a

complete mercury budget permit application according to the permitting authority’s Title V

operating permit regulations for permit renew. However, most of the commenter’s Title V

permits for the listed Mercury Budget sources will not be due for renewal during the specified

Mercury Budget time frame. The commenter asked how does the Mercury Budget permit

renewal synchronize with the Title V renewal schedule? The commenter found the proposed

wording far too vague to adequately address the nuances of the renewal process.

One commenter (OAR-2002-0056-4139) stated that the proposed general permit

requirement in 40 CFR 60.4120 specified that the Mercury Budget portion of the Title V permit is

to be administered according to the permit authority’s Title V operating permits regulations. All

submittals pursuant to the Title V permit program must be certified by a responsible official, with

specific compliance certification requirements for annual and semiannual reports. The commenter

submitted, however, 40 CFR 60.4130 of the proposed rule would require data report and
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compliance certification submittals by the authorized account representative for different

information and based on schedules that do not mesh with the Title V time frame.

Response:

Under the Hg Budget model trading rule, a Hg Budget source that is already required to

have a title V operating permit is required to submit an application to the permitting authority

for a Hg Budget permit, which will become a complete and separable part of the title V permit. 

Sources not required to have title V permits do not have to apply for Hg Budget permits. For a

source required to have title V permit, the requirements of the model trading rule are applicable

requirements that, under title V , must be incorporated into the source’s title V permit because

the requirements of the model trading rule are requirements under section 111 of the CAA. See

40 C.F.R. 70.2 (definition of “applicable requirement”). In short, contrary to the commenter’s

statements, the title V permit is incorporating the requirements established by the Hg model

trading rule, which incorporation is analogous to the way the title V permit incorporates the

requirements established by other programs (e.g., the NOx SIP Call model trading rule) under

CAA. 

Comment:

One commenter (OAR-2002-0056-2922) suggested, as a general matter, that EPA pattern

the mercury cap-and-trade program on the Title IV Acid Rain Program. In that regard, EPA, as it

does in the Title IV program, should not require Title V operating permits to be reopened or

revised for allocation, transfer, or deduction of allowances. The commenter recommended in

addition, EPA should assign serial numbers to mercury allowances. The commenter believed that

although tracking and reporting serial numbers would result in some administrative burden, that

burden would be significantly outweighed by the benefits that serial numbers would provide for

tax and accounting purposes for regulated companies and other market participants.

Response:

EPA agrees that requiring title IV operating permits to be reopened or revised for

allocation, transfer, or deduction of allowances would create an unnecessary administrative

burden, and is finalizing that these be automatically incorporated in the Hg budget permit. 

Also, EPA is assigning serial numbers to Hg allowances for the purpose of tracking.

5.9 IMPLEMENTATION

5.9.1 State Plan Requirements

Comment:

One commenter (OAR-2002-0056-2247) noted the proposed trading program would

require a state to submit its first plan by 2006 for distributing allocations for 2010-2014. The

commenter’s state cannot meet this deadline. The commenter stated that mercury control rules
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and allowance distribution will be controversial; implementation will require having the legal

framework in place, sufficient administrative resources, and time for input from the industry and

the public. The commenter believed that at least 2 years would be needed after emission guideline

promulgation to complete a rule with more time needed to actually distribute allowances. The

commenter stated submittal of plans should be required at least 24 months after federal rule

promulgation.

Response:

EPA is requiring a state to submit its plan for distributing allocations for 2010-2014 by

October 21, 2006. As discussed in the final rule preamble, EPA believes this lead time is

necessary ensures that an affected source, regardless of the State in which the unit is located,

will have sufficient time to plan for compliance and implement their compliance planning.

Comment:

One commenter (OAR-2002-0056-3543) noted states would be required to submit a

SIP-type plan to regulate existing mercury sources; the plan would include unit-specific standards

for new units under section 111(b). It was unclear to the commenter what type of plan EPA is

requesting and if it will become part of a an air quality SIP.

Response:

EPA is requiring the submission of a State plan under section 111 of the CAA. Detailed

language describing the requirements of the State plan has been added to the regulatory text.

Comment:

One commenter (OAR-2002-0056-1678) submitted that relying on SIP to establish

mercury reduction levels would be administratively cumbersome and time consuming and likely to

result in disparate regulation.

Response:

EPA is requiring the submission of a State plan under section 111 of the CAA. Detailed

language describing the requirements of the State plan has been added to the regulatory text. 

EPA has provided a model rule that States can adopt in order to limit the administrative burden

on States and to create a uniform program among participating States.

Comment:

One commenter (OAR-2002-0056-2841) believed that if EPA establishes a cap-and-trade

program under the authority of section 112(n)(1)(A) and/or 112( d), EPA should amend the

definition of “emission standard” in 40 CFR 63.2 to read “pursuant to sections 112( d), 112(h),

112(f) or 112(n) of the Act.” Additionally, the commenter believed EPA should amend 40 CFR
cxcii

63.1(e) to read “If the Administrator promulgates an emission standard under section 112(d), (h),

or (n) of the Act. . .” 

Response:

EPA is finalizing a cap-and-trade program under section 111. See preamble for more

detail.

5.9.2 Approvability of Trading Rule

Comment:

Several commenters (OAR-2002-0056-2219, -2519, -3431) opposed allowing states to

decide the allocation of trading units and the time line for updating the allocations. One

commenter (OAR-2002-0056-2519) noted that states will have the right allocate mercury

emission allowances to individual sources or to choose any other allocation scheme a state deems

appropriate. In the event a state fails to submit its SIP, the model rule would become the SIP for

that state. The commenter believed the SIP process could result in some sources in one state

getting allowances much less than what was envisioned under the EPA’s state budgets while a

source in an adjoining state could receive more allowances than under the proposal. Under such a

situation, the first source would have to purchase allowances from the second or apply emission

controls. The commenter points out that such a scenario could result in an inefficient trading

program or unfair competitive issues among sources. Furthermore, preparation and submittal of

SIP must follow certain processes mandated by state Constitution, and that could result in some

delay in adopting the rule governing the trading program. The commenter stated that additional

time would consume part of the time allowed for compliance planning to achieve the emission

caps. The commenter submitted therefore, it is critical that EPA adopt a uniform program

throughout the country, much like the existing Acid Rain Control Program, rather than a

patchwork of differing requirements among various states. Accordingly, if EPA decides on a

cap-and-trade program rather than a MACT program, the commenter prefers the CAA

section 112 approach over the CAA section 111 approach.

Another commenter (OAR-2002-0056-3431) believed a major problem with utilizing a

CAA section 111 standard of performance approach to cap-and-trade would be that it requires

further decision-making at the state level regarding allowance allocation. According to the

commenter, the experience of the Northeast states with the NOx budget rule, which similarly left

the intrastate allocations to the affected states, was that the allocation process was extremely

contentious and subject to political influence. The commenter stated that for example, if the

prevailing view within a state was to rid the state of coal-fired utilities, the allocation scheme

would provide a powerful tool for making coal-fired units prohibitively expensive to run, to the

detriment of important national objectives of maintaining fuel diversity. Consequently, the

commenter favored a uniform allocation scheme imposed at the national level, based on the heat

input criteria expressed by EPA, but determined in a way that does not favor one coal type over

another.
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Several commenters (OAR-2002-0056-0730, -1682, -2064, -2108, -4139) supported the

CAA section 111(d) approach because it would allow more state and local input. Several

commenters (OAR-2002-0056-0730, -1682, -2064) submitted states are in the best position to

make allocations that protect the environment and address hot spots. One commenter

(OAR-2002-0056-2108) preferred to develop its own system for allowance allocation, flow

control, banking, and other trading issues. Another commenter (OAR-2002-0056-4139)

supported the proposed flexibility to choose what allowance allocation methodology states will

use to determine their mercury budgets: auction or free distribution of allowances, permanent or

updated allowances, and allowances based on input, output, or emission reductions. The

commenter stated that for interstate trade, however, the rule should specify that the trade is

allowable only if the section 111(d) limits for existing sources are as stringent or more stringent in

the selling state as for the facility in the purchasing state. The commenter believed that while this

is more complicated because of the different subcategories, a matrix to represent appropriate

exchanges could be developed.

One commenter (OAR-2002-0056-3437) stated that in the NPR and SNPR states are

allowed to establish their own allocation methodology. The commenter assumed this would

include existing and new sources and any set asides. EPA then requested comment on whether an

allocation methodology should be mandated depending on whether a state participates in an

interstate trading program, an intrastate trading program, or no trading program. The commenter

believed states should have the flexibility in addressing the allocations under the cap irrespective

of participation in a particular program.

One commenter (OAR-2002-0056-3552) commented on whether to require the State to

allocate allowances to each unit in accordance with the model cap and trade rule. According to

the proposal, a state may allocate allowances using its own method. The commenter requested

the flexibility not to follow EPA’s methodology if the state determines it is not stringent enough

to protect the public health. The commenter submitted that many states are limited in their

rulemaking authority to be no stricter than federal standards.

One commenter (OAR-2002-0056-2181) noted that while EPA uses a heat input rate

adjusted by subcategories by fuel source for determining State budgets, States may choose how

they will allocate allowances to each affected Utility Unit. The commenter agreed that States

should not be mandated to use the proposed hypothetical allocation method when budgeting to

specific units. Among the choices the EPA recognized, States may consider a baseline heat input

or baseline power output, updating or permanent allocation, and auction programs. The

commenter believed that while on the one hand, EPA is careful to encourage States to utilize an

approach that is best suited for specific State circumstances, on the other, it notes that those who

adopt its method can count on a quick approval by the Agency. The commenter submitted this

could bias certain States toward adopting the EPA approach without offering thorough

consideration of the benefits of alternative allocation strategies. The commenter recommended

that EPA eliminate this inherent bias.
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Several commenters (OAR-2002-0056-1671, -2064) submitted that the rule should allow

states to permanently retire mercury credits. The commenters added that credits should expire by

a final compliance date.

One commenter (OAR-2002-0056-2898) suggested that EPA could provide a mechanism

for units to petition EPA to provide fair and accurate allocations to existing units. The

commenter supported the comments submitted to EPA on this issue by the National Rural

Electric Cooperative Association.

One commenter (OAR-2002-0056-2721) noted that EPA is leaving the options to the

individual states to determine if the allowances would be permanently issued: 1) year by year,

2) 5-10 year allocations where mercury allowance allocations would be periodically placed into

the Mercury allowance Trading system for 5-10 consecutive control periods, or 3) a single

permanent allocation where the mercury allowance allocation would be set only once in the

beginning of the trading program. The commenter supported the permanent issuance of

allowances. The commenter stated this would allow utilities to be better prepared for planning for

the future. This planning would allow them to put in-place the appropriate removal technologies

without jeopardizing electrical generation and other balance of plant issues. The commenter

stated that new units after initial allocation would be required to go to the marketplace to gain

allowances under option 3. Under options 1 and 2 the new unit would be allocated allowances

only with a corresponding reduction from an existing unit. The commenter submitted that the

uncertainty is in what allocation plan each state chooses. The commenter believed that leaving the

choice up to the states would weaken the overall trading program and place an unfair financial

burden on these facilities, especially for units in a state with few allowances.

Response:

State adoption of the model rule will ensure consistency in certain key operational

elements of the program among participating States, while allowing each State flexibility in

other important program elements. Uniformity of the key operational elements is necessary to

ensure a viable and efficient trading program with low transaction costs and minimum

administrative costs for sources, States, and EPA. Consistency in areas such as allowance

management, compliance, penalties, banking, emissions monitoring and reporting and

accountability are essential.

The EPA’s intent in issuing a model rule for the Hg Budget Trading Program is to

provide States with a model program that serves as an approvable strategy for achieving the

required reductions. States choosing to participate in the program will be responsible for

adopting State regulations to support the Hg Budget Trading Program, and submitting those

rules as part of the State Plan. There are two alternatives for a State to use in joining the Hg

Budget Trading Program: incorporate 40 CFR part 60, subpart HHHH by reference into the

State’s regulations or adopt State regulations that mirror 40 CFR part 60, subpart HHHH, but

for the potential variations described below.
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Some variations and omissions from the model rule are acceptable in a State rule. This

approach provides States flexibility while still ensuring the environmental results and

administrative feasibility of the program. EPA finalizes that in order for a State Plan to be

approved for State participation in the Hg Budget Trading Program, the State rule should not

deviate from the model rule except in the area of allowance allocation methodology. Allowances

allocation methodology includes any updating system and any methodology for allocating to new

units. Additionally, States may incorporate a mechanism for implementing more stringent

controls at the State level within their allowance allocation methodology.

State plans incorporating a trading program that is not approved for inclusion in the Hg

Budget Trading Program may still be acceptable for purposes of achieving some or all of a

State’s obligations provided the general criteria. However, only States participating in the Hg

Budget Trading Program would be included in EPA’s tracking systems for Hg emissions and

allowances used to administer the multi-state trading program.

In terms of allocations, States must include an allocation section in their rule, conform to

the timing requirements for submission of allocations to EPA that are described in this

preamble, and allocate an amount of allowances that does not exceed their State trading

program budget. However, States may allocate allowances to budget sources according to

whatever methodology they choose. EPA has included an optional allocation methodology but

States are free to allocate as they see fit within the bounds specified above, and still receive State

Plan approval for purposes of the Hg Budget Trading Program.

5.9.3 State Authority under 111

Comment:

Several commenters (OAR-2002-0056-1692, -1802, -2911, -2915, -3432, -3445, -3454,

-3463, -3543, -3556, -4191, -4891) stated a preference for a national trading program. One

commenter (OAR-2002-0056-1692) stated that the flexibility inherent in well-designed emission

trading programs, such as the Title IV acid rain program, is preferable to the rigidities of unit- or

source-specific controls. The commenter believed however, in order to secure the benefits of this

flexibility, either of the alternative regulatory vehicles EPA proposed under sections 111(d) or

112(n)(1) must lend itself to a truly national emissions trading program, with certainty in the

assignment of emission allowances–essential for planning and executing cost-effective emission

control strategies. The commenter stated that the “opt- in” nature of state participation in the

111(d) proposal, which provides too much leeway to individual state SIP determination

processes, and the open-ended potential for risk-based assessment of mercury reduction

requirements under the 112(n)(1) alternative, jeopardizes the benefits associated with a

well-designed emissions trading regime. (Many commenters expressed concerns with the opt-in

nature of state participation in the CAA 111(d) proposal; see comment below in this section.)

One commenter (OAR-2002-0056-3543) stated that a national program is needed to

control mercury emissions to help restore Texas water bodies since evidence exists that some

significant portion of the mercury originates beyond Texas borders. Several commenters
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(OAR-2002-0056-2915, -4191) submitted that mercury allowances trading should be allowed to

occur throughout the nation to make the cap and trade program as viable as possible. The

commenters believe a nation-wide trading market would reduce mercury emissions faster and

more cost effectively because there would be increased opportunities and demand for early

mercury reductions that could be “banked” for later use. Several commenters

(OAR-2002-0056-3432, -3445) stated that EPA must not allow individual states to interfere with

an emission trading compliance option. Commenter (OAR-2002-0056-3445) added that in order

for a mercury trading program to be successful, a robust marketplace is necessary. The

commenter believed that if trading is restricted, the efficiencies of a cap-and-trade system would

be lost.

Several commenters (OAR-2002-0056-1673, -2929) submitted that trading should be

allowed over the broadest interstate region or largest area possible. One commenter

(OAR-2002-0056-2929) stated that this would capitalize on all efficiencies. The commenter

believed EPA should make every attempt to promote unfettered emissions trading in the final

mercury rule.

One commenter (OAR-2002-0056-2160) submitted that if EPA chooses a cap and trade

approach, allowances should be tradable across state boundaries.

One commenter (OAR-2002-0056-2161) stated both the MACT and Cap-and-Trade

approaches have attributes and problems. Whichever approach EPA chooses, the commenter felt

it would be imperative that EPA continue to recognize in any regulation the inherent problems

with controlling mercury for plants burning subbituminous coal. The commenter believed the

proposed MACT level of control for subbituminous plants is appropriate; if EPA deemed it

necessary to appreciably change this level, the commenter strongly urged EPA to re-propose this

regulation. The commenter submitted that if EPA chose a Cap and Trade program, it should be

patterned after the highly successful Title IV SO2 program. The commenter urged EPA to ensure

that this program is applied in a consistent manner across the states. Differences in program

design or implementation by individual states must be minimized. The commenter agreed that as

EPA discussed in their proposal for an NSPS cap and trade program, the Title IV program has

demonstrated that it is an effective program and has substantially reduced emissions of acid rain

precursors.

Many commenters (OAR-2002-0056-1802, -1859, -2224, -2264, -2422, -2452, -2560,

-2835, -2850, -2897, -2911, -2948, -3452, -3463, -3514, -4891) expressed concern that the

“opt-in” nature of state participation in the CAA section 111(d) program would provide too much

uncertainty associated with individual SIP determination processes. Specific concerns stated by

the commenters included the following: states may not participate in a national trading program;

arbitrary confiscation or other limitations on the use of emission allowances; reallocation of

emission allowances among non-emitting source sectors, e.g., non-coal fired EGUs; patchwork of

programs varying from state to state; states promoting premature emission allowance retirement;

time required for review and approval of separate SIP by state approval authorities, including the

necessary notice and public hearings, followed by the necessary review by the EPA will likely

extend to a number of years; and a fragmented trading system would not allow sufficient trading
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to be economical for smaller facilities. The commenters felt that for trading programs to be

efficient, equitable, and effective, they must by uniformly applied over broad geographic regions.

Several commenters (OAR-2002-0056-2251, -2332, -2560, -2818, -2835, -2862, -2915,

-2948, -3431, -3469, -3514, -4191) believed that state participation in a mercury cap-and-trade

program should be mandatory or that states should be prohibited from interfering with the

cap-and-trade program. One commenter (OAR-2002-0056-3431) stated EPA should require

participation by all states in a mercury cap-and-trade program to create a robust and efficient

market system. The commenter stated that a national cap-and-trade program offers the most

certainty, flexibility and cost effectiveness for the industry as a whole. According to the

commenter, past experience with the Acid Rain program demonstrated that for a cap-and-trade

program to be successful, it must have broad-based participation by the states. The commenter

stated that even the NOx Budget Rule in the Northeast, which allowed for some state variation

from a model rule, was slow to develop into a robust market with readily available interstate

trades. According to the commenter, only when is there a robust market is the development of

cost effective control technologies incentivized. The commenter believed if states are given the

option not to participate in a cap and trade program or to create significant variation in their rule

pursuant to a CAA §111 SIP approach, the overall target mercury reduction may not be achieved

and non-participating states would disadvantage generation in their state by increasing generation

costs and reducing system reliability. One other commenter (OAR-2002-0056-2560) cited

success of the Title IV Acid Rain SO2 program being attributed to mandatory participation. One

commenter (OAR-2002-0056-3514) stated they would only support regulation under CAA

section 111 if states are required to fully participate in the section 111 interstate cap-and-trade

program.

One commenter (OAR-2002-0056-2862) believed a federal mercury emission program

would be most appropriate for an emission that is national and global in scope. The commenter

submitted that if EPA decides to proceed to regulate mercury under a section 111 Cap and Trade

alternative, states must be required to participate in the interstate cap-and-trade program. With

this alternative, the federal performance standard would be implemented as a state-specific

emissions cap.

One commenter (OAR-2002-0056-2948) stated that in order for the trading program to

be successful, EPA would need to prohibit states from interfering with any mercury cap-and-trade

program. The commenter added that although states are permitted under the Act to impose more

stringent emissions limitations on sources within their borders, states must be expressly prohibited

from restricting the ability of sources to sell or trade mercury allowances. The commenter also

stated that similarly, EPA needs to prohibit states from interfering with the EPA-established cap

on mercury emissions. According to the commenter, in the final rule, EPA needs to make clear

that states cannot require sources within their borders to surrender more allowances than federally

required and cannot place restrictions on the sale of mercury allowances by sources within their

borders. Another commenter (OAR-2002-0056-2835) recommended that EPA reduce the

opportunity for widely diverging state plans by prescribing the manner in which states allocate

allowances to sources participating in the trading program. Similarly, several commenters

(OAR-2002-0056-2252, -2332) stated that a mercury trade program that is state run will lead to
cxcviii

state-to-state differences in implementation. These commenters asserted that it is not clear that

this method is consistent with the goal of allowances that are “readily transferable between all

regulated utilities” (69 FR 4652 Summary dated, January 30, 2004). One commenter

(OAR-2002-0056-2818) suggested that, if EPA determines that a cap and trade program is the

best way to reduce mercury emissions, then EPA should administer the program so it is available

to all utility units.

Several commenters (OAR-2002-0056-2862, -2948) disagreed with the amount of

flexibility states will have under the CAA section 111 cap-and-trade program. One commenter

(OAR-2002-0056-2862) noted that EPA’s section 111 cap-and-trade proposal would allow states

the flexibility to determine how to allocate the capped mercury allowances to in-state sources.

State implementation plans must, however, allocate the full emissions cap, and all of the

EPA-issued allowances must be issued to in-state sources. The commenter submits that because

the state cap is essentially the CAA section 111 performance standard, states choosing not to

allocate all of their allowances would essentially be “opting out” of the section 111 program, and

modifying the underlying federal standard of performance. The Clean Air Act does not permit

this.

The second commenter (OAR-2002-0056-2948) disagreed with EPA’s proposal to allow

states to opt out of a CAA section 111 trading program. According to the commenter, because

promulgation of a section 111 trading program would necessitate a determination by EPA that the

program is the “best system” for reducing mercury emissions from coal-fired power plants, states

cannot interfere with that determination. The commenter believed that although states do have

some authority under section 111, they lack authority to change the standard of performance set

by EPA. According to the commenter, if EPA permits states to opt out of a section 111 trading

program, this will in essence allow states to change the standard of performance, which the CAA

does not authorize. The commenter added that similarly, states cannot issue only a portion of the

allowances available within the state because this would also permit that state to modify the

federally determined standard of performance.

Several commenters (OAR-2002-0056-0598, -3449, -3543) believed states should be

allowed to opt out of the CAA section 111 cap-and-trade program. One commenter

(OAR-2002-0056-3449) submitted that states should have authority not to participate in emission

trading programs and to require emission reductions beyond those specified in state budgets.

One commenter (OAR-2002-0056-2721) believed that States should be required to

participate in the inter-State trading program. The commenter submitted that in instances where

there are few or only one utility in a State (i.e., South Dakota), the utility would be at an extreme

economic disadvantage relative to a utility in a neighboring state that has multiple affected units

when allowing each state to determine independently the amount of new source set aside or

allocations of allowances to other industry sources.

One commenter (OAR-2002-0056-2922) stated that EPA must make clear that states

cannot interfere with the cap-and-trade program. The commenter offered as example, states

should be expressly prohibited from requiring units to surrender more allowances than required by
cxcix

EPA’s one-allowance-per-ounce rule or from placing restrictions on the intrastate or interstate

transfer of allowances. The commenter urged EPA to include provisions in its rules that expressly

prohibit states from interfering with the cap-and-trade program in the ways described above or in

any other way.

One commenter (OAR-2002-0056-2224) had concerns about potential adverse impacts

that might occur through an inflexible, unit-specific regulatory control program. Specifically, the

commenter was concerned that the benefits and flexibility of a market-based program could be

entirely lost if it were determined that a national cap-and-trade program is not legally authorized

or, if states declined to implement the cap-and-trade option under section 111 alternative. 

According to the commenter, to anticipate these concerns, EPA should allow states to establish

flexible procedures for implementing the mercury reduction requirements under the “section 111"

option. The commenter stated that in addition to the cap-and-trade program proposed in the

supplement notice, these procedures should allow states to implement the reductions through

emissions averaging or trading on at least a facility-wide basis. The commenter noted that one

alternate control program, which was specifically provided for in the nationwide MACT

alternative, would be the emissions averaging program modeled after the NOx acid rain program.

The commenter asserted that the rule should clarify that this provision should also specifically be

provided for under the section 111 implementation approach for states that may elect not to

participate in the nationwide cap-and-trade program. Another alternative that the commenter

strongly urged EPA to adopt was a state-wide, mass emissions (i.e., ounces/year) approach that

would involve mass emissions caps set for each facility (calculated based on the rule’s emission

rates). The commenter asserted that providing at least this much flexibility would be essential to

enable electric generators to develop least-cost strategies for controlling mercury. According to

the commenter, among other things, it would provide significant additional compliance flexibility

for multi-unit stations while meeting the overall reduction goals of the program. The commenter

stated that section 111(d) provides states with broad latitude in designing the mercury control

program, and emissions averaging would thus be an appropriate implementation mechanism that

should be available to states so long as the state program achieves the mercury reductions

required under the final EPA rule.

Response:

As discussed in the final preamble, each State must impose control requirements that the

State demonstrates will limit Statewide emissions from affected new and existing sources to the

amount of the budget. Consistent with CAIR, EPA is finalizing that States may meet their

Statewide emission budget by allowing their sources to participate in a national cap-and-trade

program. That is, a State may authorize its affected sources to buy and sell allowances out of

State, so that any difference between the State’s budget and the total amount of Statewide

emissions will be offset in another State (or States). Regardless of State participation in the

national cap-and-trade program, EPA believes that the best way to assure this emission

limitation is for the State to assign to each affected source, new and existing, an amount of

allowances that sum to the State budget. Therefore, EPA is finalizing that all regulatory

requirements be in the form of a maximum level of emissions (i.e., a cap) for the sources.
cc

As proposed in the SNPR, EPA is finalizing that each State must submit a demonstration

that it will meet its assigned Statewide emission budget, but that regardless of whether the State

participates in a trading program, the State may allocate its allowances by its own methodology

rather than following the method used by EPA to derive the state emissions budgets. This

alternative approach is consistent with the approach in the CAIR.

States remain authorized to require emissions reductions beyond those required by the

State budget, and nothing in today’s final rule will preclude the States from requiring such

stricter controls and still being eligible to participate in the Hg Budget Trading Program.

Comment:

Several commenters (OAR-2002-0056-1611, -3909) stated that the proposed rules should

not override more stringent State requirements. One commenter (OAR-2002-0056-2835) stated

that States are always free to adopt mercury control requirements more stringent than the federal

requirements to address any adverse local impacts from EGU emissions.

One commenter (OAR-2002-0056-3199) asked EPA to consider provisions that would

allow states to control individual plants in the event there is a demonstrated mercury hot spot. 

Similarly, another commenter (OAR-2002-0056-2909) stated that EPA rules must provide the

explicit right and authority for States to deal with residual local issues.

Response:

Moreover, States remain authorized to require emissions reductions beyond those

required by the State budget, and nothing in today’s final rule will preclude the States from

requiring such stricter controls and still being eligible to participate in the Hg Budget Trading

Program.

Comment:

One commenter (OAR-2002-0056-2430) stated that EPA must clearly define its role in

overseeing a cap-and-trade program if a state elects to participate. The commenter submitted that

States are unable to evaluate the cost associated with implementation of the rule without clearly

stated commitments.

Response:

States may elect to participate in an EPA-managed cap-and-trade program for coal-fired

Utility Units greater than 25 MW. To participate, a State must adopt the model cap-and-trade

rules finalized in this section of today’s rule with flexibility to modify sections regarding source

Hg allocations. For States that elect not to participate in an EPA-managed cap-and-trade

program, their respective State Hg budgets will serve as a firm cap.
cci

In a system run by EPA, source information management, emissions data reporting, and

allowance trading is done through on-line systems similar to those currently used for the Acid

Rain SO2 and NOx SIP Call programs

Comment:

Several commenters (OAR-2002-0056-2264, -2422) claimed that CAA section 111(d)

cap-and-trade program would place an unfair burden on many States that are already required to

develop and approve controversial ozone and PM2.5 SIPs. Moreover, the inclusion of mercury

emission programs within often time consuming State SIP submission and approval processes

would effectively reduce the time available for source compliance planning and control strategy

implementation. In this regard, the commenters noted that the proposed section 111(d)

SIP-based trading program has been rejected in principle by 11 of the 12 northeastern states of the

Ozone Transport Commission (OTC). Eleven of the 12 OTC states voted to oppose any

cap-and-trade program for mercury, with Virginia abstaining. The commenters pointed out that

other states have voiced similar concerns about emissions trading for mercury. The commenters

believed these developments underscore the potential difficulties associated with an emission

trading plan implemented through section 111(d).

Response:

EPA is committed to assist states in the implementation of the program. States may elect

to participate in an EPA-managed cap-and-trade program for coal-fired Utility Units greater

than 25 MW. To participate, a State must adopt the model cap-and-trade rules finalized in this

section of today’s rule with flexibility to modify sections regarding source Hg allocations. For

States that elect not to participate in an EPA-managed cap-and-trade program, their respective

State Hg budgets will serve as a firm cap.

In a system run by EPA, source information management, emissions data reporting, and

allowance trading is done through on-line systems similar to those currently used for the Acid

Rain SO2 and NOx SIP Call programs.

5.9.4 State Resources

Comment:

Several commenters (OAR-2002-0056-2120, -2219, -2247, -2430, -2871, -2887, -2889,

-2897) stated that the cap-and-trade program under CAA section 111 would place an additional

burden on states. One commenter submitted that section 111(d) would place an unfair burden on

many States that are already required to develop and approve controversial ozone and PM2.5 SIPs.

Several commenters (OAR-2002-0056-2120, -2430) asserted noted that the cap-and-trade

program proposed in the supplemental rule would appear to require significant resources for state

and local agencies, the source of which is not accounted for in EPA’s proposal. The commenters

state the same is true for the enforcement and compliance scheme. The commenters believed that

adding additional burden to overextended states is a recipe for failure.
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One commenter (OAR-2002-0056-2219) stated that because of the additional burden of

the budget permitting system it is likely that the permitting time line would be delayed and create

unacceptable delays in emission reductions. One commenter added that the resources needed to

implement a cap and trade program under section 111 would be much higher than the resources

needed for MACT standards because the state must conduct a rulemaking to obtain authority to

administer section 111(d) emission guidelines and they currently have no trading system that

could be used as a model to allocate credits. The commenter also questioned EPA’s concerns

about states being overwhelmed by requests for Title V permit modifications for 1 year

compliance extensions under a MACT standard. The commenter stated that amending permits to

extend a compliance date would be far less resource intensive than implementing and

administering the allowance distribution process in the mercury trading program.

Response:

States may elect to participate in an EPA-managed cap-and-trade program for coal-fired

Utility Units greater than 25 MW. To participate, a State must adopt the model cap-and-trade

rules finalized in this section of today’s rule with flexibility to modify sections regarding source

Hg allocations. For States that elect not to participate in an EPA-managed cap-and-trade

program, their respective State Hg budgets will serve as a firm cap.

In a system run by EPA, source information management, emissions data reporting, and

allowance trading is done through on-line systems similar to those currently used for the Acid

Rain SO2 and NOx SIP Call programs.

Comment:

One commenter (OAR-2002-0056-1596) stated that enforcement personnel have little

training about how to determine compliance with a cap-and-trade program. The commenter

believed that this approach would allow companies to hide pollution with numbers that are hard to

verify.

Response:

As discussed in the final preamble, EPA will jointly administer the cap-and-trade

program with States. EPA is requiring monitoring under Part 75 and EPA is running the system

to collect emissions data and track allowances.

Comment:

One commenter (OAR-2002-0056-3448) asserted that EPA’s lack of an effective national

strategy has driven states to do their own rules. The commenter submitted that Massachusetts,

Connecticut, New Jersey, and Wisconsin have either legislation or rules and others are sure to

follow. The commenter believed states should not have to expend resources on a problem that is

best addressed on a nationwide basis. The commenter stated that EPA has created this situation.
cciii

Response:

Under the final rule EPA is establishing a national program to reduce Hg emissions by

allowing states to participate in a cap-and-trade program.

Comment:

One commenter (OAR-2002-0056-2883) believed that the EPA should hold regional

workshops to assist municipal and state-owned utility generation facilities with compliance with

these final rules to reduce mercury and nickel.

Response:

EPA is committed to assist states in the implementation of the program.
RESPONSE TO SIGNIFICANT PUBLIC COMMENTS ON

THE PROPOSED CLEAN AIR MERCURY RULE

Received in response to:

Proposed National Emission Standards for Hazardous Air Pollutants; and, in

the Alternative, Proposed Standards of Performance for New and Existing

Stationary Sources: Electric Utility Steam Generating Units

(69 FR 4652; January 30, 2004)

Supplemental Notice for the Proposed National Emission Standards for

Hazardous Air Pollutants; and, in the Alternative, Proposed Standards of

Performance for New and Existing Stationary Sources: Electric Utility Steam

Generating Units

(69 FR 12398; March 16, 2004)

Proposed National Emission Standards for Hazardous Air Pollutants; and, in

the Alternative, Proposed Standards of Performance for New and Existing

Stationary Sources, Electric Utility Steam Generating Units: Notice of Data

Availability

(69 FR 69864; December 1, 2004)

Docket Number OAR-2002-0056

6.0 MERCURY EMISSIONS MONITORING

US Environmental Protection Agency 

Emissions Standards Division

Office of Air Quality Planning and Standards

Research Triangle Park, North Carolina 27711

15 March 2005
i

General Outline

1.0 INTRODUCTION AND BACKGROUND

2.0 APPLICABILITY AND SUBCATEGORIZATION

3.0 PERFORMANCE STANDARDS FOR COAL-FIRED ELECTRIC

UTILITY STEAM GENERATING UNITS

4.0 PERFORMANCE STANDARDS FOR OIL-FIRED ELECTRIC

UTILITY STEAM GENERATING UNITS

5.0 MERCURY CAP-AND-TRADE PROGRAM

6.0 MERCURY EMISSIONS MONITORING

7.0 IMPACT ESTIMATES

8.0 COMPLIANCE WITH EXECUTIVE ORDERS AND STATUTES

9.0 NODA

10.0 OTHER

Appendix A LIST OF COMMENTERS
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6.0 MERCURY EMISSIONS MONITORING

6.1 SELECTION OF MONITORING METHOD

Comment:

Several commenters (OAR-2002-0056-2429, -2634, -2718, -2922, -3565) noted that in

the proposed MACT in subpart UUUUU, EPA’s proposed 40 CFR part 75 revisions include

provisions for use of both Hg CEMS and a sorbent trap monitoring system meeting Method 324. 

However, EPA also proposes to prohibit new units that commence commercial operation more

than 6 months after publication of the final rule from using Method 324. The commenters do not

believe that either of EPA’s proposed alternatives to restrict use of Method 324 is appropriate or

justified.

Response:

EPA agrees with the commenters. In light of comparative field data, EPA believes that

monitoring using sorbent media should be as similar as possible to monitoring using Hg CEMS. 

Therefore, today’s final rule allows the sorbent trap methodology to be used for new units.

Comment:

One commenter (OAR-2002-0056-2375) stated that if the EPA promulgates a

requirement that all sources above a certain emissions threshold monitor with CEMS, the

commenter recommended that the threshold be 76 lb/year.

Response:

EPA’s rule will require continuous monitoring (Hg CEMS or sorbent trap monitoring

systems) for all units with annual Hg mass emissions greater than 29 lb/yr. For units with Hg

emissions of less than or equal to 29 lb/yr, a low mass emitter option is provided that is less

rigorous but still environmentally conservative.

Comment:

Numerous commenters (OAR-2002-0056-1596, -2101, -2429, -2485, -2634, -2718, -

2827, -2850, -2861, -2918, -2922, -2932, -2948, -3406, -3432, -3455, -3536, -3539, -3565)

expressed concern that EPA’s proposal is unfairly and unjustifiably biased against the sorbent trap

method. The commenters did not support Alternative #1, because it restricts the use of sorbent

traps to low emitting units. Commenters were generally more receptive to Alternative #2, except

for the proposed quality assurance/quality control (QA/QC) procedures for sorbent trap systems

(most notably the quarterly relative accuracy testing), which they found to be inappropriate,
6-ii

overly burdensome, costly, and time-consuming. Several commenters stated that EPA has no

justification for restricting the use of the sorbent trap method because it has been shown during

EPA-sponsored mercury (Hg) monitoring demonstrations that the method can achieve accuracies

comparable, and in some cases better than those achieved by Hg CEMS. Other commenters

recommended that the type of QA/QC procedures prescribed for sorbent trap systems should be

more specific to the sorbent trap technology and should be more clearly defined. Finally, a

number of commenters objected to the proposal to report the higher of the two Hg concentrations

from the paired sorbent traps, and recommended that the results be averaged instead.

Response:

Section 75.81(a) of the final rule adopts a modified version of Alternative #2, which

allows the use of sorbent trap systems for any affected unit, provided that rigorous, technologyspecific QA procedures are implemented. The operational and QA/QC procedures for sorbent

trap systems are found in section 75.15 and in appendices B and K of the final rule. EPA also

has incorporated the recommendation of the commenters to use the average of the Hg

concentrations measured by the paired sorbent traps meeting specified criteria. And in cases

where one of the traps is accidentally lost, damaged or broken, the owner or operator would be

permitted to report the results of the analysis of the other trap, if valid.

Recent field test data from several different test sites indicate that sorbent trap systems

can be as accurate as Hg CEMS. Recent field tests have answered questions regarding which

substances in the flue gas can interfere with accurate vapor phase Hg monitoring by sorbent

traps. Sorbent trap technology also has evolved, with the addition of a third section that enables

the traps to be subject to enhanced QA procedures. And the Agency has been working with

industry and equipment manufacturer representatives to develop new QA procedures that are

more relevant to the operation of a sorbent trap system. These improved QA procedures are

included in the final rule. In view of this, EPA believes that it is appropriate to extend the use of

sorbent trap systems to all affected units.

EPA notes that although the restrictions on the use of sorbent traps have been removed,

there are some inherent risks associated with the use of this technology. For instance, because

sorbent traps may contain several days of accumulated Hg mass, the potential exists for long

missing data periods, if the traps should be broken, compromised, or lost during transit or

relative accuracy test audit (RATA) of a sorbent trap system is performed, the results of the test

cannot be known until the contents of the traps have been analyzed. If the results of the analysis

are unsatisfactory, the RATA may have to be repeated. This also may resulting in a long missing

data period. However, EPA believes that these undesirable outcomes can be minimized by

following the proper handling, chain of custody, and laboratory certification procedures in the

final rule. The use of redundant backup monitoring systems can also help to reduce the amount

of missing data substitution.

Comment:
6-iii

One commenter (OAR-2002-0056-4891) stated that any monitoring method that meets

the EPA criteria should be allowed. As noted above, accurate Hg monitoring technologies,

including accurate continuous emissions monitoring systems for Hg, are not yet commercially

available. When such equipment will be successfully tested and commercially available is not

known. To facilitate the use of new Hg monitoring technologies as they are developed, the

commenter urges EPA to allow power plant owner/operators subject to the Utility Mercury

Reduction Rule (UMRR; now known as the Clean Air Mercury Rule, CAMR) to use any

monitoring method that meets EPA’s standard criteria for reliability and accuracy. Unduly

limiting the options available for monitoring emissions would only serve to drive up the cost of

what is already an extremely expensive regulatory scheme. Given the current lack of accurate Hg

emissions monitoring methods, it will be important for facilities to have the flexibility to use

monitoring methods that are developed in the future as a result of the adoption of UMRR.

Response:

EPA agrees with the commenter and has specified a performance-based approach for

monitoring criteria. The performance-based approach allows for use of various suitable

sampling and analytical technologies while maintaining a specified and documented level of

data quality.

6.2 MISSING DATA PROCEDURES

Comment:

Several commenters (OAR-2002-0056-2634, -2718, -2861, -2922, -3565) were

concerned that EPA had overlooked a potential problem with the requirement to subject Hg

CEMS and Method 324 to periodic RATAs and/or other audits that rely on comparison to EPA

test methods for Hg (including Method 29 and the Ontario-Hydro method). Unlike the

instrumental reference methods routinely used to QA SO2 and NOx CEMS, the available Hg test

methods can take days to complete and weeks for the return of test results from the laboratory. 

Under the current general provisions, a monitor that fails a RATA would be deemed

out-of-control beginning with the hour that the required test was conducted until the hour that the

test is successfully passed. This construct could lead to significant implementation problems with

respect to missing data and requirements to calculate and report data. If a source does not know

until weeks after a RATA is completed whether the test was passed, the source has no means of

minimizing missing data associated with a failed test. Similarly, once it is clear that a test has been

failed, the source must schedule and perform a new test and wait for results before determining

whether the monitor is back in control and the data are valid. Under these procedures, monitoring

systems that fail a RATA will have significant amounts of missing data due simply to the delay in

obtaining testing results. Until a method is developed that will allow for onsite results of Hg

RATA testing, EPA must provide special rules to avoid these unavoidable implementation

problems.
6-iv

Response:

EPA Agrees with the commenters. Based on field testing., EPA intends to develop

adequate criteria for a performance based instrumental reference method for Hg. Initial

evaluations of such a method have already begun.

Comment:

Several commenters (OAR-2002-0056-2922, -2634, -2718) stated that section

63.10020(c) states that any period for which a monitoring system is out of control and data are

not available constitutes a “deviation.” The commenters object to labeling each period when a

monitor fails a QA/QC test and is therefore “out-of-control” as a “deviation” of the requirement

to monitor. Monitoring systems no matter how well maintained will occasionally fail a QA/QC

test. As long as the source takes appropriate action, no deviation from the requirement to

monitor has occurred. The commenters are especially concerned about this provision given the

uncertainty surrounding the ability of the Hg CEMS to satisfy the proposed standards in PS-12A

on an ongoing basis.

Response:

EPA has decided to control Hg emissions using a cap-and-trade approach rather than by

using maximum achievable control technology (MACT, 40 CFR part 63).

Comment:

Several commenters (OAR-2002-0056-1854, -2634, -2718, -2721, -2891, -2922, -3403, -

3455, -3565, -2855) stated that the proposed missing data procedures seem to be unduly harsh

and appear to be unfairly biased against the use of the sorbent trap method. The commenters

indicated that the missing data routines should properly consider the uncertainties associated with

Hg monitoring, i.e., there is a lack of evidence that high percent monitor data availability (PMA)

is achievable with these monitoring systems. Other commenters suggested that EPA should

remove the maximum potential concentration (MPC) provision altogether for Hg monitors and fill

in all missing data periods using average concentrations until more confidence is gained in the

reliability of Hg monitors.

Response:

The final rule retains the basic missing data substitution approach for Hg that was

proposed. This approach has worked well in the Acid Rain and NOx Budget Programs. The

conservative nature of the missing data routines has provided a strong incentive to sources to

keep their monitoring systems operating and well-maintained. However, the PMA cut points in

the final rule have been loosened slightly to account for the present lack of long-term Hg

monitoring experience in the U.S. EPA will continue to collect and analyze CEMS and sorbent
6-v

trap data from various field demonstration projects and will evaluate the performance of

certified Hg CEMS operating on similar source categories (e.g., waste combustors). If the data

indicates that the PMA cut points should be changed for Hg CEMS or sorbent traps, the Agency

will initiate a rulemaking for that purpose.

The suggestion to remove the MPC provisions and to fill in all missing data periods

using average concentrations until EPA develops better procedures was not incorporated in the

final rule for two reasons. First, when add-on emission controls that reduce Hg emissions either

malfunction and are taken off-line, uncontrolled Hg emissions will result. If the Hg CEMS or

sorbent trap system is out-of-control during the control device outage, an appropriate substitute

data value must be used to represent uncontrolled Hg emissions and provide an incentive to fix

the Hg monitoring system. The MPC concept has successfully been used in the Acid Rain and

NOx Budget Programs.

Second, EPA does not agree with the commenters that using the MPC for certain missing

data periods is always unduly harsh or punitive. For the initial Hg MPC determination, the

March 16, 2004 SNPR provided three options: (1) use a coal-specific default value; or (2)

perform site-specific emission testing upstream of any control device; or (3) base the MPC on

720 hours or more of historical CEMS data on uncontrolled Hg emissions. The Agency believes

that these options provide adequate opportunity for affected units to develop appropriate MPC

values.

Regarding the missing data routines for sorbent trap systems, available field test data

have indicated that these systems are capable of performance that is equivalent to a CEMS. In

view of this, EPA believes that sorbent traps should be treated on a a more equal footing with

Hg CEMS in many areas, including the missing data provisions.

Finally, EPA notes that a new missing data policy has been posted on the Clean Air

Markets Division web site. The policy allows the four-tiered missing data algorithms to be

applied hour-by-hour, in a stepwise manner, based on the PMA. Previously, the Agency’s policy

had been to determine the PMA at the end of the missing data period and to apply a single

substitute data value (sometimes the MPC, if the ending PMA was < 80 percent) to each hour in

the missing data block. This new, more lenient interpretation of the 40 CFR part 75 missing

data requirements will result in more representative missing data substitution and minimize the

use of the MPC.

Comment:

One commenter (OAR-2002-0056-3455) stated that, in reference to Appendix A to the

Preamble--Proposed Changes to Parts 72 and 75, (Proposed Rules March 16, 2004); page 12418, 

the section dealing with missing data seems to be either incorrect or unduly harsh; in either case,

the section requires clarification. The procedure states that missing data starts when the traps that

first caused the problem were put into service, but it further states that this missing data period
6-vi

ends only when the next valid Hg concentration data are first obtained. Because the data is not

“obtained” until the traps have been analyzed and the reports sent back to the owner, this would

mean that the missing period data would not only include time that the failed traps were in

service, it would also include the time period that the next valid set of traps were in service.

Response:

The wording in the final rule has been clarified to say that the missing data period would

end on the commencement of operation of another pair of sorbent traps that contain valid Hg

concentration data.

Comment:

Several commenters (OAR-2002-0056-2634, -2718, -2922) stated that the proposed

Method 324 needs to include provisions for data availability and missing data. Because it is not

reasonable for EPA to expect 100 percent data capture from any method, EPA must specify at

what point sorbent trap data would need to be filled in and what method would be used. EPA

might also consider providing alternative minimum data collection and missing data requirements

that would to apply simply to Hg data, regardless of the method of collection.

Response:

See the Missing Data discussion in the preamble.

Comment:

Several commenters (OAR-2002-0056-2634, -2718, -2922) stated that EPA needs to

clarify how periods of startup, shutdown, and malfunction are to be treated in data collection and

reporting. The proposed rule appropriately states that deviations that occur during periods of

“startup, shutdown, or malfunction” (“SSM”) are “not violations” if the source was operating in

accordance with its SSM plan. However, the proposal does not explain whether or how those

data would be excluded from the compliance calculation, or how they would be treated with

respect to the data collection requirements. Presumably EPA does not mean that any 12-month

rolling average in excess of the standard that includes a period covered by an SSM plan is not a

violation. On the other hand, data collected during periods of SSM are not representative of

normal operations and should not be included in data averages used to determine compliance and

missing data substitution procedures. EPA needs to give additional thought to these issues and

provide clear instructions in the rule for how such periods would be treated.

Response:

These comments pertain to the January 30, 2004 NPR, in which both a MACT rule and a

NSPS rule were proposed for Hg. The proposed MACT approach has not been selected for
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promulgation. The NSPS has been finalized as a series of amendments to 40 CFR part 60,

subpart Da. The NSPS clearly states that data recorded during periods of unit startup,

shutdown, and malfunction are not included in the calculation of the 12-month rolling average

Hg emission rate. However, the owner or operator is required to report the number of hours

excluded from the calculations for those reasons.

Comment:

Several commenters (OAR-2002-0056-2634, -2718, -2922) stated that EPA proposes to

require sources that utilize a FGD system to maintain records of scrubber operating parameters

for each Hg missing data period in order to show proper operation of the scrubber. Because

recording of FGD parameters generally is not automated, this requirement could become very

burdensome if there is a significant amount of missing data. As a result, the commenters request

that EPA consider allowing sources the option of utilizing parameters other than control device

operating parameters, such as documented compliance with an SO2 permit limit using the SO2

CEMS, to establish proper operation of the FGD during Hg missing data periods. 

Response:

The final rule allows quality assured SO2 data to be used to demonstrate proper

operation of an FGD.

Comment:

Several commenters (OAR-2002-0056-2634, -2718, -2922) stated that proposed data

collection and missing data scheme under section 63.10008(d)(4) has several significant flaws.

The first flaw is the assumption that these minimum criteria are reasonable requirements for Hg

CEMS. There are no data to support the assumption that Hg CEMS will be capable of operating

within the specified performance criteria for 18 hours a day for 21 days each month. Sources

should not be penalized for failing to meet minimum criteria that may not in fact be achievable. 

As a result, EPA will need to continue to review this requirement in light of additional data

collected between now and the first compliance deadline. EPA also should revise the rules to

allow use of Method 324 as a backup for any source that chooses that option, and should allow

data from that method to be used to meet the minimum data requirements in lieu of a Hg CEMS. 

The second flaw in the rule, even if you assume that the Hg CEMS can meet the minimum

criteria, is the failure of the rule to distinguish between unit operating hours and non-operating

hours in determining if a day is complete. If the minimum requirement applies regardless of unit

operation, sources will be required to try to keep monitors running and quality assured, and to

calculate mass Hg, even if the unit is not operating in order to collect enough data for a complete

day. That is contrary to section 63.10020(a) (“you must monitor continuously at all times that the

affected source is operating”). That would also result in months with little operation, and

therefore very little actual Hg mass emissions data, being counted in the 12-month rolling average

with the same weight as months with significant operation. If, on the other hand, the source does
6-viii

not collect that data, any day the unit does not operate and most days involving a startup or

shutdown are likely to be “incomplete” and not count towards the required 21 days for a complete

month. Under the missing data provisions, that approach would mean that valid data would be

thrown out simply because there was not enough unit operation in the month. Sources should not

be required to operate monitors when they are not operating, and should not be penalized for

non-operation. As a result, EPA should give more thought to whether the data collection and

missing data provisions associated with the calculation of “monthly” averages is the best

approach.

Response:

The proposed MACT rule has not been selected for promulgation. However, the

proposed NSPS rule for Hg, which contained the same data capture requirements as the MACT

rule, has been finalized. In the final rule, the minimum data capture requirement for the Hg

monitoring systems is 75 percent of the unit operating hours in each month. If this requirement

is not met for a particular month, a substitute Hg emission rate must be reported. Compliance

with the NSPS emission limit for Hg is determined on a 12-month rolling average basis. The

rolling average is weighted according to the number of valid hours of Hg data collected in each

month, except when the 75 percent data capture requirement is not met. When that occurs, the

substitute Hg emission rate for that month is weighted according to the number of unit operating

hours in the month. Months with zero unit operating hours are not included in the rolling

average calculations.

Comment:

Several commenters (OAR-2002-0056-2634, -2718, -2922) stated that EPA proposes to

revise 40 CFR 75.20(d) to include Hg CEMS in the list of non-redundant backup monitoring

systems that can be used for up to 720 operating hours without a RATA. The commenters

request that EPA revise this section, and other sections regarding use of backup monitoring

systems and missing data, including 40 CFR 75.80(f), to allow use of sorbent trap monitoring

systems as a backup to Hg CEMS and vice versa. The EPA should also allow use of additional

paired traps as a backup to a sorbent trap monitoring system.

Response:

The final rule does not prohibit you from using sorbent traps as redundant backup

monitors.

6.3 SORBENT TRAP OPERATION AND QA/QC

In view of the many comments received regarding a large number of testing and QA

provisions in proposed Method 324, EPA has decided to revise and rename proposed Method

324 as Appendix K to Part 75 in the final rule. Based on comments received and experience
6-ix

gained from field tests since proposal, Appendix K retains certain provisions and revises others in

proposed Method 324 to include detailed, performance-based QA standards and procedures for

sorbent trap monitoring systems. 

Comment: 

One commenter (OAR-2002-0056-3455) stated that, in reference to section 75.15(a)-(e),

Page 12417, conducting proportional sampling with a Method 324 sampling train may be

conducted at a single point. If the velocity profile changes with load, as may sometimes be the

case, proportional sampling by determining the velocity at a single point may misrepresent the

total gas flow in the stack.

Response:

40 CFR part 75, Appendix K, requires that the output from a part 75 certified stack gas

flow monitor be used to maintain a proportional sample flow rate through a sorbent trap or

cartridge. All affected sources under the final rule must already comply with the 40 CFR part

75 Acid Rain Program monitoring requirements which include maintaining and quality assuring

a stack gas flow monitor. A part 75 certified flow monitor must pass a two-load RATA annually

and a three-load RATA every 5 years, and is, therefore, representative of the stack gas flow rate

across different loads.

Comment: 

One commenter (OAR-2002-0056-3455) stated that, in reference to Method 324 (40 CFR

part 63), does not meet EPA’s definition of a CEMS (page 12453, section 72.2 Definitions).

Response:

It is true that in section 72.2, a sorbent trap monitoring system is not included in the

definition of a CEMS, but rather is defined separately as an “excepted” monitoring system. 

However, EPA believes that this distinction is more semantic than substantive, since a sorbent

trap system samples the stack effluent continuously, and data from the system are combined with

hourly readings from a certified 40 CFR part 75 flow monitor to give a continuous record of Hg

mass emissions. Relative accuracy test data have shown that a sorbent trap system can measure

Hg concentration as accurately as a CEMS.

Comment: 

One commenter (OAR-2002-0056-2867) notes that EPA also stated, for the purposes of

applying Method 324, “an intermediate sampling rate of 0.3 to 0.5 L/min through each sorbent

trap would be used when the unit is operating at the normal load level, whether low, mid, or high.

The sampling rate would then be increased or decreased, as appropriate, by 0.1 L/min when the
6-x

unit operates at the other two load levels” (69 FR 12417). The commenter believed that this

sample rate adjustment procedure is not appropriate. The proportional sampling is not necessary,

and requiring a step change to the sample rate adds further complication without any appreciable

benefit. According to the commenter, a mathematical analysis of the difference between constant

flow sampling and proportional flow sampling shows a negligible difference between the two,

with a percent difference of 1.45. The commenter submitted an attachment with the simulated

data (based on a realistic scenario). The commenter stated that since the method allows for a

±25 percent change in proportional flow sampling as mentioned above in (69 FR 4736), the

percent difference between constant flow sampling and proportional flow sampling is negligible at

1.45 percent, and well within the ±25 percent range. The commenter recommended that

proportional sampling not be required because of the added complications in the design of the

sampling process, and without the appreciable increase in the accuracy of the measurements. In

the undesirable alternative that the EPA requires proportional flow sampling, the commenter

recommended the sampling should be done on a continuous proportional basis and not on a 3-step

proportional basis. The commenter submited further explanation of the reasons proportional flow

sampling is unnecessary as follows. Since Method 324 measures the concentration of the Hg in

the stack, it is independent of the flow rate. The procedure included in the rule to calculate the

total mass of the mercury emissions includes the stack flow rate as follows: “(3) If you use

Method 324 (40 CFR part 63, appendix A), determine the 12-month rolling average mercury

emission rate according to the applicable procedures in paragraphs (d)(3)(i) through (v) of this

section. (i) Sum the mercury concentrations for the emission rate period, (g/dscm). (ii) Calculate

the total volumetric flow for the emission rate period, (dscm). (iii) Multiply the total mercury

concentration times the total volumetric flow to obtain the total mass of mercury for the emission

rate period in micrograms. (iv) Calculate the mercury emission rate for an input based limit

(lb/Tbtu) using Equation 4 of this section. (v) Calculate the mercury emissions rate for an

output-based limit (lb/MWh) using Equation 5 of this section,” (69 FR 4724). The commenter

pointed out that since any changes in stack flow rate will be taken into account in this calculation,

proportional sampling is unnecessary. The commenter asks EPA to clarify their intent on

requiring proportional flow for sampling periods greater than 12 hours. The commenter contends

that this is not a necessary requirement for accurate measurement of the Hg emissions.

Response:

When stack gas flow changes, Hg concentration may also change. Therefore, the final

rule requires flow proportional sampling to better ensure a representative sample. The 3-step

adjustment procedure in the proposed rule has not been finalized. Rather, the ratio of the stack

flow rate to sample flow rate must be kept constant (+ 25 percent) from hour-to-hour.

Comment: 

One commenter (OAR-2002-0056-2063) stated that, in reference to the

Preamble--Proposed Changes to Parts 72 and 75, (Proposed Rules March 16, 2004), Method

324, since Method 324 is a Reference Method and the main vulnerability on an ongoing basis is
6-xi

the sample volume measurement, quarterly volume measurement calibrations should be required,

rather than additional Reference Method (RAA) testing.

Response:

The final rule does not require quarterly RAAs, but has instituted quarterly calibration

checks of dry gas meters, and sample-specific volume QA/QC.

Comment: 

One commenter (OAR-2002-0056-0544) suggested that should sorbent tubes be utilized

for monitoring purposes, the sorbent media should not be restricted to iodated-activated carbon

only. There is a sorbent media used to test for Hg vapor in ambient air method listed as NOSH

6009 used in industrial hygiene. These sorbent tubes are readily available from SKC Inc,

manufacturer, located in Pennsylvania, part number 226-17-1A. These tubes have been used by

many Industrial Hygienists for many years and are time proven for their reliability.

One commenter (OAR-2002-0056-2867) asserted that EPA should publish the QA/QC for

the digestion procedure in this rule and disclose the entity that has developed the analytical

procedure and written Method 324. The commenter believed this will increase the understanding

of the intent in requiring this sampling method and analytical procedure. The commenter stated

the current digestion method appears to be biased towards the use of one vendor’s procedure. 

The commenter feels this may give them an unfair market advantage in supplying the traps to the

industry. The commenter believed alternate analytical procedures should be allowed, so that one

company does not control the market.

Response:

The sorbent media monitoring requirements (formerly Method 324) have been revised to

make them performance based, thus providing significant additional flexibility in choice of

sampling and analytical approaches, as well as performance criteria used to assess the quality

and validity of the monitoring data generated. There are numerous potential approaches for

sample preparation, depending upon the analytical technique selected. The performance based

approach intentionally avoids specifying that level of detail.

Comment: 

One commenter (OAR-2002-0056-3546) stated that they had recently conducted

additional Hg sampling at the Navajo and Coronado Generating Stations to enhance their

understanding of Hg emissions from these two coal-fired facilities and the challenges of testing for

Hg in flue gas. The commenter notes that both stations were part of the 1999 ICR where the

Ontario-Hydro method was used for Hg sample collection. Attachment 1 to the commenter’s

letter contains the test results and a brief description of sampling protocols.
6-xii

Response:

The Agency appreciates the data and is evaluating it.

Comment: 

One commenter (OAR-2002-0056-2101) stated that, in reference to Method 324, if a

separate particulate filter is used in front of the trap, this filter may easily absorb gaseous Hg

species during a long sample run. Is the inlet filter material analyzed along with the sorbent

material? If so, the method measures particulate Hg as well as gaseous. Unless iso-kinetic

sampling is done, the particulate fraction may be over or under represented. If the particulate

filter material is not analyzed, the danger exists that gaseous Hg has deposited on it and will be

discarded along with the material. This would cause serious under-representation of the gaseous

phase Hg.

Response:

40 CFR part 75, Appendix K in the final rule specifies that sorbent media should be the

first thing to contact stack gas.

Comment: 

One commenter (OAR-2002-0056-2101) stated that, in the proposals, CEMs require that

stack flows be monitored exactly in order to allow calculation of an accurate emission rate.

However, in the proposed Method 324, even when variable flow rates that track emission

volumes are required (only for samples of >12 hours duration), the sampling flow rates need agree

only within ±25 percent of stack velocity and only over a 3:1 dynamic range. This wide error

allowance will produce inaccurate mass emission calculations.

Response:

Appendix K of 40 CFR part 75 requires that the output from a part 75 certified stack gas

flow monitor be used to maintain a proportional sample flow rate through a sorbent trap across

all load levels, not just the three specified in the SNPR. Most of the affected sources under the

final rule are subject to the Acid Rain Program or to the NOx Budget Program (or both) and

already have the required stack gas flow monitor. The final rule retains the requirement to

maintain a constant (+ 25 percent) ratio of stack gas flow rate to sample flow rate from hour-tohour. EPA will evaluate sorbent trap system data as time goes on, to see whether the + 25

percent criterion needs to be tightened.

Comment:

Two commenters (OAR-2002-0056-2485, -3455) noted that, in reference to proposed

Method 324 (40 CFR part 63), section 8.2.1 (Sample Collection), page 4738, an isolation valve is
6-xiii

shown in Figure 324-1. The method should suggest closing the valve to prevent negative or

positive flow due to stack gas pressure. This would also allow the tube to heat to the correct

temperature before commencement of sampling.

Response:

The sorbent media monitoring requirements (formerly Method 324) have been revised to

make them performance based providing additional flexibility as well as performance criteria

used to assess the quality and validity of the monitoring data generated. The drawing referenced

by the commenters is now offered as one example of a suitable sampling train configuration. 

There are numerous potential approaches for gas control and the performance based approach

intentionally avoids specifying that level of detail.

Comment:

One commenter (OAR-2002-0056-2101) noted that, in reference to Method 324, section

8.2.3 (Flow Rates), because the method returns a true dry concentration, the instantaneous stack

flow rate must also be a true dry value. However, the velocity measurement is a normally wet

value. This requires one of the following:

• Verification that stack moisture levels do not vary significantly with velocity or

over time;

• A moisture analyzer to allow calculation of dry flow rate;

• Some other precise and accurate method of determining current moisture levels; or

• An error analysis showing that the worst case errors introduced by failing to

perform this correction are not significant.

Response:

The final rule requires that Hg concentrations and stack gas flow rates used to calculate

Hg mass emissions must be on the same moisture basis.

Comment:

Two commenters (OAR-2002-0056-2101, -3455) stated that, in reference to proposed

Method 324 (40 CFR part 63), section 8.2.6 (Moisture Knockout), page 4738, the section should

state that data for the entire run period must be invalidated in the event that the leak check fails. 

This is because the dry gas flow meter may have been sampling after the sorbent cartridge, not

through it, resulting in low Hg readings.

Response:

EPA agrees. Table K-1 in Section 8.0 of Appendix K specifies that failure to meet the
6-xiv

post-test leak check criterion will invalidate the sorbent trap monitoring data.

Comment:

Two commenters (OAR-2002-0056-2101, -3455) stated that, in reference to proposed

Method 324 (40 CFR part 63), section 8.3.4 (Field Spikes), page 4738, this section gives the

impression that the Hg is spiked onto the cartridges before exposure. (This procedure should

possibly be renamed to lab spike, rather than field spike.) This procedure yields very little

information. Unless the sample gas matrix actually causes the removal of existing Hg on the trap,

or interference with the analysis, this procedure will always generate 100 percent recoveries. 

Even if Hg is spiked onto the cartridges after sampling, this does not provide definitive proof that

Hg was being properly captured under actual sampling conditions. Commenter OAR-2002-0056-

2101 suggested that a more valid type of spike test would be to spike the cartridges in situ, under

actual sampling conditions, towards the end of a lengthy sampling period. This could be done by

adding a high concentration of a gas containing elemental (or ionic) Hg. Spiking would be done

at a low flow rate (e.g., 100 ml/m). This spike gas would be sent to the probe, directly in front of

the cartridges and the spike duration would be chosen to produce a significant additional loading

on the cartridge. Because the spike gas is produced at a rate significantly below the cartridge

sampling rate, all of the spike would be drawn through the cartridge and none would be lost out

of the tip of the probe. Only in this way can one be assured that Hg is being captured

quantitatively throughout the entire measurement period. The spiking gas would have to be

introduced at a known flow rate and with a known concentration. A conventional saturated Hg

vapor generator would suffice.

Response:

In the final rule, Appendix K requires spiking of the third section of each sorbent trap

with elemental Hg prior to sampling. The purpose of the spiking is to serve as a QC check of the

laboratory performing the analyses. EPA does not agree with the commenter’s proposed spiking

technique. Unless one can be assured of 100 percent recovery of the Hg in each trap (the

Agency does not believe this is possible), spiking directly in front of the sorbent trap will cause

the spiked Hg to become mixed with the sampled Hg, making it impossible to separate the two.

Comment:

Two commenters (OAR-2002-0056-2485, -3455) stated that, in reference to proposed

Method 324 (40 CFR part 63), section 10.1 (Calibration and Standardization), page 4739, the

standards should contain the same quantity of leaching agent as the samples being analyzed.

Response:

The sorbent media monitoring requirements (formerly Method 324) have been revised to

make them performance based, thus providing significant additional flexibility in choice of
6-xv

sampling and analytical approaches, as well as performance criteria used to assess the quality

and validity of the monitoring data generated. There are numerous potential approaches for

sample preparation, depending upon the analytical technique selected. The performance based

approach intentionally avoids specifying that level of detail.

Comment:

One commenter (OAR-2002-0056-2867) notes that Method 324, section 11.1 states,

“The sorbent traps are received and processed in a low-mercury environment (class-100

laminar-flow hood and gaseous Hg air concentrations below 20 ng/m3

) following clean-handling

procedures” (69 FR 4739). The commenter recommended that the EPA not require the use of the

class-100 laminar-flow hood. The commenter’s experience with EPA Method 1631 for low level

Hg in water indicates that processing samples in a class-100 laminar flow hood is unnecessary to

maintain Hg contamination below stated levels. However, the room in which samples are

processed may require restricted activity to keep contamination below 20 ng/m3

. The commenter

submitted the lab should be able to achieve and maintain a low-Hg environment by the means it

deems necessary. In the event that the EPA chooses to require the class-100 laminar-flow hood,

the commenter requested EPA to specifically define the underpinnings for the use of a class-100

laminar-flow hood and define the requirements of a class-100 laminar-flow hood.

Response:

As noted previously, the sorbent media monitoring requirements have been revised to

utilize a performance based approach. With this approach, is up to individual laboratories to

utilize whatever measures they find necessary to achieve acceptable background Hg levels in

order to achieve the performance criteria for the measurement.

Comment:

One commenter (OAR-2002-0056-2867) notes that section 11.14 of Method 324 states,

“A field blank is performed by assembling a sample train, transporting it to the sampling location

during the sampling period, and recovering it as a regular sample. These data are used to ensure

that there is no contamination as a result of the sampling activities. A minimum of one field blank

at each sampling location must be completed for each test site” (69 FR 4740). The commenter

believed the requirement to assemble an entire sample train to make a field blank is excessive. 

The commenter asserted a field blank does not need to be attached to a separate sample train. 

The commenter stated simply handling the field blank trap along with the actual test sample trap

at the test location and then sending it to the lab for analysis will fulfill the goals of the field blank. 

The commenter recognizes that the requirements for a field blank should be based on actual test

data. The commenter requests that the EPA publish the test data on which the field blank

requirements are based. The commenter stated that EPA should provide data that indicate that

the process of sample train preparation and sample recovery can introduce significant

contamination into the sampling procedure, if this is indeed a requirement.
6-xvi

Response:

As noted previously, the sorbent media monitoring requirements have been revised to

utilize a performance based approach. Blanks, including reagent blanks, method blanks, and

field blanks can be used at the tester’s option to assess sources and levels of sample

contamination. Blank correction, however, is not allowed.

Comment:

Two commenters (OAR-2002-0056-2101, -3455) noted that, in reference to proposed

Method 324 (40 CFR part 63), section 11.14 (Field Blanks), page 4739, this section does not say

what is to happen with results that exceed 30 percent of the measured value. The data should be

considered invalid.

One commenter (OAR-2002-0056-3455) stated that, in reference to proposed Method

324 (40 CFR part 63), section 11.14 (Field Blanks), page 4739, Table 324-2 the table should be

completed so the corrective action is available for all QA/QC failures.

Two commenters (OAR-2002-0056-2485, -3455) stated that, in reference to proposed

Method 324 (40 CFR part 63), section 11.4 (Mercury Reduction and Purging), page 4739, the

suggested field blank of 30 percent of the measured value is much too high. Surely it would be

more sensible to define the field blank in absolute mass as per table 324-2. If a trap has a max

capacity of 1,800 g then this would equate to 540 g, which would be a serious contamination

issue.

Response:

As noted above, the sorbent media monitoring requirements have been revised to utilize a

performance based approach. Blank samples are not required, but are rather used at the

tester’s option to assess sources and levels of sample contamination. Blank correction is not

allowed and there are no criteria for acceptable blank levels.

Comment:

Two commenters (OAR-2002-0056-2485, -3455) stated that, in reference to proposed

Method 324 (40 CFR part 63), section 11.3 (Dilution Step), page 4739, the dilution volume is not

specified but potentially very large dilutions are required to fit into the calibration range of

Method 1631.

Response:

As previously noted, the sorbent media monitoring requirements have been revised to

utilize a performance based approach. With this approach, it is up to individual users to select
6-xvii

suitable analytical techniques and associated sample preparation steps in order to achieve the

performance criteria specified for the measurement and thus dilution steps are no longer

specified.

Comment:

One commenter (OAR-2002-0056-2867) stated that sections 11.0 through 11.4 define the

analytical procedure of Method 324 and use a water digestion method. The commenter submitted

that the rule should include an avenue for approval of an alternate ASTM analytical procedure, if

the alternate method is shown to provide comparable results (similar to use of ASTM methods for

the analysis of coal and ash).

One commenter (OAR-2002-0056-2485) noted that, in reference to Method 324, section

11.4, the selection of the EPA 1631 as the preferred method to analyzed the sorbent tubes has no

scientific justification. This method is extremely complex and only the most specialized

laboratories have the necessary resources to run this procedure. The commenter also noted that,

in reference to Method 324, section 11.4, the Method 1631 method has many requirements that

are not appropriate or needed to analyzed sorbent traps. The 1631 method specifies the use of

amalgamation on gold to decrease detection limits. This is not necessary because the

concentrations in the final solution are sufficiently high. The amalgamation step complicates the

measurement and introduces more error.

Two commenters (OAR-2002-0056-2485, -3455) noted that, in reference to Method 324,

section 11.4, the Method 1631 method has many requirements that are not appropriate and

needed to analyzed sorbent traps. The 1631 method specifies an oxidation using BCL. Is this

step necessary as the Hg species will be already digested during the leaching process? What is the

purpose of the BCL?

The commenters also noted that, in reference to Method 324, section 11.4, the Method

1631 method has many requirements that are not appropriate and needed to analyzed sorbent

traps. The addition of NH2OH after the BrCl oxidation to remove free halogens is clearly

specified in the 1631 method to overcome damage to the gold trap and prevent low collection

efficiency (M163l, section 11.2). Method 324 states that this stage is omitted allow the free

halogens will still be present. What is the justification in omitting such a critical stage of the 1631

method? Furthermore the sorbent leaching step uses a concentrated HN03/H2S04 mixture at

elevated temperature in a closed vessel. As mentioned in Method 324 in section 11.2 significant

quantities of noxious and corrosive gases are released. These gases are likely to be NOx fumes

which may combine with BrCl to produce NOCl fumes which may also attack the gold trap and

lower its collection efficiency.

Response:

As previously noted, the sorbent media monitoring requirements have been revised to
6-xviii

utilize a performance based approach. With this approach, it is up to individual users to select

any suitable analytical technique as long as it can achieve the performance criteria specified for

the measurement.

Comment:

One commenter (OAR-2002-0056-2485) noted that, in reference to Method 324, section

11.4, Method 1631 has many requirements that are not appropriate and needed to analyzed

sorbent traps. The method was designed for trace levels of Hg in water not sorbent tubes. The

concentration range of the method is too low (0-100 ng/L) for the expected mass of Hg on

sorbent traps. For example if the flue gas Hg concentration was 1 g/m3 sampling for 4 hours at

0.4 L/min would yield 96 ng Hg. Insufficient information is provided in the method to calculate

the final concentration of Hg in solution after sample preparation. A simple calculation however

would suggest that the mass of Hg collected would have to be diluted using 1000 ml to produce

96 ng/L to be in the concentration range of the method. If one considers the maximum allowable

mass collected on the small trap (150 g) a dilution volume of l,500,000 ml. The large sorbent

trap specifies 1800 g capacity so a dilution volume of l8,000,000 ml would be required. 

Although these calculations represent the upper capacity limits they surely demonstrate that 1631

is not an appropriate method for the analysis of sorbent tubes and the potential error of such high

dilutions

Response:

As previously noted, the sorbent media monitoring requirements have been revised to

utilize a performance based approach. With this approach Method 1631 is no longer specified;

it is up to individual users to select an suitable analytical techniques and associated steps in

order to achieve the performance criteria for the measurement.

Comment:

Two commenters (OAR-2002-0056-2101, -3455) noted that, in reference to proposed

Method 324 (40 CFR part 63), section 11.6 (Instrument Calibration), page 4739, Method 1631

uses a calibration factor approach to calibration. It does not rely on r2

 values. The method

should standardize on either a weighted or unweighted regression approach to calibration because

the two approaches may yield significantly different results. Note that the Method 1631 analytical

approach is often used with weighted, (1/r2

) least squares curve fitting.

Response:

Numerous commenters stated that Method 1631 is inappropriate for the analysis of

sorbent trap samples. EPA concurs, and all references to Method 1631 have been removed in the

final rule. The final rule allows any suitable analytical technique to be used. For the

calibration curve of the analyzer, the rule simply requires an r2 value greater than or equal to
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0.99 and requires each calibration point to be within 10 percent of the true value.

Comment:

One commenter (OAR-2002-0056-2889) stated that, in reference to Method 324, section

11.7, refers to section 15, but likely should refer to section 12.

Response:

Although the commenter is correct, the revisions to the sorbent monitoring procedures

have eliminated the need for this reference.

Comment:

Two commenters (OAR-2002-0056-2485, -3455) stated that, in reference to proposed

Method 324 (40 CFR part 63), section 11.8 (Continued Calibration Performance), page 4739, 10

percent drift on a calibration standard is too high. If the CV-AAS or CV-AFS has drifted 10

percent then the probability of passing a RA test is lessened dramatically.

One commenter (OAR-2002-0056-2867) noted that, in reference to section 11.9 of

Method 324, EPA states, “The QA/QC for the analytical portion of this method is that every

sample, after it has been prepared, is to be analyzed in duplicate with every tenth sample analyzed

in triplicate” (69 FR 4739). The commenter claims these are highly excessive requirements for

the QA/QC of the analytical portion of the method. The commenter recommended that the

QA/QC be reduced to one duplicate every tenth sample analyzed, as allowed under other EPA’s

QA/QC programs. In other EPA monitoring programs such as the methods for water analysis,

QA/QC requirements are limited to a duplicate and a spike for duplicate for every tenth sample. 

The commenter submits that if required, EPA could adopt the practices used in water monitoring

programs.

One commenter (OAR-2002-0056-2867) stated that, in reference to section 11.9 of

Method 324, the sorbent trap laboratory blank requirement of 3 percent analysis set of 20 sorbent

traps also seems excessive. The commenter recommended one blank per every tenth sorbent trap.

One commenter (OAR-2002-0056-2889) stated that, in reference to Method 324, section

11.10, should also require the independently prepared samples to be within 10 percent of the

expected value.

Response:

As previously noted, the sorbent media monitoring requirements have been revised to

utilize a performance based approach and this level of detail is no longer specified. 

Laboratories conducting analyses of the sorbent media cartridges for Hg must either be ISO
6-xx

certified or accredited or must perform the spike recovery study described in Appendix K of 40

CFR part 75 annually. Thus, adequate QC procedures will be in place to ensure the quality of

the data.

Comment:

One commenter (OAR-2002-0056-2889) stated that, in reference to Method 324, section

11.13, should in the last sentence refer to 10 percent of the measured sample results.

Response:

The commenter is referring to a requirement for solution blanks. As noted above, the

sorbent media monitoring requirements have been revised to utilize a performance based

approach. Blank samples are not required, but are rather used at the tester’s option to assess

sources and levels of sample contamination. Blank correction is not allowed and there are no

criteria for acceptable blank levels.

Comment:

One commenter (OAR-2002-0056-2889) stated that, in reference to Method 324, section

13.0, should specify the consequences of failing to achieve the required sample rate per stack

flow. Another commenter (OAR-2002-0056-2485) stated that, in reference to Method 324, Table

324-2, the table should be completed so the corrective action is available for all QA/QC failures.

Response:

EPA agrees. Table K-1 in Appendix K specifies that failure to achieve certain

performance or acceptance criteria will invalidate the sorbent trap monitoring data.

Comment:

One commenter (OAR-2002-0056-2485) stated that section 13.0 of Method 324 is

confusing.

Response:

EPA agrees and has clarified the flow-proportional sampling requirements in Appendix

K of 40 CFR part 75.

Comment:

One commenter (OAR-2002-0056-3455) stated that, in reference to proposed Method

324 (40 CFR part 63), section 13.0 (Constant Proportion Sampling), page 4740 and section
6-xxi

8.2.4 (Constant Proportion Sampling) Option 1 & Option 2, these sections are confusing. If these

criteria were to be followed, a source could set their flow rate based on 75 percent of maximum

possible stack flow and be in compliance continuously from 50 percent of flow to 100 percent of

flow. However, the commenter believes that this would result in significant under reporting of

full load data and over reporting of reduced load data. The results of this could greatly reduced

Hg emission rates. Load following is the only way to make this work and it should have the same

standards as Method 5 sampling (+/-10 percent). Simply picking a sample flow rate as suggested

in the amended sections is not appropriate either.

Response:

EPA understands the commenter’s theoretical concern and will evaluate additional data

from actual units to see whether the permissible deviation criteria needs to be tightened in the

future.

Comment:

Several commenters (OAR-2002-0056-2634, -2718, -2861, -2922, -3565) stated that

several provisions, including sections 13 and 14, purport to contain requirements for calculations

and data analysis. These sections are inadequate. These sections should contain all of the

equations and calculations needed to conduct the method and arrive at Hg emissions values that

are either in the units of applicable standards or that can be converted to those units. Procedures

for incorporating blank determinations should also be included.

Response:

EPA has addressed the commenters’ concerns in finalizing the sorbent monitoring

procedures; however, the final procedures do not include provisions for blank correction.

Comment:

Several commenters (OAR-2002-0056-2634, -2718, -2861, -2922, -3565) stated that the

proposed Method 324 appropriately requires leak checks of the sampling line with and without

the sorbent trap in place. The checks are performed using a rotameter. The commenters are

concerned that with a nominal flow rate of 0.4 L/min (see Table 324-1), 2 percent of that flow

rate (which is the maximum leakage allowed under the proposal) may be too low to be accurately

read on a standard rotameter. Accordingly, the commenters suggest that EPA consider revising

the Method 324 to quantify the leak rate based on readings from the dry gas meter over a period

of at least 1-minute.

Response:
6-xxii

EPA understands the commenters’ concerns and has revised the leak check procedures to

clarify that the dry gas meter should be used to quantify the leak rate. The leak check

specifications have also been revised to allow a leak rate up to 4 percent of the planned (pre-test

leak check) or 4 percent of the average sampling rate (post test leak check) which is consistent

with Method 5 (40 CFR 60, Appendix A).

Comment:

One commenter (OAR-2002-0056-2867) pointed out that Table 324-1 (69 FR 4738) of

Method 324 states that the maximum sample duration for the large sorbent trap is 10 days. The

commenter recommended that the maximum sample duration not be limited at this time. The

commenter stated that requiring short sampling periods adds to the cost of the monitoring

process, as the traps will have to be changed more frequently. The commenter’s experience

indicated that changing the sample trap results in approximately 30 minutes of unmonitored time. 

The 10-day sorbent trap stipulation as proposed would lead to increases in the amount of

unmonitored time, as compared to a longer sample period, which requires changing less

frequently. The commenter submitted that the use of shorter length traps also increases handling,

analysis, and operations support compared to a longer sampling trap. This extra handling and

analysis will also introduce more opportunity for error. The commenter recommended that the

sample period comport with capabilities of the carbon traps. The commenter’s experience shows

that the traps can be designed and used for longer sampling periods. In recent tests, the

commenter compared the results of two smaller sorbent traps (one 10-day and one 11-day sorbent

trap) to one large trap (a 21-day sorbent trap). The commenter claimed the test demonstrates that

the results are comparable and not dependent on the length of the sample period or size of the

trap (the commenter submitted an attachment with the test results). The commenter pointed out

that the percent difference between the weighted average concentration measured in the two

smaller traps versus the larger trap is 13.7 percent. This is well within the RA range proposed by

EPA of 20 percent when comparing methods to Ontario-Hydro (69 FR 12419). The commenter

has plans for further development of Method 324 to lengthen the sample duration. The

commenter envisioned that the capabilities of the sorbent technology will improve with time,

leading to longer duration sample collection. In this context, the commenter recommended that

EPA should instead focus on the accuracy of information and not arbitrarily limit the sampling

period to 10 days or a month.

Response:

EPA has revised the sorbent monitoring procedure to be performance-based and has

eliminated the 10-day limit on sampling duration leaving it up to the tester to identify a sampling

duration that provides the correct balance between convenience and performance.

Comment:

One commenter (OAR-2002-0056-2485) stated that, in reference to Method 324, Table
6-xxiii

324-2, the table should be completed so the corrective action is available for all QA/QC failures.

Response:

EPA agrees. Table K-1 in Section 8.0 of Appendix K specifies that failure to achieve the

performance or acceptance criteria will require corrective action in some cases, and in other

cases will invalidate the sorbent trap monitoring data.

Comment:

Several commenters (OAR-2002-0056-2634, -2718, -2861, -2922, -3565) stated that

Table 324-2 sets out the QC requirements for samples. The commenters are concerned that some

of these requirements are excessive or not sufficiently explained or studied. For example, the

requirement for laboratory blanks could be excessive for large trap lots. And, without more data,

it is not possible to determine whether the paired train criterion (which is not set out anywhere

else in the rule) is subject to the same problems as PS-12A, section 8.6.6. Finally, the field

spiking requirement is not sufficiently explained. These problems are explained more fully in

RMB’s comments.

Response:

As noted previously, the sorbent media monitoring requirements have been revised to

utilize a performance based approach. Blank samples are not required, but instead are used at

the tester’s option and, therefore, there are no criteria for acceptable blank levels. The paired

train performance criterion has been based on actual levels achieved during several EPA

demonstrations as well as stakeholder supplied data. The field spiking requirement has been

replaced with a cartridge spiking requirement for QA and normalization of the data; this new

procedure has been adequately detailed.

Comment:

Several commenters (OAR-2002-0056-2634, -2718, -2861, -2922, -3565) stated that

because Method 324 is a test method itself, they believe that EPA could justify a rule that did not

require a RATA for validation of the sorbent trap system. The commenters are not aware of any

other instance where EPA had required that an EPA test method be compared to another test

method using RATA procedures prior to use to determine compliance. Use of the RATA in this

case is unusual given the mixed performance of the Ontario-Hydro method that would be used for

the RA test. Because Method 324 is a new method that has not been employed in practice, the

commenters are not objecting to an annual RATA requirement. Such testing in the early years of

the program could provide valuable information for improvement of both methods. However, the

commenters would object to any more frequent testing. Method 324 already provides significant

QA/QC in its sampling and analysis procedures and additional RATA testing would be

unwarranted.
6-xxiv

Response:

EPA does not believe that the sorbent media measurement procedure has the quality to

serve as a reference method. However, we are confident in its performance as a monitoring

technique. We have reconsidered the RATA requirements for sorbent monitoring systems and

concluded that a yearly RATA plus enhanced performance-based QA measures in Appendix K

should suffice to provide accurate measurements.

Comment:

Several commenters (OAR-2002-0056-2634, -2718, -2861, -2922, -3565) stated that

similar to proposed PS-12A, section 8.1.1 of Method 324 proposes to require testing for SO2 and

NOx stratification at the proposed installation location. This requirement is not consistent with

other EPA regulations and should be revised to deem the location suitable as long as the RATA is

passed. As in EPA’s other rules, stratification testing should only be required if the source uses a

wet control device (or is otherwise expected to have stratification) and exercises the option to use

the short measurement line or a single measurement point during RATA testing.

Response:

The provisions of Method 324 have been revised and placed in 40 CFR part 75, appendix

K. Appendix K suggests (but does not require) that stratification testing be used to site Hg

monitors.

Comment:

Several commenters (OAR-2002-0056-3455, 2485) noted that, in reference to proposed

Method 324 (40 CFR part 63), section 8.1.6 (Pre-Test Leak Check), page 4738, a leakage rate of

less than 2 percent of the recommended flow rate of 0.4 L/min equates to less than 0.008 L/min. 

This flow rate is not measurable using a flow rate in the range of the method (0 - 0.8 L/min). A

leak check under vacuum would be more effective and accurate.

Response:

EPA agrees that the leak checks should be conducted under vacuum. The pre-test leak

check specifies ~15" Hg vacuum, while the procedures have been revised to specify that the post

test leak check be done at the maximum vacuum reached during sampling. In addition, the leak

check specifications have been revised to permit a leak rate up to 4 percent of the planned (pretest leak check) or 4 percent of the average sampling rate (post test leak check) to be consistent

with Method 5 (40 CFR 60, Appendix A).

Comment:
6-xxv

One commenter (OAR-2002-0056-2485) noted that, in reference to Method 324, section

1.0, the title is misleading as the sorbent trap is not dry during sampling and it is quite likely that a

fraction of the particulate Hg is sampled because no filtration is used.

Response:

The provisions of Method 324 have been revised and placed in 40 CFR part 75, appendix

K. 

Comment:

One commenter (OAR-2002-0056-2485) stated that, in reference to Method 324, section

6.1.2, presumably, the large and small sorbent traps have the same type of sorbent material.

Suggesting the use of larger sorbent tubes at higher duct temperatures would imply that

breakthrough of Hg is potentially a problem at temperatures of 375 °F. The length of the probe

holding the sorbent tubes is not specified. It is quite common for the flue gas to be saturated with

water so unheated sorbent traps may be subjected to condensation. Surely it is advisable to heat

the sorbent traps above the stack gas temperature for all applications.

One commenter (OAR-2002-0056-3455) stated, in reference to proposed Method

324 (40 CFR part 63): It is quite common for the flue gas to be saturated with water so unheated

sorbent traps may be subjected to condensation. Surely it is advisable to heat the sorbent traps

above the stack gas temperature for all applications. Our opinion is the specified operating

temperature of the sampling probe for Method 324 is too low. Experience and data taken in the

field have pointed out that a minimum operating temperature of 400 °F is required to transport

oxidized Hg, unless the sample probe is recovered along with the sorbent tubes.

One commenter (OAR-2002-0056-2867) stated that their experience indicates that further

development of the Method 324 for use on a wet stack is necessary and can be accomplished in

the days ahead. The commenter noted that the original sampling probe does not work in a wet

stack. Condensation builds up in the trap, and renders the sample suspect. The commenter stated

that in order to sample in a wet stack, the trap must be inside a heated probe. The commenter

pointed out that Method 324 addresses this issue in section 6.1.2 and states that the sampling

probe must be heated in duct temperatures less than 200 °F, which equate to wet stacks.

Several commenters (OAR-2002-0056-2634, -2718, -2861, -2922, -3565) stated that one

important aspect of the Method 324 measurement is avoiding condensation in the sorbent trap by

heating the sampling probe in those conditions where the gas stream may fall below the

condensation point. Section 6.1.2 requires use of a heated sampling probe for effluents below

200 °F as measured with a thermocouple. The commenter suggest the lower boundary of the

range be increased to 250 °F to ensure that no water droplets form in the sorbent trap.

One commenter (OAR-2002-0056-2867) requests that, in reference to Method 324,
6-xxvi

section 6.1.2, EPA confirm that using a heated probe does not introduce differences into the

procedure for obtaining a dry stack sample and wet stack sample. The commenter contends that

any introduced differences are not quantified at this time, and should be investigated further. 

Questions the commenter requests be answered include:

• What are the differences between the heated probe and normal probe?

• Will the differences introduce any variations into the dry/wet stack sampling

process?

• Does the heated probe effectively capture the Hg in the stack?

• If the heated probe is used on the wet stack, can it be used on all stacks to avoid

introducing differences between the wet stack/dry stack methods?

• Is this a sufficient work around for the wet stack problem?

Response:

EPA agrees that the commenters’ concerns are all valid. However, the revised sorbent

monitoring requirements are performance-based and so achievement of the performance criteria

will assure that these issues have been effectively managed for each sample. The final sorbent

monitoring provisions advise the user that these are important issues to consider in developing

their sampling strategy.

Comment:

One commenter (OAR-2002-0056-2101) stated that the preamble should clearly say that

Method 324 is intended as a measurement method, and not a reference method. This commenter

asked if, in reference to Method 324, section 1.0 (AF vs AA), tests have been done to confirm

that atomic absorption (AA) gives answers equivalent to atomic fluorescence (AF) under all

circumstances? Method 1631 is a performance based AF method that allows substitution of AA

provided that QA/QC criteria are met, however this method was originally intended for simple

matrices like waste waters, not extracts from flue gas. (It should be noted that this reviewer is not

aware of any laboratories that have achieved true Method 1631 class performance with AA based

systems, even for the simpler matrices.) EPA should exercise extreme care to ensure that AA

techniques will always yield identical results to AF techniques.

One commenter (OAR-2002-0056-2485) stated that Method 324 should also be subjected

to the same RA test as the HgCEM.

One commenter (OAR-2002-0056-2867) stated that Method 324 should be considered as

a viable reference method. The Ontario-Hydro method is the currently accepted reference method

for measuring Hg concentration in a flue gas. EPRI’s experience shows that Method 324 has less

variability than the Ontario-Hydro method in side-by-side comparisons (as previously seen in

Attachment 1). Method 324 is also a continuous monitoring system, whereas the Ontario-Hydro

method measures the Hg concentration for a snapshot of time. Thus, Method 324 has
6-xxvii

considerable advantages over the Ontario-Hydro method as a reference method. Once EPA

incorporates Method 324 as a reference method, a natural extension will be to use it to monitor

Hg emissions all the time or as a test audit for Hg CEMS. This argument is enhanced by the

underpinnings in other CEMS activities, where the reference method is used to periodically check

the daily monitoring method or can be used for daily monitoring in lieu of CEMS.

One commenter (OAR-2002-0056-2867) stated that for applications where Hg CEMS are

used and for Hg monitoring and audits to be advanced, a real time instrumental reference method

for RA audits is needed. EPA must develop such an instrumental reference method for Hg.

Several commenters (OAR-2002-0056-2485, -3455) suggested that Method 1631 was not

an appropriate method to analyze sorbent traps for many reasons.

One commenter (OAR-2002-0056-2485) noted that, in reference to Method 324, section

2.0, this section states that other recognized procedures can be used for the analysis of sorbent

tubes such as ASTM D6784-02 and method 29. Neither of these methods is suitable for this

application. Both methods use various impinger solutions none of which relate to the chemistry

used to leach the sorbent tubes. Suggesting the use of these methods will ultimately create

confusion and the method open to interpretation. For example the ASTM method has digestion

and preparations for KCl, H2SO4/KMnO4 and H2O2/HNO3 impingers. Which digestion or

procedure should be used for the sorbent tubes? Furthermore CV-AAS and CV-AFS should

ideally have matrix matched standards for calibration procedures so what type of standardization

should be used for sorbent tube leachate? The CEN 13506 methods, EPA 245.7 and 245.1 are

more appropriate options because they do not use amalgamation and have wider dynamic ranges.

One commenter (OAR-2002-0056-2040) proposes an alternative analytical technique to

analyze Hg sorbent tubes for proposed Method 324. This technique involves direct (no sample

preparation) Hg analyzer Lumex RA 915+ with Attachment Pyro915/RP91C for testing of

iodated carbon sorbent from the tubes as an alternative to chemical digestion with following

atomic fluorescent analysis of tubes. The advantages of this technology compare to proposed in

Method 324 as follows:

• Technology is based on field portable Atomic Absorption spectrometry with Zeeman

correction coupled to a furnace heated to 800 degrees C wherein Hg is converted from a

bound state to the atomic state by thermal decomposition in a two-section furnace. In the

first section of the furnace the “light” Hg compounds are preheated and burned. In the

second section a catalytic afterburner decomposes “heavy” compounds.

• Direct, onsite testing of tubes. Save time for shipping, generating of chain of custody, and

wait for laboratory results.

• Testing results will be available within 1 hour after method 324 testing tube removed from

the sampler. Analytical throughput-20 tests per hour.

• No chemical waste generated.

• NIST traceable standards used for multipoint calibration.
6-xxviii

• Detection Level to 0.5 g/kg is 10 times lower than concentration of Hg expected for

Method 324 tubes.

• No compressed gases required. 

Response:

In view of the many comments received and the Agency’s own field testing, EPA has

decided to rename proposed Method 324, and to revise it with detailed, performance-based QA

standards and procedures for sorbent trap monitoring systems. These new standards and

procedures are now included in 40 CFR part 75, Appendix K, of the final rule. EPA believes

that by taking this action, there will be less confusion and more convenience for users affected

by the Hg cap and trade program. Because the sorbent trap monitoring system requirements in

Appendix K are performance-based, the results of any analytical technique meeting the

performance criteria should be comparable to any other analytical technique meeting the same

performance criteria.

EPA did not propose Method 324 as a reference method, but rather as a set of analytical

and QA procedures for sorbent traps to be used in a Hg monitoring program. The OntarioHydro Method is the reference method for Hg in part 75 of the final rule. However, EPA is

developing a Hg instrumental reference method as part of the Agency’s field tests of Hg

monitoring systems.

Comment:

One commenter (OAR-2002-0056-3455) noted that, in reference to Appendix A to the

Preamble--Proposed Changes to Parts 72 and 75, (Proposed Rules March 16, 2004); page 12417,

EPA stated that sorbent trap systems can’t be calibrated with cylinder gas (in description of

Alternative 2, page 12417); although this may be true, it does not mean that their performance

can’t be checked. The lack of QA/QC and method validation is a very disturbing approach to

proposing a new sampling method. It is common knowledge in the measurement industry that

carbon traps can become passivated in the presence of flue gas constituents. In addition to

becoming passivated, traps are also prone to re-releasing Hg after long-term exposure to flue gas

constituents, thus creating a situation that would seriously under report Hg concentrations, and

unfortunately, the use of the second section in the trap does nothing to address either of these

problems.

Two possible solutions to this problem exist: (1) one trap in a pair could be spiked and

placed in a dual sample train, when the train is analyzed the spike could be subtracted and the

result should then match with the second train that was not spiked; or (2) one of the traps in the

paired sample could be exposed to a Hg calibration gas near the end of its sample period, this

spike could then be subtracted from the value of the spiked trap and that value compared to the

trap that was not spiked. If the value of the reference trap and the spiked trap minus the spike do

not match (i.e., within +/- 20 percent) then the data should be invalidated.
6-xxix

One commenter (OAR-2002-0056-2101) stated that, in reference to Method 324, the

periodic RATA test against a reference method will not be effective in ensuring that the method is

producing accurate results. This type of test is not capable of detecting cartridge passivation

during lengthy Method 324 runs. Passivation is expected to occur relatively late in a sample run.

Total sample volumes passed through a collection cartridge during a RATA test may be only a

few percent of the total volumes that will be passed through the cartridges during normal

sampling.

Response:

Extremely high stack gas temperatures (greater than about 350 deg F) required for

passivating sorbent material are not expected. On wet stacks, 40 CFR part 75, appendix K,

states that sorbent traps may need to be heated above the dew point to prevent condensation. 

Therefore, matrix effects that cause passivation or loss of Hg trapping efficiency should not be a

problem. However, EPA will be examining this issue further during our field testing of sorbent

media.

Comment:

One commenter (OAR-2002-0056-2867) stated that in the SNPR Section B.3., “Use of

Mercury CEMS and Sorbent Trap Systems,” the EPA proposes in Alternative 2 that the sorbent

trap method can be used by any source, with an annual 9-run RATA and quarterly 3-run RAA

required for QA. The commenter maintains that these QA requirements are excessive and the

results (pass/fail/bias) will remain unknown for days and weeks. The commenter also stated that

elsewhere, the EPA stated, “For sources with annual Hg emissions below the specified threshold

value, the QA requirements for sorbent trap monitoring systems would be less, with only an

annual RATA being required” (69 FR 12417). The commenter recommends that the QA

requirements for sorbent traps - all units, irrespective of emission rates - be consistent and limited

to an annual RATA, although the RATA may be unnecessary if Method 324 is ultimately is

adopted as a reference method. The commenter stated that the accuracy of the sorbent trap

method does not decrease with increasing unit size or larger Hg emission rate. The commenter

also stated that the EPA also stated “the Agency is willing to consider replacing the RAA

requirement with another type of substantive quarterly QA test, if commenters who favor the use

of sorbent trap systems are aware of, and can provide details of, any such test or procedures” (69

FR 12417). The commenter recommends that if quarterly checks are deemed necessary, the EPA

might include semiannual analysis of spiked and blank traps, and quarterly sample flow checks and

pump calibrations.

Response:

See Sorbent Trap Operation and QA/QC discussion in the preamble.

Comment:
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Several commenters (OAR-2002-0056-2079, -2485, -2634, -2718, -2861, -2922, -3455, -

3565) were generally opposed to the proposed quarterly relative accuracy audits (RAAs) for

sorbent trap systems as being too costly and of little value. A number of commenters suggested

that EPA should revise proposed Alternative #2 and specify QA procedures that are meaningful to

the type of measurement system that the sorbent trap actually is. For example, the volume of

stack gas sampled by the system is an important parameter in determining the Hg concentration. 

Therefore, procedures for quality-assuring the measurement of the sample volume could be

implemented. 

Some commenters favored allowing the use of proposed Method 324 for all affected units,

and stated that because Method 324 is itself a test method, it does not need additional QA

procedures. Two commenters suggested that EPA should even take steps to make Method 324 a

reference method. However, numerous other commenters objected to various provisions of

proposed Method 324 and offered suggestions for improving it. Some of the chief objections

raised were as follows:

 The allowable analytical techniques and procedures in the method are too

exclusive, and in the case of Method 1631, inappropriate. Other analytical

methodologies should be allowed;

 The impinger and dessicant method of moisture removal is inadequate;

 The leakage rate prescribed for the leak checks checks may be too low to measure;

 The method allows constant-rate sampling for collection periods less than 12

hours, which may introduce bias if unit load changes during the collection period;

 The specification for flow proportional sampling (adjust sample flow rate to

maintain proportional sampling within + 25 percent of stack gas flow rate) is not

stringent enough and can lead to inaccurate concentration measurement;

 The frequency for dry gas meter calibration is unspecified; and

 The method does not include chain of custody procedures.

A number of commenters suggested that EPA should not require the use of paired

sorbent traps and should allow the use of single sorbent traps.

Several commenters objected to the proposal in section 1.5.4 of Appendix B that

laboratories performing Method 324 be certified by the International Organization for

Standardization (ISO) to have proficiency that meets the requirements of ISO 9000. One

commenter stated that having a good blank and matrix spike program in place is much more

indicative of a good QA/QC program for Hg measurement than ISO 9000 certification. Another

commenter favored ISO certification, but not according to ISO 9000. The commenter

recommended that ISO 17025 be required instead, because it requires the laboratory to

demonstrate proficiency, rather than simply having an acceptable protocol for the analyses.

One commenter stated that EPA has not explained the appropriateness of applying a bias
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test and adjustment factor to Method 324, when it has already satisfied the same standards for

bias and precision as the Ontario-Hydro Method under EPA Method 301. Another commenter

suggested that it does not make sense to subject Hg monitors to a bias adjustment factor under

Appendix A, section 7.6 when paired reference method trains are allowed to differ by 10 percent

relative deviation (RD), based on a flawed definition of RD. The commenter asserted that it is not

reasonable to suggest that a Hg monitor is biased by comparing its readings to a pair of reference

method tests that can differ by 20 percent.

One commenter (OAR-2002-0056-2867) stated that their current experience with Method

324 (QSEMS) indicates that component reliability has to be improved. The commenter’s

experience indicates issues with the following:

• Flow meter (Totalizer) -Typical problems encountered are a delayed start to recording the

data and discontinuous recording of data after several days.

• Sampler Pump - Readings vary by ±25 percent when set at constant flow. The flow rate

also decreases overtime as particulates build up.

• Currently O2 cannot be measured and recorded with this device. Correcting to 3 percent

O2 is the typical way to compare individual test runs and to allow the detection of leaks on

line during the sampling period.

• The carbon trap plugs in high ash situations. The method will not work upstream of an

ESP without an inertial separator or other method to remove the ash.

• For wet stack application the probe will need modification.

The commenter asserted that these changes are required before QSEMS can be relied on to

demonstrate compliance. The commenter notes the industry is investing time and money into the

development of these systems, to enhance reliability by 2010. The commenter contends it is

important that the compliance deadline not be moved earlier than 2010.

Response:

In view of the many comments received and the Agency’s own field testing, EPA has

decided to rename proposed Method 324, and to revise it with detailed, performance-based QA

standards and procedures for sorbent trap monitoring systems. These new standards and

procedures are now included in 40 CFR part 75, appendix K, of the final rule. EPA believes

that by taking this action, there will be less confusion and more convenience for users affected

by the Hg cap and trade program. Today’s rule also revises both the definition of a sorbent trap

monitoring system in section 72.2 and the general guidelines for sorbent trap monitoring system

operation in section 75.15, to be consistent with the QA requirements of Appendix K.

The final rule retains the annual RATA and bias test requirements for sorbent trap

monitoring systems, but the proposed quarterly RAA requirement has been withdrawn. The

requirements to use paired traps and flow proportional sampling have also been retained. 

Finally, the ISO-9000 certification requirement for the laboratory performing the Hg analyses
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has been replaced with a requirement for the laboratory to either comply with ISO-17025 or to 

comply initially, and annually thereafter, with the spike recovery study provision in section 10 of

40 CFR part 75, Appendix K.

Several commenters recommended that EPA should require QA procedures for sorbent

traps that are more meaningful and reasonable than the procedures in the SNPR. EPA agrees

with these comments, and based on the recommendations received, today’s rule specifies such

procedures in Appendix K. Many provisions of Method 324 have been included in Appendix K

without modification, but other provisions of the method have been modified and some new QA

procedures have been added to address concerns expressed by the commenters. Some of the

more significant differences between Method 324 and Appendix K are as follows:

 Appendix K allows the use of any sample recovery and analytical methods that

are capable of quantifying the total vapor phase Hg collected on the sorbent

media. Candidate recovery techniques include leaching, digestion, and thermal

desorption. Candidate analytical techniques include ultraviolet atomic

fluorescence, ultraviolet atomic absorption, and in-situ X-ray fluorescence;

 Appendix K requires that each sorbent trap be comprised of three equal sections,

the first one for sample collection, the second to assess “breakthrough”, and the

third to allow spiking with elemental Hg, for QA purposes;

 Appendix K specifies the frequency of dry gas meter calibration, and the

appropriate calibration procedures;

 Appendix K requires ASTM sample handling and chain of custody procedures to

be followed.

 Spiking of the third section of each trap with elemental Hg is required before

each data collection period begins. 

 The laboratory performing the analyses must demonstrate the ability to recover

and quantify Hg from the sorbent media

 The measured Hg mass in the first and second sections of each trap is adjusted

(normalized), based on the percent recovery of Hg from the third (“spiked”)

section.

EPA believes that if these procedures are implemented, this will ensure the quality of the data

from sorbent trap systems.

The final rule retains the requirement to use paired sorbent traps. The SNPR proposed

the use of paired sorbent traps for the same basic reason that paired Ontario-Hydro trains are

required for RATA testing, i.e., it provides an important check on the quality of the data. The

proposed rule would have required the higher of the two Hg concentrations obtained from the

paired traps to be used for reporting. However, the final rule requires the results from the two

traps to be averaged if they meet specified criteria, and allows the results from one trap (if those

results are valid) to be reported in cases where the other trap is accidentally damaged, broken or

lost during transport and analysis. Thus, using paired sorbent traps provides a relatively
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inexpensive means of ensure against data loss should one of the traps become lost or damaged.

The commenters generally objected to the proposed quarterly relative accuracy (RA)

testing of sorbent traps, believing it to be unnecessary and costly. After consideration of recent

field data comparing the sorbent traps to Hg CEMS, EPA agrees that sorbent trap systems

should be treated more similarly to Hg CEMS. Therefore, the final rule removes the quarterly

RAA requirement, and requires only that an annual RATA be performed on a sorbent trap

monitoring system.

One commenter objected to the proposed bias test requirement for sorbent trap systems,

citing the fact that Method 324 had satisfied the same standards for bias and precision as the

Ontario-Hydro Method under EPA Method 301. EPA does not agree with this comment. The

fact that Method 324 met the bias and precision requirements of Method 301 does not imply that

Hg sorbent traps will not exhibit low bias with respect to a Hg reference method during a RATA. 

The bias test in section 7.6 of 40 CFR part 75, appendix A, is a one-tailed t-test, which, if failed,

requires a bias adjustment factor (BAF) to be applied to the subsequent emissions data. 

EPA also does not agree with the commenter who stated that bias adjustment is not

appropriate for sorbent trap systems because of the allowable 10 percent RD between the paired

reference method trains. The part 75 bias test determines systematic error, not random error,

whereas RD and relative accuracy are metrics used to quantify random error in the

measurement.

Comment:

One commenter (OAR-2002-0056-3455) suggested that, in reference to Method 324 (40

CFR part 63), section 1.1.2 (Applicability), page 4736, a Hg RATA should be performed on the

same long-term time basis as the method’s use of a CEMS, i.e., an applicable RATA time period

equal to or greater than the longest averaging period. This may mean multiple Ontario-Hydro

paired train runs during the Method 324 extended sampling time period. Moisture corrections

from the Reference Method should be applied to Method 324 data for the entire averaging period. 

A short-term averaging period for correlation to the Reference Method does not provide

long-term assurance of carbon trap performance.

Response:

The final rule requires that a minimum of 9 runs be used to calculate a RA for either Hg

CEMS or sorbent traps. For the RATA of a Hg CEMS using the Ontario-Hydro Method, or for

the RATA of a sorbent trap system (irrespective of the reference method used), the minimum time

per run must be long enough to collect a sufficient mass of Hg to analyze. EPA has decided to

implement this approach as a compromise between the desire to test the sorbent traps’ long term

performance and the practicality of performing a potentially week-long reference method test,

with the Ontario-Hydro Method.
6-xxxiv

Comment:

One commenter (OAR-2002-0056-3455) stated that, in reference to proposed Method

324 (40 CFR part 63), section 1.1.2 (Applicability), page 4736, performance verification criteria

must be established to assure that 100 percent cartridge trapping efficiency is maintained: 

• Over the full permitted temperature range of the sampling train and over the full

stack gas temperature range;

• Over the full flow rate range of the sampling train (especially the combination of

highest temperature range with highest flow rate - which would be expected to

create the highest probability of breakthrough.); and

• Over the full range of stack gas compositions. This becomes particularly

important in cases where control technology is employed. 

Response:

The extremely high stack gas temperatures required for passivating sorbent material are

not expected to be encountered in utility stacks. On wet stacks, Appendix K of 40 CFR part 75

states that sorbent traps may need to be heated above the dew point to prevent condensation. 

Therefore, matrix effects that cause passivation or loss of Hg trapping efficiency should not be a

problem. However, the Agency will be investigating this issue further during our field testing of

sorbent media.

Comment:

Commenter OAR-2002-0056-2922 stated that section 75.15 contains the Special

Provisions for using the sorbent trap monitoring method (Method 324). Section 75.15(e)

specifies proportional sampling and then further explains the proportional sampling procedure as a

change in the sampling rate in relation to load. This procedure is flawed and is in conflict with

Method 324. Any proportional sampling method will require stack flow rate or load input into

the sampling device. The sorbent traps will be located at a stack or duct location and manually

making the required flow changes, at odd times of the day, will just not be feasible. EPA should

make this section consistent with Method 324 and allow for automated input of stack flow or load

data into the sorbent sampling system and allow for automated flow rate adjustment.

Response:

EPA agrees with the commenter and the final rule requires the flow control valve and

air-tight sample pump to be controlled by the 40 CFR part 75 certified flow monitoring system. 

The final rule also requires that the data acquisition and handling system ensure that the

sampling rate is proportional to the stack gas volumetric flow rate.

Comment:
6-xxxv

Commenter OAR-2002-0056-2922 stated that section 75.15(i) should have the words “or

partial hours” added to the first sentence.

Response:

EPA believes that the suggested change is unnecessary in light of the definition of “unit

operating hour” in section 72.2 which includes “any hour (or fraction of an hour).”

6.4 QA/QC PROCEDURES FOR HG CEMS

Comment: 

One commenter (OAR-2002-0056-3406) stated that given the early stages of the

development of Hg CEMS technology, it is inappropriate to specify a mandatory performance

specification. The commenter believed facilities subject to this requirements should have the

option of proposing and complying with an alternative performance standard that provides

substantially similar assurances.

Response:

The final rule contains an alternative relative accuracy performance specification for low

emitting sources.

Comment:

One commenter (OAR-2002-0056-3455) suggested that, in reference to PS-12A, the final

rule should change the cycle time (from the proposed fixed 15 minutes) to a field determined cycle

time. Elemental Hg can achieve a 15-minute cycle, however, currently that cycle time would be

difficult for oxidized Hg to achieve. EPA should continue to work with vendors with a goal of

achieving 15 minute cycle times for all forms of Hg. A TGM blend will also take longer.

Response:

EPA’s field testing indicates that 15 minute response times and cycle times are

achievable for both elemental and oxidized Hg.

Comment:

One commenter (OAR-2002-0056-3455) suggested that, in reference to PS-12A, the

CEMS should be challenged with a calibration gas blend of Hg0

 and Hg+2 at a frequency

consistent with 40 CFR part 60, Appendix B, PS-2, introduced at the sample acquisition point,

prior to any filtration; to access sample transport for data validation.
6-xxxvi

Response:

EPA agrees with the need to periodically check the performance of the entire monitoring

system. EPA’s field testing has shown that a single injection performed daily using the

appropriate concentration of oxidized Hg is sufficient to check the upscale calibration of the Hg

CEMS from the probe tip through the analyzer and the efficiency of the HgCl2 to Hg converter. 

The final rule allows either elemental or oxidized Hg to be used to perform daily calibration

checks.

Comment:

Commenter OAR-2002-0056-2922 stated that in section 60.4171(c)(2) it is not clear

whether a source installing a new Hg monitoring system must submit a Certification Application.

In many instances, the Hg monitoring system will be a completely separate Hg/diluent system that

uses full concentration, dry basis analysis. The data acquisition system and other inputs, like stack

flow rate will be associated with a previously certified part 75 system. It is not clear whether such

a system would require a certification application to be submitted. It is also not clear how much

of the system would need to be included in the certification application.

Response:

Section 60.4171(c)(2) states that a certification application is not required if the system

has been previously certified under the Acid Rain Program or under an applicable State or

Federal NOx mass emission reduction program that adopts the requirements of 40 CFR part 75,

subpart H. Therefore, e.g., if a flow monitoring system was previously certified under, e.g., the

Acid Rain Program (part 75), a certification application for that flow monitoring system is not

required.

The final rule removes all requirements for a Hg emission rate (or Hg-diluent)

monitoring system. However, either a sorbent trap monitoring system or a Hg concentration

monitoring system is required by the final rule. A Hg concentration monitoring system consists

of a Hg pollutant concentration monitor and an automated data acquisition and handling

system. Because neither a Hg concentration monitoring system nor a sorbent trap monitoring

system was required by 40 CFR part 75 until this rulemaking, a certification application must be

submitted for either of these systems.

Comment:

Several commenters (OAR-2002-0056-1969, -1975, -2040, -2046, -2063, -2068, -2073, -

2079, -2160, -2181, -2206, -2224, -2244, -2252, -2259, -2260, -2267, -2296, -2365, -2379, -

2380, -2429, -2485, -2578, -2718, -2721, -2827, -2830, -2833, -2835, -2844, -2862, -2867, -

2877, -2889, -2891, -2898, -2900, -2918, -2922, -2929, -2947, -3200, -3413, -3436, -3443, -

3444, -3454, -3458, -3487, -3559, -3568) were in general agreement on the following points. 
6-xxxvii

Although many vendors of Hg CEMS have recently upgraded their instrument systems and these

changes should eventually improve the accuracy and reliability of Hg CEMS and reduce the labor

needed for instrument maintenance, these new instrument systems have not been tested

extensively in demonstration programs. Therefore, the ability of these instrument systems to

achieve the proposed relative accuracy, calibration error, and calibration precision requirements

has not been adequately demonstrated. Therefore, EPA does not yet have a basis or data to guide

the setting of specifications for calibration error, linearity, or relative accuracy. It appears that the

proposed performance specifications mirror those for SO2 and NOx monitoring. EPA should

commit to collecting data and evaluating these specifications as soon as calibration gases are

available, so that the specifications can be adjusted if necessary, prior to program implementation. 

EPA should require operators of Hg CEMS to conduct procedures that include but are not

necessarily limited to daily zero and span audits, quarterly relative accuracy tests and three-point

elemental Hg linearity tests, and absolute calibration audits. Analytically, there is clearly a need to

challenge the entire system often with a form of oxidized Hg. This Hg chloride (HgCl2) reference

gas would be highly desirable to check integrity of the sample interface. However, further

research needs to be required to enable the development of an accurate oxidized Hg standard. 

One device, the Hovacal, may have the potential of delivering known concentrations of HgCl2. 

EPA should recognize and accept this type of calibration system in the proposed regulation. 

There are concerns with the proposed RATA process, particularly the length of time and amount

of money that may be required to comply with the Hg monitoring requirements on an annual

basis. The final monitoring requirements must be technically achievable and capable of measuring

Hg emissions with precision, reliability, and accuracy in a cost-effective manner. The decision to

report Hg concentration on dry or wet basis needs more consideration, as well as, the evaluation

of gaseous interferences. Lastly, many of the equations and calculations are incomplete or contain

errors and many sections need further clarification.

Response:

In the final rule, the same tests are required for initial certification and on-going QA of

Hg CEMS as were proposed in the SNPR. However, note the following changes to some of the

procedures and performance specifications:

 For the 7-day calibration error test, either elemental Hg standards or a NISTtraceable source of oxidized Hg (referred to as “HgCl2 standards”in the SNPR)

may be used;

 Quarterly 3-level “system integrity checks” (which were called “converter

checks” in the SNPR) using a NIST-traceable source of oxidized Hg may be

performed in lieu of the quarterly linearity checks with elemental Hg;

 Daily calibration error checks may be performed using either elemental Hg

standards or a NIST-traceable source of oxidized Hg. The daily performance

specification has been made the same as for the 7-day calibration error test;

 The monthly converter check at three points has been replaced with a weekly
6-xxxviii

system integrity check at a single point, and the weekly test is not required if daily

calibrations are performed with a NIST-traceable source of oxidized Hg.

 When the Ontario-Hydro Method is used, paired trains are required, the results

must agree within 10 percent RD, and the results should be averaged.

Note that EPA plans to analyze RATA data from Hg monitors and may initiate a future

rulemaking to adjust the relative accuracy performance specifications and to propose a

performance-based RATA incentive system similar to the reduced frequency incentive system in

40 CFR part 75 for SO2, NOx, CO2, and flow monitors.

EPA disagrees with the commenters who stated that there is no data available to justify

the proposed performance specifications for Hg monitors. Such data have been collected from

several field test sites and for several different types of Hg concentration monitors, which show

that Hg CEMS can meet the proposed calibration error and linearity standards, and can meet a

20 percent RA standard. Therefore, except for the daily calibration error specification, which

has been tightened based on the available data, the final rule promulgates the proposed

calibration error, linearity check, and RATA performance specifications, as proposed.

EPA has retained the requirement to check the converter periodically with HgCl2

standards, because it is essential to ensure that all of the vapor phase Hg is being measured. 

The frequency of the check (which is referred to as a “system integrity check”in the final rule)

has been increased from monthly to weekly, based on supportive comments to check the entire

system more often, but the requirement to perform a 3-point check has been reduced to a singlepoint test. And the weekly test is not required if a NIST-traceable oxidized Hg source is used for

daily calibrations.

There are several different devices available that can provide oxidized Hg, including the

HOVACAL and the MerCAL. The HOVACAL has been successfully applied in the laboratory

and field to generate and deliver known concentrations of HgCl2 to Hg CEMS to achieve the

requirements of the 40 CFR part 75 system integrity check. Moreover, oxidized Hg gas

standards such as are produced by the HOVACAL and MerCAL are currently scheduled to be

independently tested by NIST, to verify their suitability as reference gas standards.

Comment:

Commenter OAR-2002-0056-2922 stated that the requirement of proposed Appendix A,

section 2.2.3 cannot be met. The commenter is not aware of any device, other than the Hovacal

that might be able to deliver “known concentrations of HgCl2" as required. The performance of

the Hovacal does not appear to be well documented.

Response:

Several different sources of gaseous, oxidized Hg are available and have been
6-xxxix

demonstrated, incuding the HOVACAL. The HOVACAL has been successfully applied in the

laboratory and field to generate and deliver known concentrations of HgCl2 to Hg CEMS to

achieve the requirements of the converter check as called for in the 40 CFR part 75 Hg CEMS

precertification requirement. Moreover, oxidized Hg gas standards such as the HOVACAL and

MerCAL are currently scheduled to be independently tested by NIST to verify their suitability as

reference gas standards.

Comment:

Commenter OAR-2002-0056-2922 stated that in Appendix A, section 3.1, the

specification should read “5% of the span value if the span value is 20 micrograms/dscm or

greater, or 1 microgram/dscm if the span value is less than 20 micrograms/dscm.” The

specification as now written penalizes any monitor with a span value between 10 and 20

micrograms/dscm.

Response:

Appendix A, section 2.1.7.3 defines span for Hg CEMS in multiples of 10

micrograms/dscm. Therefore, there will be no Hg span values between 10 and 20

micrograms/dscm. Appendix A, Section 3.1 is retained, as proposed, in the final rule.

Comment:

Commenter OAR-2002-0056-2922 stated that Equation F-29 appears to make the

calculation correctly. However, the description in section 9.1.2 is difficult to understand. A

complete set of equations and nomenclature should be provided instead of the cross references

and replacement values.

Response:

Proposed Equation F-29 applies only to Hg-diluent monitoring systems. In the final

rule, EPA has deleted Equation F-29 and all provisions related to this type of monitoring

system. The final rule requires Hg mass emissions to be determined as the product of the Hg

concentration and the stack gas flow rate.

Comment:

Commenter OAR-2002-0056-2922 stated that, both PS 12A and Method 324 are

designed to measure vapor-phase Hg. Consistent with that, EPA should make clear in the 40

CFR part 75 RATA requirements (as EPA did in PS 12A, section 8.6.2) that the filterable portion

of the reference method sample is not included when making the comparison to the CEMS.

Consistent with that change, EPA should also remove the requirements in sectioin 75.59(a)(7) to

record and report RATA results related to particle bound Hg, or justify the collection and
6-xl

submission of that additional data.

Response:

The final rule clearly states in 40 CFR 75.22 that only the vapor phase Hg, and not the

filterable portion of the reference method sample is included when making the comparison to the

CEMS. However, EPA has retained in section 75.59(a)(7) the recording and reporting of both

gaseous and particle-bound Hg, when particle-bound Hg is provided by the reference method. 

The particle-bound Hg emissions data is required in today’s final rule to provide information to

assess the need for possible future regulation of particle-bound Hg.

6.5 MERCURY MONITOR AVAILABILITY

Comment:

One commenter (OAR-2002-0056-3560) stated that no correlation has been established

between the basis for the standards and the required test methods. Plants that submitted Hg data

to the EPA used the Ontario-Hydro Method to calculate their Hg emissions. EPA then used these

data, based on the Ontario-Hydro Method, to create the Hg standards. Whether the proposed

monitoring systems are comparable to the Ontario-Hydro Method, which was used to set the Hg

emissions limits is unknown. If they are not, the Hg emissions limits could result in a standard

that is not obtainable from the outset. This would leave facilities open to notices of

violations/penalties when their failure to comply is a result of an inconsistency between analytical

methods–the Ontario-Hydro Method used to set the Hg emissions limits versus Hg CEMS,

sorbent trap monitoring systems, and long-term sampling monitoring that are to be employed to

determine if units are meeting the emissions limits for compliance purposes. Discerning whether

the test methodology utilized to create the Hg emission standards (Ontario-Hydro Method)

correlates to any of the required test methods, and especially when Hg CEMS are not yet

commercially available, is impossible.

Response:

EPA disagrees and believes Hg CEMS and sorbent trap monitoring systems have been

demonstrated to be reasonably comparable to the Ontario-Hydro Method through various field

demonstrations.

Comment:

One commenter (OAR-2002-0056-1854) noted that the analyzer can be no more than 100

feet from the sample probe. The commenter state that this means, in their case, that QA and

maintenance procedures must take place on the stack platforms where personnel will be exposed

to extreme weather conditions from time to time. The commenter also stated that their

experience would also indicate that additional staffing by specially trained personnel will be
6-xli

required because these monitors cannot be left unattended for long periods of time.

Response:

Mercury CEMS demonstration testing conducted by EPA so far has provided evidence

from a number of CEMS at a number of different utilities that the analyzer does not have to be

located on the stack platform. Regarding on-going system maintenance, the level required will

ultimately depend on the monitoring system and the emission characteristics. We have noticed a

marked improvement in amount of time needed for hands-on monitor attendance over the time

frame of demonstrations, including automation of daily check procedures and capability for

remote system adjustment, and expect significantly more improvement in the coming months.

Comment:

One commenter (OAR-2002-0056-3548) stated concerns about the technical feasibility of

operating and maintaining CEMS for Hg. The proposed monitoring requirements are beyond the

capabilities of current monitoring equipment. Although the technology is developing rapidly, the

proposed technology is analogous to EPA proposing to require 40 CFR part 75 monitoring

requirements for flow, SO2, and NOx in 1970 with a compliance deadline of 1974. This being the

case, it is imperative that EPA provide as much flexibility as possible in allowable monitoring

methods.

Response:

EPA believes that Hg CEMS and sorbent trap monitoring systems meet the proposed

monitoring requirements. The final rule contains flexibility by allowing sources to account for

their Hg emissions by using Hg CEMS, sorbent trap monitoring systems (or a combination

thereof), and, in some cases, using low mass provisions.

Comment:

One commenter (OAR-2002-0056-2915) stated concerns about the technical feasibility of

operating and maintaining CEMS for Hg. The commenter’s concerns regard the precision,

reliability, and accuracy of the monitoring alternatives identified by the EPA in the proposed Hg

rule. One area of major concern involves the proposed detection limits. The commenter asserts

that as the allowable Hg emissions levels grow smaller (particularly in the case of new or

well-controlled existing units), it becomes technically more difficult to measure Hg levels in the

emissions from an electric generating unit (EGU) and to determine how the inherent measurement

uncertainties will impact an EGU’s compliance demonstration with the Hg limits. Further, should

CEMS for Hg be required by the Hg rule, the commenter would have concerns with the proposed

RATA process, particularly the length of time and amount of money that may be required to

comply with the Hg monitoring requirements on an annual basis. The commenter asserts that the

final monitoring requirements must be technically achievable and capable of measuring Hg
6-xlii

emissions with precision, reliability, and accuracy in a cost-effective manner.

Response:

EPA believes that Hg CEMS will provide adequate precision, reliability, and accuracy

for emissions trading, however, may not be necessary for all units. Consistent with the low mass

emissions (LME) provisions for SO2 and NOx, the final rule provides a less rigorous monitoring

option for low Hg emitters.

Comment:

One commenter (OAR-2002-0056-2830) stated it is not appropriate to require CEMS

monitors on new units if operations begins more than six months after publication of the final rule.

CEMS have not been commercially demonstrated, and as commented on earlier, the commenter

believes that they cannot be commercially demonstrated within 4 years of the rule being finalized.

Response:

EPA disagrees with commenter and believes that Hg CEMS and sorbent trap monitoring

systems can be commercially demonstrated before rule implementation. However, the

requirement for new units to use Hg CEMS has been withdrawn. New units may use sorbent trap

monitoring systems instead, under both 40 CFR part 75, subpart I, and under 40 CFR part 60,

subpart Da.

Comment:

One commenter (OAR-2002-0056-2429) requested the EPA provide additional technical

information on both CEMS that meet PS12 requirements and sorbent traps that meet Method 324

requirements for various plant configurations and conditions such as wet stacks. Their units are

equipped with wet scrubbers, fabric filters, and low NOx burners.

Response:

EPA will provide additional information when available.

Comment:

One commenter (OAR-2002-0056-2899) stated that currently no Hg CEMS have been

demonstrated to be accurate and reliable. The commenter stated that although continuous

systems are available from different manufactures none have been used in continuous operation

for an extended period of time. The commenter asserts that most have been used in pilot or short

term full scale tests and generally compared to the Ontario-Hydro impinger method, which is a

short term test ranging from minutes to hours, and this gives only snapshots of the continuous
6-xliii

monitors performance. The commenter noted the current generation of continuous monitors are

based on wet chemistry requiring almost constant maintenance and calibration. The commenter

stated that although dry chemistry systems are under development and testing none are yet

commercially viable. According to the commenter, at present continuous Hg monitors not are

ready to be used for continuous compliance. The commenter stated that the EPA should allow

the option of using a periodic measurement system such as EPRI’s QuickSEM or other system

instead of a continuous monitor for compliance with this rule.

Response:

EPA disagrees with the commenter and believes that field tests have demonstrated Hg

CEMS to be accurate and reliable. The Hg CEMS have performed adequately for several

months and meet the Ontario-Hydro Reference Method specifications. Furthermore, several dry

chemistry Hg CEMS are currently being tested at sites that represent the most challenging

conditions and the Agency plans to share with industry the results of such experiences to

facilitate the selection of appropriate monitoring methodology. EPA is also confident that

substantial advancement of Hg CEMS will occur before the implementation of the rule and as

other monitoring techniques may become available, is allowing the use of systems that can meet

performance-based specifications.

Comment:

One commenter (OAR-2002-0056-5495) stated that CEMS for measuring low Hg

emissions from waste coal is not a proven technology.

Response:

EPA disagrees with the commenter and believes that field tests have demonstrated Hg

CEMS to be accurate and reliable at low Hg concentrations. The Hg CEMS have performed

adequately for several months and meet the Ontario-Hydro Reference Method RATA

specifications at two low Hg concentration (0.5 - 2 μg/dscm) coal-fired sources. EPA is also

confident that substantial advancement of Hg CEMS will occur before the implementation of the

rule and as other monitoring techniques may become available, is allowing the use of systems

that can meet performance-based specifications.

Comment:

One commenter (OAR-2002-0056-2830) agreed with the EPA that compliance be

monitored through the use of CEMS or other continuous measurement methods (e.g., sorbent

trap) for all affected sources. However, the commenter is concerned that monitoring and

recording technology has not evolved to the level of reliability necessary to collect emissions data

for compliance purposes. As entered in the EPA Docket, the EPA-funded project termed

“Long-Term Evaluation of Mercury Continuous Emission Monitoring Systems” - December 11,
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2003, it was determined that the current capabilities of Hg CEMS are not at a level that can be

relied on in a regulatory compliance environment. In almost all cases, the analyzers failed to meet

the 20 percent relative accuracy criteria for the first two phases. In Phase III, there were some

instruments that passed the relative accuracy criteria. The Carbon Bed technology was only

tested in Phase ill of the program and did exceptionally well as compared to the other CEM

systems and against the Ontario-Hydro Method. However, there are concerns that the facility

was an “optimum test site.” A substantial test for Hg analyzer systems should come under test

conditions that are strenuous and challenging in order to identify shortcomings of the systems.

The test should be completed at a facility where the sampling location has a representative

particulate loading and sulfur concentrations. The systems should also be challenged under wet

stack conditions.

Response:

EPA is currently field testing Hg CEMS and sorbent trap monitoring systems under

strenuous and challenging conditions where the sampling location is under wet stack conditions

and has a representative particulate loading and sulfur concentration. Preliminary data from 

these field tests seems to indicate that monitoring and recording technology are getting closer to

the level of reliability necessary to collect emissions data for compliance purposes, supporting

the Agency’s confidence that by the end of the demonstration technology will provide the

answers to the challenges presented.

Comment:

One commenter (OAR-2002-0056-3469) stated that lack of control and monitoring

technology impedes speedy compliance. The EPA’s proposed Hg monitoring technologies (e.g.,

CEMS 12A and Method 324) are not yet commercially available and do not yet provide accurate

data. It is not known when they will be successfully tested and commercially available.

Response:

EPA disagrees with commenter; Hg CEMS and sorbent trap monitoring systems are

commercially available and provide accurate data, as demonstrated by various completed and

ongoing field tests. In addition, EPA believes these technologies will significantly advance

before compliance is necessary.

Comment:

Is it currently feasible, or will it be feasible within the compliance timeframes of the

proposed rule, to accurately monitor a source’s Hg emissions by species?

Response:
6-xlv

The final rule requires the measurement of total vapor phase Hg, but does not require

separate monitoring of speciated Hg emissions (i.e., elemental and ionized Hg). Because of the

potential impact of Hg speciation on local versus broader geographical deposition, the Agency

considers separate monitoring of these emissions as a need to be addressed. However, at least

two current monitoring technologies can accurately monitor speciated Hg emissions. The

Agency will continue to test speciated Hg monitoring technologies. If these technologies are

adequately demonstrated, the Agency may consider a proposed rulemaking within four to five

years after program implementation, which should provide enough lead time for development

and installation of these monitoring systems.

6.6 MERCURY DILUENT SYSTEMS

Comment:

One commenter (OAR-2002-0056-3455), in reference to section 72.2 - Definitions, page

12453, asked why the proposed Hg emissions units of measurement are the same as NOx -diluent? 

The Hg concentration measurements are orders of magnitude below NOx emissions, thus applying

a diluent correction with the additional uncertainties of measurement further complicates the

direct emissions reporting uncertainties. Mercury is a resident pollutant in the fuel, it can be

measured, and measurement should parallel the same regulation requirements as SO2.

Response:

The final rule removes all mention of Hg-diluent monitoring systems and requires the

hourly Hg mass emissions to be calculated in the same manner as is done for SO2 under the Acid

Rain Program, i.e., as the product of the Hg concentration and the stack gas flow rate. The final

rule also better accommodates Hg analyzers that measure on a wet basis.

EPA believes that the rule can be considerably simplified and shortened without losing

any flexibility by deleting the provisions related to Hg-diluent monitoring systems and allowing

only Hg concentration monitoring systems and sorbent trap systems to be used. Therefore, the

final rule removes all mention of Hg-diluent monitoring systems and requires the hourly Hg

mass emissions to be calculated in the same manner as is done for SO2, i.e., as the product of the

Hg concentration and the stack gas flow rate.

6.7 LOW EMITTING UNITS

Comment:

One commenter (OAR-2002-0056-2900) questioned the need for continuous monitoring if

the EPA requires coal-fired EGUs to meet MACT standards. The commenter urges the Agency

to allow periodic monitoring and parametric monitoring approaches rather than restricting sources

to the use of Hg CEMS or sorbent trap monitoring.
6-xlvi

Response:

The Agency has decided to use a cap-and-trade program to control Hg emissions. 

Complete and accurate accounting of Hg emissions is required for a credible cap and trade

program. Therefore, Hg CEMS or sorbent traps are required in the final rule. However,

qualifying, low emitting sources may comply with today’s monitoring requirements by using

conservative default Hg emission factors and annual or semi-annual stack testing.

Comment:

Numerous commenters (OAR-2002-0056-2101, -2162, -2267, -2634, -2718, -2861, -

2867, -2900-2918, -2922, -3432, -3509, -3513, -3565, -2855) requested that EPA provide a less

rigorous, cost-effective monitoring option for low emitting units. Affected units could meet a

low-emitter criterion based on a combination of unit size, operating time, and/or control device

operation. Any marginal decrease in accuracy from less rigorous monitoring would have a

minimal impact overall, because these units represent only a small percentage of the nationwide

Hg mass emissions.

Response:

Consistent with the low mass emissions (LME) provisions in section 75.19 for SO2 and

NOx, sections 75.81(b) through (g) of the final rule provide a less rigorous monitoring option for

low Hg emitters. These provisions allow sources with estimated annual emissions of 29 lb/yr

(464 oz/yr) or less, representing about 5 percent of the nationwide Hg mass emissions, to use

periodic emission testing to quantify their Hg emissions, rather than continuously monitoring the

Hg concentration. For units with Hg emissions of 9 lb/yr (144 oz/yr) or less, annual emission

testing is required. For units with Hg emissions greater than 144 oz/yr but less than or equal to

464 oz/yr, semiannual testing is required. For reporting purposes, the owner or operator is

required to use either the highest Hg concentration from the most recent emission testing or 0.50

μg/scm, whichever is greater. If, at the end of a particular calendar year, the reported annual

Hg mass emissions for a unit exceed 464 ounces, the unit is disqualified as a low mass emitter

and the owner or operator must install and certify a Hg CEMS or sorbent trap monitoring

system within180 days of the end of that year. The final rule also contains special low mass

emitter provisions for common stack and multiple stack exhaust configurations.

The Agency believes that a low mass emitter provision can be beneficial to both EPA and

industry. It is cost-effective for industry, in that it allows periodic stack testing to be used to

estimate Hg emissions instead of requiring continuous emission monitoring. In the context of a

cap and trade program, a low emitter provision can provide environmental benefit, because it

requires conservatively high default emission factors to be used for reporting, thereby removing 

Hg allowances from circulation. Also, allowing a subset of the affected units to use less rigorous

monitoring reduces the administrative burden of program implementation, allowing EPA to

focus its attention on the higher-emitting sources.
6-xlvii

Selecting an appropriate low emitter cutoff point is of critical importance. On the one

hand, if the cutoff point is too low (i.e., too exclusive) this would not be cost-effective for the

regulated sources and would greatly increase the burden on the regulatory agencies to

implement and maintain the program. On the other hand, if the cutoff point is too high (i.e., too

inclusive), this would create inequities in the trading market.

Over the years, EPA has used a de minimis concept to either exempt low-emitting sources

from monitoring or to allow these sources to use less rigorous, lower cost techniques to monitor

emissions instead of installing CEMS:

 In the preamble of the 1993 Acid Rain Program (ARP) final rule (see 58 FR

3593, January 11, 1993), EPA’s Acid Rain Division (now the Clean Air Markets

Division) first used the de minimis concept to exempt certain new utility units

from the Acid Rain Program (i.e., units less than or equal to 25 MW that burn

only fuels with a sulfur content less than or equal to 0.05 percent by weight);

 EPA also allows gas-fired and oil-fired peaking units to use the less costly

methodology in 40 CFR part 74, appendix E, to estimate NOx emissions instead of

using CEMS, because the Agency’s analyses indicated that projected NOx

emissions from these units represent less than 1 percent of the total NOx

emissions from Acid Rain Program units.

 In 1998, EPA promulgated LME provisions in section 75.19 for SO2 and NOx (see

63 FR 57484, October 27, 1998). These provisions require the use of

conservatively high default emission rates to quantify SO2 and NOx emissions.

EPA determined the appropriate SO2 and NOx mass emissions thresholds or

“cutoff points” for unit to qualify as a low mass emissions methodology,

considering inventory and regulatory changes that had taken place since the

original1993 Acid Rain rulemaking. The selected threshold values were based on

a de minimis concept, i.e., the SO2 and NOx emissions from the units that could

potentially qualify to use the LME methodology represented less than or equal to

1 percent of the emissions from all affected units.

In 1999, EPA obtained Hg mass emissions estimates for the 1,120 utility units affected by

the SNPR, as the result of an information collection request (ICR) that appeared in the Federal

Register on April 9, 1998. These data show that if a low Hg mass emission threshold of 9 lb/yr

were selected, 228 units, representing 1 percent of the total annual Hg emissions from coal-fired

electric utility units in the U.S., could potentially qualify to use the low emitter option. However,

EPA’s analysis also indicated that by raising the cutoff point to 29 lb/yr, almost twice the

number of units (435), representing just 5 percent of the total annual Hg emissions, could

potentially qualify as low emitters. Therefore, EPA has decided to adopt the 29 lb/yr as the

qualifying low mass emission threshold for Hg.

Although the 5 percent threshold represents a departure from the traditional de minimis

value of 1 percent, the Agency believes that allowing units with Hg emissions of 29 lbs/yr or less
6-xlviii

to use the low mass emitter option is a better choice, for both economic and environmental

reasons. For continuous monitoring methodologies, the annualized cost per unit will be about

$89,500 for testing, maintenance, and operation. For sorbent trap methodologies, the

annualized cost per unit will be about $113,000 for testing, maintenance, and operation. For a

unit that emits between 9 lb/yr and 29 lb/yr of Hg, if the owner or operator elects to use the low

emitter option, today’s rule would require two stack tests per year (at $5,500 each), and an

estimated $1,500 annual cost for technical calculation, labor, and other associated costs, for a

total annual expenditure per unit of around $12,500. Therefore, for the approximately 207 units

with Hg mass emissions between 9 and 29 lb/yr, the potential savings associated with the

implementation of the low emitter option could be as high as: $89,500 - $12,500 = $77,000 *

207 units = $15,939,000 per year if LME is used instead of Hg CEMS. Alternatively, if LME is

used instead of sorbent traps, the potential savings could be even higher: $113,000 - $12,500 =

$100,500 * 207 units = $20,803,500 per year. This is achieved without losing the environmental

integrity of the program or compromising the cap, because the default Hg concentration values

used for reporting are conservatively high, and for units with flue gas desulfurization (FGD)

systems or add-on Hg emission controls, the rule requires the maximum potential concentration

(MPC) to be reported when the controls are not operating properly.

As a further justification of the 5 percent low emitter threshold for Hg, EPA notes that

there are two important differences between the Hg low mass emission provisions in section

75.81 and the LME provisions in section 75.19 for SO2 and NOx (which are based on a 1 percent

threshold). First, under section 75.19, default emission rates are used exclusively, and there is

no real-time continuous monitoring of the SO2 or NOx emissions. However, under section 75.81,

the stack gas volumetric flow rate, which is used in the hourly Hg mass emission calculations, is

continuously monitored. Second, the LME provisions in section 75.19 allow you to either use

generic default NOx emission rates without performing any emission testing, or, if you test for

NOx, you are only required to determine a new default emission rate once every 5 years. Under

section 75.81, emission testing is required initially to qualify as a low emitter, and retesting is

required either semiannually or annually thereafter, depending on the annual emission level.

6.8 RECORDKEEPING/REPORTING REQUIREMENTS

Comment:

One commenter (OAR-2002-0056-3455) stated that, in reference to Appendix A to the

Preamble--Proposed Changes to Parts 72 and 75, (Proposed Rules March 16, 2004); page

12420 (Calculation of Mercury Mass Emissions) all of the calculations for both CEMS and

sorbent methods contain a significant error. Rounding procedures for equation F-28 (hourly

emissions) require rounding of hourly emissions, in ounces, to one decimal place. This would

result in all but the largest sources registering as 0.0 oz/hr. Final rounding for reporting purposes

may be to two or three significant figures. Intermediate results that are used in subsequent

calculations should not be rounded to minimize propagation of numerical errors. For example, if

hourly emissions for a particular unit were constant and calculated as 0.35 oz/hr, rounding to 0.40
6-xlix

oz/hr would result in excess emissions of 438 oz/year. Introducing artificial arithmetic artefacts

into the emission calculations of a high value pollutant such as Hg is unwise and unnecessary.

Response:

EPA agrees with the commenter and has required in the final rule that equation F-28

results and the recordkeeping/reporting of hourly Hg mass emissions be rounded to the nearest

thousandth of an ounce. EPA’s 40 CFR part 75 policy is that intermediate results that are not

reported, but are used in subsequent hourly calculations should not be rounded to minimize

propagation of numerical errors.

Comment:

One commenter (OAR-2002-0056-3455) stated that, in reference to Appendix F to the

Preamble--Proposed Changes to Parts 75, (Proposed Rules March 16, 2004); page 12472, the

calculation procedure in Appendix F to Part 75 – Conversion Procedures contains serious errors. 

In particular, equation F-28 is erroneous and does not yield correct results. The commenter noted

that the Hg concentrations used for mass determination are not referenced to any specific CO2 or

O2 levels. This provides further support for the position that reporting on this basis is

superfluous.

Response:

EPA has corrected equation F-28 in the final rule. The final rule does not reference Hg

concentrations to any specific CO2 or O2 levels.

Comment:

One commenter (OAR-2002-0056-3455) noted that, in reference to Appendix F to the

Preamble--Proposed Changes to Parts 75, (Proposed Rules March 16, 2004); page 12472,

Equation F-28 contradicts Equation 3 (FR page 4724) by requiring hourly averaging of the Hg

concentrations and hourly totals of the stack flow before performing a calculation. Significant

flow and concentrations can take place over the course of an hour, resulting in an erroneous

calculation. This form of calculation may be appropriate for the sorbent method. However, for

CEMS, a more accurate and unbiased calculation is available by multiplying concentration and

volumetric readings together at the data rate of the CEMS and then summing to produce hourly

emissions.

Response:

EPA understands the concern of the commenter. However, because one hour periods are

the basic Hg emissions reporting increment, EPA requires sources to calculate their quarterly

and annual Hg mass emissions using hourly quantities. This allows EPA to recalculate
6-l

quarterly and annual Hg mass emissions using the same reported hourly numbers that sources

use. If sources used sub-hourly increments to calculate mass emissions, EPA’s recalculated

mass emissions based on reported hourly values would not agree with the reported numbers.

Comment:

One commenter (OAR-2002-0056-2889), although not supporting Hg trading, did

support using the electronic reporting, under the acid rain program emission reporting system, set

up for SO2 and NOx for Hg emissions reporting. This would consolidate the emission reporting

requirements under the NSPS and Acid Rain Program, which regulate the same facilities. The

addition of Hg to those pollutants already reported to the Clean Air Markets Division would

benefit EPA, States, public, the industry.

Response:

The final rule requires the same type of electronic reporting that is used under the Acid

Rain and NOx Budget Programs.

6.9 OTHER

Comment: 

One commenter (OAR-2002-0056-3200) supports EPA’s rolling 12-month averaging

calculation for compliance determinations. Mercury is not an acute health hazard and concerns

arise from long-term chronic exposure. Thus, Hg control lends itself well to a compliance

program with long-term averaging.

Response:

The Agency has decided to use a cap-and-trade approach to control Hg emissions.

However, note that the proposed NSPS for Hg has been finalized under 40 CFR 60, subpart Da,

and compliance with the Hg emission limit in 40 CFR 60.45a is determined on a 12-month

rolling average basis.

Comment: 

Two commenters (OAR-2002-0056-2068, -2422) stated that EPA’s proposed methods

for measuring Hg emissions from coal fueled power plants must address the detection limits of

those methods and how those detection limits will impact compliance demonstrations with the

new source MACT limits. The EPA must take into account the ability of existing technology to

detect Hg emissions at such minute levels, and must also discuss the range of test results which

may be allowable over time. Without such clarification, units will be unable to reliably determine if

their test results are within an acceptable range of compliance, or if they violate the limits. One
6-li

commenter (OAR-2002-0056-2422) adds that regardless of the monitoring alternatives specified

by EPA, the final rule must address the detection limits of that testing methods). As the allowable

Hg emission levels grow smaller, it becomes scientifically more difficult to assess whether the

emission limits are being met. 

Response:

In field tests of Hg monitoring methodologies, EPA has observed that low concentrations

of Hg can be detected and accurately measured with the currently-available monitoring systems. 

Mercury compliance will be determined under a cap-and-trade program, rather than MACT.

Comment: 

One commenter (OAR-2002-0056-3439) stated that the proposed supplemental rule

(dated March 16, 2004) defines the minimum acceptable test run duration for the reference test

method (Ontario-Hydro) as 2 hours. Given the very low concentration of Hg in the gas stream,

the commenter recommended a test run of longer duration or sufficient analysis of available test

data be conducted to provide adequate confidence in the 2 hour minimum test run duration.

Response:

EPA has data to indicate that 2 hours is sufficient for application to controlled sources.

However, in the final rule, the 2-hour minimum RATA run length provision has been withdrawn. 

For the RATA of a Hg CEMS using the Ontario-Hydro method, or for the RATA of a sorbent

trap system (irrespective of the reference method used), the final rule simply specifies that the

minimum time per run must be long enough to collect a sufficient mass of Hg to analyze.

Comment: 

One commenter (OAR-2002-0056-2063) recommended with regard to QA/QC

requirements that annual RATA tests using a Reference Method, either wet chemistry-based or 

Method 324 (paired trains) are appropriate for either a CEM or Method 324.

Response: 

EPA agrees with the commenter with the exception that we do not consider that sorbent

trap monitoring procedure has the quality to serve as a reference method. We are, however,

confident of its performance as a monitoring method as long as a yearly RATA is performed and

passed and the performance criteria in Appendix K are met.

Comment:

One commenter (OAR-2002-0056-2883) believed that the EPA should hold workshops to
6-lii

assist both purchasers, States, and vendors on various monitoring systems.

Response:

EPA agrees with the commenter and will provide workshops to assist both purchasers,

States, and vendors on any issues related to the final rule.

Comment:

One commenter (OAR-2002-0056-2889) stated that the proposed PS-12A only accounts

for vapor phase Hg emissions. This allows facilities to ignore particulate-bound Hg emissions

when using a CEMS. The State of Massachusetts provided test data to showed that particulatebound Hg can constitute as much as 40 percent of total Hg. The commenter urged EPA to

require total Hg emissions as the basis of compliance demonstrations per their state rules.

Response:

Nationwide, 97 percent of Hg emissions from the outlets of coal-fired utilities are vapor

phase. Currently there is no established technology, other than the Ontario-Hydro Method to

measure particulate-bound Hg. Therefore, today’s final rule only regulates vapor phase Hg

emissions.

Comment:

One commenter (OAR-2002-0056-2867) stated that for applications where Hg CEMS are

used and for Hg monitoring and audits to be advanced, the commenter submits a real time

instrumental reference method for RA audits is needed. The commenter stated that EPA must

develop such an instrumental reference method for Hg.

Response:

EPA agrees with the commenter. Based on field testing, EPA intends to develop an

instrumental reference method for Hg. Initial evaluations of such a method have already begun.

Comment:

One commenter (OAR-2002-0056-1842) stated that monitoring Hg to the degree of

accuracy required for trading ($35,000/lb) is a daunting task. Add to this the fact that EPA has

not addressed particulate Hg and suggested just ignoring this quantity. The rationale is that

particulate Hg is only three percent of the total. At $35,000/lb the ignored quantity translates into

$105,000 for a 300 MW boiler, $1,050,000/yr for a 3,000 MW plant and $105,000,000 for the

whole industry. Mercury measurement is money measurement. This number may even be larger. 

Fine particulate emissions from power plants are not measured. The commenter believed
6-liii

emissions are much larger than EPA estimates. Therefore particulate Hg emissions from plants

with old inefficient precipitators are likely to be much higher than emissions from the average

plant. Also some Hg control technologies create particulate Hg. The RJM concept is to

condense acid mist on fine particulate in order to create acid deposition sites. Under the EPA

scheme all the Hg could then be discharged and not counted. Also there is a 10 times differential

between fine particulate emissions from old precipitators and new ones. This means it will be

necessary to measure particulate Hg. Periodic Method 5 sampling will result in filter catches

which can then be analyzed for particulate Hg. The accuracy will be a function of the sampling

interval and the variations from sample to sample. A few stack tests per year may establish

particulate Hg plus or minus 50 percent. A stack test each week would reduce the inaccuracy to

some smaller range e.g., 10 percent. However continuous method 5 sampling would improve

accuracy even more. Annual Hg quantities then will be the integration of the results from sorbent

traps, Hg CEMS, method 5 tests for particulate Hg and material balances involving the amounts

in the coal, ash, fly ash, and wastewater.

Response:

Nationwide, 97 percent of Hg emissions from the outlets of coal-fired utilities are vapor

phase. Currently there is no established technology, other than the Ontario-Hydro Method to

measure particulate-bound Hg. Therefore, the final rule only regulates vapor-phase Hg

emissions. EPA will collect the particulate Hg concentrations from any source using a reference

method capable of providing particulate Hg concentrations and may initiate a future rulemaking

to require that these emissions be monitored and reported.

Comment:

Several commenters (OAR-2002-0056-2634, -2718, -2861, -2922, -3565) noted that

proposed 40 CFR 75 subpart Da section 60.50a(j) would require Hg CEMS and sorbent trap

systems to perform some QA/QC requirements “in accordance with” Procedure 1 of 40 CFR part

60, Appendix F. This presents some issues for sorbent trap systems because Procedure 1 does

not include all of the information necessary to perform those tests. In addition, with the use of 40

CFR part 60 QA/QC requirements in subpart Da, new units that are subject to both the NSPS and

the cap-and-trade program would be subject to both the specified 40 CFR part 60, Appendix F,

and the 40 CFR part 75, Appendix B, QA/QC requirements. EPA should avoid imposing these

duplicative and inconsistent requirements by explicitly stating in the subpart Da revision that Hg

CEMS and sorbent trap systems meeting the requirements of 40 CFR part 75 do not have to

comply with 40 CFR part 60, Appendix F, procedures set out in 40 CFR 60.50a(j). EPA should

use the subpart Da NOx revision in 40 CFR 60.47(c)(2) as a model. 

One commenter (OAR-2002-0056-3469) stated that to minimize duplication and

additional costs, the EPA should adopt monitoring and reporting standards that are consistent

with those for other air quality programs.
6-liv

Response:

In the final rule for Hg (40 CFR 60, subpart Da), EPA has made it clear that the

provisions of 40 CFR part 60, Appendix F do not apply to sorbent trap monitoring systems. 

Rather, sorbent trap monitoring systems must meet the applicable QA requirements in

Appendices B and K of 40 CFR part 75. An annual RATA of each sorbent trap system is

required, in addition to a number of system-specific QA tests and procedures. For the qualityassurance of data from Hg CEMS, the NSPS clearly states that sources subject to both 40 CFR

60, subpart Da and 40 CFR part 75, subpart I may implement the QA procedures in 40 CFR

part 75, Appendix B in lieu of the procedures in 40 CFR part 60, Appendix F.
RESPONSE TO SIGNIFICANT PUBLIC COMMENTS ON

THE PROPOSED CLEAN AIR MERCURY RULE

Received in response to:

Proposed National Emission Standards for Hazardous Air Pollutants; and, in

the Alternative, Proposed Standards of Performance for New and Existing

Stationary Sources: Electric Utility Steam Generating Units

(69 FR 4652; January 30, 2004)

Supplemental Notice for the Proposed National Emission Standards for

Hazardous Air Pollutants; and, in the Alternative, Proposed Standards of

Performance for New and Existing Stationary Sources: Electric Utility Steam

Generating Units

(69 FR 12398; March 16, 2004)

Proposed National Emission Standards for Hazardous Air Pollutants; and, in

the Alternative, Proposed Standards of Performance for New and Existing

Stationary Sources, Electric Utility Steam Generating Units: Notice of Data

Availability

(69 FR 69864; December 1, 2004)

Docket Number OAR-2002-0056

7.0 IMPACT ESTIMATES

US Environmental Protection Agency 

Emissions Standards Division

Office of Air Quality Planning and Standards

Research Triangle Park, North Carolina 27711

15 March 2005
i

General Outline

1.0 INTRODUCTION AND BACKGROUND

2.0 APPLICABILITY AND SUBCATEGORIZATION

3.0 PERFORMANCE STANDARDS FOR COAL-FIRED ELECTRIC

UTILITY STEAM GENERATING UNITS

4.0 PERFORMANCE STANDARDS FOR OIL-FIRED ELECTRIC

UTILITY STEAM GENERATING UNITS

5.0 MERCURY CAP-AND-TRADE PROGRAM

6.0 MERCURY EMISSIONS MONITORING

7.0 IMPACT ESTIMATES

8.0 COMPLIANCE WITH EXECUTIVE ORDERS AND STATUTES

9.0 NODA

10.0 OTHER

Appendix A LIST OF COMMENTERS
7-i

7.0 IMPACT ESTIMATES

7.1 IPM MODELING

Comment:

One commenter (OAR-2002-0056-2578) stated that both they and EPA have been

employing Eulerian regional models for simulating both deposition patterns of Hg under current

emissions, and how those deposition patterns might change under proposed utility Hg regulation.

The commenter stated that there is strong evidence that those models tend to overestimate

near-source ground-level concentrations and deposition of Hg when compared to equivalent

calculations using Gaussian plume simulation local-scale models. The commenter stated that the

consequences associated with this model precision include the following: 1) it helps explain why

models tend to show higher deposition than is measured by Hg monitoring stations in some

regions of the U.S., and 2) these overpredictions of deposition will tend to overestimate the

assessments of how much Hg is entering various waterbodies, accumulating in fish and eventually

resulting in a potential exposure to humans.

Response:

There is no evidence that in our applications of Eulerian regional models that they

overestimate ground-level wet deposition of Hg. The models generally do not show higher wet

deposition than the Hg monitoring sites. The Community Multiscale Air Quality (CMAQ) Model

used for the Clean Air Mercury Rule (CAMR) underestimated annual Hg wet deposition at the

majority of Mercury Deposition Network sites. There is not a measurement network for Hg dry

depositions or Hg concentrations, so it cannot be concluded that the Eulerian regional models

overpredict these values. In general, the Gaussian models do not have adequate atmospheric

chemistry or deposition algorithms to predict Hg as well as the Eulerian regional models.

Comment:

One commenter (OAR-2002-0056-3454) stated that the current Hg control proposal

made under the CAA, section 111 provisions would not create markets for technology

development nor encourage innovation as the projected Hg cap level was set too high (i.e., at the

revised co-benefit level). The commenter further stated that EPA’s modeling analysis does not

consider the low cost reductions that will come from enhancing existing control technologies for

greater Hg capture. The commenter stated that these innovations will reduce the cost and overall

demand for Hg-specific reductions. The commenter stated that EPA’s projections for Hg-specific

control installations under the Section 111 proposal estimate that only 1 GW, or approximately

two of the more than 1000 coal-fired boilers in the U.S., would install Hg control technologies by

2010.

Response:

EPA has set the first phase cap of CAMR at a level that represents the Hg reductions
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expected as co-benefits accompanying the SO2 and NOx caps under CAIR in 2010, of the

combined emission reductions that SO2 and NOx controls provide in terms of reducing Hg

emissions. The ability of sources to bank excess Hg allowances in the first phase of the

program, as well as the lower second phase cap, will provide a strong incentive for the

development of efficient and cost-effective Hg control technologies. In fact, developments in Hg

control technologies, such as advanced sorbents, are already occurring. EPA’s Office of

Research and Development has a white paper (available in the docket) discussing the current

state of Hg control technology development.

Comment:

One commenter (OAR-2002-0056-2578) stated that modeled predictions of when

emissions would ultimately reach the 15 ton/yr Phase II cap in the proposed cap and trade rule are

sensitive to model assumptions concerning co-benefits, control effectiveness, and other poorly

determined variables. The commenter stated that EPA assumptions produce a longer phase-in

period than the set of assumptions used by the commenter, considered more realistic based on

research results. The commenter stated that differences in emissions banking behavior between

their simulations and EPA’s results are due to three factors (the commenter provided evidence

supporting each of the following points): 1) EPA assumes larger Hg reductions from key SO2 and

NOx controls (“co-benefits”) than is the current technical consensus; 2) EPA’s cost and

effectiveness assumptions for removal of Hg using activated carbon injection are more pessimistic

than those incorporated in the commenter’s model, and; 3) Other EPA assumptions appear to

cause the model to rely more on FGD retrofits over coal switching for units to achieve SO2

targets than the commenter assumed. The commenter asserted that their simulations employ

assumptions which their researchers view as more realistic and thus result in the 15 ton cap being

met by 2020.

Response:

EPA agrees that projections of the timeline for achievement of the 15 ton second phase

Hg cap are sensitive to modeling assumptions. EPA published a NODA discussing some of these

assumptions and input the Agency received from commenters that conducted modeling of the Hg

cap-and-trade program. EPA requested comment in the NODA on the following: projected

improvements in variable operating costs for ACI over time, consideration of additional Hg

control technology options, availability of ACI, Hg control technology costs, the impact of

banking on achieving the second phase Hg cap, the level of co-benefit Hg reductions under

CAIR, and Hg removal assumptions for the various technology combinations included in IPM. 

Assumptions in IPM are discussed in detail in the documentation for IPM v. 2.1.9, which is

available in the docket. EPA’s economic analysis of the final rule is discussed in Chapter 7 of

the Regulatory Impacts Analysis (RIA). Regarding the modeling submitted by the commenter,

EPA has noted that the projected emissions of 15 tons in 2020 appear to be an artifact of the

grouping of the 2020 run year with the model end run year of 2040. EPA maintains that, in a

least-cost solution model like the commenter’s, the model would solve for the cap in the final run

year grouping. 
7-iii

4 Comment:

One commenter (OAR-2002-0056-3552) disputed EPA’s rationale for not using section

112 as a control strategy because of the anticipated absence of local or regional hot spots. The

commenter stated that EPA based this position on the expected 70 percent emission reduction

under the proposed section 111 rule and cap and trade program and that analyses of the Acid Rain

program did not show any hot spots. The commenter stated that EPA should provide evidence to

support this position, including a description of the models, assumptions, and default. The

commenter asserted that states should have the opportunity to review the modeling runs used to

determine local deposition and check input values such as default values, percent Hg in coal,

control devices and their efficiencies, and Hg composition of the emissions released. The

commenter stated that for such an important decision, the methodology EPA used to arrive at this

prediction should be clear to the states.

Response:

EPA is finalizing a cap-and-trade program under section 111. All analysis of the rule is

available in the RIA. Documentation of EPA’s models and assumptions are available in the

docket. EPA believes that the final rule will protect public health, as show in its analysis.

7.2 HEALTH

7.2.1 Mercury in Coal

Comment:

One commenter (OAR-2002-0056-3538) stated that the proposed rule downplays Hg

health risks, retreats from previous findings, and exaggerates scientific uncertainties to justify a

weak standard.

Response:

EPA disagrees with the comment. The U.S. is, for the first time, establishing Federal

rules that will limit Hg emissions from coal-fired power plants. We are moving forward with a

regulatory program that is unprecedented in the world and will address health risk resulting

from coal-fired utility Hg emissions. As new scientific and health data become available, the

standards provide for a reanalysis of the appropriateness of the level of the standard.

Comment:

One commenter (OAR-2002-0056-2929) stated that in EPA’s December 2000 regulatory

determination, EPA noted “there are uncertainties regarding the extent of the risks due to electric

utility mercury emissions.” The commenter stated that previously, in its Mercury Research

Strategy, EPA stated that “[t]he amount of mercury deposited in the United States that can be

directly attributed to domestic combustion sources remains uncertain.” The commenter further
7-iv

stated that three years later, after extensive research on the fate and transport and atmospheric

chemistry of Hg, EPA stated in the proposed Hg rule that the agency “cannot currently quantify

whether, and the extent to which, the adverse health effects occur in the populations surrounding

these facilities, and the contribution, if any, of the facilities to those problems.” The commenter

further stated that, in addressing the state of the science, the proposed rule notes that “the

relationship between Hg emission reductions from utility units and methylmercury concentrations

in fish cannot be calculated in a quantitative manner with confidence.” The commenter also stated

that EPA admits that “[t]he Agency is unable to provide a monetized estimate of the benefits of

Hg (mercury) and Ni (Nickel) emissions reduced by the proposed rule at this time.” The

commenter added that recent and comprehensive research undertaken by the Centers for Disease

Control and Prevention (CDC), which measured Hg in the blood of women, indicates that people

in the U.S. are not being exposed to levels of Hg considered to be harmful to fetuses, children, or

adults. The commenter stated that according to the CDC, “The levels reported in this NHANES

[National Health and Nutrition Examination Survey] 1999-2000 subsample for maternal-aged

females were below levels associated with in utero effects on the fetus, or with effects in children

and adults (National Academy of Sciences, 2000).” Another commenter (OAR-2002-0056-3440)

added that health effects of Hg reductions from power plants have not been demonstrated.

Response:

As part of its analysis of the final rule, EPA has estimated the health benefits of reducing

Hg from utilities. EPA’s analysis focuses on the benefits of reducing neurological impacts of

exposure to MeHg via consumption of self-caught freshwater fish. The RIA for this rule contains

this analysis in Chapter 11.

Comment:

Many State Attorney Generals contended that EPA downplayed and mischaracterized the

current science and technology concerning the public health impacts caused by Hg exposure,

which supports the need for an appropriate MACT standard under section 112. Many U.S.

Senators and one Congressman agreed that certain scientific evidence appears to have been

changed to diminish the significance of health risks. One commenter stated that EPA disregarded

the available science when evaluating the adverse health impacts of Hg exposure, ignored the

degree to which the public is exposed to Hg, did not assess the benefits to public health of

decreased MeHg ingestion in fish, and presented, without foundation, the global and local impacts

of Hg deposition. The commenters contended that there is overwhelming evidence, including

recent new data, that Hg emissions from U.S. powerplants are severely impacting inland and

coastal waters, leading to massive environmental damage and the need for fish consumption

advisories. The commenters stated that Hg emissions from U.S. powerplants are also

contributing to adverse effects on human health. The commenters stated that the relationship

between Hg emissions from coal-fired plants and the elevated levels of Hg in fish is not in dispute. 

The commenters added that there is sound scientific basis for requiring stringent controls for Hg

emissions based on EPA’s own statements. Further, the commenters stated that uncertainties that

may exist point to the need for, not the weakening of, safeguards to reduce the public’s exposure

to Hg. The commenters stated that in light of EPA’s own findings that power plants are the
7-v

largest emitters of Hg, the overwhelming evidence that 8 percent of women of childbearing age

have elevated Hg levels, that over 600,000 babies are born overexposed to Hg in utero with

potential neurological deficits, and the fact that fish consumption advisories nationwide are on the

rise, EPA regulatory response should be to establish an appropriate plant by plant MACT

standard under section 112 to achieve meaningful reductions of Hg emitted to the atmosphere.

Response:

Through this rulemaking and the separate CAIR rule, EPA is taking steps to lower the Hg

emissions from utilities. As explained in the preamble to the final rule, EPA believes that the

steps taken in these packages will provide a substantial positive step in reducing the health

effects which may result from the release of Hg from these utilities.

As part of its analysis of the final rule, EPA has estimated the health benefits of reducing

Hg from utilities. EPA’s analysis focuses on the benefits of reducing neurological impacts of

exposure to MeHg via consumption of self-caught freshwater fish. The RIA for this rule contains

this analysis in Chapter 11.

Comment:

One commenter (OAR-2002-0056-3499) stated that EPA has underestimated and

distorted the health effects caused by Hg from power plants. The commenter stated that the brief

discussion of the potential cardiovascular effects of methylmercury (MeHg) concludes that the

existing studies present conflicting results. The commenter asserted that this statement is not

documented and is largely not the case. The commenter also noted that EPA identifies those at

risk from MeHg as those who regularly and frequently consume large amounts of fish. The

commenter asserted that this is not necessarily the case and misleading. The commenter stated

that even moderate consumption of fish with high Hg concentrations can lead to significantly

elevated Hg levels and health risk.

Response:

The science of documenting and estimating the health effects of exposure to low levels of

Hg is evolving. EPA is aware that a study on potential cardiovascular effects has been recently

entered into the docket to this rulemaking (February 22, 2005). EPA was not able to evaluate

the results of this study in the determination for the final rule. EPA is aware of this effect and

other effects of low level Hg exposures. Our RIA for this rulemaking lays out our understanding

of the current state of the science and provides quantified or qualitative estimates of the effects

of reducing Hg emissions from utilities.

7.3 ENVIRONMENTAL IMPACTS

Comment:

One commenter (OAR-2002-0056-2430) recommended that if EPA pursues regulation
7-vi

under section 111, it include some type of risk and environmental health assessment including an

evaluation of the effects of Hg deposition. The commenter stated that although residual risk

requirements under section 112 address risk to public health and the environment, section 111

does not. The commenter stated that the disassociation of CAA regulations from public health

and the environment is unacceptable public policy and sets a bad precedent.

Response:

EPA has addressed the implications of the rule as suggested by the commenter.

7.4 COSTS AND ECONOMICS

Comment:

One commenter (OAR-2002-0056-3528) stated that most, if not all, small businesses will

be impacted by a regulatory structure that imposes new requirements on Electric Utility Steam

Generating Units (power plants). The commenter noted that small business owners need

electricity to run their businesses, and it is certain that if and when a new regulatory scheme is

implemented, the costs associated with it will be passed on to small firms in the form of higher

electricity prices. The commenter stated that Dr. Willie Soon, a physicist at the Solar, Stellar, and

Planetary Sciences Division of the Harvard-Smithsonian Center for Astrophysics and an

astronomer at the Mount Wilson Observatory, has noted that “industrial demands for mercury

(and hence emissions) in the U.S. have been systematically and rapidly decreasing over time

through common sense public policy controls on Hg content in less essential products like paints,

pesticides and batteries. From a regulatory-efficiency standpoint, the relatively clean U.S. power

plants are not the best target for addressing the global mercurial emission problem. Why? We

lack the technological know-how to eliminate Hg emissions... As such, the proposed regulations

are likely to drive up energy costs significantly. Since the poor and middle class pay a greater

percentage of their income on basic energy needs, the heaviest burden of such regulations will fall

on those least able to afford them.” The commenter submitted that indeed, an April 2003 report

from the U.S. Department of Energy (DOE) declared that “technology to cost-effectively reduce

mercury emissions from coal-fired plants is not yet commercially available.” The commenter

stated that one estimate placed the annual price tag of reducing Hg emissions from U.S. power

plants at $3 billion. The commenter stated that the electric power industry provides a vital service

to our nation and is a key driver of local and national economies. The commenter believed that

while EPA might contend that, on average, the costs of the rule will be “low”, even a seemingly

small 5 to 10 percent increase in electricity costs will impact small businesses, low-income families

and retiree households. The commenter believed that in the end, while it is highly unlikely that the

EPA will abandon the proposed Hg emissions regulation, the Agency must present clear scientific

justification for moving forward – that regulating will create net significant human health benefits,

especially if promulgated under the Clean Air Act. The commenter submitted that if the EPA

moves forward, it cannot require too much too soon as would be the case under a maximum

achievable control technology (MACT) requirement. The commenter noted that the 29 percent

reduction target for 2007 is not scientifically feasible as noted above. The commenter believed

that if reductions are pushed too quickly, this would endanger the use of cost-effective coal as a
7-vii

fuel and would put more pressure on already strained natural gas markets. The commenter stated

that a variety of fuels is needed so that there is no run up in prices, such as has occurred recently

for natural gas. The commenter noted that natural gas prices are very important for all

consumers, including families, farmers, manufacturers and, of course, small businesses. If

controls are required, and presented with the limited options under the proposed rule, the

commenter viewed the cap-and-trade program as less restrictive and more cost-efficient than

MACT. The commenter stated industry will not be forced to utilize expensive alternatives to

coal, the nation’s most abundant, affordable fuel source. The commenter noted that the cost

increases for small businesses will not be as high (though any cost increase is burdensome to price

sensitive small firms). Similar to the acid rain program, the commenter believed EPA should

manage the new program by laying out the rules of the road but not dictate the path to the

destination.

Response:

EPA is finalizing a cap-and-trade program for Hg emissions. One of the advantages of a

cap-and-trade approach is that the ability for emissions reductions to be achieved more

efficiently than a command and control approach. EPA projects that today’s rule will have an

impact on retail electricity prices of less than 1 percent. This analysis is discussed in Chapter 7

of the RIA. It should also be noted that EPA’s modeling does not take into account

advancements in pollution control technology and the cost reductions associated with these, such

that EPA is likely overestimating the impacts of the final rule.

Comment:

One commenter (OAR-2002-0056-3556) stated that the costs of implementing this

program are significant. The commenter supported the comments on implementation and

compliance being supplied by UARG. The commenter stated that EPA’s estimates are too low. 

The commenter stated that they are currently spending in excess of seven hundred million dollars

to implement the NOx SIP Call. The commenter stated that this number is more than a factor of 3

higher than their original estimate – which was higher than EPA’s estimate. The commenter

stated that the NOx SIP call dealt with retrofitting existing units with known technologies. The

commenter expected the costs of implementing the Hg rule to be higher, once the

to-be-determined Hg-specific controls are included in the system. The commenter stated that

many utilities, including the commenter, are facing the reality of obtaining adequate financing to

cover the costs of implementation. The commenter stated that this is further complicated by the

need to clearly layout a cost-recovery mechanism, within the current regulatory system in

Michigan. The commenter strongly recommended that EPA use a more accurate methodology

for projecting the costs of MACT, including characterizing each individual unit in the database,

using site-specific conditions to determine which technology is the least cost option.

Response:

EPA is finalizing a cap-and-trade program for Hg under section 111 of the CAA, rather

than a Hg MACT. This system allows for a variety of control technologies and provides
7-viii

incentives for achieving least-cost reductions. The projected impacts of the final CAMR are

discussed in Section 7 of the RIA. 

 Comment:

One commenter (OAR-2002-0056-4191) stated that EPA must ensure that the Hg rule

does not disadvantage coal, especially Gulf Coast lignite, because doing so would aggravate the

already precarious natural gas supply and price situation. The commenter submitted that high

natural gas prices are a significant economic challenge to business and industry, especially small

businesses. The commenter added that high natural gas prices are undermining U.S. economic

recovery, pushing jobs offshore in gas-dependent industries, and are increasing the cost of

electricity in several regions of the U.S. The commenter pointed out that during the late 1990's,

the historic surplus of natural gas disappeared due to a growing economy, governmental access

restrictions to large gas deposits onshore and offshore, and clean air regulations that encouraged

electric generators to use natural gas instead of coal. The commenter stated that by 2000, spot

market prices soared and the average annual price for gas more than doubled. The commenter

added that the industrial sector, unable to pass through costs to consumers, was hit hard. The

commenter noted that U.S. natural gas production is not keeping pace with the demands of a

growing population and a slowly recovering economy. The commenter believed that this crisis,

brought on partly by national policies encouraging the use of natural gas while discouraging its

domestic production, makes clear the need for the U.S. to maintain a diverse fuel supply and

provide adequate domestic production of energy. The commenter submitted that if the Hg rule

was to even slightly decrease the dependence on coal as a viable fuel for electric generation, the

natural gas supply and the price problems would increase. The commenter stated that it is

estimated that forced replacement of coal with natural gas as fuel in electric generation would

increase the demand for natural gas by about 35 percent and would increase natural gas prices by

about 33 percent. The commenter stated that EGUs designed to burn lignite cannot easily,

quickly, or cheaply switch to burn other fuel types. The commenter noted that lignite’s low heat

content and its other properties call for a specific boiler design. The commenter claimed that, as

such, lignite-fired EGUs would require significant alterations to allow them to burn non-lignite

fuels. The commenter added that in addition to being time consuming, such alterations would be

very expensive. The commenter stated further that companies that own and operate lignite-fired

EGUs are often parties to long-term contracts to purchase the lignite. The commenter noted that,

therefore, even if such EGUs could no longer burn lignite, they would still be required to purchase

it pursuant to any such long-term contracts. The commenter added that moreover, Gulf Coast

lignite-fired EGUs in Texas are “mine-mouth” plants, which means they are located on the

property from which the lignite is mined. The commenter stated that therefore, for many such

EGUs, rail lines to the EGUs that could be used to transport other types of fuel to the site would

have to be constructed. The commenter asserted that for the foregoing reasons, the final rule

must take into account the need to avoid any undue switching from coal, especially Gulf Coast

lignite, to another type of coal or natural gas as fuel in electric generation.

Response:

The impacts of CAMR on coal production are discussed in Chapter 7 of the RIA. Coal-
7-ix

fired generation and natural gas-fired generation are projected to remain relatively unchanged

because of the phased-in nature of CAMR, which allows industry the appropriate amount of time

to install the necessary pollution controls. Additionally, no coal capacity is projected to be

uneconomic to maintain under CAMR relative to the CAIR. 

Comment:

Several commenters (OAR-2002-0056-2609, -2684, -3380) in Colorado believed the rule

will have a negative economic impact on Aspen because continuation of high Hg emissions from

coal-fired plants subsidizes coal which contributes to global warming and prevents a level playing

field for developers of renewable energy sources.

Response:

Under this rulemaking, EPA is placing Hg emission reduction requirements on coal-fired

electricity generating units that will require investment by the industry, and, thus, is not

providing a subsidy to coal-fired generation.

Comment:

One commenter (OAR-2002-0056-2887) recommended that the capital costs and cost

effectiveness of Hg controls be expressed in terms of costs to the ratepayer (e.g., mills/kWh of

electricity). The commenter believed from this perspective, the costs are lower than those for

NOx control from electric utilities (which are considered to be cost effective by industry and state

regulators and the basis for the “Section 110 transport SIP call” and the Clean Air Interstate Rule

proposed concurrently with the MACT standard). According to the commenter, the total annual

costs for Hg controls ranges from 0.18 to 1.15 mills/kWh compared to 0.21 to 0.83 for low-NOx

burners and 1.85 to 3.62 mills/kWh for selective catalytic reduction. The commenter contended

that EPA’s presentation of cost effectiveness in terms of dollars per pound of Hg removed by a

control technology compared to the costs of controlling NOx or SO2 emissions from power plants

is misleading because Hg is emitted in far small quantities than conventional pollutants. The

commenter added that, however, Hg presents a far greater public health and environmental threat

on an equivalent mass basis.

Response:

EPA discusses the projected impact of CAMR on retail electricity prices in Chapter 7 of

the RIA. EPA believes that cost-effectiveness measures (e.g., $/ton) are useful tools to evaluate

and compare marginal costs of various programs. EPA agrees that cost-effectiveness measures

for different pollutants may not be meaningfully compared with each other. The benefits and

costs of CAMR are discussed in detail in the RIA.

Comment:

One commenter (OAR-2002-0056-4177) believed EPA’s economic analysis is inadequate
7-x

and flawed. The commenter asserted that EPA used the wrong economic benchmark. The

commenter stated that the economic cost of Hg control should not be assessed the same way as

criteria pollutants because Hg creates public health problems at lower levels. The commenter

stated that EPA should evaluate the costs in terms of the additional cost of electrical production

rather than in cost/ton of pollutant removed. The commenter stated that using the other

approach, the best Hg controls cost 0.18 to 1.15 mils/kWh. The commenter stated that given the

added costs of litigation, health care, and special education for affected children, EPA would

determine that a legally reasonable standard is economical.

Response:

EPA does evaluate the cost of Hg control in terms of the additional cost of electrical

production. This analysis is presented in Chapter 7 of the RIA. 

Comment:

One commenter (OAR-2002-0056-2819) did preliminary cost estimates for installing FGD

or ACI on their coal-fired boilers using EPA methodology and compared their estimates to those

from Public Service of New Hampshire, ADA-ES, and DOE. The commenter reported that the

results are similar to NESCAUM estimates (see Mercury Emissions from Coal-Fired Power

Plants: The Case for Regulatory Action, October 2003). The commenter reported that estimated

capital costs for FGD range from $54.2-$100.4 million and for ACI range from $0.98 to $47.3

million depending on size and other factors. The commenter stated that while these costs may not

be applicable to all units nationwide, they are sufficient to justify standards at least as stringent as

those for New Jersey and Massachusetts. The commenter added that allowing emissions

averaging can further reduce the costs.

Response:

See the preamble for EPA’s discussion of Hg control technology, and IPM

documentation (available in the docket) for EPA’s assumptions regarding the capital costs of

FGD and ACI. 

Comment:

One commenter (OAR-2002-0056-3449) believed the current costs of ACI are reasonable. 

The commenter noted that DOE has a goal of reducing it to 1/4 of current costs. The commenter

added that ACI also has low capital costs, which would allow for replacement if other technology

is shown to have lower operational costs. In support, the commenter cited the U.S. DOE Report

on Preliminary Cost Estimate of Activated Carbon Injection for Controlling Mercury Emissions

from an Unscrubbed 500 MW Coal-Fired Power Plant.

Response:

See the preamble, and EPA’s Office of Research and Development’s white paper on Hg
7-xi

control technology for the Agency’s position on the costs and availability on Hg control

technologies.

Comment:

One commenter (OAR-2002-0056-2182) stated that some political leaders in Ohio argue

that stricter environmental rules will cost jobs, but Ohio now has the dirtiest air in the nation. The

commenter added that at the same time, Hg pollution has cost their fisheries millions and

compromised public health. The commenter stated that the total health related and lost

productivity costs have not been calculated. The commenter stated that Ohio can have both

cleaner air and a strong economy - the key is to support pollution control vendors as a promising

new industry.

Response:

EPA believes that the rule being finalized is the best approach to both remove Hg from

the air and water and promote Hg-specific control technologies for use in the U.S. and around

the world.

Comment:

One commenter (OAR-2002-0056-0916) stated that proposals make excessively costly

restrictions on utilities.

Response:

EPA’s chosen cap-and-trade approach to reducing Hg emissions will limit the cost

impact on utilities relative to a command and control approach. The economic impacts of CAMR

are discussed in Chapter 7 of the RIA. Several aspects of CAMR are designed to minimize the

impact on energy production. First, EPA recommends a trading program rather than the use of

command-and-control regulations. Second, compliance deadlines are set cognizant of the

impact that those deadlines have on electricity production. Both of these aspects of CAMR

reduce the impact of the proposal on the electricity sector.

Comment:

One commenter (OAR-2002-0056-1352) stated that the proposals will be harmful to the

economy for lack of positive effect on the environment and disruption of energy supplies.

Response:

The benefits and costs of CAMR are discussed in the RIA. It should be noted that

according to EO 13211: Actions that Significantly Affect Energy Supply, Distribution, or Use,

this rule is not significant, measured incrementally to CAIR, because it does not have a greater

than 1 percent impact on the cost of electricity production and it does not result in the retirement
7-xii

of greater than 500 MW of coal-fired generation.

Several aspects of CAMR are designed to minimize the impact on energy production. 

First, EPA recommends a trading program rather than the use of command-and-control

regulations. Second, compliance deadlines are set cognizant of the impact that those deadlines

have on electricity production. Both of these aspects of CAMR reduce the impact of the

proposal on the electricity sector.

Comment:

One commenter (OAR-2002-0056-1573) stated that in setting its reductions targets and

compliance deadlines, EPA should fully consider the complexities of this new regulatory program

and the costs of compliance. The commenter stated that the power generation industry finds itself

facing the biggest round of emission reductions in its history. The commenter pointed out that the

power generation industry also faces substantial uncertainty because power plant Hg controls

have yet to be commercially demonstrated. The commenter was keenly aware that some view

compliance cost estimates on the part of industry as little more than “crying wolf” whenever a

new regulatory requirement is imposed. However, the commenter noted their experience in

implementing controls under the NOx SIP Call. The commenter stated that EPA originally

projected that two-thirds of the controls installed for NOx SIP Call compliance would consist of

Selective Non-Catalytic Reduction (SNCR) controls, with the remaining one-third mostly

consisting of Selective Catalytic Reduction (SCR) controls. The commenter also stated that EPA

also estimated SCR capital costs as about $60/kW. Now that companies have installed most of

their NOx controls, the commenter stated that EPA substantially underestimated compliance

costs. The commenter stated that across the industry, the vast majority of the NOx SIP Call

controls have been SCR, with few installations of SNCR. The commenter opted to install nine

SCRs with no SNCR at all. Contrary to EPA’s estimated compliance costs of $60/kW, the

commenter’s actual installed SCR costs were more than double that figure. The commenter

urged EPA to carefully assess the lessons learned from the regulatory initiatives of the recent past.

Response:

EPA is addressing uncertainty in the cost of Hg emissions control under CAMR by

having a first phase cap that is equal to the projected co-benefit Hg reductions under CAIR in

2010, and thus does not require the installation of Hg specific control. Additionally, the second

phase cap of 15 tons is also set with consideration for cost uncertainty faced by the industry. 

EPA believes that the use of a Hg cap-and-trade program will lead to the development of more

efficient and cost effective Hg control technology options through the market incentives provided

by the cap-and-trade mechanism.

Comment:

One commenter (OAR-2002-0056-2067) stated that in addition to the limitations with

existing control technology, structural barriers also exist in terms of monitoring equipment. The

commenter stated that to adequately demonstrate removal of Hg, monitoring equipment, such as
7-xiii

continuous emissions monitoring systems or sorbent trap monitoring technology, must also be

installed. According to the commenter, the cost of monitoring equipment, as well as the cost of

its operation and maintenance, is significant, and no monitoring technology has emerged that is

both cost effective and accurate. The commenter asserted that compliance standards must

recognize the limited development of such monitoring technology as well.

Response:

The final rule contains flexibility by allowing sources to account for their Hg emissions

by using Hg CEMS, sorbent trap monitoring systems (or a combination thereof), and, in some

cases, using low mass provisions. EPA disagrees with the commenter and believes that field

tests have demonstrated Hg CEMS to be cost effective, accurate, and reliable. The Hg CEMS

have performed adequately for several months and meet the Ontario-Hydro Reference Method

specifications. Furthermore, several dry chemistry Hg CEMS are currently being tested at sites

that represent the most challenging conditions and the Agency plans to share with industry the

results of such experiences to facilitate the selection of appropriate monitoring methodology. 

EPA is also confident that substantial advancement of Hg CEMS will occur before the

implementation of the rule and as other monitoring techniques may become available, is

allowing the use of systems that can meet performance-based specifications. The performancebased approach allows for use of various suitable sampling and analytical technologies while

maintaining a specified and documented level of data quality.

Comment:

Several commenters (OAR-2002-0056-1269, -2065, -2074, -2082) asked how much will

plants increase rates as a result of the proposals.

Response:

The impact of CAMR on retail electricity prices relative to CAIR is projected to be less

than 1 percent. This is discussed in more detail in Chapter 7 of the RIA.

Comment:

One commenter (OAR-2002-0056-2160) was concerned about the potential economic

impacts of losing their bituminous coal market. The commenter asserted that to meet stringent

and possibly unattainable limits, plants that burn bituminous coal mined in Illinois will switch to

subbituminous coal because of the cost, less stringent limit, or unavailability of control equipment. 

The commenter stated that fuel switching would have a devastating economic effect on their coal

industry (the Illinois coal market will fail), associated industries, and their tax base. The

commenter asserted that fuel neutral rules would avoid this effect.

Response:

The reductions in emissions from the power sector under CAIR and CAMR will be met
7-xiv

through the installation of pollution controls for Hg, SO2, and NOx removal. The pollution

controls can achieve up to a 95 percent SO2 removal rate, which allows industry to rely more

heavily on local bituminous coal in the eastern and central parts of the country that has a higher

sulfur content and is less expensive to transport than western subbituminous coal.

Comment:

One commenter (OAR-2002-0056-2160) stated that there is an increased risk on capital

investment because of the uncertainty in the availability of control technology. The commenter

stated that obtaining financial backing for purchasing equipment will require larger outlays from

power companies (lending institutions avoid risk). The commenter believed these increased costs

will be passed on to consumers, thus harming the State’s ability to provide inexpensive electric

power-an economic asset. The commenter stated that the proposed rules should be reviewed to

determine the availability of technologies which have minimal risk in attaining the necessary

emissions performance.

Response:

EPA’s Office of Research and Development has produced a white paper (available in the

docket) that assess the current state of Hg emissions control technology. EPA has set the first

phase cap at a level that represents projected co-benefit Hg emission reductions that will occur

under CAIR as of 2010, and the 15 ton cap in 2018 allows sources adequate time for the

installation of the necessary pollution controls.

Several aspects of CAMR are designed to minimize the impact on energy production. 

First, EPA recommends a trading program rather than the use of command-and-control

regulations. Second, compliance deadlines are set cognizant of the impact that those deadlines

have on electricity production. Both of these aspects of CAMR reduce the impact of the

proposal on the electricity sector.

Comment:

One commenter (OAR-2002-0056-1969) stated that monitoring costs for small units will

be disproportionate to the costs of compliance with the MACT emissions limit. The commenter

supported lower frequencies and lower cost monitoring requirements for those units that emit

under 25 pounds per year.

Response:

The Agency has decided to use a cap-and-trade program to control Hg emissions. 

Complete and accurate accounting of Hg emissions is required for a credible cap and trade

program. Therefore, Hg CEMS or sorbent traps are required in the final rule. However,

qualifying, low emitting sources may comply with today’s monitoring requirements by using

conservative default Hg emission factors and annual or semi-annual stack testing.
7-xv

Comment:

One commenter (OAR-2002-0056-2075) stated that if the proposed regulations result in

the closure of coal-fired generation plants, there would be significant fallout for the state,

regional, and local economies. The commenter stated that excessive regulation decreases the

capacity of U.S. companies to compete in global markets. The commenter also stated that when

the costs of compliance with environmental regulations rise, U.S. firms are less able to perform

optimally. The commenter further stated that the entire economy suffers. The commenter stated

that for Texas, coal mining results in an addition to business activity of:

$2.438 billion in annual Total Expenditures; 

$0.957 billion in annual Gross Product;

$0.713 billion in annual Personal Income;

$0.258 billion in annual Retail Sales; and 

12,684 Permanent Jobs.

The commenter stated that East Texas is where the majority of Texas’ coal mines are

concentrated. The commenter further stated that the economic impact of coal mining on the

regional economy is:

$1.356 billion in annual Total Expenditures; 

$0.526 billion in annual Gross Product;

$0.405 billion in annual Personal Income; 

$0.154 billion in annual Retail Sales; and 

7,210 Permanent Jobs.

The commenter stated that the total economic impact of coal mining and coal-fired electric

generating plants is estimated to be:

$10.498 billion in annual Total Expenditures; 

$3.516 billion in annual Gross Product;

$2.081 billion in annual Personal Income; 

$0.584 billion in annual Retail Sales; and 

33,197 Permanent Jobs.

Response:

The economic impact of CAMR is discussed in Chapter 7 of the RIA. It should be noted

that according to EO 13211: Actions that Significantly Affect Energy Supply, Distribution, or

Use, this rule is not significant, measured incrementally to CAIR, because it does not have a

greater than a 1 percent impact on the cost of electricity production and it does not result in the

retirement of greater than 500 MW of coal-fired generation.

Several aspects of CAMR are designed to minimize the impact on energy production. 

First, EPA recommends a trading program rather than the use of command-and-control
7-xvi

regulations. Second, compliance deadlines are set cognizant of the impact that those deadlines

have on electricity production. Both of these aspects of CAMR reduce the impact of the

proposal on the electricity sector.

Comment:

One commenter (OAR-2002-0056-2578) performed an analysis that compared the Hg

cap-and-trade provisions of the Clear Skies Act (CSA) of 2003 to a generic MACT standard of

2.2 lb/trillion Btu for all generating units. The commenter stated that these two policies are

reasonably similar to the two alternative Hg rules proposed by EPA. The commenter’s

cost-effectiveness analysis found that the CSA cap and trade alternative would cost less than an

illustrative MACT rule on a present-value basis by about a factor of 3, yet it would produce

slightly larger deposition changes and MeHg exposure reductions by 2020. The commenter

pointed out that in either case, however, the effectiveness of the policies in reducing deposition of

Hg in the U.S. appeared small. The commenter analyzed EPA’s December 2003 rule proposals

using the same analysis framework as before (but with greater detail and updated modeling

assumptions) and found a similar comparison. According to the commenter, the relative

cost-effectiveness of the proposed cap and trade rule compared to the proposed MACT rule

appears to be even greater than was estimated for the two alternatives studied in the earlier

analysis. The commenter stated that the primary apparent difference between the proposed

MACT rule and the cap and trade rule is that MACT provides earlier reductions than the

proposed cap and trade policy. However, this earlier implementation, according to the

commenter, leads to a small percentage change in deposition (and hence in exposure) but at an

additional $8 billion (present value) in costs.

Response:

EPA is finalizing a cap-and-trade program for Hg under section 111 of the CAA. EPA

believes there are a number of advantages to this approach relative to a MACT approach. First,

the cap-and-trade program will set a fixed limit on the total number of allowable Hg emissions,

which cannot be exceeded even when existing plants are expanded and new plants are

constructed. Second, a trading program provides a market incentive for sources to reduce

emissions beyond the required level, because of the ability to bank allowances, or sell

allowances on the market. This incentive acts to stimulate innovations in control technology that

might not occur under a command and control approach such as MACT, and will also lead to

cheaper emissions reductions overall.

Comment:

One commenter (OAR-2002-0056-2634) stated that the cost of compliance should be

proportionate to the intended environmental benefit. The commenter noted that the purpose of

controlling Hg emissions from power plants is to address potential adverse impacts that exposure

to Hg can have on human health and the environment. The commenter pointed out that, more

specifically, EPA states in the preamble to the notice of proposed rulemaking (NPR) that the

focus of this rulemaking relates to “oral exposure of MeHg as it is the route of primary interest
7-xvii

for human exposures” [69 FR 4658]. The commenter pointed out that EPA further states that

MeHg “is typically formed by biological processes after mercury has precipitated from the air and

deposited into water bodies” [69 FR 4657]. The commenter stated that, therefore, when

weighing the cost of compliance against the environmental benefit, it is imperative that EPA

consider the impact of the proposal in terms of reductions in Hg deposition (and ultimate human

exposure) versus reductions in emissions. The commenter pointed out that over 70 percent of Hg

deposition in the U.S. comes from sources outside of the U.S., and in much of the western U.S.,

between 80 percent and 100 percent of the deposition originates outside of the U.S. [“New

Findings on Mercury Dynamics,” EPRI et al., presented at the 7th Electric Utilities Environmental

Conference, Tucson, AZ, January 21, 2004]. The commenter stated that modeling performed by

EPRI indicates that a reduction of Hg emissions from coal-fired power plants to 15 tpy (an

approximate 70 percent reduction from 1999 levels) would result in only a 6.9 percent reduction

in deposition. The commenter stated that it has not been determined whether this level of

reduction in deposition will effectively reduce the levels of MeHg in the environment, which is the

stated focus of the proposed rule. The commenter stated that the level of Hg reductions and the

means to achieve those reductions must be “cost effective” in terms of the ultimate reduction in

exposure to MeHg.

Response:

Executive Order 12866 requires EPA to estimate and compare the costs and benefits for

major regulatory actions. It does not require that the monetizable benefits exceed the

monetizable costs. However, in the design of this rulemaking, EPA has carefully weighed the

costs of controlling Hg from utilities, the benefits resulting from these reductions and other

factors (e.g. the desire to provide global leadership in reducing Hg emissions). As detailed in

the preamble to this rulemaking and the regulatory support documents, EPA has selected a

regulatory approach which balances all these factors.

Comment:

One commenter (OAR-2002-0056-2721) strongly disagreed with EPA’s estimated annual

monitoring, reporting and recordkeeping costs for compliance with this regulation. The

commenter stated that EPA estimated the annual reporting costs to be $48.4 million, which

equates to approximately $85,000 per unit. The commenter claimed this number is extremely low

when taking into account the annual Hg compliance audit, which is budgeted over $30,000 for a

single annual audit alone. The commenter pointed out that the number of audits can be increased

to semi-annual or more frequent based on the actual monitor’s performance. The commenter

stated that the capital expense that EPA reported was approximately $117,000 per unit. The

commenter submitted that this value is also extremely understated. According to the commenter

there are presently no long-term Hg monitoring systems in-place at a coal-fired facility. The

commenter pointed out that the current state of monitoring is very labor intensive and involves an

extremely highly trained workforce. The commenter stated that the current monitor itself is over

$100,000 alone. The commenter further stated that this does not account for secondary systems

required to support this equipment, e.g., monitor cabinets, air supplies, electrical power supply,

electronic communication networks, data storage devices, software enhancements, etc.
7-xviii

Response:

The cost information is largely based on documents generated for the Clean Air Markets

Division, specifically the Cost Analysis of Mercury Monitoring Techniques done by Arcadis , on

November 2003, that is part of the docket. This analysis provides an overview of the cost

information gathered and analyzed to date, focusing on sources such as utility boilers that are

required to monitor Hg emissions under the proposed rule. EPA believes that sources will

probably operate the systems taking advantage of installations currently in use under other

Clean Air Act programs, such as CEMS shelters, platforms, etc and will not be the focus of

further analysis. In addition, it is estimated that no major structural modifications are needed

for access or support equipment, and that power is available in the area. Based on the

information provided by the Arcadis report, EPA estimates that the average CEMS cost will be

$80,000 and that the annual operating cost, with one RATA test done based on the Ontario

Hydro method will be also about $80,000.

EPA believes that field tests have demonstrated Hg CEMS to be accurate and reliable. 

The Hg CEMS have performed adequately for several months and meet the Ontario-Hydro

Reference Method specifications. EPA is also confident that substantial advancement of Hg

CEMS will occur before the implementation of the rule and as other monitoring techniques may

become available, is allowing the use of systems that can meet performance-based

specifications. In addition, the final rule contains flexibility by allowing sources to account for

their Hg emissions by using Hg CEMS, sorbent trap monitoring systems (or a combination

thereof), and, in some cases, using low mass provisions.

Comment:

One commenter (OAR-2002-0056-2843) expressed concern that the Hg reduction

requirements proposed by the EPA for new plants fueled with Powder River Basin (PRB) coals

will be so restrictive that they will limit the fuels that can be burned in new facilities. The

commenter’s analysis followed the forecast of available PRB fuels performed by the National

Mining Association (NMA), the Subbituminous Energy Coalition (SEC), and the Center for

Energy and Economic Development CEED); such forecasts generally suggest that the available

fuels will be less than 10 percent of the 360 million tons of coal mined annually in the PRB. The

commenter stated that if this forecast is correct, the cost of these fuels will likely be impacted so

substantially that the development of new generating resources using PRB coals might be

expected to be diminished substantially.

Response:

The impacts of CAMR on coal production and coal costs are discussed in Chapter 7 of

the RIA.

Comment:

One commenter (OAR-2002-0056-2843) believed that new coal-fired generating plants
7-xix

are vital if affordable electric energy prices are to be ensured in the future. The commenter

agreed with the DOE, Energy Information Administration, (DOE/EIA) Annual Energy Outlook

2004 forecast that projects a need for an additional 112 Gigawatts of new coal generating

capacity by 2025. The commenter believed that any new Hg emissions standard that would make

such new coal-fired generation either technically or economically infeasible will compel the U.S.

power generation industry to rely upon other fuel sources, including importation of “compliance

coal” or reversion to natural gas-fired combustion turbines as the only near- to mid-term

alternatives to provide large blocks of new electric generation capacity. The commenter stated

that consequently, imposition of such a standard would stimulate additional, significant increases

in the price of compliance coals and natural gas as well as a surge in imports associated with

increased demand for LNG. The commenter contended that such an increase in imports would

further exacerbate U.S. dependence upon off-shore energy supplies. The commenter did not

believe that this outcome has been considered in the policy debate about stringency of Hg

emissions control on U.S. coal-fired power plants. The commenter felt that such an outcome

should be unacceptable given the adverse consequences of energy inflation and further reliance

upon imported energy.

Response:

The projected economic and energy impacts of CAMR are discussed in Chapter 7 of the

RIA. It should be noted that, according to EO 13211: Actions that Significantly Affect Energy

Supply, Distribution, or Use, this rule is not significant, measured incrementally to CAIR,

because it does not have a greater than a 1 percent impact on the cost of electricity production

and it does not result in the retirement of greater than 500 MW of coal-fired generation. In fact,

CAMR is not projected to result in any additional coal retirement relative to CAIR. 

Several aspects of CAMR are designed to minimize the impact on energy production. 

First, EPA recommends a trading program rather than the use of command-and-control

regulations. Second, compliance deadlines are set cognizant of the impact that those deadlines

have on electricity production. Both of these aspects of CAMR reduce the impact of the

proposal on the electricity sector.

Comment:

One commenter (OAR-2002-0056-2843) asserted that the adverse impact of the proposed

rulemaking upon development of new coal-fired electric generation will have a direct bearing on

the financial condition of, and prospects for electric utilities and independent power producers

(IPP) alike. Specifically, the commenter stated that as a consequence of the collapse of wholesale

power markets and the malaise gripping the IPP sector for the past two years, investors and

lenders require assurance that new plants meet rigorous requirements of financial performance on

a long-term basis. The commenter pointed out that such requirements include the need to

incorporate fixed price, turnkey construction with strong technology performance guarantees,

long-term fuel contracts, long-term off-take agreements with credit-worthy entities, and the ability

to achieve compliance with current (as well as contemplated) environmental requirements.
7-xx

Response:

The projected economic and energy impacts of CAMR are discussed in Chapter 7 of the

RIA. It should be noted that, according to EO 13211: Actions that Significantly Affect Energy

Supply, Distribution, or Use, this rule is not significant, measured incrementally to CAIR,

because it does not have a greater than a 1 percent impact on the cost of electricity production

and it does not result in the retirement of greater than 500 MW of coal-fired generation. In fact,

CAMR is not projected to result in any additional coal retirement relative to CAIR.

Several aspects of CAMR are designed to minimize the impact on energy production. 

First, EPA recommends a trading program rather than the use of command-and-control

regulations. Second, compliance deadlines are set cognizant of the impact that those deadlines

have on electricity production. Both of these aspects of CAMR reduce the impact of the

proposal on the electricity sector.

35 Comment:

One commenter (OAR-2002-0056-3327) claimed that without changes requested by the

commenter, the utility Hg reductions rule (UMRR) will eliminate Gulf Coast Lignite from the

marketplace. The commenter submitted that if Texas loses Gulf Coast Lignite, it will lose more

than $17 billion annually in direct and indirect benefits, including 8,000 direct jobs and more than

100,000 indirect jobs. The commenter added that some rural communities will lose more than 50

percent of their tax revenues. The commenter also stated that without Gulf Coast Lignite, it will

become nearly impossible to develop a balanced energy policy or ensure the reliability and

affordability of electric power in Texas.

Response:

The impacts of CAMR on coal production are discussed in Chapter 7 of the CAMR RIA. 

EPA is not projecting the shutdown of any coal capacity relative to CAIR.

Comment:

One commenter (OAR-2002-0056-3403) requested that the EPA ensure that any future

Hg reductions requirements be achieved in an efficient and cost effective manner. The commenter

stated that as a not-for-profit, they will be forced to pass along the costs of meeting new Hg

emissions reduction requirements to their consumer-owners.

Response:

EPA is finalizing a cap-and-trade program for Hg under section 111 of the CAA, which

will provide for efficient and cost-effective Hg emissions reductions relative to a command and

control approach.
RESPONSE TO SIGNIFICANT PUBLIC COMMENTS ON

THE PROPOSED CLEAN AIR MERCURY RULE

Received in response to:

Proposed National Emission Standards for Hazardous Air Pollutants; and, in

the Alternative, Proposed Standards of Performance for New and Existing

Stationary Sources: Electric Utility Steam Generating Units

(69 FR 4652; January 30, 2004)

Supplemental Notice for the Proposed National Emission Standards for

Hazardous Air Pollutants; and, in the Alternative, Proposed Standards of

Performance for New and Existing Stationary Sources: Electric Utility Steam

Generating Units

(69 FR 12398; March 16, 2004)

Proposed National Emission Standards for Hazardous Air Pollutants; and, in

the Alternative, Proposed Standards of Performance for New and Existing

Stationary Sources, Electric Utility Steam Generating Units: Notice of Data

Availability

(69 FR 69864; December 1, 2004)

Docket Number OAR-2002-0056

8.0 COMPLIANCE WITH EXECUTIVE ORDERS AND STATUTES

US Environmental Protection Agency 

Emissions Standards Division

Office of Air Quality Planning and Standards

Research Triangle Park, North Carolina 27711

15 March 2005
i

General Outline

1.0 INTRODUCTION AND BACKGROUND

2.0 APPLICABILITY AND SUBCATEGORIZATION

3.0 PERFORMANCE STANDARDS FOR COAL-FIRED ELECTRIC

UTILITY STEAM GENERATING UNITS

4.0 PERFORMANCE STANDARDS FOR OIL-FIRED ELECTRIC

UTILITY STEAM GENERATING UNITS

5.0 MERCURY CAP-AND-TRADE PROGRAM

6.0 MERCURY EMISSIONS MONITORING

7.0 IMPACT ESTIMATES

8.0 COMPLIANCE WITH EXECUTIVE ORDERS AND STATUTES

9.0 NODA

10.0 OTHER

Appendix A LIST OF COMMENTERS
8-i

8.0 COMPLIANCE WITH EXECUTIVE ORDERS AND STATUTES

8.1 REGULATORY IMPACT ANALYSIS (EO 12866, ANALYSIS OF

ALTERNATIVES, BENEFITS, HEALTH COSTS)

Comment:

One commenter (OAR-2002-0056-4910) stated that EPA failed to meet the requirements

of several executive orders. Specifically the commenters stated that EPA failed to perform a

rigorous economic analysis of the alternative regulatory options pursuant to EO 12866, which

would demonstrate that more stringent MACT standards were achievable. The commenters

claimed that tighter limits would result in insignificant increased cost compared to the proposal

while providing benefits (preventing thousands of premature deaths). Commenter OAR-2002-

0056-2836 stated that U.S. Senators and Congressmen contended EPA did not comply with EO

12866 to fully analyze the impacts of its proposal using the best scientific information available. 

The commenter stated that EPA’s first option would have been to abandon the regulatory

determination the listing decision and the settlement agreement, thus the proposal should have

contained a much more comprehensive discussion of the environmental, energy, economic, and

public health impacts of the proposed action.

Six commenters (OAR-2002-0056-1471, -1606, -1755, -1817, -1823, -2127) stated that

EPA did not fulfilled its obligations under EO 12866 because it did not assess the costs and

benefits of available regulatory alternatives. The commenters stated that a full cost-benefit

analysis was required for all available technologies, and that EPA also must analyze the benefits of

Hg emission control reductions considering such factors as premature deaths, emergency room

admissions, and asthma. The commenter stated that these analyses have been published by the

Mt. Sinai School of Medicine’s Center for Children’s Health and the Environment as well as by

the Harvard School of Public Health.

Response:

EPA has developed a more complete assessment of its regulatory approach as part of this

final rulemaking action. The Regulatory Impacts Assessment (RIA) which accompanies this

rulemaking contains an assessment of the costs and benefits of the selected approach as well as

regulatory alternatives.

Comment:

Several commenters (OAR-2002-0056 -2152, -2235, -2286, -3514, -3560) questioned

whether the benefits of the proposed regulations justify the costs. One commenter (OAR-2002-

0056-3514) supported protecting public health and was prepared to make reasonable additional

reductions in power plant Hg emissions. In fact, the commenter was actively funding and

participating in research into finding technologies that would control Hg emissions from lignite

coal, as none are currently available. The commenter also felt it was important for any costly

environmental regulations deliver identifiable health and environmental benefits. The commenter
8-ii

did not believe that EPA demonstrated that reductions of Hg emissions from U.S. power plants

would deliver the expected health benefits. The commenter noted that recent studies showed that

even very significant reductions in power plant emissions would have very little impact in local or

nationwide deposition. The commenter pointed out that in the January 30 proposed rule, EPA

stated that they “cannot currently quantify whether, and the extent to which, the adverse health

effects occur in the populations surrounding these facilities, and the contribution, if any, of the

facilities to those problems” and “the relationship between Hg emission reductions from Utility

Units and methylmercury (MeHg) concentrations in fish cannot be calculated in a quantitative

manner with confidence.”

The second commenter (OAR-2002-0056-3560) pointed out that the current proposed Hg

rules failed to adequately consider the cost and benefits associated with the MACT or cap and

trade approach to Hg emissions. The commenter noted that EPA cites its own study that

apparently “supports a plausible link between anthropogenic releases of mercury from industrial

and combustion sources in the U.S. and methylmercury in fish” [69 Fed. Reg. 4652, 4658

(proposed January 30, 2004)]. The commenter further noted that EPA admitted as follows that

such a purported link is untenable: “Given the current scientific understanding of the

environmental fate and transport of [methylmercury], it is not possible to quantify how much of

the MeHg in fish consumed by the U.S. population is contributed by U.S. emissions relative to

other sources of Hg (such as natural sources and re-emissions from the global pool). As a result,

the relationship between Hg emission reductions from Utility Units and MeHg concentrations in

fish cannot be calculated in a quantitative manner with confidence. In addition, there is

uncertainty regarding over what time period these changes would occur.”

The commenter added that EPA found that nine of the top ten fish/shellfish consumed by

U.S. residents came from saltwater. [See Jon M. Heuss, An Examination of the Claims that

Utility Mercury Emissions are Poisoning US. Children and Creating Toxic Hot Spots, The

Annapolis Center for Science-Based Public Policy, at 5.] The commenter submitted thus,

reducing power plant Hg emissions may not have any significant impact on the primary exposure

route, which is human consumption of ocean fish. The commenter added that, in fact, EPA has

readily acknowledged that U.S. utilities are estimated to account only for roughly 1 percent of the

total global emissions of Hg. [See id., at 3.] The commenter, therefore, believed that the exact

extent and nature of the health benefits to be derived from reducing Hg emissions at power plants

was, at best, unclear. In all probability, the reduction of Hg emissions obtained by these

regulations (even eliminating all power plant emissions) would be unlikely to yield a measurable

reduction in Hg levels in the primary exposure pathway. The commenter concluded that in light

of the uncertain health benefits to be gained from reduction of Hg from power plants, it appeared

that the proposed Hg regulations should focus more carefully on the costs and benefits of

reducing Hg emissions.

Three commenters (OAR-2002-0056-2152, -2235, -2286) noted that EPA did not

develop a cost-benefit analysis and recommended that EPA delay the rules until there is proven

technology. Two commenters (OAR-2002-0056-0699, -4328) urged EPA to find a compromise

between the environment and economics and to temper the cost of the rule according to the costs

to industry (employers) and to consumers.
8-iii

Response:

EPA has developed a more complete assessment of its regulatory approach as part of this

final rulemaking action. The RIA which accompanies this rulemaking contains an assessment of

the costs and benefits of the selected approach as well as regulatory alternatives.

As part of its analysis of the final rule, EPA has estimated that some of the health

benefits of reducing Hg from utilities. At this time EPA is only able to provide quantitative

estimates of the benefits of reducing IQ decrements associated with exposure to MeHg for a

portion of the U.S. population, women of child-bearing age. The RIA for this rule contains this

analysis in Chapters 10 and 11 .

Comment:

One commenter (OAR-2002-0056-2578) provided results of an analysis concluding that

the Hg emissions reduction proposed by EPA would result in slightly lower exposure to Hg by

U.S. women of childbearing age and that the improvements to public health would vary by

location across the U.S. According to the commenter, the analysis indicated, that in comparison

to 1999 levels, the average exposure would decrease by about 1.46 percent across the U.S. under

the Cap & Trade scenario while under the MACT or CAIR scenarios, the average exposure

would be reduced by about 0.9 percent. The commenter’s comparison of relative changes in

exposure under the two 2020 scenarios, relative to 1999, concluded that, with respect to the

deposition case under CAIR, Cap & Trade was, in every case, more protective than MACT (that

is, for every state for which data are available, there is a greater decrease in exposure under C&T

than under MACT).

Response:

Through this rulemaking and the separate CAIR rule, EPA is limiting Hg emissions from

utilities. As explained in the preamble to the final rule, EPA believes that these rules will

provide a substantial positive step in reducing the health effects which may result from the

release of Hg from these utilities.

EPA has developed a more complete assessment of its regulatory approach as part of this

final rulemaking action. The RIA which accompanies this rulemaking contains an assessment of

the costs and benefits of the selected approach as well as regulatory alternatives.

Comment:

One commenter (OAR-2002-0056-3538) disputed EPA’s co-benefits analysis, stating that,

based on IAQR and Clear Skies, the analysis did not properly account for Hg. The commenter

stated that the costs and benefits of IAQR and Clear Skies, which would reduce Hg as a

co-benefit, do not include any monetized or quantified health and environmental benefits for Hg

reduction. The commenter believed that if the SO2 and NOx limits in the IAQR represent EPA’s

approach for Hg reduction, then the maximum achievable control technology for Hg must be at
8-iv

least equivalent to the “diminishing returns (knee of the cost curve)”, and likely beyond that, to

account for additional Hg benefits. The commenter stated that if the SO2 and NOx removal

technologies do represent MACT, EPA must then require the used of scrubbers to the extent they

are cost- effective for Hg and require SCR for NOx control year round.

Response:

EPA set the first phase cap of CAMR at a level that represents the co-benefit Hg

reductions that will occur as a result of installation of NOx and SO2 control technologies under

CAIR. EPA assessed the monetary benefits of Hg reductions in the first phase of the program in

the RIA. EPA has not asserted that NOx and SO2 removal technologies represent MACT. EPA’s

second phase cap of 15 tons will require the installation of Hg-specific control technology at

many sources, and will provide a continuous incentive for the development of increasingly

efficient and cost-effective control technologies for Hg.

Comment:

Several commenters (OAR-2002-0056-2380, -3353, -3413, 4139) questioned the

adequacy of EPA’s benefits estimate. Commenter OAR-2002-0056-4139 requested that EPA

provide estimates of the potential environmental benefits (i.e., reduction in fish Hg levels) and

time lines under the proposed approaches developed with EPA’s own recommended approach

(used in TMDL development) for relating the reductions in Hg deposition to associated

reductions in fish Hg levels (“A Qualitative Spatial Link Between Air Deposition and Fish Tissue,

Cocca, 2001). If it is not feasible to provide this, the commenter requested that EPA provide a

more thorough description of the limitations of the methodology and remaining data gaps which

need to be addressed. The commenter claimed that EPA’s position is that health benefits cannot

be assumed or estimated quantitatively and that a specific change in total Hg emissions cannot be

related to any specific change in MeHg concentration in fish or health improvements. The

commenter asserted that EPA used this position as the justification for not performing a

quantitative cost benefit analysis.

Two commenters (OAR-2002-0056-2380, -3413) stated that EPA had not accounted for

the health costs of the proposed rule. The commenters stated that the $15 billion benefit cited by

EPA was basically a savings to industry and requested that EPA perform a health impact analysis

for the medical costs and illness/deaths of the proposed alternatives.

Commenter OAR-2002-0056-3353 requested that EPA provide its best estimate of the

reduction in the Hg levels in the seafood consumed in the U.S. compared to complete elimination

of Hg, and requested a more explicit analysis of the extent of harm resulting from Hg exposures. 

The commenter felt that States should consider the total benefits of Hg control. The commenter

further stated that if elimination of Hg would not result in a significant reductions in fish

advisories, this should be acknowledged by EPA.

Response:
8-v

EPA has developed a more complete assessment of its regulatory approach as part of this

final rulemaking action. The RIA which accompanies this rulemaking contains an assessment of

the costs and benefits of the selected approach as well as regulatory alternatives. 

As part of its analysis of the final rule, EPA has estimated that some of the health

benefits of reducing Hg from utilities. freshwater fish. At this time, EPA is only able to provide

quantitative estimates of the benefits of reducing IQ decrements associated with exposure to

MeHg for a portion of the U.S. population, women of child-bearing age. The RIA for this rule

contains this analysis in Chapters 10 and 11.

Comment:

Commenter OAR-2002-0056-3459 contended that EPA failed to meet the requirements of

EO 12866 (Regulatory Planning and Review) because it did not undertake a rigorous economic

analysis of alternative MACT regulatory options. In choosing among alternative approaches, the

commenter believed that EPA should select the approaches that maximize net benefits. The costs

and benefits include both quantitative measures (to the fullest extent they can be usefully

estimated) and qualitative measures of costs and benefits that are difficult to quantify but essential

to consider. The commenter stated that EPA published guidance in 1996 for preparing these

analyses, and failed to follow either the guidance or the EO requirements. The commenter

claimed that EPA did not seriously evaluate alternatives to the MACT floor (e.g., floor based on

no subcategorization or other subcategorization criteria) and did no assessment of alternative

beyond-the-floor options (except for providing excuses why the standards ignore available

techniques). The commenter asserted that EPA then did a superficial cost and benefit assessment

of the MACT standard against a section 111 cap and trade alternative. The commenter stated

that a rigorous economic analysis demonstrated that more stringent MACT standards are

achievable, feasible, highly cost- effective, and would provide substantial additional human health

benefits (the incremental benefits would be well in excess of incremental costs). The analysis used

EPA’s emission rates (minus what the commenter deemed unjustifiable statistical adjustments),

subcategorization by fuel rank (bituminous, subbituminous, lignite), and other EPA methods and

procedures. The results of the commenter’s analysis showed that EPA’s less stringent proposal

was arbitrary and capricious. The commenter’s alternative was said to reduce Hg far more, and

more rapidly, and reduce particulate-related deaths far more at costs very close to those for

EPA’s less stringent proposals (about $5 billion more) and the commenter asserted that these

costs were conservatively (high) estimates. The commenter’s alternative scenario resulted in

slight shifts towards more bituminous coal and moderate declines in subbituminous and lignite

use. A similar shift was observed with EPA’s proposal (or any regulatory approach), but the

commenter stated that the public health and environmental benefits far outweigh the impacts of

coal market shifts. The commenter’s alternative shifted coal production from Appalachia and the

West to the Interior region, and would reduce coal use by less than 1 percent. The commenter

stated that EPA’s proposal had the same shift but increased coal use by about 6 percent. The

alternative resulted in an increase in electricity prices of about one-half cent per kilowatt hour (or

7 percent) for all power regions relative to EPA’s proposal. Coal prices under the alternative

were essentially unchanged, compared to EPA’s proposal and the price of natural gas was

essentially unaffected. The commenter asserted that the costs of the alternative were more than
8-vi

offset by the total estimated benefits of $28 billion in 2010 and $6.9 billion in 2020. Additional

benefits would be even higher if the 11 health and welfare benefits EPA identified but did not

assess were included. The commenter estimated that in 2010, the benefits of the alternative

would exceed costs by almost 6 to 1. The commenter stated that even more stringent limits are

cost effective and that EPA must consider and analyze them to fulfill EO 12866 requirements.

Response:

EPA has conducted the analyses required by EO 12866 and the results are provided in

the preamble of the final rule.

Comment:

One commenter (OAR-2002-0056-2251) stated that, based on the preamble, “... the

relationship between Hg emission reductions from Utility Units and MeHg concentrations cannot

be calculated with confidence,” and asserted that EPA should re-examine the risk to the American

people caused by coal-based utility Hg emissions and consider the health implications of Hg

regulation in a more holistic fashion, so that rules designed to reduce Hg in fish actually reflect

and address the likelihood of health benefits and the expected timing of such benefits and do not

result in arbitrary administrative actions or unintended, negative health consequences for the

public at large. The commenter stated that EPA had a dual responsibility in regard to public

health and emissions from power plants. First, the Agency must protect the public from exposure

to criteria air pollutants and HAP, as defined by the CAA. Second, EPA must assess the impact

of its regulations in a broader perspective.”

Response:

EPA has analyzed the economic and benefits impacts of the final rule and provided a

discussion of the results in the preamble to the final rule and in the RIA.

8 Comment:

One commenter (OAR-2002-0056-1842) questioned EPA’s analysis stating that only a

few air toxics accounted for most of the weight of toxics emitted. The commenter noted,

however, that there is a huge difference in toxicity equivalency quotient (TEQ) between HAP. 

The commenter stated that the average plant has a TEQ of 242,000, and that this quotient already

reflected 90 percent removal of the metals other than Hg. The commenter concluded that the

quotient with no air pollution control equipment could easily be 800,000, and if one were to

require 90 percent reduction from this uncontrolled level then the TEQ or toxic equivalent would

be 80,000. The commenter stated that if Hg were treated separately, the raw quotient would be

700,000, and that meeting a 70,000 quotient limit could easily be accomplished with the normal

particulate equipment and SO2 scrubber.

The commenter stated that the original EPA draft listed Hg with a lesser quantity emission

rate (LQER) of 0.1. The commenter compared the Hg impact with the LQER both at the 0.001
8-vii

level and at 0.01 (the toxicity for lead and chromium). The commenter stated that these

comparisons should give legislators pause before requiring a 90 percent Hg reduction. Reducing

Hg the extra 10 percent could add as much as 10 mils/kWh to electricity cost. The commenter

concluded that for the base case, an extra 10 percent reduction of HCl, chromium, and lead would

accomplish the same toxicity reduction but at a far lower cost (less than 0.5 mil/kWh). The

commenter stated that in the case where Hg was assigned a lower toxicity, the extra 10 percent

Hg reduction only reduced total toxicity by 0.5 percent. The calculations were based on

nationwide annual emissions as reported in the TRI inventory.

Response:

As discussed in the preamble to the final rule, EPA believes that Hg is the pollutant of

concern from coal-fired Utility Units. However, together the multipollutant benefits of CAIR

and CAMR will also lead to reductions of the pollutants the commenter notes.

Comment:

One commenter (OAR-2002-0056-2899) questioned EPA’s analysis stating that reducing

Hg emissions from coal-fired power plants appeared to do little to reduce the public health risk

from Hg exposure. The commenter noted that EPA has repeatedly said that it cannot quantify the

linkage between Hg emissions from coal-fired power plants and Hg levels in fish and observed

that in the preamble to the proposed rule, EPA presented an assessment of the benefits that it

predicted would result from its proposed Hg limits. The commenter noted that with regard to

Hg, EPA stated: “the Agency believes that the key rationale for controlling Hg is to reduce public

and environmental exposure to Hg, thereby reducing risk to public health and wildlife. Although

the available science does not support quantification of these benefits at this time, the Agency

believes the qualitative benefits are large enough to justify substantial investment in Hg emission

reductions.” The commenter stated that EPA’s speculation about the possible benefits from the

control of Hg emissions from coal-fired power plants is not borne out by detailed analyses

performed by EPRI.

The commenter stated that in May 2003, EPRI released a technical report analyzing the

cost effectiveness of the proposed Clear Skies legislation and a hypothetical MACT standard.

According to the commenter, the analysis first used an econometric model to predict how utilities

would act to comply with the two regulatory structures, then used an atmospheric fate and

transport model to predict how the resulting changes in Hg emissions would affect a number of

receptors in specific source regions. The deposition information was then used to estimate the

change in MeHg exposure to women of childbearing age. These changes in MeHg exposure were

then compared to the estimated costs of each regulatory scheme.

According to the commenter, EPRI’s analyses found that Hg emissions from coal-fired

power plants contributed less than 8 percent of the Hg deposited in the U.S., and that a 10

percent reduction in national ionic Hg emissions from coal-fired power plants would result in a

0.75 percent reduction in U.S. Hg deposition while a 10 percent reduction in national elemental

Hg emissions would lower U.S. Hg deposition by 0.03 percent. According to the commenter,
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even if Hg emissions from coal-fired power plants were reduced to 15 tons per year, the Hg

deposition in the U.S. would only be reduced by approximately 5 percent assuming the reductions

were linearly related.

Response:

EPA has developed a more complete assessment of its regulatory approach as part of this

final rulemaking action. The RIA which accompanies this rulemaking contains an assessment of

the costs and benefits of the selected approach as well as regulatory alternatives.

As part of its analysis of the final rule, EPA has estimated that some of the health

benefits of reducing Hg from utilities. At this time EPA is only able to provide quantitative

estimates of the benefits of reducing IQ decrements associated with exposure to MeHg for a

portion of the U.S. population, women of child-bearing age. The RIA for this rule contains this

analysis in Chapters 10 and 11.

Comment:

Commenter (OAR-2002-0056-1842) stated that utilities attempting Hg reduction were

faced with a decision as to whether to install a new baghouse, with substantial capital cost, or to

inject five times more carbon to an existing precipitator. The commenter stated that if a few years

later the utility were told it must greatly reduce fine particulate, it might well regret its Hg

removal choice. The commenter stated that toxic metal releases (lead, chromium, cadmium, etc.)

were typically proportionate to the fine particulate emissions, and that an old plant which was

permitted at 0.2 lbs of discrete particulate/MMBtu emitted more than ten times as much metal

toxics as a newly permitted coal plant with a limit of 0.018 lbs/MMBtu. The commenter stated

that fine particulate is increasingly targeted as an important health hazard, and that condensible

particulate is below 2.5 microns in diameter and includes acid mist and some organics.

The commenter claimed that the installation of scrubbers due to CAIR would substantially

reduce fine particulate, and that several scrubber systems installed in the early 1990s guaranteed

discrete particulate reductions from 0.015 lbs/MMBtu to 0.05 lbs/MMBtu. The commenter

stated that fine particles would not be captured by these systems and that most of the acid mist

(condensibles) would pass through. The commenter concluded that it is necessary to address fine

particulate (including metal toxics) along with Hg, which would be desirable not only because of

the health benefits but because focusing on one pollutant at a time was not cost effective. The

commenter cited evidence that the EPA estimates of particulate and fine particulate were much

lower than the actual quantities (March 1994 and August 1994, Vol. 44 Journal of the Air and

Waste Management Association.) One article from the Institute of Clean Air Companies was

quoted, “Rather, the issue for ICAC is whether government regulators should give utilities the

option–the voluntary choice–of responding to a possible stream of regulatory actions in an

integrated cost-effective way, thus avoiding the traditional and often unsatisfactory choice of

having to add successive “boxes” as regulatory requirements emerge piecemeal, one after the

other.”
8-ix

Comment:

One commenter (OAR-2002-0056-1842) stated that flexible incentives could dramatically

lower a utility’s (and its rate payers’) cost of compliance with the regulatory stream, provide

certainty, and elicit public praise. The commenter further suggested that incentives for

non-mandated particulate and air toxics reductions would also fit nicely with ongoing efforts (e.g.,

the U.S. EPA’s 33/50 and “cleaner/cheaper” projects, and the U.S. Department of Energy’s

voluntary utility greenhouse gas reduction projects) to use market and regulatory incentives to

reduce dangerous emissions more quickly and cost-effectively.

The commenter stated that total U.S. utility particulate (fly ash and other discrete

particles) emissions were between 437,000 tons per year (tpy) and 1.9 million tpy, compared to an

EPA estimate of 700,000 tpy, and that fine particulate emissions (fly ash PM 2.5) were between

305,000 tpy and 1.7 million tpy (compared to an EPA estimate of 99,000 tpy). The commenter

stated that these differences could be important in the setting of priorities and that EPA had

estimated that utilities emit 1.5 million tpy of sulfate aerosols, 334,000 tpy of nitrate aerosols and

27,000 tpy of organic aerosols. The commenter recommended that the economics should be

reviewed because fly ash PM2.5 emissions were 3 to 17 times greater than estimated. The

commenter stated that accurate determination of PM2.5 is critical to the program to limit arsenic,

beryllium, cadmium, chromium, lead, nickel, and other heavy metals.

Response:

The EPA believes that a carefully designed multipollutant approach – a program

designed to regulate NOx, SO2, and Hg at the same time – is the most effective way to reduce

emissions from the power sector. EPA has just finalized the CAIR rule. EPA’s modeling shows

that CAIR will significantly reduce the majority of the coal-fired power plant mercury emissions

that deposit in the U.S., and those reductions will occur in areas where mercury deposition is

currently the highest. The Clean Air Mercury Rule is expected to make additional reductions in

emissions that are transported regionally and deposited domestically, and it will reduce

emissions that contribute to atmospheric mercury worldwide.

Comment:

One commenter (OAR-2002-0056-3543) stated that a thorough technical analysis of the

programs established by the proposal was not possible without additional information from EPA.

Response:

EPA has conducted additional analyses as described in the promulgation preamble and

provided in the docket.

Comment:

Two commenters (OAR-2002-0056-2334, -2915) were concerned about possible
8-x

restriction of energy sources. Commenter OAR-2002-0056-2334 stated that the rule would

dictate air quality, energy, economic, national security and industrial competitiveness policy for

the entire U.S. The commenter stated that all of these policies would be driven by whether the

Rule will allow coal to be used for power generation in a cost competitive manner. The Rule

would determine whether coal or natural gas will be used to meet expanding electricity demand

and as a result, the price and availability of natural gas to private sector, non-utility consumers

including manufacturers, homeowners and farmers. Commenter OAR-2002-0056-2915 expressed

concern that reductions in Hg emissions that may be required by the final Hg rule not negatively

impact the diversity of fuels that are used for electricity generation in Texas or in the U.S., or

raise the cost of electricity to, or reduce the reliability of, electricity for consumers. The

commenter stated that EPA’s premise in the proposed Hg rule, was that it would preserve the

ability to use all types of coal currently used in coal-fired EGUs. However, according to the

commenter, the proposed rule did not support that premise because the proposed rule mandated

Hg emissions reductions that would be technically impossible to achieve by certain EGUs burning

certain types of coal and/or would be economically unreasonable for such EGUs. The commenter

stated that, as a result, the proposed Hg rule would almost certainly prevent the continued use of

certain types of coal as fuel in certain EGUs. The commenter asserted that this was especially

true for Gulf Coast lignite, which would cease to be as viable as a fuel for EGUs, and might cease

to be viable at all. The commenter stated that this negative impact of the proposed Hg rule would

significantly harm fuel diversity, which would increase electricity prices and decrease electricity

reliability without providing a commensurate health and environmental benefit.

Response:

EPA’s modeling has shown little significant coal switching as a result of the proposed

CAMR and CAIR actions. We do not believe that the final rules will have a negative impact on

the nation’s energy security, employment rates, or energy reliability. EPA does not feel that it is

in the best interest of the country to prohibit the use of some ranks of coal when these coals can

be adequately controlled to limit Hg emissions. EPA believes that a cap-and-trade approach

will better serve to protect the environment while at the same time allowing the U.S. to maintain

fuel diversity.

Comment:

One commenter (OAR-2002-0056-2523) stated that farmers should be considered an

important stakeholder in any rulemaking which impacts the affordability and availability of

electricity. The commenter stated that in 2002 the total energy consumed on U.S. farms exceeded

1.7 quadrillion Btu, with electricity accounting for almost 21 percent (356 trillion Btu) of that

usage. Diesel and plant nutrients were said to be the only components of overall farm energy

usage that exceeds that of electricity. According to the commenter, farmers spent $3.4 billion on

electricity in 2002, and that amount would be significantly higher for 2004. (Electricity is used to

irrigate 20 million acres in the U.S., more than diesel, propane and natural gas combined.) The

commenter added that electricity is also used to milk cows, move grain, cool poultry houses, and

light barns and homes as well as for many other critical functions. The commenter supported 

cost-effective efforts to reduce Hg pollution because of reports that large doses of Hg can be
8-xi

harmful to people, especially children. The commenter, therefore, supported reductions in Hg

emissions in rural areas and all across America. The commenter stated that, at the same time,

farm families continue to be hit hard by fuel shortages and energy price increases. The commenter

added that in just the last 12 months the availability and price of natural gas, diesel, gasoline, plant

nutrients, propane and electricity have had a major impact on the farming community.

The commenter stated that farm groups have long supported multi-emissions legislation

(based on an emissions trading program similar to that used successfully for SO2 control), such as

the proposal by Senator Voinovich that was before Congress. This legislation was predicted to

cut power plant Hg emissions by nearly 70 percent by 2018. The commenter opposed any

proposals that would force power plants to use expensive and unproven technologies. The

commenter stated that imposing specific technologies and unrealistic deadlines on power plants

could unnecessarily increase costs to utilities and electricity prices to consumers.

Response:

EPA believes that the final rule will address the concerns of the commenter. As noted

earlier, EPA concurs with the commenter’s concerns regarding the use of unproven

technologies.

Comment:

One commenter (OAR-2002-0056-2422) stated that if EPA relies upon the Maximum

Achievable Control Technology (MACT) provisions of CAA section 112, the Hg rule could be

among the most costly regulatory mandates ever issued by the Agency. The commenter stated

that reliance on an emission-trading alternative, with an emission cap and a more stringent

ultimate level of control, may reduce overall compliance costs but introduce new compliance

burdens, including constraints on the addition of new coal-based generating capacity. One of the

commenter’s principal concerns with this rulemaking was to ensure that new coal-fueled

generating sources could be permitted in a timely and economic manner, consistent with the

nation’s needs for adequate and reliable electric power supplies, in full compliance with all

applicable environmental safeguards.

Response:

EPA is finalizing a cap-and-trade program for Hg under section 111 of the CAA. The

final CAMR is not projected to have any significant impact on the amount of new coal fired

capacity projected in the power sector. The economic and energy impacts of CAIR are discussed

in Chapter 7 of the RIA.

Comment:

Two commenters (OAR-2002-0056-1952, -2264) questioned the benefits to U.S.

residents of rule limiting U.S. emissions. Commenter OAR-2002-0056-1952 stated that if the

cost of Hg removal drives U.S. electricity prices higher, we risk not only domestic job loss, but
8-xii

also substantially higher global emissions of Hg, sulfur, arsenic, NOx, and CO2. The commenter

added that there are abundant worldwide resources of coal, and that there is no reason that

coal-fired plants won’t be built in developing countries where emissions control is not as

important as jobs. The commenter expressed concern that an EPA policy intended to reduce

global emissions may actually have the opposite effect by closing down U.S. plants with good

controls and replacing them with offshore plants with no controls. The commenter recommended

a goal-driven policy that sets targets for reducing Hg and CO2 and allows market-place

economics to select the successful technologies. Commenter OAR-2002-0056-2264 expressed

concern about the cost/benefit of the proposed rule, and stated that the proposed rule would place

the burden of global Hg emission reduction on U.S. coal-fired power plants. These domestic

power plants were said to collectively represent less than 1 percent of the global emissions of Hg. 

The commenter stated that natural sources of Hg account for approximately two-thirds of global

Hg emissions, with human sources accounting for the remaining third. The commenter claimed

that recent analyses by the EPA and other experts found that as much as 70 percent of the Hg

deposited in U.S. waterways comes from outside the U.S.

Response:

EPA is aware that global Hg emissions deposit in the U.S. However, as presented in the

preamble to the final rule and elsewhere in this document, we believe that it is still prudent to

regulate U.S. sources of Hg. We have discussed the impacts of global Hg emissions on the U.S.

in the preamble and in various Technical Support Documents.

Comment:

One commenter (OAR-2002-0056-2883) believed that the EPA should consider the

energy consequences (fuel supply), Unfunded Mandates and Regulatory Act and Small Business

Regulatory Enforcement Fairness Act of 1996 (SBREFA), and energy issues as outlined in EO

12866 consequences when promulgating the final rule to control Hg and nickel from utilities.

Response:

EPA has fully complied with all three EO during this rulemaking. An economic and

energy impacts analysis, including analysis of the impacts of the rule on small entities and

government owned entities, can be found in Chapter 7 of the RIA.

Comment:

Two commenters (OAR-2002-0056-2172, -2267) stated that EPA’s Regulatory Impact

Analysis failed to consider impacts on small entities as required by the Small Business Regulatory

Fairness Act of 1996 (SBREFA). The commenters stated that Congress enacted SBREFA in

order to protect small business, small organizations and small governmental jurisdictions,

collectively referred to as “small entities,” from disproportionate or unanticipated adverse impacts

of federal rulemaking activity, and that the analyses required by SBREFA must be undertaken

prior to publication of any general notice of proposed rulemaking and must “contain a description
8-xiii

of any significant alternatives to the proposed rule which accomplish the stated objectives of

applicable statutes and which minimize any significant economic impact of the proposed rule on

small entities.” 5 U.S.C. § 603(c).

Response:

EPA performed an analysis of the impacts of the proposed rule on small entities that was

discussed in the January 30, 2004 Notice of Proposed Rulemaking (see 69 FR 4713). In the

NPR, EPA certified that the proposed rule would not have a significant impact on a substantial

number of small entities. For the final rule, EPA performed additional analysis of the impact of

CAMR on small entities, which is included in Chapter 7 of the RIA.

Comment:

One commenter (OAR-2002-0056-2830) stated that EPA had underestimated the annual

cost of monitoring, reporting and record keeping. The commenter stated that EPA had estimated

the annual reporting costs to be $48.4 million, which equated to approximately $85,000 per unit. 

The commenter felt that this was an underestimate when the annual Hg compliance audit (which

was budgeted at over $30,000 for a single annual audit) was considered. The commenter stated

that the frequency of audits can be increased to semi-annual or more frequent, based on the

monitor’s performance. The commenter stated that, at present, there are no long-term Hg

monitoring systems in-place at a coal-fired facility, that the current state of monitoring is very

labor intensive and involves an extremely highly trained workforce, and that analyzers cost over

$100,000. The commenter contended that EPA’s estimate does not account for secondary

systems required to support this equipment (e.g., monitor cabinets, air supplies, electrical power

supply, electronic communication networks, data storage devices and software enhancements).

Response:

For the final rule, EPA has done an analysis of the cost associated with monitoring,

reporting, and record keeping requirements for affected sources. EPA has estimated the annual

costs associated with these activities to be about $76 million (see final CAMR preamble Section 

VI.B. Paperwork Reduction Act).

8.2 INDIAN TRIBES (CONSULTATIONS, UNIQUE IMPACTS AND RISKS)

Comment:

Three commenters (OAR-2002-0056-2380, -2695, -3413) criticized the cost-benefit

analysis and risk assessment with respect to tribes. The commenters claimed that the models used

to assess the impacts failed to independently address tribal lands, often establishing grids based on

county boundaries that overlap tribal and State jurisdictions. The commenters requested that

EPA develop a model that is appropriate for assessing the impacts of proposed rules on Indian

lands. The commenters also stated that the risk assessment models and cost benefit models did

not account for unique tribal factors, such as subsistence and consumption levels. The
8-xiv

commenters recommended a risk assessment model based on the precautionary principle, which

properly accounts for tribal consumption levels. The commenters requested that EPA assess the

risk for a period greater than 7 generations into the future relative to tribes that maintain

subsistence lifestyles.

Comment:

Numerous commenters stated that high Hg levels in fish disproportionately affect Indian

tribes because a number of power plants were located along the waterways that tribes directly

used as food supply and that they consumed more fish than non-Indians (20 times that of the

average American). The commenters asserted that EPA must assess the disproportionate health

risk. Commenter OAR-2002-0056-4190 added that 5 pounds of fish were consumed per person

per week in the commenter’s tribe and that separate standards were needed to account for dietary

differences among tribes. One commenter recommended that the final rule also address Indian

Health Service findings on the disproportionate cardiovascular risk for Indians compared to

national levels. The commenter stated that “hot spots” may increase cardiovascular risk in Indian

people.

Comment:

One commenter (OAR-2002-0056-3457) stated that the discussion in EO 13175 is

inadequate in that it only addresses compliance costs for two units in Indian Country, whereas

Tribes are directly affected because of the effect on fishing and fish consumption in ceded territory

inland waters and Lake Superior which adversely affect the practice of important cultural

activities.

Comment:

Numerous commenters stated that EPA had not fulfilled its tribal consultation

requirements under EO 13175 or EPA Indian Policy which required EPA to fulfill its trust

responsibility to tribes and consult on a government-by-government basis. The commenters

stated that consultation was inadequate given the significance of the rule, and because Indians

were not included as stakeholders along with States. The commenters stated that this obligation

is heightened by EO 12898 which established the Environmental Justice doctrine, and that these

obligations required EPA to consult with the Tribes to determine how the proposed rule could

result in heightened or unique impacts on Indian tribes. The commenters assert that after EPA

has determined the unique impacts, EPA must then ensure that the rulemaking properly protects

the tribes rights and resources. The commenters stated that EPA must identify and address

disproportionately high human health and environmental effects on all tribes so that all people are

equally protected from health and environmental hazards, and that EPA’s proposals did not meet

legal requirements, failed to protect public health and the environment (particularly with respect

to the commenters), and created grave concerns about localized impacts.

Comment:
8-xv

Two commenters (OAR-2002-0056-2380, -3413) stated that EPA must develop a proper

tribal consultation strategy that ensures EPA will meet its trust responsibilities and conduct

government-to-government consultations.

Response:

EPA recognizes that the Federal government stands in a government-to-government

relationship with Federally recognized Tribes and ahs certain trust responsibilities to these

Tribes. This relationship and responsibility should guide EPA in the implementation of policies

and actions that affect Tribes. Pursuant to the government-to-government relationship, EPA

consults with Tribes regarding actions that affect Tribes. In addition, treaties, statutes, and

executive orders create Federal obligations regarding Tribal resources. EPA believes that its

actions in developing the final rule have been consistent with the government-to-government

relationship and that the final rule itself is consistent with the trust responsibility.

EPA does not agree with the commenters who claim that it did not consult with tribes in

developing the rule. As explained in the discussion of EPA compliance with EO 13175 in the

preamble for the final rule, EPA took the following steps to consult with Tribes. EPA gave a

presentation to a national meeting of the National Tribal Environmental Council (NTEC) in

April 2001, and encouraged Tribal input at an early stage. EPA then worked with NTEC to find

a Tribal representative to participate in the workgroup developing the rule, and included a

representative from the Navajo Nation as a member the official workgroup, with a representative

from the Campo Band later added as an alternate. In March 2004, EPA provided a briefing for

Tribal representatives, the newly formed National Tribal Air Association (NTAA), and NTEC. 

EPA received comments on this rule from a number of Tribes, and has taken those comments

and other input from Tribal representatives into consideration in development of this rule.

EPA believes that this regulation adequately protects Tribal health and is consistent with

the trust responsibility for several reasons. First, the commenters understate the significance of

the fact that Hg emissions from Utility Units currently are not subject to performance standards. 

This regulation will for the first time establish performance standards applicable to Hg

emissions, and those standards will require significant reductions in the levels of Hg emissions. 

Such reductions will provide greater protection to Tribal fish resources than would otherwise be

available. Acting to provide such heightened protection is consistent with both the statute and

the Federal trust responsibility.

Moreover, the commenters offer no specific evidence that the Hg emissions reductions

from this regulation will not adequately protect Tribal health. Their main contention is that the

regulatory approach set forth in an earlier EPA proposal would have produced a 90 percent

reduction in Hg emissions and that any smaller reduction is, therefore, inadequate. That

contention rests on a misconception of an earlier Federal Register Notice, which proposed a

finding, but did not contain any specific proposal for Hg emissions regulations, and, therefore,

did not provide for any percentage of reduction. EPA has never proposed any such rule. EPA

believes that this regulation will adequately protect Tribal health.
8-xvi

The commenters also argue that EPA has not adequately considered the significance of

Tribal fish consumption patterns, specifically the fact that Tribal fishers consume more fish than

the general population. That comment is misplaced. As described in more detail elsewhere in

this document, EPA carefully analyzed available information on fish consumption by Tribal

members and other sub-populations, and determined how to use the available data most

appropriately. One basis for EPA’s analysis was a study of tribal fish consumption in one

region to model consumption by other Tribes as well as other subpopulations. EPA’s approach

was to identify areas where the effects of Hg deposition from utility emissions had the greatest

effects. EPA then compared those high-deposition areas with locations with high Tribal

populations to assess the areas of greatest potential risk to Tribes. That analysis found very few

areas where Native Americans live and there is high residual Hg deposition caused by utilities. 

Further, the analysis shows that the standards established in the regulation will significantly

reduce risks to tribal members.

Finally, as discussed in the preamble to the regulation, this regulation establishes a

cap-and-trade program for Indian country.

As part of its analysis of the final rule, EPA has estimated that some of the health

benefits of reducing Hg from utilities. At this time EPA is only able to provide quantitative

estimates of the benefits of reducing neurological impacts of exposure to MeHg for a portion of

the U.S. population, women of child-bearing age. The RIA for this rule contains this analysis in

Chapter 11. As part of its assessment, EPA provides estimates for the benefits of this rulemaking

to subsistence fishers, including case study examples of the benefits to the some members of the

Chippewa Tribe, the Hmong, and low income fishers.

8.3 FACA

Comment:

Many commenters criticized EPA’s rulemaking process. Commenters claimed that many

U.S. Senators and Congressmen asserted that EPA’s actions may not be sufficient to meet

procedural requirements under CAA section 307(d). The commenters criticized EPA for ending

consultations with the FACA Committee, established in accordance with CAA section 117, and

noted that, at the same time, EPA appeared to be disproportionately influenced by industry law

firms.

Many commenters specifically criticized the rulemaking process for ignoring Agency

scientists and FACA recommendations and not analyzing the range of controls recommended by

FACA. The commenters pointed out that the EPA proposal was at odds with all FACA positions. 

The commenters claimed that EPA’s actions showed complete disregard of a working partnership

with States and other stakeholders, and noted that, at no time, was the possibility of a cap-andtrade program raised. Commenters believe that EPA should have consulted the States to address

regional issues prior to making the alternative proposal. Commenter OAR-2002-0056-2886

found EPA’s proposal a betrayal of the public stakeholder process. Commenter OAR-2002-

0056-2819 specifically requested that EPA reconsider the NESCAUM and STAPPA/ALAPCO
8-xvii

recommendations and incorporate them in the final rule. Commenter OAR-2002-0056-3438

believed EPA’s actions were a serious deviation from the rulemaking process and asked EPA to

re-engage the advisory process that it abandoned.

Many commenters claimed the advisory group process confirmed that EPA conceded (1)

it was legally required to adopt a MACT standard under section 112, (2) EPA had no authority

to establish a cap-and-trade program to set a MACT floor for Hg, and (3) additional modeling

needed to be done that apparently was never performed. The FACA co-chairman requested that

all FACA work, as was documented on EPA’s website, be entered into the docket. The FACA

co-chairman also stated that EPA must produce the promised IPM modeling of the workgroup’s

final recommendations. The commenters stated that the IPM runs must be completed, made

available to the workgroup, and entered into the docket. One commenter (OAR-2002-0056-

2819) found EPA’s refusals to perform the IPM modeling runs for the MACT proposal (without

cap and trade) very troubling (these runs were requested by NESCAUM and STAPPA/ALAPCO

during the FACA workgroup process). The commenter requested that EPA perform these runs

before adopting a final rule using the recommendations submitted by the commenter. This

commenter believed the results would confirm the superior environmental and health benefits

cited by State and local agencies during the FACA process. The Massachusetts Attorney General

submitted a Freedom of Information Act request regarding the modeling runs. Another

commenter (OAR-2002-0056-2878) recommended that the modeling runs include high

performing technologies and the IAQR co-benefits; failure to include the IAQR co-benefits would

make the costs of Hg reductions artificially high. Three U.S. senators and one Congressman

urged EPA to complete the analyses.

Comprehensive comments from public interest groups (OAR-2002-0056-3459) stated that

EPA’s complete disregard for the recommendations of the FACA Working Group convened for

the MACT rule contravened CAA requirements and was arbitrary, capricious, and an abuse of

discretion. The commenters noted that CAA section 117 required EPA to “to the maximum

extent practicable within the time provided, consult with appropriate advisory committees” prior

to publishing a 111 or 112 standard. The commenters added that “consult” meant to “consider”

or “to seek information or advise from” and “to seek permission or approval from”. The

commenters submitted that EPA referenced its own working group only in passing and did not

discuss its recommendations at all. These recommendations related to subcategorization, MACT

floors, variability, format of the standard, monitoring, and regulation of nickel emissions from

oil-fired units. In fact, the commenters claimed, a subset of the work group, including industry

participants, reached agreement on the subcategorization issue and presented its consensus

document to EPA. EPA’s abrupt termination of the working group and its failure to evaluate

their recommendations or even include them in the proposal at all did not, in the commenters

view, comport with section 117(c) requirement to “consult”. The commenters stated that EPA’s

subsequent proposal was weaker than any of the recommendations (including recommendations

from industry stakeholders) of the work group members. EPA even refused to perform specific

modeling runs to assess alternative MACT approaches requested by the work group.

One commenter (OAR-2002-0056-2519) stated that during the summer of 2002 EPA

initiated the two-year process under the Clean Air Act Advisory Committee’s Mercury Working
8-xviii

Group, seeking stakeholder input to develop the Hg emissions control program. That process

considered various technical, policy and legal issues associated with setting the MACT standard.

The commenter stated that at no time during those deliberations was there any suggestion to

utilize a cap-and-trade program in lieu of MACT standards. Accordingly, there was no

opportunity to fully assess and debate various issues associated with such a Hg emissions control

approach. The commenter added that in December 2000, EPA made the regulatory determination

that it was “necessary and appropriate” to regulate Hg emissions from the utility sector, triggering

the process to establish MACT standards. The commenter believed that retracting that finding

and establishing a cap-and-trade approach pursuant to CAA section 111 or 112 rendered the

chosen program vulnerable to legal challenge.

Comment:

Four commenters (OAR-2002-0056-1479, -1658, -2364, -2819) requested that all FACA

work, as is documented on EPA’s website, be entered into the docket. The commenters stated

that EPA must produce the promised IPM modeling of the workgroup’s final recommendations

and that the IPM runs must be completed, made available to the workgroup and entered into the

docket. Commenter OAR-2002-0056-2819 stated that EPA’s refusals to perform the IPM

modeling runs for the MACT proposal (without cap-and-trade) was troubling, as these runs were

requested by NESCAUM and STAPPA/ALAPCO during the FACA workgroup process. The

commenter requested that EPA perform these runs before adopting a final rule based on

recommendations submitted by the commenter. The commenter believed that the results would

confirm the superior environmental and health benefits claimed by the State and local agencies

during the FACA process.

Comment:

Four commenters (OAR-2002-0056-2364, -2010, -2012, -2015) requested that EPA

provide modeling output. Commenter OAR-2002-0056-2364 stated that EPA must run the IPM

at the control levels recommended by stakeholders in the workgroup (90 percent nationwide with

at least 70 percent for each plant) to determine the optimal time for implementation. Three

commenters (OAR-2002-0056-2010, -2012, -2015) recommended using time frames which

match the times specified in EPA’s section 111 proposal, and stated that running this analysis

would satisfy the commitments EPA made to the workgroup.

Response:

Some of the issues raised by the commenters are the subject of on-going FOIA requests

and pending litigation and, therefore, cannot be addressed here. EPA has placed all relevant

materials in the rulemaking docket. EPA took into consideration the input from the workgroup. 

However, after over a year, EPA realized that consensus was not going to be reached in a

timeframe consistent with our meeting our responsibility to propose a rule by December 15,

2003 and terminated the workgroup.

8.4 CHILDREN’S HEALTH (E.O. 13045)
8-xix

28 Comment:

One commenter (OAR-2002-0056-2523) supported cost-effective efforts to reduce Hg

pollution because of reports that large doses of Hg can be harmful to people, especially children. 

The commenter therefore supported reductions in Hg emissions in rural areas and all across

America. The commenter stated that at the same time, farm families continue to be hit hard by

fuel shortages and energy price increases.

Response:

EPA concurs that cost-effective approaches to reducing Hg emissions are most

appropriate and believes that the cap-and-trade approach is the best approach.

Comment:

Comprehensive comments from a public interest group stated that EPA failed to meet the

requirements of EO 13045 (Protection of Children from Environmental Health Risks and Safety

Risks). The commenter stated that this failure is particularly egregious because EPA

acknowledged that developing fetuses and children are at the highest risk with respect to Hg

contamination. The commenter stated that the record showed that EPA changed the language

from the Office of Management and Budget (OMB) package (“the order did not apply because

the rule was based on control technology and not risk”) to “the Agency evaluated the health and

safety effects of the proposed rule and for the reasons explained above, the Agency believes the

proposed strategies are preferable to other potentially effective and reasonably feasible

alternatives.” The commenter claims that the record demonstrates that EPA did not undertake

such analysis, and it not only failed to do any analysis of the impacts of the proposed MACT or

the section 111 cap and trade alternative on children’s health, but also failed to conduct any

analysis of the impacts compared to other approaches (potentially effective and reasonably

feasible alternatives). The commenter stated that because of this failing, the proposed strategies

can hardly be considered preferable [per section 5-501(b)] of the order. The commenter asserted

that this is but one example of how EPA’s language was changed to minimize the health risks of

Hg exposure.

Response:

EPA has developed a more complete assessment of its regulatory approach as part of this

final rulemaking action. The RIA which accompanies this rulemaking contains an assessment of

the costs and benefits of the selected approach as well as regulatory alternatives.

As part of its analysis of the final rule, EPA has estimated that some of the health

benefits of reducing Hg from utilities. At this time EPA is only able to provide quantitative

estimates of the benefits of reducing IQ decrements associated with exposure to MeHg for a

portion of the U.S. population, women of child-bearing age. The RIA for this rule contains this

analysis in Chapters 10 and 11.
8-xx

Comment:

Numerous commenters stated that Hg poses a serious health threat to children and that

EPA should elevate this issue in finalizing the rule. Many of these commenters specifically stated

that EPA had not fulfilled its obligations for the protection of children’s health under EO 13045

and had ignored recommendations of its own Children’s Health Advisory Committee regarding

Hg emissions from power plants (i.e., unique vulnerabilities of children, infants, and women of

childbearing age were not adequately considered). One commenter (OAR-2002-0056-3322)

questioned whether the current options go as far as possible and therefore requested more

analysis. This commenter specifically called on EPA to: 1) Using existing information, evaluate

the exposures and health risks to children and women of childbearing age, resulting from the

proposed options, including how these might vary under the different options; 2) Evaluate the

possibility of hot spots; and 3) Using existing information, conduct an integrated analysis of

technologies, costs, health impacts, and economic benefits before choosing a regulatory option.

Commenter OAR-2002-0056-3543 questioned EPA’s statement that the evaluation of the

proposed strategies shows the rulemaking will improve air quality and children’s health. The

commenter stated that the link between air quality and children’s health is water quality and fish

contamination, and that therefore more than air quality needs to be evaluated to fulfill the

requirements of EO 13045.

Response:

EPA has developed a more complete assessment of its regulatory approach as part of this

final rulemaking action. The RIA which accompanies this rulemaking contains an assessment of

the costs and benefits of the selected approach as well as regulatory alternatives.

As part of its analysis of the final rule, EPA has estimated that some of the health

benefits of reducing Hg from utilities. At this time EPA is only able to provide quantitative

estimates of the benefits of reducing IQ decrements associated with exposure to MeHg for a

portion of the U.S. population, women of child-bearing age. The RIA for this rule contains this

analysis in Chapters 10 and 11.

8.5 UNFUNDED MANDATES

Comment:

Two commenters (OAR-2002-0056-2172, -2267) stated that EPA’s Regulatory Impact

Analysis failed to fully consider the impacts of the proposal under UMRA, and that EPA also

failed to provide a complete and accurate assessment of the anticipated impacts of the proposed

rules pursuant to the UMRA, 2 U.S.C. § 1531 et seq. The commenters stated that EPA had

concluded that the rules would not have disproportionate budgetary effects on any particular local

governments or types of communities. The commenters stated that the rule would, in fact,

impose significant direct costs of compliance on the commenter’s municipality; and would

endanger the substantial investment that the municipality had in its electric generating facilities.
8-xxi

Response:

EPA performed an analysis of the economic impacts of CAMR on government-owned

entities, which is summarized in Chapter 7 of the RIA. EPA has chosen to finalize a cap-andtrade program for Hg, which will reduce the economic impact of the rule on municipalities,

through the flexibilities inherent in such a program.

Comment:

One commenter (OAR-2002-0056-2251) stated that under the Unfunded Mandates Act,

EPA is required to examine how the proposed regulations to reduce Hg emissions would affect

the nation’s economy, with emphasis on productivity, economic growth, full employment,

creation of productive jobs, and international competitiveness of U.S. goods and services. The

commenter believed that regulations that reduce current coal-based electricity or impede

construction of new coal-based power plants could damage our domestic economy. The

commenter believed that all domestic energy resources will be needed to meet America’s growing

demand for reliable electricity. The commenter stated that, unlike natural gas, using coal and

nuclear power (the principal alternatives to gas for generating baseload power) would not have a

negative effect on other energy sectors that would impact consumers and businesses alike. The

commenter believed that if EPA’s rulemaking caused an even greater and faster shift away from

coal to natural gas, the U.S. economy, along with millions of American workers and investors,

would be hurt.

Response:

EPA provides an analysis of the economic and energy impacts of CAMR, including an

economic analysis of the impacts of CAMR on small entities, in Chapter 7 of the RIA. Under

CAMR, coal-fired generation and natural gas-fired generation are projected to remain relatively

unchanged because of the phased-in nature of CAMR, which allows industry the appropriate

amount of time to install the necessary pollution controls.

8.6 ENERGY EFFECTS

Comment:

One commenter (OAR-2002-0056-2850) with a high percentage of industrial customers

who were high energy users struggling to compete in a competitive global market economy,

recommended that any further emission reductions applicable to electric generating units (EGU)

be implemented with reasonable time frames and cost to minimize the impact to residential and

industrial customers alike.

Response:

The EPA believes that a carefully designed multipollutant approach – a program

designed to control NOx, SO2, and Hg at the same time – is the most effective way to reduce
8-xxii

emissions from the power sector. One key feature of this approach is the interrelationship of the

timing and cap levels for NOx, SO2, and Hg. The recently finalized CAIR, combined with

today’s rule, will implement cap-and-trade programs for all three pollutants. The use of capand-trade will limit the costs of these rules relative to a command and control approach.

Comment:

One commenter (OAR-2002-0056-2334) recommended that the uncertainty of natural gas

supply be considered to prevent shortages and rationing of natural gas. The commenter stated

that current air regulation has driven electric utilities to use substantially larger amounts of natural

gas, resulting in very high prices, and that, from 1992 to 2002 natural gas demand by the electric

utility industry increased 60.5 percent and accounted for 93.6 percent of the nations’ increase in

natural gas demand (according to the EIA). The commenter recommended that the Ru1e be

implemented in a manner that is “natural gas neutral.” The commenter stated that the “46 month

U.S. natural gas crisis” cost consumers over $130 billion and that air regulation played a

significant role in that cost. The commenter recommended that the availability and reliability of

natural gas supply be considered, as U.S. natural gas production has been flat for years. (Gas

production in 1972 was 21,624 BCF and 19,047 BCF in 2002, a thirty-year time name. Gas

production in 1998 was 19,024 BCF and 19,047 BCF in 2002, a five-year time frame.) Even with

the current high rig count, production is flat to declining. The commenter stated that if electrical

utilities continue to increase their use of natural gas, there is a real possibility of shortages and

rationing of natural gas. The commenter stated that this would create an economic calamity that

is avoidable through the increased use of available clean coal technologies.

The commenter stated that electric utility purchases of natural gas compete with all other

consumers and have an unfair advantage, in that they have the ability to buy natural gas at any

price and pass the cost on to the consumer. All other consumers such as manufacturing,

home-owners and the farm community are price sensitive and given high prices would be required

to make what the commenter felt were unnecessary sacrifices. The commenter stated that, in the

past three years, 2.8 million manufacturing jobs have been lost in this country in large part due to

the increased cost of energy and that further increases in energy cost would result in further loss

of jobs.

Response:

EPA provides an analysis of the economic and energy impacts of CAMR in Chapter 7 of

the RIA. Under CAMR, coal-fired generation and natural gas-fired generation are projected to

remain relatively unchanged because of the phased-in nature of CAMR, which allows industry

the appropriate amount of time to install the necessary pollution controls while still meeting our

environmental goals. It should also be noted that, according to EO 13211: Actions that

Significantly Affect Energy Supply, Distribution, or Use, this rule is not significant, measured

incrementally to CAIR, because it does not have a greater than a 1 percent impact on the cost of

electricity production and it does not result in the retirement of greater than 500 MW of coalfired generation. In fact, CAMR is not projected to result in any additional coal retirement

relative to CAIR.
8-xxiii

Comment:

One commenter (OAR-2002-0056-2251) believed that regulations that reduce current

coal-based electricity or impede construction of new coal-based power plants could damage our

domestic economy. The commenter believed that all domestic energy resources will be needed to

meet America’s growing demand for reliable electricity. The commenter stated that, unlike

natural gas, using coal and nuclear power (the principal alternatives to gas for generating baseload

power) would not have a negative effect on other energy sectors that would impact consumers

and businesses alike. The commenter stated that if EPA’s rulemaking caused an even greater and

faster shift away from coal to natural gas, the U.S. economy, along with millions of American

workers and investors, would be hurt.

Response:

The final CAMR is not projected to have any significant impact on the amount of new

coal fired capacity projected in the power sector. Also, under CAMR, coal-fired generation and

natural gas-fired generation are projected to remain relatively unchanged because of the

phased-in nature of CAMR, which allows industry the appropriate amount of time to install the

necessary pollution controls. The economic and energy impacts of CAIR are discussed in

Chapter 7 of the RIA.

Comment:

Two commenters (OAR-2002-0056-2066, -2334) requested energy studies. One

commenter (OAR-2002-0056-2334) stated that it is essential that a new study be completed by

the EIA to determine the impact of this rule on natural gas demand and price under EO 13211. 

The commenter asserted that consumers need assurances that the way the EPA plans to

implement the rule will not increase demand for natural gas. Commenter OAR-2002-0056-2066

stated that in May 2001, EO 13211 was signed by the President and noted that, with the full

understanding that Federal Government regulations “can significantly affect the supply,

distribution, and use of energy,” the President, through EO 13211, requires agencies to prepare a

“Statement of Energy Effects” when undertaking certain actions. The commenter asserted that

EPA’s proposal on regulation of Hg emissions from electric utility steam-generating units fell

within the intent of the President’s issuance of this order as well as within the parameters outlined

in the order itself. The commenter urged the EPA to undertake such a study in full compliance

with the EO, and if it has already done so, the commenter requested that the document be

published for public review and comment.

Response:

EPA has fully complied with EO 13211 in this rulemaking. A complete economic and

energy impacts analysis is provided in Chapter 7 of the RIA.

8.7 ENVIRONMENTAL JUSTICE
8-xxiv

Comment:

Numerous commenters stated that EPA must assess the environmental justice implications

of the proposals. Commenters stated that there are environmental justice problems because

impact of lax controls fall on native people and African-Americans who consume more fish than

the rest of the population and poor inner city residents, including children, who reside near

multiple Hg emission sources. Commenters recommended that EPA also identify and analyze the

issue of disproportionate public health risk to populations that subsist on Hg-contaminated fish

and shellfish in the context of the trading proposal, as required under EO 12890. Commenter

OAR-2002-0056-3396 emphasized the disproportionate impacts on pregnant women, unborn

children, and children from poor families.

Response:

EPA has developed a more complete assessment of its regulatory approach as part of this

final rulemaking action. The RIA which accompanies this rulemaking contains an assessment of

the costs and benefits of the selected approach as well as regulatory alternatives.

As part of its analysis of the final rule, EPA has estimated that some of the health

benefits of reducing Hg from utilities. At this time EPA is only able to provide quantitative

estimates of the benefits of reducing IQ decrements associated with exposure to MeHg for a

portion of the U.S. population, women of child-bearing age. The RIA for this rule contains this

analysis in Chapters 10 and 11. As part of its assessment, EPA provides estimates for the

benefits of this rulemaking to subsistence fishers, including case study examples of the benefits

to the some members of the Chippewa Tribe, the Hmong, and low income fishers.

8.8 DATA QUALITY

Comment:

One commenter (OAR-2002-0056-2422) stated that Congress enacted new data quality

legislation as part of the FY2001 Consolidated Appropriations Act (P.L. 106-554, §515) which

expanded previous data quality report language in the FY 1999 Omnibus Appropriations Act

(P.L. 105-277). The commenter stated that in response to these Congressional directives, the

OMB had developed government-wide standards for the quality of information used and

disseminated by Federal agencies, including EPA. The commenter stated that OMB’s

“Information Quality Guidelines (October 1, 2002)” set forth the government-wide guidelines for

“ensuring and maximizing the quality, objectivity, utility and integrity of information disseminated

by Federal agencies.” The commenter quoted the guidelines as “Objectivity is a measure of

whether disseminated information is accurate, reliable and unbiased, and whether that information

is presented in an accurate, clear, complete and unbiased manner.” The commenter noted concern

about the objectivity of EPA’s Hg MACT determination process, including but not limited to the

selection of the plants included in EPA’s ICR data base and the what the commenter claimed was

EPA’s mischaracterization of coal supplies to the top-performing units selected for MACT floor

evaluations. The commenter felt that EPA’s sample of 80 plants appeared to be deliberately
8-xxv

skewed toward certain plant configurations employing advanced control technologies, and thus

was not representative of the entire population of coal-fired boilers in the U.S. The commenter

state that concerns on this point were raised in the EPA Mercury MACT Working Group process,

without apparent response by EPA. The commenter opposed MACT-based Hg regulation for

coal-fired electric generating units.

Response:

EPA is not finalizing a MACT rule for Hg, but rather, a cap-and-trade program under

section 111 of the CAA.
RESPONSE TO SIGNIFICANT PUBLIC COMMENTS ON

THE PROPOSED CLEAN AIR MERCURY RULE

Received in response to:

Proposed National Emission Standards for Hazardous Air Pollutants; and, in

the Alternative, Proposed Standards of Performance for New and Existing

Stationary Sources: Electric Utility Steam Generating Units

(69 FR 4652; January 30, 2004)

Supplemental Notice for the Proposed National Emission Standards for

Hazardous Air Pollutants; and, in the Alternative, Proposed Standards of

Performance for New and Existing Stationary Sources: Electric Utility Steam

Generating Units

(69 FR 12398; March 16, 2004)

Proposed National Emission Standards for Hazardous Air Pollutants; and, in

the Alternative, Proposed Standards of Performance for New and Existing

Stationary Sources, Electric Utility Steam Generating Units: Notice of Data

Availability

(69 FR 69864; December 1, 2004)

Docket Number OAR-2002-0056

9.0 NODA Comments

US Environmental Protection Agency 

Emissions Standards Division

Office of Air Quality Planning and Standards

Research Triangle Park, North Carolina 27711

15 March 2005
i

General Outline

1.0 INTRODUCTION AND BACKGROUND

2.0 APPLICABILITY AND SUBCATEGORIZATION

3.0 PERFORMANCE STANDARDS FOR COAL-FIRED ELECTRIC

UTILITY STEAM GENERATING UNITS

4.0 PERFORMANCE STANDARDS FOR OIL-FIRED ELECTRIC

UTILITY STEAM GENERATING UNITS

5.0 MERCURY CAP-AND-TRADE PROGRAM

6.0 MERCURY EMISSIONS MONITORING

7.0 IMPACT ESTIMATES

8.0 COMPLIANCE WITH EXECUTIVE ORDERS AND STATUTES

9.0 NODA

10.0 OTHER

Appendix A LIST OF COMMENTERS
9-i

9.0 NODA Comments

A. Electric Power Sector Modeling 

General Comments concerning Electric Power Sector Modeling 

Comment:

One commenter (OAR-2002-0056-5469) noted that the EPA NODA provides what is

stated as a summary of the model results reported by CRA in comments submitted by both the

commenter and EPRI in June 2004. In presenting its summary (Table 4 of the NODA), EPA

chose to report the EPMM emissions estimated for 2018-2019 as if they were the 2020 emissions

estimate too. This is incorrect, and hides the fact that EPMM scenarios projected that Hg

emissions would fall to 15 tons by 2020. It is extraordinary that EPA would choose to state a

completely different number in the summary table than was reported by the original investigators,

even if EPA had reason to dispute the basis for the finding of the original investigators. 

Nevertheless, even the rationale EPA provides for listing a very different emissions result than

was originally reported is wrong and reflects a misunderstanding of how optimizing models

function.

The NODA states:

“EPA notes the commenter’s projected emissions of 15 tons in 2020 appear to be an

artifact of the grouping of the 2020 run year with the model end run year of 2040. EPA

maintains that, in a leastcost solution model like EPMM, the model would solve for the

cap in the final run year grouping. Therefore, Hg emissions reported for trading scenarios

in the table below [i.e., Table 4 of the NODA] are those projected for 2019, because EPA

believes they better represent emissions in 2020.”

The commenter further stated that it is not true that optimizing models like EPMM force

emissions to reach the cap in their end year. Optimization does require that there be zero banked

emissions at the end of the model horizon, but it is perfectly possible to enter the last modeled

period (i.e., 2020-39 in this case) with a positive bank balance. If this happens, then the model

will select just enough controls for that last period so that emissions will last exactly the length of

the last period, and be exactly exhausted at the end of the terminal modeled period. For example,

if the last modeled period is 10 years long, a least-cost solution might be to enter that last 10-year

period with 10 tons in the bank, which would be used up at the rate of 1 ton per year. Controls

would be applied at the beginning of the terminal period to bring emissions to exactly 1 ton above

the final level of the cap. At the end of the 10 years, emissions would have to be reduced to

exactly the level of the cap. Thus, when the model says emissions are exactly at the cap at the

beginning of the terminal period, this is because achieving the cap by that first year (rather than by

the last year of that period) is lower-cost than the only alternative, which would be to make yet

greater reductions in one or more of the earlier periods that would enable entry into the terminal

period with a positive bank-balance.
9-ii

The commenter also noted that another way to state this is that emissions cannot be above

the final level of the cap (15 tons in this case) during any year of the terminal period unless there

is a positive balance of banked emissions at the end of the year just prior to the start of the

terminal period. This provides yet another way to demonstrate that EPA is wrong when it states

that emissions in 2020 would be closer to the level projected for 2019 than to 15 tons. Table 1

shows the emissions projected in each modeled period of EPMM for the base Hg cap scenario,

and the level of the cap that applies in each time period. The last column shows the resulting

balance in the Hg allowance bank at the end of each of the modeled periods. It is quite clear that

if emissions follow the path selected for each of the modeled periods prior to the terminal period

of 2020, then there will be no allowances in the bank at the start of 2020, and emissions must be

15 tons from 2020 onwards. This is not an “artifact” of the fact that 2020 is the first year of the

terminal model period.

Table 1. Bank Balances Under EPMM Scenario for Proposed Mercury Cap*

Year Hg Emissions

(tons per year)

Hg Cap in Same

Time Period

(tons per year)

Annual Rate of

Accumulation in

the Bank (tons

per year)

Hg Bank at

Beginning of

Period (tons)

2004-2007 44.6 na na na

2008-2009 43.3 na na na

2010-2011 34.0 34.0 0.0 0.0

2012-2014 32.2 34.0 +1.8 0.0

2015-2017 29.9 34.0 +4.1 5.3

2018-2019 23.9 15.0 -8.9 17.7

2020-2039 15.0 15.0 0.0 0.0

* Values in Table 1 are from the scenario that applies no reduction in variable O&M costs of

ACI, i.e., the standard case in Table 4 of NODA. Results are comparable for all the other

EPMM cap-and-trade scenarios reported in NODA.

It is therefore impossible to reconcile the emissions and control actions that the model

selects from 2004-2018 with any emissions level other than 15 tons starting in 2020 (and, of

course, lasting at 15 tons thereafter). If emissions in 2020 were to be 24 tons, as EPA has

incorrectly asserted, then the bank would have to be drawn down to negative 9 tons in 2020

alone. This is not how EPMM works. If EPMM were to find it cost-effective to delay

compliance with the cap beyond 2020, it would have to reduce emissions by much larger amounts

prior to 2020. It has the option to do this, but the model chooses not to. The model finds that a

time path of emissions that entails reaching exactly 15 tons by the beginning of 2020 is the leastcost solution. This may not be consistent with EPA’s IPM results, but the commenter’s June

2004 submission (see OAR-2002-0056-2929) provides an extensive explanation of the differences

in our and EPA’s model assumptions that explain that difference.

Since the preceding explanation may be difficult for non-specialists to follow, it is useful to

demonstrate that EPA is in error by employing evidence in the model runs themselves. Table 2
9-iii

lists the SO2 emissions that were reported for the same scenario, along with the caps applied. As

in Table 1, the last column shows the banked allowances (which include the amount assumed to

be in the Title IV bank just before the beginning of the first modeled year, 2004). The emissions

of SO2 do not exactly meet the SO2 cap at the beginning of 2020, as they do in the same model

run for Hg . Entering the terminal period of 2020-2039, there are 769,644 tons of SO2

in the bank. As the model does force this bank to be exactly used up by the end of that terminal

period, and at a constant level throughout that period, emissions exceeds the cap by exactly

769,644/20 tons (i.e., by 38,482 tons) in 2020 and in each of the next 20 years. Thus, a

counterexample exists in the very same model runs that EPA was summarizing to EPA’s assertion

that “the model would solve for the cap in the final run year grouping”.

Table 2. SO2 Emissions and Bank Balances Under EPMM 

Scenario for Proposed Mercury Cap*

Year SO2 Emissions

(tons per year)

SO2 Cap in Same

Time Period (tons

per year)

Annual Rate of

Accumulation in

the Bank (tons

per year)

SO2 Bank at

Beginning of

Period (tons)

2004-2007 9,340,664 9,480,000 139,336 8,000,000

2008-2009 8,100,088 9,480,000 1,379,912 8,557,344

2010-2011 6,071,281 5,086,400 -984,881 1l,317,168

2012-2014 5,552,485 5,086,400 -466,085 9,347,406

2015-2017 4.476,623 3,798,600 -1,678,023 7,949,151

2018-2019 4,871 ,319 3,798,600 -1,072,719 2,915,082

2020-2039 3,837,082 3,798,600 -38,482 769,644

* Values in Table 2 are from the scenario that applies no reduction in variable O&M costs of

ACI, i.e., the standard case in Table 4 of NODA. Results are comparable for all the other

EPMM cap-and trade scenarios reported in NODA; we use this case here because it is one for

which SO2 emissions were reported in our earlier submissions, and which EPA therefore had

the ability to review.

Nevertheless, there are some good reasons to de-emphasize reported model results

associated with the terminal model period of models such as EPMM and IPM. CRA did not

choose the time periods in EPMM with the goal of being able to report precise estimates of

emissions specifically for 2020, nor even with an expectation that any year after 2018 would have

any interest. Given that substantial emphasis has since been focused on whether the Phase II Hg

cap of 15 tons might be fully attained by about 2020, the commenter felt it is reasonable to allow

a time step for 2020 that is not the terminal time period of the EPMM model. Since release of the

NODA, the commenter added another time step to EPMM that starts in 2030 and represents the

final 20-year period (through 2049). Results for the 2030 terminal time step can be deemphasized without losing information about the likely emissions in the 2020 time frame.

The commenter ran the extended-horizon version of EPMM for the same Hg cap-andtrade assumptions that were reported in the NODA as with “improved ACI costs.” 

 provides the emissions values from the original run when 2020 was the beginning of the terminal
9-iv

model period, and from the new run which differs only in that 2030 is now the beginning of the

terminal model period. These emissions paths are illustrated in . The emissions paths are

very similar. Most importantly, emissions in 2020, even when it is not a terminal period of the

model), are still very close to the final cap of 15 tons (i.e., they are 15.4 tons). Results using a

version of EPMM where 2020 is not the terminal period further demonstrate that EPA was not

justified in replacing our reported 2020 emissions values on an ad hoc basis with our reported

2019 emissions level.

All the available models (EPMM and IPM alike) provide only an approximation of what

are emissions paths continuously changing in time because they are forced by computational

resources to simulate discrete multi-year time steps rather than the more realistic path of gradual

year-over-year emissions reductions. The actual optimal time path of emissions will be smoother,

and this means that emissions in 2020 might be somewhat higher than in 2021, and in each of the

remaining years in the 2020 time period. However, one must recall that the requirement of a nonnegative bank of Hg allowances imposes an important constraint on emissions after 2018. For

example, the EPMM model indicates that emissions in 2020-2029 would be a constant 15.4 tons. 

The bank going into that time period is 3.6 tons. Thus, even if (both cases simulate the proposed

Hg cap-and-trade scenario and assume a 2.5 percent per annum reduction in variable O and M

cost of ACI control technologies)

Table 3. Hg Emissions Projections Differing Terminal Model Periods

Terminal period

starting 2020 (June

submission)

Terminal period

starting 2030 (This

submission)

2004 44.4 44.6

2008 43.2 43.1

2010 34.0 34.0

2012 32.6 32.3

2015 29.4 28.9

2018 24.1 23.5

2020 15.0 15.4

2030 15.0 15.0
9-v

emissions in 2020 were to remain above emissions in following years of the 2020-2029 time step,

those 2020 emissions could not exceed 18.6 tons (i.e., 3.6 tons above the cap). Further, if they

were that high in 2020, then the 15 ton cap would have to be met exactly from 2021 onwards. In

other words, although ad hoc reasoning could lead one to conclude that 2020 emissions might be

as high as 18.6 tons, such ad hoc reasoning must also accept that emissions only one year later

(i.e., from 2021 onwards) must meet the Phase II cap.

Thus, modeling based on the assumptions the commenter documented in June 2004 (see

OAR-2002-0056-2929) indicates that either the Phase II cap will be met within all but a fraction

of a ton by 2020, or if it is exceeded by any significant amount in 2020, then it will be exactly

attained within one or two years after that.

Response: 

Based on the commenter's additional analysis submitted into the record, EPA agrees that

commenter's analysis projected emissions to be 15.4 tons in 2020 for the modeled Hg trading

scenario. However, we disagree with the commenter's conclusion that we misunderstand how

optimizing models function. In the NODA in which EPA summarized the commenter's analysis

submitted to the record, EPA did not state optimizing models like EPMM force emissions to

reach the cap in their end year, rather we stated that optimizing models solve for the cap. That

is to say, we agree with the commenter statement that optimization does require that there be

zero banked emissions at the end of the model horizon, i.e, solve for the cap. EPA also agrees

with the commenter that it is possible to enter the last modeled period (i.e., 2020-39 in this case)

with a positive bank balance. EPA anticipated a more gradual withdrawal of the bank given that
9-vi

additional Hg controls are being installed in the 2018-2019 timeframe. This is similar to what

EPA sees in it own modeling and what the commenter is projecting in its SO2 modeling. 

However, EPA does not dispute the additional data the commenter submitted on the bank

withdrawal in its modeling.

Comment:

One commenter (OAR-2002-0056-5469) stated that there is only one possible reason why

bank-balance accounting may not be applicable to the argument above: the so-called “safety

valve.” The concept of the “safety valve” is originally one of providing a formal, legislated ceiling

on allowance prices. It was first introduced in carbon policy proposals. EPA’s proposed rule

includes a concept that EPA calls a “safety valve,” but which would not be implemented in the

manner necessary for it to function as a price ceiling. In EPA’s proposed cap-and-trade rule in

the Clean Air Mercury Rule (CAMR), companies may “borrow” against their own future

allocations of Hg allowances if prices exceed some pre-specified amount. Borrowing against

one’s future fixed allocation is a substantially different matter than having the government issuing

as many additional allowances as might be demanded for a fixed price. The former maintains the

constraint of the cap unchanged across a set of years, whereas the latter actually loosens the cap. 

The former creates far less flexibility, because by reining in allowance prices in one year, it only

increases allowance prices (by reducing available allowances) in a later year. In all, the concept

that EPA calls a “safety valve” in its proposed rule is not a price cap at all. More importantly, it

retains a binding constraint on cumulative Hg emissions, regardless of the possible future marginal

cost of meeting that cumulative constraint. Thus, it remains correct for a discussion about the

future time path of emissions under the Hg cap-and-trade proposal to assume that sustained

negative bank balances are not cost-effective.

Response: 

EPA is not finalizing a safety valve provision in the cap-an-trade rulemaking. See final

rule preamble for further rationale.

Comment:

One commenter (OAR-2002-0056-5469) noted that the NODA states that the

commenter’s/EPRI scenarios were not performed with a safety valve. First, to the extent that the

cumulative cap remains inviolate, as described in the formal EPA proposal, the scenarios do

approximate its effect. Second, even if one were to assume a safety valve that could be

interpreted as a literal cap on Hg prices, that safety valve would not be exceeded in any scenario

the commenter ran except the one assuming no cost reduction on Hg control technology at all

during the next 15 years. Thus, CRA’s runs and results are consistent with even a true safety

valve implementation. Nevertheless, merely having the ability to borrow against one’s own future

fixed allocation would not place a ceiling on allowance prices.

Response: 

EPA agrees with the commenter.

Comment:
9-vii

One commenter (OAR-2002-0056-5469) noted that the NODA also understates the

degree of attention that CRA’s analysis gave to alternative possible rates of technological

improvement. EPA implies at p. 69869 of the NODA that CRA’s analysis included only two

alternative assumptions about the rate of technological improvement, (i.e., 2.5 percent annual

reduction in variable O&M costs and 0 percent). In fact, CRA considered five different sets of

assumptions about potential technological improvements, including none at all, and varying rates

of future reductions in variable O&M costs, and in capital costs as well as O&M costs. All of

these alternatives were presented as a set, to emphasize that the commenter were not advocating

any single assumption, but only to convey the insight that technological improvement would have

an effect on projected allowance prices (while having little or no impact on other aspects of the

policy).

Response: 

EPA was aware of the commenter other analyses, but limited the presentation of analysis

to those that offered comparisons to other commenter's analyses. EPA has considered all the

information submitted by the commenter in the final rulemaking. 

Comment:

One commenter (OAR-2002-0056-5469) noted that in OAR-2002-0056-2578, EPRI

reported on deposition patterns for 2020 that were developed with the TEAM model using unitspecific emissions projections from the EPMM model. The deposition pattern for the 15 ton

cap-and-trade scenario indicated larger deposition reductions than the MACT scenario in all

regions. It projected the largest deposition reductions concentrated in the area of the Ohio River

Valley and Middle Atlantic States, which had moderately high projected deposition under base

case conditions. These results suggested that there was no reason to conclude that the cap-andtrade policy option might create hypothetical “hot spots,” or allow hypothetically existing “hot

spots” to continue where the MACT policy option would not.

Nevertheless, EPA continues to express concerns with the possibility of hypothetical “hot

spots” persisting under a cap-and-trade program. In particular, there have been suggestions that

despite projections of broad regional reductions in deposition, there might still be a few individual

plants that are large emitters that might not individually control Hg emissions, and which could

pose a “hot-spot” concern. CRA has prepared a more detailed summary of the plant-by-plant

emissions changes in its originally-reported Hg cap-and-trade scenario. The commenter took the

unit-specific emissions for 2004 and 2020, and aggregated them to obtain plant-wide emissions,

which best represent the size of an individual utility point-source. The results of this detailed

review of the earlier EPMM .

In Figure 2, each dot represents one of the 401 coal plants in the modeled data base. They

are located on the x-axis according to the projected 2004 emissions (in kg/yr). The highest

emitting plants are those on the right side of the plot. (If the emissions of each dot are summed

up, the total is equal to EPMM’s estimated reference case US utility sector Hg emissions in 2004: 

47 tons, or 42,800 kg.) The y-axis reveals the percent Hg reduction at each plant by 2020 in the

cap-and-trade scenario, when total emissions are reduced to 15 tons, or 13,636 kg. This figure

provides a way of screening for plants that might pose a potential concern under a cap-and-trade

program for hypothesized “hot spots.” That is, the likeliest plants of concern would be those that
9-viii

are large emitters, but which either fail to control, or increase their emissions as a result of the

flexibility provided by cap-and-trade.

The set of plants that emit more than 100 kg/yr (i.e., more than 220 lb/yr) are those in the

pink triangular area of . This set contains 37 percent of all plants (150 plants), and

accounts for about 75 percent of total US emissions projected in the 2004 base year. All plants

but one in this group reduce their plant-wide emissions by at least 20 percent, and most by over

60 percent; in fact, the average projected reduction of these top 150 plants is 76 percent.

The single plant that does not reduce its emissions is a lignite-burning plant that already

has a fabric filter and wet FGD. The lignite that it uses has a relatively low Hg content. When

these attributes are combined with our assumption that ACI only reduces remaining Hg by 75

percent in a lignite plant, this plant faces a very high dollar-per-ton removal–much higher than that

projected as the marginal cost of control in the Hg allowance market when the cap has reached 15

tons. Thus, this single plant among all the top 150 emitters relies solely on allowance purchases in

response to the 15 ton cap. It is noteworthy that this plant is projected to emit the same quantity

of Hg under the proposed MACT policy option as well, because its estimated current emissions

rate meets the MACT rate limit proposed for lignite plants.

Conclusions are much the same even when we consider all plants emitting more than 50

kg/yr (i.e., more than 110 lb/yr). This set of plants includes 89 more plants that emit between 50

and 100 kg/yr (all the dots within the green rectangular area of Figure 2) as well as the 150 plants

emitting more than 100 kg/yr considered in the preceding paragraph (the dots in the pink area). 

This larger group of 239 plants accounts for 60 percent of all plants in the model database, and as

a set, they are projected to account for 90 percent of all US utility emissions in the 2004 base

year. (Otherwise stated, all the remaining plants account for only 10 percent of US emissions.)

Even when accounting for the largest-emitting plants that emit 90 percent of all utility

emissions, almost all are projected to control their emissions. The average reduction within this

larger set is 74 percent. , there are only 6 plants within this set of 239

plants that do not have a financial incentive to choose to reduce their emissions in the face of a 15

ton cap on utility emissions. Only one of the 6 is among the top 150 plants, and it was discussed

above. Of the other five:

• Two are lignite plants identical in configuration to the one described above, emitting

primarily elemental Hg (Hg0

). These two plants also have the same projected emissions

under the MACT option as under the cap-and-trade option.

• There are two plants that are projected to have a slight increase in their emissions by 2020. 

Both of these already have a wet FGD and SCR on a cold-side ESP unit. As they burn a

bituminous coal, they are assumed to obtain very large percentage reductions (i.e., 85

percent) due to the existing pollution control equipment in place. Thus, these plants face

relatively high dollars-per-ton removed from their only remaining control option, which is

to add ACI. The slight increase in Hg emissions results when these plants switch from a

high-sulfur coal to a blend with a medium-sulfur coal (in order to further reduce their SO2

emissions as the price of SO2 rises). Small increases in emissions like this are more likely

to occur on plants that already have the highest levels of co-controls. More importantly,
9-ix

however, is that these two plants also increase their emissions under the MACT option. 

That is, their current emissions rate is already below the 2.0 lb/tBtu limit required by the

proposed MACT option, and these plants have even less financial incentive to avoid minor

Hg emissions increases under the MACT option than under the cap-and-trade option. 

(EPRI’s comments on the NODA explore the local deposition implications of the Hg

emissions at these two plants. EPRI’s comments report that the projected local deposition

around these two plants actually decreases in 2020 despite the slight increase projected

from these plants individually. This is because there is so much other control being

applied to the many coal-fired sources that surround these plants, which are located in

ECAR, and those other sources also affect deposition projected within the respective 20

km squares where these plants are located.)

• The fifth plant is the lowest emitter among those that do not change their Hg emissions at

all. This plant has an existing fabric filter and wet FGD. This is a western plant burning a

blend of western bituminous and subbituminous coal. Being a western plant, it has no

incentive to add an SCR other than from Hg co-benefits, but those are low due to its use

of subbituminous coal. Being highly controlled already, it is also a relatively costly

candidate for ACI compared to other plants in the system. Like the three lignite plants,

this unit already meets its MACT standard, and so its emissions are also unchanged under

the MACT option.

Response: 

EPA generally agrees with the commenter that cap and trade is not expected to lead to

hotspots. EPA has done extensive power sector, air quality, deposition, and ecosystem modeling.

See the preamble for the rule and the Technical Support Document: Methodology Used to

Generate Deposition, Fish Tissue Methylmercury Concentrations, and Exposure for Determining

Effectiveness of Utility Emission Controls in the docket.

Comment:

The commenter (OAR-2002-0056-5460) stated that rather than providing a balanced

account of the comments EPA has received to date, the NODA instead appears to endorse those

comments that call for weaker regulations. The commenter further stated that this aspect of the

NODA is most clearly apparent in EPA’s contrasting treatment of the comments received from

the Center for Clean Air Policy (CCAP) and Cinergy concerning the costs of complying with

various regulatory approaches. See 69 Fed. Reg. at 69,867-69,868. The commenter stated that

according to the NODA, CCAP and Cinergy reached contrasting conclusions concerning the

costs and burdens associated with the CAMR. The commenter added that specifically, CCAP

concluded that EPA could impose even stricter requirements with relatively modest cost

implications, while Cinergy concluded that EPA’s existing proposal, to say nothing of stricter

regulations, was already “unrealistic.” See 69 Fed. Reg. at 69,867-69,868. The commenter

stated that rather than describing those contrasting conclusions in a balanced manner, EPA instead

appears to endorse Cinergy’s conclusion. The commenter stated that the NODA states that

CCAP’s conclusion is CCAP’s “opinion” but includes no such disclaimer for Cinergy’s

conclusion. Compare 69 Fed. Reg. at 69,867 (3d Column) with 69 Fed. Reg. at 69,868 (3d

Column). The commenter further stated that EPA also appears to accept at face value Cinergy’s

self-serving assertion that a MACT standard of 0.88 lbs/TBtu is “stringent.” 69 Fed. Reg. at
9-x

69,868 (1st Column). According to the commenter, such a standard is approximately four times

weaker than the standard that EPA should impose absent subcategorization by coal rank. 

 (explaining that EPA could set a MACT standard of 0.2 lbs/TBtu,

absent subcategorization); see also id. at A12-13 (discussing the MACT standards that should be

imposed if EPA subcategorizes). The commenter stated that in these circumstances, and in light

of its treatment of CCAP’s conclusions, the NODA should have clarified that it is simply

Cinergy’s “opinion” that a standard of 0.88 lbs/TBtu is stringent. But, the commenter stated, the

NODA contains no such explanation and Cinergy’s own comments (see OAR-2002-0056-4318)

provide no reason to accept Cinergy’s assertion as fact.

The commenter stated that EPA should not have used the NODA to present an

unbalanced description of the comments received in response to the proposed CAMR. In

addition, the commenter also objected to EPA’s failure to provide sufficient information about the

power sector modeling runs it has conducted. The commenter noted that On March 19, 2004,

Massachusetts Attorney General Thomas F. Reilly submitted a public record request to EPA

regarding its Integrated Planning Model (IPM) runs. The commenter further noted that in

response, EPA has withheld hundreds of documents alleging that they fall within Exemption 5 of

the Freedom of Information Act. See Exhibit B (Letter from Byron R. Brown, Assistant General

Counsel, EPA, to James R. Milkey dated December 9, 2004). (See OAR-2002-0056-5460.) The

commenter stated that, significantly, several of the documents EPA is withholding appear to

contain factual information bearing directly on the NODA’s discussion of power sector modeling

(and may be relevant to the CAMR for other reasons as well). The commenter further stated that

EPA’s failure to make those documents available to the public in the CAMR docket is

problematic for the following reasons: First, if EPA has ignored the documents, it may have acted

in an arbitrary and capricious manner in developing the CAMR. The commenter stated that,

alternatively, if it has considered the documents, its failure to make the documents available for

public review and comment may violate both the Clean Air Act and the Administrative Procedure

Act. See 42 U.S.C. § 7607(d)(3) (“All data, information, and documents. . . on which the

proposed rule relies shall be included in the docket. . .”); Portland Cement Ass’n v. Ruckelshaus,

486 F.2d 375, 393 (D.C. Cir. 1973) (“It is not consonant with the purpose of a rule-making

proceeding to promulgate rules on the basis of inadequate data, or on data that, [to a] critical

degree, is known only to the agency.”) The commenter stated that, accordingly, EPA should

make the documents available in the CAMR docket and should explain how, if at all, it has used

the documents in developing and proposing the CAMR.

Response:

EPA's presentation of summaries of the commenters data was not meant as an

endorsement to any of the commenters data. EPA will address the commenters concerns related

to document availability in the FOIA process.

Comment:

The commenter (OAR-2002-0056-5460) noted that EPA contends that power sector

modeling is relevant to its obligation under Section 112 of the Clean Air Act to set

beyond-the-floor standards based on an analysis of cost, non-air quality health and environmental

impacts and energy impacts. See 69 FR at 69,866 (2nd column). But, the commenter stated, the

NODA does not adequately explain how power sector modeling is relevant to assessing non-air
9-xi

quality health impacts, non-air quality environmental impacts or energy impacts. The commenter

further stated that, indeed, the NODA’s focus on comments concerning the alleged cost of certain

control measures creates the impression that power sector modeling is relevant solely to cost. 

Therefore, the commenter reiterated that EPA is required to also consider non-air quality health

and environmental impacts in setting beyond-the-floor standards pursuant to Section 112.

The commenter stated that it also bears emphasis that industry commenters have an

incentive to overstate the costs of complying with environmental regulations. The commenter

further stated that, indeed, various studies have suggested that the costs of complying with

environmental regulations are usually less than what industry commenters estimated in advance. 

The commenter added that, accordingly, EPA should look skeptically upon industry cost

estimates. The commenter stated that one reason industry cost estimates may be too high is the

failure to anticipate technological innovations that regulations will inspire. For a fuller discussion

of this issue, the commenter referred EPA to the CAMR comments of the Northeast States for

Coordinated Air Use Management (NESCAUM), OAR-2002-0056-2888, and to NESCAUM’s

September 2000 report entitled Environmental Regulation and Technology Innovation:

Controlling Mercury Emissions from Coal-Fired Boilers, a copy of which is attached as Exhibit D

(See OAR-2002-0056-5460).

Response:

EPA's approach for the final rulemaking is to establish Hg reductions under

section 111 cap through a cap-and-trade mechanism. EPA agrees with the commenter that

technology innovation is likely to reduce future control costs. To that end, EPA has included the

examination of technology improvement in its analysis of the costs of the rulemaking. See

sensitivity analysis in Chapter 7 of final CAMR Regulatory Impact Analysis.

Comment:

The commenter (OAR-2002-0056-5460) stated that none of the information that EPA has

requested is relevant to determining the proper MACT floor under Section 112 of the Clean Air

Act–a fact that EPA itself appears to recognize. See 69 Fed. Reg. 69,864-69,866 (2nd column)

(explaining why EPA believes the information it seeks concerning power sector modeling and Hg

speciation is relevant), id. at 69,872 (2nd Column) (same for the information EPA seeks

concerning its proposed revised benefits assessment methodology). The commenter stated that,

thus, the NODA does not address one of the most fundamental defects in the CAMR. The

commenter further stated that, indeed, the NODA does not even mention the MACT floor issue. 

The commenter stated that by omitting mention of that issue, EPA has presented an incomplete

account of the issues raised in the CAMR comments. The commenter also stated that in addition,

until EPA calculates a proper MACT floor pursuant to Section 112, both its prior analysis and its

proposed new analysis of the benefits of the CAMR will remain logically, factually and legally

flawed.

The commenter stated that the NODA also fails to address the legal problems inherent in

EPA’s alternative Section 111 regulatory proposal. The commenter further stated that, instead, it

focuses on a variety of technical issues that are at best a distraction from the central problems

with the CAMR. According to the commenter, for example, the NODA contains an extensive

discussion of comments EPA has received concerning the relationship between the CAMR and
9-xii

EPA’s proposed Clean Air Interstate Rule (CAIR). See 69 Fed. Reg. at 69,868-69,871. But,

according to the commenter, the EPA is required to develop lawful regulations pursuant to

Section 112 of the Clean Air Act regardless of what its models, or any commenters’ models,

reveal about the consequences of CAIR. The commenter added that, equally important, EPA

recently announced that it is delaying the implementation of the CAIR indefinitely. See Exhibit A

(D. Samuelsohn, “Bush Holds CAIR Release As Congress Shows Interest in Clear Skies,”

Greenwire, Dec. 13, 2004) (also available at

http://www.eenews.net/Greenwire/Backissues/121304/121304gw.htm ). The commenter stated

that, accordingly, EPA should not base either its Section 112 or Section 111 approach on

estimates of what CAIR might or might not accomplish.

Response:

EPA issued the NODA to take further comment on commenter's analyses submitted to

docket after proposal and their impact on final rulemaking analyses. EPA took comment on its

regulatory approach in the NPR and SNPR.

1. In some analyses, EEI assumed a 2.5 percent annual improvement in variable

operating costs for ACI. Is it appropriate for an economic forecast to assume an

improvement in costs over time and if so, what level of improvement in costs should

be assumed?

Comment:

One commenter (OAR-2002-0056-5464) believes that EPA’s modeling effort was

deficient in that it assumes that technology will not advance and that the costs will not decrease

and that as other EPA regulatory efforts have demonstrated, advances in control technology for

Hg are occurring at great speed and costs will likely continue to decline. Additionally, the model

did not consider sufficient control options, including precombustion controls, fabric filters and

improvements in the functioning of existing controls. These options would provide a range of

reductions, which were not accounted for in the model.

The commenter’s concerns about the deficiencies of some of the modeling in the NODA

and the agency’s own effort are among the reasons they believed EPA should have conducted

additional modeling of more effective MACT scenarios, with thorough discussions with the

stakeholders about realistic and up-to-date inputs and assumptions.

Response:

EPA has conducted modeling analysis for the final rule under section 111. EPA's IPM model,

due to model run time constraints, has to limit the number of control retrofit options available. 

EPA has included the examination of technology improvement in its analysis of the costs of the

final rulemaking. See sensitivity analysis in Chapter 7 of final CAMR Regulatory Impact

Analysis.

Comment:

One commenter (OAR-2002-0056-5446) stated that, typically, it is reasonable to assume

that the costs associated of with technology will fall as the technology becomes more widely
9-xiii

deployed and operational experience is obtained. However, it is premature to assume that

dedicated Hg control technology will follow this trend in the years immediately following its

introduction. In this case, the introduction of new regulation is likely to dramatically increase

demand for the dedicated controls and sorbents required and it is likely that in the initial period

supply will be not adequate for this new level of demand. Scarcity value will result in a

corresponding increase in price.

Given the time value of money these near term impacts may have a significant impact on

the net present cost of the proposed regulations. If the EPA decides it needs to more accurately

represent the evolution of cost with time it must also capture the impact of potentially dramatic

changes in the balance of supply and demand and the corresponding price impacts for both control

technologies and sorbents such as activated carbon. Absent a detailed assessment of supply and

demand the EPA should not assume that prices decline.

Response:

EPA has included the examination of technology improvement in its analysis of

the costs of the rulemaking. See sensitivity analysis in Chapter 7 of final CAMR Regulatory

Impact Analysis. Given that the first phase cap is set at 38 tons, the Hg co-benefit reductions

expected under CAIR, EPA does not anticipate demand impacts for control technologies and

sorbents. EPA's analysis of past programs, like the NOx SIP call, indicate the markets respond

to the demand for materials. See Engineering and Economic Factors Affecting the Installation

of Control Technologies for Multipollutant Strategies, EPA, October 2002, in docket.

Comment:

One commenter (OAR-2002-0056-5488) stated that in the NODA, EPA invites comment

on results from several alternative analyses submitted in comments on its proposed Hg rule and

additionally invites “updated information on issues that may be relevant to assessing the

assumptions employed in our power sector modeling.” As a preliminary matter, it should go

without saying that regulatory analyses performed by stakeholders are no substitute for the

exercise of independent judgment by EPA. While EPA should consider comments submitted by

stakeholders, it is a bedrock principle of administrative law that the agency must independently

exercise its expertise to establish the grounds for its decisions. The commenter addressed their

comments primarily to EPA’s analyses, rather than those of the outside groups that are called out

in the NODA.

EPA’s power sector modeling is fundamentally flawed because it ignores recent advances

in control technology that have already occurred and moreover assumes that no advances will

occur over the time frame of the regulations. The modeling is also overly restrictive in the control

options it allows.

In projecting control costs over the time frame of this proposal, EPA must incorporate benefits of

technological advances in control cost projections, especially given the fact that Hg control

technology is already advancing very rapidly. In fact, OMB guidelines require that cost estimates

used in agency rulemakings reflect “credible changes in technology over time.” As described

above, major advances in control technology accompanied by dramatic reductions in control costs

have been demonstrated over the past year, rendering obsolete some of the most critical
9-xiv

assumptions in EPA’s power sector modeling. EPA is fully aware of many of these advances. 

Consequently, EPA’s assumption that control costs will not change over the next decade is clearly

untenable. EPA must adjust the starting point for its control cost estimates to reflect current

reality, and further must incorporate a reasonable rate of improvement in its forecasts. Because

empirical estimates of the rate of improvement in control costs over time are sparse, EPA should

begin with reasonable base case estimates of improvement rates and conduct sensitivity analyses

to examine the importance of this parameter. Based on experience with similar control programs

and the advances in Hg control technology that have already occurred, a default assumption of no

improvement is clearly unreasonable.

Modeling performed for the Clean Air Task Force (CATF) and other environmental

groups demonstrates that much more stringent MACT emissions standards can be cost-effectively

achieved than those proposed by EPA, even utilizing EPA’s misguided scheme of setting

disparate standards by coal rank. Furthermore, even with a cursory assessment of benefits, the

CATF analysis shows that the benefits of the more stringent standards they examined would

outweigh the costs. EPA should take this comment into account in revising its own power sector

modeling, by exploring alternative levels of stringency for the MACT standards. EPA must go

beyond the CATF analysis, however, and consider stringent standards for all ranks of coal and

coal blends, for new and existing units.

Response:

EPA has conducted modeling analysis for the final rule under section 111. EPA has

included the examination of technology improvement in its analysis of the costs of the final

rulemaking. See sensitivity analysis in Chapter 7 of final CAMR Regulatory Impact Analysis.

Comment:

One commenter (OAR-2002-0056-5502) stated that technological advances anticipated

from specific on-going research programs could reduce the costs of the proposed Cap and Trade

rule by up to 30 percent, but would provide no significant reduction in the costs of the alternative

MACT approach.

Response:

EPA has conducted modeling analysis for the final rule under section 111. EPA has

included the examination of technology improvement in its analysis of the costs of the final

rulemaking. See sensitivity analysis in Chapter 7 of final CAMR Regulatory Impact Analysis.

Comment:

One commenter (OAR-2002-0056-5535) stated that EPA requested comment on whether

the economic model should account for improvement in technology costs over time. The

commenter believed that it should. The commenter noted in their comments on the proposed

rule, the IPM assumes that control technologies are static, leading to an overestimate of control

costs. In particular EPA should account for the expected decrease in the cost of activated carbon,

as this expense comprises the bulk of variable operating costs. EPA has previously stated that the

cost of activated carbon is expected to decrease by 40 percent with widespread implementation of

the technology. In addition, the IPM should be adjusted to account for the lower quantity of
9-xv

halogentated carbons that would be needed and the lower quantity of solid waste generated. 

Also, because the brominated carbons do not affect the quality of fly ash for use in concrete, EPA

must revise the assumptions in the IPM related to loss of revenue from flyash sales.

Response:

EPA has conducted modeling analysis for the final rule under section 111. EPA has

included the examination of technology improvement in its analysis of the costs of the final

rulemaking. EPA has performed a sensitivity analysis assuming the introduction of of a second

ACI option using advanced sorbents. See sensitivity analysis in Chapter 7 of final CAMR

Regulatory Impact Analysis.

Comment:

One commenter (OAR-2002-0056-5497) stated that it was inappropriate for an economic

forecast to assume a decrease in variable costs over the foreseeable future for Hg controls. With

respect to ACI, activated carbon reagent now costs $0.50/lb and is unlikely to decrease to any

significant degree. The business of manufacturing this reagent is already mature and this is not a

situation where a product with a limited production volume and history is likely to experience

decreases in unit cost. Indeed, activated carbon already has significant existing demand and the

implementation of ACI at power plants is more likely to increase its unit cost. EPA estimated in

2002 that demand for both activated and granular carbon to be 227,000 tons in 2004, in

comparison to a manufacturing capacity of 233,000 tons annually. EPA also estimated that about

70 GW of coal-fired capacity would retrofit ACI, requiring an additional 220,000 tons of

activated carbon. Doubling the demand from already high production rates could well increase

and not decrease the unit cost of activated carbon. For this reason, an assumption in EPA’s

model that activated carbon costs will remain the same over time may underestimate the actual

costs.

Response:

EPA has conducted modeling analysis for the final rule under section 111. EPA has

included the examination of technology improvement in its analysis of the costs of the final

rulemaking. EPA has performed a sensitivity analysis assuming the introduction of advanced

sorbents, leading to lower capital costs not variable operating costs. See sensitivity analysis in

Chapter 7 of final CAMR Regulatory Impact Analysis. With regard to demand for activated

carbon, EPA notes that the report cited by the commenter indicates that markets respond to the

demand for materials, much like under the NOx SIP call supply for catalyst increased with

demand. See Engineering and Economic Factors Affecting the Installation of Control

Technologies for Multipollutant Strategies, EPA, October 2002, in docket.

Comment:

One commenter (OAR-2002-0056-5469) noted that in its June 2004 submission (see

OAR-2002-0056-2929), Charles River Associates provided results for a set of five different

possible rates of technological change. These included a 2.5 percent and 4 percent p. a. rate of

reduction in our base assumptions for variable O and M costs on the sorbent-based control
9-xvi

technology (referred to generically as ACI here), and a 1 percent and 2 percent p. a. rate of

reduction in our base assumptions for capital costs, and variable and fixed O&M. The first two

cases were intended to reflect future reductions in the costs of sorbent and/or injection rates

(lb/Macf) needed to achieve each level of percentage removal through an advanced sorbent

technology. The second two cases reflected future reductions also in the cost of the baghouse

technology that is assumed necessary in our base assumptions in order to achieve the lowest $/ton

removed for percentage reductions in the 60-90 percent range (i.e., TOXECON TM). This could

imply refinements in design or materials of the baghouse, or possible development of more costeffective alternatives that would still entail initial costs, but for some less costly alternative to a

COHPAC baghouse that still reduces the sorbent injection rates than are currently necessary to

achieve high percentage reductions in front of an ESP only. Finally, a 0 percent rate of

improvement was also considered.

The commenter suggested that these scenarios presented a range of possibilities for

exploring how much the prospect of technological improvement might affect results. It is almost

certain that some degree of cost reduction will occur if time is permitted, and that the likely

reductions will be increasing with time. Charles River Associates did not suggest that anyone of

these is a most likely case, but the range of prospects is quite broad, and it provides a good test

bed for understanding the impacts of technical change on costs of a Hg cap-and-trade policy that

provides for a gradual phase-in of control installations.

In its June submission (see OAR-2002-0056-2929), the commenter reported that the

marginal costs of controls, especially in later years, were quite sensitive to any rate of

improvement, and that estimated total costs of controls also fell. These are not surprising results,

and the main interest was the degree to which allowance prices might be keep below levels such

as that set by EPA’s proposal as a “safety valve” price of $31,500 (1999$). With any but the

worst case assumption of zero technological improvement, marginal costs of control were

projected to remain below that price through 2020, even when emissions achieve the 15 ton level. 

 reproduces the allowance price sensitivities that the commenter reported in the June

submission.

Table 8. Projected Mercury Allowance Prices Under Alternative Assumptions of Rates of

Improvement in Hg Control Technology

($/lb Hg, in 1999$; 2020 marks start of terminal period in model used)

Year

Annual Rate of Technological Improvement on Activated Carbon Infection Control

Methods

0% 1.5% 2.5% 2.5% 4.0%

Capital and O&M Capital and O&M Variable O&M

only

Variable O&M

only

2010 $22,108 $21,850 $22,345 $20,854 $20,090

2012 $21,654 $19,623 $17,904 $18,727 $17,420

2015 $25,826 $23,404 $21,353 $22,335 $20,775

2018 $30,824 $27,933 $25,485 $26,657 $24,796

2020 $37,285 $28,495 $23,611 $32,536 $30,951
9-xvii

The glide paths of all five of the cases considered in our June 2004 submission are not

different enough to merit a graph. They all attained Hg emissions of 15 tons by 2020. A

conclusion that the commenter can draw from this set of runs is that technological change is more

likely to affect costs, and particularly marginal costs, of meeting a cap, but that it does not much

alter the glide path between Phase I and Phase II of a policy.

Response:

EPA agrees with the commenter that Hg technology costs are likely to improve over time.

EPA has conducted modeling analysis for the final rule under section 111. EPA has included

the examination of technology improvement in its analysis of the costs of the final rulemaking. 

EPA has performed a sensitivity analysis assuming the introduction of advanced sorbents,

leading to lower capital costs. See sensitivity analysis in Chapter 7 of final CAMR Regulatory

Impact Analysis. 

2. The IPM has limited Hg control retrofit options. Currently, it assumes that Hg

reductions are achieved only through SCR and FGD or ACI (with or without fabric

filter). Should other control options be considered(e.g., retrofit of fabric filters and

electrostatic precipitators, pre-combustion controls, and optimization of SO2 or NOx

controls?

Comment:

One commenter (OAR-2002-0056-5464) states that one of their biggest concerns

regarding the NODA is that it focuses undue attention on the IPM modeling that commenters

submitted and their related inputs, assumptions, results and, particularly, the cost of control,

control efficiency and the technical feasibility of various control options. The discussions about

cost, especially, distract from the most important point of all: the Clean Air Act clearly calls for

emissions of hazardous air pollution from electric utilities to be regulated under Section 112,

which requires EPA to establish a MACT standard that reflects at least “the average emission

limitation achieved by the best performing 12 percent of the existing sources” or “the emission

control that is achieved in practice by the best controlled similar source.” Consideration of cost is

inappropriate during the determination of the MACT floor and should be used only in calculations

of MACT levels that are beyond the floor. Therefore, the cost calculations articulated in the

NODA should not be part of the determination of the MACT floor for electric utilities.

To the extent that some of the modeling is useful in considering MACT options beyond

the floor, however, the commenter offers some general observations about what is contained in

the NODA.

The commenter does not believe the information contained in the NODA portrays the

tremendous advancements in control technology that have come about recently, even since the

proposal was issued. As up-to-date data show, controls that can result in significant, MACT-level

reductions are not only technically feasible, but are also cost-effective and commercially available. 

These controls include low NOx burners, activated carbon injection (ACI) with various sorbents,

selective catalytic reduction, enhanced wet scrubbers, fabric filters and acid gas controls for

reducing Hg emissions. These are already available for installation on coal- fired utility boilers for

all types of coal.
9-xviii

Unfortunately, several of the modeling results summarized in the NODA do not account

for recent technological developments (e.g., halogenated sorbents) or adequately consider control

options (e.g., low NOx burners or fabric filters) in their assumptions and calculations. As a result,

their conclusions do not reflect what is currently possible and skew cost and emission reduction

estimates.

The ACI-type of control, which is currently commercially available, has low capital cost

and minimal maintenance requirements. There have been recent improvements in sorbents that

result in significant cost reductions and increased control efficiency. ACI can reduce Hg

emissions by over 90 percent, can be installed quickly and is effective on both bituminous and

subbituminous coals.

Response:

EPA is finalizing a rule under Section 111 and has conducted modeling analysis for the

final rule. EPA's IPM model, due to model run time constraints, has to limit the number of

control retrofit options available. EPA agrees with the commenter that Hg technology costs are

likely to improve over time. EPA has included the examination of technology improvement in its

analysis of the costs of the final rulemaking. EPA has performed a sensitivity analysis assuming

the introduction of advanced sorbents, leading to lower capital costs. See sensitivity analysis in

Chapter 7 of final CAMR Regulatory Impact Analysis. The Agency's position on the state of Hg

technology is contained in the EPA 's Office of Research and Development whitepaper (see

Control of Emissions from Coal-Fired Electric Utility Boilers: An Update, EPA/Office of

Research and Development, March 2005).

Comment:

One commenter (OAR-2002-0056-5332) noted that EPA indicates in the NODA that “due

to model size considerations, limited knowledge on achievable levels of Hg control, and limited

know ledge on assessing the full impact of the Hg speciation profile on control,” the IPM

modeling it has performed assumes Hg reductions are achievable only through use of SCR and

wet FGD, or ACI. The commenter understands that model size considerations impose limitations

on the number of control options that can be analyzed. However, since at least some stakeholders

are questioning whether ACI should be considered to be a commercially available technology

prior to 2010 (see discussion below), limiting the modeling to these two control options may not

provide a representative range of achievable Hg emissions reductions and control costs.

The commenter suggested that the model should include, at a minimum, retrofitting plants

with fabric filters as an available control option. According to EPA’s own analysis of its extensive

ICR database, fabric filters are capable of achieving an average of 90 percent Hg removal on units

burning bituminous coal and over 70 percent removal on units burning subbituminous coal. 

Moreover, no one would question the commercial availability of this technology.

A host of other options are still undergoing testing and only preliminary performance and

cost data are available. These include: (1) optimization of existing SO2 and NOx controls; (2)

pre-combustion controls (e.g., fuel cleaning and fuel blending); (3) alternative sorbents (e.g.,

halogenated activated carbon, non-carbon based sorbents); (4) back-end additives and oxidation

catalysts; and (5) multi-pollutant technologies. In light of the ongoing testing of these control
9-xix

options and considering model size limitations, the commenter supports the decision not to

include these options in the modeling analyses.

Response:

EPA's IPM model, due to model run time constraints, has to limit the number of control

retrofit options available. EPA agrees with the commenter that Hg technology costs are likely to

improve over time. EPA has included the examination of technology improvement in its analysis

of the costs of the final rulemaking. EPA has performed a sensitivity analysis assuming the

introduction of second ACI option, using advanced sorbents, leading to lower capital costs. See

sensitivity analysis in Chapter 7 of final CAMR Regulatory Impact Analysis. The Agency's

position on the state of Hg technology is contained in the EPA 's Office of Research and

Development white paper (see Control of Emissions from Coal-Fired Electric Utility Boilers: An

Update, EPA/Office of Research and Development, March 2005).

Comment:

One commenter (OAR-2002-0056-5484) stated that in the NODA, EPA asks for updated

information on Hg control options such as activated carbon injection (with and without fabric

filters), including the time line for commercialization, cost, balance of plant impacts, and

performance. To that end, the commenter commissioned RMB Consulting and Research, Inc., to

develop the report entitled, “The Potential Effect of Activated Carbon Injection on Coal-Fired

Power Plant Operation.” This report details the operational difficulties associated with activated

carbon injection, both with and without a fabric filter. It concludes that these balance-of-plant

impacts will limit the applicability of activated carbon injection, especially into existing

electrostatic precipitators and bag houses.

Response: 

The Agency's position on the state of Hg technology, including ACI, is contained in the

EPA 's Office of Research and Development white paper (see Control of Emissions from CoalFired Electric Utility Boilers: An Update, EPA/Office of Research and Development, March

2005).

Comment:

One commenter (OAR-2002-0056-5559) stated that EPA should consider adjusting the

Hg control levels for several technologies in the IPM model to reflect optimal control. For

example, fabric filters are effective at controlling all forms of Hg species. However, decreasing

flue gas temperatures and increasing exhaust gas contact time with the filter cake can further

enhance elemental Hg control. Therefore, the control levels assumed in the IPM model for fabric

filters should be higher than the 72 percent and 90 percent average control levels determined by

the 1999 ICR data respectively for sub bituminous and bituminous fired units.

The IPM control options need to be expanded to include dedicated and integrated Hg

control technologies. At the minimum, a fabric filter operating at optimal Hg control levels

should be an available option for new and existing utility units as a dedicated control technology. 

Integrated Hg control technologies that should be added include the addition of sorbent injection

and oxidizing technologies in conjunction with new and existing control systems.
9-xx

The IPM model should also be improved by inclusion of recently tested control options.

One prime example is the development of brominated activated carbon by Sorbent Technologies. 

This sorbent has demonstrated very high Hg reductions at a cost lower than activated carbon

regardless of Hg speciation or control system. This sorbent is also available in a form compatible

with cement fly ash re-use. The availability of this sorbent and other injection materials with

similar outcomes such as sodium tetrasulfide and ADVACATE multi-pollutant sorbent support

inclusion into the IPM model. Similarly, EPA needs to incorporate advancements in oxidation

catalysts and agents into the IPM model.

Response: 

EPA's IPM model, due to model run time constraints, has to limit the number of control

retrofit options available. The ACI option in EPA' s IPM includes the addition of a pulse-jet

fabric filter to achieve 90% control. EPA has included the examination of technology

improvement in its analysis of the costs of the final rulemaking. EPA has performed a sensitivity

analysis assuming the introduction of second ACI option using advanced sorbents, leading to

lower capital costs. See sensitivity analysis in Chapter 7 of final CAMR Regulatory Impact

Analysis. The Agency's position on the state of Hg technology is contained in the EPA 's Office

of Research and Development white paper (see Control of Emissions from Coal-Fired Electric

Utility Boilers: An Update, EPA/Office of Research and Development, March 2005).

Comment:

One commenter (OAR-2002-0056-5591) stated that injecting a sorbent such as powdered

activated carbon, bromine, polysulfides, or other sorbent into the flue gas represents a relatively

simple approach to controlling Hg emissions from coal-fired boilers. The gas-phase Hg in the flue

gas contacts the sorbent and attaches to its surface. The sorbent with the Hg attached is then

collected by the existing particle control device, either an electrostatic precipitator (ESP) or fabric

filter (FF).

The air pollution control industry already has considerable experience with the

implementation of Hg controls for other industrial sectors. Sorbent injection has been

commercially proven to augment the removal of Hg in waste-to-energy plants. Experience

controlling Hg emissions has been gained in more than 60 U.S. and 120 international

waste-to-energy plants that burn municipal or industrial waste or sewage sludge. For the past two

decades, sorbent injection upstream of a baghouse has been successfully used for removing Hg

from flue gases from these facilities. Other reagents used include activated carbon, lignite coke,

sulfur containing chemicals, or combinations of these compounds. The Hg control experience

gained from the municipal and industrial waste combustors demonstrates that the air pollution

control industry has been able to control Hg in the past and is able to apply their expertise to the

electric power sector.

Powerspan Corporation’s Electro-Catalytic Oxidation (ECO) is an integrated

multipollutant control technology that achieves major reductions in emissions of nitrogen oxides

(NOx), sulfur dioxide (SO2), fine particulate matter (PM2.5), and Hg. The technology also reduces

emissions of other air toxic compounds and acid gases such as arsenic, lead, and hydrochloric acid

(HCl). ECO produces a commercial fertilizer co-product, reducing operating costs and avoiding

landfill disposal of waste.
9-xxi

ECO is situated downstream of a power plant’s existing electrostatic precipitator (ESP) or

fabric filter. The system consists of three gas-processing steps, including a barrier discharge

reactor, an ammonia-based wet scrubber, and a wet ESP. The barrier discharge reactor oxidizes

SO2, NOx, and Hg; the ammonia scrubber removes SO2, NO2, and oxidized Hg creating an

ammonium sulfate nitrate solution; and the wet ESP captures acid aerosols, fine particulate

matter, and oxidized Hg.

Liquid effluent produced by the scrubber contains dissolved ammonium sulfate nitrate

(ASN) salts, along with Hg and captured particulate matter. The ASN solution is sent to a

co-product recovery system, which includes filtration to remove ash and a sulfur impregnated

activated carbon adsorption bed, which removes Hg from the effluent stream. The Hg and spent

activated carbon are disposed of as hazardous waste. The treated co-product stream, free of Hg

and ash, can be used directly in liquid form or processed to form ammonium sulfate nitrate

fertilizer in crystalline or granular form.

KFx, Inc. has a patented and proven pre-combustion technology that transforms low-cost,

low-grade western coal (e.g., lignite or subbituminous) into a clean, affordable, efficient energy

source, called K-Fuel. K-Fuel pre-combustion technology applies heat and pressure to boost the

heat value of subbituminous coal and lignite by 30-55 percent, from approximately 8,000-8,800

Btu/lb to 11,00011,500 Btu/lb, optimizing combustion in a manner that produces more generation

output per ton of coal while lowering emissions. Moisture in the coal can be reduced by as much

as 80 percent from approximately 30 percent in the feedstock to seven percent in K-Fuel.

Similar to post combustion SO2, NOx, and PM controls, Hg emission reductions from the

K-Fuel technology are a co-benefit of the pre-combustion process. K-Fuel provides a

pre-combustion Hg removal solution, reducing Hg content by up to 70 percent or more. In

addition to Hg reductions, K-Fuel also reduces emissions of SO2 and NOx.

Response:

EPA agrees with the commenter that there are likely many technology advances in the

control of Hg. EPA has performed a sensitivity analysis assuming the introduction of second

ACI option using advanced sorbents, leading to lower capital costs. See sensitivity analysis in

Chapter 7 of final CAMR Regulatory Impact Analysis. The Agency's position on the state of Hg

technology is contained in the EPA 's Office of Research and Development white paper (see

Control of Emissions from Coal-Fired Electric Utility Boilers: An Update, EPA/Office of

Research and Development, March 2005).

Comment:

One commenter (OAR-2002-0056-5475) stated that it recommends modification of the

IPM modeling with respect to using additional control options. Additional control options (e.g.,

retrofit of fabric filters and electrostatic precipitators, brominated activated carbon injection)

should be considered in EPA’s power sector modeling. This commenter believes that the current

approach, which only takes into account selective catalytic reduction (SCR), flue gas

desulfurization (FGD), and activated carbon injection (ACI), underestimates the benefits achieved

by other technologies. Consideration of additional controls in the modeling would yield more
9-xxii

realistic results.

Response: 

EPA agrees with the commenter that there are likely many technology advances in the

control of Hg. EPA has performed a sensitivity analysis assuming the introduction of second

ACI option using advanced sorbents, leading to lower capital costs. See sensitivity analysis in

Chapter 7 of final CAMR Regulatory Impact Analysis. 

Comment:

One commenter (OAR-2002-0056-5446) stated that EPA should consider the addition of

other control options such as fabric filters and ESP’s where the performance of these technologies

can be sufficiently well characterized for the purpose of a regulatory decision.

EPA should not model control options that have not been reasonably demonstrated at an

appropriate scale and over the range of operating conditions that a real plant will encounter. 

Short-term field tests or demonstration projects are an inadequate basis for regulatory decisions.

The EPA should not include pre-combustion removal technologies unless there has been

adequate flue gas testing at sufficiently representative generating plants to ensure that

performance can be adequately characterized. Given the uncertainties and complexities of Hg flue

gas chemistry it is inappropriate to assume that reductions in coal Hg content achieved in small

scale testing will reflect the reductions flue gas Hg content that may be achieved if and when

potential pre-combustion technologies are commercialized.

The commenter said that it would be arbitrary and unreasonable to base an emissions

standard on the hypothetical performance of unproven technology.

Response:

EPA has performed a sensitivity analysis assuming the introduction of second ACI option

using advanced sorbents, leading to lower capital costs. See sensitivity analysis in Chapter 7 of

final CAMR Regulatory Impact Analysis. The Agency's position on the state of Hg technology is

contained in the EPA 's Office of Research and Development white paper (see Control of

Emissions from Coal-Fired Electric Utility Boilers: An Update, EPA/Office of Research and

Development, March 2005).

Comment:

One commenter (OAR-2002-0056-5510) stated that absent a rational basis, EPA should

not make assumptions about reduced capital and maintenance and operating costs for ACI. 

Alternatively, they believe that EPA should model a case where demand, coupled with supply

constraints, dries up capital and operating costs, in particular for the activated carbon sorbent.

World consumption of activated carbon is expected to increase by 4 percent per year from

its current level of 750,000 ton/year, effectively using up planned production capacity increases by

2005. Two-thirds of the planned capacity expansion is in China or Southeast Asia, while
9-xxiii

production facilities in the U.S. are being shut down. The availability and cost of activated carbon

is significant because all of the modeling results EPA presents in the NODA assume the

application of ACI to meet the 2010 compliance requirements, applied to 10 GW to 120 GW of

generating capacity. At a 10 lb/MM SCF treat rate, this would require 60,000 to 700,000 lb/year

of activated carbon. Therefore, there is the potential that demand for activated carbon in the U.S.

could create supply shortages and corresponding price increases.

EPA should not model control options that have not been demonstrated on a commercial

basis. As noted in our comments dated, June 29, 2004, this does not mean a control technology

that a vendor is willing to sell, but a technology that performs in a predictable manner when used

with boilers of various designs over the range of operating conditions that the plant will

encounter. Short-term field tests or demonstration projects are not sufficient to conclude that a

technology is commercially available. Modeling based on the hypothetical performance of

unproven technologies will produce speculative results and cannot be used to determine the

performance of the technology for specific units with a high degree of confidence. Such

information should not form the basis for regulatory decisions.

Response:

Given that the first phase cap is set at the Hg co-benefits of CAIR, EPA does not project

significant amount of ACI to be retrofitted until the 2018 timeframe. With regard to demand for

activated carbon, EPA notes that markets respond to the demand for materials, much like under

the NOx SIP call supply for catalyst increased with demand. See Engineering and Economic

Factors Affecting the Installation of Control Technologies for Multipollutant Strategies, EPA,

October 2002, in docket. The Agency's position on the state of Hg technology is contained in the

EPA 's Office of Research and Development white paper (see Control of Emissions from CoalFired Electric Utility Boilers: An Update, EPA/Office of Research and Development, March

2005).

Comment:

One commenter (OAR-2002-0056-5488) said that EPA should further modify its power

sector modeling to treat control choices more realistically. EPA should configure the model to

allow for retrofit applications/upgrades of fabric filters and to allow for pre-cleaning and coal

blending as control options. EPA should also include halogenated sorbents as a highly

cost-effective control option. Furthermore, EPA has assumed that sources must either control

emissions at the 90 percent level with a fabric filter or at the 60 percent level using ACI alone. 

This discontinuous and unrealistic choice is likely to inflate estimated control costs and needs to

be modified.

Response: 

EPA's IPM model, due to model run time constraints, has to limit the number of control retrofit

options available. The ACI option in EPA' s IPM includes the addition of a pulse-jet fabric filter

to achieve 90% control. EPA has included the examination of technology improvement in its

analysis of the costs of the final rulemaking. EPA has performed a sensitivity analysis assuming

the introduction of second ACI option using advanced sorbents, leading to lower capital costs. 

See sensitivity analysis in Chapter 7 of final CAMR Regulatory Impact Analysis. 
9-xxiv

Comment:

One commenter (OAR-2002-0056-5535) stated that EPA has requested comment on

whether other control options should be considered in EPA’s power sector modeling (e.g., retrofit

of fabric filters and electrostatic precipitators, pre-combustion controls, and the optimization of

SO2 or NOx controls). The answer is yes. The commenter noted that EPA has had this

information readily available since 2001 when EPA’s Office of Research and Development

published a report that described a number of retrofit options that could be undertaken to

optimize the Hg capture of conventional controls. In addition, EPA had this information in hand

in June 2002 when revisions to the IPM were being discussed with the Utility Working Group. 

These eleventh hour revisions to IPM clearly could have been made more than 2 years ago.

Response:

EPA's IPM model, due to model run time constraints, has to limit the number of control

retrofit options available. The ACI option in EPA' s IPM includes the addition of a pulse-jet

fabric filter to achieve 90% control. EPA has included the examination of technology

improvement in its analysis of the costs of the final rulemaking. EPA has performed a sensitivity

analysis assuming the introduction of second ACI option using advanced sorbents, leading to

lower capital costs. See sensitivity analysis in Chapter 7 of final CAMR Regulatory Impact

Analysis. 

Comment:

The commenter (OAR-2002-0056-5455) wanted to fully reference the Forest County

Potawatomi Community’s (FCPC) excellent comment letter to EPA on the Hg utility rule

(Document ID No. OAR-2002-0056-2173). The experts retained by the FCPC stated in

attachments to that letter why EPA’s proposed MACT standards were unacceptable and why

EPA improperly failed to consider alternate methods of removal, such as activated carbon

injection. We were unable to make specific comments on these issues as time was running short.

The commenter also felt they could not add anything to the discussion that had not already been

said in the FCPC letter. Comments made by Catherine O’Neill in her article “Mercury, Risk, and

Justice” also captured the viewpoint of Fond de Lac Band.

Response:

As explained in the final rule preamble, EPA is finalizing mercury reduction

requirements for coal-fired power plants under section 111. Also see the Technical Support

Document: Methodology Used to Generate Deposition, Fish Tissue Methylmercury

Concentrations, and Exposure for Determining Effectiveness of Utility

Emission Controls and preambles to the rules.

Comment:

The commenter (OAR-2002-0056-5460) stated that EPA should consider other pollution

control and pollution prevention measures in its power sector modeling. The commenter further

stated that some of the measures EPA should be focused on are addressed in a recent report

prepared by the National Wildlife Federation, a copy of which is attached as Exhibit E (See

Document ID No. OAR-2002-0056-5460.).
9-xxv

Response:

EPA has included the examination of technology improvement in its analysis of the costs

of the final rulemaking. EPA has performed a sensitivity analysis assuming the introduction of

second ACI option using advanced sorbents, leading to lower capital costs. See sensitivity

analysis in Chapter 7 of final CAMR Regulatory Impact Analysis. 

Comment:

One commenter (OAR-2002-0056-5548) noted that EPA proposed adopting those coal

rank allocation adjustment factors for the 2010 cap based on “equitable” grounds, with allocations

adjusted by coal rank to “reflect the concern that installation of PM, NOx and SO2 control

equipment on different coal ranks results in different Hg removal.” However, since EPA is

relying upon other Hg-specific technologies to meet any subsequent cap beyond co-benefits,

performance of PM, NOx and SO2 control technologies on coal ranks for any later cap would

seem to be irrelevant. The relevant question is whether there is anything in EPA’s projected

availability of Hg-specific controls by at least 2014 that provides any equitable basis, supported by

technical concerns, to award additional allowances to lower rank coals (and, thereby, take them

away from bituminous coal).

Response:

As discussed in the Chapter 5, section 5.6.1, EPA is finalizing coal adjustment factors for

the purpose of establishing state emission budgets of 1.0 for bituminous coals, 1.25 for

subbituminous coals, and 3.0 for lignite coals. For further discussion see final rule preamble

(section IV.C.4) and Technical Support Document for the Clean Air Mercury Rule Notice of

Final Rulemaking, State and Indian Country Emissions Budgets, EPA, March 2005.

Comment:

One commenter (OAR-2002-0056-5548) noted that, in the NODA, EPA asked for

comment as to whether disparities in current NOx and SO2 Hg control capability among coal ranks

justifies using different emissions trading allocation adjustment factors for each coal rank to

reflect this disparity. In the commenter’s opinion they did not. The point of co-benefits-based Hg

emission reductions proposed by EPA is that the Hg reductions required to meet the proposed

cap are made as a result of CAIR co-benefits, and no unit has to install controls specifically to

reduce Hg. Hence, the specific ability of a unit (or the coal rank it is using) to make Hg

reductions is largely irrelevant. Those that do need “reductions” to meet their allowance

allocations get them through allowance purchases, and the ability of and cost to any particular unit

to acquire allowances does not vary by coal rank. Notably, none of the units in the non-CAIR

states, where a large portion of subbituminous coal is consumed, have to make any Hg reductions,

and hence their ability to do so, regardless of coal rank, is irrelevant.

Response:

As discussed in the Chapter 5, section 5.6.1, EPA is finalizing coal adjustment factors for

the purpose of establishing state emission budgets of 1.0 for bituminous coals, 1.25 for

subbituminous coals, and 3.0 for lignite coals. For further discussion see final rule preamble
9-xxvi

(section IV.C.4) and Technical Support Document for the Clean Air Mercury Rule Notice of

Final Rulemaking, State and Indian Country Emissions Budgets, EPA, March 2005.

While the coal adjustment are used for determining the state budgets and are used in

EPA's example unit allocation methodology, each State or Tribe is given discretion on how to

distribute the allocations within a State or Tribe. 

Comment:

One commenter (OAR-2002-0056-5548) stated that it is important to note that the

required levels of industry-wide Hg reductions happen “automatically” as a result of co-benefits in

aggregate. Consequently, in aggregate, there is no obligation for any unit to actually install any

control equipment specifically to meet a Hg reduction requirement. EPA’s proposal declares, and

fundamentally rests upon, the principle that no unit should have to install any controls specifically

to reduce Hg, as such controls are not plausibly cost effective. Because the level of co-benefits

Hg reductions that will be achieved under the CAIR includes different reduction assumptions for

each of the coal ranks, differences in actual Hg reductions among coal ranks have already been

accounted for in setting the industry-wide co-benefits cap.

As a consequence of the co-benefits approach, neither EPA nor the commenters

referenced in the NODA may rationally award differing amounts of allowances to the various coal

ranks based on the notion that members of any coal rank will have to install controls to reduce

Hg. To do so would be to declare such Hg-only controls technically and economically unjustified

as the best system of reductions under section 111 on the one hand, but to act as if such controls

were required when allocating allowances, on the other. Hence, relative abilities among coal rank

to control Hg under the CAIR or otherwise are generally irrelevant.

While Hg control disparities among coal ranks and associated equities are not relevant in

aggregate under EPA’s co-benefits approach, they may seem to be relevant at the individual unit

level, and therefore further analysis is required. The co-benefits approach creates two general

classes of utility units: those that will install co-benefits technology and those that will not. More

specifically, for compliance purposes, two classes of utility units are created: those that buy

allowances to comply, and those that are selling allowances based on their co-benefits reductions.

Response:

As discussed in the Chapter 5, section 5.6.1, EPA is finalizing coal adjustment

factors for the purpose of establishing state emission budgets of 1.0 for bituminous coals, 1.25

for subbituminous coals, and 3.0 for lignite coals. For further discussion see final rule preamble

(section IV.C.4) and Technical Support Document for the Clean Air Mercury Rule Notice of

Final Rulemaking, State and Indian Country Emissions Budgets, EPA, March 2005.

Comment:

One commenter (OAR-2002-0056-5497) stated that the use of ACI with an electrostatic

precipitator (ESP) has inherent uncertainties that may require the retrofit of additional collecting

surface area for the ESP. The retrofit of an additional field may be required to enable the existing

ESP to maintain particulate matter control efficiency. Given the uncertainties, many ESPs may

have to be rebuilt with an increase in collecting surface area, to provide Hg control and retain
9-xxvii

control of particulate matter emissions. The commenter has provided assumptions that would

allow ESPs that need additional plate area to accommodate ACI and have assigned a $25/kW

capital charge for adding the extra field. However, that retrofit of an additional field may not be

feasible in all instances, and the $25/kW capital charge for adding the extra field is based on

situations conducive to such additions.

The commenter rejected the suggestion that fabric filters can be widely retrofit to control

particulate matter and significantly enhance Hg removal. Fabric filters are not feasible where flue

gas SO3 concentrations exceed about 5 ppm. It is possible that an engineering solution to the

effects of high SO3 concentrations on fabric filters may eventually be commercially available. 

Indeed, a panel session at the 2004 Mega-Symposium discussed possible solutions to such

problems, but none are anywhere near proven at this time. Also, fabric filters are not practical for

service in water-saturated flue gas conditions such as experienced downstream from wet

scrubbers, since the water entrained in the flue gas will mix with the ash entrained on the filter,

sealing off gas flow and fouling the filter surface.

Response:

As explained in the final rule preamble, EPA is finalizing mercury reduction

requirements for coal-fired power plants under section 111, as such EPA is not mandating a

specific control technology for compliance. The Agency's position on the state of Hg technology

is contained in the EPA 's Office of Research and Development white paper (see Control of

Emissions from Coal-Fired Electric Utility Boilers: An Update, EPA/Office of Research and

Development, March 2005).

Comment:

One commenter (OAR-2002-0056-5469) noted that the NODA had requested further

comment on the prospects of technological change in Hg control technology, on how it can be

reflected appropriately in models, and on how it might affect policy choices. In response, the

commenter has extended their analyses of technological change to attempt to reflect future

availability of new control methods that have just recently begun to be tested and show promise of

being cost-effective, especially for western coals or power plants equipped with hot-side ESPs. 

Significant questions remain about this new method’s ultimate cost, control effectiveness,

applicability to different types of units, balance-of-plant issues, and timing of commercial

availability. However, once analyzed its potential impact on a “what if” basis using a range of

assumptions related to these questions.

EPRI researchers provided information on “chemically-treated carbons” (CTC), a specific

emerging advancement in sorbent technologies that would reduce the variable and capital costs of

Hg controls. It is believed that these sorbents could become available for installations as early as

2010, and would allow the injection rate of the sorbent to be dramatically reduced for a given

percentage removal, reaching 80 percent or more at subbituminous and lignite units without the

use of a fabric filter or COHPAC.

The commenter has used the EPMM model to explore the impact of the CTC option

becoming available at a future date (ranging from 2010 to 2012) under both the cap-and-trade
9-xxviii

policy and the MACT policy. It was assumed that any controls undertaken prior to that date

would have to rely on the more costly conventional activated carbons with which the industry has

greater experience to date. In order to achieve removals that can be as high as 90 percent on

lower rank coals, sorbent injection with conventional sorbents requires the large capital

investment in a COHPAC (unless a unit already has a fabric filter). Even with bituminous coal,

the cost-effective means of achieving 90 percent removal with present technology also entails the

COHPAC investment because the sorbent injection rate would be very high without the COHPAC

than with it (e.g., about 20 lb/Macf without it, compared to about 2.5 lb/Macf with it).

There is still much uncertainty on the cost and effectiveness of all sorbent injection

technologies, but especially the newer CTC option. Using information provided by EPRI

researchers, “optimistic” and “pessimistic” CTC cases were prepared. The “optimistic” case

assumed that CTC would not affect a company’s ability to continue to sell its fly ash for use in

concrete manufacture and other current commercial uses; that the CTC technology will be

available in time for those plants that choose it as their preferred Hg control method to meet a

compliance date of 2010; and that it would be made to work for bituminous units as well. The

“pessimistic” case assumed that if CTC were used, the unit’s fly ash would no longer be viable for

concrete use; that it would be available in 2010, but at an operating cost that would be three times

more expensive than it would become by 2012; and that it would not provide cost-effective

options for bituminous units.

The effects of adding the CTC technology assumptions to the base EPMM scenario

reflecting the Hg cap-and-trade policy were:

• The total number of Hg control retrofits is not much changed, but the fraction of

retrofitted capacity that uses the CTC technology ranges from 27 percent to 64 percent.

• There is no significant effect on the emission glide path. Emissions in 2020 fall to

15.5 tons, compared to 15.4 in the standard case.

• Marginal costs of Hg control are reduced slightly compared to the case that does not have

CTC, such that they are generally in the range of $20,000 to $30,000/lb (1999$) through

2020.

• Costs of the proposed Hg cap-and-trade scenario fall by 5 to 30 percent (in the pessimistic

and optimistic cases, respectively) relative to the same modeled scenario that does not

contain CTC technology.

In contrast, the effects of the CTC assumptions on the MACT policy were very minor:

1. The total number of Hg control retrofits required by 2008 continues to be very high, with

over 67 GW of FGDs and over 64 GW of ACI-based controls required by 2008.

2. Only about 10 percent of capacity uses the CTC technology to meet the MACT. Those

10 percent do this by moth-balling during 2010-2011. The avoided capital costs of

COHPAC offset their lost revenues, making waiting their preferred option.
9-xxix

3. Emissions in 2008 remain at about 32 tons, and fall to about 30 tons by 2020, as in our

original MACT case.

4. Costs of the proposed MACT scenario are effectively unchanged from the case without

the CTC technology: $9.9 billion (1999$) compared to the original cost estimate of $10.1

billion (1999$).

These model results demonstrate what simple common sense is: if a MACT policy is

implemented very soon, while relevant technologies are still in the early phases of innovation, it

will be unable to benefit from technological improvement. These analyses do add some further

value, however:

1. They provide an example of the impact of technological improvement on Hg control

performance and costs through the case study of a specific technology.

2. They place a quantitative range on the potential cost reduction that this line of research

might provide under a flexible, phased-in Hg policy.

3. They make it clear that the main beneficiaries of this potential innovation in Hg control

technology under a MACT will be the marginal coal units that have small revenue

prospects to start with, whereas a large portion of the universe of coal units can benefit

from such an innovation under the more flexibly-timed cap-and-trade approach.

Based on these data, the commenter believed that technological advance in the specific

form of chemically-treated carbon sorbents could reduce the estimated costs of the proposed capand-trade policy to a significant degree, but it would provide no significant reduction in the costs

of the alternative MACT approach. In all, the main message regarding technological change is

that its benefits are largely lost in a MACT setting, or in a setting that requires controls to be

installed very rapidly. When a policy is designed to allow flexibility to adjust timing of controls,

and to create sustained incentives to continue to reduce costs by pricing every unit of emissions,

then costs of control may be moderated.

Response:

As explained in the final rule preamble, EPA is finalizing mercury reduction

requirements for coal-fired power plants under section 111. EPA has included the examination

of technology improvement in its analysis of the costs of the final rulemaking. EPA has

performed a sensitivity analysis assuming the introduction of second ACI option using advanced

sorbents, leading to lower capital costs. See sensitivity analysis in Chapter 7 of final CAMR

Regulatory Impact Analysis. 

3. To the extent that additional control considerations should be included, EPA is

seeking data on the time line for commercialization, cost, balance of plant issues,

and performance of such options.

Comment:

One commenter (OAR-2002-0056-5484) noted that over the past several months,
9-xxx

pollution control equipment vendors have made many public pronouncements regarding the

effectiveness of their equipment for Hg control. Unfortunately, when those same vendors are

asked to guarantee Hg removal efficiency in contracts that they sign with their utility customers,

the control levels that they are willing to guarantee are much less than the optimistic claims they

have made in public forums. For example, the commenter has signed an agreement with a major

vendor to supply an SO2 scrubber, which will also capture some of the Hg emissions. The

differences between the public statements of this supplier and the actual contract language are

described in Attachment 2 in of Docket ID No. OAR-2002-0056-5484.

Response:

The Agency's position on the state of Hg technology is contained in the EPA 's Office of

Research and Development white paper (see Control of Emissions from Coal-Fired Electric

Utility Boilers: An Update, EPA/Office of Research and Development, March 2005).

Comment:

One commenter (OAR-2002-0056-5484) noted that EPA’s proposed Clean Air

Mercury Rule would require continuous monitoring of Hg emissions from electric utility steam

generating units, either through the installation of Continuous Emissions Monitoring systems

(CEMs) or through another appropriate method, such as proposed Method 324, Determination of

Vapor Phase Flue Gas Mercury Emissions From Stationary Sources Using Dry Sorbent Trap

Sampling. However, EPA’s March 16, 2004, supplemental proposal states that Method 324

would only be available under certain limited circumstances, such as only for low-emitting units,

or if quarterly relative accuracy test audits (RATAs) are performed. The commenter is concerned

that such limitations will unnecessarily limit the applicability of Method 324, and, therefore,

commissioned RMB Consulting and Research to develop the attached report, “Review of an

Alternative Method for Continuous Mercury Emission Measurement: Method 324–Determination

of Vapor Phase Flue Gas Mercury Emissions from Stationary Source Using Dry Sorbent Trap

Sampling.” This report concludes that Method 324, also known as the EPRI Quick SEMTM

method, provides results comparable to both Hg CEMs and to the Ontario Hydro reference

method.

The EPA has expressed concern that in order to administer a cap and trade program,

realtime Hg emissions information is necessary and, therefore, CEMs will be necessary. 

However, the commenter wishes to emphasize that Quick SEMTM does provide continuous

sampling and laboratories are developing analytical methodologies that will allow sample results

to be available in hours, instead of the days that were previously required. Therefore, Quick

SEMTM results will be available in time to provide information necessary for administration of a

cap and trade program. The commenter urges EPA to promulgate Method 324 without

restrictions on its use.

Response: 

EPA agrees with the commenter. In light of comparative field data, EPA believes

that monitoring using sorbent media should be as similar as possible to monitoring using Hg

CEMS and therefore Section 75.81(a) of the final rule allows the use of sorbent trap systems for

any affected unit, provided that rigorous, technology-specific QA procedures are implemented.

The operational and QA/QC procedures for sorbent trap systems are found in section 75.15 and

in appendices B and K of the final rule.
9-xxxi

Recent field test data from several different test sites indicate that sorbent trap systems

can be as accurate as Hg CEMS. However, EPA notes that although the restrictions on the use

of sorbent traps have been removed, there are some inherent risks associated with the use of this

technology. For instance, because sorbent traps may contain several days of accumulated Hg

mass, the potential exists for long missing data periods, if the traps should be broken,

compromised, or lost during transit or relative accuracy test audit (RATA) of a sorbent trap

system is performed, the results of the test cannot be known until the contents of the traps have

been analyzed. If the results of the analysis are unsatisfactory, the RATA may have to be

repeated. This also may resulting in a long missing data period. However, EPA believes that

these undesirable outcomes can be minimized by following the proper handling, chain of

custody, and laboratory certification procedures in the final rule. The use of redundant backup

monitoring systems can also help to reduce the amount of missing data substitution.

Comment:

One commenter (OAR-2002-0056-5556) noted that the EPA appropriately cites the

Detroit Edison, St. Clair, Michigan pilot study on page 69870 in the Federal Register. This study

is important in that it documents the successful application of the brominated powdered activated

carbon (B-PACTM) process at the existing DTE Energy’s Detroit Edison St. Clair Power Plant in

August 2004. This preliminary 30-day pilot study conducted as part of the U.S. Department of

Energy’s National Energy Technology Laboratory’s “Advanced Utility Mercury-Sorbent

Field-Testing Program” demonstrated a 94 percent Hg control with B-PACTM injected into a

cold-side electrostatic precipitator. This commenter noted that this study also demonstrated an 85

percent cost reduction from the current technology cost baseline (Nelson, S. 2004 and McCoy,

M., et. al., 2004), and believes the final study should be factored into the EPA’s analysis and

regulatory decision.

Response: 

EPA has included the examination of technology improvement in its analysis of the costs

of the final rulemaking. EPA has performed a sensitivity analysis assuming the introduction of

second ACI option using advanced sorbents, leading to lower capital costs. See sensitivity

analysis in Chapter 7 of final CAMR Regulatory Impact Analysis. 

Comment:

One commenter (OAR-2002-0056-5556) noted that in the NODA, the EPA states that the

Integrated Planning Model utilized “finds the least-cost solution to meeting electricity demand

subject to environmental, transmission, reserve margin, and other system operating constraints for

any specified region and time period.” Since the goal of the MACT standard is not to find a

“least-cost” solution but rather a “best technology” solution, a model based on “least-cost” is not

appropriate. Whatever modeling approach the EPA utilizes in its final analysis should be

technology-driven and used to set a true MACT floor under Section 112 of the CAA.

Response: 

EPA uses IPM to analyze the projected impact of environmental policies on the

electric power sector in the 48 contiguous States and the District of Columbia. IPM is a multi-
9-xxxii

regional, dynamic, deterministic linear programming model of the U.S. electric power sector. 

EPA used IPM to project both the national level and the unit level of utility unit Hg emissions

under different control scenarios. EPA also used IPM to project the costs of those controls. As

explained in the final rule preamble, EPA is finalizing mercury reduction requirements for coalfired power plants under section 111.

Comment:

One commenter (OAR-2002-0056-5591) stated that EPA has requested comment

concerning the availability of sorbent injection technologies to serve the electric power market. 

Activated carbon injection equipment is currently being sold to utilities. ACI equipment is

identical for all coal types including bituminous, subbituminous, lignites and blends. Therefore,

ACI equipment can be purchased for all coals and all plant configurations.

The specific sorbents may vary for different coals and operating conditions. In addition,

the ability to accurately predict the levels of Hg removal that will be achieved will vary for

different coals depending on the available performance data. For example, there have been a

significant number of tests over the past year and a half on PRB coals and North Dakota lignites. 

Therefore, it is possible to estimate results for these configurations. There is less data on

bituminous coals, so predictions will be less precise. Several full-scale field tests will be

conducted on bituminous coals during 2005 and 2006. The first test on a Texas lignite will be

conducted in 2005. Until this occurs, it is difficult to predict performance on Texas lignite.

The performance of activated carbon injection systems for lignite, subbituminous, and

bituminous coals on various coal-fired power plant configurations are given in The Hg

reduction performance for these power plant scenarios are based on results from full-scale

demonstrations that have been documented in various technical papers presented at major electric

power conferences.

Table 1. Activated Carbon Injection Control Technology Options

Plant

Configuration

Technolog

y

Coal

Type

%

Reduction Costc Year

Commer

c- ially

Availabl

e

Min Ma

x

Avg.

Totala

Avg.

Incrm.

b

Capital

($/kW)

O&M

($/kWh

)

CESPd ACJf,g Bit 50 90 70 70 1.5 to 3 .0012 2004

ACIg,h Sub 0 95 80 80 1.5 to 3 .0005 2004

ACIi Lig 0 80 63 63 1.5 to 3 .0005 2004

CESP/FGD ACIj Bit 50 90 70 70 1.5 to 3 .0012 2004

ACI Sub 0 95 80 80 1.5 to 3 .0005 2004

ACIk Lig 0 80 60 70 1.5 to 3 .0005 2004

CESP/FGDdry ACI Bit 80 >90 >90 88 1.5 to 3 .00012 2004
Plant

Configuration

Technolog

y

Coal

Type

%

Reduction Costc Year

Commer

c- ially

Availabl

e

Min Ma

x

Avg.

Totala

Avg.

Incrm.

b

Capital

($/kW)

O&M

($/kWh

)

9-xxxiii

ACI Sub 0 90 80 85 1.5 to 3 .00017 2004

ACI Lig 0 90 70 70 1.5 to 3 .00017 2004

CESP/SCR/FG

D ACI Bit 50 90 70 70 1.5 to 3 .0012 2004

ACI Sub 0 95 80 80 1.5 to 3 .0005 2004

ACI Lig 0 80 60 60 1.5 to 3 .0005 2004

FF ACJl Bit 20 95 85 80 1.5 to 3 .00036 2004

ACJl,m Sub 20 90 90 80 1.5 to 3 .00054 2004

ACI Lig 20 80 80 75 1.5 to 3 .00054 2004

FF/FGD ACI Bit 50 95 90 70 1.5 to 3 .00012 2004

ACJl Sub 30 90 90 80 1.5 to 3 .00027 2004

ACI Lig 30 90 85 70 1.5 to 3 .00027 2004

FF/SCR/FGDdryACI Bit 80 >90 >90 50 1.5 to 3 .00012 2004

ACIn Sub 0 >90 >90 90 1.5 to 3 .00017 2004

ACIo Lig 0 90 75 70 1.5 to 3 .00017 2004

FF/SCR/FGD ACI Bit 50 95 90 70 1.5 to 3 .00012 2004

ACI Sub 30 90 90 80 1.5 to 3 .00027 2004

ACI Lig 30 80 80 70 1.5 to 3 .00027 2004

HESPe TOXECO

Np

Bit 20 95 85 80 3 + 15

to 3+ 50

.00036 2004

TOXECO

N

Sub 20 90 90 80 3 + 15

to 3+ 50

.00036 2004

TOXECO

N

Lig 20 80 80 70 3 + 15

to 3+ 50

.00054 2004

HESP/FGD TOXECO

N

Bit 50 95 90 70 3 + 15

to 3+ 50

.00012 2004

TOXECO

N

Sub 30 90 90 80 3 + 15

to 3+ 50

.00036 2004

TOXECO

N

Lig 30 80 80 70 3 + 15

to 3+ 50

.00027 2004

HESP/FGDdryTOXECO

N

Bit 80 >90 >90 50 3 + 15

to 3+ 50

.00012 2004
Plant

Configuration

Technolog

y

Coal

Type

%

Reduction Costc Year

Commer

c- ially

Availabl

e

Min Ma

x

Avg.

Totala

Avg.

Incrm.

b

Capital

($/kW)

O&M

($/kWh

)

9-xxxiv

TOXECO

N

Sub 0 >90 >90 90 3 + 15

to 3+ 50

.00017 2004

TOXECO

N

Lig 0 90 88 70 3 + 15

to 3+ 50

.00017 2004

HESP/SCR/FG

D

TOXECO

N

Bit 50 95 90 70 3 + 15

to 3+ 50

.00012 2004

TOXECO

N

Sub 30 90 90 80 3 + 15

to 3+ 50

.00036 2004

TOXECO

N

Lig 30 80 80 70 3 + 15

to 3+ 50

.00027 2004

a This is the percent reduction attributable to the existing pollution controls and the technology.

b This is the percent reduction attributable only to the technology. c In EPA’s modeling, is it appropriate for an economic forecast to assume an improvement in

costs over time (such as through technology cost reductions or through future technology

innovation).

d CESP - represents cold-side electrostatic precipitator e HESP - represents hot-side electrostatic precipitator

f Durham, M., J. Bustard, T. Starns, C. Martin, R. Schlager, C. Lindsey, K. Baldrey, and R.

Monso (2004). “Full-Scale Evaluations of Sorbent Injection for Mercury Control on Power

Plants Burning Bituminous and Subbituminous Coals.” Power-Gen 2002, Orlando, FL,

December 10-12.

g Nelson, S. Jr., R. Landreth, Q. Zhou, J. Miller (2004). “Accumulated Power-Plant Mercury

Removal Experience with Brominated PAC Injection.” Combined Power Plant Air Pollutant

Control Mega Symposium, Washington, DC, August 30 - September 2.

h Starns, T. Sjostrom, S., J. Bustard, M. Durham et al (2004). “Full-Scale Evaluation of

Mercury Control by Injecting Activated Carbon Upstream of a Spray Dryer and Fabric

Filter.” Presented at PowerGen 2004, Orlando, FL, November 30 -December 4.

I Thompson, J.D., J. Pavlish, and M. Holmes (2004). “Enhancing Carbon Reactivity for

Mercury Control: Field Test Results from Leland Olds.” Combined Power Plant Air Pollutant

Control Mega Symposium, Washington, D.C., August 29 - September 2.

j Dombrowski, K., et. al., (2004). “Sorbent Injection for Mercury Control Upstream of SmallSCA ESPs.” Combined Power Plant Air Pollutant Control Mega Symposium, Washington,

D.C., August 29-September 2.

k Starns, T, J. Amrhein, C. Martin, S. Sjostom, C. Bullinger, D. Stockdill, M. Strohfus, R.

Chang, (2004). ‘’Full-Scale Evaluation of TOXECONIFM on a Lignite-Fired Boiler.”

Presentation at the Combined Power Plant Air Pollutant Control Mega Symposium,

Washington, D.C., August 29September 2.

I Ley. T., T. Ebner, K. Fisher, R. Slye, R. Patton, R. Chang, (2004). “Assessment of Low-Cost

Novel Sorbents for Coal-Fired Power Plant Mercury Control.” Combined Power Plant Air
9-xxxv

Pollutant Control Mega Symposium, Washington, D.C., August 29-September 2. m Haythornthwaite, S., S. Sjostrom, et. al., (1997). “Demonstration of Dry Carbon-Based

Sorbent Injection for Mercury Control in Utility ESPs and Baghouses.” EPRI-DOE-EPA

Combined Utility Air Pollutant Control Symposium, Washington, D.C., August 25-29. n Sjostrom, S., et. al., (2004). “Full-Scale Evaluation of Mercury Control by Injecting

Activated Carbon Upstream of a Spray Dryer and Fabric Filter.” Combined Power Plant Air

Pollutant Control Mega Symposium, Washington, D.C., August 29 - September 2. o Machalek, T., et. al., (2004). “Full-Scale Activated Carbon Injection for Mercury Control in

Flue Gas Derived from North Dakota Lignite.” Combined Power Plant Air Pollutant Control

Mega Symposium, Washington, D.C., August 29-September 2.

p Berry, M, J. Bustard., et. al., (2004). “Field Test Program for Long-Term Operation of a

COHPAC@ System for Removing Mercury from Coal-Fired Flue Gas.” Combined Power

Plant Air Pollutant Control Mega Symposium, Washington, D.C., August 29-September 2.

The commenter said that companies are providing firm price proposals with performance

guarantees for every coal and boiler type. Activated carbon injection equipment is currently being

sold to utilities. ACI equipment is identical for all coal types including bituminous,

subbituminous, lignites and blends. Therefore, ACI equipment can be purchased for all coals.

The material resources, labor and time required to install the control equipment is an

additional topic to consider. With regards to the items that impact APC vendors, there are

sufficient fabrication/manufacturing resources in the U.S. market to support a rapid retrofit of the

industry with sorbent injection systems in addition to the systems required for the Clean Air

Interstate Rule. These systems are relatively simple compared to FGD and SCR systems and the

major components are commonly used in a variety of industrial processes from numerous

manufacturers throughout the U.S.

As mentioned in the commenter’s previous comments on EPA’s proposed Hg rule, there

is significant excess production capacity of powder activated carbon and a strong interest in

investing significant capital in building new production facilities exists among current suppliers

(both in the U.S. and in China). A new Hg regulation would create a significant new market for

activated carbon. In order to build new production capacity, between a two- to four-year period

would be needed to expand production. However, all of the activated carbon suppliers said that

they would be hesitant to invest capital resources to increase capacity based only on the promise

of a new regulation. A decade or so ago, the AC industry increased capacity when EPA

announced that they were going to tighten up drinking water standards. After the new capacity

was added, EPA did not follow up with new regulations, which produced a glut of activated

carbon. Some companies went out of business because of this, and the industry as a whole is just

now recovering. As a result, it is unlikely that new AC production will move beyond the planning

stages until there is the certainty of a regulation.

Concerning resources for fabric filter systems, should the market dictate the need for

secondary PM control (not all applications will require this) there will be sufficient engineering

and material resources to complete the necessary projects. There are several examples where the

industry has had to retrofit a significant number of boilers with APC controls to meet new

environmental regulations. Examples include the retrofit of ESPs in the 1970s and the more

recent retrofit of almost 100 GW of SCRs for the NOx SIP Call. These examples support the
9-xxxvi

assertion that, should the utility industry need to retrofit a large number of coal-fired boilers with

Hg controls, it can be accomplished in a short period of time. The industries that support this

market (APC suppliers, fabricators, construction firms, etc.) have repeatedly demonstrated their

ability to meet rapidly increasing market demand. In addition, increasing demand for systems and

fabrication can also be met by foreign suppliers of silos, fabric filter systems, fabrication and

supply of PAC.

If there is a bottleneck in retrofitting the U.S. fleet of coal-fired boilers, it is not likely to

be in the area of the supply of capital equipment or under supply of sorbents but more likely to be

impacted by issues that are within the scope of the utility or regulatory community itself. 

Examples include areas such as project permitting/PUC approval, availability of project financing,

and unit outage scheduling. These are all items that are out of the control of APC vendors but

may impact the timing for control installation.

The commenter noted that EPA reported that the Edison Electric Institute (EEI) estimated

that ACI would be less expensive per pound of Hg removed than EPA has estimated. Meanwhile,

other power industry models assumed higher capital costs for ACI than EPA in its modeled

scenarios. EPA is seeking comment on whether its assumptions for Hg control technology costs

are reasonable.

EPA raised several questions in the NODA requesting information on sorbent injection

technologies and how best to make modeling assumptions to reflect current and future capabilities

of Hg control technologies. One of the questions raised by EPA was concerning the use of

discounted variable operating costs for activated carbon injection (ACI). EPA questioned

whether it would be appropriate for an economic forecast to assume an improvement in costs

over time (such as through technology cost reductions or through future technology innovation),

and what level of improvement in costs to assume. Specifically, EPA questioned whether a

2.5 percent annual improvement in variable operating costs for ACI should be incorporated into

their modeling as has been done for similar power sector models.

In regards to decreasing costs, it is appropriate to assume that the cost of sorbent

technologies will decrease with time due to equipment/technology innovation, improvements in

sorbent removal efficiencies, and the reduction in sorbent production costs. The primary cost of

sorbent injection technology is due to sorbent usage so the largest cost reductions are likely to be

made with the sorbent costs. The capital costs for ACI are relatively low as the equipment is

mechanically simple compared to FGD and SCR systems for coal-fired power plants. Activated

carbon injection systems consist of a bulk-storage silo; blower/feeder system to convey the

activated carbon from the silo through hard piping leading to the flue gas duct; and injection

probes located in the flue gas duct. Currently, the annual operating costs for these systems will be

more than the cost to construct the system.

Costs are expected to decrease as sorbents are developed specifically for the coal-fired

boiler application. It is widely known that the current sorbents have much higher capacity for Hg

removal than can effectively be used in a coal-fired power plant application. This is because the

injected sorbent will be rapped off the plates of the electrostatic precipitator or cleaned off the

bags of the fabric filter before the absorption/adsorption capacity of the sorbent has been fully

utilized. Therefore, work is being done to produce a lower capacity, lower cost sorbent that will
9-xxxvii

be more appropriate for use in this industry.

It is also expected that technical innovations will lead to lower cost sorbents. For

example, ADA-ES has reported improved Hg removals on full-scale tests with NORIT’s new

activated carbon named E-3. These tests showed that significantly higher levels of Hg could be

removed at significantly lower feed rates than earlier tests indicated. With this kind of technology

improvement, the overall cost for Hg removal will decrease over this. This is especially true for

Western coals (i.e., lignite and subbituminous) as sorbent injection rates are expected to be higher

for those units yielding a drop in operating costs by a factor of two to four. It is expected that

similar improvements in sorbents will result in similar cost reductions for bituminous coals.

As far as production costs are concerned, there will likely be a reduction in cost to

produce sorbent products for the power industry due to economies of scale. Currently, activated

carbon is already manufactured by numerous vendors for a wide variety of customized

applications requiring inefficient and expensive materials handling to provide the different

treatments and particle size requirements. In addition, the demand for activated carbon is

seasonal and therefore the use of the equipment is not optimized. To meet the power industry

demands, it is likely that new production facilities will be built to produce only a few products so

there will be an increase in efficiency and reduction in cost. In addition, the power market will be

much more consistent and predictable, which will serve to optimize the production equipment.

Once the sorbents are specifically produced for power industry applications, the pricing

trend for activated carbon should act very much like other commodities. On average, pricing for

most commodity items will normally stay unchanged or decrease slightly over time as market

forces encourage cost reductions. Since inflation in the U.S. normally runs around 2-3 percent,

any commodity that does not increase in price decreases (in real terms) by around this amount

every year. It is safe to assume that activated carbon prices will decrease by at least 2-3 percent

in real terms (net inflation). The most likely scenario is that prices for sorbents will initially

decrease by much more than 2-3 percent as the market for this specific application grows and will

reach a steady state annual reduction of 2-3 percent.

The final decrease in costs will come about through innovative equipment/technology

configurations such as the EPRI TOXECON II. Currently, EPA modeling includes the cost for

the loss of sale of power plant fly ash plus landfill costs to dispose of the fly ash. The EPRI

TOXECON II process eliminates the cost of loss of sale of the fly ash for concrete without the

need for a new fabric filter. As a result, plants will be able to avoid one of the most costly aspects

of the technology. As shown in , the capital cost of installing a COHPAC fabric filter is

expected to range between $15 - 50/kW depending on the plant configuration. Also given in

, the capital cost of installation ACI systems is expected to range between $1.5-3/kW.

When considering the combination of the decrease in cost of sorbent technologies with

time due to equipment/technology innovation, improvements in sorbent removal efficiencies, and

the reduction in sorbent production costs; it is safe to assume that costs for this technology will

decrease over time. A more likely scenario for costs of ACI over the next three to five years

would be more significant reductions in overall costs by a factor of 2 or more compared to current

EPA and DOE projections of only 2.5 percent.
9-xxxviii

The ECO process is currently being commercially demonstrated in a 50-MW slipstream

unit at First Energy Corporation’s R.E. Burger Plant in Shadyside, Ohio. The unit processes flue

gas from a plant burning eastern bituminous coal. As of August 2004, ECO performance has met

or exceeded most commercial objectives. Mercury removal across the ECO system has ranged

from 75-85 percent with total inlet Hg concentration up to 16 g/Nm3. SO2 removal is routinely

greater than 99 percent with inlet SO2 concentrations up to 2200 ppm and outlet concentrations

below 10 ppm. NOx removal has been as high as 82 percent with outlet levels of 0.05 lb/MMBtu.

Prior to proceeding with the 50-MW commercial demonstration unit, Powerspan

conducted pilot testing in a I-MW slipstream unit at the R.E. Burger Plant. During approximately

18 months of testing, the plant burned a blend of bituminous and subbituminous coals. Typical

values for Hg concentration, chlorine, and sulfur content in the coal were 0.09 ppm Hg,

0.06 percent chlorine, and 1.9 percent sulfur. Ontario-Hydro sampling was conducted by Air

Compliance Testing (Cleveland, Ohio) at the ECO pilot unit in May 2002. Ontario Hydro testing

measures gas-phase Hg (elemental and oxidized forms) and Hg bound to particulate matter in the

flue gas. Air Compliance’s testing consisted of three sample runs each on the inlet and outlet flue

gas streams. Two of the three sets of sample runs had sample durations in each location of four

hours while sampling for the remaining set of runs lasted three hours in each location. The Hg

removal for particulate, oxidized, and elemental are provided in with the overall Hg

removal measured at 88 percent.

Table 2. Mercury Removal at ECO Pilot Demonstration

Hg Fraction ECO Inlet ECO Outlet % Removal

Particle Bound Hg (g/dscm) 0.62 0.016 97.4

Oxidized Hg (g/dscm) 5.81 0.022 99.6

Elemental Hg (g/dscm) 0.16 0.75

Total Hg (g/dscm) 6.59 0.79 88.0

 provides estimates of the ECO process performance for various plant

configurations. It is expected that 80 percent Hg removal across the ECO system will be

achieved with the application of the ECO process for units burning bituminous coals. The

average incremental removal for fabric filter and hot-side ESP applications are expected to be

similar to that demonstrated at the ECO commercial demonstration unit at the R.E. Burger Plant,

which employs a cold-side ESP. The cost and performance estimates are based on results

currently being commercially demonstrated in a 50-MW slipstream unit at First Energy Corp.’s

R.E. Burger Plant.

Table 2. Mercury Removal Capacity of ECO Commercial Technology

Plant

Configuration

Coal

Type

% Reduction Cost

Year

Commercially

Available
9-xxxix

Min Max

Avg.

Totala

Avg.

Increm.b

Capital

($/kW)

O&M

($/kW

h)

% Expected

Change Cost ±w/

timec

CESPd Bit ff f 80 225 0.0027 Decrease 2006

FF Bit 80 225 0.0027 Decease 2006

HESPe Bit 80 225 0.0027 Decrease 2006

a This is the percent reduction attributable to the existing pollution controls and the technology.

b This is the percent reduction attributable only to the technology.

c In EPA’s modeling, is it appropriate for an economic forecast to assume an improvement in

costs over time (such as through technology cost reductions or through future technology

innovation).

d CESP-represents cold-side electrostatic precipitator

e HESP-represents hot-side electrostatic precipitator

f Measurements of the Hg content in the coal and in the flue gas upstream of the plant’s ESP

have not been made.

The ECO process is currently being commercially demonstrated in a 50-MW slipstream

unit at First Energy Corporation’s R.E. Burger Plant in Shadyside, Ohio. Previously, ECO was

pilot tested in a 1-MW slipstream unit at the same plant. Commercial demonstration testing is

planned to complete in the first quarter of 2005. Based on this project, Powerspan will offer

commercial ECO systems with industry standard guarantees and warranties by the beginning of

2006.

It is estimated that the capital cost of the multipollutant ECO process will be $225/kW and

the operation and maintenance costs will be $0.0027/kWh. These are the estimated costs for

cold-side ESP application based on the experience at the Burger Plant. The cost for fabric filter

and hot-side ESP applications are expected to be similar to cold-side ESP application. To

estimate the cost effectiveness of the process for Hg removal, it is estimated that the variable cost

of Hg removal in the ECO process is $800 per pound of Hg, including the sorbent media and its

disposal. The costs are expected to decrease over time due to technology innovations; however,

the level of cost reduction has not yet been estimated.

Since the K-Fuel process reduces emissions of multiple pollutants, coal-fired facilities that

will most benefit from burning K-Fuel to reduce Hg emissions include those units that will achieve

the most co-benefit from SO2 and NOx emission reductions as well as heat rate improvements. 

K-Fuel will benefit units burning high sulfur bituminous coal with no SO2 control, units burning

declining supplies of Central Appalachian SO2 compliant coal, units that have switched from

bituminous to subbituminous coal to meet the Title IV Acid Rain requirements with a resulting

loss in generating capacity, units with no post-combustion SO2 or NOx control, and small

generating units that are searching for low capital cost Hg control. K-Fuel can also be burned in

units currently burning subbitminous coal and lignite, the feedstocks for K-Fuel.

K-Fuel is a commercially viable pre-combustion solution and proven technology for

western coal to reduce Hg emissions from coal-fired power plants. K-Fuel accomplishes Hg
9-xl

reduction through its coal beneficiation process. In effect, by combusting K-Fuel the utility is

achieving Hg reduction for free since Hg removal has already occurred during the K-Fuel process

prior to combustion by a utility.

 below provides laboratory data for various feedstocks of sub bituminous coal,

along with the corresponding reduction in Hg, increase in heat rate (Btu), and reduction in

moisture content achieved by the K-Fuel process. The information presented demonstrates that

the effectiveness of the process is dependent upon the properties of the unique coal feedstock.

To date, the K-Fuel pre-combustion process has not been optimized for Hg emission

reduction but is a co-benefit of the pre-combustion process. In , the amount of Hg

removal listed is the amount of Hg reduced in the coal prior to combustion and does not consider

the potential additional reductions from existing control technologies (e.g., electrostatic

precipitators, fabric filters, etc.). As a result, the Hg reduction numbers below are a beginning

point for the ultimate Hg reduction achievable when burning K-Fuel, not accounting for plant

specific characteristics.

A facility knows when it purchases K-Fuel how much Hg has already been removed and

what amount of Hg is in the K-Fuel prior to combustion. Additional Hg removal above that

already achieved in the K-Fuel will be dependent upon unit specific characteristics such as

installed pollution control devices and boiler characteristics, as mentioned below.

Table 4. Emissions Reductions from Laboratory Tests using F-Fuel Process

Coala

ID

Coal As

Rec.

Moistur

e

Percent

Coal

As Rec.

Btu/Lb

Coal As

Rec.

Hg

lbs/TBt

u

K-Fuel

As Rec.

Moistur

e

Percent

K-Fuel

As Rec.

Btu/Lb

K-Fuel

Hg

lbs/TBt

u

Moistur

e

Remova

l

Percent

Btu

Increase

Percent

Total

Mercur

y

Remova

l

Percent

Coal 1 31.06 8520 1.98 6.06 11667 0.63 80 37 68

Coal 2 27.00 8969 24.17 5.74 11683 3.75 79 30 85

Coal 3 28.41 8536 12.58 6.46 11331 3.10 77 33 75

Coal 4 32.04 7903 7.99 7.06 11162 1.84 78 41 77

Coal 5 31.72 8126 6.30 8.00 11091 2.30 75 37 63

Coal 6 30.93 8235 3.51 6.91 11149 2.02 78 35 42

Coal 7 31.20 8032 4.05 7.09 10535 1.93 77 31 52

a

 Subbituminous coals were used for all of the laboratory tests.

K-Fuel does not impose any installation, capital, or operating costs in addition to the cost

of K-Fuel per ton to achieve Hg reduction since Hg reduction is already achieved in K-Fuel prior

to combustion in a coal-fired unit. As a solid coal fuel, K-Fuel will not negatively impact system

components or byproducts since there are no chemicals, additives, or other substances added to

the combustion process, flue gas, or to the K-Fuel itself to enhance Hg removal Currently, KFx
9-xli

conservatively estimates that K-Fuel will be sold for $33 per ton (including transportation costs),

though market conditions and other factors may impact the price.

In June 2004, KFx announced its purchase of the Fort Union mine site near Gillette,

Wyoming as the location for a commercial K-Fuel production facility. The site includes

approximately 1,000 acres of land, a rail loop with load out facilities, a coal crusher, related

buildings, water disposal wells and about 500,000 tons of remaining coal reserves. Private money

is fully funding the project and the Wyoming Department of Environmental Quality (WYDEQ)

has finalized all permits necessary for construction. The final air quality permit was granted from

WYDEQ on November 8, 2004 and ground was broken on the site November 10, 2004. 

Concrete foundations have begun being poured as of December 2004. Fabrication of the major

process components of the facility is near completion.

The feedstock coal to produce K-Fuel will be purchased from adjacent mines in the

Powder River Basin. Initial output from the facility will be 750,000 tons per year and two-thirds

of the output has been pre-sold with the remaining portion to be used for test burns to facilitate

additional markets for K-Fuel. The K-Fuel production facility is expected to be in commercial

operation in the summer of 2005. The facility can be expanded to produce up to 8 million tons

per year of K-Fuel and KFx expects that with the first commercial plant in operation the

development of future plants will be accelerated. KFx is examining potential commercial sites in

Wyoming, Alaska, South Dakota, and other locations for additional K-Fuel production facilities. 

KFx plans to own and operate the K-Fuel production facilities, as well as license K-Fuel

technology to third parties in the U.S. and internationally.

Response: 

EPA appreciates the commenters input to the record on the status of control

technologies. The Agency's position on the state of Hg technology is contained in the EPA 's

Office of Research and Development white paper (see Control of Emissions from Coal-Fired

Electric Utility Boilers: An Update, EPA/Office of Research and Development, March 2005).

Comment:

One commenter (OAR-2002-0056-5472) noted that its commitment to environmental

stewardship led it to participate as a partner with Sorbent Technologies Corporation and others in

a U.S. Department of Energy (DOE) co-funded project to test an advanced halogenated activated

carbon. The test objective was to determine the Hg removal performance and relative costs of

sorbent injection for advanced sorbent materials in a large-scale field trial. One of the sites tested

was the commenter’s St. Clair Power Plant Unit 1 (STCPP U1) with a cold-side electrostatic

precipitator (ESP) using subbituminous coal, or a blend of subbituminous and bituminous coal. 

STCPP U1 is nominally 150 MW, but a completely split duct configuration allows testing to be

completed on half of the flue gas stream, without resorting to the uncertainty of slipstream

configurations.

The commenter offered STCPP U1 to testing for several reasons. The majority of

Hg-related testing done previously was completed on units burning either bituminous,

subbituminous, or lignite coals. Since most of the commenter’s units burn a blend of bituminous

and subbituminous coals, it was interested in improving the understanding of the effect of these
9-xlii

blends on the ability to control Hg emissions. STCPP U1 an effectively burn 100 percent

subbituminous and blends up to 70 percent subbituminous and 30 percent bituminous. This unit

could provide the opportunity to test either 100 percent subbituminous or the blended fuel.

Response:

EPA appreciates the commenters input to the record on the status of control

technologies. The Agency's position on the state of Hg technology is contained in the EPA 's

Office of Research and Development white paper (see Control of Emissions from Coal-Fired

Electric Utility Boilers: An Update, EPA/Office of Research and Development, March 2005).

Comment:

One commenter (OAR-2002-0056-5472) was concerned about the ability of normal sized

ESPs to remove the additional particulate loading resulting from injection of sorbents. STCPP

U1 is equipped with a 700 SCA (specific collection area) ESP, which is about three times larger

than the average sized ESP. Not knowing how much sorbent would be injected or the ability of

the ESP to remove particulate under the injection conditions, this unit’s ESP could be expected to

handle any possible additional loading. This means that particulate removal would not be

expected to limit testing for Hg removal even at higher injection rates.

In addition, the commenter believed that this testing opportunity would provide some

insight into the balance-of- plant impacts it might expect if using sorbent injection as an emission

control technology at this or other coal-fired boilers.

Baseline testing and parametric testing demonstrated that B*PACTM could be expected to

provide the best results of the sorbents tested, even at a lower injection rate of 3 lbs/Macf. The

final step of this test was to inject B*PAC at 3 lbs/Macf for a 30-day period, while the boiler

operated under normal (varying) load conditions. Over the 30-day test period, the sorbent

injection equipment constructed for the test was able to adequately follow the boiler load swings

and maintain a consistent injection rate. The Hg removal rate averaged 93 percent over the

30 day period. The commenter reported that these promising results encourage additional testing

for longer duration under more challenging conditions.

Response: 

EPA appreciates the commenters input to the record on the status of control

technologies. The Agency's position on the state of Hg technology is contained in the EPA 's

Office of Research and Development white paper (see Control of Emissions from Coal-Fired

Electric Utility Boilers: An Update, EPA/Office of Research and Development, March 2005).

Comment:

One commenter (OAR-2002-0056-5472) noted that longer testing periods (minimally one

year) are required to hopefully identify any unintended and unanticipated consequences resulting

from the operation of this and other technologies. Cumulative effects on collection equipment or

other downstream equipment not identified in a 30-day test could be identified after longer term

operation, as has been experienced with other control technologies. Identification of an
9-xliii

unanticipated consequence after a commitment to a particular technology puts the electric supply

at risk. The commenter believes that this is an unacceptable result of rushing a little-tested

technology into operation. A technology must be tested under various fuels and operating

conditions to validate commercial viability. One 30-day test cannot provide the operational

assurances necessary to ensure the performance and reliability required of electric generating

units.

The commenter reported that the particulate control equipment was never expected to be

a challenge or represent a normal operation during this test. This unit was chosen, in part,

because of an equipment configuration that would eliminate particulate collection as a concern. 

The ESPs on STCPP U1, however, approach 3 times the collection capability of a normal electric

generating unit ESP. Additional testing is required to demonstrate what operational impacts

might be expected on smaller ESPs (<250 SCA) and what equipment and operational

modifications might be required for long-term operation of sorbent injection technologies.

Response: 

EPA appreciates the commenters input to the record on the status of control

technologies. The Agency's position on the state of Hg technology is contained in the EPA 's

Office of Research and Development white paper (see Control of Emissions from Coal-Fired

Electric Utility Boilers: An Update, EPA/Office of Research and Development, March 2005).

Comment:

One commenter (OAR-2002-0056-5472) reported that much of the industry’s fly ash is

currently used productively for commercial uses. The B-PAC sorbent used in this test makes fly

ash unusable as a concrete additive, which necessitates landfi1l disposal of a previously useful

byproduct. There is a need to develop and then conduct similar tests with “concrete-friendly”

sorbents which will keep these productive uses for fly ash viable.

Because of the short-term nature of this test, there is a still need to further investigate

equipment risks, such as potential corrosion in ductwork and gas handling equipment and the

possibility of contamination issues in areas of fly ash hideout.

The ultimate fate of halogens, including bromine, in the flue gas stream is a continuing

area of concern. Any concerns about the possible formation of toxic byproducts in flue gas

stream must be thoroughly investigated and dispelled before this technology can be widely

deployed. There have only been preliminary tests conducted in coal-fired electric generating

boiler flue gas streams, and this issue requires significantly further research.

In addition to these specific comments offered related to the company’s experience testing

Brominated activated carbon injection, the commenter also supports the comments submitted by

the Edison Electric Institute (EEI), the Utility Air Regulated Group (UARG), and the Electric

Power Research Institute (EPRI).

Response: 

EPA appreciates the commenters input to the record on the status of control technologies. The

Agency's position on the state of Hg technology is contained in the EPA 's Office of Research
9-xliv

and Development white paper (see Control of Emissions from Coal-Fired Electric Utility

Boilers: An Update, EPA/Office of Research and Development, March 2005).

Comment:

One commenter (OAR-2002-0056-5496) is an advocate of public policies that are

protective of public health and is prepared to make reasonable additional reductions in power

plant Hg emissions. This commenter has been a strong advocate for the Minnesota Mercury

Contamination Reduction Initiative and achieved about 17 percent reduction in Hg stack

emissions in 2000 compared to 1990 levels through optimizing fuel sourcing and plant operation. 

The commenter’s coal units are also over 70 percent wet scrubbed for particulate and sulfur

dioxide removal, which combined with other voluntary Hg reduction activities has reduced base

line emissions relative to 1990 and compared to other utility units. Consequently, an equitable

allocation of Hg reduction requirement stringency, either through unit specific requirements or

cap-and-trade program allowance allocation methodology is important for assuring reasonable

credit for early action. The commenter supports an equitable cap-and-trade approach as the

preferred option for regulating electric power sector Hg emissions, as that provides the most

flexibility for achieving compliance using new and often unproven technology.

Response: 

EPA is finalizing a cap-and-trade approach under section 111. See final rule preamble

for rationale.

Comment:

One commenter (OAR-2002-0056-5496) notes that the technology EPA and other

modelers have presumed to be effective for achieving high percentages of Hg removal in their

Integrated Planning Model involves use of activated carbon injection followed by particulate

collection. However, over 70 percent of this commenter’s coal generation is operated with wet

scrubbers, providing for particulate removal while delivering sulfur dioxide emission reductions. 

The commenter has injected activated carbon into its wet scrubbers and found only small

improvements in Hg removal (zero to 30 percent) over the realm of typical activated carbon

injection rates. The wet scrubbers create a near-saturated flue gas with entrained water droplets,

making operation with a fabric filter downstream of the scrubber impractical due to filter

plugging. The flue gas temperature upstream of the wet scrubbers is too high for reliable filter

operation. Consequently, units operating with existing wet scrubbers are not amenable to retrofit

of activated carbon and fabric filter technology.

Response: 

EPA is finalizing a cap-and-trade approach under section 111. See final rule preamble

for rationale. Under a cap-and-trade approach the commenter will have flexibility in its

compliance options including buying allowances. EPA also notes that ACI with a pulse-jet

fabric may be installed upstream of wet scrubber. The Agency's position on the state of Hg

technology is contained in the EPA 's Office of Research and Development white paper (see

Control of Emissions from Coal-Fired Electric Utility Boilers: An Update, EPA/Office of

Research and Development, March 2005).
9-xlv

Comment:

One commenter (OAR-2002-0056-5496) notes that IPM modeling presumes uniform

control costs and percent Hg reductions for coal units that are targeted to retrofit activated

carbon injection and fabric filters, without sufficient consideration of unit size (economy of scale),

coal type (concentration and species of Hg emitted) or current emission rates. Incremental

reductions in the targeted Hg emissions cap should be expected to give increasingly higher Hg

reduction costs in terms of dollars per pound Hg removal when performing modeling. For

example, the Table 1–Summary of CCAP Power Sector Modeling (Federal Register Volume 69

No 230 page 69868) presents a linear incremental cost as the Hg cap is reduced from 15 tons to

7.5 tons over a regime of affected units that would be expected to exhibit higher costs due to

economy of scale or lower Hg content coal. Linear consideration of unit control retrofit costs

affirms the IPM does not adequately address incremental control costs.

Response: 

The commenter is incorrect that IPM modeling uses uniform control costs and percent

Hg reductions. Hg-specific control costs (ACI) vary by size of the unit and coal type burned. 

Hg removal varies by coal type and control type. In addition scrubbers and SCR also consider

economies of scale. See IPM documentation in docket for further discussion of control cost and

performance assumptions.

Comment:

One commenter (OAR-2002-0056-5561) stated that the demand growth assumptions used

in our sensitivity analyses, published in the NODA, appeared to be reasonable. The average

growth rate of 1.8 percent per year was identical to the latest demand forecast published in

Energy Information Administration’s 2005 Annual Energy Outlook. Demand forecasts used by

other analysts such as Cinergy (2.3 percent per year) may be too high. The natural gas price

assumptions used in the commenter’s sensitivity analyses, on the other hand, may be somewhat

low. Use of higher gas price assumptions would be expected to raise system costs in both the

base and policy cases. It was not clear what effect higher gas prices would have on the

incremental cost of the various Hg policy scenarios that were investigated. However, the

sensitivity runs the commenter evaluated with higher gas prices and load growth assumptions

resulted in very modest increases in system costs (roughly 1 percent) for the increasingly tighter

second Phase Hg caps over the system cost increases under increasingly stringent scenarios using

our original lower gas price and load growth assumptions. (See Document ID No.

 submitted on June 29, 2004 for details on the Air Quality Dialogue

analyses.)

Response:

As discussed in EPA's IPM documentation, EPA uses its natural gas prices and

demand forecasts different from those of EIA. EPA has performed a sensitivity analysis

examining the impact of uses EIA natural gas prices and electric growth projections. See chapter

7 of final rule CAMR RIA.

Comment:
9-xlvi

One commenter (OAR-2002-0056-5521) provided the following information:

Limestone Forced Oxidation (LFSO)

This cost estimate was for the cost of installing, operating, and maintaining LFSO only.

Merrimack Station

Cost Estimate (1995

Dollars)

MK 1 (113 MWe) MK2 (320 MWe)

Capital $48/kW ($54,240,000)* $250/kW ($80,000,000)*

Fixed O&M $16.0/kW/yr ($1,808,000/yr) $10.0/kW-yr ($3,200,000/yr)

Variable O&M 1.1 mills/kWh ( $868,733/yr) 1.1 mills/kWh ($2,527,360/yr)

Total Annual** 10.26 mills/kWh ($8,100,733/yr) 5.98 mills/kWh ($13,727,360/yr)

* This capital cost estimate included the costs for a reagent feed system, a wet SO2 removal

system, a flue gas handling system, a waste/by-product handling system and support

equipment (exhaust stack) but didn’t include a cost estimate for replacement of primary fans if

required.

** Used 2002 MWh to estimate cost in mills/kWh.

Powdered Activated Carbon Injection

This cost estimate was for the cost of installing, operating, and maintaining the Powdered

Activated Carbon Injection only. Costs were calculated using U.S. EPA’s and U.S. DOE’s

Mercury Control Performance and Cost Model (MCPCM), September 30, 2000.

Merrimack Station

Cost Estimate (1999 Dollars) MK 1 (113 MWe) MK2 (320 MWe)

Capital $8.49/kW*** ($ 959,370) $5.97/kW*** ($1,910,400)

Fixed O&M $3.64/kW/yr ($411,320/yr) $1.64/kW/yr ($524,800/yr)

Variable O&M 1.10 mills/kWh ($868,733/yr) 1.10 mills/kWh

($2,527,360/yr)

Total Annual** 1.74 mills/kWh

($1,375,990/yr)

1.41 mills/kWh

($3,243,200/yr)

** Used 2002 MWh to estimate cost in mills/kWh.

*** Total Control Capital Costs including process equipment, field materials, field labor,

indirect field costs, engineering and home office overhead/fees, process contingency,

project contingency, and general facilities.
9-xlvii

Powdered Activated Carbon Injection & Spray Cooling

This cost estimate was for the cost of installing, operating, and maintaining the Powdered

Activated Carbon Injection and Spray Cooling system only. Costs were calculated using U.S.

EPA’s and U.S. DOE’s Mercury Control Performance and Cost Model (MCPCM), September

30,2000.

Merrimack Station

Cost Estimate (1999

Dollars)

MK 1 (113 Mwe) MK2 (320 MWe)

Capital $24.63/kW***($2,783,190) $17.20/kW***($5,504,000)

Fixed O&M $5.58/kW/yr ($630,540/yr) $2.99/kW/yr ($956,800/yr)

Variable O&M 1.13 mills/kWh ($900,323/yr) 1.14 mills/kWh

($2,619,264/yr)

Total Annual** 2.29 mills/kWh

($1,809,182/yr)

1.80 mills/kWh

($4,126,464/yr)

** Used 2002 MWh to estimate cost in mills/kWh.

*** Total Control Capital Costs including process equipment, field materials, field labor,

indirect field costs, engineering and home office overhead/fees, process contingency,

project contingency, and general facilities.

Powdered Activated Carbon Injection & Pulse Jet Fabric Filter

This cost estimate is for the cost of installing, operating, and maintaining the Powdered

Activated Carbon Injection, and Pulse Jet Fabric Filter system only. Costs were calculated using

U.S. EPA’s and U.S. DOE’s Mercury Control Performance and Cost Model (MCPCM),

September 30, 2000.

Merrimack Station

Cost Estimate (1999

Dollars)

MK 1 (113 Mwe) MK2 (320 MWe)

Capital $50.38/kW*** ($5,692,940) $40.00/kW*** ($12,800,000)

Fixed O&M $8.68/kW/yr ($980,840/yr) $5.73/kW/yr ($1,833,600/yr)

Variable O&M 1.15 mills/kWh ($908,221/yr) 1.15 mills/kWh

($2,642,240/yr)

Total Annual** 3.11 mills/kWh

($2,458,355/yr)

2.51 mills/kWh

($5,755,840/yr)
9-xlviii

** Used 2002 MWh to estimate cost in mills/kWh.

*** Total Control Capital Costs including process equipment, field materials, field labor,

indirect field costs, engineering and home office overhead/fees, process contingency,

project contingency, and general facilities.

Powdered Activated Carbon Injection, Spray Cooling & Pulse Jet Fabric Filter

This cost estimate was for the cost of installing, operating, and maintaining the Powdered

Activated Carbon Injection, Spray Cooling, and Pulse Jet Fabric Filter system only. Costs were

calculated using U.S. EPA’s and U.S. DOE’s Mercury Control Performance and Cost Model

(MCPCM), September 30, 2000.

Merrimack Station

Cost Estimate (1999 Dollars) MK 1 (113 Mwe) MK2 (320 MWe)

Capital $66.53/kW*** ($7,517,850) $51.23/kW*** ($16,393,600)

Fixed O&M $10.62/kW/yr

($1,200,060/yr)

$7.08/kW/yr ($2,265,600/yr)

Variable O&M 1.19 mills/kWh ($939,811/yr) 1.19 mills/kWh

($2,734,144/yr)

Total Annual** 3.66 mills/kWh

($2,891,660/yr)

2.89 mills/kWh

($6,639,104/yr)

** Used 2002 MWh to estimate cost in mills/kWh.

*** Total Control Capital Costs including process equipment, field materials, field labor,

indirect field costs, engineering & home office overhead/fees, process contingency,

project contingency, and general facilities.

Response:

EPA appreciates the commenters input to the record on the status of control technologies. The

Agency's position on the state of Hg technology is contained in the EPA 's Office of Research

and Development white paper (see Control of Emissions from Coal-Fired Electric Utility

Boilers: An Update, EPA/Office of Research and Development, March 2005).

Comment:

One commenter (OAR-2002-0056-5456) noted that the DOE National Environmental

Technology Laboratory (NETL) recently issued their next round of awards for testing of

advanced Hg reduction technologies at coal-fired power plants. This testing is to take place in the

2005-2007 time frame. The point of this discussion is to note that scientific testing and research

on Hg monitoring and control equipment are still continuing and will continue for the next few

years. If the technologies related to Hg issues were sufficiently demonstrated, there would be no

need for continuation of the testing programs of this nature.
9-xlix

The commenter has been participating in various Hg projects that attempt to present a

better understanding of various issues related to Hg emissions from the combustion of coal in

electric utility steam generating units, specifically those burning PRB subbituminous coal. These

projects involve studying Hg emissions control technologies and Hg emissions monitoring.

The DOE/NETL announcement of the awards states “With an eye on future federal

regulations aimed at reducing Hg emissions, the DOE has selected six additional projects as part

of a DOE research program to advance the technical readiness of Hg control options for the

Nation’s fleet of coal-fired power plants. The six projects in this next round of awards build on

last year’s selection of eight projects, and will verify technology performance, evaluate costs, and

assess balance-of plant impacts. The projects will field test advanced, post-combustion

technologies involving all coal types at utilities using pulverized coal or cyclone-boiler

configurations, and focus on technologies capable of removing Hg from flue gas containing higher

concentrations of elemental Hg. The technologies include sorbent injection, wet flue gas

desulfurization systems enhancement, and combustion optimization. Both rounds of selections

are aimed at meeting the Energy Department’s near-term goal of having technologies that can

capture 50-70 percent of Hg emissions ready for commercial demonstration by 2005 for power

plants burning bituminous coal, and by 2007 for those that burn low-rank coals and blends. The

Energy Department has set a longer term goal of having technologies that can achieve 90 percent

Hg reduction for all fuel types ready for commercial demonstration by 2010, and is also looking

to reduce the cost of Hg control by 25-50 percent over baseline, activated-carbon costs, which

range from $50,000-$70,000 per pound of mercury removed.”

The important statement in the above is that DOE/NETL is seeking to be ready for

commercial demonstration, not commercial use, of Hg control by 2005 for bituminous coals, and

2007 for low rank coals (lignite and subbituminous coal).

Response:

EPA appreciates the commenters input to the record on the status of control

technologies. The Agency's position on the state of Hg technology is contained in the EPA 's

Office of Research and Development white paper (see Control of Emissions from Coal-Fired

Electric Utility Boilers: An Update, EPA/Office of Research and Development, March 2005).

Comment:

One commenter (OAR-2002-0056-5458) noted that in the January Federal Register

proposal, EPA fails to acknowledge the ongoing work being conducted under the U.S.

Department of Energy/National Energy Technology Laboratory (DOE/NETL) Mercury Control

Technology Research Program on coal fired power plants. Four full-scale demonstration projects

have tested the effectiveness of carbon injection in tandem with conventional criteria air pollution

control devices currently in use at utilities. Specifically, the E.C. Gaston plant in Alabama burning

low sulfur bituminous coal achieved greater than a 90 percent Hg removal rate using carbon

injection, along with a hot side electrostatic precipitator (ESP) and a compact hybrid particulate

collector (COHPAC) baghouse for particulate control. The Brayton Point plant in Massachusetts

burning low sulfur bituminous coal achieved a 90 percent Hg removal rate using carbon injection

in combination with a cold-sided ESP. The Pleasant Prairie plant in Wisconsin burning

sub-bituminous coal achieved a 65 percent removal rate using carbon injection with a cold-sided
9-l

ESP. Significantly, the E.C. Gaston Plant achieved a high Hg removal rate and used considerably

less carbon injection as a result of the addition of a COHPAC baghouse or fabric filter in

comparison to the other projects. The additional pollution control equipment has the potential to

significantly increase Hg removal rates from sources burning both bituminous and sub-bituminous

coal.

Real reductions for both Hg and sulfur can be achieved when Utility Units install wet

scrubbers or spray dryer adsorbers, in conjunction with fabric filters. According to the

Information Collection Request III data, the lowest emissions of Hg and sulfur were achieved

when these pollution control devices were used. The Department analyzed emissions data from

Utility Units in eight states surrounding New York. This analysis showed that the Utility Units

achieving the greatest Hg reduction were ones utilizing fabric filters. Several of the better

controlled units have ESPs but also used a wet scrubber for sulfur control. The Department has

experience with municipal waste combustors (MWCs) in New York that use carbon injection in

combination with fabric filters or ESPs. These MWCs equipped with carbon injection and ESPs

achieve Hg emissions reductions of at least 85 percent. MWCs equipped with carbon injection

and fabric filters achieve reductions greater than 90 percent. Mercury is predominantly emitted in

the oxidized form by MWCs.

The Supplemental Notice and a letter to the Air Docket from the DOE (Document ID No.

OAR-2002-0056-0044) describe the need for six years to adequately conduct a commercial

demonstration of Hg controls. The Department believes that this long time frame is not justifiable

and it appears that EPA is attempting to selectively develop time lines to justify a cap-and-trade

program. Upon closer examination, the average six year figure includes a pre-award period

greater than 12 months, with each full-scale demonstration project taking another 12 months, and

allows for inflation during the operation and reporting time line by including the time it takes to

prepare a report on the project. A more realistic value for commercial demonstration is in the

range of three to four years, especially in light of all of the full-scale Hg demonstration projects

already completed or currently being conducted.

The goal of the DOE/NETL Mercury Control Technology Research Program is for these

technologies to be available for bituminous sources by 2005 and for lignite and sub-bituminous

sources by 2007. The program also describes the commercial development of advanced Hg

control technology that will achieve a 90 percent Hg reduction for all coal types by 2010. In fact,

the field testing of this technology at a number of coal fired units was already underway in 2003. 

If these goals are attained, widespread commercial deployment of extremely efficient Hg air

pollution control technologies could begin to occur in 2008 for bituminous sources and 2011 for

lignite and sub-bituminous sources.

Response:

EPA appreciates the commenters input to the record on the status of control

technologies. The Agency's position on the state of Hg technology is contained in the EPA 's

Office of Research and Development white paper (see Control of Emissions from Coal-Fired

Electric Utility Boilers: An Update, EPA/Office of Research and Development, March 2005).

Comment:
9-li

One commenter (OAR-2002-0056-5446) believed that the variety of input assumptions,

particularly in regard to costs and Emission Modification Factors (EMF), used in the modeling

analysis highlight the uncertainty associated with the cost and performance of Hg control

technologies. Given the limited data available, this uncertainty is to be expected and simply

reflects limited knowledge in the area. Therefore, any final rule must be sufficiently flexible to

accommodate the high degree of uncertainty inherent in the available data. The commenter

believed that a national “cap and trade” based regulation with appropriate caps and timing will

provide an important component of flexibility and will help the EPA address this inherent

uncertainty.

Furthermore even the range of assumptions used in the commentator’s models only

indicates that there is uncertainty in the cost and performance of a typical plant and typical coal. 

The models do not account for the wide variability of coals and process conditions that can result

in significant differences in performance between two plants with nominally similar coals and

identical control technology. It is important that the EPA recognize that the performance of the

average plant does not represent the behavior of the fleet. In order to understand the implications

of the regulation EPA must undertake some form of probability analysis that considers natural

variability in coal properties and unit performance and assesses their impact on the modeled

results.

Failing to account for variability in fuel type and unit operation will make it difficult if not

impossible for EPA to establish limits that are technically achievable for all affected units.

Response:

EPA is finalizing a cap-and-trade approach under section 111. See final rule preamble

for rationale. EPA's IPM modeling does take into account some extent variability of coals and

control configurations. IPM provides for extensive modeling of the coal sector, where coals can

be selected by mercury content and sulfur content. For further discussion see EPA's IPM

documentation in rulemaking docket.

Comment:

One commenter (OAR-2002-0056-5510) was concerned that the various input

assumptions used in the commenters’ modeling analysis do not account for the wide variability of

coals and process conditions encompassed by the full fleet of US utility boilers. Failing to

account for variability in fuel type and unit operation will make it difficult if not impossible for

EPA to establish limits that are technically achievable for affected units. The commenter

suggested, phased alternative to establishing a national cap and trade program, as articulated in

comments dated May 14, 2004, and again in these comments in response to II.B.4.g, would

address the variability concern through ensuring a far better database than currently exists.

Response:

EPA is finalizing a cap-and-trade approach under section 111. EPA is establishing a

phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for

rationale.
9-lii

Comment:

One commenter (OAR-2002-0056-5488) states that activated carbon injection (ACI) has

been extensively tested in several full-scale tests and pilot-scale tests and in a recent long-term test

performed at the Gaston power plant. Full scale testing performed by ADA-ES along with testing

performed by EPRI showed that high levels of Hg control, at least 90 percent, could be achieved

on a cost-effective basis at coal-fired power plants with ACI regardless of the rank of coal burned,

with the utilization of modern particulate matter control equipment (i.e., a fabric filter or a

polishing baghouse downstream of an electrostatic precipitator). Long-term tests of ACI

outfitted with a small baghouse downstream of a hot-side ESP have continued at the Gaston

power plant, which burns bituminous coal. This combination effectively addresses problems with

carbon-contamination of fly ash that can occur when activated carbon injection is used with an

ESP alone. It is also quite viable for retrofit applications, because of the compact size of the

polishing baghouse. The tests conducted at Gaston show that such units can achieve greater than

90 percent Hg control on a long-term average basis, with appropriately sized baghouses and

activated carbon injection rates. The Gaston investigators, from ADA-ES, EPRI and DOE,

conclude that “activated carbon injection systems are simple, reliable and commercially available.” 

The conclusion that activated carbon injection is commercially available today has also been

affirmed by the national trade association of control technology vendors.

Beyond activated carbon injection, EPA neglected to seriously consider several other

highly effective approaches that are available for reducing Hg emissions from existing coal-fired

power plants. These include Electro-catalytic oxidationTM, advanced dry FGD, coal blending for

plants burning sub-bituminous coal, injection of non-carbon based sorbents, and pre-combustion

coal scrubbing to increase combustion efficiency of lignite and sub-bituminous coals while

simultaneously removing Hg, N, and S before the coal is burned.

Advanced dry FGD technology is widely used in Europe and has been demonstrated at

Roanoke Valley Energy’s 55 MW bituminous coal fired Unit 2 with Hg removal in excess of

95 percent. Two companies actively marketing advanced dry FGD are F.L. Smidth AirTech,

which is marketing their Gas Suspension Absorber (GSA) as a retrofit with an existing ESP or

Pulse Jet fabric filters; and RJM-Beaumont which is marketing their Rapid Absorption Process

(RAP) as a multipollutant (SO2, PM and Hg) control technology.

Electro-catalytic oxidationTM (ECO) technology has been demonstrated on a 2000 scfm

pilot at First Energy’s Burger Plant in Akron, OH, which has been operating since March 2002. 

Pilot test results indicate 80-90 percent Hg removal under any inlet condition. Early results from

a 50 MW commercial demonstration system at Burger indicate similar performance to the pilot

tests. A 510 MW ECO system is planned for installation at AmerenUE’s Sioux Plant in Missouri

following successful completion of the Burger demonstration.

Response:

EPA appreciates the commenters input to the record on the status of control

technologies. The Agency's position on the state of Hg technology is contained in the EPA 's

Office of Research and Development white paper (see Control of Emissions from Coal-Fired

Electric Utility Boilers: An Update, EPA/Office of Research and Development, March 2005).
9-liii

Comment:

One commenter (OAR-2002-0056-5502) referenced technological improvement. The

history of technology development, including that of environmental controls, clearly shows that

technology does improve with time. Examples (see Document ID No. OAR-2002-0056-5502)

are provided to support a modest improvement rate of 2.5 percent per year, which is one of the

several cases (along with quicker and slower growth cases) modeled by Charles River Associates

for the EEI and the commenter’s submittals in June 2004. Because technology improvement

affects the control technology choices made by power plants in the model analysis, and therefore

provides a more realistic prediction of the industry’s likely response to the various proposed

regulatory scenarios, the commenter believed it is important, and very appropriate, to include cost

reductions and/or performance improvements in an economic model.

Control considerations for modeling. The detailed comments provide information on the

topics identified in EPA’s question (under §II.B.4.c)-timeline for commercialization, cost, balance

of plant impacts, and control performance. While the commenter could not comment on

commercialization issues as they do not own and operate power plants, they have provided the

conditions they believe are needed for Hg controls to be considered “commercially available.”

These include consistent, predictable results from the approximately 30 field tests sponsored by

DOE and the co-funded by the industry and the commenter, as well as enough truly long-term

tests (e.g., 12-18 months) to ensure that the industry understands how to operate the equipment

reliably and manage and plant impacts that may be caused by the technology. A technology that

gets this far is then ready to be procured by the first users, with full implementation by al plants

that select this technology several years later.

Response:

EPA appreciates the commenters input to the record on the status of control

technologies. The Agency's position on the state of Hg technology is contained in the EPA 's

Office of Research and Development white paper (see Control of Emissions from Coal-Fired

Electric Utility Boilers: An Update, EPA/Office of Research and Development, March 2005).

EPA has included the examination of technology improvement in its analysis of the costs of the

final rulemaking. EPA has performed a sensitivity analysis assuming the introduction of second

ACI option using advanced sorbents, leading to lower capital costs. See sensitivity analysis in

Chapter 7 of final CAMR Regulatory Impact Analysis. 

Comment:

One commenter (OAR-2002-0056-5505) stated that the Department of Energy (DOE)

National Environmental Technology Laboratory (NETL) recently issued their next round of

awards for testing of advanced Hg reduction technologies at coal-fired power plants. This testing

is to take place in the 2005-2007 time period. The point of this discussion is to note that scientific

testing and research on Hg control technologies are still continuing and will continue to do so

now and for the next number of years. If the technology were sufficiently demonstrated, there

would be no need for continuation of the testing programs of this nature.

The DOE/NETL announcement of the awards (5 November 2004) states “With an eye on
9-liv

future federal regulations aimed at reducing Hg emissions, the DOE has selected six additional

projects as part of a DOE research program to advance the technical readiness of Hg control

options for the Nation’s fleet of coal-fired power plants.

The six projects in this second round of awards build on last year’s selection of eight

projects, and will verify technology performance, evaluate costs, and assess balance-of plant

impacts. The projects will field test advanced, post-combustion technologies involving all coal

types at utilities using pulverized coal or cyclone-boiler configurations, and focus on technologies

capable of removing Hg from flue gas containing higher concentrations of elemental Hg. The

technologies include sorbent injection, wet flue gas desulfurization systems enhancement, and

combustion optimization.

Both rounds of selections are aimed at meeting the Energy Department’s near-term goal

of having technologies that can capture 50-70 percent of Hg emissions ready for commercial

demonstration by 2005 for power plants burning bituminous coal, and by 2007 for those that burn

low-rank coals and blends. The Energy Department has set a longer term goal of having

technologies that can achieve 90 percent Hg reduction for all fuel types ready for commercial

demonstration by 2010, and is also looking to reduce the cost of Hg control by 25-50 percent

over baseline, activated-carbon costs, which range from $50,000 to $70,000 per pound of

mercury removed.”

The important statement in the above is that DOE/NETL is seeking to be ready for

commercial demonstration, not commercial use, of Hg control by 2005 for bituminous coals, and

2007 for low rank coals (lignite and subbituminous coal).

Response:

EPA appreciates the commenters input to the record on the status of control

technologies. The Agency's position on the state of Hg technology is contained in the EPA 's

Office of Research and Development white paper (see Control of Emissions from Coal-Fired

Electric Utility Boilers: An Update, EPA/Office of Research and Development, March 2005).

Comment:

The commenter (OAR-2002-0056-5519) stated that information referred to earlier

demonstrated that Hg controls were commercially viable and cost effective:

• Low NOx burners, activated carbon injection (ACI), selective catalytic reduction (SCR),

and acid gas controls [including Lime Stone Forced Oxidation (LFSO)] and wet

Electrostatic Precipitators (wet-ESPs) for reducing Hg emissions, were already

commercially available and ready for installation on all coal-fired electric steam generating

units for all types of coal, and

• The maximum total control costs for achieving 90 percent Hg removal efficiency on a 100

MW coal-fired electric steam generating unit was less than $6 per month to a homeowner

who used 500 kWh per month of electricity.

(Note that this worst case total capital cost estimate for a 100 MW unit to install LSFO with a
9-lv

new stack and a balanced draft conversion of the boiler was $65.2 million dollars, 2002 dollars). 

More recent control cost estimates in 2003 dollars calculated for new IPM modeling indicated

that the cost to install LFSO for 500 MW unit were as follows: total capital cost=$236 million,

fixed O&M=$9.16 per kW/yr and variable O&M=$1.08 mills/kWh. Recent health data indicated

that if plant specific, Hg controls were not required and not installed on coal-fired electric steam

generating units, the same homeowner would be required to expend numerous times more in

healthcare costs. Simply put, air pollution controls capable of achieving 90 percent Hg removal

efficiency could be installed on all coalfired electric steam generating units 100 MW or larger at

an average monthly cost to the homeowner that is much more cost effective than dealing with its

environmental and health cost consequences.

Response:

EPA appreciates the commenters input to the record on the status of control

technologies. The Agency's position on the state of Hg technology is contained in the EPA 's

Office of Research and Development white paper (see Control of Emissions from Coal-Fired

Electric Utility Boilers: An Update, EPA/Office of Research and Development, March 2005).

Comment:

One commenter (OAR-2002-0056-5497) stated that they do not believe that EPA’s

modeling of the power sector has omitted any control technologies that are reasonably likely to be

available or likely to be commercialized within the time frame for decision and implementation of

Hg control technologies, consistent with the timelines envisioned by the Clear Skies Initiative. 

The preceding response discussed the problems with modifying an ESP to increase collecting

plate area when ACI is employed and with the widespread retrofit of fabric filters.

While promoted vigorously by vendors with a commercial interest in such technologies,

halogenated activated carbons, such as one containing bromine or iodine, are technologies that

should not be considered commercially available or proven. While there has been a single test

with brominated ACI that involved one-half of the flue gas stream from a 150 MW unit that

indicated this might eventually hold some promise, innumerable uncertainties remain with this

technology. A 30-day test period is simply insufficient to understand the long-term effects that

might be encountered when such potentially corrosive substances are injected into a utility boiler. 

There would likely be effects on the ability to sell or dispose of fly ash, corrosion on ductwork

and/or collecting plates, and possibly the production of potentially harmful by-products such as

dioxin.

Response:

EPA appreciates the commenters input to the record on the status of control

technologies. The Agency's position on the state of Hg technology is contained in the EPA 's

Office of Research and Development white paper (see Control of Emissions from Coal-Fired

Electric Utility Boilers: An Update, EPA/Office of Research and Development, March 2005).

4. CATF and Cinergy both modeled more stringent MACT-type options. CATF

assumed that ACI would be available in 2005 for all coal types. Cinergy assumed

that ACI would be available in 2005 for all coal types in one scenario and in 2010 for
9-lvi

all coal types for another scenario. EPA assumed commercial application only

beginning in 2010 with 70-90 percent removal levels. The year of availability for

ACI makes a large difference in the projected impacts of a MACT-type option. 

What assumptions for ACI availability are most appropriate to consider in a

modeling analysis, at what quantities, for what coal types, and why?

Comment:

One commenter (OAR-2002-0056-5464) reviewed the IPM modeling summaries

highlights as an important fact: the results are only as good as the variables used in the model. 

That is, the inputs and assumptions used in the model are not only critical to its accuracy and

success but, more importantly, assumptions about availability, control efficiency and cost (both

capital and operation and maintenance costs) predetermine its results. Unfortunately, they

believed several of the assumptions and inputs described in the NODA are fundamentally flawed

and account for unrealistic results. For example, the Cinergy model assumes that ACI would not

be available until 2010 (five years from now). This is erroneous, in that ACI is available now. 

Further, if a unit has difficulty complying with the MACT limit by 2008, using ACI and the

existing control system on the unit, then the Clean Air Act, under Sections 112(i)(3) and

112(i)(4), contains provisions that could offer additional time. Because ACI is available now and

the Clean Air Act provides for extensions for more substantial control device addition or

replacement, the commenter does not agree there would be a need for power plants to shut down

for as long as two years, as the Cinergy model assumes. In fact, installation of ACI requires little

down time and may be sufficient on many plants to achieve substantial Hg control. With

halogenated sorbents, this may be all that is required for most plants to achieve 90 percent or

more control. In cases where existing particulate control at coalfired units is poor and needs to be

replaced or supplemented with more effective particulate control, the compliance period for the

rule should be adequate to avoid disruptions in power supply. If needed, more time can be

allotted on a case-by-case basis, long-term shutdowns can be avoided, and any shutdowns can be

planned to avoid disruptions.

Response:

EPA appreciates the commenters input to the record on the status of control

technologies. The Agency's position on the state of Hg technology is contained in the EPA 's

Office of Research and Development white paper (see Control of Emissions from Coal-Fired

Electric Utility Boilers: An Update, EPA/Office of Research and Development, March 2005).

Comment:

One commenter (OAR-2002-0056-5332) agreed that the year of availability of ACI as a

control option for Hg is a key issue in the modeling analyses. The Agency has apparently

received many comments on this issue, ranging from the view that the technology is commercially

available today to the opinion that it will not be commercially available until well after 2010. The

commenter does not have first-hand information with respect to the date on which ACI should be

considered a commercially viable option for Hg control from coal-fired power plants. However,

the commenter offers the following evidence in support of the proposition that this technology

should be considered available on the earlier end of the time frame being considered, with the

caveat that the effectiveness and cost of ACI in reducing Hg emissions will depend to some
9-lvii

degree on the details of plant configuration and type of coal burned.

First, ICAC, which is the national trade association of companies that supply air pollution

control and monitoring technology, has gone on record in written comments submitted to EPA,

and in testimony presented at a Congressional hearing, that ACI systems are currently available,

have already been used in full-scale applications for the power sector and other industrial sectors,

and can be applied to any plant configuration and coal type. It can be argued that considerations

of self interest may contribute to ICAC’s conclusions. On the other hand, ICAC’s claims that

site-specific guarantees for activated carbon systems are being offered commercially in the

marketplace today for many plant configurations and coal types certainly should not be ignored.

Second, a number of states, including Massachusetts, New Jersey, Wisconsin and

Connecticut, have already promulgated Hg reduction requirements. In some of these states, strict

Hg reduction requirements are being imposed in the 2006 to 2008 timeframe, and compliance will

require use of ACI or of another approach that will achieve similar levels of reduction. In

developing these regulations, the states have conducted evaluations that have lead them to

conclude that activated carbon will be a commercially available option in this timeframe.

And finally, the regulations EPA promulgates will themselves play a role in driving the

commercial availability of ACI and other control technologies. Relatively stringent standards will

propel the commercial availability of technology, while less strict requirements will forfeit this

benefit. By the same token, the more certainty the requirements offer from a legal

perspective-whether by virtue of legislation or rules that are likely to withstand legal challenge-the

more likely the requirements will be to drive the early commercial availability of controls.

Response:

EPA is finalizing a cap-and-trade approach under section 111. EPA is establishing a

phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for

rationale. EPA appreciates the commenters input to the record on the status of control

technologies. The Agency's position on the state of Hg technology is contained in the EPA 's

Office of Research and Development white paper (see Control of Emissions from Coal-Fired

Electric Utility Boilers: An Update, EPA/Office of Research and Development, March 2005).

Comment:

One commenter (OAR-2002-0056-5475) noted that the utility of using ACI as a control

method was discussed in the NODA. The acting principle of ACI is that by injecting carbon

additional Hg is captured in the existing particulate control device in a manner similar to how the

particulate form of Hg in the gas stream is already being captured. The commenter states that it is

in favor of the use of this approach for significantly reducing Hg emissions. This technology has

been used to successfully reduce Hg emissions at several coal-fired utilities across all coal types.

Response: 

EPA appreciates the commenters input to the record on the status of control

technologies. The Agency's position on the state of Hg technology is contained in the EPA 's

Office of Research and Development white paper (see Control of Emissions from Coal-Fired

Electric Utility Boilers: An Update, EPA/Office of Research and Development, March 2005).
9-lviii

Comment:

One commenter (OAR-2002-0056-5475) noted that brominated activated carbon injection, a form

of ACI where the carbon is combined with bromine before injection, has demonstrated 95 percent

Hg removal at Great River Energy’s Stanton 10 Plant. Injecting brominated activated carbon

tends to convert a higher portion of the elemental Hg to the oxidized form. This is analogous to

the effect naturally occurring chlorine in coal has on Hg emissions. Achieving 95 percent removal

at the Stanton 10 Plant is significant since it burns lignite coal, which is generally recognized as

the most difficult to control. Lignite is difficult to control, in part, because lignite’s chlorine

content is typically low. This commenter states that it does not appear that EPA has considered

the impacts of the recent improvements to the ACI technology in the proposed MACT rule.

Response: 

EPA appreciates the commenters input to the record on the status of control

technologies. The Agency's position on the state of Hg technology is contained in the EPA 's

Office of Research and Development white paper (see Control of Emissions from Coal-Fired

Electric Utility Boilers: An Update, EPA/Office of Research and Development, March 2005).

EPA has included the examination of technology improvement in its analysis of the costs of the

final rulemaking. EPA has performed a sensitivity analysis assuming the introduction of second

ACI option using advanced sorbents, leading to lower capital costs. See sensitivity analysis in

Chapter 7 of final CAMR Regulatory Impact Analysis. 

Comment:

One commenter (OAR-2002-0056-5447) said that while they remain encouraged about

the potential for ACI and other Hg control technologies, the basic facts have not changed since

the commenter filed its April 30, 2004, comments. No technology, including ACI, has been

demonstrated to achieve the emission rate proposed under the new source MACT or NSPS

regulatory schemes on a commercial scale for all but the lowest Hg content coals. No vendors of

control technology are willing to guarantee Hg removal at the rates needed to achieve the

proposed new source emission levels. This lack of guarantees affects financing, choice of fuel,

and ultimately the economic viability of the unit. If units are not economically viable, they will not

be developed and the nation’s energy supply will suffer.

The commenter noted that any estimate of when Hg-specific control technologies will

become commercially available remains uncertain. All technologies must be tested on a broad

range of coals over longer periods of time. Balance-of-plant issues must be identified and

resolved.

EPA must base its ACI availability and performance projections on realistic development

estimates and not on assumptions that there will be “funding [for and the] successful

implementation of an aggressive, comprehensive [ACI] research and development program at

both EPA and the U.S. Department of Energy.” 69 Fed. Reg. 69870, col. 2-3. EPA explained in

its January 2004 white paper that implementation of such a research and development program is

the basis for its projection that ACI technology will be available for commercial application after

2010 and that removal levels in the 70-90 percent range could be achievable. 69 Fed. Reg.

69870, col. 2. In fact, there is no assurance that ACI will be commercially available by 2010.
9-lix

Response:

EPA appreciates the commenters input to the record on the status of control

technologies. The Agency's position on the state of Hg technology is contained in the EPA 's

Office of Research and Development white paper (see Control of Emissions from Coal-Fired

Electric Utility Boilers: An Update, EPA/Office of Research and Development, March 2005). 

EPA has included the examination of technology improvement in its analysis of the costs of the

final rulemaking. EPA has performed a sensitivity analysis assuming the introduction of second

ACI option using advanced sorbents, leading to lower capital costs. See sensitivity analysis in

Chapter 7 of final CAMR Regulatory Impact Analysis. Commenter is referred to the preamble

for discussion of NSPS limits.

Comment:

One commenter (OAR-2002-0056-5458) contended that the results of the numerous

modeling summaries provided in the NODA are only as good as the input variables. The

December 2000 finding clearly established an “appropriate and necessary” finding to reduce Hg

emissions by properly developing a NESHAP for coal fired utility plants. The commenter

believed the use of activated carbon injection and other alternative sorbents which will reduce Hg

emissions from both bituminous and sub-bituminous coals has advanced greatly and would be

available much earlier than 2010 as speculated in some of IPM runs provided in the NODA. The

commenter was also concerned that the EPA did not conduct, and provide for comment, the

additional modeling with the IPM to evaluate the more stringent MACT options. This was

previously requested by the state environmental agency representatives who served on the Federal

Advisory Committee Act Utility Workgroup.

The IPM input data comparing MACT based approaches with alternative regulatory

approaches relies solely on the projected Hg reductions achieved with using activated carbon

injection (ACI) or similar sorbents. The analysis presented by Cinergy used a stringent MACT

value for all subcategories of coal but questioned the ability of ACI’s availability by 2010. The

DOE recently announced that six new projects would be in their second round of field testing for

ACI and new sorbents. (This is in addition to last year’s selection of eight projects by DOE.)

Both rounds of testing are aimed at meeting the DOE’s near term goal of having technologies that

can capture 50-70 percent of Hg emissions ready for commercial demonstration by 2005 for

plants burning bituminous coal and by 2007 for those burning lower rank coals and blends. By

2010, the DOE expects costs to be reduced by 25-50 percent.

Response:

EPA is finalizing a cap-and-trade approach under section 111. EPA is establishing a

phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for

rationale. EPA appreciates the commenters input to the record on the status of control

technologies. The Agency's position on the state of Hg technology is contained in the EPA 's

Office of Research and Development white paper (see Control of Emissions from Coal-Fired

Electric Utility Boilers: An Update, EPA/Office of Research and Development, March 2005).

Comment:

One commenter (OAR-2002-0056-5446) stated that it was worth noting that even with
9-lx

discrepancies in assumptions models of a stringent MACT without sub-categorization or with

inadequate subcategorization, predict a dramatic decline in demand for sub-bituminous coal. For

example, Cinergy modeling of a strict MACT without sub-categorization1 shows sub-bituminous

and lignite plants shutting down prior to the availability of dedicated control technologies. In

reality it is extremely unlikely that these plants would shut down for several years and then restart

when control technology became available. They would be far more likely to switch fuels or be

permanently retired. In this case the very significant declines in the use of subbituminous and

lignite coals predicted would have a very dramatic impact on US electricity supplies and regional

economies.

In addition, modeling by the Clean Air Task Force (CATF) of an Alternate Mercury

Control Scenario with a reduced level of sub-categorization showed a 27 percent decline in

sub-bituminous coal use relative to 2003.

These results demonstrate that the EPA must incorporate sub-categorization by coal rank

if it is to meet its commitment of implementing a rule that ensures a level playing field for all coal

types.

Response:

EPA is finalizing a cap-and-trade approach under section 111. As discussed in other

comment responses, the final rule takes into account the different levels of mercury control that

lignite, bituminous, and subbituminous coals can achieve and uses coal adjustment factors for

determining the state emission budgets and for EPA's example allocation for States to allocate at

the unit level. For further discussion see final rule preamble (section IV.C.4) and Technical

Support Document for the Clean Air Mercury Rule Notice of Final Rulemaking, State and Indian

Country Emissions Budgets, EPA, March 2005.

Comment:

One commenter (OAR-2002-0056-5510) stated that DOE projects that ACI technology,

capable of achieving a 50-70 percent reduction in Hg emissions from all coal types, will be

commercially available by 2010. In this regard, assumptions may be used for modeling purposes,

but those assumptions must have a rational basis, and must be conservative enough to take into

account the uncertainty and variability associated with ACI controls on the full range of boilers

and fuel types. The commenter referred to their supplemental Hg rule comments dated June 29,

2004:

“A fundamental problem in developing and predicting the performance of mercury control

technology is that mercury chemistry is poorly understood, particularly in context to the

wide range of conditions encountered in coalfired power plants. Correlations of mercury

speciation with flue gas composition are instructive, but have poor predictive power (i.e.,

wide confidence intervals) as discussed in the commenter’s May 14 comments on the rule. 

These numerical correlations fail to account for such important factors as flue gas and fly

ash composition, including unburned carbon, and heterogeneous gas-solid reactions

between mercury and the fly ash1. Work on scientifically based (i.e., a priori) chemical

models is underway, but their usefulness remains to be seen.”
9-lxi

Response:

EPA appreciates the commenters input to the record on the status of control

technologies. The Agency's position on the state of Hg technology is contained in the EPA 's

Office of Research and Development white paper (see Control of Emissions from Coal-Fired

Electric Utility Boilers: An Update, EPA/Office of Research and Development, March 2005).

Comment:

One commenter (OAR-2002-0056-5491) said that a revolution has occurred over the last

year in power-plant Hg-control technology. Coal chlorine content has now been made irrelevant. 

Consequently, the currently-proposed Hg MACT structures, limits, and timetables need to be

radically modified.

The EPA’s current MACT proposals were based on a fundamental assumption that the

low chlorine content of Western subbituminous coals and lignites severely limited the performance

of Hg reduction technology with these fuels.

For the traditional MACT proposal, this resulted in differing Hg emission floor limits

subcategorized by coal rank.

For the cap-and-trade proposals, this resulted in differing emission-allowance allocation

adjustment-factors by coal rank.

Treating the different coal ranks differently because of their chlorine contents resulted in

highly divergent standards which would lead to significant marketplace inequities and distortions:

Coal Type

Proposed Emission Standards Allocation

Adjustmen

t Factors Existing Plants (lb

Hg/TBtus)

New Plants (10-6 lb Hg/

MWh)

Lignite 9.2 62 3

Subbituminous 5.8 20 1.25

Bituminous 2.0 6 1

Fortunately, vast improvements in the performance and cost-effectiveness of activated

carbon injection technology (ACI) for low-chlorine subbituminous coal and lignites have recently

been conclusively demonstrated. Multiple DOE-co-sponsored full-scale retrofit demonstrations

by different contractors of ACI with brominated carbons at plants burning low-chlorine fuels this

past year consistently achieved Hg emission rates of less than 1.0 lb Hg/TBtus at very low costs. 

Moreover, these new brominated carbons are now commercially available for use by any plant.

Consequently, the currently-proposed Hg MACT structures, limits, and timetables have to be

radically modified to account for these developments.

At the very least, the MACT floor levels or adjustment factors for subbituminous coals
9-lxii

and lignites now have to be lowered to the levels currently proposed for bituminous coals. More

responsibly, subcategorized standards based in plant particulate-control equipment, rather than by

coal rank, should be promulgated, with resulting MACT floor levels of 1.0 lb Hg/TBtu or below. 

If a cap-and-trade system is proposed instead, its 2010 cap should be in the range of 8 to 10 tons

of Hg per year, not 34.

Response:

EPA is finalizing a cap-and-trade approach under section 111. EPA is establishing a

phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for

rationale. The final rule takes into account the different levels of mercury control that lignite,

bituminous, and subbituminous coals can achieve using existing NOx and SO2 controls and uses

coal adjustment factors for determining the state emission budgets and for EPA's example

allocation for States to allocate at the unit level. For further discussion see final rule preamble

(section IV.C.4) and Technical Support Document for the Clean Air Mercury Rule Notice of

Final Rulemaking, State and Indian Country Emissions Budgets, EPA, March 2005.

Comment:

One commenter (OAR-2002-0056-5488) noted that EPA’s January 30, 2004 proposed

rule making erroneously and unlawfully found that ACI for Hg control at EGUs is “not available

on a commercial basis.” As discussed in the commenter’s June 27, 2004, comments, this assertion

is manifestly unreasonable and contrary to law. Moreover, EPA’s assumptions about the costs of

controlling Hg, which were never justified, have now been rendered virtually meaningless based

on the advances achieved with low-cost halogenated sorbents.

While EPA is obligated to consider all comments submitted to the administrative record, it

should be extremely skeptical of cost analyses performed by the industry to be regulated, as time

and time again they have proven to be skewed toward dramatically overstating compliance costs. 

The assumption made by Cinergy in its power sector modeling that ACI will not be commercially

available until 2010 is a case in point. This assumption is laughable, given that ACI is

commercially available today. The corresponding suggestion that coal plants will temporarily

have to shut down is reminiscent of the hyperbolic statements of impending doom voiced by

representatives of the automotive industry when they faced emissions regulations in the 1970's. 

Likewise, Cinergy provides no support or justification whatsoever for the increased costs of SO2

control, increased cost of SCR, reduced Hg co-benefits and elevated discount rate that were

assumed in its modeling, compared to EPA’s analysis.

Response:

For final rule modeling analysis, EPA is not incorporating other commenter assumptions

into its modeling analysis. The assumptions used in EPA analysis of the final rule are discussed

in EPA's IPM documentation, available in the docket. EPA appreciates the commenters input to

the record on the status of control technologies. The Agency's position on the state of Hg

technology is contained in the EPA 's Office of Research and Development white paper (see

Control of Emissions from Coal-Fired Electric Utility Boilers: An Update, EPA/Office of

Research and Development, March 2005).

Comment:
9-lxiii

One commenter (OAR-2002-0056-5492) noted that ACI technology is currently being

offered for sale to utilities. For example, Council Bluffs Station is required to reduce Hg

emissions by 85 percent or use an injection rate of 10 lb/mmacf. Several vendors bid on this

system and offered guarantees. The commenter believes that an average 70 percent Hg reduction

is achievable over a large number of boiler installations using today’s technology. Based on this

input, they believed that ACI technology capable of Hg reduction over a large number of

installations is or will be commercially available by 2007-2008 for all coal types.

Response:

EPA appreciates the commenters input to the record on the status of control

technologies. The Agency's position on the state of Hg technology is contained in the EPA 's

Office of Research and Development white paper (see Control of Emissions from Coal-Fired

Electric Utility Boilers: An Update, EPA/Office of Research and Development, March 2005).

Comment:

One commenter (OAR-2002-0056-5502) referenced ACI availability and costs. Sorbent

injection, either with conventional activated carbon (ACI) or chemically-treated carbon (CTC)

appears to reduce Hg in the flue gas from on all coals. However, the maximum reduction

achievable and the percent reduction at any given sorbent injection ratio varies with coal type. 

This is especially true for ACI at plants fueled with western coals. CTCs show promise in

overcoming these constraints for those fuels, especially at plants equipped with a spray dryer and

baghouse, but many questions remain about this new technology–sustainable and widely

applicable high removals, possible emissions of the treatment chemical and/or corrosion caused by

it, large quantity availability of consistent quality material, etc. ACI costs for 70 percent Hg

reduction are predicted to range from 1.6 to 3.0 mills/kWh for low-sulfur eastern or Western

fuels; presumably, most plants burning medium–to high-sulfur eastern fuels would have an FGD

and therefore not need sorbent injection.

Response:

EPA appreciates the commenters input to the record on the status of control

technologies. The Agency's position on the state of Hg technology is contained in the EPA 's

Office of Research and Development white paper (see Control of Emissions from Coal-Fired

Electric Utility Boilers: An Update, EPA/Office of Research and Development, March 2005).

Comment:

One commenter (OAR-2002-0056-5429) stated that during 1999, EPA gathered data as

part of the ICR program to measure Hg capture in emission control equipment designed to

capture SO2, NOx, and particulates. These data showed that the same emission control equipment

captured lower amounts of Hg at plants burning subbituminous and lignite coals. When

sorbent-based Hg control technology was first applied to plants burning these Western coals, it

was discovered that while 50-70 percent Hg removal was achievable for units with ESPs, there

appeared to be a ceiling that prevented any higher levels of Hg removal for these coals (Durham

et. al., 2002).

It was speculated that the reason for the poorer capture of Hg from Western coals was
9-lxiv

that these coals had lower concentrations of halogens such as chlorine, bromine, and fluorine. It

appeared that halogens in coal resulted in gas-phase species that were critical in the reaction

processes that captured Hg. During 2004, research and development was conducted to determine

if higher levels of Hg removal could be achieved by supplementing halogens at these plants. 

Full-scale field tests were conducted in which various halogens were added to the coal, sprayed

into the boiler and impregnated onto the sorbent.

During 2004, full-scale field tests were performed on plants the burn subbituminous

Powder River Basin (PRB) coals and lignites. Two key configurations of emission control

equipment were evaluation:

• Spray dryer followed by a fabric filter

• ESP only

The first configuration was selected because the most likely air pollution control

configurations for new units burning subbituminous PRB coal or a lignite will be a spray dryer

absorber (SDA) followed by a fabric filter (FF). This configuration offers cost advantages to

meet stringent multi-pollutant control regulations. However, available data indicate that this

configuration demonstrates particularly low, native Hg removal and the effectiveness of

non-chemically treated activated carbon is limited (Sjostrom et. al. 2002).

The commenter, with support from DOE NETL and industry partners, conducted a Hg

control demonstration using sorbent injection into the SDA-FF at Sunflower Electric’s 360-MW

Holcomb Station. Holcomb Station is located near Garden City, Kansas. The unit is a

load-following sub-critical 360-MW pulverized coal opposed-fired Babcock and Wilcox Carolina

type radiant boiler designed to burn PRB coal. The existing unit is equipped with three spray dry

absorber modules followed by two very low air/cloth ratio reverse air fabric filters. Holcomb

primarily burns two different PRB coals, Jacobs Ranch and Black Thunder.

This test program was designed to provide a full-scale evaluation of different technologies

that can overcome the limited Hg removal achievable at these sites. Each technology was based

on supplementing certain halogens that are not available in sufficient quantities in these coals. 

The program was very successful in that three different technologies were found that have the

potential to produce high levels (>80 percent) of Hg removal in this difficult application (Starns,

et. al., 2004b). These technologies are:

1. Coal Blending: By blending western bituminous coal with PRB coal, the Hg removal

across the system increased to almost 80 percent even without injecting another sorbent. 

It is highly likely that firing a blend of Black Thunder and West Elk coals with ACI could

result in greater than 90 percent Hg removal. Results with other coal blends must be

evaluated.

2. Chemical Addition to the Coal: KNX, a proprietary chemical developed by ALSTOM

Power, was found to enhance the performance of a standard activated carbon. Mercury

removal of 86 percent was measured at a carbon feed rate of just 1.0 lb/MMacf.

3. Chemically Enhanced Sorbent: A proprietary product of NORIT Americas, FGD-E3,
9-lxv

produced Hg removal in excess of 90 percent.

It should be noted that the first two approaches were tested for very short periods of time. 

However, the effects were verified and demonstrated the potential of these technologies. In

contrast, the test program on NORIT’s E-3 involved injecting the enhanced sorbent for four

weeks. The results obtained during this period showed very high levels of Hg removal, average of

93 percent, at a significantly reduced injection rate of 1.2 lb/MMacf. During this test period Hg

emissions averaged 0.8 lb/TBtu.

In addition to the Holcomb tests, URS conducted a DOE/NETL sponsored program at the

Great River Energy’s Stanton Station Unit 10 (Machalek, et. al., 2004). This unit fires North

Dakota lignite and has the identical configuration of a spray dryer/baghouse as Holcomb. During

this test program two halogenated sorbents were tested, NORIT’s E-3 and Sorbent Technologies

B*PAC. Mercury removal levels greater than 90 percent were achieved at an injection rate of 1.5

lb/MMacf with both of these sorbents.

Following the success of the halogenated sorbents on spray dryer/fabric filters, a second

round of testing was conducted on plants burning subbituminous coals that only have ESPs for

emission control. This configuration represents the majority of existing plants that burn

subbituminous coals and was therefore very important to the industry. Two tests were conducted

during the summer and fall of 2004. The commenter conducted a test program at the Ameren

Meramec Station, which burns 100 percent PRB coal, as part of a DOE/NETL sponsored

program (Starns et. al., 2004c).

During this program, the performance of NORIT standard carbon Darco FOD was

compared to the halogenated version Darco FOD E-3. With the standard carbon, the “ceiling

effect” is observed in that a maximum removal of about 70 percent Hg removal is achieved at a

feed rate of 3-5 lb/MMacf. No additional Hg removal is obtained even if the carbon feed rate is

double and tripled. In contract, the E-3 overcomes this effect and greater than 90 percent Hg

removal is achieved at a feed rate of 3 lb/MMacf.

A similar program was conducted by Sorbent Technologies at the Detroit Edison St. Clair

Station (Nelson, et. al., 2004). This unit burns a blend of 85 percent PRB coal with 15 percent

Eastern bituminous coal. This test involved the one month evaluation of Hg removal using

Sorbent Technology’s brominated activated carbon B*PAC injected upstream of the cold-side

ESP. During the duration of the test program, B-PAC removed 94 percent of the Hg emissions

when injected at a rate of 3 lb/MMacf. The Hg emission rate was reduced to 0.4 lb/TBtu.

The Department of Energy National Technology Laboratory, Southern Company, and

EPRI funded a program to evaluate sorbent injection for Hg control for a year of continuous

operation (Bustard et. al., 2004; Berry et. al., 2004). The test was conducted at Alabama Power

Company’s Plant Gaston Unit 3. The overall objective was to evaluate the long-term effects of

sorbent injection on Hg capture and COHPAC® performance. Data from the testing will be used

to determine:

1. Air-to-cloth ratio;

2. Advantages/disadvantages of high-permeability fabrics; and 
9-lxvi

3. Design criteria and costs for new TOXECONTM systems.

Long-Term Original Bags

Activated carbon was injected into the COHPAC baghouse nearly continuously from June

26 through November 25. presents a snapshot of data during the long-term test. Inlet

and outlet total vapor-phase Hg, calculated Hg removal, carbon injection concentration, baghouse

cleaning frequency, and inlet mass loading are presented. Mercury removal varied between 50

and 98 percent, with an overall average of 86 percent.

One thing that was clear from these tests was that the current air-to-cloth ratio was too

high to inject sufficient carbon to achieve 90 percent Hg control. A new TOXECON baghouse

would have to be designed at a lower air-to-cloth ratio. One way to overcome the operating

limitations at this site was to operate at low load/lower flow for an extended period. While at

these conditions, carbon injection could be increased and performance data could be tracked. The

primary objectives of these short tests were to 1) determine the injection concentration necessary

to achieve 90 percent removal and 2) determine the impact of carbon injection on cleaning

frequency at this lower air-to-cloth (A/C) ratio. An educated estimate of the ideal air-to-cloth

ratio was about 6.0 ft/min.

Southern Company was able to schedule an extended period of low load operation for

Gaston Unit 3. Three injection rates were evaluated during the 72-hour test. The first test was

conducted at the highest injection rate possible under normal operating conditions, 20 lb/h. At

this rate and the lower flow, the injection concentration was 0.9 lb/MMacf instead of 0.6

lbs/MMacf. The injection concentrations were then increased up to a maximum of nominally 3.3

lb/MMacf.

The results from this test, including inlet and outlet Hg concentrations, Hg removal, and

cleaning frequency are presented in . At an injection concentration of 0.9 lb/MMacf, Hg

removal was between 80 and 90 percent. When injection concentration was increased above 2

lb/MMacf, Hg removal was well above 90 percent and there were no episodes when the removal

dropped below this level. Cleaning frequency was acceptable at all injection rates.

Table 1. Results Summary from Low-Load Tests, November 2003

Injection

Rate

(lb/h)

Injection

Concentration

(lbs/MMacf)

Inlet Hg

Concentration

(g/Nm3

)

Outlet Hg

Concentration

(g/Nm3)

RE

(%)

Cleaning

Frequency

(pulses/bag/hour)

20 0.9 20.6 3.2 84.2 0.6

45a 2.0 22.2 1.0 94.6 0.8

70 3.3 21.4 0.61 97.1 1.4 a

 Last 18 hours of 45 lb/h test.

A set (2,300 bags) of high-perm bags was purchased and installed in the B-side baghouse. 

The differences in design were denier (an indication of fiber diameter; 2.7 versus 7.0 denier) and
9-lxvii

permeability (nominally 30 versus 130 cfm/ft2 @ 0.5" H2O). The primary goals for this test were

to:

1. Demonstrate improved pressure drop performance of the high-perm bags; and

2. Increase carbon injection concentration to achieve a higher Hg removal than was possible

with the original bags.

Carbon injection rate was incrementally increased from 20 to 45 lb/h. Because baghouse

cleaning frequency was acceptable, it was possible to inject at a constant rate and not reduce

injection when inlet mass loading increased. Average Hg removal for five different injection

conditions is shown in . The average Hg removal was higher in each of the shorter tests

than the 85.6 percent removal that was measured for the four-month carbon injection tests with

the original bags. These tests show that there is no difference in the effectiveness of carbon

injection for Hg control using either the original bags or the high-perm bags.

Table 2. Average Mercury Removal, Inlet Mass Loading, and Cleaning 

Frequency with High Perm Bags

Injection Rate

(lb/h)

Injection

Concentration

(lbs/MMacf)

RE

(%)

Inlet Mass Loading

(gr/acf)

Cleaning

Frequency

(pulses/bag/hour)

20 0.6 87 0.1 0.6

25 0.8 91 0.05 0.7

30 1.0 94 0.06 0.7

35 1.1 93 0.02 0.6

45a 1.3a 92a 0.05a 1.0a

a

 Long-term test-these data are from only the first two weeks at this condition.

Because it is expected that cleaning frequency will increase over time, especially as the

new bags season, the long-term tests were conducted at an injection rate of 45 lb/h. For a two

week period with an injection rate of 45 lbs/h (1.3 lb/MMacf), Hg removal was 92 percent, with a

maximum hourly value of 98 percent and a minimum hourly value of 80 percent.

Conclusions from Long-Term Test

• TOXECON units designed at lower air-to-cloth ratios than COHPAC units are capable of

high, 90 percent, Hg removal. For TOXECON baghouses, it is recommended that the

maximum design gross air-to-cloth ratio be 6.0 ft/min.

• Activated carbon injection systems are simple, reliable, and commercially available. The

control programs can be easily adapted to varying operating requirements.

• Continuous Hg measurements are challenging but possible. Advancements to the

analyzers were made and the analyzers operated 24/7 for nearly 20 months.
9-lxviii

• Activated carbon effectively reduced Hg emissions for extended periods over a wide range

of operating variables with a COHPAC baghouse.

• At an average injection concentration of 0.55 lb/MMacf, over a four-month period

average Hg removal was 86 percent.

• For these tests, injection concentration was limited by high, baseline COHPAC cleaning

frequency.

• High inlet loading into the COHPAC baghouse contributed to variable baseline Hg

removal. It is also believed that these conditions allowed for higher Hg removal at a

relatively low carbon injection concentration.

• Replacing the original 2.7 denier bags with 7 denier, high-perm bags, improved the

COHPAC’s ability to handle periods of high inlet loading.

• Short tests at higher injection rates with the high-perm bags showed that is was possible to

achieve greater than 90 percent average Hg removal. However, Hg removal still varied

between 80 and 98 percent during these periods and higher injection rates would be

required to maintain consistent, 90 percent removal.

EPRI TOXECON TECHNOLOGIES

For some plants, one of the disadvantages of injecting activated carbon is its impact on the

salability or reuse of ash. Tests have shown that the activated carbon interferes with chemicals

used in making concrete. One straightforward, cost-effective approach to achieving high Hg

removal without contaminating the fly ash is the use of the EPRI COHPAC® (COHPAC) and

TOXECONTM (TOXECON) processes that are currently commercially available. COHPAC is an

EPRI-patented concept that places a high air-to-cloth ratio baghouse downstream of an existing

ESP to improve overall particulate collection efficiency. The process becomes TOXECON when

a sorbent such as activated carbon is injected upstream of the baghouse located downstream of an

ESP. With this configuration, the ash collected upstream of the carbon injection remains

acceptable for sale (typically >99 percent of the ash.) The downstream baghouse provides an

effective mechanism for the activated carbon to have intimate contact with vapor-phase Hg,

resulting in high levels of Hg control at relatively low sorbent injection rates.

The advantages of the TOXECON configuration are:

• Sorbents are mixed with a small fraction of the ash (nominally 1 percent), which reduces

the impact on ash reuse and waste disposal.

• Full-scale field tests have confirmed that fabric filters require only 10-20 percent of the

sorbent required by ESPs to achieve similar removal efficiencies.

• Capital costs for COHPAC are less than other options such as replacing the ESP with a

full-sized baghouse or larger ESP.
9-lxix

• COHPAC requires much less physical space than either a larger ESP or full-size baghouse

system.

• Outage time can be significantly reduced with COHPAC systems in comparison to major

ESP rebuilds/upgrades.

The TOXECONTM configuration offers an advantage over injecting carbon ahead of a

single particulate control device because it prevents contaminating fly ash with carbon. Although

it is a highly effective configuration for removing Hg from flue gas, retrofitting existing plants

with a baghouse can be expensive. An attractive alternative solution is EPRI’s TOXECON IITM

technology, in which the same effect can be achieved without a baghouse but instead uses the

existing multi-field ESP alone. In this configuration, carbon is injected within the ESP into

downstream collecting fields. The majority of the fly ash is collected in the inlet ESP fields while

carbon is injected in one or more downstream ESP fields. With this approach, most of the fly ash

in the flue gas will have been collected in the first several fields (in general, 70-90 percent of the

ash in flue gas is collected in each field), and beneficial use of this ash can is preserved since it will

contain no carbon. The remaining fields of the ESP will then serve to collect the injected carbon. 

Any ESP with multiple fields can potentially use this approach. Besides activated carbon, other

sorbents that can capture Hg can be used.

The main advantages of this approach are:

• preservation of the large majority of fly ash sales,

• potential for sorbent recycle, regeneration and reuse,

• enhanced oxidation of elemental Hg to increase capture in a downstream scrubber,

• minimal capital cost, and

• minimizes amount of Hg-bearing byproducts needing processing or disposal.

In August of 2004, the commenter first reported the results of the first full-scale

evaluation of TOXECON IITM at Coal Creek Station through a program funded by Great River

Energy and EPRI (Starns, et al. 2004a). These short-term tests demonstrated promise for Hg

removals of >70 percent. Results with the mid-ESP injection of TOXECON IITM are comparable

to those obtained injecting the sorbent upstream of the ESP.

The commenter stated that this technology is based on the fact that up to 90 percent

in-flight capture of Hg can be achieved with a residence time of only one-half second as

demonstrated on their earlier programs funded by NETL. In an ESP, the gas velocity is 4-6 feet

per second, so a one-half second residence time requires 2-3 feet of space. This amount of space

is often available between sections of an ESP.

It should also be noted that the data was obtained using the standard NORIT Carbon

Darco FOD. In both cases the “ceiling effect” is clearly visible indicating the deficiency of

gas-phase halogens. During 2005, the commenter will conduct a full-scale field test of

TOXECON IITM on a plant burning 100 percent PRB coal. The halogenated sorbent E-3 will be

tested at this site. If these tests confirm the performance of this advanced sorbent for this

application, then higher levels of Hg removal will be achieved at greatly reduced injection rates. 

Keeping the sorbent injection rates low minimizes the potential of any negative effects of the
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carbon on the electrical components in the ESP. The combination of TOXECON II and E-3

would provide a very low cost option for plants burning Western coals that want to achieve high

levels of Hg control while continuing to sell the majority of their ash.

Impact of Enhanced Sorbents on Economics of Mercury Control

The commenter stated that based upon the results of the first four full-scale field tests,

cost estimates were made for applying this technology to the US fleet of coal-fired boilers. In an

EPA analysis, it was concluded that 80-90 percent control of Hg for the majority of plants could

be achieved for less than $2/MWh (Srivastava et. al., 2004). A DOE analysis concluded that 60-

90 percent Hg removal would cost between 1.3 and 2.4 $/MWh depending on the coal and type

of emission control equipment (Hoffmann and Ratafia-Brown; 2003). In addition, DOE has

established goals of reducing costs over time by 25-50 percent by funding full-scale field tests of

improved technology.

The test results achieved during 2004 show significant improvement in both the levels of

Hg removal achievable and the cost of control technology. From four different full-scale field test

programs conducted on PRB, lignite, and PRB/bituminous blends, greater than 90 percent Hg

removal was achieved on the most difficult emission control equipment configurations at a cost of

less than $0.6/MWhr. This shows how rapidly the sorbent-based Hg control technology is

advancing.

It should also be pointed out that one of the additional advantages of the technology is

that all of the users can benefit from the improvements in sorbents as they become available. The

technology is sufficiently generic that the improved products can be feed using the same sorbent

storage and feed equipment. This means that as additional progress is made in sorbents over the

next 3 to 5 years resulting in even lower costs, the power industry will be able to take advantage

of the improvements even if it purchase the equipment today. In other words, an early adopter is

not stuck with 2004 technology if a decision is made today on equipment for 2008.

Response:

EPA appreciates the commenters input to the record on the status of control

technologies. The Agency's position on the state of Hg technology is contained in the EPA 's

Office of Research and Development white paper (see Control of Emissions from Coal-Fired

Electric Utility Boilers: An Update, EPA/Office of Research and Development, March 2005). 

EPA has included the examination of technology improvement in its analysis of the costs of the

final rulemaking. EPA has performed a sensitivity analysis assuming the introduction of second

ACI option using advanced sorbents, leading to lower capital costs. See sensitivity analysis in

Chapter 7 of final CAMR Regulatory Impact Analysis.

Comment:

One commenter (OAR-2002-0056-5535) agreed with EPA that Cinergy’s assumption

concerning the date of availability of ACI drives the results of this analysis, and focused our

comments on this issue. EPA has already stated that it is aware of additional Hg data, particularly

the testing of various halogenated sorbents. Given the success of the halogenated sorbents in

capturing Hg during initial testing, it is no surprise that over extended test periods (30 days),
9-lxxi

these sorbents delivered Hg reductions higher than 90 percent at these subbituminous coal-fired

boilers. Given the most recent test data and the numerous studies presented at the 2004

“Mega-Symposium” (EPA was a sponsor, so the agency is surely aware of the data presented),

the agency must concede that a national Hg reduction well in excess of 30 percent is achievable.

At issue then is the timing of the availability of such controls. EPA has received

assurances from the Institute of Clean Air Companies (ICAC) that the equipment and manpower

needed to design, manufacture and install the control equipment will be available to meet the

requirements of a MACT standard. Industry counters with the assertions that neither the

equipment nor the manpower will be available and further that the performance of the technology

performance is not assured.

The commenter has explored the issue of new technology acceptance in the electric power

sector and their analysis lends valuable insight into where Hg control technology is today in terms

of commercialization and adoption. Basically, the development and acceptance of new

technology has followed 6 steps. They are:

1. Laboratory testing,

2. Pilot-scale testing,

3. Full-scale field tests,

4. Full-scale tests at multiple sites,

5. Long-term demonstration at several sites, and 

6. Widespread implementation.

Regarding the first two steps, laboratory and pilot-scale testing of Hg control technologies

took place in the early to mid-90s. Full-scale field tests, including full-scale tests at multiple sites

were completed during 2001-2003 as illustrates. lists the facilities by coal type

and within each coal type in roughly chronological order. Thus, it is apparent that during the later

tests, as the technology has rapidly advanced, the Hg-capture efficiency has increased to the 90

percent range across all coal types. In addition, it can be seen that the earlier tests required

considerably more carbon to achieve the same results as the later tests with halogenated sorbents. 

The need for less carbon will considerably reduce control costs.

Table 1. Full-Scale Tests of Sorbent Injection Completed: 2001-2003

Site Coal Equipment

Injection Rate

(lb/MMacf) 

Percent Hg

Capture

Brayton Point LS-Bituminous ESP (2) 10 94.5%

PGE LS-Bituminous ESP 10 90%

Cliffside LS-Bituminous HS-ESP 6.4 > 80%

Gaston LS-Bituminous HSESP/COHPAC0.55 86%

Lausche HS-Bituminous ESP 4 70%

St. Clair Bit./Sub. Blend ESP 3 90%
Site Coal Equipment

Injection Rate

(lb/MMacf) 

Percent Hg

Capture

9-lxxii

Pleasant Prairie Subbituminous ESP 11.3 66%

St. Clair Subbituminous ESP 3 94+%

Holcomb Subbituminous SDA/FF 1.2 93%

Meramec Subbituminous ESP 3 90%

Stanton 10 Lignite SDA/FF 1.5 95%

Stanton 10 Lignite SDA/FF 1.5 90%

Source: Durham, M.D. Advances in mercury control technology to meet future needs. Presented

at PowerGen, December 2, 2004. Orlando, Florida.

Step 5 entails long-term demonstrations at multiple sites. A year-long test has already

been completed at the Gaston plant (average reduction 86 percent with an average performing

sorbent) and 3 other month-long tests have also been completed with success at the Holcomb, St.

Clair and Meramec stations. As shown in , numerous other full-scale tests at a variety of

plants are either ongoing or scheduled in the 2004-2005 timeframe.

The commenter also note that state Hg rules will go into effect by 2008, which will

provide additional long-term commercial experience with Hg controls. Compliance with some of

the state rules begins in 2008, consequently these facilities will have installed, tested and operated

ACI systems long before the compliance date. By 2008, 15 boilers in Massachusetts,

Connecticut, and New Jersey will be controlling Hg by more than 90 percent. These

bituminous-fired boilers have control configurations that are similar to 60 percent of the fleet and

will provide the early proving ground that industry maintains is needed prior to widespread

implementation of this technology.

Given this systematic evolution of the adaptation of activated carbon technology to the

power sector, the commenter was confident that this technology will not just be available prior to

2010 but widely commercially available in time to facilitate compliance with a 2008 MACT

standard. The commenter also noted for the record that not all plants will need to use ACI to

comply with a stringent standard. Conventional controls will achieve a stringent emissions level

for many plants, and precombustion controls and other technologies not represented in the IPM

(e.g., oxidizing catalysts and multipollutant controls) will also be options.

Table 2. Full-Scale Tests of Sorbent Injection Ongoing and Scheduled: 2004-2005

Site Coal Equipment Company

Gaston Low-S Bit FF ADA-ES

Holcomb PRB SDA/FF ADA-ES

Arapohoe PRB FF ADA Tech

Stanton 10 ND Lignite SDA/FF Apogee

Yates 1 Low-S Bit ESP/FGD URS
Site Coal Equipment Company

9-lxxiii

Yates 2 Low-S Bit ESP URS

Leland Olds ND Lignite C- ESP EERC

Meramec PRB C- ESP ADA-ES

Buck Low-S Bit H-ESPC-ESP Sorbent Tech

St. Clair PRB/Bit C- ESP Sorbent Tech

Miami Fort High-S Bit C- ESP ADA Tech

Conesville High-S Bit ESP/FGD ADA-ES

Nanticoke PRB/Bit ESP ADA-ES

Arapahoe PRB FF ADA Tech

Antelope Valley ND Lignite SDA/FF EERC

Stanton 1 ND Lignite C-ESP Apogee

M.R. Young ND Lignite FGD EERC

Monticello TX Lignite FGD EERC

Source: Durham, M.D. Advances in mercury control technology to meet future needs. 

Presented at PowerGen, December 2, 2004. Orlando, Florida.

Response:

 EPA appreciates the commenters input to the record on the status of control technologies. 

The Agency's position on the state of Hg technology is contained in the EPA 's Office of

Research and Development white paper (see Control of Emissions from Coal-Fired Electric

Utility Boilers: An Update, EPA/Office of Research and Development, March 2005). 

Comment:

One commenter (OAR-2002-0056-5566) submitting documentation to support its position

that technology to capture Hg from power plant flue gas is readily available, effective, and

affordable. Hence, the commenter urges the U.S. Environmental Protection Agency to finalize

expeditiously a Maximum Achievable Control Technology standard that reflects the state of

technology and the legal requirements of Section 112 of the Clean Air Act.

Recent large scale tests have been completed at several power plants nationwide that

demonstrate high Hg removal is possible using sorbent injection (see attached).

Activated carbon injection systems are simple, reliable, and commercially available. 

The control programs can be easily adapted to varying operating requirements. 

Over a four-month period average mercury removal was 86 percent. (Berry, Irvin,

Monroe, et. al., 2004)

Three different technologies [coal blending, chemical additives, and chemically

enhanced sorbents] were found that have the potential to produce high levels

(>80 percent) of mercury removal in [power plants that burn PRB coal). 
9-lxxiv

(Sjostrom, Starns, Amrhein, et. al., 2004)

Recent analysis completed by the commenter found the cost of high Hg removal to be

affordable (see attached). Using EPA’s cost estimates for installing sorbent injection and

advanced dry scrubbers, the commenter found that 90 percent Hg control would cost an average

of 0.15 and 0.22 cents/kWh, a one to three percent increase. These cost figures are in line with

estimates previously published by the Institute of Clean Air Companies, which estimates a 1.2 to

3.7 percent increase, and by the Department of Energy which estimates that 60-90 percent control

would cost 0.191 to 0.236 cents/kWh.

[The commenter’s] analysis found that retrofitting every coal-fired utility boiler

with mercury control equipment...would cost the average household from about 70

cents to over $2.00 a month... The cost of attaining 90 percent mercury control is

only slightly higher than 70-80 percent control.

Finally, to date, four states have finalized rules requiring coal-fired power plants to make

significant cuts in its Hg emissions by the end of the decade (see attached). According to the

Institute of Clean Air Companies, power plants already are bidding on or finalizing contracts for

Hg control equipment. Over 50 plants likely will be affected by the new rules finalized by the

states of Connecticut, Massachusetts, Wisconsin, and New Jersey. The pollution control market

is responding to the increasing demand, making it feasible for companies to meet tight Hg limits.

The EPA has at its disposal extensive technical documentation to support a stringent

MACT standard for coal-fired power plants, a standard that would achieve reductions comparable

to those achieved through other MACT standards. A stringent standard with flexible compliance

mechanisms can be developed to ensure that the timing and level of reductions are not

compromised. The commenter urges the EPA to explore all options in fashioning a MACT rule

for coal-fired power plants, and to adopt an appropriate MACT rule expeditiously.

Response:

EPA is finalizing a cap-and-trade approach under section 111. EPA is establishing a

phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for

rationale. EPA appreciates the commenters input to the record on the status of control

technologies. The Agency's position on the state of Hg technology is contained in the EPA 's

Office of Research and Development white paper (see Control of Emissions from Coal-Fired

Electric Utility Boilers: An Update, EPA/Office of Research and Development, March 2005).

Comment:

The commenter (OAR-2002-0056-5519) assumed that EPA would use the most recent

definition of “commercially available” advocated by representatives of the electric power industry;

that is, “technology that has gone through at least one year of long-term testing,” one would have

concluded that sorbent-based technologies (including activated carbon injection) and other

combinations of technology used in series; [including selective catalytic reduction (SCR), flue gas

desulfurization (FGD) and fabric filters (FF)], were currently commercially available. If EPA

wold include in its determination of commercial availability all of the technologies that had already

been used for at least the past 5 years by coal-fired power plants located in Europe; for example,
9-lxxv

wet electrostatic precipitators (wet-ESPs), EPA would be forced to conclude that those

technologies are not only commercially available, but also proven in practice.

The commenter was pleased to provide the following additional technical information to

support these comments and responded to EPA’s request on the availability and cost effectiveness

of these controls:

1. “Field Test Program for Long-Term Operation of a COHP AC System for Removing

Mercury from Coal-Fire Flue Gas,” Report No. 41591R09, October 25,2004,

,

2. “Evaluation of Sorbent Injection for Mercury Control,” Report No. 41986R04, October

29, 2004, ,

3. “Pilot Testing of Oxidation Catalysts for Enhanced Mercury Control by Wet FGD,” Paper

#36, Mega Symposium, , and

4. Field Test Program to Develop Comprehensive Design, Operating and Cost Data for

Mercury Control Systems on Non-Scrubbed Coal-Fired Boilers, Report No. 41005R19,

October 25, 2004, .

Response:

EPA appreciates the commenters input to the record on the status of control

technologies. The Agency's position on the state of Hg technology is contained in the EPA 's

Office of Research and Development white paper (see Control of Emissions from Coal-Fired

Electric Utility Boilers: An Update, EPA/Office of Research and Development, March 2005).

Comment:

One commenter (OAR-2002-0056-5477) referenced the cost of Hg control technologies

by stating that it is also important to note that both the capital costs and cost effectiveness of

controlling Hg from coal-fired boilers need to be presented in a realistic manner. For example, a

common but quite misleading practice is to present cost effectiveness in terms of dollars per

pound of Hg removed from the application of ACI or other technologies and compare this to the

costs of controlling a ton of NOx or SO2 from power plants. For example, typical values of cost

effectiveness are as follows: $5,000 to $30,000 per pound of Hg removed for ACI; $100 to $200

per ton of SO2 removed; and $1,000 to $1,500 per ton of NOx removed. Obviously, the control

costs appear high using such a comparison because Hg is emitted in far smaller quantities than

conventional pollutants (in the U.S., power plants currently emit “only” 48 tons per year of Hg;

compared to 5 million tons per year of NOx and over 10 million tons per year of SO2). Control

costs for Hg on a pound for pound or ton for ton basis are therefore necessarily higher. However,

it must be emphasized that Hg presents a far greater public health and environmental hazard on an

equivalent mass basis when compared to criteria pollutants such as SO2 and NOx.

A more illuminating metric for estimating true costs of technology for a project is when

the costs of controlling Hg with a technology such as ACI are expressed in terms of cost to the

ratepayer (e.g., mills per kWh of electricity). When this approach is followed, the costs are even
9-lxxvi

lower than the costs currently being incurred for control of pollutants such as NOx from EGUs. 

Note that these values for NOx are considered cost-effective by industry and regulatory agencies,

and were the basis for recent (1997-1998) state and federal requirements for wide-scale NOx

reductions from EGUs in the eastern U.S. under “Section 110 Transport SIP call” as well as the

EPA’s newly proposed (on January 30, 2004) Clean Air Interstate Rule (CAIR).

Response:

EPA's modeling of the final rulemaking includes presentation of results in several metrics

including marginal cost and retail electricity prices. See Chapter 7 of Final CAMR RIA for

further discussion of rulemaking analysis.

Comment:

The commenter,(OAR-2002-0056-5404), in response to EPA’s request for comment

regarding the various assumptions used for the modeling analyses conducted by EPA, CCAP,

Cinergy, CATF and EEI, submitted that its analysis is based on the most accurate assumptions

and therefore results in the most accurate predictions regarding compliance costs and the timing

of emissions reductions expected as a result of EPA’s proposed utility Hg rule. Moreover, the

generic industry-wide cost projections derived from the commenter’s modeling are fully

supported by the more recent company-specific cost estimates completed as part of the

commenter’s cost recovery filings with its state utility commission. The commenter noted that

other commenters modeled the effects of EPA’s Hg utility rule using overly optimistic

assumptions, which rendered overly optimistic conclusions regarding costs and achievability. 

According to the commenter, because their analysis is based on the most realistic assumptions, the

commenter’s analysis most accurately models the impacts of cost and timing associated with

EPA’s Hg utility rule.

The commenter noted that EPA recently published revised assumptions documentation

used for its Integrated Planning Model (IPM) Base Case 2004 (v.2.1.9). The commenter further

noted that the major changes incorporated into EPA Base Case 2004 include the capital costs of

Selective Catalytic Reduction (SCR) retrofits, its gas price forecast, the number of plants available

to switch to PRB coal, the cost and performance of new builds, and an update to particulate

controls on existing units. However, according to the commenter, EPA has left unchanged a

number of improbable assumptions that several commenters raised previously, including: the load

growth rate of 1.55 percent, the cost and performance of wet Flue Gas Desulfurization (FGD)

($201/kW), the cost and performance of Activated Carbon Injection (ACI) and ACI and Fabric

Filter (FF), the Hg co-benefits of FGD+SCR, the Hg emissions modification factors, and model

plant aggregations amongst others. Furthermore, according to the commenter, as EPA did not

mention any revision to the way coal units are aggregated, it appears EPA still plans to perform

MACT policy modeling runs without the capability of modeling plant-level emission constraints. 

The commenter stated that this model plant aggregation change is of particular importance when

analyzing Mercury MACT regulations that are implemented on a plant averaging basis. In

performing its IPM modeling analysis, the commenter took particular care to represent the model

plants in IPM along physical plant lines to capture the interactions that may occur between

individual units at the plant level. The commenter believed that the lack of this resolution in the

EPA analysis (as well as analysis by other parties relying on the EPA version of IPM) represents a
9-lxxvii

fundamental oversight in the studies performed.The commenter referred back to its Confidential

Business Information (CBI) Comments filed in March 2004 as to why disaggregating coal units to

the plant level allows for more realistic assessments of plant-level emission constraints.

Demand And Peak Growth

The commenter noted that the starting point for the EPA Base Case 2004 electric load

growth is the projections from the reference case of AEO 2004. The commenter stated that, as in

the past, EPA reduced demand growth levels in the AEO projection to account for voluntary

energy efficiency programs. According to the commenter, the average annual growth rate in

AEO 2004, based on the electric sales forecasts, is 1.77 percent. The commenter stated that EPA

revised this growth rate down to 1.55 percent. According to the commenter, this results in a final

calculated growth rate that is unchanged from the EPA Base Case 2003. The commenter stated

that, as it does with air quality modeling, EPA should not include in its future energy demand

modeling legislative or regulatory provisions that have not already been adopted. According to

the commenter, at a minimum, EPA should use the AEO growth rates or other historically based

growth rates in its reference case and, if necessary, carry out sensitivity runs with higher and

lower alternative energy growth patterns that bound potential future economic growth scenarios. 

The commenter referred back to its CBI Comments filed in March 2004 as to why the load

growth rate it uses in its analysis much more closely reflects reality.

The commenter stated that EPA’s lower average demand growth rates, and the resultant

energy consumption, directly impact the system and the costs of regulation. The commenter

further stated that the CCAP, in a number of sensitivities based on the EPA CSA scenario,

directly uses the higher average annual growth rate projected by AEO 2003. The commenter

noted that other modeling results provided in the NODA utilize higher average annual growth

rates. The commenter assumed a 2.3 percent annual average load growth rate and EEI assumed a

1.7 percent average annual growth rate. According to the commenter, as the annual energy

growth rate is compounded over the study period, a relatively small difference in the rate has

enormous implications over time.

Natural Gas Prices Have Been Revised Upwards, But Not Enough

The commenter noted that the EPA Base Case 2004 incorporates a higher natural gas

forecast, with the Henry Hub wellhead price increasing, in 1999 dollars, to $3.16 in 2020

compared to $2.94 in the EPA Base Case 2003. According to the commenter, this revision of

natural gas prices better represents the trajectory of natural gas prices going forward as evident in

comparisons with the other natural gas forecasts utilized by EIA in its Annual Energy Outlook

(AEO) 2003 and 2004, as well as in the other models submitted by the commenter and the EEI in

their comments. According to the commenter, though this revision has shifted the natural gas

supply curve upwards, it still falls well below the other forecasts previously mentioned. The

commenter noted that AEO 2003 predicts, in 1999 dollars, a price of $3.53 in 2020 and the

difference between AEO and EPA becomes slightly more pronounced with a price of $4.03 in

2020 forecasted in AEO 2004. The commenter further noted that the forecast used in their

modeling is comparable to AEO with a price of $3.45 in 2020 while EEI reaches $4.13 in 2020. 

The commenter referred to section II of its CBI Comments for a detailed description of how both

the commenter and EPA derive their natural gas prices and how they differ. The commenter
9-lxxviii

stated that gas price forecasts are important in analyses such as these as less expensive gas prices

artificially alleviate the pressure on coal units to generate, and exaggerate the ease of which the

system can inexpensively rely on new gas-fired generation to make up the shortfall. The

commenter further stated that over the past 12 to 24 months, various federal agencies and

committees have investigated the short- and long-term implications of natural gas usage and price

projections. According to the commenter, EPA has not provided a comparison of its estimates to

other federal findings which show significantly higher prices and decreasing domestic supply. The

commenter stated that EPA’s final analysis of the impact of these rules should include a range of

natural gas price forecasts based on potential real world implications if EPA’s overly optimistic

assumptions do not come true.

The commenter has noted that historical gas prices have been volatile, but have been

consistently higher then forecasts made by EPA, a trend especially evident when comparing the

gas prices EPA used during the late 1990s for analyzing the impact of SIP Call regulation on the

industry. The commenter noted that the table below compares recent forecasts made by EPA to

historical gas prices. According to the commenter, from 2000 through 2004 these periods

overlap. The commenter stated that it is worth noting that when comparing actual 2000-2004

historical data to that forecast by EPA in its 1995 and 1998 assumptions, actual prices were

approximately $4.29/MMBtu, while the average of EPA’s forecast over that same time period

results in a price of less than $2.00/mmBtu–a difference of over 100 percent.

Higher SCR Capital Cost Assumption

The commenter stated that in the case of unit retrofit costs, especially SCR costs, the

differences between EPA’s estimates and the commenter’s actual experience is quite substantial. 

The commenter stated that in the new EPA 2004 (v.2.1.9) assumptions, EPA increased its capital

cost assumption of SCRs from $62/kW to $83/kW (for a representative 500 MW unit). While the

commenter believed this move is in the right direction, it does not come close to reflecting the

actual costs of retrofitting such devices on existing generating units. The commenter’s estimates

for SCR costs were developed through the knowledge and experience gained during nine SCR

retrofit projects totaling 6,000 MW of capacity. The commenter stated that these actual costs for

compliance with the NOx SIP Call have been provided to their state utility regulatory commissions

for review and approval. In May 2004, the commenter’s regulated utility subsidiary in Indiana,

PSI Energy, received approval of these same NOx pollution control retrofit costs. The

commenter stated that EPA apparently has not verified its NOx control cost information by

comparing it with the most recent state utility regulatory commission cost recovery filings in

states which have recently implemented the NOx SIP Call. The commenter also stated that it

should be noted that the large number of SCRs retrofitted as a result of the SIP Call represents

the more cost-effective (i.e., lower capital cost) units. The commenter added that EPA apparently

has not considered the increasing difficulty, and thus the higher capital cost, of retrofitting

increasingly smaller units as the NOx caps get tighter. The commenter referred to costs

documented and made available to EPA in their past CBI comments.

No Changes To Cost And Performance Of Wet FGD And ACI and FF

The commenter stated that with the updates included in the EPA Base Case 2004, the cost

and performance of a Wet FGD and ACI and FF remain the same. According to the commenter,
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for a representative 500 MW unit, the capital cost of a Wet FGD is $201/kW and $55/kW for an

ACI and FF. The commenter believed these capital costs continue to be significantly understated

and emphasized that the cost assumptions used in its analysis, as documented and made available

to EPA in the commenter’s CBI Comments, Section V, more closely represent real-world retrofit

cost levels that will generally be experienced by the utility industry. The commenter noted that

these retrofit costs were derived from engineering estimates by the Chicago firm, Sargent &

Lundy, which has extensive experience in the design and application of these technologies.

The commenter stated that while the generic industry-wide cost estimates provided in their

past CBI comments indicate that EPA has significantly understated compliance costs, more recent

analyses undertaken by the commenter provide further support for this conclusion. The

commenter has recently started construction on a number of new wet FGD projects and has

provided more refined cost estimates to the Indiana Utility Regulatory Commission (PSI Energy

Cause 42622 and 42718) identifying the Company’s projected costs for complying with the

proposed SO2, NOx, and Hg reduction requirements. According to the commenter, the more

highly refined commenter-specific cost estimates provided to the Indiana Commission show costs

in excess of the generic cost projections previously provided to EPA in the commenter’s CBI

Comments. The commenter urged EPA, at a minimum, to use their more representative cost

estimates for pollution control retrofits which have been previously provided.

The commenter stated that EPA did not choose to update the emission reduction factors

associated with these pollution controls from those assumed in the EPA Base Case 2003

(v.2.1.6). The commenter noted that on a unit with an exiting CESP particulate control, EPA

continues to assume that a Wet FGD burning bituminous coal has an emission reduction factor of

66 percent compared with 59 percent assumed by the commenter. The commenter noted that the

co-benefit of a wet FGD combined with a SCR on a unit burning bituminous coal is assumed, by

EPA to result in a 90 percent reduction of Hg. This is higher than the 85 percent co-benefit that

the commenter believed is achievable and sustainable, and has particular significance regarding

the stringency of an Hg policy that is feasible without significant additional cost. The commenter

stated that this difference is found across different existing particulate controls and once again

highlights EPA’s more aggressive assumptions for cost and performance of retrofit options. The

commenter stated that more detailed information of their experience of the actual costs of these

pollution control technologies can be found in Section V of their CBI Comments. According to

the commenter, while EPA moderated some of its very aggressive assumptions for emission

reductions factors (ERF’s) when updating from the EPA Base Case 2002 (v.2.1) to the EPA Base

Case 2003 (2.1.6), the commenter believed that this issue should have been readdressed in the

latest update. According to the commenter, based on recent test data, EPA acknowledges the

difficulties associated with the still overly-aggressive co-benefit assumptions it assumed in its

2003 and 2004 Base Cases (v.2.1.6 and v.2.1.9), in the text of the NODA (pg. 69871),

particularly regarding sub-bituminous coals. The commenter stated that, for example, for a unit

configured with a coldside ESP and with a FGD and SCR, EPA recommends changing the ERF

from 66 percent to 16 percent. The commenter believed that these updates should be

incorporated into any future EPA modeling as they reflect actual results at test units. The

commenter also noted that these changes will have a significant impact on the Hg reduction levels

that can be achieved through co-benefits, and therefore the cost of attaining Hg reductions

system-wide.
9-lxxx

The commenter stated that one clarifying point must be made regarding their assumption

of ACI availability. The commenter further stated that in the EPA NODA, Section 4, part D,

EPA states that for the commenter’s other modeled scenarios, including a MACT scenario, it

assumed ACI would be available in 2005. The commenter stated that this is factually incorrect. 

According to the commenter, they modeled the availability of ACI beginning in 2007 for its policy

scenarios, but believed that widespread commercial availability of ACI is not likely before 2010.

Other Major Assumptions

The commenter stated that EPA recognizes the need for regular updating of model inputs

to keep up with changing energy, environmental and macroeconomic markets and understanding

of future conditions. The commenter further stated that, however, EPA has not taken this process

to the next logical step which is an analysis of the accuracy of the models output. The commenter

noted that in the case of air quality modeling the EPA has detailed guidance, Guideline for Air

Quality Models, Appendix W (July 2003) 40 CFR Part 51 on the application of models and

testing the models output against known actual air quality measurements and conditions.

The commenter pointed out that the true test of a model’s capabilities is when its output

compares favorably, within an acceptable confidence interval, to actual observed data. According

to the commenter, neither in this most recent IPM modeling nor in any case prior to that has EPA

ever provided information about how the IPM modeling output compares to representative

known energy or environmental outcomes in the real world. The commenter stated that in this

most recent reference case modeling EPA skips over the recent historical years and the current

year and does not even provide any model output results until 2007. The commenter further

stated that, thus, affected sources have no way of checking the reliability of the models input

assumptions or output when compared against historical or recent actual energy prices, allowance

prices or SO2, NOx or Hg emissions. The commenter added that these uncorroborated national,

state or plant level emissions are the same emissions that are then used as inputs into the air

quality models that EPA, and in some cases state regulatory agencies, use to evaluate in-state

source impacts as well as significant contribution impacts of long range interstate transport. The

commenter stated that, thus, affected sources and decision-makers have no basis for quantifying

the accuracy, precision and sensitivity of the model to changes in model assumptions and

ultimately in making emission control policy decisions. The commenter recommended that EPA

provide an evaluation of the IPM model based on a systematic performance evaluation of a wide

range of temporal and spatial outputs using current real world model inputs.

Table 1 details the major assumptions across each of the modeling described in the

comments submitted by the commenter, CCAP, CATF, and EEI. The following section will lay

out the implications of these assumptions on the results from these different modeling comments.

Table 1
9-lxxxi

Category Commenter 5404 EPA (v.2.1.6) EPA (v.2.1.9)

Source Commenter

Assumptions

Document 02.03.04

EPA Assumptions

Updates v.2.1.6, July

2003

EPA Assumptions

Updates v.2.1.9,

October 2003

Energy and Peak

Demand (natl avg)

2.3% Demand

Growth, 2.2% Peak

Growth

1.55% Demand and

Peak Growth

no changes from

2.1.6

SO2 Control Cost and

Performance

500MW = $276/kW

(+adders for MACT

& timing)

500MW = $201/kW no changes from

2.1.6

Nox Control Cost

and Performance

(SCR)

500MW = $194/kW 500MW =

$62.15/kW

500MW =

$82.27/kW

SO2 and NOX

Controls for Mercury

SCR+FGD 85% Hg

co-benefit (bit with

CESP)

SCR+FGD average

90% Hg co-benefit

(bit)

no changes from

2.1.6

Mercury Control

Cost and

Performance (ACI

and Fabric Filter)

500MW = $95/kW 500MW - $55/kW no changes from

2.1.6

Reference Gas Price

Forecast (Henry Hub)

2005-$3.92, 2010-

$3.66, 2015-$3.49,

2020-$3.54

2005-$2.89, 2010-

$2.97, 2015-$2.96,

2020-$2.94

2010-$3.20, 2015-

$3.25, 2020-$3.16

PRB Fuel Switching

Capital, FO&M, and

VO&M PRB adders

into 3 separate size

categories. Additional

Adders for heat rate

penalty and 5 yr

amortization

(amortization CSA

only)

$50/kW adder increased # of plants

available $50/kW

adder

Capital Charge Rate

(CCR) and Discount

Rates (DR)

DR = 7.1%, CCR

=13.6%(retrofits)

DR = 5.34%, CCR

=12.0%(retrofits)

no changes from

2.1.6

Cost and

Performance of New

Builds

Commenter cost and

performance for gas

units,ICF cost and

performance for coal

units

Updated According

to AEO 2003

Updated According

to AEO 2004
Category Commenter 5404 EPA (v.2.1.6) EPA (v.2.1.9)

Source Commenter

Assumptions

Document 02.03.04

EPA Assumptions

Updates v.2.1.6, July

2003

EPA Assumptions

Updates v.2.1.9,

October 2003

9-lxxxii

Mercury EMF

EMF based on ICR

data for all non

commenter units.

Commenter specified

EMFs for commenter

units.

Updated Attachment

K. Changes made to

all types, most

significantly to cobenefits for SNCRs

and wet FGDs.

no changes from

2.1.6

Plant Aggregation Model plant along

physical lines

Model Plant Model Plant

Model Run Years

2004, 2006, 2007,

2008, 2009, 2011,

2015, 2020

2005, 2010, 2015,

2020

2005, 2010, 2015,

2020

Table 1 (has different headings)

Category CCAP CATF EEI (CRA)

Source EPA Assumptions

v. 2.1.6, July 2003

EPA Assumptions

Updates v. 2.1.6, July

2003

EEI Assumptions

Energy and Peak

Demand (natl avg)

EPA Assumptions

Updates v.2.1.6, July

2003, AEO 2003: 1.8%

Demand and Peak

Growth

1.55% Demand and

Peak Growth

1.8% Demand Growth,

1.95% Peak Growth

SO2 Control Cost and

Performance (Wet

FGD)

500 MW = $201/kW 500 MW = $201/kW 500 MW = $201/kW

Nox Control Cost and

Performance (SCR)

500MW = $62.15/kW 500MW = $62.15/kW 500MW = $62.15/kW

SO2 and NOX Controls

for Mercury

SCR+FGD average

90% Hg co-benefit (bit)

SCR+FGD average

90% Hg co-benefit (bit)

SCR+FGD average

85% Hg co-benefit (bit)

Mercury Control Cost

and Performance (ACI

and Fabric Filter)

500MW ~ $55/kW 500MW ~ $55/kW 500MW=$41.29/kW

Reference Gas Price

Forecast (Henry Hub)

Various Scenarios used

the following

assumptions: 1) EPA

(v2.1.6) 2) AEO 2003,

2005-$2.88, 2010-

$3.29, 2015-$3.55,

2020-$3.69

2005-$2.89, 2010-

$2.97, 2015-$2.96,

2020-$2.94

2004-$4.98, 2010-

$3.33, 2015-$4.06,

2020-$4.13
Category CCAP CATF EEI (CRA)

Source EPA Assumptions

v. 2.1.6, July 2003

EPA Assumptions

Updates v. 2.1.6, July

2003

EEI Assumptions

9-lxxxiii

PRB Fuel Switching

$50/kW adder $50/kW adder 50% annual limit for

noncurrent PRB-fired

units

CCR and Discount

Rates (DR)

DR = 5.34%, CCR

=12.0%(retrofits)

DR = 5.34%, CCR

=12.0%(retrofits)

DR = 6.05%, CCR

=13.32%(retrofits)

Cost and Performance

of New Builds

Updated according to

AEO 2003

Updated According to

AEO 2003

Updated According to

AEO 2004

Mercury EMF

Updated Attachment K.

Changes made to all

types, most significantly

to co-benefits for

SNCRs and wet FGDs.

Updated Attachment K.

Changes made to all

types, most significantly

to co-benefits for

SNCRs and wet FGDs.

Hg co-benefits based

on EPA’s 1999 ICR

data. ACI assumptions

from EPRI

Plant Aggregation Model plant Model Plant Unit Groups

Model Run Years 2005, 2010, 2015, 2020 2005, 2010, 2015, 2020 2004, 2008, 2010,

2012, 2015, 2018, 2020

The commenter reviewed the modeling results provided to EPA by other parties during

the comment period. The commenter noted that the majority of parties filing power sector

modeling results seem to agree that demand growth and natural gas price assumptions used by

EPA warrant modification, and so use assumptions from other sources in their model runs. The

commenter stated that it is extremely important to emphasize that in long-term planning models,

such as the IPM model used by the parties to analyze the cost of new regulations, model input

assumptions regarding demand growth and natural gas prices dramatically affect overall costs of

regulation. The commenter stated that these assumptions should be further considered by EPA as

it proceeds with its rulemaking. The commenter provided comments on some individual party

modeling as indicated below.

Modeling Results Provided by CCAP

The commenter stated that CCAP produced more than a dozen runs that seem to

demonstrate that timing and stringency of Hg caps have little bearing on the cost of regulation. 

The commenter also stated that it should be noted that the runs performed by CCAP were based

on the EPA modeling runs that analyzed the proposed Clear Skies Amendments and do not

specifically model the CAIR rule as proposed. The commenter stated that the results are

therefore not directly comparable to any of the modeling analyses performed by EPA in the course

of this rulemaking. The commenter therefore focused its comments on the conclusion that timing

and stringency of Hg caps, in general, are not very significant.

The commenter stated that it would be reasonable to expect that the timing of a Hg cap

would not be very significant if two things could be assumed: (1) The implementation of the initial

Hg cap coincides with any new SO2 and NOx regulations–so that Hg reduction benefits resulting
9-lxxxiv

from the installation of scrubbers and SCRs are available for complying with the Hg policy, and

(2) There is sufficient time to install all compliance options (and compliance options are

commercially available) before the policy takes effect. The commenter stated that, unfortunately,

neither can be assumed in this case. The commenter noted that under the MACT policy that EPA

proposes, Hg regulation would be introduced two years before new regulations for SO2 and NOx

take effect. The commenter stated that this would result in unnecessary costs as coal units would

need to comply with the Hg policy before controlling for SO2 and NOx–lessening the ability of

FGD and SCR co-benefits to reduce the burden of Hg regulation. The commenter further stated

that CCAP’s results do not show this result because it modeled a different policy–Clear

Skies–which requires new NOx controls to be in place fully two years before Hg regulations take

effect (2008 vs 2010), and SO2 controls to be in place at the same time Hg regulations take effect. 

According to the commenter, similarly, CCAP avoided genuine concerns over when ACI controls

would become commercially available (the commenter does not expect wide availability before

2010) and how quickly the U.S. coal fleet could be outfitted with ACI, FGD, and SCR controls

by assuming everything would be universally available from the beginning of the run. The

commenter stated that, therefore, any claim that timing does not matter is erroneous, predicated

on modeling CSA as opposed to the relevant policies, and being over-optimistic about the

availability of controls.

The commenter stated that, likewise, it would be reasonable to expect that the stringency

of Hg caps would not be significant if the cost of installing controls is low, the effectiveness of

those controls is high, and the cost of substituting options other than coal-fired generation is

modest. The commenter, however, believed the cost of retrofits to be much greater than the

estimates of CCAP, which used EPA assumptions, especially for the smaller units that would

become the price-setting units as the caps were made more stringent. The commenter also

believed Hg EMFs to be larger (i.e., the reductions smaller), and the cost of natural gas to be

greater–which both increases the need, and the cost, of switching from coal-fired generation to

meet more stringent caps. It is the commenter’s belief that more stringent caps would not be

possible without greatly increasing the cost burden of Hg regulation.

Modeling Results Provided By CATF

The commenter noted that the Clean Air Task Force (“CATF”) performed two runs using

EPA assumptions. The commenter stated that the first run shows CAMR MACT plus CAIR

using EPA assumptions, which allows for a relatively direct comparison with the commenter’s

model results for CAMR MACT plus CAIR. According to the commenter, from this comparison,

it is clear that EPA assumptions allow more pollution controls to be installed at lower costs than

the commenter’s assumptions allow–reducing the cost of regulation.

The commenter stated that the second run provided by CATF shows that EPA

assumptions allow for a much more stringent MACT rate while significantly increasing regulatory

costs by about 30 percent. The commenter further stated that this result is predicated on FGD

and SCR combinations providing the 90 percent reduction needed for the stringent MACT for

both bituminous and sub-bituminous coal units. The commenter maintained that it is unlikely that

an FGD and SCR combination could be depended on to meet such a strict standard, particularly

for units burning sub-bituminous coal.
9-lxxxv

Modeling Results Provided By EEI

The commenter stated that EEI runs adopt the industry’s view on FGD and SCR

co-benefits and other Hg emission factors, and therefore show higher annual Hg emissions under

MACT policies than EPA assumptions produce. The commenter added that, in fact, EEI’s

forecast for emission levels are very similar to the emission levels shown in the commenter’s

filing. The commenter further added that even so, it could be said EEI’s runs do not go far

enough. The commenter believed EEI’s assumptions for costs of emission control equipment

were comparable to EPA’s cost estimates. The commenter states that while energy demand

growth assumptions were marginally increased from EPA’s starting point, the growth rate is still

fully one-third below historical growth and far below what is likely to occur over the forecast

period. The commenter further states that these assumptions serve to significantly reduce EEI’s

estimates of regulatory costs.

The commenter stated that, in sum, there are significant issues with the assumptions used

by the other commenters in their modeling analyses, resulting in overly optimistic projections

regarding control costs and achievability of reductions. Based on the foregoing, the commenter

submitted that its assumptions are the most realistic and that its modeling, therefore, most

accurately predicts the costs of the proposed rule as well as the achievability of the proposed

timing. The commenter stated that EPA’s final rule should include a series of analyses that factor

in assumptions comparable to the commenter’s assumptions.

Response:

EPA appreciates the commenters suggestions. A complete discussion of EPA’s modeling

of costs and energy impacts can be found in Chapter 7 of the Regulatory Impact Analysis. EPA

also appreciates the commenters input to the record on the status of control technologies. The

Agency's position on the state of Hg technology is contained in the EPA 's Office of Research

and Development white paper (see Control of Emissions from Coal-Fired Electric Utility

Boilers: An Update, EPA/Office of Research and Development, March 2005).

Comment:

The commenter (OAR-2002-0056-5460) stated that ample evidence suggests that

Activated Carbon Injection (ACI) and other Hg control options are already commercially

available. See Document ID No. OAR-2002-0056-3454 (Institute of Clean Air Companies

Comments); and No. OAR 2002-0056-2888 (NESCAUM Comments). The commenter stated

that given the evidence of commercial availability, EPA has not adequately explained its

conclusion that ACI will not be available for commercial application until after 2010.

Response:

EPA appreciates the commenters input to the record on the status of control

technologies. The Agency's position on the state of Hg technology is contained in the EPA 's

Office of Research and Development white paper (see Control of Emissions from Coal-Fired

Electric Utility Boilers: An Update, EPA/Office of Research and Development, March 2005). 

Comment:
9-lxxxvi

One commenter (OAR-2002-0056-5548) stated that ACI or a similar Hg-specific control

technology will be necessary to meet any of the lower caps (i.e., beyond co-benefit reductions)

under consideration (e.g., EEl’s 2015 cap or EPA’s 2018 cap). However, many commenters have

advocated that the allowance allocation adjustment factors for EPA’s proposed Phase I 2010 cap

(or allowance adjustment factors proposed by others) continue on into later stages of the Hg

program. Cinergy has stated that such allocation preferences should end with any cap beginning

in 2015. The commenter agrees with Cinergy’s position on this issue.

Response:

The final rule takes into account the different levels of mercury control that lignite,

bituminous, and subbituminous coals can achieve using existing NOx and SO2 controls and uses

coal adjustment factors for determining the state emission budgets and determining unit-level

allocation under EPA's example allocation methodology for States. For further discussion see

final rule preamble (section IV.C.4) and Technical Support Document for the Clean Air

Mercury Rule Notice of Final Rulemaking, State and Indian Country Emissions Budgets, EPA,

March 2005.

Comment:

One commenter (OAR-2002-0056-5548) stated that ACI will be available for initial

application by 2010 and for widespread commercial application by 2012-2015. EPA has staked

its decision to lower the cap beyond co-benefits on its expectation that “ACI technology would be

available for commercial application after 2010 and that removal levels in the 70 percent to 90

percent range could be achievable.” It is noteworthy that all of the modeling that EPA highlights

in the NODA assumes some availability of ACI by 2010. In a July 20, 2004 report to EPA by

DOE officials responsible for development of Hg-specific control technologies such as ACI, DOE

concluded “ACI works,” but needs further demonstration, now underway, to be commercially

available by 2010-2012. Hence, there is little question about the technology becoming available

for all coal ranks.

The commenter believed that the issue of levels of control with ACI among coal ranks

must be addressed. DOE reports that its near term goals remain to demonstrate 50-70 percent

reduction on bituminous coals by 2005 and on lower ranks coals by 2007.6 Thus, DOE’s near

term goals do not show any variation by coal rank, and the later demonstration date of 2007 for

lower rank coals is irrelevant for post 2014 application. To date, there is no basis to believe that

DOE will not achieve its stated goals. As referenced in the NODA, early pilot testing of a

COHPAC system on a bituminous unit (Gaston) showed longer-term testing removals of 78

percent, and ACI (not COHPAC) testing at a subbituminous coal-fired unit (Pleasant Prairie)

showed longer-term testing removals in the range of 60-70 percent. Testing at two other

bituminous plants (Salem Harbor and Brayton Point) showed longer-term removals at higher

levels, although there are some concerns about whether either of these units is sufficiently

representative for replication.

In its July report to EPA, DOE further states that its longer-term goal is to demonstrate

emission reductions of 90 percent by 2010. However, in the July presentation, its current

projection (“DOE estimate for performance potential with ACI”) for ACI/COHPAC is 80 percent

removal for a CS-ESP bituminous unit, 70 percent removal for CS-ESP and CS-ESP/FGD-Dry
9-lxxxvii

subbituminous units, and 70 percent removal for all lignite units (except that HS-ESP/FGD lignite

units increase to 83 percent). It is these DOE projections upon which EPA is basing its proposed

decision to implement a cap significantly lower than co-benefits.

Based upon this information, the commenter believed that EPA must evaluate the equities

of allowance allocation adjustments among coal ranks for post co-benefits caps. The first risk to

evaluate is technology/compliance risk. There is a risk that the as yet unproven technologies upon

which DOE relies will not work well, or will not work well at the levels predicted. However, this

risk is generally equal among all coal ranks. The DOE currently has 41 field tests underway

which will be completed by 2007. Of these 41 tests, 27 involve subbituminous or lignite coals. 

These extensive tests, the majority of which concentrate on low-rank coals, indicate that DOE will

be able to achieve its stated removal targets within the given timeframes. However, no coal rank

has any more of guarantee that this will in fact come to pass than any other.

The commenter added that there has been short-term testing is true for all coal ranks, and

the fact that there might be a few more short-term field tests for bituminous coal would seem to

make little overall difference in technology/compliance risk because there has been no substantial

testing beyond short-term field tests for any coal rank. Hence, the technology risks associated

with DOE meeting its stated control technology goals remain equal among coal ranks.

The commenter also noted that there is no greater compliance risk for any coal rank

because each coal rank has an available “backstop” technology that will allow it to comply. 

Bituminous units can install FGD to reach 60 percent removals, and subbituminous units can

install FF to reach 65 percent removal (CRA 2004 EMFs). The commenter did not believe there

is any plausible basis to mandate these control technologies now solely for Hg removal, as EPA

has concluded, when developing Hg-specific control technologies show such promise and greater

cost-effectiveness. However, that conclusion becomes less appropriate for any post-cobenefits

caps. In the event that technology risk impacts one coal rank but not another in the compliance

year, either coal rank has an available backstop compliance option, and therefore compliance risk

remains equal among coal ranks for the later caps and cannot justify application of any allowance

allocation factors (the fact that the backstop technology for either coal rank may cost more than

an ACI-based alternative is not a relevant basis to adjust allocations because both subbituminous

and bituminous coal users share equal technology development risk ACI, and their backstop

technologies are both within the same range of cost-effectiveness) .

Based on the above information, the commenter believed that EPA clearly cannot support

an allocation adjustment ratio whereby bituminous coal is assigned a factor of 1 and lower ranks

coals are assigned higher factors for post co-benefits caps because that approach assumes that

bituminous coals have no technology compliance risk, and that lower rank coals have greater

technology/compliance risk, which is simply not true. As well, an allocation ratio of 1.25 for

subbituminous and 3 for lignite, and seemingly derived for a co-benefits approach, bears no

relationship to whatever differing levels of risk might be perceived among the coal ranks for

Hg-specific control technologies that have not been commercially deployed (the control

differences are nominal (10 percent) and do not warrant those allocation ratios). Thus, there is

nothing that is either “directionally correct” or “equitable” in awarding extra allowances to low

rank coals that bears any relationship to the technical and compliance risks among coal ranks for

post co-benefits caps.
9-lxxxviii

Response:

EPA appreciates the commenters input to the record on the status of control

technologies. The Agency's position on the state of Hg technology is contained in the EPA 's

Office of Research and Development white paper (see Control of Emissions from Coal-Fired

Electric Utility Boilers: An Update, EPA/Office of Research and Development, March 2005).

EPA's IPM modeling assumption for ACI are based on EPA's Office of Research and

Development (ORD) assessment. Although modeled in IPM to be available immediately for all

coal-fired generation as a simplification of modeling, ORD assessment concluded that ACI

could not be fully deployed on all plants by 2010 timeframe.

The final rule takes into account the different levels of mercury control that lignite,

bituminous, and subbituminous coals can achieve using existing NOx and SO2 controls and uses

coal adjustment factors for determining the state emission budgets and determining unit-level

allocation under EPA's example allocation methodology for States. For further discussion see

final rule preamble (section IV.C.4) and Technical Support Document for the Clean Air

Mercury Rule Notice of Final Rulemaking, State and Indian Country Emissions Budgets, EPA,

March 2005.

Comment:

One commenter (OAR-2002-0056-5548) noted that there is a 10 percent difference

between DOE’s removal targets for ACI applied to bituminous coal (80 percent) and the lower

rank coals (70 percent) (all ranks share an equal risk that these levels will not be achieved in

practice). The difference between these controls levels is both small (10 percent) and equal to or

above the nominal required reduction (an aggregate 70 percent reduction in Hg for EPA’s 15-ton

cap). The commenter was not aware of any compelling reason to subsidize low rank coal users

that may have nominally different control costs. Nor is the commenter aware of any compelling

reason for EPA to require bituminous coal users to provide that subsidy (in the form of lost

allowances due to allocation ratios) to users of the other coal ranks.

The commenter was not aware of any policies or reasons supporting such subsidy because

they appear not to have happened under similar circumstances. Thus, the commenter is not aware

that EPA considered subsidizing bituminous coal under the CAIR because it would cost users of

that coal rank significantly more to meet SO2 caps than users of subbituminous coal. Nor is the

commenter aware that EPA considered granting bituminous coal users extra SO2 allowances

under CAIR to help prevent such users from switching to subbituminous coals to meet their SO2

requirements.

For similar reasons, the commenter found no plausible, equitable basis for awarding such

subsidies here. If the market finds it more difficult or expensive to control Hg emissions from

lower rank coals than from bituminous coals it will decide whether to buy allowances to cover

that shortfall, or it will switch coals, which is how it resolved control issues under Title IV (Acid

Rain) of the Clean Air Act Amendments of 1990, how it will resolve control issues under CAIR,

and how it should resolve control issues under the Hg rule.

It is also important to note that a 70 percent Hg reduction for subbituminous coal results

in essentially the same emissions as an 80 percent reduction on bituminous coal. The mean Hg

content in subbituminous coal is 5.74 lb/TBtu, and the mean Hg content for bituminous coal is
9-lxxxix

8.59 lb/TBtu. If Hg emissions from each coal are reduced by 70 percent and 80 percent

respectively, the resulting Hg emissions are 1.722 lb/TBtu for subbituminous and 1.718 lb/TBtu

for bituminous coal, or no difference at all. In fact, on a risk basis, the less homogeneous nature

of bituminous coals means that these equal aggregate numbers underestimate the greater

reduction risk associated with bituminous coals.

Response:

EPA is finalizing a cap-and-trade approach under section 111. EPA is establishing a

phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for

rationale. The final rule takes into account the different levels of mercury control that lignite,

bituminous, and subbituminous coals can achieve using existing NOx and SO2 controls and uses

coal adjustment factors for determining the state emission budgets and determining unit-level

allocation under EPA's example allocation methodology for States. For further discussion see

final rule preamble (section IV.C.4) and Technical Support Document for the Clean Air

Mercury Rule Notice of Final Rulemaking, State and Indian Country Emissions Budgets, EPA,

March 2005.

Comment:

One commenter (OAR-2002-0056-5548) noted that, in the NODA, EPA presented the

results of a number of attempts to model the impact and costs of various proposed Hg rules. The

significant divergence in the modeling results, even for ostensibly similar regulatory scenarios,

demonstrates the fundamental problem in devising this rule given the high degree of uncertainty in

the model inputs and assumptions. It argues strongly in favor of the commenter’s original

recommendation, to defer setting a hard cap until adequate information is available about the

performance and cost of co-benefit and Hg-specific control technologies.

First, the commenter did not believe that EPA’s, EEI’s or Cinergy’s model inputs are

quite right, although each has developed appropriate inputs for individual components. The

commenter also did not believe that EEI’s model is correct because it has apparently assigned

little or no cost to switching to subbituminous coal for SO2 compliance, while both EPA and

Cinergy have assigned costs to that action. This would tend to underestimate the level of FGD

installation needed for compliance with the CAIR, and therefore underestimate co-benefits. 

Hence, the commenter believes that either EPA’s or Cinergy’s inputs on the cost for coal

switching should be used, and generally believes that Cinergy’s formula presents a more

comprehensive approach, although there may be little difference in results between Cinergy’s or

EPA’s inputs.

Next, the commenter believed that EPA has significantly underestimated the cost of

control equipment. This would tend to overestimate the number of FGD units that would be

installed to meet the CAIR, and hence overestimate co-benefits. The commenter also believed

that either EEI’s numbers or Cinergy’s pollution control cost numbers better reflect current

reality. These two variables, plus the EMF factors, are what will most influence the final estimate

of co-benefits reductions, cost and performance. The commenter had no comment on growth

numbers.

Response:
9-xc

EPA is finalizing a cap-and-trade approach under section 111. EPA is establishing a

phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for

rationale. See comment response above for EPA's response to commenter's criticism of EPA

modeling. EPA agrees with the commenter that modeling that shows costs for coal switiching is

a better representation of costs.

Comment:

One commenter (OAR-2002-0056-5497) stated that in order to respond to this question,

it is important to define what is meant by “availability.” Four stages of development must be

recognized in this context: (1) tests, (2) demonstrations, (3) commercially available at individual

units, and (4) commercially available for the entire utility system. For a nationwide rulemaking

that imposes controls on the entire population of coal-fired boilers in this nation, commercial

availability for the entire system of boilers in this nation is the most important issue.

A test is a short-term evaluation of Hg removal as a function of different variables, such as

injection rate of activated carbon, flue gas temperature, etc. and may gather information for a few

hours to up to 30 days. A test might identify obvious balance-of-plant impacts, but not subtle

impacts that will require more operating time. In the context of the ACI work completed to date,

the commenter considered all field work with ACI/ESP to be tests. A demonstration requires

one to two years of operation, including an assessment of impacts on the plant that require the

accumulation of significant operating hours. Commercial availability at a unit scale is where a

utility can purchase an individual or limited number of processes, and receive credible

performance guarantees. Also, unit scale Hg controls may only be commercially available for

certain boiler types, unit configurations, or fuel types. The purchaser can access an experience

base assuring risks to operation are commensurate with other aspects of plant operation (e.g., the

process does not risk operations any more than usual activities). Finally, commercial availability

at the system scale requires both commercial availability at the unit scale, and the necessary

infrastructure to provide reagents, construction material and manpower, and transport of key

process requirements for the entire population of boilers. System availability is the ultimate goal

that must be achieved to enable broad utilization of a technology.

The commenter had provided an estimate of the availability of ACI technology for each of

these four stages of development. The earliest that any technology will be available on a system

basis is 2011 and for some configurations of coal type, control technology and Hg reduction level

availability on a system basis will not be achieved until 2014.

Finally, the utility industry has had many experiences that have demonstrated why several

years of demonstration effort are required before a new control technology should be applied

broadly. For example, hot-side ESPs were deployed without sufficient experience and resulted in

many unanticipated problems. In the mid-1970s, the first hot-side ESP applications on boilers

firing western low sulfur coal found persistent particulate matter removal shortfalls, in contrast to

performance predictions and guarantees offered by suppliers. Research was initiated in the early

1980s to provided an explanation of this behavior, which resulted in a solution five years after the

problem was first identified and long after these ESPs were in commercial service.

This experience is significant for ACI, especially in applications at units with smaller
9-xci

ESPS. Carbon particles or fly ash co-mingled with carbon may quickly accept–and then

ultimately lose–the electrostatic charge so that a certain fraction of carbon injected could be

released from the plate before rapping, to be either re-entrained or to disturb the quiescent zone

within the collection hopper. This complication has not been observed with ACI demonstrations

to date for two reasons. First, the ESP units employed in the demonstration tests exhibit

relatively generous specific collecting area so that any carbon material that eludes collection in the

first few fields is ultimately collected in later fields. Second, the duration of tests has been limited. 

It is not clear how long it will take to establish steady-state conditions within the collected ash

layer. As demonstrated with the hot-side ESP experience, steady state conditions with respect to

electrical properties of the entire layer of ash must be established, not simply the outer layer

adjacent to the flue gas.

The commenter suggested for these reasons, it would be imprudent to require the

deployment of insufficiently demonstrated technologies to the entire population of coal-fired

utility boilers and to potentially jeopardize the reliability of the electricity supply in this nation.

Response:

EPA appreciates the commenter's input to the record on the status of control

technologies. The Agency's position on the state of Hg technology is contained in the EPA 's

Office of Research and Development white paper (see Control of Emissions from Coal-Fired

Electric Utility Boilers: An Update, EPA/Office of Research and Development, March 2005). 

5. EEI estimated that ACI would be less expensive per pound of Hg removed than

EPA estimated. Cinergy assumed higher capital costs for ACI than EPA. Are

EPA’s Hg control cost assumptions reasonable? EPA is seeking additional detailed

data addressing the validity of the cost assumptions for ACI.

Comment:

One commenter (OAR-2002-0056-5475) noted that highly effective Hg control

technologies are available and cost effective. Two companies that supply bromated activated

carbon injection (B-ACI) for utility power plants offer removal rate guarantees. The ACI industry

reports that there is a sufficient supply of activated carbon to supply the anticipated demand for

Hg control by the regulated industry. More than 800,000 tons of activated carbon are currently

produced worldwide annually. The technology has proven to be more cost effective than initially

thought by EPA. The cost of ACI has been reported to be ranging between $2,000 and $20,000

per pound of Hg removed, much less than the control cost of $50,000/lb that was considered in

the proposed rule. The B-ACI technique has reduced the amount of activated carbon necessary

to create the same effect. By reducing the amount of activated carbon needed the B-ACI

technology will have a significant impact on the results of IPM modeling included in the proposed

rule. This commenter stated that the impact from the use of B-ACI will serve to positively

enhance the economic viability of Hg control under MACT. It would also address any potential

concerns regarding sufficient availability of activated carbon.

Response: 

EPA appreciates the commenter's input to the record on the status of control

technologies. The Agency's position on the state of Hg technology is contained in the EPA 's
9-xcii

Office of Research and Development white paper (see Control of Emissions from Coal-Fired

Electric Utility Boilers: An Update, EPA/Office of Research and Development, March 2005).

Comment:

One commenter (OAR-2002-0056-5510) stated that EPA should analyze supply and price

response to demand created by the various ACI scenarios. The current supply of activated carbon

is not sufficient to accommodate a substantial demand from the utility sector and it could take up

to five years to bring activated carbon production facilities on line.

Response:

Given that the first phase cap is set at the Hg co-benefits of CAIR, EPA does not project

significant amount of ACI to be retrofitted until the 2018 timeframe. With regard to demand for

activated carbon, EPA notes that markets respond to the demand for materials, much like under

the NOx SIP call supply for catalyst increased with demand. See Engineering and Economic

Factors Affecting the Installation of Control Technologies for Multipollutant Strategies, EPA,

October 2002, in docket. 

Comment:

One commenter (OAR-2002-0056-5488) stated that halogen-impregnated sorbents have

been shown to dramatically improve the effectiveness of sorbent injection systems, particularly for

sub-bituminous and lignite coals. These systems are also commercially available, as evidenced by

the fact that construction of the subbituminous coal-fired unit 4 of MidAmerican Energy’s

Council Bluffs power plant is moving forward under a permit that relies on their use or use of an

equivalently effective control method. This unit was permitted with the condition that it achieve a

high degree of Hg reduction, which was deemed achievable based on test results obtained for

lignite coal with iodine-impregnated carbon.

The combination of sub-bituminous coal with a spray dryer for SO2 removal has been

viewed as a challenging configuration for Hg control, because the spray dryer is thought to

remove halogens that are needed to enhance Hg capture from the flue gases. However, in recent

tests at Sunflower Electric’s Holcomb Station, 77 percent Hg removal was achieved through

injection of a proprietary halogen-treated sorbent offered by NORIT Americas, at a very low

injection rate of just 0.7 lb/MMacf. The cost of the sorbent was just $0.65/lb, making it much

more cost effective than either iodine-impregnated carbon or injection of untreated activated

carbon (at higher injection rates). Of note, rates of Hg capture at the Holcomb Station were also

boosted significantly simply by blending the sub-bituminous coal with a western bituminous coal

that had higher chlorine content.

Recent test results achieved with brominated powdered activated carbon (B*PAC) are

also impressive. B*PAC has been tested at seven different power plants, including four full-scale

tests. Mercury removal rates ranged from 70-98 percent across a wide variety of coals and

configurations. Researchers at DOE and Sorbent Technologies Corp. have estimated from these

tests that with B*PAC costing about $0.75/lb, Hg removal costs may be just 10-20 percent of

DOE’s baseline estimates.
9-xciii

Full-scale tests with B*PAC have recently been conducted at Detroit Edison’s St. Clair

Power Plant, which typically burns 85 percent sub-bituminous coal blended with 15 percent

bituminous coal and is equipped with a cold-side ESP. Mercury speciation upstream of the

sorbent injection point is estimated to be 80-90 percent elemental Hg. Nevertheless, Hg removal

rates of 90 percent or higher were achieved with B*PAC injection rates of just 3 lb/MMacf, with

no additional control equipment required. The B*PAC vendor estimates that with cold-side ESP,

90 percent removal can be achieved at a cost of less than $9000 of sorbent per pound of Hg

removed. Moreover, because B*PAC injection rates are so low, its use has negligible impact on

characteristics of fly ash for use in cement.

Environmental Defense and Western Resource Advocates have produced a white paper

entitled Mercury Air Pollution: The Case for Rigorous MACT Standards for Subbituminous Coal,

which shows that there is no technical justification for a separate subcategory of Hg MACT

standards for plants burning subbituminous coal. A copy of this paper was attached to our June

29, 2004, comments and is incorporated by reference herein. Although produced more than a

year ago, that paper found that 90 percent Hg reduction is achievable at effectively the same costs

irrespective of whether a plant burns bituminous or subbituminous coal or a blend of the two (as

is common practice), using activated carbon injection and either a fabric filter or an ESP with a

compact baghouse for particulate collection.

Since that paper was issued in May 2003, many advances have been made in Hg control

technologies. These technological advances, such as using halogenated sorbents in a sorbent

injection system, advanced dry FGD, ECO technology, or even simply blending some higher

chlorine bituminous coal at subbituminous or lignite fired power plants, are discussed in detail

above. The pilot and full scale tests of these technological improvements continue to prove that

high levels of Hg control can be cost effectively achieved at all coal- fired power plants, regardless

of the type of coal burned.

As mentioned above, the Iowa Department of Natural Resources(IDNR) recently imposed

an emissions limit reflecting 83 percent reduction in Hg as MACT for a new unit burning

subbituminous coal at MidAmerican Energy’s Council Bluffs power plant. In doing so, the IDNR

relied on results from a full-scale test of activated carbon injection for Hg control at Great River

Energy’s Stanton Generating Station, which burns North Dakota lignite coal. Tests at Stanton

found that on average 81 percent Hg removal could be obtained with the use of activated carbon

and a spray dryer/baghouse combination. Moreover, with the use of iodine-impregnated activated

carbon, 97 percent Hg removal efficiency could be achieved. The IDNR determined that the

subbituminous coal to be burned at the Council Bluffs plant was similar to lignite coal in terms of

Hg emissions, and thus relied on the Stanton test to justify the MidAmerican permit limits. 

Subsequent tests at Stanton with B*PAC injection and the spray/dryer baghouse combination

have demonstrated nearly 90 percent removal with only 1 lb/MMacf sorbent injection, at an

estimated cost of only $2500 per pound of Hg removed. These tests demonstrate that the Stanton

facility, burning lignite coal, could easily and cost-effectively meet an emissions limit of 1 lb/TBtu,

almost a factor of 10 lower than EPA’s proposed MACT for existing lignite facilities.

EPA’s proposal to set disparate standards depending on rank of coal is thus unjustified

and lacking in any reasoned basis. Moreover, the approach unfairly subjects those who live near

power plants burning lower rank coal to much higher levels of Hg emissions. EPA must take into
9-xciv

account recent information that shows technology is currently available to achieve high levels of

Hg control on a cost-effective basis regardless of the rank of coal to be burned and use this

information to set uniform, protective standards.

Response:

EPA is finalizing a cap-and-trade approach under section 111. EPA is establishing a

phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for

rationale. The final rule takes into account the different levels of mercury control that lignite,

bituminous, and subbituminous coals can achieve using existing NOx and SO2 controls and uses

coal adjustment factors for determining the state emission budgets and determining unit-level

allocation under EPA's example allocation methodology for States. For further discussion see

final rule preamble (section IV.C.4) and Technical Support Document for the Clean Air

Mercury Rule Notice of Final Rulemaking, State and Indian Country Emissions Budgets, EPA,

March 2005.

EPA appreciates the commenter's input to the record on the status of control

technologies. The Agency's position on the state of Hg technology is contained in the EPA 's

Office of Research and Development white paper (see Control of Emissions from Coal-Fired

Electric Utility Boilers: An Update, EPA/Office of Research and Development, March 2005). 

Comment:

One commenter’s (OAR-2002-0056-5492) question: “EPA is seeking additional detailed

data addressing the validity of the costs assumed for ACI.”

The response to this question is divided into two parts: activated carbon availability and

development of new sorbents.

Activated carbon availability: If the activated carbon industry converted to a

24/7 production scenario, then the productivity would conservatively lead to about 60,000 tpy of

excess carbon available in the U.S. Assuming a 15 lb/MMcfm activated carbon injection rate used

in conjunction with CS-ESP, the excess activated carbon production capacity could be used to

control Hg emissions from about 6 GWe generating capacity. If one assumed that all units that

were retrofitted with ACI also installed fabric filters, then the assumed injection rate would be

lowered to about 1 lb/MMcfm and about 105 GWe of capacity could be controlled using

activated carbon. Since EPA modeling suggests that about 2 GWe of ACI capacity will be

required in 2015, the cost for commercially available activated carbon between now and 2010

should not be driven upward due to demand vs. supply constraints.

Other models project higher ACI installed capacity. In the Notice, EPA cited model

results that projected 13 to 17 GWe of installed ACI capacity for cap and trade scenarios for 2010

annual Hg emissions between 25-34 tpy. For various MACT approaches, the installed ACI

capacity was between 15 and 120 GWe. The worldwide excess production capacity is estimated

to be 150,000 tpy of activated carbon. Depending on the injection rate, this would limit the

installed ACI capacity to 15-22 GWe. Regulations which require more than 22 GWe of ACI

capacity would cause a supply-demand constraint and cause the price of activated carbon to

increase in response to the demand. The activated carbon supply vs. the 2010 installed ACI

capacity must be carefully studied.
9-xcv

Development of new sorbents; The activated carbon sorbent is the largest Hg control

annual cost component. There have been numerous tests of brominated activated carbons on

Powder River Basin and lignite coals. In those tests, significantly improved performance has been

recorded. During a four week test program at the subbituminous coal fired, 360 MWe Sunflower

Electric Holcomb Station, Hg removal increased from a baseline of less than 20 percent to over

90 percent for the entire period at injection rates less than 1 lb/MMcfm. The projected cost of the

sorbent is a factor of two higher than conventional activated carbons, but the usage rate is a factor

of seven to ten less. This will result in a significant decrease in annual operating cost.

There is potential for activated carbon injection technology to reduce costs significantly,

by a factor of 3 to 7 between now and 2010. Utilities can take advantage of improved carbon

performance since they can change their carbon specifications after the equipment is installed.

Response:

Given that the first phase cap is set at the Hg co-benefits of CAIR, EPA does not project

significant amount of ACI to be retrofitted until the 2018 timeframe. With regard to demand for

activated carbon, EPA notes that markets respond to the demand for materials, much like under

the NOx SIP call supply for catalyst increased with demand. See Engineering and Economic

Factors Affecting the Installation of Control Technologies for Multipollutant Strategies, EPA,

October 2002, in docket. 

Comment:

One commenter (OAR-2002-0056-5571) stated that while the technology vendors

participate in conferences and announce the viability of control technologies (mostly Activated

Carbon Injection) for ~200 MW units, there have been known and guaranteed controls at <200

MW units. Worse, virtually no vendors have focused on <100 MW units. This commenter fully

supported the comments submitted by UARG and the study conducted by Charles Rivers

Associates (CRA) on the inadequacy of a three-year period for complying with EPA’s MACT

limits. EPA has the discretionary authority to extend the compliance deadline by a year. This

commenter believes that EPA should use its discretionary authority under § 112(i)(3)(B) and

extend the deadline by a year for all units, and it should assist public power utility units needing

even more time in obtaining presidential extensions on a case-by-case basis.

The process of funding and installing a major retrofit is different for small public power

systems than for larger investor-owned systems. Public power units must normally obtain

financing through publicly approved bonds. This is not a process that moves quickly, nor is it one

with a guarantee of success. Once the funding approval process is completed, these small units

most then compete with large, privately held units to obtain services from vendors of emission

control equipment and to procure skilled labor to install that equipment. An equipment vendor is

far more likely to be responsive to a large utility (often an investor utility) seeking a number of

multi-million dollar retrofits than to a small public system with an environmental compliance staff

of one or two Full-time Equivalents (FTEs) and a limited compliance budget.

Response: 

EPA is finalizing a cap-and-trade approach under section 111. EPA is establishing a

phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for
9-xcvi

rationale. Given that EPA is finalizing a cap-and-trade approach, the program would not

necessarily require the installation of coantrols on units less than 100 MW.

Comment:

The commenter (OAR-2002-0056-5404) stated that currently, most power plants market

some of their fly ash for use in ready-mix concrete and other beneficial applications. The

commenter added that some plants with scrubbers market gypsum produced in the wet flue gas

desulfurization (FGD) process for use in wallboard fabrication.

The commenter noted that as explained in their June 24 comments and the comments of

others, installation of an activated carbon injection system to control Hg emissions would cause

elevated carbon levels to prevent these beneficial uses of power plant fly ash. The commenter

stated that activated carbon that has the greatest capture efficiency is in the 4-8 micron range. 

The commenter added that most of this activated carbon will be captured by the plant’s ESP or

fabric filter, and thus will be present in the fly ash. The commenter further added that testing

experience has shown that, because of the small size of these carbon particles, some of the

activated carbon is carried through into the scrubber system. The commenter stated that the

presence of carbon in either fly ash or the gypsum produced by wet scrubbers is highly

problematic to beneficial reuse.

The commenter stated that fly ash can be utilized as a substitute for cement in ready-mix

concrete–but to do so, it needs to comply with ASTM-C618, which specifies the maximum

acceptable carbon content for concrete filler applications. The commenter added that it is

necessary to limit carbon content in concrete because carbon reduces the strength of the concrete

and causes premature failure. The commenter noted that this result occurs because carbon

inhibits air entrainment in the concrete. The commenter stated that air increases the strength of

concrete and reduces the permeability of the concrete. (The commenter noted that fly ash reduces

the amount of Portland cement that needs to be used in the concrete.) According to the

commenter, state transportation departments typically tighten the maximum allowable carbon

content as compared to the ASTM standard. The commenter notes that the ASTM standard for

carbon content of concrete filler, as well as two state DOT specifications, are shown in 

.

The commenter notes that gypsum produced in wet flue gas desulfurization (scrubber)

processes is used in construction materials and wallboard. The commenter also notes that a

portion of the gypsum is also used to produce spackling or “mud” for wallboard installation. The

commenter further notes that for cosmetic reasons, gypsum needs to be high purity and white in

color. The commenter added that, however, even very small levels of carbon in wallboard will

cause the paper to peel, making the wallboard unusable. The commenter stated that, accordingly,

to be usable, the gypsum material quality needs to be high with very small amounts of carbon. 

The commenter noted that gypsum specifications for wallboard use also are set forth in the table

below. The commenter pointed out that, as noted above, however, because of the small size of

the ACI carbon particles, some carbon will inevitably bleed through to the scrubber, resulting in

gypsum product degradation (and, as discussed in the commenter’s June 24 comments, potential

catastrophic scrubber foaming issues).
9-xcvii

Table 2. Carbon Content Specifications for Product Streams

Concrete/Constructi

on

Pennsylvania

Department of

Transportation

Texas Department of

Transportation Wallboard

Ash ASTM-C618

<6 percent

ASTM-C618 and

<4 percent

ASTM-C618 and

<3 percent

NA

Gypsum * NA NA *

*gypsum specification is 92 percent CaSO4 and 2 percent total inerts. Inerts include a

combination of ash, limestone minerals and carbon.

The commenter stated that recently, some representatives of the control technology

industry have claimed that the problem of increased carbon levels in fly ash and scrubber gypsum

has been “solved.” The commenter stated that, for example, one company has been aggressively

marketing a brominated activated carbon technology. According to the commenter, they claim

that, because the bromination results in less carbon being needed to achieve Hg removal, there is

no issue of increased carbon levels in fly ash with this technology. The commenter stated that

these assertions are, to date, unproven.

The commenter stated that this company has not claimed that anything in its process

eliminates increased carbon levels in fly ash; it simply reduces the total amount of carbon used in

the injection process. The commenter further stated that, however, carbon levels may still exceed

ASTM or State standards (or the specifications of the companies that are accepting the fly

ash)–and may still be high enough to lower the structural stability of the concrete. The

commenter stated that this is particularly the case because the DTE St. Clair plant on which the

company’s ACI was tested included an inordinately large ESP, one of the largest in the industry. 

The commenter stated that, indeed, this ESP was 700 SCA, as compared to much smaller ESP

with an average size of 200-250 SCA for the rest of the industry. According to the commenter,

as a result, the St. Clair plant was able to achieve a higher removal efficiency with a lower level of

carbon injections than would be expected from most power plants, raising further concerns about

the actual levels of carbon that would be present in the fly ash. The commenter stated that, in

addition, the tests at St. Clair were of very short duration and are not of sufficient length to be

considered “commercial operation.”

The commenter stated that even if the ash meets ASTM specifications, does not impact

the structural stability of concrete and would otherwise be acceptable to concrete manufacturers,

the levels of carbon present in the ash would discolor the concrete–and thus almost certainly

render it unacceptable to most concrete manufacturers. The commenter added that, similarly, as

noted above, even trace amounts of carbon (which certainly would be expected even from the

smaller amounts of brominated ACI proposed by the company) would render scrubber waste

unusable as gypsum. The commenter stated that, thus, even if the carbon issue could be solved

with respect to fly ash, it would not be solved with respect to scrubber gypsum.

The commenter stated that, in sum, the control technology industry has not yet come close

to proving that the issue of increased carbon levels in fly ash is solved. The commenter added

that yet a single power plant can generate thousands of tons of fly ash and gypsum per day, and if
9-xcviii

those wastes cannot be beneficially reused, they must be disposed of. The commenter further

added that the cost and adverse environmental effects associated with that disposal would be

further exacerbated by the fact that building materials and wallboard manufacturers would be

forced to purchase natural gypsum instead of reusing the plant’s byproducts. The commenter

stated that, also, the more plants that are required to install activated carbon injection, the less

gypsum would be available for use in wallboard manufacture–and the more mining that would be

required. The commenter further stated that this major increase in mining activity would have

additional significant adverse environmental impacts. The commenter stated that, finally, vast

amounts of activated carbon will need to be produced and transported to support wide-spread

application of ACI technology for the control of Hg emissions. Accordingly, notwithstanding

recent developments in ACI technology, the commenter believed that it would be inappropriate

for EPA to base its Hg removal program on broad use of ACI without first considering the

serious environmental impacts associated with disposal of millions of tons of new solid waste per

year, as well as the environmental impacts associated with production and transport of activated

carbon, and the mining of gypsum to replace that which currently comes from scrubber gypsum.

The commenter stated that indeed, § 112(d)(2) and § 111 (d) both specifically require EPA to

consider such “non-air quality health and environmental impacts” when setting standards, thus

mandating that EPA consider such effects before it can set standards that would require ACI.

Response:

EPA appreciates the commenter's input to the record on the status of control

technologies. EPA also notes that ACI with a pulse-jet fabric may be installed upstream of wet

scrubber. The Agency's position on the state of Hg technology is contained in the EPA 's Office

of Research and Development white paper (see Control of Emissions from Coal-Fired Electric

Utility Boilers: An Update, EPA/Office of Research and Development, March 2005). 

Given that the first phase cap is set at the Hg co-benefits of CAIR, EPA does not project

significant amount of ACI to be retrofitted until the 2018 timeframe. With regard to demand for

activated carbon, EPA notes that markets respond to the demand for materials, much like under

the NOx SIP call supply for catalyst increased with demand. See Engineering and Economic

Factors Affecting the Installation of Control Technologies for Multipollutant Strategies, EPA,

October 2002, in docket. 

Comment:

One commenter (OAR-2002-0056-5548) stated that the cost of activated carbon could

significantly increase if the demand exceeds the supply. Depending on the final carbon

specifications, the annual excess activated carbon capacity is 60,000 tpy (US), 30,000 tpy

(Germany), and 60,000 tpy (China) for a total worldwide excess capacity if 150,000 tpy. EPA’s

IPM modeling projects that 13 GWe of ACI could be installed by 2010. At a 15 lb/MMacf

injection rate, 13 GWe of capacity is equivalent to a consumption of 130,000 tpy of activated

carbon. This is about 87 percent of the worldwide excess capacity. At a 10 lb/MMacf injection

rate, 13 GWe of installed ACI would consume about 87,000 tpy of activated carbon or 58 percent

of worldwide excess capacity. This analysis assumes that ACI is installed only on units equipped

with CS-ESPs (a conservative assumption). If a significant fraction of units were equipped with

FF, then the carbon injection rate would be lowered to 4 to 5 lb/MMacf. If all units retrofitted

with ACI were equipped with FF, then the projected annual carbon usage would be 43,500 tpy,

which is 72 percent of the excess US capacity.
9-xcix

If ACI installations were to exceed about 15-20 GWe, then the demand for activated

carbon would exceed the supply and the delivered cost could increase dramatically. Greater

demand could be offset by the construction of additional activated carbon production capacity. 

For example, RWE is one of the world’s leading producers of activated carbon. Their product,

“HOK,” has been tested successfully for Hg reduction at power plants in the U.S., and is used for

similar purposes in Europe. According to Juergen Wirling, RWE’s international sales manager,

“if appropriate supply and purchase agreements are concluded and economic efficiency is given,

an [additional] annual delivery quantity of over 100,000 tonnes of Activated Lignite will be

possible. A prerequisite here is that for sales planning purposes or the initiation of measures

aimed at stepping up production, a minimum lead time of three to four years will be available. 

The [RWE] annual production capacity of Activated Lignite already amounts to approx. 200,000

tonnes today. The raw material lignite is extracted from the Group’s own surface mines, so that,

in this respect too, sufficient security is provided.”

These data indicate that, while the supply of activated carbon is marginally sufficient to

meet projected near-term needs of about 10 GW capacity, there is reason for concern if ACI

installations exceed expectations, and for the adequacy of longer term supply, if levels of ACI

usage reach those projected by various modelers. EPA should consider explicitly the elasticity of

ACI supply and demand in modeling the cost of ACI applications.

A second issue is the development of promoted (e.g., brominated) activated carbons. 

According to NORIT, brominated carbon would cost about 30 percent more than the current

NORIT FGD costs of about $0.50/lb delivered, or $0.65/lb to $0.70/lb delivered. However, if, as

projected based on recent research, the brominated carbon dosage is one-seventh the standard

carbon dosage for equivalent Hg removal, the cost of ACI would be significantly lower using

brominated activated carbon. Assuming a 10 lb/MMacf dosage for NORIT FGD and $0.50 lib

carbon cost and a 1.42 lb/MMacf dosage for the brominated carbon and a $0.70 cost, the use of

brominated carbon would lower the sorbent cost by a factor of five.

There have been a number of intermediate term (two week to one month tests) tests of

brominated carbon. The Hg removal at a site burning PRB coals and equipped with a SDA/FF

averaged 93 percent at an injection concentration of 1.2 lb/MMacf. The results support the

significant reduction in carbon dosage rate. At the recent PowerGen Conference, Hg reduction

vs. injection rate performance data were presented. For a plant burning PRB coal and equipped

with a CS-ESP, >90 percent Hg reduction was achieved at a brominated carbon injection rate of

about 1.5 lb/MMacf. This is significantly better performance than NORIT FGD, which achieved

75 percent reduction at an injection rate of about 6 lb/MMacf. For a 500 MWe boiler with a

SDA/FF burning a PRB coal, the NORIT FGD would cost $4,000,000 per year and the NORIT

brominated carbon would cost $1,000,000 per year. The Hg removal cost effectiveness was

lowered improved from $8,000/lb to $2,000/lb. Questions remain about the environmental impact

of using brominated sorbents, but the performance and cost improvements suggested by these

results warrant further evaluation. EPA should evaluate the cost impacts of advanced sorbents

using the IPM model because significant advances in sorbent technology are occurring.

Response:

Given that the first phase cap is set at the Hg co-benefits of CAIR, EPA does not project

significant amount of ACI to be retrofitted until the 2018 timeframe. With regard to demand for
9-c

activated carbon, EPA notes that markets respond to the demand for materials, much like under

the NOx SIP call supply for catalyst increased with demand. See Engineering and Economic

Factors Affecting the Installation of Control Technologies for Multipollutant Strategies, EPA,

October 2002, in docket. EPA has included the examination of technology improvement in its

analysis of the costs of the final rulemaking. EPA has performed a sensitivity analysis assuming

the introduction of a second ACI using advanced sorbents, leading to lower capital costs. See

sensitivity analysis in Chapter 7 of final CAMR Regulatory Impact Analysis. The Agency's

position on the state of Hg technology is contained in the EPA 's Office of Research and

Development white paper (see Control of Emissions from Coal-Fired Electric Utility Boilers: An

Update, EPA/Office of Research and Development, March 2005).

Comment:

One commenter (OAR-2002-0056-5497) stated that it was inappropriate for an economic

forecast to assume a decrease in fixed capital costs of Hg control technologies. The utility

industry learned from its experience with SCRs that EPA’s and state regulators’ early estimates

were far lower than actual capital costs. This is relevant because, like SCR, plant-specific ACI

costs and balance of plant issues remain uncertain and actual costs will be driven by those factors. 

In addition, costs will have to be adjusted higher to reflect the changes in the price and availability

of steel. In the late-1990s, Northeast States for Coordinated Air Use Management (NESCAUM)

stated that most SCR applications would cost $80-90/kW. EPA’s Acid Rain Division estimated

capital costs between $40 75/kW and the Institute of Clean Air Companies (ICAC) predicted

capital costs around $50/kW. In 2004, EPA is still publishing cost algorithms that generally argue

the capital cost is less than $100/kW. Two recent surveys to determine installed SCR equipment

cost show actual incurred costs average $125-140/kW, and for some installations approach

$200/kW.

From time-to-time, EPA and environmental groups assert that the costs of SO2 control in

the Acid Rain program “proves” that costs of pollution control equipment are always much lower

than originally estimated. This argument is a red herring. The costs of the SO2 program declined

because of extrinsic economic factors that are unlikely to be repeated in any other situation. The

federal government deregulated the railroad industry in the early 1990s, thereby vastly reducing

the costs of transporting western low sulfur coal to the east. Many utilities were able to switch

fuel supplies and avoid control technology costs altogether. This hardly shows that SO2 control

technologies dropped considerably. A more apt comparison (but unlikely scenario) in this context

would be an assumption that natural gas prices dropped so low that coal fired power plants were

able to “lower” Hg control costs by switching from coal to natural gas.

A complete assessment of Hg control technology cost requires including the impact of

elevated carbon in ash on solid byproduct management. Higher carbon in fly ash will compromise

its market value, perhaps eliminating the resale option entirely, and requiring disposal and

management. The utility industry has known for decades that when combustion NOx controls are

utilized that higher carbon in ash can render fly ash unmarketable. This is especially true for

concrete, which is the largest and most valuable byproduct use of fly ash. According to the

American Coal Ash Association (ACAA), fly ash for sale as concrete supplement derives the

highest resale value ($20-$45/ton), and comprises by far the largest end use category. Virtually

all Portland cement is prepared with several additives to enhance the following features: it must be
9-ci

“workable” or easy to pore into forms and shape; undamaged by exposure to alternating freeze

and thaw environments; and consume a minimum amount much water to maximize ultimate

strength. The problem with carbon in fly ash is that it interferes with all of these features in

concrete.

In general, carbon content of fly ash must be 5 percent or less to be marketable, which is

generally achievable for most units that fire their design coal and have properly tuned combustion

systems. However, injecting ACI will generally elevate carbon in fly ash by approximately 4

percent above the 3-4 percent that would otherwise be expected. This tends to render concrete

made from such ash discolored, weakened, more difficult to work, and less durable in freezing

climates. These problems would likely worsen with halogenated ACI.

The impact of elevated carbon in fly ash on the cost of using ACI for Hg control is due to

both loss of revenue from the sale of fly ash and the costs of permitting and disposing of material

that previously was sold. The commenter’s comments previously assumed that 35 percent of the

fly ash generated in the U.S. would be rendered unmarketable and incur a charge of $24/ton due

to a revenue loss of $12/ton and a disposal and management fee of $12/ton. The commenter has

now updated their prior estimates. The weighted value of the revenue from ash sales, using

information from the ACAA, is about $24/ton. The costs of disposal can vary widely on a

case-by-case basis, but information provided by the ACAA supports an average cost of $ 12/ton. 

Thus the cost to utilities that can do longer dispose of their fly ash because they are using ACI is

probably closer to $36/ton.

Response:

See comment response above for discussion of EPA modeling assumption for control

technology costs. EPA also notes that ACI with a pulse-jet fabric may be installed upstream of

wet scrubber. The Agency's position on the state of Hg technology is contained in the EPA 's

Office of Research and Development white paper (see Control of Emissions from Coal-Fired

Electric Utility Boilers: An Update, EPA/Office of Research and Development, March 2005).

6. Analyses of Hg trading programs by EPA and commenters indicate that variations

in the first phase cap level and timing of the cap impact when the final cap level will

be achieved. Although banking in the first phase impacts the timing of achieving

the second phase cap, it should not affect the cumulative Hg emissions reduction

ultimately achieved. EPA is seeking additional information on the impact banking

may have on the timing of achieving the second phase cap.

Comment:

One commenter (OAR-2002-0056-5561) stated that in addition, the commenter had the

following specific comment on the environmental impacts of emissions banking, which is informed

by the modeling that occurred within the commenter’s Air Quality Dialogue. Modeling

conducted in the commenter’s Air Quality Dialogue indicated that emissions banking could be

beneficial from an environmental standpoint, potentially resulting in important near-term emissions

reductions and environmental improvements that could outweigh the additional time required to

meet a second phase cap. In a scenario without a Phase 1 emissions cap (the Phase 2 cap was set
9-cii

at 10 tons in 2018), the modeling projects that firms would delay any action until the approach of

the binding cap, resulting in 16 percent fewer reductions in Hg emissions on a cumulative basis

through 2022 than under a comparable scenario that included a Phase 1 cap set at 26 tons. The

cost savings from not having to meet a 26-ton Phase 1 cap were insignificant (net present value of

$0.3 billion for the 2005 to 2030 period) in the scenario without a Phase 1 cap, and the modeling

showed a spike in costs just before the compliance year. Of course, the relative environmental

and cost advantages of banking would depend on the chosen cap levels and timing. The

commenter expected the near-term environmental benefits of emissions banking would be reduced

if the first phase cap is set at a co-benefits control level.

Response:

EPA is finalizing a cap-and-trade approach under section 111. EPA is establishing a

phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for

rationale. The cap-and-trade program will include a provision for banking. See final rule

preamble and Chapter 5 comment responses for further discussion of banking.

Comment:

One commenter (OAR-2002-0056-5510) said that in regard to banking and the timing of

achieving the second phase cap, the commenter had proposed an alternative cap and trade

program, which, among other things, significantly reduces the amount of banking that can occur

prior to 2018–increasing the likelihood that actual coal-based power plant emissions in 2018 will

be 15 tons.

Response:

EPA is finalizing a cap-and-trade approach under section 111. EPA is establishing a

phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for

rationale. The cap-and-trade program will include a provision for banking. See final rule

preamble and Chapter 5 comment responses for further discussion of banking.

Comment:

One commenter (OAR-2002-0056-5493) stated that pursuant to these regulatory

proposals, EPA intends to reduce Hg emissions from coal-fired power plants by 70 percent by

setting a permanent 15-ton cap in 2018 regardless of the future growth in the energy sector. 

Thus, the cap would effectively become more stringent as more power plants are constructed in

order to keep their collective emissions below 15 tons. EPA proposes to set the near-term Hg

emissions cap in 2010 at a level that can be achieved through the installation of FGD and SCR

units that will be necessary to meet 2010 caps on SO2 and NOx under existing cap-and trade

programs. The commenter agreed with EPA that this “multi-pollutant” approach is the most

effective and reasonable way to reduce emissions from coal-fired power plants in the near-term.

However, there is no provision in the proposed cap-and-trade approach that permits credit

for reduction of Hg emissions achieved before the near-term cap become effective in 2010. The

Building and Construction Trades Department (BCTD) of the AFL-CIO agrees with the

comments submitted by the Unions for Jobs and the Environment on June 29, 2004, that a

mechanism should be incorporated in the proposed rule that affords credit for reduction of Hg
9-ciii

emissions in advance of the 2010 cap date. Such credit would encourage the installation and/or

modification of technologies sooner than later thereby helping to avoid the inevitable last-minute

crunch that will create an unnecessary burden on the limited supply of skilled manpower available

to install FGD and SCR units.

Response:

EPA is finalizing a cap-and-trade approach under section 111. EPA is establishing a

phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for

rationale. The cap-and-trade program will include a provision for banking. See final rule

preamble and Chapter 5 comment responses for further discussion of banking. EPA is not

including a provision for early reduction credits in the final rulemaking. See Chapter 5 response

to comments for further discussion of ERCs.

Comment:

One commenter (OAR-2002-0056-5502) stated that emissions were projected to be 15

tons by 2020 in every Cap and Trade case examined using the EPMM and reported to EPA in

June 2004. In the NODA, EPA characterized the 2020 emissions estimates reported for EPMM

Cap and Trade scenarios as, variously, either 23 or 24 tons. Additional examples are provided

demonstrating the validity and robustness of the earlier projection of about 15 tons by 2020.

Response:

EPA has examined the commenters analysis and notes that its own analysis shows a more

gradual emission glide path in meeting the second phase cap. See Chapter 7 of final rule RIA

for further discussion of EPA emissions projections.

Comment:

One commenter (OAR-2002-0056-5535) stated that EPA seeks comment on a number of

economic modeling analyses performed by different stakeholder groups. The commenter’s

primary comment on this aspect of the NODA was that it fails to honor the commitment

Administrator Leavitt made to the public: to ensure that the rule will be “done in a way that will

maximize the level of reductions” based on the available technology. In particular, the NODA

does not present any new EPA analyses of stricter MACT scenarios, much less examine the

different control options put forward by stakeholder groups participating in the Utility MACT

Working Group.

A second concern the commenter had regarding the various cap-and-trade scenarios that

were modeled was that none ensures that actual emissions will be equal to, or lower than, the cap

level by the date the cap goes into effect. For example, the Center for Clean Air Policy (CCAP)

modeled a 7.5 ton cap in 2015, yet the results predict that 11 tons will still be emitted in 2020. 

EPA asks for comments on the so-called “glide path” of the reductions, and the commenter

reiterated their earlier comments that the safety valve provision and the facilities’ unrestricted

ability to borrow from future allowance years means that emissions will continue to exceed the

cap far into the future, perhaps indefinitely. EPA must recognize that the cap and trade options

all result in a cumulative loading of Hg into the environment for 10 to 20 years longer than a

proper MACT standard, in far greater amounts. This additional loading of a persistent,
9-civ

bioaccumulative metal is unacceptable.

With regard to the specific modeling results, the analysis that was of most interest to the

commenter was the Cinergy Corporation’s (Cinergy) “stringent MACT” modeling, and the

commenter’s assessment of that approach is discussed in detail below. Before turning to

Cinergy’s modeling, however, it bears reiterating our prior comments about the CCAP work. 

CCAP’s report states:

Tightening the mercury emissions-reduction cap from 15 tons in 2018 to 10 tons in 2018

is projected to increase total [three pollutant program] compliance costs by approximately

5 percent ($3.1 billion in net present value terms). Further tightening the cap by

advancing the compliance date to 2015 would add approximately another 5 percent to

total 3P costs, and reducing the cap to 7.5 tons in the same compliance period would

increase total 3P costs by an additional 4 percent. In addition, even the most aggressive of

these options (7.5 tons cap in 2015) has almost no impact on wholesale electricity prices

both nationally (within 0.2 percent) and regionally (-1.5 to 2.1 percent), reflecting how the

cost may not be passed on directly to wholesale electricity consumers. Cumulative

mercury emission reductions increase between 8 and 28 percent through 2022 with these

more aggressive caps and timetables. Moreover, the impact of such changes on national

and regional coal production is slight (-1 to 5 percent).

What that means for present purposes is that even if EPA persists in its unlawful scheme

to regulate Hg pollution under section 111 of the Clean Air Act (which of course it should not

do), a much more stringent approach is economically feasible.

Cinergy modeled a MACT control regime becoming effective in 2008 and reducing

approximately 39 tons of annual Hg emissions (an 81 percent cut). Even though Cinergy’s

assumptions included higher capital costs and less Hg co-control by NOx and SO2 controls than

EPA’s modeling, and also included the extreme assumption that activated carbon injection (ACI)

would not be available until after 2010, the commenter note that the average annual costs of

control in 2010 and 2020 (calculated by dividing the net present value of $130 billion in 2010 and

2020 by 20 years) are on the order of $6.5 billion, which is economically feasible. Although the

NODA states that Cinergy’s modeling of this scenario resulted in significant increases in power

prices and fuel prices in the short term, the commenter was unable to verify that this is indeed the

case as the full model results inexcusably were not included in the public version of Cinergy’s

comments. The public deserves the right to see the concurrent SO2 reductions of Cinergy’s

stringent MACT scenario to see if the benefits of this scenario outweigh the costs. The

commenter had every reason to believe they do.

Response:

EPA is finalizing a cap-and-trade approach under section 111. EPA is establishing a

phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for

rationale. Discussion of EPA's cost modeling can be found in Chapter 7 of the final CAMR RIA. 

Further details on commenters analysis are found in their submittals to the docket.

Comment:
9-cv

The commenter (OAR-2002-0056-5455) noted that in studying Table 1 of the NODA, it

appeared that it really was not much more expensive to control Hg emissions to 7.5 tons per year

rather than 15 tons per year. A two-phase cap of 15 tons was projected to cost $3.3 billion by

2010 and $6.7 billion by 2020. But a two-phase cap of 7.5 tons was expected to cost $4.6 billion

by 2010 and $7.1 billion by 2020. The difference by 2020 is only 6 percent. For all of EPA’s

sloppy calculations, incorrect assumptions, and failure to carry out a proper MACT

determination, it only made a 6 percent difference in cost. It would be hard to overstate the level

of disgust in the Indian community over the way EPA has handled this rulemaking.

Response:

EPA is finalizing a cap-and-trade approach under section 111. EPA is establishing a

phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for

rationale. Discussion of EPA's cost modeling can be found in Chapter 7 of the final CAMR RIA.

Comment:

The commenter (OAR-2002-0056-5404) stated that the NODA recognizes that

“[a]lthough banking in the first phase impacts the timing of achieving the second phase cap, it

should not affect the cumulative Hg emissions reductions ultimately achieved under the program.” 

69 Fed. Reg. 69870. The commenter stated that EPA nonetheless requests comment on “the

impact banking may have on the timing of achieving the second phase cap.” Id. The commenter

strongly supported unrestricted banking of Hg allowances; according to the commenter, indeed,

there is no policy basis to restrict trading, even if unrestricted banking delays the date by which

sources achieve source-specific limits that correspond to the Phase II emissions reductions on an

annual basis.

The commenter stated that in addition to having no impact on the cumulative Hg

emissions reductions ultimately achieved under a cap-and-trade program, if unrestricted banking

means (as it likely will) that the Phase II cap will not be achieved exactly by 2018, this will be the

case because Phase I Hg reductions will have gone beyond what Phase I requires. According to

the commenter, that is, Hg allowances have a vintage year before which they cannot be used; thus

a source can exceed the Phase II cap in 2018 only if it has reduced emissions beyond what is

required under Phase I, carrying Phase I allowances over to Phase II. The commenter stated that

these greater emissions reductions achieved during Phase I arguably are preferable for the

environment, but at a minimum are neutral from an environmental perspective.

The commenter stated that the fact that emissions in Phase II may exceed the cap because

of surplus reductions in Phase I can pose no adverse environmental consequences unless the

pollutant at issue poses significant acute health risks. According to the commenter, Hg is not

such a pollutant; environmental issues associated with Hg result from the deposition of Hg on

water is converted to methylmercury (MeHg), which in turn can bioaccumulate in fish, and

subsequently in people. The commenter stated that this is a long-term process, however, and

concerns regarding Hg emissions should focus on cumulative environmental loadings over time,

not on local, short-term emissions. According to the commenter, unrestricted banking cannot, by

definition, allow cumulative emissions over the life of the program to exceed what they would be

if banking were restricted. The commenter stated that, thus, no policy basis exists for any
9-cvi

restriction on the banking of Hg emissions.

The commenter added that, moreover, there are significant policy benefits to allowing

unrestricted banking. The commenter stated that banking can provide significant cost savings

with respect, as well as promoting efficient emissions reduction. The commenter added that

unrestricted banking will also provide affected sources with valuable compliance flexibilities and

incentives for technological development. The commenter stated that, as noted in their June 24

comments, no currently available control technology exists that would enable the power

generation sector to achieve a 15 ton cap. The commenter further stated that by permitting

unrestricted banking, system owners and operators will have the incentive to reduce Hg emissions

earlier and in amounts greater than the rule requires in order to bank allowances that they can use

to facilitate compliance at the beginning of Phase II. The commenter stated that these allowance

surpluses will give sources the compliance flexibility they need to experiment with promising new

technologies–which may have the potential to reduce Hg emissions efficiently and

cost-effectively–without fear of consequences associated with non-compliance. According to the

commenter, unrestricted banking will thereby ease the regulatory burdens associated with

achieving the 2018 cap because sources will have greater flexibility to identify and implement

new, promising control technologies. The commenter stated that, moreover, as noted above,

unrestricted banking results in no environmental disbenefits. The commenter further stated that to

the extent that Hg emissions from power plants could be identified as a human health concern,

such concern would be limited to the contribution of those emissions to the global pool. The

commenter stated that in any event, a flexible cap and trade program with unrestricted banking

would be an effective mechanism to reduce the contribution of the power generation sector to the

global Hg pool.

The commenter noted that, in sum, permitting sources to retain unused allowances from

one calendar year for use in a later calendar year will encourage early emissions reductions,

provide flexibility to affected sources to meet environmental objectives, and facilitate the

development of new, innovative Hg reduction control strategies. The commenter stated that

given that unrestricted banking provides the foregoing benefits with no corresponding

environmental disbenefits, EPA should allow unrestricted banking in the final rule.

Response:

EPA is finalizing a cap-and-trade approach under section 111. EPA is establishing a

phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for

rationale. The cap-and-trade program will include a provision for banking. See final rule

preamble and Chapter 5 comment responses for further discussion of banking. 

Comment:

One commenter (OAR-2002-0056-5548) stated that based on their review of the available

information, the commenter could find no plausible basis to employ any allowance allocation

adjustment factors by coal rank for any cap that is in effect after 2014. The level of the cap is

irrelevant; because by 2014 EPA projects, and proposes to rely upon, the commercial availability

of Hg-specific control technologies, and these technologies are expected to deliver reasonably

similar removals across all coal ranks.
9-cvii

Response:

The final rule takes into account the different levels of mercury control that lignite,

bituminous, and subbituminous coals can achieve using existing NOx and SO2 controls and uses

coal adjustment factors for determining the state emission budgets and determining unit-level

allocation under EPA's example allocation methodology for States. For further discussion see

final rule preamble (section IV.C.4) and Technical Support Document for the Clean Air

Mercury Rule Notice of Final Rulemaking, State and Indian Country Emissions Budgets, EPA,

March 2005.

Comment: 

One commenter (OAR-2002-0056-5548) stated that bituminous users and subbituminous

users that do not comply with their Hg reduction obligations through co-benefits will have to

purchase allowances under the trading program, and that price will not vary depending on the

rank of coal burned by the allowance purchaser. That is the very point of a trading program,

which is, as EPA notes, “cost-effective,” because it allows sources that can reduce Hg more

cost-effectively to do so, and pass those savings on to other units that cannot make reductions

that are as cost-effective. In other words, under a trading program, sources with the lowest

compliance costs bear the burden of control.

There are those who might be concerned about allowance availability on a unit-specific

basis, even though co-benefits reductions will generate adequate allowances on an aggregate

basis. While this potential concern is one that is equal across coal ranks, because there will be

many bituminous units that will be relying on allowance purchases for compliance as well as units

burning low rank coals, this concern is also easily addressed through restrictions on banking. If

EPA makes adjustments to its banking provisions to largely prohibit banking, particularly in the

first few years of any co-benefits program, all allowances will be held on a “use it or lose it” basis,

and consequently will be sold to those that need them for compliance. The commenter did not

believe that allowance hoarding is a likely outcome, nor one that would become an extended

practice, but a phase-in provision for banking whereby banking is restricted in the early years

would certainly address that issue. As an alternative, and likely a better solution, EPA could

develop a conditional restriction on banking whereby allowance banking is prohibited unless the

allowances are first offered for sale at an annual EPA auction, and, if not purchased by one that

needs them for same year compliance, may be banked without restriction. This approach would

only restrict banking to the degree necessary to ensure that all sources that must rely on allowance

purchases to comply under a co-benefits approach can obtain them. EPA can also help address

allowance availability concerns, and provide an incentive for early adoption of Hg-specific control

technology, by restricting banking to those reductions that result from the application of

Hg-specific control technology, i.e., beyond simple co-benefit reductions.

Response:

EPA is finalizing a cap-and-trade approach under section 111. EPA is establishing a

phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for

rationale. The cap-and-trade program will include a provision for banking. See final rule

preamble and Chapter 5 comment responses for further discussion of banking. The final rule

takes into account the different levels of mercury control that lignite, bituminous, and

subbituminous coals can achieve using existing NOx and SO2 controls and uses coal adjustment
9-cviii

factors for determining the state emission budgets and determining unit-level allocation under

EPA's example allocation methodology for States. For further discussion see final rule

preamble (section IV.C.4) and Technical Support Document for the Clean Air Mercury Rule

Notice of Final Rulemaking, State and Indian Country Emissions Budgets, EPA, March 2005.

Comment:

One commenter (OAR-2002-0056-5497) noted that EEI commissioned Charles River

Associates (CRA) to perform a number of sensitivity runs using EPMM to identify those factors

that affect the “glide path” and the timing in achieving the second phase cap. CRA’s analysis is

being submitted as part of EEI’s NODA comments (see OAR-2002-0056-5469). The commenter

refers EPA to EEI’s NODA comments for the detailed presentation of CRA’s work.

Briefly, CRA’s work shows that the two factors that have the greatest impact on the

“glide path” and the timing of emission reductions to achieve the second phase cap emission level

are: (1) how closely the first phase cap is set to the true level of co-benefits and (2) the duration

of the first phase cap. If the first phase cap is set below the level of true co-benefits, then more

banking would occur during the first phase and full achievement of the second phase cap emission

level would occur later. The longer the duration of the first phase cap, the greater the amount of

banking and, again, deferred achievement of the second phase cap emission level.

Other factors with smaller effects on the “glide path” are the assumptions one uses about

the growth in the use of low sulfur coal and the stringency of the second phase cap. Changes in

assumptions about the growth of the use of low sulfur coal primarily affect the level of predicted

co-benefits in the first phase. The stringency of the second phase cap affects the ultimate cost of

compliance and hence the desire of companies to put off the capital costs of second phase

compliance by early banking. CRA found that changes in technology cost assumptions do not

have a major impact on the “glide path.”

These sensitivity results continue to point out the wisdom of the alternate Hg cap

and-trade proposal offered by the commenter and a variety of other industry commenters. That

proposal would not set a “hard” cap” for the first phase; rather, the Hg co-benefits would be what

they are. Mercury trading would not be allowed during the first phase, but early reduction credits

could be earned for installing Hg-specific control equipment. A second phase would begin in

2015 with a cap of 24 tons of Hg per year. In the second phase, Hg allowances would be

allocated and Hg trading would occur. The third phase would begin in 2018 with a cap of 15 tons

per year.

Under this industry proposal, the first phase cap could not be set at a level below the true

co-benefits level; thus, the amount of banking could be expected to be less. Indeed, the only

credits that would be accrued from 2010 to 2015 would be those associated with the early

installation of Hg control equipment. Providing for early reduction credits would foster early

reductions in Hg emissions and assist in identifying and solving technical issues that will

undoubtedly arise when a new technology is installed. Beginning the second phase in 2015–only

three years before the proposed third-phase 15-ton cap would take effect–would limit the period

during which allowances could be banked, making it likely that full achievement of the third phase

cap emission limit would occur in or not long after 2018.
9-cix

Response:

EPA is finalizing a cap-and-trade approach under section 111. EPA is establishing a

phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for

rationale. The cap-and-trade program will include a provision for banking. See final rule

preamble and Chapter 5 comment responses for further discussion of banking. EPA is not

including a provision for early reduction credits in the final rulemaking. See Chapter 5 response

to comments for further discussion of ERCs.

Comment:

One commenter (OAR-2002-0056-5469) noted that the EPMM model runs reported in

the commenter’s earlier submission (see OAR-2002-0056-2929) projected that emissions of Hg

would reach the level of the Phase II cap of 15 tons by 2020. It has been widely reported that

EPA’s analysis of the same scenario using its own assumptions and the IPM model did not come

close to reaching the level of the Phase II by 2020, or even by the end of its 2026 model period. 

CRA’s report, submitted with the commenter’s comments, provided an explanation of the likely

reasons for EPA’s assumptions to have produced such a different glide path for the same

scenario. There were three basic reasons:

1. EPA set the Phase I cap at 34 tons, which was equal to “co-benefits” under EPA’s

modeling assumptions. Industry’s assumptions implied that “co-benefits” were

substantially higher, at 39.9 tons. The main reasons for these differences in co-benefits

were:

a. EPA assumed greater incremental Hg control resulting from addition of FGD, and

from adding SCRs to units with FGDs as well, particularly for subbituminous

coals, but also for FGDs added at bituminous-fired units.

b. Even without consideration of the Hg co-benefits from FGDs, EPA’s assumptions

led to a greater propensity to meet SO2 caps through capital-intensive FGDs rather

than through use of lower-sulfur coals.

2. EPA’s marginal cost curve for addition of ACIs (to achieve Hg controls beyond the cobenefits level) was higher and steeper than the technological cost and effectiveness

assumptions used by industry.

The commenter noted that CRA explained how the net impact of these differences in

assumptions was that EPA’s model would find it cost-effective to bank much larger amounts

during Phase I of the proposed Hg cap-and-trade policy option (when reductions could be met

largely via co-benefits that were relatively cheap compared to those assumed by industry) and to

avoid for a relatively longer time the deeper cuts of Phase II (which would require ACI

investments that were relatively more expensive than assumed by industry). In other words, when

the Phase I cap is set closer to co-benefits, the glide path to the final level of the cap will be more

extended during Phase II. The more costly the Phase II cap is to meet, the more extended the

glide path will be (i.e., more banking will occur in Phase I, thus lengthening the period of time

until emissions would reach the final cap). By setting the Phase I cap at its model’s estimated

level of co-benefits, and having a Phase II cap that would be relatively expensive to meet, EPA’s
9-cx

was maximizing the chances that its model would project a long delay before annual emissions

near the Phase II cap.

Industry analyses did not find this to be a realistic glide path if the cap were to be set at 34

tons, for the simple reason that industry’s data indicate that a 34 ton cap would be far below the

low-cost zone of co-benefits, and so the Phase I cap would quite expensive to meet in its own

right. Thus, far less banking would be warranted in Phase I, and industry projects a quicker glide

path to the proposed Phase II cap, with a much smaller bank to deplete, and thus relatively

prompt attainment of the actual level of the Phase II cap.

The commenter stated that in response to the NODA, CRA has prepared a number of

additional sensitivity cases using EPMM to substantiate the above logic, and to better elucidate

the particular parameters that might most alter the length of the glide path to a Phase II cap. The

commenter explored the role of (a) uncertainties in EPMM assumptions that fundamentally

determine the co-benefits level; (b) the stringency of the Phase II cap relative to the Phase I cap;

(c) impact of setting the Phase I cap closer to the expected level of co-benefits; (d) shortening the

duration of Phase I, with alternative assumptions about the timing and phase-in of an ultimate 15

ton cap; and (e) the role of rate of technological improvement. Except where noted, all of the

runs described in this section were prepared with the extended version of EPMM that includes a

terminal model period at 2030. Thus, the 2020 emissions results that the commenter reported

here are not from a terminal period. Also, all of the runs assume a 2.5 percent per annum (p.a).

reduction in the variable cost of Hg control technologies except where the commenter specifically

explore the role of alternative assumptions about technological change (in Section III, see

Document ID No. OAR-2002-0056-5469).

The commenter found that the most important determinants of the glide path are how

close the Phase I cap is to the level of co-benefits, and the duration of Phase I. These have the

most direct connection to the size of the bank that can be built up at relatively low cost prior to

entry into Phase II, and that, in turn, most directly affects the length of time before annual

emissions must actually be at the Phase II cap. The commenter also found that the effects on the

glide path of setting a Phase I cap set at or near co-benefits levels can be offset effectively by an

earlier introduction of Phase II, or even an interim cap before the 15 ton level. This two-pronged

adjustment to the proposed Hg cap appears to strike a good balance between a reasonable rate of

introduction of new Hg control technology that can maximize the potential benefits of

technological advancement, and avoiding significant delays in when actual annual emissions would

be at the level of the 15 ton cap.

Response:

EPA is finalizing a cap-and-trade approach under section 111. EPA is establishing a

phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for

rationale. EPA has examined the commenter's analysis and notes that its own analysis shows a

more gradual emission glide path in meeting the second phase cap. See Chapter 7 of final rule

RIA for further discussion of EPA emissions projections.

Comment:

One commenter (OAR-2002-0056-5469) noted that they previously identified uncertainty
9-cxi

in the amount of FGD that would be installed versus use of lower-sulfur coals to meet SO2 caps

as one of the possible uncertainties in our estimate of co-benefits. One assumption in EPMM that

might affect the mix of SO2 compliance choices regards the availability of lower-sulfur coals. The

standard EPMM assumptions have been to allow up to 2 percent p.a. growth in use of coals in

each of several coal quality categories. However, recent experiences in coal markets have

suggested that the lowest-sulfur forms of Eastern bituminous coals may not have even that much

potential for growth in supply without major cost increases.

The commenter decided to look at how the FGD choices might be adjusted if this coal

were only allowed to grow at 0.5 percent p.a. All other coals continued to face 2 percent p.a.

growth limits, except for the high-sulfur bituminous coals, which were no longer constrained at

all. This run did produce a fairly dramatic increase in the quantity of FGDs installed by 2010, and

a correspondingly lower co-benefits level. In 2010, it projects a co-benefits level of 38.9 tons, as

compared to 40 tons under our standard coal growth assumptions. While there are more FGDs in

this case, there is a more gradual introduction of ACIs. The net effect is only a very modest

change in the glide path. Emissions in 2020 are at 15.6 tons, compared to 15.4 tons in the

standard case reported in Section I.A. (see OAR-2002-0056-5469).

This scenario suggests that the role of a preference for FGD in determining co-benefits

and a glide path to Phase II may be fairly minor. The commenter found that industry’s estimate of

2010 co-benefits might be as low as 38.9 tons, rather than the 39.9 tons originally reported (which

is now estimated at 40.0 tons using the version of EPMM with the extended model horizon). This

difference does not affect the estimated present value cost of the Hg cap-and-trade proposal,

which is $1.8 billion (1999 dollars) for both the lower or higher assumptions about low-sulfur

bituminous coal availability.

Another area of substantial uncertainty on co-benefits relates to the specific assumptions

that are made about the reductions that are associated with different configurations of PM, SO2,

and NOx controls. In particular, there has been much debate over whether SCRs produce

additional Hg reduction when added to units with an FGD that are burning a lower rank coal. 

EPRI reports in its comments on the NODA that there may be some new evidence that there

could be a very small amount of co-benefits in such units. Although the evidence is from a single

plant, and may not apply to all low-rank configurations, the commenter tested the effect of

adding a 5 percent co-benefit from SCR to all subbituminous and lignite-burning plants. This had

almost no impact at all on our co-benefits estimates: the 40.0 ton estimate from the base model

was reduced to 39.9 tons.

Response:

EPA is finalizing a cap-and-trade approach under section 111. EPA is establishing a

phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for

rationale. EPA agrees that different modeling assumptions can impact the projection Hg cobenefits from NOx and SO2 controls under CAIR. As discussed in the NODA, for the final

rulemaking analysis, EPA has made changes to some of its co-benefit assumptions for

subbituminous units with SCR and FGD controls. EPA is also using a newer version of EPA's

IPM for the final rulemaking. Changes to the modeling assumptions can found in the IPM

documentation in the rulemaking docket (see Documentation Summary for EPA Base Case 2004

(v.2.1.9) Using the Integrated Planning Model, EPA, October 2004). EPA has examined the
9-cxii

commenter's analysis and notes that its own analysis shows a more gradual emission glide path

in meeting the second phase cap. See Chapter 7 of final rule RIA for further discussion of EPA

emissions projections.

Comment:

One commenter (OAR-2002-0056-5469) noted that another possible factor that the

commenter posited could lengthen the glide path is how stringently the Phase II cap is set relative

to the stringency of the Phase I cap. To explore this possibility, the commenter considered the

impacts of a Phase II cap set at 7.5 tons rather than 15 tons, while keeping the Phase I cap at 34

tons, the presumed level of the proposed Clean Air Mercury Rule (CAMR). This would have the

effect of making the marginal cost of meeting the Phase II cap once the bank is depleted much

more costly relative to the marginal costs of exactly meeting the Phase I cap. The result should be

an incentive to bank more during Phase I, in order to reduce the rate of increase of marginal costs

of control (also called emissions prices) back to about the corporate discount rate. If this were to

happen, the glide path to the Phase II cap would be lengthened.

This is exactly what the commenter found in this scenario. The marginal costs, Hg

emissions, and cumulative amount of Hg emissions banked are shown in Table 4. The most

dramatic effect of this scenario is that Phase II is not only delayed beyond 2020, but projected

emissions are still well above the Phase II cap through the end of the terminal model period:

projected emissions in 2020-2029 are 11 tons, and they are still 9.3 tons for the entire period

2030-2049. The 7.5 ton cap is never fully met until the first year after the model stops accounting

for costs of control, in 2050. This delay is accomplished by accumulating a bank exceeding 86

tons during Phase 1. Even with this lengthy delaying action, the marginal cost of controls in 2020

is over $45,000/lb (1999 dollars).

The commenter also found that the 7.5 ton Phase II cap increases the present value of the

policy’s cost quite significantly. Our estimated present value (through 2020) of costs of the

proposed Hg cap-and-trade policy is $1.8 billion (1999 dollars). With the same assumptions, a

7.5 ton cap in Phase II is estimated to be $4.6 billion. Tightening the Phase II cap in 2018 from

15 tons to 7.5 tons increases policy costs by 160 percent.

Table 4. Results of Scenario with 7.5 ton Phase II Cap in 2018

Hg Emissions (tons per

year)

Hg Bank at Beginning of

Period (tons)

Marginal cost of Hg

controls in Period

2004 44.6 na na

2008 43.1 na na

2010 28.3 0.0 $25,691

2012 23.6 11.3 $28,872

2015 19.3 42.4 $34,435

2018 15.4 86.6 $41,098

2020 11.0 70.9 $45,586

2030 9.3 35.6 $99,693
9-cxiii

The commenter also ran a case where no banking was allowed during Phase I, thus forcing

the model to actually meet the 7.5 ton cap in 2018 and thereafter. The purpose of this was to

determine the sensitivity of marginal costs to a cap of 7.5 tons. This case produced marginal

control costs of $120,000/lb in 2018, and $94,000/lb in 2020 (both 1999 dollars). The falling

marginal control cost reflects the effect of the 2.5 percent p.a. decline in variable O&M costs of

ACI. This rate of decline is not insignificant, but certainly insufficient to make attainment of a 7.5

ton cap occur without very high allowance prices.

The stringency of the 7.5 ton cap also is reflected in terms of its implications for

retrofitting. When the 7.5 ton cap is met in 2018, fully 78 percent of existing coal capacity has

been retrofitted by ACI at 90 percent controls, in addition to the usual large number of FGD and

SCR installations (about 107 GW and 56 GW of additional FGDs and SCRs, respectively, are

also added by 2018). Clearly most plants are installing ACI as well as FGDs and SCRs.

The commenter found that this was a particularly interesting scenario in light of the

comments that were submitted to EPA in June 2004 by the Center for Clean Air Policy (CCAP),

and which were summarized in the NODA. The NODA summarizes CCAP’s views based on a

comparable model run with IPM as “concluding that the incremental changes in the timing and

stringency of a Hg cap have, in CCAP’s opinion, relatively modest cost implications.” The

commenter reviewed the detailed results of CCAP’s runs, and found that our results are actually

very similar to those found by CCAP for the 7.5 ton cap case:

• CCAP’s scenario for a 7.5 ton cap in Phase II (with Phase I banking) projects that

emissions in 2020-2025 would still be 11.3 tons and the marginal cost of control in 2020

would be $88,060/lb (1999 dollars).

• CCAP’s results for a 7.5 ton cap in Phase II (with no Phase I banking) projects that the

marginal cost of meeting the 7.5 ton cap would be $165,500/lb in 2018 and $129,500 in

2020 (1999 dollars).

• CCAP’s costs of having a more stringent 7.5 ton cap in 2015 is also at least 150 percent

more costly than a 15 ton cap in 2018, even based on much lower EPA gas price

assumptions.

In brief, CCAP’s analysis finds the 7.5 ton cap more costly to achieve than does CRA’s

analysis. There is obviously a “knee in the curve” of the marginal control costs at a cap level

greater than 7.5 tons. The commenter therefore conclude that EPA’s interpretation of the CCAP

results, that the timing and stringency of the Hg cap “have relatively modest cost implications” is

a judgment that the commenter found inconsistent with CCAP’s own modeling results.

CCAP reports that it considered alternative levels of the Phase II cap in an effort to

“identify a possible middle ground solution... in which a less stringent Phase I target is traded off

against a more stringent Phase 2 target.” The commenter’s analyses suggested that increasing the

stringency of the Phase II cap can be counterproductive. It can delay attainment of the Phase II

cap for extended periods, while creating a much more rapid rate of investment in the emerging

technology that may exacerbate efforts for a measured and cost-effective phase-in process. If one

goal is to design a policy that will enable a gradual phase-in of investments in emerging forms of
9-cxiv

control technology, thereby maximizing the opportunities and incentives for technological

improvements to be gained, then it does not make sense to have a stringent Phase I cap, but it also

does not make sense for the Phase II cap to be very stringent relative to the Phase I cap. A

proposal for a cap as tight 7.5 tons is inconsistent with CCAP’s much more important point, that

a gradual phase in period, and incentives for early action are desirable elements of a sound policy

where a control technology is still in an emergent stage.

Response:

EPA has examined the commenter's analysis in context of the final rulemaking. EPA is

finalizing a cap-and-trade approach under section 111. EPA is establishing a phase I cap of 38

tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for rationale. 

Comment:

One commenter (OAR-2002-0056-5469) stated that there are some important merits to

setting the Phase I cap at a level close to the “true” co-benefits levels. Most importantly,

development, testing, and commercialization of Hg control technology for electric generating

units is still at an early stage. The difficulties of achieving various levels of Hg control across the

universe of generating units are highly uncertain and there is little if any experience with

commercial installation. Because of this, rates of technological improvement in the technology

are very high and a gradual phase-in helps motivate more intensive research, while also enhancing

potential for carrying the learning from the first several installations into the wider set of

installations that will come with time. At the same time, there is a risk that setting the Phase I cap

at the “true” co-benefits level will create a longer-than-desirable glide path will be to the Phase II

cap level.

Below, the commenter discussed results of a couple of scenarios evaluated to substantiate

this point, and then the commenter turned to an alternative that more effectively resolves the glide

path concern while preserving the benefits of setting Phase I cap at the “true” co-benefits level 

(see OAR-2002-0056-5469).

In CRA’s analyses, the “true” level of co-benefits emissions in 2010 is either 38.8 tons or

40 tons. It is 38.8 tons in 2010 under the assumption of 0.5 percent maximum annual growth in

low-sulfur bituminous coal, and it is 40 tons in 2010 under the assumption of 2 percent maximum

annual growth in the same. The commenter’s analyses of EPA’s proposed cap-and-trade policy

option, however, have used 34 tons as the Phase I cap. The commenter had used this value

because EPA stated in its notice of proposed rulemaking that it would set the Phase I cap at the

co-benefits level, and also that it estimated co-benefits to be 34 tons. A cap must be set at a welldefined level, and cannot vary depending on one’s views about what might constitute the intended

goal of co-benefits. Although 34 tons was not the “true” co-benefits level in our model, there is

no reason to believe that EPA would select a Phase I cap at any level other than what it estimated

as “true” co-benefits (see OAR-2002-0056-5469).

The commenter noted in our earlier submissions that EPA’s projected glide path would be

much longer than that projected by EPMM because the 34 ton cap was achievable solely by “true”

co-benefits in EPA’s modeling, but was much lower than the EPMM co-benefits level, and

therefore more costly to meet in CRA’s modeling. EPA’s model would thus project much more
9-cxv

banking in Phase I than would EPMM, thereby delaying full implementation of Phase II emissions

levels in the Agency’s runs. In the current analysis, the commenter simulated this effect in the

EPMM model by running scenarios where the commenter set the Phase I cap at EPMM’s

projected co-benefits levels, for the two sets of coal assumptions, respectively. The commenter

left the Phase II cap at 15 tons, since this value appeared to have no connection to particular

model assumptions.

Tables 5 and 6 contrast the timing of ACI and FGD installations, respectively, for the case

of Phase I being set by the co-benefits level, and the case of Phase I being set at a 34 ton cap. 

Figure 3 presents the glide paths of Hg emissions for both coal constraint cases. The predicted

effect on the glide path is apparent. Projected emissions remain 2 tons above the Phase II cap

until 2030 in the case where the Phase I cap is set at co-benefits. This is the largest single source

of glide path sensitivity that the commenter had found for a 15 ton Phase II cap. It would appear

to explain much of the difference between the CRA projections of 2020 emissions reaching the

national target level, and the more extended period to reach that target that has been reported as

the EPA finding.

As noted, the advantage of a cap at co-benefits levels in the early years is that it creates a

better environment for a gradual and non-disruptive commercial phase-in of a technology that can

best be described as still emergent. By setting the cap at this level, one creates desirable

incentives for early action by allowing banking to occur. However, if the cap remains at the cobenefit level for an extended period of time, a relatively large bank may be possible to build up. 

This implies benefits from early reductions, but at the same time, it means that the rate of decrease

towards the Phase II cap will be slowed. The best way to preserve the merits of a cap set at cobenefits level, while managing for a relatively prompt attainment of Phase II is to alter the length

of Phase I. The next section turns to this prospect, exploring how the glide path can be managed

while still setting the Phase I cap set at the estimated co-benefits level.

Table 5. Quantities of New ACI Retrofits by Time Period (MW)

Year

Standard Low-S Coal Assumptions (2010

co-benefits=40 tons)

Low Supply Growth of Low-S Bituminous

(2010 co-benefits=38.8 tons)

Proposed Policy:

Phase I cap at 34

tons

Phase I cap at cobenefits

Proposed Policy:

Phase I cap at 34

tons

Phase I cap at cobenefits

2004 1,050 244 1,050 244

2008 1111

2010 16,835 4,537 11,660 5,679

2012 1,352 3,442 22,220 511

2015 16,398 11,092 19,848 15,158

2018 23,646 26,373 48,238 19,326

2020 49,079 51,067 22,220 56,514

2030 5,695 17,679 8,084 17,745
9-cxvi

Table 6. Quantities of New FGD Retrofits by Time Period (MW)

Year

Standard Low-S Coal Assumptions (2010

co-benefits=40 tons)

Low Supply Growth of Low-S Bituminous

(2010 co-benefits=38.8 tons)

Proposed Policy:

Phase I cap at 34

tons

Phase I cap at cobenefits

Proposed Policy:

Phase I cap at 34

tons

Phase I cap at cobenefits

2004 1,315 2,983 5,227 4,907

2008 8,159 5,936 6,907 6,677

2010 32,791 26,517 42,537 40,048

2012 13,678 19,816 6,457 8,686

2015 3,444 4,041 5,112 5,458

2018 12,024 10,710 17,893 17,481

2020 31,103 32,437 33,736 34,475

2030 15,330 16,187 9,511 10,219

Response:

EPA has examined the commenter's analysis in context of the final rulemaking. EPA is

finalizing a cap-and-trade approach under section 111. EPA is establishing a phase I cap of 38

tons in 2010 and phase II cap of 15 tons in 2018. The first phase cap is based on EPA modeling

of the Hg co-benefits of SO2 and NOx controls installed for compliance with the CAIR

rulemaking. See final rule preamble for rationale and Chapter 7 of final CAMR RIA for
9-cxvii

discussion of emissions projections. 

Comment:

One commenter (OAR-2002-0056-5469) stated that four (4) additional scenarios were run

that explored alternative timings of a Phase II cap that might be paired with a Phase I cap set at

“true” co-benefits. Two scenarios were run assuming that the Phase II cap is implemented in

2015 instead of 2018 (one for each set of coal supply assumptions, and hence with different

assumptions about co-benefits, to match the two scenarios described in comment above). The

other two scenarios are the “Alternative Cap Proposal” (see OAR-2002-0056-4894) that

commenter submitted to EPA on August 13, 2004 for each co-benefits case. This alternative

proposal would strike an intermediate ground by tightening the cap in the period 2015-2017, but

only to 24 tons, with the 15 ton cap following in 2018.

Figure 4 compares the glide path of each of these four scenarios to those in the previous

section where the commenter set the cap at co-benefits in Phase I, but still allowing Phase II to

enter force in 2018. Table 7 shows the associated quantities of ACI controls in each time step,

which can be compared to the values in Table 5 as well. The early introduction of Phase II

increases the rate of early action in Phase I, but still gets emissions to 15 tons by 2020. However,

the commenter’s proposed alternative scenario, with an intermediate cap at 24 tons, provides a

similar reduction by 2020, but with a slower rate of investments in the early years, when the costs

of control are the most uncertain.

The estimated costs are fairly sensitive to the decision on level of the cap during 2015-

2017. As a point of reference, the estimated present value of the Hg cap as proposed (i.e., 34

tons in Phase I, and Phase II starting in 2018) is $1.8 billion (1999 dollars). By allowing the

Phase I cap to be set at co-benefits (as determined by the model), but continuing to keep Phase II

in 2018, costs would fall to about $1.2 or 1.3 billion, and attainment of the Phase II cap could be

delayed well beyond 2020. By introducing the 15 ton cap in 2015, costs would increase to about

$2.6 or 2.8 billion, although emissions would be at 15 tons by 2020. In contrast, the alternative

proposed by the commenter, would cost only $1.8 or 1.9 billion, and would still provide

assurance of attainment of the 15 ton emissions level by about 2020.

Thus, a combination of a co-benefits based cap in Phase I with a shorter duration of Phase

I provides better assurance against excessive costs during program start-up, as well as better

assurance of reaching the 15 ton emission level somewhere in the 2020 time frame. If interim

caps are used instead of bluntly moving the 15 ton cap forward in time, the policy costs need not

increase, while still providing assurance of timely attainment of the 15 ton level of emissions.

The commenter’s alternative cap proposal is very similar in nature to the simplistic

sensitivity case that simply brings in a 15 ton cap by 2015. It has the same properties of requiring

only cost-effective early action through 2015, yet bringing emissions to 15 tons promptly. The

mechanism for accomplishing this effect was the same: by tightening the cap in 2015 in such a

way that an allowance bank would not continue to accumulate at increasing rates for three
9-cxviii

additional years before the imposition of Phase II. The main differences of the alternative

proposed policy from simply introducing the Phase II cap by 2015 are:

• Under the commenter’s proposed alternative there would be no formally binding cap in the

2010-2015 time frame, providing further guarantees that early reductions would be 

Table 7. Quantities of New ACI Retrofits by Time Period (MW) With Phase I Cap Set at

Co-benefits Level, for Alternative Timings of Phase II Cap

Year

Standard Low-S Coal Assumptions (2010

co-benefits = 40 tons)

Low Supply Growth of Low-S Bituminous

(2010 co-benefits = 38.8 tons)

15 ton cap by 2015

24 ton cap in 2015-

2017 15 ton cap by 2015

24 ton cap in 2015-

2017

2004 1,050 1,050 1,050 1,050

2008 1111

2010 18,189 6,491 18,892 7,424

2012 15,715 12,029 18,204 14,466

2015 31,126 27,590 24,294 22,274

2018 17,417 23,780 22,792 26,686

2020 27,004 39,080 26,905 37,341

2030 4,044 5,024 2,902 5,469
9-cxix

against literal co-benefits rather than against an inherently uncertain estimate of what that

co-benefit level would be. From a modeling perspective, where no uncertainties are

simulated, this would have no impact on our results, but it obviously does have relevance

to consideration of cost risks.

• Another difference that remains open to deliberation is the precise level of the cap in the

2015-2017 period. In one sensitivity case the commenter used 15 tons, whereas the

alternative proposal by the commenter allows it to be 24 tons, substantially less stringent. 

The correct level to choose for the interim cap could be informed by whether it

significantly alters the timing of attainment of the 15 ton emissions goal. The commenter’s

analyses indicate that a 24 ton cap in 2015 would ensure the prospects of prompt

attainment of the 15-ton goal while maintaining a relatively gradual rate of Hg control

investments during Phase I and keeping policy costs low.

It is important to note that the modest impacts on costs from an early introduction of

Phase II only occur when this acceleration is combined with a Phase I period that is truly set at

co-benefits (either by providing early reduction credits or by setting the cap at an accurate

estimate of the literal co-benefits level).

Response:

EPA has examined the commenter's analysis in context of the final rulemaking. EPA is

finalizing a cap-and-trade approach under section 111. EPA is establishing a phase I cap of 38

tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for rationale and

Chapter 7 of final CAMR RIA for discussion of modeling analysis. 

7. Cinergy estimated a co-benefit of Hg reductions associated with implementation of

the proposed CAIR at 38 tons in 2010; EEI Estimated a co-benefit level of 40 tons in

2010. EPA additional comment on the reasonableness of its IPM assumptions for

co-benefit reductions. EPA also sought comment on appropriate emission

modification factors (EMF)–a component of the estimated Hg co-benefit reductions.

Comment:

One commenter (OAR-2002-0056-5464) believed the modeled cost estimates were too

high and the assumptions of co-benefits from the proposed Clean Air Interstate Rule were lower

than even EPA’s projections.

Response:

EPA has examined the commenter's analysis in context of the final rulemaking. EPA is

finalizing a cap-and-trade approach under section 111. EPA is establishing a phase I cap of 38

tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for rationale and

Chapter 7 of final CAMR RIA for discussion of modeling analysis. 

Comment:
9-cxx

One commenter (OAR-2002-0056-5332) stated that EPA requests comments on the

“co-benefits” of Hg reductions associatewith implementation of the proposed CAIR. This issue is

extremely important, as EPA is proposing to establish the Hg co-benefits level as the first-phase

emission limitation of its section 111 proposal.

Initially, the Agency had estimated a Hg co-benefits level of 26 tons (down from 48 tons);

that is, it estimated that air pollution control devices installed to reduce the emissions of pollutants

other than Hg from coal- fired units would reduce Hg emissions by 22 tons, resulting in the

incidental reduction of Hg emissions to a level of 26 tons. Based apparently on subsequent

revisions to its modeling assumptions, EPA increased the co-benefits level to the current estimate

of 34 tons; that is, it concluded that incidental Hg removal would be less than originally estimated,

14 tons rather than 22 tons. Now, some stakeholders are suggesting that the co-benefits level

should be raised to something closer to 40 tons, meaning that incidental Hg reductions would be

even lower (only eight tons). Apart from the technical justification or lack thereof for this

co-benefits level (see discussion below), the commenter noted that a cap-and-trade program with

a 40-ton cap would free a great many sources from the need to make any reduction at all in their

emissions of Hg. It would also allow many sources easily to over control in Phase I, bank the

excess allowances, and use the banked allowances in future control years. This would push back

the time that the Phase II cap will ultimately be achieved even further than is the case under

EPA’s currently proposed cap-and-trade proposal.

Based on its modeling, EPA concludes that average Hg removal from existing air pollution

control devices across all coal types and control configurations is currently approximately 36

percent (48 tons emitted versus 75 tons contained in coal). EPA currently estimates that with the

controls installed to comply with the CAIR proposal, annual Hg emissions from existing air

pollution control equipment will drop further, from 48 tons to 34 tons per year, which represents

about a 29 percent reduction from current emissions.

However, EPA’s estimate of Hg co-benefit levels reflect only incidental Hg reduction

from control devices designed and operated to remove other air pollutants, such as SO2, NOx, and

particulate matter, with no attempt to optimize their operation for Hg removal. The commenter

believed that the capture of Hg by existing controls can be increased significantly, simply by

optimizing reductions from equipment installed to control other pollutants. A great deal of work

is being done on measures that can be taken to optimize Hg reductions from existing air pollution

control equipment, including the injection of oxidants (e.g., chloride) into flue gas to promote the

oxidation of elemental Hg from SCR at units burning lower rank coals (which are typically low in

chloride levels), and the addition of chemicals to enhance the removal of oxidized Hg in wet FGD

systems and to prevent re-emissions of Hg.

The commenter believed that the Hg co-benefits of CAIR should perhaps be reduced from

EPA’s current estimate of 34 tons; in other words, the commenter’s view was that reductions in

Hg emissions achieved as a co-benefit of efforts to control other pollutants are greater than EPA

currently estimates. By the same token, the commenter did not believe that there would be any

justification for increasing the Hg co-benefits figure to more than 34 tons, as that would require
9-cxxi

the conclusion that other controls would not be as effective in reducing Hg emissions as the

available data indicate.

Response:

EPA is finalizing a cap-and-trade approach under section 111. EPA is establishing a

phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for

rationale. The first phase cap is based on EPA modeling of the Hg co-benefits of SO2 and NOx

controls installed for compliance with the CAIR rulemaking. See final rule preamble for

rationale and Chapter 7 of final CAMR RIA for discussion of emissions projections. As

discussed in the NODA, for the final rulemaking analysis, EPA has made changes to some of its

co-benefit assumptions for subbituminous units with SCR and FGD controls. EPA is also using

a newer version of EPA's IPM for the final rulemaking. Changes to the modeling assumptions

can found in the IPM documentation in the rulemaking docket (see Documentation Summary for

EPA Base Case 2004 (v.2.1.9) Using the Integrated Planning Model, EPA, October 2004).

Comment:

One commenter (OAR-2002-0056-5446) said there is considerable uncertainty over the

extent of “co-benefit” reductions; however the current IPM assumptions fall within the likely

range of co-benefit reductions.

Care must be taken when assuming co-benefit reductions as most reductions are calculated

from analysis of the ICR emissions data which represent a limited snapshot of emissions from a

few units taken over a very short period of time, with a limited number of coals. The data do not

account for the wide variability of coals and process conditions encompassed by the full fleet of

generator boilers. As stated previously the EPA must undertake some form of risk or probability

analysis that considers variability in coal properties and unit performance to if it is to fully

understand the implications of the proposed rule.

Response:

EPA is finalizing a cap-and-trade approach under section 111. EPA is establishing a

phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for

rationale. The first phase cap is based on EPA modeling of the Hg co-benefits of SO2 and NOx

controls installed for compliance with the CAIR rulemaking. See final rule preamble for

rationale and Chapter 7 of final CAMR RIA for discussion of emissions projections. As

discussed in the NODA, for the final rulemaking analysis, EPA has made changes to some of its

co-benefit assumptions for subbituminous units with SCR and FGD controls. EPA is also using

a newer version of EPA's IPM for the final rulemaking. Changes to the modeling assumptions

can found in the IPM documentation in the rulemaking docket (see Documentation Summary for

EPA Base Case 2004 (v.2.1.9) Using the Integrated Planning Model, EPA, October 2004).

Comment:

One commenter (OAR-2002-0056-5510) stated that in regard to co-benefit reductions (or
9-cxxii

corresponding emission modification factors, EMF), the commenter noted that most of the

estimates are based upon analysis of EPA’s 1999 ICR data set. The commenter pointed out in

comments dated May 14, 2004, the ICR emissions data represent a limited snapshot of emissions

from a few units taken over a very short period of time, with a limited number of fuels. The data

do not account for the wide variability of coals and process conditions encompassed by the full

fleet of utility boilers. As a result, relatively little is known about long-term Hg emissions

performance of the units that were tested or what may be achieved through a broader application

of co-benefit technologies. Because of the lack of understanding associated with the level of Hg

reductions that will be achieved through co-benefit reductions or future removal technologies, the

commenter had recommended an alternative cap and trade program. This alternative would

provide for co-benefit reductions in the first phase, coupled with an assessment of Hg emissions

and performance characteristics of control technologies. An interim cap–effective in 2015–and

coal type allocation adjustment factors would be based on this assessment. A final cap of 15 tons

would be effective 2018.

The advantages to this proposal are: 1) it allows for the use of actual emissions data–as

opposed to speculation about what may be achievable in the future–in the setting of the interim

cap (i.e., it provides for a target that is known to be achievable); 2) it will provide for a

mechanism that allows EPA to ensure a balance regulatory approach to Hg reductions (i.e., a rule

that does not create regional disparities by advantaging one coal type over another). The

commenter was particularly concerned about this issue because its members produce coal in every

coal-producing region of the US, and represent coals of every rank.

Proposed allocation adjustment factors are based EPA’s assessment of the relative ease

with which Hg can be removed from different coal types; their intent is to “level the playing field.”

Because reductions associated with cobenefits are still not well understood, and Hg specific

control technologies will not be available until the 2010 time frame, the allocation adjustment

factors should not be set until EPA has a better sense of the capabilities of these technologies.

While Hg reductions will take place through the expanded use of co-benefit technology as

required by CAIR, and promising Hg-specific technology is under development, it is premature to

set a MACT, NSPS standard, cap, or emission allowance allocations because of the lack of

reliable data on Hg emissions and the performance of control technology. It would be arbitrary

and unreasonable to base an emissions standard on the hypothetical performance of unproven

technology.

To the extent that EPA relies on EMFs for modeling purposes, those factors should be

conservative enough to allow for the various sources of variability and uncertainty associated with

co-benefit removal rates on different coal types. Where co-benefit reductions are the product of

speculation within a range the commenter recommended a conservative estimation of the EMF at

the low end of the range; where evidence exists that co-benefit reductions are not being achieved,

the commenter recommended an EMF of 1 (i.e., no co-benefit reductions). The commenter noted

the results of a recent study conducted by the Energy and Environmental Research Center using a

slipstream SCR unit at one lignite-fired power plant to determine the ability of new and aged
9-cxxiii

catalyst to oxidize Hg. The results indicate “limited oxidation of Hg across the SCR catalyst

when firing lignite coals” and that the sulfation of calcium and sodium ash deposits foul the

catalyst rendering the SCIR–technology ineffective for NOx control. An article describing the

findings has been accepted for publication in Fuel Processing Technology. A copy of the “article

in press” entitled, “SCR catalyst performance in flue gases derived from subbituminous and lignite

coals” is attached (see e-docket text, Attachment 1).

Response:

EPA is finalizing a cap-and-trade approach under section 111. EPA is establishing a

phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for

rationale. The first phase cap is based on EPA modeling of the Hg co-benefits of SO2 and NOx

controls installed for compliance with the CAIR rulemaking. See final rule preamble for

rationale and Chapter 7 of final CAMR RIA for discussion of emissions projections. As

discussed in the NODA, for the final rulemaking analysis, EPA has made changes to some of its

co-benefit assumptions for subbituminous units with SCR and FGD controls. EPA is also using

a newer version of EPA's IPM for the final rulemaking. Changes to the modeling assumptions

can found in the IPM documentation in the rulemaking docket (see Documentation Summary for

EPA Base Case 2004 (v.2.1.9) Using the Integrated Planning Model, EPA, October 2004).

EPA projections of Hg co-benefits are based on 1999 Hg ICR emission test data and

other more recent testing conducted by EPA, DOE, and industry participants. Overall the 1999

Hg ICR data revealed higher levels of Hg capture for bituminous coal-fired plants as compared

to subbituminous and lignite coal-fired plants and a significant capture of ionic Hg in wet-FGD

scrubbers. Additional Hg testing indicates that for bituminous coals SCR has the ability to

convert elemental Hg to ionic Hg and thus allow easier capture in a wet-FGD scrubber. This

understanding of Hg capture was incorporated into EPA modeling assumptions and is the basis

for our projections of Hg co-benefits from installation of scrubbers and SCR under CAIR. (For

further discussion see Control of Emissions from Coal-Fired Electric Utility Boilers: An Update,

EPA/Office of Research and Development, March 2005, in the docket).

Comment:

One commenter (OAR-2002-0056-5502) state that estimated emissions in 2010 after

co-benefits of CAIR alone are realized remain in the range of 39-40 tons. Variations of the

assumptions in EPMM that affect its estimate of co-benefits, accounting for new information from

the commenter and other researchers, did not produce any significant change from the level of

39.9 tons that was reported in the earlier submittal.

Response:

EPA has examined the commenter's analysis in context of the final rulemaking. EPA is

finalizing a cap-and-trade approach under section 111. EPA is establishing a phase I cap of 38

tons in 2010 and phase II cap of 15 tons in 2018. The first phase cap is based on EPA modeling

of the Hg co-benefits of SO2 and NOx controls installed for compliance with the CAIR

rulemaking. See final rule preamble for rationale and Chapter 7 of final CAMR RIA for

discussion of modeling analysis.
9-cxxiv

Comment:

One commenter (OAR-2002-0056-5460) stated that EPA should not be concerned with

the co-benefits of Hg reductions associated with implementation of the proposed CAIR. The

commenter further stated that EPA is required to regulate power plant Hg emissions pursuant to

Section 112 regardless of what CAIR may accomplish. The commenter added that, indeed, it is

required to do so promptly, both under the plain language of the Clean Air Act and under a

consent decree between EPA and the Natural Resources Defense Council (NRDC). See 42

U.S.C. § 112(c); OAR-2002-0056-3459 (NRDC comments) (describing consent decree). The

commenter stated that given these requirements, and given EPA’s own admission that CAIR may

never become law, EPA should not continue to focus on the hypothetical consequences of CAIR.

Response:

EPA has examined the commenter's analysis in context of the final rulemaking. EPA is

finalizing a cap-and-trade approach under section 111. EPA is establishing a phase I cap of 38

tons in 2010 and phase II cap of 15 tons in 2018. The first phase cap is based on EPA modeling

of the Hg co-benefits of SO2 and NOx controls installed for compliance with the CAIR

rulemaking. See final rule preamble for rationale and Chapter 7 of final CAMR RIA for

discussion of modeling analysis.

Comment:

One commenter (OAR-2002-0056-5548) stated that CRA’s 2004 EMF data (EEI data)

better reflect current knowledge than EPA’s, but should be modified as discussed below based on

our more recent data. The commenter believed that EPA must augment and modify these EMFs

using all available data that meet appropriate experimental quality criteria. In that context, the

commenter reiterated their comment made on the initial proposal that much of the ICR Part III

emissions data on which EPA has relied heavily does not meet reasonable tests of data quality and

should be discounted, if only to meet EPA’s stated objectives and obligations under the Data

Quality Act.

CONSOL Energy Inc., in cooperation with the U.S. Department of Energy’s National

Energy Technology lab (DOE NETL), the Ohio Coal Development Office (OCDO), the Illinois

Clean Coal Institute (ICCI), and the Electric Power Research Institute (EPRI), has conducted an

extensive test program to measure Hg speciation and emissions on coal-fired boilers with wet and

dry Flue Gas Desulfurization (FGD) with and without Selective Catalytic Reduction (SCR)

equipment. All of the units burned bituminous coal, and all but one of the wet-FGD units had an

ESP for particulate control. Speciated measurements of Hg in the flue gas were made across the

particulate control device as well as the FGD, and in the case of SCR-equipped units, ahead of the

SCR. Appendix A provides detail on each unit, including the type of FGD, SCR and particulate

collection device, and citations to more complete reports of the various tests. The Ontario Hydro

Method (OHM) was used for all of these tests with the exception of the Hg removal across the

ESP which was based on the Hg content of the ESP fly ash.
9-cxxv

One important criterion for assessing the accuracy of Hg emission measurements is a

material balance (notably lacking in the ICR Part III data), wherein the Hg content of the coal is

measured and compared against the sum of the stack Hg emissions and the Hg contents of all

process streams that contain Hg including such streams as the bottom ash, ESP ash, FGD solids,

and mill reject pyrites. All of the data contained in Appendix A and summarized below have a

material balance closure of ± 120 percent thus assuring a high degree of data quality.

Table 1 below lists each unit’s emission control devices, the Hg removal across the ESP,

the total (coal-to-stack) Hg removal and the average Hg removal for various emissions control

configurations.
9-cxxvi

Table 1. Mercury Removal, Various Pollution Control Configurations

Bit

Coal

Plants SCR

Part.

Control

Device FGD

%Hg

Removal

across

ESP

%Hg

Removal

Coal-toStack

1 Yes FF Lime Spray Dryer 87.3 ± 3.4

2 Yes FF Lime Spray Dryer 94.6 ± 0.3

Average percent Hg Removal for SCR/FF/FGD 91.06 ± 5.2

5 Yes ESP Limestone, in-situ Oxidation 17 85.8 ± 2.8

6 Yes ESP Limestone, in-situ Oxidation 24 88.2 ± 4.2

7 Yes ESP Limestone, in-situ Oxidation 6 83.6 ± 2.7

8 Yes ESP Mg-Lime, ex-situ Oxidation* 71.6 ± 5.2

9 Yes ESP Mg-Lime, Inhibited Oxidation 86.7 ± 2.8

10 Yes ESP Mg-Lime, Inhibited Oxidation 89.2 ± 3.6

11 Yes Vent.

Scrub

Mg-Lime Vent., Scrub. Inhib.

Oxidation

85.1 ± 1.7

Average percent Hg Removal for SCR/CS-ESP/FGD 15.7 ± 9.1 86.1 ± 2.1

13 No ESP Limestone, in-situ Oxidation 48.7 ± 4.5

14 No ESP Limestone, in-situ Oxidation 23 74.6 ± 1.4

17 No ESP Mg-Lime, Nat. Oxidation 24.0 ± 11 66 ± 3

18 No ESP Limestone, in-situ Oxidation 7.0 ± 2.0 56.0 ± 6

19 No ESP Limestone, Nat. Oxidation 13.0 ± 2.0 72 ± 9

21 No ESP Limestone, Nat. Oxidation 9.0 ± 1.0 67 ± 3

22 No ESP Mg-Lime, Nat. Oxidation 11.0 ± 6.0 63 ± 4

Average % Hg Removal for CS-ESP/FGD 14.5 ± 7.3 63.9 ± 9.0

12 Yes ESP 13 19.6 ± 20.7

*15 percent of flue gas is bypassed around FGD. Calculated percent Hg removal would be 84

percent.

This commenter and others stated that EPA must consider coal and process variability in

any MACT, cap or allowance allocation determination. In each of the tests shown in Table 1,
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four OHM tests were performed over a two to three day period. The variability evident from the

test results over this short period of time is significant and must be considered by EPA. The

standard deviation for SCR/FGD equipped units is 2.1 percent, indicating a relatively small

variability among these measurements. The Hg removals from the FGD-only units have a

standard deviation of 9.0 percent, indicating a greater variability among these units. Based on the

test variability shown at each unit and the variability between units, the commenter believed that

EPA must use a conservative EMF number to allow for the margin of variability inherent in both

the Hg measurements and the performance of coal-fired units due to coal Hg content and process

control. Therefore, the commenter recommended that EPA use EMF values reflecting the

performance at the lower bound of a confidence interval calculated as one standard deviation

about the average. Table 2 below compares the EMF’s calculated in this manner from the data in

Table 1 above to the EMF’s provided by EPA in Table 5 of the NODA.

Table 2. EMF Comparisons

Name of Control

EPA 2003 EMFs CRA 2004 EMFs

EIA AE02004

EMFs

CONSOL Energy

EMFs

Bit EMF Bit EMF Bit EMF Bit EMF

PC/CS-ESP 0.64 0.65 0.64 0.93

PC/CS-ESP/FGD 0.34 0.40 0.34 0.45

PC/CSESP/SCR/FGD0.10 0.15 0.10 0.16

PC/FF/SCR/FGDDryN/A N/A N/A 0.14

PC/SCR/ESP N/A N/A N/A 0.80

The commenter believed that the EMFs for the wet FGD units are similar, though

somewhat greater than those proposed by CRA. One notable difference is the EMF for CS-ESPonly units. Because of the interest in Hg reduction as a co-benefit of NOx and SOx controls, there

has been relatively little done to characterize emissions from this, the most common class of unit

in use now. As the commenter noted in their June, 2004 comments on the initial proposal, these

units were highly under-represented in the ICR Part III database. The commenter believed that

EPA should revise the estimated EMF for these units to 0.93, based on the results presented here.

Response:

EPA has examined the commenter's analysis in context of the final rulemaking. EPA is

establishing a phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule

preamble for rationale. The first phase cap is based on EPA modeling of the Hg co-benefits of 

SO2 and NOx controls installed for compliance with the CAIR rulemaking. See final rule

preamble for rationale and Chapter 7 of final CAMR RIA for discussion of emissions

projections. As discussed in the NODA, for the final rulemaking analysis, EPA has made

changes to some of its co-benefit assumptions for subbituminous units with SCR and FGD

controls. EPA is also using a newer version of EPA's IPM for the final rulemaking. Changes to
9-cxxviii

the modeling assumptions can found in the IPM documentation in the rulemaking docket (see

Documentation Summary for EPA Base Case 2004 (v.2.1.9) Using the Integrated Planning

Model, EPA, October 2004).

EPA projections of Hg co-benefits are based on 1999 Hg ICR emission test data and

other more recent testing conducted by EPA, DOE, and industry participants. Overall the 1999

Hg ICR data revealed higher levels of Hg capture for bituminous coal-fired plants as compared

to subbituminous and lignite coal-fired plants and a significant capture of ionic Hg in wet-FGD

scrubbers. Additional Hg testing indicates that for bituminous coals SCR has the ability to

convert elemental Hg to ionic Hg and thus allow easier capture in a wet-FGD scrubber. This

understanding of Hg capture was incorporated into EPA modeling assumptions and is the basis

for our projections of Hg co-benefits from installation of scrubbers and SCR under CAIR. (For

further discussion see Control of Emissions from Coal-Fired Electric Utility Boilers: An Update,

EPA/Office of Research and Development, March 2005, in the docket)

Comment:

One commenter (OAR-2002-0056-5548) stated that by definition, co-benefit reductions

occur anyway as a result of control technologies installed to meet the CAIR. Hence, it is

unnecessary to establish a cap to achieve Hg reductions through co-benefits.

As the commenter noted in their initial comments, because co-benefit Hg reductions will

occur anyway, EPA’s better course is to measure precisely what these co-benefits are, and use

that information to set an interim cap in 2012, that would be effective in 2015. Setting the initial

cap in 2012 allows EPA to quantify the precise amount of co-benefits reductions, and also allows

EPA to dispense with its grossly unfair coal rank allowance allocation “adjustment” factors, since

no such adjustments would be needed in the absence of an initial 2010 cap. As well, by 2012,

EPA will be able to properly assess the performance of new Hg-specific control reduction

technologies such as ACI to reduce Hg emissions across all coal ranks. The commenter was

confident that the technology will show that roughly equal removal levels can be achieved across

all coal ranks. Hence, EPA would not be justified in establishing allowance allocation adjustment

factors for any subsequent cap.

The commenter noted that the EEI’s modeled “Alternative Hg Trading” scenario outlined

in the NODA generally follows this approach by establishing no first phase co-benefits cap, and

setting an initial firm cap (24 TPY) in 2015. Because the EEI proposal would allow banking of

early reduction credits above co-benefits, the eligibility of actions that qualify for early reduction

credit would need to be defined. However, this early reduction and banking system is wholly

discretionary, and consequently there is no need to adjust allocation of allowances by coal rank to

implement it since there is no specific obligation by any individual source to reduce Hg emissions

to a pre-determined level.

Response:

EPA is finalizing a cap-and-trade approach under section 111. EPA is establishing a

phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for
9-cxxix

rationale. The cap-and-trade program will include a provision for banking. See final rule

preamble and Chapter 5 comment responses for further discussion of banking. EPA is not

including a provision for early reduction credits in the final rulemaking. See Chapter 5 response

to comments for further discussion of ERCs.

8. More recent test data on subbituminous coal-fired units equipped with SCR

indicate that SCR does not enhance the oxidation of Hg0

 on such coals and, thus,

does not provide for additional capture in a wet scrubber (OAR-2002-0056-1268,

-1270). Based on these data, EPA is considering revising the emission modification

factor (EMF) for subbituminous coal-fired units equipped with SCR and wet FGD

in the IPM model. EPA recommends use of the EMF control combination before an

SCR is added (i.e., ascribe no additional control due to the addition of the SCF). 

EPA requests comments on these proposed changes: for CS-ESP/SCR/FGD, use

CS-ESP/FGD (0.84); for FF/SCR/FGD, use FF/FGD (0.27); and for HSESP/SCR/FGD, use HS-ESP/FGD (0.80). EPA also requests comment on the

appropriateness of using other test data (DOE and EPRI tests) for EMF

development and asks commenters to submit any relevant data.

Comment:

One commenter (OAR-2002-0056-5475) mentioned that EPA may rely on information

gleaned from reports that were not available for public review prior to the end of the comment

period. The commenter recommends that any reports, or studies, relied upon in making

determinations relevant to the Hg rule be made available for public review.

Response: 

EPA projections of Hg co-benefits are based on 1999 Hg ICR emission test data and

other more recent testing conducted by EPA, DOE, and industry participants. This testing is

summarized in reports by EPA, DOE and others and are available on EPA's website. In

addition a comprehensive summary of this test was prepared by EPA's Office of Research and

Development (ORD) assessment and made available in the docket at time of the proposal.

available in For the final rule ORD has prepared an updated assessment (see Control of

Emissions from Coal-Fired Electric Utility Boilers: An Update, EPA/Office of Research and

Development, March 2005, in the docket).

Comment:

One commenter (OAR-2002-0056-5482) stated that in August 2003, a pilot-scale SCR

reactor was installed at a Fort Union mine-mouth lignite-fired EGU located in North Dakota. The

study was conducted by the Energy and Environmental Research Center (EERC) to determine the

ability of new and aged catalyst to oxidize Hg at full-scale EGUs. The results indicate that SCR

technology was not effective in oxidizing Hg and that the sulfation of calcium and sodium ash

deposits foul the catalyst rendering the SCR technology ineffective for NOx control.
9-cxxx

An article describing the findings has been accepted for publication in Fuel Processing

Technology. A copy of the “article in press” entitled, “SCR Catalyst Performance in Flue Gases

Derived from Subbituminous and Lignite Coals” can be downloaded from the EERC ftp site:

ftp://ftp.undeerc.orglbenson/ .

The article is also available online via Science Direct in the “Articles in Press” section for

the following title: http://authors.elsevier.com/sd/article/S0378382004001870 .

Response:

EPA has examined the commenter's analysis in context of the final rulemaking. EPA's

modeling Hg co-benefit assumptions already assume that SCR does not enhance Hg control for

lignite plants.

Comment:

One commenter (OAR-2002-0056-5482) noted that Table 5 of the NODA, “Hg Removal

Assumptions for Pollution Control Equipment,” identifies lignite EMF factors for various EGU

pollution control configurations. As noted in the above EERC study and EPA’s acknowledgment

of a lack of SCR elemental Hg reduction co-benefits for subbituminous coal (similar to Fort

Union lignite), the this commenter recommends an EMF factor designation of 1.0 or “NA” (not

applicable) for all Fort Union EGU pollution control configurations employing SCR.

As previously noted, elemental Hg is the predominant form of Fort Union Hg emissions

and conventional air pollution control equipment provides little or no incidental removal. An

important factor impacting EMF values is the high variability of Hg and important species such as

chloride and alkali. The interplay of the chemical factors coupled with EGU operation variations

would not justify an EMF factor of less than 1.0. The EMF factor of 0.56 for configuration

PC/CS-ESP/FGD is not representative of Fort Union lignite EGU emissions.

The commenter recommends an EMF factor of 1.0 be employed for PC/CS-ESP/FGD,

similar to the PC/CS-ESP, FF/FGD-Dry and PC/FF configurations.

No Fort Union configurations of PC/CS-ESP/FGD-Dry are known. The commenter

recommends an EMF factor designation of “NA.”

The commenter also recommends an EMF factor of “NA” for all PC/HS-ESP pollution

control configurations since the technology is not applicable or utilized by Fort Union EGUs.

Response: 

EPA projections of Hg co-benefits are based on 1999 Hg ICR emission test data and

other more recent testing conducted by EPA, DOE, and industry participants. EPA believes the

lignite factors used for final rulemaking analysis are supported by ICR test data. (For further

discussion see Control of Emissions from Coal-Fired Electric Utility Boilers: An Update,

EPA/Office of Research and Development, March 2005, in the docket.)
9-cxxxi

Comment:

One commenter (OAR-2002-0056-5446) stated that in order to provide a level playing

field any “cap-and-trade” type regulatory approach must include appropriate allocation factors. 

The factors currently proposed by the EPA, 1.0 for bituminous, 1.25 for subbituminous and 3.0

for lignite do not adequately address this issue. Even the EPA states that these factors are only

“directionally correct,” this is a completely inadequate basis for setting a regulatory standard.

Furthermore, assessment of the EMFs used in the different models indicates that these

allocation factors are likely to be inadequate. For the most common generating configuration

(PC/CS-ESP representing approximately 59 percent of generating capacity) the EPA and EIA

assume a 36 percent Hg reduction for bituminous coal and a 3 percent reduction for

subbituminous coal, CRA assumes a 35 percent reduction for bituminous coal and a 20 percent

reduction for sub-bituminous coal. For the second most common configuration

(PC/CS-ESP/FGD representing approx 16 percent of capacity) the EPA and EIA assume a

66 percent Hg reduction for bituminous coal, and a 16 percent and 27 percent reduction

respectively for subbituminous coal. Even when adjusted for average Hg content of bituminous

and subbituminous coals these reduction factors imply that the allocation factor for subbituminous

coal should be higher that the 1.25 proposed by the EPA.

However given the wide range of uncertainty in the reduction factors (e.g., a reduction

factor of between 3 percent and 20 percent for PC/CS-ESP with sub-bituminous coal) basing

allocation factors on the relative proportions of elemental Hg produced by the different coal ranks

is likely to be a more robust approach.

Because the amount of elemental Hg produced effectively reflects the difficulty of control,

factors based on elemental Hg content are more likely to result in an even distribution of the

compliance burden between coal ranks in the long term. However, because plant configuration

also affects Hg capture and as subbituminous coal is typically burned in plant configurations that

produce little co-benefit capture (e.g., plants with dry scrubbers) a subbituminous factor based

purely on elemental Hg content will be inadequate to avoid fuel switching in the short term. As

per our original comments, factors of 1.0 for bituminous, 1.9 for subbituminous and 2.95 for

lignite, as proposed by the industry majority during the CAAAC process, appear to be the most

appropriate. These factors have been calculated from the floors developed by industry majority

position, which included representatives from the unions, the major coal producing regions and a

large proportion of the electric utility industry.

Testing to date indicates that the presence of an SCR does not enhance Hg removal from

sub-bituminous coals. Therefore, the commenter strongly supports the EPA’s recommendation

that the EMF assume that the presence of an SCR provides no additional Hg control for

sub-bituminous coals.

Response:

As discussed in the Chapter 5, section 5.6.1, EPA is finalizing coal adjustment factors for
9-cxxxii

the purpose of establishing state emission budgets of 1.0 for bituminous coals, 1.25 for

subbituminous coals, and 3.0 for lignite coals. For further discussion see final rule preamble

(section IV.C.4) and Technical Support Document for the Clean Air Mercury Rule Notice of

Final Rulemaking, State and Indian Country Emissions Budgets, EPA, March 2005.

Comment:

One commenter (OAR-2002-0056-5510) stated that EPA should draw upon whatever

data is available, provided appropriate data quality controls have been applied. In this regard,

however, the commenter again drew attention to the problems with EPA’s use of the ICR Part III

data set, as outlined in their May 14, 2004 comments. In particular, the commenter noted their

concerns associated with EPA’s use of short-term test data. Great care should be taken to

account for the uncertainty and variability in coal quality, unit operation, and to the variable

performance of pollution control devices. The commenter does not believe that the large degree

of uncertainty incorporated by these variables can be adequately attenuated through short term

tests performed on a limited number of units, coal types, plant configurations and operating

conditions. To resolve these problems, EPA should institute a comprehensive test program, as

elsewhere described in these comments.

Response:

EPA has used the best data were possible in developing its analysis for the final

rulemaking. The Agency's position on the state of Hg technology is contained in the EPA 's

Office of Research and Development white paper (see Control of Emissions from Coal-Fired

Electric Utility Boilers: An Update, EPA/Office of Research and Development, March 2005).

Comment:

One commenter’s (OAR-2002-0056-5492) question: EPA is considering making three

changes to the subbituminous coal EMF used in the IPM: for CS-ESP/SCR/FGD use

CS-ESP/FGD (.84); for FF/CR/FGD use FF/FGD (.27); and for HS-ESP/SCR/FGD use

HS-ESP/FGD (.8). EPA is seeking comments on these proposed changes.

In the NODA, EPA cites two literature references: OAR-2002-0056-1268 and

OAR-2002-0056-1270. These two references cite the same source data, based on a single test. 

The two reports are using information developed and reported in an EPRI report. In the report,

EPRI and their contractor point out several exceptions to standard flue gas sampling procedures. 

First, the samples are single point and are not a full or even a partial traverse of the duct. Flue gas

stratification could mean that the observations are not representative of the entire flue gas stream. 

Second, only duplicate flue gas Hg samples were obtained. In all EPA methods, samples are

obtained in triplicate. The authors state that “. . . the data set presented here is small, so the

reader should exercise caution in extrapolating the results. . . .”

In addition, the authors state that “an increase in oxidized Hg from 8 percent to 18 percent

(occurred) across the SCR.” They go on further to state “Consequently, Hg capture across the
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ESP increased from 60 percent to 78 percent as a result of SCR operation.” The authors

statements in the cited reports do not support EPA’s conclusion that “SCR does not enhance the

oxidation of Hg.” The commenter respectfully suggested that the proposed changes are

unwarranted based on the data submitted by EPA.

Question: EPA is seeking comment on the appropriateness of using other test data for

EPM development and requests commenters submit any test data that may be relevant.

The Department of Energy has operated a COHPAC system for Hg removal at the

Southern Company Gaston Station which fired a low sulfur bituminous coal for about one year.

At an injection concentration of 0.55 lb/mmacf and using 2.7 denier bags, over a four-month

period the average Hg removal was 86 percent. During shorter-term tests using higher denier

bags, 7 denier, it was possible to achieve greater than 90 percent Hg removal. The weekly

average Hg removals observed at the Gaston site are presented in e-docket text.

In addition to the COHPAC tests, additional tests were conducted using activated carbon

injection on CS-ESP and SCR/dry FGD units firing subbituminous coals. For example, at the

subbituminous coal fired Sunflower Electrics Holcomb Station which is equipped with a SCR/dry

FGD system, over 90 percent Hg reduction was achieved for the entire 4-week test period.

In addition, there have been tests at Pleasant Prairie Station that fires a subbituminous coal

and is equipped with a CS-ESP. At an injection rate of 11 lb/mmacf, 73 percent Hg removal was

reported.

Additional tests were completed on both bituminous and subbituminous coals. There are a

number of publications listed at the following web address: www.adaes.com under “Publications”

on the tool bar. There have been at least four full-scale evaluations of ACI on PRB coal fired

units (Holcomb Arapahoe (two tests), Meramec) and four tests on lignite fired boilers(Antelope

Valley, Stanton 1, M.R. Young, and Monticello). 

Response:

EPA appreciates the commenter's input to the record on the status of control

technologies. The Agency's position on the state of Hg technology is contained in the EPA 's

Office of Research and Development white paper (see Control of Emissions from Coal-Fired

Electric Utility Boilers: An Update, EPA/Office of Research and Development, March 2005). 

Comment:

One commenter (OAR-2002-0056-5502) referenced co-benefits and agreed with EPA’s

proposal to assign no co-benefit to the addition of an SCR at a site with an SO2 control that is

burning a western fuel. This is generally supported by the small, but growing, body of data

available to date. These data are provided in the detailed comments, as are suggested EMFs for a

number of fuel/air pollution control configurations.
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Power plants firing a bituminous coal can expect to experience oxidized Hg fractions in

the flue gas entering the FGD that range from 75-90 percent–i.e., high but not necessarily always

in the 90 percent range. There does not appear to be a significant increase in Hg oxidation for

PRB coals, and potential low-chloride bituminous coals.

Response:

EPA projections of Hg co-benefits are based on 1999 Hg ICR emission test data and

other more recent testing conducted by EPA, DOE, and industry participants. EPA believes the 

factors used for final rulemaking analysis are supported by test data. EPA's Hg co-benefit

assumptions can found in the IPM documentation in the rulemaking docket (see Documentation

Summary for EPA Base Case 2004 (v.2.1.9) Using the Integrated Planning Model, EPA,

October 2004). The Agency's position on the state of Hg technology is contained in the EPA 's

Office of Research and Development white paper (see Control of Emissions from Coal-Fired

Electric Utility Boilers: An Update, EPA/Office of Research and Development, March 2005). 

Comment:

One commenter (OAR-2002-0056-5535) said that in conducting the various modeling

exercises, different stakeholders used different emission modification factors (EMF) to calculate

the Hg co-control benefits of different NOx and SO2 controls. The EPA requests comments on

what EMF are appropriate. As shown in Table 5 of the NODA, there are differences in EMF the

agency has developed and those used by Charles River Associates (CRA) for industry stakeholder

modeling. The commenter noted that the EMF used by CRA are consistently lower than the EMF

developed by EPA, that is, they result in less co-control of Hg emissions than assumed by EPA. 

The result, not surprisingly, is that industry stakeholders estimate that Hg emissions will be higher

after implementation of CAIR requirements than EPA has stated. Because EPA has proposed to

establish the first phase of its pollution trading scheme to reflect reductions achieved as a

co-benefit of CAIR, the effect of industry’s suggested EMF changes would be to inflate the initial

Hg cap, making it easier to meet without significant control, or making it easier for companies to

bank allowances for future use.

With the exception of new data on the effects of SCR on Hg oxidation when

subbituminous coals are fired, the commenter saw no new information in the other commenter’s

remarks that should lead EPA to change the EMF in the IPM. EPA developed the existing EMF

after analyzing the extensive ICR data set. In contrast, there are no new analyses of Hg

co-control presented by other commenters. Thus, EPA need not revise its EMF, despite the

desire of industry stakeholders to raise the first phase Hg cap. With respect to EPA’s intention to

revise the EMF associated with the use of SCR with subbituminous coals, the agency does not

provide sufficient information for us to comment on whether this is a legitimate action. The

agency merely refers to “more recent test data.” EPA must submit to the docket all of the test

data along with the agency’s analysis of such test data in support of any such changes to the EMF. 

Revising the EMF associated with the use of SCR with subbituminous coals without making such

data and analysis publicly available would be arbitrary.
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Fourth, EPA also mentions Hg speciation in the context of conducting economic modeling

with the IPM. With respect to the use of different speciation profiles in the IPM, EPA notes that

the national estimate of emissions of the three forms of Hg is Hg0

–54 percent, Hg+2–43 percent,

and Hgp–3 percent. The agency states that plant-specific estimates based on these data were used

in the IPM modeling activities. The IPM should not be revised with respect to Hg speciation. To

the extent that different speciation profiles have been estimated for different coal types and

control device configurations, these data have already been incorporated into the IPM through the

use of EMF. The EMF are average control levels that are calculated from average Hg and

chlorine levels in coal and averages of test data, so the use of average speciation profiles in the

IPM model is appropriate. The commenter noted however, that EPA could and should improve

the speciation profiles used in deposition modeling, as discussed above.

Response:

EPA projections of Hg co-benefits are based on 1999 Hg ICR emission test data and

other more recent testing conducted by EPA, DOE, and industry participants. This testing is

summarized in reports by EPA, DOE and others and are available on EPA's website. In

addition a comprehensive summary of this test was prepared by EPA's Office of Research and

Development (ORD) assessment and made available in the docket at time of the proposal. For

the final rule ORD has prepared an updated assessment (see Control of Emissions from CoalFired Electric Utility Boilers: An Update, EPA/Office of Research and Development, March

2005, in the docket). With regard to speciated profiles, IPM modeling includes only total Hg

emissions projections as output. EPA than post-processes IPM unit level results to determine the

speciated form of Hg at the unit level. This information is than used in deposition modeling. 

The determination on speciated emissions is based on 1999 ICR data.

Comment:

One commenter (OAR-2002-0056-5548) noted that EPA was considering revising the

EMFs for subbituminous coal-fired units equipped with SCR and wet FGD. After reviewing the

literature cited by EPA to support this change and discussing the supporting data with EPA R&D

and EPRI, the commenter did not believe that the available data support the proposed changes. 

First, there are not two independent literature sources as cited by EPA in the NODA. These two

papers simply report the same information from a single set of measurements on a PRB coal-fired

unit, equipped with an SCR, a CS-ESP, originally reported in EPRI Report 1005400 dated

December 2002. Notably, although EPA proposes to use these data to modify the EMFs for

FGD-equipped units, the one test cited in these two reports was done on a unit with no FGD. It

also is noteworthy that the report states, “Caution is urged in drawing conclusions from this

limited set of data. The results are based on short-term tests that might be misleading due to the

potential for substantial variation in total and speciated mercury concentration.” Moreover, the

results do show a significant increase in oxidized Hg across the SCR (from 8 percent to 18

percent), and a total Hg removal (78 percent) for a SCR-CESP unit. The commenter believed

that the proper manner to evaluate the effect of SCR operations is the impact on total Hg

removal. These results, the only ones that EPA cites, indicate that a boiler equipped with an

SCR-CS ESP combination firing a subbituminous coal can achieve a 78 percent Hg reduction. 
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One of the cited references states “Consequently, mercury capture across the ESP increased from

60 percent to 78 percent as a result of SCR operation.” The EPA, DOE, and EPRI authors

ascribe a significant increase in Hg removal to the SCR operation. The cited literature does not

support EPA’s contention that they should “...ascribe no additional control due to the addition of

the SCR...” Rather the cited papers state that the operation of the SCR improved total Hg

capture.

The commenter added that in addition to the papers cited by EPA in the NODA, there was

a joint study conducted by EPA R&D and EPRI at the Texas Genco WA Parish Station. (The

final report is in draft.) The Parish Station burns subbituminous coal and is equipped with an

SCR/FF/wet FGD air pollution control system. This system achieved 64 percent Hg control with

the FF/wet FGD in operation. With the SCR/FF/wet-FF/wet-FGD in operation, the Hg removal

increased to 79 percent. Again the operation of the SCR significantly increased the co-benefit Hg

removal of the air pollution control system.

In the commenter’s opinion the literature provided no supporting information for the

proposed changes to the EMFs. Instead, it indicates that the EMF for subbituminous coal-fired

units equipped with CS-ESP/SCR/FGD should be 0.2, and for units equipped with SCR/FF/FGD

should be between 0.2 and 0.3.

Response:

EPA projections of Hg co-benefits are based on 1999 Hg ICR emission test data and

other more recent testing conducted by EPA, DOE, and industry participants. EPA has assumed

for the final rulemaking analysis that for subbituninous-fired units that SCR has the no ability to

convert elemental Hg to ionic Hg and thus allow easier capture in a wet-FGD scrubber. EPA is

thus using the emission modification factors for CS-ESP/SCR/FGD, use CS-ESP/FGD (0.84);

for FF/SCR/FGD, use FF/FGD (0.27); and for HS-ESP/SCR/FGD, use HS-ESP/FGD (0.80). 

EPA EPA's Hg co-benefit assumptions can found in the IPM documentation in the rulemaking

docket (see Documentation Summary for EPA Base Case 2004 (v.2.1.9) Using the Integrated

Planning Model, EPA, October 2004). The Agency's position on the state of Hg technology is

contained in the EPA 's Office of Research and Development white paper (see Control of

Emissions from Coal-Fired Electric Utility Boilers: An Update, EPA/Office of Research and

Development, March 2005). 

Comment:

One commenter (OAR-2002-0056-5497) stated that the different levels of Hg co-benefits

predicted from implementation of the CAIR rule are hardly surprising. The 1999 Information

Collection Request (ICR) stack testing results, which serve as the basis for most emission

modification factors, showed highly variable Hg removals in plants equipped with the same

control equipment. In addition, predicting the level of Hg co-benefits resulting from the CAIR

rule requires one to estimate the effects of SCRs on Hg removal. Mercury testing of SCRs is

limited and questions remain about a number of factors that may affect the amount of elemental

Hg that is converted to ionic Hg in an SCR. As a result of these uncertainties, it is impossible to
9-cxxxvii

predict the true co-benefits that will be achieved from implementation of the CAIR rule. As was

described in the preceding response, the commenter believed that instead of trying to set a “hard”

cap based on co-benefits in 2010. EPA would be better served by imposing a “soft” cap and

commencing trading

in 2015.

The commenter agreed with the Electric Power Research Institute (EPRI) that many of

the EMFs should be revised, in most cases very slightly, to reflect additional information that has

been received since EPA last ran its IPM model. For example, for bituminous coals, the

commenter recommended these changes:

• CS-ESP/wet FGD: Revise EPA’s EMF from 0.34 to 0.40 because six additional test

results have doubled the database.

• SCR/CS-ESP/wet FGD: Revise EPA’s EMF from 0.10 to 0.15 based upon ICR

measurements and recent SCR/FGD co-benefits tests.

For other configurations (e.g., SCR/FF/wet FGD and SCR/FF/dry FGD) the commenter

believed that no change is justified. A complete list of our recommendations is attached.

Response:

EPA is finalizing a cap-and-trade approach under section 111. EPA is establishing a

phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for

rationale. EPA projections of Hg co-benefits are based on 1999 Hg ICR emission test data and

other more recent testing conducted by EPA, DOE, and industry participants. EPA EPA's Hg

co-benefit assumptions can found in the IPM documentation in the rulemaking docket (see

Documentation Summary for EPA Base Case 2004 (v.2.1.9) Using the Integrated Planning

Model, EPA, October 2004). The Agency's position on the state of Hg technology is contained

in the EPA 's Office of Research and Development white paper (see Control of Emissions from

Coal-Fired Electric Utility Boilers: An Update, EPA/Office of Research and Development,

March 2005). 

Comment:

One commenter (OAR-2002-0056-5497) stated that they believed that there were

inadequate data to assign any measurable or reproducible level of SCR co-benefits for either wet

or dry scrubbers. Two independent sources of data support this conclusion.

First, EPRI has synthesized the increase in oxidized Hg across SCR equipment at 18 sites. 

Of the 18 sites, three fire Powder River Basin (“PRB”) coal and exhibit an increase in oxidized Hg

between effectively zero (Site S9) to 19 percent (Site 1). These data suggest there is effectively

no Hg oxidation across the SCR catalyst. The commenter did not think that the anomalous Site 1

unit–a cyclone boiler–is representative of the boiler design and characteristics of the boiler

population in this nation. That boiler has relatively low particulate matter loading, elevated NOx
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level entering the SCR reactor, and the lowest space velocity (e.g., most generous catalyst

volume) of any of the tested units. Cyclone boilers comprise less than 5 percent of the boiler

population. The other units are representative of boiler design and catalyst space velocity. While

they suggest a 3-4 percent increase in Hg oxidation with PRB coal, this is within the “noise” of

the measurement systems.

The second set of data that supports this conclusion is the measurement of increased Hg

removal across a wet scrubber due to SCR. Of the sites reported, only Site 11 is equipped with

wet scrubber. The use of SCR induces an 11 percent increase in the removal of Hg by a wet

scrubber. Site 11 is equipped with a fabric filter that precedes the wet scrubber, and EPRI reports

that much of the Hg oxidation occurs across the fabric filter, unrelated to the SCR. 

Consequently, it appears that much of the 11 percent increase in Hg removal is due to the fabric

filter, and not the SCR.

For these reasons, and because the data are sparse and preliminary, the commenter suggested that

zero co-benefits be assigned to the role of SCR on PRB and other subbituminous coals.

Response:

EPA has assumed for the final rulemaking analysis that for subbituninous-fired units that

SCR has the no ability to convert elemental Hg to ionic Hg and thus allow easier capture in a

wet-FGD scrubber. EPA EPA's Hg co-benefit assumptions can found in the IPM documentation

in the rulemaking docket (see Documentation Summary for EPA Base Case 2004 (v.2.1.9) Using

the Integrated Planning Model, EPA, October 2004). 

Comment:

One commenter (OAR-2002-0056-5411) stated that their results indicated that the EMFs

are not related to coal rank, but do vary with coal age. The consistent relationship between the

EMFs and the geologic age of coal, coupled with simple criteria that definitively establish the age

of coal, provide a scientifically justified and practical basis to subcategorize coal for regulation of

Hg emissions.

The commenter stated that commercial U.S. coal was formed during two, substantially

different geologic ages, and can be broadly grouped as older Paleozoic coal, and younger

Mesozoic/Cenozoic coal. The mutually exclusive geographic occurrence of Paleozoic coal and

Mesozoic/Cenozoic coal is significant. Unlike coal rank, which varies locally, with ASTM

standard vintage, and with assay precision, geologic age can be unambiguously determined based

on coal origin location. Moreover, the origin location of coal shipments to units 50 MW is

publicly reported; if regulation of units as small as 25 MW is required, determining the coal origin

location is clearly less burdensome than representative sampling for coal rank assays. Finally, a

precise coal origin location is not required to establish geologic age. Indeed, the “state-of-origin”

reported on FERC form 423 is sufficient to establish geologic age for current coal production.

The commenter also stated that in the unlikely event that the age of a coal shipment is
9-cxxxix

disputed, the 200 million year interval between Paleozoic coal and Mesozoic/Cenozoic coal is

significant. Ubiquitous pollen from angiosperms (flowering plants), as well as certain terpene

resins, are found in Cretaceous and Paleogene coal, but absent from Paleozoic coal.

Consequently, if shipment receipts or transportation records prove insufficient, palynological or

geochemical assays can definitively settle such disputes.

The commenter calculated Emission Modification Factors (EMFs) for five of the

12 emission control technologies listed in Table 5 of the December 1, 2005 Federal Register

Notice (69 FR p. 69871). Their calculation method is described in their docket comment

(Appendix B) together with the tabulated data used for this calculation. The results are illustrated

in the figure below, which shows greater Hg capture for units burning Paleozoic coal than for

units burning Mesozoic/Cenozoic coal. Note that all U.S. Paleozoic age coal is bituminous or

anthracite rank, whereas the rank of U.S. Mesozoic/Cenozoic age coal varies. Importantly, the

figure below also shows that the EMF does not vary with coal rank, but does vary with coal age.

The commenter added that the EMFs that they calculated are not directly comparable to

those shown in Table 5 of the NODA. Nonetheless, with two minor exceptions, our EMFs are

generally closest to the CRA 2004 values listed in the table. The first exception is for the

relatively small HS-ESP/FGD technology class, where our EMF values are more similar to the

EPA and EIA values. Secondly, our EMFs for the important CS-ESP/FGD technology class

suggest slightly less Hg capture for this class than any of corresponding EMFs in the table.

U.S. Cenozoic/Mesozoic age coal has greater fractional mercury emissions (EMF

values) than U.S. Paleozoic age coal, when burned in units equipped with conventional

emission control technologies; this difference is not related to coal rank.
9-cxl

Notes, PC: pulverized coal; HS-ESP: hot-side electrostatic precipitator; CS-ESP: cold side

electrostatic precipitator; HS-ESP-FGD: hot-side electrostatic precipitator with wet Flue Gas

Desulphurization; FF-FGD-Dry: Fabric Filter and spray dry adsorption Flue Gas

Desulphurization.

More than 25,800 ICR records were used to calculate the EMF values presented in the

figure above; ~5,500 ICR coal assay data records where the location origin was not reported were

ignored, as were ~3,300 records corresponding to blended coals. The tonnage weighted EMFs

calculated for this comment (Table 3) indicate the fractional emissions expected if all U.S. coal

were burned in each technology class, rather than the coals that are currently burned. Although

this approach is neutral with respect to fuel switching, it may overestimate Hg emissions for some

units that burn blended coal. The omission of blended coals is likely to have slightly decreased

our EMF’s for CESP/FGD units and PC/FF-FGD-Dry units. This effect can be demonstrated for

these technologies using the equations listed in Table Bl (see OAR-2002-0056-5411), which

predict net improved Hg capture for blends containing both high and low chlorine coal. The

equations show predicted Hg capture substantially increases as chlorine content approaches 500

ppm, but only modestly rises above 1000 ppm chlorine. Thus, blending to optimum chlorine

content between 500 and 1000 ppm, should result in a net reduction of Hg emissions.

A potentially more significant limitation of the EMFs presented in this comment is equally

applicable to those listed in Table 5 of the NODA. Current FF/FGD-Dry technology is limited to

low-sulfur coal. Fortunately, excluding the ~30 percent of U.S. coal production that contains

more than 1 lb sulfur/106

 Btu, does not significantly change the our calculated EMFs for

FF-FGD-Dry technology; respective EMFs for Paleozoic and Mesozoic/Cenozoic coal are 0.13

and 0.64, for low-sulfur coal burned in units with FF/FGD-Dry technology. However, assuming a

1 lb sulfur /106

 Btu limit, FF/FGD-Dry technology is only applicable to ~25 percent of northern

lignite, and hardly any Texas lignite, or coal from Ohio and Northern Pennsylvania - all of these

areas produce relatively high Hg coal. Consequently, one of the best existing Hg reduction

technologies is not appropriate for many coals with the highest Hg contents.

Due to time constraints, the commenter noted without comment the remarkably improved

Hg capture suggested by the EMFs listed in Table 5 for units with SCR technology compared to

those without SCR. For the same reason, the commenter had not considered Indonesian,

Venezuelan, Columbian, Polish, or Alaskan coal, although these calculations are comparatively

straightforward. Evaluation of potential coal supplies from countries not included in the ICR is

more problematic; assay data from the USGS international coal data base might be useful for this

purpose.

Response:

For the final rulemaking, EPA is using Hg emission modification factors based on coal

rank. We believe this approach is consistent with our understanding of Hg control. The

Agency's position on the state of Hg technology is contained in the EPA 's Office of Research

and Development white paper (see Control of Emissions from Coal-Fired Electric Utility

Boilers: An Update, EPA/Office of Research and Development, March 2005). EPA EPA's Hg
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co-benefit assumptions can found in the IPM documentation in the rulemaking docket (see

Documentation Summary for EPA Base Case 2004 (v.2.1.9) Using the Integrated Planning

Model, EPA, October 2004).

B. Issues of Hg Speciation

General Comments Concerning Issues of Mercury Speciation

Comment:

One commenter (OAR-2002-0056-5460) stated that the NODA reveals an undue concern

for alleged uncertainties concerning Hg speciation and the relative contribution of domestic power

plants to global Hg emissions. The commenter further stated that EPA need not and should not

delay regulation of domestic power plant Hg emissions until those alleged uncertainties are

resolved. According to the commenter, rather, to the extent uncertainties exist concerning such

topics as Hg speciation, transport, deposition and exposure, those uncertainties provide a basis for

imposing stricter protections so as to ensure an adequate margin of safety. The commenter stated

that no other approach is consistent with the preventive and precautionary purposes of the CAA.

The commenter (OAR-2002-0056-5460) also stated that developing a Hg speciation

profile is not relevant to setting a proper MACT floor pursuant to CAA section 112. The

commenter added that, rather, by statute that floor is to be based on the average of actual

emissions achieved by the top 12 percent of the coal-fired power plants for which EPA has data. 

The commenter added that, equally important, developing a speciation profile will not cure the

legal defects in EPA’s proposed section 111 approach.

The commenter stated that a speciation profile might be relevant to certain aspects of the

beyond-the-floor analysis required by section 112, but EPA cannot and should not use either the

fact of speciation, or uncertainty about the nature of such speciation, as a basis for concluding that

section 112 no longer applies. The commenter further stated that, indeed, EPA’s December 2000

determination that it was necessary and appropriate to regulate Hg emissions from power plants

was not limited to particular species of Hg, and no basis exists for EPA to revisit or revise that

determination now.

Response:

EPA is not delaying regulation of U.S. utility units until all uncertainties are resolved. 

However, we believe that these uncertainties do factor into the approach that should be taken in

such regulation. We believe that the cap-and-trade approach being finalized adequately

accounts for the uncertainties.

Comment:
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One commenter (OAR-2002-0056-5535) stated that the Agency’s interest in speciation

profiles and how they relate to Hg control, fate and transport, and ultimately human exposure

raises the question of whether the Agency is contemplating basing emission rates or trading

schemes on the level of different Hg species emitted. The overall impression left by this line of

inquiry is that the Agency is suggesting that only oxidized Hg emissions from power plant need to

be controlled. This is clearly inappropriate and arbitrary – elemental Hg is no less important than

oxidized Hg in terms of the environmental and public health impacts in the U.S. To imply that

elemental Hg does not contribute to Hg exposure in the U.S. is incorrect, because elemental Hg is

eventually oxidized and deposited. This deposition can occur on the east coast of the U.S. as a

result of emissions from a boiler located in the western U.S., or it may occur in the western U.S.

from elemental Hg emissions circling the globe. Comments submitted to the EPA by a

consortium of scientists convened by the Hubbard Brook Research Foundation (HBRF)

emphasize that elemental Hg can be rapidly converted to oxidized Hg and deposited locally or

regionally. This process is known to occur after polar sunrises in the Arctic and Antarctic

atmosphere and in the marine boundary layer in the presence of marine aerosols. Furthermore,

emissions of oxidants from utilities and other high-temperature sources provide ample reactants

for oxidizing elemental Hg. New research shows that dry deposition of elemental Hg, uptake of

elemental Hg by the forest canopy and subsequent litter fall can provide more than twice as much

Hg to a watershed than wet deposition. Moreover elemental Hg can be converted to reactive

gaseous Hg (RGM or oxidized Hg) at a tree’s leaf surface, thereby enhancing the deposition of

elemental Hg at the local and regional scale and reducing long range transport. Consequently,

there is ample evidence that emissions of elemental Hg must be reduced in conjunction with

oxidized Hg emissions.

In addition, EPA cannot even entertain the notion that elemental Hg emissions need not be

controlled from U.S. power plants and maintain an ounce of credibility in global Hg protocol

discussions. One of Administrator Leavitt’s “guiding principles” recognizes that Hg is a global

issue and asks what opportunities there are to reduce Hg emissions worldwide. The opportunities

to reduce global emissions (and their subsequent impacts in the U.S.) will only arise if the U.S. is

serious about reducing total Hg emissions from coal-fired power plants.

Comment:

One commenter (OAR-2002-0056-5464) noted that the NODA includes a discussion

about speciation. It is unclear to them what EPA means by this discussion. If EPA’s intention is

to regulate by species, it is important to note that the workgroup discussed that idea briefly and

rejected it as an unworkable solution. Further, although some companies have indicated that Hg

emitted as oxidized all becomes elemental Hg in the plume as it exits the stack, this is counter to

the vast research on Hg’s behavior in the atmosphere. The key point here is that this industry

finding is too preliminary, is within the error of measurements, and has had inconsistent results in

different power plant plumes. Even if this one reaction among many is confirmed in later studies,

this work needs to be interpreted in the context of many other atmospheric reactions of Hg whose

net effect and direction tendency is just the opposite: conversion of elemental Hg into oxidized

Hg. Oxidized Hg deposits locally and regionally, and a MACT that requires ALL power plants to
9-cxliii

substantially reduce emissions significantly (80-90 percent) would protect against hot spots.

The discussion about speciation relates to the atmospheric fate and transport of Hg

emissions. Regardless of where emissions originate, in a world where international transport is

becoming an increasing public health concern, there is no justification for this country turning its

back on our contributions to transboundary pollution. This commenter believed the U.S. should

show leadership by controlling Hg emitted here, regardless of where and how emissions travel.

Response:

EPA is showing leadership through issuance of this first-ever regulation limiting Hg

emissions from coal-fired power plants. We agree that, at this time, it is inappropriate to

regulate Hg emissions by species and, therefore, have structured the final rule on a total Hg

basis.

Comment:

One commenter (OAR-2002-0056-5559) stated that the 1999 ICR data is the most

comprehensive body of Hg speciation data available that was developed through consistent and

standard measurement methods. The commenter stated that EPA should rely on the ICR data as

the primary basis for evaluating existing Hg control measures. The additional body of Hg

emission testing conducted since 1999 by researchers and industry can be used to augment the

ICR data but in doing so EPA needs to account for differences in testing methods and conditions.

Response:

EPA concurs with the commenter.

Comment:

One commenter (OAR-2002-0056-5474) stated that it fully supports using different

multipliers for the different coal ranks for the reasons stated above, but is concerned that the

multiplier will be determined by using the coal or coals that a unit burned in 1999 rather than the

coal a unit is actually burning at the time the rules are finalized. That approach is inequitable and

grossly unfair to any unit that has switched from a higher to lower rank coal since 1999. This

commenter has two units that made the decision in 2001 to switch from bituminous to

subbituminous coal, to reduce NOx emissions to comply with new anticipated regulatory

requirements. The engineering and design work needed to make the equipment and operational

changes necessary for such a switch was started in late 2001. Construction commenced in early

2002 and was completed in 2003. After several test burns in 2003, subbituminous coal became

the sole fuel source at the beginning of 2004. The commenter has no plans to switch back to

bituminous coal in the future at such units. In fact, such an occurrence would be extremely

unlikely, since the move was made to meet more stringent permanent NOx requirements for these

units. Using EPA’s methodology, the baseline heat input for these units will be multiplied by 1.0
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when computing the number of allowances to be allocated to such units either for the State

trading program budget or for a Federal trading program administered by EPA. However, as

these units will be combusting subbituminous coal when the Hg reduction requirements become

effective, such units will be unfairly penalized, since they will not be allocated allowances based

on the coal actually being burned, which will result in approximately 25 percent fewer allowances

for each unit. EPA should not punish units that switched fuels to comply with earlier

environmental requirements not related to the CAMR, by allocating allowances based on the fuel

type burned in an arbitrary baseline year, 1999, rather than the fuel being burned at the time when

the rules are actually finalized.

Moreover, there may be Utility Units that have done the opposite of this commenter (i.e.,

that have instead switched to a higher rank coal since 1999). If EPA were to use 1999 as the

determining year for these units, their owners would receive a windfall of allowances, because the

proposed methodology would base the allowance allocation on a coal type that is in fact no longer

being burned.

To remedy this, this commenter suggests the following approach. EPA should use as the

determinate for which coal rank multiplier to apply, the rank of coal that was combusted by such

unit in the year the CAMR rule is finalized. Ideally, the goal should be to award allowances based

on the rank of coal that a unit is actually burning. Alternatively, EPA should specifically allow for

units like the commenter’s that switched fuels to a lower coal rank to petition EPA and, if States

are actually allocating allowances to Hg budget units, the relevant State, to receive an adjustment

to the coal rank factor in recognition of any situation like the one described above that would

allocate Hg allowances in an inequitable manner to units that switched fuels.

Response:

EPA is using 1999 coal type as the basis for the adjustment of the baseline for

establishing plant mercury allocations to be used in developing the state and tribal emission

budgets for the final rulemaking. However, in the example allocation methodology for states to

allocate at the unit level EPA is finalizing a different approach. EPA's example allows states to

use baseline heat input for the years 2000 through 2004 and coal type for those years. Under the

model trading rule, EPA notes that States and Tribes have the authority to allocate at the unit

level as they choose. See Chapter 5 and final rule preamble for further discussion of emission

budgets and allocation methodology.

Comment:

One commenter (OAR-2002-0056-5548) stated that EPA should adjust the Hg allowance

allocations, by coal rank, to reflect the disparity of Hg removal efficiencies that NOx and SO2

controls have among coal ranks in any emissions trading program established under sections 111

or 112. This commenter, and others, agreed with EPA’s proposal that coal rank emission control

disparities justify using differing allowance allocation adjustments for each coal rank. However,

the commenter argued that the allowance allocation adjustment factor for subbituminous coals
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should be increased from the proposaled factor of 1.25 to a higher factor of 1.5.

Response:

EPA is finalizing coal adjustment factors for the purpose of establishing state emission

budgets of 1.0 for bituminous coals, 1.25 for subbituminous coals, and 3.0 for lignite coals. 

These adjustment factors are considered to be appropriate numbers based on the test data

currently available. For further discussion see final rule preamble (section IV.C.4) and 

Technical Support Document for the Clean Air Mercury Rule Notice of Final Rulemaking, State

and Indian Country Emissions Budgets, EPA, March 2005.

Comment:

One commenter (OAR-2002-0056-5548) suggested that it should be obvious that EPA’s

allowance allocation approach, and the similar approaches advocated by Southern, UARG, and

others, based on speciation and control issues, are fundamentally flawed. The primary question

has been articulated by WEST Associates’ comment that “for facilities that would have to

purchase allowances, WEST Associates recommends that an additional allocation adjustment

factor be applied that promotes equitable allowance distribution, particularly in Phase I of the

cap” program reasoning that “it is critical that the allocations of mercury allowances reflect the

relative level of mercury control for bituminous, subbituminous and lignite coal ranks that will be

achieved, within each coal rank, by the SO2 and NOx controls required under the CAIR by 2010.” 

That this comment, and similar comments by Southern, UARG, and the SEC that EPA has cited

in the NODA, is a misconception seems clear. There is absolutely no reason to adjust allowance

allocations for purchasers of allowances based on relative levels of Hg reduction capability among

coal ranks because purchasers of allowances are not reducing anything; they are simply buying

allowances representing reductions made by others. That is the very point of the entire cobenefits cap-and-trade approach, where allowance purchases, and not controls, are the means to

compliance for many sources. It is equally obvious that allowance purchasers do not pay different

prices depending upon the rank of coal they burn. A purchaser of Hg allowances has the same

equitable status regardless of the rank of coal burned. The only relevant consideration at issue is

the price at which these three classes of allowance purchasers (bituminous, subbituminous, and

lignite) must buy allowances. And that price is exactly the same between all of the coal ranks.

Response:

EPA is finalizing coal adjustment factors for the purpose of establishing state emission

budgets of 1.0 for bituminous coals, 1.25 for subbituminous coals, and 3.0 for lignite coals. 

These adjustment factors are considered to be appropriate numbers based on the test data

currently available. For further discussion see final rule preamble (section IV.C.4) and 

Technical Support Document for the Clean Air Mercury Rule Notice of Final Rulemaking, State

and Indian Country Emissions Budgets, EPA, March 2005.

Comment:
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One commenter (OAR-2002-0056-5332) stated that the modeling results reported in the

NODA do not fill the gap. Because the modeling was done by numerous stakeholders with

different objectives, crucial assumptions (e.g., demand growth; natural gas prices; availability,

performance, and cost of control technologies) vary, with no attempt at systematic inquiry. 

Moreover, the results are not presented in uniform metrics and, therefore, in many cases are not

comparable. The commenter urged the Agency to undertake a systematic, transparent modeling

effort, along the lines that the Clean Energy Group and other stakeholders have recommended.

Response:

EPA is finalizing a cap-and-trade approach under section 111. Analyses in support of

the process will be presented in the final CAMR Regulatory Impact Analysis document.

1. EPA received numerous comments on subcategorization by coal type and the

speciation profiles resulting from the combustion of various types of coal. EPA

sought additional specific data and information on the speciation profiles of various

types and blends of coal.

Comment:

One commenter (OAR-2002-0056-5484) provided detailed information and a technical

report with its comments (OAR-2002-0056-2948) of June 29,2004, on the speciation of Hg in

coal-fired power plant plumes. In the NODA, EPA has asked for more information on Hg

speciation and has also indicated that it is performing a benefits analysis that attempts to estimate

the reduction in adverse human health effects that will occur as a result of reducing Hg emissions

from coal-fired power plants. To this end, this commenter wishes to provide more information to

supplement the information provided in June and to re-state the implications of this information. 

OAR-2002-0056-5484 is the latest summary of the research which has shown that the fraction of

Hg emitted as oxidized Hg from coal-fired power plants is rapidly converted to elemental Hg. 

Current models do not account for this conversion. Research is underway by EPRI and others to

better understand the chemical mechanisms that explain this observation and to incorporate the

mechanisms into air quality models. The most important implication of this research finding is

that, because the observed transformations are not taken into account in current assessments,

current estimates of the benefits from reducing power plant Hg are overestimated. This

overstatement applies to the results of the most comprehensive assessment conducted to date –

that conducted by EPRI – which already shows that very small Hg deposition and exposure

reductions will result from either the cap-and-trade or MACT approaches. EPA should include

these transformations in whatever benefits estimation it conducts.

Comment:

One commenter (OAR-2002-0056-5556) referred to the speciation of Hg and noted that

new information challenged the estimated lifetime of elemental Hg before it is deposited. Also,

new data are demonstrating the oxidation of elemental Hg to reactive gaseous Hg during periods
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of enhanced photochemical activity with high ozone and warm temperatures (OAR-2002-0056-

5557).

Response:

EPA has addressed the commenter's issue through the application of the Community

Multiscale Air Quality (CMAQ) modeling system in estimating current and future levels of total

mercury deposition for the purposes of this rule. This sophisticated photochemical air quality

model is able to differentiate across Hg emissions species and account for the complex

atmospheric reactions as referenced by this commenter. The model and these specific reactions

are detailed in the Air Quality Modeling TSD (docket #OAR-2002-0056-6130).

Comment:

One commenter (OAR-2002-0056-5564) noted that the principal business of San Miguel

Electric Cooperative, Inc., is the production of electric energy in South Central Texas. 

Production includes one coal-fired power plant and one lignite mine. The lignite mine supplies

fuel only for the San Miguel Generating Station and produces, on average, 3.3 million tons of

lignite/year. The one generating unit fires only lignite provided by this mine and comprises

100 percent of San Miguel’s generating capacity; average yearly output is 3.2 million MWh.

The commenter provided comments on the issues of Hg speciation. The commenter’s unit

has an ESP and a wet FGD system for controlling PM and SO2 and has performed two stack tests

for Hg. These tests were conducted in 2002 and 2004 using appropriate methods and the test

results were provided in the comments.

Response:

EPA appreciates the submission of the data.

Comment:

The commenter (OAR-2002-0056-5490) stated that their comments are all related to the

second section, “Electric Utility Sector Modeling and Hg Speciation,” especially as it relates to

Gulf Coast lignite. The commenter continued its research into the Hg content of the coals it

combusts, the speciation of the Hg in the flue gases prior to existing control devices, the removal

efficiencies of the existing control devices and the Hg emissions (and speciation) from its stacks.

Unfortunately, the reports for the testing had not been finalized at this time. The commenter also

participated in four DOE Hg control technology projects. The results of Hg analysis on samples

of coal taken through October 31, 2004, from pulverizer feeders at the commenter’s nine coalfired units were provided in the comments. All of these units, except Sandow Unit 4, burned

blends of Gulf Coast lignite and western subbituminous coal. The minimum Hg-in-coal values are

from high percentage subbituminous samples and the maximum values are from high percentage

lignite samples. Sandow Unit 4 burned Gulf Coast lignite only.
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The Cl in the Gulf Coast lignite ranged from less than 1 part per million (ppm) to 170

ppm, which is less than the 1999 ICR Part II analysis indicated. Chlorine content affected the

speciation of Hg generated from firing coal.

Response:

EPA appreciates the submission of the data.

Comment:

Two commenters (OAR-2002-0056-5456, -5505) mentioned that EPA is seeking input on

issues of Hg speciation. The NODA states, “During this data collection effort, incoming coal

shipments for all coal-fired power plants in the U.S. were tested for Hg content (for calendar year

1999).” Perhaps the more fundamental issue than the speciation of the Hg is one of if the Hg

content of the coal is accurate in the EPA ICR database. There has been much controversy

expressed that the proposed MACT Hg emission standards for subbituminous coal are too high

creating a “compliance coal” for Hg, particularly for PRB coal. This conclusion was based upon

an analysis of the EPA coal Hg content database.

Since that time, there has been some testing of advanced Hg control technologies with

various types of coals and control configurations. Also included in these analyses were a

quantification of the coal Hg content, and inlet total vapor (Hg).

The commenter was a participant in the testing done at Sunflower Electric’s Holcomb

Station, located near Garden City, Kansas. The plant burns Wyoming PRB coal, and has a

SDA/FF control configuration, which is widely considered to be a “typical” configuration for

future coal-fired plants; particularly those that consume PRB coal. Mercury reduction testing

took place at this plant, funded by the DOE and others. The results of the test are presented

figures 1 and 2 of OAR-2002-0056-5456 , and show that in this test PRB coal significantly

exceeds EPA’s proposed MACT Hg emission limit of 5.8 lb Hg/TBtu for subbituminous coal.

Comment:

Commenter OAR-2002-0056-5505 provided information from Arapahoe Unit 3, a 44

MWe PRB coal-fired unit in the Denver metro area. The unit is equipped with a reverse air fabric

filter and a dry sodium injection system for SO2 removal. Testing at this plant occurred over a

two-week period in May 2004 to evaluate the use of Amended Silicates for Hg removal. The

interesting part of the work from the perspective of the commenter is that it included two separate

PRB coals. These coals were burned separately, and were not mixed during the test. One of the

coals had significantly higher Hg content that the other coal.

The commenter provided results for the higher Hg-content coal tests. In both tests, PRB

Coal A yielded significantly higher results than EPA’s proposed MACT emission limit of 5.8 lb

Hg/TBtu. From the final report, PRB Coal A “had nearly twice the Hg of [PRB Coal B] with a

Hg content of 0.071 ppm (as-received basis). [PRB Coal A] yielded flue gas vapor-phase Hg
9-cxlix

concentrations in the range of 12 to 16 g/Nm3

. For Xcel’s samples from [PRB Coal A]

shipments to Arapahoe, their average Hg content has been measured as 0.06 ppm, somewhat

lower than the value for the [PRB Coal A] sample obtained during the May trial.”

Response:

EPA appreciates the commenter's input to the record on the status of control

technologies. The Agency's position on the state of Hg technology is contained in the EPA 's

Office of Research and Development white paper (see Control of Emissions from Coal-Fired

Electric Utility Boilers: An Update, EPA/Office of Research and Development, March 2005). 

Comment:

One commenter (OAR-2002-0056-5502) referenced Hg speciation. Test results obtained

by the commenter in the last year have not markedly changed the speciation correlations

developed from the ICR. While coal Cl content appears to drive the degree of flue gas Hg

oxidation, other factors may also have a noticeable effect on this process; tests and chemical

modeling studies are seeking to quantify the role and significance of these other factors.

Speciation continues to be viewed as important for determining the most applicable and

cost-effective controls, the achievable emission levels, and, to a certain extent, the potential

impact of emissions from a given plant on Hg deposition onto downwind water bodies.

Response:

EPA appreciates the commenter's input to the record on the status of control

technologies. The Agency's position on the state of Hg technology is contained in the EPA 's

Office of Research and Development white paper (see Control of Emissions from Coal-Fired

Electric Utility Boilers: An Update, EPA/Office of Research and Development, March 2005). 

Comment:

One commenter (OAR-2002-0056-5497) stated that subsequent to the ICR stack

sampling in 1999, Hg speciation measurements have been taken as part of research studies

sponsored by DOE, EPRI and others. These studies have explored, among other things, the

effect of SCR on Hg oxidation and Hg removal using ACI. In addition, a number of coal-fired

power plants have conducted their own sampling of Hg emissions to determine the levels and

species of Hg that are emitted.

In general, this additional testing has produced results that continue to show Hg emission

variability like that seen during the ICR stack testing. As EPRI’s NODA comments indicate (see

OAR-2002-0056-5469), these recent Hg results do not substantially change the Hg speciation

correlations that EPRI produced using the ICR data.

Response:

EPA appreciates the commenter's input to the record on the status of control

technologies. The Agency's position on the state of Hg technology is contained in the EPA 's

Office of Research and Development white paper (see Control of Emissions from Coal-Fired
9-cl

Electric Utility Boilers: An Update, EPA/Office of Research and Development, March 2005). 

Comment:

One commenter (OAR-2002-0056-5494) noted that the NODA solicits input on, among

other matters, issues related to “Hg speciation” and the results of four approaches of modeling Hg

emissions under various emission control equipment deployment scenarios. All those model

calculations start with certain assumptions about the relative proportions of the chemical

composition of Hg emissions exiting the stacks (three species – elemental, ionized, and

particle-bound) from coals classified as bituminous, subbituminous, and lignite.

This commenter addresses two issues relating to coal ranks/Hg speciation: (1) uncertainty

associated with compliance with the proposed regulations for coal used at several Southwestern

power plants, and (2) questions associated with the appropriateness of developing the proposed

Hg rule utilizing the ICR III database’s Hg emissions data segregated under the three coal rank

classifications. Specifically, these comments address unique problems in applying the ASTM

methodology referenced in the proposed rule to determine coal ranks and compliance obligations.

EPA’s proposed rule refers to the ASTM coal ranking methodology and sets different Hg

emission limitations for different coal ranks. However, the ASTM coal ranking methodology 

may not be appropriate for regulating Hg emissions from certain coal-fired power plants. The

ASTM methodology is based on analyses on a “moist” basis, or the moisture content of the coal

in the mine. ASTM D388-99 clearly requires that coal rank should be determined while the coal

is in the mine. Coal ranking classification made any other way, such as under “as received” is

designated by ASTM D388-99 as “apparent rank.”

The EPA’s ICR data collection efforts discuss reporting coal properties on an “as

received” basis at each respective coal fired power plant. In some cases, as discussed below, coal

determined to be subbituminous in the mine according to the ASTM methodology could very well

transform to bituminous when it is “received” at the plants, stored on site, or while combusted in

a boiler, because its “inherent moisture” value could change.

Moreover, in the case of coals whose heating value falls in the overlapping region between

10,500 to 11,500 Btu/lb, only an agglomeration test can definitively determine its actual coal rank

(D388-99). The proposed rule does not contemplate situations like those identified here and

raises considerable ambiguity as to the applicable regulatory requirements. This situation is very

different from the “coal blending” scenario addressed in the proposed rule to establish the

appropriate emission limit. This commenter believes that the rule should be made very clear as to

what the operator’s regulatory obligations are. Specifically, the commenter requests that EPA

expressly state in the rule where the coal rank should be determined: at the mine, “as received” at

the plant, or when the coal is combusted in the boiler.

EPA developed the rule, as noted above, by segregating Hg emissions test data (ICR III)

from 81 units by the rank of the coal used during the emission tests. In this process, coal data

were taken from the ICR III test reports, and constituted coal characteristics on an “as received”
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basis. Data for one of the four units used in calculating the MACT level for subbituminous coal

came from the commenter’s Cholla Power Plant (Cholla Unit 3), and in 1999 Cholla reported the

coal used during the ICR III tests to be “Bituminous/Subbituminous.” Recently, Cholla has

reviewed coal data submitted to the EPA under ICR III and ICR II throughout 1999, and

concluded that Cholla burned bituminous coal most of the time. In fact, that review has also

concluded that Cholla Unit 3 burned bibuminous coal during the ICR III testing. Based on these

conclusions, the commenter believes that EPA segregated ICR III data from Cholla Unit 3 in the

incorrect subbituminous category.

The commenter’s review of the ICR III data for the other three top performing units (used

to calculate the subbituminous MACT level) suggests that at least two of those units’ coal ranks

may have been incorrectly classified . Thus, if the coal ranks have indeed been misclassified

before calculating the MACT levels for the subbituminous coal category, the coal rank-based

determination of Hg emission limitations may be in error.

The commenter understands that similar concerns were included in the comments

submitted to the EPA in the proposed rulemaking by the Subbituminous Energy Coalition (SEC). 

Therefore, the commenter respectfully requests that EPA reassess the classification of ICR III Hg

emissions test data by coal rank and the subsequent statistical analyses done in developing the

proposed MACT levels/national Hg emissions cap and trade program (and its allowance

allocations).

Commenter OAR-2002-0056-5494 agreed that EPA has found that the Cl content of coal

determines the relative proportions of various chemical species of Hg emitted. For example,

combusting Eastern bituminous coal (with its high Cl content) creates higher proportions of

ionized and particle-bound Hg, while Western subbituminous, Western bituminous, and lignite

coals (all with much lower Cl content) create a higher proportion of elemental Hg. EPA has also

found that ionized and particle-bound Hg emissions are more efficiently controlled in existing

pollution control devices (such as SO2 scrubbers and PM control devices). Therefore, modeling

results of Hg emissions from stacks depend on the assumed relative proportions of the three Hg

species.

The commenter believed that regulating Hg emissions on the ASTM methodology of coal

ranking (based primarily on heating value) may not be appropriate, at least where the Btu value

for bituminous and subbituminous coal overlaps (as noted by ASTM D388-99). EPA’s proposed

rule sets MACT levels based on coal ranks: for example, the proposed emissions limits are

2.0 lb/TBtu for bituminous and 5.81 lb/Btu for subbituminous coals. There are several plants in

the Western and Southwestern U.S. that utilize coal whose rank can vary between bituminous and

subbituminous from time to time, even for coal coming from the same seam. Given below are

two different types of examples where the commenter believes such changes can occur.

First, the commenter considered the case of coal whose heating value falls in the

“overlapping region” between bituminous and subbituminous coals. Several Western power

plants are “mine-mouth” plants, and hence, restricted to utilize coal burned in the adjacent mine. 

One such plant, the commenter’s Four Corners Power Plant, uses coal from the Navajo Mine on
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the Navajo Reservation in Northwestern New Mexico. Navajo Mine’s coal has fairly low heating

value (typically under 9,000 Btu, on an “as received basis”) and very high ash content (typically

20-25 percent). Over the past decades, the mine operator assured the commenter that its coal

was subbituminous coal.

If the ASTM methodology is utilized, the Navajo Mine’s coal’s “mineral-free” heating

value often falls in the 10,500 to 11,500 Btu range, the overlap region between bituminous and

subbituminous coal classification. Under such conditions, ASTM methodology requires an

“agglomeration test” to determine the coal rank. Very limited agglomeration tests conducted by

the commenter indicate that the Navajo Mine’s coal could be bituminous, contrary to long-held

belief and assurances from the coal supplier. EPA’s proposed rule (69 FR 4665) emphasizes the

significance of coal rank in the engineering design of power plants and their operation. Therefore,

Four Corners, and several other plants in the Southwest designed to burn subbituminous coal,

may be forced to comply with the Hg emission limitation applicable to bituminous coal.

The commenter reported that its experience with coal from the McKinley Mine in New

Mexico used at the Cholla Plant provides a situation completely different from the above example. 

There, the “apparent rank” on occasion falls in the range of 11,300 to 11,800 Btu/lb range. If the

“Free Swelling Index” is applied to that coal, that coal is non-agglomerating, and thus, will be

classified as subbituminous. Under those circumstances, coal from the McKinley Mine could vary

from bituminous to subbituminous on a daily basis.

The commenter reported that EPA staff said that they never envisioned that plants would

undertake “agglomeration tests” on a routine basis, as it is time-consuming and expensive. This

situation leads to two potential problems. First, the commenter notes that there is considerable

uncertainty concerning the plant’s compliance obligations under both MACT and cap-and-trade

regulatory approaches (i.e., via calculation of the national cap as well as the Hg allowance

allocations). Second, the commenter notes that in situations like the one described above, it may

be possible to “blend coals” in such way to bring its heating value to just below the threshold level

to classify it as subbituminous. Such a situation can create opportunities for “gaming” the

regulatory system. These potential scenarios are untenable and should be clearly addressed in the

final rule.

The commenter related the second issue to variability in moisture content, which can

change during the mining process, transportation to the power plant, and combustion in a boiler. 

For example, the Cholla Power Plant (as well as certain other power plants in the Southwest)

utilizes coal from several mines, including the McKinley Mine in New Mexico. Typically,

McKinley Mine adds about 3 to 4 percent moisture in dust suppression activities. Adding

moisture reduces its heating value, and according to the ASTM methodology coal rank is

determined on a moist, mineral free basis for subbituminous coals. At the plant, storage of coal in

the open (prior to combustion) and pulverization can result in loss of some moisture.

The commenter reported that when EPA assembled the ICR II and III database, no

guidance was given to plant operators about any adherence to ASTM methodology in developing

the data and reporting it to EPA. Accordingly, plant operators relied on the information on coal
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ranks provided by the coal suppliers, and reported the same data to the ICR database. It appears

that EPA developed the coal rank-based Hg rule, and the ASTM methodology was brought in

later as an afterthought. Upon careful review of the ASTM methodology, the commenter believes

that potential problems like the ones discussed above exist. If EPA retains the coal rank-based

Hg regulatory scheme, then the commenter recommends that the rule should clarify that the coal

rank reported by the coal supplier (mine) will be the basis of determining the appropriate Hg

emission limitation. This commenter believes that forcing the plants to conduct agglomeration

tests on a routine basis is unreasonable and will create uncertainty in plants’ compliance

obligations.

Because Cholla Unit 3 was one the four “top performing” units used to calculate the

MACT level for the subbituminous coal category, the commenter recently reviewed the coal data

reported in 1999. The commenter found that the coal rank data was reported as

“Bituminous/Subbituminous” during the ICR III tests. After the proposed rule was published

with its reference to ASTM methodology, the commenter recently calculated the Btu value of the

coal on a moist, mineral-free basis, utilizing the coal analysis data reported in Cholla’s ICR III test

report. These calculations, as per ASTM methodology, lead us to conclude that Cholla Unit 3

indeed burned bituminous coal during the ICR III testing. Accordingly, the commenter believed

that ICR III test data from Cholla Unit 3 were inappropriately classified under the subbituminous

coal category, and consequently, use of data from that unit to calculate the subbituminous MACT

level may be in error.

The commenter had also evaluated the coal ranks reported for some of the units that were

tested under ICR III, and the commenter believed that EPA’s grouping of units under

bituminous/subbituminous categories may be erroneous in certain cases. The commenter

provided a table of the coal Btu values from the ICR III test reports for the four units used in

setting the MACT level for subbituminous coal. If the ASTM guidelines on Btu content were to

be used, three of those four (i.e., AES Hawaii, Clay Boswell Unit 2, Cholla Unit 3) units clearly

fall under the bituminous category, rather than subbituminous category. This raises questions

about the validity of the proposed MACT levels for subbituminous coal, and raises a similar

problem for the cap-and-trade proposal.

The commenter is aware of the uncertainty with the type of coal used (and associated

potential misclassification) during the ICR III tests at the Valmont Plant in Colorado reported by

Xcel Energy. Data from that plant was used to calculate the MACT level for the bituminous coal

category. However, had the coal indeed been subbituminous (rather than the assumed

bituminous), the proposed MACT levels for both bituminous and subbituminous would be

significantly different.

The commenter stated that, based on the new information on the possible misclassification

of coal ranks in the ICR III Database presented here, they believed that EPA should reassess the

MACT levels and cap-and-trade allowance allocations included in the proposed Hg rulemaking. 

This commenter believed that EPA should address the unique compliance uncertainty created for

several Western/Southwestern plants using certain coals whose heating value (Btu) falls in the

overlap area for bituminous and subbituminous coal ranks. Therefore, should EPA retain the coal
9-cliv

rank-based approach to regulate Hg emissions, the commenter recommends that EPA use the

same Hg emissions limitation for low Cl content Western bituminous coal and subbituminous

coal.

The commenter also believed that the Cl content of the coal is a better basis for regulating

Hg emissions than the proposed coal rank-based approach, which relies on the ASTM

methodology that was never intended and is not appropriate for characterizing Hg emissions. 

Finally, in the event that EPA retains the coal rank-based approach of regulating Hg emissions,

this commenter recommends that plants using Western bituminous coal be subjected to MACT

levels and allowance allocations identical to those plants using subbituminous coals.

Response:

EPA appreciates the commenter's input to the record on the status of control

technologies. The Agency's position on the state of Hg technology is contained in the EPA 's

Office of Research and Development white paper (see Control of Emissions from Coal-Fired

Electric Utility Boilers: An Update, EPA/Office of Research and Development, March 2005). 

Comment:

Commenter OAR-2002-0056-5548 noted that commenter OAR-2002-0056-2535/5505

had urged EPA to reevaluate the MACT determination for Wyoming subbituminous coals to

account for large differences in Wyoming PRB and other western subbituminous coals. 

Commenter OAR-2002-0056-2535/5505 is, in effect, asking EPA to further subcategorize

subbituminous coals based on differences, such as a distinction between ASTM sub-classifications

within the subbituminous rank, as they discuss in their comments. Commenter OAR-2002-0056-

5548 believed that the commenter OAR-2002-0056-2535/5505’s argument points out one of the

fundamental flaws with the attempt to subcategorize by coal rank, because rank is not predicative

of coal properties of relevance to Hg emissions and control. Furthermore, if EPA were to do so

for subbituminous coal, it also must further subcategorize bituminous coals based on the even

greater differences in bituminous coals from different regions of the country. Commenter OAR2002-0056-5548 believes that, at a minimum, EPA should subcategorize bituminous coals by rank

(High volatile A, B, and C, medium volatile, and low volatile), and further by geographic region

(western, mid-continent, northern, central, and southern Appalachia). Within these regions,

bituminous coals are produced from individual seams which themselves exhibit large differences in

coal properties. A decision by EPA to further subcategorize one rank coal without doing so for

all ranks of coal would clearly be arbitrary and would fail to ensure an equitable treatment for

coals of all ranks, which EPA states as one of its objectives.

In its original comments on the rule and in these NODA comments, commenter OAR2002-0056-5548 demonstrated, using the IRC Part II coal analysis data, that 62 percent of all

subbituminous coals sampled would meet the proposed 5.8 lb/TBtu MACT limit with no Hg

reduction, largely eliminating the speciation or any other control issue. The average

subbituminous coal has a Hg content of 5.7 lb/TBtu, thus making subbituminous coal, in

aggregate, a compliance coal, given the proposed 12-month averaging period of the rule.
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In its comments, commenter OAR-2002-0056-2535/5505 attempts to refute this

compliance coal demonstration by presenting ICR Part III emissions data from 10 plants burning

Wyoming PRB coal, purporting to show that Hg emissions from the majority of these plants are

in excess of the 5.8 lb/TBtu limit. EPA should discount this for two reasons. First, commenter

OAR-2002-0056-2535/5505 acknowledges in its comments that the ICR Part III data, which

consists of only short-term sampling at 80 power plants, is highly suspect. Commenter OAR2002-0056-5548 strongly concurred with that observation and point out that none of the units

that meet the data quality criteria burns a Wyoming PRB coal. Therefore, the attempts of

commenter OAR-2002-0056-2535/5505 to use the ICR Part III data to support a conclusion

concerning plant emissions contradicts their clear understanding of the limitations of the ICR Part

III data.

Second, the IRC Part II data set, on which commenter OAR-2002-0056-2535/5505 relied,

is much more substantial and robust, because it contains the Hg contents of thousands of coal

samples from most mines, sampled as delivered to most power plants in the country for a full

year. Commenter OAR-2002-0056-5548 provided a table reporting the mean and median Hg

contents from the ICR Part II data base for the 509 coal shipments sampled as delivered to the

nine plants for which commenter OAR-2002-0056-2535/5505 presented emissions data. 

Contrary to the SEC’s assertion, six of the nine plants (67 percent) received coals in compliance

with the proposed 5.8 lb/TBtu limit in 1999, and the three that did not would require an average

reduction of only 10 percent to come into compliance. That reduction is well within the range of

EEI/CRA’s subbituminous EMF for a CS-ESP. Thus, assuming only a modest reduction across

existing emission control equipment, these plants would require no further reduction to come into

compliance. The average Hg content of coals delivered to the same nine plants in commenter

OAR-2002-0056-2535/5505’s comments was 5.2 lb/TBtu, further supporting the commenter

OAR-2002-0056-5548’s conclusion that the 5.8 lb/TBtu MACT limit effectively would

denominate subbituminous coals as compliance coals.

Commenter OAR-2002-0056-2535/5505 stated that “elemental mercury comprises 70-80

percent for the total mercury emitted from the furnace” for subbituminous coal-fire units. They

do not provide a source for this statement, but it appears to overstate the percentage of elemental

Hg in the flue gas of such units. An analysis of the ICR Part III data for Hg speciation at the inlet

to the last control device at each subbituminous-coal-fired station reveals an average elemental Hg

concentration of 59 ± 23 percent. Some particulate or oxidized Hg may have been removed

ahead of the flue gas measurement point, so this should be considered an upper bound on the

average percentage of elemental Hg in the flue gas for subbituminous coal-fired units. Note that

this average excludes those plants identified by commenter OAR-2002-0056-2535/5505 as

misidentified by the EPA as burning only subbituminous coal.

Commenter OAR-2002-0056-2535/5505 contended that the imputed emission factors

calculated from EPA’s proposed allowance adjustment factors under section 111 results in

“relatively little” subcategorization. Commenter OAR-2002-0056-5548 opposes the imposition

of any allowance adjustment factors. The commenter believed that too little is known at present

about Hg emissions and control technology to ensure that they are equitable and result in

achievable emission limits (a position with which commenter OAR-2002-0056-2535/5505
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concurs). The commenter also contended the development of Hg-specific control technology will

obviate the rationale for allowance adjustments in the future. Nevertheless, commenter OAR2002-0056-2535/5505 would support the use of EPA’s section 112 MACT limits as the basis for

allowance adjustment factors. This would simply create under the guise of a cap-and-trade

program the same inequity as in the MACT proposal, under which subbituminous coal fired units

would receive sufficient allowances as to require no Hg reductions, and most likely receive excess

allowances from which they would profit by selling them to bituminous coal-fired units which face

a stringent, and in some cases unachievable, compliance burden.

Response:

EPA believes that the comments provided by commenters OAR-2002-0056-5494 and -

5548 relate, variously, to the issues of subcategorization (either more or fewer subcategories)

and the use of the ASTM ranking scheme to delineate the subcategories, rather to the issue of Hg

speciation. EPA has addressed, earlier in this document, other comments related to the issue of

subcategorization and has presented its rationale for the use of subcategories.

We are, however, somewhat perplexed regarding the comments related to a utility “not

knowing” the rank of coal being fired and on the use of the ASTM classification methodology as

the basis for determining the rank of coal burned, and, thus, “membership” in the appropriate

subcategory. EPA based its subcategorization on the coal rank information provided by the

utility, not on the coal analysis data provided by the utility. That is, if a utility reported that

their coal was (e.g.) “subbituminous,” EPA did not question the statement. During the period of

the ICR, EPA requested that the responding utilities provide to EPA only the Hg- and Clcontents of their coals as new information. The remaining coal information requested (e.g., coal

rank; heating value; moisture, ash, and sulfur content) was that information already being

provided to the DOE. Each U.S. utility company (including combined heat and power

companies) is required by law to submit to the DOE/EIA for each Utility Unit the rank of coal

burned, on a monthly or annual basis, on at least one of the following forms:

EIA Form-423: Monthly Cost and Quality of Fuels for Electric Plants Report

(“Column ‘c’Fuel)

EIA Form-767: Steam-Electric Plant Operation and Design Report (“Fuel

Code”)

EIA Form-860: Annual Electric Generator Report (“Energy Source Code”)

EIA Form-860m: Monthly Update to the Annual Electric Generator Report

(“Energy Source Code”)

EIA Form-906: Power Plant Report (“Energy Source”)

EIA Form-920: Combined Heat and Power Plant Report (“Energy Source”)

Thus, utility companies are currently obtaining the coal rank information being reported to DOE

from someone, somehow to comply with this legal requirement. EPA is not asking for any

additional information or analyses upon which to establish a given Utility Unit in a subcategory

for purposes of either the final NSPS or cap-and-trade provisions. Rather than being able to

“game” the system, units that blend two or more ranks of coal are required to use specified
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procedures for determining their applicable NSPS emission limit.

EPA continues to believe that the ASTM ranking methodology is the one most widely

recognized within the industry and, therefore, is appropriate for this rulemaking. Given the

existing legal requirement to provide DOE with the coal rank being utilized, EPA believes that

the industry knows what coal rank it is consuming in its units.

2. EPA sought comment on if/when a standard (or average) speciation profile should

be used for either the CAA section 111 or CAA section 112 regulatory approach.

Comment:

One commenter (OAR-2002-0056-5475) stated that under Part II, Sub-Part C of the

NODA, EPA indicates that it received comments related to the speciation of Hg. The commenter

stated that speciation is fundamentally important since the ability of control devices to remove Hg

is directly related to the form of Hg in the flue gas. The three species of Hg that exist in plant

emissions are elemental, ionic/oxidized, and particulate. Oxidized and particulate are known to be

the more easily captured forms of Hg. Average Hg speciation data from the 81 power plants that

were the basis of the MACT floor calculations, is set forth in the NODA (69 FR 69871). The

calculated averages of the speciated Hg forms across all coal types were: 54 percent elemental,

43 percent oxidized, and 3 percent particulate.

Response: 

EPA appreciates the commenter's input to the record on the status of control

technologies. The Agency's position on the state of Hg technology is contained in the EPA 's

Office of Research and Development white paper (see Control of Emissions from Coal-Fired

Electric Utility Boilers: An Update, EPA/Office of Research and Development, March 2005). 

Comment:

One commenter (OAR-2002-0056-5475) objected to the notion of using an average

speciation profile to predict the characteristics of Hg emissions from coal fired utilities. The

percentages of the three forms of Hg emissions can vary widely from facility to facility, even in

the same coal category. For example, it has been determined that within a given coal category the

proportion of oxidized Hg emitted is proportional to the Cl content of the coal. Commenter

OAR-2002-0056-2038 noted that average speciation for electric utilities range between

10 percent and 90 percent for the oxidized form. The Brookhaven National Laboratory’s May

2003 study utilized data from the Bruce Mansfield Plant in Shippingport, PA, and the Monticello

Power Plant in Monticello, TX. The fraction of the oxidized form of Hg between these two

plants varied between 19.7 percent and 60.4 percent, respectively. Given the disparate speciation

data that exists for Hg emissions, this commenter recommends that a sensitivity analysis be

performed to evaluate the effect that the range of values for the oxidized form of Hg has on the

proposed rule.
9-clviii

Response: 

EPA appreciates the commenters concerns. Please see EPA 's Office of Research and

Development white paper (see Control of Emissions from Coal-Fired Electric Utility Boilers: An

Update, EPA/Office of Research and Development, March 2005) for a discussion of the

importance of speciation for mercury capture. Also, please see Chapter 7 of the Regulatory

Impact Analysis for a discussion of how we took speciation into account in our power sector

modeling and see Chapter 8 for a discussion of how we took speciation into account in our air

quality and deposition modeling.

Comment:

Two commenters (OAR-2002-0056-5510, -5548) said that an average speciation profile

cannot capture the large degree of variability and uncertainty associated emissions from different

coal types, and should not be used for either section 111 or 112 regulation.

In the case of MACT regulation, if the standard is set based upon an average speciation

profile, coals with greater Hg concentrations will not be able to comply–even if the unit is meeting

a targeted percentage reduction. For example, the average Hg content of bituminous coal

reported in the ICR Part II data is 8.4 lb/TBtu. Assuming the availability of a Hg control

technology able to achieve 50 to 70 percent reduction (DOE’s goal for 2010), the “average”

bituminous coal could achieve an emission rate of 2.5 to 4.2 lb/TBtu. However, coals from the

State of Ohio, which have an average Hg concentration of 15.7 lb/TBtu, would need to achieve

75 to 85 percent removal to meet a standard in this range, beyond the range of the hypothetical

then-available technology. As a result, these coals could not be used in compliance with the

MACT.

Although this risk may be somewhat lessened under a cap-and-trade rule, because

operators have the potential ability to purchase allowances, there is no assurance that allowances

will be available in sufficient quantity to meet compliance needs. To the degree that allowances

are not available, the explicit compliance problem under the MACT described above becomes

effectively the same liability under the cap-and-trade program.

Response:

EPA is finalizing a cap and trade rule. Please see the CAMR preamble for a complete

discussion. EPA appreciates the commenters concerns. Please see EPA 's Office of Research and

Development white paper (see Control of Emissions from Coal-Fired Electric Utility Boilers: An

Update, EPA/Office of Research and Development, March 2005) for a discussion of the

importance of speciation for mercury capture. Also, please see Chapter 7 of the Regulatory

Impact Analysis for a discussion of how we took speciation into account in our power sector

modeling and see Chapter 8 for a discussion of how we took speciation into account in our air

quality and deposition modeling.

Comment:

One commenter (OAR-2002-0056-5502) referenced using average vs. individual power
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plant speciation in modeling and used individual speciation in the model runs conducted for it to

gain insights into the potential changes in deposition patterns as a result of different Hg emission

reduction scenarios. The commenter recommends that EPA do the same to develop similar

insights, as these are important to inform decisions on cap-and-trade vs. MACT.

Response:

EPA is finalizing a cap and trade rule. Please see the CAMR preamble for a complete

discussion. EPA appreciates the commenters concerns. Please see EPA 's Office of Research and

Development white paper (see Control of Emissions from Coal-Fired Electric Utility Boilers: An

Update, EPA/Office of Research and Development, March 2005) for a discussion of the

importance of speciation for mercury capture. Also, please see Chapter 7 of the Regulatory

Impact Analysis for a discussion of how we took speciation into account in our power sector

modeling and see Chapter 8 for a discussion of how we took speciation into account in our air

quality and deposition modeling.

Comment:

One commenter (OAR-2002-0056-5497) stated that given the repeated concerns voiced

about Hg “hot spots,” it makes sense to use the best estimates of Hg speciation in any dispersion

modeling. EPA’s 1999 ICR request produced a year of detailed coal data for all coal-fired power

plants in the U.S. These coal data can be used along with Hg speciation correlations that EPRI

developed from the 1999 ICR Hg stack sampling to produce Hg speciation estimates for every

coal-fired unit in the country. This is exactly how EPRI modeled Hg deposition in the U.S. 

EPRI’s modeling results were provided in EPRI CAMR comments dated June 16, 2004 and in the

comments EPRI is submitting in response to this NODA. The commenter believes that EPA

should follow a similar approach in any Hg deposition modeling it may perform. EPA should not

use an average speciation value for each coal rank.

Response:

EPA appreciates the commenters concerns. Please see EPA 's Office of Research and

Development white paper (see Control of Emissions from Coal-Fired Electric Utility Boilers: An

Update, EPA/Office of Research and Development, March 2005) for a discussion of the

importance of speciation for mercury capture. Also, please see Chapter 7 of the Regulatory

Impact Analysis for a discussion of how we took speciation into account in our power sector

modeling and see Chapter 8 for a discussion of how we took speciation into account in our air

quality and deposition modeling. EPA has addressed the hot spots issue in the revision Federal

Register notice and in the Technical Support Document: Methodology Used to Generate

Deposition, Fish Tissue Methylmercury Concentrations, and Exposure for Determining

Effectiveness of Utility Emission Controls in the docket.

3. Is it currently feasible, or will it be feasible within the compliance timeframes of the

proposed rule, to accurate monitor a source’s Hg emissions by species?

Comment:
9-clx

As part of the commenter’s (OAR-2002-0056-5490) Mercury Research Program, they

had purchased two Hg CEMS. The analyzers, manufactured by Nippon, are “dry” monitors and

appeared to be fairly reliable. Most of the problems that the commenter saw had been in the

sample conditioning system. A great deal of effort had gone into increasing the reliability of the

sample conditioning system. High temperatures had to be maintained throughout or fouling of the

glassware would occur. The commenter has installed a completely glass-lined probe to help

maintain closer tolerances with sampling temperatures. Even with all the effort put into making

the system run reliably, they are only getting about 5 days of continuous operation without

significant maintenance. Until these problems are resolved, it will not matter if the monitor can

measure speciated Hg. The commenter’s Hg CEMS are capable of measuring speciated

(elemental and oxidized) Hg.

Response:

EPA believes that field tests have demonstrated Hg CEMS to be accurate and reliable.

The Hg CEMS have performed adequately for several months and meet the Ontario-Hydro

Reference Method specifications. Furthermore, several dry chemistry Hg CEMS are currently

being tested at sites that represent the most challenging conditions and the Agency plans to

share with industry the results of such experiences to facilitate the selection of appropriate

monitoring methodology. EPA also agrees with the commenter that the sample conditioning

system provides one of the most challenging aspects of operating a successful Hg CEMS, but

feels confident that substantial advancement of the sample conditioning system will occur before

the implementation of the rule and as other monitoring techniques may become available, is

allowing the use of systems that can meet performance-based specifications.

The final rule requires the measurement of total vapor phase Hg, but does not require

separate monitoring of speciated Hg emissions (i.e., elemental and ionized Hg). Because of the

potential impact of Hg speciation on local versus broader geographical deposition, the Agency

considers separate monitoring of these emissions as a need to be addressed. However, at least

two current monitoring technologies can accurately monitor speciated Hg emissions. The Agency

will continue to test speciated Hg monitoring technologies. If these technologies are adequately

demonstrated, the Agency may consider a proposed rulemaking within four to five years after

program implementation, which should provide enough lead time for development and

installation of these monitoring systems.

Comment:

One commenter (OAR-2002-0056-5510) noted that speciated Hg emissions can currently

be measured via the Ontario Hydro Method. However, when the tests are being conducted

specific attention must be provided to the experimental method to ensure data reliability. As

pointed out in the commenter’s May 14, 2004, comments, EPA’s IGR Part III data contain many

instances of incomplete or invalid testing.

CEMS, or semi-continuous methods like proposed EPA Method 324, for the

measurement of total Hg emissions are projected to be available in the 2008 time frame and would

be sufficient to demonstrate compliance with the proposed standards. The commenter believed
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adequate information can be gathered using CEMS or semi-continuous methods for total Hg

emissions, combined with periodic Ontario Hydro sampling for speciated emissions profiles, if

adequate methods for monitoring speciated Hg are not developed by that time.

As noted in the commenter’s May 14, 2004, comments, adequate technical data do not

exist at this time to provide a reasoned basis for the allocation of allowances among coal types for

purposes of an initial reduction in 2010. For this reason, the commenter recommended that Hg

monitoring begin on affected units in the 2008 time frame in order to determine prospective

emissions allocations by coal type for an interim 2015 emissions cap. The analysis required for

setting appropriate allocations will necessarily require speciated emissions information over the

full range of operational conditions including emissions during partial load, transient operations

and during maintenance events.

Response:

The final rule requires the measurement of total vapor phase Hg, but does not require

separate monitoring of speciated Hg emissions (i.e., elemental and ionized Hg). Because of the

potential impact of Hg speciation on local versus broader geographical deposition, the Agency

considers separate monitoring of these emissions as a need to be addressed. However, at least

two current monitoring technologies can accurately monitor speciated Hg emissions. The Agency

will continue to test speciated Hg monitoring technologies. If these technologies are adequately

demonstrated, the Agency may consider a proposed rulemaking within four to five years after

program implementation, which should provide enough lead time for development and

installation of these monitoring systems.

Comment:

One commenter (OAR-2002-0056-5502) referenced future availability of speciating

continuous Hg monitors. Assuming the developers (and future suppliers) of continuous Hg

monitors are successful in developing accurate, reliable and robust instruments for

near-continuous measurements of total Hg, they should be able to enhance these to also provide

near-continuous speciated measurements with 1 to 2 years after commercialization of the total Hg

monitors.

Response:

At least two current monitoring technologies can accurately monitor speciated Hg

emissions. EPA agrees with the commenter and the Agency will continue to test speciated Hg

monitoring technologies. If these technologies are adequately demonstrated, the Agency may

consider a proposed rulemaking within four to five years after program implementation, which

should provide enough lead time for development and installation of these monitoring systems.

Comment:

One commenter (OAR-2002-0056-5535) stated that EPA’s specific question about

whether it is currently feasible, or will be feasible within the compliance time frames of the
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proposed rule, to accurately monitor a source’s Hg emissions by species is irrelevant. EPA has

already stated that continuous Hg monitors that measure total Hg have been validated and will be

required for compliance with the final rule. Total Hg emissions must be reduced from these

sources.

Response:

The final rule requires the measurement of total vapor phase Hg, but does not require

separate monitoring of speciated Hg emissions (i.e., elemental and ionized Hg). Because of the

potential impact of Hg speciation on local versus broader geographical deposition, the Agency

considers separate monitoring of these emissions as a need to be addressed. However, at least

two current monitoring technologies can accurately monitor speciated Hg emissions. The Agency

will continue to test speciated Hg monitoring technologies. If these technologies are adequately

demonstrated, the Agency may consider a proposed rulemaking within four to five years after

program implementation, which should provide enough lead time for development and

installation of these monitoring systems.

Comment:

One commenter (OAR-2002-0056-5497) stated that although the Ontario-Hydro Method

(ASTM Method D6784-02) provides only short-term emissions data, it is currently capable of

providing accurate and repeatable data on Hg emissions at the stack by species. The commenter

believed that speciated data collected by EPA pursuant to its Hg ICR using the Ontario-Hydro

Method clearly documents the need for subcategorization of the utility industry based on coal type

in any final MACT rule.

As for continuous monitoring of Hg emissions by species, there is no commercially

available monitor capable of providing Hg emissions data by species, and there is almost no

possibility that a such a monitor will become available within the compliance timeframe of the

proposed rules. A number of tasks remain to be completed before the existing Hg CEMS (all of

which measure total Hg) can be deemed sufficiently accurate and reliable for use in the proposed

regulatory programs.

Response:

At least two current monitoring technologies can accurately monitor speciated Hg

emissions. The Agency will continue to test speciated Hg monitoring technologies. If these

technologies are adequately demonstrated, the Agency may consider a proposed rulemaking

within four to five years after program implementation, which should provide enough lead time

for development and installation of these monitoring systems. The final rule requires the

measurement of total vapor phase Hg, but does not require separate monitoring of speciated Hg

emissions (i.e., elemental and ionized Hg). Because of the potential impact of Hg speciation on

local versus broader geographical deposition, the Agency considers separate monitoring of these

emissions as a need to be addressed.
9-clxiii

C. EPA’s Proposed Revised Benefits Assessment

General Comments concerning EPA’s Proposed Revised Benefits Assessment

Comment:

The commenter (OAR-2002-0056-5460) agreed that EPA should improve its estimate of

human exposure to Hg that arises from power plant emissions. The commenter stated that two

notes of caution must be sounded, however.

The commenter stated that first, the proposed revised benefits assessments methodology

described in the NODA will not cure the fundamental defects in the proposed CAMR. The

commenter pointed out that, for example, the revised methodology does not address, let alone

remedy, EPA’s failure to calculate a proper Section 112 MACT floor. And, the commenter

added, as long as EPA continues to underestimate the benefits associated with a proper Section

112 approach, it will continue to overestimate the comparative benefits of its proposed Section

111 approach. The commenter, therefore, reiterated that EPA should focus its energies on

remedying the problems with its Section 112 proposal.

The commenter further stated that second, EPA cannot and should not delay regulation

until all alleged scientific uncertainties concerning power plant Hg emissions have been resolved. 

The commenter stated that, to the contrary, to the extent uncertainties exist concerning Hg

speciation, deposition, transport and exposure, EPA should err on the side of caution so as to

fulfill the preventive and precautionary purposes of the Clean Air Act. See American Lung Ass’n,

134 F.3d at 389; Lead Industries Ass’n, 647 F.2d at 1155; see also 42 U.S.C. § 7412(d)(2)

(requiring EPA to impose emissions standards that “require the maximum degree of reduction in

emissions. . .”). The commenter added that, furthermore, as previously noted, EPA is required to

regulate power plant emissions promptly.

Response:

EPA appreciates the commenters concerns. EPA is finalizing a cap-and-trade approach

under section 111. Please see the Revision of December 2000 Regulatory Finding on the

Emissions of Hazardous Air Pollutants from Electric Utility Steam Generating Units and the

Removal of Coal- and Oil-fired Electric Utility Steam Generating Units from the Section 112(c)

List for a discussion of the Agency’s rationale for not proceeding under Section 112. For a

discussion of our exposure modeling, please see the Technical Support Document: Methodology

Used to Generate Deposition, Fish Tissue Methylmercury Concentrations, and Exposure for

Determining Effectiveness of Utility Emission Controls and the Regulatory Impact Analysis in

the docket.

Comment:

With regard to the first three steps of the proposed revised benefits assessment

methodology, the commenter (OAR-2002-0056-5460) reiterated that EPA should not allow any

alleged uncertainties in the scientific evidence to prevent it from regulating power plant Hg

emissions in a manner adequate to protect human health and the environment. The commenter
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stated that existing science confirms the need to regulate power plant emissions and any scientific

uncertainties should be resolved in favor of more protective requirements.

Response:

EPA is finalizing a cap-and-trade approach under section 111. Please see Chapters 10

and 11 of the CAMR Regulatory Impact Analysis for a discussion of the exposure modeling and

benefit methodologies used to analyze the benefits associated with this rulemaking.

Comment:

Two commenters (OAR-2002-0056-5365, -5404) supported EPA’s proposed general

methodology for revising its assessment of the benefits associated with Hg emissions reductions

from power plants. The commenters believed that the revised benefits assessment methodology

generally is an appropriate, reasonably accurate quantification of benefits associated with the

implementation of EPA’s proposed regulation of Hg emissions (See 69 Fed. Reg. 69864, 69872.). 

In particular, the commenters supported EPA’s revised methodology insofar as it focuses on

quantification of benefits from Hg reductions (See 69 Fed. Reg. at 69873.). According to the

commenters, that is, the Agency’s requests for further comment in the NODA indicate that EPA’s

benefits analysis appropriately has shifted toward issues that are central to the purpose of the Hg

regulation, in particular, changes in human exposure to Hg as a result of the emissions reductions

that will be required by the rule, and potential consequent changes in public health (See 69 Fed.

Reg. at 69876.).

The commenters stated that by contrast, EPA’s benefits assessment in the NPR dated Jan.

30,2004, as well as EPA’s conclusion that the benefits of the proposed rule far outweigh the

costs, was essentially faulty and misleading in that the assessment and its consequent conclusions

were premised on tangential and/or irrelevant information. According to the commenters, for

example, in the NPR dated January 30,2004, EPA predicted that the implementation of Hg

MACT would result in benefits equal to $15 billion which would be offset by costs equal to less

than $2 billion—a net benefit valued at greater than $13 billion. The commenters stated that

EPA’s figures are misleading, however, because none of the quantified benefit is attributable to

EPA’s proposed Hg regulation. According to the commenters, rather, the benefit reflects

ancillary NOx and SO2 reductions expected to be achieved as co-benefits resulting from the

operation of MACT-imposed Hg controls. The commenters stated that in any event, according to

EPA, “most or all of the ancillary benefits of control would be achieved anyway, regardless of

whether a section 112 MACT is promulgated.” See 69 Fed. Reg. at 4711 (“[E]ven if no [

mercury] controls were imposed [pursuant to the rule-making], most major coal-fired units would

have to reduce their SO2 and NOx emissions as part of the effort to bring the nation into

attainment with new air quality standards.”). According to the commenters, considering the

foregoing, EPA’s benefits assessment in the NPR is of limited value, because it quantifies only

benefits that are ancillary to the core purpose of the proposed rule and are likely to be realized in

any case. The commenters believed that it is fundamentally inappropriate to justify a rule—as

EPA did in the NPR—based on emissions reductions that are not related to the central purpose of

the rule and that are likely to occur whether or not the rule is promulgated. Thus, in response to

EPA’s requests for comment regarding the revised benefits assessment, the commenters strongly
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believed that the Agency must focus on quantifying benefits that are central to the purpose of the

regulation.

As such, the commenters supported the overall methodology outlined in the NODA,

which will enable EPA to assess the potential public health benefits associated with reducing Hg

emissions from power plants, i.e., the benefits to public health that are related to the purpose of

this rule. According to the commenters, such quantification is admittedly difficult, as there is no

direct correlation between power plant Hg emissions and human MeHg exposure (which, as EPA

recognizes, is the public health outcome of concern). As such, the commenters concurred with

EPA that the Agency must undertake the following five-step assessment in order to translate

power plant Hg emissions reductions into public health outcomes: (I) quantify Hg emissions

projected from power plants under the Base Case as compared to after implementation of the Hg

rule, including quantifying Hg emissions that result from sources other than U.S. coal-fired plants;

(ii) model changes atmospheric dispersion, atmospheric speciation, and Hg deposition as a result

of Hg reductions from power plants; (iii) model the link between changes in Hg deposition and

changes in MeHg concentrations in fish; (iv) assess types and amounts offish consumed by U.S.

customers and extrapolate resulting changes in MeHg exposures resulting from reduced power

plant Hg emissions; and (v) assess how reductions in MeHg exposure affect human health.

Although the commenters supported the overall methodology EPA has articulated, and

concurred that the Agency has properly identified the five necessary steps to enable quantification

of the public health benefits associated with the proposed rule, the commenters also supported the

concerns articulated by the Electric Power Research Institute (“EPRI”) and others with respect to

specific aspects of how EPA proposes to conduct specific aspects of the benefits assessment. For

example, the commenters concurred with EPRI that there are some significant weaknesses in how

the MMAPs model quantifies the link between changes in Hg deposition and changes in MeHg

concentrations in fish. The commenters urged EPA to seriously consider these critiques of

specific aspects of the benefits assessment before it finalizes this analysis.

Response:

The benefits analysis completed for the RIA is not intended to model local-scale changes

in fish tissue concentrations and exposures in support of site-specific risk analysis. Instead,

modeling conducted for the RIA is intended to capture generalized regional changes in

methlmercury exposure resulting from reductions in power plant mercury emissions in order to

support a national-scale benefits assessment focusing on the 37 state eastern US study area. For

additional details on the benefits analysis modeling framework see Section 10 of the RIA.

EPA recognizes the complexities associated with methylation of mercury deposited in

waterbodies and watersheds and subsequent biomagnification within the aquatic foodweb. While

there are dynamic fate/transport models that can be used to conduct detailed site-specific

modeling of mercury in aquatic and terrestrial environments for purposes of predicting mercury

fish tissue concentrations (e.g., the dynamic mercury cycling model), it is not feasible to utilize

these resource-intensive models for a regional- or nationals-scale analysis. Therefore, EPA

selected the MMAPs models for application in the RIA. EPA fully recognizes the limitations and
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simplifying assumptions associated with this model, but believes that it has sufficient precision to

support a benefits analysis conducted at the regional- or national-scale (i.e., it can capture

general trends in mercury fish tissue response to changes in mercury deposition from power

plants). However, to provide additional perspective on the relationship between mercury

deposition and fish tissue concentration changes (especially in relation to MMAPS linearity

assumption and the lag time required for systems to reach steady state), EPA has conducted

several detailed local-scale sensitivity analyses. The results of these case studies are presented

and discussed in Appendix D.

The RIA includes an assessment, to the extent possible given our scientific understanding

of mercury and its behavior in the environment and impacts on human health, of the health

benefits associated with the proposed regulatory options. Due to limitations in our current

understanding of these technical areas related to mercury this benefit analysis is limited to the

self-caught freshwater fish consumption pathway and to IQ deficits in prenatally-exposed

infants. In keeping with precedent in evaluating benefits of air regulations (REFERENCE), cobenefits (in this case resulting from potential reductions in direct PM2.5) are also included in

the RIA.

Comment:

One commenter (OAR-2002-0056-5535) referenced EPA’s Revised Benefits

Methodology Must Account Fully for the Risks and Public-Health Costs of Hg Pollution

EPA’s NODA seeks public comment on a suite of technical issues, supposedly to assist

the agency in developing its final assessment of the benefits of Hg control pursuant to Executive

Order 12866. Specifically, EPA asks for public input on “the U.S. power plant contribution to

total Hg deposition within the U.S.,” the agency’s planned approach to “evaluate how Hg moves

through the atmosphere and how it ultimately will be deposited,” “the strengths and weaknesses

of different approaches for modeling the anticipated response offish tissue [MeHg] concentrations

to declines in deposition,” the “consumption data” to be used in EPA’s “analysis concerning the

relationship between reductions in MeHg concentrations in fish tissue and reductions of human

exposure to MeHg,” and “all aspects of the methodology for estimating the relationship between

reductions in MeHg exposure and improvements in health.”

These sweeping requests for information suggest that EPA is interested in more than

simply calculating the benefits of a Hg control regime. Instead, the agency appears to be giving

the utility industry another chance to advance claims that power plants are neither a significant

cause of U.S. Hg deposition nor a public health concern, and to argue that EPA should weaken its

proposed Hg rule before finalizing it. Indeed, EPA acknowledges that this information may be

used to influence the stringency of the final rules, saying:

“To the extent that we receive any comments or other information in the process of

completing the benefits assessment for purposes of EO12866 and to the extent that such

information bears on the statutory factors relevant to setting either a beyond-the-floor

standard for Hg under CAA Section 112(d) or a standard of performance for Hg under
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CAA Section 111, we intend to evaluate and consider that information as we make a final

decision as to which regulatory approach to pursue.”

This open-ended invitation for comment reveals how far EPA has veered from its

statutory responsibilities under § 112 of the Act. At this stage of the rulemaking process, the

agency should be refining its understanding of the issues central to the development of a proper

MACT standard by correcting the problems created by its proposal to subcategorize by coal rank,

by abandoning its inflation of the emission standards to account for “variability,” by making an

unbiased assessment of the state of Hg control technology in light of manufacturers’ comments,

and by conducting the modeling (and additional technical work) necessary to evaluate the cost,

energy impacts, and non-air quality impacts of numerous above-the-floor control options. 

Outrageously, EPA instead seeks to revisit issues considered four years ago when the agency

concluded that regulating power plants’ hazardous air emissions was “appropriate and necessary,”

and gives the public a mere month to make–again–the scientific case for stringent controls on

utility units.

Response:

EPA is finalizing a cap-and-trade approach under section 111. Please see Chapters 10

and 11 of the CAMR Regulatory Impact Analysis for a discussion of the exposure modeling and

benefit methodologies used to analyze the benefits associated with this rulemaking.

1. Step 1: Analyzing Hg Emissions from Other Sources. EPA plans to do fate and

transport modeling of emissions originating in other countries to allow an estimated

of U.S. power plant contribution to total Hg deposition in the U.S. EPP received

comments relevant to this issue from the Center for Energy and Economic

Development (OAR-2002-0056-2256), Electric Power Research Institute

(OAR-2002-0056-2578), Hubbard Brook Research Foundation

(OAR-2002-0056-2038), National Mining Association (OAR-2002-0056-2434), TXU

Energy (OAR-2002-0056-1831), and Utility Air Regulatory Group

(OAR-2002-0056-2922). Some of these comments used different approaches for

stimulating boundary conditions for apportioning Hg exposure from domestic and

international sources, and EPA asks for input on these alternative approaches and

analyses.

Comment:

One commenter (OAR-2002-0056-5458) noted that EPA requested that stakeholders

identify sources of Hg emissions other than coal fired utilities for inclusion into the IPM. The lack

of Hg source data in the 1999 National Emission Inventory (NEI) is a direct result of the

Agency’s decision not to include hazardous air pollutants in its Consolidated Emission Reporting

Rule. Other source categories not regulated for Hg emissions include sewage sludge incineration

and Portland cement plants that burn coal. Of combustion sources, coal fired utilities make up

half the Hg emitted in New York State. The Department has promulgated and implemented more

stringent state regulations that contain stricter emission limits for Hg emissions for the municipal

waste combustion source category than promulgated by the EPA. The current estimated Hg
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emissions inventory for stationary sources in New York is attached as Table 1 (see

OAR-2002-0056-5458). The Department is evaluating other source categories for reductions and

hopes that EPA will propose a NESHAP for the utility sector that will provide meaningful

reductions of national Hg emissions.

Resources:

EPA appreciates the additional information submitted by the commenter. EPA is

finalizing a cap-and-trade approach under section 111. Please see Chapter 8 of the CAMR

Regulatory Impact Analysis for a discussion of the air quality modeling for the CAMR

regulatory options and the resulting change in mercury deposition.

Comment:

One commenter (OAR-2002-0056-5488) stated that studies from the Florida Everglades

and Wisconsin, as well as the heterogeneity among the states in Hg deposition highlight the

localized nature of Hg deposition. Any benefits estimation must model local deposition,

methylation, and the consumption of fish contaminated by such local deposition, whether that

consumption occurs locally or more nationally. The NODA refers to the EPA’s intent “to

estimate the U.S. power plant contribution to total Hg deposition within the U.S.” From a public

health perspective, this estimate is meaningless, as Hg deposition, methylation, and human

exposure from U.S. coal-fired power plants depend on highly localized conditions and are

unrelated to the U.S. fraction of total Hg deposition averaged over the entire U.S. land mass.

Response:

Please see Chapter 3 of the CAMR Regulatory Impact Analysis for a detailed discussion

of mercury in the environment, including an assessment of the response time for systems after a

change in mercury deposition. Please also see Section 8 for a discussion of the change in

mercury deposition based on air quality modeling and Chapters 11 for a benefits analysis of the

CAMR. 

Comment:

One commenter (OAR-2002-0056-5535) presented several specific issues below that

would benefit from such careful peer review. They did not intend this list to be comprehensive,

but merely included it to illustrate that the agency must address critical scientific issues prior to

making changes to its deposition and watershed models or conducting other components of the

proposed analyses. This overview serves to demonstrate that it would be foolish to hold up final

Hg regulations while EPA further investigates certain technical issues concerning the emissions,

fate, and toxicity of Hg from power plants.

• Global model of Hg transport. The global model of Hg transport developed by the

Electric Power Research Institute needs thorough vetting by the broader scientific

community before it, or results generated by it, are adopted by the EPA. In particular, the

spatial resolution of EPRI’s model is coarse and the effect of that resolution profoundly

affects the modeling results.
9-clxix

Response:

EPA appreciates the commenters input. EPA is finalizing a cap-and-trade approach

under section 111. Please see Chapter 8 of the Regulatory Impact Analysis for a discussion of

the air quality modeling used to analyze the CAMR rule. 

Comment:

One commenter (OAR-2002-0056-5423) notes that natural sources of Hg emissions

dominate the small amount of Hg emissions from U.S. power plants. This commenter believes

that this fact brings into stark reality that any meaningful control of Hg emissions toward a

realistic “reduction” in Hg deposited on U.S. soils will be almost impossible. There are well over

5,000 surface and submarine volcanoes in the world, with about 50 to 60 eruptions each month,

according to the Smithsonian Institution. Volcanic degassing may be the single largest source of

ocean and atmospheric Hg. For example, at Roaming Mountain, Wyoming, researchers measured

Hg emanating from the clay hillside at up to 2,400 nanograms per square meter per hour. By

comparison, background levels away from geothermal areas range from zero to ten. So Hg

emissions from active geothermal areas could be tens and hundreds times more than from other

background areas.

For obvious reasons, volcanic degassing and other geothermal activities as dominant

sources of Hg have not received much attention or have been downplayed. For example, EPA

staff provided the Administrator with an outdated volcanic accounting study. Figure A1 (see

OAR-2002-0056-5423) clearly shows that EPA’s current adopted value for the annual

contribution of atmospheric Hg by volcanic eruptions and degassing is significantly under

accounted for by about a factor of 6 to 7. When adjusted to reflect a more accurate accounting of

volcanic Hg emission (Figure A2, see OAR-2002-0056-5423), U.S. power plant contributions to

the annual estimated Hg budget world-wide fall to an insignificant 0.8 percent or less.

Figure A3 (see OAR-2002-0056-5423) maps the range of potential volcanic activity in the

Western U.S. These are also potential sources of enormous Hg degassing and deposition,

especially Yellowstone National Park.

Figure A4 (see OAR-2002-0056-5423) emphasizes that the pools of Hg stored in U.S.

forests and peat lands (covering less than 2 percent of U.S. area) swamp the 100-150 tons total

annual anthropogenic Hg emission from U.S. sources.

Taken together, these figures support EPA’s admission of poor accounting for (a) natural

sources of Hg emission and (b) the large pool of background Hg at all times available for emission

from the natural ecosystems and geological settings within the U.S.

Yellowstone National Park is just one such geological reservoir of Hg. A report issued

last fall by the Idaho National Engineering and Environmental Lab showed that several places in

Yellowstone Park have higher levels of airborne Hg than power plants. It went on to say that

Yellowstone could emit or exceed as much Hg as all of Wyoming’s eight coal-fired power plants

combined.
9-clxx

At Yellowstone Lake, researchers have discovered submerged faults, explosion craters,

domal features, hydrothermal vents, lava flows extending far out into the lake and much more. 

Mercury may propagate from these natural features up through the food chain transforming into

MeHg in native cutthroat trout.

And since Yellowstone is the headwaters of important tributaries to the Missouri

(Yellowstone River) and Columbia (Snake River), no one knows how far the natural

contamination carries through the Earth’s air and water systems.

However, the Hg presence and emissions were noted by experts to pose no danger to park

rangers or visitors. Even native grizzly bears who consume up to 400 lb of spawning cutthroat

trout exhibit no ill effects, according to researchers with the Interagency Grizzly Bear Study

Team.

Thus, the most important question for EPA’s Hg emission and deposition modeling team

to answer confidently is whether the proposed CAMR to control Hg emissions from U.S. power

plants can assure any consequential “reduction” of Hg deposition in U.S. soils, leading to any

reputed public health “benefits.”

Response: 

Please see Chapter 3 of the CAMR Regulatory Impact Analysis for a detailed discussion

of mercury in the environment, including an assessment of the response time for systems after a

change in mercury deposition. Please also see Section 8 for a discussion of the change in

mercury deposition based on air quality modeling and Chapters 11 for a benefits analysis of the

CAMR. 

Comment:

One commenter (OAR-2002-0056-5423) provides an important challenge for EPA’s Hg

emission and deposition modeling team (Figure B1, see OAR-2002-0056-5423). It shows the

results from recent measurements of Hg content in Illinois soils clearly suggesting that

atmospheric deposition from any past or current U.S. power plants is insignificant compared to

the large quantity of background Hg already resided in soils across the state. This is why it is

extremely difficult for EPA to convincingly show that the Hg from U.S. power plant emissions

will be selectively filtered by the ecosystem components in Illinois (or anywhere else) to bring

about increased levels of MeHg in freshwater fish while ignoring the large pool of natural Hg in

the native ecosystem. It is therefore extremely difficult, if not impossible, for EPA to plausibly

demonstrate the assertion that its proposed CAMR can/will bring about any direct, measurable

improvement in public health.

In Figure B2 (see OAR-2002-0056-5423), the commenter provides a recent Hg emission

and deposition budget analysis for the northeastern Chinese city of Changchun. Scientists found

that of that 7.1 tons of Hg emitted by the city of Changchun, only less than 12 percent of

coal-fired power plant Hg was deposited back into the local area, while most escaped as

contributions to regional and global cycling of Hg.
9-clxxi

This scenario of the local Hg emission and deposition budget at Changchun, China may

serve as a useful model verification target for the EPA’s Hg emission and deposition modeling

team under a wide range of meteorological and climatic conditions and settings.

Man-made atmospheric deposition of Hg is a very small contributor to the huge amount of

natural Hg in Illinois and U.S. soils

(1) It has been estimated that “anthropogenic activities could have increased world soil Hg

content by [only] 0.02 percent.”

(2) From the measured high Hg content in Illinois soils, it would take 9000 years at the currently

measured atmospheric deposition rate to dump all the Hg to the top 380-cm of Illinois soils.

(3) If assuming the average Hg in the top 140-cm of U.S. soils to be about 10 ppb, it would take

14,000 years at the current atmospheric deposition rate to do it.

Response: 

EPA appreciates the commenters input. Please see Chapter 3 of the CAMR Regulatory

Impact Analysis for a detailed discussion of mercury in the environment, including an

assessment of the response time for systems after a change in mercury deposition. Please also

see Section 8 for a discussion of the change in mercury deposition based on air quality

modeling. 

Comment:

One commenter (OAR-2002-0056-5423) presents an important observational target for

EPA’s modelers (Figure C1, see OAR-2002-0056-5423). First, it is important to point out that

the Hg in rainwater or moist air exists mostly in the dissolved ionic form of Hg (Hg2+) rather than

MeHg–the biologically active form of Hg that may affect human health at extraordinary dose

levels. Figure C1 (see OAR-2002-0056-5423) shows that most (72.5 percent) of the MeHg in the

Chesapeake Bay ecosystems comes from in-situ production. Remote transport of MeHg from

rivers contributes about another 20 percent, and atmospheric deposition sources may contribute

toward production of as little as 7.5 percent of MeHg in the Chesapeake Bay’s ecosystems. Such

a scenario of the MeHg budget clearly emphasizes the need for better scientific understanding of

the complex physical, chemical and biological factors controlling the production and destruction

of MeHg, and why the levels of MeHg in an ecosystem do not depend directly on available

amounts of inorganic Hg (i.e., from background or power plant emissions).

Sources of MeHg in the Chesapeake Bay: Atmospheric deposition is a not an important

contributor Percentage contribution of 70 percent MeHg sources 60 percent in the Chesapeake

Bay In-situ Production Rivers Atmospheric Deposition Reference: Mason et al. (1999)

Response: 

EPA appreciates the commenters input. Please see Chapter 3 of the CAMR Regulatory

Impact Analysis for a detailed discussion of mercury in the environment, including an

assessment of the response time for systems after a change in mercury deposition. Please also
9-clxxii

see Section 8 for a discussion of the change in mercury deposition based on air quality

modeling.

Comment:

The commenter (OAR-2002-0056-5460) stated that UARG, following EPRI, argues that

Hg pollution is a global problem and, therefore, EPA should not regulate Hg emissions pursuant

to Section 112. See UARG Comments at 25-26. The commenter noted that, in particular,

UARG contends that only 25 percent of domestic Hg deposition stems from domestic

anthropogenic sources. Id. (citing EPRI Comments at 13). But little, the commenter stated, if

any, basis exists to have confidence in UARG’s estimates given EPA’s conclusion that Hg’s fate

in the environment can not be tracked with precision and that Hg emitted from any source may be

re-emitted into the environment. See 69 Fed. Reg. 4652, 4658 (Jan. 30, 2004). The commenter

stated that indeed, UARG itself contends that “the state-of-the-science on Hg cycling is too

imprecise to predict” the consequences of changes in Hg deposition. UARG Comments at 26

n.57.

The commenter stated that, more importantly, even if UARG is correct that Hg is a global

problem, it does not follow that EPA should not regulate domestic power plant emissions

pursuant to section 112. The commenter further stated that to the contrary, the Court of Appeals

for the D.C. Circuit has already made clear that whether a pollutant has local, regional or global

consequences is not, standing alone, a sufficient legal basis for concluding that the pollutant

should not be regulated. See American Lung Ass’n, 134 F.3d at 392 (rejecting EPA’s argument

that it could avoid revising a national ambient air quality standard simply by claiming that the

pollutant at issue had local effects only). The commenter added that simply because EPA cannot

prevent Hg from entering the U.S. from other countries is not a reason for EPA to avoid

regulating domestic Hg emissions. The commenter stated that UARG’s argument that local

emissions should be exempt from regulation because they cause only part of the problem makes

no sense: Just because pollution enters our borders from somewhere else is not a reason to allow

domestic sources to create even more pollution. The commenter further stated that, indeed, it is

well-established that a polluter may be enjoined from contributing to a public nuisance even where

the polluter’s contributions alone are insufficient to create the nuisance. See, e.g., The Law of

Torts § 52 (“Pollution of a stream to even a slight extent becomes unreasonable when similar

pollution by others makes the condition of the stream approach the danger point.”); Cox v. City

of Dallas, 256 F.3d 281,292 n.19 (5th Cir. 2001) (explaining that nuisance liability attaches where

one simply contributes to the nuisance); City of New York v. Beretta U.S.A. Corp., 315 F. Supp.

2d 256, 282 (E.D.N.Y. 2004) (“Where it is difficult or impossible to separate the injury caused by

one contributing actor from that caused by another and where each contributing actor’s

responsibility individually does not constitute a substantial interference with a public right,

defendants may still be found liable for conduct creating in the aggregate a public nuisance if the

suit is one for injunctive relief”).

The commenter stated that at bottom, EPRI and UARG appear to be arguing that EPA

needs greater proof that power plant Hg emissions cause harm before it can regulate those

emissions. But, the commenter stated, no reason exists for EPA to allow harm from Hg emissions
9-clxxiii

to continue until it has yet more concrete proof of that harm. The commenter further stated that

to the contrary, existing science already confirms the harm is sufficient for EPA to act. The

commenter stated that, finally, given the overarching flaws in EPRI’s and UARG’s comments,

EPA should look with skepticism upon their more detailed technical claims.

Response:

EPA appreciates the commenters input. Please see Chapter 3 of the CAMR Regulatory

Impact Analysis for a detailed discussion of mercury in the environment, including an

assessment of the response time for systems after a change in mercury deposition. Please also

see Section 8 for a discussion of the change in mercury deposition based on air quality

modeling.

Comment:

One commenter (OAR-2002-0056-5497) stated that any emissions inventory must do a

good job of defining the global sources of Hg emissions. Recent modeling by EPRI and others

has revealed that a substantial majority of Hg that is deposited in the U.S. (about 75 percent)

originates from natural sources and anthropogenic sources outside the U.S. Asian sources may

provide 20 percent of the Hg deposited in the U.S. EPRI’s NODA comments (see OAR-2002-

0056-5469) offer a number of sources of information on global Hg emissions.

Modeling of Hg emissions from global and domestic sources remains a challenging

exercise. To date, Hg model results have not matched the levels of Hg in water bodies and fish in

various parts of the U.S. The atmospheric chemistry of Hg may hold the key to this disparity. As

EPRI notes in its NODA comments, atmospheric Hg reactions can move in different directions. 

For major urban sources, including mobile sources, elemental Hg can be rapidly oxidized to ionic

Hg which can then be removed form the atmosphere by wet and dry processes. By contrast, ionic

Hg emitted from coal-fired power plants appears to be reduced to elemental Hg shortly after

leaving the stack. Recent results from Edgerton suggest that models that do not account for this

atmospheric reduction of ionic Hg will over predict the local and regional Hg deposition from

coal-fired power plants.

Future EPA modeling should use the results of global modeling to define the boundary

conditions for domestic modeling. Global modeling is a better scientific approach for setting

boundary conditions than arbitrarily setting those conditions. If EPA uses the results of global

modeling to set boundary conditions, it should still review those results to ensure they are

reasonable.

Response:

EPA appreciates the commenters input. Please see Chapter 3 of the CAMR Regulatory

Impact Analysis for a detailed discussion of mercury in the environment, including an

assessment of the response time for systems after a change in mercury deposition. Please also

see Section 8 for a discussion of the change in mercury deposition based on air quality

modeling.
9-clxxiv

2. Step 2: Analyzing Air Dispersion Modeling Capabilities. EPA plans on modeling

the atmospheric dispersion, atmospheric speciation, and deposition of Hg using the

REMSAD and CMAQ models, with the GEOS-CHEM global model for boundary

conditions input. The simulated results will be compared with ambient monitoring

data from the Mercury Deposition Network (MDN). EPA requested comments on

the use of these models and approach. EPA received comments on the use of models

for assessing the impacts of the proposed programs on Hg deposition patterns from

the Center for Energy and Economic Development (OAR-2002-0056-2256), Clean

Air Task Force et al (OAR-2002-0056-3460), Electric Power Research Institute

(OAR-2002-0056-2578), and Utility Air Regulatory Group (OAR-2002-0056-2922). 

EPA also sought comment on the alternative approaches suggested by some of these

commenters.

Comment:

One commenter (OAR-2002-0056-5464) highlighted another concern related to EPA’s

proposed rule, which is the issue of hot spots. The commenter believed the definition of a “hot

spot” in the proposal is insufficient. The proposal states, “a power plant may lead to a hot spot if

the contribution of the plant’s emissions of Hg to local deposition is sufficient to cause blood Hg

levels of highly exposed individuals near the plant to exceed the RID” (69 Federal Register 4702). 

The commenter was very concerned that the proposal considers the effects of only one plant at a

time in determining if there is a hot spot. This method of determining hot-spots ignores the

cumulative, localized impacts of Hg deposition caused by multiple, nearby or co-located,

coal-fired utility boilers by individually quantifying and analyzing the air quality impact of each

boiler in the absence of the others. This is contrary to previously adopted, long-standing,

peer-reviewed EPA procedures for performing air quality modeling on stationary sources for

criteria pollutants and is not acceptable for performing air quality modeling for more hazardous

pollutants like Hg.

The commenter had an additional concern related to the improvement of existing hot spots

and stated that 45 states have issued fish consumption advisories due to Hg. Clearly a

contaminated water body is a hot spot that already exists. In fact, the current situation indicates

that we have “hot states” and “hot regions” and not just localized hot spots. The commenter

feared that EPA’s proposal, which calls for a nationwide market-based cap-and-trade program,

will not ameliorate the problem of existing hot spots or areas.

The commenter categorically disagreed with UARG’s position and strongly urged EPA, if

the agency decides to proceed with a rule under Section 111, to maintain the ability of state and

local agencies to opt out of the trading program.

The Clean Air Act explicitly allows state and local air pollution control agencies to adopt

programs more stringent than those of the federal government. Specifically, section 116 states

that air quality agencies are not precluded from adopting or enforcing any standards, limitations or

requirements as long as they are at least as stringent as those required under the federal program. 
9-clxxv

The only exceptions are found in section 119 of the Clean Air Act, which preempts certain state

and local regulation of mobile sources. Therefore, UARG’s suggested approach, in which EPA

would preempt state and local agencies’ ability to adopt a more stringent program that does not

permit trading, is in direct conflict with section 116 of the Clean Air Act.

The commenter stated that for a variety of reasons, maintaining the ability of state and

local agencies to adopt more stringent programs is essential. Not the least of these reasons is that

state and local agencies will need some way of addressing and preventing hot spots in their areas. 

In fact, EPA appropriately acknowledged this in its January 30, 2004, proposal by stating,

“[s]tates retain the power under the proposed section 111 rule to adopt stricter regulations to

address local hot spots or other problems” (69 Federal Register 4702).

UARG expresses concern in its comments that allowing states to opt out of the program

would result in a “patchwork approach”. The commenter contended that a federal standard, such

as what EPA has proposed, that is less stringent than the law requires would be to blame for any

patchwork effect. In fact, state and local agencies have already begun to adopt their own

programs to ensure adequate public health protection in their states (see attached table). If EPA

and industry wish there to be more national consistency, EPA can accomplish this by adopting a

protective standard consistent with the requirements of Section 112(d). Fewer state and local

agencies may then feel compelled to adopt different approaches (see OAR-2002-0056-5464).

Response:

EPA has examined the commenter's concerns in context of the final rulemaking. 

EPA is finalizing a cap-and-trade approach under section 111. EPA has addressed the hot spots

issue in the Revision of December 2000 Regulatory Finding on the Emissions of Hazardous Air

Pollutants from Electric Utility Steam Generating Units and the Removal of Coal- and Oil-fired

Electric Utility Steam Generating Units from the Section 112(c) List for a discussion of the

Agency’s rationale for not proceeding under Section 112 Notice and in the Technical Support

Document: Methodology Used to Generate Deposition, Fish Tissue Methylmercury

Concentrations, and Exposure for Determining Effectiveness of Utility Emission Controls in the

docket.

Comment:

One commenter (OAR-2002-0056-5559), beginning in 2001, began a two-year effort to

develop a Hg atmospheric modeling system for Wisconsin and the Great Lakes region. Partial

funding for this work was provided by a grant, #X97599601, from EPA.

Based on this experience, the commenter had the following comments on the modeling of

Hg deposition that EPA is proposing to conduct as part of the revised benefits assessment.

Step 1–Analyzing Mercury Emissions from Other Sources. The commenter used

1999 National Emission Inventory (NEI) to build emissions estimates for Hg and conducted

considerable quality assurance of the Hg emissions data. Based on experience with the 1999 NEI

Hg emissions data, if EPA chooses to use the 2002 NEI data, this commenter recommends that
9-clxxvi

EPA conduct considerable quality assurance of these data, before they are used in model

simulations.

In simulations, the commenter added Canadian and Mexican emission sources. Although

those data are somewhat incomplete, the commenter would be happy to share these data with

EPA.

Step 2–Analyzing Air Dispersion Modeling Capability. There is a significant amount of

uncertainty associated with the simulation of Hg deposition. EPA should conduct an uncertainty

analysis with the modeling system to evaluate the effect on the modeling simulations for changes

to the underlining assumptions in the model. In particular, EPA should evaluate changes to the

wet deposition algorithms, dry deposition algorithms and emissions speciation profiles and

processes that form MeHg in water bodies.

There is some anecdotal evidence such as around the White Pine smelter in Michigan and

around certain Florida point sources, that reductions in Hg emissions at large sources results in a

reduction in Hg concentration in nearby water bodies. To date, this phenomenon has not been

satisfactorily simulated with Eulerian grid models. EPA should further investigate this

phenomenon, since it seems to highlight a significant problem with the current state of the science

Hg modeling systems and puts into doubt the interpretation of the results of model simulations. If

a significant improvement in nearby water quality results from a reduction in Hg emissions, this

commenter will realize a much greater benefit from power plant Hg reductions than has been

demonstrated by previous model simulations.

EPA should reconsider its selection of the Regional Modeling System for Aerosols and

Deposition (REMSAD) for one of the models to use in its analyses. Under a grant, AER and

Environ worked with the commenter to create a version of the Comprehensive Air Quality Model

with extensions (CAMx) that includes the most up-to-date Hg chemistry and deposition

algorithms. The model development and simulations were peer reviewed by Alpine Geophysics. 

When measured wet deposition at Mercury Deposition Network (MDN) sites was compared with

model results, the commenter found that CAMx provided much better model performance than

REMSAD.

Deposition is very sensitive to rainfall simulation in MM5. Since, in the eastern U.S., a

significant portion of annual Hg wet deposition occurs in convective rain events, it is important to

properly simulate convection in the meteorological model. In model performance testing for

MM5, the commenter found that using a 12 Km grid spacing rather than 36 Km, 46 vertical layers

rather than 34, and the Reisner Graupel Ice scheme rather than Simple Ice provided superior

performance for a convective rainfall event in the Great Lakes area. These changes will adversely

affect model run time, but may be worth employing for comparison purposes.

Response: 

Please see Chapter 3 of the CAMR Regulatory Impact Analysis for a detailed discussion

of mercury in the environment, including an assessment of the response time for systems after a

change in mercury deposition. Please also see Section 8 for a discussion of the change in
9-clxxvii

mercury deposition based on air quality modeling.

Comment:

The commenter (OAR-2002-0056-5563) wished to specifically address the issue of

utilizing modeling under the notice of data availability for the Clean Air Mercury Rule. The

commenter felt that modeling should only compliment a comprehensive monitoring program of

Hg pollution. Monitoring should not be limited to the Great Lakes and Eastern portion of the

country-it should be extended to all parts of the U.S., especially to tribal lands and communities. 

The utilization of the Community Multiscale Air Quality (CMAQ) and Regional Modeling System

for Aerosols and Deposition (REMSAD) models that the EPA had used and intended to use in the

future for modeling the atmospheric dispersion, speciation, and deposition of Hg did not address

tribal concerns effectively. The EPA’s plan was to use a 36-kilometer modeling grid for both

CMAQ and REMSAD in assessing the aforementioned items. However, these models were

equipped to handle 12 and 4-kilometer modeling grids. In order to assess the real effects of Hg

on tribal lands, the commenter urged the EPA to utilize the latter modeling grids. This rational

was related to the size of tribal lands and communities. Most tribes occupied land closer to these

grid sizes. Furthermore, the proportion of the proposed models for both CMAQ and REMSAD

models failed to distinguish between different jurisdictions such as tribal, state, and county lands. 

This issue failed in carrying out the trust responsibility of the federal government. Tribal lands, as

sovereign Nations, had the right to be indicated as such in modeling practices. In addition, the

NTAA also feels that proposed modeling techniques will error in properly addressing

jurisdictional point sources of Hg. Therefore, modeling output could be adversely affected.

Response:

Please see Chapter 3 of the CAMR Regulatory Impact Analysis for a detailed discussion

of mercury in the environment, including an assessment of the response time for systems after a

change in mercury deposition. Please also see Section 8 for a discussion of the change in

mercury deposition based on air quality modeling and Chapters 11 for a benefits analysis of the

CAMR. 

Comment:

One commenter (OAR-2002-0056-5458) agreed with the subcategorization of coal types

for regulatory purposes in response to the NODA section II.C.3.b., but disagrees with the

standard (or average) speciation profile in modeling analysis. Work conducted by the Department

on the 1999 Information Collection Request (ICR) shows that the majority of Hg emitted in the

eastern half of the US is predominantly in the oxidized form. The speciation profile cited in the

NODA, 54 percent elemental, and 43 percent oxidized and 3 percent particulate Hg, is a national

average and does not represent the Northeast States potential deposited burden. The

Department’s analysis of the ICR data indicates a profile closer to 30 percent elemental,

65 percent oxidized and 5 percent particulate Hg for sources which are impacting New York.

The NODA focuses on industry sponsored research about the speciation of atmospheric

Hg after it exits the stack and how emissions rapidly converted to elemental Hg in the plume will
9-clxxviii

not be deposited in the U.S. due to their long atmospheric residence time (Air Docket

OAR-2002-0056-2928 and OAR-2002-0056-2848). This entire data set was not included in the

docket and the Department could not locate any information which indicates the data had

undergone any public and peer review. The EPA must cautiously evaluate the results and

conclusions drawn from this research in light of the unknown and non-linear relationship between

Hg emissions and deposition. There are many factors which need to be assessed when evaluating

atmospheric Hg transformation and potential deposition scenarios. The NODA must consider the

emerging science about the atmospheric chemistry and deposition of Hg. These recent findings

indicate that the abundance of oxidized Hg increases with altitude in the troposphere, and airborne

halogens and oxidants, such as ozone facilitate the oxidation of elemental Hg, which in turn

increases both wet and dry deposition of Hg. The reactions are occurring in areas with high

seasonal ozone levels and also appear to take place in the temperate coastal zone. Researchers

have concluded that a short half-life for elemental Hg is probable.

Response:

EPA appreciates the commenters concerns. Please see EPA 's Office of Research and

Development white paper (see Control of Emissions from Coal-Fired Electric Utility Boilers: An

Update, EPA/Office of Research and Development, March 2005) for a discussion of the

importance of speciation for mercury capture. Also, please see Chapter 7 of the Regulatory

Impact Analysis for a discussion of how we took speciation into account in our power sector

modeling and see Chapter 8 for a discussion of how we took speciation into account in our air

quality and deposition modeling. Please see Chapter 3 of the CAMR Regulatory Impact

Analysis for a detailed discussion of mercury in the environment, including an assessment of the

response time for systems after a change in mercury deposition.

Comment:

One commenter (OAR-2002-0056-5425) said their comments were specific to the

Community Multiscale Air Quality (CMAQ) and Regional Modeling System for Aerosols and

Deposition (REMSAD) models that the EPA has used and intends to use in the future for

modeling the atmospheric dispersion, speciation, and deposition of Hg. The EPA is planning to

use 36 kilometer modeling grids for both CMAQ and REMSAD in assessing the aforementioned

items although these same models are equipped to handle 12 and 4 kilometer modeling grids. In

the interest of assessing the true effects of Hg dispersion, speciation and deposition on tribal

lands, the EPA should use the latter modeling grids because most tribes occupy lands closer to

these grid sizes as opposed to the former grid size being proposed by the EPA for modeling. 

Furthermore, the spatial resolution of the gridded output for both the CMAQ and REMSAD

models fails to distinguish between different jurisdictions such as tribal, state and county lands. 

Such a failure could likely cause the models to incorrectly attribute (e.g., mislocate) one

jurisdiction’s Hg point source to another jurisdiction (such as a tribe’s land). This incorrect

attribution of a point source could then adversely affect the results of the modeling output. A

means for mitigating this problem is to assign a numeric code to the jurisdiction within the grid

cell having the dominant contribution to emissions in that cell. This would help the models to

produce more accurate results otherwise impossible under current model designs.
9-clxxix

Response:

EPA appreciates the commenters input. Please see Chapter 8 of the Regulatory

Impact Analysis for a discussion of EPA’s air quality modeling analysis. Please also see EPA’s

Technical Support Document for the Final Clean Air Mercury Rule: Air Quality Modeling.

Comment:

One commenter (OAR-2002-0056-5502) referenced research results reported to U.S. 

EPA in June 2004 analyzed Hg deposition for a 2004 Base Case emissions inventory and two

2020 scenarios, the proposed Maximum Achievable Control Technology (MACT) rule and the

proposed Cap and Trade (C&T) rule. Additional analyses of Hg deposition patterns for 2004 and

equivalent patterns under the MACT and C&T rules have now been carried out.

These additional analyses have examined the deposition that would result from utility

sources that are projected under MACT and/or C&T to not implement controls specifically to

reduce Hg emissions. Mercury emissions from these sources (in addition to all the other utility

sources that will be reducing their Hg emissions) are found to have insignificant impacts on nearby

and distant deposition patterns for the C&T case, relative to the MACT case. Receiving waters

downwind from these locations are calculated to experience no significant additional deposition

due solely to these sources individually or as a group not initiating Hg-specific controls. Thus,

under EPA and other definitions of utility Hg deposition “hot spots,” these particular sources do

not in themselves bring about “hot spot” conditions under a C&T rule relative to either a MACT

rule or 2004 emissions conditions.

Measurements of speciated Hg in the ambient atmosphere are needed to improve our

understanding of the atmospheric fate and transport of Hg. The commenter recommended that

the available information on speciated Hg concentrations be used to (1) provide insights on the

processes that appear to influence Hg speciation in the atmosphere, (2) evaluate the performance

of global and continental models of atmospheric Hg vs. surface and aloft data, and (3) quantify

the limitations and possible biases of those models. Those limitations and biases should then be

taken into account when evaluating the potential benefits of Hg emission reductions.

The MDN data are extremely useful to evaluate the ability of models to reproduce the

regional patterns of Hg wet deposition. The MDN data have also highlighted the fact that Hg

deposition is significantly different from sulfate deposition. Sulfate wet deposition shows a clear

west-to-east increasing gradient whereas Hg wet deposition shows primarily a north-to-south

increasing gradient. These results suggest that sulfate wet deposition is strongly influenced by

regional emission sources whereas Hg is not. Instead, Hg wet deposition appears to be influenced

primarily by oxidant concentrations that are conducive to the oxidation of Hg0 to Hg+2.

Comment:

One commenter (OAR-2002-0056-5497) suggested that the Mercury Deposition Network

(MDN) data are useful in evaluating the ability of models to reproduce regional patterns of wet

deposition of Hg. However, the MDN was never designed to monitor the local deposition of Hg. 
9-clxxx

Consequently, MDN data should not be used to evaluate model predictions of near-field

deposition.

For the reasons detailed in EPRI’s NODA comments (see OAR-2002-0056-5469), the

commenter agrees that the Industrial Source Complex (ISC) and Regional Lagrangian Model of

Air Pollution (RELMAP) models used for the Hg Study are not the best means of assessing local

and global Hg deposition. These models are outdated and do not reflect the current state of the

science. Whatever model(s) EPA ultimately chooses, EPA must recognize that a grid-based

model may over predict local Hg deposition by a factor of two or more when compared to the

results of a plume model.

Response:

EPA appreciates the commenters input. Please see Chapter 8 of the Regulatory Impact

Analysis for a discussion of EPA’s air quality modeling analysis. Please also see EPA’s

Technical Support Document for the Final Clean Air Mercury Rule: Air Quality Modeling.

3. Step 3: Modeling Ecosystem Dynamics. EPA plans to quantify Hg deposition

associated with Hg reductions to estimate changes in human exposure to

methylmercury that may result from reductions in power plant emissions. This

requires quantifying the linkage between different levels of Hg deposition and fish

tissue methylmercury concentration. EPA is currently considering using the Water

Office’s Mercury Maps (Mmaps) for this purpose, supplemented by case studies,

and requested comment on this approach. To complement the case studies, EPA

asked for both empirical information and modeled scenarios that show the effects of

ecosystem properties other than total Hg loading on accumulation in organisms in

different ecosystems and, specifically, on new knowledge related to factors affecting

methylation and demethylation in a range of aquatic ecosystem types. EPA also

sought comment on data and/or analytic tools that can be used to forecast

methylation rates and bioaccumulation rates in aquatic ecosystems. EPA received

analyses of the changes in fish concentrations expected as a result of changes in

deposition from Chippewa Indians (OAR-2002-0056-2118), Environmental Defense

(OAR-2002-0056-2878), Electric Power Research Institute (OAR-2002-0056-2578,

-2589, -2593), Hubbard Brook Research Foundation (2038), NESCAUM

(OAR-2002-0056-2887, -2890), and TXU Energy (OAR-2002-0056-1831) and asked

for comment on their analyses.

Comment:

One commenter (OAR-2002-0056-5544) has been monitoring Hg in sediments and fish in

reservoirs on one particular river and its tributaries over the last 30 years. Based on this extensive

data set, several observations can be made:

• Mercury levels in this reservoir sediment have declined substantially since 1973.

• Mercury content in fish in the reservoirs was varied but has generally shown constant or

reducing trends.
9-clxxxi

• Generation of power from coal-fired facilities in the region has increased over this period.

The commenter has been working in cooperation with state agencies in the Tennessee

Valley to determine the overall condition of streams and lakes and the level of contaminants in fish

for three decades. Mutual efforts specifically related to Hg began in 1970 in response to

discovery of Hg contaminated fish in the Great Lakes and adoption of guidelines for Hg in fish by

the U.S. Food and Drug Administration. The commenter collected a variety of fish species and

sediment samples from throughout the are in the early 1970's and reported current fish tissue

monitoring program began in 1987 and continued as part of their Vital Signs Monitoring

Program. The commenter has monitored hundreds of locations throughout the Tennessee Valley

over the years.

Mercury levels in the commenter’s area reservoir sediments have declined substantially

since 1973. The commenter conducted a special study in 1973 of sediments from the forebay area

(i.e., the area just upstream of a dam) of 26 reservoirs. A comparison of the results from 1973

with recent Vital Signs Monitoring data from the same locations indicates a substantial decrease in

Hg concentrations throughout the commenter’s area from the early 1973s to the late 1990s. The

large reduction in sediment Hg occurred in the 1970s as many large industrial users of Hg

changed production methods to less Hg-intensive operations. In locations without historical

industrial point sources of Hg, no increases have been observed in sediment Hg concentration.

Mercury levels in fish tend to be low in largemouth bass and catfish in the reservoirs of the

commenter’s main river. In samples collected since 1990's in the reservoirs, largemouth bass

show a mean concentration of total Hg around 0.2 mg/kg. Largemouth bass are routinely

included in many studies because they are at the top of the food chain. Since 1970, the Hg

concentrations in largemouth bass and channel catfish have remained relatively steady with no

apparent increase.

In furtherance of its congressional mandate to promote the safe and efficient use of

electric energy, the commenter has long supported and conducted research into various subjects

associated with the generation of electricity. This includes the publication of various technical

reports and studies. Among these publications are a series of “On the Air” reports that are

technical notes on important air topics. The November 2004 “On the Air” focused on TVA’s

sampling of Hg levels in the Tennessee Valley region and was entitled, “Three decades of

Mercury Levels in the Tennessee River System”. The commenter is enclosing a copy of this

document with our comments. It presents the above information in more detail and shows that a

decline in Hg concentrations in the Tennessee River has occurred over a period of time when coal

combustion has increased substantially (see OAR-2002-0056-5544).

Response:

EPA has examined the commenter's concerns in context of the final rulemaking. As

described in the Technical Support Document: Methodology Used to Generate Deposition, Fish

Tissue Methylmercury Concentrations, and Exposure for Determining Effectiveness of Utility

Emission Controls in the docket, we have limited the fish tissue samples to more recent years for

some analysis in part for reasons similar to those raised by the commenter.
9-clxxxii

Comment:

One commenter’s (OAR-2002-0056-5559) studies at Little Rock Lake in northern

Wisconsin indicated that environmental improvement may be occurring from actions already taken

to reduce Hg air emissions. For a five-year period beginning in 1995, researchers measured Hg

air deposition, and levels of Hg in lake water and in fish tissue. The studies documented declines

in Hg levels for all these parameters with reductions of Hg levels in yellow perch tissue averaging

5 percent annually. The declines measured show that Little Rock Lake is responding more rapidly

to changes in deposition of Hg than the decline in acidity from sulfur dioxide emission reductions. 

This is a promising indication that reducing Hg deposition will lead to lower lake Hg levels as well

as a reduction in fish tissue.

Response: 

EPA appreciates the commenter's input to the record. We pursued several case studies as

described in Chapter 3 of the Regulatory Impact Analysis that address time-lags at various

ecosystems.

Comment:

One commenter (OAR-2002-0056-5517) notes that as demonstrated by peer-reviewed

research performed by scientists at Princeton University, the level of methymercury in the world’s

oceans is not controlled by atmospheric Hg. In this respect, a particularly significant omission of

the NODA is its failure to note the observation of these Princeton University scientists whose

findings provide strong evidence that the concentration of MeHg in the world’s oceans does not

respond to anthropogenic emissions of Hg. Rather, oceanic biogeochemical processes, possibly

involving deep ocean sediments, control the level of methymercury in the world’s oceans. Thus,

this commenter believes that regardless of what Hg emissions controls are put in place at

coal-fired power plants, the levels of MeHg in ocean fish will remain virtually unchanged.

The commenter points out that EPA, in its NODA, has produced no peer-reviewed data

that would contradict the finding of the Princeton study. Moreover, the Princeton study aside,

given the fact that the world’s oceans contain millions of tons of Hg, reducing some or even all of

the less than 50 tons of Hg emissions released from U.S. coal-fired power plants will leave the

levels of Hg in the world’s oceans virtually unchanged. Consequently, the levels of MeHg in the

ocean fish that Americans eat every day will be virtually unchanged. Unless EPA can produce

peer-reviewed data that convincingly contradicts the Princeton study findings, it must be

presumed as prima facie evidence arguing against any assertion by EPA that curtailing Hg

emissions from power plants would have any effect on the level of MeHg found in ocean fish.

If the Princeton study is correct concerning the constancy of the amount of Hg in the

world’s oceans, then the modeling EPA proposes to use to estimate reductions of MeHg in

marine fish is entirely inappropriate and must not be used. This is because the models, by their

very design, would incorrectly predict that lowering emissions of Hg from coal-fired power plants

will in fact lower the levels of MeHg in the ocean.
9-clxxxiii

However, actual oceanic field data taken by the Princeton University scientists clearly

indicate that this is not the case and that regardless of whether atmospheric levels of Hg change,

the level of MeHg in the ocean remains unchanged. No model that EPA proposes to use reflects

this fact. If these scientists are correct in their surmisal, then limiting emissions of Hg from

coal-fired power plants will have absolutely no significant effect on the levels of MeHg in marine

fish, consumption of which constitutes the major route of human exposure to this chemical. The

commenter states that this important finding has a very significant bearing on estimates of the

benefits of reducing power plant emissions of Hg and must be taken into account.

Response: 

EPA appreciates the commenter's input to the record. For several reasons described in

the Regulatory Impact Analysis, EPA focused its analysis on recreationally caught freshwater

fish.

Comment:

One commenter (OAR-2002-0056-5458) did not agree with the EPA formal definition of

a Hg hot spot. The definition based on modeling Hg deposition rates by utilities and determining

how the removal of those emissions will hypothetically reduce the amount of MeHg in fish is

flawed logic. A Hg hot spot is an existing area or region which already has had its natural

resources (fish and wildlife) adversely impacted by Hg emissions resulting in the issuance of fish

advisories to protect public health. Existing Hg concentrations in fish and wildlife should be used

to define Hg hot spots.

The proposed scale of modeling responses of fish tissues to changes in Hg emissions to

the atmosphere is unclear in the NODA. National-scale modeling would appear to have a

tendency to dilute or obscure the benefits of reduced Hg emissions, particularly for the

northeastern and east coast states. This dilution or obscuring of benefits is not scientifically sound

or acceptable. For fresh waters of the U.S., modeling should be scaled to at least a regional basis

although benefits of Hg emission reductions will be even greater in localities and waters with

closer proximity to the sources of Hg emissions.

Response:

EPA has addressed the hot spots issue in the revision Federal Register notice and in the

Technical Support Document: Methodology Used to Generate Deposition, Fish Tissue

Methylmercury Concentrations, and Exposure for Determining Effectiveness of Utility Emission

Controls in the docket.

Comment:

One commenter (OAR-2002-0056-5502) stated that power plant emission reductions will

reduce Hg deposition in the Eastern U.S., and MeHg concentrations in wild freshwater fish are

likely to drop in response. Much of the freshwater fish consumed in the U.S. is farm-raised, and

does not contribute significantly to exposure. But because so much more marine fish than wild

freshwater fish is consumed, the affect on total exposure is modest. The range of exposure
9-clxxxiv

reduction from Hg controls under any of the scenarios under consideration was from 0.4-

6.5 percent, depending on the state. The average of the calculated state reduction was about

1.6 percent. These reductions apply to those who eat a typical mix of marine and wild freshwater

fish, based on state recreational fishing data. Some members of the population such as

subsistence fishers may experience greater exposure reductions.

EPA’s MMaps tool assumes that 1) there is a linear relationship between atmospheric

deposition and MeHg in fish, 2) atmospheric deposition is the only significant source of Hg to

lakes, and 3) fish tissue Hg is at steady state equilibrium with the water. Data (from the

METAALICUS study) and modeling results negating these assumptions are provided. 

Furthermore, it is still not possible to accurately forecast either the lag time or the level of

response of fish tissue following reductions in Hg deposition. Modeling runs with the

commenter’s Dynamic Mercury Cycling Model have indicated lag times of decades to more than

100 years. Regardless of the complexity of models describing the behavior of Hg in the

environment, characteristics of both terrestrial and aquatic ecosystems such as microbial activity,

pH, dissolved organic matter, algal productivity, redox potential, temperature, hydrodynamics,

etc. make it very difficult to accurately conduct broad-brush regional modeling of the responses of

fish tissues to reductions in atmospheric Hg deposition.

Reductions in Hg emissions from U.S. coal-fired power plants will have only a small effect

on U.S. exposures to MeHg. This is because most exposure to MeHg occurs through

consumption of marine fish. Marine fish will be largely unaffected by U.S. power plant emission

reductions because the reductions are so small, less than 1 percent, of global emissions. The

predominance in U.S. commerce of North Pacific marine fish implies an even lower sensitivity to

U.S. Hg reductions, due to prevailing winds and the uncertainty about the availability of MeHg in

marine environments.

Response:

The benefits analysis completed for the RIA is not intended to model local-scale changes

in fish tissue concentrations and exposures in support of site-specific risk analysis. Instead,

modeling conducted for the RIA is intended to capture generalized regional changes in

methlmercury exposure resulting from reductions in power plant mercury emissions in order to

support a national-scale benefits assessment focusing on the 37-State eastern U.S. study area. 

For additional details on the benefits analysis modeling framework see Section 10 of the RIA.

EPA recognizes the complexities associated with methylation of mercury deposited in

waterbodies and watersheds and subsequent biomagnification within the aquatic foodweb. While

there are dynamic fate/transport models that can be used to conduct detailed site-specific

modeling of mercury in aquatic and terrestrial environments for purposes of predicting mercury

fish tissue concentrations (e.g., the dynamic mercury cycling model), it is not feasible to utilize

these resource-intensive models for a regional- or nationals-scale analysis. Therefore, EPA

selected the MMAPs models for application in the RIA. EPA fully recognizes the limitations and

simplifying assumptions associated with this model, but believes that it has sufficient precision to

support a benefits analysis conducted at the regional- or national-scale (i.e., it can capture
9-clxxxv

general trends in mercury fish tissue response to changes in mercury deposition from power

plants). However, to provide additional perspective on the relationship between mercury

deposition and fish tissue concentration changes (especially in relation to MMAPS linearity

assumption and the lag time required for systems to reach steady state), EPA has conducted

several detailed local-scale sensitivity analyses. The results of these case studies are presented

and discussed in Appendix D.

EPA recognizes both (a) the technical challenges in predicting the change in saltwater

fish mercury concentrations resulting from reductions in US power plant emissions and (b) the

relatively small contribution that US power plants make to total deposition over saltwater

habitats for commercial fish (Note, however that because of the high proportion of US fish

consumption associated with saltwater fish, even a relatively low impact of US power plant

emissions on those fish could produce significant benefits). Because primarily of technical

challenges in translating mercury emissions reductions from US power plants into changes in

saltwater fish mercury concentrations, EPA has not included this exposure pathway (saltwater

fish consumption) in the primary benefits analysis.

EPA agrees with the commentor that there is significant uncertainty associated with

predicting the lag (time) required for fish to reach new steady state mercury concentrations

following reductions in mercury deposition to watersheds/waterbodies. EPA also recognizes,

that, depending on the specific aquatic system under consideration, lag times could extend over

decades. Consequently, EPA has provided benefits results in the RIA reflecting a range of lag

periods (from 0 years to 100 years).

Comment:

One commenter (OAR-2002-0056-5465) stated that even working within the narrowly

framed revised benefits assessment proposed by EPA, numerous issues arose. The commenter

hereby incorporated by reference the arguments elaborated in the attached articles insofar as they

spoke to the questions raised by the NODA. In particular, the commenter drew EPA’s attention

to the discussion and sources cited by Professor O’Neill regarding the biological, chemical, and

physical processes relevant to determining Hg exposure for those in the upper Great Lakes.

Response:

EPA appreciates the commenters concerns. EPA addresses ecosystem response to

mercury loading in Chapter 3 of the Regulatory Impact Analysis. 

Comment:

One commenter (OAR-2002-0056-5535) presented several specific issues that would benefit from such

careful peer review. The commenter did not intend this list to be comprehensive, but merely include it to illustrate

that the agency must address critical scientific issues prior to making changes to its deposition and watershed

models or conducting other components of the proposed analyses. This overview serves to demonstrate that it

would be foolish to hold up final Hg regulations while EPA further investigates certain technical issues concerning

the emissions, fate, and toxicity of Hg from power plants.

Hg Speciation in Deposition Modeling. The NODA points out that HBRF said that an average speciation profile
9-clxxxvi

should not be used when modeling or estimating deposition. This statement was made in the context of Hg

deposition modeling because using an average speciation profile for emissions would likely underestimate the

amount of local, regional and continental deposition. This is because speciation drives assumptions about the

residence time of Hg in the atmosphere, which controls transport and the likelihood that Hg emitted in the U.S.

will deposit in outside the U.S. For example, the more Hg emitted as elemental, the higher the proportion of Hg

that is transported longer distances. In particular, the EPA should incorporate new speciation data for Northeast

plants. A revised speciation profile for Northeast plants is: 70 percent oxidized Hg and 30 percent elemental Hg.

Hg Maps (MMAPS). MMAPS is a useful tool for roughly evaluating the impacts of Hg deposition on fish Hg

levels. However, as the agency notes, it is still undergoing external peer review and the commenter expects the

agency will need time to address peer review comments. Hindering the applicability of MMAPs is the lack of fish

concentration data for many watersheds and the “averaging” of results across large watersheds. The commenter

thought MMAPS was best suited to the application for which it was developed–evaluating specific watersheds

where additional information on population exposure can be considered when evaluating the results of the

assessment.

Response:

EPA appreciates the commenters concerns. Please see EPA 's Office of Research

and Development white paper (see Control of Emissions from Coal-Fired Electric Utility

Boilers: An Update, EPA/Office of Research and Development, March 2005) for a discussion of

the importance of speciation for mercury capture. Also, please see Chapter 7 of the Regulatory

Impact Analysis for a discussion of how we took speciation into account in our power sector

modeling and see Chapter 8 for a discussion of how we took speciation into account in our air

quality and deposition modeling. See the Regulatory Impact Analysis and the Technical Support

Document: Methodology Used to Generate Deposition, Fish Tissue Methylmercury

Concentrations, and Exposure for Determining Effectiveness of Utility Emission Controls in the

docket for a discussion of the application of Mercury Maps assumption.

Comment:

One commenter (OAR-2002-0056-5423) presented a figure illustrating no evidence of increasing trend or

any change in Hg of deep-sea fish (blue hake): 1970s versus 1880s fish (Figure E1, see OAR-2002-0056-5423).

“To test for a change in mercury content in the last century, two samples of the deep-sea fish

named blue hake (Antimora rostrata) were analyzed. Antimora rostrata is resident throughout

the world’s oceans at depths of 1000-3000 m but does not venture into depths shallower than 800

m [actually about 200 m in the cold waters of the polar region]; therefore, this deep-sea species is

not exposed to local estuarine, coastal, or atmospheric inputs of mercury. A sample of 21

specimens collected in the 1880s was compared with a sample of 66 specimens collected in the

1970s in the western North Atlantic Ocean. In both recent and old fish mercury increased as a

function of length, but comparison of the two concentration vs. length relationships shows that

there has not been an increase in mercury concentration in deep-sea fish in the last century. This

result supports the idea that the relatively high concentration of mercury found in marine fish

that inhabit the surface and deep waters of the open ocean result from natural processes, not 20th

century industrial pollution.” [Barber et al. (1984) Environmental Science & Technology, vol.

18, 552-555; Barber et al. (1972) Science, vol. 178, 636-639]

This commenter presented a figure (Figure E1, see OAR-2002-0056-5423) showing that although one can

find a clear increase of Hg concentration in the tissue of the deep sea fish (blue hake) caught from western Atlantic

waters as the size of the fish increases, one can hardly see any significant changes in the fish tissue Hg-size
9-clxxxvii

relation for fish samples caught in 1880s when compared to the modern samples caught in the 1970s. This

research clearly suggests that Hg concentration in world ocean fish is not likely to be changed or modified by any

amount of alteration of inorganic Hg sources (either anthropogenic or natural). This is why the claim that the

current EPA CAMR will lead to a measurable reduction in MeHg accumulated in world ocean fish or even fish

from local U.S. lakes is factually misleading. Additional evidence and comments by the commenter follow.

Figure E2 , (see OAR-2002-0056-5423) shows recent results by Kraepiel et. al., (2003, Environmental

Science & Technology, vol. 37, 5551-5558) which found no clear increase in the Hg levels of Yellowfin tuna

caught in 1998 relative to a similar cohort caught in 1971.

The theoretical expectation (similar to EPA’s) was that the MeHg concentration “should have increased

by 9 to 26 percent” over the interval “if methylation occurred in the mixed layer or in the thermocline [of the

Pacific oceans].” The theory was not proven. The commenter further noted that Zhang et al. (2002, Ambio, vol.

31,482-484) has recently estimated that China’s Hg emissions from coal combustion are increasing at the rate of

5 percent per year (from available data from 1978 through 1995), which is consistent with the theoretical

expectation of increase in the amount of MeHg in the waters of the Pacific Ocean if the Hg-to-MeHg conversion

process is sensitive to industrial emissions. To the contrary, Kraepiel et al. (2003) clearly concluded that “[s]uch

an increase is statistically inconsistent with the constant Hg concentrations measured in tuna. The commenter

concluded tentatively that Hg methylation in the oceans occurs in deep waters or in sediments.” (p. 5551). This is

why the relatively small man-made sources of Hg emissions can neither overwhelm nor directly alter the natural

cycling of Hg in the environment and biosphere.

Independent results shown in Figure E3 (see OAR-2002-0056-5423) support and update the finding of

Zhang et al. (2002) that industrial Hg emissions from China (and India) are increasing significantly from 1990 to

2000 and that amount, both in the absolute amount and the rate of increase, dwarfed the rather small amount of

industrial Hg emissions from the U.S. EPA’s CAMR should seriously consider and weighing this important fact if

there is to be any effective Hg emission management rulings.

Figure E4 (see OAR-2002-0056-5423) shows additional new evidence against any increasing trend in Hg

levels in fish by examining concentrations in tissue of striped bass from the San Francisco Bay area over the period

1970-2000. The study’s findings also clearly show that in any given year there is at least one striped bass sample

containing Hg values above EPA’s consumption advisory threshold value of 0.5 ppm. Perhaps even more

significant, those striped bass with Hg concentration values above 0.5 ppm had no apparent connection to power

plant Hg emissions.

Figure E4 (see OAR-2002-0056-5423) illustrates no evidence of increasing trend in Hg concentration in

striped bass caught off San Francisco Bay area from 1970-2000. The commenter notes that at any given year there

is at least one striped bass with Hg level above the EPA’s consumption advisory threshold of 0.5 ppm since 1970

with no apparent tie to any U.S. power plant Hg emission sources. Also although no increasing trend is clear for

Hg, declines were noted in the fish tissue’s DDT and chlordane in the late 90s. Those declines may be related to

the use curtailment of these two chemicals in the 70s and 80s.

Figure E4 (see OAR-2002-0056-5423) reveals another important finding from this new study. Even

though no accumulation trend was noted for Hg in striped bass in the 1970-2000 period, significant declines in the

late 1990s were noted for other contaminants like DDT and chlordane in San Francisco Bay’s fish tissues. The

authors suggest that the declines may be linked to known curtailed usage of the two chemicals in the 1970s and

1980s. Thus, the combined findings suggest a more complicated and complex chain of biomethylation and

bioaccumulation for Hg in fish. That is, compared to other contaminants it appears that the pathway and behavior

of Hg transformation and accumulation in fish differs significantly.

A similar tendency was recently reported (Yamaguchi et al., 2003, Chemosphere, vol. 50, 265-273) for levels of
9-clxxxviii

contaminants in fish from upper River Thames in Britain by a group of zoologists from Oxford University and

Cornell University. These authors concluded that although the recent decrease in environmental contamination

level of PCBs may be partly associated with industrial and human activities, it was difficult to find such

associations for Hg.

Response: 

EPA appreciates the commenter's input to the record. For several reasons described in

the Regulatory Impact Analysis, EPA focused its analysis on recreationally caught freshwater

fish.

Comment:

One commenter (OAR-2002-0056-5423) presented a figure (Figure F1, see OAR-2002-0056-5423) that

confirms admission by EPA that trace levels of MeHg in fish depend on the complex physical, chemical, and

biological factors within each unique ecosystem. More importantly, it evidences that despite the relatively constant

level of total inorganic Hg available in all four (3 open water and 1 salt marshland) of the sampling sites (the four

blue bars in Figure F1) in this study, the production and concentration levels of MeHg were significantly enhanced

at the biologically active and organically rich marsh wetland site (the tallest red bar marked “marsh” in Figure F1). 

The authors concluded that “sediment geochemistry (redox, sulfide, pH, organic content, etc.) is a much more

important control on MeHg production than is the absolute total mercury concentration” (p. 266 of MarvinDiPasquale et. al., 2003, Environmental Geology, vol. 43, 260-267).

The San Francisco Bay findings add to the body of evidence showing that either adding or reducing Hg

atmospheric deposition from any coal-fired power plant would not measurably affect MeHg levels in the San

Francisco Bay ecosystems. To the contrary, MeHg levels are naturally self-limited by specific ecosystem dynamics,

water quality variables like dissolved sulfate, parameters like the population of algae and/ or zooplankton,

availability of nutrients and/or sunlight and so on.

Response: 

EPA appreciates the commenter's input to the record. For several reasons described in

the Regulatory Impact Analysis, EPA focused its analysis on recreationally caught freshwater

fish.

Comment:

Generally agreeing with EPA’s assessment, one commenter (OAR-2002-0056-5423) offers an additional

new and important model validation target for EPA’s modeling team to factor. Figure G1 (see

OAR-2002-0056-5423) shows a very important observation concerning the accumulation of MeHg in various

watershed systems. It shows a particular “MeHg accumulation paradox” in that the relative percentage of MeHg

converted from raw Hg available actually decreases as the amount of raw Hg available increases. The authors of

these important findings suggest that as the amount of raw Hg increases in a watershed system, there are actually

more bacterial operons (i.e., bacterial enzymes encoded by the Hg resistance (mer) operon) available to

significantly break down the MeHg produced, and thus explaining the observed “MeHg accumulation paradox.” 

Again, the proposed EPA’s CAMR needs to fully account for the underlying science before making costly and

ineffectual compliance rulings.

Response: 

EPA appreciates the commenter's input to the record. EPA’s ecosystem modeling is

described in detail in Chapter 3 of the Regulatory Impact Anaysis.
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Comment:

One commenter (OAR-2002-0056-5423) believed it is very important to emphasize that the best available

science suggests repeatedly that the stated assumptions in EPA’s MMaps model are likely to be wrong. Therefore,

they cannot be meaningfully applied for a realistic assessment of how a change in Hg emissions from power plants

can possibly affect concentrations of MeHg in fish.

First, Figure D1 (see OAR-2002-0056-5423) provides real data that “the physical, chemical, and

biological characteristics of the ecosystem(s)” never remained constant over time. That alone invalidates the

critical model assumption.

Figure H1 (see OAR-2002-0056-5423) offers another important target for validating the assumptions in

EPA’s MMaps model. It shows that local atmospheric deposition of Hg has negligible contribution to the annual

budget of Hg to the Lake Whatcom ecosystems, thus directly challenging EPA’s MMaps assumption that “air

deposition is the only significant source of Hg to a water body.”

No local man-made Hg “pollution” at Lake Whatcom, Bellingham, WA: Annual input of Hg from local

industrial sources is negligible

Paulson (2004) Sources of mercury in sediments, water, and fish of the Lakes of Whatcom County,

Washington, U.S. Geological Survey Scientific Investigations Report 2004-5084 (August 2004)

The author of the new Lake Whatcom study further noted:

“Concerns about mercury (Hg) contamination in Lake Whatcom, Washington, were raised in the

late 1990s after a watershed protection survey reported elevated concentrations of Hg in

smallmouth bass. The USGS ... cooperated to develop a study to review existing data and to

collect new data that would lead to a better understanding of Hg deposition to Lake Whatcom and

other lakes in Whatcom County. Of all the lakes examined, basin 1 of Lake Whatcom would

have been most affected by the Hg emissions from the chlor-alkali plant and the municipal

sewage-sludge incinerator in the City of Bellingham. The length-adjusted concentrations of Hg

in largemouth and smallmouth bass were not related to estimated deposition rates of Hg to the

lakes from local atmospheric sources. Hg concentrations in dated sediment core samples indicate

that increase in Hg sedimentation were largest during the first half of the 20th century. Increases

in Hg sedimentation were smaller after the chlor-alkali plant and the incinerators began

operating between 1964 and 1984. Analysis of sediments recently deposited in basin 1 of Lake

Whatcom, Lake Terrell, and Lake Samish indicates a decrease in Hg sedimentation.” (p. 1 of

Paulson, Sources of mercury in sediments, water, and fish of the Lakes of Whatcom County,

Washington, U.S. Geological Survey Scientific Investigations Report 2004-5084, August 2004)

Response: 

EPA appreciates the commenter's input to the record. EPA’s ecosystem modeling is

descbribed in detail in Chapter 3 of the Regulatory Impact Analysis. Also see the Technical

Support Document: Methodology Used to Generate Deposition, Fish Tissue Methylmercury

Concentrations, and Exposure for Determining Effectiveness of Utility Emission Controls in the

docket.

Comment:

One commenter (OAR-2002-0056-5423) believed that it should be fairly clear from the peer-reviewed
9-cxc

literature exhibited in comments (A) through (H) that EPA’s MMaps isn’t simply suffering from “limitations,” but

is instead terminally overwhelmed by numerous demonstrably flawed assumptions in its irrational determination to

claim a reduction of Hg emissions from U.S. power plants can or will lead to a reduction in accumulation of MeHg

in ocean or U.S. freshwater fish.

Figure I1 (see OAR-2002-0056-5423) presents for EPA’s modelers yet additional, recently published fish

Hg data sets of various sport fish species caught from 17 “areas of concern for Hg contamination” in the Canadian

Great Lakes from 1971 to 1997. The results again evidence that historical changes in Hg concentrations are not

simply to be expected from local industrial Hg emissions. In fact, the author concluded that, “Differences observed

[among different areas of concern] did not consistently parallel expectations associated with historical presence of

chlor-alkali plants in the vicinities of some locations.” More importantly, the author also noted that “An attempt to

correlate the fish tissue Hg with the frequency of occurrence of infantile cerebral palsy at AOC [areas of concern]

was unsuccessful.” Further Hg-related health issues are addressed in comments (K) through (Q) in e-docket text.

“The tissue mercury concentration in six species of fish collected at the 17 Areas of Concern [AOC] were

analyzed. A linear increase in Hg concentration with fish length was found, but slopes differed among locations. 

The temporal pattern over the period 1971-1997 differed across species in fish collected in Lake St. Clair; in at

least two species there was evidence of increased Hg concentration during the 1990s that had been suggested in an

earlier analysis. AOC differed significantly in observed tissue concentrations. Differences observed did not

consistently parallel expectations associated with historical presence of chlor-alkali plants in the vicinities of some

locations. An attempt to correlate the fish tissue Hg with the frequency of occurrence of infantile cerebral palsy at

AOC was unsuccessful.”

Response: 

EPA appreciates the commenter's input to the record. The limitations and

aplication of Mercury Maps is described in detail in the RIA and Technical Support Document: 

Methodology Used to Generate Deposition, Fish Tissue Methylmercury Concentrations, and

Exposure for Determining Effectiveness of Utility Emission Controls in the docket.

Comment:

One commenter (OAR-2002-0056-5423) notes that this partial admission on the highly limited use of

MMaps by EPA goes a long way toward illustrating the commenter’s concerns regarding the scientifically

questionable direction of EPA’s modeling effort. Figure J1 (see OAR-2002-0056-5423) confirms that the top 15

fish and sea foods consumed in the U.S., representing about 90 percent of the U.S. commercial market, is

accounted for by marine and farm-raised species. (According to UN statistics, domestic fresh water fish may

account for as little as 0.05 percent of total U.S. consumption.) This alone renders EPA’s MMaps modeling results

on MeHg levels in freshwater fish almost irrelevant or largely insignificant.

Considering the insignificant Hg emissions from U.S. coal-fired power plants (i.e., less than 1 percent of

annual global emissions budget) and the millions of tons of natural Hg available in world oceans from deep

venting, it is clear that there will be no detectable change in trace MeHg in oceanic fish even if EPA were to

impose zero emission standards for all U.S. Hg sources. Evidence provided in comment (E) (i.e., Figures El, E2

and E4, see OAR-2002-0056-5423) alone should be adequate for our hypothesis. (If trace levels of MeHg did not

increase in a wide variety of fish along with rapidly growing worldwide anthropogenic emissions (See figure E3),

what rationale is there that fish MeHg levels would drop in response to falling U.S. emissions?) Meanwhile, the

strictest burden of proof for EPA rule making demands a clear demonstration (not invalid modeling assumptions)

that its CAMR rulings can deliver a clear and meaningful reduction in MeHg in world ocean fish. Seafood

Consumed in the U.S. Accounts for 90 percent of the Commercial Market. Source: Carrington and Bolger (2002)

Risk Analysis, vol. 22,689-699 + updates in Carrington and Bolger (2003) ‘s Intervention Analysis Draft Report.
9-cxci

Response: 

EPA appreciates the commenter's input to the record. The limitations and aplication of Mercury

Maps is described in detail in the RIA and Technical Support Document: Methodology Used to

Generate Deposition, Fish Tissue Methylmercury Concentrations, and Exposure for Determining

Effectiveness of Utility Emission Controls in the docket.

Comment:

Using a global model such as the GEOS-CHEM model to provide the boundary conditions for a

continental model (REM SAD or CMAQ) is a more scientifically sound approach than prescribing those regional

boundary conditions. It is necessary to conduct a performance evaluation of the global model to ensure that the

boundary conditions provided to the continental model are realistic. It is also desirable to have a consistent

formulation of the physical and chemical processes governing the Hg species concentrations in both the global and

continental models.

Response:

EPA appreciates the commenter's input to the record. For discussion of the air quality

modeling, please see chapter 8 of the RIA and EPA’s Technical Support Document for the Final

Clean Air Mercury Rule: Air Quality Modeling .

Comment:

One commenter (OAR-2002-0056-5535) presented several specific issues that would benefit from such

careful peer review. They did not intend this list to be comprehensive, but merely included it to illustrate that the

agency must address critical scientific issues prior to making changes to its deposition and watershed models or

conducting other components of the proposed analyses. This overview serves to demonstrate that it would be

foolish to hold up final Hg regulations while EPA further investigates certain technical issues concerning the

emissions, fate, and toxicity of Hg from power plants.

Atmospheric Hg reactions. Another problem with EPRI’s global Hg model is the incorporation of

atmospheric Hg reactions that are very uncertain. In particular, the incorporation and effect of Hg reduction

reactions needs investigation. It is also unclear whether the EPRI or EPA models fully account for the many

conversion processes that can occur in the atmosphere or the conversion/uptake of Hg by the forest canopy. Both

of these processes would increase local deposition. Specifically, it is now well-documented that elemental Hg is

converted to oxidized Hg in the presence of ozone and chloride. This is particularly important along the eastern

seaboard where both ozone and sea salt are high.

Community Multiscale Air Quality (CMAQ) model. The commenter understood that EPA has been

developing CMAQ over a number of years as a potential replacement for REMSAD. However, the commenter

stated that the CMAQ is not yet in the public domain and has not been externally peer-reviewed to the extent it

must be prior to its adoption by EPA.

Response

EPA appreciates the commenter's input to the record. For discussion of the air quality

modeling, please see chapter 8 of the RIA and EPA’s Technical Support Document for the Final

Clean Air Mercury Rule: Air Quality Modeling .

Comment:

One commenter (OAR-2002-0056-5423) agrees with EPA’s call for increased understanding about how
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dry Hg deposition adds to the total ecosystem deposition. Figure D1 shows a new set of Hg deposition data

obtained from sedimentary cores representative of the past 11,000 years in Elk Lake in Minnesota. These data

might serve as an important benchmark in wet and dry depositions under a very wide range of meteorological and

climatic conditions as well as a variety of Hg sources (for example, Hg-enriched dusts and sands from nearby

Nebraska sand hills or Hg from local and regional forest fires) for EPA’s REMSAD and CMAQ models to

demonstrate both the correctness and robustness of their atmospheric transport, chemistry and deposition modules. 

Measurements of Hg over the past 11,000 years in Elk Lake, MN show that today’s Hg level is neither exceptional

nor alarming.

Response: 

EPA appreciates the commenter's input to the record. For discussion of the air quality

modeling, please see chapter 8 of the RIA and EPA’s Technical Support Document for the Final

Clean Air Mercury Rule: Air Quality Modeling . Please see Chapter 3 of the CAMR Regulatory

Impact Analysis for a detailed discussion of mercury in the environment, including an

assessment of the response time for systems after a change in mercury deposition. 

Comment:

One commenter (OAR-2002-0056-5497) noted that EPA was the major co-funder of a technical workshop

on Mercury Monitoring and Assessment held in Pensacola, Florida, on September 14-17,2003. The Workshop was

also co-funded by EPRI and sponsored by the Society of Environmental Toxicology and Chemistry (SETAC). 

Participants included 32 Hg scientists from academia, industry, government, and nonprofit organizations. The

purpose of the workshop was to identify a variety of environmental and ecological indicators to assess trends due to

changes in Hg emissions and fluxes to the environment. Participants at the workshop were also charged with the

preliminary development of a network of monitoring stations with emphasis on North America in order to evaluate

the effects of Hg regulatory actions being implemented by Canada and the U.S.

Two products from this workshop will be published in 2005. A paper, Monitoring the Environmental

Response to Changing Atmospheric Mercury Deposition (Mason et. al., in press), is scheduled for publication in

Environmental Science and Technology in its January issue. In addition, a book, Mercury Monitoring and

Assessment (Newman et. al., in preparation), will be published by SET AC Publications later this year. This

major, EPA-initiated effort is not mentioned in EPA’s proposed revised benefits assessment. Since the direct

monitoring of Hg impacts on human, wildlife, and ecosystem health would provide the most irrefutable evidence of

the success (or lack of success) of EPA’s regulatory strategy, this initiative should be given a primary role in EPA’s

benefits assessment.

The Relationship of Reductions in Air Deposition of Mercury to Methylmercury in Fish Tissue

EPA’s benefits analysis requires that it quantify how a reduction in Hg emissions to the air translates into

reductions of MeHg in fish tissue. The most important thing for EPA to recognize is that a reduction in air

emissions of Hg cannot be expected to result in a reduction in fish tissue Hg in a manner that is predictable by a

generally applicable rule–whether linear, sub-linear, or time-dependent. The entire array of physical, chemical,

and biological processes that influence the conversion of elemental Hg in the air to MeHg in fish tissue is complex. 

Moreover, the relative importance of these factors differs on a site-specific basis.

EPA proposes to use a steady state source-receptor model (Mercury Maps or

MMaps) as a tool to predict the biological responses (changes in Hg content) to

reductions in emissions of Hg from coal-fired utility boilers. As explained in more detail below, Mercury Maps

should only be used as a preliminary screening tool whose results must be ground-truthed by subsequent, more

definitive investigations.
9-cxciii

Additionally, any screening tool must recognize that only Hg deposited directly to a water body (or

flowing overland without reacting with soil) is readily and quickly incorporated into biota. Mercury deposition to

uplands does not readily migrate to waterbodies but instead becomes incorporated into the humic matter of soil. 

While some very small amount of this Hg in soil may eventually leach to a water body, such a process occurs over

decades, so that any newly deposited Hg has an insignificant effect on the total amount of Hg that has already

accumulated in soil over thousands of years. Any modeling process that EPA uses must treat deposition directly to

the lake surface differently from deposition to the surrounding

uplands.

The Florida Mercury Report Does Not Demonstrate that Changes in Air Emissions Result in Rapid Changes

in Fish Tissue Mercury

EPA should not give undue weight to a study in Florida that shows large reductions in fish tissue Hg in

the aftermath of reductions in air emissions. For one thing, the Everglades, where this study was conducted, are a

unique ecosystem, and results from the Everglades cannot be extrapolated to other locales.

In November 2003, the Florida Department of Environmental Protection combined two earlier Hg reports

into a single document that the commenter will call the “Florida Study”. This report has been widely publicized

and widely misinterpreted. It does not show that reductions in air deposition will rapidly be followed by reductions

in fish tissue Hg, and certainly not outside the unique environment of the Everglades.

Analyses of the Florida Study by EPRI reveal the following important facts:

• The Hg emissions released by municipal and medical waste incinerators are different from those released

by power plants.

• There are two major forms of Hg in emissions–oxidized (ionic), which is water soluble, and

elemental, which is not water soluble.

• Most incinerator Hg is in the water-soluble form, whereas the form of Hg released from power

plants depends upon many factors such as the type of coal being burned. Recent research has

shown that most of the Hg released by utilities (at least 60 percent) is the non-water-soluble

elemental form and that a significant amount of the remainder converts to this non-soluble form

shortly after leaving the stack.

• The form of Hg emitted is critical, because oxidized Hg can be washed into local rivers, lakes,

and streams by rainfall, whereas elemental Hg is carried away by wind and enters the global Hg

cycle.

• The Florida Everglades Study represents a unique ecological system not typical of, and in fact strikingly

different from, other US waterways. Thus, the results from this study are not necessarily applicable to

other areas.

• The Everglades are in a tropical zone (no seasons), the water is shallow, and the bottom

sediments are much different from those in other water bodies throughout, the U.S. Other

waterways also have different levels of acidity, biological activity” dissolved oxygen, and

turbidity. These differences can dramatically affect Hg cycling and uptake by biological

organisms. Thus, it is unlikely that the changes in Hg in fish, both the amount and the rate of

decline, would be observed in other U.S. waters.

• The claim that changes in Hg emissions result in rapid changes in fish Hg content is not supported by the

data or findings.
9-cxciv

• The Florida Study assumes that Hg deposition in the Everglades originates only from local

sources (primarily incinerators and power plants). However, data measurements and long-range

transport modeling indicate otherwise.

• In fact, despite decreases in Hg emissions from incinerators, no deposition data exist spanning

the reduction period, and other regional and global changes were occurring during the same

period. Therefore, it is not possible to determine how much, if any, the amount of Hg being

deposited in the Everglades has changed.

• Indeed, both EPA and EPRI have modeled Hg transport and concluded that over 60 percent of Hg

currently deposited in Florida originates outside the U.S. Guentzel et al. (200 I) hypothesized

that long-range (global) transport of reactive gaseous Hg (RGM), coupled with strong

thunderstorm activity during summer months, represents > 50 percent of the Hg deposition in

southern Florida.58 The authors highlight the importance of non-atmospheric loading factors and

global sources of Hg:

• The contrast between uniform Hg deposition and geographical “hot spots” in fish Hg concentrations from

the Everglades region further suggests that aquatic/terrestrial Hg cycling processes, rather than

atmospheric source strength, are responsible for the hot spots... .From our analysis of the data, we

conclude that significant reduction in rainfall Hg deposition over the Florida Everglades will likely

require reductions in local and global Hg emissions.

• In addition, not all the change in fish Hg content can be attributed to the unknown change in

deposition because other factors that mediate the ecosystem response to Hg load have also

changed. Several theories have been suggested involving changing nutrient levels and water

flows in the Everglades. Further research is needed to understand this situation.

• The atmospheric transport model used by the State of Florida to estimate Hg deposition has limitations.

• The model does not incorporate chemical reactions in the atmosphere. It also does not include

global sources of Hg, only local emissions. Thus, it cannot effectively simulate the actual Hg

deposition.

• EPRI’s recent research findings indicate that power plant Hg controls would not significantly change the

amount of Hg contained in fish, or the human exposure to it.

• In early 2003, EPRI completed a comprehensive study of U.S. power plant Hg emissions,

potential Hg controls, and responses of fish to changes in Hg in their habitat waters. The results

showed that reducing Hg emissions from power plants by approximately 50 percent would result

in a reduction of Hg in fish of about 11⁄2 percent. This study, combining atmospheric data and

models, fish consumption information from U.S. government studies, and an economic model of

the U.S. utility industry, relies on more recent information than the two-year-old Florida study

report released on November 6, 2003.

The Steady-State Linear Relationship Between Air Deposition and Methylmercury Concentrations

in Fish as Reflected in the Mercury Maps Model Is Not Generally Appropriate

EPA requests comment on the use of the steady-state linear relationship between air deposition and MeHg

concentrations in fish, as reflected in the MMaps model. The MMaps model was developed by EPA’s Office of

Water to assess what levels of reduction in Hg deposition would be needed to achieve the fish Hg criterion of 0.3

ppm. It was intended to apply only to watersheds where the principle source of Hg is atmospheric deposition and

where there is no known land-based source of Hg discharge into the waterways.
9-cxcv

The MMaps model is simplified compared to other models and for that reason can be applied over a

broader geographic scale. But it has limitations, among which are the following:

• The model uses the arithmetic average of all fish Hg data in each Hydrologic Unit Code (HUC) watershed. 

This averaging may blur the substantial differences in water chemistry and fish Hg, both spatially and

temporally, that are known to exist within a single watershed. An alternative approach may be to

associate the fish Hg level with both the deposition loads as well as other relevant water chemistry

parameters (pH; nutrient levels; extent of anoxia in waterbody; water temperature; etc.). This may

provide a better prediction of the responses in specific waterbodies as opposed to making a prediction of

the fish Hg response for an entire HUC watershed. Further, the analysis should be confined to a particular

species of fish, preferably with a similar size or weight range.

• The output of MMaps is highly dependent on the extent of state-specific fish tissue data records. For

states that have a relatively long record offish Hg levels from a variety of water body types, the accuracy of

the true existing Hg levels is relatively high. For states that have monitored Hg levels in fish only

recently, or sporadically, the comparison of “average” HUC fish tissue Hg to EPA’s MeHg fish tissue

criterion incorporates high uncertainty. EPA’s summary of state fish tissue monitoring data for 1990-95

indicates considerable state-to-state variation in the number of water bodies sampled, the number of total

collections, the species sampled for, the number of fish analyzed, and the frequency of monitoring. The

report also indicates the distribution of species sampled for Hg levels. Two sport fish species (largemouth

bass and channel catfish) were sampled more extensively than any other species. Only two states (Kansas

and Washington State) do not report Hg levels for largemouth bass. EPA should consider standardizing

MMaps by using Hg analysis data for two species only: largemouth bass and channel catfish. A

standardization of fish length or age would further increase the accuracy of what watersheds actually may

have fish that exceed the human health fish tissue criterion.

• The EPA report uses the modeling results from the Everglades TMDL to help corroborate the assumption

of a linear response. However, there are two concerns, as noted above. First, the Everglades TMDL

assumed all the fish changes were caused by local emission changes and did not consider other regional

and global changes or any local ecosystem changes that would mediate that assumption. Thus, the actual

reduction in fish Hg due to atmospheric deposition reduction in the U.S. would be less than predicted by

Mmaps if the simulated changes in Hg deposition from changes in U.S. emissions do not account for

global sources. Second, the intercept was considered by the TMDL researchers to be due to the fact that

sediment Hg is recycled to the water column by macrophyte roots. The redistribution of Hg from

sediments may be an important source to the water column in some waterbodies. Matty and Long found

that, in the Great Lakes, the most important processes influencing levels of Hg in sediments (decay of

organic matter, iron and manganese redox cycling, exchange of Hg from porewater to sediments) would

result in the long-term retention of Hg near the sediment-water interface. This Hg would be available for

assimilation by benthic organisms. This source (legacy sediment Hg) would not be influenced by cutbacks

in atmospheric deposition. The TMDL report also stated that the intercept is partly a function of the

length of simulation time–the longer the time, the smaller the intercept.

• The assumptions that are critical in causing the model to exhibit a linear response to air deposition were

discussed in the Everglades TMDL report but were not discussed in the EPA report. These assumptions

include:

• Methylation was allowed to occur only in sediment, based on porewater Hg(II) concentration. 

Large stratified reservoirs and lakes with anoxic zones can have methylation in the water

column. Thus, the Everglades system is not representative of all types of waterbodies.

• Geochemical factors that could influence the Hg(II) concentration in the porewater such as

cinnabar formation were not included. If such factors are controlling the Hg(II) concentration,
9-cxcvi

then a reduction in deposition load may not cause a linear change in Hg(II) concentration.

• Methylation/demethylation rates were limited only by Hg substrates. Other factors such as

carbon supply are important and can influence the rates. Watras et. al., studied 15 lakes in

northern Wisconsin, and found relatively low concentrations of sediment MeHg. The authors

suggested that a high rate of demethylation accounted for this observation. Based on recent work

by Marvin DiPasquale et. al. (2000), demethylation rates become nonlinear at high

concentrations of Hg. This latter possibility was not considered in the Everglades TMDL,

although it may be less important in that system than in waterbodies with natural elevated Hg.

• The model is based on a uniform linkage between atmospheric deposition of Hg and the amount that

reaches a waterbody for eventual uptake by fish. This type of analysis does not consider the effect of

varying retention based on different types of land uses and the effect of canopy type on dry deposition. 

The actual response to the same decrease in atmospheric load would vary across watersheds because the

proportion of the load reaching the waterbody would not be the same.

• The apparent linear response of fish to decreases in atmospheric loading does not seem compatible with a

hypothesis of differing methylation efficiency in waterbodies. Other factors such as temperature are

important in controlling fish metabolism, which then influences the response of fish to a given MeHg

concentration. A more detailed comparison of fish data with wide geographic coverage to the Hg

deposition data may reveal that the response is not as linear as thought.

• Variability in the fish data could be used to derive an estimate of the uncertainty in fish response to any l

ad .cutbacks. The assessment of variability in an explicit form. allows policy makers to determine

whether small changes in fish tissue Hg as a result of changing deposition loads will be masked by the

inherent variability of the data and so may be unmeasurable or even indiscernible. Due to multiple factors

such as fish species, age, size, and changes in diet during their lifetime, fish data for a given waterbody

are extremely variable.

• The fish data set could be extended to include other available data, particularly to close the data gap in

several of the western states, where no geo-referenced fish data were presented in Mercury Maps.

• EPA acknowledges the need for higher resolution modeling in order for predictions of fish Hg changes to

have some accuracy:

• Estimates of percent air deposition reductions, by watershed, as generated from a regional air deposition

model, would be needed to predict fish concentration changes.

In summary, the commenter believed that the scientific knowledge of Hg source and receptor processes

should compel EPA to use MMaps as a preliminary screening tool only, subject to verification by watershedspecific information. All in all, the key assumptions of MMaps (all Hg from atmospheric sources and equilibrium

conditions for Hg levels in fish and other compartments) make the predictive analysis highly sensitive to variable

watershed processes, physical and chemical factors affecting methylation, and biological interactions. All of these

factors are known to control, or influence, Hg cycling and bioavailability.

An Evaluation of the EPA’s Assumed Linear Relationship Between Changes in Atmospheric Emissions and

Resulting Fish Tissue Mercury Concentrations-The Great Lakes

The commenter stated that there is a considerable amount of information on Hg sources to the Great

Lakes, as well as Hg deposition, rates of sediment accumulation, and measured levels in Great Lakes fish. Using

this information, one can evaluate the key assumptions of the linear source-receptor response by comparing the

long-term (and new) information on the Hg in the Great Lakes, against the predictions inherent in the linear
9-cxcvii

model.

1. Sources of Hg and deposition to the Great Lakes

Cohen et. al., modeled the total annual deposition of Hg to the Great Lakes, and the relative contributions by

specific sources (industry sector, U.S. vs. Canadian sources). They estimated that the annual atmospheric

deposition of Hg to Lake Michigan was highest (750 kg/yr), followed by Lakes Superior, Erie, and Huron (425-490

kg/yr), and Lake Ontario (220 kg/yr); however, current and historic additions of Hg are much greater than

atmospheric deposition in the case of Lake Superior. In an earlier publication, Shannon and Voldner reported

estimates of annual deposition to the Great Lakes. Lake Erie and Lake Michigan had the highest estimated

deposition (728 1,012 kg/yr), followed by Lake Superior. Lake Ontario had the lowest estimated annual deposition

(297 kg/yr). Interestingly, the authors also found that the estimated annual rate of Hg volatilization from all lakes

(2.3-13.7 t/yr) was within the range of total Hg loading to all lakes (4.7 t/yr).

2. Sediment Hg levels in the Great Lakes

In a recent publication, Marvin et. al., reported on long-term sediment Hg levels in the Great Lakes. 

Based on the most recent surveys, Lake Huron had the lowest sediment Hg levels. The western basin of Lake Erie

had the second highest sediment Hg levels, while Lake Ontario had the highest levels. These Hg level patterns

would not be expected based on total atmospheric load (deposition) estimates. If annual deposition of Hg alone

dictated sediment Hg, the highest Hg levels would be expected in Lake Michigan, while the lowest sediment Hg

levels would be expected in Lake Ontario. The authors, however, clearly pointed out the differences in Hg sources

to each of the Great Lakes. While estimates indicate Lake Superior receives most of the external Hg loading from

atmospheric sources, the relatively high sediment Hg levels in Lake Ontario are due to localized (major urban)

sources, and Hg loads coming from the Niagra River. Clearly, for the Great Lakes, Hg deposition information

alone cannot be used to predict resulting comparative sediment levels. The authors indicate that sediment Hg

levels have declined drastically across the Great Lakes since the 1960s: lakewide decreases in mean sediment levels

ranged from 25 percent (Lake Ontario) to 80 percent (Lake Huron).

3. Mercury levels in Great Lakes fish

If EPA’s linear source-receptor response assumption were valid, then one would expect that Hg levels in

Great Lakes fish would mirror comparative deposition rates, when compared across identical species and age

classes. The Canadian Department of Fisheries and Oceans summarized information on long-term Hg level trends

for two species sampled in all of the Great Lakes: rainbow smelt and lake trout. Mean concentrations for the years

1977-1995 were presented. The lowest Hg levels are found in lake trout from Lake Erie–(average concentration

during 1990-1995 (0.6 ppm); lake trout from Lake Ontario had the second lowest mean concentration (0.8-0.9

ppm), and lake trout from Lakes Superior and Huron had the highest mean Hg levels (1.2-1.3 ppm). For smelt,

once again Lake Erie samples contained the least amount of Hg (0.2 ppm), Lake Ontario samples had the second

highest level (0.21-0.25 ppm), and Lakes Huron and Superior fish samples had the highest Hg levels (0.4 and 0.55

ppm, respectively). Long-term Hg concentration data for two sentinel fish species in the Great Lakes indicate, like

sediment data, that atmospheric deposition information alone provides no useful information for resulting levels of

Hg in lake biotic and abiotic compartments.

Factors Affecting Methylation

The factors affecting methylation of Hg were summarized in a 2003 report entitled “Implementation of

EPA’s Methylmercury Criterion for Fish Tissue,” by AMEC Earth and Environmental and ENVIRON with

support from the EPRI.

Formation of MeHg in aquatic systems is influenced by a number of environmental factors. While the

microbial activity and the concentration of bioavailable Hg primarily determine methylation rates, parameters such
9-cxcviii

as temperature, pH, redox potential, and the presence of inorganic and organic complexing agents playa complex,

yet poorly understood, role in the methylation process. The following is a list of some technical publications that

indicate the most important factors controlling Hg mobility and bioavailability:

Microbial Activity: It generally is believed that anaerobic sulfate-reducing bacteria are the principal

methylators of inorganic Hg in both freshwater and estuarine environments (e.g., Gilmour et. al., 1992). Recent

studies also indicate that these same bacteria also are capable of mediating MeHg degradation. Not all sulfatereducing bacteria are capable of Hg methylation, and methylation rates are not always correlated with sulfate

concentration or with sulfate-reduction rates. The efficiency of microbial MeHg production appears to depend

chiefly on the activity and structure of the bacterial community, bioavailable Hg concentration, and the availability

of nutrients and electron acceptors such as sulfate (Choi and Bartha 1994). According to Compeau and Bartha

(1985), the methylation potential of sulfate-reducing bacteria is greatest in sulfate-limiting environments, but at

high sulfate concentrations, sulfide produced in respiration may inhibit methylation through the formation of HgS

precipitates or charged Hg-S complexes that are not readily bioavailable.

Sulfide: Several studies have reported that high sulfide concentrations inhibit MeHg formation, and an

inverse relationship between sulfide concentration and MeHg production in sediments and pore waters also has

been observed. On the other hand, increased MeHg production also has been observed under certain sulfide

concentrations (e.g., Craig and Moreton 1983). This suggests that, while high concentrations of sulfide can greatly

reduce MeHg production, methylation is not usually completely inhibited (Ullrich et. at., 2001). It is generally

believed that the inhibitory effect of sulfide on methylation is due to the formation of insoluble HgS precipitates

that are not bioavailable. However, high concentrations of dissolved Hg observed in sulfidic porewaters suggests

that sulfide may actually help mobilize Hg through the formation of soluble Hg-sulfide complexes. Sulfide may

also affect methylation through the formation of neutral HgS0

 species that can diffuse readily through cell

membranes (Benoit et. al., 1999). On the other hand, formation of charged polysulfide complexes actually can

decrease bioavailability, but its effect on methylation is not clear. As the primary pathway for methylation is by

sulfate-reducing bacteria, more research is needed to identify the role of various sulfur species and other

parameters on MeHg formation.

Temperature: Several studies have indicated that maximum methylation activity occurs during mid- or

late summer (e.g., Watras et. al., 1995). Other studies have found higher MeHg concentrations in spring than in

summer. While increased temperature can contribute to increased microbial activity, it also affects seasonal

changes in productivity/nutrient supply, redox conditions, and demethylation rates.

pH: There has been concern that low pH values may lead to increases in the production and/or

bioaccumulation of MeHg because elevated Hg levels have been observed from fish in acidified lakes. Enhanced

methylation has been observed in low-pH waters and sediments; however, this process is dependent on the redox

state of the system (in anaerobic systems, acidic pH lowers MeHg production) and other factors. pH may indirectly

affect methylation by altering the mobility and partitioning of Hg and MeHg in soils, stimulating MeHg production

through the addition of sulfate (in acid rain) and by changing microbial activity (particularly the 49 sulfatereducing species) or cellular uptake of Hg+2. Changes in pH also can alter Hg speciation (e.g., enhanced

production of elemental Hg, altering the binding of Hg to organic matter and other ligands), which in turn can

affect the amount of ionic Hg available for microbial methylation. Demethylation rates are also pH-sensitive, albeit

to a lesser extent than methylation rates.

Organic Matter: The role of organic matter in methylation also is very complex and poorly understood. 

Observed increases in MeHg concentrations with higher dissolved organic carbon (DOC) concentrations have been

attributed to a stimulating effect of organic nutrients on microbial methylation activity (i.e., microbes utilizing

organic matter as energy source when sulfate is limiting). Direct abiotic methylation of Hg by humic and fulvic

acids (the refractory portions of dissolved organic matter) also could be very important, particularly in wetlands

where high generation of MeHg has been observed. This mechanism largely has been ignored and, to date, it is

not clear to what extent abiotic methylation contributes to MeHg production in organic-rich sediments and lake
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waters. It may be hypothesized that where organic matter is labile and readily biodegradable, it may promote

methylation by stimulating microbial growth, and where the organic matter is recalcitrant and consists of highmolecular-weight humic and fulvic acids, it may contribute to abiotic methylation.

Decreased methylation has also been observed at high concentrations of organic matter in both natural

systems and experimental studies, and it has been suggested that DOC may strongly bind with inorganic Hg at

sulfur-containing functional groups, rendering them unavailable for bacterial methylation. Even if MeHg forms, it

may be complexed by DOC and, therefore, not available for bioaccumulation. DOC also can compete with sulfide

for Hg binding and favor the mobilization of Hg through the formation of Hg-DOC complexes. In Hg binding with

DOC, pH may play an important role where protons compete with metal binding sites in organic matter. Humic

substances, which are recalcitrant, high-molecular-weight fractions of organic matter, also can reduce Hg+2 to the

volatile Hg0

 species, both directly as well as by enhancing the reduction rates in photochemical reactions, thus

reducing the Hg burden available for methylation.

Redox Conditions: Even though Hg methylation occurs in both aerobic and anaerobic conditions in the

natural environment, methylation rates are highest in anoxic sediments and waters, and the stability of MeHg is

greatest in anaerobic environments. This may be due to the reduced activity of sulfate-reducing bacteria under

aerobic conditions and the enhanced degradation of MeHg in aerobic conditions. It appears that anaerobic

methylation is predominantly microbial in nature and, therefore, enhanced by the presence of organic matter;

whereas abiotic methylation is favored under aerobic conditions and is suppressed by the presence of organic

matter (possibly due to complexation with organic matter rendering Hg unavailable for methylation). 

Methylmercury concentrations usually are highest in the moderately anaerobic surface sediments (mostly at the

oxic-anoxic interface) and rapidly decline with depth. Likewise, in stratified lakes and estuaries, MeHg

concentrations are usually highest at the oxic/anoxic boundary layer. Changes in redox conditions in water column

and sediment layers also result in seasonal variations in MeHg concentrations. Organic matter, nutrients, pH, and

sulfides significantly influence the redox effects on MeHg production.

Salinity: The methylating activity in marine and estuarine sediments is usually lower than in freshwater

sediments, partly due to salinity effects. The negative effect appears to be a result of formation of charged sulfide

complexes (from sulfate in sea salt) in seawater and charged Hg-chloride complexes such as HgCl4

-2 that limit the

methylation process. Thus, estuarine fish tend to have lower MeHg in their tissue than comparable species in

freshwater fish (Gilmour and Riedel 2000).

In summary, Hg methylation is primarily a microbially mediated process, and the precise mechanism of

MeHg formation still is unclear. Mercury methylation and demethylation rates in aquatic systems are influenced

by both the speciation and biochemical availability of Hg and by a large number of interrelated environmental

variables, such as biological activity, nutrient availability, pH, temperature, redox potential, and inorganic and

organic complexing agents. The importance of each of these parameters and their complex interactions varies

across different ecosystems and even within the same type of water bodies. Different mechanisms of methylation

may occur in sediments and in water. Seasonal variations in MeHg production appear to be related to temperature,

redox effects, seasonal changes in nutrient availability and Hg availability. Sulfur speciation and dissolved organic

matter complexation are other important factors that are not well understood.

Knowledge Gaps

Despite the vast body of literature on the subject (348 publications cited in Ullrich et. al., 2001), we still

are unable to predict Hg methylation rates or the likely effects of environmental perturbations on methylation

processes in natural systems due to the complexity of the systems described above. Since laboratory studies look at

simple systems with few variables at a time, it also is difficult to directly compare the results of the laboratory

studies published to date with the processes and rates in the natural environment. Knowledge gaps exist in the

following areas:
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Biotic vs. Abiotic Methylation: While it widely is believed that Hg methylation is biologically mediated,

review of literature by Ullrich et. al. (2001) suggests that there may be more than one mechanism of MeHg

formation. Abiotic methylation, particularly that mediated by humic substances, could be very important in

wetlands and other ecosystems, but the significance of such processes in natural environments is unknown. 

Methylation vs. Demethylation: A portion of MeHg generated is demethylated by microorganisms, photochemical

reactions, and other processes. Sulfate-reducing bacteria, which were considered to be important methylating

agents, also now are considered to be active demethylators. It is not clear what environmental conditions cause

these microbes to carry out methylation instead of demethylation.

Biomethylation: Review of the literature suggests that methylation can be caused by sulfate-reducing

bacteria as well as a number of other types of bacteria that have not yet been identified. In the case of methylation

by sulfate-reducing bacteria, the optimum sulfate concentrations required for methylation vary widely between

different ecosystems and are difficult to predict. For example, bacteria in estuarine systems can methylate Hg at

much higher sulfate concentrations than in freshwater systems. In addition, since bacteria that methylate Hg also

are capable of demethylating, we are unable to predict biomethylation rates in natural systems.

Role of Organic Matter: Natural organic matter in soils, sediments, and water affect methylation in

several ways. While natural organic matter can provide a stimulating effect on bacterial methylation in some

systems, it may promote abiotic methylation in other systems or inhibit Hg methylation (due to strong

complexation) under other environmental conditions. The exact role of organic matter in a given system often is

ignored in predicting methylation rates. Because of the complex structure and composition of organic matter and

due to the paucity of thermodynamic data for organic matter–Hg complexes, the role of organic matter on the

speciation and bioavailability of Hg has not been well described or modeled.

Sulfur Chemistry: Sulfur speciation is an important variable in the methylation process. In addition to the

role of sulfate on the methylation process, reduced sulfur can complex with Hg and form charged or uncharged Hgsulfide complexes determining whether or not Hg becomes available to the microbes for methylation. Various

stoichiometries of Hg-sulfide complexes have only been speculated, and competitive reactions between sulfide,

organic matter, and Hg are not well defined.

Synergistic and Antagonistic Effects: From previous discussions it is apparent that each of the variables

discussed above have multiple influences on the methylation and demethylation process. For example, low

concentrations of sulfate can limit microbial methylation, while high concentrations of sulfate can result in the

formation of excess sulfide concentrations that complex with Hg and inhibit Hg methylation. Some of the above

parameters can alter the effect of other influencing factors on Hg methylation. For example, pH and redox can

directly affect methylation and bioaccumulation as well as altering Hg speciation, sulfur chemistry, and microbial

activity. Due to the complex role of anyone of the above parameters on methylation, it is difficult to predict their

combined effect in natural systems with existing models. There are many factors affecting methylation, but the

current science is not adequate to resolve which factors are most important and allow models to move towards a

more predictive capability. Research into factors affecting methylation is ongoing, however, with significant

progress expected over the next several years.

METAALICUS Project: Some of the questions on the rates and factors governing Hg methylation may be

answered by the Mercury Experiment to Assess Atmospheric Loading in Canada and the U.S. (METAALICUS)

project currently underway at the Experimental Lakes Area (ELA) in western Ontario, Canada (Harris et. al.,

2001). METAALICUS is a multi-disciplinary whole-ecosystem experiment in which a different isotope of Hg in

the inorganic form (Hg(II)) is added to the upland, the wetland, and the lake surface to determine the relationship

between atmospheric Hg loading and fish Hg concentrations. One of the goals is to determine how much of the

newly deposited atmospheric Hg becomes bioavailable for methylation and biological uptake.

Implications of Knowledge Gaps
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Any efforts to reduce MeHg concentration in fish tissue require a clear understanding of the processes that

produce MeHg and factors that promote demethylation. Methylmercury production in aquatic systems is not a

simple function of total Hg concentration in the system. Rather, as discussed above, it is affected by a number of

complex, interrelated factors, which may result in a nonlinear relationship between total Hg and MeHg. Since any

or all of these (or other) parameters can control methylation, either alone or in a complex interrelated process,

ecosystems respond differently to changes in these parameters and, at present, there is no simple way to predict

methylation rates in natural environments. In the Florida Everglades, for example, contrary to conventional

wisdom, the percentage MeHg increases from north to south, opposite the gradients in nutrient, sulfate, and sulfide

concentrations (Gilmour et. al., 1998). Regulatory measures, such as reducing Hg loading rates from atmospheric

or point sources, will be less successful in reducing Hg levels in fish without greater understanding of these

complex processes.

Marine and Farm-Raised Species

Because MMaps is designed to simulate natural freshwater systems, EPA does not have an appropriate

method for assessing how a change in Hg deposition relates to a change in MeHg in fish tissue found in marine

environments or farm-raised species.

Time Lag

In the NODA, EPA points out that MMaps does not account for the time lag between reducing Hg

deposition and reducing MeHg concentrations in fish. In METAALICUS, newly deposited Hg appeared to be

more available to bacteria to convert to MeHg than Hg that was in the system for longer periods of time

(historically deposited Hg). EPA also observes that systems that receive most of their Hg input directly from the

atmosphere may respond more rapidly to changes in emissions than those receiving significant inputs of Hg from

the catchment area. EPA asks for information that can be used to extend or extrapolate the results of the

METAALICUS experiment to other freshwater systems and information on Hg cycling and bioavailability in

coastal and marine ecosystems.

The findings of the METAALICUS study, as reported in the scientific literature, are valuable because they

provide empirical information on the relative importance of Hg sources to Hg cycling in the study lake (UIF). It

should be noted, however, that the principal researchers have acknowledged that caution be used when

extrapolating the METAALICUS results to other watersheds. Hintelmann et. al. (2002) state that: 

This conclusion [importance of newly deposited mercury to lake cycling and little runoff from the

catchment area] is so far limited to terrestrial upland systems such as U1F. Further

METAALICUS studies are underway investigating similar processes in wetlands and aquatic

(lake) systems, keeping in mind that lakes receive mercury via direct atmospheric deposition as

well as runoff. . . the overall contributions of old versus new mercury to mercury in runoff and

the overall response time of watersheds to changes in atmospheric mercury deposition will most

likely depend on the balance of wet and dry deposition as well as the fraction of rain events that

are large enough to cause significant immediate runoff of newly deposited mercury.

While the METAALICUS study suggests a relatively short time lag between rates of Hg addition and lake

compartment assimilation, the time lag of such a response will likely be unique to each watershed, and each water

body within a watershed. This is because the factors that control the mass loading and mobilization of Hg to water

bodies are unique.

Also, the quick response time observed in METAALICUS was observed only for the Hg isotope directly

applied to the lake surface. EPA’s screening model presently assumes that the same quick and linear response

occurs with Hg deposition to uplands as well as water surfaces. The Florida, METAALICUS, Scandinavian, and

all other field observations demonstrated quick responses (and then nonlinear or sub linear) only for directly
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applied Hg.

EPRI modeled the changes in fish Hg concentrations for four lakes (two in

Wisconsin, one in Ontario, one in Florida) following a hypothetical reduction in inorganic Hg loading to the lakes,

using an updated version of D-MCM. Different modeling scenarios of varying sediment depth (1-3 cm) and

exchangeability of inorganic Hg to MeHg (availability of inorganic Hg for methylation) were performed. The

following table indicates the time required for fish Hg concentrations to reach 90 percent of the long-term steady

state concentration:

Modeling assumptions (variables) Lake response (time required for fish tissue Hg at

90 percent equilibrium concentration)

Sediment layer = 3 cm, 100 percent inorganic Hg

available for methylation

40-160 yrs

Sediment layer = 1 cm, 100 percent inorganic Hg

available for methylation (Pallette Lake)

39-122 yrs

Sediment layer = 1 cm, 10 percent inorganic Hg

available for methylation

23 yrs

The modeling analysis indicates two important results: first, the response time between reductions in

extemalloads and stable changed fish tissue concentration is NOT instantaneous (within 10 years). Secondly, key

assumptions of within-lake processes (in this study, two variables affecting Hg availability in sediments) can have a

pronounced effect on the predicted timing of long-term fish concentration change. This study provides important

insights regarding EPA’s expectations and assumptions of ecosystem response. In short, a relatively rapid

response (as appears to be indicated by the METAALICUS study) would only be applicable to those types of lakes

that the study was conducted at (northern temperate, oligotrophic). As indicated above, the technical literature is

replete with examples showing that non-atmospheric load factors are largely responsible for the mobility and

bioavailability of Hg.

Response:

EPA appreciates the commenter's input to the record. Please see the RIA.

4. Step 4: Fish Consumption and Human Exposure. EPA plans to address the relationship between

reductions in methylmercury concentrations in fish tissue and reductions in human exposure

through consumption. EPA plans on using the National Listing of Fish Advisories, supplemented b

the National Fish Tissue Study, for information on methylmercury concentrations in fish and

consumption data (including women of childbearing age, children, subsistence farmers and high-end

consumers) to determine the relationship between reductions in concentrations in fish tissue and

reductions in human exposure. EPA requested comment on whether the methylmercury fish

concentration or fish consumption rates used in the Water Quality Criterion could be used for local,

regional, or national assessments. EPA also requested data on the usefulness of the fish consumption

data provided by the Clean Air Task Force et al (OAR-2002-0056-3460), Edison Electric Institute

(OAR-2002-0056-2929), Electric Power Research Institute (OAR-2002-0056-2578), Forest County

Potawatomi Community (OAR-2002-0056-2173), Minnesota Conservation Foundation et. al.

(OAR-2002-0056-2415), and Southern Environmental Law Center (OAR-2002-0056-4222).

Comment:

One commenter (OAR-2002-0056-5422) said that EPA should consider the loss of health benefits
9-cciii

associated with reduced fish consumption due to an overly conservative reference dose (RfD) for Hg blood levels in

determining net health benefits due to the CAMR. The vast majority of health studies have concluded that the

benefits of fish consumption by all segments of the general population far outweigh any effects due to blood Hg

levels greater than EPA’s RfD and at levels approaching the World Health Organization (WHO) level of concern. 

The use of the RfD as the basis for calculating fish warning Hg levels has resulted in a reduction in fish

consumption and the related loss of health benefits to the public. The commenter supported the comments of the

Center for Science and Public Policy in this regard (see OAR-2002-0056-5423).

Response:

Although EPA considers inclusion of the NFTS data extremely valuable in providing additional coverage

for the study area, it is important to note that the majority of measured fish tissue concentrations were contributed

by the NLFA and not by the NFTS. This fact partially addresses the commentor’s concerns (i.e., the benefits

analysis primarily reflects NLFA data with a smaller relative contribution from the NFTS dataset). However,

several points can be made in response to concerns raised by the commentor regarding the NFTS data. Although

NFTS composites do reduce variability (primarily related to fish size), because size information is available for

many of the entries in NLFA, standardization using the NDMMFT model did have access to variability data

related to size through the NLFA. The Great Lakes are not being included in the primary benefits analysis

because of greater uncertainty in linking mercury deposition changes from power plants to fish tissue

concentrations relative to lakes and rivers. The relatively small NFTS dataset is offset to some extent by inclusion

of the larger NLFA dataset, although concerns of fish tissue sampling coverage (both spatially and temporally) do

persist. For additional information on fish tissue datasets used in the benefits analysis, see Sections 10 and 14.

EPA agrees with the commentor that NLFA data (when reflecting areas of increased fishing activity)

would be preferable to randomly collected data for purposes of supporting a benefits analysis. However, given the

patchy nature of the NLFA and the variety of sampling protocols used by different states in collecting data

included in the NLFA, EPA considers the NFTS data to be very useful in filling in gaps in coverages and in

providing a consistent randomly-sampled dataset to augment the purposively sampled data contained in the

NLFA.

As described in other responses, the Agency has high confidence in the RfD for methylmercury. EPA

encourages the public to vary the species and sources of fish in order to obtain the benefits of fish consumption

while avoiding elevated exposures to methylmercury. The fish advisory developed jointly with the Food and Drug

Administration emphasizes the benefits of including fish in a healthy diet while informing the public on ways to

reduce methylmercury exposure (http://www.epa.gov/waterscience/fishadvice/advice.html).

Comment:

Commenter OAR-2002-0056-5475 stated that the EPA defines Hg ‘hot spot’ as “a mercury deposition

point dominated by utility plant contributions whose removal would result in fish tissue levels dropping from above

to below the Fish Tissue Criterion of 0.3 ppm.” The commenter found this definition to be self-limiting, implying

no significant Hg impact on the environment when, in fact, the emitting facility may cause a Hg problem without

including background Hg emissions. This is an absurd notion since it would allow for any increment of Hg

emissions from a specific facility providing the background fish tissue Hg concentration is not below 0.3 ppm. For

example, if the Hg fish tissue level for fish found near a utility plant is 1.0 ppm, yet the fish tissue Hg content from

background emission sources would still be 0.35 ppm after removal of the Hg from the nearby utility plant, this

area would not be considered a ‘hotspot’ since the fish would still remain over the 0.3 ppm concentration. This

commenter stated that besides arbitrarily limiting the identification of local Hg impacts, this type of definition fails

to take into account the substantial risk that could be posed by designating significantly elevated Hg concentrations

as acceptable.

Response:
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EPA has addressed the hot spots issue in the revision Federal Register notice and in the

Technical Support Document: Methodology Used to Generate Deposition, Fish Tissue

Methylmercury Concentrations, and Exposure for Determining Effectiveness of Utility Emission

Controls in the docket.

Comment:

One commenter (OAR-2002-0056-5475) stated that the inability to quantify a facility’s Hg speciation

percentages on an on-going basis supports its concern that a cap-and-trade approach may be inappropriate

compared to the standard MACT approach. The actual ‘hot spots’ that could be allowed to continue to exist as a

result of a cap-and-trade approach may present unacceptable health risks to some of the citizens of Pennsylvania.

Response: 

EPA appreciates the commenters concerns. Please see EPA 's Office of Research and

Development white paper (see Control of Emissions from Coal-Fired Electric Utility Boilers: An

Update, EPA/Office of Research and Development, March 2005) for a discussion of the

importance of speciation for mercury capture. Also, please see Chapter 7 of the Regulatory

Impact Analysis for a discussion of how we took speciation into account in our power sector

modeling and see Chapter 8 for a discussion of how we took speciation into account in our air

quality and deposition modeling. EPA has addressed the hot spots issue in the revision Federal

Register notice and in the Technical Support Document: Methodology Used to Generate

Deposition, Fish Tissue Methylmercury Concentrations, and Exposure for Determining

Effectiveness of Utility Emission Controls in the docket.

Comment:

One commenter (OAR-2002-0056-5476) responded specifically to Step 4 of EPA’s Proposed Revised

Benefits Methodology: Fish Consumption and Human Exposure. This commenter believes that EPA’s assumed

consumption levels of 142.4 grams/day underestimates actual levels of fish consumed. The 1993 Survey of Tribal

Spearers conducted by the Great Lakes Indian Fish and Wildlife Commission (GLIFWC ) indicates that Ojibwe

tribal members across Minnesota, Wisconsin and Michigan consume anywhere from 155.8 to 240.7 grams/day in

conjunction with fall spearing. The spring spearing season can lead to consumption rates anywhere from

189.6-393.8 grams/day. The Leech Lake Band of Ojibwe Federally recognized Tribe with MCT membership has

reported that they had determined that a fish consumption rate of 227 grams/day is possible under its

treaty-protected fish harvesting right. The GLIFWC study also showed that 95 percent tribal respondents

consumed at least one meal per week of the walleye caught during spearing and over 12 percent ate more than 7

meals per week. This consumption is very seasonal in nature, with consumption rate varying by as much as 150

grams/day between the fall and the spring but also has started to show more year-round harvest and consumption,

as well as extended food storage through freezing. However, GLIFWC’s survey is only a minimum threshold since

the results are based solely on the those who have participated in the survey for some for traditional gatherers,

these numbers may be higher since more traditional gatherers might not respond in a survey but are likely to

consume more than the highest numbers the survey participants have reported in this survey.

The 1993 survey reveals that the average meal size may differ widely among groups. EPA assumes an

average meal size of 6 ounces, or about 170 grams. However, GLIFWC finds that Tribal members responding to

the survey and exercising their Fishing rights tend to eat an average meal ranging from 13-27 ounces, or about

369-766 grams; this range being only a minimum.

Mercury levels in fish caught and eaten locally may exceed levels found in commercially available fish or
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shellfish. U.S. Health and Human Services and EPA data show the commercially important fish like tuna, shrimp,

salmon, and catfish can range in concentrations from 0.01-0.35 ppm. But recent EPA data for freshwater fish

show that concentrations for important species like walleye, bass, trout, pike, and perch can vary from 0.25-1.03

ppm. This study further shows that, in a representative sampling of fish from U.S. lakes, 80 percent of predator

fish levels exceeded US EPA’s safe limit of 0.13 ppm for women. Fifty-five percent of all freshwater fish

(predatory and non-predatory) sampled exceeded this level and 66 percent of all fish sampled exceeded US EPA’s

safe limit for children under three. By contrast, MCT used a 0.05 ppm trigger level for a 1 meal/week

consumption advisory for sensitive populations.

In all instances, the numbers given above exceed EPA’s assumed levels of consumption and Hg content,

sometimes by large amounts. In further support of the commenter’s viewpoint, EPA’s document Fish

Consumption and Environmental Justice: A Report Developed from the National Environmental Justice Advisory

Committee Meeting of December 3-6, 2001 (2002 revised) states that although EPA’s numbers are an

improvement over previous figures, they do not address consumption at the highest potential rates. The

commenter urges EPA to take this new information into account when reviewing data about human exposure.

Both the EPA and the FDA have addressed Hg in fish tissue, but neither has done anything to address Hg

in other food sources such as wild rice, moose, and wild birds. According to this commenter, Hg levels in some

wild ducks occur at the same levels as in fish tissue. Although these results are from only a limited number of

ducks and follow-up studies are needed, this is disturbing information that EPA may not be aware of. Because

moose, ducks, and other animals eat primarily water plants, they are vulnerable to the effects of Hg poisoning. 

EPA does not attempt to address cumulative effects of toxic exposures in people who consume large quantities of

other natural resources (e.g., venison, moose, bear, waterfowl, wild rice, blueberries). An analysis of local fish

tissue samples typical of those consumed by the commenter were sampled, and commenter consumption advisories

were set accordingly. For other MCT component Bands such as the Mille Lacs Band of Ojibwe Indians, the

commenter has had to rely on those advisories set by MCT and those set by the State of Minnesota. Sensitive

populations are advised to eat no more than one meal per month of most fish species, even if care is taken to eat

only the smaller fish of the species. For those fishing for subsistence or cultural practice, this is a ridiculously

small amount of fish. It is clear that most Band members are eating amounts in excess of this recommended level

of consumption. The commenter does not believe this issue and the issue of persistence of toxic hazards created in

the environment due to past weak or neglected resource protection were addressed in EPA’s analysis.

The stationary-source industries, such as the electric utility and steam generating units, should not have

the role to tell the commenter (via the IPM model) at what level standards should be set so they can deliver

electricity to the commenter while fulfilling regulations at the least cost to themselves. It is up to EPA to

determine how much Hg can be allowed in the environment and for utilities to use their business ingenuity to

determine how they can best meet the standards EPA has set. Likewise, EPA should not tell the commenter how

many and what type of fish can be consumed. Instead, the commenter should be able to tell EPA what its

consumption levels are and EPA should make the fish safe for the commenter at those levels, preferably safe at any

level. If this precedence is set, soon EPA will be calling upon the commenter to limit the amount of air it can

breath and water it can drink. Limiting consumption of an otherwise healthy food source is not the answer.

The newspaper article “Mercury’s Dangers Persist” (Milwaukee Journal Sentinel, Section G1: April 12,

2004) reported that even when people are aware of the dangers of eating fish from local waters, they often ignore

the warnings. Likewise, the commenter believes that many indigenous peoples are unlikely to stop a

subsistence-based, culturally rich tradition even though concentrations and number of toxic contaminants continue

to increase. Despite warnings, some of these people will continue to fish and assume the risk of possibly suffering

from ill health effect from toxins or else go hungry. Since Hg can be neither tasted nor smelled in fish meat, this

may embolden some consumers to eat more than what is recommended as being safe.

Comments submitted by Electric Public Research Institute (EPRI) (Electric Public Research Institute, US

EPA Document ID No. OAR-2002-0056-2578, June 26, 2004) addressing fish consumption rates of tribal people
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do not appear to be accurate. Since EPRI favors less stringent control options than the commenter does, it is

highly inappropriate for EPRI to offer information about this subject. EPRI can have no information on this

subject that is better than information that comes directly from the tribes. Although EPRI used NHANES and EPA

data, it would be far more appropriate to let tribes describe their own consumption patterns, as these vary widely

around the nation. EPRI comments that maternal cord blood results showing higher levels of Hg than originally

protected have already been accounted for by including a single uncertainly factor for inter individual uncertainty

into the derived Reference Dose. EPRI’s model assumed a mean consumption rate of 3.7 gram/day and a

maximum of 200 grams/day. Elsewhere, EPRI used EPA’s mean consumption estimate of 14.3 and a 95th

percentile rate of 61.63 grams/day (comparable to the NHANES numbers of 14 and 68.75 grams/day). The tribally

specific data found by GLIFWC indicate that the actual numbers used should be much higher.

EPRI also made assumptions for the NHANES data about whether fish sampled were freshwater, marine,

or farm-raised. The commenter prefers the use of locally generated data, rather than NHANES data; through

GLIFWC and research conducted by MCT and by the commenter, the commenter has highly localized data that

gives real answers about what tribal members eat. The commenter also prefers the use of local data to NHANES

data as lake acidity varies widely from region to region and the lakes in Minnesota are of an acidity that readily

promotes methylation of Hg. In order to get a truly accurate picture, why not use the best data that is available?

EPRI estimated freshwater fraction versus marine fraction for Minnesota is also not indicative of what tribal

members eat. The estimate of only 36.55 percent freshwater fish being eaten is far too low.

Comments submitted by Edison Electric Institute (EEI) (Edison Electric Institute, USEPA Document ID

No. OAR-2002-0056-2929: June 29, 2004) state that fish consumption is not a problem in the U.S. because only a

small portion of fish consumed by U.S. residents is affected by Hg deposition. The commenter strongly disagrees

with this statement provided by EEI and instead would say a large portion of the population is consuming fish

regardless of their actual Hg levels. The real question should be what is industry doing to ensure all our

food-sources (and not just fish) are free of Hg and other toxins such that they will continue to have consumers in

the future for their product.

First, if we examine the population numbers, the National Center for Health Statistics states that in the

U.S. alone, 4.03 million babies were born in 2001. The 2000 Census shows that there were nearly 62 million

women between the ages of 15 and 44. The Center for Disease Control states that in 2003, 70.9 percent of new

mothers nursed in the hospital. Out of 4.03 million babies, that means that 2.86 million were breast-fed within

their first few days of life. This totals up to 68.89 million sensitive humans being exposed to Hg on a daily basis. 

Breast-fed infants were counted twice, as they were exposed both in utero and while breast-feeding. Thus,

23 percent of the total U.S. population of 297.3 million is potentially at risk from eating fish.

Second, local fish have been tested and found to contain Hg. Advisories have been issued for local fish

consumption, not just by the commenter but by 44 states in the Union. Locally caught fish probably comprise

95 percent of all fish eaten by Band members. If EEI can include such egregiously incorrect statements as these,

the rest of its comments are suspect.

EEI further states that most Americans, however, eat little fish. Half of all U.S. citizens eat no fish

whatsoever and, of those who do, the weekly average consumption is about one-quarter pound. Nearly all this fish

is store-bought ocean fish, which is unlikely to much Hg emitted from U.S. sources. EEI’s comments, at least in

this subject, are totally erroneous and unprofessionally naive. Catherine O’Neill’s article Mercury, Risk, and

Justice (34 ELR 11070, 12-2004) refutes this statement with data from NHANES III, which asserts that roughly

88 percent of all adults consume fish and shellfish at least once a month; and 1 percent consume fish daily. This

study also shows that the population who eats fish frequently differs greatly from the population who eats fish less

often. In short, Americans of color consume fish far more often than white respondents do, which puts these

groups at special risks.

The EEI comments also assert that since a recent University of Rochester study has concluded that
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children in the Seychelles Islands appear to be unaffected by Hg exposure, that the utility industry should be let off

the hook. The commenter believes that if the positions were reversed, EEI would also feel also the results of one

study cannot totally refute the findings of many other studies. Although the results of the Seychelle study are

surprising and show the need for further research, the whole of Hg study and regulation cannot be abandoned over

it. In fact, the National Research Council of the U.S. National Academy of Sciences has concluded that the Faroe

Islands study is more appropriate for use than the Seychelles study for deriving the Reference Dose (Clean Air

Task Force, Natural Resources Defense Council, U.S. EPA Document ID No. OAR-2002-0056-3460: June 29,

2004). The commenter urges EPA to follow this advice.

The EEI supports the statement by the American Medical Association that because of the wide variations

in the concentrations of Hg in fish and shellfish, it is possible to have the nutritional benefits of moderate fish

consumption and avoid fish high in Hg (cit. Edison Electric Institute, US EPA Document ID No.

OAR-2002-0056-2929: June 29, 2004). While this may be true of the typical consumer, subsistence level people

do not have the option of spending money on store-bought fish or restaurant meals. The fish available to them are

native species that come from local waters.

Response:

EPA appreciates the commenter's input to the record . Please see the RIA for a detailed

description of EPA’s modeling. Please also see EPA’s discussion of hot spots in the revision

Federal Register notice and in the Technical Support Document: Methodology Used to

Generate Deposition, Fish Tissue Methylmercury Concentrations, and Exposure for Determining

Effectiveness of Utility Emission Controls in the docket. 

Comment:

One commenter (OAR-2002-0056-5447) noted that a significant reduction in Hg emissions from

coal-fueled power plants will result in very little change in human exposures in the U.S. A reduction of 7 percent

would result in a reduction in MeHg exposure for women of childbearing age by 0.5 to 0.75 percent.13

While Peabody supports EPA’s goal of improving its science related to Hg deposition and

bio-accumulation of Hg in fish, even a significant improvement in EPA’s simplistic modeling will not change the

basic conclusion that there will be little overall impact on either Hg deposition in the U.S. or on Hg levels in fish if

Hg emissions are decreased from U.S. coal-fueled power plants. In contrast, as stated above, the high cost of

compliance with these regulations will result in increased electrical costs to consumers and therefore increased

mortality.

Response:

EPA appreciates the commenters input. Please see Chapter 11 of the Regulatory Impact Analysis for a

description of the benefits of the CAMR. 

Comment:

One commenter (OAR-2002-0056-5458) referred to the EPA and EPRI comment that existing freshwater

fish data collected by the States may be biased because it is collected in areas of suspected contamination is

misguided. The commenter has a fish sampling program that was developed to protect public health and has been

collecting samples in areas where the only known Hg contribution is from atmospheric deposition. To suggest that

the National Study of Chemical Residues of Lake Fish Tissue Study is superior for use in a Hg benefits

determination over data collected by the State fish surveys is a serious error in judgement by the EPA. The EPA

must analyze and integrate the existing fish concentration data collected by the States in any assessment of fish
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consumption. Contrary to the statement in the NODA that this data will overestimate exposure to anglers and their

families, the commenter believes this data could be used to get a realistic estimate of exposure to anglers and their

families, especially if the anglers are female and of child-bearing age.

The commenter is concerned about the use of the National Listing of Fish Advisories. If this database is

to be used, it is acknowledged that a bias toward overestimation of Hg concentrations will occur on a national

scale. However, other information is available within the states for other waters and/or species which could reduce

or eliminate this bias. The data would be difficult, at best, to accumulate within the time frame necessary for

consideration within this rule-making. A further confounding factor is a lack of uniformity among the states in the

criterion used to cause placement of a health advisory on a fishery containing excessive Hg concentrations. For

example, many states use the EPA Hg criterion of 0.3 mg/kg, whereas some states, including New York, use the

US Food and Drug Administration criterion of 1.0 mg/kg for the establishment of health advice for Hg in fish. 

Further, for states with a large number of waters (such as New York with over 7800 lakes, ponds and reservoirs,

over 52,000 miles of streams, and 1.1 million acres of marine waters), it is physically and fiscally impossible to

examine fish from all waters for Hg concentrations. Therefore, it is a certainty that the National Listing of Fish

Advisories will significantly underestimate the numbers and acreage of waters containing fish with Hg in excess of

the EPA criterion. Also, upon review of EPA’s National Listing of Fish Advisories web-page, the commenter

found the data presented for individual fish from New York waters are for the years 1990-1997 only, thus, it is

somewhat dated, limited and incomplete. The listing of health advisories is current through 2003, but of little

value for EPA’s purposes (i.e., to estimate MeHg concentrations in fish and consumption rates of such fish)

because actual Hg concentrations are not given and only species with Hg concentrations above the advisory

criterion are listed.

The National Study of Chemical Residues in Lake Fish Tissue was designed to provide a statistical

representation (with stratified random sampling by size of lakes) of the relative distribution of Hg in fish

throughout the US, although it excludes the Great Lakes. The study was designed to select one composite of a

bottom dwelling fish species and one composite of a predator fish species. Recommended bottom dwelling species

included brown bullhead or similar catfish species, carp, or white sucker. All these bottom dwelling species are

not good accumulators of Hg since they represent lower trophic levels, typically are not predatory, and often do not

show substantial accumulations of Hg even when concentrations may be elevated in other species. The predatory

species recommended in the project design include largemouth and smallmouth bass and walleye, among others,

which represent top level predator species that are good indicators of Hg concentrations within a waterbody,

provided they are present within the water. Not all waters sampled will contain one or more of these predator

species. Other predator species included in the study (several species of trout plus northern pike and black or white

crappie) provide indications of Hg concentrations that are intermediate between the bottom dwelling fish and the

top predators.

Use of the National Study of Chemical Residues in Lake Fish Tissue results could present bias based on

how the data is presented. First, the five Great Lakes are excluded, and each of the Great Lakes are known to

contain species of fish which exceed the EPA Hg criterion of 0.3 mg/kg, therefore, millions of acres of water may

be excluded from consideration, i.e., 2.65 million acres in New York alone. Second, the relative proportion of

lakes adversely affected by Hg could be characterized as either numbers of waters or surface acreage. 

Characterization by both methods should be incorporated into an evaluation to give a more accurate description of

impact and potential benefits to be derived. Other concerns that the commenter has about the utility of this study

as it relates to EPA’s goals include: 1) measurements of variability in the data will be limited because samples are

composites (i.e., only one data record for each species per lake); 2) sample composites limit assessments to one size

class of fish per lake, restricting the chance to examine fish size-Hg concentration relationships; 3) this study will

only provide a very generic regional assessment of fish Hg concentrations because less than 0.5 percent (n=25) of

the lakes in the state were sampled and the distribution of those lakes selected do not reflect the distribution of

lakes within the state (lakes in the Adirondacks, a six million acre area known to have Hg issues, represent over

60 percent of lakes in New York while only 36 percent of the national study lakes in New York were from the

Adirondacks); 4) the analysis of only two species per lake is restrictive and the data are further diluted because
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species selection varied by lake; and 5) overall this was a screening-level study with limited application for

determining important regional and size/species-related Hg concentration patterns in a variety of popular and

edible fish species.

The commenter is concerned with some of the potential assumptions that can be used to determine human

exposure and requests that the EPA adhere to the maximum individual risk (MIR) concept as discussed in the

Residual Risk Report to Congress. In the case of MeHg exposure, the MIR represents the highest estimated risk to

an exposed individual based on realistic high-end consumption and fish Hg concentration inputs. The use of the

average Hg concentration for the average fish combined with the average fish consumption rate will result in an

average benefit determination that will underestimate the benefits of reducing Hg emissions. The EPA exposure

handbook has fish consumption rate for the 95th percentile at 25 grams per day for non-subsistence people and 170

grams per day for subsistence fish eaters. The EPA Methyl Mercury Water Quality Criterion uses freshwater fish

consumption rates of 156.3 grams/day for children, 165.5 grams /day for women of child-bearing age and 17.5

grams/day for adults in the general population. The benefits analysis should reflect the MIR concept and use the

high-end consumption parameters for fish consumption for women of childbearing age and children to insure a

proper accounting of the benefits of reducing Hg emissions for this sector of the population.

Response:

Please see Chapter 5 of the RIA for a discussion of concentrations of mercury in fish. Please also see the

Revision of December 2000 Regulatory Finding on the Emissions of Hazardous Air Pollutants

from Electric Utility Steam Generating Units and the Removal of Coal- and Oil-fired Electric

Utility Steam Generating Units from the Section 112(c) List for a discussion of the Agency’s

rationale for not proceeding under Section 112 Notice and in the Technical Support Document: 

Methodology Used to Generate Deposition, Fish Tissue Methylmercury Concentrations, and

Exposure for Determining Effectiveness of Utility Emission Controls in the docket.

Comment:

One commenter (OAR-2002-0056-5535) presented below, several specific issues that would benefit from

such careful peer review. The commenter did not intend this list to be comprehensive, but merely included it to

illustrate that the agency must address critical scientific issues prior to making changes to its deposition and

watershed models or conducting other components of the proposed analyses. This overview serves to demonstrate

that it would be foolish to hold up final Hg regulations while EPA further investigates certain technical issues

concerning the emissions, fate, and toxicity of Hg from power plants.

Hg deposition and estuarine and marine species. Although EPRI has conducted an assessment of the

impact of Hg deposition on marine and estuarine fish species, this is a particular area where EPA needs to consult

the broader scientific community.

The commenter urged the agency to give additional weight to the findings of the METAALICUS project

as the researchers on this team are internationally recognized Hg experts conducting unbiased scientific research. 

The commenter noted that EPA was quick to emphasize that results from METAALICUS were ongoing and still

being refined while offering no such caution when describing PERI’s conclusions on numerous scientific issues

(e.g., plume transformation, global inventories, global transport of Hg, marine impacts, human exposure, etc.)

The Mercury Report to Congress contains a large amount of data on high-end fish consumers. EPA

should augment this information with more recent regional studies on fish consumption patterns such as have been

conducted in New England.

The commenter continued to take issue with the current EPA definition of hot spots which is limited to

levels of Hg in fish tissue that would cause the human population to exceed the RfD. Given the human and
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ecological health risks associated with Hg exposure, the definition of hot spots should be recast to include local,

regional and national hot spots as identified by (1) hot spots in deposition, (2) hot spots in water, and (3) hot spots

in biota.

New research regarding the extent of Hg in water, fish and wildlife and the occurrence of hot spots in the

Northeast U.S. is forthcoming in the journal Ecotoxicology. EPA should incorporate these findings is any new

assessments of the impacts of Hg emissions.

The commenter stated that despite the scientific uncertainties of the broad assessment that EPA has

described, the agency can still improve the benefits assessment in the short term for the purpose of preparing a

Regulatory Impacts Analysis for the final rule. Specifically, an assessment and monetization of cardiovascular

effects in children and adults and the loss of IQ points in children can be accomplished with the data at hand

concerning Hg blood levels in the U.S.

Please see Chapter 3 of the CAMR Regulatory Impact Analysis for a detailed discussion

of mercury in the environment, including an assessment of the response time for systems after a

change in mercury deposition. Please also see Section 8 for a discussion of the change in

mercury deposition based on air quality modeling and Chapters 11 for a benefits analysis of the

CAMR. Please also see the Revision of December 2000 Regulatory Finding on the Emissions of

Hazardous Air Pollutants from Electric Utility Steam Generating Units and the Removal of

Coal- and Oil-fired Electric Utility Steam Generating Units from the Section 112(c) List for a

discussion of the Agency’s rationale for not proceeding under Section 112 Notice and in the

Technical Support Document: Methodology Used to Generate Deposition, Fish Tissue

Methylmercury Concentrations, and Exposure for Determining Effectiveness of Utility Emission

Controls in the docket.

Comment:

The commenter (OAR-2002-0056-5465) stated that additionally, they would like to address Part II of the

NODA, “Step 4 of EPA’s Revised Benefits Methodology: Fish Consumption and Human Exposure.” Again, note

that by focusing its comments, the commenter does not mean to suggest that this is the only step in EPA’s

proposed method that warrants critique.

As EPA noted, consumption of fish was the primary pathway for human exposure to MeHg. As such, two

sets of factors became important to determining human exposure: those describing the concentration of MeHg in

fish tissue and those describing fish consumption practices for humans.

Methylmercury Concentration

In the NODA, EPA indicated that it is considering looking to the National Study of Chemical Residues in

Lake Fish Tissue (also referred to as the National Fish Tissue Study (NFTS)), given its concern that data from the

EPA’s National Listing of Fish Advisories (NLFA), which is collected by state agencies, may be “biased.”

Specifically, EPA argued that the fact that states generally collect fish tissue Hg data from (a) “areas of increased

angling activity,” and (b) “areas of suspected contamination” means that this data may “overestimate exposure to

anglers and their families.” This concern is largely misplaced. First, from a public health perspective, it is entirely

appropriate to sample from areas likely to be fished, i.e., “areas of increased angling activity,” in order to

determine the MeHg concentration in species likely to be consumed by humans. To prefer a random sampling

method (as undertaken in the NFTS) is to misfocus the relevant inquiry. If the waterbodies sampled are not fished

by humans, then humans are not going to be exposed via fish in those waterbodies. The effect, of course, is to
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dilute the relevant value for mean MeHg concentration in fish tissue, resulting in an estimate of exposure that is

inaccurate and thus scientifically unsound. On a related note, it makes sense to consider, additionally, the

concentration in the tissue of fish caught in areas once favored by humans but no longer fished due to advisories

warning of contamination. Because humans would fish in these areas but for unaddressed contamination, it is

reasonable to set environmental standards at levels protective of consumption here. Second, although some states

and tribes initially began their data collection efforts with waterbodies that they believed to be contaminated, it

should be kept in mind that many states and tribes have been gathering this data for some time, and have now

sampled broadly and extensively from the waterbodies within their respective jurisdictions. In fact, the commenter

urged the EPA to consult with the Great Lakes Indian Fish and Wildlife Commission (GLIFWC) about data they

have gathered that documents MeHg concentration in the tissue of locally consumed species at levels greater than

suggested by state or federal data.

Fish Consumption Rates and Practices

EPA stated in the NODA that it is seeking information on fish consumption rates by different affected

populations, particularly in the eastern half of the U.S. The commenter referred EPA to the analysis of various

groups’ fish consumption practices conducted by Professor O’Neill (in the attached article, see

OAR-2002-0056-5465) and to the fish consumption rates for the various Ojibwe and other Great Lakes tribes cited

therein. The commenter also referred EPA to the discussion and studies in the report of the National

Environmental Justice Advisory Committee, Fish Consumption and Environmental Justice.

EPA asked specifically whether the fish consumption rates used in the Water Quality Criterionx or

produced in the Peterson, et al., study are appropriate for assessing the effects on, inter alia, tribal populations. In

the first place, the commenter emphasized that the only ones with the knowledge to respond to this question are the

affected tribes themselves. Thus, if EPA is to produce an accurate and defensible assessment, it must pose this

question directly to the various tribes. Moreover, EPA should honor its commitment to consult with tribes on a

government-to-government basis on issues, such as this, that affect tribal rights and resources.

Although the commenter deferred to tribes’ individual responses to the above question, it nevertheless

noted that the fish consumption rates used by the Water Quality Criterion (produced by the national CSFII study)

and produced by the local Peterson, et. al., study are markedly lower–more than an order of magnitude lower - than

the fish consumption rate produced by a 1993 GLIFWC survey of tribal spearers (189.6 to 393.8 grams/day in the

spring) and the fish consumption rate adopted by the Leech Lake Band, one of the Minnesota Chippewa Tribe

members (227 grams/day). These differences and their implications are elaborated in the attached article by

Professor O’Neill. Further (see OAR-2002-0056-5465) , a host of other aspects of tribal members’ different fish

consumption practices (e.g., “acute” consumption in accordance with seasonal or cultural practices; different

average meal size; different species consumed) are relevant to an assessment of exposure and must be considered

by EPA. Several of these aspects are discussed in the attached article by Professor O’Neill (see e-docket

OAR-2002-0056-5465); in addition, CPR refers EPA to discussions by tribal commenters such as the Fond du Lac

Tribe. xii As a general matter, in assessing the effects on tribal populations, EPA should eschew data from studies

that are national in focus (such as the CFSII study) and/or are non-tribally conducted (such as the Peterson, et al.,

study), in favor of studies of the relevant tribal population conducted by the tribe/the relevant intertribal association

(or at least suggested by the tribe in consultation). Such a preference would produce more accurate and therefore

scientifically defensible results. In this vein, the commenter found EPRI’s suggested fish consumption rates

particularly ill conceived. PERI purports to construct “local” fish consumption rates, but does so by weaving

together a host of assumptions that simply do not comport with actual local practice, that serve chiefly to

underestimate exposure (e.g., PERI assumes a fish MeHg concentration of 0.12 mg/kg MeHg), and that work

backward from NHANES data on blood Hg levels to fabricate likely consumption rates for each state - a highly

questionable method in the face of numerous empirical studies documenting actual local consumption rates.

Finally, the commenter noted that EPA needed to account for the fact that the tribal consumption rates

described in the Peterson, et al., study may reflect current consumption levels that are artificially low. As the
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Peterson study itself notes, some tribal members may have already altered their fishing and fish consumption

practices to some degree in view of the fish consumption advisories issued by the states and the tribes. To the

extent this is the case, the fish consumption rate that is generated by a survey such as that conducted by Peterson

does not reflect what tribal members would consume, were the fish not contaminated with Hg. Patrick West, et al.,

termed this the “suppression effect:” that is, the fish consumption rate revealed by surveys in these instances

reflects a “suppressed” rate of consumption. This point applies with particular force to tribes, who have treaty

guarantees to a certain level of consumption. Even if tribal members have had to forego fish recently because fish

have been allowed to become contaminated, they are entitled not to do so; thus environmental standards should be

set to protect consumption at the higher, treaty-guaranteed level of consumption, not the lower, suppressed level of

consumption. Again, tribes will be uniquely positioned to be able to identify and account for suppression effects

for their populations; as such, tribally conducted studies or tribally interpreted data are to be preferred.

Response:

EPA agrees that for some situations (e.g., commenter examples) the value 142.4 may be an underestimate

of fish consumption. This is the value that the Agency recommends in its water quality standards program to

States with high-consuming sub-populations, in lieu of site-specific data when those states are faced with

developing a water quality standard for methylmercury that is protective of the fish consumption use of state

waters demonstrated by those sub-populations. Where a state has local information indicating higher rates of fish

consumption than 142.4, it is recommended that they use it. In the benefits analyses performed for this rule,

several consumption scenarios were considered based on the available data pertinent to the population modeled

(recreational anglers), but the value of 142.4 g/day was not used.

The EPA has included four potentially high-risk populations in the RIA, including: (a) high-end

recreational fisher anglers (with consumption rates at or above the 95th percentile for this group), (b)

economically disadvantaged high-end consumers with poverty-status income and fish consumption rates at or

above the 95th percentile for freshwater anglers, (c) Hmong in Minnesota and Wisconsin and (d) Chippewa in

Minnesota, Wisconsin and Michigan. These special population are intended to provide coverage for groups of

individuals who through choice, necessity or socio-cultural practices consume relatively high levels of self-caught

freshwater fish. Inclusion of these four special populations is also intended to support consideration of

distributional equity in relation to EGU-based environmental regulation (i.e., would a subset of the US population

benefit disproportionately from regulations to reduce mercury emissions from EGUs)? 

Fish consumption rates for all four special populations have been developed based on peer-reviewed

survey data that are representative of the particular group of interest. In the case of the Chippewas, EPA has

used a mean value obtained from the literature (see RIA Chapter 10 for additional details). However, it was not

possible to identify a high-end percentile consumption rate based on peer-reviewed literature and consequently,

the mean consumption rate was used in the benefits analysis without consideration for variability in fish

consumption rates across individuals. However, in response to information provided in NODA comments

(including that provided by this commentor), EPA has conducted a sensitivity analysis for high-end fish

consumption by the Chippewa population using (a) the maximum delta fish tissue concentration (for Walleye)

modeled in states where Chippewa are located for the RIA for Option 1 and Option 2 (i.e., the maximum change in

MeHg fish tissue concentrations modeled in Michigan, Wisconsin or Minnesota under CAMR Options 1 and 2)

and (b) the maximum seasonal fish consumption rate provided in the NODA comments (i.e., 393.8 g/day). The

results suggest that total IQ reductions under Option 1 and 2, even under these conservative assumptions (i.e.,

highest change in mercury fish tissue concentrations under Option 1 and Option 2 and the highest seasonal fish

consumption rate), are relatively low at 0.32 IQ points per child. This relatively low IQ benefit for this

conservative scenario reflects the fact that, while states where the Chippewa are located may have relatively high

absolute (total) MeHg concentrations in target fish species, modeled EGU deposition over these areas is relatively

low and consequently, CAMR is likely to produce relatively small changes in mercury fish tissue concentrations

compared with other areas where EGU deposition is higher (e.g., the Ohio river valley). These findings argue

against a distributional equity concern for the Chippewa in this portion of the study area (although this conclusion
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needs to be considered in the context of the overall precision and specificity of the benefits model used in this RIA

which is not intended for site-specific analysis and was developed for application at the regional-level).

EPA acknowledges that states contributing data to the NLFA may use different protocols that result in

mercury fish tissue concentrations having different degrees of bias (e.g., focus on most impacted waterbodies

versus waterbodies most heavily fished). The degree of uncertainty and potential relevance in adversely impacting

the RIA will depend on the specific protocol being considered. If a state focuses fish sampling on areas

experiencing heavy fishing activity, then this will actually benefit the economic analysis by contributing fish tissue

measurements from waterbodies experiencing fishing activity. Conversely, states that focus on areas believed to

have a mercury contamination problem, could bias the NLFA dataset in a conservative direction if those

waterbodies are not fished relative to other less-impacted waterbodies. Given potential concerns over the NLFA

and potential bias resulting from the individual state’s sampling protocols, EPA completed a statistical

comparison of the NLFA and the NFTS datasets (the NFTS uses a rigorous statistical sampling procedure to

provide unbiased coverage for waterbodies). This statistical comparison showed that the NLFA and NFTS

datasets were indistinguishable statistically except at the extreme high end, where there was some conservative

bias identified in the NFTS. These findings support the use of the NLFA (along with the NFTS) in conducting

national or regional benefits analyses, since these analyses focus on generalized trends in mercury fish

contamination. However, EPA acknowedges that assessments of extreme high-end exposure and risk could be

biased somewhat high if the NLFA data are used. However, it is important to reiterate that, if the NLFA bias

reflects waterbodies where fishing activity is likely, then this identified high-end bias may not be problematic and

indeed, could be preferred (i.e., it would not represent true bias).

Although EPA considers inclusion of the NFTS data extremely valuable in providing additional coverage

for the study area, it is important to note that the majority of measured fish tissue concentrations were contributed

by the NLFA and not by the NFTS. This fact partially addresses the commentor’s concerns (i.e., the benefits

analysis primarily reflects NLFA data with a smaller relative contribution from the NFTS dataset). However,

several points can be made in response to concerns raised by the commentor regarding the NFTS data. Although

NFTS composites do reduce variability (primarily related to fish size), because size information is available for

many of the entries in NLFA, standardization using the NDMMFT model did have access to variability data

related to size through the NLFA. The Great Lakes are not being included in the primary benefits analysis

because of greater uncertainty in linking mercury deposition changes from power plants to fish tissue

concentrations relative to lakes and rivers. The relatively small NFTS dataset is offset to some extent by inclusion

of the larger NLFA dataset, although concerns of fish tissue sampling coverage (both spatially and temporally) do

persist. For additional information on fish tissue datasets used in the benefits analysis, see Sections 10 and 14.

Comment:

One commenter (OAR-2002-0056-5455), in reference to fish consumption and human exposure,

responded specifically to Step 4 of EPA’s Proposed Revised Benefits Methodology: Fish Consumption and Human

Exposure. The commenter believed that EPA’s assumed consumption level of 142.4 grams/day underestimates

actual levels consumed by the commenters. A survey by the Great Lakes Indian Fish and Wildlife Commission

(GLIFWC) indicated that members of Ojibwe Great Lakes tribes consumed anywhere from 155.8-240.7 grams/day

in conjunction with fall spearing. The spring spearing season can lead to consumption rates anywhere from

189.6-393.8 g/day. The Leech Lake Band, one of the Minnesota Chippewa Tribe member bands, has determined

that a fish consumption rate of 227 g/day is possible under its treaty-protected fish harvesting right. The GLIFWC

study also showed that 95 percent tribal respondents consumed at least one meal per week of the walleye caught

during spearing and over 12 percent ate more than 7 meals per week. This consumption is very seasonal in nature,

with consumption rates varying by as much as 150 g/day between the fall and the spring. The survey also reveals

that the average meal size may differ widely among groups. EPA assumes an “average” meal size of 6 ounces, or

about 170 grams. However, GLIFWC finds that tribal fishers tend to eat an “average” meal ranging from 13-27

ounces, about 369-766 grams. EPA should adjust their analysis accordingly.
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Mercury levels in fish caught and eaten locally may exceed levels found in commercially available fish or

shellfish. U.S. Health and Human Services and EPA data show that commercially important fish like tuna,

shrimp, salmon, and catfish can range in MeHg concentrations from 0.01-0.35 parts per million (ppm). But recent

EPA data for freshwater fish show that MeHg concentrations for important species like walleye, bass, trout, pike,

and perch can vary from 0.25-1.03 ppm. This study further shows that, in a representative sampling of fish from

U.S. lakes, 80 percent of predator fish levels exceeded EPA’s safe limit of 0.13 ppm for women. Fifty-five percent

of all freshwater fish (predatory and non-predatory) sampled exceeded this level and 76 percent of all fish sampled

exceeded EPA’s safe limit for children under three. By contrast, the commenter used a 0.05 ppm trigger level for a

“1 meal/week” consumption advisory for sensitive populations.

In all instances, the numbers given above exceed EPA’s assumed levels of consumption and Hg content,

sometimes by large amounts. In further support of our viewpoint, EPA’s document Fish Consumption and

Environmental Justice: A Report Developed from the National Environmental Justice Advisory Committee

Meeting of December 3-6, 2001 (2002 revised), states that although EPA’s numbers are an improvement over

previous figures, they do not address consumption at the highest potential rates. Please take this new information

into account when reviewing your data about human exposure.

EPA made no attempt to address cumulative effects of toxic exposures in people who consume large

quantities of other natural resources (i.e., venison, moose, bear, waterfowl, wild rice, blueberries), although this

would be a scientifically sound idea if EPA truly wants to protect sensitive members of the population. An analysis

of local fish tissue samples typical of those consumed by the commenters were analyzed and Reservation

consumption advisories set accordingly. Sensitive populations are advised to eat no more than one meal per month

of most fish species, even if care is taken to eat only the smaller fish of the species. For those fishing for

subsistence or cultural practice, this is a ridiculously small amount of fish. It is likely that most commenters were

eating amounts in excess of this recommendation. Also, because the fish are harvested with nets, it is impossible

to target “safe” sizes. This issue was also not addressed in EPA’s analysis.

As alluded to in the previous paragraph, EPA has addressed Hg in fish tissue but has done nothing to

address Hg in other food sources such as wild rice, moose, and waterfowl. The commenter had found that Hg

levels in some wild ducks occur at the same levels as in fish tissue. Although these results are from only a limited

number of ducks and follow-up studies are needed, this is disturbing information that EPA may not be aware of. 

Because moose, ducks, and other animals eat primarily water plants, they are vulnerable to the effects of Hg

poisoning.

It should not be utility’s role to tell the public (via the IPM model) at what level standards should be set so

they can deliver electricity to us while fulfilling regulations at the least cost to themselves. It is up to EPA to

determine how much Hg can be allowed in the environment and for utilities to use their business acumen to

determine how they can best meet the standards EPA has set. Likewise, EPA should not tell tribes how many and

what type of fish they can consume. Instead, the tribes should be able to tell EPA what their consumption levels

are and EPA should make the fish safe for them to consume at those levels. If this precedence is set, soon EPA

will be calling upon us to limit the amount of air we can breathe and water we can drink. Limiting consumption of

an otherwise healthy food source is not the answer.

Studies showed that even when people were aware of the dangers of eating fish from local waters, they

often ignored the warnings. Likewise, the commenter believed that many tribal people are unlikely to give up a

subsistence-based, culturally rich tradition even though warnings have been issued. Some of these people will

either continue to fish or go hungry. Since Hg can be neither tasted nor smelled in fish meat, this may embolden

some consumers to eat more than is safe. Furthermore, most people are unaware of recent findings indicating that

consumption of Hg-contaminated fish can lead to heart disease. Both men and those women not of childbearing

age may be over consuming based on their ignorance of this information.

Comments submitted by PERI addressing fish consumption rates of tribal people are not accurate. Since
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PERI favors less stringent control options than the tribes do, it is highly inappropriate for PERI to offer

information about this subject. PERI can have no information on this topic that is better than information that

comes directly from the tribes. Although PERI used NHANES and EPA data, it would be far more appropriate to

let tribes describe their own consumption patterns, as these vary widely around the nation. PERI comments that

maternal cord blood results showing higher levels of Hg than originally thought have already been accounted for

“by including a single uncertainly factor for inter-individual uncertainty into the derived Reference Dose.” The

commenter wonders why Reference Doses got only one factor of uncertainty while the MACT standard calculated

by EPA contains several factors to correct for variability in MACT floor calculations, compliance methods, fuel

types, etc.. EPRI’s model assumed a mean consumption rate of 3.7 g/day and a maximum of 200 g/day. 

Elsewhere, PERI used EPA’s mean consumption estimate of 14.3 and a 95th percentile rate of 61.63 g/day

(comparable to the NHANES numbers of 14 and 68.75 g/day). The tribally specific data given earlier in this letter

indicated that the actual numbers used should be much higher to account for seasonal variation. While the

commenter assumed a daily consumption rate of 60 g/day in setting its water quality standards, this rate of

consumption is believed to be far more common than what would occur at the 95th percentile.”

PERI also made assumptions for the NHANES data about whether fish sampled were freshwater, marine,

or farm-raised. Again, the commenter preferred the use of locally-generated data, rather than NHANES data,

because such localized data gives real answers about what tribal members eat, which are better than projections

from non-tribal people. In addition, local data helps capture lake acidity variability that occurs from region to

region. As lakes in northern Minnesota are of an acidity that readily promotes methylation of Hg, the commenter

believed it is essential that local data be used as much as possible. In order to get a truly accurate picture, why not

use the best data that is available? EPRI’s estimated “freshwater fraction versus marine fraction” for Minnesota is

also not indicative of what tribal members eat. The estimate of only 36.55 percent freshwater fish (of total fish

consumed) is far too low.

Comments submitted by Edison Electric Institute (EEI) stated that fish consumption is not a problem in

the U.S. because only a small portion of fish consumed by U.S. residents is affected by Hg deposition. A large

portion of the population is consuming fish, and those fish are contaminated with Hg. First, let’s look at

population numbers. The National Center for Health Statistics states that, in the U.S., 4.03 million babies were

born in 2001. The 2000 Census shows that there were nearly 62 million women between the ages of 15 and 44. 

The Center for Disease Control states that in 2003, 70.9 percent of new mothers nursed in the hospital. Out of

4.03 million babies, that means that 2.86 million were breast-fed within their first few days of life. This totals up

to 68.89 million sensitive humans being exposed to Hg on a daily basis. Breast-fed infants were counted twice, as

they were exposed both in utero and while breast feeding. Thus, 23 percent of the total U.S. population of 297.3

million is potentially at risk from eating fish. Second, local fish have been tested and found to contain Hg in levels

that exceed EPA recommendations. Advisories have been issued for local fish consumption, not just by the

commenter but also by 44 states in the Union. Locally caught fish probably comprise 95 percent of all fish eaten by

Band members. If EEI can include such egregiously incorrect statements as these, the rest of its comments are

suspect.

EEI further claims, “Most Americans, however, eat little fish. Half of all Americans eat no fish

whatsoever and, of those who do, the weekly average consumption is about one quarter pound. Nearly all this fish

is store-bought ocean fish, which is unlikely to contain much Hg emitted from U.S. sources”. This statement is

totally erroneous and downright bizarre. Catherine O’Neill’s article refutes this statement with data from

NHANES III, which asserts “roughly 88 percent of all adults consume fish and shellfish at least once a month; and

1 percent consume fish daily.” This study also shows that composition of the group who eats fish frequently differs

greatly from the group who eats fish less often. In short, Americans in minority groups consume fish far more

often than white respondents do, putting these groups at higher risk.

The EEI comments also assert that since a recent University of Rochester study has concluded that

children in the Seychelles Islands appear to be unaffected by Hg exposure, the utility industry should be let off the

hook. As I’m sure EEI would feel if the positions were reversed, the results of one study cannot totally refute the
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contradictory findings of many other studies. Although the results of the Seychelles study are surprising and show

the need for further research, the whole of Hg study and regulation can’t be abandoned over it. In fact, the

National Research Council of the U.S. National Academy of Sciences has concluded that the Faroe Islands study is

more appropriate for use than the Seychelles study for deriving the Reference Dose. The commenter urged EPA to

follow this advice rather than the biased comments from EEI.

The EEI supports the statement by the American Medical Association that “because of the wide variations

in the concentrations of Hg in fish and shellfish, it is possible to have the nutritional benefits of moderate fish

consumption and avoid fish high in Hg.” While this may be true of the typical consumer, subsistence level people

do not have the option of spending money on store-bought fish or restaurant meals. The fish available to them are

native species that come from local waters.

So, in summary, the commenter did not agree with the fish consumption rates used in this rulemaking. 

The Water Quality Criterion uses a consumption rate of 17.5 g/day (or lower), which has been shown to be too low

for tribal people. The commenter also was suspicious of the consumption rates given in Peterson, et. al., because

they do not agree with data obtained from GLIFWC and the Leech Lake Band. The commenter had not had

sufficient time to thoroughly review the Peterson study, the commenter are simply wary of its results. It could be

that the people surveyed have already changed their consumption habits to account for Hg contamination. If so, it

is an example of an indirect curtailing of treaty rights and is unacceptable. The relatively low consumption

patterns evidenced by the study may also be a function of efforts made by the Wisconsin Department of Natural

Resources and by the specific tribal governments to inform people of consumption advisories. As an

Environmental Justice aside, let me point out the Peterson study’s finding that Hg levels were highest among the

unemployed.

The NODA also seeks comment on EPA’s plan to use National Fish Tissue Study (NFTS) values for

methylHg concentrations in fish. EPA favors the use of NFTS data over National Listing of Fish Advisories

(NLFA) data because the former were gathered by random sample while the NLFA data are gathered from areas of

increased angling activity and from areas of suspected contamination (as explained in the NODA). The

commenter believed this reasoning is exactly backward. If one wants to protect the most sensitive members of the

population, worst-case scenarios must be considered. That means looking at those who eat the highest quantities of

fish and those who eat the most heavily contaminated fish. The commenter believed this is highly appropriate

based on a public health perspective. Second, GLIFWC data suggests levels of contamination higher than those

put forth by EPA.

Response:

EPA agrees that for some situations (e.g., commenter examples) the value 142.4 may be an underestimate

of fish consumption. This is the value that the Agency recommends in its water quality standards program to

States with high-consuming sub-populations, in lieu of site-specific data when those states are faced with

developing a water quality standard for methylmercury that is protective of the fish consumption use of state

waters demonstrated by those sub-populations. Where a state has local information indicating higher rates of fish

consumption than 142.4, it is recommended that they use it. In the benefits analyses performed for this rule,

several consumption scenarios were considered based on the available data pertinent to the population modeled

(recreational anglers), but the value of 142.4 g/day was not used.

EPA has included four potentially high-risk populations in the RIA, including: (a) high-end recreational

fisher anglers (with consumption rates at or above the 95th percentile for this group), (b) economically

disadvantaged high-end consumers with poverty-status income and fish consumption rates at or above the 95th

percentile for freshwater anglers, (c) Hmong in Minnesota and Wisconsin and (d) Chippewa in Minnesota,

Wisconsin, and Michigan. These special population are intended to provide coverage for groups of individuals

who through choice, necessity or socio-cultural practices consume relatively high levels of self-caught freshwater

fish. Inclusion of these four special populations is also intended to support consideration of distributional equity
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in relation to EGU-based environmental regulation (i.e., would a subset of the US population benefit

disproportionately from regulations to reduce mercury emissions from EGUs)?

Fish consumption rates for all four special populations have been developed based on peer-reviewed

survey data that are representative of the particular group of interest. In the case of the Chippewa, EPA has used

a mean value obtained from the literature (see RIA Chapter 10 for additional details). However, it was not

possible to identify a high-end percentile consumption rate based on peer-reviewed literature and consequently,

the mean consumption rate was used in the benefits analysis without consideration for variability in fish

consumption rates across individuals. However, in response to information provided in NODA comments

(including that provided by this commenter), EPA has conducted a sensitivity analysis for high-end fish

consumption by the Chippewa population using (a) the maximum delta fish tissue concentration (for Walleye)

modeled in states where Chippewa are located for the RIA for Option 1 and Option 2 (i.e., the maximum change in

MeHg fish tissue concentrations modeled in Michigan, Wisconsin or Minnesota under CAMR Options 1 and 2)

and (b) the maximum seasonal fish consumption rate provided in the NODA comments (i.e., 393.8 g/day). The

results suggest that total IQ reductions under Option 1 and 2, even under these conservative assumptions (i.e.,

highest change in mercury fish tissue concentrations under Option 1 and Option 2 and the highest seasonal fish

consumption rate), are relatively low at 0.32 IQ points per child. This relatively low IQ benefit for this

conservative scenario reflects the fact that, while states where the Chippewa are located may have relatively high

absolute (total) MeHg concentrations in target fish species, modeled EGU deposition over these areas is relatively

low and consequently, CAMR is likely to produce relatively small changes in mercury fish tissue concentrations

compared with other areas where EGU deposition is higher (e.g., the Ohio river valley). These findings argue

against a distributional equity concern for the Chippewa in this portion of the study area (although this conclusion

needs to be considered in the context of the overall precision and specificity of the benefits model used in this RIA

which is not intended for site-specific analysis and was developed for application at the regional-level).

The National Research Council has identified fish consumption as the primary pathway of concern for

exposure to methylmercury in the United States and consequently, the RIA has focused on this exposure pathway

and has not considered other dietary categories such as non-fish meat and vegetables. EPA does recognize that

additional dietary pathways may contribute to overall methylmercury exposure, however these pathways are likely

to be overshadowed by the fish consumption pathway. Even in the case of subsistence sub-populations who may

obtain a significant amount of their protein and/or calories from self-produced food stuffs, fish is expected to

represent the dominant methyl-mercury source. In the case of ducks, although they may have methlymercury

concentrations that match fish concentrations (although as the commentor noted, these studies have limitations),

because ducks are not likely to consume upper-trophic level fish, their mercury levels are likely to be low

compared with upper trophic level (predator) fish. For these reasons, EPA does not believe that significant

uncertainty is introduced into either the primary benefits analysis, or consideration of distributional/equity issues

through exclusion of these non-fish dietary pathways.

The RIA used measured mercury fish tissue data collected by both states (National Listing of Fish

Advisories) and the EPA (National Fish Tissue Survey) and was not based on generalized data on mercury

concentrations in commercial fish. While not providing complete coverage for all areas potentially fished by

modeled populations including Native American populations such as the Chippewa, this fish tissue data set, does

provide a reasonable degree of coverage for mercury fish tissue contamination in the context of conducting a

benefits analysis. In the case of the Native American case study modeled for the RIA (the Chippewa), exposure

modeling was based on (a) fish tissue concentrations for waterbodies in the potential fishing activity zone of the

Chippewa in Michigan and Minnesota and (b) fishing activity modeling that reflects reasonable assumptions

regarding trip travel distances associated with fishing activity by the Chippewa. In other words, the benefits

analysis was not based on generalized assumption regarding mercury contamination in commercial fish, but

rather on measured mercury fish tissue concentrations measured in waterbodies likely accessed by this population.

Although EPA considers inclusion of the NFTS data extremely valuable in providing additional coverage

for the study area, it is important to note that the majority of measured fish tissue concentrations were contributed
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by the NLFA and not by the NFTS. This fact partially addresses the commentor’s concerns (i.e., the benefits

analysis primarily reflects NLFA data with a smaller relative contribution from the NFTS dataset). EPA agrees

with the commentor that NLFA data (when reflecting areas of increased fishing activity) would be preferable to

randomly collected data for purposes of supporting a benefits analysis. However, given the patchy nature of the

NLFA and the variety of sampling protocols used by different states in collecting data included in the NLFA, EPA

considers the NFTS data to be very useful in filling in gaps in coverages and in providing a consistent randomlysampled dataset to augment the purposively sampled data contained in the NLFA.

Comment:

Comment:

One commenter (OAR-2002-0056-5423) presents an important source of information. shows

the distribution of hair Hg values of 56 pregnant women sampled from 12 different native communities across

Alaska. This 2002 survey by the State of Alaska Epidemiology Office confirms that on average Alaskan native

pregnant women (with a mean hair Hg value of 0.6 ppm) consumed more fish than other average U.S. women

(who have a mean hair Hg value of about 0.2 ppm based on the ongoing CDC’s NHANES database). It is also

clear from Figure K1 (see e-docket OAR-2002-0056-5423), based on the examination of 8 Aleutian mummies

dated to about 550 years ago, that the native Alaskans had long been naturally exposed to significantly large levels

of MeHg through fish and marine mammals in their traditional diets without any plausible “contamination” by

power plant Hg emissions.

Exposure to MeHg in Alaska: Today Versus 550 Years Ago. Today’s distribution with a mean of 0.6

ppm. Compare 0.6 ppm to the mean level of MeHg in 550-year old with one mummy with MeHg as high as 4.6

ppm. Aleutian mummies: 1.2 ppm (mean of 4 adults) 1.44 ppm (mean of 4 infants). State of Alaska

Epidemiology Bulletin No. 29(December 11, 2002).

Regarding other native populations in Eastern North America, field records from Nunavik, Quebec

(Figure K2, see e-docket OAR-2002-0056-5423) suggest that the prenatal exposure level of MeHg, lead and

persistent organic pollutants (or POPs) in Inuit infants born between 1994 and 2001 has declined significantly. 

The authors of this new research paper concluded that “A significant reduction of lead and Hg concentrations was

found, but there was no clear linear or exponential trend. The decreases observed could be explained by a decrease

in food contamination, by changes in dietary habits, or, most likely by a combination of both. Although questions

remain as to the exact causes of decline, it is encouraging to observe such an improvement in prenatal exposure for

this highly exposed population.”

Concentrations of Hg, lead and persistent organic pollutants in umbilical cord blood of Inuit infants born

in Nunavik, Quebec have been decreasing from 1994 to 2001 “A significant reduction of lead and Hg

concentrations was found, but there was no clear linear or exponential trend. The decreases observed could be

explained by a decrease in food contamination, by changes in dietary habits, or, most likely by a combination of

both. Although questions remain as to the exact causes of decline, it is encouraging to observe such an

improvement in prenatal exposure for this highly exposed population.”

Equally important are explanations and cautions from this team of Laval University Medical Center

researchers in an earlier publication (Dewailly et. al., 2001, Archives of Environmental Health, vol. 56, 350-357):

“According to recommendations formulated by the World Health Organization (WHO), no more than

5 percent of individuals in a population should display a methylmercury concentration that exceeds 1000

nmol/L [or converted to 200 g/L MeHg in blood]. Concentrations of total mercury noted in present study

did not exceed 560 nmol/L [112 g/L]. WHO issued more stringent recommendations for pregnant

women, stating that not more than 5 percent of this subgroup should exhibit methylmercury concentration
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above 400 nmol/L [80 g/L]. In our survey, no women of childbearing age exhibited concentrations of

this magnitude. Recent data from Faroe Island suggest that the neurologic status of children can be

affected by low-level prenatal exposure to mercury. There are, however, major differences between the

diet of Faroese and the diet of Inuits, and care must be exerted before one concludes that Inuit children are

at risk. [I]n view of the high selenium intake [in the diets of the Inuit population from consumption of

mattak (beluga whale skin) which is about 2.4 times higher than that measured in the Farose], which may

counteract methylmercury-induced toxicity, local public health authorities did not recommend reducing

seafood consumption.”

If EPA has serious concerns for native populations, it should focus on the fact that instead of advancing

health and safety for these peoples, Hg warnings are already causing harm. John Middaugh, State Epidemiologist

of Alaska, recently warned FDA:

“Advisories based upon risk assessment without consideration of well-established public health benefits of

fish consumption have great potential to harm public health if reductions in fish consumption occur.”

Middaugh reported that many native Alaskan communities abandoned traditional fish diets since the

FDA’s 2001 Hg advisory, with a subsequent increase in diabetes, heart disease, and vitamin A and D deficiencies.

Response:

As described in other responses, the Agency has high confidence in the RfD for methylmercury. EPA

encourages the public to vary the species and sources of fish in order to obtain the benefits of fish consumption

while avoiding elevated exposures to methylmercury. The fish advisory developed jointly with the Food and Drug

Administration emphasizes the benefits of including fish in a healthy diet while informing the public on ways to

reduce methylmercury exposure (http://www.epa.gov/waterscience/fishadvice/advice.html).

Comment:

One commenter (OAR-2002-0056-5423) supports EPA’s intention to properly apply information from the

ongoing CDC’s NHANES database (which some at EPA have not done), but must stress that no women (Figure

L1, see e-docket OAR-2002-0056-5423) or children (Figure L2, see e-docket OAR-2002-0056-5423) in the current

NHANES survey are actually harmed by the levels of Hg in their blood from fish consumption.

The commenter will delay comments on the ultra-conservative nature of the MeHg RfD value set by EPA,

as shown in Figures L1 and L2, to comment (O) (see e-docket OAR-2002-0056-5423). The commenter will also

confirm in comment (O) that EPA’s MeHg RfD was derived from the Faroe Islands Children Study that was

plagued by contaminants like PCBs and DDT through consumption of pilot whale products and hence is widely

recognized in professional circles as incompatible with or irrelevant to the U.S. consumption profile of a wide

variety of fish (i.e., excluding whale products).

Response:

In deriving the reference dose for methylmercury, EPA relied on an integrated analysis involving three

studies. These longitudinal, developmental studies were conducted in the Seychelles Islands, the Faroe Islands,

and New Zealand. The Seychelles study yielded scant evidence of impairment related to in utero methylmercury

exposure, whereas the other two studies found dose-related effects on a number of neuropsychological endpoints.

In the assessment developed for the RfD, emphasis is placed on the results of the Faroe Islands study, the larger of

the two studies that identified methylmercury-related developmental neurotoxicity. Supporting evidence from the

New Zealand study provides assurance that choosing this focus is the appropriate strategy for protecting public

health. Conclusions from the National Research Council review of methylmercury support this use of the Faroes

Island study and disagree with the suggestion of a role for PCBs in the neurological effects observed (NRC. 2000. 
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Toxicological Effects of Methylmercury. National Academy Press.), saying that

“The committee concludes that there do not appear to be any serious flaws in the design and conduct of

the Seychelles Islands, Faroe Islands, and New Zealand studies that would preclude their use in a risk

assessment.”

The Agency’s derivation of the RfD also followed the National Research Council recommendation for an overall

composite uncertainty factor of no less than 10.

In summary, the Agency’s overall confidence in this RfD assessment is high. Three high-quality

epidemiological studies published since the last derivation of the oral RfD in 1995, have been included in the

analysis. Two of the studies (Faroe Islands, New Zealand) reported effects on a number of neuropsychological

endpoints, whereas the third (Seychelles Islands) reported no effects related to in utero exposure to

methylmercury. Benchmark dose analysis of a number of endpoints from both the New Zealand and Faroe Islands

study converged on an RfD of 0.1 μg/kg-day, as did the integrative analysis combining all three studies. Although

there was coexposure to PCBs in the Faroe Islands study, statistical analysis indicated that the effects of PCBs

and methylmercury were independent. Moreover, benchmark dose analysis of the endpoints that were

significantly associated with methylmercury yielded RfDs that were approximately the same when corrected for

PCBs. The same was true when the analysis was or based on the subset of the cohort in the lowest tertile with

respect to PCB levels, as compared with the full cohort. These findings provide further evidence that the identified

effects are in fact the result of methylmercury exposure.

Comment:

The commenter (OAR-2002-0056-5460) stated that with regard to step four of the proposed revised

benefits assessment methodology, EPA has not adequately explained how it intends to supplement data from the

National Listing of Fish Advisories with data from the National Study of Chemical Residues in Lake Fish Tissue,

let alone why such supplementation is necessary. The commenter added that EPA has likewise failed to explain

why it is appropriate to develop, in the context of the CAMR, national estimates of the mean concentrations of 268

chemicals in fish tissue from lakes and reservoirs across the U.S. The commenter stated that EPA should not use

national estimates to underestimate Hg concentrations, or Hg exposure, in any particular region or area of the

country.

Response:

The benefits analysis completed for the RIA is not intended to model local-scale changes in fish tissue

concentrations and exposures in support of site-specific risk analysis. Instead, modeling conducted for the RIA is

intended to capture generalized regional changes in methlmercury exposure resulting from reductions in power

plant mercury emissions in order to support a national-scale benefits assessment focusing on the 37-State eastern

US study area. For additional details on the benefits analysis modeling framework see Section 10 of the RIA.

Although EPA is not conducting local-scale modeling of mercury fish tissue concentration changes

resulting from decreased mercury deposition, the modeling framework used in this RIA is believed to have

sufficient precision to generate reasonably accurate benefits estimates. Specifically, 36km2

 CMAQ grid cell air

modeling results are used to project deposition changes over individual fish tissue sampling locations for purposes

of predicting changes in fish tissue concentrations related to emissions reductions from power plants. In addition,

recreational anglers and additional potential high-exposure populations (e.g., high-end consumers and Chippewa)

are modeled using relatively spatially-differentiated behavioral and exposure models which consider both the

distribution of fishers across the study area (at the US Census block group, or 8-digit HUC level) and the potential

behavior of fishers in accessing different areas or zones for fishing. This modeling framework is believed to

provide sufficient spatial resolution in characterizing regional patterns of population-level exposure to mercury

through fishing activity (and consumption) to support the benefits analysis. For additional detail on the benefits
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modeling framework, see Section 10 of the RIA.

Although EPA considers inclusion of the NFTS data extremely valuable in providing additional coverage

for the study area, it is important to note that the majority of measured fish tissue concentrations were contributed

by the NLFA and not by the NFTS. This fact partially addresses the commentor’s concerns (i.e., the benefits

analysis primarily reflects NLFA data with a smaller relative contribution from the NFTS dataset). EPA agrees

with the commentor that NLFA data (when reflecting areas of increased fishing activity) would be preferable to

randomly collected data for purposes of supporting a benefits analysis. However, given the patchy nature of the

NLFA and the variety of sampling protocols used by different states in collecting data included in the NLFA, EPA

considers the NFTS data to be very useful in filling in gaps in coverages and in providing a consistent randomlysampled dataset to augment the purposively sampled data contained in the NLFA.

The procedure used to generate a single standardized fish tissue dataset for use in supporting the benefits

analysis using data from both the NLFA and NFTS datasets is described in the CAMR RIA. Regarding the

rationale for combining the two datasets, EPA believes that the NLFA provides a large number of fish tissue

samples with some bias for areas likely fished (which is advantageous in supporting the benefits analysis), while

the NFTS, with its statistically random sampling strategy, provides consistent spatial coverage for waterbodies

across the study area and in that way, can fill in gaps left by the NLFA.

Comment:

One commenter (OAR-2002-0056-5497) stated that the development of an assessment protocol that melds

regional fish consumption patterns with the distribution of MeHg concentrations in fish is an immensely

challenging and complex undertaking. Existing fish tissue samples must be normalized to account for differences

in fish age, length, etc. Fish consumption data must be developed at the regional level to reflect differences in the

types of species consumed, the source of those fish (including whether they come from highly productive

waterbodies or not)” and the amount of fish consumed. The commenter does not see how the analyses described in

Step 4 could be completed, in any scientifically valid way, by March 15, 2005.

EPA’s request for comments on the incorporation of the National Listing of Fish Advisories’ (NLF A) and

National Fish Tissue Study’s (NFTS) fish tissue data into the National Descriptive Model of Mercury and Fish

Tissue (NDMMFT) suffers from EPA’s failure to make the pertinent material available in the docket. EPA’s

promise to place these materials in the docket “when available” makes it difficult, if not impossible, to respond to

EPA’s questions in a detailed manner. EPA should not use NDMMFT in a benefits analysis without further public

comment.

As for the fish consumption rates incorporated into EPA’s MeHg fish tissue criterion, they are

conservative. The default consumption rate of 17.5 grams/day is based on a value representing the 90th percentile

of the value for freshwater and estuarine fish from a 1995-96 study conducted by the Department of Agriculture. 

Default fish intake rates for recreational and subsistence fishers of 17.5 grams/day and 142.4 grams/day

respectively are based on values representative of the 90th and 99th percentiles of the general population. The fish

tissue criterion is designed to be highly protective, not to accurately predict fish consumption rates in a way that

would be realistic for a benefits analysis.

Response:

EPA has implemented a methodology for the RIA that accomplishes most of the technical tasks noted by

the commenter. For the RIA, EPA has used the NDMMFT statistical model to effective standardize the measured

fish tissue concentrations with regard to size (length) and species. This produces a standardized (diet relevant) set

of fish species and lengths for use in the benefits analysis and avoids the inclusion of non-diet relevant

sizes/species in exposure modeling. Regarding fish consumption rates, EPA acknowledges that regional

differences are likely to exist both for recreational anglers as well as high-consumption (subsistence) populations. 

However, with regard to recreational anglers, EPA could not identify regional- or local-scale studies in the
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literature with sufficient collective coverage to allow comprehensive modeling of the 37-State study area without

leaving large gaps in geographic coverage (i.e., individual studies covering smaller geographic areas or

watersheds were identified, but they could not be combined to provide a cohesive coverage for the study area). 

Ultimately, the consumption rates for the recreational angler that were used in the RIA were obtained from peerreviewed studies and are representative of general trends in behavior for this group. For special populations (i.e.,

the Chippewa and Hmong), consumption rates based on peer-reviewed studies focusing on these specific ethnic

groups were used. The RIA contains an expanded description of our application of the NDMMF. More

information about the model itself can be found at http://pubs.water.usgs.gov/sir20045199/.

5. Step 5: Assessing the relationship between reductions in human exposure and improvements in

public health. EPA sought comment on all aspects of its proposed revised methodology for

estimating the relationship between reductions in methylmercury exposure and improvements in

health. In particular, EPA sought comment on: (1) the focus on neurodevelopment health of

children; (2) the selection of IQ as an endpoint for quantification of neurodevelopmental effects and

whether it is an appropriate endpoint for benefits analysis; (3) whether other neurodevelopmental

effects can be quantified and are amendable to economic valuation; (4) whether, and if so how, data

from the Faroe Islands, New Zealand, and Seychelles Islands studies can be integrated for the

benefits analysis; the choice of the K=1 model for estimating the relationship between exposure and

IQ and practical alternatives to that approach; and the appropriateness of using a linear doseresponse model given the EPA’s reference dose, which assumes a threshold does below which there

is not likely to be an appreciable risk of deleterious effects during a lifetime.

Comment:

The commenter (OAR-2002-0056-5542) has historically been united in its advocacy that federal

regulatory agencies such as the EPA must use sound science and risk prioritization. The commenter has supported

“scientifically sound risk analysis; risk-based prioritization; benefit-cost analysis; flexible, efficient, cost-effective

risk management; and public participation in all phases of the process.” The commenters stated that their policy

also expressly supports a conclusion made by EPA in its document, “Reducing Risk: Setting Priorities and

Strategies for Environmental Protection, 2 September 1990,” which states:

There are heavy costs involved if society fails to set environmental priorities based on risk. If

finite resources are expended on lower-priority problems, at the expense of higher-priority risks,

then society will face needlessly high risks. If the priorities are established based on the greatest

opportunities to reduce risk, total risk will be reduced in a more efficient way, lessening threats to

both public health and local and global ecosystems.

The commenter was concerned that the EPA is chasing a Hg emissions reduction goal that is a

low-priority problem that represents little or no risk, but would nevertheless be squandering finite economic

resources that are needed for economic growth and for meeting higher priority risks. Since the EPA’s Hg decisions

could have the effect of dramatically reducing coal use in the U.S., generators trying to fulfill the nation’s growing

need for electricity would then be forced from abundant coal to either scarce natural gas or future nuclear power.

The commenter noted that the current EPA has access to almost a decade more research regarding both

the real science of public health exposure to U.S. power plant emissions of elemental Hg and to the net public

health benefits of eating fish, the primary source of Hg accumulation in the body. The commenter believed that the

EPA must correct the refuted science that was the foundation of the Agency’s reference dose, and therefore the

foundation of the agency’s proposed Hg rule.
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Under the sound science category, the commenter believed the central issues for the agency are whether

any level of MeHg consumption by humans was acceptable; and whether reducing elemental Hg emissions from

U.S. power plants will have any measurable impact on the MeHg levels in fish broadly consumed by the American

public. Many epidemiological studies have been undertaken since the EPA first picked its reference dose level that

show almost uniformly that some levels of MeHg in humans are acceptable. Further, natural levels of MeHg, as

well as the deposition of elemental Hg from sources outside the U.S., ensure that even closing U.S. coal-fired

power plants will not affect the quantities of MeHg in fish that the U.S. population ingests.

As carefully documented in the comments filed by the Utility Air Regulatory Group (URAG) on June 29,

2004, the EPA made a number of serious procedural mistakes and deviations from its customary and or appropriate

processes in order to conclude that Hg emissions from coal-fired power plants were adversely affecting public

health. The nation is facing many real risks of terrorism and natural events, such as infectious diseases,

hurricanes, volcanoes or tsunamis. Manufacturers in particular are facing intense and sometimes unfair

international competition and escalating structural costs at home from an out-of-control legal system, skyrocketing

pensions and health benefit costs, high corporate taxation, high energy costs and over-zealous regulation. The

nation, and certainly the manufacturing sector (which still accounts for 13 percent of the U.S. economy), can ill

afford expensive regulations promulgated in order to chase minor or negative net risks to public health.

The EPA itself has stated that there is a reference dose level of MeHg in the body “below which there is no

danger to human health.” Other entities, including the World Health Organization, the U.S. Federal Food and

Drug Administration (FDA), the Agency for Toxic Substances and Disease Registry (ATSDR), Health Canada

(Canada’s FDA) and the U.K. Committee on Toxicity in Chemicals in Food have all picked levels at which MeHg

in the body is not harmful, and the threshold levels set by each organization are well above the EPA’s

recommended level. In other words, the EPA has not only picked an unnecessarily low level of human exposure

compared to five other U.S. and international organizations, but it now appears that the agency is suggesting that

there is no dose of MeHg that is safe. If that is what the EPA is now concluding, it is not only contrary to all

existing scientific evidence, including the on-going analysis of the value of selenium in countering MeHg

exposure, it constitutes a tragic application of the easily-abused precautionary principle. Moreover, how is the

EPA proposing to measure the positive health impact of the Hg reductions it is proposing? If the EPA discovers

that there is no measurable positive impact from its new rules, would the EPA then rescind its regulations?

Only by declaring that there is no safe dose of MeHg can the EPA justify reducing emissions from U.S.

power plants. This is because there is ample evidence to show that elemental Hg emissions from U.S. power plants

are a very small percentage of the elemental Hg falling onto U.S. soil and waters. Further, there is ample evidence,

submitted in detailed comments by the Center for Science and Public Policy and others to this NODA, that MeHg

levels in fish and humans who eat them have remained constant since before the industrial revolution and

subsequent abundant coal use. In defending its position that reducing Hg emissions from power plants will result

in lower MeHg levels in fish, the EPA has given some weight to the Florida Mercury Report of Nov. 6, 2002,

regarding MeHg changes in fish in the Everglades during the 1990's after Hg emission controls were placed on

waste incinerators in the area. However, the assumptions of this study have been challenged. (See “A Framework

for Assessing the Cost-Effectiveness of Electric Power Sector Mercury Control Policies”, PERI, May 2003. [In a

press release issued on November 13, 2003, PERI observed that the Everglades study is flawed in several material

ways, including by not recognizing substantial differences between incinerator and power plant emissions.)

If the EPA determines that there is no safe Hg level, then the agency must either order a ban on all fish or

eliminate all sources–natural and anthropogenic–of elemental Hg into the environment. Of course, it is impossible

to eliminate Hg that is transported in the air from Asia, that naturally exists in the soil and oceans, and that is

emitted from forest fires and volcanoes. Merely regulating one very small part of the Hg cycle U.S. power

plants–would do little if anything to protect human health from exposure to MeHg from fish. Accordingly, a ban

on eating fish would be the only logical outcome of a policy driven by a belief that there is no safe Hg level.

The EPA has an opportunity to correct the health-science record before the agency puts its full reputation
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as the protector of public health behind staff opinions that are now based on refuted, discredited, decade-old

studies, including the Faroe Island study. It is now clear that the Faroe Island study was discredited after the

original EPA analysis and after the National Research Council study of 2000, both of which the EPA is currently

relying on to justify its proposed reference dose.

The commenter either supported the fishing industry or were in the fish processing industry. These

companies are severely affected by any scare mongering that frightens Americans away from eating fish as part of

their diet. For a detailed analysis of the net harm of scaring people away from eating fish, including the loss of net

pregnancy and net cardiovascular benefits, see the comments being submitted on this NODA by the Center for

Science and Public Policy. The Center for Science and Public Policy also provides analysis of the deficiencies and

failings of several studies that find negative cardiovascular effects from consuming MeHg from fish. The EPA also

should recognize that The Institute of Medicine is going to do a two-year study of the benefits of fish consumption,

which could embarrass any EPA actions that have resulted in driving people away from fish consumption for no

measurable health benefit.

The commenter added that any EPA analysis must consider other risks to public health that occur when

electricity and natural gas prices skyrocket as a consequence of excessive EPA regulation of coal-fired electric

generation. Clearly, additional costs on manufactures will continue to erode the manufacturing employment base

in this country as they struggle to compete with low-cost foreign manufacturers. However, not only are

manufacturing jobs at risk–and the higher compensation, better health care and pension plans that manufacturing

workers enjoy compared to the rest of the economy–but so are risks associated with a lower tax bases that is the

result of having a weak manufacturing sector, which would lead to lower public services, including health clinics. 

A weak manufacturing sector and high electricity costs will sap the investment markets upon which millions of

current and potential retirees depend. Finally, dramatically increasing the costs of electricity and natural gas prices

paid by homeowners must be recognized as harming many economically disadvantaged people, who have the least

capacity to absorb these additional costs.

Thus, the EPA’s actions to regulate Hg emissions have the significant - and so far unaccounted for by the

EPA - potential for harming public health that must be weighed against the minuscule benefits of regulating

elemental Hg emissions from U.S. coal-based power plants.

Response:

Please see the RIA as well as the Revision of December 2000 Regulatory Finding on the

Emissions of Hazardous Air Pollutants from Electric Utility Steam Generating Units and the

Removal of Coal- and Oil-fired Electric Utility Steam Generating Units from the Section 112(c)

List for a discussion of the Agency’s rationale for not proceeding under Section 112 Notice and

in the Technical Support Document: Methodology Used to Generate Deposition, Fish Tissue

Methylmercury Concentrations, and Exposure for Determining Effectiveness of Utility Emission

Controls in the docket.

Comment:

One commenter (OAR-2002-0056-5556) noted that the EPA need not limit its benefits analysis to any

single quantifiable health benefit but rather should consider all pertinent anticipated benefits to human health. It

may be especially important to include a discussion on the benefits to adult cardiovascular health as this effect has

been correlated with MeHg exposures at or below levels associated with neurodevelopmental effects (Toxicological

Effects of Methylmercury, National Academy of Sciences, 2003). This commenter stated that it is also important

to include any expected improvements in water quality and subsequent reductions of MeHg in fish tissue, realizing

that a reduction in Hg emissions of at least 75 percent may be required before measurable environmental impacts

can be detected.
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Response:

EPA recognizes that research is ongoing in a number of areas related to both mortality and morbidity in

relation to methylmercury exposure. However, at the time of this regulation, existing peer-reviewed evidence was

not considered sufficiently conclusive to include these additional health endpoints in the primary benefits analysis

and EPA has focused on reductions in IQ resulting from prenatal exposure in estimating health-related benefits. 

See Appendix B for a detailed discussion of the current status of research involving the mortality endpoint for

methylmercury exposure.

Comment:

One commenter (OAR-2002-0056-5471) referenced comments on the Proposed Rule that supports the

control of Hg from coal-fired EUSGUs through a cap-and-trade program. However, for the ultimate rule to

establish a regulatory program that reflects a reasonable estimate of benefits from Hg emission reductions, this

commenter believes that EPA must assign to EUSGU Hg emissions only those health risks that can be traced to

those emissions.

In the preamble to the Proposed Rule, the Agency claimed that substantial benefits would result from the

proposed CAMR. But the claimed benefits are based almost entirely on the value of estimated health benefits from

the decline in ambient PM2.5 caused by the SO2 and NOx reductions resulting from the control measures required to

reduce Hg emissions (primarily SO2 scrubbers and selective catalytic reduction (SCR)). Because the Proposed Rule

relied almost exclusively on these co-benefits of the proposed regulatory control of Hg, this commenter stated that

no health benefits were directly associated with reductions in Hg emissions. The Agency’s intention in the NODA,

at least in part, appears to be to develop a methodology to better quantify benefits attributable to the proposed

CAMR by isolating the benefits of Hg emissions reductions from those benefits associated with SO2 and NOx

emission reductions. While this commenter supports the Agency’s undertaking of the additional analysis, EPA’s

proposed approach to assessing the benefits of Hg emissions reductions creates a danger of overestimation of those

benefits.

Response:

EPA has developed a benefits analysis methodology for this RIA that is designed to provide unbiased

estimates of health-related benefits resulting from regulatory options considered under CAMR. In keeping with

convention, efforts have been made to use peer-reviewed methods and data sets when available and to avoid

introducing conservative assumptions at all stages in the benefits modeling process. EPA’s emphasis on

representativeness has meant that a number of health endpoints, that may ultimately be supported by research

findings (e.g., cardiovascular-related mortality and immunologic-related morbidity), have been excluded from the

primary analysis in order to include only those endpoints in the formal benefits analysis for which there is strong

peer-reviewed support. For additional details on the modeling framework including all key assumptions and input

datasets, please review Chapter 10 in the RIA.

Comment:

One commenter (OAR-2002-0056-5471) noted that in the NODA, EPA requests general comments on

analytical approaches to translating estimates of reductions in Hg emissions from EUSGUs into approximate health

outcomes in humans. It has been suggested that one guide for this analysis is the Agency’s regulation of lead. In

the late 1970s, EPA initiated a successful program designed to eliminate all lead emissions into the environment

primarily through the phase-out of leaded gasoline. Since airborne lead emissions are linked to blood lead levels in

children and related neurological impacts, it may appear reasonable to utilize the lead elimination model for

dealing with Hg.

However, this commenter believes there are significant differences between the nature of lead emissions
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and EUSGU Hg emissions and the health benefits reasonably associated with reducing those emissions. If these

differences are not taken into account, the commenter believes that blindly making assumptions for Hg emissions

reductions based on the Agency’s experience with lead will cause EPA to overestimate the benefits of Hg emissions

reductions. First, virtually all airborne lead is attributed to anthropogenic sources while a large percentage of

airborne Hg (greater than 50 percent) is due to natural sources. Thus, while the Agency acted reasonably in

targeting all lead emissions, it is impossible to eliminate all airborne Hg emissions. Second, lead emissions and

ambient lead concentrations are primarily associated with urban areas while Hg emissions and ambient Hg

concentration are widespread on a global scale. Third, while there appears to be no lower limit for neurological

impacts for lead blood levels, Hg blood levels have a clear threshold below which there are no neurological

impacts. Fourth, while neurological impacts were clearly shown at blood lead levels present in children in U.S.

urban areas in the 1970s, no such neurological impacts have been noted or documented at Hg blood levels currently

found in child-bearing age women or children in the U.S.

Response: 

Comment:

One commenter (OAR-2002-0056-5471) noted that in explaining Step 5 of its revised benefits analysis,

EPA seeks comment on its proposed use of three studies, including a study from the Faroe Islands, to estimate the

relationship between reductions in MeHg exposure and improvements in health and its proposed use of intelligence

quotient (IQ) decrements associated with prenatal MeHg exposure to quantify and value the health benefits of

reduced exposure to MeHg.

EPA has selected a reference dose (RID) for Hg in maternal blood (5.8 ppb) that serves as a de-facto

threshold. This number, which is 10 times below the threshold number developed from the Faroe Islands study

and 14 times lower than the World Health Organization’s level of concern, is very conservative. This commenter

believes that if an unrealistically low threshold for Hg blood levels were used to estimate benefits, reductions in

blood levels between the true threshold and the unrealistically low one would create the appearance of a benefit

where there is none.

The commenter stated that the danger of using the RID as the benchmark for assuming benefits is

revealed by EPA’s proposal to develop a relationship between Hg emissions and general population IQ. There is

no evidence of IQ impact at blood Hg levels greater than the RID but below the Faroe Island threshold level. Yet,

if this relationship were then coupled with an imputed value for increased IQ for the general population, large

estimated benefits could be generated that would not exist. Likewise, if EPA’s proposed assumption of a linear

response between blood Hg levels and IQ would lead to an imputed benefit for reducing blood Hg below the

threshold level, the Agency would be creating benefits that do not exist.

While the commenter does not support all the findings of the Faroe Islands study, the study provides a minimum

threshold for blood Hg levels. This commenter recommends that the Agency use at least the threshold level

established in that study (if not a higher one, such as the WHO level of concern), and not the RID, as the

benchmark for measuring health benefits.

Response: 

Please see Chapters 10 and 11 of the RIA for a discussion of the CAMR benefits. 

Comment:

One commenter (OAR-2002-0056-5476) commented on Step 5 of the NODA addressing cost/benefit

analyses and how reduction will improve human health. The commenter finds that EPA’s benefits analysis does

nothing to address the importance of fishing as a cultural practice. There is no way to place a dollar amount on the

benefit to spiritual well-being as a result of practicing a centuries-old tradition and passing it on to our children. In
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a more concrete measurement, EPA does nothing to address replacing a subsistence food source that provides a

significant amount of nutrition for our Band members. In making a local, easily obtainable food source inedible

due to poisoning, EPA should calculate the costs that will be incurred in cleaning up these toxins to improve the

health and physical well-being of the people and the health of the environment for today’s and future generations. 

The commenter was also unaware of any attempts EPA has made to quantify the costs of the learning and

educational problems that exposed children may experience. For example, the loss in lifetime earnings resulting

from retardation of mental aptitude in the generalized population as a result of Hg poisoning has been estimated at

$2.3 billion per year. By refusing to set adequate MACT standards, EPA is shifting this economic burden onto the

heads of indigenous people and their communities as a whole. Another error in the EPA’s cost/benefit analysis

comes from the projection of $15 billion in savings due to health-related benefits from its proposed rule when

forecasted against the do nothing option. These are simply health benefits that accrue from EPA’s very

substandard proposal. The commenter believes that if the more stringent MACT standard were set in place,

additional billions of dollars could be saved.

This commenter believes that EPA has also failed to assess tourism-related impacts. Tourism in $9.8

billion annually in Minnesota alone. Of this total, sport enthusiasts spend $1.58 billion, or 16 percent. Locally,

Lake Mille Lacs universally recognized as a premier trophy fishing lake and its Lake-related tourism adds an

estimated $150 million into the local economy annually. Although it is unknown to what level fish advisories

impact these number, fishing and tourism bring in income that the State of Minnesota cannot afford to lose. The

other Great Lakes states of Wisconsin, Michigan, Illinois, Indiana, and Ohio face similar situations. Together,

these States, along with Minnesota, attract 7.8 million anglers annually who spend $5 billion in fishing-related

dollars. Although these are not directly health-related issues, they certainly need to be addressed in EPA’s

economic considerations.

The commenter also takes issue with the modeling performed in the analysis. The commenter does not

believe the science of modeling is at a state where it can accurately be used for Hg due to the lack of understanding

about dry deposition. Currently among many ambient air-monitoring personnel, there is a strong opinion that

there are too few dry deposition monitors in the North American continent and barely adequate network of wet

deposition monitors in the eastern half of the U.S., with very little of either monitors existing on Anishinaabewaki

(Indian Country) so it is very hard to say how much wet or dry deposition of Hg is occurring in these areas. Based

on this concern, the commenter believes it is not in the Band’s interest to propose a cap and trade program relying

on the results of EPA’s models. In turn, the commenter asks the EPA to uphold its Trust responsibility obligations

by erring on the side of caution rather than be wrong in such an important matter. To account for the lack of

confidence in the models, EPA should abandon its idea of cap-and-trade and cleave to a MACT standard.

The commenter believes that the National Emissions Inventories used in EPA’s analysis probably

underestimated the amount of Hg emitted from some sources, especially in the western and central regions of the

U.S., such as miscellaneous product disposal. EPA has used the best information it has available, but it should

leave a margin of safety to account for inaccuracies.

The commenter believes there is a MACT calculation problem. The EPA seems to have followed a

methodology recommended by a utility trade group, using a short-term worst-case analysis to develop a long-term

average standard. This method used only the 2.5 percent worst emissions from relevant sources, ignoring the

97.5 percent best emission reductions.

The commenter would like to reference the excellent comment letter by the Forest County Potawatomi

Community ( FCPC ) to EPA on the Mercury Utility Rule (US EPA Document ID No. OAR-2002-0056-2173,

April 27, 2004). The experts retained by the FCPC stated in attachments to that letter why EPA’s proposed MACT

standards are unacceptable and why EPA improperly failed to consider alternate methods of removal, such as

activated carbon injection. The commenter is unable to make specific comments on these issues as time is running

short. The commenter also believes that it cannot add anything to the discussion that has not already been said in

the FCPC letter.
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In studying Table 1 of the Notice of Data Availability, it appears that it really is not much more expensive

to control emissions of 7.5 tons per year rather than of 15 tons per year. A two-phase cap of 15 tons is projected to

cost $3.3 billion by 2010 and $6.7 billion by 2020. But a two-phase cap of 7.5 tons is expected to cost $4.6 billion

by 2010 and $7.1 billion by 2020. The difference by 2020 is only 6 percent! Even with all of EPA’s incomplete

assumptions that lead to faulty calculations and failure to carry out a proper MACT determination, it only makes a

6 percent difference in cost.

Though most of the Band members are oblivious to any of EPA’s calculations or rule-making, among

those of us in Tribal Government who are entrusted and statutally obligated to protect the health of our Band

members and the health of the natural resources available to the Band members, or to our Band members who

actively seek to information, it would be hard to over-state the level of utter disbelief expressed across

Anishinaabewaki over the way EPA has handled this rule-making.

Response:

EPA has used a cost-of-illness function based on lost earnings resulting from methylmercury exposure as

the basis for its primary benefits estimate in the RIA (i.e., prenatal methylmercury exposure through maternal

consumption producing IQ decrements in children which translate into lost earnings later in life). This valuation

function, which is based on the approach used in past EPA regulations concerning lead exposure, also considers

the impact of lowered IQ on years of education achieved. EPA acknowledges that because this function is based

on cost-of-illness and not willingness-to-pay (WTP), it likely represents a lower bound for valuation of the IQ

decrements and that a more comprehensive WTP-based function would capture other factors such as those listed

by the commentor above. Note, EPA did not use a WTP-based function in the benefits analysis because peerreviewed literature does not support derivation of such a function at this time.

Comment:

One commenter (OAR-2002-0056-5517) notes that the NODA fails to provide a scientifically sound

reason as to why EPA adds a factor-of-ten safety factor in calculating what is an acceptable daily intake of MeHg

from eating fish. Adding such a safety factor is usually done to account for how sensitive populations, such as

children, who are believed to be more sensitive to MeHg than adults, differ in response to the general population.

This commenter points out that the reason the additional safety factor, as used by EPA, is questionable is

that the available studies of the health effects of MeHg exposures focus both on healthy and sensitive

subpopulations inclusively, thus their particular susceptibilities are already accounted for, obviating the need for

any added safety factor. EPA has provided no information in this NODA that would justify the inclusion of the

factor-of-ten safety factor used by the agency; as such its use is clearly arbitrary and capricious. Moreover, there is

no explicit statutory authority in the Clean Air Act that mandates the use of such a safety factor.

In their comments to EPA concerning the agency’s proposed rule to control emissions of Hg from

coal-fired power plants, other national trade associations have also addressed the questionable safety factor used by

EPA in establishing what is an acceptable daily intake of MeHg from eating fish. These organizations also find

that the use of the factor-of-ten safety factor is not justified. The commenter believes that its observations have

merit and must be given careful consideration.

Response:

In deriving the reference dose for methylmercury, EPA relied on an integrated analysis involving three

studies. These longitudinal, developmental studies were conducted in the Seychelles Islands, the Faroe Islands,

and New Zealand. The Seychelles study yielded scant evidence of impairment related to in utero methylmercury

exposure, whereas the other two studies found dose-related effects on a number of neuropsychological endpoints.

In the assessment developed for the RfD, emphasis is placed on the results of the Faroe Islands study, the larger of
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the two studies that identified methylmercury-related developmental neurotoxicity. Supporting evidence from the

New Zealand study provides assurance that choosing this focus is the appropriate strategy for protecting public

health. Conclusions from the National Research Council review of methylmercury support this use of the Faroes

Island study and disagree with the suggestion of a role for PCBs in the neurological effects observed (NRC. 2000. 

Toxicological Effects of Methylmercury. National Academy Press.), saying that

“The committee concludes that there do not appear to be any serious flaws in the design and conduct of

the Seychelles Islands, Faroe Islands, and New Zealand studies that would preclude their use in a risk

assessment.”

The Agency’s derivation of the RfD also followed the National Research Council recommendation for an overall

composite uncertainty factor of no less than 10.

In summary, the Agency’s overall confidence in this RfD assessment is high. Three high-quality

epidemiological studies published since the last derivation of the oral RfD in 1995, have been included in the

analysis. Two of the studies (Faroe Islands, New Zealand) reported effects on a number of neuropsychological

endpoints, whereas the third (Seychelles Islands) reported no effects related to in utero exposure to

methylmercury. Benchmark dose analysis of a number of endpoints from both the New Zealand and Faroe Islands

study converged on an RfD of 0.1 μg/kg-day, as did the integrative analysis combining all three studies. Although

there was coexposure to PCBs in the Faroe Islands study, statistical analysis indicated that the effects of PCBs

and methylmercury were independent. Moreover, benchmark dose analysis of the endpoints that were significantly

associated with methylmercury yielded RfDs that were approximately the same when corrected for PCBs. The

same was true when the analysis was or based on the subset of the cohort in the lowest tertile with respect to PCB

levels, as compared with the full cohort. These findings provide further evidence that the identified effects are in

fact the result of methylmercury exposure.

Comment:

One commenter (OAR-2002-0056-5517) reports that it recently received an e-mail communication from

Professor Gary Myers of Rochester University who leads the child development study of prenatal MeHg exposure

from ocean fish consumption in the Seychelles Islands. His e-mail message concerns EPA’s stated intention

outlined in the NODA to analyze whether data from the various major MeHg exposure-effects studies, such as

those of the Seychelles and Faroe Islanders, can be integrated. Dr. Myers observes, “I do not think there is any way

to compare the two [Seychelles and Faroe Island] studies regarding exposure. They are simply different.” In view

of this communication, the commenter suggests that EPA confer further with Dr. Myers on this matter to clarify

the specifics of his expressed concern.

Response: 

Please see Chapter 9 of the RIA for a discussion of the derivation of a dose-response function using both

the Seychelles and Faroes data. 

Comment:

One commenter (OAR-2002-0056-5447) stated that EPA’s NODA poses a number of questions related to

modeling runs that have been performed to simulate electric system operation and decision making to predict how

utilities would comply with EPA’s two proposed regulatory options. 69 Fed. Reg. 69866-69872. EPA states that

modeling predictions of how electric generation would shift in response to the Hg rule is relevant because EPA is

required to examine “cost, nonair quality health and environmental impacts, and energy requirements” under both

Clean Air Act (CAA) § 111 and 112(d). 69 Fed. Reg. 69866

The commenter also noted that EPA also requests comments on its proposed revisions to its benefits

assessment under EO12866. 69 Fed. Reg. 69,872. EO12866 states that “agencies should assess all costs and
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benefits of available regulatory alternatives.” EO12866, Section 1. Costs and benefits must be considered on a

“net” basis, meaning both positive and negative public health effects of a regulation must be considered together. 

Id. The fact that it is difficult to quantify certain costs and benefits does not mean these costs and benefits may be

ignored. Under EO12866, “[c]osts and benefits shall be understood to include both quantifiable measures (to the

fullest extent that these can be usefully estimated) and qualitative measures of costs and benefits that are difficult to

quantify, but nevertheless essential to consider.” Id. EPA’s analysis of the “cost [and] nonair quality health and

environmental impacts” and its EO12866 benefits assessment are defective because they fail to consider significant

societal costs associated with unduly-stringent Hg regulations. Indeed, a number of outcomes forecast by the

modeling performed in this docket (e.g., plants shutting down) would cause significant economic and human

health impacts that are overlooked in EPA’s analysis. If coal plants are modeled to shut down (e.g., Cinergy’s

model of “Stringent MACT Plus CAIR,” 69 Fed. Reg. 69868, col. 3) or reduce capacity factors, these shut downs

will cause the economic impacts of increased gas and electricity prices. These higher prices will, in turn, cause

higher costs in the manufacturing sector, loss of jobs, and the loss of energy security. According to a recent study,

“replacement of U.S. coal-fueled power could impact household income by an estimated $125-$225 billion in

2010,”

In addition, forcing a shift in the nation’s fuel supply from coal to natural gas will result in significant

increased risks to public health. Depending on the models used, removing coal from America’s energy mix would

directly result in anywhere from 7,000-51,000 premature adult deaths per year. However, severe mortality impacts

would result even if EPA’s regulations do not cause a complete shut down of coal-fueled electricity, but only cause

some shift from low-cost coal generation to higher priced gas generation. One model shows that an aggregate

reduction in household income of $8.9 million induces one additional adult death. These deaths would fall

disproportionately on lower-income households.

Modeling outcomes that predict some coal-fueled units will be shut down or run at decreased capacity

must incorporate all potential impacts of such shut-downs or decreases in capacity when assessing the costs of the

regulation. At this point, EPA’s forecast modeling and benefit analysis does not consider the societal impacts of

regulations that would cause power plants to shut down or run at decreased capacity. Until such analysis is

provided, EPA has not met its obligation under EO12866 to assess all the costs and benefits of its Hg regulation

and to do so on a net basis. For the same reason, EPA will have failed to fully assess the “cost, nonair quality

health and environmental impacts” of the regulation under CAA §111 and 112(d).

Response:

The comment raises issues under the general broad issue of correctly differentiating between social costs

and economic impacts. It is critical that proper analysis not violate economic theory and the principles of benefitcost analysis in doing so. The commentor suggests EPA should consider the following when calculating full

societal costs:

(1) potential shut down of or decreased capacity in EGUs

(2) Higher energy costs

(3) Loss of jobs

(4) Loss of income

(5) Loss of energy security

We address each of these separately.

(1) Potential shut down or decreased capacity in EGUs. In fact the IPM model used by EPA to estimate costs and

other impacts, does provide an estimate of EGU shutdowns and decreased capacity, if relevant. The IPM model

estimates the costs of meeting the U.S. demand for electricity. To the extent that some EGUs shutdown, the model

must replace that lost capacity with other capacity. The cost of replacing this lost capacity is estimated by IPM. 

Hence, we want to be clear that the cost of plant shut downs (in the form of higher electricity prices) is calculated
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and is part of our cost estimates we routinely calculate.

(2) Higher energy costs. It is true that pollution control requirements can lead to higher energy prices. The IPM

model does provide estimates of higher energy prices as a result of the regulation.

(3) Loss of jobs. The commentor argues that the increased cost of electricity will lead to loss of jobs. It is true

that higher electricity prices can ripple through the economy and disrupt particular industries. However, to a first

approximation, the increased spending for pollution control equipment creates the same number of jobs as the loss

in jobs from higher electricity prices. Hence, we generally consider job loss to be serious economic impact,

worthy of consideration, but it is not, in general, considered to be a "net" cost of a regulation. In fact, job

creation by a regulation is one component of the costs. WOrkers who make pollution control equipment must be

paid. This is part of the cost of buying pollution control equipment.

There is, however, one mechanism that can lead to reduced labor hours in the economy that can be a cost. In the

1990's and beyond, economists have identified and investigated the so-called tax interaction effect. The problem

arises because we the economy already taxes labor services a great deal. These labor taxes tend to generate too

little labor being provided to the economy. Any regulation that gives rise to higher prices, can further depress the

real wage. In doing so, workers provide even less labor services to the economy. While this is conceptually

understood by economic modelers, the empirical estimates of this effect vary widely. Further, the benefits of

environmental improvement tend to raise the productivity of the American worker. Reduced mercury, for

example, will raise IQ levels in the economy. As workers get smarter, productivity increases. Hence, these type of

interaction effects can affect both the costs and benefits.

(4) Loss of income -- as in the case of jobs, some workers will find themselves with higher income and some with

lower income. In general, job losses (or gains) are not counted as social costs of the regulation.

(5) Loss of energy security. The IPM model does give estimates of the source fuels for the production of

electricity. We will then be able to estimate whether imports of oil or natural gas (or other forms of energy) will

go up or down as a result of this regulation.

Comment:

One commenter (OAR-2002-0056-5458) believed the benefits analysis must be focused on the

neurodevelopmental health of children. In the benefit analysis referenced in the proposal and identified in the

NODA, IQ reduction was chosen as the health endpoint to quantify the benefits of reducing MeHg exposure in

children. The commenter is concerned about the use of IQ as the endpoint for benefits quantification across the

three major epidemiological studies used to develop the MeHg reference dose (RID) because IQ was only directly

measured in the New Zealand study. Based upon notes from the Mercury Neurotoxicity Workshop, the selection of

IQ as the neurological endpoint for quantification seems to be based almost entirely on the fact that decrements in

IQ can be monetized. The commenter will reserve its comments on this aspect of the benefits analysis until it is

available for public review and comment.

Response:

Please see Chapter 9 of the RIA for a discussion of the derivation of the dose-response curve and Chaters

10 and 11 for a discussion of the monetized benefits. 

Comment:

One commenter (OAR-2002-0056-5488) said that to date, the EPA has not assessed the public health

benefits from reduced Hg exposure to the population, instead relying on analyses of public health co-benefits

resulting from reduced exposure to criteria air pollutants. The NODA expresses the agency’s intent to conduct

analyses of the benefits resulting from avoidance of IQ reduction in children, but it does not specify the range of
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regulatory options to be considered. Within the NODA, the only two scenarios mentioned are the base case and the

reductions afforded by the proposed CAMR. The commenter believed that such a limited analysis is entirely

insufficient to justify the setting of Hg reduction levels on a health basis. The commenter requested that the EPA

analyze and compare the public health benefits associated with Hg reduction levels that are more protective than

those proposed under the CAMR and more consistent with Hg reductions levels demonstrated above to be

achievable.

In addition, just as the agency relied on the co-benefits from reduction of criteria air pollutants in its

initial benefit estimate of the proposed CAMR, in the revised benefits analysis, co-benefits from any additional

reduction of criteria air pollutants as well as co-benefits of reductions in other toxic air pollutants must be added on

to the benefits from avoidance of IQ reduction related to reduced exposure to MeHg in each Hg reduction scenario

modeled.

The commenter agreed with the agency that the avoidance of IQ reduction is the best studied and most

easily monetized benefit of reduced MeHg exposure, and this outcome should be included in the revised benefits

analysis. But other serious health effects must also be accounted for in EPA’s benefits analysis. EPA’s benefits

analysis must give full consideration to the impacts on the immune and cardiovascular systems in addition to the

nervous system. There is compelling evidence that additional health benefits result from reduced population

exposure to MeHg beyond avoidance of IQ reduction. The commenter, therefore urged the agency to include in its

analysis the cardiovascular and immune system effects of Hg and expressly acknowledge that the actual health

benefits are greater than those estimated based on consideration of IQ effects (or reduced exposure to criteria air

pollutants) alone. In addition, the agency must account for benefits from avoided neurological effects such as

motor dysfunction that are not captured by estimates of lost income from IQ reduction.

The selection of an appropriate dose response model must ultimately depend on which model best fits the

data. The combined data from the Seychelles, Faroe Islands, and New Zealand studies are well-modeled by a

linear dose response curve. The use of a linear instead of a threshold model is supported by the EPA IRIS

database, which notes that no threshold was detected for MeHg neurotoxicity in the Faroe Islands study, as well as

the National Research Council report on MeHg. Use of a linear model will also facilitate the estimation of health

benefits from MeHg reductions below the modest levels currently proposed in the CAMR. Accordingly, the best

available science shows that a linear dose response model should be used to properly estimate the health benefits of

Hg pollution control options.

Given the complexity of this type of analysis and its application in the regulatory setting, the commenter

requested that all assumptions, methods and uncertainties in the modeling of Hg reduction benefits be clearly and

publicly documented and thoroughly peer-reviewed by a balanced body of outside experts.

Response:

The RIA includes an assessment, to the extent possible given our scientific understanding of mercury and

its behavior in the environment and impacts on human health, of the health benefits associated with the proposed

regulatory options. Due to limitations in our current understanding of these technical areas related to mercury

this benefit analysis is limited to the self-caught freshwater fish consumption pathway and to IQ deficits in

prenatally-exposed infants. In keeping with precedent in evaluating benefits of air regulations (REFERENCE),

co-benefits (in this case resulting from potential reductions in direct PM2.5) are also included in the RIA.

EPA acknowledges that emission control equipment used to reduce mercury emissions may reduce

emissions of other pollutants including PM and associated HAPs. While EPA has included an analysis of potential

cobenefits associated with reductions in direct PM2.5, limitations in our current understanding of differential

toxicity prevent us from modeling health benefits from reduced exposure to HAPs associated with that PM. 

Similarly, while EPA concurs with the National Academy of Sciences, that a variety of health endpoints may be

associated with methylmercury exposure in addition to IQ (e.g., immune system effects, cardiovascular mortality
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and additional neurodevelopmental endpoints), there is insufficient peer-reviewed evidence at this time for

conducting formal analysis of these endpoints for inclusion in the primary benefits estimate.

Comment:

One commenter (OAR-2002-0056-5502) referenced MeHg and Cardiovascular Effects. Evidence that

exposure to MeHg via fish consumption leads to a high risk of adverse cardiovascular events is generally lacking;

published findings are contradictory and inconsistent nature, and associations weak. Multiple contributing factors

for cardiovascular health and striking cultural differences in coronary heart disease rates contribute to overall

weakness in findings. It does not appear that there is “emerging evidence” that MeHg has major effects on

cardiovascular systems, nor is there good evidence for fish Hg diminishing the cardio-protective effect of fish

intake.

IQ and Neurobehavioral Tests. IQ neither meets requirements for a well-defined health effect for MeHg

exposure, nor has it been used as a primary health endpoint in the children’s MeHg studies. Major barriers to

conducting a meta-analysis of the Faeroe Islands, New Zealand and Seychelles Islands studies are: the

heterogeneity of the study designs; the neurobehavioral test batteries administered; the ages at testing; the lack of a

consistent pattern of significant results across studies (most results are non-significant; however); the differences in

study populations; and the differences in confounders measured and included in the final multivariate models. 

These inconsistencies and other shortcomings are major barriers to conducting a valid meta-analysis of the cohort

studies to date.

Use of a Linear Dose-Response Model. Alternatives to the K=1 model need to be considered. Published

analyses of the Seychelles study suggest evidence for a non-linear association for one or two neurobehavioral test

endpoints with a threshold that is consistent with previous estimates from the Iraqi study. Non-linear models need

to be applied to New Zealand and Faroes results prior to making a final determination of the best model to fit these

data. Further, a linear dose-response model is questionable given that the standard RID established by EPA

assumes a threshold dose below which there is not likely to be an appreciable risk of deleterious effects during a

lifetime.

Response:

EPA does not have access to the study data for the three key studies. The only data available to EPA are

regression coefficients and other statistics that have been published by the study investigators. Therefore, EPA is

not able to conduct any modeling that would examine alternative shapes to the dose-response relationship,

including non-linear models. EPA's analysis involves a statistical integration of linear dose-response functions

that have been reported by the study investigators. We believe that use of a linear function, in conjunction with

using a nonthreshold model, in our analysis is well-justified by the following considerations: 1) The National

Research Council's 2000 report on methylmercury used linear model results for deriving benchmark doses, and

cautioned against use of supralinear models; 2) the Faroe Islands research team reported that K-power models

(with the NRC-recommended constraint of K >1, i.e. with supralinearity excluded) fit best with the linear

specification, i.e. K=1; 3) linear model results are available for IQ for all three studies, and no non-linear model

results are available from the three studies (except for Faroes log model), and raw data are not available to us for

conducting analysis of dose-response shape or other issues; and 4) the lowest exposures in the Faroe Islands

study overlap with U.S. exposure range, although there is less overlap with the other two studies. Nonetheless,

EPA's Reference Dose and the analysis supporting its derivation was reviewed positively by the National

Academcy of Sciences and the Agency continues to support its level and the implications. We conclude that any

analysis of the IQ benefits needs to deploy several models -- with a threshold and without to capture the full range

of uncertainty. EPA acknowledges that there are complexities, including a variety of potential confounders, that

must be considered in relation to potential cardiovascular mortality linked to methylmercury exposure. For

additional discussion of this endpoint, see Appendix D.
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Comment:

One commenter (OAR-2002-0056-5535) stated that MeHg poisoning incidents, particularly the

well-known incident in Minamata, Japan, have established Hg as a neurodevelopmental toxicant. Three

prospective epidemiological studies, in the Faroe Islands, the Seychelles, and New Zealand, have been singled out

over the past five years for the development of dose response calculations. The study in the Faroe Islands

documented subtle deficits of several functional domains at prenatal MeHg exposure levels previously thought to be

safe. This finding was in agreement with the New Zealand study, as well as cross-sectional epidemiological

studies in French Guiana and the Amazon that also showed effects but do not lend themselves to dose-response

analysis. Results from the Seychelles have not been concordant, however; to date, this prospective study has not

shown effects. In keeping with prevailing standards of public health protection, EPA and the NAS have used the

Faroe and New Zealand studies as the basis for regulatory decision making.

The Faroese study recently has been updated to include state of the art neurological testing administered to

the cohort of children under study as they have matured. Previously, in a 1997 report on the Faroese population,

researchers examined children at age 7 and reported on abnormalities in CNS-mediated functions (such as

achievement of developmental milestones) and sensitive measures of neurological function (such as evoked

potentials, visual and auditory acuity, and neuropsychological functions). The new data cover subsequent

examinations of the Faroese children at age 14 years; tests included brainstem auditory evoked potentials

(BAEP’s). The authors report that the signal from the acoustic nerve to the brainstem was significantly delayed in

a dose-related fashion with prenatal exposure to Hg. Because they observed this effect at both 7 and 14 years, the

authors suggested that this effect of Hg on the developing brain is irreversible. This Hg-associated delay in

transmission appeared to be parallel to the effects on the child’s cognitive function. The measurement of BAEPs is

an objective assessment that is independent of confounding factors, such as age and socioeconomic. Most

concerning, these children had an average exposure similar to the “safe” limit (i.e., the reference dose)

recommended by EPA.

Although the mechanism by which MeHg adversely affects the developing brain is not completely

understood, there are numerous ways that the compound has been shown to affect neurons. It causes biochemical

and structural changes in mitochondria (the energy producer in the cell), disrupts protein synthesis, causes

membrane damage in nerve cells, and may create free radicals that damage lipids and result in neuronal damage. 

Oxidative damage may be a factor in MeHg toxicity, since concentrations of the repair enzyme glutathione decline

and then increase after exposure to MeHg. MeHg also has been shown to disrupt cell division and cell migration

by disrupting structural microtubular proteins. None of these effects is likely to have a clear threshold below which

it does not occur.

Other Important Health Endpoints

Beyond neurotoxicity, research links Hg with a host of other health effects. First, the impact of Hg on

overall growth and development has been supported by data published since 2000. In the Faroese cohort, pre- and

postnatal MeHg exposure was found to be associated with decreased postnatal growth, particularly before

18 months of age. The authors found that, “irrespective of duration of breast-feeding, a doubling of the Hg

concentration in cord blood was associated with a decrease in weight and height.” Second, Hg may have

immunotoxic effects. Hg induces autoimmune disease in rodents. Highly susceptible mouse strains develop

multiple autoimmune manifestations after exposure to inorganic Hg, including proliferation of lymphocytes,

elevated levels of autoantibodies, overproduction of immunoglobulins (IgG and IgE), and circulating immune

complexes that can clog the kidney and vasculature. Now, a recent cross-sectional study provides evidence that a

population of Hg-exposed adults living in the Amazon region has an increased prevalence of elevated

autoantibodies, indicative of autoimmune dysfunction.

Third, several studies have linked Hg exposure to cardiovascular disease. Although some fish species

contain beneficial omega-3 fatty acids, and fish is a low-fat source of protein, recent studies raise the possibility
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that moderate Hg content in fish may in fact diminish the cardio-protective effect of fish intake. A 2000 study

reported an association between moderate hair Hg content and accelerated progression of arteriosclerosis in the

carotid arteries leading to the brain (determined by ultrasonographic assessment of common carotid intima-media

thickness) in a prospective study among 1,014 men aged 42-60 years in Finland. Hair Hg levels greater than 2

ppm (well within the range of the U.S. adult population) showed a doubling of the risk of cardiovascular mortality. 

This study was recently updated and reported that Hg in hair above 2 ppm may be a risk factor for acute coronary

events and cardiovascular disease, coronary heart disease, and all-cause mortality in middle-aged eastern Finnish

men.

Similarly, a study published in the New England Journal of Medicine reported that toenail Hg level (an

indicator of total Hg exposure) was directly associated with the risk of myocardial infarction. This case-control

study was conducted in eight European countries and Israel, and studied 684 men with a first diagnosis of

myocardial infarction. The authors report that the Hg levels in the patients were 15 percent higher than those in

controls (95 percent confidence interval, 5 to 25 percent). The risk-factor-adjusted odds ratio for myocardial

infarction associated with the highest as compared with the lowest quintile of Hg was 2.16, a more than twofold

increase in the risk. The authors suggest certain mechanisms that may contribute to this effect, including

inactivating the protective, antioxidant properties of the repair enzymes glutathione or catalase, inducing cell

membrane damage by lipid peroxidation, promoting platelet aggregability and blood coagulability, and affecting

the inflammatory response, among several others.

Although a third study on cardiovascular health was unable to replicate these findings, the study

population consisted largely of dentists who had occupational exposure to elemental Hg. Since Hg exposure

measurements in this study were based on total Hg, the elemental Hg exposure could have confounded detection of

a MeHg effect. In fact, when the dentists were removed from the study, an association with cardiovascular

outcomes (albeit not statistically significant, possibly due to the smaller sample size) was seen with Hg exposure.

The new data on MeHg indicate that neurodevelopmental effects are likely to be permanent and to be

present-according to objective measures–at Hg levels lower than previously reported. It is also increasingly clear

that the neurodevelopmental endpoint is not the only endpoint of concern for human health, and that the

immunotoxicity of Hg will be an area of increasing concern in the future. The immunotoxicity issue is reason for

an especially precautionary approach to development of a benefits calculation. The data on cardiovascular

endpoints are sufficiently robust at this point that they should be included in a benefits assessment for Hg. The

public health and economic burden of cardiovascular disease in the U.S. is very significant, and the effect of Hg,

even if relatively modest, is significant and worthy of inclusion in the agency’s estimate of the benefits of Hg

regulation. In our opinion, it would be a mistake for the agency to ignore any of these endpoints in its benefits

assessment, even though the commenter agreed that neurodevelopment in children is an especially important

endpoint.

The focus on neurodevelopmental health of children

Although the commenter agreed that a credible benefits assessment for this rule should address the

well-established neurodevelopmental health effects of Hg toxicity, they did not believe this should be the exclusive

focus. A July 2000 review by the National Academy of Sciences (NAS) concluded that neurodevelopmental effects

were the most sensitive and well-documented effects of MeHg exposure, based on the best available data at the

time. EPA’s RfD of 0.0001 milligrams per kilogram of body weight per day (mg/kg/day) derives from a

neurodevelopmental endpoint, and the NAS determined that EPA’s RfD “is a scientifically justified level for the

protection of public health.” The RfD was based on three epidemiological studies of prenatal MeHg exposure in

the Faroe Islands, New Zealand, and Seychelles Islands. These studies examined neurodevelopmental outcomes

through the administration of numerous partial or full assessments of IQ, problem solving, social and adaptive

behavior, language functions, motor skills, attention, memory, and other functions. Although the NAS panel

found that all three studies are well-designed, prospective, longitudinal studies, it also concluded that, “given the

strengths of the Faroe Islands study, it is the most appropriate study for deriving an RfD.”
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However, as discussed above, Hg exposure has also now been linked to immune system dysfunction, other

developmental effects, and cardiovascular disease. These potentially permanent, severe, and life-threatening

effects are associated with environmentally relevant levels of Hg exposure. When calculating the benefits of

reducing Hg exposure it would be a mistake to focus on the neurodevelopmental outcomes to the exclusion of all of

these other important health endpoints. To do so would ignore the extensive new scientific information on MeHg

and would also seriously underestimate the health benefits of Hg reduction.

IQ as an endpoint for quantification of neurodevelopmental effects

EPA asks for comments regarding whether IQ is an appropriate metric for quantifying

neurodevelopmental impacts. It is not a sufficient one. The array of neuropsychological deficits associated with

even low levels of Hg exposure during early life stages includes behavioral alterations and impaired language,

attention, memory, and, to a lesser extent, visuospatial and motor functions. Most concerning, some of these

effects are detectable at exposure levels currently considered acceptable by EPA. It is clear that Hg effects are not

localized to discrete brain regions when these exposures occur prenatally or perinatally, and any credible benefits

analysis must quantitatively account for the broad spectrum of brain damage associated with Hg. Measurements of

IQ are inadequate to capture fully the profile of Hg neurodevelopmental toxicity; IQ tests do not capture

impairments of manual dexterity, motor functions, and hand-eye coordination, all known to be associated with Hg

exposure. Accordingly, to be more credible, a benefits analysis must explicitly calculate the sweeping benefits of

reduced exposure for protection of the fragile, complex developing nervous system.

Quantification and economic valuation of neurodevelopmental and other health effects

An economic valuation will not be complete unless it can account for adverse effects of early-life exposure

to Hg on cognitive abilities, neurodevelopmental deficits such as motor disabilities and hand-eye co-ordination,

immune system toxicity, impaired growth and development, and cardiovascular disease. A full economic valuation

of Hg toxicity must quantitatively account for the full array of neurodevelopmental deficits known to be associated

with Hg, such as learning, memory, IQ, visuospatial, and motor deficits. In addition, an economic valuation that

claims to represent Hg toxicity must also account for Hg-associated immunotoxicity, reproductive effects and

cardiovascular disease risks. If this cannot be done, perhaps because the data are not sufficiently robust for such a

calculation, then the resulting uncertainty and potential for error must be stated, and incorporated into the final

analysis.

The commenter supported a comprehensive approach for the development of a credible benefits analysis,

but emphasized that any such analysis must consider the variability within the data and the uncertainty inherent in

the exposure assessment and model methodology. It may be helpful in developing an integrative,

data-comprehensive benefits model, for EPA to review the NAS report. The NAS used data from the Faroe

Islands, New Zealand, and the Seychelles Islands studies to develop an integrative analysis of Hg toxicity. EPA

itself developed the RfD of 0.1 g/kg body weight per day for MeHg by integrating data from these three studies, so

it is apparent that the agency is capable of such an integrated assessment. It is consistent with EPA practice to

consider the weight of evidence of the available literature. The NAS approach relied upon a hierarchical random

effects model designed to take proper account of appropriate study-to-study and outcome-to-outcome heterogeneity

across the studies. Such a model provided a useful tool for separating random versus systematic variation and

thereby provides more stable estimates of study-specific and outcome-specific benchmark doses. The effect of the

hierarchical modeling was to smooth away much of the random variability observed in the original data,

particularly the more extreme values.

Use of the K=1 model

PA seeks comment on whether, by using a K-model with K=1, it should presume that reducing Hg

exposure will reduce adverse health effects in a linear fashion. The researchers analyzing data from the Faroe

Islands study have investigated various models applied to their data set. They have found that a log curve is the
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best fit with the data, but the improvement over a linear curve is of borderline statistical significance (p=0.06). 

Accordingly, the researchers have used a linear model for their analyses. It appears that the choice of either a

linear or a log model is reasonable. It would be unreasonable, however, for the agency to continue the past practice

of using a threshold model with a NOAEL, as such a model is unsupported by the existing data.

An alternative approach could involve doing a benchmark dose extrapolation that incorporates all

available data on Hg toxicity. The benchmark dose (BMDL) method is coming into increasing use as a pragmatic

way of dealing with dose-response relationships deriving from multiple endpoints and multiple datasets, without a

clear indication of a threshold, such as the Hg data. The BMDL is the lower 95 percent confidence limit of the

dose of a substance that increases the risk of an abnormal response by a benchmark response, such as a

5-10 percent response compared with a reference population. Such an approach would require the use of an

uncertainty factor; because a BMDL is not a no-effect level, an additional multiplier is necessary to provide

sufficient assurance that the public at large would be protected from an adverse health effect.

Use of a linear dose-response model and the appropriateness of assuming that Hg has a threshold for adverse

health effects

The data from the Faroe Islands study do not reveal evidence of a threshold below which Hg does not

exhibit some toxic effect on the developing brain. Mechanistic data also support the lack of a threshold, as Hg has

numerous adverse effects on neurons that would not be expected to have a threshold of action. Therefore the

choice of a linear model makes the most sense for analysis of the MeHg data.

Recent data from the Faroe Islands study indicate that the BMDL for deficits in neurophysiological

function is more likely to be associated with 5 g/g Hg in hair, instead of the 11 g/g that the NAS calculated,

meaning that the neurological effects of Hg have been demonstrated at an even lower dose than previously

reported. The difference is due to exposure misclassification. All calculations so far have assumed that the

exposure estimates were more precise than they really are. The Faroe Islands research team recently showed that

hair-Hg is somewhat imprecise-that is, in this case, how well the hair measurements reflected the true cord-blood

Hg exposure. Imprecise exposure assessments result in an underestimation of the true magnitude of the effect of an

exposure to MeHg. Recalculation of the benchmark dose indicated that it had been overestimated by a factor of

two. Accordingly, recalculating the exposure limit using the adjusted benchmark dose would result in a limit

approximately one-half the one used by EPA in calculating the RfD.

The commenter was also concerned about potential industry pressure on EPA to revise the RfD or to

undermine any conclusions the agency has made about risks to the U.S. population. The commenter was aware

that agency officials met with seafood industry representatives in February 2004. Accordingly, the Clean Air Task

Force requested disclosure of materials related to this meeting (and any other materials related to this or other

similar meetings) pursuant to the Freedom of Information Act, 5 U.S.C. §552. Although EPA received that

request on November 2, 2004 and is required to “respond to requests no later than 20 working days from the date

the request is received and logged in,” 40 CFR §2.104(a), the agency has not provided the Clean Air Task Force

with a substantive response. The commenter is looking forward to the agency’s response so that they can be

assured that the seafood industry has not prompted EPA’s newfound interest in the RfD.

Response:

In developing the RfD, the Agency did rely on benchmark dose modeling as the most appropriate method

of quantifying the dose-effect relationship in the three principal studies, which was also the recommendation of the

NRC (2000). EPA chose not to make a numerical adjustment between cord-blood and maternal-blood mercury. 

The relationship between cord-blood and maternal-blood mercury is considered subject to variability and

uncertainty, and was included in the determination of the uncertainty factor.

The RIA includes an assessment, to the extent possible given our scientific understanding of mercury and

its behavior in the environment and impacts on human health, of the health benefits associated with the proposed
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regulatory options. Due to limitations in our current understanding of these technical areas related to mercury

this benefit analysis is limited to the self-caught freshwater fish consumption pathway and to IQ deficits in

prenatally-exposed infants. In keeping with precedent in evaluating benefits of air regulations (REFERENCE),

co-benefits (in this case resulting from potential reductions in direct PM2.5) are also included in the RIA.

EPA concurs with the National Academy of Sciences, that a variety of health endpoints may be

associated with methylmercury exposure in addition to IQ (e.g., immune system effects, cardiovascular mortality

and additional neurodevelopmental endpoints). However, there is insufficient peer-reviewed evidence at this time

for conducting formal analysis of these endpoints for inclusion in the primary benefits estimate.

EPA acknowledges that emission control equipment used to reduce mercury emissions may reduce

emissions of other pollutants including PM and associated HAPs. While EPA has included an analysis of potential

cobenefits associated with reductions in direct PM2.5, limitations in our current understanding of differential

toxicity prevent us from modeling health benefits from reduced exposure to HAPs associated with that PM. 

Similarly, while EPA concurs with the National Academy of Sciences, that a variety of health endpoints may be

associated with methylmercury exposure in addition to IQ (e.g., immune system effects, cardiovascular mortality

and additional neurodevelopmental endpoints), there is insufficient peer-reviewed evidence at this time for

conducting formal analysis of these endpoints for inclusion in the primary benefits estimate.

Comment:

One commenter (OAR-2002-0056-5465) stated that at the most fundamental level, EPA’s proposed

revised benefits assessment appeared to suffer from the same flaw that undermined its initial benefits assessment

for the CAMR: while EPA proposed to account for the costs and benefits of the Maximum Achievable Control

Technology (MACT) and cap-and-trade alternatives as proposed by EPA in its January 30,2004 proposed rule,

EPA failed to consider whether a more protective rule would produce an even more favorable accounting of costs

and benefits. As Professors Heinzerling and Steinzor document, this failure stood in stark contrast to the current

practice of the Office of Management and Budget’s Office of Information and Regulatory Affairs in implementing

EO12866. Moreover, as numerous commenters have pointed out, EPA’s proposed approaches rest on dubious

scientific and legal footing; a legally defensible rule would in fact require much more stringent reductions in Hg

emissions from coal-fired utilities. Against this backdrop, EPA’s failure to consider the costs and benefits of a

more stringent rule is particularly egregious.

Second, as EPA now concedes, it cannot accurately assess the benefits of Hg emissions regulation without

considering the independent benefits of reducing the adverse effects of Hg contamination. However, in order to

produce an accurate accounting, EPA must not define narrowly the benefits at issue, i.e., EPA cannot consider only

a subset of the direct effects on human health (and then only those that are quantifiable or monetizable). Instead,

EPA must consider broadly the direct and indirect effects on human health and well-being. Included within this

broader definition are those effects felt not only by individual humans but also by relevant groups (e.g., adverse

impacts on the various Ojibwe and other tribes’ ability to continue important traditional, cultural and religious

practices). EPA must also consider the effects on ecological health. The commenter thus urged EPA to refer to

those tribal and other commenters, e.g., the Forest County Potawatomi Community and the Fond du Lac Tribe, that

have know ledge of and are uniquely positioned to speak to the nature and extent of the adverse effects of Hg

contamination.

Finally, EPA does not appear to contemplate any assessment of the distribution of the costs and benefits of

the CAMR and more protective alternatives. However, as Professor O’Neill demonstrates, various subpopulations’

different circumstances of exposure mean that the adverse effects of Hg reductions that are delayed and/or

diminished will not be distributed equally. Rather, the harms will be visited disproportionately on American

Indian tribes and their members–especially those in the Great Lakes states, where there is a likelihood of “hot

spots” under the EPA’s proposed cap-and-trade approach–and on other communities of color and low-income

groups. Indeed, it is clear from the preamble to the proposed CAMR that the EPA is well aware of who it is that
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will be adversely affected by a more lenient rule. In order to fulfill its obligations under EO12898 regarding

environmental justice–as well as its obligations under the federal trust responsibility, treaties, and various other

legal doctrines–EPA must assess and address the distributive implications of its proposed rule.

Response:

EPA included four potentially high-risk populations in the RIA, including: (a) high-end recreational

fisher anglers (with consumption rates at or above the 95th percentile for this group), (b) economically

disadvantaged high-end consumers with poverty-status income and fish consumption rates at or above the 95th

percentile for freshwater anglers, (c) Hmong in Minnesota and Wisconsin and (d) Chippewa in Minnesota,

Wisconsin and Michigan. These special population are intended to provide coverage for groups of individuals

who through choice, necessity or socio-cultural practices consume relatively high levels of self-caught freshwater

fish. Inclusion of these four special populations is also intended to support consideration of distributional/equity

in relation to EGU-based environmental regulation (i.e., would a subset of the US population benefit

disproportionately from regulations to reduce mercury emissions from EGUs)? 

Fish consumption rates for all four special populations have been developed based on peer-reviewed

survey data that are representative of the particular group of interest. In the case of the Chippewa, we have used

a mean value obtained from the literature (see RIA Chapter 10 for additional details). However, it was not

possible to identify a high-end percentile consumption rate based on peer-reviewed literature and consequently,

the mean consumption rate was used in the benefits analysis without consideration for variability in fish

consumption rates across individuals. However, in response to information (including that provided by this

commentor), EPA has conducted a sensitivity analysis for high end fish consumption by the Chippewa population

using (a) the maximum delta fish tissue concentration modeled in the RIA for Option 1 and Option 2 for the

Chippewa (i.e., the maximum change in MeHg fish tissue concentrations modeled for the Chippewa under CAMR

Options 1 and 2) and (b) the maximum seasonal fish consumption rate provided in the NODA comments (i.e.,

393.8 g/day). The results suggest that total IQ reductions under Option 1 and 2, even under these conservative

assumptions (i.e., highest change in mercury fish tissue concentrations under Option 1 and Option 2 and the

highest seasonal fish consumption rate), are relatively low at 0.02 IQ points per child. This relatively low IQ

benefit for this conservative scenario reflects the fact that, while states where the Chippewa are located may have

relatively high absolute (total) MeHg concentrations in target fish species, modeled EGU deposition over these

areas is relatively low and consequently, CAMR is likely to produce smaller changes in mercury fish tissue

concentrations compared with other areas where EGU deposition is higher. These findings argue against a

distributional equity concern for the Chippewa in this portion of the study area (although this conclusion needs to

be considered in the context of the overall precision and specificity of the benefits model used in this RIA which is

not intended for site-specific analysis and was developed for application at the regional-level).

 EPA has used a cost-of-illness function based on lost earnings resulting from methylmercury exposure as

the basis for its primary benefits estimate in the RIA (i.e., prenatal methylmercury exposure through maternal

consumption producing IQ decrements in children which translate into lost earnings later in life). This valuation

function, which is based on the approach used in past EPA regulations concerning lead exposure, also considers

the impact of lowered IQ on years of education achieved. EPA acknowledges that because this function is based

on cost-of-illness and not willingness-to-pay (WTP), it likely represents a lower bound for valuation of the IQ

decrements and that a more comprehensive WTP-based function would capture other factors such as those listed

by the commentor above. Note, EPA did not use a WTP-based function in the benefits analysis because peerreviewed literature does not support derivation of such a function at this time.

Comment:

One commenter (OAR-2002-0056-5571) noted that EPA has requested comments as to how reductions in

population-level exposures of Hg will improve public health. (Question 1) The commenter noted that it is

important to understand that there is a threshold for Hg levels in the blood below which there are no effects. This
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is in contrast to lead, which appears to have no clear threshold level. Unlike lead a significant (>50 percent)

percentage of atmospheric Hg is from natural sources. Mercury has been present in fish tissue prior to the

industrial revolution. EPA has selected an RfD for Hg in maternal blood (5.8 ppb) that serves as a de-facto

threshold. This number, which is 10 times below the threshold number developed from the Faroe Islands study

and 14 times lower than the WHO level of concern, is very conservative. This commenter believes that if an

unrealistically low threshold (ULT) for Hg blood levels were used to estimate benefits, reductions in blood levels

between the true threshold and the ULT would create the appearance of a benefit where there is none.

EPA has requested comments as to the appropriateness of using IQ as an endpoint for both quantifying

neurological development and the benefit analysis for reduced exposure to MeHg. In addition, EPA requested

comments on the appropriateness of a linear dose response model evaluating health impacts. The commenter

noted that there is a concern that EPA may wish to develop a relationship between Hg emissions and general

population IQ. If this relationship were then coupled with an imputed value for increased IQ for the general

population, large estimated benefits could be generated that would not exist, since there is no evidence of IQ

impact at blood Hg levels greater than the RfD but below the Faroe Island threshold level. There are opportunities

to calculate an imputed value for IQ changes, for example, recent work by Jones and Schneider estimates that a 1

point increase in national IQ is associated with a 0.16 percent annual increase in GNP. This commenter believes

that there is also a concern that assuming a linear response between blood Hg and IQ would lead to an imputed

benefit for reducing blood Hg below the threshold level, again creating benefits that do not exist.

Comment:

One commenter (OAR-2002-0056-5571) notes that EPA’s successful lead reduction program is not an

appropriate model for Hg. Lead is a pollutant that has been linked to neurological damage similar to that of Hg. 

In the late 1970s, EPA initiated a successful program designed to eliminate all lead emissions into the environment

primarily through the phase-out of leaded gasoline. Since airborne lead emissions are linked to blood lead levels in

children and related neurological impacts, it may appear reasonable to utilize the lead elimination model for

dealing with Hg. However, there are important reasons why the program to reduce lead (total elimination of air

emissions) is not appropriate for dealing with Hg.

• Virtually all airborne lead is attributed to anthropogenic sources while a large percentage of airborne Hg

(>50 percent) is due to natural sources. It is impossible to eliminate all airborne Hg emissions.

• Lead emissions and ambient lead concentrations are primarily associated with urban areas while Hg

emissions and ambient Hg concentration are global.

• While there appears to be no lower limit for neurological impacts for lead blood levels, Hg blood levels

have a clear threshold below which there are no neurological impacts.

• While neurological impacts were clearly shown at blood lead levels present in urban US children in the

1970s, no such neurological impacts have been noted or documented at Hg blood levels currently found in

American child-bearing age women or children.

This commenter believes that EPA should consider the loss of health benefits associated with reduced fish

consumption due to an overly conservative RID for Hg blood levels in determining net health benefits due to the

CAMR. The vast majority of health studies have concluded that the benefits of fish consumption by all segments

of the general population far outweigh any effects due to blood Hg levels greater than EPA’s RID and at levels

approaching the WHO level of concern. The use of the RID as the basis for calculating fish warning Hg levels has

resulted in a reduction in fish consumption and the related loss of health benefits to the public. The commenter

supports the comments of the Center for Science and Public Policy in this regard.

In conclusion, the commenter believes that the combination of (1) an overly conservative blood Hg
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threshold and a linear dose response with assumed benefits accruing below the threshold level along with (2) the

failure to properly account for the loss of health benefits due to reduced fish consumption based on EPA’s RID will

produce unwarranted and unrealistically high estimated benefits from Hg emission reductions from the proposed

CAMR.

Response:

As described in other responses, the Agency has high confidence in the RfD for methylmercury. EPA

encourages the public to vary the species and sources of fish in order to obtain the benefits of fish consumption

while avoiding elevated exposures to methylmercury. The fish advisory developed jointly with the Food and Drug

Administration emphasizes the benefits of including fish in a healthy diet while informing the public on ways to

reduce methylmercury exposure (http://www.epa.gov/waterscience/fishadvice/advice.html).

Comment:

The commenter (OAR-2002-0056-5455) also wished to comment on Step 5 of the NODA addressing

cost/benefit analyses and how Hg reduction will improve human health. The commenter found that EPA’s benefits

analysis did nothing to address the importance of fishing as a cultural practice. There was no way to place a dollar

amount on the benefit to spiritual well being as a result of practicing a centuries-old tradition and passing it on to

our children. In a more concrete measurement, EPA did nothing to address replacing a subsistence food source

that provided a significant amount of nutrition for the commenter’s members. In making a local, easily obtainable

food source inedible due to poisoning, EPA should calculate the costs that will be incurred in finding alternate

sources of nutrition. The commenter was also unaware of any attempts EPA had made to quantify the costs of the

learning and educational problems that exposed children may experience. For example, the loss in lifetime

earnings resulting from lowered IQ’s in the generalized population as a result of Hg poisoning has been estimated

at $2.3 billion per year. By refusing to set adequate MACT standards, EPA was heaping most of this loss on the

heads of native people. Another error in EPA’s cost/benefit analysis came from the projection of $15 billion in

savings due to health-related benefits from their proposed rule. These were simply health benefits that accrued

from EPA’s very substandard proposal. If a proper MACT standard were set in place, additional billions of dollars

could be saved.

EPA had also failed to assess tourism-related impacts. Tourism brought in $9.8 billion annually in

Minnesota alone. Of this total, sport fishing enthusiasts spend $1.58 billion, or 16 percent. Although it was

unknown to what level fish advisories impacted these number, fishing and tourism brought in income that the state

of Minnesota could not afford to lose. The other Great Lakes states of Wisconsin, Michigan, Illinois, Indiana, and

Ohio face similar situations. Together, these states, along with Minnesota, attract 7.8 million anglers annually

who spend $5 billion in fishing-related dollars. Although these are not directly health-related issues, they certainly

need to be addressed in EPA’s economic considerations.

Response:

EPA has used a cost-of-illness function based on lost earnings resulting from methylmercury exposure as

the basis for its primary benefits estimate in the RIA (i.e., prenatal methylmercury exposure through maternal

consumption producing IQ decrements in children which translate into lost earnings later in life). This valuation

function, which is based on the approach used in past EPA regulations concerning lead exposure, also considers

the impact of lowered IQ on years of education achieved. EPA acknowledges that because this function is based

on cost-of-illness and not willingness-to-pay (WTP), it likely represents a lower bound for valuation of the IQ

decrements and that a more comprehensive WTP-based function would capture other factors such as those listed

by the commentor above. Note, EPA did not use a WTP-based function in the benefits analysis because peerreviewed literature does not support derivation of such a function at this time.
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Comment:

Four commenters (OAR-2002-0056-2224, -2835, -2867, -2922) filed comments to supplement EPA’s

discussion of its statutory authority to regulate under CAA section 111 and to establish a cap-and-trade program. 

They stated that CAA section 111 confers broad legal authority for the regulation of existing sources under a

Federal-State partnership. The legislative history and the relationship between the plans developed for the

State-Federal partnerships under CAA section 110 and section 111 further supports EPA’s determination that a

flexible emissions trading program can be implemented under section 111(d).

The commenters noted that this partnership contemplates EPA establishing “standards of performance” at

the national level and each state developing a regulatory program for implementing and enforcing those standards

at the state level. The commenters pointed out that the statute explicitly notes that the Federal-State partnership

under CAA section 111(d) is to be modeled after the regulatory process used under CAA section 110. In that

regulatory context, CAA section 110 provides States with wide latitude in developing emissions control strategies

for achieving Federal air quality goals — National Ambient Air Quality Standards (NAAQS) established by EPA

at the national level.

Both the statute and legislative history confirm that Congress delegated broad legal authority to adopt

flexible regulatory mechanisms for controlling existing sources under section 111(d)(1). This broad delegation of

authority provides sufficient authority for EPA to establish flexible “standards of performance” that need not

prescribe when, how, and the degree to which each affected unit must achieve that emissions limitation — either

on a unit-by-unit basis or facility-by-facility basis. In addition, the CAA authorizes States to implement and

enforce those standards of performance through cap-and-trade program or other such flexible, market-based

mechanism that implements the reduction requirement imposed under the standard of performance, while taking

into consideration “the remaining useful life” of the source as well as “other factors.” EPA’s proposed trading

scheme is one effective mechanism for States to address concerns regarding existing units whose remaining useful

life is limited such that the purchase of allowances may be appropriate in lieu of making additional major pollution

control investments at those units. Commenter OAR-2002-0056-2835 described in detail how this interpretation is

confirmed in the legislative history to CAA section 111(d).

Another indication of the broad discretion accorded to EPA and States in implementing and enforcing

standards of performance under section 111 (d)(1) is the relationship that this section has with section 110. 

Section 111 (d)(1) requires EPA to promulgate regulations that establish SIP-like procedures similar to those in

section 110 to be used by States in submitting their plans. The CAA section 111(d) plans and SIP programs are

complementary to one another – in particular, a State’s plan under section 110 (or section 172, for non-attainment

areas) can be used to meet the standards under section 111(d). States can thus use the SIP regulatory tools in CAA

sections 110(a)(2)(A) and 172(c)(6) to establish “enforceable emissions limitations and other control measures” to

achieve this end. One such regulatory tool available to States explicitly referenced under these sections is the

adoption of “economic incentives such as fees, marketable permits, and auctions of emissions rights,” when

developing a plan to comply with the standards under section 111(d)(1).

This complementary relationship was confirmed in EPA’s guidance for implementing the Emission

Guidelines for Municipal Waste Combustors established under CAA sections 111(d) and 129. EPA’s guidance

explained that where the SIP requirements are adequate to meet the section 111(d)/129 standard - which are

required to be more rigorous than emission guidelines under only section 111(d) - the State has the authority to

submit a section 111(d)/129 plan that relies on the requirements of the SIP to meet the section 111 (d)/129

standard. The commenter adds that the section 111(d)/129 rule for Municipal Waste Combustors also clearly

contemplated that States would use trading when implementing and enforcing the standards-the rule explicitly

provided that a state plan could “establish a program to allow owners or operators of municipal waste combustor

plants to engage in trading of nitrogen oxides emission credits.”
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Commenter OAR-2002-0056-2867 stated that EPA has correctly harmonized these conflicting statutory

provisions, and interpreted them in a way that effectuates the purposes of the statute as whole. The commenter

agreed that the key provision in the definition of a “standard of performance” under CAA section 111 is the phrase

“the best system of emissions reduction.” Since this phrase is not defined by statute, EPA has broad discretion in

determining what is the “best system of emissions reduction,” so long as the system ultimately selected “has been

adequately demonstrated.” The commenter pointed out the definition places no other explicit statutory constraints

on EPA in making this determination, except that it must consider the following factors: the cost of achieving the

Hg reductions, non-air quality health and environmental impacts, and energy requirements. The commenter

concluded that the statute requires the standards of performance be based on “the degree of emission limitation

achievable” by the best system of emissions reduction system selected by EPA. As evidenced by the success of

other cap-and-trade programs for the power sector, i.e., the NOx SIP Call and the Title IV Acid Rain Program, the

trading program approach arguably satisfies the statutory requirement for setting the standard of performance

based on the best system of emission reduction for the electric utility source category.

The commenter felt it is important to note that the statutory definition does not require specific units or

facilities to install emissions control technology. In addition, the definition is silent on whether or not the standard

of performance prescribing specific emissions limits should directly apply on a unit-by-unit or facility-by-facility

basis. The commenter also noted that the definition is silent on whether each unit or facility must achieve specific

reduction levels continuously or averaged over a specific period of time. (Regarding this issue, the commenter

pointed out that CAA section 302(1) also contains a definition of the term “standard of performance,” which

defines the term to mean “a requirement of continuous emission reduction, including any requirement relating to

the operation or maintenance of a source to assure continuous emissions reduction.” It appears to the commenter

that this definition would not be controlling for purposes of setting standards of performance under section 111,

given that Congress chose to adopt another specific definition of standard of performance in CAA section 111.

Three commenters (OAR-2002-0056-2224, -2835, -2867) emphasized that CAA section 111(d)(1) itself

does not independently mandate that standards of performance for existing sources impose a source-specific

requirement for continuous emission reduction. Thus, a State plan incorporating a standard of performance that

employs a cap-and-trade mechanism would not conflict with the statutory requirements of section 111(d)(1). 

However, a strong case can be made for the proposition that the emissions cap and allowance-holding requirement

in EPA’s proposed section 111(d) trading program impose a “continuous emissions reduction” requirement on

affected electric utility units. The proposed cap-and-trade program establishes a permanent cap on Hg emissions

and requires affected sources to hold allowances that correspond to the level of Hg emissions from those sources at

all times. By its very elements, the proposed cap-and-trade program is a continuous method of emission reduction

given that there is no point in time when an affected source can emit Hg without holding allowances that

correspond to those emissions. EPA’s proposal also requires continuous emissions monitoring to assure that a

source complies with the requirements of the cap-and-trade program at all times. Thus, if a court were ever to

construe section 111(d)(1) to require a “continuous emission reduction,” the features of EPA’s proposed trading

program should meet that requirement.

The legislative history of the term “standard of performance,” does not specifically reference an allowance

trading system as a regulatory mechanism for controlling emissions under CAA section111(d), but generally

reflects Congress’ intent that existing sources be accorded considerable flexibility in meeting the section 111(d)

standards. Such legislative intent for compliance flexibility provides general support for EPA’s interpretation that

the term “standard of performance” may include an allowance trading program, as proposed in the Hg rule,

because such a trading program accords flexibility to sources.

According to the commenter, the Senate debate on the 1990 amendments reinforces this statutory

interpretation, in light of Congress’ express action removing any specific percent reduction requirement from the

concept of “standards of performance.” As an example, the commenter states that Senator Baucus explains that

Congress adopted a percentage reduction requirement in the 1977 CAA Amendments to ensure that coal-fired

electric generating units did not rely on low-sulfur “compliance” coal alone to meet NSPS for SO2. According to
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Senator Baucus, a percentage reduction requirement across the board was supposed to require SO2 scrubbers

regardless of the rank of coal combusted; however, this approach accentuated the regional split over coal use that

existed prior to 1977. With the adoption of the SO2 emissions cap under the Title IV acid rain program, the

percentage reduction requirement was no longer necessary and could in fact be a barrier to flexible compliance

under the acid rain trading program. The commenter continues that accordingly, Congress elected to repeal the

percent reduction requirement during the 1990 CAA Amendments.

The commenter also referenced remarks in debate by Senator Bond during the 1990 CAA Amendments

that also pertain to the removal of the percentage reduction requirement and, indirectly, the continuous emission

reduction requirement. Specifically, Senator Bond explained that both the House and the Senate rejected the

concept of the percentage reduction and “directed EPA to come up with an alternative standard that would allow

utilities to meet it in the most flexible manner possible.” Senator Bond further noted that the new standards could

be met by fuel switching, the use of technology and fuel switching, by technology alone, and by intermittent

controls or intermittent operation. Senator Bond continued by stating that “[t]he way the language is constructed,

intermittent controls can be allowed to comply with this section of the act. So for the first time in 13 years we will

have EPA setting. . . emission levels for SO2 that will not require the use of the scrubbers for compliance.”

The commenter stated that this flexibility was not intended to be limited to utility standards, or the

operation of the Acid Rain Program, but was to be afforded to all sources subject to “standards of performance”

under section 111. The commenter felt it would be ironic if EPA failed to take advantage of the flexibility

specifically intended by Congress to benefit the utility industry in the context of developing requirements for Hg

control, since EPA itself has not identified any particular control technology as the basis for its standards.

Response:

Section 111(d)(1) authorizes EPA to promulgate regulations that establish a State Implementation Planlike (SIP-like) procedure under which each State submits to EPA a plan that, under subparagraph (A), “establishes

standards of performance for any existing source” for certain air pollutants, and which, under subparagraph (B),

“provides for the implementation and enforcement of such standards of performance.” Paragraph (1) continues,

“Regulations of the Administrator under this paragraph shall permit the State in applying a standard of

performance to any particular source under a plan submitted under this paragraph to take into consideration,

among other factors, the remaining useful life of the existing source to which such standard applies.”

Section 111(a) defines, “(f)or purposes of...section (111),” the term “standard of performance” to mean

a standard for emissions of air pollutants which reflects the degree of emission limitation

achievable through the application of the best system of emission reduction which (taking into

account the cost of achieving such reduction and any non-air quality health and environmental

impact and energy requirements) the Administrator determines has been adequately

demonstrated.

Taken together, these provisions authorize EPA to promulgate a “standard of performance” that States

must, through a SIP-like system, apply to existing sources. A “standard of performance” is defined as a rule that

reflects emission limits to the degree achievable through “the best system of emission reduction” that EPA

“determines has been adequately demonstrated,” considering costs and other factors.

A cap-and-trade program reduces the overall amount of emissions by (i) requiring sources to hold

allowances to cover their emissions on a one-for-one basis; (ii) limiting overall allowances so that they cannot

exceed specified levels (the “cap”); and (iii) reducing the cap to less than the amount of emissions actually

emitted, or allowed to be emitted, at the start of the program. In addition, the cap may be reduced further over

time. Authorizing the allowances to be traded maximizes the cost-effectiveness of the emissions reductions in

accordance with market forces. Sources have an incentive to endeavor to reduce their emissions cost-effectively; if

they can reduce emissions below the number of allowances they receive, they may then sell their excess allowances

on the open market. On the other hand, sources have an incentive to not put on controls that cost more than the

allowances they may buy on the open market.
1 The legislative history of the term, “standard of performance,” does not address an

allowance/trading system, but does indicate that Congress intended that existing sources be accorded flexibility in

meeting the standards. See “Clean Air Act Amendments of 1977,” Committee on Interstate and Foreign

Commerce, H.R. Rep. No. 95-294 at 195, reprinted in 4 “A Legislative History of the Clean Air Act Amendments

of 1977,” Congressional Research Service, 2662. Because Congress intended flexibility for existing sources, EPA

interprets this legislative history as generally supportive of interpreting “standard of performance” to include an

allowance/trading program because such a program accords flexibility to sources. The legislative history contains

no direct indication that Congress intended to preclude EPA from implementing section 111 for existing sources

through a cap-and-trade program.

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The term “standard of performance” is not explicitly defined to include or exclude an emissions cap and

allowance trading program. In today’s action, EPA finalizes its proposal to interpret the term “standard of

performance,” as applied to existing sources, to include a cap-and-trade program. 

Because Congress did not speak precisely to this issue, EPA’s interpretation of the term to authorize a

cap-and-trade program is entitled to deference and should be upheld by a Court because the interpretation is

reasonable. Chevron, U.S.A., Inc. v. Natural Resources Defense Council, Inc., 467 U.S. 837, 842-73 (1984). This

interpretation is supported by a careful reading of the section 111(a) definition of the term, quoted above. 

In the phrase, “standard of performance,” the first operative term is “standard” and the standard must be

“for emissions of air pollutants.” The ordinary definition of “standard” is “[a]n accepted measure of comparison

for quantitative or qualitative value,” or “criterion.” Webster’s II New Riverside University Dictionary 1131

(1984). Under the cap-and-trade requirement, each existing source is obligated to hold an allowance for each unit

of mercury that it emits. This requirement to hold allowances sufficient to cover emissions meets the definition of

the term, “standard” because the requirement constitutes a means of measurement, or a type of a criterion, “for

emissions of air pollutants.” That is, the measure or criterion for a source’s emissions of air pollutants is the

amount of allowances that the source holds.

A cap-and-trade program is also consistent with the remaining components of the term “standard of

performance,” that is, the “standard for emissions of air pollutants” must be one (i) “which reflects the degree of

emission limitation achievable” (i.e., which requires an amount of emissions reductions that can be achieved), (ii)

“through the application of the best system of emission reduction which (taking into account the cost of achieving

such reduction and any nonair quality health and environmental impact and energy requirements) the

Administrator determines has been adequately demonstrated.”111 

The key component of the last part of this definition is the phrase, “best system of emission reduction.” 

While the parenthetical following this phrase obligates EPA to consider the factors specified in that parenthetical,

the term “best system” itself is not defined, and implicitly accords broad discretion to the Administrator. The term

“system” implies a broad set of emissions reductions, and the term “best” confers upon the Administrator the

authority to promulgate regulations requiring a system that he or she considers superior. The parenthetical phrase

in the definition mandates consideration of certain factors, but the definition does not indicate how to weight those

factors, how specifically to apply them, or whether other factors may be considered. Nor does the provision

provide any other explicit constraints in determining the “best system.” This broad authority conferred on the

Administrator supports the view that the Administrator is authorized to interpret a cap-and-trade program as,

under the present circumstances, the “best system,” and thus as authorized under section 111(a) and (d) 

Nor do any other provisions of section 111(d) indicate that the term “standard of performance” may not be

defined to include a cap-and-trade program. Section 111(d)(1)(B) refers to the “implementation and enforcement

of such standards of performance,” and section 111(d)(1) refers to the State “in applying a standard of performance

to any particular source,” but all of these references readily accommodate a cap-and-trade program.

Although section 111(a) defines “standard of performance” for purposes of section 111, section 302(l)

defines the same term, “(w)hen used in this Act,” to mean “a requirement of continuous emission reduction,

including any requirement relating to the operation or maintenance of a source to assure continuous emission

reduction.” The term “continuous” is not defined in the CAA.

Because section 111(a) defines “standard of performance” for purposes of section 111, EPA believes that

the section 302(l) definition does not apply to section 111. However, even if the section 302(l) definition applied
2 This interpretation of the term “continuous” is consistent with the legislative history of that term. 

See H.R. Rep. No. 95-294 at 92, reprinted in 4 Congressional Research Service, A Legislative History of the Clean

Air Act Amendments of 1977, 2559.

3

 Non-electricity generating units are also included in the States’ programs.

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to the term “standard of performance” as used in section 111(d)(1), EPA believes that a cap-and-trade program

meets the definition. A cap-and-trade program with an overall cap set below current emissions is a “requirement

of...emission reduction.” Moreover, it is a requirement of “continuous” emissions reductions because all of a

source’s emissions must be covered by allowances sufficient to cover those emissions. That is, there is never a time

when sources may emit without needing allowances to cover those emissions.22

We note that EPA has on one prior occasion authorized emissions trading under section 111(d). (The

Emission Guidelines and Compliance Times for Large Municipal Waste Combustors that are Constructed on or

Before September 20, 1994; 40 CFR Part 60, subpart Cb.) This provision allows for a NOx trading program

implemented by individual States. Section 60.33b(C)(2) states,

A State plan may establish a program to allow owners or operators of municipal waste combustor

plants to engage in trading of nitrogen oxides emission credits. A trading program must be

approved by the Administrator before implementation.

Today’s proposal is wholly consistent with this prior section 111(d) trading provision.

Having interpreted the term “standard of performance” to include a cap-and-trade program, EPA must

next “determine” that such a system is “the best system of emissions reductions which (taking into account the cost

of achieving such reduction and any non-air quality health and environmental impact and energy

requirements)...has been adequately demonstrated.” Section 111(a)(1). EPA has determined that a cap-and-trade

program based on control technology available in the relevant time frame is the best system for reducing Hg

emissions from existing coal-fired Utility Units.

Since the passage of the 1990 Amendments to the CAA, EPA has had significant experience with the capand-trade program for utilities. The 1990 Amendments provided, in Title IV, for the acid rain program, a national

cap-and-trade program that covers SO2 emissions from utilities. Title IV requires sources to hold allowances for

each ton of SO2 emissions, on a one-for-one basis. EPA allocates the allowances for annual periods, in amounts

initially determined by the statute, that decrease further at a statutorily specified time. This program has resulted

in an annual reduction in SO2 emissions from utilities from 15.9 million tons in 1990 (the year the Amendments

were enacted) to 10.6 million tons in 2003 (the most recent year for which data was available). Emissions in

2003 were 41 percent lower than 1980, despite a significant increase in electrical generation. At full

implementation after 2010, emissions will be limited to 8.95 million tons, a 50 percent reduction from 1980 levels. 

The Acid Rain program allowed sources to trade allowances, thereby maximizing overall cost-effectiveness.

In addition, in the 1998 NOx SIP Call rulemaking, EPA promulgated a NOx reduction requirement that

affects 21 States and the District of Columbia (“Finding of Significant Contribution and Rulemaking for Certain

States in the Ozone Transport Assessment Group Region for Purposes of Reducing Regional Transport of Ozone;

Rule,” 63 FR 57,356 (October 27, 1998)). All of the affected jurisdictions are implementing the requirements

through a cap-and-trade program for NOx emissions primarily from utilities.33 These programs are contained in

SIP that EPA has approved; and EPA is administering the trading programs. However, for most States, the

requirements did not need to be implemented until May, 2004.

Further, EPA recently promulgated the Clean Air Implementation Rule (CAIR), which requires SIP

revisions in 28 States and the District of Columbia to reduce emissions of SO2 and or Nox because those emissions

contribute significantly to attainment problems for the PM2.5 or 8-hour ozone national ambient air quality

standards in downwind States. The EPA Administrator signed the CAIR on March 10, 2005, and the rule and

associated documents are available at http://www.epa.gov/cair/rule.html. Like the Nox SIP Call, in CAIR, EPA

authorizes, and fully expects, the States to comply with the emissions reduction requirements through

implementation of a cap-and-trade program.

The success of the Acid Rain and Nox SIP Call cap-and-trade programs for utility SO2 and Nox

emissions, respectively, which EPA duplicated in large measure with the CAIR cap-and-trade programs, leads
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EPA to conclude that a cap-and-trade program for Hg emissions from utilities qualifies as the “best system of

emission reductions” that “has been adequately demonstrated.” A market system that employs a fixed tonnage

limitation (or cap) for Hg sources from the power sector provides the greatest certainty that a specific level of

emissions will be attained and maintained because a predetermined level of reductions is ensured. The EPA will

administer a Hg trading program and will require the use of monitoring to allow both EPA and sources to track

progress, ensure compliance, and provide credibility to the trading component of the program. The benefits of the

cap-and-trade program are further described elsewhere in today’s notice and in the separate Federal Register notice

announcing EPA’s revision of its December 2000 regulatory determination and removing Utility Units from the

112(c) list of categories. 

EPA agrees that section 111(d), by relying on the Federal-state partnership, appears to incorporate the

flexibility in type of acceptable State plan that is acceptable for purposes of section 110. The acceptability of capand-trade programs for section 110 SIP planning purposes suggests that they should be acceptable for section

111(d) state planning purposes.

EPA agrees that the statutory provisions that define “standard of performance” are silent on whether such

standard applies on a unit-by-unit, facility-by-facility, or other basis; and are silent on whether the regulated entity

must achieve specific reductions levels continuously, on an average basis, or on some other basis. Because the

provisions are silent, EPA has authority to apply a reasonable interpretation, and EPA considers the cap-and-trade

program to be reasonable.

EPA further agrees that no provision of section 111(d) by its terms, nor any statements in the

accompanying legislative history, suggest that a technological requirement, or any other specific requirement that

is in the nature of a command-and-control requirement, must apply to each individual existing unit. EPA further

agrees that statements in the legislative history emphasize the flexibility that States were to be accorded in

fashioning plans for individual sources or groups of sources. H.R. Rep. No. 95-294 at 195, reprinted in Legislative

History of the Clean Air Act Amendments of 1977 at 2662 (each state is to develop a “plan” that should “be based

on the best available means (not necessarily technological) for categories of existing sources to reduce emissions;”

EPA is to “establish guidelines as to what the best system is for each [category of sources];” states “are responsible

for determining the applicability of [the] guidelines to any particular source or sources”).

EPA further agrees that a cap-and-trade program is a mechanism for taking into account remaining useful

life of the existing sources because it offers existing sources the opportunity to comply with requirements through

the purchase of allowances, and that the consistency of a cap-and-trade program with the section 111(d)

requirements lends further support for the reasonableness of interpreting the term “standard of performance” to

authorize a cap-and-trade program.

EPA further agrees that statements in the 1990 legislative history describing the repeal of the percentage

reduction requirements as designed to enhance flexibility offer further support for EPA’s interpretation of section

111(d) to allow a cap-and-trade program. E.g., Senate Debate on the Clean Air Act Amendments of 1990

Conference Report, reprinted in 1 Legislative History of the Clean Air Act Amendments of 1990, at 1149

(statement of Sen. Simpson).

Comment

Four commenters (OAR-2002-0056-2359, -2823, -2920, -3459) contended that even if the regulation of

HAP were available under 111(d), EPA’s proposal under section 111(d) is not an adequate substitute for section

112 regulation. EPA acted arbitrarily and capriciously in implying that section 111 regulation, including a cap and

trade approach, is adequate to address the harmful regional and local health and ecological impacts of HAP

emissions from power plants (2823). 

Response

EPA disagrees with commenters’ view that the Title IV and Nox SIP Call programs do not provide useful

precedent for a cap-and-trade program because, according to commenters those programs operated against a

backdrop of other requirements for local controls, including SIP measures, NSPS provisions, and NSR

requirements. EPA believes that the commenters are incorrect because many existing sources subject to Title IV or

the Nox SIP Call are not subject to other control requirements (because, for example, they were in existence before
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the promulgation of otherwise applicable NSPS rules, they are in attainment areas and thereby avoid

nonattainment SIP requirements, and they have not taken actions that would subject themselves to PSD

requirements). In any event, the utility of the Title IV and Nox SIP Call programs is that they demonstrated that

their cap-and-trade programs succeeded in cost-effective achieving reductions.

EPA acknowledges commenters’ views that in some instances, the cap-and-trade program may be

associated with increased emissions, or, at least, emissions levels that stay constant, in a particular location or

state. EPA modeled the effect of the cap-and-trade program on mercury emissions. The section 112 revision

notice and accompanying documents describe the results, including the lack of “hot spots.”

One commenter (OAR-2002-0056-5570), responded to EPA’s request for more

information on the types of fish Americans eat and the concentrations of

Hg found in these fish, the location where these fish are caught, and

the types, amounts, location and Hg levels in fish consumed by highly

exposed populations, the commenter would like to reiterate their

previous point that relevant analysis has already been done and that EPA

should utilize their own existing estimates for fish consumption

patterns and vulnerable populations. Most notably, in preparation for

the new joint EPA/FDA advisory on Hg in fish, both Agencies undertook an

evaluation of consumption patterns, locations and vulnerable

populations. In addition, external partners including a number of

states and environmental and public health organizations have also

tracked such data. Across all of these analyses, there is broad

consensus about the pervasiveness of Hg contamination, and the high

number of states with fish advisories for Hg.

 In addition, the commenter would like to affirm EPA’s apparent

intent to look at susceptible populations (i.e., the tails of the fish

consumption distribution, not just the average) to ensure that all

Americans are adequately protected.

 Response:

EPA appreciates the input from the commenter. We have carefully studied

fish consumption patterns and our analysis is presented in the RIA and in the

Effectiveness TSD.

 Comment:

 One commenter (OAR-2002-0056-5477) stated that recent scientific

studies have confirmed the serious health risks to the developing fetus

from MeHg exposure. In addition, recent studies confirm that a greater

amount of MeHg is distributed to the fetus than previously estimated,

leading to a doubling of an earlier annual estimate of newborn infants

at risk in the U.S. from 300,000 to 600,000. In the Northeast, the

prospect of over 84,000 newborns per year potentially at-risk for

irreversible neurological deficits and cardiovascular abnormalities from

MeHg exposure represents one of the most critical public health threats

in our region today.

 Over 15,000 fish samples collected in the Northeast region confirm

widespread Hg contamination of our aquatic ecosystems, irreparably

threatening human health and wildlife unless actions are taken to reduce

significant sources of Hg emissions. All Northeast states have issued

fish consumption advisories because of Hg contamination. In addition to

the toll on human health and wildlife, Hg contamination also threatens

the tourist and recreational fishing industries, which contribute $3

billion a year to our regional economy.

 Recent scientific field studies have shown that reductions in Hg
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emissions lead to reductions in the Hg concentrations in fish tissue.

After several years of implementing effective regulations to control Hg

emissions from municipal waste combustors, medical waste incinerators,

and other sources in the Northeast, the electric utility steam

generating units (EGUs) remain the largest uncontrolled source category

of Hg and other hazardous air pollutant (HAP) emissions in the region.

Further, transported Hg emissions from out-of-region coal-fired EGUs are

a major contributor to Hg deposition in the Northeast. In view of the

public health and environmental impacts associated with exposure to Hg

and other hazardous pollutants, the commenter believed it was extremely

important that the EPA take swift and aggressive steps to reduce

emissions of these pollutants from EGUs burning coal and oil.

 Response:

We have carefully studied fish consumption patterns and our

analysis is presented in the RIA and in the Effectiveness TSD.

Comment:

 One commenter (OAR-2002-0056-5464) stated that another portion of

the NODA on which EPA has requested comments is its proposed revised

benefits analysis. The commenter reiterated that Section 112(d) is

clear about the fact that MACT should be a technology-based approach,

with requirements no less stringent than what well-controlled sources

are accomplishing (i.e., "the average emission limitation achieved by

the best performing 12 percent of the existing sources" or "the emission

control that is achieved in practice by the best controlled similar

source"). Congress did not intend MACT to be based on risk assessment

or cost-benefit. However, to the extent that EPA could establish a more

stringent MACT beyond the floor and may consider cost-benefit in doing

so, the commenter offered several comments to improve the benefits

analysis.

 The commenter was concerned that EPA’s earlier benefits analysis

calculated costs relative only to reductions in emissions of fine

particulate matter (PM2.5) and focused on only certain health effects.

It did not include a comprehensive list of PM2.5-related health effects,

nor did it cover health effects related to Hg, other HAPs, ozone, sulfur

dioxide, nitrogen oxides or welfare effects related to Hg, PM, ozone,

nitrogen and sulfate deposition. While they were pleased that EPA plans

to expand its benefits analysis to include some of the health effects

related to Hg, they did not believe it will go far enough. For example,

the benefits analysis will include studies related to the effects of Hg

exposure on IQ, but it will not adequately consider the cardiovascular

health effects. There are emerging data and well-developed studies

showing an increase in death from heart attacks in men following Hg

exposure. Furthermore, in considering IQ, EPA’s analysis examines only

decreased income resulting from lowered IQ and does not consider costs

related to therapy, tutoring, special education and other remedial

efforts.

 Due to the commenter’s concern that even the revised benefits

analysis will underestimate the benefits of Hg reduction programs, they

recommend that the benefits analysis be much more comprehensive and

inclusive. Where quantitative data related to benefits are not

available, the multiple benefits of additional Hg controls should be

evaluated qualitatively and given weight in determining MACT limits that

are more stringent than the MACT floor.

 The commenter was concerned that the proposed definition of a hot

spot indicates that the plant must cause exposures above the RID and

believed this was inadequate. As suggested by the National Academy of

Sciences panel that considered the health effects of MeHg, and further
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supported by more recent research, the dose-response to Hg appears to be

linear and effects have been reported at doses below the RID. It seems,

therefore, that the definition of "hot spot" should not rely upon the

RID.

 Given the uncertainty that EPA has admitted relative to its

modeling, the commenter felt the agency could not offer assurances about

its calculations of the contributions of individual plants. When added

to questions about health effects below the current RID, the commenter

believed EPA’s definition of hot spots in the proposal is inappropriate

and does not protect public health.

 Response:

EPA appreciates the input. Please see the RIA.

Comment:

 One commenter (OAR-2002-0056-5422) noted that EPA has requested

comments as to how reductions in population-level exposures of Hg will

improve public health. The commenter stated that it was important to

understand that there is a threshold for Hg levels in the blood below

which there are no effects. This is in contrast to lead, which appears

to have no clear threshold level. Unlike lead a significant (>50

percent) percentage of atmospheric Hg is from natural sources. Mercury

has been present in fish tissue prior to the industrial revolution. EPA

has selected an RfD for Hg in maternal blood (5.8 ppb) that serves as a

de-facto threshold. This number, which is 10 times below the threshold

number developed from the Faroe Islands study and 14 times lower than

the WHO level of concern, is very conservative. If an unrealistically

low threshold (ULT) for Hg blood levels were used to estimate benefits,

reductions in blood levels between the true threshold and the ULT would

create the appearance of a benefit where there is none.

 EPA has requested comments as to the appropriateness of using IQ

as an endpoint for both quantifying neurological development and the

benefit analysis for reduced exposure to MeHg. In addition, EPA

requested comments on the appropriateness of a linear dose response

model evaluating health impacts. There is a concern that EPA may wish

to develop a relationship between Hg emissions and general population

IQ. If this relationship were then coupled with an imputed value for

increased IQ for the general population, large estimated benefits could

be generated that would not exist, since there is no evidence of IQ

impact at blood Hg levels greater than the RfD but below the Faroe

Island threshold level. There are opportunities to calculate an imputed

value for IQ changes, for example, recent work by Jones and Schneider

estimates that a 1 point increase in national IQ is associated with a

0.16 percent annual increase in GNP. There is also a concern that
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assuming a linear response between blood Hg and IQ would lead to an

imputed benefit for reducing blood Hg below the threshold level, again

creating benefits that do not exist

 EPA’s successful lead reduction program is not an appropriate

model for Hg. Lead is a pollutant that has been linked to neurological

damage similar to that of Hg. In the late 1970s, EPA initiated a

successful program designed to eliminate all lead emissions into the

environment primarily through the phase-out of leaded gasoline. Since

airborne lead emissions are linked to blood lead levels in children and

related neurological impacts, it may appear reasonable to utilize the

lead elimination model for dealing with Hg. However, there are

important reasons why the program to reduce lead (total elimination of

air emissions) is not appropriate for dealing with Hg.

• Virtually all airborne lead is attributed to anthropogenic sources

 while a large percentage of airborne Hg (>50 percent) is due to

 natural sources. It is impossible to eliminate all airborne Hg

 emissions.

• Lead emissions and ambient lead concentrations are primarily

 associated with urban areas while Hg emissions and ambient Hg

 concentration are global.

• While there appears to be no lower limit for neurological impacts

 for lead blood levels, Hg blood levels have a clear threshold

 below which there are no neurological impacts.

• While neurological impacts were clearly shown at blood lead levels

 present in urban US children in the 1970s, no such neurological

 impacts have been noted or documented at Hg blood levels currently

 found in American child-bearing age women or children.

Response:

EPA appreciates the input. Please see the RIA.

Comment:

One commenter (OAR-2002-0056-5477) stated that in its NODA, EPA notes that it had

included a benefits assessment in its earlier proposed CAMR. The commenter would like to note

that EPA’s benefits assessment was inadequate for the important issue of establishing
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“Beyond-the-floor MACT.” EPA goes on to state that it has “preliminarily revised its proposed

approach to analyzing the benefits associated with Hg emission reductions from power plants.” In

our earlier comments, the commenter did not propose a methodology for benefits assessment. 

Since then the commenter ha completed an extensive and comprehensive draft report “Estimating

Reductions in U.S. Mercury Exposures from Decreased Power Plant Emissions and the

Associated Economic Benefit,” that is undergoing an intensive peer review. The extensive

scientific work that forms the basis of this report was undertaken by the commenter with Harvard

Center for Risk Analysis (HCRA), part of the Harvard School of Public Health (HSPH).

The report was prepared by Glenn Rice of HSPH as part of his doctoral work under the

direction of Dr. James Hammitt, Director, Harvard Center for Risk Analysis. The report covers

diverse areas of research, including: Hg emissions from sources, atmospheric transport and fate of

Hg, atmospheric modeling and estimation of Hg deposition, relationship between Hg deposition

and MeHg levels in fish (and how they change with changes in emissions), current and future

exposures of humans to Hg in fish, dose response functions, and finally, the monetization of the

benefits related to reduced Hg emissions from coal-fired power plants. The report evaluates these

effects in four sequential tasks:

Task 1: Estimation of the effect of a specified reduction in power plant emissions of Hg

on changes in regional Hg deposition and the resulting concentrations of MeHg in fish.

Task 2: Estimation of the effect of changes in MeHg concentrations in fish on human

uptake.

Task 3: Estimation of the effect of changes in human uptake on the incidence of adverse

human health effects.

Task 4: Quantification of the “monetized” value of the change in incidence of health

effects.

Some of the benefits of controlling Hg are monetized for two Hg control scenarios. These

are based on Clear Skies Initiative (CSI) Phase I, 2010 (26 TPY cap) and Phase II, 2020 (15 TPY

cap). The Hg deposition levels for the base case (2001), as well as two pairs of base case/control

case scenarios (Phase I and Phase II) were developed by the EPA using the REMSAD model as

part of the Agency’s analysis of the Clear Skies Initiative. The commenter’s analysis estimated

two sets of monetized benefits (for Scenario 1 and Scenario 2) which are based on comparing the

control case and base case deposition levels for CSI Phase I and for Phase II. The Hg emission

estimates for the base case as well as for four future scenarios were also provided by EPA, based

on IPM outputs.

The commenter’s analysis evaluated the effect of changes in Hg emissions assuming no

changes in the population or dietary patterns of U.S. residents. For this reason, the results are

best interpreted as an estimate of the benefits of lower Hg emissions in a steady-state world with

population and fish consumption patterns similar to current conditions. To estimate the benefits
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of reduced Hg emissions in future years would require projecting changes in human population,

fish harvesting and consumption, the temporal relationship between changes in Hg emissions from

power plants and levels of MeHg in fish, and other factors.

To account for the effects of changes in Hg deposition on MeHg levels in fish, the U.S.

landmass was divided into five regions (West, Midwest, Mid Atlantic, Southeast, and Northeast). 

Additionally, the surrounding waters were studied as three regions for commercial and non

commercial fish (Gulf, Atlantic, and “all other marine waters.”). Estimates of human uptake of

MeHg through fish consumption are based on regional patterns of consumption of fish species,

both commercial and non-commercial.

The report integrates the avoided costs (or “benefits”) for two endpoints associated with a

reduction in the neurological effects that result from intrauterine MeHg exposures and with

reductions in adult fatal and non-fatal cardiovascular (myocardial) events related to adult MeHg

exposures. The effects of MeHg intake on myocardial events are less certain than the effects on

neurological events. The neurological benefits were valued using a cost-of-illness model based on

IQ-point gains that could result from decreased MeHg exposures. The non-fatal myocardial

events were valued using a cost-of-illness approach. The premature mortality events were valued

using a willingness-to-pay or value-of-statistical-life approach.

These neurological effects and the fatal and non-fatal cardiovascular effects likely account

for a large fraction of the total monetary value of damage to humans that is associated with MeHg

exposures. The study also discusses two additional effects that have been observed in children

and associated with intrauterine MeHg exposures: increased blood pressure and decreased heart

rate variability. However, the study does not quantify these risks, because the increased blood

pressure does not appear to persist and the clinical significance of changes in heart rate variability

of otherwise healthy children is not known.

Based on the preliminary results of the detailed analysis, benefits for Scenario 1 (26 TPY

cap) associated with improved IQ range from $64 million (assuming a neurotoxicity threshold

equal to the RfD) to $160 million (assuming no threshold). The corresponding benefits for

Scenario 2 (15 TPY cap) are $93 million to $230 million. Much larger benefits are associated

with avoided cardiovascular events (fatal and non-fatal). For Scenario 1, the monetized benefits

are $2.7 billion. The corresponding benefits for Scenario 2 are $3.8 billion. All of these

monetized benefits are per year. The total annual benefits for the two endpoints studied range

from $2.8 billion for Scenario 1 to just over $4 billion for Scenario 2.

It is important to note that there is considerable uncertainty in the analysis and this

includes a difference in the degree of confidence in the underlying studies for MeHg neurotoxicity

(based on the various “islands” studies) and the studies related to effects of MeHg on the

cardiovascular system. The neurological effects associated with in utero MeHg exposures are

well documented and have been thoroughly evaluated by a number of research and advisory

groups (e.g., National Research Council, 2000). However, the current published literature

providing evidence for evaluating the association between cardiovascular events with adult MeHg
9-ccliv

exposures is substantially smaller and more recent than that for the neurotoxic events.

It is also important to note that the commenter’s study did not evaluate monetized benefits

associated with EPA’s proposed MACT approach under Section 112 or EPA’s preferred

approach of performance standards under Section 111 of the Clean Air Act or other more

stringent and technologically feasible control levels (for example, less stringent of 90 percent

control (from Hg in coal) or 0.6 lb/TBTU, as proposed by the States Stakeholders, (see Appendix

A, Page 10-16, see OAR-2002-0056-5477) since EPA did not undertake modeling of these

scenarios with IPM and REMSAD/CMAQ modeling. However, it should be obvious to EPA that

monetized benefits would be substantially higher for the proposal offered by the States

Stakeholders for only a small increase in costs (based on application of extremely cost-effective

and commercially available technologies such as ACI). Thus, The commenter stood by their

previous comments in support of a 90 percent reduction in Hg emissions from coal-fired EGUs.

Response:

EPA appreciates the commenters input. Due to the summary nature of the information

provided, EPA was not able to fully evaluate the analysis and its inputs and therefore was not in

a position to incorporate the analysis summary or conclusions. 

Comment:

One commenter (OAR-2002-0056-5423) points out that, as shown in comment (O),

EPA’s premise for negative child neurodevelopment is based essentially on one endpoint from the

Faroe Island study that is representative of exposure to a cocktail of toxic chemicals like PCBs,

DDT and MeHg rather than MeHg alone as demanded by EPA’s CAMR power plant emission

controls. This commenter suggests that EPA’s claim for health “benefits” from its CAMR is

hypothetical or almost impossible to demonstrate because the suggested health concerns were

drawn on either flawed or irrelevant epidemiological data.

In direct contrast to claims of health concerns from consuming fish with trace amounts of

MeHg, this commenter offers findings from recent scientific studies supporting claims of

significant children health-related benefits derived through adequate consumption of fish or fish oil

containing omega-3 polyunsaturated fatty acids.

Helland et. al., (2003, Pediatrics, vol. 111, e39-e44) recently stated that:

“Pregnant women [of Oslo, Norway] were recruited in week 18 of pregnancy to

take 10 mL of cod liver oil [with about 2g of DHA+EPA] or corn oil until 3

months after delivery [in a randomized and double-blinded study]. Children who

were born to mothers who had taken cod liver oil (n=48) during pregnancy and

lactation scored higher [by 4 points] on the Mental Processing Composite of the

K-ABC [Kaufman Assessment Battery for Children] at 4 years of age as compared

with children whose mothers had taken corn oil. This study indicates that maternal
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supplementation with very-long-chain n-3 PUFAs during pregnancy and lactation

improves the intelligence of children at 4 years of age.”

Daniels et al. (2004, Epidemiology, 15,394-402) found that:

“Fish intake by mother during pregnancy and by the infant postnatally, was

associated with higher mean [child] development scores [in a cohort of 7421

British children]. For example, the adjusted mean MacArthur [vocabulary]

comprehension score for children [15 months old] whose mothers consumed fish

four or more times per week was 72 compared with 68 among those whose

mothers did not consume fish. Although total cord mercury levels increased with

maternal fish intake, our data did not suggest adverse developmental effects

associated with mercury. In a small study of subjects in [this] ALSPAC study,

maternal DHA levels were associated with improved visual stereo acuity among

offspring at 3.5 years of age. Fish intake during pregnancy has the potential to

improve fetal development because it is a good source of iron and long chain

omega fatty acids, which are necessary for proper development and function of the

nervous system.”

Finally, in another new study, Smuts et al. (2003, Obstetrics and Gynecology, vol.

101,469-479) explains:

“[Our] study was a randomized, double-blind, controlled, clinical trial to determine

the effects of increasing docosahexaenoic [DHA] acid intake during the third

trimester of pregnancy on pregnancy and birth outcomes. Subjects were supplied

with [DHA-] enriched eggs (mean of 133 mg of [DHA] per egg) or ordinary eggs

(mean of 33 mg of [DHA] per egg). Eighty-three percent of subjects completed

the study (291 of 350 enrolled). No subject was discontinued for an adverse

event. No safety concerns were raised by the study. The current study found a

6-day longer period of gestation when [DHA] intake was increased ... Olsen et al.

suggested that higher [DHA+EPA] intake from fish by Faroe Islanders compared

with Danes was the reason for longer gestation in Faroe Islanders. The authors

subsequently demonstrated increases in gestation of 4 and 8.5 days, respectively, in

randomized clinical trials that provided 2.7 g per day of [DHA+EPA] to a group of

healthy pregnant women and to healthy pregnant women with a previous pre-term

delivery.”

The commenter notes that claims of concern for fetal and child health by EPA and Hg

activists appear disingenuous because they largely failed to emphasize to the public the benefits of

fish consumption. This activism could unnecessarily terrorize expectant mothers into not eating a

food that promotes better fetal development and child health.

Premature birth is a striking example. So serious is this outcome that the March of Dimes

organization has adopted it as a primary cause. More than 470,000 babies are born prematurely
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every year in the U.S. These infants aren’t just small; they’re developmentally “unfinished.”

The March of Dimes provides these facts on prematurely born babies:

• Has increased by 29 percent since 1981

• Accounts for 12 percent of all live births

• Can happen to any pregnant woman

• Is the leading killer of babies in their first month of life

• Is a major cause of long-term health problems, including cerebral palsy, mental

retardation, blindness, chronic lung problems, Respiratory distress syndrome and bleeding

in the brain

• Is the number one obstetrical problem in the country

• Robs families of the full potential of their children, society of their future leaders and our

nation of strong and healthy citizens

• Places tremendous financial burdens on everyone. Hospital charges for infants with a

principle diagnosis of prematurely average $75,000, and add up to billions of dollars each

year.

Recognizing the role of fish nutrition plays in helping prevent the tragedy of premature

births, the March of Dimes is funding a Danish and Chinese research team to further clarify the

issue. One of the researchers, Dr. Sjurdur Olsen of Denmark reported that Danish women who

consumed fish or seafood at least once a week during the first 16 weeks of pregnancy have three

times less risk of low-birth weight or premature births. But a closer look at the literature will

reveal ample evidence already available that women who avoid fish in their diets during pregnancy

are at increased risk for delivering their babies early, which increases risk for their babies being

born small, sick and dying.

Response: 

The US Government emphasizes that fish and shellfish are an important part of a healthy

diet for women and young children; and that women and young children should include fish or

shellfish in their diets due to the many nutritional benefits. Recommendations for selecting and

eating fish or shellfish are made by EPA and FDA. These recommendations, if followed, should

enable women and young children to receive the benefits of eating fish and shellfish and, at the

same time, they can be confident that they have minimized their exposure to the harmful effects

of mercury. 

Comment:

One commenter (OAR-2002-0056-5423) notes that the postulated but unconfirmed

effects of MeHg on cardiovascular health in the NRC (2000) report appear to have contributed to

EPA’s RfD for MeHg.

Alan Stern, of the New Jersey Department of Environmental Protection and member of
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the NRC (2000) MeHg committee, recently revealed:

“In 2000, the National Research Council’s Committee on the Toxicological Effects

of Methylmercury issued a report (NRC, 2000) in which it considered the various

adverse health effects associated with the exposure to methylmercury (MeHg). 

Among the effects considered were cardiovascular effects. The committee

concluded that ‘Given the limits of the available data, neurotoxicity is the most

sensitive, well-documented health endpoints. However, there is emerging evidence

of potential effects on both the immune and cardiovascular systems at low doses of

exposure. Although these effects are not well understood, emerging data

underscore the need for continued research and raise the possibility of adverse

effects ... at or below the current levels of concern for developmental

neurotoxicity.’ The committee recommended that an overall uncertainty factor of

adjustment of 10 be applied to the neurodevelopmental point of departure to

derive a MeHg reference dose (RfD). This uncertainty factor, in part, addressed

the possibility that cardiovascular effects may ultimately prove to be a more

sensitive endpoint than neurodevelopment effects. The US EPA, in its derivation

of an RfD for methylmercury, followed the lead of the NRC committee in applying

a similar rationale for its 10-fold uncertainty factor adjustment (US EPA 2004).”

The commenter suggests that EPA should be more critical in providing an independent

assessment on this potentially dangerous and poorly documented claim. To that end, the

commenter offers several concise criticisms on the two main published studies (as cited by EPA’s

NODA) suggesting a connection between MeHg exposure from fish and cardiovascular disease

(CVD), coronary health disease (CHD) and even death in adults. (A longer and more thorough

review on this recent alarmism about the negative impacts of fish intake on cardiac health can be

found in “Fish, Mercury and Cardiac Health” by CSPP.) But it should be pointed out that the

third study cited by the EPA’s NODA, the Yoshizawa et al. (2002, New England Journal of

Medicine, vol. 347, 1755-1760) paper, actually reported their inability to confirm an association

of total Hg exposure and risk of CVD based on a 5-year follow-up of 33,737 U.S. male health

professionals. The results of Yoshizawa et al. (2002) clearly did not raise the “possibility that

MeHg in fish can reduce the cardio-protective effects of fish consumption in adult males” as

incorrectly implied by EPA’s citation.

First, the commenter provides some background on the two studies claiming negative

cardiac health associations with fish consumption.

(1) The Finnish Study by Salonen et al. (1995, Circulation, vol. 91,645-655; 2000,

Atherosclerosis, vol. 148,265-273) and Virtanen et. al., (2002, poster presentation in the April

23-26, 2002 American Heart Association, Asia Pacific Scientific Forum at Honolulu, Hawaii): A

study of 2005 men from Kuopio, eastern Finland found that men in the highest quarter (>2.5 ppm)

had a 1.6-fold risk of CVD death and 1.7-fold risk of CHD death when compared to men in the

lowest three quarters after adjusting for numerous risk factors including age, LDL (bad)

cholesterol and triglyceride, intakes of saturated animal fatty acids and etc.
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(2) The European/Israeli Study by Guallar et. al., (2002, New England Journal of Medicine, vol.

347, 1747-1754): A case-control study of 684 men with 724 controls reported increasing toe nail

Hg level from 0.11 to 0.66 ppm (about 0.34-2 ppm in equivalent hair Hg levels) is associated with

a doubling of the risk of myocardial infarction after adjusting for numerous risk factors like age,

family history of heart attack, smoking status, alcohol intake, diabetes, history of hypertension,

selenium intake, etc.

However, as explained in the commenter’s report, “Fish, Mercury and Cardiac Health,” 

numerous risk factors other than MeHg in fish will more likely explain most of the findings in

Salonen et. al., (1995, 2000) and Guallar et. al., (2002).

Statistics of mortality from Coronary Heart Disease: Men of Eastern Finland are especially

vulnerable

“The intake of diary products, potatoes, butter, and sugar products was very high in Finland. A

similar but lower intake pattern was observed in The Netherlands. Fruit, meat and pastry

consumption was high in the USA. Cereals and wine consumption was high in Italy, while bread

consumption was high in Yugoslavia with the exception of the Belgrade cohort. In Greece, the

intake of olive oil and fruit was very high, while the Japanese cohorts were characterized by a high

consumption of fish, rice, and soy products.”

Table 1: Age-standardized 25-year death rates per 1000 from CHD in 16 cohorts of the

Seven Countries Study. Standard error of rate in parenthesis.

Cohorts N CHD (death rates/1,OOO)

US Railroad, USA 2571 160 (7)

East Finland, Finland 817 268 (15)

West Finland, Finland 860 180 (13)

Zutphen, The Netherlands 878 169 (13)

Crevalcore, Italy 993 93 (9)

Montegiorgio, Italy 719 60 (9)

Rome Railroad, Italy 768 87 (10)

Dalmatia, Croatia 671 54 (9)

Crete, Greece 686 25 (6)

Corfu, Greece 529 48 (9)

Tanushimaru, Japan 508 30 (8)
Cohorts N CHD (death rates/1,OOO)

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Ushibuka, Japan 502 36 (8)

Velika Krsna, Serbia 511 43 (9)

Zrenjanin, Serbia 516 116 (14)

Belgrade, Serbia 536 106 (13)

Slavonia, Croatia 696 89 (10)

Menotti et al., 1999, European Journal of Epidemiology, vol. 15, 507-515

The commenter’s criticisms on Salonen et. al., (1995, 2000) include the following points:

(1) Salonen et. al., (1995) own admission: “Theoretically, our findings could be specific only for

men in Eastern Finland, who traditionally have a high intake of meat, fish, and saturated animal fat

and a low intake of selenium and vitamin C and, most likely, other vegetable-derived

antioxidants.”

(2) The Kupio population has one of the highest recorded rates of CHD and high consumption of

animal fat with high measured levels of LDL (bad) cholesterol.

(3) Stern (2005, Environmental Research, in press) pointed out that even in Salonen et al. (1995)

as long as 9 years already elapsed between the collection of hair and urine samples and the

recording of a CVD and CHD and death event. Updated report of KIHD Hg-related results in

Virtanen et. al., (2002) extends the elapse time to 16 years or so and hence contributing to a

serious potential misclassification of causes and effects.

(4) Clarkson (2002) noted that highest recorded hair level is 15.7 ppm and more than 6 standard

deviations from the mean and only a small percentage of the population has high hair Hg. Yet

high-value points may playa major role in this type of study, “it would have been of interest to see

if these correlations persisted when the very high mercury levels were excluded.”

(5) No clear accounting for stress–which is believed to be a major risk factor.

The commenter’s criticisms on Guallar et. al., (2002) include the following points:

(1) Contradicted by the negative results of Yoshizawa et al. (2002) 5-year follow-up study of

33.737 US male health professionals that covers a wider range of toenail Hg from 0 to 14.6 ppm

(or about 45 ppm in equivalent hair Hg level)

(2) Why is LDL cholesterol not measured and identified as a risk factor (while HDL and total

cholesterol were measured)?
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(3) Serious challenges and questions from Plante and Babo (2003) in New England Journal of

Medicine (vol. 348, 2151-2152): “Patients with Minamata disease and hair mercury levels above

100 ppm did not have a higher rate of death from heart disease than controls, nor did they have a

higher degree of arteriosclerosis. In the Minamata region of Japan, a population of approximately

50,000 with an average hair mercury level of 50 ppm did not have a higher rate of death from

heart disease than a reference population of 800,000 with an average level of 9 ppm. Cree Indians

with an average hair mercury concentration of 10 ppm have a lower risk of death from circulatory

disease than the rest of the population in Quebec, in which the average hair mercury level is

0.5 ppm. If, as Guallar et. al., suggest, mercury increases the risk of myocardial infarction by

more than 100 percent when the hair mercury level reaches 2 ppm, how can one explain the

absence of effects at doses greater than 100 ppm?”

Concerning “sudden death” the clinical evidence continues that fish nutrition can lower the

risk:

“The n-3 fatty acids found in fish are strongly associated with a reduced risk of sudden

death among men without evidence of prior cardiovascular disease. As compared with

men with levels of long-chain n-3 fatty acids in the lowest quartile, those with levels in the

highest quartile had an 81 percent lower risk of sudden death.” (Albert et. al., 2002)

“[W]e have summarized the growing clinical evidence that these n-3 fatty acids are

antiarrhythmic and can prevent sudden cardiac death in humans. These n-3 fatty

acids have been part of the human diet for some 2 to 4 million years. They are safe

and have been listed on the GRAS (‘generally regarded as safe’) list according to

the Food and Drug Administration in amounts up to 3.5 g of fish oil per day.” 

(Leaf et. al., 2003)

“Alexander Leaf and colleagues suggest a hypothesized cellular mechanism

through which 3 PUFAs affect ion channels to reduce the risk of arrhythmia. The

messages ... are clear. For clinicians, it is time to implement the current American

Heart Association dietary guidelines that recommend the dietary intake of 1 to 2

fish meals, particularly fatty fish, each week. For policymakers, there is a need to

consider new indication for treatment with low-dose n-3 PUFAs supplements ...”

(Siscovick et. al., 2003)

Speaking on cardiac risk concerns, Professor Tom Clarkson, Distinguished Professor of

Environmental Medicine at the University of Rochester has commented that:

“Eating lots of ocean fish isn’t much of a hazard compared to missing out on the

benefits from not eating fish. A slew of scientific reports have shown that eating

fish helps protect against cardiovascular disease and enhances brain development

before and after birth. Fish is a rich source of low-fat protein and is full of fatty

acids known to lower cholesterol. Overstating the almost negligible risk of

mercury could adversely affect millions of people who face the risk of heart
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disease.”

Dr. Eric Rimm, Professor of Epidemiology and Nutrition at Harvard School of Public

Health agreed:

“The message of fish being good has been lost and people are learning more about

the hypothetical scare of a contaminant than they are of the well documented

benefits of coronary disease reduction. The danger of the tuna fish is not well

documented compared to the potential dangers for a 50-year-old male or female

who are at a much higher risk of coronary health.”

Response:

EPA acknowledges that there are complexities, including a variety of potential

confounders, that must be considered in relation to potential cardiovascular mortality linked to

methylmercury exposure. For additional discussion of this endpoint, see Appendix D and

Appendix B of RIA for this rule.

Comment:

One commenter (OAR-2002-0056-5423) presents Figure O1 to show the rarely seen

“evidence” that both EPA and the “NAS review” in 2000 (see more criticisms of the “NAS”

[actually NRC (2000)] review under comment P below) had adopted to support their claims of

negative neurodevelopmental impacts from prenatal exposure to MeHg through maternal

consumption. The result was drawn from the Faroe Island children study originally published by

Grandjean et al. (1997, Neurotoxicology and Teratology, vol. 19, 417-428) and the particular

endpoint test (see additional criticisms by CSPP in comment Q below) is the so-called cued

Boston Naming Test (note that this is not to be equated to “IQ” as represented in the final section

of EPA’s NODA).

The commenter points out that Figure O1 clearly suggests a significant scatter in the test

scores as MeHg exposure level changes. It is also worth reminding that this particular endpoint is

indeed the best evidence allowing the EPA and “NAS” suggestions of negative impacts with

increasing MeHg exposure–as guided by various statistical fitting lines in Figure O1 despite the

large scatter. More important to note in Figure O1 is the relative position of the EPA adopted

level of MeHg RfD in the equivalent blood Hg levels of 5.8 ppb (marked as red dashed vertical

line in Figure 01). The superposition of the EPA’s adopted MeHg RfD shows a clear disconnect

to the underlying data which forms the original claim for negative impacts linked to MeHg

exposures. The commenter believes that this result makes clear the distinction between the actual

levels of harm or concern for MeHg and the hypothetical and ultra-precautionary level of safety

set by EPA’s RfD shown in Figure L1 above.

The commenter notes that there are even more serious issues in the underlying

epidemiological data from the Faroe Island children study which exposes its selection for an RfD
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level as highly inappropriate. Not the least of which is the refusal of the Faroe Islands researchers

to release their raw data to allow independent statistical analyses violates EPA’s own data quality

guidelines.

The MeHg exposure profile for the Faroe Island study is neither compatible nor directly

applicable to U.S. fish consumers. By admissions of the original Faroe Island study researchers

(mainly Dr. Philippe Grandjean and Dr. Pal Weihe) and several published scientific evaluations of

the Faroe Island study, the Faroe Island results should best be considered as a study assessing

exposures to a mixture of chemicals like PCBs, DDT and MeHg rather than MeHg alone. It has

long been noted and admitted that the Faroe Island study cohorts were contaminated by maternal

exposure to high levels of DDT and PCBs via consumption of pilot whale meat and fat. The

PCBs levels were evaluated to be about 600 times the so-called Aroclor 1254 RfD level

established by EPA’s own Integrated Risk Information System (Dourson et al., 2001,

Neurotoxicology, vol. 22, 677-689).

In addition, the commenter states that it should not go unnoticed that in a letter to the

EPA, Drs. Kenneth Poirer and Michael Dourson, both as former EPA’s RfD/Reference

Concentration Work Group co-chairs, had previously provided their scientific findings to the

Technical Information Staff at EPA, advising that: “The Faeroe Island studies are not the proper

choice for the critical study for a methylmercury RfD.” EPA continues to ignore this and more

recent scientific evaluations.

Finally, in a February 9, 2004 open letter there is the crucial clarification by Faroe Island

Children Study’s Chief Physician, Dr. Pal Weihe, that the Faroese children are exposed to Hg by

consumption of pilot whale meat only, not fish. In contrast, says Dr. Weihe, the fish consumption

most likely is beneficial to their health. Dr. Weihe’s letter follows:

To whom it may concern:

Faroe Islands women do not eat Hg-tainted fish and fish consumption does not

harm Faroese children.

In the Boston Herald, Friday, February 6, 2004, p. 20 the following was stated

about a Hg study in the Faroe Islands conducted in the cooperation with the

Harvard University: “A fish industry spokesman said that the Harvard study was

flawed because Faroe Islands women typically eat far more mercury-tainted fish

than do Americans.”

As the researcher in charge of the Hg studies on children in the Faroe Islands since

1985 I want to correct this statement. The Faroese children are not exposed to

methylmercury by eating fish. They are exposed to Hg by the traditional

consumption of pilot whale meat. Fish normally consumed in the Faroes, e.g. Cod

and haddock, are low in Hg and do not, to my opinion constitute any threat to the

health of the Faroese children. In the contrary the fish consumption most likely is
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beneficial to their health.

The Faroese authorities in 1998 recommended women who plan to become

pregnant within months, pregnant women, and nursing women to abstain from

eating pilot whale meat. The Hg concentration in the blood of pregnant women

has declined dramatically since and are now below the US-EPA limit.

Yours sincerely,

Pal Weihe, Chief Physician

The commenter asks, how can EPA or the National Research Council seriously cling to

the Faroe study for its RfD for fish consumption when the lead author states the study has nothing

to do with MeHg in fish, but only in whale meat? How can Dr. Grandjean claim associations

between IQ levels in Faroese children and fish consumption (see further discussion under

comment Q below) when Dr. Weihe reports that those children (a) are not exposed to MeHg by

eating fish, (b) are exposed to no health threat from fish, and (c) actually benefit from maternal

fish consumption?

The commenter urges EPA to discontinue relying on the very weak (and inappropriate)

scientific foundation to base its claim of negative impacts on children neurodevelopments using

the results of the inferior Faroe children study.

The commenter further documents here additional evidence of the extremism or ultraprecautionary nature of the current EPA RfD for MeHg.

First, it is clear from the ethical guidelines established by the Institutional Review Board of

the National Center for Health Statistics of the CDC that approved the NHANES study that

cautions are issued to NHANES participants only if their total hair Hg levels are above 15 ppm or

total blood Hg above 200 ppb (McDowell et. al., 2004, Environmental Health Perspectives, in

press, available online May 27, 2004). The ultra-precaution by EPA is connected to its RfD

which considers a blood Hg level to be safe only at levels below 5.8 ppb, which is dramatically

lower than the ethical guideline established by the Institutional Review Board of CDC.

Second, it is obvious from the latest results of the Japanese hair Hg measurements for

8665 individuals collected in 10 different locations over 1999 to 2002 by Yasutake et al. (2004,

Journal of Health Science, vol. 50 (2), 120-125) that the overwhelming majority of the Japanese

population, i.e., 87 percent, has hair mercury levels exceeding the mercury” safety” level set by

EPA’s RfD. Since there is no detectable epidemics of any defective mental capability of both the

Japanese adult and children populations, the commenter suggested that such reality confirms the

ultra-precautionary nature of the current EPA RfD level for MeHg, and conclude that the actual

levels of concern from MeHg exposure occurs at much higher levels (see for example, various

values identified in Figure L1) than an the RfD value of 5.8 ppb in blood Hg adopted by EPA.

Response:
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EPA acknowledges that there are complexities, including a variety of potential

confounders, that must be considered in relation to potential cardiovascular mortality linked to

methylmercury exposure. For additional discussion of this endpoint, see Appendix D.

Comment:

One commenter (OAR-2002-0056-5423) believes that this particular statement by EPA is

both confusing and misleading. The statement all by itself appears contradictory to what was

stated in comment (O) that EPA’s RfD was derived from a single neurodevelopmental endpoint.

In addition, the commenter believes that any reference to the NRC (2000) report,

Toxicological Effects of Methylmercury, about the review and assessment of these three

epidemiological studies would be more complete in noting that:

“The committee concludes that there do not appear to be any serious flaws in the

design and conduct of the Seychelles, Faroe Islands, and New Zealand studies that

would preclude their use in a risk assessment. However, because there is a large

body of scientific evidence showing adverse neurodevelopmental effects

[unfortunately, the NRC did not provide any precise citation for such evidence] ...

the committee concludes that an RfD should not be derived from a study, such as

the Seychelles study, that did not observe an association with MeHg.” (p. 6)

Therefore, the commenter concludes that the high-quality results from the Seychelles

study (with additional assessment noted below) were ignored by NRC (2000) not for any

scientifically defensible reasons, but because of a direct bias to recommend only results that show

evidence for “adverse neurodevelopmental effects.” This situation is truly unfortunate because it

is relatively well-known that the results of the Faroe Island study had been contaminated by

simultaneous exposures to other toxic chemicals like PCBs and DDT.

A post NRC (2000) analysis by Dourson et al. (2001, Neurotoxicology, vol. 22, 677-689)

recommended that “The Faroe Islands data are from exposures to a mixture of chemicals. The

Seychelles Island data are from exposures to primarily one chemical, MeHg.... We would...

encourage EPA to use the Seychelles Island data as the basis of its MeHg RfD.”

The commenter believes that this is why it is scientifically appropriate to challenge the

biased conclusions of NRC (2000) and hence EPA’s basis for its MeHg RfD. The Seychelles

Island results are clearly superior for deriving RfD exposure to MeHg for the U.S. population. 

This is so simply because that study is without toxic confounders and the Seychelles Island

mothers consumed ocean fish containing MeHg concentrations comparable to those consumed by

the general U.S. population.

In contrast to the Faroe Island study, the Seychelles Child Development Study (SCDS),

“was specifically designed to test the validity of [the] hypothesis [of adverse neurodevelopmental

effects] in a well-nourished population exposed to MeHg only from high consumption of
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unpolluted ocean fish.” The research authors recently concluded:

“[SCDS] longitudinal assessment at 9 years of age indicates no detectable adverse

effects in a population consuming large quantities of a wide variety of ocean fish. 

These results are consistent with our earlier findings in the same children examined

at 6, 19, 29 and 66 months of age. In Seychelles, fetal exposure was continuous

through frequent consumption of ocean fish containing concentrations of MeHg

comparable to those consumed by the general population in the USA. We

recorded effects from covariates known to affect child development, but did not

find an association with prenatal mercury” (p. 1692 of Myers et al., 2003, The

Lancet, vol. 361, 1686-1692).

Constantine Lyketsos of the John Hopkins Hospital (2003, Lancet, vol. 361, p. 1668) in

offering a professional overview on the implications of the Seychelles study concluded:

“On balance, the existing evidence suggests that methyl mercury exposure from

fish consumption during pregnancy, of the level seen in most parts of the world,

does not have measurable cognitive or behavioral effects in later childhood. This

conclusion is especially true against the background of the several other variables

that affect cognitive-behavioral development. The positive findings from the

Faeroe Islands and New Zealand studies may be related to the fact that pilot-whale

blubber and shark muscle contain 5-7 times the concentrations of methyl mercury

than the fish consumed in the Seychelles. While higher concentrations in seafood

do not necessarily lead to higher levels in maternal hair, consumption of much

larger boluses by the mother could lead to greater difficulty on the part of the

developing fetus to detoxify the mercury by natural mechanisms, as Meyers and

colleagues propose. Whatever the answer, the discrepant findings from the various

studies need explaining. Whilst there is always an issue of power to detect an

effect in a study reporting null findings, this is not likely to be the case in the

Seychelles study with the sample size involved. If there is subtle association that

could only have been detected in a much larger sample or through the use of more

sensitive tests, it can reasonably be argued that the effect would be small enough to

be essentially meaningless from the practical point of view. For now, there is no

reason for pregnant women to reduce fish consumption below current levels,

which are probably safe.”

Response:

In deriving the reference dose for methylmercury, EPA relied on an integrated analysis

involving three studies. These longitudinal, developmental studies were conducted in the

Seychelles Islands, the Faroe Islands, and New Zealand. The Seychelles study yielded scant

evidence of impairment related to in utero methylmercury exposure, whereas the other two

studies found dose-related effects on a number of neuropsychological endpoints. In the

assessment developed for the RfD, emphasis is placed on the results of the Faroe Islands study,
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the larger of the two studies that identified methylmercury-related developmental neurotoxicity.

Supporting evidence from the New Zealand study provides assurance that choosing this focus is

the appropriate strategy for protecting public health. Conclusions from the National Research

Council review of methylmercury support this use of the Faroes Island study and disagree with

the suggestion of a role for PCBs in the neurological effects observed (NRC. 2000. 

Toxicological Effects of Methylmercury. National Academy Press.), saying that

“The committee concludes that there do not appear to be any serious flaws in the design

and conduct of the Seychelles Islands, Faroe Islands, and New Zealand studies that

would preclude their use in a risk assessment.”

The Agency’s derivation of the RfD also followed the National Research Council

recommendation for an overall composite uncertainty factor of no less than 10.

In summary, the Agency’s overall confidence in this RfD assessment is high. Three

high-quality epidemiological studies published since the last derivation of the oral RfD in 1995,

have been included in the analysis. Two of the studies (Faroe Islands, New Zealand) reported

effects on a number of neuropsychological endpoints, whereas the third (Seychelles Islands)

reported no effects related to in utero exposure to methylmercury. Benchmark dose analysis of a

number of endpoints from both the New Zealand and Faroe Islands study converged on an RfD

of 0.1 μg/kg-day, as did the integrative analysis combining all three studies. Although there was

coexposure to PCBs in the Faroe Islands study, statistical analysis indicated that the effects of

PCBs and methylmercury were independent. Moreover, benchmark dose analysis of the

endpoints that were significantly associated with methylmercury yielded RfDs that were

approximately the same when corrected for PCBs. The same was true when the analysis was or

based on the subset of the cohort in the lowest tertile with respect to PCB levels, as compared

with the full cohort. These findings provide further evidence that the identified effects are in fact

the result of methylmercury exposure.

Comment:

One commenter (OAR-2002-0056-5423) notes that the primary author the Faroe Island

study, Dr. Philippe Grandjean, was found to have admitted in the May 20, 2002 Mercury Forum

held at Mobile, Alabama (http://www.masgc.org/mercury/) that “In conclusion, the commenter

had obtained evidence of subtle adverse effects on neurobehavioral functions, blood pressure, and

growth. At age 7 years, a doubling of the Hg exposure corresponds to a developmental delay of

up to 2 months. Although IQ tests were not done, such delays would be comparable to a loss of

about 1.5 IQ points.”

Another relevant notice is the statement in Dr. Grandjean’s written testimony at the

Mercury MACT Rule Hearing at Maine State House on March 1, 2004, that “Even though the

children that the commenter examined were all basically normal, we have documented detectable

deficits that appear to be permanent.” CSPP takes the statement to suggest that Faroese children

are essentially all normal with normal functioning capability despite the permanent “detectable
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deficits” of the sort described by Grandjean.

Finally, it was also clear that the cued Boston Naming Test conducted by the Faroe study

does not constitute a proper IQ test.

The commenter believes that, in short, Dr. Grandjean’s statements are contradictory at

best. They would not hold up in a rigorous scientific evaluation by other experts or his peers. 

They should not go unchallenged by EPA either, especially as his raw data are not transparent.

But the commenter notes that the really relevant question to assessing the statement in (Q)

is whether if any or all of these reputed neurodevelopmental outcomes and tests can be shown to

be related to MeHg exposure. In that regard, it is important to consider that for a total 17

neuropsychological tests conducted by the Faroe study to search for associations with prenatal

exposure to MeHg, only 3 tests (both the cured and uncured Boston Naming Tests and the socalled Neurobehavioral Evaluation System Continuous Performance Test) yielded statistically

significant correlations only if the Faroe researcher considers maternal cord blood as an

independent predictor (Budd-Jorgensen et. al., 2003, Environmetrics, vol. 14, 105-120). The

statistical correlation for the same 3 test scores dramatically turned insignificant or only marginally

significant when the measured maternal hair Hg is adopted as the independent variable instead.

Dr. Gary Myers, one of the main authors of the Seychelles Island Child Development

Study, makes the point that even the 3 statistical associations found by the Faroe Island study are

a lot less impressive than one is lead to think if one properly weighs in the statistical odds. In a

July 29, 2003's testimony to the Senate Environment and Public Work Committee, Myers noted:

“Through 107 months (9 years) and over 57 primary endpoints, the [Seychelles

Island] study has found only three statistical associations with prenatal MeHg

exposure. One of these associations was adverse, one was beneficial and one was

indeterminate. These results might be expected to occur by chance and do not

support the hypothesis that adverse developmental effects result from prenatal

MeHg exposure in the range commonly achieved by consuming large amounts of

fish. The test results do show associations with factors known to affect child

development such as maternal IQ and home environment so there is evidence that

the tests are functioning well [i.e., the Seychelles Island Child Development Study

shows evidence for a high degree of internal consistency].”

Myer concluded in his senate testimony:

“We do not believe that there is presently good scientific evidence that moderate

fish consumption is harmful to the fetus. However, fish is an important source of

protein in many countries and large numbers of mothers around the world rely on

fish for proper nutrition. Good maternal nutrition is essential to the baby’s health. 

Additionally, there is increasing evidence that the nutrients in fish are important for

brain development and perhaps for cardiac and brain function in older individuals.”
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The commenter believes that in the context of positive or negative brain development from

trace-Hg fish consumption, real world data trumps modeling or alarmist assertions. For example,

in the latest data from the Trends in International Mathematics and Science Study, students (grade

4 and 8) in Asia continued to excel. Singapore, Hong Kong, Japan and Korea were among the

top performers in over 50 countries participating. The U.S. placed well below these countries. 

As EPA noted, Asians are among the largest fish consuming peoples in the world. If alarming

neuropsychological and neurodevelopmental deficits from prenatal MeHg exposure through fish

consumption (as interpreted by Dr. Grandjean in the Faroe children study) are correct, then these

Asian students are the very populations that should be evidencing an epidemic in low IQ, instead

of topping the curve on international standardized math and science tests.

Response:

As many factors influence performance, relative rankings on the International

Mathematics and Science Study are not indicative of the impact of MeHG. As stated above, in

deriving the reference dose for methylmercury, EPA relied on an integrated analysis involving

three studies. These longitudinal, developmental studies were conducted in the Seychelles

Islands, the Faroe Islands, and New Zealand. The Agency’s overall confidence in this RfD

assessment is high. The US Government also emphasizes that fish and shellfish are an important

part of a healthy diet for women and young children; and that women and young children should

include fish or shellfish in their diets due to the many nutritional benefits. Recommendations for

selecting and eating fish or shellfish are made by EPA and FDA. These recommendations, if

followed, should enable women and young children to receive the benefits of eating fish and

shellfish and, at the same time, they can be confident that they have minimized their exposure to

the harmful effects of mercury. 

Comment:

The commenter (OAR-2002-0056-5460) stated that in response to EPA’s request for

feedback on the comments submitted by the Electric Power Research Institute (“PERI”) and the

UARG (see 69 Fed. Reg. at 69,873 [2nd Column]), the commenter noted that those comments

suffer from profound factual, logical and legal flaws. The commenter further stated that,

accordingly, EPA need not attempt to respond to every last technical assertion advanced by those

commenters. The commenter added that listed below are two illustrative examples of threshold,

overarching problems in the PERI and UARG comments.

The commenter stated that, first, in a strained attempt to argue that domestic power plants

do not contribute to Hg hot spots, PERI writes that a particular “geographic location” is

“utility-influenced” only if 50 percent or more of the Hg depositing there stems from utilities (See

OAR-2002-0056-2578 [“PERI Comments”]). But, the commenter stated, PERI provides no

reason to adopt its definition of “utility-influenced” and no such reason exists. The commenter

added that, plainly, utilities can contribute less than 50 percent of the Hg in a given location and

still influence that location. See, e.g., William L. Prosser, W. Page Keeton, et al., The Law of
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Torts § 52 (5th ed. 1984) (“Pollution of a stream to even a slight extent becomes unreasonable

when similar pollution by others makes the condition of the stream approach the danger point.”);

U.S. v. Alcan Aluminum Corp., 315 F.3d 179, 187 (2d Cir. 2003) (explaining that harm that is

minimal on its own may be significant when combined with other harms). The commenter stated

that, in addition, EPRI’s argument that domestic power plants do not cause hot spots cannot be

reconciled with its simultaneous assertion that the “state-of-the-science is too imprecise” to

measure the significance of reduced Hg emissions (see also OAR-2002-0056-2922 (UARG

Comments)). The commenter further stated that PERI is simultaneously claiming that EPA

cannot measure the consequences of reducing Hg emissions and that power plants are only a small

part of the Hg problem. The commenter stated that PERI cannot have it both ways: Either the

significance of power plant emissions can be measured with precision, or it cannot be. The

commenter stated that , in all events, however, EPA has already determined that Hg power plant

emissions require regulation pursuant to Section 112, and no factual or legal basis exists to undo

that decision now.

Response:

EPA has examined the commenter's concerns in context of the final rulemaking. EPA is

finalizing a cap-and-trade approach under section 111. EPA has addressed the hot spots issue

in the Revision of December 2000 Regulatory Finding on the Emissions of Hazardous Air

Pollutants from Electric Utility Steam Generating Units and the Removal of Coal- and Oil-fired

Electric Utility Steam Generating Units from the Section 112(c) List for a discussion of the

Agency’s rationale for not proceeding under Section 112 Notice and in the Technical Support

Document: Methodology Used to Generate Deposition, Fish Tissue Methylmercury

Concentrations, and Exposure for Determining Effectiveness of Utility Emission Controls in the

docket.

Comment:

The commenter (OAR-2002-0056-5460) states that with regard to step five of EPA’s

proposed revised benefits assessment methodology, EPA has not adequately explained several

aspects of its focus on IQ as the neurodevelopmental endpoint. See 69 Fed. Reg. at 69,878. The

commenter further stated that, for example, EPA has not adequately explained why it is not also

evaluating other neurodevelopmental endpoints. The commenter added that it has likewise failed

to explain how it will use the Faroe Islands and Seychelles Islands studies to measure IQ

decrements, especially given its admission that those studies did not conduct sufficient tests to

estimate IQ.

Response:

As part of its analysis of the final rule, EPA has estimated some of the health benefits of

reducing Hg from utilities. At this time EPA is only able to provide quantative estimates of the

benefits of reducing neurological impacts of exposure to MeHg for a portion of the U.S.

population. Please refer to Chapter 2 of the RIA for a description of approach and rationale. 
9-cclxx

Comment:

One commenter (OAR-2002-0056-5497) stated that the NODA indicated that an analysis

currently being performed by EPA and Harvard researchers will be peer-reviewed and placed in

the docket “as soon as it is available.” The commenter questions whether EPA can even complete

the detailed analysis described in Step 5 by March 15, 2005 – the date on which EPA says it will

issue a final CAMR – much less having it peer reviewed. The commenter further doubts whether

interested parties will have a meaningful opportunity to review and comment on this analysis

before a final rule is issued. This lack of a meaningful comment opportunity is of particular

concern because this last-minute analysis appears to be designed to overstate whatever health

effects may result from Hg emissions from coal-fired power plants.

The commenter asked why was this detailed health effects assessment not included as part

of the Hg or utility studies? Why was it not presented as part of the proposed rulemaking

package? A number of questions in this part of the NODA involve human health assumptions and

approaches that are significantly different than those recommended by the National Academy of

Science (NAS) and those used by EPA in establishing a Reference Dose (RID) for MeHg. Why

were those new approaches not vetted as part of the Integrated Risk Information System (IRIS)

database process or in some broader forum?

The commenter’s earlier comments contained a series of criticisms about EPA’s RID

process. Those comments expressed concerns about how EPA had manipulated assumptions to

produce a reference dose that was lower than ones produced by other federal or international

organizations. Many of the questions posed by EPA in the NODA seem aimed at further

manipulating available information to find even lower levels of cause and effect relationships.

Question a: The focus of neurodevelopmental health of children

The neurodevelopmental health of children should remain the focus of MeHg health

effects. Other health endpoints such as cardiovascular effects should not be used in place of

neurodevelopmental effects on children. The cardiovascular studies cited by EPA and other

commenters raise many scientific questions. The cardiovascular studies have yielded,

contradictory results. The Finnish study by Salonen that first raised concerns about the linkage

between MeHg exposure and cardiovascular disease has many problems. These problems are

discussed in detail in EPRI’s NODA comments and comments submitted by the Center for

Science and Public Policy. Briefly, Salonen’s conclusions rest on relative risk relationships that

are so low as to be questionable whether they really exist. In addition, coronary heart disease has

multiple risk factors that cannot be completely controlled in a study design–the eastern Finland

study group had high intake of meat, fish and saturated animal fat and a low intake of vitamins

and other vegetable-derived antioxidants. Finally, follow-up studies of this Finnish population

were greatly separated in time, casting further doubts on Salonen’s findings.

The ongoing National Health and Nutrition Examination Study (“NHANES”) study has
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failed to find a relationship between blood Hg concentrations and blood pressure, raising further

questions about the relationship between MeHg exposures and cardiovascular disease. Therefore,

the focus of any benefits analysis should remain on the neurodevelopmental health of children,

until other health endpoints have been studied to the extent of the neurodevelopmental ones and

those other endpoints are shown to be more sensitive than the neurodevelopmental ones.

Question b: The selection of IQ as an endpoint for quantification of neurodevelopmental

effects and whether it is an appropriate endpoint for benefits analysis for reduced exposure

to MeHg

There is no indication that IQ is a good measure of potential impacts of prenatal MeHg

exposure. The Seychelles and New Zealand studies did not find statistically significant

associations between MeHg exposures and IQ reductions. Testing in the Faroes did not include

measures of I Q. Indeed, there was no consensus among the three tests in the design phase that

IQ was an important domain that was likely to be affected by MeHg exposure.

As EPRI’s NODA comments explain in greater detail, IQ tests are not a validated

measure of brain function. Furthermore, the lack of a global IQ measure can mask subtle changes

in a specific domain.

Quite simply, the fact that IQ differences can be monetized in a benefits analysis does not

make IQ a good measure of MeHg exposure.

Question c: Whether other neurodevelopmental effects can be quantified and are amenable

to economic valuation

At this time, The commenter does not offer a response to this question.

Question d: Whether, and if so how, data from the Faroes Islands, New Zealand, and

Seychelles Islands studies can be integrated for purposes of a benefits assessment

EPRI’s NODA comments explain in great detail why integrating the Faroes, Seychelles

and New Zealand results into a meta analysis is not scientifically sound. The commenter agreed

with those comments. Factors that hinder integration include: different study populations that

have cultural differences and different possible confounders, different testing ages among the

study subjects, different diets (the diets in the Seychelles and New Zealand were based largely fish

consumption while the diet in the Faroes relied heavily on consumption of pilot whale),

differences in exposure measurements (the Faroes researchers used cord blood while the

Seychelles and New Zealand researchers used hair samples), different outcome tests were used in

each study, and differences in the covariates measured and included in multivariate analyses. 

Furthermore, there is no consistent pattern of significant results across studies. If IQ is used as

the endpoint in the meta analysis, then a surrogate needs to be found for the Faroes results. The

choice of any surrogate is problematic. For all these reasons, the lack of comparability among the

three studies precludes combining their results in a meta analysis that could be used in a benefits
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analysis.

Question e: The choice of the K=1 model for estimating the relationship between exposure

and IQ and practical alternatives to that approach

Assuming a K=1 model is inconsistent with the recommendation of the NAS panel which

favored a K 1 model.87 A K=1 assumption is also contrary to the results of two statistical

analyses of the Seychelles results that are discussed in EPRI’s NODA comments. These analyses

indicate non-linear associations between MeHg exposures and test performance. Thus, the choice

of K=1 model is not yet warranted.

Question f: The appropriateness and consistency of using a linear dose-response model

given the RfD established by EPA in 2001 (reflecting NAS review in 2000), which assumes a

threshold dose below which there is not likely to be an appreciable risk of deleterious effects

during a lifetime

In many ways, this question answers itself. A linear dose response model, that presumably

passes through the zero point, is inconsistent with the RID that EPA has established for MeHg

that assumes a threshold effect level. A linear model is also inconsistent with similar values that

have been used by the Agency for Toxic Substances and Disease Registry (ATSDR) and the

WHO in their development of RID analogues. As the question notes, the NAS panel, whose

report EPA relies on to support its RID, also viewed a threshold model as most appropriate for

MeHg.

Unfortunately, the NODA offers scant explanation of why EPA now believes that

switching to a linear model is appropriate. EPA offers no explanation as to why it may now,

interpret the Faroes, Seychelles and New Zealand results as supporting a linear model. The

NODA simply recites, without explanation, that a group of Harvard researchers will likely assume

a linear dose-response relationship.” The only other hint in the NODA as to why EPA may be

considering using a linear model is the “practicality” of using a linear model because it “would

allow [EPA] to estimate benefits of reductions in exposure due to power plants without a

complete assessment of the other sources of exposure.” While a linear model may ease the

Agency’s burden, it is nonsensical to use such a model if it does not comport with actual scientific

observation. Indeed, a linear model will vastly overstate the benefits attributed to limiting Hg

emissions from coal-fired power plants. EPA should not change from its RID threshold model

without a public review and comment process that at least rivals the one it provided when it last

revised its MeHg RID. Merely mentioning that the Agency is considering using a model without

a detailed explanation why hardly suffices as adequate notice.

Response:

EPA does not have access to the study data for the three key studies. The only data

available to EPA are regression coefficients and other statistics that have been published by the

study investigators. Therefore, EPA is not able to conduct any modeling that would examine
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alternative shapes to the dose-response relationship, including non-linear models. EPA's

analysis involves a statistical integration of linear dose-response functions that have been

reported by the study investigators. We believe that use of a linear function, in conjunction with

using a nonthreshold model, in our analysis is well-justified by the following considerations: 1)

The National Research Council's 2000 report on methylmercury used linear model results for

deriving benchmark doses, and cautioned against use of supralinear models; 2) the Faroe

Islands research team reported that K-power models (with the NRC-recommended constraint of

K >1, i.e., with supralinearity excluded) fit best with the linear specification, i.e., K = 1; 3) 

linear model results are available for IQ for all three studies, and no non-linear model results

are available from the three studies (except for Faroes log model), and raw data are not

available to us for conducting analysis of dose-response shape or other issues; and 4) the lowest

exposures in the Faroe Islands study overlap with U.S. exposure range, although there is less

overlap with the other two studies. Nonetheless, EPA's Reference Dose and the analysis

supporting its derivation was reviewed positively by the National Academcy of Sciences and the

Agency continues to support its level and the implications. We conclude that any analysis of the

IQ benefits needs to deploy several models -- with a threshold and without to capture the full

range of uncertainty. EPA acknowledges that there are complexities, including a variety of

potential confounders, that must be considered in relation to potential cardiovascular mortality

linked to methylmercury exposure. For additional discussion of this endpoint, see Appendix D.

D. Other Comments

Comment:

One commenter (OAR-2002-0056-5476) reports that to date, it has yet to receive any

responses to its request to EPA Region 5 to fulfill their Trust responsibilities and intervene on the

commenter’s behalf in the rule-making process. Therefore, this commenter is calling on EPA

Headquarters to act on its behalf and set MACT standards that will reduce Hg emissions from

utilities by 90 percent in the next 10 years. This will also fulfill EPA’s obligations under the

Environmental Justice Doctrine. As outlined in the Forest County Potawatomi’s comment letter

to EPA (see e-docket OAR-2002-0056-2173: April 27, 2004), EPA has recognized its special

obligation to protect the environmental interests of the commenter when carrying out its duties. 

The Indian Policy, first adopted in 1984, also calls for EPA to work directly with tribes on a

government-to-government basis and to encourage tribes to participate in policy-making. It has

not been made known to the commenter of any efforts that EPA has made to fulfill any of these

obligations. No consultation has taken place with the commenter, and the commenter’s requests

for Trust responsibility to be carried out have remained unaddressed.

Response:

EPA recognizes that the Federal government stands in a government-to-government

relationship with Federally recognized Tribes and has certain trust responsibilities to these

Tribes. This relationship and responsibility should guide EPA in the implementation of policies

and actions that affect Tribes. Pursuant to the government-to-government relationship, EPA
9-cclxxiv

consults with Tribes regarding actions that affect Tribes. In addition, treaties, statutes, and

executive orders create Federal obligations regarding Tribal resources. EPA believes that its

actions in developing the final rule have been consistent with the government-to-government

relationship and that the final rule itself is consistent with the trust responsibility.

EPA does not agree with the commenters who claim that it did not consult with tribes in

developing the rule. As explained in the discussion of EPA compliance with EO in the preamble

for the final rule, EPA took the following steps to consult with Tribes. EPA gave a presentation

to a national meeting of the National Tribal Environmental Council (NTEC) in April 2001, and

encouraged Tribal input at an early stage. EPA then worked with NTEC to find a Tribal

representative to participate in the workgroup developing the rule, and included a representative

from the Navajo Nation as a member the official workgroup, with a representative from the

Campo Band later added as an alternate. In March 2004, EPA provided a briefing for Tribal

representatives, the newly formed National Tribal Air Association (NTAA), and NTEC. EPA

received comments on this rule from a number of Tribes, and has taken those comments and

other input from Tribal representatives into consideration in development of this rule.

EPA disagrees that the rule will not adequately protect Tribal fishing rights. EPA agrees

that some Tribes have unique legal rights to fish arising from treaties, statutes, executive orders,

and agreements. EPA also recognizes that Tribal members may catch and consume more fish

than the general public as a result of Tribal fishing rights as well as Tribal culture, traditions,

and subsistence lifestyles.

EPA believes that this regulation adequately protects Tribal health and is consistent with

the trust responsibility for several reasons. First, the commenters understate the significance of

the fact that Hg emissions from Utility Units currently are not subject to performance standards. 

This regulation will for the first time establish performance standards applicable to Hg

emissions, and those standards will require significant reductions in the levels of Hg emissions. 

Such reductions will provide greater protection to Tribal fish resources than would otherwise be

available. Acting to provide such heightened protection is consistent with both the statute and

the Federal trust responsibility.

Moreover, the commenters offer no specific evidence that the Hg emissions reductions

from this regulation will not adequately protect Tribal health. Their main contention is that the

regulatory approach set forth in an earlier EPA proposal would have produced a 90 percent

reduction in Hg emissions and that any smaller reduction is, therefore, inadequate. That

contention rests on a misconception of an earlier Federal Register Notice, which proposed a

finding, but did not contain any specific proposal for Hg emissions regulations, and, therefore,

did not provide for any percentage of reduction. EPA has never proposed any such rule. EPA

believes that this regulation will adequately protect Tribal health.

The commenters also argue that EPA has not adequately considered the significance of

Tribal fish consumption patterns, specifically the fact that Tribal fishers consume more fish than

the general population. That comment is misplaced. As described in more detail elsewhere in
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this document, EPA carefully analyzed available information on fish consumption by Tribal

members and other sub-populations, and determined how to use the available data most

appropriately. One basis for EPA’s analysis was a study of tribal fish consumption in one

region to model consumption by other Tribes as well as other subpopulations. EPA’s approach

was to identify areas where the effects of Hg deposition from utility emissions had the greatest

effects. EPA then compared those high-deposition areas with locations with high Tribal

populations to assess the areas of greatest potential risk to Tribes. That analysis found that very

few areas where Native Americans live corresponds with high residual Hg deposition caused by

utilities. It found further, that the standards established in the regulation will significantly

reduce risks to tribal members.

Finally, as discussed in the preamble to the regulation, this regulation establishes a capand-trade program for Indian country.

As part of its analysis of the this final rule, EPA has estimated the some of the health

benefits of reducing Hg from utilities. At this time EPA is only able to provide quantative

estimates of the benefits of reducing neurological impacts of exposure to MeHg for a portion of

the U.S. population. This population covers people who recreationally catch and consume

freshwater fish. The RIA for this rule contains this analysis in Chapter 11. As part of its

assessment, EPA provides estimates for the benefits of this rulemaking to subsistence fishers,

including case study examples of the benefits to the some members of the Chippewa Tribe, the

Hmong, and low income fishers.

Comment:

One commenter (OAR-2002-0056-5476) notes that EPA has a specific obligation to

protect tribal way of life and cultural resources, not only rights and resources. Court decisions

have held that trust responsibility is not limited to the protection of treaty rights, reservation

lands, and other property held in trust for the tribes and that federal agencies may not permit

actions which would interfere with treaty rights. Instead, trust responsibility extends to all actions

of the federal governments that may affect Indian tribes, including those rights, resources, and

interests recognized under treaty, statue, executive order, and common law.

The commenter’s rights include rights to the lands, waters, and natural environment of the

Reservation. Arizona v. California, 373 U.S. 546 (1963) holds that tribes are entitled to sufficient

water and other resources to make the Reservation livable and to maintain their way of life. 

Tribes also hold rights to hunt, fish and gather on reservation lands and waters.

In addition, Congress has specifically recognized the applicability of the trust responsibility

in tribal cultural resources by instating a number of federal laws in this area. Further, the Tribes’

right to practice traditional religions under the First Amendment is recognized in the American

Indian Religious Freedom Act, 42 U.S.C. Section 1996, 1996a. The EPA has fallen far short of

its obligations in this rulemaking.
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Though the Environmental Justice guidelines dictate that EPA must identify and address

disproportionately high and adverse human health or environmental effects of its programs,

policies, and activities on minority populations and low-income populations, unfortunately, it

appears as though these guidelines are being largely ignored for the purposes of providing special

treatment to utilities. The commenter encourages EPA to assure the Tribes that EPA is actively

addressing these Environmental Justice issues per the guidelines EPA has set out for itself.

Response:

EPA recognizes that the Federal government stands in a government-to-government

relationship with Federally recognized Tribes and has certain trust responsibilities to these

Tribes. This relationship and responsibility should guide EPA in the implementation of policies

and actions that affect Tribes. Pursuant to the government-to-government relationship, EPA

consults with Tribes regarding actions that affect Tribes. In addition, treaties, statutes, and

executive orders create Federal obligations regarding Tribal resources. EPA believes that its

actions in developing the final rule have been consistent with the government-to-government

relationship and that the final rule itself is consistent with the trust responsibility.

EPA does not agree with the commenters who claim that it did not consult with tribes in

developing the rule. As explained in the discussion of EPA compliance with EO in the preamble

for the final rule, EPA took the following steps to consult with Tribes. EPA gave a presentation

to a national meeting of the National Tribal Environmental Council (NTEC) in April 2001, and

encouraged Tribal input at an early stage. EPA then worked with NTEC to find a Tribal

representative to participate in the workgroup developing the rule, and included a representative

from the Navajo Nation as a member the official workgroup, with a representative from the

Campo Band later added as an alternate. In March 2004, EPA provided a briefing for Tribal

representatives, the newly formed National Tribal Air Association (NTAA), and NTEC. EPA

received comments on this rule from a number of Tribes, and has taken those comments and

other input from Tribal representatives into consideration in development of this rule.

EPA disagrees that the rule will not adequately protect Tribal fishing rights. EPA agrees

that some Tribes have unique legal rights to fish arising from treaties, statutes, executive orders,

and agreements. EPA also recognizes that Tribal members may catch and consume more fish

than the general public as a result of Tribal fishing rights as well as Tribal culture, traditions,

and subsistence lifestyles.

EPA believes that this regulation adequately protects Tribal health and is consistent with

the trust responsibility for several reasons. First, the commenters understate the significance of

the fact that Hg emissions from Utility Units currently are not subject to performance standards. 

This regulation will for the first time establish performance standards applicable to Hg

emissions, and those standards will require significant reductions in the levels of Hg emissions. 

Such reductions will provide greater protection to Tribal fish resources than would otherwise be

available. Acting to provide such heightened protection is consistent with both the statute and

the Federal trust responsibility.
9-cclxxvii

Moreover, the commenters offer no specific evidence that the Hg emissions reductions

from this regulation will not adequately protect Tribal health. Their main contention is that the

regulatory approach set forth in an earlier EPA proposal would have produced a 90 percent

reduction in Hg emissions and that any smaller reduction is, therefore, inadequate. That

contention rests on a misconception of an earlier Federal Register Notice, which proposed a

finding, but did not contain any specific proposal for Hg emissions regulations, and, therefore,

did not provide for any percentage of reduction. EPA has never proposed any such rule. EPA

believes that this regulation will adequately protect Tribal health.

The commenters also argue that EPA has not adequately considered the significance of

Tribal fish consumption patterns, specifically the fact that Tribal fishers consume more fish than

the general population. That comment is misplaced. As described in more detail elsewhere in

this document, EPA carefully analyzed available information on fish consumption by Tribal

members and other sub-populations, and determined how to use the available data most

appropriately. One basis for EPA’s analysis was a study of tribal fish consumption in one

region to model consumption by other Tribes as well as other subpopulations. EPA’s approach

was to identify areas where the effects of Hg deposition from utility emissions had the greatest

effects. EPA then compared those high-deposition areas with locations with high Tribal

populations to assess the areas of greatest potential risk to Tribes. That analysis found that very

few areas where Native Americans live corresponds with high residual Hg deposition caused by

utilities. It found further, that the standards established in the regulation will significantly

reduce risks to tribal members.

Finally, as discussed in the preamble to the regulation, this regulation establishes a capand-trade program for Indian country.

As part of its analysis of the this final rule, EPA has estimated the some of the health

benefits of reducing Hg from utilities. At this time EPA is only able to provide quantative

estimates of the benefits of reducing neurological impacts of exposure to MeHg for a portion of

the U.S. population. This population covers people who recreationally catch and consume

freshwater fish. The RIA for this rule contains this analysis in Chapter 11. As part of its

assessment, EPA provides estimates for the benefits of this rulemaking to subsistence fishers,

including case study examples of the benefits to the some members of the Chippewa Tribe, the

Hmong, and low income fishers.

Comment

One commenter (OAR-2002-0056-5492) made the following recommendations to the

EPA regarding development of a final proposal for Hg control:

• Carbon Injection (ACI) is maturing quickly. Using a methodology that says

subbituminous coal needs a credit multiplier or higher emissions, results in fuel bias against

bituminous coal and the states that produce bituminous coal.
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• The commenter believes that wet ESPs and SCRs remove more oxidized Hg than EPA

results show.

• The western coal state congressional delegations, who are saying that technology will not

be available to remove Hg from their sub-bituminous coal, are ignoring the benefits

America has already received from investments in developing clean coal technology for Hg

removal and punishing bituminous coal users.

• A MACT standard should be fuel neutral, i.e., no separate standards for different coal

ranks.

• A fuel-neutral MACT of 3.0 lbs Hg/TBtu or less for existing EGUs will reduce Hg

emissions to less than 34 tons/year.

• A MACT standard should incorporate an alternative method to calculate plant Hg

emissions limits based on a percent reduction from the raw coal as mined. Such an

alternative would provide some amount of relief for those coals with unusually high Hg

content while still achieving meaningful reductions.

• Under the alternative cap and trade proposals, implementation dates should be adjusted to

coincide with other regulatory actions, including the Clean Air Interstate Rule and

multi-pollutant strategies such as Clear Skies.

• A cap and trade rule should not include Fuel Adjustment Factors.

• A cap and trade rule should address so-called “hot spots” that could result from allowance

trading.

The commenter appreciated the opportunity to provide comments to the U.S. EPA

regarding the proposed Hg regulations. The commenter would be pleased to provide additional

information and are willing to meet with the U.S. EPA regarding our statement.

Response:

EPA has examined the commenter's concerns in context of the final rulemaking. EPA is

finalizing a cap-and-trade approach under section 111. Please see the Revision of December

2000 Regulatory Finding on the Emissions of Hazardous Air Pollutants from Electric Utility

Steam Generating Units and the Removal of Coal- and Oil-fired Electric Utility Steam

Generating Units from the Section 112(c) List for a discussion of the Agency’s rationale for not

proceeding under Section 112. 

EPA appreciates the commenter's input to the record on the status of control

technologies. The Agency's position on the state of Hg technology is contained in the EPA 's

Office of Research and Development white paper (see Control of Emissions from Coal-Fired
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Electric Utility Boilers: An Update, EPA/Office of Research and Development, March 2005). 

Comment:

One commenter (OAR-2002-0056-5571) reports key public power concerns in response

to the EPA NODA. This commenter prefers a cap and trade approach to controlling Hg without

disadvantaging smaller utilities with only one generating unit or few fuel options. The commenter

endorses comments from UARG and PERI.

The commenter continues to support an exemption for small units and requests that EPA

streamline the monitoring requirements for small and/or exempt units regardless of decision to use

cap and trade approach (Sec. 111 or 112 (n) (1) (A) or MACT Approach:

The commenter believes that EPA should provide for alternative treatment for small

utilities ~50 MW. (Questions 5 & 6)

With regard to de minimis threshold, this commenter continues to support EPA’s

suggested exemption for units that emit less than 25 pounds of Hg annually, and encourages EPA

to extend the exemption to units that emit up to 50 pounds a year. EPA’s re-examination of the

benefits associated with the Utility MACT in the NODA lends further support to an exemption. 

As EPA notes in the NODA, there are open issues regarding the benefits of the total Hg

reductions being proposed in the Utility MACT for all electric utility steam generating units in the

U.S. This issue is even more relevant to the minimal emissions from small units, where the costs

of monitoring and compliance are clearly significant, but the benefits are small and uncertain. For

this reason, and the others set out in the commenter’s previous comments in this rulemaking,

including the likelihood that many of the commenter’s smaller units will be forced to close under

the pressure of the Utility MACT rule and the Clean Air Interstate Rule (CAIR rule), and the

impacts of that on the national transmission grid), the commenter requests that EPA exempt these

small units from the Utility MACT.

Response:

As discussed above and in the final rule preamble (section IV.D.3.iv), EPA is not

finalizing a low-emitter exclusion and EPA recommends States address small business entities

through the allocation process.

Comment:

With regard to monitoring for smaller utilities, one commenter (OAR-2002-0056-5571)

requests that EPA also simplify monitoring for smaller and/ or exempt units. Monitoring costs

present a significant compliance cost, particularly for small units, and one that is unwarranted in

light of the minimal risk that these units pose. For an exempt unit, the monitoring costs to prove

that a unit is exempt could prove to be as significant as the costs of compliance with the rule,

thereby defeating the purpose of the exemption. EPA estimates the capital cost of Hg CEMS
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range from $95,000 to $135,000. Annual operating and maintenance costs are estimated to range

between $45,000 to $65,000. Under the upper end of the range, the first year’s monitoring cost,

equal to $200,000 per year, would be in the same range as controlling for Hg through allowance

purchases ($20,000) for a unit that emitted, as many of the commenter’s members do, about 10

pounds per year.

The commenter notes that not only are the monitoring costs for these small units

enormous, but they are particularly inappropriate in light of the minimal risks presented by small

units. Units subject to a 50 pound exemption account for a small fraction of the Hg emitted in the

U.S. The total Hg emissions from these units are just over 6 tons per year, or less than 15 percent

of the Hg emitted from all coal-fired power plants. The emissions for all units less than 25 pounds

are less than 2 tons per year, or less than 5 percent of total Hg emissions. Further, as EPA notes

in the NODA, there are open issues regarding the benefits of the total Hg reductions from all

utilities in the U.S. discussed in the Utility MACT. This raises serious questions about the even

smaller and less certain benefits of regulating small emitters, particularly when monitoring and

compliance costs for the small emitters are substantial.

The commenter recommends that for these small and/or exempt units, EPA adopt the Hg

monitoring requirements that have already been developed for small units in the context of

another MACT rulemaking. The MACT for Industrial, Commercial and Institutional Boilers and

Process Heaters applies to utility boilers that generate equal to or less than 25 MW (as well as

industrial units that generate less than 25 MW) and includes requirements for Hg testing. See

National Emission Standards for Hazardous Air Pollutants for Industrial, Commercial, and

Institutional Boilers and Process Heaters, 69 Fed. Reg. 55,218 (September 13, 2004). These

testing requirements are particularly appropriate for the smaller units in the Utility MACT, which

have significant similarities to the units in the Boiler MACT, including small size and limited

emissions.

The monitoring requirements for the Boiler MACT include initial and annual stack tests

(using EPA method 29, Part 60, Appendix A or ASTM D6784-02), or, in the alternative, fuel

testing (using ASTM D3684-01, see Table 6 attached). The general monitoring requirements

from the Industrial Boiler MACT are attached in Appendix II to these comments. These

monitoring requirements, including the continuous compliance requirements, are more appropriate

to small and/or exempt units in the Utility MACT rule than the significant costs associated with

CEMS, while ensuring that these units continue to qualify as small and/or exempt.

If EPA determines that Boiler MACT monitoring requirements cannot be used of Utility

MACT, the commenter also encourages the EPA to adopt phased-in monitoring requirements for

small and/or exempt units. There are still significant uncertainties associated with the current

monitoring technology. These technology issues will present a particular hardship on municipally

owned utilities. Smaller municipal utilities face substantial challenges because they lack the

resources to address these monitoring issues and are unable to get priority in hiring consultants. 

EPA should delay the Hg monitoring requirements for exempt and/or small sources until at least

2010 when Hg monitoring technology may be more fully developed, demonstrated, and less
9-cclxxxi

expensive.

Response:

As discussed above and in the final rule preamble (section IV.D.3.iv), EPA is not

finalizing a low-emitter exclusion and EPA recommends States address small business entities

through the allocation process.

Comment:

One commenter (OAR-2002-0056-5571) believed that should a cap-and-trade program be

implemented, EPA has proposed an exemption for small emitters. It suggests an exemption for

units that emit 25 pounds or less. According to EPA’s data, this would apply to 3.9 percent of

emissions nationwide. The commenter believed that EPA should restyle the small emitter

exemption so that it applies to existing units at small plants emitting, with a minimum of 25

pounds on a per unit basis.

Response:

As discussed above and in the final rule preamble (section IV.D.3.iv), EPA is not

finalizing a low-emitter exclusion and EPA recommends States address small business entities

through the allocation process.

Comment:

One commenter (OAR-2002-0056-5571) urges the EPA to also consider other de minimis

options offered by public power communities (including the >95 pound plant wide suggestion for

community utilities that meet the SBREFA definition). Earlier the commenter provided

references to the UMRA, Regulatory Flexibility Act, SBREFA Act of 1996 and Executive Order

12866 that would justify making some practical decisions about a de minimis exemption. 

Whatever de minimis level the EPA ultimately sets in the final rule. The commenter does not

believe that this de minimis should not subject the larger units/plants to more stringent cap levels.

Response:

As discussed above and in the final rule preamble (section IV.D.3.iv), EPA is not

finalizing a low-emitter exclusion and EPA recommends States address small business entities

through the allocation process.

Comment:

One commenter (OAR-2002-0056-5571) believes that the EPA’s final rule should

emphatically state that the smaller utility systems (particularly those that meet the SBREFA

definition) should be able to work with their state agencies and permit writers to determine the
9-cclxxxii

most practical and reliable method to perform monitoring functions at lowest cost (considering

capital expense, operating and maintenance, and on-going staff training expenses). Many public

power utilities simply don’t have the personnel skills to perform these highly sophisticated

monitoring runs. Also many public power communities are two hours away from major

metropolitan areas or airport hubs so that frequent visits by CEM manufacturers, vendors,

contractors, or service personnel would be prohibitively expensive.

Response:

As discussed above and in the final rule preamble (section IV.D.3.iv), EPA is not

finalizing a low-emitter exclusion and EPA recommends States address small business entities

through the allocation process.

Comment:

One commenter (OAR-2002-0056-5571) strongly urges the U.S. EPA to encourage states

to work with the smaller Hg emitters to allow creative Hg reduction/mitigation/removal or

prevention projects. Holland Board of Public Works is a municipal utility with approximately

30,000 households in Michigan. Earlier in 2004 the municipal utility initiated a community

program to encourage the voluntary return of Hg thermometers to reduce Hg from household

environments, landfills and the wastewater system. The utility provided digital thermometers to

those who returned a glass thermometer containing Hg or other Hg-containing items. In the span

of a few months the Holland Board of Public Works collected 28 pounds of Hg through this

program in addition to working with commercial industrial customers. Comparatively, the

Holland Board of Public Works emits approximately 8 pounds of total Hg annually through

combined oil, coal and gas generation. The commenter believes that the EPA and states should

encourage alternative methods like this innovative method to reduce Hg that are cost effective in

the final rule. The Clean Air Act authorized the EPA to consider work practices and other

alternatives when they are demonstrated to be effective and can be proven. The commenter

strongly urges the EPA to allow state agencies to work with smaller emitters on this type of

alternative to MACT if the EPA promulgates a MACT standard or if it authorizes a cap and trade

program that a state declines to opt into.

Response:

As discussed above and in the final rule preamble (section IV.D.3.iv), EPA is not

finalizing a low-emitter exclusion and EPA recommends States address small business entities

through the allocation process.

Comment:

The commenter (OAR-2002-0056-5455) also took issue with the modeling performed in

the analysis. The commenter does not believe the science of modeling has reached a point where

it can accurately be used for Hg transport and deposition due to the lack of understanding about
9-cclxxxiii

dry deposition. Few deposition monitors exist in Indian Country so it’s very hard to say how

much wet or dry deposition is occurring in these areas 15. Based on this concern, the commenter

believed it is reckless to propose a cap and trade program relying on the results of EPA’s models. 

It is better to err on the side of caution than to be wrong in such an important matter. To account

for the lack of confidence in the models, EPA should abandon its idea of cap and trade and stick

to a MACT standard.

The commenter believed that the air emission inventories used in EPA’s analysis probably

underestimated the amount of Hg emitted from some sources, such as miscellaneous product

disposal. EPA has used the best information it has available, but it should leave a margin of safety

to account for inaccuracies.

Response:

EPA is finalizing a cap-and-trade approach under section 111. Please see the Revision

of December 2000 Regulatory Finding on the Emissions of Hazardous Air Pollutants from

Electric Utility Steam Generating Units and the Removal of Coal- and Oil-fired Electric Utility

Steam Generating Units from the Section 112(c) List for a discussion of the Agency’s rationale

for not proceeding under Section 112. 

Comment:

The commenter (OAR-2002-0056-5551) stated that firstly, standards for controlling

HAPs from coal fired power plants must follow the requirements of Section 112 of the Clean Air

Act. The commenter noted that for existing power plants, each MACT limit must be at least as

stringent as the limit which is achievable by the average of the best controlled 12 percent of

similar units for which there is data. The commenter noted that this is commonly referred to as

the MACT floor. The commenter stated that the standards should be more stringent if justified by

cost, benefit and feasibility. According to the commenter, hence, the NODA information on costs

and benefits is primarily relevant for setting more stringent standards than the MACT floor. The

commenter believed that the NODA is useful for setting MACT standards better than the MACT

floor for subbituminous and lignite coal combustion, if a coal neutral standard is not set. The

commenter stated that, however, information on costs and benefits are irrelevant to the setting of

the MACT floor.

While the commenter believed that the choice of 3 mg per MWh or 90 percent control,

annual averages, is an appropriate MACT standard for all coals, the commenter noted that EPA

may choose to set MACT limits by principle coal type, i.e., bituminous, subbituminous, and

lignite. In such an event, the commenter recommended that EPA set better than the MACT floor

limits for subbituminous and lignite coals in view of the generally limited control systems currently

in place for these coals and the recent success in controlling Hg from these coals using

halogenated activated carbon injection. The commenter stated that the rate component of the

standard should remain the same as bituminous coal to facilitate compliance determination for

blended coals. The commenter added that, alternatively, blended coals should be subject to the
9-cclxxxiv

most stringent rate for the coals being blended. The commenter stated that the control efficiency

component of a MACT limit for subbituminous and lignite coals could be somewhat less stringent

than for bituminous coals, in view of the somewhat lower Hg content of these coals and the lesser

amount of data for control of Hg from these coals. According to the commenter, 3 mg per MWhr

or 80 percent control would be a reasonable MACT standard for these coals at this time.

Response:

EPA is finalizing a cap-and-trade approach under section 111. Please see the Revision

of December 2000 Regulatory Finding on the Emissions of Hazardous Air Pollutants from

Electric Utility Steam Generating Units and the Removal of Coal- and Oil-fired Electric Utility

Steam Generating Units from the Section 112(c) List for a discussion of the Agency’s rationale

for not proceeding under Section 112. 
RESPONSE TO SIGNIFICANT PUBLIC COMMENTS ON

THE PROPOSED CLEAN AIR MERCURY RULE

Received in response to:

Proposed National Emission Standards for Hazardous Air Pollutants; and, in

the Alternative, Proposed Standards of Performance for New and Existing

Stationary Sources: Electric Utility Steam Generating Units

(69 FR 4652; January 30, 2004)

Supplemental Notice for the Proposed National Emission Standards for

Hazardous Air Pollutants; and, in the Alternative, Proposed Standards of

Performance for New and Existing Stationary Sources: Electric Utility Steam

Generating Units

(69 FR 12398; March 16, 2004)

Proposed National Emission Standards for Hazardous Air Pollutants; and, in

the Alternative, Proposed Standards of Performance for New and Existing

Stationary Sources, Electric Utility Steam Generating Units: Notice of Data

Availability

(69 FR 69864; December 1, 2004)

Docket Number OAR-2002-0056

10.0 OTHER

US Environmental Protection Agency 

Emissions Standards Division

Office of Air Quality Planning and Standards

Research Triangle Park, North Carolina 27711

15 March 2005
i

General Outline

1.0 INTRODUCTION AND BACKGROUND

2.0 APPLICABILITY AND SUBCATEGORIZATION

3.0 PERFORMANCE STANDARDS FOR COAL-FIRED ELECTRIC

UTILITY STEAM GENERATING UNITS

4.0 PERFORMANCE STANDARDS FOR OIL-FIRED ELECTRIC

UTILITY STEAM GENERATING UNITS

5.0 MERCURY CAP-AND-TRADE PROGRAM

6.0 MERCURY EMISSIONS MONITORING

7.0 IMPACT ESTIMATES

8.0 COMPLIANCE WITH EXECUTIVE ORDERS AND STATUTES

9.0 NODA

10.0 OTHER

Appendix A LIST OF COMMENTERS
10-i

10.0 OTHER

10.1 OTHER MERCURY SOURCES

Comment:

One commenter (OAR-2002-0056-2695) requested that the final rule address Hg

emissions from international sources. A second commenter (OAR-2002-0056-3552) noted that a

global approach will be needed to address emissions from international sources because areas

west of the Mississippi River receive less total Hg deposition, but a higher total Hg deposition

from sources outside the U.S.

Response:

Anthropogenic Hg emissions from the U.S. are estimated to account for roughly three

percent of total global emissions, and emissions from the U.S. power sector are estimated to

account for about one percent of global emissions. (United Nations Environment Programme.

Chemicals, Global Mercury Assessment, Geneva, 2002.). Although the U.S. has no legal

authority to regulate Hg emission sources outside its boundaries, the U.S. is a leader in

promoting and facilitating global reductions in Hg use and releases. 

The U.S. engages international partners, multilaterally and bilaterally, to address key Hg

issues including data collection and inventory development, source characterization, and best

practices for emissions and use reduction. Most recently, the U.S. has provided leadership in

the United Nations Environment Program (UNEP) Governing Council (GC). In 2003, the

UNEP GC adopted a U.S. proposal establishing the UNEP Mercury Program to facilitate and

conduct technical assistance and capacity building to support efforts of developing countries

and countries with economies in transition to take action regarding Hg pollution. In February

2005, the UNEP GC adopted a U.S. proposal that accelerates the work of the UNEP Mercury

program by engaging countries in partnerships and collaborative activities to produce tangible

results in the near term by facilitating global reductions in Hg exposure, use, and release. This

agreement will advance specific projects in key source countries and priority sectors by

engaging a diverse array of stakeholders, including governments, the private sector,

international organizations, and nongovernmental organizations, to leverage resources,

technical capacity and expertise. 

Other examples of U.S. international efforts in this area include our work with the Arctic

Council Action Plan (ACAP) and the Arctic Monitoring and Assessment Program (AMAP) to

strengthen capacity building and technical cooperation program; and our support for the

development of Russia’s Hg action plan and inventory, as well as support for a regional Arctic

inventory and emissions reductions projects. The U.S. has also developed bilateral Hg

cooperation programs to foster assessment and sector specific improvements in China and India.

The U.S. has been a global leader in taking actions to address our domestic Hg

emissions. Now, the U.S. is the first country in the world with plans to regulate Hg emissions
10-ii

from power plants. We believe that this section 111 regulation will further the leadership of the

U.S. in this area as well as encourage development of Hg control technologies that may be

utilized worldwide.

Comment:

Eight commenters (OAR-2002-0056-1327, -1471, -1611, -1664, -2110, -2219, -2878, -

3457) stated that it is unclear how the U.S. will meet its obligations under the Great Lakes Water

Quality Agreement, Great Lakes Binational Toxics Strategy, New England Governors and

Eastern Canadian Premiers Mercury Action Plan, and the 1998 Protocol to the Convention on

Long-Range Transboundary Air Pollution signed by the U.S., Canada and Europe, and other

international agreements because the proposal would allow such high emissions of Hg.

Response:

EPA believes that the final rule will significantly reduce Hg emissions, as is explained

more fully in the preamble and elsewhere in this response to comments document and the

rulemaking record. Thus the rule will advance the objectives of the international instruments

cited by the commenters.

Comment:

One commenter (OAR-2002-0056-1436) stated that EPA should be more concerned

about Hg as a preservative in vaccinations.

Response:

Approving the use of Hg as a preservative in vaccines is not within EPA’s authority. 

Such authority rests with the U.S. Food and Drug Administration (FDA). Information on Hg in

vaccines (thimerosol) may be found at http://www.fda.gov/cber/vaccine/thimerosal.htm and at

http://www.cdc.gov/nip/vacsafe/concerns/thimerosal/default.htm.

Comment:

Numerous commenters (OAR-2002-0056-2695, -3552, and others listed in this

paragraph) pointed out the need to address other sources of Hg emissions. Several commenters 

(OAR-2002-0056-1104, -1251, -1293, -1308, -1530, -1611, -2729, -2750, -2765, -2981, -3243, -

3122, -3657, -4050, -4410, -4417, -4620, -4718, -5007) stated that Hg should be banned from all

products (e.g., dental amalgam, vaccinations, additives in paints and pesticides, electronic

equipment), and that emissions from all other industrial sources (industrial boilers, hazardous

waste incinerators, Cl production) need to be controlled. Several of these commenters described

severe health effects from dental amalgam. One commenter (OAR-2002-0056-3199) supported

control of Hg emissions from coal-fired power plants, but noted that power plants were not the

only sources of Hg and stated that a better inventory of all sources (e.g., chlor-alkali plants,

automobile/white goods scrap yards, and shredders [including furnaces using products from
10-iii

shredders], etc.) was needed. The commenter stated that these emissions were also significant

and merited further study.

Response:

A number of the sources of Hg exposure noted by the commenters (e.g., dental amalgam,

vaccinations) are not within the statutory authority of the EPA. As noted earlier, approving Hg

use in vaccinations is under the authority of the FDA. Similarly, dental amalgams fall under the

purview of the FDA; information on the research being conducted on the use of mercury in

dental amalgams may be found at http://www.fda.gov/OHRMS/DOCKETS/98fr/03-11648.html

and consumer information on the use of Hg in dental amalgams may be found at

http://www.fda.gov/cdrh/consumer/amalgams.html. Information about activities on many of the

other sources noted by the commenters may be found through www.epa.gov/mercury. EPA

agrees that coal-fired utility units are not the only source of Hg in the U.S.; the industrial

sources of Hg noted by the commenters are the subject of other regulatory efforts by EPA under

the CAA. In 1990, more than two-thirds of U.S. anthropogenic Hg emissions came from just

three industrial source categories: coal fired power plants, municipal waste combustion, and

medical waste incineration. In 1990, EPA issued final regulations for large municipal waste

combustors (MWC), a sector which emitted approximately 57 tons of Hg emissions. 

Implementation of large MWC regulations has reduced Hg emissions by 88 percent from 1990

emission levels. In 2005, these regulations are projected to reduce MWC emissions by 91

percent from 1990 emission levels. Medical waste incerators are also subject to stringent

emissions standards, and have reduced Hg emissions by 97 percent from 1990 emissions.

Regulations to limit Hg emissions from chlorine production facilities that use Hg cells

and regulation of industrial boilers, will further reduce emissions of Hg when they become

effective in the next few years. EPA issued final standards for Hg from chlor-alkali production

on December 19, 2003. EPA expects that these standards, when fully implemented by the end of

2006, will cut Hg emissions from point sources at these facilities by 74 percent and will cut total

Hg reductions from these facilities by about 11 percent from 1999 emission levels. EPA has also

issued regulations to reduce Hg emissions from industrial boilers. EPA estimates that this

regulation, when fully implemented in 2007, will reduce emissions by 17 percent from 12 tons to

10 tons per year.

In addition, actions to limit the use of Hg, most notably Congressional action to limit the

use of Hg in batteries and EPA regulatory limits on the use of Hg in paint, reduced the Hg

content of waste contributed to the reduction of Hg emissions from waste combustion during the

1990s.

Comment:

One commenter (OAR-2002-0056-3426) stated that policymakers should implement

regulations to obtain maximum control of Hg from all sources with uniform limits, develop

scientifically-based fish consumption guidelines that ensure that 98 percent of the population is

within EPA’s safe level of MeHg exposure, and cooperate internationally to reduce the global
10-iv

problem.

Response:

EPA is working along the lines that the commenter suggests. As discussed in responses

to comments presented elsewhere in this document above, regulations are being established for

the significant Hg-emitting sources based on the requirements of the CAA. In addition, as

discussed above, EPA is working with the international community to address emissions of Hg. 

EPA believes that the final utility rule will serve to reduce deposition of Hg and, thus, lead to

improvements in fish tissue Hg concentrations.

Comment:

One commenter (OAR-2002-0056-3543) recommended that the final rule address the

disposal of Hg removed from the air emissions. The commenter felt that, from the perspective of

watershed and fish contamination, no progress would be made if only the route of contamination

(but not the extent) were changed.

Response:

This is an area of research that EPA continues to pursue through its Offices of Research

and Development and Solid Waste, in coordination with other Federal agencies and industry

groups. The findings to-date indicate that, for most management practices, leaching of Hg does

not appear to be of concern for land disposal of coal combustion residues (CCR), including from

those sources where carbon sorbents have been tested for Hg control. (“Potential for CrossMedia Transfers from Management of Mercury-Enriched Coal Combustion Residues,” OAR2002-0056-6139) Further evaluation is warranted to understand whether the extent of this

leaching would pose a potential concern.

10.2 STAKEHOLDER INFLUENCE

Comment:

Many commenters specifically criticized industry influence on EPA’s rulemaking. Many

commenters stated that the proposals favor the industry over public health. Many pointed to the

use of Latham and Watkins language in the preamble. One commenter (OAR-2002-0056-2160)

specifically stated that whole sections were lifted from the report of a firm representing interests

of western coal producers. The science used by EPA in establishing the limits for bituminous and

subbituminous coal was questioned because of the undue influence of certain constituent groups. 

Two Congressmen requested detailed information on this rulemaking process.

Response:

EPA is aware of the concern expressed by the commenters and has responded to the

Congressional inquiries. The material in question was provided to the EPA through the Clean
10-v

Air Act Advisory Committee working group process established under the Federal Advisory

Committee Act (FACA) and, thus, we do not feel that its use was inappropriate.

Comment:

One commenter (OAR-2002-0056-3517) urged EPA to balance comments received from

the various stakeholders to make sure that the Hg rules do not become a driver for the coal

market.

Response:

EPA has considered all comments received on or before January 3, 2005, in developing

the final rule.

Comment:

One commenter (OAR-2002-0056-2248) stated that the involvement of a senior EPA

official in both the Hg lawsuit against the Agency and in EPA’s settlement of the matter presented

the appearance of a conflict of interest that must be investigated to preserve the right to

constitutional due process. The commenter felt that a potentially serious conflict of interest

overshadowed the current rulemaking, and that the presence of David Doniger as a senior

member of EPA’s air office during this rulemaking, as well as his participation in the matter at

EPA, raised serious questions about the rulemaking’s transparency and validity. The commenter

asserted that this official’s participation in the rulemaking violated the fundamental constitutional

right of due process and necessitated postponement of further action on the rule until this

apparent conflict has been fully investigated.

Response:

The issue noted by the commenter is the subject of a Freedom of Information Act (FOIA)

by the commenter and, thus, EPA can not respond at this time to the comment.

10.3 LEGAL ISSUES

10.3.1 Broad Authority Under CAA Section 111(d)

Comment:

Four commenters (OAR-2002-0056-2224, -2835, -2867, -2922) filed comments to

supplement EPA’s discussion of its statutory authority to regulate under CAA section 111 and to

establish a cap-and-trade program. They stated that CAA section 111 confers broad legal

authority for the regulation of existing sources under a Federal-State partnership. The legislative

history and the relationship between the plans developed for the State-Federal partnerships under

CAA section 110 and section 111 further supports EPA’s determination that a flexible emissions

trading program can be implemented under section 111(d).
10-vi

The commenters noted that this partnership contemplates EPA establishing “standards of

performance” at the national level and each state developing a regulatory program for

implementing and enforcing those standards at the state level. The commenters pointed out that

the statute explicitly notes that the Federal-State partnership under CAA section 111(d) is to be

modeled after the regulatory process used under CAA section 110. In that regulatory context,

CAA section 110 provides States with wide latitude in developing emissions control strategies for

achieving Federal air quality goals — National Ambient Air Quality Standards (NAAQS)

established by EPA at the national level.

Both the statute and legislative history confirm that Congress delegated broad legal

authority to adopt flexible regulatory mechanisms for controlling existing sources under section

111(d)(1). This broad delegation of authority provides sufficient authority for EPA to establish

flexible “standards of performance” that need not prescribe when, how, and the degree to which

each affected unit must achieve that emissions limitation — either on a unit-by-unit basis or

facility-by-facility basis. In addition, the CAA authorizes States to implement and enforce those

standards of performance through cap-and-trade program or other such flexible, market-based

mechanism that implements the reduction requirement imposed under the standard of

performance, while taking into consideration “the remaining useful life” of the source as well as

“other factors.” EPA’s proposed trading scheme is one effective mechanism for States to address

concerns regarding existing units whose remaining useful life is limited such that the purchase of

allowances may be appropriate in lieu of making additional major pollution control investments at

those units. Commenter OAR-2002-0056-2835 described in detail how this interpretation is

confirmed in the legislative history to CAA section 111(d).

Another indication of the broad discretion accorded to EPA and States in implementing

and enforcing standards of performance under section 111 (d)(1) is the relationship that this

section has with section 110. Section 111 (d)(1) requires EPA to promulgate regulations that

establish SIP-like procedures similar to those in section 110 to be used by States in submitting

their plans. The CAA section 111(d) plans and SIP programs are complementary to one another

– in particular, a State’s plan under section 110 (or section 172, for non-attainment areas) can be

used to meet the standards under section 111(d). States can thus use the SIP regulatory tools in

CAA sections 110(a)(2)(A) and 172(c)(6) to establish “enforceable emissions limitations and

other control measures” to achieve this end. One such regulatory tool available to States

explicitly referenced under these sections is the adoption of “economic incentives such as fees,

marketable permits, and auctions of emissions rights,” when developing a plan to comply with the

standards under section 111(d)(1).

This complementary relationship was confirmed in EPA’s guidance for implementing the

Emission Guidelines for Municipal Waste Combustors established under CAA sections 111(d) and

129. EPA’s guidance explained that where the SIP requirements are adequate to meet the section

111(d)/129 standard - which are required to be more rigorous than emission guidelines under only

section 111(d) - the State has the authority to submit a section 111(d)/129 plan that relies on the

requirements of the SIP to meet the section 111 (d)/129 standard. The commenter adds that the

section 111(d)/129 rule for Municipal Waste Combustors also clearly contemplated that States

would use trading when implementing and enforcing the standards-the rule explicitly provided
10-vii

that a state plan could “establish a program to allow owners or operators of municipal waste

combustor plants to engage in trading of nitrogen oxides emission credits.”

Commenter OAR-2002-0056-2867 stated that EPA has correctly harmonized these

conflicting statutory provisions, and interpreted them in a way that effectuates the purposes of the

statute as whole. The commenter agreed that the key provision in the definition of a “standard of

performance” under CAA section 111 is the phrase “the best system of emissions reduction.” 

Since this phrase is not defined by statute, EPA has broad discretion in determining what is the

“best system of emissions reduction,” so long as the system ultimately selected “has been

adequately demonstrated.” The commenter pointed out the definition places no other explicit

statutory constraints on EPA in making this determination, except that it must consider the

following factors: the cost of achieving the Hg reductions, non-air quality health and

environmental impacts, and energy requirements. The commenter concluded that the statute

requires the standards of performance be based on “the degree of emission limitation achievable”

by the best system of emissions reduction system selected by EPA. As evidenced by the success

of other cap-and-trade programs for the power sector, i.e., the NOx SIP Call and the Title IV

Acid Rain Program, the trading program approach satisfies the statutory requirement for setting

the standard of performance based on the best system of emission reduction for the electric utility

source category.

The commenter felt it is important to note that the statutory definition does not require

specific units or facilities to install emissions control technology. In addition, the definition is

silent on whether or not the standard of performance prescribing specific emissions limits should

directly apply on a unit-by-unit or facility-by-facility basis. The commenter also noted that the

definition is silent on whether each unit or facility must achieve specific reduction levels

continuously or averaged over a specific period of time. (Regarding this issue, the commenter

pointed out that CAA section 302(1) also contains a definition of the term “standard of

performance,” which defines the term to mean “a requirement of continuous emission reduction,

including any requirement relating to the operation or maintenance of a source to assure

continuous emissions reduction.” It appears to the commenter that this definition would not be

controlling for purposes of setting standards of performance under section 111, given that

Congress chose to adopt another specific definition of standard of performance in CAA section

111.

Three commenters (OAR-2002-0056-2224, -2835, -2867) emphasized that CAA section

111(d)(1) itself does not independently mandate that standards of performance for existing

sources impose a source-specific requirement for continuous emission reduction. Thus, a State

plan incorporating a standard of performance that employs a cap-and-trade mechanism would not

conflict with the statutory requirements of section 111(d)(1). However, a strong case can be

made for the proposition that the emissions cap and allowance-holding requirement in EPA’s

proposed section 111(d) trading program impose a “continuous emissions reduction” requirement

on affected electric utility units. The proposed cap-and-trade program establishes a permanent

cap on Hg emissions and requires affected sources to hold allowances that correspond to the level

of Hg emissions from those sources at all times. By its very elements, the proposed cap-and-trade

program is a continuous method of emission reduction given that there is no point in time when an
10-viii

affected source can emit Hg without holding allowances that correspond to those emissions. 

EPA’s proposal also requires continuous emissions monitoring to assure that a source complies

with the requirements of the cap-and-trade program at all times. Thus, if a court were ever to

construe section 111(d)(1) to require a “continuous emission reduction,” the features of EPA’s

proposed trading program should meet that requirement.

The legislative history of the term “standard of performance,” does not specifically

reference an allowance trading system as a regulatory mechanism for controlling emissions under

CAA section111(d), but generally reflects Congress’ intent that existing sources be accorded

considerable flexibility in meeting the section 111(d) standards. Such legislative intent for

compliance flexibility provides general support for EPA’s interpretation that the term “standard of

performance” may include an allowance trading program, as proposed in the Hg rule, because

such a trading program accords flexibility to sources.

According to the commenter, the Senate debate on the 1990 amendments reinforces this

statutory interpretation, in light of Congress’ express action removing any specific percent

reduction requirement from the concept of “standards of performance.” As an example, the

commenter states that Senator Baucus explains that Congress adopted a percentage reduction

requirement in the 1977 CAA Amendments to ensure that coal-fired electric generating units did

not rely on low-sulfur “compliance” coal alone to meet NSPS for SO2. According to Senator

Baucus, a percentage reduction requirement across the board was supposed to require SO2

scrubbers regardless of the rank of coal combusted; however, this approach accentuated the

regional split over coal use that existed prior to 1977. With the adoption of the SO2 emissions

cap under the Title IV acid rain program, the percentage reduction requirement was no longer

necessary and could in fact be a barrier to flexible compliance under the acid rain trading program. 

The commenter continues that accordingly, Congress elected to repeal the percent reduction

requirement during the 1990 CAA Amendments.

The commenter also referenced remarks in debate by Senator Bond during the 1990 CAA

Amendments that also pertain to the removal of the percentage reduction requirement and,

indirectly, the continuous emission reduction requirement. Specifically, Senator Bond explained

that both the House and the Senate rejected the concept of the percentage reduction and “directed

EPA to come up with an alternative standard that would allow utilities to meet it in the most

flexible manner possible.” Senator Bond further noted that the new standards could be met by

fuel switching, the use of technology and fuel switching, by technology alone, and by intermittent

controls or intermittent operation. Senator Bond continued by stating that “[t]he way the

language is constructed, intermittent controls can be allowed to comply with this section of the

act. So for the first time in 13 years we will have EPA setting. . . emission levels for SO2 that will

not require the use of the scrubbers for compliance.”

The commenter stated that this flexibility was not intended to be limited to utility

standards, or the operation of the Acid Rain Program, but was to be afforded to all sources

subject to “standards of performance” under section 111. The commenter felt it would be ironic if

EPA failed to take advantage of the flexibility specifically intended by Congress to benefit the

utility industry in the context of developing requirements for Hg control, since EPA itself has not
10-ix

identified any particular control technology as the basis for its standards.

Response:

EPA concurs with the comments.

10.3.2 EPA Must Regulate Under Section 112

Comment:

 Several commenters (OAR-2002-0056-2108, -2173, -2330, -2332, -2359, -2575, -2823,

-2836, -2871, -2878, -2880, -2889, -2920, -2924, -3393, -3394,-3459, -4139) argued that EPA

lacks authority to regulate HAP under section 111.

Response:

Those comments are summarized and responded to in the Response to Comments

(“Response to Significant Public Comments Concerning the Proposed Revision of the December

2000 Appropriate and Necessary Finding and the Removal of Utility Units from the Section

112(c) List”). We incorporate those comments and responses herein by reference. EPA also

believes it has addressed these concerns in the revision of EPA’s CAA section 112(n)

determination.

10.3.4 Clean Water Act

Comment:

Many public interest groups (more than 73) contended that EPA completely ignored its

statutory obligations to control non-point sources of pollution under Clean Water Act (CWA)

section 303(d)(4)(B). Although the CWA does not give EPA direct authority to impose controls

on individual non-point sources, EPA is responsible for ensuring that non-point source pollution

does not undermine state water quality goals. Atmospheric deposition of Hg from power plants is

an acknowledged and significant source of non-point source pollution. The relaxed controls 

under the proposed rule will lead to decreasing waster quality and violations of state water quality

standards. EPA must implement Hg non-point source controls that meet best management

practices of the CWA’s antidegradation provisions. Commenter OAR-2002-0056-2575 stated

that EPA utterly failed to consider the CWA compliance implications of the proposal or of their

own collaborative effort to reduce deposition of toxics to all waterbodies through their Air-Water

Interface Work Plan general strategy.

Response:

Commenters cite to section 303(d)(4)((B) of the Clean Water Act (CWA) and assert that

EPA has ignored its statutory obligations under the CWA to control nonpoint sources of

pollution. Commenters are mistaken regarding EPA’s obligations or authorities under the
10-x

CWA to control nonpoint sources of pollution. Section 303(d)(4)(B) is a provision that

addresses when a permitting authority may include less stringent effluent limitations in a point

source NPDES permit. The section does not address nonpoint sources of pollution. There is a

reference in CWA section 303(d)(4)(B) to EPA’s antidegradation policy. EPA’s antidegradation

policy, however, does not authorize EPA to regulate, or compel States to regulate, nonpoint

sources of pollution. See American Wildlands, et al. v. Browner et al., 260 F.3d 1192, 1198

(10th Cir. 2001)) Commenters appear to admit as much when they say that “the CWA does not

give EPA direct authority to impose controls on individual nonpoint sources . . .” To the extent

that commenters believe that the CWA or EPA’s antidegradation policy obligates, or gives

authority to, EPA to regulate or compel States to regulate nonpoint sources of pollution,

commenters are wrong and their position is unsupported by relevant case law. As the U.S. Court

of Appeals for the Fourth Circuit has recognized: “Congress consciously distinguished between

point source and nonpoint source discharges, giving EPA authority under the Act to regulate

only the former.” Appalachian Power Co. v. Train, 545 F.2d at 1373. See also American

Wildlands, 260 F.3d at 1197; Kennecott Copper Corp. v. EPA, 612 F.2d 1232, 1243 (10th Cir.

1979); United States v. Earth Sciences, Inc., 599 F.2d 368 at 371. As discussed in the preamble,

EPA believes that following implementation of CAIR and today’s action, utility-attributable Hg

emissions are not reasonably anticipated to result in hazards to public health.

10.4 TRIBAL TRUST RESPONSIBILITIES

Comment:

Many Indian tribes and organizations (OAR-2002-0056-1327, -1618, -2010, -2118, -

2173, -2380, -2694, -2695, -2814, -2891, -3311, -3335, -3413, -3457, -3549, -3550, -3551, -

5455) stated that the rule does not comply with EPA's federal trust responsibility, and is

inconsistent with EPA's Indian Policy because EPA did not adequately consult with tribes in

developing the rule and because the rule does not adequately protect the health of Indians. They

assert that tribes have treaty rights to fish, and that the rule does not adequately protect those

rights because it does not reduce mercury emissions to a level that protects the health and safety

of tribal members who consume fish. They note that EPA's assessment of the risks for tribal

members must take into account their high levels of fish consumption, and the unique traditional,

cultural, and subsistence importance of fish for many tribes. Finally, some commenters object to

EPA’s failure to provide for a cap-and-trade program in Indian country.

Response:

EPA recognizes that the Federal government stands in a government-to-government

relationship with Federally recognized Tribes and has certain trust responsibilities to these

Tribes. This relationship and responsibility should guide EPA in the implementation of policies

and actions that affect Tribes. Pursuant to the government-to-government relationship, EPA

consults with Tribes regarding actions that affect Tribes. In addition, treaties, statutes, and

executive orders create Federal obligations regarding Tribal resources. EPA believes that its

actions in developing the final rule have been consistent with the government-to-government

relationship and that the final rule itself is consistent with the trust responsibility.
10-xi

EPA does not agree with the commenters who claim that it did not consult with tribes in

developing the rule. As explained in the discussion of EPA compliance with EO in the preamble

for the final rule, EPA took the following steps to consult with Tribes. EPA gave a presentation

to a national meeting of the National Tribal Environmental Council (NTEC) in April 2001, and

encouraged Tribal input at an early stage. EPA then worked with NTEC to find a Tribal

representative to participate in the workgroup developing the rule, and included a representative

from the Navajo Nation as a member the official workgroup, with a representative from the

Campo Band later added as an alternate. In March 2004, EPA provided a briefing for Tribal

representatives, the newly formed National Tribal Air Association (NTAA), and NTEC. EPA

received comments on this rule from a number of Tribes, and has taken those comments and

other input from Tribal representatives into consideration in development of this rule.

EPA disagrees that the rule will not adequately protect Tribal fishing rights. EPA agrees

that some Tribes have unique legal rights to fish arising from treaties, statutes, executive orders,

and agreements. EPA also recognizes that Tribal members may catch and consume more fish

than the general public as a result of Tribal fishing rights as well as Tribal culture, traditions,

and subsistence lifestyles.

EPA believes that this regulation adequately protects Tribal health and is consistent with

the trust responsibility for several reasons. First, the commenters understate the significance of

the fact that Hg emissions from Utility Units currently are not subject to performance standards. 

This regulation will for the first time establish performance standards applicable to Hg

emissions, and those standards will require significant reductions in the levels of Hg emissions. 

Such reductions will provide greater protection to Tribal fish resources than would otherwise be

available. Acting to provide such heightened protection is consistent with both the statute and

the Federal trust responsibility.

Moreover, the commenters offer no specific evidence that the Hg emissions reductions

from this regulation will not adequately protect Tribal health. Their main contention is that the

regulatory approach set forth in an earlier EPA proposal would have produced a 90 percent

reduction in Hg emissions and that any smaller reduction is, therefore, inadequate. That

contention rests on a misconception of an earlier Federal Register Notice, which proposed a

finding, but did not contain any specific proposal for Hg emissions regulations, and, therefore,

did not provide for any percentage of reduction. EPA has never proposed any such rule. EPA

believes that this regulation will adequately protect Tribal health.

The commenters also argue that EPA has not adequately considered the significance of

Tribal fish consumption patterns, specifically the fact that Tribal fishers consume more fish than

the general population. That comment is misplaced. As described in more detail elsewhere in

this document, EPA carefully analyzed available information on fish consumption by Tribal

members and other sub-populations, and determined how to use the available data most

appropriately. One basis for EPA’s analysis was a study of tribal fish consumption in one

region to model consumption by other Tribes as well as other subpopulations. EPA’s approach

was to identify areas where the effects of Hg deposition from utility emissions had the greatest

effects. EPA then compared those high-deposition areas with locations with high Tribal
10-xii

populations to assess the areas of greatest potential risk to Tribes. That analysis found that very

few areas where Native Americans live corresponds with high residual Hg deposition caused by

utilities. It found further, that the standards established in the regulation will significantly

reduce risks to tribal members.

Finally, as discussed in the preamble to the regulation, this regulation establishes a

cap-and-trade program for Indian country.

As part of its analysis of the this final rule, EPA has estimated the some of the health

benefits of reducing Hg from utilities. At this time EPA is only able to provide quantitative

estimates of the benefits of reducing neurological impacts of exposure to MeHg for a portion of

the U.S. population. This population covers people who recreationally catch and consume

freshwater fish. The RIA for this rule contains this analysis in Chapter 11. As part of its

assessment, EPA provides estimates for the benefits of this rulemaking to subsistence fishers,

including case study examples of the benefits to the some members of the Chippewa Tribe, the

Hmong, and low income fishers.

10.6 PROCEDURAL ISSUES

Comment:

One commenter (OAR-2002-0056-4132) asserted that EPA was pursuing an

inappropriate administrative process, and that the proposal should have been designated an

advance notice of proposed rule making (ANOPR). The commenter stated that the proposal was

an inappropriate approach to regulatory development and would result in litigation. The

commenter stated that affected parties were not being provided an opportunity to comment on the

specific regulatory language that might drive significant investments in capital equipment, and

characterized the proposal as a menu of possible approaches.

Response:

We disagree with the commenter that the proposed rule constituted an inappropriate

administrative process. EPA properly issued a proposed rule in January 2004, and proposed

three separate regulatory approaches concerning HAP emissions from Utility Units. In

addition, the January 2004 proposed rule and the March 2004 supplemental notice contained

proposed regulatory language, and we believe that those proposed regulations, coupled with the

extensive discussion provided in the preamble to the proposed rule and supplement notice,

afforded the public a sufficient opportunity to comment on the proposed regulatory language. 

Indeed, EPA received over 500,000 comments on the proposal, about 5,000 of which were

unique, and several of which addressed the regulatory text pertinent to the section 111 standards

of performance.

Comment:

One commenter (OAR-2002-0056-1138) requested that EPA provide information on the
10-xiii

background and training of enforcement personnel. The commenter also requested an estimate of

the number of new jobs that are created for every new law or regulation, as well as an estimate of

total job growth for the present year.

Response:

This comment has no relevance to how EPA sets standards of performance under CAA

section 111, and therefore no response is required.

10.7 GENERAL COMMENTS

Comment:

A large number of commenters, primarily from the general public through individual

letters and mass mail campaigns, provided general comment along the lines of:

(1) The proposed rules are a roll-back of the CAA;

(2) The CAA requires 90 percent removal; and

(3) The time-frame proposed for the emission reductions is too long.

Response:

EPA believes that these comments stem, in part, from a misunderstanding of the CAA. 

There has been no “roll-back” of the CAA. First, EPA does not have the authority to change the

CAA (only Congress can do that). Further, there are no current Federal regulations requiring

the reduction of Hg or Ni emissions from Utility Units to be “rolled-back.” This is the first time

that Federal regulations limiting these pollutants have been proposed. In addition, the CAA

does not mandate any specific emission reduction. Emission standards are to be based on the

level of control achieved in practice and on the level of emission control technologies that the

Administrator has been adequately demonstrated. The timing of the emission reductions have

been addressed elsewhere in this document.
RESPONSE TO SIGNIFICANT PUBLIC COMMENTS ON

THE PROPOSED CLEAN AIR MERCURY RULE

Received in response to:

Proposed National Emission Standards for Hazardous Air Pollutants; and, in

the Alternative, Proposed Standards of Performance for New and Existing

Stationary Sources: Electric Utility Steam Generating Units

(69 FR 4652; January 30, 2004)

Supplemental Notice for the Proposed National Emission Standards for

Hazardous Air Pollutants; and, in the Alternative, Proposed Standards of

Performance for New and Existing Stationary Sources: Electric Utility Steam

Generating Units

(69 FR 12398; March 16, 2004)

Proposed National Emission Standards for Hazardous Air Pollutants; and, in

the Alternative, Proposed Standards of Performance for New and Existing

Stationary Sources, Electric Utility Steam Generating Units: Notice of Data

Availability

(69 FR 69864; December 1, 2004)

Docket Number OAR-2002-0056

Appendix A – List of Commenters

US Environmental Protection Agency 

Emissions Standards Division

Office of Air Quality Planning and Standards

Research Triangle Park, North Carolina 27711

15 March 2005
i

General Outline

1.0 INTRODUCTION AND BACKGROUND

2.0 APPLICABILITY AND SUBCATEGORIZATION

3.0 PERFORMANCE STANDARDS FOR COAL-FIRED ELECTRIC UTILITY

STEAM GENERATING UNITS

4.0 PERFORMANCE STANDARDS FOR OIL-FIRED ELECTRIC UTILITY STEAM

GENERATING UNITS

5.0 MERCURY CAP-AND-TRADE PROGRAM

6.0 MERCURY EMISSIONS MONITORING

7.0 IMPACT ESTIMATES

8.0 COMPLIANCE WITH EXECUTIVE ORDERS AND STATUTES

9.0 NODA

10.0 OTHER

Appendix A LIST OF COMMENTERS
A-i

Table A-1. List of commenters on the Proposed NESHAP; and, in the Alternative, Proposed

Standards of Performance for New and Existing Stationary Sources: Electric

Utility Steam Generating Units

Docket ID No.

OAR-2002-0056 Commenter

0032 Brent A. Tozzer

0033 Ron Kuolous

0090 Mary Patt Garr

0091 Anonymous

0093 Anonymous

0094 Anonymous

0095 Linda Costello

0097 Joseph Traugott

0098 Chris Skidmore

0099 V. R. Sansone

0100 Anonymous

0101 Rosemary Adams

0102

2

554 mass mailings

0103 Maureen Russell

0106 Anonymous

0109 Sarah Jane Geraldi

0110 Tyler Morrison

0111 B. Kamke

0112 Judith VanDuzer

0113 Anonymous

0114 George Smith

0116 Morgan F. Simmons
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-ii

0117 Chuckie Walker

0118

2

393 mass mailings

0119

2

5,692 mass mailings

0120 Anonymous

0121

2

20,056 mass mailings

0122

1

Ann Pierson

0124 Susan Brown

0125

2

367 mass mailings

0127 Dr. Lindsay Lafford

0128 Marian M. Pelton

0129 Michele Mukatis

0130 Marion A. Mulholland

0131 Clark James

0132 Clark Andelin

0133 Ruth A. Tallman

0134 Roger Zum

0135 Anonymous

0136 David Stupin

0137 Anonymous

0138 Anonymous

0139 Anonymous

0140 Beth Goldenfield

0141 Chris Sapp

0142 Cindy Beeson
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-iii

0143 Courtney Weber

0144 Drew Huening

0145 John Purdy

0146 John O’Leary

0147 Joseph Barrett

0148 Kurt Weiss

0149 Megan Mietelski

0150 Paul Franckowiak

0151 Rebecca Heal

0152 Robert Stein

0153 Stephanie Trick

0154 Tanya Dobbs

0155 Teri Crocket

0156 Terry Hughs

0157 Tom McFarland

0158 Will Bolton

0159 Anonymous

0160 Bill Daugaard

0161 Bob Leggett

0162 Dee Holm

0163 Diana Nihem

0164, 0568 Diane Sklensky

0165 Dorothy Skovholt

0166 Jill Welch
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-iv

0167 Gabriel Grabin

0168 Anonymous

0169 Anonymous

0170 Jody Erickson

0171 Judith Englander

0172 Kara Ravenscroft

0174 Karen Johnson

0175 Lia Hutton

0176 Michael Larimore

0177 Paul Chadwick

0178 Peter Raptis

0179 Peter Reynolds

0180 Rabbi Fred Scherlinder Dobb

0181 Roy Johnson

0182 Scott Tobias

0183 Anne Gregory

0184 Anne Hoskins

0185 Christy Chase

0186 Clifford May

0187 Collin Olson

0188 Dean Petrich

0189 Deborah Leiner Fields

0190 Erica Mullen

0191 Gregory Kaplan
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-v

0192 Harold McNaron

0193 James Kaplar

0194 Jeff Fletcher

0195 Jerome Bargo

0196 Margaret Welke

0197 Mary Kaplar

0198 Mary King

0199 Michael Ackerman

0200 Michael Grill

0202 Michael Mauldin

0204 Michael Shapiro

0205 Ravi Grover

0206 Pat Simpson

0207 Robert Shroy

0208 Susan Evilsizer

0209 Suzanne Rosenblatt

0210 Tina Shang

0211 Mike Gravina

0212, 0213 Carolyn Corn

0214 Teresa J. Frakes

0215 Anonymous

0216 Shirley Cook

0217 Matthew English

0218 Kay Brunnier
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-vi

0219 Lea Siciliano

0220 Alan Posich

0221 Amanda Richmond

0222 Andrew Rowland 

0223 Antonio Cutolo-Ring

0224 David Fox

0225 Gregory King

0227 John Schmidt

0228 Kristen Hannum

0229 Linda Kimberly

0230 Martha Gene Landry-Murphy

0231 Mary Niedermeier

0232 Kevin Naze

0233 Joseph Grinnel

0234 Colleen Spark

0235 Magnus Borgehammar

0236 Carole Pooler

0237 Kevin Pamulak

0238 Marion Sebastion

0239 Paul C. Lee

0240 Catrina Poindexter

0242 Paula Burgess

0243 Priscilla Mattison

0244 Rebecca Goodrich
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-vii

0245

1

Anonymous

0246 Trevor Goodger-Hill

0247 Robert Jarecke

0248 Chuck Watterson

0249 Juliana K. Dulmage

0250 Ruth Dasche

0251 Clyde Hanson, Sierra Club North Star Chapter

0252 Rachael Lindsay

0253 Nina Eichacher

0254 Susannah Nade

0255 Katie Stan

0256 Erin Smith

0257 Timothy Hinkle

02582, 08332 Maureen D. Smith, Senior Assistant Attorney General, Environmental

Protection Bureau, Department of Justice, New Hampshire

0259 Henry Frank

0260 Jessica Noble

0261 Renee and Larry Stern

0262 James Swaney

0263 Carl Jansen

0264 Jan Saecker

0265 Susan Chandler Schoof

0266 Kevin S. Randall

0267 Sarah Murdock
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-viii

0268 Sue Howell

0269 Wanda Ballentine

0270 Adam Fedor

0271 Agnes Kelly

0272 Alex Sproul

0273 Bruce Livingston

0274 Charles Reed

0275 Charles Rinehart

0276 Christin Cifelli

0277 Darius Sivin

0278 Debora Hunter

0279 Derek Mazurek

0280 Ethyl Healy

0281 James Richard

0282 Joel Berns

0283 Kate Cleland-Sipfle

0284 Laura Jobe

0285 Michael Tieman

0286 Roberta Blaylock

0287 Ana Kasa

0288 Scott Bonner

0289 Shaler Stidham

0290 Stephen Goodrich

0291 Tamara Mason
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-ix

0292 Connie J. Conklin

0293 Anonymous

0294 Elizabeth

0295 Gary Schmitz

0296 Anonymous

0297 Christopher Blystone

0298 Carl Lowenburg

0299 Carol Harder

0300 Martin Steitz

0301 Rita Pittillo

0302 Geraldine Martinea

0303, 0627 Asbin-Nichols Family

0304 Ellen S. Harring

0305 Hollie A Williams

0306 Richard Kark

0307 Charlotte Brewer

0308 Constance Weidman

0309 Julie Keeling

0310 Victor Leger

0311 Joseph Wilde-Ramsing

0312, 04012

, 0447 Erick Tirud, Assistant Attorney General, Vermont

0313 Erik Gehring

0314 Julie Wright

0315 Lori J. Rolander
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-x

0316 Jim Traweek

0317 Chuck Meyer

0318 Pam Mentsh

0319 Ellen Howard

0320 Manaune A. Kinzer

0321 Bradley C. Burwith

0322

2

Gerald D. Reid, Assistant Attorney General, Maine

0323 Lydia Garvey

0324 Robert I. Miller

0325 Marcia Higgins

0326 Stew Hopkins

0327 Elizabeth Rhodes

0328 Bettie Minette Cooper

0329 Lucille E. Bowen

0330 David Zeff

0331 Cedar Barston

0332 Fern S. Katz

0333 Phyllis Barnister

0334 Anonymous

0335 Anonymous

0336 Paul Debreczeny

0337 Anonymous

0345 Deborah Stirling

0346 Patrick Bosold
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xi

0347 Anonymous

0348 Anonymous

0349 Oscar Shirani

0350 Peter S. Raab

0351 Joshua Saks

0352 Anonymous

0353 Anonymous

0354, 0355 Arthur H.

0356 Anonymous

0357 Troy Kimmel

0358 Rachel Cogen

0359 Paul Piersma

0360 John Kloetzel

0361 Henry Frank

0362 Anthony Ciranna

0363 Joanna Whitlow

0364 Brenda Lillis

0365 Julie Snibel

0366 Judy M. Judd, Professor

0367 Joseph and Yvonne Hammerquist

0368 Karen Mills

0369 Mark Meraner

0370 Robert Sims

0371 Renee Dolney
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xii

0372 Albert Davis

0373 Rachel Herbener

0374

1

Bobbie Dee Flowers

0375 Karen De Boer

0376 Alternate Energy Group, Indiana University of Pennsylvania

0377 Mary Stadel

0378 Helen Neville

0379 Anonymous

0380 Audrey Adams

0381 Norm Anderson

0382 Anonymous

0383 Christina Pogoloff

0384 Jerry Stifleman and Tracey Oliveto

0385 E. Mark

0386 Susan Anderson

0387 Gayle Stark

0388 Leila Evelev

0389 Charlotte Brewer

0390 Vince Deur

0391

2

Glen Compton

0392 Anonymous

0393

2

Michael Logsdon

0394 Julie Bushey Trevor

0395 Leigh Loftin
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xiii

0396 Doug Viner

0397 Lynn Bauer

0398 Michael Wexler

0399 Charlotte Trolinger

0400 Robert McGuigan

0402 Anna Keyzers

0403 Eric Weis

0404 Rev. Ilse Peetz

0405 Barbara Greene

0406 Karl Volk

0407 Doris Marshall

0408 Harry Gushikuma

0409 Alice T. Day

0410 Irene Hayes

0411 William A. Collins

0412 Faye F. Shaw

0413 Robert and Helen Lane

0414 Judith T. Hickson

0415 Osmond Molarsky

0416 Laura Kay Collins

0417 Harry S. Hinch

0418 Nancy L. Cook

0419 Dr. and Mrs. G. S. Gilchrist

0420 Zora Klein
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xiv

0421 M.T. Brace

0422 Sister Virginia Fabilli

0423 John W. Slocum

0424 Elizabeth Candels

0425 Helena Stone

0426 Janet C. Tillotson

0427 Frances W. Stevenson

0428 Deborah McNeil

0429 Anonymous

0430 Gordon Mallett

0431 C. Watton

0432 Anonymous

0433 Anonymous

0434 Amy Tidd, Sierra Club Turtle Coast

0435 Anonymous

0436 Tia Goss Sawhney

0437 Richard Dickens

0438 Daniel Herzberg

0439 Mark Lindquist

0440 Matthew A. Schwab

0441 Larry Lambeth

0442 Judith Hickson

0443 Mark Doppke

0444 Michael Hayes
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xv

0445 Henry Frank

0446 Peter Hess

0448 Ronald Moore

0449 Randall Rust

0451 Anonymous

0452 Stu Slote

0453 Anonymous

0454 John Haigis

0455 Dan Hobert

0456, 0457 Karen Philhower

0458

2

25 mass mailings

0459

2

144 mass mailings

0460 Nathaniel Hart

0461 Ken Whitton

0462 Amy Simmons

0464 Paul Weihe

0465 Rebecca Clark

0466 Peter Glick

0467 Kathy Finch

0468 Robert Ewing

0469 Susan Hammond

0470 Daniel Faust

0471 Clairvaux McFarland

0472 Gary Schmitz
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xvi

0473 Keith Law

0474 Francis Wolf

0475 David Harris

0476 Therese Curtis

0477 Anthony Hinrichs

0478 Erik and Dee Voldal

0479 Terri Allen

0480 Anonymous

0481 Andrew Moss

0482

2

103 mass mailings

0483 Karl Volk

0484 Bonnie Dugan

0485 Judi Friedman

0486

2

2,223 mass mailings

0487

2

167 mass mailings

0488 Jan Meyers

0489 Andrew Hudson

0490 Karin Westdyk

0491 Paul Moss

0492 Callie Lowenstein

0493 Ellen Tanner

0494 Doug Viner

0495 Andrea Medaugh

0496 Juliet Rynear
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xvii

0497, 0499 Anonymous

0498 Paul Knutson

0500 Pamela Sprague

0501 Gary Stewart

0502 A.J. Ralls

0503 Lynn Bauer

0504 Leigh Loftin

0505 Michael Wexler

0506 Daniel Lambert

0507 Anonymous

0508 Raymond Coulombe

0509 Anonymous

0510 Vincent and Vinita Burns

0511 David Manni

0512 Lela McNutt

0513 Stephen Volkmer-Jones

0514 Bryan Wyberg

0515 Marian Cooley

0516 Anonymous

0517 Karen Green

0518 Priscilla Mcaneny

0519 Fred Carr

0520 Jonathon Lotz

0521 Linda Keller
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xviii

0522 Peter Davis

0523 Peggy Bridgman

0524 Naomi Warner

0525 Renetta Balzer

0526 Elisabeth L. Gray

0527 Robert Arnold

0528 Dan Magee

0529 Miriam Mulder

0530 Lora Lumpe

0531 Wallace M. Elton

0532 Randy Schutt

0533 Mark Giese

0534 Rachel Dolney

0535 Howard Holt

0536 Anne Lauren

0537 Mary Love

0538 Amy McClellan

0538, 1808 Ginny Dudek, Physicians for Social Responsibility

0539 Desiree Tullos

0540 Timothy Nakayama

0541 Pamela Burt

0542 Amber Aerts

0543 Albert Weinhardt

0544 Joseph Siperstein, President, Ohio Lumex Company
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xix

0545 Celiste Felciano

0546 Lauren Demore

0547 Roy Corr

0548 Mike Turner

0549 Martin and Anne Steitz

0550 Gerald DeMaire

0551 Ann White

0552 Neil Robinson

0553 Will Tuttle, Ph.D

0554 Ann Bausch

05552

, 08212,

16081

, 3448,

3449, 3466,

3488, 3489

William O’Sullivan, Director, Division of Air Quality, New Jersey;

Bradley Campbell, Commissioner, New Jersey Department of 

Environmental Protection

0556 Joseph Barr

0557 Marjorie Derrick

0558 Barbara Lubasch

0559 Susan Bolgiano

0560 Martha D. Austin

0561 27 mass mailings

0562 George J. Rosenbilt

0563 Cheryl Hammond

0564 Henry Frank

0565 Frank Purcuinelli

0566 Kevin R. Jones
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xx

0567 Ted Sowinski

0568 Diane Sklensky

0569 Chris Weston

0570 Bob Newgard

0571 Audrey Seymour

0572 Chris Berg

0573 Graham Stafford

0574 Mary E. Bolton

0575 Keri Smith

0576 Bonnie Hart

0577 Dave Mellinger

0578 Cheryl Gross

0579 Ann Isaksen

0580 Michael D. Conlon

0581 Peter Steinhart

0582 Richard Hay

0584 Debra Kirchhof-Glazier

0585 William R. Thompson

0586 Bart

0587 Arvia E. Morrow and Peter Clitherow

0588 Diana Olhbaum

0589 Michael Brown

0590 Vincent Bowers

0591 Trevor Swoverland
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xxi

0592 Jay Starkey

0593 Carol Summers

0594 Anonymous

0595 Wolfgang Rougle

0596 Chandlee Dickey

0597 Joel and Linda Morris

0598 Bruce Nesmith

0599 Sean M. Dee

0600 Sarah Curry

0601 Nita Ferguson

0602 Bill Potter

0603 Paul Fell

0604 Steve Freedkin

0605 Katelyn Perry

0606 Lynn Weintraub

0607 Lauretta Lange

0608 Julian Powers

0609 Mary A. Simpson

0610 Erin Maloney

0611 Amanda Behrens

0612 John Amadio

0613 Diane Walker

0614 Elizabeth McSweeney

0615 Teresa G. Lyons
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xxii

0616 Heather Aston

0617 James Fuqua

0618 Marie Mallin

0619 Nick Lutz

0620 Mario Solis

0621 John McGruder

0622 968 mass mailings

0623 451 mass mailings

0624 Agnieszka Pinette

0625 220 mass mailings

0626 10 mass mailings

0627 Asbin-Nichols Family

0628 Anne Haug

0629

2

2 mass mailings

0630

2

13 mass mailings

0631 Robert S. Wallerstein

0632 Eartha Newsong

0633, 0634 Robert S. Freeman

0635 Tam H. Greene

0636 Carl and Robyn Campbell

0637 Anonymous

0638 Scott Newman

0639 Anonymous

0640 Anonymous
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xxiii

0641 Anonymous

0642 Kathy Oswalt

0643 Paul D’aura

0644 Richard Gilman

0645 Steve Knockemus

0646 Kim Struyk

0647 Anonymous

0648 Moira Smullen

0649 Indra N. Frank, MD

0650 Michael Brown

0652 William S. Bike

0655 Sue Travis

0658 Bob Fehribach

0659 Michael Vinciquerra

0660 Melissa Klein

0661 Connie Hohfeld Molbeck and James E. Molbeck, Jr.

0662 Sarah Curry

0663, 0664 Myrtle H. Cox

0673 Judy Thornber

0675 Susan Troxell

0678 Glenn Luba

0679 Donald R. Cumming

0681 Mike Shackelford

0682 Cheryl Casker
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xxiv

0684 Gaston Locklear

0686 Mike Riggs

0687 Elizabeth Geiger

0688 Jay Byrnes

0689 Kristie Turnbaugh

0690 Mary Hoffman

0691 Ronald and Sara Wenda

0692 Barbara M. Parramore

0693 Michael Riggs

0694 Chris A. Stockner

0695 Lee Meyers

0696 Scott Fisher

0697 John Maheu

0698 Dean Petrich

0699 David Carek

0700 David Brown

0701 Kathy Finch

0702 Jenny Ball

0703 Mary C. Voltaggio

0704 Joan Candalino

0705 Judith Green

0706 Douglass Gerleman

0707 Bobbie Dee Flowers

0708 Phil Medeiros
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xxv

0709 Dan Keifer

0710 Mary Kearns

0711 C.J. Clawson

0712 Wing Goodale

0713 Jeri Mueller

0714 David Smolinsky

0715 Richard Robertson

0716 Craig Havens

0717 Ken Reynolds

0718 Anonymous

0719 Richard and Evelyn Avery

0720 Low Taylor

0721 Denise Kelley

0722 Chloe Curry

0723 Niall Stephens

0724 Mary Celeste Reese

0725 Sharon Labelle

0726 Liz Cullington

0727 Debbie Netardus

0728 Barbara Leibundguth

0729 Mary Daily and Household

0730 Gail Marie Chester

0730, 1566, 1670 N. Marcia Jimenez, Environmental Commissioner, Chicago

0731 Gary S. Entre
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xxvi

0732 Joanna Willimetz

0733 Carol S. Mills

0734 Curtis T. Fowle

0735 Dona M. Baba

0736 Joane Dunhill

0737 Trisha Woolcott

0738 Sharon E. Cody

0739 7 Connecticut citizens

0741 Sherwin Sharan

0742 Jan Garton

0743 Kate Beckwith

0744 Laverne Briscoe

0745 Marjorie Homza

0746 Kenneth LaFord

0748 Virginia Booz Ullrey

0749 Lynn Darling, Audubon-Sierra Club-Nature Conservancy

0750 Monica Moore

0751 Barry Fahrer

0752 John Orr

0753 Lorraine Gentz

0754 Carlos Hernandez

0755 Robert Ross

0756 Joe Peter Burton

0758 Mary Jo Manley
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xxvii

0759 Nancy Lev

0760 Ethan Perry

0761 Ernesta Kraczkiewicz

0762 Kristin Kavanagh

0763 William K. Simeral, Sierra Club

0764 George Sorvalis

0765 Richard Fitzpatrick

0766 William Curtis

0767 Daniel Flasar

0767 Daniel Flasar, Washington University School of Medicine

0768 Martin Wallace

0769 Ettus Hiatt

0770 Pete Wilson

0771 Wendy Noel Frederick

0772 Mark Doppke

0773 Dolores Tippett

0774 Erin Moore

0775 Jean Hill-Pond

0776 Vivian Bergstedt

0777 H. V. Harris

0779 Corinne Higbee

0780 Richard H. Davis

0781 Gail Stewart

0782 Mike and Ellen Dale
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xxviii

0783 Phil Krenz

0784 Robin Crumpton

0785 Barbara Zaroff

0786 Nathan Herald

0787 Dan Burton

0788 Beth Belanger

0789 Jim Slaughter

0790 J. Perino

0791 Lillian Lageyre

0792 Frank McMahon

0793 Suzanne Connolly-Howes

0794 Joaquin Sapien

0795 Carol Stroebel, Friends of the North Fork Shenandoah River

0802 Glenn Parsons

0803 Dorothy Blaustein

0804 Nancy Rogers

0805 Brad Currier

0806 Jerry Goodman

0807 Nancy Hale

0808 Jim Hale, Sierra Club

0809 William Haines

0810 Marliss Rogers

0811 David

0812 David Kass
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xxix

0813 Betty Leech

0814 Ruth V. Steen

0815 Matthew Olsson

0816 Carol Else

0817 J.K. Reynolds

0818 M. Wilson

0819 Dolores Rodriguez

0820 John Walliser

0822 Rebecca Kurowski

0823 Inga E. Thompson

0824 Robert C. McMurray

0825 Diane Schroeder

0826 Evan Martin

0827 Teresa Smigelski

0828 William J. Schultz

0829 Dale Whorl

0830 Patricia Michael

0831 Chris Weehler

0832 Frances Freewater

0834

2

Bill Richardson, Governor of New Mexico

0835 Hildegarde Hannum

0836 Diane J. Peterson

0837 Anthony H. Hinrichs

0838 Bonno Bernard
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xxx

0839 Hedi Gerson

0840 Catherine O’Connell-Cahill

0841 Scottie Foerber

0842 Glenys Spitze

0843 John Castronavo

0844 Rosalind Michahelles

0845 Susan Dianne Rice

0846 Leonore Johnson

0847 Liz Mills 

0848 Adam Lifter, Environmental Defense Action Fund

0849 Stan Baker

0850 Judith Lockwood

0851 Paul A. Kotta

0852 Caroline Getz

0853 Judith E. Fletcher

0854 Alan Richmond

0855 Troye Kauffman

0856 Harriet Wright

0857 V.S. Clay

0858 Frank Capparelli

0859 Debra Ovadia

0860 Rev. Cynthia Crowner

0862 Charles T. Phillips

0863 Anonymous
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xxxi

0864 Tina Holzer

0865 Margaret Chenoweth, Spirithaven Foundation Inc.

0866 Julia Zaslow

0867 James L. Folz

0868 Ann Reed

0869 Don J. McCrery, Sierra Club, Coulee Region

0870 Christine Danyi

0871 Wendy Colschen, Sierra Club, Coulee Region

0872 Lauren Steiner

0873 Dirk and Elizabeth Faegre

0874 Walter Hamilton

0875 Jeanne Forbes

0876 Don Morgan

0877 Devin Post

0878 Renate Brown

0879 Michael Weissman

0880 Alice

0881 Mary McCurnin

0882 Norma Eppinger

0883 Roxanne Boyle

0884 Calvin Lindsay Elmendorf

0885 Michael A. Rubin

0886 Leo Stack

0887 Stanley Grossel
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xxxii

0888 Kenneth R. Schmidt

0889 Nanette Nelson

0890 Nancy Solomon

0891 Sue Nattinger

0892 Evan Colletti

0893 C. L. Spray

0894 Patricia Etue

0895 Anne Kaufhold

0896 Lisa Printz

0897 Barbara Seidel

0898 Roger Southworth

0899 JoAnn Durfee

0900 Sheryle Pettet

0901 Vitaly Volmensky

0902, 0956 Lance Joseph Marietta

0903 Loretta Van Coppenolle

0904 Julia Sapir

0905 Di Ana Marcus

0906 Joan W. Montagne

0907 Linn D. Barrett

0908 Anonymous

0909 Anonymous

0910 Armand C. Hale

0911 Anonymous
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xxxiii

0912 James Luth

0913 Anonymous

0914 Anonymous

0915 Robert L. Anderson

0916 Arlene Howell

0917 Anonymous

0918 Cynthia Clayton

0919 Harold Stevens

0920 Kim Rangel

0921 Anonymous

0922 Anonymous

0923 Joseph A. Valastro

0924 Joseph Breeden

0925 Anonymous

0926 Raymond Zachary

0927 James Shaw

0928 Anonymous

0929 James Boone

0930 Jim and Gail Richardson

0931 Ken Sher

0932 Stephen Potter

0933 Anonymous

0934 Dick Wright

0935 Kenny Schultz
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xxxiv

0936 Anonymous

0937 Glen Ehnert

0938 Sandi Steidley

0939 David Fiel

0940 James Windholz

0941 Siegel L. Junker

0942 Rick Sealander

0943 Malcolm R. Innerarity

0944 Anonymous

0945 Jayson A. Alteiri

0946 Carol M. Shelton

0947 Jerry Willner

0948 Bruce Youngbert

0949 Anonymous

0950 James R. Brunner

0951 Anonymous

0952 John, Sherry, and Jonathan Swanson

0953 Mr. and Mrs. Richard L. Smith

0954 Brenda Ballard-Ream

0955 Joe Metzinger

0957 David J. Booth

0958 Arthur Meader

0959 Anne Beaumont

0960 David Cayford
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xxxv

0961 Lisa Perrine

0963 Bruce Robertson

0966 Azel Beckner

0969 Marni Nacheff

0974 Eugenia Stoddard

09762, 1624,

1801, 1775,

1863, 2871

James A. Joy III, President, STAPPA; Cory Chadwick, President,

STAPPA/ALAPCO; Brock Nicholson, STAPPA/ALAPCO; Joyce E.

Epps, STAPPA/ALAPCO; Sandra Ely, STAPPA/ALAPCO; James A.

Joy, President, STAPPA and Dennis J. McLerran, President, ALAPCO

0978 Dana C. McGuire

0979 David Evans

0980 Margaret Peacock

0981 Marge Johnson

0982 Leo Beers

0983 Clara Blair

0984 Lindsay Lafford

0985 Andrew Lenz

0986 Audrey Schulman

0987 Anonymous

0988 Vicky R. Peterson Howell

0989 John Eakins

0990 Mary Ellen Rozmus

0991 Christopher Warren

0992 Anonymous

0993 Anonymous
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xxxvi

0994 Anonymous

0995 Tracy Petitjean

0996 Phillip Higley

0997 Vernon Kuhns

0998 David Siegel

0999 Bill Levin

1000 James Quinn

1001 Pamela Tabor

1002 William Johnson

1003 James Huntsman

1004 Brad and Bernice Pohlmann

1004 Carl E. Venne, Chairman, Crow Tribe of Indians

1005 Gus Beall

1006 Ronald Thompson

1007 Allen Brooks

1008 Sharon Fox

1009 James Woodruff

1010 Lance C. Lane

1011 Diane Dempsey-Shiber

1012 Bob Golenkow

1013 Sherry Salomon

1014 Anonymous

1015 James Dryer

1016 Anonymous
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xxxvii

1017 Anonymous

1018 Lee Mimms

1019 Robin Trellis

1020 Anonymous

1021 Martha A. Pitts

1022 Anonymous

1023 Greg Mitchell

1024 Dallas Snyder

1025 Anonymous

1026 Tracy Keiper

1027 Grace Gomez

1028 Edward S. Quest

1029 Mark Stewart

1030 Carl Bundy

1031 Joseph DiMarco

1032 James Brook

1033 Tucker Ruberti

1034 Richard E. Brown, American Veterinary Medical Association

1035 Brian Forrest

1036 Michael J. Murtha

1037 Janice H. Shawl

1038 Anonymous

1039 Katie Griffin

1040 Evelyn Nichols
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xxxviii

1041 Nat Thompson

1042 Emily Bartha

1043 Anonymous

1044 Anonymous

1045 Anonymous

1046 Anonymous

1046 Ed Lone Fight, Crow Tribe

1047 Anonymous

1048 Anonymous

1049 James Dearmore

1050 Arlene H. Wieland

1051 Mary Gutzwiller

1052, 1053 Rudy Lehle

1054 Elizabeth Piner

1055 Milla Kette

1056 Anonymous

1057 Raymond Herrmann

1058 Dott Clarke Koch

1059 Doug Farnen

1060 D. Murphy Hunt

1061 Paul Calabrese

1062 Donald E. Basse

1063 Shawn Branch

1064 Izzy Marrone
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xxxix

1065 Mary Bowen

1066 Anonymous

1067 Pete Gandy

1068 Lynn Silvernale

1069 Bill Hampton

1070 Anonymous

1071 Anonymous

1072 Thomas Houser

1073 John De Nicola

1074 Scott W. Witten

1075 Tim Peplaw

1076 Anonymous

1077 HiAnonymous

1078 Ken

1079 Bill Cook

1080 Joe Nemecek

1081 Anonymous

1082 Anonymous

1083 Jeanette Strother

1084 Edna Crews

1085 Anonymous

1086 Jeanne Schmelzer

1087 Randel Bradley

1088 Marie Michael
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xl

1089 Robert Charles Duffey

1090 Larry Anderson

1091, 1092, 1093 Janis Starkman

1094 Jerald L. Martineau

1095 Steve Trebus

1096 Agnes and Len Tillerson

1097 Anonymous

1098 Richard Wahl

1099 James V. Cole

1100 Mikel W. Conner

1101 R.M. Tambascio

1102 Zane Withrow

1103 Robert Stockman

1104 Theodore E. Bruszewski, Phd.

1105 Rod Brace

1106 Don and Ellie Foust

1107 Anonymous

1108 Anonymous

1109 Matthew Anderson

1110 Douglas Meyer

1112 Dee Anderson

1113 Steve Bazon

1114 Carol White

1115 Nancy Lewis
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xli

1116 Matthew Daniels

1117 Charles Kalina

1118 Richard Blain

1119 Whitney Wiggins

1120 Richard Ressler

1121 Donna Warner

1122 Bob Osland

1123 Joe Bartlett

1124 Mary Newnum

1125 Lindsay McMillan

1126 MaryElen Velahos

1127 Morgan Polotan

1128 Barbara L. Redi

1129 Deborah Oberbillig

1130 Jim Sollars

1131 Betty Bains, Sierra Club

1132 Seth Rolland

1133 Julie Patten

1134 Allen and Juanita Ward

1135 Anonymous

1136 Hannah Reinhart

1137 Walt Oicle

1138 Jeff Jackson, Center for Advanced Research and Technology

1139 Christine Clayton
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xlii

1140 Jennifer Shroder

1141 Dorothy Louis

1142 Jane Freij

1143 E.J. Cheshire

1144 Fran Daggett

1145 Joyce Wilson

1146 Raymond Leon Currier

1147 Grace Pasquarello

1148 Anne Baskin

1149 Stephanie Lafontaine

1150 Percy Lilly

1151 Julie Denision

1152 Robert Gumlock

1153 Ora Lee Young

1154 Beatrice Stone

1155 Theresa Jaworowski

1156 Susan Shouse

1157 Michael Gallaway

1158 Holly Robbins

1159 Bess M. Greenfield

1160 Kimball Hugh Bradshaw

1161 Robert L. Milne

1162 Maxine A. Dalton

1163 David B. Patterson
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xliii

1164 James P. Beck

1165 Amanda Sedillo

1166 Peter Taylor

1167 Sharon Cunningham

1168 John P. Bucki

1169 Diane M. Long

1170 Charles Carter

1171 Moira Smullen

1172 Mel Williams

1173 Paul Cowden

1174 Kate Merrick

1175 Pamela Lundquist

1176 Alan Arqueza

1177 K. V’Spek

1178 Stephen Carey

1179 Connie Golisano

1180 Paul Averill Liebow

1181 Joseph Ponisciak

1182 Fred and Cheryl Heinecke

1183 John Rogalski

1184 Matt Jorgensen

1185 Kelly P. Coleman

1186 Natalie Keiser

1187 Tim Bryson
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xliv

1188 Deb Coyle

1189 Brian Dodge

1190 Kathryn Franke

1191 Wendy A. Parda

1192, 2448 Brian Cladoosby, Chairman, Swinomish Tribal Community

1193 Jeff Ruch, Public Employees for Environmental Responsibility 

1194 Julia R. Lassotovitch

1195 Janice Patterson

1196 Alan J. Benedict

1197 Deborah D. Stewart

1198 Lee Marinaccio

1199 Erik T. Rotto

1200 Rikki Enzor

1201 Evelyn Vetere

1202 Christine M. Hicks

1203 Larry Bogo

1204 Natalie B. Killeen

1205 Sanford Gottlieb

1206 Shirley Bandy

1207 Molly McCoy Straus

1208 Cecil Lubitz

1209 Debby McMillan

1210 Colter McCorkindale

1211 Joe Stocken
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xlv

1212 Lee Martin

1213 Sue Howell

1214 Craig Schwnerman

1215 Jackie Howe

1216, 1229 Kimberly Carter, MD

1217 Annaka Larson

1218 George T. Riley

1219 Gary Botzek

1220 Mark Johnson

1221 James R. Wilson, M.D.

1222 Eric A. Sartori

1223 Rachel C. Baultinghause

1224 Joanne L Jacobson and Stuart Riches

1225 Mha Atma S. Khalsa

1226 John C. Haas

1227 Tammy de Sola

1228 James W. McMekin

1230 Joseph James

1231 Jyllian Smolev

1232 Henrietta L. Wiley

1233 Debbie Netardus

1234 Monastery of St. Gertrude

1235 Mr. and Mrs. Lance Hartford

1236 Anonymous
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xlvi

1237 J.D. Nesbitt

1238, 1239 William M. Clark

1240 Thomas Heisey

1241 Michael Kunz

1242 William E. Fisher, Jr.

1243 Anonymous

1244 Donald Estrada

1245 Suzie Clay

1246 Sharon Smith

1248 Renee Evanoff

1249 Kimberly A. Marusshok

1250 Patricia A. Hogan

1251 Ronald Gombach

1252 Gary Matson

1253 John Hanus

1254 Brad Shepard

1255 Matthew Pavolka

1256 Nancy Sohn

1257 Gayle Stark

1258 Marlene Renwyck

1259 Daniel P. Fischer

1261 Weavers Way Cooperative

1262 Holly Earnest

1263 Justin Burke Walsh
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xlvii

1264 Margaret Yaggie

1265 John Brooks and Family

1266 Denise Bash

1267 Scott Brown

1269 George Clements

1273 Scott Lewis

1274 Karen Bosc

1275 Susan H. Cushman

1276 Jim Fronk

1277 Sheryll Perry

1278 Amy Stuckey

1279 Mike Thompson

1280 Jimmy W. Hosch, Ph.D.

1281 Mary V. Hull

1282 Donna Eyman

1283 Daniel Heyduk

1284 Rachael Dillman

1285

1

Lucille Nurkse

1286 Dinda Evans

1287 Paul G. Rubin

1288 Karen Bright

1289 Carol L. Schneider

1290 Dolores Hazlebeck

1291 Bruce Hogan
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xlviii

1292 Susan A. Pohl

1293 S. Ward Eccles

1294 Sandra R. Fackler

1295 Cynthia Radcliffe

1296 Robert Fener

1297 Louise Poulter

1298 Ellen Fauerbach

1299 Christopher Kearney

1300 Steven Gehman

1301 Andrew Mongeon

1302, 1303 Brian Chisdak

1304 Diana Danford

1305 Debra, Kenn, and Raina Duncan

1306 Dr. P.M. Schlosser

1307 John Engh

1308 Robert Kulp, Jr.

1309 Lindsay Holliday

1310 Heather Soloman Wright

1311 Anonymous

1312, 1617 Ajay Goyal, SASY Inc.

1313, 1315 Carol Stark, Citizens Against Ruining the Environment Ellen Rendulich

et al., Citizens Against Ruining the Environment

1314 Anonymous

1316 Jessica Woodward
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xlix

1317 John Mulhall

1318 David Vaughan

1319 Geoffrey Taylor

1320 Alfred and Mary Jane Hasemeier

1321 Peter Todd

1322 Joan Hooker

1323 Hoyt Johnston

1324 John Lambert

1325

2

Jody Lanier

1326 Rev. Virginia Brown

1327 Robert Peacock, Chairman, Business Committee for Band of Lake

Superior Chippewa

1328 David S. Baskin, M.D.

1329 Bradley Robert Dean

1330 Linda Ewald

1331 Lydia Garvey

1332 Dr. and Mrs. Gilchrist

1333 Steve Hopkins

1334 Victor Leger

1335 Chuck Meyer

1336 Kaaren Mills

1337 Reevis and Joanna Scott Picher

1338 Holly Williams

1339 Anonymous
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-l

1340 Thomas Kardos

1341 Timothy W. Ames

1342 Theresa Hutchins

1343 Anonymous

1344 Inese Holte, TOXIC

1345 Anonymous

1346 Woodfin Bauer

1347 Joseph Holtzman

1348 Anonymous

1349 George W. Schnabel

1350 Anonymous

1351 Anonymous

1352 Wendy Smith

1353 Anonymous

1354 Anonymous

1355 Ann Waterhouse

1356 Anonymous

1357 Anonymous

1358 Anonymous

1359 Scott and Laura Helgeson

1360 Tim Schumann

1361 Tasha Waldron

1362, 1363 Julie Gagliano

1364, 1365 Erich C. Morris
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-li

1366

1

Anonymous

1369 Anonymous

1370 Carol Dalrymple

1371 Anonymous

1372 Kent Brooks

1373 Kathryn Canetti

1374

2

Frances H. Clark

1375 Christopher Clark

1376 Melanie Clements

1378 George Cavros, Sierra Club/Broward County

1402 Sarah Martin

1403

2

Rachael Mason

1404 Ronald Matt

1405 Pam Menish

1406 Jean D. Messina

1407 Dave Momenee

1408 Phyllis Smith Nickel

1409 Marie Olasov

1410 Karen O’Neil

1411 Janee P. Peters

1412 Loretta Papaulla

1413 Ralph G. Pound

1414 Jesse Powers

1415 Marcia L. Reiter
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-lii

1416 Kathleen Rospenda

1417 Kristina Schiermeister

1418 Phil Scott

1419

2

Gloria and Leo Seigel

1420 1,420 mass Sierra Club/Mackinac Chapter mailings

1421 C. Stancioff

1422 Rachel Strasz

1423 Sarah A. Sweeny

1424

2

John Terrell

1425 Rachel Thompson

1426 John Tsingas

1427 Anonymous

1428 Anonymous

1429 Issac Vas

1430 Robert Weinberg

1431 Stephen Wells

1432

2

Catherine and Paul Williams

1433 J. Woods

1435 Jim Stoll

1436 Paul Kangas

1437 Munsom

1438 Vinita and Vincent Burns

1439 Mary Brenneman

1440 Trisha Wollcott
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-liii

1441 Dorothy Wolf

1442 Ruth V. Steen

1443 J.K. Reynolds

1444 Gail Marie Chester

1445 Carol Else

1446 Glenys Spitze

1447 David Zeff

1448 Susanne C. Jessen

1449 V.S. Clay

1450 Catherine O’Connell-Cahill

1451 Elizabeth J. and Luther R. Candels

1452 M.T. Brace

1453 Laura Kay Collins

1454 Sister Rita Mary Olszewski

1455 Celeste Felliano

1456 Kay Brunnier

1457 Robert and Helen Lane

1459 Anonymous

1466 Anonymous

1467 Anonymous

1468 David Schuster

1469 Kathy Altf

1470 Bob and Ellen Lempera

1471 Susan M. Collins, U.S. Senate
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-liv

1472 Karen L. Keller

1473 Dan De La Forest

1474 Gregory Fix

1475 Phyllis Arthur, President, County Commission of Mason County

1476 Paul Mack

1477 Wren Osborn

1478 Matt Stringer

1479, 1740, 3262,

3562, 3333

Peter Heed, Attorney General, State of New Hampshire for Attorneys

General and Chief Environmental Enforcement Officers for 12 States

1480 Sidney Wanzer, M.D.

1481 Constance and David Williams

1482 Ollie Harvey, Mayor, City of Ripley, West Virginia

1483 Richard Milam, Mayor, City of St. Albans, West Virginia

1484 Amy Bidwell

1485 Anthony Shoberg

1486 Tracy Plombon

1487 Frances Lamberts

1488 Elizabeth Bouma Holtrop

1490 Jamie Chichering

1491 Jack Saye

1492 Marion Sirefman

1493 Jonathan Parfrey, Physicians for Social Responsibility

1494 Jill Jensen

1495 Marsha Pernat
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-lv

1496 Senja Lopac

1497 C. Geri

1498 Erica Voss

1499 , 3206, 34290 Barry Stemshorn, Assistant Deputy Minister, Environment Canada;

Sierra Legal Defense Fund (Canada)

1500 Praveen Gonugunta

1501 Mary Zabinski

1502 Sunshine Willard

1503 Violet Stark

1504 Marion J. Aherne

1505 Wayne Martin

1506 Anonymous

1507 Anonymous

1508 Anonymous

1508 Bernard Windham, Dental Amalgan Mercury Syndrome

1509 Sue Vernier

1510 H.M. Jones

1511 Anonymous

1512 Anonymous

1513 Anonymous

1514 Anonymous

1515 Anonymous

1516 Vasilios Contis, et al.

1517 Jay Snodgrass
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-lvi

1518 S.L. Horton

1519 Martin Vongrej

1520 Bill Pielsticker, Chair Wisconsin Council of Trout Unlimited

1521 Anonymous

1522 John M. Wiggins

1523 Anonymous

1524 Eindall K. Stine

1525 Anonymous

1526 Harvie Beavers

1527 Anonymous

1528 Stephen Miller

1529 Arnold Staloff

1531 Joan Patterson

1532 Lisa S. Qualls

1533 Dee Ann Diedrich

1534 Beth Judy

1535 Michael Solomont

1536 William Menghi

1537 Anonymous

1538 David Armstrong

1539

3

Thomas Keller, PPL Services Corp.

1540

2

Kimberly Massicotte, Assistant Attorney General, State of Connecticut

1541 Anonymous

1544 Lisa Beebee
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-lvii

1547 Gabriel Ruijsenaars

1551 Nita Garber

1552 Benjamin Heine

1553 Trout Unlimited, Blue Ridge Chapter

1554 Anonymous

1555 Steven Heiskary, North American Lake Management Society

1556, 1557, 1558 Anonymous 

1559 Anonymous

1561 Janis Peters

1562 Anonymous

1563 Anonymous

1564 Thomas M. Krauskopt

1565 Anonymous

1567, 1568 Dick Salonek

1569, 1571 Richard D. Carvajal, M.D.

1570 Jocelyn A. Ziemian

1572 Anonymous

1573

1

Anonymous

1574 Anonymous

1575 T.H. Crawford

1576 Anonymous

1577 Anonymous

1578 Larry Varnell

1579 Clayton Bollin
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-lviii

1580 Anonymous

1581 Anonymous

1582 Cathy Mihaly

1583 Robert M. Keliher, The Calumet Ecological Park Association

1584 Gerald J. and Ruth J. Moyar

1585 Sara L. Bein

1586 Jeremy Green

1587 Jennifer Kothlow

1588 Jonathon Osmond

1589 Robert O. Preyer

1590 Sandra Spendlove

1591 Ramona Finos

1592 Janice Owens

1593 Marta Taylor

1594 Willi Lehner

1595 Karen L. Keller

1596 Brandt Mannchen, Sierra Club/Houston

1597 Nelson H. Hawkins

1598 Bruce Hooke

1599 Becky Lee, et al.

1600 Nancy Thompson

1601 Anonymous

1602 Mr. and Mrs. Americo A. Fusco

1606

3

Ajay Goyal
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-lix

1606

3

Ariele Llorens

1606

3

Bill Moore

1606

3

Blayne Grave

1606

3

Brian Urbaszewski, American Lung Association

1606

3

Caroline Herzenberg

1606

3

Coleen Sarna

1606

3

Dave Madden

1606

3

David Hetzel

1606

3

David Cugell, M.D.

1606

3

Donna Green

1606

3

Edward Haggard

1606

3

Elaine Kittredge

1606

3

Erin Jorhadl-Redin

1606

3

Gina Lettiere

1606

3

Ginger Duiven

1606

3

Indra Frank

1606

3

Jackie Schomer

1606

3

Jacob Zausch

1606

3

Jill DeWitt

1606

3

Joan Para

1606

3

Joe Highland

1606

3

Johathan Parfrey, Physicians for Social Responsibility, LA

16063, 1632 John Heinrich, Wisconsin Department of Natural Resources; Henry

Anderson, Wisconsin Department of Health and Family Services
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-lx

1606

3

John Raffensperger

1606

3

Julia Allison Risser

1606

3

Kim Novick

1606

3

Kristi Kowal

1606

3

Laura Urbaszewski

1606

3

Lauren Mansell

16063, 1665 Lee Francis , Physicians for Social Responsibility

1606

3

Lee Foushee, Indigenous Womens Mercury Investigation 

1606

3

Lisa Diment

1606

3

Lisa Yee

1606

3

Margaret McClintock

1606

3

Marjorie Ettlinger, League of Women Voters

1606

3

Mary Holms

1606

3

Michael B. Kaye

1606

3

Michael Grill

1606

3

Michael B. Kaye

1606

3

Michael Brill

1606

3

Michele Sommers

1606

3

Michelle Navarre Cleary

1606

3

Pat Guinn, Lt. Governor, State of Illinois

1606

3

Patty Crow

1606

3

Rebecca Winkler

1606

3

Roberta Richardson

1606

3

Roger Grissette
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-lxi

1606

3

Sandra Benzeev

1606

3

Sandy Justis

1606

3

Shannon Fisk, Environmental Law and Policy Center

1606

3

Stephanie Montgomery

1606

3

Steve Frankel

1606

3

Susan Zingle, Lake County Conservation Alliance

1606

3

Thomas Robert Hartmann

1606

3

Vince Bertolini

1608

3

Al Seiss

1608

3

Allen Muller, Green Delaware

1608

3

Amanda Bergson-Shilcock

1608

3

Angela Ledford, Clean the Air

1608

3

Ann Wynn

16083

, 1783,

2889, 2892,

2893, 2894,

2896, 4133,

4134

Barbara Kwetz, Massachusetts Department of Environmental

Protection; Robert Golledge, Commissioner, Massachusetts Department

of Environmental Protection

1608

3

Beth L. McGee, Chesapeake Bay Foundation

1608

3

Bill Hall

1608

3

Brad Sift

1608

3

Brian Bradley

1608

3

Brian Smith

16083

, 1759 Carol Ward, Dental Amalgan Mercury Syndrom

1608

3

Cathy Harris
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-lxii

1608

3

Cercie Urbanski

1608

3

Christine Cantrell

1608

3

Claudia Vanderslide

1608

3

Coralie Pryde

1608

3

David Joseph Trickett

1608

3

David Prescott

1608

3

Debbie Heaton

1608

3

Denise Ryan

1608

3

Dereth Glance, Citizens Campaign for the Environment, NY

1608

3

Dr. L. Matthew Schwartz

1608

3

Ellen Silbergeld

16083

, 1765 Freya Koss, Consumers for Dental Choice

1608

3

Freyda Black

1608

3

Gabriel Grabin for Lisa Graves Marcucci, Jefferson Action Group

1608

3

Germane A. Germeyer

1608

3

Grace Vodga

1608

3

Hans Banardson

1608

3

Harriet Hirslich

1608

3

Hugh Gorman

1608

3

Janet Kenepp

1608

3

Jason K. Barbie, NY Public Interest Research Group

1608

3

Jay Treat

1608

3

Jim Black

1608

3

Joe Connelly
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-lxiii

1608

3

John Le Bourgeois

1608

3

John Kearney

1608

3

John Stanton, National Environmental Trust2

1608

3

John Shennan, Adirondack Council

1608

3

John Hinck, National Resources Council

1608

3

John Stanton, National Environmental Trust

1608

3

Jonathan Lewis, Clean Air Task Force

1608

3

Julie Bussiere

1608

3

Kate Territo

1608

3

Kate Erdei

1608

3

Kevin Scott

1608, 1778, 3539 Lenny Dupuis and Pamela F. Faggert, Dominion Resources, Inc.

1608

3

Leslie Smith

1608

3

Linda Cald

1608

3

Lisa Zubowicz, PennFuture

1608

3

Loretta Dunne

1608

3

Lyman Welch, Mid-Atlantic Environmental Law Center

1608

3

Mabel Mallard

1608

3

Magalee Larson Temple

1608

3

Marsha Low, Clean Air Council

1608

3

Marvin Lewis

1608

3

Marvin Lewis

1608

3

Marvin Thall

1608

3

Matthew Miller, Maryland Public Interest Research Group
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-lxiv

1608

3

Matthew Miller, Maryland Public Interest Research Group

1608

3

Mekel Marcy

1608

3

Meredith Wood

1608

3

Michael Ferrantino, Group Against Smog and Pollution

1608

3

Michelle Wallhagen

1608

3

Mike Ewall

1608

3

Mike Rosenberg, Green Party of Philadelphia

1608

3

Nathan Wilcox, PennEnvironment

1608

3

Nicholas O. Scull

1608

3

Peter Lehner, Office of Attorney General of New York

1608

3

Rich Garella

1608 Robert C. Dalton, Aspect Enterprises

1608

3

Robin Mann

1608

3

Rosemary Volpe

1608

3

Ruth Bolter

1608

3

Scott Newman

1608

3

Susan Govreeski, League of Conservation Voters Education Fund

1608

3

Teresa Mendez-Quigley, Women’s Health and Environment Network

1608

3

Virginia Craciun

1608

3

W. Robert Campbell, Sierra Club

1608

3

Walter Stern

1608

3

William B. Wycoff

1608

3

William Cook, Citizen Campaign for the Environment

1611

3

Alice Teich,, Physicians for Social Responsibility
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-lxv

1611

3

Allison Best

1611

3

Allison Donnelly

1611

3

Beth Barfield, Virginia Independent Power Producers

1611

3

Bill Delmar

1611

3

Bill Wood

1611

3

Braden Craig

1611

3

Brian Garrett

1611 Brock Nicholson, NC Division of Air Quality

1611

3

Christine Stefani

1611

3

Cynthia Walker

1611

3

Dan Ryan

1611

3

Dr. Jessica Christie

1611

3

Dr. John Hammond

16113

, 2909, 3391 Dr. Luanne Williams, North Carolina Department of Health and Human

Resources; B. Keith Overcash, Director, North Carolina Department of

Environment and Natural Resources

1611

3

Gail Rouche, Wake County Association for Retarded Citizens

1611

3

Hart Pillow

1611

3

Heather Joacobs, Pamlico-Tar River Foundation

1611

3

Holly Bankoski

1611

3

Jeanne Ansley

1611

3

Jeannene Wiseman

1611

3

Jill Freeman

1611

3

Jill Stevens, National Parks Conservation Association

1611

3

Khristi Tominson
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-lxvi

1611

3

L.C. Coonse

1611, 4891, 4890,

4892, 48933

Laura LaValle and Michael J. Nasi, Lloyd, Gosselink, Blevins, Rochelle,

Baldwin, and Townsend, Texas Lignite Coalition

1611

3

Mark Zumbach

1611

3

Mary Frazer

1611

3

Matt Wasson

1611

3

Matthew Barton

1611

3

Michael Stalnaker

1611

3

Molly Diggens, Sierra Club/North Carolina

1611

3

Nancy McDermott

1611

3

Nichole Grice

1611

3

Nora Gottlieb

1611

3

Pamela Irwin, Sierra Club/Virginia

1611

3

Paul Miller

1611

3

Peter Adler

1611

3

Peter Walker

1611

3

Rachel Zajac

1611

3

Rebecca Robins

1611

3

Rep. Paul Luebke, NC House of Representatives

1611

3

Robert Manning, Esq., Hopping Green and Sams

1611

3

Robin Jenkins, R.N.

1611

3

Scott Gollwitzer

1611

3

Senator Ellie Kinnaird, NC Senate

1611

3

Ti Harmony
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-lxvii

1611

3

Tiffany Urban

1611

3

Tim McBrayer

1611

3

Tom Transue

1611

3

Wayne Wilson

1611

3

Wendy Michener

1615 5,092 mass mailings

1618, 2173, 2174,

2175, 2176,

2177, 2178,

2179, 2193,

2194, 2195,

2376, 2377,

3496-3504,

3414, 3415

Al Miham, Forest County Potawatomi Community; Harold Frank,

Chairman, Forest County Potawatomi Community; Lawrence Daniels,

Natural Resources Director and Therese Hubacher, Air Specialist and

Gretchen Watkins, Water Specialists, Forest County Potawatomi

Community Tribal Natural Resources/EPA

1619 Andy Knott, Hoosier Environmental Council

1620 Boise D. Jones, Environmental Justice Advocates of Minnesota

1621 Brad Maurer, Ohio Smallmouth Alliance

1622 Carey Hamilton, Save the Dunes Council

1623 Cathy Woolums, MidAmerican Energy Holdings Company

1625, 1772, 1819,

1860, 2929,

4894, 4895,

4896, 5469

Dan Riedinger, John Kinsman, Michael Rossler, Michael Rossler,

Quinlin Shea, Michael Rossler, Edison Electric Institute and Charles

River Associates (memorandum to Edison Electric Institute)

1626 Danielle Welliever, Evangelical Lutheran Church in America

1627, 3521, 5472 Dennis Leonard and Michael Rodenberg, Detroit Edison Company

1628 Ellen Rendulich, Citizens Against Ruining the Environment

1629 Eric Uram, Sierra Club/ Midwest Office

1629

3

Eric Uram, Mercury Free Wisconsin
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-lxviii

1630 Erin Jordahl Redline, Clean Water Action Alliance

1631

3

F. Daniel Cantrell on behalf of Congressman Danny K. Davis

1633 Anonymous

1634 Jean de Smet

1635 John R. Ackerman

1636 David Grafke

1637 Debra Kirchhof-Glazier

1638 Louette Rogers

1639 Winifred and Frederick Wilhelm

1640 Mary M. Sass

1641 Calvin J. Haneline

1642 Diane

1643 Adam A. Krzmarzick

1644 Penelge Perez DeNormandie

1645 Enid S. Winchell

1646 Anonymous

1647 Diana Smith

1648

2

Rachel Mason

1649 Peggy P. Elliott

1650 Elizabeth Donaldson

1651 Dennis Thomas

1652 William J. Sappenfield

1653 Celine Wozman

1654 Janice Grant
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-lxix

1655

4

John P. Devine, Jr., Natural Resources Defense Council

1656 James W. Coursey, Illinois Council of Trout Unlimited

1657 Jean Flemma, Prairie Rivers Network

1658, 2041, 2364 John A. Paul, Ohio Regional Air Pollution Control Agency

1659 John W. Thompson, Clean Air Task Force

1660, 1779 Karen Truskowski, Dental Amalgan Mercury Syndrome

1661 Katherine Duck, Indiana Interfaith Environmental Task Force

1662 Kathleen Schuler, Institute for Agriculture and Trade Policy

1663 Kurt Waltzer, Ohio Environmental Council

1664 Laurel O’Sullivan, Lake Michigan Federation and Delta Institute

1666 Lee H. Walker, New Coalition for Economic and Social Change

1667 Leise Jones, U.S. Public Interest Research Group

1668 Linda Gray Sonner, Presbyterians for Restoring Creation

1669 Marc Looze, Clean Wisconsin

1671 Marcia Wilhite, Association of State and Interstate Water Pollution

Control Administrators

1672 Majorie Ettlinger, League of Women Voters and Lake Michigan

Interleague Group

1673 Mary Kenkel, Cinergy Corp.

1674 Matt Little, Mercury-Free Minnesota Coalition

1675 Michael T.W. Carey, Ohio Coal Association

1676 Michelle Gottlieb, Physicians for Social Responsibility/ Greater Boston

1677 P. Bruce Hill, Ken American Resources, Inc.

1678 Paul Zugger, Michigan United Conservation Clubs

1679 Peg Lautenschlager, Attorney General, State of Wisconsin
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-lxx

1680 Phillip M. Gonet, Illinois Coal Association

1681 Rebecca Stanfield, Illinois Public Interest Research Group

16823, 1967,

2108, 2109,

3302, 2160

Renee Cipriano, Director, Illinois Environmental Protection Agency; Bill

Hoback, Chief, Office of Coal Development and Marketing, Illinois

Department of Commerce and Economic Opportunity

1683 Rich Femling, Rose Creek Anglers, Inc.

1684 Robert Shimek, Indigenous Environmental Network

1685 Ryan Canney, Citizen Action Illinois

1686 Sarah Streed, Wisconsin Interfaith Climate and Energy Campaign

1687 Sara Welch, Izaak Walton League of America

1688 Shane Staten, Sierra Club/Missouri Chapter

1689 Verena Owen, Lake County Conservation Alliance

1690 Zoe Lipman, National Wildlife Federation

1692 Hal Quinn, National Mining Association

1693 Vicki Levengood, National Environmental Trust

1694 Anonymous

1695 Norman Birchfiled

1696 Anonymous

1697 Matt Fine Silver

1698 Dan Kien

1699 Anonymous

1700 Anonymous

1701 Anonymous

1702 Anonymous

1703 Anonymous
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-lxxi

1704 Anonymous

1705 Anonymous

1706 Scott Olsen

1707 Anonymous

1708 David Levner

1709 Lynn E. Frederiksen

1710 Anonymous

1711 Rachel Betesh

1713 Anonymous

1714 Melissa D. Bernardin, Clean Water Action

1715

1

Danielle White

1716 Gabin Barbour and Sarah M. Brown

1717 J.Y.

1718 Mr. and Mrs. Robert Cossins

1719 Janice Gibbons

1720 Lora Chamberline, D.O.

1721 Wilt Stites

1722 Tom Meacham

1723 Lori Chilefone

1724 James J. Norman

1725

1

Sarah Hunter

1726

1

John Garrett Baker

1727 Paul Luehrmann

1728 Bethany Knighton
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-lxxii

1729 James Balne and Shirely Balne

1730 Marilina Resasco

1731 Oganes Pahlevanyan

1732 Wendy Hanophy

1733 Richard Schuckman

1734 Elaine Manzeke Eagon and Paul H. Eagon

1735

2

Sarah Novey

1736 Dr. Lewis Cuthbert, Alliance for a Clean Environment

1737 Catherine E. Anderson

1738 Susie Tanenbaum

1739 Ryan Thomas Morra

1741 Gaylah Balter

1743 Matt Potter

1744 Daniel F. Cebelinski

1746

2

John Dukovich

1747 Linda S. Sanders

1748 Jeannie Roberts

1749 Brian Jacobs

1750 Marylyn and Stewart Stroup

1751 David B. Olson

1752 Darsi McCarthy

1753 Anonymous

1755

2

Ellen K. Silbergeld, Professor of Environmental Health Sciences and

Epidemiology, John Hopkins University
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-lxxiii

1755

3

Michael McCally, Physicians for Social Responsibility

1756 Alan J. Muller, Green Delaware

1757 Rev. Arthur Waskow, Shalom Center

1758 Dr. Bert Zauderer, Coal Tech Corporation

1761 Catherine Bowes, National Wildlife Federation

1762 Dr. Lynn Shanks, Maple Creek Mining, Inc.

1763, 2886, 2887,

2888, 2890

Dawn R. Gallagher, NESCAUM; Praveen Amar, NESCAUM

1764 Frank O’Donnell, Clean Air Trust

1766 Gary Anderson, ARIPPA 

1768, 3530 Jeffrey Marks and Dave Harvey, National Association of Manufacturers

1769 Jeffrey W. Stehy, University of Maryland Department of Meteorology

1770 Jerome Balter, Public Interest Law Center of Philadelphia

1771 John Hinck, Natural Resources Council of Maine

1773, 3441, 3442 Joseph Otis Minott, Clean Air Council

1774 Joy Bergey, Center for the Celebration of Creation

1776 Karen Hadden, Sustainable Energy and Economic Development

Coalition and Public Citizen

1777, 2764 Kyle Kinner, Physicians for Social Responsibility

1779 Michael Gross, Coalition on the Environment and Jewish Life

1780 Nancy Parks, Sierra Club, Pennsylvania

1781, 2924, 2925,

3567

Nicholas DiPasquale, Commonwealth of Pennsylvania, Pennsylvania

Department of Environmental Protection

1782 Omar Taylor, Northeast Environmental Justice Network

1785 Sharon Finlayson, New Jersey Environmental Federation
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-lxxiv

1786 Susan Gobreski, League of Conservation Voters Education Fund

1788 Wisssahickon Charter School

1789 Ed Knorr, Green Action Alliance

1790, 1857, 1784,

3516

Scott Segal and Frank Maisano, Electric Reliability Coordinating

Council

1791 Gilliam Ream, Maryland Public Interest Research Group

1792 Jeffrey Solow

1793 Mayoli Larson

1794 Navis Bermudez, Sierra Club

1795 Charles T. Mcllhinney, Jr., Pennsylvania House of Representatives

1796

3

Amy Schaich

1796

3

Arthur Stamoulis

1796

3

Brandy Mangum 

1796

3

Brian Garrett 

1796

3

Christine Wunsche

1796

3

Christine Miller

1796

3

David Armstrong

1796

3

David and Marsha Low

1796

3

Dr. Jessica Joyce Christie

1796

3

G.A Germeyer

1796

3

Henry Jonas Magaziner

1796

3

Janet Nyce

1796

3

Joan Candalino

1796

3

Lisa Mosca
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-lxxv

1796

3

Loretta Dunne

1796

3

Marc Guerra, M.D.

1796

3

Melissa Gee

1796

3

Michelle Walhagen

1796

3

Mollie Brown

1796

3

P.J. Puryear 

1796

3

Paul Nettesheim 

1796

3

Paul Murray

1796

3

Sue Althouse

1796

3

Sylvia Buchlioz

1797 Alice Garland on behalf of John Edwards, U.S. Senate

1799 Allison Martin, South Carolina Coastal Conservation League

1800 Amy Carson, Moms Against Mercury

1802 Charles R. Wakild, Progress Energy Service Company

1803, 1854 David Duncan

1804, 3454, 3455,

3563, 5056,

5500, 5591

David Foerter, Institute of Clean Air Companies

1805 David Knight, Sierra Club

1806 Elizabeth Ouzts, North Carolina Public Interest Research Group

1807, 4962 Felice Stadler, National Wildlife Federation

1809 Harvard Ayers, Appalachian Voices

1810 Hope Taylor-Guevara, Clean Water for North Carolina

1811 Jeff Gleason, Southern Environmental Law Center

1812 Dr. John C. Pittman, North Carolina Integrative Medical Society
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-lxxvi

1813 Katherine Shea, Physicians for Social Responsibility

1814 Kris W. Knudsen, Duke Energy Corporation

1815 Lewis Patrie, Physicians for Social Responsibility, Western NC

1816 Marmie Clark, Elders for Peace

1817 Martha Keating, Clean Air Task Force

1818, 2945 Michael O. McKown, Murray Energy Corporation

1820 Michael Shore

1821 Mike Evans, North Carolina Wildlife Federation

1822 Richard Harkrader, North Carolina Sustainable Energy Association

1823 Tancred Miller, Sierra Club, North Carolina

1824 Valerie True, Southern Alliance for Clean Energy

1825 Louise Romanow, League of Women Voters of Wake County

1826, 5484-5487,

5489

Danny Herrin and C.M. Hobson, Southern Company

1827 Mary Alsentzer and Heather Jacobs, Pamlico-Tar River Foundation

1828 Pediatric Health Professionals

1829 Sarah Heath Olesiuk

1834 David W. Knuth, Marshall County Chamber of Commerce

1835 Tracy V. Drake, Chief Executive Officer, Columbian County Port

Authority

1836 Lucille P. Duca

1837 5 mass unknown mailings

1838 Rem and Louise Edwards

1839 Sheralyn M. Heyse, R.N.

1840 Patricia Ann Young
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-lxxvii

1841 Dr. Jennifer L. Howse, President, March of Dimes

1842 The McIlvaine Company

1843 Daria Barbour

1844 Lou Ann R. Danforth

1848

3

Amanda Champany, Colorado People’s Environment for an Economic

Network

1848

3

Amy Livingston

1848

3

Amy Prater, Washington Park United Church of Christ

1848

3

Andrew Kear

1848

3

Bruce Glenn, Eco-Justice Ministries

1848

3

Carol Boigon, City Councilwoman for Denver

1848

3

Charles Wanner, San Juan Citizens Alliance of Durango Colorado

1848

3

Clarence Baer, First Plymouth Congregational Church

1848

3

Cody Hamilton

1848

3

Dan Halleman

1848

3

David Grossman

1848

3

David Barber, Citizens for Clean Air and Water in Pueblo and Southern

Colorado

1848

3

Dr. David B. King

1848

3

Dr. Ken Gerdes

1848

3

Elizabeth O’Donnell

1848

3

Emma Young

1848

3

Eric Phillips-Nania

1848

3

James Todd

1848

3

Jeremy Neufeld
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-lxxviii

1848

3

John Roper

1848

3

Josh Blum

1848

3

Joyce Johnson

1848

3

Judy Linski

1848

3

Justin Dawe, Environment Colorado

1848

3

Ken Regelson

1848

3

Kristin Casper, Greenpeace Clean Energy Now

1848

3

Leslie Glustrum

1848

3

Lin Berrett

1848

3

Lynn Judson

1848

3

Marilyn Starns

18483

, 18483,

2094, 2660

Michael Fowler, Permit Section, New Mexico Environment Department;

Sandra Ely, Air Quality Section, New Mexico Environment Department;

Dr. Ronald E. Voorhees, New Mexico Department of Health; Ron

Curry, Cabinet Secretary, New Mexico Environmental Department and

Patricia Montoya, Cabinet Secretary, Department of Health

1848

3

Noah Zakim

1848

3

Rafaele Schiffman

1848

3

Rebecca Dickson

1848

3

Rich Rebman, Renegade Research

1848

3

Sarah Milligan

1848

3

Sean Schumer

1848

3

Sonya Guram

1848

3

Steven Krichbaum

1848

3

Tom Dickson-Hunt
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-lxxix

1848

3

Unny Nambudiripad, Western Clean Energy Campaign

1848

3

Wayne Massi

1851 Andy Schultheiss, League of Conservation Voters Education Fund

1852 Carrie Kowalski, KFX Inc.

1853 Cindy Copeland

1856 Elizabeth Andrews, National Environmental Trust

1858 John Rosapepe, Sierra Club, Rocky Mountain Chapter

1859 Lee Eberley, XCEL Energy

1861 Pam Milmoe, Boulder County Public Health

1862 Rich Moore, Grand Canyon Trust

1864 Alicia Delgado

1865 Andrew Van Lue

1866 Anonymous

1867 Danielle Koepke

1868 Ellen Salvador

1869 Judy Raizen

1870 Michael Maer

1871 Naccome Chaunto Garlich

1872 Paul D. Garcia

1873 Raquel Holguin

1874 Ryan Yoder

1875 Windy Elizabeth Cook

1876 Zoila Lora Saputo

1877 Anonymous
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-lxxx

1878 Mary T. Bowen

1879 Victoria S. Awarey

1880 Vise and Laura Vise

1881 Kurt Karbusicky

1882 Glynis Kinnan

1883 Karen Rahn

1884 Janet C. DiNapoli

1885 Lorrie Streifel

1887 Barbara J. Hamill

1888 Lori Segall

1889 Robert Farley, Princeton-Mercer County Chamber of Commerce

1890 Ron Shaffer

1891 Cheryl Pomeroy

1892 Vickie L. Jones

1893 Janet I. Green

1894

2

Natalie Faes

1895 Albert L. Walker

1896 Daniel S. Moroney

1897 Shelly Moran

1898 Laurie A. Fitch

1899 James Conroy

1900 Emmett S. Pugh III, Mayor, City of Beckley

1901 David A. Schultz

1902 James. H. Douglass, Governor, State of Vermont
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-lxxxi

1903 Maria Keirnan

1904 Crystal Michaliszyn

1905 Anonymous

1906 Anonymous

1907 Deborah Scott

1908 Jeanne E. O’Neill

1909 Edward Hayden

1910 Alison Wiley

1913 Anonymous

1914 Tom Ward

1915 Darwin Spaysky

1916 Sue E. Anderson

1917 Earlene Webster

1918 Anonymous

1919 James R. Sutton

1920 Mary Kay and Rick Wilson

1921 Hank Epstein

1922 Dolores Petry

1923 John D. Lloyd, M.D.

1924 Paul K. Holmes

1925 Dr. Pamela Hannaman-Pittman

1926 Julia Glenn

1927 Eileen Weinsteiger

1928 Ruby Hruby
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-lxxxii

1929 James W. Buchanan

1930 Kem Moser

1931 Jocelyn Muggli

1932 Karl and Kathy Richardson

1933 Tammy Mercer

1934 Michael Pease

1935 Sharon Outler

1936 Jane Scudder

1937 Dianne E. Adams

1938 Jasper J. Medici

1939 Cary Terral

1940 Deborah Pardi

1941 Peter Carminati

1942 Thomas Pullano, M.D.

1943 Kathleen Stried Noe

1946 Geoff Schaefer

1950 Jenny Pike

1951 Nancy Rissler

1952 John K. Alderman, President, Material Automation Systems and Service,

Inc.

1955 Robert A. Wyman et al., Latham and Watkins

1956 Mary Gorman

1957 Anonymous

1958 Anonymous
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-lxxxiii

1959 Amy Mattix

1960 Robert Plumley

1961, 3470 Carl E. Benne, Chairman, Crow Tribe of Indians, Crow Tribe Executive

Branch

1962 Anonymous

1963 Cindy

1964 David G. Hill

1965 Heather Doyle

1966 Chris Keenan

1968 Regis McCann

1969 Terry Graumann, Manager, Otter Tail Power Company

1970 Frank N. Egerton

1971 Anonymous

1972 Anonymous

1973 Kristi Espiinoza

1974 Anonymous

1975 Ed Leary

1976-1984 EPA Telephone Hotline Comments covering 19 Jan 2004 through week

of 22 March 2004

1986 Diane St. Germain

1987 Terry Aikin

1988 Al and Marti Marino

1989 Karl B. Bucholz and Karen H. Robinson

1990 Mark Jacobson and Phyllis Stuart-Jacobson

1991 Patricia P. Willis and Thomas M. Willis, Jr., Adirondack Mountain Club
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-lxxxiv

1992 Cheryl Pomeroy

1993 Jean M. Geissler

1994 Jennifer Brook-Kothlow

1995 A. Carmen

1996 St John’s Church senior class

1997 Marcia R. Kaminski

1998 Alfred and Mary Jane Hasemeier

1999 Anonymous

2000 Janice Owens

2001 Peter Kozlowski

2002 Dennis Miller

2003 Marni J. Good

2004 Janet Burkhart

2005 Joanne Holbrook

2006 Richard Schuckman

2007 Dr. A-Lea Salis Louis

2008 Russell Hill, Vice President, Boral Material Technologies Inc.

2009 Mark Johnson

2010, 2013 Frank Ettawageshik, Odawa Tribal Chairman

2011 Neil F. Woodworth, Counsel, Adirondack Mountain Club

2012 Anonymous

2014 Georgina M. Lampman, President, Water Quality Section, American

Fisheries Society

2015 Anonymous
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-lxxxv

2016 Anonymous

2017 Laurie Puscas

2018 Luanne K. Williams

2019 Nate Lengacher

2020 Judy Sewell, Henderson Area Chamber of Commerce

2021 Anonymous

2022 Anonymous

2023 R.T. Rybak, Mayor of Minneapolis

2024, 2025 Lynn Hardwick

2026 DuWayne A. Wenger

2027 John W. Barnett

2028 Jennifer K. Bunting

2029 Nancy Wiegand

2030 Judy Archibald

2031, 2262 Dereth Glance and Adrienne Esposito, Citizens Campaign for the

Environment

2032 Anonymous

2033 Austin Investors

2034 Tami Burdo

2035 Eileen Kramer

2036 Anthony and Patricia Busalacchi

2037 Rita M. Jarman
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-lxxxvi

2038, 2367, 2854,

2858, 4916-

4929, 4983-

4985

David Sleeper, Hubbard Brook Research Foundation and 35 mercury

scientists

2040 Joseph Siperstein, President, Ohio Lumex Company

2042 Rodger a. Kershner, Howard and Howard Attorneys

2043 Kirby Tyndall, Ph.D.

2045 Kent Newman

2046, 2432, 2433,

2502, 2521,

5282, 5332

Anne G. Berwick, Associate Director, The Clean Energy Group

2047 Anonymous

2048 Anonymous

2049 Los Alamos National Laboratory

2050 Anonymous

2051 Barbara J. Crouch

2052 Carol Braswell

2053 Jeannie Bridges

2054 Dennis R. James, Fuel Quality Administrator, North American Coal

Corporation

2055 Anonymous

2056 Craig Kullman

2057 American Academy of Pediatrics, American Public Health Association,

Alliance for Healthy Homes

2058 Joe Miner

2062 Andrew Eisenberg, MD, Chair, Texas Medical Association
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-lxxxvii

2063, 5429-5440 Jean B., ADA-Environmental Systems, and Sheila Glesmann, Emission

Strategies, Inc.

2064, 2213, 2359,

2905

Al Shea, Administrator, Air And Waste Division, Wisconsin Department

of Natural Resources; Scott Hassett, Secretary, Wisconsin Department

of Natural Resources

2065 John M. Wylie

2066 Norbert Dee, Director, Environment and Safety, National Petrochemical

and Refiners Association (NPRA)

2067 Mr. Simon, Manager, State Government Relations, Missouri River

Energy Services

2068, 2069-2070,

5477

Frederick D. Palmer and Roger B. Walcott, Jr., Peabody Energy

2071 Thomas Dernoga, Chair, Metropolitan Washington Council of

Governments

2072 Karen Banks

2074 Anonymous

2075, 2266 John Stroud, President, North East Texas Economic Developers

Roundtable

2076 Anonymous

2077 Anonymous

2078 Stanton W. Rogers

2079 Energy and Environmental Research Center

2080 Anonymous

2081 Charles Revill

2082 Gary and Nancy Haygood

2083 Gary L. Spicer

2084 Theodore Keebaugh
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-lxxxviii

2085 Stephen E. Woock, Weyerhauser

2086 Anonymous

2087 Leon F. Szeptycki, Trout Unlimited Eastern Conservation Director

2088 Del McCabe

2089 Debbie Lennie

2090, 2142 Brian Houseal, The Adirondack Council

2091, 2331 D. L. Berry, Regulatory Affairs Expertise Center, Dow Chemical

Company

2092 John Denman

2093 Jerry Wood

2095 Anonymous

2096 Anonymous

2097 Cliff Germain

2098 Arthur B. Scharlach

2099 Anonymous

2100 Anonymous

2101, 2103 Tekran Inc.

2102 Hughes Stanley

2104 Raylene Patterson Conner

2105, 2220, 2231 Kevin S. Barnett, Senior Consultant, Alcoa Corporate Center

2106 Sue Steinmo

2107 Joel Swadesh

2110 Cathy Green

2111 Brian T. Traux
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-lxxxix

2112 Carl E. Edlund, EPA Region 6

2113 Cynthia Durlin

2114 Stephanie Green, Texas Public Interest Research Group

2115 G.E. West, Chairman, Committee of Energy Resources, Texas House of

Representatives

2116 Gifford Miller and Christine Quinn, New York City Council Committees

on Environmental Protection, Health, and Waterfronts

2117 Michael K. Taylor, Rea and Associates

2118 Donald Moore, Sr., Tribal Chairman, Bad River Band of Lake Superior

Chippewa

2119 Dee W. Hart, Tatum District School Superintendent

2120 Ronald F. Hammerschmidt, Director, Kansas Department of Health and

Environment

2121 Mass campaign, Unitarian Society of North Hampton and Florence

2122 Joyce Watts

2123 Kenneth H. Busz, Huntington Regional Chamber of Commerce

2125 Mary L. Jelks, MD

2126 Stan Pitts

2127 Frank Carl

2128 Tiffany Cesto, et al.

2129 John Hubert

2130 Douglas Pintar

2131 C.J. Guerin-Fuoco

2132 Joy Drohan

2133 Ben Hueftle
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xc

2134 Grace E. Grant

2135 Robert D. Herron, James R. Griffith, and Terry L. Wagner, Carroll

County Board of Commissioners

2136 E. Howard Youmans

2137 Gail G. Kincaide, Executive Director, Association of Women’s Health,

Obstetric and Neonatal Nurses

2138 Pat Parsons

2139 Sarah Swinerton

2140 Jan Charvat

2141 Edith Chase

2143 Fred E. Werner

2144 Donald S. and Mary C. Robinson

2145 Jason Flores

2146 Karen J. Miller

2147 Barbara Benson

2148 Caren M. Kanin

2149 Carol Wyocki, President, ECHO

2150 Mary Qincian

2151 Em’rym Artvnian

2152 Robert C. Ashley

2153 Alex Bowers

2154 Jan Waterman

2155 Susan and Robert Wildermuth

2156 Ruth E. Stiver

2157 Robert and Janice Carrico
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xci

2158 Mary Jane and Alan Williams and family

2159 Shirley and Rong-sheng Jin

2161 James M. Parker, Manager, Environmental Engineering, PPL Montana,

LLC Colstrip Steam Electric Station

2162, 2184 Bill E. Ramsey, Executive Director, Association of Independent Power

Producers in the Anthracite and Bituminous Regions of Pennsylvania

(ARIPPA)

2163 Clifton H. Brown, Jr., President, ADA Technologies, Inc.

2164 Anonymous

2165 Anonymous

2166 Erica

2167, 2168 Patrick Sheedy

2169 Robert E. Busch, President and Chief Operating Officer, PSEG Services

Corporation

2170, 2441 Cecil E. Roberts, President, United Mine Workers of America

2171 Anonymous

2172 American Municipal Power-Ohio

2180 Bradley H. Spooner, Environmental Sciences, Municipal Electric

Authority of Georgia (MEGAPOWER)

2181 Neal Pospisil, Director, Safety, Health, and Environment, Calpine

Corporation

2182, 2183 Eric Fingerhut, U.S. Senate

2185 65 mass mailings

2186-2192 Robert Ferguson, Executive Director, Center for Science and Public

Policy

2195 Lee A. Dew, Ph.D.
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xcii

2196 Martha Bergsten

2197 Jan Gares

2198 Ali Mirzakhalili, Administrator, Division of Air and Waste Management,

Delaware

2199 Jim DiPeso, Policy Director, REP America

2200 Ernest Charles Carwey

2201 Brenda Rothstein

2202 Mary Johnston

2203 Alana Aronin

2204 Judge Danny Pat Crooks, Titus County, Texas

2205 Maureen K. Headington, President, Stand Up/Save Lives Campaign

2206 Karen Ritter, Senior Regulatory Analyst, American Petroleum Institute

2207 Diana Kennedy and Pat Carr, Mount Pleasant and Titus County

Chamber of Commerce

2208 C.J. Stood

2209, 2412, 2413 Stan Scott, et al.

2210 John Nils Hanson, Chairman, President, and CEO, Joy Global, Inc.

2211 Claudia A. Clifford, Executive Director, Montana Nurses Association

2212 Roger D. Hailey, Henderson County School Superintendent

2214 Tony Wooster

2215 Joyce Raines

2216 Sandra G. Miller

2217 Rachael Elwes

2218 Sue Henderson, General Manager, Henderson Economic Development

Corporation
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xciii

2219 Laurel O’Sullivan, Lake Michigan Federation and Abigal Corso, Delta

Institute

2221 Mike Fields, Titus County Commissioner

2222 Dawn Falleur, Green Environmental Coalition

2223 Hudson Old

2224 Lynne H. Church, President, Electric Power Supply Association

2224, 2356 Todd Staples, Texas State Senate

2225 Laurie Maher

2226 Anne Sellers

2227 Bonnie New, Health Professionals for Clean Air

2228 Dennis Bonnen, Texas House of Representatives

2229 Dr. Jonathan S. and Elizabeth B. Griffiths

2230 Roy Sanders and Dolores Sanders

2232 Judge Sandra Hodges, Rusk County

2233 Bruce Hoeft

2234 Ben Glacken

2235 Joel P. Palin

2236 Patrick Huber

2237 Illegible

2238 Victor Marrero

2239 Jonathan Todd

2240 Francesca C. Howe

2241 Dan Hall, NH Trout Unlimited Council

2242 Fred Sampson, President, West Virginia Environmental Council
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xciv

2243 James B. Thompson, Senior Vice President, Indeck Energy Services

2244 Michel R. Benoit, Executive Director, Cement Kiln Recycling Coalition

2245 Lanier and Sandra Brumback

2246

1, 3

J.C. Wynn

2247, 43112, 2378 Sheryl Corrigan, Commissioner, Minnesota Pollution Control Agency;

Ann Jackson, Minnesota Pollution Control Agency

2248, 2249, 2250 William L. Kovacs, Vice President, Environment, Technology and

Regulatory Affairs, U.S. Chamber of Commerce

2249, 2268 David Doniger, Policy Director, NRDC Climate Center

2251, 2252, 2253,

2254, 2255,

2256

Stephen L. Miller, President and Chief Executive Officer, Center for

Energy and Economic Development

2257 Anonymous

2258 Anonymous

2259 James Reynolds, President, CR Clean Air Technologies

2260 Mark W. Schwirtz, Apache Station

2261 Joseph Bologna, North Branch Energy, Inc.

2263 Cedric Robinson

2264, 1848, 1855 Peter Keppler, Chairman, Stuart Sanderson, and Dianne Orf, Colorado

Mining Association

2265 Caribou Commons Society et al.

2267 Andrew L. Kolesar, Thompson Hine (for City of Hamilton)

2269, 2270, 2271 John Harja, Executive Director, Utah Resource Development

Coordinating Committee

2272 Anonymous

2273 Robert Dalton
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xcv

2274 Chris Tyler

2275 Judy Archibald

2276 Anonymous

2277 Roy W. Wood, Eastman Kodak Company

2278 Anonymous

2281 The Wiggins family

2282 M.A. Fischette

2283 M.T. Brace

2284 Leah Graygor

2285 Mary L. Kuenn

2286 Scott Wilde

2287 Robert Holbrook

2288 Dorrance and Lydia Halverson

2289 Timothy A. O’Shea

2290 Carol Schulz

2291 Michael Sticht and Donna Wyszomierski

2292 Beverly J. O’Roake

2293 Rebecca Satryan

2294 Genevieve F. Healy

2295 Richard Parker

2296 Mary Ann Baumgart, Minnesota Valley Testing Laboratories

2297 Matthew Tanner

2298 Kay Brenholt

2299 John W. Parsons, Jr.
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xcvi

2300 Basil R. Northam

2301 Laurie B. Egre

2302 Kate Sherwood and Pieter van Niekerk

2303, 2369 150 mass mailings

2304 D.N. Montgomery

2305 Lorna Kircher

2306 Louise L. Gregg

2307 Janet Morton

2308 Ellen Eisele

2309 Keith Williams

2310 Zeke Martinez

2311 Jeff Jones

2312 Robert Adams

2313 Phyllis McCormick and family

2314 Jerry Johnson

2315 James M. Dooley

2316 Peter Shank

2317 Carol White

2318 Crystal Lew

2319 Jessica Osgood

2320 John Barrett

2321 Ann Marie Davis

2322 David Fulton

2323 Donald R. Meyers et al., Eastern Ohio Development Alliance
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xcvii

2324 Andy Patterson, Chairman, Southern Alleghenies Conservancy

2325 Ragnhild Holmquist

2326 Sarah Merrill

2327 Blondell Reynolds Brown, Philadelphia City Council

2328 Robert G. McIntosh

2329 Thomas D. Korns, President, Wells Creek Watershed Association

2330 Nancy C. Wrona, Director, Air Quality Division, Arizona Department of

Environmental Quality

2331, 2091 Don Berry, The Dow Chemical Company

2332 Dennis Norton, Manager, Environmental Services, Portland General

Electric Company

2333 William Rossbach, Chair, Missoula City-County Air Pollution Control

Board

2334, 3345, 3346 Paul N. Cicio, Executive Director, Industrial Energy Consumers of

America

2335 64 Members, Minnesota House of Representatives

2336 Carol Siewert

2337 Anonymous

2338, 2339 Nelson Klein

2340 20/20 Vision et al.

2341 American Lung Association et al.

2343 Marion and Joyce Cavanaugh

2344 Anonymous

2345 Betty Ponder

2346 Janet E. Bailey, Executive Director, Development Authority of Mercer

County
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xcviii

2347 Lee A. Dew

2348 58 mass mailings

2349 Marcus H. Higginbotham

2350 Sid Stroud

2351 Brett Derveloy

2352 Ann Louis Heckert

2353 Brent L. Warner

2354 Thomas M. Menino, Mayor of Boston

2355 John Auerbach, Executive Director, Public Health Commission, Boston,

Massachusetts

2356 Todd Staples, Texas State Senate

2357 Dan Olson, President, Western States Air Resources Council

2358 Tish Mammeli

2360 Alice C. Butler

2361 Dannie Joe Flandry

2362 Michael R. Helfrich, President, Codorus Creek Improvement Partnership

2363 April Ingle, Executive Director, Georgia River Network

2365 Larry LaMaack, Executive Director, Wyoming Municipal Power Agency

2366 Brenda Garmon

2368 Cherly K. Middleton

2370 Sharon G. Mabbott

2371 Michael J. Carlson

2372 Gordon C. Crighton

2373 Outdoor Gardeners
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-xcix

2373 Ruth Almond, et al.

2374 J. Cagozzelli

23755365 Bryant Danner, Executive Vice President, Edison International

23802559 Pearl Capoeman-Baller, Chairperson, National Tribal Environmental

Council

2381 Jason E. Pacifico

2382 Kevin Ronkko

2383 Sue Flynn

2384 Jeanete Liu

2385 Bartholomenv S. Tapoly

2386 Kourtney Salzman

2387 Victor Mercycles

2388 Julian Bauman

2389 Kathryn Denny, Unitarian Society of Northamption and Florence

2389 Kathryn Denny

2390 Jane J. Henzy

2391 BP

2392 Lucy Sullivan

2393 Scott K. Gray

2394 Helen and Thomas Powers

2395 Scott Taylor

2396 Mrs. Norman Baglini

2397 Shabnaum Singh

2398 Ann Jones
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-c

2399 Rod Kinard

2400 Flora Jones

2401 Fred Lennox

2402 Kristal Fredriksen

2403 Tim G. Bywer

2404 Jeanne Taylor

2405 Helena W. Melone

2406 Aspam Pearson

2407 Katelyn Anne Dolan

2408 Mrs. D. Meritt

2409 Ann Antonucci

2410 Kimberly Soaper

2411 Madeline Sone

2412, 2413 845 mass mailings

2414 David L. Gard, Michigan Environmental Council

2415 Jim Bahl, President, Minnesota Conservation Federation

2415 Jim Bahl, President, Minnesota Conservation Federation

2416 Carol Benham

2417 Joe Simecek

2418, 2455 Heather Leslie

2419 Fritz Beckworth

2420, 2543, 2544 Steven Brown, Vice President, Environmental Council of the States

2421 Anonymous
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-ci

2422, 2876, 2434,

2435, 2436,

2874, 2877,

4254, 4255,

4256, 5457,

5459, 5510

Harold P. Quinn, Senior Vice President and General Counsel, and A.

Todd Johnston, Director, National Mining Association

2423 Hunter Ritter

2424 Nora Freeman

2425 Mae R. Petrie

2426 Wayne Stroessner, Wisconsin Interfaith Climate Change Campaign

2427 Betty Hedges, President, Rockland County Conservation Association

2428 Ray Allen, Texas House of Representatives

2429 Mark J. Sedlacek, Director of Environmental Services, Los Angles

Department of Water and Sewer

2430 Chuck Layman, Central States Air Resources Agencies Association

2431 Paul Oakley, Executive Director, Coalition for Affordable and Reliable

Energy

2437 Conclan Kilernman

2438 T. Materazzi

2439

2

42 mass mailings

2440 Kathryn Rolfes

2442 Russell W. Owens

2443 Shelley Eckert

2444 Mary Sheppard

2445 Charlene Hoag

2446 Name illegible
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cii

2447 Maureen Larsen

2449 James French

2450 Joseph Orenstein

2451 Richard Dunn

2452 Bruce D. Alexander, Strategy Manager, Exelon Corporation

2453 Joseph Bello

2456, 2457, 2516,

2517

Sally R. Weiss, M.D.

2458

1

Anonymous

2459 Andrea Pazandak

2460 Walter Whitehead

2461 Kathy S. Brown

2462 Gail McGraw

2463 Margaret Easter

2464 Anonymous

2465 Jim Koop

2466 Joanne M. MCormack

2467 Kathy Morley

2468 Sharon M. Stoltzfus

2469 Robert and Dyan Ellebracht

2470 Christina Hayakawa

2471 Dr. Justin J. Kelly

2472 Maryann Letiecq

2473 June Ford
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-ciii

2474 Tom Todia

2476 Anne C. Fishel

2477 Larry J. Krutho

2478 Marjorie S. Price

2479 Jessica Grant

2480 Karen Green Stone

2481 Kari L. Dudley

2482 Karen Salzman

2483, 4189 William W. Phillips, Aroostook Band of Micmacs

2484 Anonymous

2485, 2486 P.S. Analytical, Inc.

2487 Anonymous

2488 Dana Pye

2489 Amanda Hensley

2490 Susan Marlow

2491 Stephen

2492 Gail

2493 Carolyn Lunsford

2494 Janice Williams

2495 Peggy Loddengaard

2496 Jackie Carlson

2497 Tammy Dohr

2498 Nancy Cochran

2499 Kerchstin Wipperfurth
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-civ

2500 Carol Anne Valdez

2501 Karen R. Mason

2503 Rita Childo

2504 Robert D. Teetz, Director, Environmental Engineering and Compliance,

Keyspan Corporation

2505 Liz Stahl

2506 D. Knott

2507 David Stuggs

2508 Lorraine McKnerney

2509 Effie P. Stewart

2510 Martha Stavish

2511 Sondra Morrison

2512 Kathy MacLean

2513 Neil Uptegrove

2514 Sandra J. M

2515 Andrea Stabler

2516 Heather Leslie

2517 Dr. Sally R. Weiss

2518 Anonymous

2519, 3536, 5494 C.V. Mathai, Manager for Environmental Policy, Arizona Public Service

Company

2520 Margaret Spittler

2522 Ryan Grant

2523 Keith J. Dittrich, President, American Corn Growers Association

2525 T.G. Tyler
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cv

2526 The Marshall household

2527 Hyn Geldes

2528 Joan Shapiro

2529 Brian Pockat

2530

2

850 mass mailings

2531 Mark W. Luberda, Administrator, Town of Caledonia, Wisconsin

2532 Anonymous

2533 Anonymous

2534 Anonymous

2535, 2379 Robert M. Boettcher, Subbituminous Energy Coalition

2536 Monique Allen

2537 Robert E. Rutkowski

2538 Jessica Grabowski

2539 Kent Bailey

2540, 3264 John Derrickson, President, Friends of Upper Mississippi Fisheries

Services

2541, 2542 Craig Scherenem

2546 Chris Conkey

2547, 2952 M. Gary Helm, Conecitv Energy Holding Company

2548 Carol Roca

2549 Mary Brenneman

2550 Joanne Hertz

2551 Jennifer Smith

2552 Lenard Fitzgerald
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cvi

2553 Jeremy Anderson

2554 Karen A. Patten, Vasilios Keramidas, and Anastasia Kermidas

2555 Steven B. Wheeler

2556 Ellen Wilts

2557 Ramesh Bhatt, Sierra Club/Cumberland Chapter

2558 Mackie Wesley

2560 George G. Thullesen, District Electric Company (Empire)

2561 Carol Wilson

2562 James Rapp

2563 Dennis Goldstein

2564 Gordon Wenger

2569 Wade Diel

2570 Anonymous

2571 Anonymous

2575 Waterkeeper Alliance

2576 Anonymous

2577 Alabama Department of Environmental Management

2578, 2279, 2280,

2581, 2582,

2583, 2584,

2585, 2586,

2587, 2588,

2589, 2590,

2591, 2592,

2593, 2594,

2595, 4886,

4887, 4888,

5450-5450

Richard Carlton and Leonard Levin, EPRI
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cvii

2596 Erin Reilly

2597 David Branecky, OGE Energy Group

2598 Hans Streuli

2599 Ralph Jones

2600 Prof. Tabin Sosnick

2601 June C. Porter

2602 Donna Mummery

2603 William and Betty Jane Diedrich

2604 Katherine Smith

2605 Christine Sullivan

2606 David Brower

2607 Lia Marshall

2608 Nicholas Archer

2609 Jacque R. Whitsitt, Director, Colorado Association of Ski Towns

2610 Jill Thompson

2611 Ronald R. Shelton

2612 Elizabeth Robertson

2613 Deborah J. Boyle

2614 Matthew Ardin

2615 Charlene Chong

2616 Amanda Wong

2617 Left Corner Green Team

2618 Glenn S. Shealy

2619 C.D. Piner
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cviii

2620 Michael A. Donlon, MD

2621 John B. Lorning

2622 Lynne and Dave Michaels

2623 Don Cooke

2624 Hank Dickson

2625 Helen J. Binns, MD

2626 William B. Weil, MD

2627 James R. Hughes, MD

2628

1

Janice V. McConnell

2629 Chris Sanders

2630, 2695, 3203,

3566

Angela Benedict-Dunn, Chairwoman, National Tribal Air Association

2631 Josh Nunya

2632 Brian Fitzpatrick

2633 Kevin Paulison

2634, 2839 Cosimo De Masi, Tucson Electric Power Company

2635 Kimberly Klepatz

2636 Michael Collins

2637 John Baird

2638 Carmen A. Klucsor

2639 Rebecca Lexa

2640 Dan Williams

2641 Harry E. Moran II

2642 Elin Defrin
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cix

2643 Russell J. Novkov

2644 Ester Nicoleodeon

2645 Cheryl McClish

2646 Mara Palmer

2647 Diane Hart

2648 E.M. Layman

2649 Lisa Printz

2650 Kimberly Klepatz

2651 Karen Diem

2652 Ivor R. Moskowitz

2653 Lee Patten

2656 Kate Lester

2657 Teresa Sue Bratton, MD

2658 Raymond Syzmiedan

2659 Randall G. German

2661 Associated Electric Cooperative

2662 Valerie Taylor

2663 Mary L. Zaron

2664 Mary Helen Korlich

2665 Jerry Balash

2666 Chris Hubbard

2667 Sharon M. Guy

2668 Noel M. Smith

2669 Barbara Stockford
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cx

2670 Susan McMillan

2671 Anne Reilly

2672 Newman

2673 Carrie Weil

2674 Dorothy Gailer

2675 Wendy Miner Ashley

2676 Lola Redmon

2677 Mason McKibben

2678 Michael J. Mayo

2679 Victoria Crompton

2680 Michael D. Nellis

2681 Jamie Frailey

2682 Arthur Bailey

2683 Julie Martha

2684 John Hans Pryor, Mayor, Telluride, Colorado

2685 Ronald Goldberg

2686 Gayle Reynolds

2687 Kurt Metzl, MD

2688 Sue Manly

2689 Donald R. Burgess, American Academy of Pediatrics

2690 Lee McCollum

2691 Matthew Bromberg

2692, 3315 Donald L. Blankenship, Massey Energy Company

2693 E. Savatgy
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxi

2694 Ben Johnson, Makah Tribal Council Chairman

2696 Scott Traficante

2697 Mary Beth

2698 Angelo Zinna

2699 Cheryl Jansen

2700 Deborah Leiner (Fields), MD

2701 Eric Gilbertson

2702 Matthew Jones

2703 Michael Fagan, DVM

2704 Michael Robertson

2705 Nomee Davies

2706 Beth Mowry

2707 Larz Raymond

2708 Lisa Schaffer

2709 Lara Clayton

2710 Sudha Bonne

2711 Colleen F. Moore

2712 Anonymous

2713 Christopher Gavigan

2714 Anonymous

2715 Anonymous

2716 Meem Lewandoski

2717 Kathy G. Lesiuk

2718, 5404 Cinergy Corporation
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxii

2719 Jerri Higgins

2720 EPA Region 6

2721, 3542 Ronald R. Harper, Basin Electric Power Cooperative

2722 Anonymous

2723 Anonymous

2724 Anonymous

2725 Jim Sims, Western Business Roundtable

2726 Anonymous

2727 Anonymous

2728 Ruth and Tom Heino

2729 Anonymous

2730 Anne C. Askren

2731 Anonymous

2732 Deborah Swarts

2733 Anonymous

2734 Anonymous

2735 Anonymous

2736 Steve

2737 Carlos Vazquez

2738 Rosemary Volpe

2739 Harry Miller, MD

2740 Corrine Cody

2741 Frances M. Szymanek

2742 Ruth Schemum
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxiii

2743 Patron

2744 Donna Arnold

2745 Richard and Joyce Hybil

2746 Carolyn Corn

2747 Magnus Borgehammar

2748 Kathleen Freud

2749 Connie

2750 Connie Conklin

2751 Marvin Wagan

2752 Chief Charles Enyart, Eastern Shawnee Tribe of Oklahoma

2753 Lindsay Lafford, MD

2754 Sheila Kryston

2755

2

Michael J. Myers, Assistant Attorney General, New York Environmental

Protection Bureau

2756 Laura Kay Collins

2757 Elinor Brady

2758 Max and Mary Herink

2759 Teresa G. Lyons

2760 Dr. Ouida W. Meier

2761 Barbara Sachau

2762 Stephen and Ann Devitt

2763 Tom Collina

2766

1

Rebecca Zimmerman

2767 Phillip Clapp, President, National Environmental Trust Joint Comments
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxiv

2772 Richard D. Chorro

2773 Anne Theresa Ageson

2774 George T. Benjamin

2775 Connor McMillan

2776 Lucy Fortson

2777 Margaret E. Emerson

2778 Janet A. Holden

2779 Leslie Hodes

2780 Mary J. Grimes

2781 Margaret Budz

2782 Barry and Janis Sandt

2783 Dolores Jordan

2784 Geralyn Leannah

2785 Richard Wells

2786

1

Harold Slosson

2787 James Burgen

2788 Lorne K. Garrettson, MD

2789 Gordon B. Glade, MD

2790 Mary L. Brenneman

2791 Mary L. Wright

2792

2

Mary McQueen

2793 Gunnel Fernikoff

2794 R. Siekkinen

2795 Edward M. Brown, MD
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxv

2796 Michael Germain, MD

2797 Jeanne

2798 Joanna Brook

2799 Kate Adams

2800 Leslie Dwight

2801 Anonymous

2802 Tom Luther

2803 Martha Johnson Gilburg

2804 Mary Low

2805 Sylvia Dawkins

2806 Tina

2807 Vicki Neal

2808 Winchester Dermody and Chrisoula Kiriazis, MD

2809 Caroline Ailanthus

2810 David Addison

2811 Deborah Leiner, MD

2812 Laura M. Holbrook

2813 Michael Lippa

2814, 4137 Chiefs James W. Ransom, Barbara A. Lazore, and Margaret Terrance,

St. Regis Mohawk Tribe

2815 Christina Studt

2816 Gary L. Hickey, Dynegy Inc.

2817 M. Jane Brady, Attorney General, State of Delaware

2818 George Ellis, Pennsylvania Coal Association
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxvi

2819, 2820, 2961,

3012, 3038,

3168, 3169,

3170, 3171,

3172, 3173,

3174, 3175,

3176, 3177,

3178, 3179,

3180, 3181,

3182, 3183,

3184, 3185,

3186, 3187

Jeffrey T. Underhill, New Hampshire Department of Environmental

Services

2821 Candace Pratt

2822 M. Brant

2823, 3430, 3490,

3491

Peter C. Harvey, Attorney General, State of New Jersey et al., MultiState Comments

2824 Mark Venable

2825 Anonymous

2826 Association of Illinois Electric Cooperatives

2827, 2828 Robert J. Barkanic, PPL Services

2829 Anonymous

2830, 5482 N.D. Lignite Energy Council

2831 Anonymous

2832 Joseph D. Leary

2833 Jeffrey Marks, National Association of Manufacturers

2834 John T. Graves, Environmental Manager, Minnkota Power

2835 William Neal, Large Public Power Council

2836, 2840 James Jeffords et al., U.S. Senate
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxvii

2837 Anonymous

2838, 4222 Southern Environmental Law Conference

2841 Cathy S. Woolums and Steven C. Guyer, MidAmerican Energy

2842, 3341 Gerard B. Mack, Project Manager, Estill County Energy Partners, LLC)

2843 Sand Sage Power

2844, 3541 Richard T. Bye, Texas Genco LP

2845 Unions for Jobs and the Environment

2846 Robert J. Vann II

2847 W. Earl Watkins, Jr. Sunflower Electric Power Company

2848, 5491, 5623,

5628, 5629

Sid Nelson, Jr., Sorbent Technologies

2849 John Pelerine and Steve Smokey, Stanton Generating Station; Mark

Strohfus, Great River Energy; ramsay Chang, EPRI, and Sharon

Sjostrom, Tim Ebner and Rick Slye, Apogee Scientific, Inc.

2850 Michael G. Cashin, Minnesota Power (Allete)

2851 Melissa Davis

2852 Jed 

2853 Douglas Henderson

2859 Anonymous

2860 John Benedict, Director, Division of Air Quality, West Virginia

Department of Environmental Protection

2861 Michael W. Stroben, Duke Energy

2862 Kristine M. Krause, We Energies (no name in index)

2863 Robert E. Jordan

2864, 4138 Charles C. Bering, Watertown Citizens for Environmental Safety
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxviii

2865 Anonymous

2866 Jane L. Harman, DVM

2867, 3557, 3558 John M. MacManus, American Electric Power Service Corp

2868 Diana Steel

2869 Julie Metty and Jo Ann Beckwith

2870 David Thomas, Alliance Coal, LLC

2872 Anonymous

2873, 2944, 2951 Sid Nelson Jr., Sorbent Technologies Corporation

2875 Michael T.W. Carey, Ohio Coal Association

2878, 4686, 4688-

4696

Environmental Defense (National)

2879, 3476, 3451,

5478, 5547-

5548, 5562,

5630, 5631

Neal J. Cabral, McGuireWoods LLP, on behalf of American Coal For

Balanced Mercury Regulations (The Bituminous Coal Coalition) 

2880, 2881, 3532,

1767

Thomas C. Synder, Director, Air and Radiation Management

Administration, Maryland Department of the Environment; George S.

Aburn, Maryland Department of the Environment

2882, 2885 American Public Power Association

2883 Peter Steitz, Wisconsin Public Power Inc

2884 Anonymous

2891, 4912, 4913,

4914, 4915,

5473

Rae E. Cronmiller and Bill Wernhoff, National Rural Electric

Cooperative Association 

2891 Rae E. Cronmiller and Bill Wemhoff, The National Rural Electric

Cooperative Association

2895 Public Service Company of New Mexico
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxix

2897, 5466 Kennecott Energy

2898, 3450 J.M. Shafer, Vice President, Tri-State Generation and Transmission

Association, Inc.

2899 Kenneth J. Anderson, Ameren Corporation

2900 Class of 85 Regulatory Response Group

2901, 2902, 2927 Clean Energy Group

2903 Bryant C. Danner, EIX

2904, 3568 John S. Lyons, Director, Environmental and Public Protection, Kentucky

Department for Environmental Protection

2906, 3544 T. Ted Cromwell, Managing Director, Environment, American

Chemistry Council 

2907 Olon Plunk, Xcel Energy

2908 Melanie Homan

2910, 3404 Sheri-Ann Loo, Hawaiian Electric

2911 Louis P. Pocalujka, Consumers Energy

2912, 5471 Class of 85

2913 Manitowoc Public Utilities

2914 Sean Smith, Bluewater Network

2915 John Fainter, Association of Electric Companies of Texas

2916, 3515 Coal Utilization Research Council and Shannon M. Angielski, Coal

Utilization Research Council

2917 Joel Schwartz, American Enterprise Institute

2918, 1434 David Steele, West Associates

2920 Sierra Club (National)

2921 Anonymous
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxx

2922, 2923, 2933,

2926, 2928,

2942, 2932,

2934, 2935,

2936, 2938,

2939, 2941

UARG

2930, 5456 Nebraska Public Power District

2931 Stephanie Strother

2937 Charles Ungurean, Oxford Mining Company

2943 Anonymous

2946 Greenpeace

2947, 2948, 2949,

2950

Southern Company

2953 Mary Joan Shea

2954 Anonymous

2955 Anonymous

2956 Anonymous

2957 Anonymous

2962 Melissa Grabner-Hagen

2963 Anonymous

2964 Canary Burton

2965 Christopher Rich

2966 Cynthia McWilliams

2967 Gabriella Taylor

2968 Helen J. Klophenstein

2969 Jean C. Pelletiere
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxxi

2970 B. Sachau

2971 K. Bidwell

2972 Linda Weltner

2973 Lucia Dolan

2974 Michael Bourbina, Jr.

2975 Mike Mezrah

2976 Randy Sailer

2977 Sean Oleary

2978 Sean Speers

2979 Robyn Bagley

2980 Sondra J. Kahler

2981 William Scott Anderson

2982 Bill McLaughry

2983 Anonymous

2984 Tom

2985 Aimar Damon

2986 Aimar Geisdorf

2987 Allen Martin

2988 Amelia Minton

2989 Amy Martyn

2990 Andrea Friedmann

2991 Aneda Sanders

2992 Angela Pruitt

2993 Angela Ramey
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxxii

2994 Ann Diamond

2995 Anna Gray

2996 Anne Dooling

2997 Ann Privateer

2999 Anonymous

3000 Ardel A. Nelson

3001 Carol Krakowsky

3002 Art Krakowsky

3003 Oleh Sydor

3004 Art Firth

3005 Marilee B. Snyder

3006 Autumn Yatable

3007 Michael

3008 Alex Ruprecht

3009 A.R. Martin, PhD

3010 Barbara Scott-Rarick

3011 Barb Juras

3013 Anonymous

3014 Barbara Drumeller

3015 Barbara Marzette

3016 Barbara E. Masters

3017 Rudolph and Barbara Klare

3018 Sue Prater Battett

3019 Barrett Lombardo
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxxiii

3020 Anonymous

3021 Barbara Dana

3022 Anonymous

3023 Betty and Jack Dean

3024 Mike Jones

3025 Betty Handel

3026 Betty Vig

3027 Beverly Fuller

3028 Beverly Veltman

3029 Bill Bonte

3030 Bill Marsh

3031 Bill Martin

3032 Barbara Swenson

3033 Robert Udjemian

3034 Bob Case

3035 Phyllis Doyle

3036 Bob Francey

3037 Bob Moser

3039 Gina Pisello

3040 Brian Gabelman

3041 Janice Chapman and Bruce Moore

3042 Bruce Patrick

3043 Richard Butler

3044 Bud Goodrich
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxxiv

3045 Phyllis Rose

3046 Bartley A. Lagomarsino

3047 Harry C. Cox

3048 Edward Vincent

3049 Cappy Walls

3050 Melissa M.

3051 Carey Fitzmaurice

3052 Carla Byrnes

3053 Doris Carlino

3054 Carlos Victoria

3055 Carol Nelson

3056 Carol Silber

3057 Carol Stewart

3058 Caroline Becker

3059 Carolyn Fisher

3060 Carolyn Maki

3061 Cassie Schnaterly

3062 Catherine Wells

3063 Robert W. Buselmeier

3064 Charles Gallagher

3065 Charlene M. Key

3066, 3067 Susan E. Dudley and Daniel R. Simmons, George Mason University

Mercatus Center

3068 Charles D. Johnson
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxxv

3069 Charles Hopkins

3070 E. Charles Uphoff

3071 Charlie and Cathyann Jones

3072 Chris and Tanya Rocholl

3073 Chris Erickson

3074 Miles C. Kara

3075 Chuck Sherman

3076 Colin Klimek

3077 Craig Knox

3078 Jennifer Crain

3079 Anonymous

3080 Charles and Tandy Hersh

3081 Cynthia Nichols

3082 C. Beau Daane

3083 Dave Brancaccio

3084 William C. and Daily M. Stedman

3085 Dale Bulla

3086 Dale Johnson

3087 J. Dan Pittillo

3088 Dan Schotter

3089 Dana Turman

3090 Elizabeth N. Myers

3091 Daniel Lee Richards

3092 Dan O’Brien
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxxvi

3093 David Ashland

3094 David Gordon

3095 Dave LeVech

3096 Dr. Dave Sidney

3097 David Bennett

3098 David Hyland

3099 Dave Plazak

3100 David Krauser

3101 David L. Pedersen

3102 Dave Favreau

3103 David Peters

3104 David B. Pittard

3105 Nisha Dawson

3106 Gregory A. Brentano Salem

3107 Debra Gehl

3108 Debra Rodman

3109 Wesolowki Family

3110 Derek Supple

3111 Diana Henderson

3112 Diane Vlazny

3113 Dina Garrett

3114 Donald Bensinger

3115 Donald Spenser

3116 Donna L. Moran
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxxvii

3117 Donna Willingham

3118 Dorothy Coe de Hernandez

3119 Dorothy Pruess

3120 Douglas P. Sibley

3121 Charles Rives

3122 Harrison Hoyt

3123 Elaine Arnold

3124 Elizabeth Marino

3125 Elizabeth Reuthe

3126 Elois Duncan

3127 Sheryl Morris

3128 Eva P. Ingle

3129 Gene Featherstone

3130 Anonymous

3131 Fred Polvere

3132 Paul Funston

3133 Gary L. York

3134 Anonymous

3135 Anonymous

3136 Gerri Plansker

3137 Virginia Jensen

3138 Anonymous

3139 Geraldine Bannister

3140 Eileen M. Wallace
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxxviii

3141 G. Raynolds

3142 Greg Bryant

3143 Anonymous

3144 Grey Parry

3145 Gregory and Amy Maonhan

3146 Gwen Lingren

3147 George Yates

3148 Anne Foster

3149 Heidi Machen

3150 Helen Barolini

3151 Helen Mullally

3152 Helen N. Hanna

3153 Herbert Parker

3154 Henry Rewun

3155 Howard Goldin, MD

3156 Howard Stahl

3157 Ian Duncan

3158 Ira Leidel

3159 Jacquelyn Griffith

3160 Anonymous

3161 James J. Sardino

3162 J.E. O’Halloran

3163 James O’Shea
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxxix

3164 Jim Thompson, P.E., James E. Thompson and Associates, Consulting

Engineers

3165 Jim Wilson

3166 Jamieson Scott

3167 Jane Hertel

3188 Susan Cole

3189 Laura Linn

3190 Lois E. Thompson

3191 Daniel Johnson

3192 Avil Ogilvy

3193 Helen M. Polzer

3194 Mari Messer

3195 Peter Langr

3196 David Keethler

3197 Mario Craig

3198, 3342 Marion Loonis, Executive Director, Wyoming Mining Association 

3199 Christopher Jones, Director, Ohio EPA

3200 Paul E. Reynolds, Hoosier Energy Rural Electric Cooperative

3201, 3417, 4129 Gary L. Anderson, Plant Manager, Ebensburg Power Company

3202 Arthur J. Rocque, Jr., Connecticut Department of Environmental

Protection

3204 Todd H. Haanes

3205 Montana Environmental Information Center/Rocky Mountain Office of

Environmental Defense/Our Children’s Earth Foundation

3208 Robert Norrgard, Western Fuels Association
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxxx

3208 Robert P. Norrgard

3209 Patrick Gregory, Ph.D., President, American Society of Ichthyologists

and Herpetologists

3210, 3405 Erin M. Crotty, Commissioner, New York Department of Environmental

Conservation

3211, 3507 Pete Homer, National Indian Business Association

3212 E. Clay Shaw, U.S. House of Representatives

3213 Joseph M. Garfunkel

3214 Dr. Keith M. Perrin, President, American Academy of Pediatrics

3214 Keith M. Perrin, MD

3215 Sandra C. Adams, Executive Director, MCH Coalition

3216 Marie and Ron Forman

3217 Carolyn F. Wilkerson

3218 Craig K. Breton, Santa Clara Valley Audubon Society

3219 Elina

3220 Rebecca A. Lexa

3221 Gary Young, Air Quality Division, Polk County, Iowa

3222 Ed Geiger, Frontier GeoSciences

3223 Debbie Netardus

3224 Mark Dayton, U.S. Senate

3225 Sherwood L. Boehlert, U.S. House of Representatives

3226 Patricia Garvey

3227 John J. McEneny, New York State Assembly

3228 Renee M. Espinosa

3229 Mike Kadas, Mayor, Missoula, Montana
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxxxi

3230 Vicki Bielanski

32312

, 3291 Jason K. Babble, New York Public Interest Research Group

3231 Jill Young

3232 Craig Sharpe, Executive Director, Montana Wildlife Federation

3233 Dale Martinez, Governor, Pueblo of San Ildenfonso

3234 Deena L. Sprague

3235 Lloyd Doggett, U.S. House of Representatives

3236 W. Gary Bowman

3237 John Carter

3238 Barbara Kler

3239 Virginia Quinonez

3240

2

Jesse L. Jackson, Jr., U.S. House of Representatives

3241 Mary Celeste

3242

2

James R. Langevin, U.S. House of Representatives

3243 Robert Anderson, MD

3244 Luke Metzger, TexPIRG

3245 Mike Turner

3246 Harry A. Olsen

3247

2

Norm Coleman, U.S. Senate

3248

2

Martin Frost, U.S. House of Representative

3249

2

Jeff Bingaman, U.S. Senate

3250

2

Jim Ranstad, U.S. House of Representatives

3251 Sister Kay Ryan

3252

2

Jeb Bradley and Charles F. Bass, U.S. House of Representatives
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxxxii

3253

2

Betty McCollum, U.S. House of Representatives

3254 Ben Eubanks

3255 Anna Harlowe, Ecology Center of Southern California

3256 Lisa A. Cooney

3257, 3397, 3477 J. Brett Harvey, President and CEO, CONSOL Energy

3258 Taylor Clemants

3259 Mary Frantz, PhD

3260 Daniel Schramm

3261 Andrea F. Nuciforo, Jr., Massachusetts State Senate

3263 Claudia A. Clifford, Montana Nurse’s Association

3265

2

Bill Nelson and Bob Graham, U.S. Senate

3266

2

John H. McHugh and John E. Sweeney, U.S. House of Representatives

3267

2

Collin C. Peterson, U.S. House of Representatives

3268

2

Tom Allen and Michael Michaud, U.S. House of Representatives

3269

2

Jan Schakowsky, U.S. House of Representatives

3270

2

Hillary Rodham Clinton and Charles E. Schumer, U.S. Senate

3271

1

M. Jane Cooper

3272

2

Robert Brady, U.S. House of Representatives

3273 Donald R. Garlilt

3274 Martin Buck

3275 Marion Olson, President, Tinkers Creek Land Conservancy

3276

2

Joseph Hoeffel, U.S. House of Representatives

3277

1

Sandra Say

3278 Agnes L. West 
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxxxiii

3279

2

Bill Nelson, U.S. Senate

3280 Blanche Murtagh

32812, 3357 John D. Dingell, U.S. House of Representatives

3282

2

Tammy Baldwin, U.S. House of Representatives

3283

2

John Lesch, Minnesota House of Representatives

3284 Elise Miller, Institute for Children’s Environmental Health, Joint

Comments of 8 Groups

3285 Michael Gochfeld, MD, Robert Wood Johnson Medical School,

Environmental and Occupational Health Sciences Institute/NJ Task

Force

3286 Hillary Rodham Clinton, U.S. Senate

3287 Barbara Boxer, James M. Jeffords, and Patrick J. Leahy, U.S. Senate

3288 Dave Freudenthal, Governor, Wyoming

3289

2

Stephanie Gross, TexPIRG

3290 Patrick J. Leahy et al., U.S. Senate

3292

2

Edward J. Markey, et al., U.S. House of Representatives

3293 Mark Kirk et al., U.S. House of Representatives

3294

2

Matthew Dean, Physicians for Social Responsibility/ NYC

3295

2

Raul M. Grijalva, U.S. House of Representatives

3296

2

Northeast Partners for Mercury Reduction

3297

1

Lelani Landis

3298

2

Dakota Resource Council

3299

2

David Wu et al., U.S. House of Representatives

3300 Amy Hohnowski, National Environmental Trust

3301

2

Joseph Otis Minott, Clean Air Council, et al.
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxxxiv

3303

2

Stephen Smith, Southern Alliance for Clean Energy, et al.

3304 Eliot L. Engel, U.S. House of Representatives

3305 Millard Meyers, Executive Director, 1854 Authority

3306 John K. Alderman

3307 Keri Messina, Executive Director, New Hampshire Wildlife Federation

3308 William P. Krebs, Krebs and Sisler, LP

3309 W. Gladstone, MD, et al.

3310 Jenny Pike

3311 William E. Emery, President, Keweenaw Bay Indian Community

3312 Natalie Dube

3313 Richard M. Dailey, Mayor, City of Chicago

3314 Thomas P. DiNapoli, New York State Assembly

3316 Louise Bensen, Chairwomen, Hualapai Nation of the Grand Canyon

3317 Todd Halenbeck

3318 Sister Margaret Turk

3319 Liz Brater, Michigan State Senate

3321 Mary L Jenks, Chair of Air Pollution, Manasota

3322, 3349, 3354 Dr. Melanie A. Marty, Chair, Children’s Health Protection Advisory

Committee

3322, 3349, 3354 Dr. Melanie A. Marty, Chair, Children’s Health Protection Advisory

Committee

3323 Jim Gerlach, U.S. House of Representatives

3324 Rich Boucher et al., U.S. Congress

3325 Norman W. Deschampe, President, Minnesota Chippewa Tribe
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxxxv

3326 Jan K. Platt, Environmental Protection Commission, Hillsborough

County, Florida 

3327 Michael L. Williams, Commissioner, Railroad Commission of Texas

3329 Charles B. Anderson, MD

3330 Beth M. Mancuso

3331 Lisa M. Nnene

3334 Wendy Smith

3335 Norman Deschampe, Tribal Chairman, Grand Portage Reservation Tribal

Council

3336 Paul O’Bryne, President, Florida Environmental Health Association

3337 James H. Douglas, Governor, State of Vermont

3338 Michael Noble, Executive Director, Minnesotans for an Energy Efficient

Economy

3339 Donna Shanake

3340 Gifford Miller, New York City Council

3343, 3344 Bob Perciasepe

3347 Jim Cooper et al., U.S. House of Representatives

3348 Elizabeth Sword, Executive Director, Children’s Health Environmental

Coalition

3350 Greg Lake

3351

2

Louise M. Slaughter, U.S. House of Representatives

3353 John M. Heuss, Air Improvement Resource, Inc.

3356 Patrick J. Leahy et al., U.S. Senate

3358 Henry A. Waxman and Tom Allen, U.S. House of Representatives

3359 Janna Raber
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxxxvi

3360 Elizabeth F. Nygaard

3361 Grace and Joe Ford

3362 M.G. Vancane

3363 Sherry and Brian Buisker

3364 Jeremy Phelps

3365 Gayle McCaleb

3366 J. Nathan Noland, President, Indiana Coal Council Inc.

3367

1

Virginia B. Haddens

3368 Judith Koral

3369 Linda Engard

3370 Paul Scott

3371 L. J. Gray

3372 Brij Naubria

3373 M. Brent Dolezalek

3374 D. Kenney

3375 Randy Keck

3376 Eric D. Peterson

3377 Michael Schrader

3378 Louie Campos

3379 Martin and Gail Votaw

3380 Helen Kalin, Klanderud, Mayor, City of Aspen

3381 Paul Kruppa

3382

1

Daniel F. Carvey

3383 Jeffrey Soleno
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxxxvii

3384 Eric Tully and Elizabeth Pachuilo

3385 James Burde

3386 Tom Byrns

3387 Abdul Rahman Shareef

3388 Jean McNamrwon

3389 Douglas D. Lewis

3390 Cheryl Molleur

3392 Richard Spotts

3393 Mike Hatch, Attorney General, State of Minnesota

3394 Lisa Madigan, Attorney General, State of Illinois

3395 Henry St. Germaine, Chairman, Lac du Flambeau Tribe

3396 John L. Carr et al., Catholic Coalition for Children and a Safe

Environment

3398 Terry L. O’Clair, Director, Air Quality Division, North Dakota

Department of Health

3399 Joan Brian

3400 Willie Braun, AES Warrior Run

3401 Anonymous

3402, 3406 Ronald Drewnowski, PSEG

3403 David N. Smith, Old Dominion

3412, 3413 John A. Mirabal, Governor, Pueblos of Taos

3418 Ronald Broadwater

3419 Steven Heim

3421 5,000 mass mailings from Physicians for Social Responsibility

3422 Janet W. Loeb
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxxxviii

3425 Michael Coill

3426, 3427 Robert K. Musil, Director and CEO, Physicians for Social Responsibility

3428 387 mass mailings

3431, 2940, 3545 AES Corporation

3432 Harold M. Frank, Dairyland Power Cooperative

3433, 3434, 3435 J.P. Crametz, Oncept

3435, 3438, 3439,

4243-42521

Carol A. Couch, Director, Environmental Protection Division, Georgia

Department of Natural Resources

3436, 3437 Lori F. Kaplan, Indiana Department of Environmental Management

3440 Mary S. Miksa, Texas Association of Business 

3443, 3407, 3408,

3409

John W. Shipp, Tennessee Valley Authority

3444 Randall R. LaBauve, FPL

3445 Charles R. Waklid, Progress Energy

3446 Stacey Davis, Center for Clean Air Policy

3452 Doug Bogen, New Hampshire Program Director, Clean Water Action

3457, 3527 James H. Schlender, Executive Administrator, Great Lakes Indian Fish

and Wildlife Commission

3459, 4910 Clean Air Task Force et al Comprehensive Comments

3463, 3464 Jospeh G. Eutizi, San Miguel Electronic Cooperative

3465 Thomas B. Carter, Portland Cement Association

3467, 3468, 3469 Todd M. Myers, President, Westmoreland Coal Sales Company

3471 2 mass mailings

3472 88 mass mailings

3473 1,475 mass mailings
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxxxix

3474 10,187 mass mailings

3475 187 mass mailings

3478-3487, 3494,

5490

Mike McCall, TXU Power

3505 Dale Drogseth

3506 Curtis Schacher

3508 Henrietta L. Wiley

3509 Matthew W. Ward, Spiegeland McDiarmid, Michigan Municipal Electric

Association

3510 Victor G. Carrillo, Texas Railroad Commissioner

3511 Gordon Robertson and Tom Bedell, FishNet

3512 Appalachian Center for the Economy and the Environment

3513 Curtis Q. Warner, Arkansas Electric Cooperative Corp

3514 Jay Skabo, Montana-Dakota Utilities

3517 Greg Schaefer, Arch Coal Inc

3519 P.G. Para, JEA

3520 John L. Carr, U.S. Conference of Bishops Joint Comments

3522 Earnest E. Wessman, Pacificorp

3523 Laura Barker

3524 James L. Martin, President, 60 Plus Association

3525 Dee Martin, Council of Industrial Boiler Owners

3525 Robert Bessette, CIBO

3526 Bruce Niles, Sierra Club, Midwest

3528 Karen Kerrigan, Small Business Survival Committee

3529 Paul Hansen, Executive Director, Izaak Walton League of America
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxl

3531 Michael Born, Ohio electric Utlities Env Committee by Shumaker, Loop

and Kendrick

3533 Bruce L. Rockwood, JD

3534 William B. Raney, West Virginia Coal Association

3535 Mary Beth Murphy, Supervisor, Town of Somers, NY

3537, 5474 Douglas J. Fulle, Ogelthorpe Power

3538 Eric V. Schaeffer, Director, Environmental Integrity Project

3543, 3544 Glenn Shankle, Acting Executive Director, Texas Commission on

Environmental Quality

3546 Comment submitted by Richard M. Hayslip, Salt River Project

3547 Comment submitted by Patricia McCullough,Northeast Utilities Service

Company

3548 J. Derek Furstenwerth

3549 George King, Chairman, Red Lake Band of Chippewa Indians

3550 Mille Lacs Band of Ohjibwe Indians

3551 Brandy Toft, Leech Lake Band of Ojibwe

3552 Stephen Mahfood, Director, Missouri Department of Natural Resources

3555, 3556 Louis P. Pocalujka, Consumers Energy

3559, 3560 Sheldon A. Zabel, Schiff Hardin, Southern Illinois Power Company

Cooperative

3561 Tom Allen, U.S. House of Representatives

3564, 3565 Dale A. Kanary, FirstEnergy Corp

3569 Adele Hilsen

3570 Aileen Ryan

3571 Akhil Kumar
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxli

3572 Alana Kaplan

3573 Alfie Shird

3574 Drs. Allana and John Elovson

3575 Alma Burnett

3576 Amy Goode

3577 Ana Salinas

3578 Andrea Smith

3579 Andrew Heilveil

3580 Andy Boatwright

3581 Andy Edgar

3582 Ann Bass

3583 Annabel Weidinger

3584 Anne Furse

3585 Annette and Dan Armstrong

3586 Anton Grambihler

3587 Arline Granberg

3588 Art Yeske

3589 Allen Spens

3590 A. David Katz

3591 Ellen Dunscomb

3592 Dr. Barbara Edgar

3593 Craig Duncan

3594 Barbara Hann

3595 Barbara Jarvis
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxlii

3596 Barbara Holzman

3597 William Walker

3598 Bonnie Weikle

3599 Bob Reid

3600 Ron Bracken

3601 Braden Josephson

3602 James Brian Gilmore

3603 Caroyln Frame

3604 Carolyn Shaffer

3605 Carrie Porter

3606 Cary Birdsall

3607 Catherine Dadey

3608 Charles Hunt

3609 Charles T. Rawls

3610 Robert and Cheryl Verner

3611 Christopher Highley

3612 Christopher Spanos

3613 Cindy Solvang

3614 Cindy Vallo

3615 Clarence and Eileen Carlson

3616 Conrad Banner

3617 Corinne Kawecki

3618 Craig DeLancey

3619 Mike Cotter and Cynthia Roche-Cotter
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxliii

3620 Prof. David Voltmer

3621 David and Carol Butler

3622 Dawn Tigas

3623 Debroah B. Evans

3624 Dee Feickert

3625 Douglas La Tourette

3626 Nancy Stevens

3627 Dorcas Pohl

3628 Douglas Anderson

3629 Anonymous

3630 D.W. Day

3631 Eli Ganias

3632 Eric Norman

3633 Erik Roberts

3634 Ester Erickson

3635 Deborah Shore

3636 Florence Levitt

3637 Gail Jonas

3638 Gail Kniffel

3639 Gail Micca

3640 Nilda Gaqrcia

3641 Gary Baker

3642 Gary Christensen

3643 Julia and Brian Gaynor
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxliv

3644 Gerry Benedetti

3645 Jonathan Good

3646 G. Porter

3647 Gretta Zorn

3648 Anonymous

3649 Lyman W. Griswold

3650 Kathleen Reilly

3651 Louise Matney

3652 Adam Prato

3653 David Digatono

3654 Harold A. Mackey

3655 H. Bower

3656 Harvey Kravetz

3657 Joe Parry-Hill

3658 Anonymous

3659 Ida Talalla

3660 Paula Oeler

3661 Ira Shakman

3662 Ira Lichtenstein

3663 Isabelle M. Healy

3664 Joanne Friday

3665 Jackie K.

3666 Jen St. Clair

3667 Anonymous
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxlv

3668 Janet Williams

3669 Jeanette A. Barnett

3670 Jeni and Bill Foster

3671 Jim Presswood

3672 Jim and Joyce Spain

3673 John Misaros

3674 John Quayle

3675 Kay Gates, Sierra Club, Loxahatchee Group

3676 John Stages

3677 Jeff Osborn

3678 Joseph Lebovich

3679 Joshua Mead

3680 Juan Orona

3681 Julie Miller

3682 Julie Pearson

3683 Julien Girard

3684 Virginia Martelli

3685 K. Tulli

3686 Karen Elly-Trapani

3687 Karen Irvin

3688 Katherine Bongfeldt

3689 Kathleen Irons

3690 Kathy D’Antonia

3691 Kathy Schuler
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxlvi

3692 Caroline Parsons-Korn

3693 Ken and Ann Sinarski

3694 Cinergy Corporation

3695 Ken Strong

3696 Kerry Ness

3697 Kerry Dreamboat

3698

1

William E. Muckleroy

3699 Elaine Kumin

3700 Lauren Start

3701 Lauren Miller

3702 Lee Imbof

3703 Leif J. Jensen

3704 Linda Whitworth-Reed

3705 Lee Hitt

3706 Patricia Lloyd

3707 Linda E. Sindelar

3708 Lynn Steeves

3709 Erin Weik

3710 Maria Bohnert

3711 John Anderson

3712 Marilyn F. Propp

3713 Mark Rosenkranz

3714 Mark Winberry

3715 Mark Zajackowski
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxlvii

3716 Maureen Dompe

3717 Susan Binzer

3718 Mohammed Ali

3719 Michael L. Burke

3720 Michael Gatt

3721 Michael G. Miller

3722 Michael Ferro

3723 Mike Santa Maria, PhD

3724 Mikola

3725 Mirzda Erika Berzins

3726 Miriam Almeleh

3727 Mitzi

3728 Mary S. Huhn and Marilyn K. Cartwright

3729 William Morris

3730 Margaret Linehan

3731 Julian and Muriel Kane

3732 Michael D. Williams, PhD

3733 Dr. Nancy Erber

3734 Nancy Collins-Warner

3735 Nancy Friedemann

3736 Niall Bjornlund

3737 Jane Allen

3738 Nicole Caroret

3740 Rodney K. Gross
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxlviii

3741 Patricia Christensen

3742 Patricia Eisenberg

3743 Patricia Lane

3744 Susan Paternoster

3745 Patty Adams

3746 Paul Alexander

3747 Paul Hanley

3748 Paul Leinenbach

3749 Paul Moulton

3751 Pekari 

3752 Peter Gold

3753 Peter Henderson

3754 Audrey Porreca

3755 Frank Pwowell

3756 Priscilla Maynard

3757 R. Hitt

3758 R. Lyons, MD

3759 Randel Metz

3760 Ingrid Carlson

3761 Rikki Fields

3762 Ruth Morris

3763 Rob Cumberland

3764 Robert Cingolani

3765 Robert Smiles
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxlix

3766 Rory Vose

3767 Richard and Karen Rundell

3768 Russell Bartt, MD

3769 Ryan J. McNeff

3770 Paul Schwab

3771 Bob Knight

3772 Shira Mendes de Leon

3773 Helen Song

3774 Stanford Gobb

3775 Steven and Kathleen Breckhill

3776 Steven Blaisdell

3777 Marilyn Hendlund

3778 James F. Daniels

3779 Susan Covert

3780 Susan Springs Meggs

3781 Suzanne and Tom

3782 Tatiana Martushev

3783 Terence Brown

3784 Debra L. Stevens

3785 Timon Malloy

3786 Timothy Anderson

3787 Timothy Ryan

3788 Thomas Lott

3789 Tom Ballard
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cl

3790 Tom Welander

3791 Christine M. Ardoin

3792 Valerie Kurtz

3793 Steven Vause

3794 Victoria Lois-Dompe

3795 Victor Maureen

3796 Rose Levering

3797 Wayne and Lynne Tiemeier

3798 Bill Welch

3799 Anonymous

3800 Christopher Childs

3801 Steven G. Kozelka

3802 Jeff Kalibjian

3803 Bill Paxton

3804 C. Alexander Cohen

3805 K. Shearer

3806 Dianne Bentley

3807 Laura Weinberg Aronow

3808 Patrick McGlew

3809 Anne Kelty

3810 Hally DeCarion

3811 Jean L. Woodman

3812 Samantha Mulford-Phillips

3813 Shannon Daley-Harris
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cli

3814 Sondra R. Dunne

3815 Steven and Cynthia Clawges

3816 Thomas A. Mosher

3817 Christopher Stahnke

3818 Steven Swarter

3819 M.E. Petrilla

3820 Carol G. Sharp

3821 Jonathan Ingle

3822 Mary Cassell

3823 Adrienne Kandel

3824 Michael and Heidi Obolensky

3825 Dr. Demelza Costa

3826 Diana Cleland-Boyle

3827 Max Edgar

3828 Josh Hertel

3829 Gerri Plansker

3830 Dagny Sanmiguel

3831 Brendan McKiernan

3832 Cheryl Scaccio

3833 Brian Wilga

3834 Carol Korty

3835 Daniel Hooley

3836 Scott Tyrell

3837 Jacob Lorfing and Miriam Klotz
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-clii

3838 David M.F. McNeil

3839 Verona Aeits-Rojas

3840 Anonymous

3841 John and Dorothy Loper

3842 Kathleen Fitzgerald

3843 Katherine Nadeau

3844 Jonathan

3845 Barry Stern, Ph.D

3846 R. Arefe

3847 Dakota Baker

3848 Emily Ingalls

3849 J. Wheat

3850 John R. Buchser

3851 Nelson H. Oliver, Ph.D

3852 Robert Natario

3853 Robert E. Jordan

3854 Helene Stoffey

3855 Dick Ravenscroft

3856 Randy Niere

3857 Jane Schnitzer

3858 Janet and Herb Stoner

3859 Janet Crockett

3860 Janet L. Smith

3861 James A. Scharr
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cliii

3862 Jason Wesco

3863 Jeffrey Cartwright-Smith

3864 J.D. Sitter

3865 Jacquelyn L. Davin

3866 Jean Hennig

3867 Jean McMahon

3868 Jeannie Peterson

3869 Jeff Barrell

3870 Susan Luth

3871 Jeffery Popek

3872 Jon and Janet Morris

3873 Jennie and Phillip Marlow

3874 Jennifer Macon

3875 Jerrold W. Jordan

3876 R. James Wardman

3877 Mary Jo Winston

3878 JoAnne Gostas

3879 Joanne Fisher

3880 Jody Evenson

3881 J.R. Kraus

3882 John Stephany

3883 Virginia King

3884 J.G. Basalt

3885 John B. Hervey
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cliv

3886 Edie Miskewicz

3887 John Haxton

3888 John Roebuck

3889 John Smith

3890 John

3891 John Gladkowski

3892 Jon Anderson

3893 Jon Joiner

3894 Jon Wood

3895 Joseph Navari

3896 Joe Biniek

3897 Josie B.

3898 Michael Brennan

3899 J. Scrosno

3900 Judy Mellow

3901 Don and Julianne King

3902 J.W.

3903 J. Robert Bragonier, MD

3904 Kathleen Hutchins

3905 Kay and Tony

3906 Keith McCaffery

3907 Kenneth Jandes

3908 Kenn Ritza

3909 Kenny Mastro
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-clv

3910 Kent Wilson

3911 Kevin

3912 Kevin McGuckin

3913 Kevin O’Hara

3914 Kim Fridinger

3915 K.M Chen

3916 Kristin Scharr

3917 Emily Lamb

3918 Carol Sui Man Lam

3919 Lance Higdon

3920 Carol Denning

3921 Larry Denning

3922 Laura

3923 Lauren T.

3924 Rachel Leah Borenstien

3925 Lee Dickerson

3926 Leanne Culbreath

3927 Shirley Milbert

3928 Leonardo Pucci

3929 Lillian Fox

3930 Lin Ewing

3931 Linda J. Vogel

3932 Linda Page

3933 Lisa Butterfield
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-clvi

3934 Marc T. Anderson

3935 Rebecca Lish

3936 Liz Martin

3937 Lucy Mallar

3938 Linda G. Miklowitz

3939 Loretta Henrie

3940 Lydia Roane

3941 Anonymous

3942 Lynn McGarvey

3943 Mara Kerkez

3944 Karl Leitzenmayer

3945 Margaret Holcomb 

3946 Margaret Shake

3947 Marguerite Hughes

3948 Marilyn Adams

3949 Marilyn Howe

3950 Marion Glennon

3951 Garey C.Engle

3952 Mark Smith-Poelz

3954 Marlene Hartley

3955 Martha Parrish

3957 Maureen Williams

3958 Anonymous

3959 Marilyn DeMoss
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-clvii

3960 Melba Dagy

3961 Melissa A. Riesland

3962 Neal Hamilton

3963 Michael Brennan

3964 M.ichael and Sheila Chrestensen

3965 Michael Hoban

3966 Michael Milazzo

3967 Michael Scharr

3968 Michael and Nancy Schill

3969 Michele Happe

3970 Michelle H.

3971 Mike Powell

3974 Mike Scoles

3975 Mike H. Wurzburg

3976 M. Padgett

3977 Anonymous

3978 Milton Pelavin

3979 Anonymous

3980 Mohan Sikka

3981 F. William Weaver

3982 Dick

3983 Michael Taylor

3984 Mark Fresolone

3985 Michael Tracy
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-clviii

3986 Nancy

3987 Nancy Burhop

3988 Nancy Parish

3989 Nandy P. Stages

3990 Jerome Durkin

3991 Nina M. Whiteley

3992 Norman and Gayle Ray

3993 Norman Watkins

3994 Owen Marron

3995 Pat Kennedy

3996 Pat Tibbs

3997 Paul Kelly

3998 Paul Sepp Eisi

3999 Margaret Curtin

4000 Homer R. Reese, Jr.

4001 Anonymous

4002 Eleanor Santos

4003 Pat Burton

4004 Peter Willingham

4005 Edward Wall

4006 Anonymous

4007 Wayne and Jennifer Politsch

4008 Rajive Rajan

4009 Rebecca Summer
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-clix

4010 Leora Pendleton

4011 Michael Orlov

4012 R. Fuury

4013 Anonymous

4014 Richard E. Kravath

4015 Richard Osborne

4016 Richard C.Treadway

4017 Richard Turtle

4018 Richard Vanderslice

4019 Rick Lutz

4020 R.J. Klaves

4021 Ronald Kaiserman

4022 Rob Short

4023 Robert Short

4024 Phoebe Mahan Wing

4025 Richard D. Morton

4026 Robert Sadofsky

4027

1

Claude, Ellen, and Robert Griggs

4028 Robert Patterson

4029 Roger Hoehn

4030 Rolando M. Penn

4031 Ron Jacobus

4032 Rosalee Wolfe

4033 Bill Sheets and Rosemary Craig
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-clx

4034 Ross Burnaman

4035 Sam Dewitt

4036 Sandra Lamar

4037 Sanquinetta Higgins

4038 Sara Crisler-Cobb

4039 Sara Loughlin

4040 J. Graham

4041 Tom Scheder

4042 Scott Staats

4043 Richard Schribner, MD

4044 M. Selva

4045 Sergio Mundarain

4047 Shirley Ross

4048 Sigrid

4049 Marcia Kelley

4050 Sonnie

4051 Nancy Weinbrenner

4052 Stacy Bautista

4053 Stan Hall

4054 Stanley Shaw

4055 Stephen Lutze

4056 Straw Willy

4057 Steven Turtil

4058 Sue T. Parker
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-clxi

4059 Susan Sidney

4060 Susan Dietrich

4061 Susan K. Beale

4062 Susan Heaney

4063 Suzanne Wienberg

4064 James Benthall

4065 Theresa White

4066 Therese Carson

4067 Tim Estes

4068 Tom

4069 Tom Ayers

4070 Tom Byrns

4071 Tom Sherlock

4072 Thomas and Joan McCullough

4073 Dr. Thomas Poulson

4074 Tracie

4075 Tracy K. Stillwell

4076 Anonymous

4077 John Turney

4078 Diane Valetta

4079 William Revet

4080 Marsha Andrews

4081 Warren Nelms

4082 William Sternman
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-clxii

4083 Bill Smalley

4084 Wayne Mackeil

4085 Frank L. Mulhelm

4086 Anton J. Mraz

4087 S. Galen Smith, PhD

4088 Loraine W. Andrews

4089 Robert Zucchi

4090 Paul Jacobson

4091 David Addison

4092 45 mass mailings from Harvest Co-Op Markets

4093 103,274 mass mailings from MoveOn Org

4094 2 mass mailings from Left Corner Green Team

4095 6 mass mailings

4096 20 mass mailings

4097 Mr. and Mrs. Adams

4098 3 mass mailings

4099 99 mass mailings

4100 144 mass mailings

4101 316 mass mailings from Earth Tones, Green Alerts

4102 136 mass mailings from unknown, lignite

4103 49 mass mailings from Americans for Balanced Energy Choices

4104 2 mass mailings

4105 12,320 mass mailings

4106 2,610 mass mailings
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-clxiii

4107 1,057 mass mailings from Clean Wisconsin

4108 Helen K. Sexmer

4109 31 mass mailings from Audubon Society

4110 Celia Lambom

4111 George Milton

4112 Skip Kundahl

4113 Joe Gutkaski, President, Montana River Action

4114 Meghan Platek

4115 Lisa J. Whitmore

4116 Tina Norris

4117 Ed Mensah

4118 Barbara H. Lorenz

4119 Heather Nelson

4120 Margaret T. LoGalbo

4121 Allan T. Lacey

4122 Mark Hendrick

4123

1

Charles McLaughlin

4124

1

Jack Shaner

4125 Victoria P. Day

4126 Diane Ferraiolo

4127 Tex G. Hall, President, National Congress of American Indian

4128 Brooke Suter, Connecticut Director, Clean Water Action

4130 Audrey Leverton

4131

1

David Nicholson
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-clxiv

4132 Amy Wright, Dayton Power and Light Company

4135

1

Usha Turner

4136 R.L. Jeanes

4139, 4220, 4221 Steve E. Chester, Michigan Department of Environmental Quality

4140 3,292 mass mailings from Sierra Club, John Muir Society

4141 Edward Carnelli

4142 Forest Gee

4143 Paul Cipriano

4144 Fred H. Behnken

4145 1,318 mass mailings

4146 Marvin Dodge

4147 James D. Kotarski

4148 Thomas Denio

4149 Mark Miller, MD

4150 Malcolm Quint

4151 Geoffery M. Footner

4152 Michael Rufini

4153 Darlene Stengel

4154 Sheila A. Williams

4155 Benjamin Derrick

4156 John J. Gosling

4157 Craig R. Hannah

4158 Frank Damon

4159 Aaron Cloutier
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-clxv

4160 Ilene and Gaylord Younghein

4161 Eric C. Rupp

4162 Elizabeth S. Merriam

4163 Lawrence Eugene Smith

4164 Holly Shisler

4165 Shanda Bowditch

4166 Premena

4167 Candence D. Schruber

4168 Mary Ellen Norman

4169 Judith B. Flemke

4170 Maureen Dodge

4171 Jay Simmons

4172 Marvin Dodge

4173 Steven Chan

4174 Jill Leelum

4175

1

Paul Hedges

4176

1

Bonnie Kay Howard

4177 Dawn R. Gallagher, Commissioner, Maine Department of Environmental

Protection

4178 Emily Jo Goulden

4179 Richard French, Jr.

4180 Elizabeth Sibley

4181

1

Jim Cusimano

4182 George and Dale. Davidson
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-clxvi

4183 Bob and Helen Floyd

4184 Jerome F. Downs

4185

1

Buffy Francisco

4186

1

Lois M. Schwarz

4187 Michael Buckley

4188

1

Dale L. Koontz

4190 Colleen E. Swan, Tribal Administrator, Native Village of Kivalina

4191, 3554 John Fainter, Association of Electric Companies of Texas

4192 Jo Hanson

4193 72 mass mailings from Parkview Jr. High School

4195 Jane Garbacz

4196 Wesley Sweitzer

4197 Alma Avilla-Pilchman

4198 Jack Norman

4199 Glenn Gabryel

4200 Lara Shackelford

4201 Valerie Berk

4202 Mark Singer

4203 Dan and Leslie Schmidt

4204 Roger

4205 Barbara Dobos

4206 47 mass mailings from Paideia School

4207 Cathy M. Kennedy

4208 Anne Stern
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-clxvii

4209 Peter J. Silverman

4210 Megan Thomas

4211 Ellen Aiken

4212 Greg Roth

4213 Harry W. Read

4214 Jason P. McGraw

4215 Jane M. Heimlich

4216 Lorraine and Joseph Tash

4217 J.D. Dolan

4218 Neill De Paoli

4219

1

Daniel J. Odistro

4223 Aldo B. Mysek

4224 Anthony Geron

4225 Robinson and Joan Lappin

4226 Chris Chesney

4227 David Viles

4228 Dena Hollowwood

4229 Jim and Diane Malcolm

4230 Douglas Harnby

4231 Ernie Herzberger

4232 Allan Frandsen

4233 Joe C. Gordon III

4234 Heather Williams

4235 Ann Coppola
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-clxviii

4236 Jan Harmon

4237 Nathaniel O. Keohane, PhD

4238 Mitchell Solovay

4239 Paul Martin

4240 Sunshine and Art

4241 R.J. Ruppenthal

4242 Anonymous

4253 Evelyn Green

4257 Jaime

4258 Darren Schmidt

4259 Sharrhan and Jonathan

4260 Lynn Martin

4261 Katarina Wittich

4262 Teresa McMichael

4263 Joyce R. Tomkins

4264 Clay Wickiser

4267 3 mass mailings from Belgrade Clinic, PLLP

4268 1,232 mass mailings

4269 91 mass mailings

4270 1,700 mass mailings

4271 6 mass mailings

4272 19 mass mailings

4273 9 mass mailings

4274 66 mass mailings
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-clxix

4275 1,170 mass mailings from League of Conservation Voters

4276 300 mass mailings from Green Action

4277

1

Michael Trunzo

4278 Michael Prewett

4279

1

Foster S. Gray

4280 Margaret Williamson

4281 Jo Ann and John Zarins

4282 Ginger Hoffman

4283 Darren Williams

4284 Dean and Dran Reese

4285 Elizabeth Ketcham

4286 Sean Larkin

4287 Nola Davis

4288 Victoria Kelly

4289 Erich Baum

4290 Sandy O’Brien

4291 Victor Marrero

4292

1

Lois Coleman

4293 Geert Aerts

4294 Ellen Hambrick

4295 Lois and Fred G. Andres

4296 Andrea Wilkus

4297 Zachary Lawson

4298 William and Irene Birge
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-clxx

4299 Douglas Norseth

4300 Dennis P. Graham

4301 Julie Hynes

4302 John Dukovich

4303 Ron Sutherland

4304 Virginia Leech

4305 Lisa R. Sattler

4306 Leah Y.Y. Bravo

4307 Karen DiDomenicis

4308 Peggy Staton

4309 Susan Renison

4310 Eleanor Masheff

4313 J. Rodriguez

4314

1

Jennifer A. Heindl

4315 Mary and Jack Palmer

4316

1

Deborah Hayes

4319 Barbara Weyand

4320 Scott Jones

4321 Dennis Godburn

4322

1

Marjorie Larson

4323

1

Linda Claire

4324 George Papadi

4325 Jim Watson

4326 Reg Rollins
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-clxxi

4327 George Ruth

4328 Paul Clark

4329 Theresa Galvin

4330 Jim Borchert

4331 Carol Simonek

4332 Dale Drogseth

4333 Georgia Russell

4334 Bob and Ruth Johnson

4335 Jessica Alesandro

4336 Heather Beghtol

4337 Carol Geisler

4338 Kelly Varndell

4339 Don Von Ebers

4340 Ben Hauben

4341 Terry C. Collins

4342 Julia Sathler

4343 Dodi Reinoehl

4344 Ronald H. Janetzke

4345 Paige Eaton

4346 Gail Stidolph

4347 Rosario Martin

4348 David Eaton

4349 Tonya Martinez

4350 James Dunham
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-clxxii

4351 Gregory and Ellen Erickson

4352 Benjamin van der Veen

4353 Sue Peters

4354 Geoffery Bruce

4355 Janet Easter

4356 Mr. and Mrs. Paul Ingrisch

4357 Wayne Black, NMD

4358 Jacob Paul

4359 Karen Jane Peterson

4360 Kim White

4361 Leslie Limberg

4362 John Luther

4363 Michelle Walthall

4364 Anne Wood

4365 Kenneth Jones

4366 Laura Widman

4367 Patty Hoffman

4368 Anonymous

4369 Karen Cook

4370 John Kerry

4372 Jocelyn Parrish

4373 Jihn Deamon

4374 Connor Kerns

4375 Marilyn Beaver
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-clxxiii

4376 Marguerita Burke

4377 Joe and Jill Collard

4378 Sandy Switzer

4379 Robert Thalmann

4380 Barbara Glenewinkel

4381 Michael

4383 John Gilhousen

4384 Brent Pharis

4385 David Gil

4386 Janey Lee

4387 Shari Johnson-Adams

4388 Peggy Dubach

4389 John Palmer

4390 William Peirce

4391 Heather Chapman

4392 Jim Pittman

4393 Andrew Wass

4394 Steve Moberg

4395 Barbara Hammond

4396 Kathleen

4397 Kyle Farley

4398 Patricia Nicely

4399 Pamela Deaton

4400 Eric Mankin
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-clxxiv

4401 Colleen J.G. Clark

4402 Kim Kilman

4403 David K. Richardson

4404 Tiffani

4405 Mike Epa Chambers

4406 Paul Dirshka

4407 Barbara Berringer

4408 Paul Regan

4409 Patricia Wilz

4410 Dr. Cecilia Zuniga

4411 Ann Storie

4412 Pam Leis and family

4413 Cathy Fitzpatrick

4414 Kirby Hughes

4415 Jayne Tamburello

4416 Peter Taglia

4417 Diana Harris

4418 Stacy Wewe

4419 Fern R. Burgis

4420 Diane McCluskey

4421

1

Nicholas Rosenstock

4422 Robert M. Hensley

4423 Anthony Napolillo

4424 Holly James
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-clxxv

4425 M. Keleher

4426 B. Sachau

4427 Jeffrey Cartwright-Smith

4428 J. Wang

4429 Lee Spivey

4430 Marcella Sarson

4431 Michael and Margie Myers

4432 Mary M. Downing

4433 Pete Esquiro

4434 Peter Mueller

4435 John Petrushka

4436 Rachel Myers

4437 Richard Bole

4438 Richard Schribner, MD

4439 Sarah Causey

4440 Sean Gutknecht

4441 Jane Alexander

4442 Tom Sanders

4443 Brendan Smith

4444 Deborah Vantreuren

4445 Karessa Townsend

4446 Carol Antill

4447 Marlene Satter

4448 John Duffield
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-clxxvi

4449 Diana V. Steel

4450 Chris Zenos

4451 1,899 mass mailings from Southern Alliance for Clean Energy

4452 Lois M. Congdon

4453 Fay C. Graning

4454 Robert Manning, Florida Electric Power Coordinating Group

4455, 4456 John H. LeSeur, Hastings Utilities and City of Grand Island, Nebraska

4457 Holly Wise Rohrbach

4458 John T. Miller

4459 Denny Jernigan

4460 Barbara Moore Rumsey

4461 Nancy C. Tigner

4462 Helen Magnavita

4463 Martha Gidney

4464 Marlan Cooley

4465 Mark M. Giese

4466 R.J. Ruppenthal

4467 298 mass mailings

4468 Ali Ariniega

4469 Gene Winter

4470 Patsy S. Crosby

4471 Susan Lucalio

4472 Megan E. Furniss

4473 Marya Howell-Carter, PhD
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-clxxvii

4474 Lucia L. Armstrong

4475 Jonathan Coss

4476 D. Clark Boykin

4477 R. Imogene Gotchall

4478 Anna Harlowe, Ecology Center of Southern California

4479 Phillips R. Goldsworthy

4480 Sheryl Scott

4481 Richard Sarertsky

4482

1

Peggy Schmidt

4483 Elizabeth Ketcham

4484 Sylvia Hazlehurst

4485

1

Jim Odgen

4486 Charles P. Rfau

4487 Charles W. Larson

4488 Thel Dominici

4489 Jeanne Rehwinkel

4490 Kathy Woods

4491 Chrys Gardener

4492 Robert Shaffer

4493 Beverly Shaffer

4494 Casey Hemhyles

4495 Laura McMurray

4496

1

A.A. Allen

4497 Michael G. Polski
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-clxxviii

4498 Allen Tindell

4499 Robert Giambalvo

4500 Maryanne Owens

4501 George M. Spoon

4502 Greg Matza

4503 Randall E. Hartman

4504 Rodney Baumbach

4505 Mary Anne Guggenheim, MD

4506 Carol Siewert

4507 Anthony Countey

4509 JoAnn Nishiura

4510 Barbara L. Black

4511 Bryan Brodie

4512 Gail Arnault

4513 Kevin Fischer

4514 Elise Harvey

4515 Lynnette Rizek Hanne

4517 Danny Thorpe

4518 Robert D. Britz

4519 Lynn Morell

4520 Edward Darmohray

4521 Harold J. Liebrecht

4522 Mary Schrunk

4523 M. Hessek
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-clxxix

4524 Carol Davis

4525 Donna Tamres

4526 Loreen Spangler

4527 Joanne Mann

4528 Suzanne and Allen Bassin

4529 Gloria Dunn

4530 Jim Pittman

4531 Maxine

4532 Bernie Johnson

4533 Donna Ridgeway

4534 Jesus Camarillo

4535 Susan Barker

4536 Sunny Julius

4537 Jane Kovac

4538 Kathy Johnson

4539 Susan Loperete

4540 Margaret Ellis

4541 Deborah Oliff

4542 Christina Martin

4543 Dean Zagone

4544 Patricia Ohnikian

4545 Adina Warren

4546 Janet Accardi

4547 Raymond A. Firestone, PhD
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-clxxx

4548 Teresa Jones

4549 Rebecca Hierholzer

4550 Judith B. Halloran

4551 Debbie Plumley

4552 Joseph Monaghan

4553 Carey Crist

4554 Dr. John L. and Susan Robertson

4555 Shelly Boose

4556 Chuck and Kathy Brinkman

4557 Jamie Pogach

4558 Jerry Young

4559 Lorna

4560 Nicole Ramos

4561 Karen Gonzalez

4562 David Hilger

4563 Yvonne Britt

4564 Rad Benson

4565 Lori D. Tripp

4566 Joe Garisson

4568 Dayna Dunbar

4569 Brian G. Supplee

4570 Charles Harwood

4571 Gila Markov

4572 Dale Green
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-clxxxi

4573 Sarah Mauney

4574 Nyla Fonger

4575 Joanne Carolan

4576 Marjorie J. Walters

4577 Iris Lonker

4578 Dorothy Fairweather

4579 Jerry Spalding Fredin

4580 Kim Sterner

4581 Joan Russell

4582 Helen Melvin

4583 Ellen Levy

4584 Linda Fisher

4585 Debbie Hemlock

4586 Timmy Chen

4587 Tracy Carlson

4588 Barbara Sheeley

4589 Hal Baden

4590 Carolyn Cole

4591 J. Kirk and Marcay Dickens

4592 Lois and Marvin Barger

4593 Ann Storie

4594 Bea Ann Bridges

4595 Trevor J. Owen

4596 Laura Wolf
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-clxxxii

4597 Lisa Marshall

4598 Kim Dunn

4599 Lisa Edwards

4600 Stacey Kirms

4601 RaDonna Roland

4602 Catherine Sumners

4603 Meggan McEvoy

4604 Ruth Ann Humphrey

4605 Patricia Williams

4606 Irma Call

4607 Rosalind Mearns

4608 Ruth McIntosh

4609 Richard C. Stancliff

4610 Ed Masters

4611 Suzanne Skinner

4612 Frenesa K. Hall, MD

4613 Paul Regan

4614 Frances K. Tetens

4615 Tom Sheeley

4616 Tony Siegle

4617 Wilson Bryan

4618 The Ward Family

4619 Peggy Lee

4620 Anonymous
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-clxxxiii

4621 Anonymous

4622 Lin Hall

4623 Thomas C. Maurer

4624 Betty Jennings

4625 Jennifer B. Frazier

4626 Bernadine Rettger

4628 Elizabeth Ward

4629 Bridget Fonger

4630 June Davis

4631 Pamela Gale Park

4632 Loraine Scime

4633 Shelly Tracy

4634 Marilyn Cuffee-Gordon

4636 Lisa O’Neil

4637 Phyl Morello

4638 Dwayne Tuttle

4639 Kathleen Gabriel

4640 John and Verna Wright

4641 John Dziak

4642 Kayde Cadwell

4643 June Foster Stinson

4644 Glormil

4645 David Turnbell

4647 Anonymous
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-clxxxiv

4648 Galen and Paula

4649 Rick Temple

4651 Cara Gifford

4652 Christine Rogers

4653 253 mass mailings

4654 Peggy Lee

4655 Peter McClelland

4656 A.J. Maimbourg

4657 Carolyn G. Crombie

4658 Aaron Dougherty

4659 76 mass mailings from Illinois PIRG and Education Fund

4660 10 mass mailings from PIRG Michigan

4661 183 mass mailings from League of Conservation Voters Education Fund

4662

1

15 mass mailings

4663 3 mass mailings from Sierra Club

4664 11,717 mass mailings

4665 15 mass mailings

4666 390 mass mailings from Sierra Club

4667 1,330 mass mailings from SC Partnership

4668 194 mass mailings

4669 150 mass mailings from Environmental Maine

4670 5 mass mailings from Environmental Maine

4671 283 mass mailings

4672 1,379 mass mailings from Wisconsin Earth Day Coalition
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-clxxxv

4673 82 mass mailings from Sierra Club North Star Chapter

4674 902 mass mailings from League of Conservation Voters Education Fund

4675 927 mass mailings from Montana PIRG

4676 2,540 mass mailings from Save the Clean Air Act Organization

4677 870 mass mailings Penn Environment

4678 4,101 mass mailings from Environment Colorado

4679 6,086 mass mailings from Environment California

4680 120 mass mailings from Illinois PIRG and Education Fund

4681 7,644 mass mailings from Penn Environment

4682 9,956 mass mailings from State PIRGs

4683 10,407 mass mailings from Sierra Club

4684 114,639 mass mailings from State PIRGs

4685 2,358 mass mailings

4697 Kirk Freundenburg

4698 Ann Wilsnack

4699 Anne Wood

4700 Bob Bramblett

4701 Carey Crist

4702 Charlene Woodcock

4703 Cheryl Heath

4704 Sean McCandless

4705 Crystal Bevans

4706 Cyane Gresham

4707 Dave Daulton
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-clxxxvi

4708 David K. Richardson

4709 Anonymous

4710 Dennis Dimster

4711 Derek McLaughlin

4712 David Giffen

4713 Edward Askew

4714 Debra Shankland

4715 David Keller

4716 Jim Miller

4717 Howard Edson

4718 Jay and Lucia Weinroth

4719 Jeff Lane

4720 Jessica Murdaugh

4721 Joe Jennings

4722 Keith Brown

4723 Karen L. Hansen

4724 Kirk Freudenburg

4725 D. Keith

4726 Katherine Duncanson

4727 Ken Thygerson

4728 Marla Rolfe

4729 Megan Harris

4730 Melissa Powers

4731 Tawny Mata
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-clxxxvii

4732 Michael Bennett

4733 M.J. Gardner

4734 Nancy Kessler

4735 Nita Ferguson

4736 Melissa J. Brenneman

4737 Ellen Weiner

4738 Amanda Leogue

4739 Ragen Tilzey

4740 Ralph Klawitter

4741 Steven Rychnovsky

4742 Chuck Swensen

4743 Vickie Bielanski

4744 William G. Wales

4745 Patricia DeMarco-Rowe

4746 Tanya Dobbs

4747 Ann Rumrill

4748 Pamela Heskett

4749 Linda Rose

4750 4 mass mailings

4751 Marybeth Clark

4752 Janet Gilbert

4753

1

Ginny Mayhew

4754 7,399 mass mailings

4755 Thomas Stiles
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-clxxxviii

4756 Michael Peltneir

4757 R.H. Williams

4758 Ginny Corzire

4759 Peggy Louise Daulton

4760 Joline Bettendorf

4761 Nancy Schiegg

4762 Claire Iverson

4763 Lee Walker Oxenham, Patapsco Riverkeeper

4764 Robert Rutowski

4765 Kate Godfrey

4766 Tania Banak

4767 John Ulloth, Sierra Club, Angeles Chapter

4768 Marion Thorne

4769 Allan H. Messinger

4770 Carmen Pirotte

4771 Jim Sconyers, Sierra Club, New Hampshire

4772 Alan C. Hasselwander

4773 Anabell Kinney

4774 Anita Moris

4775 William DeForest

4776 Bonita DiGennaro

4777 Carol Vericker 

4778 Charles M. Paden, PhD

4779 Claire Hartford Hornsten, President, Women’s Public Forum
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-clxxxix

4780 John Garret Baker

4781 D. Meehan

4782 Gwenyth M. Nichols

4783 David Kohn

4784 Dru Carter

4785 Matthew and Elizabeth Stein

4786 Erin Maloney

4787 Eve Fox

4788 Glenna Lea Citron

4789 Gwynne Brown

4790 Henry Massery

4791 Janis Haansen Klinger

4792 Jewel Down

4793 Kimberly Murphy

4794 John Thornberg

4795 Claude Roland, MD

4796 Jonathan Davids

4797 Kenneth Hill

4798 Kyle Farley

4799 Kristen J. Garrett

4800 Lawrence D’Arco

4801 Amy Rudson

4802 Christine Dawkins

4803 Meggen Harris
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxc

4804 Amanda O’Hearn, PhD

4805 Patrick Marcell

4806 Paul Crouser

4807 Stephen and Ann Devitt 

4808 Peter Lee

4809 Pierre Musy

4810 Russell Behrman

4811 Robert H. Delves

4812 J. Richard Manier, Jr.

4813 Ronald Harris

4814 Rosario Martin

4815 Rosemarie M. Jeffery, MD

4816 Ruth Kuhfahl

4817 Geoffrey Greene

4818 Susan Localio

4819 Todd D. Johnson

4820 Dr. Peter J. Veverka

4821 Vicki Stephens

4822 Marcy Bode

4823 William and Margo Cooper

4824 Rozane Williamson

4825 Amanda Chrisp

4826 Herb Mintz

4827 Sharon Wang
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxci

4828 Marian Hackney

4829 John de Souza

4830 Steve Blum

4831 Doug Poole

4832 Mel and Gail Minthorn

4833

1

Nicholas Rosenstock

4834 Michael J. Mayo

4835 Benjamin Allen

4836 April Ford

4837 Barbara Presson

4838 Anonymous

4839 Ben and Stacy Merrick

4840 Bruce L. Renguist

4841 Chris Mihill

4842 Gertrude Freidel

4843 Lona Rosenfeld

4844 Dan Schotter

4845 David Weitzler

4846 Donna J. Williams

4847 James Wilson

4848

1

Marjorie Larson

4849 Linda S. Sanders

4850 Karen Cowdrey

4851 Milton Hanzel
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxcii

4852 Evan Francis

4853 Nancy Matyasovsky

4854 Peggy Kyprianides

4855 Susan Bawin Coonradt

4856 Robert Lowery

4857 Patricia Nicely

4858

1

Tim Lingg

4859 Todd Bradshaw

4860 T. Reid Kavieff

4861 Jill

4862 Christine R. Masterson

4863 Homer J. Hall

4864 Jackie Needleman

4865 Pete Jimenez

4866 Mr. and Mrs. Martin Glynn

4867 33,498 mass mailings

4868 502 mass mailings

4869 31 mass mailings

4870 Neila Jack

4871 2 mass mailings

4872 10 mass mailings

4873 22 mass mailings

4874 82 mass mailings

4875 374 mass mailings
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxciii

4876 34 mass mailings

4877 78 mass mailings

4878 3,656 mass mailings

4879 279 mass mailings

4880 100 mass mailings

4881 29 mass mailings

4882 11,849 mass mailings

4883 16,667 mass mailings

4884 3 mass mailings

4885 981 mass mailings

4899 Gil Freedman

4900 Anonymous

4901 Chris Robbins

4902 Kathy Knudsen

4903 Paul Thib

4905 Ann Walton

4906 Mike Shifflet

4907 13 mass mailings

4908 Jennifer Garrick

4936 Kevin Fitzpatrick

4937 Jeanette Hartge

4938 Marc B. Horin

4939 Nicholas Shestople

4940 Mike Jones
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxciv

4941 Ben Eubanks

4942 Kristen Rachford

4943 Frances E. Harkins

4944 Anonymous

4945 Denise Brown

4946 Anonymous

4947 Holly Terschuur

4948 Marilyn Brittner

4949 Sharon L. Oler

4950 L. Evelyn Beason

4951 James B. Mitchell, PhD

4952 Carolyn Ulrich

4953 Anne M. Hanada

4954 Lois Miles and family

4955 Juanita Wright Potter

4956 Patricia A. Baldwin

4957 Buck O’Herin

4958 Mariel E. Matthews

4959 Faith Helen Farris

4960 Dr. Andrew Millard

4961 Linda Davis

4963 4 mass mailings

4964 750 mass mailings

4965 Carol E. Colip
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxcv

4966 Joan Sprague

4967 Peter W. Joseph, MD

4968 Dorothy Horton

4969 T. Hudson

4970 Mark Potter, MD

4971 Tom Aldridge

4973 Carol Long

4975 3 mass mailings

4977 Sean Palfrey, MD

4978 Rachael Blumenthal

4979 Anne C. Godfrey

4980 Rhoda Lonow

4981 Janet M. Redding

4982 Pamela P. McVety

4986 James A Rapp

4987 Fayetta P. Weaver

4988 Marjorie M. Donn

4989 2 mass mailings

4990 Nancy Corson Carter

4991 M.D. Hanson

4992 Marilyn Jacobs

4993 Anonymous

4994 Amber Powers

4995 Danna P. Murch
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxcvi

4996 Nancy dell’Aquilla

5002 Nathan Pierce

5003 Judi Keppler

5004 Sam West

5005 Elaine Storella

5006 Jessie Magnuson

5007 Christie Thomas

5008 Tetsa Skordos

5009 Joy Peterson

5010 Leighanna Kelley Midkiff

5011 Tom McDonnell

5013 Doris Hartman

5014 Phyllis F. Campbell

5015 Susan Bergmann

5016 J.C. Englert

5017 Helen Jo Williams

5018 Darlene Wagner

5019 Karl B. Bucholz and Karen H. Robinson

5020 Jane Krentz

5021 Allen Davisson

5022 Gil Freedman

5023 Anonymous

5024 Chris Robbins

5025 Kathy Knudsen
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxcvii

5026 Paul Thib

5027 Nicholas S. Carpenter

5028 Richard Holt

5029 Karen Meyer

5030 Glen Becker

5031 Kristy Hartje

5032 Camille Holthaus

5033 Margaret Young

5034 Marc Polansky

5035 Elizabeth Cohen

5036 Hilary Lorraine

5037 Karen Luepke

5038 Christen C. Garrett

5039 Robert F. Delaney

5040 Andrew J. Spano, Westchester County Executive, NY

5041 Stephanie Klotz

5042 Wendy Tokuda

5043 Katie Phipps

5044 Tatyana Livshultz

5045 Mike Shifflet

5046 Janet and Donald Mackenzie

5047 Christina Hasseth

5048 M. Levy

5050 Bob Taft, Governor, Ohio
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxcviii

5051 Patrick Leahy, et al., U.S. Senate

5052 Alabama Waterfowl Association

5053 National Wildlife Association

5054 Victor Carrillo, Texas Railroad Commission

5055 Robert and Geraldine Folz

5056 David C. Foerter, Institute of Clean Air Companies

5057 Audrey Falcon, Chief, Saginaw Chippewa Indian Tribe

5058 Ian Nelson

5059 Jane Hagrave

5060 John Osner

5061D Mass campaign, Sierra Club

5062 Christopher Hord, Sierra Club, Georgia Chapter

5063D Mass campaign, Wisconsin Earth Day Coalition 2004

5064D Mass campaign, Penn Environment

5065D Mass campaign, Environment California

5066D Mass campaign, Environment Colorado

5067 Chris Spalding

5068D Mass campaign, LCV Education Fund

5069 Dr. Charles Powers, NY Academy of Sciences

5070 Edger P. Stegmann

5071 J. Sipkins

5073 2657 mass campaign, Greenpeace mailings

5073 Brandy Toft, Leech Lake Band of Ojibwe

5074 404 mass campaign mailings
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cxcix

5075 833 mass campaign mailings, Audobon Ohio et al.

5076 George and Myra Hurst

5077 Miriam L. Wolin

5078 Barbara Greenman

5079 Annette Wilber

5080 Ethel M. Kinkaid

5081 James E. Wagner

5082 Candice Peters

5083 Jan Rice

5084 John Paniperin

5085 Ann Regel

5086 Richard A. Kendrick

5087 Pedro L. Lanabina

5088 Sue Lorens

5089 Randy Heidenfelder

5090 Mary L. Roark

5091 Ruth Niswander

5092 Valeri McCaly

5093 Dan Feiertag

5094 Barry Fansher

5095 Barbara Hillhouse

5096 Liis McKenna

5097 Evelyn N. Brew

5098 Bruce Pisby
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cc

5099 Nancy B. Delaiti

5100 Shari Bachmann

5101 Robert M. Hensley

5102 Laura Manthe

5103 Anonymous

5104 James Coes

5106 Brandon R.

5109 69 mass campaign mailings

5110 66 mass campaign mailings

5111 Donald Manzull, U.S. Congress

5124 Maria Van Kirk

5126 16 mass campaign mailings

5128 25 mass campaign mailings

5129 9,231 mass campaign mailings

5130 Richard Smith

5131 Craig Overbeck

5132 Marc Stein

5133 Theresa Neuroth

5134 Julie Sutor

5135 Kris Medic

5136 Ken Mosher

5137 Rollin Newcomb

5138 Patricia Miller

5139 Eun Swansong
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cci

5140 Anonymous

5141 Anonymous

5142 Nicholas Engelfried

5143 John Bollinger

5144 Tina Engelfried

5147 Janice Watten

5149 Anonymous

5152 7 mass campaign mailings

5153 5 mass campaign mailings

5154 7 mass campaign mailings

5155 17 mass campaign mailings

5156 1,579 mass campaign mailings

5157 18 mass campaign mailings, Little Chute Elementary School

5158 George A. Jones

5159 Brandon Aikin

5160 Eloise Heimann

5161 Susan Scheppler

5162 Jessica Moy

5163, 5165 Ted Light

5166 William Huggins

5167, 5174 Paul Cowden

5187 1 mass campaign mailing

5193 Rosemary Engelfried

5194 Renae Robertson
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-ccii

5195 Billie Robertson

5198 Roger Hoffman

5199 Ted Beringer

5200 Anonymous

5253 1,161 mass campaign mailings

5254 Tina Spears

5258 124 mass campaign mailings

5260 Ellen Lougee

5261 David Leithhauser

5264 Irene Lieberman

5266 Robert Hunter

5267 Diane Sklensky

5268 Karin Kirulis

5269 Lynn Kinnucan

5270 Bassam Imam

5271 Jerise Fogel

5272 Alaina Borget

5273 Robert A. Mertz

5274 James Swaney

5275 Judith Gilliland

5276 Carey Blanchard

5277 Susanna Levin

5278 Dr. Carole Warner

5279 James Berg
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cciii

5280 Karin Kvale

5281 Diana Varley

5282 The Clean Energy Group

5283 Tressa Schendel

5285 Chris Wells

5286 William Robens

5287 Laura E. Tudor

5288 Eric Zuber

5289 Ron Hildebrand

5290 Mary Young

5291 Dawn Brennan

5292 Althea Godfrey

5293 Patricia Archbold

5294 Suzanne Marckx

5295 K. Oneill

5296 Craig Scheunemann

5297 John Phillips

5298 Sandra Collins

5299 Max Hemmert

5300 David Fitzjarrell

5301 Liz Lundberg

5302 Dr. Wendy.Yona Noon

5303 812 mass campaign mailings

5304 105 mass campaign mailings 
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-cciv

5305 Beth Hamilton

5306 Roy Fouts

5307 Robert Shroy

5308 Robert Mossman

5309 Lynell Martinez

5310 Joe Culbertson Jr.

5311 Fred Vanderbeek

5312 Erica Schwartz

5313 700 mass campaign mailings, Clean Wisconsin

5315 Brandon

5316 Peter Garrett

5317 Susan Miller

5318 Brian Scott

5319 Michael Fiori, MD

5320 Mary Ann Maxson

5321 John Witte, Ph.D

5322 Monique Maisenhalter

5323 Gerrit Crouse, Ph.D

5324 Milan and Patricia Murchek

5325 Jay Allaire

5326 Ann Modro

5327 Matt Roman

5328 Pat Gallagher

5329 Arthur Gilbert
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-ccv

5330 Delwin Johnson

5331 Heather A. Ridle

5332 The Clean Energy Group

5333 Anonymous

5334 Terry Travers-Davin

5335 Hilda Knowles

5336 Anonymous

5348 Priscilla Ivester

5349 Wendy Rosenau

5350 Erin Morgan

5351 Daniel Dougherty

5352 Chris Baeckstrom

5353, 5354 Lorri Carrell

5355 Anonymous

5356 Bernadine Bellmor

5357 Anna Gray

5358 Kathy Dato

5359 Victoria Hager Rose

5360 Chuck Abbate

5361 Doug Fogel

5362 Melissa Hester

5363 Henry Schrieber

5364 Robert Reed

5365 Bryant C. Danner, Edison International
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-ccvi

5366 Stephen Johnson

5367 Wanda S. Ballentine

5368 James Jenkins

5369 Bev Stadick

5370 Robert L. Powers

5371 Julian Huerta

5372 Jesse Ayotte

5373 Nori Muster

5374 Ann Isaksen

5375 Bob Barcus

5376 137 mass campaign mailings, Sierra Club

5377 Eugene Dallas Gay

5378 Seth M. Robbins

5379 J. Michael Reisert

5380 William C. Mahaffey

5381 Michael L. Gourley

5382 Arthur F. Kistler

5383 Neil Anthony Busche

5384 Donald H. Miller

5385 Kathleen Doris Janacek

5386 Sean Conley

5387 Jeff Leibfreid

5388 Luke Allen Russell

5389 Joe Roger
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-ccvii

5390 Mrs. Marian Buckner

5391 Clarence A. Petty

5392 James

5393 Cynthia Kobak

5394 Candice Peters

5395 Susan Scheppler

5396 R. Allen

5397 Ann Regel

5398 Barbara Voelker

5399 Bonnie J. Walling

5400 Luann Lindstrom

5401 Doug LaFullette

5402 2,100 mass campaign mailings, Sierra Club

5403 Whitney Parks

5404 John L. Stowell, Cinergy Corp

5405 Anonymous

5406 Edward J. Barton

5407 Aishaa Abdul-Karim

5408 Deb Belmore

5409 Michele Theberge

5410 Linda Foster

5411 Jeff Quick, Utah Geological Survey, Utah

5412 Pauline Blocker, President, Save Our Sea Life Org, Inc. 

5413, 5414 Jane K. Stahl, Connecticut DEP
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-ccviii

5415 Cassidy Weyel

5416 Margaret Manzo

5417 Pala

5419 Pat

5420, 5565 John A. Paul, RAPCA

5421 Kevin Donnelly and John Belvins, Connecticut DNREC

5422 Charles B. Sedman, Consultant and Willard L. Goss, RJM-Beaumont

5422 Robert L. Kappelman, Florida Municipal Electric Association Large

Generator Coalition

5422 Robert L. Kappelmann, Florida Municipal Electric Association Large

Generator Coalition

5423 Robert Ferguson, Center for Science and Public Policy

5424 Catherine Gay

5425 Robert F. Gruenig

5426, 5427 Charles B. Sedman, Consultant and Willard L. Goss, RJM-Beaumont

5428 Charles T. Phillips

5429-5440 ADA Environmental Systems

5442 Robert Ferguson, Center for Science and Public Policy

5443, 5461-5463 Robert W. Golledge, Jr., Massachusetts DEP

5444 Anonymous

5445 Michael L. Marvin, Business Council for Sustainable Energy and John

W. Jimison, U.S. Combined Heat and Power Association

5446 Mark H. Davies, Kennecott Energy Company

5447 Frederick D. Palmer and Rogert B. Walcott, Peabody Energy

5448 S. Morgan
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-ccix

5449 Ingeborg Eibl

5450-5454 Dr. Leonard Levin, Electric Power Research Institute

5455, 5512, 5513 Christine Berini, Fond du Lac Band of Lake Superior Chippewa

5455 Michael L. Marbin, Business Council for Sustainable Energy and John

W. Jimison, US Combined Heat and Power Association

5456 Joe L. Citta, Jr., Nebraska Public Power District

5457, 5459, 5510 A. Todd Johnston, National Mining Association

5458 Carl Johnson, New York State Department of Environmental

Conservation

5460, 5514, 5515 Eliot Spitzer, New York Attorney General; Richard Blumenthal,

Connecticut Attorney General; Thomas F. Reilly, Massachusetts

Attorney General; Connecticut Attorney General; Kelly A. Ayotte, New

Hampshire Attorney General; William H. Sorrell, Vermont Attorney

General; and Peggy A. Lautenschlager, Wisconsin Attorney General

5464 Nancy L. Seidman, STAPPA and Dennis J. McLerran, ALAPCO

5465-5468 Catherine A. O’Neill, Center for Progressive Regulation

5469 Quinlin J. Shea, Edison Electric Institute

5470 Charles Richardson

5471 Class of ‘85 Regulatory Response Group

5472 William Rogers, Detroit Edison Company

5473 National Rural Electric Cooperative Association

5474 Douglas J. Fulle, Oglethorpe Power Corporation

5475 Kathleen A. McGinty, Pennsylvania Department of Environmental

Protection

5476 Charles J. Lippert, Mille Lacs Band of Ojibwe Indians

5477, 5479, 5480,

5481, 5483

Northeast States for Coordinated Air Use Management (NESCAUM)
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-ccx

5478, 5547, 5548,

5562, 5630,

5631

Neal J. Cabral, McGuireWoods LLP, for American Coal for Balanced

Mercury Regulation (The Bituminous Coal Coalition)

5482 John W. Dwyer, Lignite Energy Council

5484-5487, 5489 C.M. Hobson, Southern Company

5488 Environmental Defense et al

5490 Shawn Glacken, TXU Power

5491, 5623, 5628,

5629

Sid Nelson Jr., Sorbent Technologies

5492 Bill Hoback, Illinois Department of Commerce and Economic

Opportunity

5493 Edward C. Sullivan, AFL-CIO

5494 C.V. Mathai, Arizona Public Service Company

5495 Tractebel Power Inc

5495 Tractebel Power Inc.

5496 Michael G. Cashin, Minnesota Power Company-Allete

5497 Hunton and Williams LLP for Utility Air Regulatory Group

5498, 5499, 5501 Bill Edmonds, WEST Associates

5500, 5591 David C. Foerter, Institute for Clean Air Companies

5502 Richard Carlton, Paul Chu, Leonard Levin, George Offen, and Janice

Yager, Electric Power Research Institute

5503 Susan Ford

5504, 5505, 5508,

5511

Alan E. Bland, Subbituminous Energy Coalition

5506, 5507 Brandy Toft, Leech Lake Band of Ojibwe

5509 Terry R. Yellig, Sherman, Dunn, Cohen, Liefer and Yellig for AFL-CIO
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-ccxi

5516, 5517 William L. Kovacs, U.S. Chamber of Commerce

5518-5530 Jeffery T. Underhill, New Hampshire Department of Environmental

Services

5534-5540 Jon Devine, Natural Resources Defense Council

5542 Marshall E. Whitenton, National Association of Manufacturers

5543

5544

John W. Shipp, Jr., Tennessee Valley Authority

5545, 5546, 5590 Michael J. Nassi and Lloyd Gosselink for Gulf Coast Lignite Coalition

5550, 5551-5554 William O’Sullivan, New Jersey Department of Environmental

Protection

5556, 5557 Steven E. Chester, Michigan Department of Environmental Quality

5558, 5559, 5589 Al Shea, Wisconsin Department of Natural Resources

5560, 5561 Edward A. Helme and Stacey E. Davis, Center for Clean Air Policy

5563 J. Stephen Hartsfield, National Tribal Air Association

5564 Joseph E. Euitizi, San Miguel Electric Cooperative, Inc.

5566 Felice Stadler, National Wildlife Federation

5567 3 mass campaign mailings

5568, 5569 Gypsum Association

5570 Melanie A. Marty, Children’s Health Protection Advisory Committee

5571 Therese Pugh, American Public Power Association

5572 95 Mass campaign-State PIRGs

5573 Anonymous

5574 Thomas Glynn El

5575 Alma Smith

5576 John Pamperin
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-ccxii

5578 Carla D. Hanson

5579 Edward A. Pahnke

5580 Carol Wilson

5581 Jack Litka

5582 Tom Tomilson

5583 Michele E. Mukatis

5584 April Stouffer

5585 Diane G. Conway

5586 J.W. Ward

5587 Paul Cardran

5588 Helen Kalin Klanderud, Mayor, Aspen, Colorado

5592 2 mass campaign mailings, Sierra Club

5593 Bengt and Polly Ohman

5594 P. Vilinsky

5595 Cynthia Leahy

5596 Mindy Drossner

5597 Lillian and Charles Rhinehart

5598 Elizabeth Watts

5599 Miriam L. Wolin

5600 Richard Samuels

5601 Thomas Aldridge

5602 Marilyn R. Cornelius

5603 Kathryn Wild

5604 Daniel Byrd et al.
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-ccxiii

5605 Myfanwy Plank

5606 Marilyn Hamete

5607 Robert Francis Piazza

5608 Kathy Harty

5609 L. Jean Anderson

5610 Arthur O. Long

5611 Eleiza Parkson

5612 Marlene Boecken

5613 Jim DeCecco

5614 Paula Cardia

5615 Clerence Guerin

5616 Francis Volpe

5617 Violette B. Van Belle

5618 India Loevner

5619 Terrie Derstine

5620 Sharon Ford

5621 Kathleen Bailey

5625 Judy Valentine

5626 URS Group et al.

5627 Duke Power et al.

5632 Anonymous

5633 D. Roxey

5634 L. Wooldridge
Table A-1 (Continued)

Docket ID No.

OAR-2002-0056 Commenter

A-ccxiv

5768 Record of telephone comments received, weeks of March 29-June 18,

2004

1 Not applicable (Interstate Air Quality Rule, New Source Review, Clean Air Planning Act,

CAFÉ standards, nuclear waste).

2 Request for public hearing and/or extension of comment period.

3 Public hearing testimony (Chicago, IL; Philadelphia, PA; Research Triangle Park, NC; or

Denver, CO).