Wednesday,

May 18, 2005

Part II

Environmental 

Protection Agency

40 CFR Parts 60, 72, and 75

Standards of Performance for New and 

Existing Stationary Sources: Electric 

Utility Steam Generating Units; Final Rule

28606 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Parts 60, 72, and 75

[OAR–2002–0056; FRL–7888–1] 

RIN 2060–AJ65

Standards of Performance for New and 

Existing Stationary Sources: Electric 

Utility Steam Generating Units

AGENCY: Environmental Protection 

Agency (EPA).

ACTION: Final rule.

SUMMARY: In this document, EPA is 

finalizing the Clean Air Mercury Rule 

(CAMR) and establishing standards of 

performance for mercury (Hg) for new 

and existing coal-fired electric utility 

steam generating units (Utility Units), as 

defined in Clean Air Act (CAA) section 

111. The amendments to CAA section 

111 rules would establish a mechanism 

by which Hg emissions from new and 

existing coal-fired Utility Units are 

capped at specified, nation-wide levels. 

A first phase cap of 38 tons per year 

(tpy) becomes effective in 2010, and a 

second phase cap of 15 tpy becomes 

effective in 2018. Facilities must 

demonstrate compliance with the 

standard by holding one ‘‘allowance’’ 

for each ounce of Hg emitted in any 

given year. Allowances are readily 

transferrable among all regulated 

facilities. Such a ‘‘cap-and-trade’’ 

approach to limiting Hg emissions is the 

most cost-effective way to achieve the 

reductions in Hg emissions from the 

power sector. 

The added benefit of the cap-andtrade approach is that it dovetails well 

with the sulfur dioxide (SO2) and 

nitrogen oxides (NOX) emission caps 

under the final Clean Air Interstate Rule 

(CAIR) that was signed on March 10, 

2005. CAIR establishes a broadlyapplicable cap-and-trade program that 

significantly limit SO2 and NOX

emissions from the power sector. The 

advantage of regulating Hg at the same 

time and using the same regulatory 

mechanism as for SO2 and NOX is that 

significant Hg emissions reductions, 

especially reductions of oxidized Hg, 

can and will be achieved by the air 

pollution controls designed and 

installed to reduce SO2 and NOX. 

Significant Hg emissions reductions can 

be obtained as a ‘‘co-benefit’’ of 

controlling emissions of SO2 and NOX; 

thus, the coordinated regulation of Hg, 

SO2, and NOX allows Hg reductions to 

be achieved in a cost-effective manner. 

The final rule also finalizes a 

performance specification (PS) 

(Performance Specification 12A, 

‘‘Specification and Test Methods for 

Total Vapor Phase Mercury Continuous 

Emission Monitoring Systems in 

Stationary Sources’’) and a test method 

(‘‘Quality Assurance and Operating 

Procedures for Sorbent Trap Monitoring 

Systems’’). 

The EPA is also taking final action to 

amend the definition of ‘‘designated 

pollutant.’’ The existing definition 

predates the Clean Air Act Amendments 

of 1990 (the CAAA) and, as a result, 

refers to section 112(b)(1)(A) which no 

longer exists. The EPA is also amending 

the definition of ‘‘designated pollutant’’ 

so that it conforms to EPA’s 

interpretation of the provisions of CAA 

section 111(d)(1)(A), as amended by the 

CAAA. That interpretation is explained 

in detail in a separate Federal Register

notice (70 FR 15994; March 29, 2005) 

announcing EPA’s revision of its 

December 2000 regulatory 

determination and removing Utility 

Units from the 112(c) list of categories. 

For these reasons, EPA has determined 

that it is appropriate to promulgate the 

revised definition of ‘‘designated 

pollutant’’ without prior notice and 

opportunity for comment.

DATES: The final rule is effective on July 

18, 2005. The Incorporation by 

Reference of certain publications listed 

in the final rule are approved by the 

Director of the Office of the Federal 

Register as of July 18, 2005.

ADDRESSES: Docket. EPA has established 

a docket for this action under Docket ID 

No. OAR–2002–0056 and legacy Docket 

ID No. A–92–55. All documents in the 

legacy docket are listed in the legacy 

docket index available through the Air 

and Radiation Docket; all documents in 

the EDOCKET are listed in the 

EDOCKET index at http://www.epa.gov/

edocket. Although listed in the indices, 

some information is not publicly 

available, i.e., CBI or other information 

whose disclosure is restricted by statute. 

Certain other material, such as 

copyrighted material, is not placed on 

the EDOCKET Internet site and will be 

publicly available only in hard-copy 

form. Publicly available docket 

materials are available either 

electronically in EDOCKET or in hard 

copy at the Air and Radiation Docket, 

EPA/DC, EPA West, Room B102, 1301 

Constitution Ave., NW., Washington, 

DC. The Public Reading Room is open 

from 8:30 a.m. to 4:30 p.m., Monday 

through Friday, excluding legal 

holidays. The telephone number for the 

Public Reading Room is (202) 566–1744, 

and the telephone number for the Air 

and Radiation Docket is (202) 566–1742.

FOR FURTHER INFORMATION CONTACT: For 

information concerning analyses 

performed in developing the final rule, 

contact Mr. William Maxwell, 

Combustion Group, Emission Standards 

Division (C439–01), EPA, Research 

Triangle Park, North Carolina, 27711; 

telephone number (919) 541–5430; fax 

number (919) 541–5450; electronic mail 

address: maxwell.bill@epa.gov.

SUPPLEMENTARY INFORMATION: Regulated 

Entities. Categories and entities 

potentially regulated by the final rule 

include the following:

Category NAICS

code 1 Examples of potentially regulated entities 

Industry ....................................................... 221112 Fossil fuel-fired electric utility steam generating units.

Federal government ................................... 2 221122 Fossil fuel-fired electric utility steam generating units owned by the Federal government. 

State/local/Tribal government .................... 2 221122

921150

Fossil fuel-fired electric utility steam generating units owned by municipalities. 

Fossil fuel-fired electric utility steam generating units in Indian country. 

1 North American Industry Classification System. 

2Federal, State, or local government-owned and operated establishments are classified according to the activity in which they are engaged. 

This table is not intended to be 

exhaustive, but rather provides a guide 

for readers regarding entities likely to be 

regulated by the final rule. This table 

lists examples of the types of entities 

EPA is now aware could potentially be 

regulated by the final rule. Other types 

of entities not listed could also be 

affected. To determine whether your 

facility, company, business, 

organization, etc., is regulated by the 

final rule, you should examine the 

applicability criteria in 40 CFR 60.45a of 

the final new source performance 

standards (NSPS) amendments. If you 

have questions regarding the 

applicability of the final rule to a 

particular entity, consult your State or 

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28607

local agency (or EPA Regional Office) 

described in the preceding FOR FURTHER

INFORMATION CONTACT section. 

Worldwide Web (WWW). In addition 

to being available in the docket, an 

electronic copy of today’s document 

will also be available on the WWW 

through EPA’s Technology Transfer 

Network (TTN). Following signature by 

the Acting Administrator, a copy of the 

final rule will be posted on the TTN’s 

policy and guidance page for newly 

proposed or promulgated rules at

http://www.epa.gov/ttn/oarpg. The TTN 

provides information and technology 

exchange in various areas of air 

pollution control. 

Judicial Review. Under CAA section 

307(b), judicial review of the final NSPS 

is available only by filing a petition for 

review in the U.S. Court of Appeals for 

the District of Columbia Circuit on or 

before July 18, 2005. Under CAA section 

307(D)(7)(B), only those objections to 

the final rule which were raised with 

reasonable specificity during the period 

for public comment may be raised 

during judicial review. Moreover, under 

CAA section 307(b)(2), the requirements 

established by the final rule may not be 

challenged separately in any civil or 

criminal proceedings brought by EPA to 

enforce these requirements. 

Outline. The information presented in 

this preamble is organized as follows:

I. Background 

A. What is the source of authority for 

development of the final rule? 

B. What is the regulatory background for 

the final rule? 

C. What is the relationship between the 

final rule and the section 112 delisting 

action? 

D. What is the relationship between the 

final rule and other combustion rules? 

II. Revision of Regulatory Finding on the 

Emissions of Hazardous Air Pollutants 

from Utility Units 

III. Summary of the Final Rule Amendments 

A. Who is subject to the final rule? 

B. What are the primary sources of 

emissions, and what are the emissions? 

C. What is the affected source? 

D. What are the emission limitations and 

work practice standards? 

E. What are the performance testing, initial 

compliance, and continuous compliance 

requirements? 

F. What are the notification, recordkeeping, 

and reporting requirements? 

IV. Significant Comments and Changes Since 

Proposal 

A. Why is EPA not taking final action to 

regulate Ni emissions from oil-fired 

units? 

B. How did EPA select the regulatory 

approach for coal-fired units for the final 

rule? 

C. How did EPA determine the NSPS 

under CAA section 111(b) for the final 

rule? 

D. How did EPA determine the Hg capand-trade program under CAA section 

111(d) for the final rule? 

E. CAMR Model Cap-and-trade Program 

F. Standard of Performance Requirements 

G. What are the performance testing and 

other compliance provisions? 

V. Summary of the Environmental, Energy, 

Cost, and Economic Impacts 

A. What are the air quality impacts? 

B. What are the non-air health, 

environmental, and energy impacts? 

C. What are the cost and economic 

impacts? 

VI. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act 

D. Unfunded Mandates Reform Act 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation 

and Coordination with Indian Tribal 

Governments 

G. Executive Order 13045: Protection of 

Children from Environmental Health and 

Safety Risks 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer and 

Advancement Act 

J. Executive Order 12898: Federal Actions 

to Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

K. Congressional Review Act

I. Background 

A. What is the source of authority for 

development of the final rule? 

CAA section 111 creates a program for 

the establishment of ‘‘standards of 

performance.’’ A ‘‘standard of 

performance’’ is ‘‘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, any non-air quality health 

and environmental impacts and energy 

requirements), the Administrator 

determines has been adequately 

demonstrated.’’ (See CAA section 

111(a)(1).) 

For new sources, EPA must first 

establish a list of stationary source 

categories, which, the Administrator has 

determined ‘‘causes, or contributes 

significantly to, air pollution which may 

reasonably be anticipated to endanger 

public health or welfare.’’ (See CAA 

section 110(b)(1)(A).) EPA must then set 

Federal standards of performance for 

new sources within each listed source 

category. (See CAA section 

111(b)(1)(B).) Like section 112(d) 

standards, the standards for new sources 

under section 111(b) apply nationally 

and are effective upon promulgation. 

(See CAA section 111(b)(1)(B).) 

Existing sources are addressed under 

CAA section 111(d). EPA can issue 

standards of performance for existing 

sources in a source category only if it 

has established standards of 

performance for new sources in that 

same category under section 111(b), and 

only for certain pollutants. (See CAA 

section 111(d)(1).) Section 111(d) 

authorizes EPA to promulgate standards 

of performance that States must adopt 

through a State Implementation Plans 

(SIP)-like process, which requires State 

rulemaking action followed by review 

and approval of State plans by EPA. If 

a State fails to submit a satisfactory 

plan, EPA has the authority to prescribe 

a plan for the State. (See CAA section 

111(d)(2)(A).) Below in this document, 

we discuss in more detail (i) the 

applicable standards of performance for 

the regulatory requirements, (ii) the 

legal authority under CAA section 

111(d) to regulate Hg from coal-fired 

Utility Units, and (iii) the legal authority 

to implement a cap-and-trade program 

for existing Utility Units.

B. What is the regulatory background for 

the final rule? 

1. What are the relevant Federal 

Register actions? 

On December 20, 2000, EPA issued a 

finding pursuant to CAA section 

112(n)(1)(A) that it was appropriate and 

necessary to regulate coal- and oil-fired 

Utility Units under section 112. In 

making this finding, EPA considered the 

Utility Study, which was completed and 

submitted to Congress in February 1998. 

In December 2000, EPA concluded 

that the positive appropriate and 

necessary determination under section 

112(n)(1)(A) constituted a decision to 

list coal- and oil-fired Utility Units on 

the section 112(c) source category list. 

Relying on CAA section 112(e)(4), EPA 

explained in its December 2000 finding 

that neither the appropriate and 

necessary finding under section 

112(n)(1)(A), nor the associated listing 

were subject to judicial review at that 

time. EPA did not add natural-gas fired 

units to the section 112(c) list in 

December 2000 because it did not make 

a positive appropriate and necessary 

finding for such units. 

On January 30, 2004, EPA published 

in the Federal Register a notice of 

proposed rulemaking (NPR) entitled 

‘‘Proposed National Emissions 

Standards for Hazardous Air Pollutants; 

and, in the Alternative, Proposed 

Standards of Performance for New and 

Existing Stationary Sources: Electric 

Utility Steam Generating Units.’’ In that 

28608 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

1We did not propose revising the December 2000 

finding for gas-fired Utility Units because EPA 

continues to believe that regualtion of such units 

under section 112 is not appropriate and necessary. 

We therefore take no action today with regard to 

gas-fired Utility Units.

rule, EPA proposed three alternative 

regulatory approaches. First, EPA 

proposed to retain the December 2000 

Finding and associated listing of coaland oil-fired Utility Units and to issue 

maximum achievable control 

technology-based (MACT) national 

emission standards for hazardous air 

pollutants (NESHAP) for such units. 

Second, EPA alternatively proposed 

revising the Agency’s December 2000 

Finding, removing coal- and oil-fired 

Utility Units from the section 112(c) 

list,1 and issuing final standards of 

performance under CAA section 111 for 

new and existing coal-fired units that 

emit Hg and new and existing oil-fired 

units that emit nickel (Ni). Finally, as a 

third alternative, EPA proposed 

retaining the December 2000 finding 

and regulating Hg emissions from 

Utility Units under CAA section 

112(n)(1)(A).

Shortly thereafter, on March 16, 2004, 

EPA published in the Federal Register

a supplemental notice of proposed 

rulemaking (SNPR) entitled 

‘‘Supplemental Notice of 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.’’ In that notice, 

EPA proposed certain additional 

regulatory text, which largely governed 

the proposed section 111 standards of 

performance for Hg, which included a 

cap-and-trade program. The 

supplemental notice also proposed State 

plan approvability criteria and a model 

cap-and-trade rule for Hg emissions 

from coal-fired Utility Units. The 

Agency received thousands of 

comments on the proposed rule and 

supplemental notice. Some of the more 

significant comments relating to today’s 

action are addressed in this preamble. 

We respond to the other significant 

comments in the response to comments 

document entitled Response to 

‘‘Significant Public Comments on the 

Proposed Clean Air Mercury Rule,’’

which is in the docket. 

On December 1, 2004, EPA published 

in the Federal Register a notice of data 

availability (NODA) entitled ‘‘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.’’ EPA issued this notice: (1) 

To seek additional input on certain new 

data and information concerning Hg that 

the Agency received in response to the 

January 30, 2004 NPR and March 16, 

2004 SNPR; and (2) to seek input on a 

revised proposed benefits methodology 

for assessing the benefits of Hg 

regulation. EPA conducts benefits 

analysis for rulemakings consistent with 

the provisions of Executive Order (EO) 

12866. 

2. How did the public participate in 

developing the final rule? 

Upon signature on December 15, 

2003, the proposed rule was posted on 

the Agency’s Internet Web site for 

public review. Following publication of 

the NPR in the Federal Register (69 FR 

4652; January 30, 2004), a 60-day public 

comment period ensued. Concurrent 

public hearings were held in Research 

Triangle Park, NC, Philadelphia, PA, 

and Chicago, IL, on February 25 and 26, 

2004, at which time any member of the 

public could provide oral comment on 

the NPR. On March 16, 2004, a SNPR 

was published in the Federal Register

(69 FR 12398). On March 17, 2004, EPA 

announced that the public comment 

period on the NPR and SNPR had been 

extended to April 30, 2004. A public 

hearing on the SNPR was held in 

Denver, CO, on March 31, 2004, during 

which time members of the public could 

provide oral comment on any aspect of 

the NPR or SNPR. On May 5, 2004, EPA 

announced (69 FR 25052) that the 

public comment period for the NPR and 

SNPR had been reopened and extended 

until June 29, 2004. On December 1, 

2004, EPA published a NODA with a 

public comment period until January 3, 

2005 (69 FR 69864). In addition to the 

public comment process, EPA met with 

a number of stakeholder groups and has 

placed in the docket records of these 

meetings. Comments received after the 

close of the public comment period on 

the NODA (January 3, 2005), were not 

considered in the analyses. 

Approximately 500,000 public 

comments were received during this 

period, indicating wide public interest 

and access. 

C. What is the relationship between the 

final rule and the section 112 delisting 

action? 

In a separate Federal Register notice 

(70 FR 15994; March 29, 2005), EPA 

published a final Agency action which 

delists Utility Units under section 

112(n)(1)(A). In that action, EPA revised 

the regulatory finding that it issued in 

December 2000 pursuant to CAA section 

112(n)(1)(A), and based on that revision, 

removed coal- and oil-fired electric 

utility steam generating units (coal- and 

oil-fired Utility Units) from the CAA 

section 112(c) list. Section 112(n)(1)(A) 

of the CAA is the threshold statutory 

provision underlying this action. 

Congress enacted this special provision 

for Utility Units which gives EPA 

considerable discretion in determining 

whether Utility Units should be 

regulated under section 112. The 

provision requires EPA to conduct a 

study to examine the hazards to public 

health that are reasonably anticipated to 

occur as the result of hazardous air 

pollutant (HAP) emissions from Utility 

Units after imposition of the 

requirements of the CAA. The provision 

also provides that EPA shall regulate 

Utility Units under section 112, but only 

if the Administrator determines that 

such regulation is both ‘‘appropriate’’

and ‘‘necessary’’ considering, among 

other things, the results of the study. 

EPA completed the study in 1998 

(Utility Study), and in December 2000 

found that it was ‘‘appropriate and 

necessary’’ to regulate coal- and oil-fired 

Utility Units under CAA section 112. 

That December 2000 finding focused 

primarily on Hg emissions from coalfired Utility Units. In January 2004, EPA 

proposed revising the December 2000 

appropriate and necessary finding and, 

based on that revision, removing coaland oil-fired Utility Units from the 

section 112(c) list.

In a separate Federal Register notice 

(70 FR 15994; March 29, 2005), we 

revised the December 2000 appropriate 

and necessary finding and concluding 

that it is not appropriate and necessary 

to regulate coal- and oil-fired Utility 

Units under section 112. We took this 

action because we now believe that the 

December 2000 finding lacked 

foundation and because recent 

information demonstrates that it is not 

appropriate or necessary to regulate 

coal- and oil-fired Utility Units under 

section 112. Based solely on the revised 

finding, we are removing coal- and oilfired Utility Units from the section 

112(c) list and instead establishing 

standards of performance for Hg for new 

and existing coal-fired Utility Units, as 

defined in CAA section 111. 

The reasons supporting today’s action 

are described in detail in a separate final 

Agency action published in the Federal 

Register (70 FR 15994; March 29, 2005). 

D. What is the relationship between the 

final rule and other combustion rules? 

Revised NSPS for SO2, NOX, and 

particulate matter (PM) were proposed 

under CAA section 111 for Utility Units 

(40 CFR part 60, subpart Da) and 

industrial boilers (IB) (40 CFR part 60, 

subpart Db) on February 28, 2005 (70 FR 

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28609

9706). EPA earlier promulgated NSPS 

for Utility Units (1979) and for IB 

(1987). In addition, the EPA 

promulgated another combustionrelated standard under CAA section 

112: Industrial, commercial, and 

institutional boilers and process heaters 

(40 CFR part 63, subpart DDDDD) on 

September 13, 2004 (69 FR 55218). 

All of the rules pertain to sources that 

combust fossil fuels for electrical power, 

process operations, or heating. The 

applicability of these rules differ with 

respect to the size of the unit 

(megawatts electric (MWe) or British 

thermal unit per hour (Btu/hr)) they 

regulate, the boiler/furnace technology 

they employ, or the portion of their 

electrical output (if any) for sale to any 

utility power distribution systems. 

Any combustion unit that produces 

steam to serve a generator that produces 

electricity exclusively for industrial, 

commercial, or institutional purposes is 

considered an IB unit. A fossil fuel-fired 

combustion unit that serves a generator 

that produces electricity for sale is not 

considered to be a Utility Unit under the 

final rule if its size is less than or equal 

to 25 MWe. Also, a cogeneration facility 

that sells electricity to any utility power 

distribution system equal to more than 

one-third of their potential electric 

output capacity and more than 25 MWe 

during any portion of a year is 

considered to be an electric utility steam 

generating unit. 

Because of the similarities in the 

design and operational characteristics of 

the units that would be regulated by the 

different combustion rules, there are 

situations where coal-fired units 

potentially could be subject to multiple 

rules. An example of this situation 

would be cogeneration units that are 

covered under the proposed IB rule, 

potentially meeting the definition of a 

Utility Unit, and vice versa. This might 

occur where a decision is made to 

increase/decrease the proportion of 

production output being supplied to the 

electric utility grid, thus causing the 

unit to exceed the IB/electric utility 

cogeneration criteria (i.e. greater than 

one-third of its potential output capacity 

and greater than 25 MWe). As discussed 

below, EPA has clarified the definitions 

and applicability provisions to lessen 

any confusion as to which rule a unit 

may be subject to. 

II. Revision of Regulatory Finding on 

the Emissions of Hazardous Air 

Pollutants from Utility Units 

In a separately published Federal 

Register action (70 FR 15994; March 29, 

2005), EPA revised the regulatory 

finding that it issued in December 2000 

pursuant to CAA section 112(n)(1)(A), 

and based on that revision, removed 

coal- and oil-fired electric utility steam 

generating units (coal- and oil-fired 

Utility Units) from the CAA section 

112(c) source category list. Section 

112(n)(1)(A) of the CAA is the threshold 

statutory provision underlying the 

action. That provision requires EPA to 

conduct a study to examine the hazards 

to public health that are reasonably 

anticipated to occur as the result of HAP 

emissions from Utility Units after 

imposition of the requirements of the 

CAA. The provision also provides that 

EPA shall regulate Utility Units under 

CAA section 112, but only if the 

Administrator determines that such 

regulation is both appropriate and 

necessary considering, among other 

things, the results of the study. EPA 

completed the Utility Study in 1998, 

and in December 2000 found that it was 

appropriate and necessary to regulate 

coal- and oil-fired Utility Units under 

CAA section 112. That December 2000 

finding focused primarily on Hg 

emissions from coal-fired Utility Units. 

In light of the finding, EPA in December 

2000 announced its decision to list coaland oil-fired Utility Units on the CAA 

section 112(c) list of regulated source 

categories. In January 2004, EPA 

proposed revising the December 2000 

appropriate and necessary finding and, 

based on that revision, removing coaland oil-fired Utility Units from the CAA 

section 112(c) list. 

By a separately published Federal 

Register action (70 FR 15994; March 29, 

2005), we revised the December 2000 

appropriate and necessary finding and 

concluded that it is neither appropriate 

nor necessary to regulate coal- and oilfired Utility Units under CAA section 

112. We took this action because we 

now believe that the December 2000 

finding lacked foundation and because 

recent information demonstrates that it 

is not appropriate or necessary to 

regulate coal- and oil-fired Utility Units 

under CAA section 112. Based solely on 

the revised finding, we are removing 

coal- and oil-fired Utility Units from the 

CAA section 112(c) list. The reasons 

supporting today’s action are described 

in detail in the separately published 

Federal Register notice (70 FR 15994; 

March 29, 2005). 

EPA revised its December 2000 

determination and removed coal- and 

oil-fired Utility Units from the CAA 

section 112(c) source category list 

because we have concluded that utility 

HAP emissions remaining after 

implementation of other requirements of 

the CAA, including in particular the 

CAIR, do not cause hazards to public 

health that would warrant regulation 

under CAA section 112. 

The HAP of greatest concern from 

coal-fired utilities is Hg. Although we 

believe that after implementation of 

CAIR, remaining utility emissions will 

not pose hazards to public health, we do 

believe that it is appropriate to establish 

national, uniform Hg emission 

standards for new and modified coalfired utilities, as defined elsewhere in 

this preamble. Effective controls have 

been adequately demonstrated to reduce 

utility emissions; such reductions will 

further the goal of reducing the 

domestic and global Hg pool. 

Under the structure of the CAA, once 

we establish NSPS for new sources 

under section 111(b), we must, with 

respect to designated pollutants, 

establish 111(d) standards for existing 

sources. Specifically, section 111(d) 

provides that the Administrator ‘‘shall 

prescribe regulations which establish a 

procedure under which each State shall 

submit * * * a plan which establishes 

standards of performance for any 

existing source for any air pollutant 

* * * to which a standard of 

performance under this section would 

apply if such existing source were a new 

source.’’ Thus, because we deem it 

appropriate to establish NSPS for Hg 

emissions from new sources, we are 

obligated to establish NSPS Hg 

standards for existing sources as well.

III. Summary of the Final Rule 

Amendments 

A. Who is subject to the final rule? 

EPA is finalizing applicability 

provisions for 40 CFR part 60, subparts 

Da and HHHH that are consistent with 

historical applicability and definition 

determinations under the CAA section 

111 and Acid Rain programs. EPA 

realizes that these definitions are 

somewhat different because of 

differences in the underlying statutory 

authority. EPA believes that it is 

appropriate to finalize the applicability 

and definitions of the revised subpart 

Da NSPS consistent with the historical 

interpretations. Similarly, EPA believes 

that it is appropriate to finalize the 

applicability and definitions of subpart 

HHHH consistent with those of the Acid 

Rain and CAIR programs because of the 

similarities in their trading regimes. 

The 40 CFR part 60, subpart Da NSPS 

apply to Utility Units capable of firing 

more than 73 megawatts (MW) (250 

million Btu/hr; MMBtu/hr) heat input of 

fossil fuel. The current NSPS also apply 

to industrial cogeneration facilities that 

sell more than 25 MW of electrical 

output and more than one-third of their 

potential output capacity to any utility 

power distribution system. Utility Units 

subject to revised subpart Da are also 

28610 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

subject to 40 CFR part 60, subpart 

HHHH. 

The following units in a State shall be 

Hg Budget units (i.e., units that are 

subject to the Hg Budget Trading 

Program), and any source that includes 

one or more such units shall be a Hg 

Budget source, subject to the 

requirements of subpart HHHH: 

(a) Except as provided in paragraph 

(b), a stationary, fossil fuel-fired boiler 

or stationary, fossil fuel-fired 

combustion turbine serving at any time, 

since the start-up of a unit’s combustion 

chamber, a generator with nameplate 

capacity of more than 25 MWe 

producing electricity for sale. 

(b) For a unit that qualifies as a 

cogeneration unit starting on the date 

the unit first produces electricity, a 

cogeneration unit 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. If a unit qualifies as a 

cogeneration unit starting on the date 

the unit first produces electricity but 

subsequently no longer qualifies as a 

cogeneration unit, the unit shall be 

subject to paragraph (a) of this section 

starting on the day on which the unit 

first no longer qualifies as a 

cogeneration unit. 

The Hg provisions of 40 CFR part 60, 

subparts Da and HHHH apply only to 

coal-fired Utility Units (i.e., units where 

any amount of coal or coal-derived fuel 

is used at any time). This is similar to 

the definition that is used in the Acid 

Rain Program to identify coal-fired 

units. 

B. What are the primary sources of 

emissions, and what are the emissions? 

The final rule amendments add Hg to 

the list of pollutants covered under 40 

CFR part 60, subpart Da, by establishing 

emission limits for new sources and 

guidelines for existing sources. New 

sources (and existing subpart Da 

facilities), however, remain subject to 

the applicable existing subpart Da 

emission limits for NOX, SO2, and PM. 

C. What is the affected source? 

Only those coal-fired Utility Units for 

which construction, modification, or 

reconstruction is commenced after 

January 30, 2004, will be affected by the 

new-source provisions of the final rule 

amendments under CAA section 111(b). 

Coal-fired Utility Units existing on 

January 30, 2004, will be affected 

facilities for purposes of the CAA 

section 111(d) guidelines finalized in 

the final rule. 

D. What are the emission limitations 

and work practice standards? 

The following standards of 

performance for Hg are being finalized 

in the final rule for new coal-fired 40 

CFR part 60, subpart Da units:

Bituminous units: 0.0026 nanograms per 

joule (ng/J) (21 × 10¥6 pounds per 

megawatt-hour (lb/MWh)); 

Subbituminous units: 

Wet FGD—0.0053 ng/J (42 × 10¥6 lb/

MWh); 

Dry FGD—0.0098 ng/J (78 × 10¥6 lb/

MWh); 

Lignite units: 0.0183 ng/J (145 × 10¥6

lb/MWh); 

Coal refuse units: 0.00018 ng/J (1.4 x 

10¥6 lb/MWh); 

Integrated gasification combined cycle 

(IGCC) units: 0.0025 ng/J (20 × 10¥6

lb/MWh). 

All of these standards are based on 

gross energy output.

In addition, to complying with these 

standards, new units, along with 

existing coal-fired Utility Units will be 

subject to the cap-and-trade provisions 

being finalized in the final rule. The 

specifics of the cap are described below. 

Compliance with the final standards 

of performance for Hg will be on a 12-

month rolling average basis, as 

explained below. This compliance 

period is appropriate given the nature of 

the health hazard presented by Hg. 

E. What are the performance testing, 

initial compliance, and continuous 

compliance requirements? 

Under 40 CFR part 60, subpart Da, 

new or reconstructed units must 

commence their initial performance test 

by the applicable date in 40 CFR 60.8(a). 

Because compliance with the Hg 

emission limits in 40 CFR 60.45a is on 

a 12-month rolling average basis, the 

initial performance test consists of 12 

months of data collection with certified 

continuous monitoring systems, to 

determine the average Hg emission rate. 

New and existing units under 40 CFR 

part 60, subpart HHHH must certify the 

required continuous monitoring systems 

and begin reporting Hg mass emissions 

data by the applicable compliance date 

in 40 CFR 60.4170(b). 

Under 40 CFR 60.49a(s), the owner/

operator is required to prepare a unitspecific monitoring plan and submit the 

plan to the Administrator for approval, 

no less than 45 days before commencing 

the certification tests of the continuous 

monitoring systems. The final rule 

amendments require that the plan 

address certain aspects with regard to 

the monitoring system; installation, 

performance and equipment 

specifications; performance evaluations; 

operation and maintenance procedures; 

quality assurance (QA) techniques; and 

recordkeeping and reporting 

procedures. The final amendments 

require all continuous monitoring 

systems to be certified prior to the 

commencement of the initial 

performance test.

Mercury Emission Limits. Compliance 

with the final standard of performance 

for Hg will be determined based on a 

rolling 12-month average calculation. 

The rolling average is weighted 

according to the number of hours of 

valid Hg emissions data collected each 

month, unless insufficient valid data are 

collected in the month, as explained 

below. The Hg emissions are 

determined by continuously collecting 

Hg emission data from each affected 

unit by installing and operating a 

continuous emission monitoring system 

(CEMS) or an appropriate long-term 

method (e.g., sorbent trap) that can 

collect an uninterrupted, continuous 

sample of the Hg in the flue gases 

emitted from the unit. The final rule 

amendments will allow the owner/

operator to use any CEMS that meets the 

requirements in Performance 

Specification 12A (PS–12A), 

‘‘Specifications and Test Procedures for 

Total Vapor-phase Mercury Continuous 

Monitoring Systems in Stationary 

Sources.’’ Alternatively, a Hg 

concentration CEMS that meets the 

requirements of 40 CFR part 75, or a 

sorbent trap monitoring system that 

meets the requirements of 40 CFR 75.15 

and 40 CFR part 75, appendix K, may 

be used. Note that EPA has revised and 

renamed proposed Method 324, 

‘‘Determination of Vapor Phase Flue Gas 

Mercury Emissions from Stationary 

Sources Using Dry Sorbent Trap 

Sampling’’ as 40 CFR part 75, appendix 

K). 

For on-going quality control (QC) of 

the Hg CEMS, the final rule requires the 

calibration drift and quarterly accuracy 

assessment procedures in 40 CFR part 

60, appendix F, to be implemented. The 

quarterly accuracy tests consist of a 

relative accuracy test audit (RATA) and 

three measurement error tests (as 

described in PS 12A), using mercuric 

chloride (HgCl2) standards. In lieu of 

implementing the 40 CFR part 60, 

appendix F procedures, the owner or 

operator may QA the data from the Hg 

CEMS according to 40 CFR part 75, 

appendix B. For sorbent trap monitoring 

systems, and annual RATA is required, 

and the on-going QA procedures of 40 

CFR part 75, appendix K, must be met. 

The final rule requires valid Hg mass 

emissions data to be obtained for a 

minimum of 75 percent of the unit 

operating hours in each month. If this 

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28611

requirement is not met, the Hg data for 

the month are discarded. In each 12-

month cycle, if there are any months in 

which the data capture requirement is 

not met, data substitution is required. 

For the first such occurrence, the mean 

Hg emission rate for the last 12 months 

is reported, and for any subsequent 

occurrences, the maximum emission 

rate from the past 12 months is reported. 

For any month in which a substitute Hg 

emission rate is reported, the substitute 

emission rate is weighted according to 

the number of unit operating hours in 

that month when the 12-month rolling 

average is calculated. 

For new cogeneration units, steam is 

also generated for process use. The 

energy content of this process steam 

must also be considered in determining 

compliance with the output-based 

standard. Therefore, the owner/operator 

of a new cogeneration unit will be 

required to calculate emission rates 

based on electrical output to the grid 

plus half the equivalent electrical 

output energy in the unit’s process 

steam. The procedure for determining 

these Hg emission rates is described in 

40 CFR 60.50a(g), and is consistent with 

those currently used in 40 CFR part 60, 

subpart Da. 

The owner/operator of a new coalfired unit that burns a blend of fuels 

will develop a unit-specific Hg emission 

limitation; the unit-specific Hg emission 

rate will be used for the portion of the 

compliance period in which the unit 

burned the blend of fuels. The 

procedure for determining the emission 

limitations is outlined in 40 CFR 

60.45a(a)(5)(i). The owner/operator of an 

existing coal-fired unit that burns a 

blend of fuels will have to meet the 

limitations applicable under its unitspecific Hg allocation as outlined 

elsewhere in the final rule. 

F. What are the notification, 

recordkeeping, and reporting 

requirements? 

The final rule requires the owner or 

operator to maintain records of all 

information needed to demonstrate 

compliance with the applicable Hg 

emission limit, including the results of 

performance tests, data from the 

continuous monitoring systems, fuel 

analyses, calculations used to assess 

compliance, and any other information 

specified in 40 CFR 60.7 (General 

Provisions).

Mercury compliance reports are 

required semiannually, under 40 CFR 

60.51. Each compliance report must 

include the following information for 

each month of the reporting period: (1) 

The number of unit operating hours; (2) 

the number of unit operating hours with 

valid Hg emissions data; (3) the 

calculated monthly Hg emission rate; (4) 

the number of hours (if any) excluded 

from the emission calculations due to 

startup, shutdown and malfunction; (5) 

the 12-month rolling average Hg 

emission rate; and (6) the 40 CFR part 

60, appendix F data assessment report 

(DAR), or equivalent summary of QA 

test results if 40 CFR part 75 QA 

procedures are implemented. 

IV. Significant Comments and Changes 

Since Proposal 

A. Why is EPA not taking final action 

to regulate Ni emissions from oil-fired 

units? 

In the January 30, 2004 NPR, EPA 

proposed to regulate Ni emissions from 

oil-fired units based on information 

collected and reported in the Utility 

Study. During the ensuing public 

comment period on the January 30, 2004 

NPR, the March 2004 SNPR, and the 

December 2004 NODA, EPA received 

new information indicating that there 

were fewer oil-fired units in operation 

and that Ni emissions had diminished 

since the Utility Study. Accordingly, in 

the final rule, EPA is not taking final 

action on the proposal to regulate Ni 

emissions from oil-fired units. 

B. How did EPA select the regulatory 

approach for coal-fired units for the 

final rule? 

1. Applicability 

EPA is maintaining the discrete 

applicability definitions of ‘‘electric 

utility steam generating unit’’ that have 

historically been used under the CAA 

section 111 NSPS and the CAA section 

401 Acid Rain programs. 

As defined in 40 CFR 60.41a, an 

‘‘electric utility steam generating unit’’

means

any steam electric generating unit that is 

constructed for the purpose of supplying 

more than one-third of its potential electric 

output capacity and more than 25 MW 

electrical output to any utility power 

distribution system for sale. Any steam 

supplied to a steam distribution system for 

the purpose of providing steam to a steamelectric generator that would produce 

electrical energy for sale is also considered in 

determining the electrical energy output 

capacity of the affected facility.

In the NPR, EPA proposed to modify 

the definition of an ‘‘electric utility 

steam generating unit’’ to mean

any fossil fuel-fired combustion unit of more 

than 25 megawatts electric (MWe) that serves 

a generator that produces electricity for sale. 

A unit that cogenerates 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.

This proposed change in the 

definition was made as a part of the 

proposed CAA section 112 rulemaking 

alternative; however, it was EPA’s intent 

that this change also apply to the CAA 

section 111 rulemaking alternative and, 

therefore, EPA is finalizing it as part of 

the section 111 rule today. 

Only Utility Units that are fired by 

coal in any amount, or combinations of 

fuels that include coal, are subject to the 

final rule. Integrated gasification 

combined cycle units are also subject to 

the final rule. 

An affected source under NSPS is the 

equipment or collection of equipment to 

which the NSPS rule limitations or 

control technology is applicable. For the 

final rule, the affected source will be the 

group of coal-fired units at a facility (a 

contiguous plant site where one or more 

Utility Units are located). Each unit will 

consist of the combination of a furnace 

firing a boiler used to produce steam, 

which is in turn used for a steamelectric generator that produces 

electrical energy for sale. This definition 

of affected source will include a wide 

range of regulated units with varying 

process configurations and emission 

profile characteristics. 

EPA received comment requesting 

clarification of the applicability 

definition relating to whether a unit 

would be classified as a Utility Unit or 

an IB. For the purposes of 40 CFR part 

60, subpart Da, EPA believes that the 

definition being finalized today in 40 

CFR part 60, subpart Da clearly defines 

two categories of new sources—Utility 

Units and non-Utility Units (which 

could include IB units, etc.). That is, all 

three conditions must be met in order 

for a unit to be classified as a Utility 

Unit: (1) Must sell more than 25 MWe 

to any utility power distribution system; 

(2) any individual boiler must be 

capable of combusting more than 73 

MW (250 MMBtu/hr) heat input (which 

equates to 25 MWe on an output basis); 

and (3) if the unit is a cogeneration unit, 

it must sell more than one-third of its 

potential electric output capacity. The 

Agency’s historical interpretation of the 

40 CFR part 60, subpart Da definition 

has been that a boiler meeting the 

capacity definition (i.e., greater than 250 

MMBtu/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 40 CFR part 60, 

subpart Da. However, one or more new 

boilers with heat input capacities less 

than 250 MMBtu/hr each but connected 

to an electrical generator with a 

28612 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

generation capacity of greater than 25 

MWe would not be considered Utility 

Units under 40 CFR part 60, subpart Da 

because they individually do not meet 

the definition (they would be 

considered IB). 

Under the final 40 CFR part 60, 

subpart HHHH rule, EPA is continuing 

the definition of an Utility Unit used in 

the Acid Rain and CAIR trading 

programs. A coal-fired Utility Unit is a 

unit serving at any time, since the startup of a unit’s combustion chamber, a 

generator with nameplate capacity of 

more than 25 MWe producing electricity 

for sale. For a unit that qualifies as a 

cogeneration unit during the 12-month 

period starting on the date the unit first 

produces electricity and continues to 

qualify as a cogeneration unit, a 

cogeneration unit 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. If a unit qualifies as a 

cogeneration unit during the 12-month 

period starting on the date the unit first 

produces electricity but subsequently no 

longer qualifies as a cogeneration unit, 

the unit shall be subject to paragraph (a) 

of this definition starting on the day on 

which the unit first no longer qualifies 

as a cogeneration unit. These criteria are 

similar to the definition in the NPR and 

SNPR with the clarification that the 

criteria be determined on an annual 

basis. These criteria are the same used 

in the CAIR and are similar to those 

used in the Acid Rain Program to 

determine whether a cogeneration unit 

is a Utility Unit and the NOX SIP Call 

to determine whether a cogeneration 

unit is an Utility Unit or a non-Utility 

Unit.

2. Subcategorization 

Under CAA section 111(b)(2), the 

Administrator has the discretion to 

‘‘* * * distinguish among classes, 

types, and sizes within categories of 

new sources * * *’’ in establishing 

standards when differences between 

given types of sources within a category 

lead to corresponding differences in the 

nature of emissions and the technical 

feasibility of applying emission control 

techniques. At proposal, EPA examined 

a number of options for subcategorizing 

coal-fired Utility Units, including by 

coal rank and by process type. Based on 

the information available, EPA proposed 

to use five subcategories for establishing 

Hg limits based on a combination of 

coal rank and process type in the final 

rule (bituminous coal, subbituminous 

coal, lignite coal, coal refuse, and IGCC). 

EPA is today finalizing these five 

subcategories. 

EPA received numerous comments 

both in support of and in opposition to 

the proposed subcategorization 

approach for both new and existing 

Utility Units. Those commenters 

opposed to the proposed approach 

suggested several alternative 

approaches, including no 

subcategorization, combining 

bituminous and subbituminous coal 

ranks in one subcategory, a separate 

subcategory for Gulf Coast lignite, and a 

separate subcategory for fluidized bed 

combustion (FBC) units, among others. 

Other commenters indicated that any 

subcategorization approach should be 

‘‘fuel neutral,’’ i.e., not disadvantage any 

rank of coal or lead to fuel switching, 

and/or should not result in the loss of 

viability of any coal rank. 

Those commenters opposed to 

subcategorization generally argued that 

subcategorization can only be done on 

three criteria: Class, type, and size of 

sources and contended that the fact that 

coal rank is one of the characteristics of 

a coal-fired boiler does not mean it can 

be used for subcategorization. The 

commenters 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 

commenters stated that EPA had also 

provided unsupported claims that fuel 

switching would require significant 

modification or retooling of a unit. The 

commenters cited case law to support 

their contention that EPA’s proposed 

subcategorization is not permitted and 

stated that EPA’s justification for 

rejecting a no subcategorization option 

is factually and legally indefensible. 

A similar argument was presented by 

those commenters suggesting a single 

subcategory for bituminous and 

subbituminous coals. That is, given the 

extent of coal blending, particularly 

with respect to these two coal ranks, a 

single subcategory was appropriate. 

Further, the commenters argued that the 

proposed emission limits for the two 

subcategories disadvantaged bituminous 

coal. 

Commenters representing producers 

and users of Gulf Coast lignite suggested 

that a separate subcategory should be 

established for this coal because of its 

significantly higher Hg content, even 

when compared to Fort Union lignite. 

Gulf Coast lignite, therefore, is more 

difficult to control. 

Several commenters suggested that 

the American Society of Testing and 

Materials (ASTM) classification 

methodology for ranking coals is an 

inappropriate basis upon which to base 

subcategorization. This claim was made 

primarily because of the overlaps in the 

ASTM classification methodology and 

the fact that some Western coal seams 

are alleged to provide both bituminous 

and subbituminous coal ranks. Reliance 

on the ASTM methodology would create 

problems for the users of this coal in 

determining which subcategory they 

were in. 

Several commenters indicated that a 

separate subcategory for FBC units, is 

appropriate because FBC units use a 

fundamentally different combustion 

process than pulverized-coal (PC) units, 

making them a different type of source. 

Commenters concerned that the 

nation’s fuel supply not be jeopardized 

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 combined heat and 

power (CHP). The commenters stated 

that the final rule must facilitate—not 

discourage—the availability of an 

adequate and diverse fuel supply for the 

future, including all coal ranks, natural 

gas, nuclear energy, hydroelectric, and 

renewable sources. According to several 

commenters, the final rule must not 

aggravate the already precarious natural 

gas supply which is currently 

inadequate. 

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, 40 CFR part 60, 

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 emissions 

reductions on the various coal ranks. 

Although EPA has recently proposed 

(February 28, 2005; 70 FR 9706) to 

change the format of the NOX emission 

limits and to establish common SO2

emission limits regardless of coal rank, 

we believe that the conditions existing 

when we proposed 40 CFR 60, subpart 

Da in 1978 (e.g., the inability of the 

technologies to control SO2 and NOX

equally from all coal ranks) still exist for 

Hg and justify the use of 

subcategorization by coal rank for the 

Hg emission limits. At some point in the 

future, the performance of control 

technologies on Hg emissions could 

advance to the point that the rank of 

coal being fired is irrelevant to the level 

of Hg control that can be achieved 

(similar to the point reached by controls 

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28613

for SO2 and NOX emissions). If that 

occurs, EPA may consider adjusting the 

approach to Hg controls appropriately.

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) cannot 

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. To do otherwise entails a loss 

of efficiency and/or significant increases 

in maintenance costs. 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. 

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 nonagglomerating 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, 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. Further, 

EPA is perplexed by the comments 

indicating that Utility Units do not 

know the coal rank that they are firing 

and would incur additional costs to 

determine this for the purpose of 

establishing their subcategory. Electric 

utilities are currently required by law to 

report to the U.S. Department of Energy, 

Energy Information Administration 

(DOE/EIA) on one or more of six 

different forms, the rank of coal burned 

in each Utility Unit. EPA is not 

suggesting that these utilities do 

anything different in establishing their 

subcategory and respective emission 

limit. Utility Units that blend coals from 

different ranks would need to follow the 

specified procedures for establishing the 

appropriate emission limit for blended 

coals. EPA, therefore, believes that, at 

this time, coal rank is an appropriate 

and justifiable basis on which to 

subcategorize for the purposes of the 

final rule. 

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 the revised 

NSPS Hg emission limits, discussed 

later in this preamble, 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 become available, including 

that generated through the studies on 

emerging Hg control technologies by the 

DOE, and reassess issues of further 

subcategorizing lignites during the 

normal 8-year NSPS review cycle. 

With regard to FBC units, EPA agrees 

that such units operate and are designed 

differently than conventional PC boilers. 

However, with the exception of FBC 

units firing coal refuse, there was no 

clear indication from the available data 

that such units influenced the ultimate 

Hg control. That is, in some cases, FBC 

units were better than most with respect 

to their Hg emissions; in other cases, 

FBC units were worse 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. 

EPA’s modeling has shown minimal 

coal switching as a result of the final 

CAMR and CAIR actions. We believe 

that this rebuts the commenters’

suggestions that the final rule will cause 

one or another coal rank to be 

‘‘advantaged’’ or ‘‘disadvantaged’’ with 

respect to other coal ranks. Further, we 

do not believe that the final rule will 

have a negative impact on the nation’s 

energy security, employment rates, or 

energy reliability. 

New units designed to burn 

bituminous coals will still not be able to 

burn lignite coals (for example) and, 

thus, EPA believes that the need for 

subcategorization remains, even for new 

units. 

C. How did EPA determine the NSPS 

under CAA section 111(b) for the final 

rule? 

1. Criteria Under CAA Section 111 

CAA section 111 creates a program for 

the establishment of ‘‘standards of 

performance.’’ A ‘‘standard of 

performance’’ is ‘‘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 

the cost of achieving such reduction, 

any non-air quality health and 

environmental impacts and energy 

requirements), the Administrator 

determines has been adequately 

demonstrated.’’ (See CAA section 

111(a)(1).) 

For new sources, EPA must first 

establish a list of stationary source 

categories which the Administrator has 

determined ‘‘causes, or contributes 

significantly to, air pollution which may 

reasonably be anticipated to endanger 

public health or welfare.’’ (See CAA 

section 111(b)(1)(A).) EPA must then set 

Federal standards of performance for 

new sources within each listed source 

category. (See CAA section 

111(b)(1)(B).) Like CAA section 112(d) 

standards, the standards for new sources 

under section 111(b) apply nationally 

and are effective upon promulgation. 

(See CAA section 111(b)(1)(B).)

Section 111(b) covers any category of 

sources that causes or contributes to air 

pollution that may reasonably be 

anticipated to endanger public health or 

welfare and provides EPA authority to 

regulate new sources of such air 

pollution. EPA included Utility Units 

on the section 111(b) list of stationary 

sources in 1979 and has issued final 

standards of performance for new 

Utility Units for pollutants, such as 

NOX, PM, and SO2. (See 44 FR 33580; 

June 11, 1979; 40 CFR part 60, subpart 

Da.) Nothing in the language of section 

111(b) precludes EPA from issuing 

additional standards of performance for 

28614 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

other pollutants, including HAP, 

emitted from new Utility Units. 

Moreover, nothing in CAA section 

112(n)(1)(A) suggests that Congress 

sought to preclude EPA from regulating 

Utility Units under CAA section 111(b). 

Indeed, section 112(n)(1)(A) provides to 

the contrary, in that it calls for an 

analysis of utility HAP emissions ‘‘after 

imposition of the requirements’’ of the 

CAA, which we have reasonably 

interpreted to mean those authorities 

that EPA reasonably anticipates will be 

implemented and will reduce utility 

HAP emissions. 

2. Mercury Control Technologies 

At proposal, EPA stated that available 

information indicates that Hg emissions 

from coal-fired Utility Units are 

minimized in some cases through the 

use of PM controls (e.g., fabric filter or 

electrostatic precipitator (ESP)) coupled 

with a flue gas desulfurization (FGD) 

system. For bituminous-fired units, use 

of a selective catalytic reduction (SCR) 

or selective non-catalytic reduction 

(SNCR) system in conjunction with one 

of these systems may further enhance 

Hg removal. This SCR-induced 

enhanced Hg removal appears to be 

absent for subbituminous- and lignitefired units. 

The EPA believes the best potential 

way of reducing Hg emissions from 

IGCC units, on the other hand, is to 

remove Hg from the synthetic gas 

(syngas) before combustion. An existing 

industrial IGCC unit has demonstrated a 

process, using sulfur-impregnated 

activated carbon (AC) beds, that has 

proven to yield 90 to 95 percent Hg 

removal from the coal syngas. Available 

information indicates that this 

technology could be adapted to the 

electric utility IGCC units, and EPA 

believes this to be a viable option for 

new IGCC units. 

In selecting a regulatory approach for 

formulating emission standards to limit 

Hg emissions from new coal-fired 

Utility Units, the performance of the 

control technologies discussed on Hg 

above were considered. After 

considering the available information, 

EPA has determined that the technical 

basis (i.e., the best system of emission 

reduction which the Administrator 

determines has been adequately 

demonstrated, or best demonstrated 

technology, BDT) selected for 

establishing Hg emission limits for new 

sources is the use of effective PM 

controls (e.g., fabric filter or ESP) and 

wet or dry FGD systems on 

subbituminous-, lignite-, and coal 

refuse-fired units; effective PM controls, 

wet or dry FGD systems, and SCR or 

SNCR on bituminous-fired units; and 

AC beds for IGCC units. 

EPA received several public 

comments that disagreed with the EPA’s 

conclusion at proposal that Hg-specific 

controls for Utility Units, including 

activated carbon injection (ACI), will 

not be commercially available on a wide 

scale until 2010 or later. Arguments 

stated by these commenters included 

the following assertions: (a) Mercury 

control technologies are available now 

and EPA disregarded studies on 

emerging Hg control technologies by the 

DOE, the industry, and others. (b) 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. (c) Field 

testing of ACI has shown 90 percent 

capture of Hg. Units equipped with FGD 

units and fabric filters can obtain near 

90 percent removal of Hg. (d) Studies 

indicate that the cost of Hg controls 

would be comparable to the cost of 

controls for other pollutants and EPA 

disregarded these studies and the 

emerging state-of-the-art Hg control 

technologies. (e) Permits have been 

issued that will rely on sorbent injection 

technologies such as ACI (e.g., 

MidAmerican Energy, Council Bluffs 

Unit 4, issued by IA; and Wisconsin 

Public Service Corporation, Weston 

Unit 4, issued by WI). These permits 

show that Hg removal technologies 

capable of achieving more than 80 

percent control are available. 

EPA agrees, based on the limited test 

data available, that some coal-fired units 

have exhibited greater than 90 percent 

Hg reductions during short-term sorbent 

injection studies. However, not all units 

have been able to achieve this level of 

control, even with similar control 

technologies installed and no units have 

been able to achieve this level of control 

for an extended period of time. EPA 

disagrees with the commenters’

assessment, however, regarding the 

extent to which Hg-specific control 

technologies, including ACI, are 

currently available and on the time 

necessary for them to become 

commercially available. Although we do 

believe that these technologies have 

been currently demonstrated to be 

capable of achieving significant 

reductions in Hg emissions, we do not 

believe that they are available now for 

wide-spread or long-term 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. 

With the exception of one test that has 

lasted approximately 1 year, no Utility 

Unit has operated a Hg-specific control 

technology full-scale for longer than 

approximately a month. Further, the 

technologies have not been fully 

evaluated on any coal ranks for an 

extended period of time and have not 

even been evaluated under short-term 

conditions for some coal ranks (e.g., 

Gulf Coast lignite). In addition, other 

aspects of the use of Hg-specific control 

technologies (e.g., balance of plant, 

waste issues, atmospheric concerns) 

have not been fully addressed. Studies 

continue to (1) evaluate the impact of 

using both ACI and enhanced ACI (e.g., 

corrosion) on the coal-fired facility as a 

whole; (2) assess the impact of the ACI 

or enhanced ACI on the reuse and 

disposal of fly ash; and (3) evaluate the 

other atmospheric emissions and the 

impacts that may result from use of ACI 

or enhanced ACI (e.g., brominated 

dioxins emitted either directly or 

formed following emission to the 

atmosphere).

As discussed in the EPA Office of 

Research and Development’s (ORD) 

revised White Paper ‘‘Control of 

Mercury Emissions from Coal Fired 

Electric Utility Boilers: An Update’’

(OAR–2002–0056), since the release of 

the earlier White Paper ‘‘Control of 

Mercury Emissions from Coal-fired 

Electric Utility Boilers’’ (OAR–2002–

0056), additional data, mostly from 

short-term tests, have become available 

on Hg control approaches for Utility 

Units. Also, as noted above, the DOE 

and EPA have underway broad and 

aggressive research program, which will 

yield experience and data in the next 

few years. Accordingly, EPA continues 

to believe that ACI and enhanced 

multipollutant controls have been 

demonstrated to effectively remove Hg 

and will be available after 2010 for 

commercial application on most or all 

key combinations of coal rank and 

control technology to provide Hg 

removal levels between 60 and 90 

percent on individual Utility Units. 

Considering the progress made with 

halogenated AC sorbents and other 

chemical injection approaches to date, 

we now believe that optimized 

multipollutant controls may be available 

in the 2010 to 2015 timeframe for 

commercial application on most, if not 

all, key combinations of coal rank and 

control technology to provide Hg 

removal levels between 90 and 95 

percent. Such optimized controls could 

include use of sorbent (ACI or 

halogenated ACI) with enhanced SCR 

and/or enhanced FGD systems. These 

controls provide justification for a 2018 

cap at a level below what is projected 

to be achieved from SO2 and NOX

reduction levels alone. Although EPA is 

optimistic that such controls may be 

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28615

available for use on some scale prior to 

2018, it does not believe that such 

controls can be installed and operated 

on a national scale before that date. 

Based on these tests, on-going studies, 

and discussions, we do not believe that 

the Hg-specific technologies have 

demonstrated an ability to consistently 

reduce Hg emissions by 90 percent (or 

any other level) at the present time. 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. Further, although not 

ready for use in establishing a 

nationwide emission regulation at this 

time, EPA believes that installation of 

Hg-specific control technologies, 

including ACI, on a limited number of 

units is possible well in advance of the 

Phase II cap. The economic incentives 

inherent in the two-phase cap-and-trade 

program finalized today will serve to 

advance the technologies such that they 

are widely available for use in 

complying with the Phase II cap. 

3. Emissions Limitations 

EPA established the proposed 

emission limits by direct transfer from 

the proposed new-source CAA section 

112 emission limits. During the public 

comment period, it was pointed out by 

a number of commenters that under 

CAA 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 non-air quality 

health and environmental impact and 

energy requirements)’’ rather than ‘‘not 

be less stringent than the emission 

control that is achieved in practice by 

the best controlled similar source’’

under CAA section 112. The 

commenters pointed out that emission 

limits under both CAA sections 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 which ignores costs at what 

is referred to the floor level of control. 

Commenters further noted that the 

proposed emission limits would 

preclude new coal-fired units from 

being built and offered approved permit 

levels as evidence that the proposed 

limits were unachievable. 

EPA agrees with the commenters who 

indicated that the NSPS limits were not 

established in a manner consistent with 

the requirements of CAA section 111. 

Therefore, we 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 

arrived at the following NSPS Hg 

emission limits for the five 

subcategories:

Bituminous units: 0.0026 ng/J (21 ×

10¥6 lb/MWh); 

Subbituminous units: 

—Wet FGD units: 0.0053 ng/J (42 ×

10¥6 lb/MWh); 

—Dry FGD units: 0.0098 ng/J (78 ×

10¥6 lb/MWh); 

Lignite units: 0.0183 ng/J (145 × 10¥6

lb/MWh); 

Coal refuse units: 0.00018 ng/J (1.4 ×

10¥6 lb/MWh); 

IGCC units: 0.0025 ng/J (20 × 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 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 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 was determined to be the 

combination of a fabric filter and a FGD 

(wet or dry) system. However, recent 

test data reports show that a bituminous 

coal based system including a SCR, ESP 

and wet FGD may also be capable of 

meeting the performance limit set for 

bituminous coal-fired Utility Units, and 

this information was considered in 

setting the new source limits. 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 

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 

28616 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

2The 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 

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 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 × 10¥6 lb/MWh 

to 39 × 10¥6 lb/MWh; those for 

subbituminous-fired units range from 11 

× 10¥6 lb/MWh to 126 × 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 

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. 

Although EPA has re-analyzed the 

available data and revised its NSPS Hg 

emission limits, we continue to believe 

that these limits are of short-term value 

only. That is, the Hg cap being finalized 

today will be a greater long-term factor 

in constraining Hg emissions from new 

coal-fired Utility Units than will the 

new-source emission limits being issued 

today. In addition, the new source 

review (NSR) provisions provide an 

additional constraint on new-source 

emissions, further diminishing the 

importance of the revised new-source 

Hg emission limits. Essentially, the new 

source limits become a ‘‘backstop’’ for 

the trading program and other NSR 

requirements. Further, it is not our 

intention to exclude any type of 

domestic coal from the market. If 

information becomes available in the 

future that we feel adversely impacts the 

coals or the fuel market, we will review 

and reconsider these limits. 

As required by CAA section 111(a)(1), 

EPA has considered the cost of 

achieving the reductions in Hg 

emissions required by the new-source 

standards, the non-air quality health 

and environmental impacts arising from 

the implementation of the new-source 

standards and the energy requirements 

associated with the new-source 

standards and determined that they are 

all reasonable. (The costs of complying 

with CAMR as a whole are discussed 

briefly below, and in more detail in the 

two air dockets for the CAMR rule: 

Docket ID No. OAR–2002–0056 and 

Docket ID No. A–92–55. The non-air 

quality health and environmental 

impacts arising from the 

implementation of CAMR, as well as the 

energy requirements associated with 

CAMR, are discussed briefly below, and 

in more detail in Docket ID No. OAR–

2002–0056 and Docket ID No. A–92–55.)

D. How did EPA determine the Hg capand-trade program under CAA section 

111(d) for the final rule? 

1. Criteria Under CAA Section 111 for 

Standards of Performance for Existing 

Sources and Authority for Cap-andTrade Under CAA Section 111(d) 

CAA section 111(d)(1) authorizes EPA 

to promulgate regulations that establish 

a 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.’’

CAA 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 

requiring sources to hold allowances to 

cover their emissions on a one-for-one 

basis; by limiting overall allowances so 

that they cannot exceed specified levels 

(the ‘‘cap’’); and by 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 costeffectively; 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. 

The term ‘‘standard of performance’’

is not explicitly defined to include or 

exclude an emissions cap and allowance 

trading program. In the final rule, EPA 

interprets the term ‘‘standard of 

performance,’’ as applied to existing 

sources, to include a cap-and-trade 

program. This interpretation is 

supported by a careful reading of the 

section 111(a) definition of the term, 

quoted above: A requirement for a capand-trade program (i) constitutes a 

‘‘standard for emissions of air 

pollutants’’ (i.e., a rule for air 

emissions), (ii) ‘‘which reflects the 

degree of emission limitation 

achievable’’ (i.e., which requires an 

amount of emissions reductions that can 

be achieved), (iii) ‘‘through application 

of (a) * * * system of emission 

reduction’’ (i.e., in this case, a cap-andtrade program that caps allowances at a 

level lower than current emissions).2

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28617

Research Service, 2662. The 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.

3This 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 ‘‘A 

Legislative History of the Clean Air Act 

Amendments of 1977,’’ Congressional Research 

Service, 2559.

4Non-electricity generating units are also 

included in the States’ programs.

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 capand-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. 

Even if the 302(l) definition applied 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.3

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.

The final rule is wholly consistent with 

this prior CAA section 111(d) trading 

provision. 

Having interpreted the term ‘‘standard 

of performance’’ to include a cap-andtrade 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 nonair quality health and environmental 

impact and energy requirements) * * * 

has been adequately demonstrated.’’

(See CAA section 111(a)(1).) EPA has 

determined that a cap-and-trade 

program based on control technology 

available in the relevant timeframe is 

the best system for reducing Hg 

emissions from existing coal-fired 

Utility Units. 

Since the passage of the 1990 CAAA, 

EPA has had significant experience with 

the cap-and-trade program for utilities. 

The 1990 CAAA 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-forone 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 CAAA were enacted) to 

10.2 million tons in 2002 (the most 

recent year for which data is available). 

Emissions in 2002 were 9 percent lower 

than 2000 levels and 41 percent lower 

than 1980, despite a significant increase 

in electrical generation. As discussed 

elsewhere, 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-andtrade program for NOX emissions 

primarily from utilities.4 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.

The success of the Acid Rain cap-andtrade program for utility SO2 emissions, 

which EPA duplicated in large measure 

with the NOX SIP Call cap-and-trade 

program for, primarily, utility NOX

emissiofrom 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. 

2. What Is Justification for the National 

Hg Budget? 

The EPA believes that a carefully 

designed ‘‘multi-pollutant’’ approach, a 

program designed to control NOX, SO2, 

and Hg at the same time (i.e., CAIR 

implemented with CAMR), is the most 

effective way to reduce emissions from 

the power sector. One key feature of 

such an approach is the 

interrelationship of the timing and cap 

levels for NOX, SO2, and Hg. Our 

analyses show that the use of FGD (to 

reduce SO2 emissions) and SCR (to 

reduce NOX) also has the effect of 

controlling Hg emissions at the same 

time. We have designed the CAIR and 

CAMR approach to take advantage of 

this so-called Hg ‘‘co-benefit.’’ We 

believe, based on the results of 

sophisticated economic and 

environmental modeling analyses, that 

the Phase I Hg cap should be set at a 

level that reflects these co-benefits, and 

that additional controls designed 

specifically for Hg should not be 

required until after 2010. Furthermore, 

a multipollutant approach that focuses 

first on SO2 and NOX reductions will 

also achieve significant reductions in 

oxidized Hg. As explained elsewhere in 

this document, reductions in this Hg 

species are the most beneficial to 

reductions in U.S. Hg deposition. 

A Phase I cap based on ‘‘co-benefits’’

fulfills EPA’s obligation to set a 

standard of performance based on the 

best system of emissions reduction that 

has been adequately demonstrated. Both 

DOE and ORD research currently 

indicate that Hg-specific air pollution 

control technology, most notably 

sorbent injection, may one day allow 

facilities to reliably reduce Hg emissions 

to levels significantly below the ‘‘cobenefits’’ levels achieved through 

application of SO2 and NOX control 

technologies. However, Hg-specific 

technologies such as ACI have not been 

28618 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

demonstrated in practice on full-scale 

power plants for extended periods of 

time, nor are they considered 

commercially available at this time. 

Current information on these 

technologies, as outlined in the revised 

ORD White Paper, ‘‘Control of Mercury 

Emissions from Coal Fired Electric 

Utility Boilers: An Update,’’ (OAR–

2002–0056) is only adequate for us to 

conclude that such technologies are 

adequately demonstrated for use in the 

2010 to 2018 time-frame to allow for 

compliance with the CAMR Phase II Hg 

cap. Therefore, for purposes of setting 

the 2010 Hg cap, we conclude that Hg 

reductions achieved as a ‘‘co-benefit’’ of 

controlling SO2 and NOX under CAIR 

should dictate the appropriate cap level. 

We find that requiring SO2 and NOX

controls beyond those needed to meet 

the requirements of CAIR solely for 

purposes of further reducing Hg 

emissions by 2010 is not reasonable 

because the incremental cost 

effectiveness of such a requirement 

would be extraordinarily high. 

Furthermore, our analysis of 

engineering, financial, and other factors 

lead us to conclude under CAIR that a 

two-phased schedule was needed to 

allow the implementation of as much of 

the controls as feasible by an early date, 

with a later time for the remaining 

controls (see further discussion of this 

point below). 

a. CAIR Phase I Requirements. The 

CAIR-CAMR approach, which does not 

impose any Phase I Hg reduction 

requirements beyond those required to 

control SO2 and NOX emissions under 

Phase I of CAIR, sets the Phase I Hg 

emissions cap at 38 tpy. Thus, a cap of 

38 tons reflects the co-benefits level and 

is established as a fixed cap in the final 

rule. 

In the final CAIR, EPA evaluated the 

amounts of SO2 and NOX emissions in 

upwind States that contribute 

significantly to downwind fine particle 

(PM2.5) nonattainment, and the amounts 

of NOX emissions in upwind States that 

contribute significantly to downwind 

ozone nonattainment. That is, EPA 

determined the amounts of emissions 

that must be eliminated to help 

downwind States achieve attainment, by 

applying highly cost-effective control 

measures to Utility Units and 

determining the emissions reductions 

that would result. 

From past experience in examining 

multi-pollutant emissions trading 

programs for SO2 and NOX, EPA 

recognized that the air pollution control 

retrofits that result from a program to 

achieve highly cost-effective reductions 

are quite significant and can not be 

immediately installed. Such retrofits 

require a large pool of specialized labor 

resources, in particular, boilermakers, 

the availability of which will be a major 

limiting factor in the amount and timing 

of reductions. 

EPA also recognized that the 

regulated industry will need to secure 

large amounts of capital to meet the 

control requirements while managing an 

already large debt load, and is facing 

other large capital requirements to 

improve the transmission system. 

Furthermore, allowing pollution control 

retrofits to be installed over time 

enables the industry to take advantage 

of planned outages at power plants 

(unplanned outages can lead to lost 

revenue and adversely impact 

consumers) and to enable project 

management to learn from early 

installations how to deal with some of 

the engineering challenges that some 

plants/facilities/units pose, especially 

for the smaller units that often present 

space limitations. In addition, such 

phased installation of controls also 

minimizes any potential impact on the 

power grid and its stability and 

reliability.

In the final CAIR, EPA finalized a 

two-phased schedule for implementing 

the CAIR annual emission reduction 

requirements. The first phase includes 

two separate compliance deadlines: 

Implementation of NOX reductions are 

required by January 1, 2009 (covering 

2009–2014) and that for SO2 reductions 

by January 1, 2010 (covering 2010–

2014). The EPA based its final rule, 

among other things, on its analysis of 

engineering, financial, and other factors 

that affect the timing for installing the 

emission controls that would be most 

cost-effective—and are, therefore, the 

most likely to be adopted—for States to 

meet the CAIR requirements. Those air 

pollution controls are primarily 

expected to be retrofitted FGD systems 

(scrubbers) for SO2 and SCR systems for 

NOX on coal-fired power plants. 

The EPA’s projections showed a 

significant number of affected sources 

installing these controls. The final twophased schedule under CAIR allows the 

implementation of as much of the 

controls as feasible by an early date, 

with a later time for the remaining 

controls. The EPA has performed 

several analyses to verify the adequacy 

of the available boilermaker labor for the 

installation of CAIR’s Phase I controls. 

These analyses were not based just on 

using EPA’s assumptions for the key 

factors affecting the boilermaker 

availability, but also on the assumptions 

suggested by commenters for these 

factors to determine the robustness of 

our key conclusions. See final CAIR 

preamble for further discussion of this 

analysis and see CAMR docket for 

documents supporting this analysis. 

b. Utility Mercury Emission 

Reductions Expected as Co-Benefits 

From CAIR. The final CAIR requires 

annual SO2 and NOX reductions in 23 

States and the District of Columbia, and 

also requires ozone season NOX

reductions in 25 States and the District 

of Columbia. Many of the CAIR States 

are affected by both the annual SO2 and 

NOX reduction requirements and the 

ozone season NOX requirements. CAIR 

was designed to achieve significant 

emissions reductions of SO2 and NOX in 

a highly cost-effective manner to reduce 

the transport of fine particles that have 

been found to contribute to 

nonattainment. EPA analysis has found 

that the most efficient method to 

achieve the emissions reduction targets 

is through a cap-and-trade system on the 

power sector that States have the option 

of adopting. In fact, States may choose 

not to participate in the optional capand-trade program and may choose to 

obtain equivalent emissions reductions 

from other sectors. However, EPA 

believes that a region-wide cap-andtrade system for the power sector is the 

best approach for reducing emissions. 

The power sector accounted for 67 

percent of nationwide SO2 emissions 

and 22 percent of nationwide NOX

emissions in 2002. 

EPA expects that States will choose to 

implement the final CAIR program in 

much the same way they chose to 

implement their requirements under the 

NOX SIP Call. As noted above, under the 

NOX SIP Call, EPA gave States ozone 

season NOX reduction requirements and 

the option of participating in cap-andtrade program. In the final rulemaking, 

EPA analysis indicated that the most 

cost-efficient method to achieve 

reductions targets would be through a 

cap-and-trade program. Each affected 

State, in its approved SIP, chose to 

control emissions from Utility Units and 

to participate in the cap-and-trade 

program. 

Therefore, EPA anticipates that States 

will comply with CAIR by controlling 

Utility Unit SO2 and NOX emissions. 

Further, EPA anticipates that States will 

implement those reductions through the 

cap-and-trade approach, because the 

power sector represents the majority of 

national SO2 emissions and the majority 

of stationary NOX emissions, and 

represents highly cost-effective sources 

of reductions of SO2 and NOX (for 

further discussion of cost-effectiveness, 

see final CAIR preamble). EPA modeled 

a region-wide cap-and-trade system for 

the power sector in the States covered 

by CAIR, and this modeling projected 

that most reductions in NOX and SO2

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28619

would come through the installation of 

scrubbers, for SO2 control, and SCR, for 

NOX control (see Regulatory Impact 

Analysis (RIA) for CAIR and CAMR in 

docket). Scrubbers and SCR are proven 

technologies for controlling SO2 and 

NOX emissions and sources have 

installed them to comply with the Acid 

Rain trading program and the NOX SIP 

Call trading program. EPA’s modeling 

also projected that the installation of 

these controls would also achieve Hg 

emissions reductions as a co-benefit. 

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 

(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). That emissions 

testing has provided a better 

understanding of Hg emissions from 

Utility Units and their capture in 

pollution control devices. Mercury 

speciates into three basic forms, ionic, 

elemental, and particulate (particulate 

represents a small portion of total 

emissions). Ionic, or non-elemental, Hg 

compounds are the most important from 

a near-field deposition stand-point. In 

general, ionic Hg compounds are more 

readily controlled (because they tend to 

be water soluble) than is elemental Hg 

and the presence of chlorine 

compounds (which tend to be higher for 

bituminous coals) results in increased 

ionic Hg. 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. 

Given the history of the Acid Rain 

and NOX SIP Call trading programs, 

EPA anticipates that reductions in SO2

emissions will begin to occur before 

2010 (limited to a degree by the time 

and resources needed to install control 

technologies) because of the ability to 

bank SO2 emission allowances. 

Companies have an incentive to achieve 

greater and faster SO2 reductions than 

needed to meet the current Acid Rain 

cap because the excess allowances they 

generate can be ‘‘banked’’ and either 

later sold on the market or used to 

demonstrate compliance in 2010 and 

beyond at the facility that generated the 

excess allowances. Based on the 

analysis of CAIR, EPA’s modeling 

projects that Hg emissions would be 

38.0 tons (12 tons of non-elemental Hg) 

in 2010, 34.4 tons in 2015 (10 tons of 

non-elemental Hg), and 34.0 tons in 

2020 (9 tons of non-elemental Hg), about 

a 20 and 30 percent reduction (in 2010 

and 2015, respectively) from a 1999 

baseline of 48 tons. With respect to 

oxidized Hg, emissions in 2020 are 7.9 

tons compared to 20.6 tons in 2001. 

This 62 percent drop in oxidized Hg 

emissions is particularly important 

because this species of Hg deposits more 

readily. For further discussion of EPA 

modeling results and projected 

emissions see chapter 8 of the RIA.

c. Availability of Hg Technology. 

Additionally, EPA is setting a Hg 

emissions cap of 15 tpy in 2018 from 

coal-fired Utility Units. This cap reflects 

a level of Hg emissions reductions that 

exceeds the level that would be 

achieved solely as a co-benefit of 

controlling SO2 and NOX under CAIR. 

We conclude that this approach is 

warranted because we find Hg-specific 

air pollution control technologies such 

as ACI are adequately demonstrated for 

use sufficiently before 2018 to allow for 

their deployment across the field of 

units to comply with the Phase II cap in 

2018. This conclusion relies on the fact 

that the current-day pilot scale ACI 

projects at power plants should yield 

information that ought to be usable in 

implementing similar pilot scale 

projects at other facilities. Data from all 

of these pilot studies ultimately should 

allow companies to design full scale 

applications that should provide 

reasonable assurance that emissions 

limitations can be reliably achieved over 

extended compliance periods. We do 

not believe that such full scale 

technologies can be developed and 

widely implemented within the next 5 

years; however, it is reasonable to 

assume that this can be accomplished 

over the next 13 years. 

d. CAMR Reductions Requirements in 

2018. As discussed above, EPA is setting 

a cap of 15 tons in 2018 for coal-fired 

Utility Units. EPA projected future Hg 

emissions from the power generation 

sector using the Integrated Planning 

Model (IPM). The 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-regional, dynamic, deterministic 

linear programming model of the U.S. 

electric power sector. The EPA used 

IPM to project both the national level 

and the unit level of utility unit Hg 

emissions under different control 

scenarios. The EPA also used IPM to 

project the costs of those controls. 

In these IPM runs, EPA assumed that 

States would implement the Hg 

requirements through the Hg cap-andtrade program that EPA is establishing 

in the final rule. The cap-and-trade 

program is implemented in two phases, 

with a hard cap of 38 tons in 2010 (set 

at the co-benefits reduction under CAIR) 

and 15 tons in 2018. EPA modeling of 

CAA section 111 projects banking of 

allowances due to excess Hg reductions 

in the 2010 to 2017 timeframe for 

compliance with the cap in 2018 and 

beyond timeframe. A cap-and-trade 

program assures that those reductions 

will be achieved with the least cost. For 

that reason, EPA believes it reasonable 

to assume that States will adopt the 

program even though they are not 

required to do so. See 69 FR 4652, 

4700–4703 for a detailed discussion of 

the benefits of the cap-and-trade 

approach. 

As discussed above, under the CAIR 

scenario modeled by EPA, SO2 and NOX

emission reductions (and Hg co-benefit 

reductions) are projected to result from 

the installation of additional FGD and 

additional SCR units on existing coalfired generation capacity. Under the 

CAMR scenario modeled by EPA, units 

are projected to install SCR and 

scrubbers to meet their SO2 and NOX

requirements and take additional steps 

to address the remaining Hg reduction 

requirements under CAA section 111, 

including adding Hg-specific control 

technologies (model applies ACI), 

additional scrubbers and SCR, dispatch 

changes, and coal switching. Many of 

these reductions are projected to result 

from large units installing controls and 

selling excess allowances. Under the 

cap-and-trade approach we are 

projecting that Hg reductions result 

from units that are most cost effective to 

control, which enables those units that 

are not cost effective to install controls 

to use other approaches for compliance 

including buying allowances, switching 

fuels, or making dispatch changes. 

Based on the analysis of CAMR, EPA’s 

modeling projects that Hg emissions 

would be 31.3 tons in 2010, 27.9 tons 

in 2015, and 24.3 tons in 2020, about a 

35 percent reduction in 2010, about 42 

percent reduction in 2015, and about 50 

percent reduction in 2020 from a 1999 

baseline of 48 tons. For further 

discussion of EPA modeling results and 

projected emissions see chapter 8 of the 

RIA. EPA is not requiring further 

reductions by 2015, beyond the CAIR 

Phase I cap co-benefits, and, therefore, 

we are not adjusting Hg allowances 

downward beginning in 2015, rather 

28620 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

5Even assuming, arguendo, that the term 

‘‘standard of performance’’ prohibited an emissions 

cap and allowance trading program, the regulatory 

approach being employed in the final rule and the 

technologies on which EPA has based its cap 

calculations are consistent with and permitted by 

CAA section 111.

adjusting allowances in 2018. EPA 

maintains that it is not necessary for the 

2015 Hg cap to mirror the Hg co-benefits 

achieved in CAIR Phase II cap because: 

(1) These co-benefits would result 

automatically from the need to meet SO2

and NOX caps; the market will assure 

that the Hg reductions will occur; and 

(2) in 2018, the lower cap takes into 

account the reduced Hg emissions 

resulting from CAIR Phase II 

implementation. As we can see from the 

CAMR analysis, 2015 Hg emissions are 

projected to be substantially below the 

co-benefits projections under CAIR (34 

tons in 2015). Thus, EPA maintains that 

it is not necessary to have the 2015 Hg 

cap mirror the Hg co-benefits achieved 

in CAIR Phase II cap because the 2018 

cap ensures those reductions. 

As discussed in detail in the separate 

Federal Register notice (70 FR 15994; 

March 29, 2005) announcing EPA’s 

revision of its December 2000 regulatory 

determination and removing coal- and 

oil-fired Utility Units from the CAA 

section 112(c) list, EPA believes that the 

term ‘‘standard of performance’’ as used 

in CAA section 111 can include marketbased programs such a cap-and-trade 

program. The EPA also believes that in 

the context of a cap-and-trade program, 

the phrase ‘‘best system of emission 

reduction which (taking into account 

the cost of achieving such reduction and 

any non-air quality health and 

environmental impacts and energy 

requirements) the Administrator 

determines has been adequately 

demonstrated’’ refers to the combination 

of the cap-and-trade mechanism and the 

technology needed to achieve the 

chosen cap level. The EPA further 

believes that a particular technology can 

be adequately demonstrated to achieve 

a specified level of emissions reduction 

at one point in time, but, for a number 

of possible reasons, not be capable of 

achieving that level of reductions on a 

broad scale until a later point in time. 

For example, EPA might conclude that 

a particular technology is capable of 

achieving reductions in the emission of 

specified pollutants in the range of 90 

to 95 percent, while at the same time 

concluding that the technology is not 

currently commercially available and, 

therefore, not susceptible to widespread 

use. As a result, it would be 

inappropriate for EPA to establish a cap 

based on the use of such controls and 

require compliance with that cap in the 

near term, but reasonable to establish a 

cap on that basis and require 

compliance with that cap at a later point 

in time when the necessary technology 

becomes widely available.

CAA section 111 authorizes EPA to 

promulgate standards of performance 

based on systems of emission reduction 

that have been ‘‘adequately 

demonstrated.’’ Traditionally EPA has 

set its section 111 standards based on a 

determination that particular control 

technologies are ‘‘adequately 

demonstrated.’’ In the final rule, EPA 

has determined that the technologies 

necessary to achieve the emission cap 

limits for 2010 have been adequately 

demonstrated, and that the technologies 

necessary to achieve the 2018 caps have 

been adequately demonstrated to be 

available to achieve compliance with 

those limits by 2018.5

In Portland Cement Association v. 

EPA (486 F.2d 375) (DC Cir. 1973), the 

Court rejected the argument that the 

words ‘‘adequately demonstrated’’ in 

CAA section 111 meant that the relevant 

technology already must be in existence 

and that plants now in existence be able 

to presently meet the proposed 

standards. Rather, the CAA’s 

requirement that the degree of emission 

limitation be ‘‘adequately 

demonstrated’’ means that a plant now 

in existence must be able to meet the 

presently-effective standards for existing 

units, but that insofar as new plants and 

future requirements are concerned, 

section 111 authorizes EPA to ‘‘look 

toward what may fairly be projected for 

the regulated future, rather than the 

state-of-the-art at present.’’ The court 

said:

The Administrator may make a projection 

based on existing technology, though that 

projection is subject to the restraints of 

reasonableness and cannot be based on 

‘‘crystal ball’’ inquiry. 478 F.2d at 629. As 

there, the question of availability is partially 

dependent on ‘‘lead time,’’ the time in which 

the technology will have to be available. 

Since the standards here put into effect will 

control new plants immediately, as opposed 

to one or two years in the future, the latitude 

of projection is correspondingly narrowed. If 

actual tests are not relied on, but instead a 

prediction is made, ‘‘its validity as applied to 

this case rests on the reliability of [the] 

prediction and the nature of [the] 

assumptions.’’ (citation omitted)

See also Lignite Energy Council v. 

EPA, 198 F.3d 930 (DC Cir. 1999) 

(section 111 ‘‘looks toward what may 

fairly be projected for the regulated 

future, rather than the state of the art at 

present’’) (quoting Portland Cement). 

These cases address CAA section 111(b) 

standards for new sources, where 

achievement of the standards is 

mandated on a short-term basis. We 

believe that EPA standards set under the 

authority of CAA section 111(d), where 

the compliance deadlines are not so 

immediate, afford EPA significant 

flexibility, commensurate with the 

amount of lead-time being given to 

affected sources. The cases make clear 

that while a determination about a 

technology or performance standard’s 

achievability may not be based on 

‘‘mere speculation or conjecture,’’ a 

technology or standard that may not 

necessarily be considered ‘‘adequately 

demonstrated’’ at present nonetheless 

can be considered ‘‘adequately 

demonstrated’’ for a compliance date in 

the future. We have explained in today’s 

action why we believe both the 2010 

and 2018 emissions caps can be met. 

Since we believe that Hg-specific 

technologies capable of meeting the 

requirements of the 2018 emission 

limits will be available for broad 

commercial deployment by 2018, we 

believe those technologies are 

‘‘adequately demonstrated’’ for the 2018 

emission caps. 

Here, EPA has concluded that Hgspecific controls, such as ACI, have 

been adequately demonstrated as being 

effective in substantially reducing Hg 

emissions, but are not currently 

available for commercial application on 

a broad scale. As a result, EPA cannot 

establish a Hg emission cap based on 

the widespread use of Hg-specific 

controls and require compliance with 

that cap in the near term. The EPA has, 

therefore, set the level of the 2010 cap 

on Hg emissions on the basis of the 

reductions in Hg emissions achievable 

as co-benefits of efforts to reduce 

emissions of SO2 and NOX in 

accordance with CAIR. The EPA 

believes that establishing the Phase I 

cap on the basis of these co-benefits 

fulfills its obligation to set a standard of 

performance which is both based on the 

best system of emissions reductions that 

has been adequately demonstrated and 

achievable in the designated timeframe. 

As stated above, EPA has determined 

that Hg-specific controls have been 

adequately demonstrated as being 

effective in substantially reducing Hg 

emissions, but that such controls are not 

currently available for commercial 

application on a broad scale and, 

therefore, cannot serve as the basis for 

the 2010 Hg emissions cap. EPA 

believes, however, based on currently 

available information (ORD revised 

white paper ‘‘Control of Mercury 

Emissions from Coal Fired Electric 

Utility Boilers: An Update,’’ and DOE 

white paper ‘‘Mercury Control 

Technologies,’’ both of which may be 

found in the OAR–2002–0056), that 

such controls will be commercially 

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28621

available sometime after 2010 and can 

be installed and operational on a nationwide basis by 2018. The EPA has, 

therefore, established a Phase II Hg 

emissions cap based on the reductions 

in Hg emissions founded in the CAIR 

program and reductions that can be 

reasonably obtained through the use of 

Hg-specific controls. This cap is 

effective in 2018. That is, the 2018 cap 

is based on the level of Hg emissions 

reductions that will be achievable by the 

combined use of co-benefit (CAIR) and 

Hg-specific controls. The Phase II cap is 

timed such that these technologies can 

be installed and operational on a 

nationwide basis, i.e., until the 

technology becomes generally available. 

The need to achieve Hg reductions 

beyond those secured through the CAIR 

co-benefits program are wholly 

consistent with the Agency’s mission to 

leverage the monies spent domestically 

on global reductions of anthropogenic 

Hg emissions. As explained elsewhere 

in this preamble and the supporting 

docket, in order to significantly impact 

nationwide Hg deposition and, thus, 

human exposure to methylmercury 

(MeHg), the U.S. must be a leader in 

incentivizing global Hg emissions 

reductions. To that end, the Phase II cap 

serves as a driver for continued research 

and development of Hg-specific control 

technologies, while providing a global 

market for the application of such 

equipment, which ultimately may serve 

to significantly reduce the global pool of 

Hg emissions. The timing of the Phase 

II cap is such that new technologies can 

be developed, installed, demonstrated 

and commercially deployed with little 

impact to the stability of the power grid. 

EPA is today finalizing a NSPS for Hg 

for coal-fired Utility Units under CAA 

section 111 in lieu of a MACT standard 

for Hg. As set forth in greater detail 

below and in the related final rule, the 

Agency has determined that it is not 

‘‘necessary and appropriate’’ to establish 

a MACT standard under CAA section 

112 for electric utility steam generating 

units since utility HAP emissions 

remaining after implementation of other 

requirements of the CAA do not pose 

hazards to public health. For this 

reason, it is not necessary for the 

Agency to undertake any further 

analysis of Hg emissions from existing 

units in order to establish a MACT floor, 

as this information is irrelevant to the 

development of the NSPS. Nor is it 

necessary to conduct an additional costbenefit analysis of potential MACT 

standards since the Agency has 

concluded, as a matter of law and 

policy, that a MACT standard is not 

appropriate or necessary.

e. Cost-effectiveness of the Hg Cap in 

2018. As discussed above under CAMR, 

EPA projected future Hg emissions and 

the cost of those controls from the 

power generation sector using the IPM. 

In these IPM runs, EPA assumed that 

States would implement the Hg 

requirements through the Hg cap-andtrade program that EPA is establishing 

in the final rule. 

The 15-ton cap in 2018 is supported 

by cost considerations and the 

sophisticated economic modeling 

completed in support of the CAIR and 

CAMR regulations. These cost 

considerations include establishing a 

cap level that does not have significant 

impacts on energy supply and the cost 

of energy to the consumer. This 

modeling shows that the 15-ton Phase II 

cap will, in fact, require Hg-specific 

controls to be installed on certain Utility 

Units; however, such controls should 

not have any significant impact on 

power availability, reliability, or pricing 

to consumers. Moreover, our models 

predict that a 15-ton cap would not 

cause any significant shift in the fuels 

currently utilized by power plants or in 

the source of these fuels. For further 

discussion of EPA modeling results and 

projected costs see Chapter 8 of the RIA. 

3. State and Indian Country Emissions 

Reductions Requirements 

The EPA below also outlines a 

method for apportioning the nationwide budget to individual States and to 

coal-fired Utility Units located in Indian 

country. The EPA maintains that the 

emission budget provides an efficient 

method for achieving necessary 

reductions in Hg emissions (as 

described in earlier sections of this 

preamble), while providing substantial 

flexibility in implementing the program. 

a. Geographic Scope of Trading 

Program. The final rule will apply to all 

coal-fired Utility Units located in all 50 

States of the U.S., as well as those 

located in Indian country. (As used 

herein, the term ‘‘Indian country’’

generally refers to all areas within 

Indian reservations, dependent Indian 

communities, and Indian allotments. 

The EPA or, in appropriate 

circumstances, an individual Tribe 

generally will be responsible for 

implementing a trading program in 

Indian country.) As discussed further 

below, each State has been assigned a 

Statewide emissions budget for Hg. Each 

of these States must submit a State Plan 

revision detailing the controls that will 

be implemented to meet its specified 

budget for reductions from coal-fired 

Utility Units. States are not required to 

adopt and implement the proposed 

emission trading rule, but they are 

required to be in compliance with their 

statewide Hg emission budget. Should 

some States choose to achieve the 

mandated reductions by using an 

approach other than the proposed 

emissions trading rule, the geographic 

scope of the trading program would not 

be nationwide. Mercury emission 

budgets have also been assigned to coalfired Utility Units that will be affected 

by the final rule which are located in 

Indian country. The EPA generally will 

implement the emission trading rule for 

coal-fired Utility Units located in Indian 

country unless a Tribe seeks and obtains 

Treatment-as-a-State (TAS) status and 

submits a Tribal implementation plan 

(TIP) to implement the allocated Hg 

emissions budget. Eligible Tribes which 

choose to do so will be responsible for 

submitting a TIP analogous to the State 

plans discussed throughout this 

preamble, and, like States, can chose to 

adopt the Model Cap-and-Trade Rule 

described elsewhere in this action. 

b. State and Indian Country Emission 

Budgets. Each of the States and the 

District of Columbia covered by the final 

rule has been assigned a State emissions 

budget for Hg. A Hg emissions budget 

has also been assigned to each coal-fired 

Utility Unit located in Indian country. 

As discussed in detail below, these 

budgets were developed by totaling 

unit-level emissions reductions 

requirements for coal-fired electricity 

generating devices. States have the 

flexibility to meet these State budgets by 

participating in a trading program or 

establishing another methodology for Hg 

emissions reductions from coal-fired 

electric generating units, as discussed 

elsewhere in this action. States have the 

ability to require reductions beyond 

those required by the State budget. 

Tribes which choose to seek and obtain 

TAS status for that purpose, have the 

same flexibility in developing an 

appropriate TIP. The State Hg emission 

budgets are a permanent cap regardless 

of growth in the electric sector and, 

therefore, States have the responsibility 

of incorporating new units in their Hg 

emission budgets. Similarly, the Hg 

emission budgets allocated to coal-fired 

Utility Units located in Indian country 

act as a permanent cap and EPA or a 

Tribe which has obtained TAS status 

and is implementing an approved TIP 

has responsibility for incorporating new 

units into the allocated Hg emission 

budget. 

As proposed in the NPR and SNPR, 

EPA is finalizing a formula for 

determining the total amount of 

emissions for the Budget Trading 

Program for each specific State or coalfired Utility Unit located in Indian 

country using that same mechanism, 

28622 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

finalizing the amount of emissions for 

the Program within each State for 2010 

and 2018. That formula is the sum of the 

weighted shares for each affected Utility 

Unit in the State or Indian country, 

based on the proportionate share of their 

baseline heat input, adjusted to reflect 

the ranks of coal combusted by the unit 

during the baseline period, to total heat 

input of all affected units. As discussed 

further below, EPA is finalizing 

adjustment factors of 1 for bituminous, 

1.25 for subbituminous, and 3 for lignite 

coals. 

As discussed elsewhere in this 

preamble, new sources will comply 

with NSPS for Hg. In addition, as 

proposed in the NPR and SNPR, new 

sources will be covered under the Hg 

cap of the trading program, and will be 

required to hold allowances equal to 

their emissions. As discussed under the 

model cap-and-trade program, EPA is 

also finalizing the allocation 

methodology in the model cap-andtrade program a mechanism whereby 

these new sources do not receive an 

adjustment to their allocated share of 

the allowances (that reflects the rank of 

coal combusted). 

c. Rationale for Unit-level 

Allowances. Different ranks of coal may 

achieve different Hg reductions 

depending on the control equipment 

installed at the unit. In order to develop 

State and Indian country emissions 

budgets from unit allocations, EPA 

proposed that allowances would be 

distributed to States based on their 

share of total heat input. These 

allocations were then adjusted to reflect 

the concern that the installation of PM, 

NOX, and SO2 control equipment on 

different coal ranks results in different 

Hg removal. 

In the NPR and SNPR, for purposes of 

this hypothetical allocation of 

allowances, EPA proposed that each 

unit’s baseline heat input is adjusted to 

reflect the ranks of coal combusted by 

the unit during the baseline period. 

Adjustment factors of 1 for bituminous, 

1.25 for subbituminous, and 3 for lignite 

coals were proposed in the NPR. 

Alternatively, for purposes of this 

hypothetical calculation of State 

budgets, EPA took comment on using 

adjustment factors based on the MACT 

emission rates proposed in the NPR and 

the proportionate share of their baseline 

heat input to total heat input of all 

affected units.

Several commenters supported the 

proposed adjustment factors of 1 for 

bituminous, 1.25 for subbituminous, 

and 3 for lignite coals. Many 

commenters supported revisions to the 

adjustment factors, including a factor of 

1.5 for subbituminous. Several other 

commenters supported the use of no 

adjustment factors. Although supporting 

the use of multipliers for the coal ranks, 

some commenters argued that EPA 

should provide more scientific basis for 

the adjustment factors and 

recommended at minimum using 

adjustment factors based on the MACT 

approach. 

For the final rule, EPA is finalizing 

adjustment factors of 1 for bituminous, 

1.25 for subbituminous, and 3 for lignite 

coals based on the expectation that Hg 

in the coal ranks reacts differently to 

NOX and SO2 control equipment and 

that the heat input of the different coal 

ranks varies. The conclusion that Hg in 

each of the coals reacts differently to 

NOX and SO2 control equipment was 

based on information collected in the 

ICR as well as more recent data 

collected by EPA, DOE, and industry 

sources. This information, which was 

collected from units of various coal 

ranks and control equipment 

configuration, indicated differing levels 

of Hg removal. The test data indicated 

that installation of PM, NOX, and SO2

controls on plants burning bituminous 

coals resulted in greater Hg reduction on 

average than plants burning 

subbituminous coals or lignite coals. 

Likewise, the test data indicated that 

installation of PM, NOX, and SO2

controls on plants burning 

subbituminous coals resulted in 

somewhat greater Hg removal than 

plants burning lignite coals. On average, 

units burning lignite coal showed the 

least Hg removal of the three coal ranks. 

Further discussion of these adjustment 

factors can be found in the docket (see 

‘‘Technical Support Document for the 

Clean Air Mercury Rule Notice of Final 

Rulemaking, State, and Indian Country 

Emissions Budgets,’’ EPA, March 2005). 

These adjustment factors are 

considered to be reasonable based on 

the test data currently available. 

Although, we realize that these factors 

do not in all cases accurately predict 

relative rates of Hg emissions from 

Utility Units with NOX and SO2

controls, the values we have assigned to 

the factors will succeed in equitably 

distributing allowances to the States and 

Tribes on the basis of the affected 

industry within their borders. As 

discussed in the model cap-and-trade 

program, EPA is finalizing under the 

example allocation methodology that 

allocations by States to new sources will 

not be adjusted by coal type. 

d. Distribution of State and Indian 

Country Budgets. The trading program 

establishes a cap on Hg emissions for 

affected electric generating units of 38 

tpy starting in 2010 and 15 tpy in 2018. 

The unit-level emission allocations are 

the basis for establishing State and 

Indian country emission budgets with 

the State budgets equaling the total of 

the individual unit emission limits in a 

given State (see Table 1 of this 

preamble). Similarly, sufficient 

allowances have been allocated to coalfired Utility Units located in Indian 

country to cover the individual unit 

emission limits for those units. States 

also have the flexibility to not 

participate in the trading program or 

require more stringent Hg emissions 

reductions. States that do not participate 

in the trading program can establish 

their own methodology for meeting 

State Hg budgets by obtaining 

reductions from affected Utility Units. 

As proposed in the NPR and SNPR, EPA 

is finalizing the requirement that new 

coal-fired Utility Units will be subject to 

the State Hg emission cap. State budgets 

remain the same after the inclusion of 

new units and States have the 

responsibility of addressing new units 

in their respective emission budgets. 

Similarly, the budgets for coal-fired 

Utility Units located in Indian country 

will remain the same after the inclusion 

of new units and EPA or a Tribe with 

an approved TIP, as appropriate, has 

responsibility for addressing new units 

in the respective emission budget. 

EPA received comments from Tribes 

noting that only States currently receive 

allowances under the proposal, despite 

unit allocations being made to sources 

located in Indian country, and 

requesting that Tribes be accommodated 

into the cap-and-trade program. Because 

under CAA authority eligible Tribes 

may be treated in the same manner as 

States for CAA programs for 

reservations and for other areas within 

their jurisdiction, EPA agrees with the 

commenters that these Tribal sources 

need to be included in the cap-and-trade 

program, and the final CAMR 

establishes budgets for existing coalfired sources located in Indian country. 

In the final rule, EPA is establishing 

a Tribal budget for three existing coalfired Utility Units in Indian country. 

These are Navajo Generating Station 

(Salt River Project; Page, AZ), Bonanza 

Power Plant (Deseret Generation and 

Transmission Cooperative; Vernal, UT), 

and Four Corners Power Plant (Salt 

River Project/Arizona Public Service; 

Fruitland, NM). Navajo Generating 

Station and Four Corners Power Plant 

are on lands belonging to Navajo Nation, 

and Bonanza Power Plant is located on 

the Uintah and Ouray Reservation of the 

Ute Indian Tribe. Therefore, in addition 

to the 50 State budgets, the final rule 

also contains a budget for these Utility 

Units. The budget for units located in 

Indian country was calculated using the 

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28623

same methodology as State budgets. In 

the proposed rule, these three units in 

Indian country were erroneously 

included in the State budgets for 

Arizona, Utah, and New Mexico. The 

emissions budgets for the final rule for 

Arizona, Utah, and New Mexico are 

adjusted to reflect the movement of 

these sources to the Indian country 

emission budget. 

For areas of Indian country that do 

not currently have any coal-fired 

electricity generation, EPA intends to 

address any future planned construction 

of coal-fired Utility Units in those areas 

on a case-by-case basis, by working with 

the relevant Tribal government to 

regulate the Utility Units through either 

a TIP, if an eligible Tribe chooses to 

submit one, or Federal implementation 

plan (FIP). This is the same approach 

that is taken in the CAIR. EPA does not 

believe there is sufficient information to 

design allocation provisions for new 

generation which locates in Indian 

country at this time. Therefore, rather 

than create a Federal allowance setaside for Tribes, the EPA will work with 

Tribes and potentially affected States to 

address concerns regarding the equity of 

allowance allocations on a case-by-case 

basis as the need arises. The EPA may 

choose to revisit this issue through a 

separate rulemaking in the future. 

In the SNPR, because three States and 

the District of Columbia have no coalfired Utility Units, EPA proposed Hg 

emission budgets of zero tons for three 

States (Idaho, Rhode Island, and 

Vermont) and the District of Columbia. 

EPA did not receive adverse comments 

from these States on their proposed 

budgets and is finalizing Hg emission 

budgets of zero tons for three States 

(Idaho, Rhode Island, and Vermont) and 

the District of Columbia. If these States 

or the District of Columbia participate in 

the CAMR trading program, new coalfired Utility Units will be required to 

hold allowances equal to their 

emissions. As participants in the capand-trade program, these sources could 

buy allowances and meet their 

requirements. This is similar to 

situation that new units face under the 

existing Acid Rain Program. The final 

State and Indian country Hg emission 

budgets are presented in Table 1 of this 

preamble.

TABLE 1.—STATE HG EMISSION BUDGETS

State 

Budget

(tons) 

2010–2017 2018 and

thereafter 

Alaska .............................................................................................................................................................. 0.005 0.002 

Alabama ........................................................................................................................................................... 1.289 0.509 

Arkansas .......................................................................................................................................................... 0.516 0.204 

Arizona ............................................................................................................................................................. 0.454 0.179 

California .......................................................................................................................................................... 0.041 0.016 

Colorado .......................................................................................................................................................... 0.706 0.279 

Connecticut ...................................................................................................................................................... 0.053 0.021 

Delaware .......................................................................................................................................................... 0.072 0.028 

District of Columbia ......................................................................................................................................... 0 0 

Florida .............................................................................................................................................................. 1.233 0.487 

Georgia ............................................................................................................................................................ 1.227 0.484 

Hawaii .............................................................................................................................................................. 0.024 0.009 

Idaho ................................................................................................................................................................ 0 0 

Iowa ................................................................................................................................................................. 0.727 0.287 

Illinois ............................................................................................................................................................... 1.594 0.629 

Indiana ............................................................................................................................................................. 2.098 0.828 

Kansas ............................................................................................................................................................. 0.723 0.285 

Kentucky .......................................................................................................................................................... 1.525 0.602 

Louisiana .......................................................................................................................................................... 0.601 0.237 

Massachusetts ................................................................................................................................................. 0.172 0.068 

Maryland .......................................................................................................................................................... 0.49 0.193 

Maine ............................................................................................................................................................... 0.001 0.001 

Michigan ........................................................................................................................................................... 1.303 0.514 

Minnesota ........................................................................................................................................................ 0.695 0.274 

Missouri ............................................................................................................................................................ 1.393 0.55 

Mississippi ........................................................................................................................................................ 0.291 0.115 

Montana ........................................................................................................................................................... 0.378 0.149 

Navajo Nation Indian Country ......................................................................................................................... 0.601 0.237 

North Carolina .................................................................................................................................................. 1.133 0.447 

North Dakota .................................................................................................................................................... 1.564 0.617 

Nebraska .......................................................................................................................................................... 0.421 0.166 

New Hampshire ............................................................................................................................................... 0.063 0.025 

New Jersey ...................................................................................................................................................... 0.153 0.06 

New Mexico ..................................................................................................................................................... 0.299 0.118 

Nevada ............................................................................................................................................................. 0.285 0.112 

New York ......................................................................................................................................................... 0.393 0.155 

Ohio ................................................................................................................................................................. 2.057 0.812 

Oklahoma ......................................................................................................................................................... 0.721 0.285 

Oregon ............................................................................................................................................................. 0.076 0.03 

Pennsylvania .................................................................................................................................................... 1.78 0.702 

Rhode Island .................................................................................................................................................... 0 0 

South Carolina ................................................................................................................................................. 0.58 0.229 

South Dakota ................................................................................................................................................... 0.072 0.029 

Tennessee ....................................................................................................................................................... 0.944 0.373 

Texas ............................................................................................................................................................... 4.657 1.838 

Utah ................................................................................................................................................................. 0.506 0.2 

28624 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

TABLE 1.—STATE HG EMISSION BUDGETS—Continued

State 

Budget

(tons) 

2010–2017 2018 and

thereafter 

Ute Indian Tribe Reservation Indian Country .................................................................................................. 0.06 0.024 

Virginia ............................................................................................................................................................. 0.592 0.234 

Vermont ........................................................................................................................................................... 0 0 

Washington ...................................................................................................................................................... 0.198 0.078 

Wisconsin ......................................................................................................................................................... 0.89 0.351 

West Virginia .................................................................................................................................................... 1.394 0.55 

Wyoming .......................................................................................................................................................... 0.952 0.376 

As required by CAA section 111(a)(1), 

EPA has considered the cost of 

achieving the reductions in Hg 

emissions mandated by the section 

111(d) requirements for existing Utility 

Units, the non-air quality health and 

environmental impacts arising from the 

implementation of those requirements 

and the energy requirements associated 

with those requirements and 

determined that they are all reasonable. 

(The costs of complying with CAMR as 

a whole are discussed briefly below, and 

in more detail in the two air dockets for 

the CAMR rule: Docket ID No. OAR–

2002–0056 and Docket ID No. A–92–55. 

The non-air quality health and 

environmental impacts arising from the 

implementation of CAMR, as well as the 

energy requirements associated with 

CAMR, are discussed briefly below, and 

in more detail in Docket ID No. OAR–

2002–0056 and Docket ID No. A–92–55.) 

E. CAMR Model Cap-and-Trade 

Program 

1. What Is the Overall Structure of the 

Model Hg Cap-and-Trade Program? 

EPA is finalizing model rules for the 

CAMR Hg trading program that States 

can use to meet the emission reduction 

requirements in the CAMR. These rules 

are designed to be referenced by States 

in State rulemaking. State use of the 

model cap-and-trade rules helps to 

ensure consistency between the State 

programs, which is necessary for the 

market aspects of the trading program to 

function properly. Although not as 

effective as a legislated program such as 

the President’s Clear Skies legislation, 

this does allow the CAMR program to 

build on the successful Acid Rain 

Program. Consistency in the CAMR 

requirements from State-to-State 

benefits the affected sources, as well as 

EPA which administers the program on 

behalf of States. 

This section focuses on the structure 

which adds a model rule for the CAMR 

in 40 CFR part 60, subpart HHHH. 

Commenters (who supported the capan-trade approach) generally supported 

the proposed structure of the model 

rule. The final rule adopts the basic 

structure of this model rule. Later 

sections of the rule discuss specific 

aspects of the model rule that have been 

modified or maintained in response to 

comment. 

The model rules rely on the detailed 

unit-level emissions monitoring and 

reporting procedures of 40 CFR part 75 

and consistent allowance management 

practices. (Note that full CAMR-related 

State Plan requirements, i.e., 40 CFR 

part 60, are discussed elsewhere in this 

action.) Additionally, a discussion of 

the final revisions to parts 72 through 77 

in order to, among other things, 

facilitate the interaction of the title IV 

Acid Rain Program’s SO2 cap-and-trade 

provisions and those of the CAMR Hg 

trading program is provided elsewhere 

in this action. 

a. Road Map of Model Cap-and-trade 

Rule. The following is a brief ‘‘road 

map’’ to the final CAMR cap-and-trade 

program and is provided as a 

convenience to the reader. Please refer 

to the detailed discussions of the CAMR 

programmatic elements throughout the 

final rule for further information on 

each aspect. 

State Participation: 

• 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 the final rule 

with flexibility to modify sections 

regarding source Hg allocations. 

• For States that elect not to 

participate in an EPA-managed cap-andtrade program, their respective State Hg 

budgets will serve as a firm cap. 

Emission Allowances: 

• The CAMR cap-and-trade program 

will rely upon CAMR annual Hg 

allowances allocated by the States. 

Allocation of Allowances to Sources: 

• Hg allowances will be allocated 

based upon the States chosen allocation 

methodology. EPA’s model Hg rule has 

provided an example allocation, 

complete with regulatory text, that may 

be used by States or replaced by text 

that implements a States alternative 

allocation methodology. 

Emission Monitoring and Reporting 

by Sources: 

• Sources monitor and report their 

emissions using 40 CFR part 75. 

• 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. 

Compliance and Penalties: 

• For the Hg cap-and-trade program, 

any source found to have excess 

emissions must: (1) Surrender 

allowances sufficient to offset the excess 

emissions; and, (2) surrender 

allowances from the next control period 

equal to three times the excess 

emissions.

b. Comments Regarding the Use of a 

Cap-and-Trade Approach and the 

Proposed Structure. As discussed 

elsewhere in this action, many 

commenters did not support the capand-trade approach. For the many 

commenters, however, that did support 

the cap-and-trade approach, they also 

supported EPA’s overall framework of 

the model rule to achieve the mandated 

emissions reductions. Many 

commenters supported States having the 

flexibility to achieve emissions 

reductions however they chose, 

including developing their own capand-trade program or choosing not to 

participate. Other commenters did not 

support giving the States flexibility to 

participate in the program and 

supported requiring their participation, 

including imposing a uniform national 

allocation scheme. (Note that comments 

on specific mechanisms within the capand-trade program are discussed in the 

topic-specific sections that follow.) 

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28625

2. What is the Process for States to 

Adopt the Model Cap-and-Trade 

Program, and How Will it Interact With 

Existing Programs? 

a. Adopting the Hg Model Cap-andTrade Program. States may choose to 

participate in the EPA-administered 

cap-and-trade program, which is a fully 

approvable control strategy for 

achieving all of the emissions 

reductions required under the final rule 

in a more cost-effective manner than 

other control strategies. States may 

simply reference the model rules in 

their State rules and, thereby, comply 

with the requirements for Statewide 

budget demonstrations detailed 

elsewhere in this action. Specifically, 

States can adopt the Hg cap-and-trade 

program whether by incorporating by 

reference the CAMR cap-and-trade rule 

(40 CFR part 60, subpart HHHH) or 

codifying the provisions of the CAMR 

cap-and-trade rule, in order to 

participate in the EPA-administered Hg 

cap-and-trade program. 

As proposed, EPA is requiring States 

that wish to participate in the EPAmanaged cap-and-trade program to use 

the model rule to ensure that all 

participating sources, regardless of 

which State they are located, are subject 

to the same trading and allowance 

holding requirements. Further, requiring 

States to use the complete model rule 

provides for accurate, certain, and 

consistent quantification of emissions. 

Because emissions quantification is the 

basis for applying the emissions 

authorization provided by each 

allowance and emissions authorizations 

(in the form of allowances) are the 

valuable commodity traded in the 

market, the emissions quantification 

requirements of the model rule are 

necessary to maintain the integrity of 

the cap-and-trade approach of the 

program and therefore to ensure that the 

environmental goals of the program are 

met. 

b. Flexibility in Adopting Hg Model 

Cap-and-trade Rule. It is important to 

have consistency on a State-to-State 

basis with the basic requirements of the 

cap-and-trade approach when 

implementing a multi-State cap-andtrade program. Such consistency 

ensures the: Preservation of the integrity 

of the cap-and-trade approach so that 

the required emissions reductions are 

achieved; smooth and efficient 

operation of the trading market and 

infrastructure across all States so that 

compliance and administrative costs are 

minimized; and equitable treatment of 

owners and operators of regulated 

sources. However, EPA believes that 

some differences are possible without 

jeopardizing the environmental and 

other goals of the program. Therefore, 

the final rule allows States to modify the 

model rule language to best suit their 

unique circumstances with regard to 

allocation methodologies. 

States may develop their own Hg 

allocations methodologies, provided 

allocation information is submitted to 

EPA in the required timeframe. (Unitlevel allocations and the related 

comments are discussed in greater detail 

elsewhere in this action. This includes 

a discussion of the provisions 

establishing the advance notice States 

must provide for unit-by-unit 

allocations.) 

3. What Sources Are Affected Under the 

Model Cap-and-Trade Rule? 

In the January 2004 NPR, EPA 

proposed a method for developing 

budgets that assumed reductions only 

from coal-fired Utility Units. Utility 

Units were defined as: Coal-fired, noncogeneration electric utility steam 

generating units serving a generator 

with a nameplate capacity of greater 

than 25 MWe; and coal-fired 

cogeneration electric utility steam 

generating units meeting certain criteria 

(referred to as the ‘‘one-third potential 

electric output capacity criteria’’). In the 

SNPR, EPA proposed a model cap-andtrade rule that applied to the same 

categories of sources. We are finalizing 

the nameplate capacity cut-off that we 

proposed in the NPR for developing 

budgets and that we proposed in the 

SNPR for the applicability of the model 

trading rules. We are also finalizing the 

‘‘fossil fuel-fired’’ definition and the 

one-third electric output capacity 

criteria that were proposed. The actual 

rule language in the SNPR describing 

the sources to which the model rules 

apply is being slightly revised to be 

clearer in response to some comments 

that the proposed language was not 

clear. 

a. 25 MW Cut-off. EPA is retaining the 

25 MW cut-off for Utility Units for 

budget and model rule purposes. EPA 

believes it is reasonable to assume no 

further control of air emissions from 

smaller Utility Units. Available air 

emissions data indicate that the 

collective emissions from small Utility 

Units are relatively small and that 

further regulating their emissions would 

be burdensome, to both the regulated 

community and regulators, given the 

relatively large number of such units. 

For example, Hg emissions from Utility 

Units of 25 MWe or less in the U.S. 

represent about 1 percent of Hg 

emissions from Utility Units, 

respectively. Consequently, EPA 

believes that administrative actions to 

control this large group with small 

emissions would be inordinate and, 

thus does not believe these small units 

should be included. This approach of 

using a 25 MWe cut-off for Utility Units 

is consistent with existing SO2 and NOX

cap-and-trade programs such as the NOX

SIP Call (where existing and new Utility 

Units at or under this cut-off are, for 

similar reasons, not required to be 

included) and the Acid Rain Program 

(where this cut-off is applied to existing 

units and to new units combusting clean 

fuel). 

b. Definition of Coal-fired. EPA is 

finalizing the proposed definition of 

coal-fired, i.e., where any amount of 

coal or coal-derived fuel is used at any 

time. This is similar to the definition 

that is used in the Acid Rain Program 

to identify coal-fired units. EPA did not 

receive comments on this definition 

except that one commenter stated that 

coal refuse-fired plants should not be 

subject to CAMR. 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. 

c. Exemption for Cogeneration Units. 

As proposed, EPA is finalizing an 

exemption from the model cap-andtrade program for cogeneration units, 

i.e., units having equipment used to 

produce electricity and useful thermal 

energy for industrial, commercial, 

heating, or cooling purposes through 

sequential use of energy and meeting 

certain operating standards (discussed 

below). EPA is adopting, with some 

clarifications, the proposed definition of 

cogeneration unit and the proposed 

criteria for determining which 

cogeneration units qualify for the 

exemption from the model cap-andtrade programs.

(1) One-third Potential Electric 

Output Capacity. EPA is finalizing the 

one-third potential electric output 

capacity criteria in the NPR and SNPR 

with some clarifications. Under the final 

rule, the following cogeneration units 

are Utility Units: Any cogeneration unit 

serving a generator with a nameplate 

capacity of greater 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, which ever is greater, to any 

utility power distribution system for 

sale. These criteria are similar to the 

definition in the proposals with the 

clarification that the criteria be applied 

on an annual basis. These criteria are 

the same used in the CAIR and are 

similar to those used in the Acid Rain 

28626 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

Program to determine whether a 

cogeneration unit is a Utility Unit and 

the NOX SIP Call to determine whether 

a cogeneration unit is an Utility Unit or 

a non-Utility Unit. The primary 

difference between the proposed criteria 

and the one-third potential electric 

criteria for the Acid Rain and NOX SIP 

Call programs is that these programs 

applied the criteria to the initial 

operation of the unit and then to 3-year 

rolling average periods while the final 

CAMR criteria are applied to each 

individual year starting with the 

commencement of operation. EPA 

believes that using an individual year 

approach will streamline the 

application and administration of this 

exemption. 

Some commenters supported that the 

one-third criteria be applied on annual 

basis and supported that the criteria be 

consistent with CAIR and the Acid Rain 

program. Several commenters suggested 

exempting all cogeneration units instead 

of using the proposed criteria and cite 

the high efficiency of cogeneration as a 

reason for a complete exemption. EPA 

believes it is important to include in the 

CAMR program all units, including 

cogeneration units, that are substantially 

in the business of selling electricity. The 

proposed one-third potential electric 

output criteria described above are 

intended to do that. 

Inclusion of all units substantially in 

the electricity sales business minimizes 

the potential for shifting utilization, and 

emissions, from regulated to 

unregulated units in that business and 

thereby freeing up allowances, with the 

result that total emissions from 

generation of electricity for sale exceed 

the CAMR emission cap. The fact that 

units in the electricity sales business are 

generally interconnected through their 

access to the grid significantly increases 

the potential for utilization shifting. 

(2) Clarifying ‘‘For Sale.’’ Several 

commenters requested EPA confirm 

that, for purposes of applying the onethird potential electric output criteria, 

simultaneous purchases and sales of 

electricity are to be measured on a ‘‘net’’

basis, as is done in the Acid Rain 

Program. EPA confirms that, for 

purposes of applying the one-third 

potential electric output criteria in the 

CAMR program and the model cap-andtrade 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 electricityconsuming 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. 

(3) Multiple Cogeneration Units. 

Some commenters suggested aggregating 

multiple cogeneration units that are 

connected to a utility distribution 

system through a single point when 

applying the one-third potential electric 

output capacity criteria. According to 

the commenters, facilities may have 

some cogeneration units over the size 

threshold for inclusion in the rule, 

while others may be below it. These 

commenters suggested that it is not 

feasible to determine which unit is 

producing the electricity exported to the 

outside grid. EPA proposed 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. 

(4) Proposed Low-emitter Exclusion. 

In the January 30, 2004 NPR, EPA took 

comment on the possibility of excluding 

from the Phase II cap units with low Hg 

emissions rates (e.g., emitting less than 

25 pounds per year (lb/yr)). In the final 

rule, EPA is not finalizing a low-emitter 

exclusion. In proposing the possible 

low-emitter exclusion, EPA was 

concerned about the final rule’s impact 

on small business entities. EPA also 

indicated concern about units with low 

Hg emissions rate because the new, Hgspecific control technologies that we 

expect to be developed prior to the 

Phase II cap deadline may not 

practicably apply to such units. The 

1999 ICR data indicated that the 396 

smallest emitting coal-fired units 

account for less than 5 percent of total 

Hg emissions. EPA also indicated in the 

proposal that there is reason to believe 

that the 15 ton Phase II cap can be 

achieved in a cost-effective manner, 

even if the lowest emitting 396 units are 

excluded from coverage under this cap. 

Several commenters supported the 

provision excluding low-emitting units 

from the cap-and-trade program, while 

other commenters expressed opposition 

to the provision. Several commenters 

further suggested that, if the Agency 

excludes these units in a cap-and-trade 

program, the overall Hg 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). 

Some commenters supported other 

options for the exclusion, including an 

exclusion that started in Phase I, an 

exclusion based on 50 lb/yr, and an 

exclusion based on 100 to 140 MWe size 

cut-off.

As stated earlier, 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 (i.e., 

greater than 250 MWe). 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 sellers of allowances 

because they are already achieving 

emissions reductions. Therefore, EPA 

maintains that the low-emitter exclusion 

may not be the best way to address 

small entity burden. For the final rule, 

EPA is not finalizing a low-emitter 

exclusion and EPA recommends States 

address small 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 the 25 MWe 

size cut-off minimizes the burden for 

small business entities by ensuring that 

compliance is met in a least-cost 

fashion. 

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28627

4. How Are Emission Allowances 

Allocated to Sources? 

It is important to ensure that: The 

integrity of the cap-and-trade approach 

is preserved so that the required 

emissions reductions are achieved; the 

compliance and administrative costs are 

minimized; and source owners and 

operators are equitably treated. 

Accordingly, EPA believes that some 

limited differences, such as allowance 

allocation methodologies are possible 

without jeopardizing the environmental 

and other goals of the cap-and-trade 

program. 

a. Allocation of Hg Allowances. Each 

State participating in the EPAadministered cap-and-trade programs 

must develop a method for allocating 

(i.e., distributing) an amount of 

allowances authorizing the emissions 

tonnage of the State’s CAMR budget. 

Each State has the flexibility to allocate 

its allowances however they choose, so 

long as certain timing requirements are 

met. 

b. Required Aspects of a State Hg 

Allocation Approach. Although it is 

EPA’s intent to provide States with as 

much flexibility as possible in 

developing allocation approach, there 

are some aspects of State allocations 

that must be consistent for all States. All 

State allocation systems are required to 

include specific provisions that 

establish when States notify EPA and 

sources of the unit-by-unit allocations. 

These provisions establish a deadline 

for each State to submit to EPA its unitby-unit allocations for processing into 

the electronic allowance tracking 

system. Because the Administrator will 

then expeditiously record the submitted 

allowance allocations, sources will 

thereby be notified of, and have access 

to, allocations with a minimum lead 

time (about 3 years) before the 

allowances can be used to meet the Hg 

emission limit. 

The final rule finalizes the proposal to 

require States to submit unit-by-unit 

allocations of allowances for existing 

units for a given year no less than 3 

years prior to the allowance vintage 

year; this approach was supported by 

commenters. Requiring States to submit 

allocations and thereby provide a 

minimum lead time before the 

allowances can be used to meet the Hg 

emission limit 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. 

Allocating allowances less than 3 years 

in advance of the compliance year may 

reduce a CAMR unit’s ability to plan for 

and implement compliance and, 

consequently, increase compliance 

costs. For example, shorter lead time 

will reduce the period for buying or 

selling allowances and could prevent 

sources from participating in allowance 

futures markets, a mechanism for 

hedging risk and lowering costs. 

Further, requiring a uniform, 

minimum lead-time for submission of 

allocations allows EPA to perform its 

allocation-recordation activities in a 

coordinated and efficient manner in 

order to complete expeditiously the 

recordation and thereby promote a fair 

and competitive allowance market 

across the region. 

c. Flexibility and Options for a State 

Hg Allowance Allocations Approach. 

Allowance allocation decisions in a capand-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. Consequently, States are 

given latitude in developing their Hg 

allocation approach. Hg allocation 

methodology elements for which States 

will have flexibility include: 

• The cost of the allowance 

distribution (e.g., free distribution or 

auction); 

• The frequency of allocations (e.g., 

permanent or periodically updated); 

• The basis for distributing the 

allowances (e.g., heat-input or power 

output); and, 

• The use of allowance set-asides and 

their size, if used (e.g., new unit setasides or set asides for energy efficiency, 

for development of IGCC generation, for 

renewables, or for small units). 

Some commenters have argued 

against giving States flexibility in 

determining allocations, citing concerns 

about complexity of operating in 

different markets and about the 

robustness of the trading system. EPA 

maintains that offering such flexibility, 

as it did in the NOX SIP call, does not 

compromise the effectiveness of the 

trading program while maintaining the 

principle of federalism. 

A number of commenters have argued 

against allowing (or requiring) the use of 

allowance auctions, while others did 

not believe that EPA should recommend 

auctions. For the final rule, although 

there are some clear potential benefits to 

using auctions for allocating allowances 

(as noted in the SNPR), EPA believes 

that the decision regarding utilizing 

auctions rightly belongs to the States 

and Tribes. EPA is not requiring, 

restricting, or barring State use of 

auctions for allocating allowances. 

A number of commenters supported 

allowing the use of allowance set-asides 

for various purposes. In the final rule, 

EPA is leaving the decision on using setasides up to the States, so that States 

may craft their allocation approach to 

meet their State-specific policy goals. 

d. Example Allowance Hg Allocation 

Methodology. In the SNPR, EPA 

included an example (offered for 

informational guidance) of an allocation 

methodology that includes allowances 

for new generation and is 

administratively straightforward. EPA is 

including in today’s preamble, this 

‘‘modified output’’ example allocations 

approach, as was outlined in the SNPR. 

EPA maintains that the choice of 

allocation methodology does not affect 

the achievement of the specific 

environmental goals of the CAMR 

program. 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.

This example method involves inputbased allocations for existing coal units 

(with different ratios based on coal 

type), with updating to take into 

account new generation on a modifiedoutput basis. It also utilizes a new 

source set-aside for new units that have 

not yet established baseline data to be 

used for updating. Providing allowances 

for new sources would address a 

number of commenter concerns about 

the negative effect of new units not 

having access to allowances. 

As discussed in the methodology for 

determining State budgets, many 

comments were received on the use of 

coal adjustment factors for the 

allocation process. In the NPR and 

SNPR, EPA proposed 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 the final rule. In the 

final rule 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. 

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 capand-trade program for existing sources 

on the basis of historic baseline heat 

input. EPA proposed January 1, 2001 as 

the cut-off on-line date for considering 

units as existing units. The cut-off online date was selected so that any unit 

28628 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

meeting the cut-off date would have at 

least 5 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. Annual 

operating data is now available for 2003. 

EPA is finalizing January 1, 2001 as the 

cut-off on-line date for considering units 

as existing units because units meeting 

the cut-off date will have at least 5 years 

of operating data (i.e., data for 2000 

through 2004). 

The allowances for 2015 and later will 

be allocated from the State’s Hg budget 

annually, 6 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). As new units enter 

into service and establish a baseline, 

they are allocated allowances in 

proportion to their share of the total 

calculated heat input (which is existing 

unit heat input plus new units’

modified output). Allowances allocated 

to existing units slowly decline as their 

share of total calculated heat input 

decreases with the entry of new units. 

After 5 years of operation, a new unit 

will have an adequate operating 

baseline of output data to be 

incorporated into the calculations for 

allocations to all affected units. The 

average of the highest 3 years from these 

5 years will be multiplied by the heatinput conversion factor to calculate the 

heat input value that will be used to 

determine the new unit’s allocation 

from the pool of allowances for all 

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.

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. 

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. 

In its example, EPA is allocating to 

existing units by heat input and 

including adjustments by coal type (1.0 

for bituminous coals, 1.25 for 

subbituminous coals, and 3.0 for lignite 

coals). However, EPA is not finalizing 

adjustments by coal type with the 

modified output approach, because we 

do not want to favor any particular new 

coal generation. Allocating to new (not 

existing) sources on the basis of input 

would serve to subsidize less-efficient 

new generation. For a given amount of 

generation, more efficient units will 

have the lower fuel input or heat input. 

Allocating to new units based on heat 

input could encourage the building of 

less efficient units because they would 

get more allowances than an equivalent 

efficient, lower heat-input unit. The 

modified output approach, as described 

below, will encourage new, clean 

generation and will not reward less 

efficient new units. 

Under the example method, 

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 7,900 Btu per 

kilowatt-hour (Btu/kWh). The 7,900 

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 

EIA’s Annual Energy Outlook (AEO) 

2004. See Energy Information 

Administration, ‘‘Annual Energy 

Outlook 2004, with Projections to 

2025,’’ January 2004. Assumptions for 

DOE’s National Energy Modeling 

System (NEMS) model can be found at 

http://www.eia.doe.gov/oiaf/archive/

aeo04/assumption/tbl38.html). A single 

conversion rate will create consistent 

and level incentives for efficient 

generation, rather than favoring new 

units with higher heat rates. 

For new cogeneration units, their 

share of the allowances will be 

calculated by converting the available 

thermal output (Btu) of useable steam 

from a boiler or useable heat from a heat 

exchanger to an equivalent heat input 

by dividing the total thermal output 

(Btu) by a general boiler/heat exchanger 

efficiency of 80 percent. 

Steam and heat output, like electrical 

output, is a useable form of energy that 

can be utilized to power other 

processes. Because it would be nearly 

impossible to adequately define the 

efficiency in converting steam energy 

into the final product for all of the 

various processes, this approach focuses 

on the efficiency of a cogeneration unit 

in capturing energy in the form of steam 

or heat from the fuel input. 

Commenters expressed concern about 

a single conversion factor, arguing for 

different factors for different coals and 

technologies. 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 that, because all 

allocations are proportionally reduced 

after a new source is integrated into the 

market, higher conversion factors also 

lower allocations to existing sources. 

Today’s example method 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. In the SNPR, EPA 

proposed a level 2 percent set-aside for 

all years. 

Commenters supported a new source 

set-aside and one commenter pointed to 

EIA forecasts for coal to grow by 112 

gigawatts (GW) by 2025. 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 example new 

source set-aside would provide for that 

growth. 

Individual States using a version of 

the example method may want to adjust 

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28629

6Auctions could provide States with a less 

distortionary source of revenue.

7 5 percent of the allowances will go to a new 

source set-aside.

this initial 5-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 online 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 

unused set-aside allowances will be 

redistributed to existing units in 

proportion to their existing allocations. 

For the example method, EPA is 

assuming that new units will begin 

receiving allowances from the State- or 

Indian country-established 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. For 

instance, a source might 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 setaside, 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 NOX allocations method. 

Several commenters, for instance, have 

noted their desire for full output-based 

allocations (in contrast to the hybrid 

approach in the example above). In the 

past, the EPA had sponsored a workgroup to assist States wishing to adopt 

output-based NOX allocations for the 

NOX SIP Call. Documents from meetings 

of this group and the resulting guidance 

report (found at http://www.epa.gov/

airmarkets/fednox/workgrp.html)

together with additional resources such 

as the EPA-sponsored report ‘‘OutputBased Regulations: A Handbook for Air 

Regulators’’ (found at http://

www.epa.gov/cleanenergy/pdf/

output_rpt.pdf) can help States, should 

they choose to adopt any output-based 

elements in their allocation plans. 

As an another alternative example, 

States could decide to include elements 

of auctions into their allowance 

allocation programs.6 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 below.

During the first year of the trading 

program, 94 percent of the Hg 

allowances could, for example, be 

allocated to affected units with an 

auction held for the remaining 1 percent 

of the Hg allowances.7 Each subsequent 

year, an additional 1 percent of the 

allowances (for the first 20 years of the 

program), and then an additional 2.5 

percent thereafter, could be auctioned 

until eventually all the allowances are 

auctioned. With such a system, for the 

first 20 years of the trading programs, 

the majority of allowances could be 

distributed for free via the allocation. 

Allowances allocated for these earlier 

years are generally more valuable than 

allowances allocated for later years 

because of the time value of money. 

Thus, most emitting units could receive 

relatively more allowances in the early 

years of the program, when they would 

be facing the higher expenses of taking 

action to control their emissions.

Auctions could be designed by the 

State to promote an efficient 

distribution of allowances and a 

competitive market. Allowances could 

be offered for sale before or during the 

year for which such allowances may be 

used to meet the requirement to hold 

allowances. States will decide on the 

frequency and timing of auctions. Each 

auction could be open to any person, 

who could submit bids according to 

auction procedures, a bidding schedule, 

a bidding means, and by fulfilling 

requirements for financial guarantees as 

specified by the State. Winning bids, 

and required payments, for allowances 

could be determined in accordance with 

the State program and ownership of 

allowances will be recorded in the EPA 

Allowance Tracking System after the 

required payment is received. 

The auction could be a multipleround auction. Interested bidders could 

submit before the auction, one or more 

initial bids to purchase a specified 

quantity of Hg allowances at a reserve 

price specified by the State, specifying 

the appropriate account in the 

Allowance Tracking System in which 

such allowances will be recorded. Each 

bid could be guaranteed by a certified 

check, a funds transfer, or, in a form 

acceptable to the State, a letter of credit 

for such quantity multiplied by the 

reserve price. For each round of the 

auction, the State would announce 

current round reserve prices for Hg and 

determine whether the sum of the 

acceptable bids exceeds the quantity of 

such allowances available for auction. If 

the sum of the acceptable bids for Hg 

allowances exceeds the quantity of such 

allowances the State would increase the 

reserve price for the next round. After 

the auction, the State will publish the 

names of winning and losing bidders, 

their quantities awarded, and the final 

prices. The State will return payment to 

unsuccessful bidders and add any 

unsold allowances to the next relevant 

auction. 

In summary, the final rule provides, 

for States participating in the EPAadministered CAMR cap-and-trade 

program, 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. 

5. What Mechanisms Affect the Trading 

of Emission Allowances? 

a. Banking. (1) The CAMR NPR and 

SNPR Proposal for the Model Rule and 

Input from Commenters. Banking is the 

retention of unused allowances from 

one calendar year for use in a later 

calendar year. Banking allows sources to 

make reductions beyond required levels 

and ‘‘bank’’ the unused allowances for 

use later. Generally, banking has several 

advantages: (a) Banking results in early 

reductions as companies over-control 

their emissions; it is very unlikely that 

significant levels of early reductions 

would occur without banking. (b) 

Banked allowances can be used at any 

time so, they provide flexibility for 

companies to respond to growth and 

changing marketplace conditions over 

time. (c) Banking can result in emissions 

above the cap level in the later years of 

the compliance period, however, 

because the cap is permanent banking 

does not result in an increase in 

cumulative emissions. This is an 

important trade-off for getting early 

reductions.

28630 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

The January 30, 2004 NPR and March 

16, 2004 SNPR proposed that the Hg 

cap-and-trade program allow banking 

after the start of the Hg trading program, 

and that use of banked allowances be 

allowed without restrictions. 

Comments Regarding Unrestricted 

Banking After the Start of the Hg Capand-Trade Program. Many commenters 

supported EPA’s proposal to allow 

unrestricted banking and the use of 

banked Hg allowances. Further, they 

agreed that banking with no restrictions 

on use will encourage early emissions 

reductions, stimulate the trading 

market, encourage efficient pollution 

control, and provide flexibility to 

affected sources in meeting 

environmental objectives. A few 

commenters opposed EPA’s proposal of 

banking without restriction after the 

start of the Hg cap-and-trade program. 

These commmenters generally pointed 

out that allowing unrestricted banking 

delays the achievement of the Phase II 

cap. 

(2) The Final Hg Model Rule and 

Banking. Banking of allowances 

provides flexibility to sources, 

encourages earlier or greater reductions 

than required, stimulates the market, 

and encourages efficiency. EPA has 

acknowledged that allowing 

unrestricted banking after the start of 

the program will result in the Phase II 

cap being achieved over a longer 

timeframe but it will also yield greater 

cumulative reductions early in the 

program than would be required by the 

program cap. Furthermore, banking does 

not reduce the overall reduction 

requirement, and will not affect 

cumulative Hg reductions over the full 

course of the program. EPA is finalizing 

that banking will be allowed without 

restriction after the start of the Hg capand-trade program. 

b. Hg Safety Valve Mechanism. (1) 

The CAMR NPR and SNPR Proposal for 

the Safety Valve and Input from 

Commenters. In the January 30, 2004 

NPR and March 16, 2004 SNPR, EPA 

proposed a safety valve provision that 

set the maximum cost purchasers must 

pay for Hg emissions allowances. This 

provision was intended to address some 

of the uncertainty associated with the 

cost of Hg control. 

Under the safety valve mechanism, 

the price of allowances is effectively 

(although not legally) capped. Sources 

may purchase allowances from 

subsequent year budgets at the safetyvalve price at any time. However, it is 

unlikely they would do so unless the 

market allowance price exceeded the 

safety valve price. The purpose of this 

provision is to minimize unanticipated 

market volatility and provide more 

market information that industry can 

rely upon for compliance decisions. The 

safety valve mechanism ensures the cost 

of control does not exceed a certain 

level, but also ensures that emissions 

reductions are achieved. The future year 

cap is reduced by the borrowed amount, 

ensuring the integrity of the caps. 

EPA proposed a price of $2,187.50 for 

a Hg allowance (covering one ounce) 

and that this price would be annually 

adjusted for inflation. EPA also 

proposed that the permitting authority 

deduct corresponding allowances from 

future allowance budgets. EPA noted 

that the safety valve mechanism would 

need to be incorporated into a State’s 

chosen allocations methodology to 

ensure the availability of un-distributed 

allowances from which purchasers 

could borrow. Making allowances 

available through the safety valve 

without taking them away from future 

budgets would undermine the integrity 

of the cap. 

Comments regarding the need for 

safety valve. Many commenters 

supported the inclusion of a safety valve 

to reduce market uncertainty and 

guarantee a maximum price at which 

emissions allowances can be purchased. 

These commenters generally cited 

uncertainty pertaining to technology 

availability and cost as the reason for 

their support. Other commenters 

suggested that the safety valve provision 

should be eliminated. Some of these 

commenters noted that EPA’s cost 

analysis of the cap-and-trade program 

was projecting that a safety valve price 

of $2,187.50/ounce would be triggered, 

delaying achievement of the cap. Other 

commenters noted that the safety valve 

provision could contribute to Hg ‘‘hot 

spots,’’ and that the provision is counter 

to market-based approach. 

(2) The Final Hg Model Rule and the 

Safety Valve. EPA will not include a Hg 

safety valve mechanism in the final rule. 

EPA maintains that the safety valve 

mechanism is not necessary to address 

market volatility associated with Hg 

reduction requirements under CAMR. 

EPA maintains that the design of the 

CAMR trading program, a two-phased 

approach of 38 tpy in 2010 and 15 tpy 

in 2018, reduces the likelihood of 

extreme market volatility that the safety 

valve was intended to mitigate. The 

program includes a cap in the first 

phase based on the Hg co-benefit 

reductions expected under the CAIR 

program for SO2 and NOX. In addition, 

the program provides lead time for 

compliance for each phase and allows 

banking of allowances in the first phase, 

which provides flexibility in achieving 

emissions reductions under the second 

phase. EPA experience with the Acid 

Rain program and the NOX Budget 

Program indicates that market volatility 

has not been a significant factor in these 

trading programs, and that it has been 

greater during the early years of the 

programs. EPA believes that setting the 

Phase I Hg cap at CAIR co-benefits 

should limit market volatility caused by 

uncertainty early in the program. 

EPA also maintains that the timelines 

and caps of the CAMR trading program 

achieve emissions reductions without 

unacceptable costs. The Phase I cap of 

the program is based on co-benefit 

reduction expected under the CAIR 

program, and the Phase II cap represents 

a level of reductions that EPA has 

determined can be achieved without 

very high marginal costs, especially 

given recent advancements in the area 

of Hg control technology. EPA’s 

economic modeling of the CAMR 

program (see chapter 8 of the RIA) 

projects that in the first phase of the 

program, the marginal cost of control 

remains under $35,000 per lb (the 

proposed safety valve price). Although 

in the second phase of the CAMR 

program, economic modeling projects 

marginal costs above this level, the 

modeling assumes no improvements in 

the cost of Hg control technology over 

time. Given that this is the first time Hg 

from coal-fired utilities is being 

addressed by Federal regulation, and 

given the current level of research and 

demonstration of Hg control 

technologies, control cost are expected 

to improve over time. Because of the 

uncertainty around Hg control 

technologies like ACI, EPA has 

conservatively included no cost 

improvement in its basic modeling 

assumptions. Given the development in 

advanced sorbents for ACI, EPA 

examined the impact of Hg technology 

improvements by providing a lower cost 

Hg control option in future years. That 

modeling projected Hg marginal costs 

below $35,000/lb. 

6. What Are the Source-Level Emissions 

Monitoring and Reporting 

Requirements? 

The final rule adds subpart I to 40 

CFR part 75. Subpart I specifies the 

basic emission monitoring requirements 

necessary to administer a Hg trading 

program for new and existing Utility 

Units. The final rule also revises the 

regulatory language at several places in 

40 CFR parts 72 and 75, to include 

specific Hg monitoring definitions and 

provisions, in support of 40 CFR part 

75, subpart I. Affected units will be 

required to comply with these Hg 

monitoring provisions, if and when 40 

CFR part 75, subpart I is adopted by 

State or Tribal agencies as part of a Hg 

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28631

cap-and-trade program. The changes to 

40 CFR part 75 are discussed in greater 

detail elsewhere in this action.

Monitoring and reporting of an 

affected source’s emissions are integral 

parts of any cap-and-trade program. 

Consistent and accurate measurement of 

emissions ensures that each allowance 

actually represents one ounce of 

emissions and that one ounce of 

reported emissions from one source is 

equivalent to one ounce of reported 

emissions from another source. This 

establishes the integrity of each 

allowance and instills confidence in the 

market mechanisms that are designed to 

provide sources with flexibility in 

achieving compliance. Those 

flexibilities result in substantial cost 

savings to the industry. 

Given the variability in the unit type, 

manner of operation, and fuel mix 

among coal-fired Utility Units, EPA 

believes that emissions must be 

monitored continuously in order to 

ensure the precision, reliability, 

accuracy, and timeliness of emissions 

data that support the cap-and-trade 

program. The final rule allows two 

methodologies for continuously 

monitoring Hg emissions: (1) Hg CEMS; 

and (2) sorbent trap monitoring systems. 

Based on preliminary evaluations, EPA 

believes it is reasonable to expect that 

both technologies will be welldeveloped by the time a Hg emissions 

trading program is implemented. 

In the SNPR, EPA solicited comment 

on two alternative approaches for the 

continuous monitoring of Hg emissions. 

In the first alternative, most sources 

would be required to use CEMS, with 

low-emitting sources having Hg mass 

emissions at or below a specified 

threshold value being allowed to use 

sorbent trap monitoring systems. In the 

second proposed alternative, all sources 

would be allowed to use either CEMS or 

sorbent trap monitoring systems. 

However, the sorbent trap systems 

would be subject to QA procedures 

comparable to those required for a 

CEMS, and the QA procedures would be 

more stringent for units with Hg mass 

emissions above a specified threshold 

value. The final rule adopts a 

modification of the second proposed 

alternative. Sorbent trap monitoring 

systems may be used ‘‘across the 

board,’’ provided that rigorous QA 

procedures are implemented. These QA 

requirements, which are found in 40 

CFR 75.15 and in 40 CFR part 75, 

appendices B and K, are based on input 

from commenters and from EPA’s own 

research. The proposed rule would have 

required quarterly relative accuracy 

audits for many of the sorbent trap 

systems. The final rule replaces this 

proposed requirement with alternative 

procedures that are more suitable for 

sorbent trap systems. 

For affected sources with Hg 

emissions at or below a specified 

threshold value, 40 CFR 75.81(b) of the 

final rule provides additional regulatory 

flexibility by allowing default Hg 

concentrations obtained from periodic 

Hg emission testing to be used to 

quantify Hg mass emissions, instead of 

continuously monitoring the Hg 

concentration. The use of this low mass 

emitter option is restricted to sources 

that emit no more than 29 lb (464 

ounce) of Hg per year. The rationale for 

this threshold is given elsewhere in this 

action. 

The amendments to 40 CFR part 75 

set forth the specific monitoring and 

reporting requirements for Hg mass 

emissions and include the additional 

provisions necessary for a cap-and-trade 

program. The provisions of 40 CFR part 

75 are used in both the Acid Rain and 

the NOX Budget Trading programs, and 

most sources affected by the final rule 

are already meeting the requirements of 

40 CFR part 75 for one or both of those 

programs. 

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). As stated 

elsewhere in this action, EPA does not 

believe that utility-attributable hot spots 

will be an issue after implementation of 

CAIR and CAMR. Nevertheless, we are 

committed to monitoring closely the 

effects of utility emissions. We commit 

to, and retain authority to, address the 

situation appropriately. As part of this 

commitment, the Agency believes that it 

is important to understand and monitor 

the speciation profile of Hg emissions. 

However, the Agency does not believe 

that speciating Hg monitors are 

appropriate at this time. For this reason, 

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 to 

reflect changes in the monitoring 

requirements within 4 to 5 years after 

program implementation, which should 

provide enough lead time for 

development and installation of these 

monitoring systems. 

In order to ensure program integrity, 

the model trading rule requires States to 

include year-round 40 CFR part 75 

monitoring and reporting for Hg for all 

sources. Deadlines for monitor 

certification and other details are 

specified in the model rule. EPA 

believes that if these provisions are 

implemented, emissions will be 

accurately and consistently monitored 

and reported from unit-to-unit and from 

State-to-State. 

As is required for the Acid Rain 

program and the NOX Budget Trading 

program, Hg emissions data will be 

provided to EPA on a quarterly basis in 

a format specified by the Agency and 

submitted to EPA electronically using 

EPA provided software. We found this 

centralized reporting requirement 

necessary to ensure consistent review, 

checking, and posting of the emissions 

and monitoring data from all affected 

sources, which contributes to the 

integrity and efficiency of the trading 

program. 

Finally, consistent with the current 

requirements in 40 CFR part 75 for the 

Acid Rain and the NOX SIP Call 

programs, the final rule allows sources, 

under 40 CFR 60.4175 of 40 CFR part 

60, subpart HHHH, and under 40 CFR 

75.80(h) of 40 CFR part 75, subpart I, to 

petition for an alternative to any of the 

specified monitoring requirements in 

the final rule. This provision also 

provides sources with the flexibility to 

petition to use an alternative monitoring 

system under 40 CFR part 75, subpart E 

as long as the requirements of 40 CFR 

75.66 are met. 

7. Are There Additional Changes to the 

Proposed Model Cap-and-Trade Rule 

Reflected in the Regulatory Language? 

The final rule includes some minor 

changes to the model rule’s regulatory 

text that improve the implementability 

of the rules or clarify aspects of the rules 

identified by EPA or commenters. (Note 

that elsewhere in this action are 

highlighted the more significant 

modifications included in the final 

model rules.) 

These include: 

• The definition of ‘‘nameplate 

capacity’’ is clarified;

• The language on closing of general 

accounts is clarified; 

Another example of where today’s 

final model trading rules incorporate 

relatively minor changes from the 

proposed model trading rules involves 

the provisions in the standard 

requirements concerning liability under 

the trading programs. The proposed Hg 

model trading rule includes, under the 

standard requirements in the 40 CFR 

60.4154(d)(3) provision stating that any 

person who knowingly violates the Hg 

trading programs or knowingly makes a 

false material statement under the 

trading programs will be subject to 

28632 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

enforcement action under applicable 

State or Federal law. The final Hg model 

trading rule excludes this provision for 

the following reasons. First, the 

proposed rule provision is unnecessary 

because, even in its absence, applicable 

State or Federal law authorizes 

enforcement actions and penalties in the 

case of knowing violations or knowing 

submission of false statements. 

Moreover, the proposed rule provision 

is incomplete. It does not purport to 

cover, and has no impact on, liability for 

violations that are not knowingly 

committed or false submissions that are 

not knowingly made. Applicable State 

and Federal law already authorizes 

enforcement actions and penalties, 

under appropriate circumstances, for 

non-knowing violations or false 

submissions. Because the proposed rule 

provision is unnecessary and 

incomplete, the final model Hg trading 

rule does not include this provision. 

However, EPA emphasizes that, on its 

face, the provision that was proposed, 

but eliminated in the final rule, in no 

way limits liability, or the ability of the 

State or EPA to take enforcement action, 

to only knowing violations or knowing 

false submissions. 

F. Standard of Performance 

Requirements 

1. Introduction 

As proposed in the NPR and SNPR, 

and finalized today, under CAA section 

111, each State is required to submit a 

State Plan demonstrating that each State 

will meet the assigned Statewide Hg 

emission budget. Each State Plan should 

include fully-adopted State rules for the 

Hg reduction strategy with compliance 

dates providing for controls by 2010 and 

2018. 

The purpose of this section is to 

identify criteria for determining 

approvability of a State submittal in 

response to the performance standard 

requirements. This section also 

describes the actions the Agency 

intends to take if a State fails to submit 

a satisfactory plan. In addition, this 

section sets forth the criteria for States 

to receive approvability of trading rule 

within a State Plan. 

2. Performance Standard Approvability 

Criteria 

As discussed in the NPR and SNPR, 

CAA sections 111(a) and (d)(1) 

authorize EPA to promulgate a 

‘‘standard of performance’’ that States 

must apply to existing sources through 

a State plan. As also discussed in the 

NPR and elsewhere in the final rule, 

EPA is interpreting the term ‘‘standard 

of performance,’’ as applied to existing 

sources, to include a cap-and-trade 

program. 

The State budgets are not an 

independently enforceable requirement. 

Rather, 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 capand-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. 

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. 

Moreover, States remain authorized to 

require emissions reductions beyond 

those required by the State budget, and 

nothing in the final rule will preclude 

the States from requiring such stricter 

controls and still being eligible to 

participate in the Hg Budget Trading 

Program. 

In addition, as proposed in the SNPR, 

EPA finalizes today that sources will be 

required to comply with the 40 CFR part 

75 requirements. EPA believes that 

compliance with these requirements are 

necessary to demonstrate compliance 

with a mass emissions limit. 

If a State fails to submit a State plan 

as proposed to be required in the final 

rule, EPA will prescribe a Federal plan 

for that State, under CAA section 

111(d)(2)(A). EPA proposes today’s 

model rule as that Federal plan. 

3. Approvability of Trading Rule Within 

a State Plan 

a. Necessary Common Components of 

Trading Rule. As discussed in the SNPR 

and for the final rule, EPA intends to 

approve the portion of any State’s plan 

submission that adopts the model rule, 

provided: (1) The State has the legal 

authority to adopt the model rule and 

implement its responsibilities under the 

model rule, and (2) the State Plan 

submission accurately reflects the Hg 

reductions to be expected from the 

State’s adoption of the model rule. 

Provided a State meets these two 

criteria, then EPA intends to approve 

the model rule portion of the State’s 

plan submission. 

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.

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. 

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28633

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. 

b. Revisions to Regulations. As 

proposed in the SNPR, the final rule 

finalizes revisions to the regulatory 

provisions in 40 CFR 60.21 and 60.24 to 

make clear that a standard of 

performance for existing sources under 

CAA section 111(d) may include an 

allowance program of the type described 

today. 

G. What Are the Performance Testing 

and Other Compliance Provisions? 

1. Summary of Major Comments and 

Responses 

a. Use of Sorbent Trap Monitoring 

Systems. EPA proposed two alternatives 

for the use of sorbent trap monitoring 

systems. Alternative #1 would allow the 

use of sorbent trap systems for a subset 

of the affected units. The use of sorbent 

traps would be limited to low-emitting 

units, having estimated 3-year average 

Hg emissions of 144 ounce (9 lb) or less, 

for the same 3 calendar years used to 

allocate the Hg allowances. The 

threshold value of 9 lb/yr year was 

based on 1999 data gathered by EPA 

under an ICR that appeared in the 

Federal Register on April 9, 1998. Based 

solely on the 1999 ICR data, 228 of the 

1,120 coal-fired Utility Units in the 

database (i.e., 20 percent of the units), 

representing 1 percent of the 48 tons of 

estimated nationwide emissions, would 

qualify to use sorbent trap monitoring 

systems. EPA also took comment on 

three other threshold values, i.e., 29 lb/

yr, 46 lb/yr, and 76 lb/yr, representing, 

respectively, 435, 565, and 724 of the 

1,120 units in the database. 

Alternative #2 would allow any 

source to use either CEMS or sorbent 

traps. For sources with annual Hg 

emissions below a specified threshold 

value (we took comment on four values, 

i.e., 9 lb/yr, 29 lb/yr, 46 lb/yr, or 76 lb/

yr), the QA requirements for sorbent 

trap monitoring systems would consist 

of the procedures in proposed Method 

324 of 40 CFR part 63 plus an annual 

RATA. For sources with annual Hg 

emissions above the specified threshold, 

quarterly relative accuracy (RA) testing 

(i.e., a full 9-run RATA once a year and 

3-run RAs in the other three quarters of 

the year) would be required in addition 

to the proposed Method 324 procedures. 

EPA also requested comment on the 

appropriateness of proposed QA 

procedures for sorbent trap monitoring 

systems. Numerous commenters 

expressed concern that EPA’s proposal 

was 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 

QA/QC procedures for sorbent trap 

systems (most notably the quarterly RA 

testing), which they found to be 

inappropriate, 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 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. 

The final rule adopts under 40 CFR 

75.81(a) a modified version of 

Alternative #2, which allows the use of 

sorbent trap systems for any affected 

unit, provided that rigorous, 

application-specific QA procedures are 

implemented. The operational and QA/

QC procedures for sorbent trap systems 

are found in 40 CFR 75.15 and in 40 

CFR part 75, 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. 

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 

segment that enables the individual 

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 monitoring approach. 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 

analysis, or if they fail to meet the QC 

criteria. Also, when a 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 result 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.

2. Compliance Flexibility for Low 

Emitters 

The SNPR did not contain any special 

monitoring provisions for units with 

low mass emissions (LME). All affected 

units would be required to continuously 

monitor the Hg concentration, using 

either CEMS or sorbent trap monitoring 

systems. 

Numerous commenters requested that 

EPA provide a less rigorous, costeffective monitoring option for low 

emitting units. Affected units could 

meet a low emitter criterion based on a 

28634 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

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. 

Consistent with the LME provisions 

in 40 CFR 75.19 for SO2 and NOX, 40 

CFR 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 

ounce/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 ounce/yr) or 

less, annual emission testing is required. 

For units with Hg emissions greater than 

144 ounce/yr but less than or equal to 

464 ounce/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 

micrograms per standard cubic meter 

(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 ounce, 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 within 180 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 costeffective for industry, in that it allows 

periodic stack testing to be used to 

estimate Hg emissions instead of 

requiring CEMS. In the context of a capand-trade program, a low emitter 

provision can provide environmental 

benefit, because it requires 

conservatively high default emission 

factors to be used for reporting, as 

explained in the paragraphs below. 

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 higheremitting sources. 

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 lowemitting 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 final rule (see 58 FR 3593, 

January 11, 1993), EPA’s Acid Rain 

Division (now the Clean Air Markets 

Division, CAMD) first used the de 

minimis concept to exempt certain new 

Utility Units from the Acid Rain 

Program (i.e., units ≤ 25 MW that burn 

only fuels with a sulfur content ≤ 0.05 

percent by weight); 

• EPA also allows gas-fired and oilfired peaking units to use the less costly 

methodology in 40 CFR part 75, 

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 40 CFR 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 original 1993 

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 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 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, the 

final 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/yr 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/yr. 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 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 LME 

provisions in 40 CFR 75.81 and the LME 

provisions in 40 CFR 75.19 for SO2 and 

NOX (which are based on a 1 percent 

threshold). First, under 40 CFR 75.19, 

default emission rates are used 

exclusively, and there is no real-time 

continuous monitoring of the SO2 or 

NOX emissions. However, under 40 CFR 

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 40 CFR 75.19 allow 

sources 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 

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28635

a new default emission rate once every 

5 years. Under 40 CFR 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. 

3. Missing Data 

To address missing data from Hg 

CEMS, EPA proposed to add a new 

section to the rule, 40 CFR 75.38, which 

would require the same initial and 

standard missing data routines that are 

used for SO2 monitors to be applied to 

Hg CEMS. That is, until 720 hours of 

quality-assured Hg data have been 

collected following initial certification, 

the substitute data value for any period 

of missing data would be the average of 

the Hg concentrations recorded before 

and after the missing data period. 

Thereafter, the percent monitor data 

availability (PMA) would be calculated 

hour-by-hour, and the familiar fourtiered standard missing data procedures 

of 40 CFR 75.33(b) would be applied. 

Using this approach, the substitute data 

values would become increasingly 

conservative as the PMA decreases and 

the length of the missing data period 

increases. For PMA values below 80 

percent, the MPC would be reported.

For a unit equipped with an FGD 

system that meaningfully reduces the 

concentration of Hg emitted to the 

atmosphere, or for a unit equipped with 

add-on Hg emission controls, the initial 

and standard Hg missing data 

procedures would apply only when the 

FGD or add-on controls are documented 

to be operating properly, in accordance 

with 40 CFR 75.58(b)(3). For any hour 

in which the FGD or add-on controls are 

not operating properly, the MPC would 

be the required substitute data value. 

Also for units equipped with FGD 

systems or add-on Hg emission controls, 

proposed 40 CFR 75.38 would allow the 

owner or operator to petition to use the 

maximum controlled Hg concentration 

or emission rate in the 720-hour missing 

data lookback (in lieu of the maximum 

recorded value) when the PMA is less 

than 90.0 percent. 

EPA considered using the load-based 

NOX missing data routines in 40 CFR 

75.33(c) as the model for Hg, but this 

approach was not proposed in the 

absence of any data indicating that 

vapor phase Hg emissions are loaddependent. The Agency solicited 

comments on the proposed missing data 

approach. 

EPA also proposed to add initial and 

standard missing data procedures for 

sorbent trap monitoring systems, in a 

new section, 40 CFR 75.39. Missing data 

substitution would be required 

whenever a gas sample is not extracted 

from the stack, or when the results of 

the Hg analyses representing a 

particular period of unit operation are 

missing or invalid. 

The initial missing data procedures 

for sorbent trap systems would be 

applied from the hour of certification 

until 720 quality-assured hours of data 

have been collected. The initial missing 

data algorithm would require the owner 

or operator to average the Hg 

concentrations from all valid sorbent 

trap analyses to date, including data 

from the initial certification test runs, 

and to fill in this average concentration 

for each hour of the missing data period. 

Once 720 quality-assured hours of Hg 

concentration data were collected, the 

owner or operator would begin 

reporting the PMA and would begin 

using the standard missing data 

algorithms. The standard missing data 

procedures for sorbent trap systems 

would also follow a ‘‘tiered’’ approach, 

based on the PMA. For example, at high 

PMA (greater than or equal to 95.0 

percent), the substitute data value 

would be the average Hg concentration 

obtained from all valid sorbent trap 

analyses in the previous 12 months. At 

lower PMA values, the substitute data 

values would become increasingly 

conservative, until finally, if the PMA 

dropped below 80.0 percent, the MPC 

would be reported. 

Similar to the proposed provision for 

Hg CEMS, if a unit using sorbent traps 

is equipped with an FGD system or addon Hg emission controls, the initial and 

standard missing data procedures could 

only be applied for hours in which 

proper operation of the emission 

controls is documented. In the absence 

of such documentation, the MPC would 

be reported. 

Several commenters 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 PMA is achievable 

with these monitoring systems. Other 

commenters suggested that EPA should 

remove the 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. 

The final rule retains the proposed 

missing data provisions for Hg CEMS, 

but slightly relaxes the PMA cut-points. 

In the proposed four-tiered missing data 

procedure the cut points separating the 

tiers are at 95 percent, 90 percent, and 

80 percent PMA. The final rule lowers 

these to 90 percent, 80 percent, and 70 

percent PMA, respectively for Hg 

concentration monitors. The final rule 

also retains the MPC concept, and 

amends the proposed missing data 

procedures for sorbent traps to more 

closely match the Hg CEMS missing 

data procedures. 

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. The Agency will 

continue to collect and analyze CEMS 

and sorbent 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 indicate that the PMA cutpoints 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 

28636 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

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 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 

CAMD 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 less 

than 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.

4. Instrumental Reference Method for 

Hg 

Only a wet chemistry method, the 

Ontario Hydro Method, was proposed to 

perform RATAs of Hg CEMS and 

sorbent trap monitoring systems. 

Some commenters objected to the use 

of the Ontario Hydro Method for RATA 

testing, stating that due to the 

complexity of wet chemical methods 

and their inability to produce accurate 

concentrations, there will be some cases 

where a properly functioning Hg CEMS 

will fail a RATA due to inaccuracies in 

the reference method. Other 

commenters noted that unlike the 

instrumental reference methods 

routinely used to QA SO2 and NOX

CEMS, the Ontario Hydro Method can 

take days to complete and weeks for the 

return of test results from the laboratory, 

which could lead to significant 

implementation problems with respect 

to missing data and requirements to 

calculate and report data. A number of 

commenters stated that for applications 

where Hg CEMS are used, a real time 

instrumental reference method for 

RATAs is needed, and that EPA should 

develop such an instrumental method. 

Use of an instrumental method for 

RATAs of Hg monitoring systems and 

sorbent trap systems is allowed by 40 

CFR 75.22 of the final rule, subject to 

approval by the Administrator. EPA will 

propose a Hg instrumental reference 

method once sufficient field test data 

are collected and analyzed. 

At present, EPA is conducting field 

demonstrations of Hg monitoring 

technology. One of the high priority 

items in these studies is the 

development of a suitable instrumental 

method for Hg. When the field testing is 

complete, EPA intends to propose and 

promulgate the instrumental method. A 

Hg instrumental reference method for 

RATA testing is vastly preferable to the 

Ontario Hydro Method and will greatly 

facilitate the implementation of a Hg 

cap-and-trade program. The Ontario 

Hydro Method, which is a wet 

chemistry method that uses numerous 

glass impingers, requires at least a one 

week turn-around to obtain results, and 

(as with all wet chemistry methods) is 

cumbersome to use and subject to 

operator error. 

5. QA/QC Procedures for Hg CEMS 

For initial certification, EPA proposed 

to require the following tests for Hg 

CEMS: 

• A 7-day calibration error test, using 

elemental Hg calibration gas standards. 

The monitor would be required to meet 

a performance specification of 5.0 

percent of span on each day of the test 

or (for span values of 10 μg/scm) an 

alternate specification of 1.0 μg/scm 

absolute difference between reference 

gas and CEMS; 

• A 3-point linearity check, using 

elemental Hg calibration gas standards. 

The monitor would be required to meet 

a performance specification of 10.0 

percent of the reference gas 

concentration at each gas level or an 

alternate specification of 1.0 μg/scm 

absolute difference between reference 

gas and CEMS; 

• A cycle time test. The maximum 

allowable cycle time would be 15 

minutes; 

• A RATA, using the Ontario Hydro 

Method. The monitor would be required 

to achieve a relative accuracy of 20.0 

percent. Alternatively, if the Hg 

concentration during the RATA is less 

than 5.0 μg/scm, the results would be 

acceptable if the mean difference 

between the reference method and 

CEMS does not exceed 1.0 μg/scm. 

• A bias test, using data from the 

RATA, to ensure that the CEMS is not 

biased low with respect to the reference 

method. 

• A 3-point converter check, using 

HgCl2 standards. The monitor would be 

required to meet a performance 

specification of 5.0 percent of span at 

each gas level. 

For ongoing QA/QC, we proposed the 

following QA/QC tests: 

• Daily 2-point calibration error 

checks, using elemental Hg gas 

standards. The monitor would be 

required to meet a performance 

specification of 7.5 percent of span or an 

alternate specification of 1.5 μg/scm 

absolute difference between reference 

gas and CEMS; 

• Quarterly 3-point linearity checks, 

using elemental Hg gas standards. The 

performance specifications would be the 

same as for initial certification. 

• Monthly 3-point converter checks 

using HgCl2 standards. The performance 

specifications would be the same as for 

initial certification. 

• Annual RATA and bias test. The 

performance specifications would be the 

same as for initial certification. 

After reviewing the proposed rule, 

commenters were in general agreement 

on the following points. 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 RA. 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 RA tests and 3-

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 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. 

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28637

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.

After considering the comments 

received, the Agency decided to retain 

in the final rule, the same tests as were 

required for initial certification and ongoing QA of Hg CEMS 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 

National Institute of Standards and 

Technology (NIST)-traceable 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 NISTtraceable 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 3 

points has been replaced with a weekly 

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 of 

the relative deviation (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 RA 

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 are 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. 

A more detailed discussion of these 

studies is provided in the Response to 

Comments document. 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 single-point 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. 

6. Sorbent Trap Operation and QA/QC 

General guidelines for operating 

sorbent trap systems were proposed in 

40 CFR 75.15. The use of paired traps 

would be required, and the stack gas 

would be sampled at a rate that is 

proportional to the stack gas volumetric 

flow rate. Proposed Method 324 would 

be used as the protocol for operating the 

monitoring systems and for analyzing 

the Hg samples collected by the sorbent 

traps. 

Additional QA requirements for 

sorbent trap systems were proposed in 

sections 1.5, 2.3 and 2.7 of 40 CFR part 

75, appendix B. Development of a QA/

QC program and plan would be 

required. Key components of this 

program would be assignment of 

permanent identification (ID) numbers 

to the sorbent traps, keeping of records 

of the dates and times that each trap is 

used, establishment of a chain of 

custody for transporting and analyzing 

the traps, documentation that the 

laboratory analyzing the samples is 

certified according to International 

Organization for Standardization (ISO) 

9000 standards, explanations of the leak 

check and other QA test procedures, 

and the rationale for the minimum 

acceptable data collection time for each 

trap. In addition, the data acceptance 

and QC criteria of proposed Method 324 

would be included in the QA plan. 

An annual RATA and bias test of each 

sorbent trap system would be required, 

using the Ontario Hydro Method as the 

reference method. And if proposed 

Alternative #2 were implemented (i.e., 

allowing sorbent trap systems to be used 

by any affected unit), for units with 

annual Hg mass emissions above a 

certain threshold value (we took 

comment on four thresholds, i.e., 9 lb/

hr, 29 lb/hr, 46 lb/hr, and 76 lb/hr), 

additional 3-run RAs would be required 

in the other three quarters of the year. 

The commenters were generally 

opposed to the proposed quarterly RAs 

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 

proposed 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 

proposed 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 EPA 

Method 1631 of 40 CFR part 136, 

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 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 

28638 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

• 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 40 CFR part 

75, appendix B that laboratories 

performing proposed Method 324 be 

certified by the 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 test and adjustment 

factor to proposed Method 324, when it 

has already satisfied the same standards 

for bias and precision as the Ontario 

Hydro Method under EPA Method 301 

of 40 CFR part 63. Another commenter 

suggested that it does not make sense to 

subject Hg monitors to a bias adjustment 

factor under 40 CFR part 75, appendix 

A, section 7.6 when paired reference 

method trains are allowed to differ by 

10 percent 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. 

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 40 

CFR part 75, appendix K in the final 

rule. Based on comments received and 

experience gained from field tests since 

proposal, 40 CFR part 75, appendix K 

retains certain provisions and revises 

others in proposed Method 324 to 

include detailed, performance-based 

criteria, QA standards and procedures 

for sorbent trap monitoring systems. The 

final 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 40 CFR 75.15, to be 

consistent with the requirements of 40 

CFR part 75, appendix K. 

The final rule retains the annual 

RATA and bias test requirements for 

sorbent trap monitoring systems, but the 

proposed quarterly RA 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 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, the final 

rule specifies such procedures in 40 

CFR part 75, appendix K. Many 

provisions of proposed Method 324 

have been included in 40 CFR part 75, 

appendix K, without modification, but 

other provisions of the proposed 

Method have been modified to employ 

a more performance-based approach and 

some new QA procedures have been 

added to address concerns expressed by 

the commenters. Some of the more 

significant differences between 

proposed Method 324 and 40 CFR part 

75, appendix K, are as follows: 

• 40 CFR part 75, 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 (UV AF), ultraviolet atomic 

absorption (UV AA), and in-situ X-ray 

fluorescence (XRF); 

• 40 CFR part 75, appendix K, 

requires that each sorbent trap be 

comprised of three equal sections, 

capable of being separately analyzed. 

The first section is for sample 

collection, the second to assess 

‘‘breakthrough,’’ and the third to allow 

spiking with elemental Hg for QA 

purposes; 

• 40 CFR part 75, appendix K, 

specifies the frequency of dry gas meter 

calibration and the appropriate 

calibration procedures; 

• 40 CFR part 75, 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 the data collection period begins; 

• The laboratory performing the 

analyses must demonstrate the ability to 

recover and quantify Hg from the 

sorbent media; and 

• The measured Hg mass in the first 

and second sections of each trap is 

adjusted, 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 paired 

concentrations agree within 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 inexpensive means of 

ensuring against data loss should one of 

the traps become lost or damaged.

The commenters generally objected to 

the proposed quarterly relative accuracy 

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 RA 

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 

proposed Method 324 had satisfied the 

same standards for bias and precision as 

the Ontario Hydro Method under EPA 

Method 301 of 40 CFR part 63. EPA 

does not agree with this comment. The 

fact that proposed 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 

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28639

sorbent trap systems because of the 

allowable 10 percent RD between the 

paired reference method trains. The 40 

CFR 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. 

7. Mercury-Diluent Systems 

Mercury-diluent monitoring systems 

(consisting of a Hg pollutant 

concentration monitor, an O2 or CO2

diluent gas monitor, and an automated 

data acquisition and handling system) to 

measure Hg emission rate in lb/1012 Btu 

were allowed in the proposed rule. 

One commenter asked why the 

proposed Hg emissions units of 

measurement are the same as NOXdiluent. 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. 

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, as 

proposed, 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. 

V. Summary of the Environmental, 

Energy, Cost, and Economic Impacts 

A. What Are the Air Quality Impacts? 

EPA has assessed the change in the 

amount of Hg deposited in the 

continental U.S. as a result of the final 

rule. The recently promulgated CAIR 

significantly reduced utility attributable 

Hg deposition. Both the selected CAMR 

approach and the regulatory alternative 

result in small additional shifts in the 

overall distribution of Hg deposition 

from utilities reactive to the CAIR result. 

Table 2 of this preamble presents the 

frequency and cumulative distributions 

of the reductions in deposition 

associated with the CAMR requirements 

and the CAMR alternative. We also 

provide the reduction in deposition 

from the 2020 base case with CAIR 

implemented relative to the 2001 base 

case. This change (2001 Base—2020 

CAIR) shows that there are both 

increases and decreases in deposition. 

Negative reductions (increases) are due 

to growth in non-utility Hg emissions, 

and growth in utility emissions in areas 

unaffected by CAIR. Reductions in 

deposition are largely due to the 

implementation of CAIR controls at 

utilities.

TABLE 2.—DISTRIBUTIONS OF REDUCTIONS IN TOTAL MERCURY DEPOSITION

Range

(μg/m2) 

2001 base—2020 base 

(with CAIR) 

2020 base (with CAIR)—

2020 CAMR

requirements 

2020 base (with CAIR)—

2020 CAMR requirements 

2020 CAMP requirements—2020 CAMR alternative 

Percent Cumulative

percent Percent Cumulative

percent 

Percent Cumulative

percent Percent Cumulative

percent 

<=0 ................................. 6.59 6.59 2.13 2.13 0.83 0.83 0.28 0.28 

0–1 ................................. 58.02 64.61 97.03 99.17 97.87 98.70 99.58 99.86 

1–2 ................................. 12.06 76.67 0.83 100.00 1.30 100.00 0.14 100.00 

2–3 ................................. 7.33 84.00 0.00 100.00 0.00 100.00 0.00 100.00 

3–4 ................................. 5.10 89.10 0.00 100.00 0.00 100.00 0.00 100.00 

4–5 ................................. 3.71 92.81 0.00 100.00 0.00 100.00 0.00 100.00 

5–10 ............................... 6.08 98.89 0.00 100.00 0.00 100.00 0.00 100.00 

10–15 ............................. 0.88 99.77 0.00 100.00 0.00 100.00 0.00 100.00 

15–20 ............................. 0.23 100.00 0.00 100.00 0.00 100.00 0.00 100.00 

Source: Technical Support Document: Methodology Used to Generate Deposition, Fish Tissue Methylmercury Concentrations, and Exposure 

for Determining Effectiveness of Utility Emission Controls 

B. What Are the Non-Air Health, 

Environmental, and Energy Impacts? 

According to EO 13211 ‘‘Actions that 

Significantly Affect Energy Supply, 

Distribution, or Use,’’ the final 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 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 final 

rule on the electricity sector.

C. What Are the Cost and Economic 

Impacts? 

The projected annual costs of CAMR 

to the power industry are $160 million 

in 2010, $100 million in 2015, and $750 

million in 2020. These costs represent 

the total cost to the electricitygenerating industry of reducing Hg 

emissions to meet the caps set forth in 

the final rule and are incremental costs 

to the requirements to meet NOX and 

SO2 emissions caps set forth in the 

CAIR. Estimates are in 1999 dollars. 

Retail electricity prices are projected 

to increase roughly 0.2 percent higher 

with CAMR in 2020 when compared to 

CAIR. Natural gas prices are projected to 

increase by roughly 1.6 percent with 

CAMR in 2020 when compared to CAIR. 

There will be continued reliance on 

coal-fired generation, which is projected 

to remain at roughly 50 percent of total 

electricity generated and no coal-fired 

capacity projected to be uneconomic to 

28640 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

maintain incremental to CAIR. As 

demand grows in the future, additional 

coal-fired generation is projected to be 

built. As a result, coal production for 

electricity generation is projected to 

increase from 2003 levels by about 13 

percent in 2010 and 20 percent by 2020, 

and we expect a small shift towards 

greater coal production in Appalachia 

and the Interior coal regions of the 

country with CAMR compared to 2003. 

Additional information on the cost 

and economic impacts of CAMR is 

provided in the discussion under EO 

12866 below. 

VI. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review 

Under EO 12866 (58 FR 51735, 

October 4, 1993), the Agency must 

determine whether a regulatory action is 

‘‘significant’’ and, therefore, subject to 

Office of Management and Budget 

(OMB) review and the requirements of 

the EO. The EO defines ‘‘significant 

regulatory action’’ as one that is likely 

to result in a rule that may: 

(1) Have an annual effect on the 

economy of $100 million or more or 

adversely affect in a material way the 

economy, a sector of the economy, 

productivity, competition, jobs, the 

environment, public health or safety, or 

State, local, or Tribal governments or 

communities; 

(2) Create a serious inconsistency or 

otherwise interfere with an action taken 

or planned by another agency; 

(3) Materially alter the budgetary 

impact of entitlements, grants, user fees, 

or loan programs or the rights and 

obligations of recipients thereof; or 

(4) Raise novel legal or policy issues 

arising out of legal mandates, the 

President’s priorities, or the principles 

set forth in the EO. 

In view of its important policy 

implications and potential effect on the 

economy of over $100 million, the final 

rule has been judged to be an 

economically ‘‘significant regulatory 

action’’ within the meaning of the EO. 

As a result, the final rule was submitted 

to OMB for review, and EPA has 

prepared an economic analysis of the 

final rule entitled ‘‘Regulatory Impact 

Analysis of the Final Clean Air Mercury 

Rule’’ (March 2005) (OAR–2002–0056). 

CAMR is an example of 

environmental regulation that 

recognizes and balances the need for 

energy diversity, reliability, and 

affordability. 

1. What Economic Analyses Were 

Conducted for the Final Rule? 

The analyses conducted for the final 

rule provide several important analyses 

of impacts on public welfare. These 

include an analysis of the social 

benefits, social costs, and net benefits of 

the regulatory scenario. The economic 

analyses also address issues involving 

small business impacts, unfunded 

mandates (including impacts for Tribal 

governments), environmental justice, 

children’s health, energy impacts, and 

requirements of the Paperwork 

Reduction Act (PRA). 

2. What Are the Benefits and Costs of 

the Final Rule? 

a. Control Scenario. The final CAMR 

requires annual Hg reductions for the 

power sector in 50 States, the District of 

Columbia, and in Indian country. EPA 

considered the final CAIR for SO2 and 

NOX requirements and all promulgated 

CAA requirements and known State 

actions in the baseline used to develop 

the estimates of benefits and costs for 

the final rule. A more complete 

description of the reduction 

requirements and how they were 

calculated is described earlier in this 

preamble. 

CAMR was designed to achieve 

significant Hg emissions reductions 

from the power sector in a much more 

cost-effective manner than a facilityspecific or unit-specific approach. EPA 

analysis has found that the most costeffective method to achieve the 

emissions reductions targets is through 

a cap-and-trade system that States have 

the option of adopting. States, in fact, 

can choose not to participate in the 

optional cap-and-trade program. 

However, EPA believes that a cap-andtrade system for the power sector is the 

best approach for reducing Hg emissions 

and EPA’s analysis assumes that States 

will adopt this more cost effective 

approach. 

b. Cost Analysis and Economic 

Impacts. For the final rule, EPA 

analyzed the costs using the IPM. IPM 

is a dynamic linear programming model 

that can be used to examine the 

economic impacts of air pollution 

control policies for Hg, SO2, and NOX

throughout the contiguous U.S. for the 

entire power system. Documentation for 

IPM can be found in the docket for the 

final rule or at http://www.epa.gov/

airmarkets/epa-ipm. 

CAMR calls for environmental 

improvement and emission reductions 

from the power sector while recognizing 

the need to maintain energy diversity 

and reliability. 

The projected annual costs of CAMR 

to the power industry are $160 million 

in 2010, $100 million in 2015, and $750 

million in 2020. These costs represent 

the total cost to the electricitygenerating industry of reducing Hg 

emissions to meet the caps set forth in 

the final rule and are incremental costs 

to the requirements to meet NOX and 

SO2 emissions caps set forth in the 

CAIR. Estimates are in 1999 dollars. 

Retail electricity prices are projected 

to increase roughly 0.2 percent higher 

with CAMR in 2020 when compared to 

CAIR. Natural gas prices are projected to 

increase by roughly 1.6 percent with 

CAMR in 2020 when compared to CAIR. 

There will be continued reliance on 

coal-fired generation, which is projected 

to remain at roughly 50 percent of total 

electricity generated and no coal-fired 

capacity projected to be uneconomic to 

maintain incremental to CAIR. As 

demand grows in the future, additional 

coal-fired generation is projected to be 

built. As a result, coal production for 

electricity generation is projected to 

increase from 2003 levels by about 13 

percent in 2010 and 20 percent by 2020, 

and we expect a small shift towards 

greater coal production in Appalachia 

and the Interior coal regions of the 

country with CAMR compared to 2003.

c. Human Health and Welfare Benefit 

Analysis. The Hg emissions reductions 

associated with implementing the final 

CAMR will produce a variety of 

benefits. Mercury emitted from utilities 

and other natural and man-made 

sources is carried by winds through the 

air and eventually is deposited to water 

and land. In water, some Hg is 

transformed to MeHg through biological 

processes. Methylmercury, a highly 

toxic form of Hg, is the form of Hg of 

concern for the purpose of the final rule. 

Once Hg has been transformed into 

MeHg, it can be ingested by the lower 

trophic level organisms where it can 

bioaccumulate in fish tissue (i.e., 

concentrations in predatory fish build 

up over the fish’s entire lifetime, 

accumulating in the fish tissue as 

predatory fish consume other species in 

the food chain). Thus, fish and wildlife 

at the top of the food chain can have Hg 

concentrations that are higher than the 

lower species, and they can have 

concentrations of Hg that are higher 

than the concentration found in the 

water body itself. Therefore, the most 

common form of exposure to Hg for 

humans and wildlife is through the 

consumption of Hg contained in 

predatory fish, such as: Shark, 

swordfish, king mackerel, tilefish and 

recreationally caught bass, perch, 

walleye or other freshwater fish species. 

When humans consume fish 

containing MeHg, the ingested MeHg is 

almost completely absorbed into the 

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28641

8National Research Council (NRC). 2000. 

Toxicological Effects of Methylmercury. Committee 

on the Toxicological Effects of Methylmercury, 

Board on Environmental Studies and Toxicology, 

Commission on Life Sciences, National Research 

Council. National Academy Press, Washington, DC.

9See footnote 3 of chapter 11 of the RIA for an 

explanation of the basis for the monetization.

blood and distributed to all tissues 

(including the brain). 

In pregnant women, MeHg can be 

passed on to the developing fetus, and 

at sufficient exposure may lead to a 

number of neurological effects in 

children. Thus, children who are 

exposed to low concentrations of MeHg 

prenatally may be at increased risk of 

poor performance on neurobehavioral 

tests, such as those measuring attention, 

fine motor function, language skills, 

visual-spatial abilities (like drawing), 

and verbal memory. The effects from 

prenatal exposure can occur even at 

doses that do not result in effects in the 

mother. A full discussion of the 

neurological health effects of Hg is 

provided by the National Research 

Council in ‘‘Neurological Effects of 

Methylmercury.’’ 8 Some 

subpopulations in the U.S. (e.g., certain 

Native Americans, Southeast Asian 

Americans, recreational and subsistence 

anglers) consume larger amounts of fish 

than the general population and may be 

at a greater risk to the adverse health 

effects from Hg due to increased 

exposure.

EPA held a workshop with several of 

the National Research Council (NRC) 

panel members in 2002. Participants 

were asked about which studies should 

be considered in generating doseresponse functions for developmental 

neurotoxicity. Participants were also 

asked about endpoints to consider for 

monetization, and they suggested 

looking at neurological tests that might 

lead to changes in IQ or other 

neurodevelopmental impacts. EPA 

determined that IQ decrements due to 

Hg exposure is one endpoint that EPA 

should focus on for a benefit analysis, 

because it can be monetized.9 The focus 

population for the benefit analysis is 

women of childbearing age who 

consume freshwater, recreationallycaught fish. Methylmercury is a 

developmental neurotoxicant with 

greatest biological sensitivity from in 

utero exposure.

Three large-scale epidemiological 

studies have examined the effects of low 

dose prenatal Hg exposure and 

neurodevelopmental outcomes through 

the administration of numerous tests of 

cognitive functioning. These studies 

were conducted in the Faroe Islands 

(Grandjean et al. 1997), New Zealand 

(Kjellstrom et al. 1989, Crump et al.

1998), and the Seychelles Islands 

(Davidson et al. 1998, Myers et al.

2003). Based on recommendations from 

participants at the Hg workshop 

discussed above, and the ability to 

monetize IQ decrements, EPA combined 

data and information from all three of 

these studies to develop a combined 

dose-response function for IQ 

decrements to apply in a benefit 

analysis. 

CAMR may also reduce emissions of 

directly emitted PM, which contribute 

to the formation of PM2.5. In general, 

exposure to high concentrations of PM2.5

may aggravate existing respiratory and 

cardiovascular disease including 

asthma, bronchitis and emphysema, 

especially in children and the elderly. 

Exposure to PM2.5 can lead to decreased 

lung function, and alterations in lung 

tissue and structure and in respiratory 

tract defense mechanisms which may 

then lead to, increased respiratory 

symptoms and disease, or in more 

severe cases, premature death or 

increased hospital admissions and 

emergency room visits. Children, the 

elderly, and people with 

cardiopulmonary disease, such as 

asthma, are most at risk from these 

health effects. PM2.5 can also form a 

haze that reduces the visibility of scenic 

areas, can cause acidification of water 

bodies, and have other impacts on soil, 

plants, and materials. 

Due to both technical and resource 

limits in available modeling, we have 

only been able to quantify and monetize 

the benefits for a few of the endpoints 

associated with reducing Hg, and 

directly emitted PM. In the ‘‘Regulatory 

Impact Analysis of the Final Clean Air 

Mercury Rule,’’ we provide an analysis 

of the benefits from avoided IQ 

decrements in potentially prenatally 

exposed children from the reduction of 

MeHg exposures and the benefits of 

reducing directly emitted PM. 

There are several fish consumption 

pathways considered by the Agency for 

the benefit analysis, including: 

Consumption from commercial sources 

(including saltwater and freshwater fish 

from domestic and foreign producers), 

consumption of commercial fish raised 

at fish farms (aquaculture), and 

consumption of recreationally caught 

freshwater and saltwater fish. As 

explained in the RIA, we believe that 

the focus of the analysis on 

recreationally and subsistence caught 

freshwater fish captures the bulk of the 

benefits. Nevertheless, we believe that 

the analysis captures the bulk of the 

benefits. 

To model recreational angling and 

prenatal exposure from this 

consumption pathway (i.e., women of 

childbearing age consuming freshwater 

fish and, hence, exposing the fetus in 

utero), we consider two modeling 

approaches: One approach that 

estimates the distance anglers are likely 

to travel from their households to water 

bodies for fishing activities (referred to 

as the Population Centroid Approach), 

and another approach that models how 

often recreational anglers fish at certain 

locations (referred to as the Angler 

Destination Approach). These resulting 

benefits from the two exposure 

modeling approaches differ, however, 

we expected they are likely to capture 

the range of actual behavior (and likely 

exposure) of recreational anglers.

This approach forms the core analytic 

underpinnings for the final benefit 

numbers, but incorporates an 

assumption of no threshold, and, 

therefore, reflects an upper-bound on 

the number of people affected by Hg. A 

more simplified approach used to 

simulate exposure scenarios under the 

assumption of two different thresholds. 

This threshold analysis provides 

‘‘scaling factors,’’ or benefits as a 

percent of the no threshold case. We 

consider two benchmark levels of 

exposure established by regulatory 

agencies as possible thresholds: (1) A 

threshold equal to EPA’s reference dose 

(RfD) of 0.1 micrograms per kilogram 

per day (ug/kg-day) and (2) a threshold 

in the neighborhood of the World 

Health Organization and Health Canada 

benchmarks of 0.23 and 0.2 ug/kg-day 

respectively. Scaling factors for the no 

threshold benefits from the more 

detailed analysis range from 4 percent to 

34 percent. The final estimates of IQrelated benefits are arrayed in a 

hierarchy from most certain to less 

certain benefits. 

In addition, the current state of 

knowledge of the science indicates that 

there is likely a lag in the time between 

the reduction in Hg deposition to a 

water body and the change in MeHg 

concentrations in fish tissue. Based on 

a review of available literature and a 

series of case studies conducted by EPA, 

the lag period for changes in fish tissue 

(and hence changes in avoided IQ 

decrements) can range from less than 5 

years to more than 50 years, with an 

average time span of 1 to 3 decades (10 

to 30 years). In the benefit analysis 

presented in the RIA, we present a range 

of results assuming a series of potential 

lag scenarios (including 5, 10, 20, and 

50 years) on the total benefits. The 10- 

and 20-year lag periods are presented as 

the likely outcome of results from the 

analysis, while the 5- and 50-year lag 

periods are presented to show the 

outcomes if the time span to steady-state 

28642 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

10 It should no noted that the degree of 

uncertainty associated with these effects varies as 

does our knowledge about whether the effects are 

seen at levels consistent with those in the U.S.

is less than or more than the average lag 

periods observed in the case studies. 

We also present future year benefits 

discounted at a 3 percent and a 7 

percent rate. In addition, due to the 

potential for intergenerational effects, 

the 50 year lag is assessed using a 1 

percent discount rate as well as the 3 

and 7 percent discount rates (in 

accordance with the EPA Economic 

Guidelines). Benefits are evaluated after 

full implementation of CAMR (in 2020, 

2 years after imposition of the Phase II 

cap) and presented in 1999 dollars. The 

resulting benefits presented in the RIA 

show a range of potential values based 

on all of these sources of variability in 

the estimate. 

Giving consideration to all of the 

possible outcomes discussed in the RIA, 

the range of annual monetized benefits 

of CAMR under a 10- to 20-year lag 

period are approximately $0.4 million to 

$3.0 million using a 3 percent discount 

rate (or $0.2 million to $2.0 million 

using a 7 percent discount rate). 

In addition to the benefits of reducing 

exposures to MeHg from recreational 

freshwater angling, there are several 

additional benefits that may be 

associated with reduced exposures to 

MeHg; however, the literature with 

regard to these effects is less developed 

than the literature for childhood 

neurodevelopmental effects.10 Because 

of the uncertainty associated with these 

effects, and, in most cases, the lack of 

sufficient data to evaluate whether or 

not these effects are present at levels 

associated with U.S. exposures, we did 

not quantify these benefits. Most 

notably these effects include:

• Cardiovascular effects—Some 

recent epidemiological studies in men 

suggest that MeHg is associated with a 

higher risk of acute myocardial 

infarction, coronary heart disease and 

cardiovascular disease in some 

populations. Other recent studies have 

not observed this association. The 

studies that have observed an 

association suggest that the exposure to 

MeHg may attenuate the beneficial 

effects of fish consumption. The 

findings to date and the plausible 

biologic mechanisms warrant additional 

research in this arena (Stern 2005; Chan 

and Egeland 2004). 

• Ecosystem effects—Plant and 

aquatic life, as well as fish, birds, and 

mammalian wildlife can be affected by 

Hg exposure; however overarching 

conclusions about ecosystem health and 

population effects are difficult to make 

at this time. 

• Other effects—There is some recent 

evidence that exposures of MeHg may 

result in genotoxic or immunotoxic 

effects. Other research with less 

corroboration suggest that reproductive, 

renal, and hematological impacts may 

be of concern. Overall, there is a 

relatively small body of evidence from 

human studies that suggests exposure to 

MeHg can result in immunotoxic effects 

and the NRC concluded that evidence 

that human exposure caused genetic 

damage is inconclusive. There are 

insufficient human data to evaluate 

whether these effects are consistent with 

levels in the U.S. population. See 

chapter 2 of the RIA. 

In an analysis of the possible cobenefits associated with emission 

reductions of directly emitted PM, we 

estimated the total change in incidence 

of premature mortality. We conducted 

an illustrative analysis using a 

simplified air quality and exposure 

modeling approach (the SourceReceptor Matrix) to derive a benefit 

transfer value (i.e., $ benefit per ton PM) 

that were applied to total estimate 

emission reductions of direct PM. The 

total estimated PM-related benefits are 

approximately $1.4 million to $40 

million; however, the calculation of 

these benefits is highly dependent on 

uncertain future technology choices of 

the industry. Because of this significant 

uncertainty, therefore, these benefit 

estimates are not included in our 

primary benefit estimate. 

In response to potential risks of 

consuming fish containing elevated 

concentrations of Hg, EPA and the U.S. 

Food and Drug Administration (FDA) 

have issued a joint fish consumption 

advisory which provides recommended 

limits on consumption of certain fish 

species (shark, swordfish, king 

mackerel, tilefish) for different 

populations. This joint EPA and FDA 

advisory recommends that women who 

may become pregnant, pregnant women, 

nursing mothers, and young children to 

avoid some types of fish and eat fish 

and shellfish that are lower in Hg, 

diversifying the types of fish they 

consume, and by checking any local 

advisories that may exist for local rivers 

and streams. 

3. How Do the Benefits Compare to the 

Costs of the Final Rule?

The costs presented above are EPA’s 

best estimate of the direct private costs 

of the CAMR. In estimating the net 

benefits of regulation (benefits minus 

costs), the appropriate cost measure is 

‘‘social costs.’’ Social costs represent the 

total welfare costs of the rule to society. 

These costs do not consider transfer 

payments (such as taxes) that are simply 

redistributions of wealth. Using these 

alternate discount rates, the social costs 

of the final rule are estimated to be 

approximately $848 million in 2020 

when assuming a 3 percent discount 

rate. These costs become $896 million 

in 2020 if one assumes a 7 percent 

discount rate. The costs of the CAMR 

using the adjusted discount rates differ 

from the private costs of the CAMR 

generated using IPM because the social 

costs do not include certain transfer 

payments, primarily taxes, that are 

considered a redistribution of wealth 

rather than a social cost. 

As is discussed above, the total social 

benefits that EPA was able to monetize 

in the RIA total $0.4 million to $3.0 

million using a 3 percent discount rate, 

and $0.2 million to $2.0 million using 

a 7 percent discount rate. 

Thus, the annual monetized net 

benefit in 2020 (social benefits minus 

social costs) of the CAMR program is 

approximately ¥$846 million or ¥$895 

million (using 3 percent and 7 percent 

discount rates, respectively) annually in 

2020. Although the final rule is 

expected to result in a net cost to 

society, it achieves a significant 

reduction in Hg emissions by domestic 

sources. In addition, the cost of reduced 

earnings borne by U.S. citizens from Hg 

exposure falls disproportionately on 

prenatally exposed children of 

populations who consume larger 

amounts of recreationally caught 

freshwater fish than the general 

population. 

The annualized cost of the CAMR, as 

quantified here, is EPA’s best 

assessment of the cost of implementing 

the CAMR, assuming that States adopt 

the model cap-and-trade program. These 

costs are generated from rigorous 

economic modeling of changes in the 

power sector due to the CAMR. This 

type of analysis using IPM has 

undergone peer review and been upheld 

in Federal courts. The direct cost 

includes, but is not limited to, capital 

investments in pollution controls, 

operating expenses of the pollution 

controls, investments in new generating 

sources, and additional fuel 

expenditures. The EPA believes that 

these costs reflect, as closely as possible, 

the additional costs of the CAMR to 

industry. The relatively small cost 

associated with monitoring emissions, 

reporting, and recordkeeping for 

affected sources is not included in these 

annualized cost estimates, but EPA has 

done a separate analysis and estimated 

the cost to less than $76 million. 

However, there may exist certain costs 

that EPA has not quantified in these 

estimates. These costs may include costs 

of transitioning to the CAMR, such as 

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28643

11United States Environmental Protection 

Agency, 2000. Guidelines for Preparing Economic 

Analyses. http://www.yosemite1.epa.gov/ee/epa/

eed/hsf/pages/Guideline.html. Office of 

Management and Budget, The Executive Office of 

the President, 2003. Circular A–4. http://

www.whitehouse.gov/omb/circulars.

employment shifts as workers are 

retrained at the same company or reemployed elsewhere in the economy, 

and certain relatively small permitting 

costs associated with title IV that new 

program entrants face. Costs may be 

understated since an optimization 

model was employed that assumes cost 

minimization, and the regulated 

community may not react in the same 

manner to comply with the final rule. 

Although EPA has not quantified these 

costs, the Agency believes that they are 

small compared to the quantified costs 

of the program on the power sector. The 

annualized cost estimates presented are 

the best and most accurate based upon 

available information.

TABLE 3.—SUMMARY OF ANNUAL BENEFITS, COSTS, AND NET BENEFITS OF THE CAMR a

[billions of 1999 dollars] 

Description 

2020

(millions of

1999 dollars) 

Social Costs: c

3 percent discount rate ............................................................................................................................................................... $848.0

7 percent discount rate ............................................................................................................................................................... 896.0

Social Benefits b, c

3 percent discount rate: 

EPA RfD .............................................................................................................................................................................. 0.4–1.0

No Threshold ....................................................................................................................................................................... 1.7–3.0

7 percent discount rate: 

EPA RfD .............................................................................................................................................................................. 0.2–0.7

No Threshold ....................................................................................................................................................................... 0.8–2.0

Unquantified benefits and costs U 

Annual Net Benefits (Benefits-Costs): c, d

3 percent discount rate: 

EPA RfD .............................................................................................................................................................................. ¥848 + U 

No Threshold ....................................................................................................................................................................... ¥846 + U 

7 percent discount rate: 

EPA RfD .............................................................................................................................................................................. ¥896 + U 

No Threshold ....................................................................................................................................................................... ¥895 + U 

aAll estimates are rounded to first significant digits and represent annualized benefits and costs anticipated in 2020. 

b Not all possible benefits are quantified and monetized in this analysis. B is the sum of all unquantified benefits. Potential benefit categories 

that have not been quantified and monetized are listed in section 10 of the RIA. c Results reflect 3 percent and 7 percent discount rates consistent with EPA and OMB guidelines for preparing economic analyses (U.S. EPA, 

2000, and OMB, 2003).11

d Net benefits are rounded to the nearest $100 million. Columnar totals may not sum due to rounding. 

Every benefit-cost analysis examining 

the potential effects of a change in 

environmental protection requirements 

is limited to some extent by data gaps, 

limitations in model capabilities (such 

as geographic coverage), and 

uncertainties in the underlying 

scientific and economic studies used to 

configure the benefit and cost models. 

Gaps in the scientific literature often 

result in the inability to estimate 

quantitative changes in health and 

environmental effects. Gaps in the 

economics literature often result in the 

inability to assign economic values even 

to those health and environmental 

outcomes that can be quantified. 

Although uncertainties in the 

underlying scientific and economics 

literature (that may result in 

overestimation or underestimation of 

benefits) are discussed in detail in the 

economic analyses and its supporting 

documents and references, the key 

uncertainties which have a bearing on 

the results of the benefit-cost analysis of 

the final rule include the following:

• EPA’s inability to quantify 

potentially significant benefit categories; 

• Uncertainties in population growth 

and baseline incidence rates; 

• Uncertainties in projection of 

emissions inventories and air quality 

into the future; 

• Uncertainty in the estimated 

relationships of health and welfare 

effects to changes in pollutant 

concentrations; 

• Uncertainties in exposure 

estimation; and 

• Uncertainties associated with the 

effect of potential future actions to limit 

emissions. 

Despite these uncertainties, we 

believe the benefit-cost analysis 

provides a reasonable indication of the 

expected economic benefits of the final 

rule in future years under a set of 

reasonable assumptions. 

The benefits estimates generated for 

the final rule are subject to a number of 

assumptions and uncertainties, that are 

discussed throughout the ‘‘Regulatory 

Impact Analysis for the Final Clean Air 

Mercury Rule’’ (March 2005) (OAR–

2002–0056). 

B. Paperwork Reduction Act 

The information collection 

requirements in the final rule will be 

submitted for approval to OMB under 

the Paperwork Reduction Act, 44 U.S.C. 

3501 et seq. The information collection 

requirements are not enforceable until 

OMB approves them.

The information requirements are 

based on notification, recordkeeping 

and reporting requirements in the NSPS. 

The recordkeeping and reporting 

requirements are specifically authorized 

by CAA section 114 (42 U.S.C. 7414) 

and are, therefore, mandatory. All 

information submitted to EPA pursuant 

to the recordkeeping and reporting 

requirements for which a claim of 

confidentiality is made is safeguarded 

according to Agency policies set forth in 

40 CFR. 

The EPA is still working on the 

projected cost and hour burden for 

information requirements mandated by 

the NSPS. Those estimates will be 

28644 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

provided to OMB and notice of their 

availability provided to the public when 

they are completed. The information 

requirements mandated by the NSPS 

requirements for existing sources will be 

essentially the same as those for CAIR. 

The ICR for CAIR has been designated 

as EPA ICR number 2137.01. The EPA 

will, nevertheless, provide a full 

estimate of the projected cost and hour 

burden for those information 

requirements to OMB and provide the 

public with notice of the availability of 

that information. Burden means the 

total time, effort, or financial resources 

expended by persons to generate, 

maintain, retain, or disclose or provide 

information to or for a Federal agency. 

This includes the time needed to review 

instructions; develop, acquire, install, 

and utilize technology and systems for 

the purposes of collecting, validating, 

and verifying information, processing 

and maintaining information, and 

disclosing and providing information; 

adjust the existing ways to comply with 

any previously applicable instructions 

and requirements; train personnel to be 

able to respond to a collection of 

information; search data sources; 

complete and review the collection of 

information; and transmit or otherwise 

disclose the information. 

An agency may not conduct or 

sponsor, and a person is not required to 

respond to a collection of information 

unless it displays a currently valid OMB 

control number. The OMB control 

numbers for EPA’s regulations in 40 

CFR are listed in 40 CFR part 9. When 

the ICR is approved by OMB, the 

Agency will publish a technical 

amendment to 40 CFR part 9 in the 

Federal Register to display the OMB 

control number for the approved 

information collection requirements 

contained in the final rule. 

C. Regulatory Flexibility Act 

The Regulatory Flexibility Act (5 

U.S.C. 601 et seq.) (RFA), as amended 

by the Small Business Regulatory 

Enforcement Fairness Act (Pub. L. 104–

121) (SBREFA), provides that whenever 

an agency is required to publish a 

general notice of rulemaking, it must 

prepare and make available an initial 

regulatory flexibility analysis, unless it 

certifies that the rule, if promulgated, 

will not have ‘‘a significant economic 

impact on a substantial number of small 

entities.’’ (See 5 U.S.C. section 605(b).) 

Small entities include small businesses, 

small organizations, and small 

governmental jurisdictions. 

As was discussed in the January 30, 

2004 NPR and the March 16, 2004 

SNPR, EPA determined that it was not 

necessary to prepare a regulatory 

flexibility analysis in conjunction with 

the final rule. EPA also announced in 

the NPR its determination that, based on 

analysis conducted for the proposed 

rule, CAMR would not have a 

significant impact on a substantial 

number of small entities. Although not 

required by the RFA, the Agency has 

conducted an additional analysis of the 

effects of CAMR on small entities in 

order to provide additional information 

to States and affected sources. 

For purposes of assessing the impacts 

of the final rule on small entities, small 

entity is defined as: (1) A small business 

that is identified by the NAICS Code, as 

defined by the Small Business 

Administration (SBA); (2) a small 

governmental jurisdiction that is a 

government of a city, county, town, 

school district, or special district with a 

population of less that 50,000; and (3) 

a small organization that is any not-forprofit enterprise which is independently 

owned and operated and is not 

dominant in its field. Categories and 

entities potentially regulated by the 

final rule with applicable NAICS codes 

are provided in the Supplementary 

Information section of this action. 

According to the SBA size standards 

for NAICS code 221122 Utilities-Fossil 

Fuel Electric Power Generation, a firm 

is small if, including its affiliates, it is 

primarily engaged in the generation, 

transmission, and or distribution of 

electric energy for sale and its total 

electric output for the preceding fiscal 

year did not exceed 4 million MWh. 

Courts have interpreted the RFA to 

require a regulatory flexibility analysis 

only when small entities will be subject 

to the requirements of the rule. (See 

Michigan v. EPA, 213 F.3d 663, 668–69 

(DC Cir. 2000), cert. den. 121 S.Ct. 225, 

149 L.Ed.2d 135 (2001).) 

The final rule would not establish 

requirements applicable to small 

entities, other than those that are new 

sources subject to NSPS. We believe that 

there will not by any such small entities 

subject to the final rule because the IPM 

projects no new construction of coalfired utility units. Additionally, the 

CAMR rule does not establish 

requirements applicable to small 

entities because the final rule requires 

States to develop, adopt, and submit a 

State Plan that would achieve the 

necessary Hg emissions reductions, and 

would leave to the States the task of 

determining how to obtain those 

reductions, including which Utility 

Units to regulate. 

EPA’s analysis of the final rule 

supports the results of the earlier 

analysis discussed in the NPR that 

found that CAMR would not have a 

significant direct impact on a 

substantial number of small entities, 

although there could be an increase in 

their costs of electricity. Analysis 

conducted for the final rule projects that 

in 2020, 2 years into the start of the 

second phase of the cap-and-trade 

program, the total compliance costs to 

small entities under CAMR would be 

approximately $37 million. This is just 

under 1 percent of the total projected 

electricity generation revenues to small 

entities for 2020. A few of the 80 small 

entities identified in EPA’s analysis may 

experience significant costs in 2020. 

These entities do not bank over the 

course of the program, and must 

purchase allowances in 2020 to cover 

their emissions. It is important to note 

that the marginal cost of Hg control in 

2020 projected by EPA modeling is 

largely responsible for the presence of 

significant impacts. EPA’s modeling 

assumes no improvements in the cost or 

effectiveness of Hg control technology 

over time. In reality, by 2020, costs of 

Hg control are expected to have 

declined, such that the actual impacts of 

the cap-and-trade program on small 

entities will be less than projected. 

Additionally, given that most of the 

small entities identified operate in 

market environments in which they can 

pass on compliance costs to consumers, 

most of these entities should be able to 

recover their costs of compliance with 

CAMR.

Two other points should be 

considered when evaluating the impact 

of CAMR, specifically, and cap-andtrade programs more generally, on small 

entities. First, under CAMR, the capand-trade program is designed such that 

States determine how Hg allowances are 

to be allocated across units. A State that 

wishes to mitigate the impact of the 

final rule on small entities might choose 

to allocate Hg allowances in a manner 

that is favorable to small entities. 

Finally, the use of cap-and-trade in 

general will limit impacts on small 

entities relative to a less flexible 

command-and-control program. 

D. Unfunded Mandates Reform Act 

Title II of the Unfunded Mandates 

Reform Act of 1995 (Pub. L. 104–4) 

(UMRA), establishes requirements for 

Federal agencies to assess the effects of 

their regulatory actions on State, local, 

and Tribal governments and the private 

sector. Under UMRA section 202, 2 

U.S.C. 1532, EPA generally must 

prepare a written statement, including a 

cost-benefit analysis, for any proposed 

or final rule that ‘‘includes any Federal 

mandate that may result in the 

expenditure by State, local, and Tribal 

governments, in the aggregate, or by the 

private sector, of $100,000,000 or more 

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28645

* * * in any one year.’’ A ‘‘Federal 

mandate’’ is defined under section 

421(6), 2 U.S.C. 658(6), to include a 

‘‘Federal intergovernmental mandate’’

and a ‘‘Federal private sector mandate.’’

A ‘‘Federal intergovernmental 

mandate,’’ in turn, is defined to include 

a regulation that ‘‘would impose an 

enforceable duty upon State, local, or 

Tribal governments,’’ section 

421(5)(A)(i), 2 U.S.C. 658(5)(A)(i), 

except for, among other things, a duty 

that is ‘‘a condition of Federal 

assistance,’’ section 421(5)(A)(i)(I). A 

‘‘Federal private sector mandate’’

includes a regulation that ‘‘would 

impose an enforceable duty upon the 

private sector,’’ with certain exceptions, 

section 421(7)(A), 2 U.S.C. 658(7)(A). 

Before promulgating an EPA rule for 

which a written statement is needed 

under UMRA section 202, UMRA 

section 205, 2 U.S.C. 1535, generally 

requires EPA to identify and consider a 

reasonable number of regulatory 

alternatives and adopt the least costly, 

most cost-effective, or least burdensome 

alternative that achieves the objectives 

of the rule. 

The EPA prepared a written statement 

for the final rule consistent with the 

requirements of UMRA section 202. 

Furthermore, as EPA stated in the final 

rule, EPA is not directly establishing 

any regulatory requirements that may 

significantly or uniquely affect small 

governments, including Tribal 

governments. Thus, EPA is not obligated 

to develop under UMRA section 203 a 

small government agency plan. 

Furthermore, in a manner consistent 

with the intergovernmental consultation 

provisions of UMRA section 204, EPA 

carried out consultations with the 

governmental entities affected by the 

final rule. 

For the final rule, EPA has conducted 

an analysis of the potential economic 

impacts anticipated of CAMR on 

government-owned entities. These 

results support EPA’s assertion in the 

NPR that the proposed rule would not 

have a disproportionate budgetary 

impact on government entities. Overall, 

analysis conducted for the final rule 

projects that in 2020, 2 years into the 

start of the second phase of the cap-andtrade program, compliance costs to 

government-owned entities would be 

approximately $48 million. This cost is 

less than one-half of 1 percent of 

projected electricity generation revenues 

for these entities in 2020. A few of the 

88 entities identified in EPA analysis 

are projected to experience significant 

costs in 2020. These entities do not bank 

over the course of the program, and 

must purchase allowances in 2020 to 

cover their emissions. As was the case 

in EPA’s analysis of small entities, it is 

important to note that the marginal cost 

of Hg control in 2020 projected by EPA 

modeling is largely responsible for the 

presence of significant impacts in the 

analysis. EPA modeling assumes no 

improvements in the cost or 

effectiveness of Hg control technology 

over time. In reality, by 2020, costs of 

Hg control are expected to have 

declined, such that the impacts of the 

cap-and-trade program on small entities 

would be reduced. Additionally, given 

that most of the small entities identified 

operate in market environments in 

which they can pass on compliance 

costs to consumers, most of these 

entities should be able to recover their 

costs of compliance with CAMR. 

Potentially adverse impacts of CAMR 

on State and municipality-owned 

entities could be limited by the fact that 

the cap-and-trade program is designed 

such that States determine how Hg 

allowances are to be allocated across 

units. A State that wishes to mitigate the 

impact of the final rule on State or 

municipality-owned entities might 

choose to allocate Hg allowances in a 

manner that is favorable to these 

entities. Finally, the use of cap-andtrade in general will limit impacts on 

entities owned by small governments 

relative to a less flexible command-andcontrol program. 

EPA has determined that the final rule 

may result in expenditures of more than 

$100 million to the private sector in any 

single year. EPA believes that the final 

rule represents the least costly, most 

cost-effective approach to achieve the 

air quality goals of the final rule. The 

costs and benefits associated with the 

final rule are discussed above and in the 

RIA. 

As noted earlier, however, EPA 

prepared for the final rule the statement 

that would be required by UMRA if its 

statutory provisions applied, and EPA 

has consulted with governmental 

entities as would be required by UMRA. 

Consequently, it is not necessary for 

EPA to reach a conclusion as to the 

applicability of the UMRA 

requirements. 

E. Executive Order 13132: Federalism 

EO 13132 (64 FR 43255, August 10, 

1999) requires EPA to develop an 

accountable process to ensure 

‘‘meaningful and timely input by State 

and local officials in the development of 

regulatory policies that have federalism 

implications.’’ ‘‘Policies that have 

federalism implications’’ is defined in 

the EO to include regulations that have 

‘‘substantial direct effects on the States, 

on the relationship between the national 

government and the States, or on the 

distribution of power and 

responsibilities among the various 

levels of government.’’

The final rule does not have 

federalism implications. It will not have 

substantial direct effects on the States, 

on the relationship between the national 

government and the States, or on the 

distribution of power and 

responsibilities among the various 

levels of government, as specified in EO 

13132. The CAA establishes the 

relationship between the Federal 

government and the States, and the final 

rule does not impact that relationship. 

Thus, EO 13132 does not apply to the 

final rule. In the spirit of EO 13132, and 

consistent with EPA policy to promote 

communications between EPA and State 

and local governments, EPA specifically 

solicited comment on the rule, as 

proposed, from State and local officials. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments

EO 13175 (65 FR 67249, November 9, 

2000) requires EPA to develop an 

accountable process to ensure 

‘‘meaningful and timely input by Tribal 

officials in the development of 

regulatory policies that have Tribal 

implications.’’ The final rule does not 

have ‘‘Tribal implications’’ as specified 

in EO 13175 because it does not have a 

substantial direct effect on one or more 

Indian Tribes. No Tribe has 

implemented a federally enforceable air 

quality management program under the 

CAA at this time. Furthermore, the final 

rule does not affect the relationship or 

distribution of power and 

responsibilities between the Federal 

government and Indian Tribes. The 

CAA and the Tribal Authority Rule 

(TAR) (40 CFR 49.1 through 49.11) 

establish the relationship of the Federal 

government and Tribes in developing 

plans to attain the national ambient air 

quality standards (NAAQS), and the 

final rule does nothing to modify that 

relationship. Because the final rule does 

not have Tribal implications, EO 13175 

does not apply. 

The final rule addresses pollution 

composed of Hg and mercuric 

compounds. The final CAMR requires 

annual Hg reductions for the power 

sector in 50 States, the District of 

Columbia, and in Indian country, 

through a cap-and-trade system that 

States and eligible Tribes have the 

option of adopting. The CAA provides 

for States and eligible Tribes to develop 

plans to regulate emissions of air 

pollutants within their areas. The 

regulations clarify the statutory 

obligations of States and eligible Tribes 

that develop plans to implement the 

28646 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

final rule. The TAR gives eligible Tribes 

the opportunity to develop and 

implement CAA programs, but it leaves 

to the discretion of the Tribe whether to 

develop these programs and which 

programs, or appropriate elements of a 

program, the Tribe will adopt. As noted 

earlier, the EPA will implement the 

emission trading rule for coal-fired 

Utility Units located in Indian Country 

in accordance with the TAR unless the 

relevant Tribe for the land on which a 

particular coal-fired Utility Unit is 

located seeks and obtains TAS status 

and submits a TIP to implement the 

allocated Hg emissions budget. Tribes 

which choose to do so will be 

responsible for submitting a TIP 

analogous to the State Plans discussed 

throughout this preamble, and, like 

States, can chose to adopt the model 

cap-and-trade rule described elsewhere 

in this action. 

EPA notes that in the event a Tribe 

does implement a TIP in the future, the 

final rule could have implications for 

that Tribe, but it would not impose 

substantial direct costs upon the Tribe, 

nor preempt Tribal law. As provided 

above, EPA has estimated that the total 

annual private costs for the final rule for 

Hg as implemented by State, local, and 

eligible Tribal governments (or EPA in 

the absence of any Tribe seeking TAS 

status) is approximately $160 million in 

2010, $100 million in 2015, and $750 

million in 2020 (1999$). There are 

currently three coal-fired Utility Units 

located in Indian country that will be 

affected by the final rule and the 

percentage of Indian country that will 

be impacted is very small. For eligible 

Tribes that choose to regulate sources in 

Indian country, the costs would be 

attributed to inspecting regulated 

facilities and enforcing adopted 

regulations. 

EPA consulted with Tribal officials in 

developing the final rule. The EPA 

encouraged Tribal input at an early 

stage. A Tribal representative from the 

Navajo Nation was a member the official 

workgroup and was provided with all 

workgroup materials. The EPA has 

provided two briefings for Tribal 

representatives and the newly formed 

National Tribal Air Association (NTAA), 

and other national Tribal forums such as 

the National Tribal Environmental 

Council (NTEC) and the National Tribal 

Forum during the period prior to 

issuance of the NPR. Another briefing 

for Tribal representatives, NTAA, and 

NTEC was provided post-proposal to 

provide opportunity for additional 

input. Input from Tribal representatives 

has been taken into consideration in 

development of the final rule. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

and Safety Risks 

EO 13045 (62 FR 19885, April 23, 

1997) applies to any rule that (1) is 

determined to be ‘‘economically 

significant’’ as defined under EO 12866, 

and (2) concerns an environmental 

health or safety risk that EPA has reason 

to believe may have a disproportionate 

effect on children. If the regulatory 

action meets both criteria, Section 5–

501 of the EO directs the Agency to 

evaluate the environmental health or 

safety effects of the planned rule on 

children, and explain why the planned 

regulation is preferable to other 

potentially effective and reasonably 

feasible alternatives considered by the 

Agency. 

The final rule is subject to the EO 

because it is an economically significant 

regulatory action as defined by EO 

12866, and we believe that the 

environmental health or safety risk 

addressed by this action may have a 

disproportionate effect on children. 

Accordingly, we have evaluated the 

environmental health or safety effects of 

the final rule on children. The results of 

this evaluation are discussed elsewhere 

in this preamble and the RIA, and are 

contained in the docket. 

As discussed in the RIA, EPA and the 

NRC of the National Academy of 

Science (NAS) identified 

neurodevelopmental effects as the most 

sensitive endpoints (NRC 2000) and, 

thus, the appropriate endpoint upon 

which to establish a health-based 

standard establishing the level of 

exposure to MeHg that would result in 

a nonappreciable risk. As such, EPA has 

established its health-based ingestion 

rate, or RfD at a level designed to protect 

children prenatally exposed to MeHg. 

The RfD is an estimate (with uncertainty 

spanning perhaps an order of 

magnitude) of a daily exposure to the 

human population (including sensitive 

subgroups) that is likely to be without 

an appreciable risk of deleterious effects 

during a lifetime (EPA 2002). EPA 

believes that exposures at or below the 

RfD are unlikely to be associated with 

appreciable risk of deleterious effects. It 

is important to note, however, that the 

RfD does not define an exposure level 

corresponding to zero risk; Hg exposure 

near or below the RfD could pose a very 

low level of risk which EPA deems to 

be non-appreciable. It is also important 

to note that the RfD does not define a 

bright line, above which individuals are 

at risk of adverse effect. CAMR benefits 

prenatally exposed children by 

contributing to the reduction in the 

number of women of childbearing age 

who ingest Hg at a rate that exceeds the 

RfD due solely to power plants and by 

contributing the to the overall reduction 

in exposure to MeHg of women of 

childbearing age. 

In order to protect prenatally exposed 

children, it is appropriate to focus on 

reducing MeHg exposure for women of 

childbearing age. In the U.S., the 

primary means of exposure to MeHg is 

through the consumption of fish 

containing MeHg. When emitted, Hg 

deposits in water bodies where bacteria 

in the sediment can convert that Hg in 

the MeHg which can then 

bioaccumulate in fish. By reducing the 

amount of Hg deposition, CAMR 

reduces the amount of Hg that is 

available for methylation, which in turn 

reduces the amount that can be taken up 

by fish and then consumed by women 

of childbearing age. This chain of events 

ultimately reduces exposure to the 

developing fetus. Thus, CAMR is 

specifically targeted at protecting 

children in their most vulnerable 

phase—during fetal development.

EPA’s ability to reduce exposure by 

reducing Utility Unit emissions is 

limited by the fact that emissions from 

U.S. Utility Units are only one source of 

domestic Hg deposition. Further, the 

impact of U.S. Utility Unit emissions on 

fish tissue MeHg concentrations is not 

likely to be as significant for marine 

species, which on average accounts for 

about 63 percent of consumption for the 

U.S. general population and 60 percent 

of consumption for U.S. women of 

childbearing age. Nevertheless, EPA 

chose a regulatory approach that 

required Hg-specific reductions of 

Utility Unit emissions by setting a cap 

on total emissions in 2018. This Hgspecific cap, combined with the cobenefits associated with reductions of 

SO2 and NOX required by EPA’s CAIR, 

will provide for reduction in MeHg 

exposure to U.S. women of childbearing 

age. 

CAMR will reduce the level of 

exposures to children from current 

levels today. In section 11 of the RIA, 

we estimate that 529,000 to 825,000 

children will be exposed to MeHg 

prenatally in 2020. Our RIA analyses 

assess how IQ decrements, which were 

used as a surrogate representing the 

neurodevelopmental effects of MeHg 

exposure, will be reduced as a result of 

CAMR. Because these analyses only 

quantitatively assess benefits in terms of 

IQ loss, the overall quantified benefit to 

the prenatally exposed children is likely 

to be understated. Compared to the 

other regulatory alternative considered 

during the final rule, the selected 

approach delivers about the same 

amount of benefits at a lower cost. 

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28647

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

EO 13211 (66 FR 28355, May 22, 

2001) provides that agencies shall 

prepare and submit to the Administrator 

of the Office of Regulatory Affairs, OMB, 

a Statement of Energy Effects for certain 

actions identified as ‘‘significant energy 

actions.’’ Section 4(b) of EO 13211 

defines ‘‘significant energy actions’’ as 

any action by an agency (normally 

published in the Federal Register) that 

promulgates or is expected to lead to the 

promulgation of a final rule or 

regulation, including notices of inquiry, 

advance notices of final rulemaking, and 

notices of final rulemaking: (1)(i) That is 

a significant regulatory action under EO 

12866 or any successor order, and (ii) is 

likely to have a significant adverse effect 

on the supply, distribution, or use of 

energy; or (2) that is designated by the 

Administrator of the Office of 

Information and Regulatory Affairs as a 

‘‘significant energy action.’’ Although 

the final rule is a significant regulatory 

action under EO 12866, the final rule 

likely will not have a significant adverse 

effect on the supply, distribution, or use 

of energy. 

CAMR, in conjunction with CAIR, has 

the potential to require installation of 

significant amounts of control 

equipment at power plants that are 

integral to the country’s electric power 

supply, and, in light of this, EPA has 

focused on minimizing the impacts of 

CAMR throughout the development of 

the final rule. The final rule uses costeffective, market-based mechanisms 

while providing regulatory certainty and 

sufficient time to achieve reductions of 

Hg emissions from the power sector in 

a way that will help the country 

maintain electric reliability and 

affordability while ensuring 

environmental goals are met. In 

addition, Hg reductions have been 

coordinated with the CAIR, with the 

first phase reductions set at a cap level 

that reflects the Hg reductions that 

would be achieved from the SO2 and 

NOX cap levels under CAIR. Although 

the Administration has sought multipollutant legislation, like the Clear Skies 

Act, EPA has acted in accordance with 

the CAA to ensure substantial reduction 

of pollution to protect human health 

and welfare. 

EPA has conducted the analysis of the 

final rule assuming States participate in 

a cap-and-trade program to reduce 

emissions from Utility Units. EPA does 

not believe that the final rule will have 

any impacts incremental to CAIR that 

exceed the significance criteria, 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 addition, the EPA believes that a 

number of features of the final rule serve 

to reduce its impact on energy supply. 

First, the optional trading program 

provides considerable flexibility to the 

power sector and enables industry to 

comply with the emission reduction 

requirements in the most cost-effective 

manner, thus minimizing overall costs 

and the ultimate impact on energy 

supply. The ability to use banked 

allowances from the first phase of the 

program also provides additional 

flexibility. Second, the CAMR caps are 

set in two phases, provide adequate 

time for Utility Units to install pollution 

controls, and Hg reductions have been 

coordinated with the CAIR, with the 

first phase reductions set at a cap level 

that reflects the Hg reductions that 

would be achieved from the SO2 and 

NOX cap levels under CAIR. 

For more details concerning energy 

impacts, see ‘‘Regulatory Impact 

Analysis for the Final Clean Air 

Mercury Rule’’ (March 2005) (OAR–

2002–0056). 

I. National Technology Transfer and 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act (NTTAA) of 1995 (Pub. L. 104–113; 

Section 12(d), 15 U.S.C. 272 note) 

directs EPA to use voluntary consensus 

standards (VCS) in their regulatory and 

procurement activities unless to do so 

would be inconsistent with applicable 

law or otherwise impractical. Voluntary 

consensus standards are technical 

standards (e.g., materials specifications, 

test methods, sampling procedures, 

business practices) developed or 

adopted by one or more voluntary 

consensus bodies. NTTAA directs EPA 

to provide Congress, through annual 

reports to OMB, with explanations 

when an agency does not use available 

and applicable VCS. 

The final rule involves technical 

standards. The EPA methods cited in 

the final rule are: 1, 1A, 2, 2A, 2C, 2D, 

2F, 2G, 2H, 3, 3A, 3B, 4, 6, 6A, 6C, 7, 

7A, 7C, 7D, 7E, 19, 20, and 29 (for Hg 

only) of 40 CFR part 60, appendix A; PS 

2 and 12A of 40 CFR part 60, appendix 

B; 40 CFR part 75, appendix K; and 

ASTM D6784–02, ‘‘Standard Test 

Method for Elemental, Oxidized, 

Particle-Bound and Total Mercury Gas 

Generated from Coal-Fired Stationary 

Sources (Ontario Hydro Method).’’

Consistent with the NTTAA, EPA 

conducted searches to identify VCS in 

addition to these EPA methods/

performance specifications. No 

applicable VCS were identified for EPA 

Method 1A, 2A, 2D, 2F, 2G, 2H, 7D, and 

19, of 40 CFR part 60, appendix A; 40 

CFR part 75, appendix K; and ASTM 

D6784–02. The search and review 

results have been documented and are 

placed in the docket for the final rule. 

One VCS was identified as an 

acceptable alternative for the EPA 

methods cited in the final rule. The VCS 

ASME PTC 19–10–1981–Part 10, ‘‘Flue 

and Exhaust Gas Analyses,’’ is cited in 

the final rule for its manual method for 

measuring the oxygen, carbon dioxide 

(CO2), SO2, and NOX content of exhaust 

gas. These parts of ASME PTC 19–10–

1981–Part 10 are acceptable alternatives 

to EPA Methods 3B, 6, 6A, 7, 7C, and 

20 of 40 CFR part 60 (SO2 only).

The standard ASTM D6784–02, 

Standard Test Method for Elemental, 

Oxidized, Particle-Bound and Total 

Mercury Gas Generated from Coal-Fired 

Stationary Sources (Ontario Hydro 

Method), cited in the final rule for 

measuring Hg emissions is a VCS. 

In addition to the VCS EPA uses in 

the final rule, the search for emissions 

measurement procedures identified 14 

other VCS. The EPA determined that 12 

of these 14 standards identified for 

measuring air emissions or surrogates 

subject to emission standards in the 

final rule were impractical alternatives 

to EPA test methods/performance 

specifications for the purposes of the 

rule. Therefore, the EPA does not intend 

to adopt these standards. The reasons 

for the determinations of these 12 

standards are found in the docket. 

Two of the 14 VCS identified in this 

search were not available at the time the 

review was conducted for the purposes 

of the final rule because they are under 

development by a voluntary consensus 

body: ASME/BSR MFC 12M, ‘‘Flow in 

Closed Conduits Using Multiport 

Averaging Pitot Primary Flowmeters,’’

for EPA Method 2, and ASME/BSR MFC 

13M, ‘‘Flow Measurement by Velocity 

Traverse,’’ for EPA Method 2 (and 

possibly 1). 

The EPA testing methods, 

performance specifications, and 

procedures required are discussed in 40 

CFR 60.49a, 40 CFR part 75, and PS 

12A. Under 40 CFR 63.7(f) and 63.8(f) 

of subpart A of the General Provisions, 

a source may apply to EPA for 

permission to use alternative test 

methods or alternative monitoring 

requirements in place of any of the EPA 

testing methods, performance 

specifications, or procedures. 

28648 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

12U.S. Environmental Protection Agency, 1998. 

Guidance for Incorporating Environmental Justice 

Concerns in EPA’s NEPA Compliance analyses. 

Office of Federal Activities, Washington, DC, April, 

1998.

J. Executive Order 12898: Federal 

Actions to Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

EO 12898 requires Federal agencies to 

consider the impact of programs, 

policies, and activities on minority 

populations and low-income 

populations. According to EPA 

guidance,12 agencies are to assess 

whether minority or low-income 

populations face risks or a rate of 

exposure to hazards that are significant 

and that ‘‘appreciably exceed or is likely 

to appreciably exceed the risk or rate to 

the general population or to the 

appropriate comparison group.’’ (EPA, 

1998)

In accordance with EO 12898, the 

Agency has considered whether the 

final rule may have disproportionate 

negative impacts on minority or low 

income populations. The Agency 

expects the final rule to lead to 

beneficial reductions in air pollution 

and exposures generally with a small 

negative impact through increased 

utility bills. The increase in the price for 

electric power is estimated to be 0.2 

percent of retail electricity prices and is 

shared among all members of society 

equally and, thus, is not considered to 

be a disproportionate impact on 

minority populations and low-income 

populations. For this reason, negative 

impacts to these sub-populations that 

appreciably exceed similar impacts to 

the general population are not expected. 

There will be beneficial outcomes to 

these populations as a result of this 

action. In the absence of CAMR, there 

are health effects that are likely to affect 

certain populations in the U.S., 

including subsistence anglers, Native 

Americans, and Asian American. These 

populations may include low income 

and minority populations who are 

disproportionately impacted by Hg 

exposures due to their economic, 

cultural, and religious activities that 

lead to higher levels of consumption of 

fish than the general population. The 

CAMR is expected to reduce exposures 

to these populations. 

For subsistence anglers, we conducted 

an analysis in section 10 of the RIA 

using two alternative approaches to 

determine potentially exposed 

subsistence anglers, including one 

analytical approach based on income 

(i.e., the population below $10,000 

annual income who may eat self-caught 

fish as a means of obtaining a low-cost 

source of protein), and another 

analytical approach based on total 

consumption levels (i.e., those anglers 

who eat two to three fish meals per day 

are assumed to be subsistence). Our 

analysis shows that the final rule will 

result in total benefits (under a scenario 

of no threshold on effects at low doses 

of Hg) accrued to potentially prenatally 

exposed children in the homes of 

subsistence anglers of $454,000 to 

$573,000 in 2020 when using a 3 

percent discount rate (or $212,000 to 

$391,000 when using a 7 percent 

discount rate). 

We also conducted case studies of the 

potential benefits of CAMR to a Native 

American population and an Asian 

American population located in 

Wisconsin, Minnesota, and (for one of 

the case studies) Michigan. The Agency 

was unable to transfer the results of 

these case studies to the rest of the 

Native American and Asian American 

populations in the U.S. due to missing 

data elements for analysis in other parts 

of the country. 

In the case study of the Chippewa in 

Minnesota, Wisconsin, and Michigan, 

we determined that this group would 

accrue total benefits (under an 

assumption of no threshold on effects at 

low doses of Hg) of $6,300 to $6,700 in 

2020 when using a 3 percent discount 

rate across the group as a whole (or 

$3,000 to $4,600 when using a 7 percent 

discount rate) due to reduced Hg 

exposures from consuming self-caught 

freshwater fish. Other tribal populations 

were not evaluated due to lack of 

reliable data on yearly (annual) selfcaught fish consumption by location 

and tribe (although they were 

considered in a sensitivity analysis 

examining the issue of distributional 

equity—see below). 

In a case study of the Hmong (a 

Southeast Asian-American population) 

in Minnesota and Wisconsin, we 

determined that the population would 

accrue total benefits (under an 

assumption of no threshold on effects at 

low doses of Hg) of $3,300 to $3,500 

when using a 3 percent discount rate (or 

$1,500 to $2,400 when using a 7 percent 

discount rate).

To further examine whether high fishconsuming (subsistence) populations 

might be disproportionately benefitted 

by the final rule (i.e., whether 

distributional equity is a consideration) 

and in response to concerns received in 

the comments on the NODA regarding 

high fish consumption rates for Ojibwe 

in the Great Lakes area, EPA conducted 

a sensitivity analysis focusing 

specifically on the distributional equity 

issue. The sensitivity analysis applied 

high-end (near bounding) fish 

consumption rates for Native American 

subsistence populations to the 

maximum expected Hg fish-tissue 

concentration changes predicted to 

result from CAMR within regions of the 

37-State study area with recognized 

Native American populations. The fish 

consumption rates used in this 

sensitivity analysis were based on 

comments received through the NODA 

characterizing high-end consumption 

for the Ojibwe Tribes in Wisconsin and 

Minnesota. These values represent very 

high consumption rates exceeding the 

high-end (95th percentile) consumption 

rates recommended by the EPA for 

Native American subsistence 

populations and consequently are 

appropriate for a sensitivity analysis. 

The sensitivity analysis suggested that, 

although Native American subsistence 

populations (and other high fish 

consuming populations) might 

experience relatively larger health 

benefits from the final rule compared 

with general recreational angler, the 

absolute degree of health benefits 

involved are relatively low (i.e., less 

than a 1.0 IQ point change per fisher for 

any of the locations modeled). This 

sensitivity analysis also provided 

coverage for the Hmong population 

modeled for the RIA, and the 

conclusions cited above regarding 

relatively low IQ changes (less than 1.0) 

can also be applied to this high fish 

consuming population. 

K. Congressional Review Act 

The Congressional Review Act, 5 

U.S.C. 801 et seq., as added by SBREFA 

of 1996, generally provides that before 

a rule may take effect, the agency 

promulgating the rule must submit a 

rule report, which includes a copy of 

the rule, to each House of the Congress 

and to the Comptroller General of the 

U.S. The EPA will submit a report 

containing the final rule and other 

required information to the U.S. Senate, 

the U.S. House of Representatives, and 

the Comptroller General of the U.S. 

prior to publication of the rule in the 

Federal Register. A Major rule cannot 

take effect until 60 days after it is 

published in the Federal Register. The 

final rule is a ‘‘major rule’’ as defined by 

5 U.S.C. 804(2).

List of Subjects 

40 CFR Part 60

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Coal, Electric 

power plants, Incorporation by 

reference, Intergovernmental relations, 

Metals, Natural gas, Nitrogen dioxide, 

Particulate matter, Reporting and 

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28649 

recordkeeping requirements, Sulfur 

oxides 

40 CFR Part 72 

Acid rain, Administrative practice 

and procedure, Air pollution control, 

Electric utilities, Intergovernmental 

relations, Nitrogen oxides, Reporting 

and recordkeeping requirements, Sulfur 

oxides. 

40 CFR Part 75 

Acid rain, Air pollution control, 

Carbon dioxide, Electric utilities, 

Incorporation by reference, Nitrogen 

oxides, Reporting and recordkeeping 

requirements, Sulfur oxides. 

Dated: March 15, 2005. 

Stephen Johnson, 

Acting Administrator. 

■ For the reasons stated in the preamble, 

title 40, chapter I, parts 60, 72, and 75 

of the Code of the Federal Regulations 

are amended as follows: 

PART 60—[AMENDED] 

■ 1. The authority citation for part 60 

continues to read as follows: 

Authority: 42 U.S.C. 7401, 7403, 7426, and 

7601. 

■ 2. Section 60.17 is amended by: 

■ a. In the introductory text, the phrase 

‘‘(MD–35)’’ is revised to read ‘‘(C267–

01);’’

■ b. In paragraph (a)(12), revising the 

term ‘‘77, 90, 91, 95, 98a’’ to read ‘‘77, 

90, 91, 95, 98a, 99 (Reapproved 

2004) ε1 ;’’ revising the word 

‘‘§§ 60.41(f),’’ to read ‘‘§§ 60.24(h)(8), 

60.41(f);’’ and revising the words ‘‘and 

60.251(b) and (c).’’ to read ‘‘60.251(b) 

and (c), and 60.4102.’’

■ c. In paragraph (a)(22), revising the 

term ‘‘87, 91, 97’’ to read ‘‘87, 91, 97, 

03a’’ and revising the word §§ 60.41b 

and 60.41c’’ to read ‘‘§§ 60.41a of 

subpart Da of this part, 60.41b of 

subpart Db of this part, and 60.41c of 

subpart Dc of this part.’’

■ d. By adding paragraph (a)(76) to read 

as follows: 

§ 60.17 Incorporations by Reference. 

* * * * * 

(a) * * * 

(76) ASTM D6784–02, Standard Test 

Method for Elemental, Oxidized, 

Particle-Bound and Total Mercury in 

Flue Gas Generated from Coal-Fired 

Stationary Sources (Ontario Hydro 

Method), IBR approved for appendix B 

to part 60, Performance Specification 

12A, section 8.6.2. 

* * * * * 

■ 3. Section 60.21 is amended by: 

■ a. Revise paragraphs (a) and (f); and 

■ b. Add a new paragraph (k) to read as 

follows: 

§ 60.21 Definitions. 

* * * * * 

(a) Designated pollutant means any 

air pollutant, the emissions of which are 

subject to a standard of performance for 

new stationary sources, but for which 

air quality criteria have not been issued 

and that is not included on a list 

published under section 108(a) of the 

Act. Designated pollutant also means 

any air pollutant, the emissions of 

which are subject to a standard of 

performance for new stationary sources, 

that is on the section 112(b)(1) list and 

is emitted from a facility that is not part 

of a source category regulated under 

section 112. Designated pollutant does 

not include pollutants on the section 

112(b)(1) list that are emitted from a 

facility that is part of a source category 

regulated under section 112. 

* * * * * 

(f) Emission standard means a legally 

enforceable regulation setting forth an 

allowable rate of emissions into the 

atmosphere, establishing an allowance 

system, or prescribing equipment 

specifications for control of air pollution 

emissions. 

* * * * * 

(k) Allowance system means a control 

program under which the owner or 

operator of each designated facility is 

required to hold an authorization for 

each specified unit of a designated 

pollutant emitted from that facility 

during a specified period and which 

limits the total amount of such 

authorizations available to be held for a 

designated pollutant for a specified 

period and allows the transfer of such 

authorizations not used to meet the 

authorization-holding requirement. 

■ 4. Section 60.24 is amended by: 

■ a. Revising paragraph (b)(1); and 

■ b. Adding a new paragraph (h) to read 

as follows: 

§ 60.24 Emission standards and 

compliance schedules. 

* * * * * 

(b)(1) Emission standards shall either 

be based on an allowance system or 

prescribe allowable rates of emissions 

except when it is clearly impracticable. 

* * * 

* * * * * 

(h) Each of the States identified in 

paragraph (h)(1) of this section shall be 

subject to the requirements of 

paragraphs (h)(2) through (7) of this 

section. 

(1) Alaska, Alabama, Arkansas, 

Arizona, California, Colorado, 

Connecticut, Delaware, Florida, Georgia, 

Hawaii, Idaho, Illinois, Indiana, Iowa, 

Kansas, Kentucky, Louisiana, Maine, 

Maryland, Massachusetts, Michigan, 

Minnesota, Mississippi, Missouri, 

Montana, Nebraska, Nevada, New 

Hampshire, New Jersey, New Mexico, 

New York, North Carolina, North 

Dakota, Ohio, Oklahoma, Oregon, 

Pennsylvania, Rhode Island, South 

Carolina, South Dakota, Tennessee, 

Texas, Utah, Vermont, Virginia, 

Washington, West Virginia, Wisconsin, 

Wyoming, and the District of Columbia 

shall each, and, if approved for 

treatment as a State under part 49 of this 

chapter, the Navajo Nation and the Ute 

Indian Tribe may each, submit a State 

plan meeting the requirements of 

paragraphs (h)(2) through (7) of this 

section and the other applicable 

requirements for a State plan under this 

subpart. 

(2) The State’s State plan under 

paragraph (h)(1) of this section must be 

submitted to the Administrator by no 

later than November 17, 2006. The State 

shall deliver five copies of the State 

plan to the appropriate Regional Office, 

with a letter giving notice of such 

action. 

(3) The State’s State plan under 

paragraph (h)(1) of this section shall 

contain emission standards and 

compliance schedules and demonstrate 

that they will result in compliance with 

the State’s annual electrical generating 

unit (EGU) mercury (Hg) budget for the 

appropriate periods. The amount of the 

annual EGU Hg budget, in tons of Hg 

per year, shall be as follows, for the 

indicated State for the indicated period: 

State 

Annual EGU Hg budget 

(tons) 

2010–2017 2018 and 

thereafter 

Alaska ............... 0 .005 0 .002 

Alabama ............ 1 .289 0 .509 

Arkansas ........... 0 .516 0 .204 

Arizona .............. 0 .454 0 .179 

California ........... 0 .041 0 .016 

Colorado ........... 0 .706 0 .279 

Connecticut ....... 0 .053 0 .021 

Delaware ........... 0 .072 0 .028 

District of Columbia ............ 0 0 

Florida ............... 1 .233 0 .487 

Georgia ............. 1 .227 0 .484 

Hawaii ............... 0 .024 0 .009 

Idaho ................. 0 0 

Iowa .................. 0 .727 0 .287 

Illinois ................ 1 .594 0 .629 

Indiana .............. 2 .098 0 .828 

Kansas .............. 0 .723 0 .285 

Kentucky ........... 1 .525 0 .602 

Louisiana .......... 0 .601 0 .237 

Massachusetts .. 0 .172 0 .068 

Maryland ........... 0 .49 0 .193 

Maine ................ 0 .001 0 .001 

Michigan ........... 1 .303 0 .514 

28650 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

State 

Annual EGU Hg budget 

(tons) 

2010–2017 2018 and 

thereafter 

Minnesota ......... 0 .695 0 .274 

Missouri ............ 1 .393 0 .55 

Mississippi ........ 0 .291 0 .115 

Montana ............ 0 .378 0 .149 

North Carolina .. 1 .133 0 .447 

North Dakota .... 1 .564 0 .617 

Nebraska .......... 0 .421 0 .166 

New Hampshire 0 .063 0 .025 

New Jersey ....... 0 .153 0 .06 

New Mexico ...... 0 .299 0 .118 

Nevada ............. 0 .285 0 .112 

New York .......... 0 .393 0 .155 

Ohio .................. 2 .056 0 .812 

Oklahoma ......... 0 .721 0 .285 

Oregon .............. 0 .076 0 .03 

Pennsylvania .... 1 .78 0 .702 

Rhode Island .... 0 0 

South Carolina .. 0 .58 0 .229 

South Dakota .... 0 .072 0 .029 

Tennessee ........ 0 .944 0 .373 

Texas ................ 4 .657 1 .838 

Utah .................. 0 .506 0 .2 

Virginia .............. 0 .592 0 .234 

Vermont ............ 0 0 

Washington ....... 0 .198 0 .078 

Wisconsin ......... 0 .89 0 .351 

West Virginia .... 1 .394 0 .55 

Wyoming ........... 0 .952 0 .376 

Navajo Nation 

Indian country 0 .601 0 .237 

Ute Indian Tribe 

Indian country 0 .06 0 .024 

(4) Each State plan under paragraph 

(h)(1) of this section shall require EGUs 

to comply with the monitoring, record 

keeping, and reporting provisions of 

part 75 of this chapter with regard to Hg 

mass emissions. 

(5) In addition to meeting the 

requirements of § 60.26, each State plan 

under paragraph (h)(1) of this section 

must show that the State has legal 

authority to: 

(i) Adopt emissions standards and 

compliance schedules necessary for 

attainment and maintenance of the 

State’s relevant annual EGU Hg budget 

under paragraph (h)(3) of this section; 

and 

(ii) Require owners or operators of 

EGUs in the State to meet the 

monitoring, record keeping, and 

reporting requirements described in 

paragraph (h)(4) of this section. 

(6)(i) Notwithstanding the provisions 

of paragraphs (h)(3) and (5)(i) of this 

section, if a State adopts regulations 

substantively identical to subpart 

HHHH of this part (Hg Budget Trading 

Program), incorporates such subpart by 

reference into its regulations, or adopts 

regulations that differ substantively 

from such subpart only as set forth in 

paragraph (h)(6)(ii) of this section, then 

such allowance system in the State’s 

State plan is automatically approved as 

meeting the requirements of paragraph 

(h)(3) of this section, provided that the 

State demonstrates that it has the legal 

authority to take such action and to 

implement its responsibilities under 

such regulations. 

(ii) If a State adopts an allowance 

system that differs substantively from 

subpart HHHH of this part only as 

follows, then the emissions trading 

program is approved as set forth in 

paragraph (h)(6)(i) of this section. 

(A) The State may decline to adopt 

the allocation provisions set forth in 

§§ 60.4141 and 60.4142 and may instead 

adopt any methodology for allocating 

Hg allowances. 

(B) The State’s methodology under 

paragraph (h)(6)(ii)(A) of this section 

must not allow the State to allocate Hg 

allowances for a year in excess of the 

amount in the State’s annual EGU Hg 

budget for such year under paragraph 

(h)(3) of this section; 

(C) The State’s methodology under 

paragraph (h)(6)(ii)(A) of this section 

must require that, for EGUs 

commencing operation before January 1, 

2001, the State will determine, and 

notify the Administrator of, each unit’s 

allocation of Hg allowances by October 

31, 2006 for 2010, 2011, and 2012 and 

by October 31, 2009 and October 31 of 

each year thereafter for the fourth year 

after the year of the notification 

deadline; and 

(D) The State’s methodology under 

paragraph (h)(6)(ii)(A) of this section 

must require that, for EGUs 

commencing operation on or after 

January 1, 2001, the State will 

determine, and notify the Administrator 

of, each unit’s allocation of Hg 

allowances by October 31 of the year for 

which the Hg allowances are allocated. 

(7) If a State adopts an allowance 

system that differs substantively from 

subpart HHHH of this part, other than 

as set forth in paragraph (h)(6)(ii) of this 

section, then such allowance system is 

not automatically approved as set forth 

in paragraph (h)(6)(i) or (ii) of this 

section and will be reviewed by the 

Administrator for approvability in 

accordance with the other provisions of 

paragraphs (h)(2) through (5) of this 

section and the other applicable 

requirements for a State plan under this 

subpart, provided that the Hg 

allowances issued under such 

allowance system shall not, and the 

State plan under paragraph (h)(1) of this 

section shall state that such Hg 

allowances shall not, qualify as Hg 

allowances under any allowance system 

approved under paragraph (h)(6)(i) or 

(ii) of this section. 

(8) The terms used in this paragraph 

(h) shall have the following meanings: 

Administrator means the 

Administrator of the United States 

Environmental Protection Agency or the 

Administrator’s duly authorized 

representative. 

Allocate or allocation means, with 

regard to Hg allowances, the 

determination of the amount of Hg 

allowances to be initially credited to a 

source. 

Boiler means an enclosed fossil-or 

other fuel-fired combustion device used 

to produce heat and to transfer heat to 

recirculating water, steam, or other 

medium. 

Bottoming-cycle cogeneration unit 

means a cogeneration unit in which the 

energy input to the unit is first used to 

produce useful thermal energy and at 

least some of the reject heat from the 

useful thermal energy application or 

process is then used for electricity 

production. 

Coal means any solid fuel classified as 

anthracite, bituminous, subbituminous, 

or lignite by the American Society of 

Testing and Materials (ASTM) Standard 

Specification for Classification of Coals 

by Rank D388–77, 90, 91, 95, 98a, or 99 

(Reapproved 2004) ε1 (incorporated by 

reference, see § 60.17). 

Coal-derived fuel means any fuel 

(whether in a solid, liquid, or gaseous 

state) produced by the mechanical, 

thermal, or chemical processing of coal. 

Coal-fired means combusting any 

amount of coal or coal-derived fuel, 

alone or in combination with any 

amount of any other fuel, during any 

year. 

Cogeneration unit means a stationary, 

coal-fired boiler or stationary, coal-fired 

combustion turbine: 

(1) Having equipment used to produce 

electricity and useful thermal energy for 

industrial, commercial, heating, or 

cooling purposes through the sequential 

use of energy; and 

(2) Producing during the 12-month 

period starting on the date the unit first 

produces electricity and during any 

calendar year after which the unit first 

produces electricity: 

(i) For a topping-cycle cogeneration 

unit, 

(A) Useful thermal energy not less 

than 5 percent of total energy output; 

and 

(B) Useful power that, when added to 

one-half of useful thermal energy 

produced, is not less then 42.5 percent 

of total energy input, if useful thermal 

energy produced is 15 percent or more 

of total energy output, or not less than 

45 percent of total energy input, if 

useful thermal energy produced is less 

than 15 percent of total energy output. 

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28651

(ii) For a bottoming-cycle 

cogeneration unit, useful power not less 

than 45 percent of total energy input. 

Combustion turbine means: 

(1) An enclosed device comprising a 

compressor, a combustion, and a turbine 

and in which the flue gas resulting from 

the combustion of fuel in the 

combustion passes through the turbine, 

rotating the turbine; and 

(2) If the enclosed device under 

paragraph (1) of this definition is 

combined cycle, any associated heat 

recovery steam generator and steam 

turbine. 

Commence operation means to have 

begun any mechanical, chemical, or 

electronic process, including, with 

regard to a unit, start-up of a unit’s 

combustion chamber. 

Electric generating unit or EGU

means: 

(1) Except as provided in paragraph 

(2) of this definition, a stationary, coalfired boiler or stationary, coal-fired 

combustion turbine in the State serving 

at any time, since the start-up of a unit’s 

combustion chamber, a generator with 

nameplate capacity of more than 25 

megawatts electric (MW) producing 

electricity for sale. 

(2) For a unit that qualifies as a 

cogeneration unit during the 12-month 

period starting on the date the unit first 

produces electricity and continues to 

qualify as a cogeneration unit, a 

cogeneration unit in the State serving at 

any time a generator with nameplate 

capacity of more than 25 MW 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. If a unit qualifies as a cogeneration 

unit during the 12-month period starting 

on the date the unit first produces 

electricity but subsequently no longer 

qualifies as a cogeneration unit, the unit 

shall be subject to paragraph (1) of this 

definition starting on the day on which 

the unit first no longer qualifies as a 

cogeneration unit.

Generator means a device that 

produces electricity. 

Gross electrical output means, with 

regard to a cogeneration unit, electricity 

made available for use, including any 

such electricity used in the power 

production process (which process 

includes, but is not limited to, any onsite processing or treatment of fuel 

combusted at the unit and any on-site 

emission controls). 

Gross thermal energy means, with 

regard to a cogeneration unit, useful 

thermal energy output plus, where such 

output is made available for an 

industrial or commercial process, any 

heat contained in condensate return or 

makeup water. 

Heat input means, with regard to a 

specified period of time, the product (in 

million British thermal units per unit 

time, MMBTU/time) of the gross 

calorific value of the fuel (in Btu per 

pound, Btu/lb) divided by 1,000,000 

Btu/MMBTU and multiplied by the fuel 

feed rate into a combustion device (in lb 

of fuel/time), as measured, recorded, 

and reported to the Administrator by the 

Hg designated representative and 

determined by the Administrator in 

accordance with §§ 60.4170 through 

60.4176 and excluding the heat derived 

from preheated combustion air, 

reticulated flue gases, or exhaust from 

other sources. 

Hg allowance means a limited 

authorization issued by the permitting 

authority to emit one ounce of Hg 

during a control period of the specified 

calendar year for which the 

authorization is allocated or of any 

calendar year thereafter. 

Life-of-the-unit, firm power 

contractual arrangement means a unit 

participation power sales agreement 

under which a customer reserves, or is 

entitled to receive, a specified amount 

or percentage of nameplate capacity and 

associated energy generated by any 

specified unit and pays its proportional 

amount of such unit’s total costs, 

pursuant to a contract: 

(1) For the life of the unit; 

(2) For a cumulative term of no less 

than 30 years, including contracts that 

permit an election for early termination; 

or 

(3) For a period no less than 25 years 

or 70 percent of the economic useful life 

of the unit determined as of the time the 

unit is built, with option rights to 

purchase or release some portion of the 

nameplate capacity and associated 

energy generated by the unit at the end 

of the period. 

Maximum design heat input means, 

starting from the initial installation of a 

unit, the maximum amount of fuel per 

hour (in Btu/hr) that a unit is capable of 

combusting on a steady-state basis as 

specified by the manufacturer of the 

unit, or, starting from the completion of 

any subsequent physical change in the 

unit resulting in a decrease in the 

maximum amount of fuel per hour (in 

Btu per hour, Btu/hr) that a unit is 

capable of combusting on a steady-state 

basis, such decreased maximum amount 

as specified by the person conducting 

the physical change. 

Nameplate capacity means, starting 

from the initial installation of a 

generator, the maximum electrical 

generating output (in MW) that the 

generator is capable of producing on a 

steady-state basis and during 

continuous operation (when not 

restricted by seasonal or other derates) 

as specified by the manufacturer of the 

generator or, starting from the 

completion of any subsequent physical 

change in the generator resulting in an 

increase in the maximum electrical 

generating output (in MW) that the 

generator is capable of producing on a 

steady-state basis and during 

continuous operation (when not 

restricted by seasonal or other derates), 

such increased maximum amount as 

specified by the person conducting the 

physical change. 

Operator means any person who 

operates, controls, or supervises an EGU 

or a source that includes an EGU and 

shall include, but not be limited to, any 

holding company, utility system, or 

plant manager of such EGU or source. 

Ounce means 2.84 × 107 micrograms. 

Owner means any of the following 

persons: 

(1) With regard to a Hg Budget source 

or a Hg Budget unit at a source, 

respectively: 

(i) Any holder of any portion of the 

legal or equitable title in a Hg Budget 

unit at the source or the Hg Budget unit; 

(ii) Any holder of a leasehold interest 

in a Hg Budget unit at the source or the 

Hg Budget unit; or 

(iii) Any purchaser of power from a 

Hg Budget unit at the source or the Hg 

Budget unit under a life-of-the-unit, firm 

power contractual arrangement; 

provided that, unless expressly 

provided for in a leasehold agreement, 

owner shall not include a passive lessor, 

or a person who has an equitable 

interest through such lessor, whose 

rental payments are not based (either 

directly or indirectly) on the revenues or 

income from such Hg Budget unit; or 

(2) With regard to any general 

account, any person who has an 

ownership interest with respect to the 

Hg allowances held in the general 

account and who is subject to the 

binding agreement for the Hg authorized 

account representative to represent the 

person’s ownership interest with respect 

to Hg allowances. 

Potential electrical output capacity

means 33 percent of a unit’s maximum 

design heat input, divided by 3,413 Btu 

per kilowatt-hour (Btu/kWh), divided by 

1,000 kWh per megawatt-hour (kWh/

MWh), and multiplied by 8,760 hr/yr. 

Sequential use of energy means: 

(1) For a topping-cycle cogeneration 

unit, the use of reject heat from 

electricity production in a useful 

thermal energy application or process; 

or 

(2) For a bottoming-cycle cogeneration 

unit, the use of reject heat from seful 

28652 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

thermal energy application or process in 

electricity production. 

Source means all buildings, 

structures, or installations located in 

one or more contiguous or adjacent 

properties under common control of the 

same person or persons. 

State means: 

(1) For purposes of referring to a 

governing entity, one of the States in the 

United States, the District of Columbia, 

or, if approved for treatment as a State 

under part 49 of this chapter, the Navajo 

Nation or Ute Indian Tribe that adopts 

the Hg Budget Trading Program 

pursuant to § 60.24(h)(6); or 

(2) For purposes of referring to a 

geographic area, one of the States in the 

United States, the District of Columbia, 

the Navajo Nation Indian country, or the 

Ute Tribe Indian country. 

Topping-cycle cogeneration unit 

means a cogeneration unit in which the 

energy input to the unit is first used to 

produce useful power, including 

electricity, and at least some of the 

reject heat from the electricity 

production is then used to provide 

useful thermal energy. 

Total energy input means, with regard 

to a cogeneration unit, total energy of all 

forms supplied to the cogeneration unit, 

excluding energy produced by the 

cogeneration unit itself. 

Total energy output means, with 

regard to a cogeneration unit, the sum 

of useful power and useful thermal 

energy produced by the cogeneration 

unit. 

Unit means a stationary coal-fired 

boiler or a stationary coal-fired 

combustion turbine. 

Useful power means, with regard to a 

cogeneration unit, electricity or 

mechanical energy made available for 

use, excluding any such energy used in 

the power production process (which 

process includes, but is not limited to, 

any on-site processing or treatment of 

fuel combusted at the unit and any onsite emission controls). 

Useful thermal energy means, with 

regard to a cogeneration unit, thermal 

energy that is: 

(1) Made available to an industrial or 

commercial process (not a power 

production process), excluding any heat 

contained in condensate return or 

makeup water; 

(2) Used in a heat application (e.g., 

space heating or domestic hot water 

heating); or 

(3) Used in a space cooling 

application (i.e., thermal energy used by 

an absorption chiller). 

Utility power distribution system 

means the portion of an electricity grid 

owned or operated by a utility and 

dedicated to delivering electricity to 

customers. 

Subpart Da—[Amended] 

■ 5. Section 60.41a is amended by 

revising the definition of ‘‘Electric utility 

steam generating unit,’’ and by adding 

in alphabetical order the definitions of 

‘‘Bituminous coal,’’ ‘‘Coal,’’ ‘‘Coal-fired 

electric utility steam generating unit,’’

‘‘Cogeneration,’’ ‘‘Dry flue gas 

desulfurization technology or dry FGD,’’

‘‘Electrostatic precipitator,’’ ‘‘Emission 

limitation,’’ ‘‘Emission rate period,’’

‘‘Federally enforceable,’’ ‘‘Gaseous fuel,’’

‘‘Integrated gasification combined cycle 

electric utility steam generating unit,’’

‘‘Natural gas,’’ and ‘‘Responsible 

official’’ and ‘‘Wet flue gas 

desulfurization technology or wet FGD’’

to read as follows: 

§ 60.41a Definitions. 

* * * * * 

Bituminous coal means coal that is 

classified as bituminous according to 

the American Society of Testing and 

Materials (ASTM) Standard 

Specification for Classification of Coals 

by Rank D388–77, 90, 91, 95, 98a, or 99 

(Reapproved 2004)ε1 (incorporated by 

reference, see § 60.17). 

* * * * * 

Coal means all solid fuels classified as 

anthracite, bituminous, subbituminous, 

or lignite by the American Society of 

Testing and Materials (ASTM) Standard 

Specification for Classification of Coals 

by Rank D388–77, 90, 91, 95, 98a, or 99 

(Reapproved 2004)ε1 (incorporated by 

reference, see § 60.17), coal refuse, and 

petroleum coke. Synthetic fuels derived 

from coal for the purpose of creating 

useful heat, including but not limited to 

solvent-refined coal, gasified coal, coaloil mixtures, and coal-water mixtures 

are included in this definition for the 

purposes of this subpart. 

Coal-fired electric utility steam 

generating unit means an electric utility 

steam generating unit that burns coal, 

coal refuse, or a synthetic gas derived 

from coal either exclusively, in any 

combination together, or in any 

combination with other supplemental 

fuels in any amount. Examples of 

supplemental fuels include, but are not 

limited to, petroleum coke and tirederived fuels. 

* * * * * 

Cogeneration means a facility that 

simultaneously produces both electrical 

(or mechanical) and useful thermal 

energy from the same primary energy 

source. 

* * * * * 

Dry flue gas desulfurization 

technology or dry FGD means a sulfur 

dioxide control system that is located 

downstream of the steam generating 

unit and removes sulfur oxides from the 

combustion gases of the steam 

generating unit by contacting the 

combustion gases with an alkaline 

slurry or solution and forming a dry 

powder material. This definition 

includes devices where the dry powder 

material is subsequently converted to 

another form. Alkaline slurries or 

solutions used in dry FGD technology 

include, but are not limited to, lime and 

sodium. 

* * * * * 

Electric utility steam generating unit 

means any fossil fuel-fired combustion 

unit of more than 25 megawatts electric 

(MW) that serves a generator that 

produces electricity for sale. A unit that 

cogenerates steam and electricity and 

supplies more than one-third of its 

potential electric output capacity and 

more than 25 MW output to any utility 

power distribution system for sale is 

also considered an electric utility steam 

generating unit. 

Electrostatic precipitator or ESP 

means an add-on air pollution control 

device used to capture particulate 

matter by charging the particles using an 

electrostatic field, collecting the 

particles using a grounded collecting 

surface, and transporting the particles 

into a hopper. 

* * * * * 

Emission limitation means any 

emissions limit or operating limit. 

Emission rate period means any 

calendar month included in a 12-month 

rolling average period. 

Federally enforceable means all 

limitations and conditions that are 

enforceable by the Administrator, 

including the requirements of 40 CFR 

parts 60 and 61, requirements within 

any applicable State implementation 

plan, and any permit requirements 

established under 40 CFR 52.21 or 40 

CFR 51.18 and 40 CFR 51.24. 

* * * * * 

Gaseous fuel means any fuel derived 

from coal or petroleum that is present as 

a gas at standard conditions and 

includes, but is not limited to, refinery 

fuel gas, process gas, and coke-oven gas. 

* * * * * 

Integrated gasification combined 

cycle electric utility steam generating 

unit or IGCC means a coal-fired electric 

utility steam generating unit that burns 

a synthetic gas derived from coal in a 

combined-cycle gas turbine. No coal is 

directly burned in the unit during 

operation. 

* * * * * 

Natural gas means: 

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28653

(1) A naturally occurring mixture of 

hydrocarbon and nonhydrocarbon gases 

found in geologic formations beneath 

the earth’s surface, of which the 

principal constituent is methane; or 

(2) Liquid petroleum gas, as defined 

by the American Society of Testing and 

Materials (ASTM) Standard 

Specification for Liquid Petroleum 

Gases D1835–87, 91, 97, or 03a 

(incorporated by reference, see § 60.17).

* * * * *

Responsible official means 

responsible official as defined in 40 CFR 

70.2.

* * * * *

Wet flue gas desulfurization 

technology or wet FGD means a sulfur 

dioxide control system that is located 

downstream of the steam generating 

unit and removes sulfur oxides from the 

combustion gases of the steam 

generating unit by contacting the 

combustion gases with an alkaline 

slurry or solution and forming a liquid 

material. This definition applies to 

devices where the aqueous liquid 

material product of this contact is 

subsequently converted to other forms. 

Alkaline reagents used in wet FGD 

technology include, but are not limited 

to, lime, limestone, and sodium.

* * * * *

■ 6. Subpart Da is amended by:

■ a. Redesignating § 60.49a as § 60.51a;

■ b. Redesignating § 60.48a as § 60.50a;

■ c. Redesignating § 60.47a as § 60.49a;

■ d. Redesignating § 60.46a as § 60.48a;

■ e. Redesignating § 60.45a as § 60.47a;

■ f. Adding new §§ 60.45a; and

■ g. Adding and reserving new § 60.46a 

to read as follows:

§ 60.45a Standard for mercury. 

(a) For each coal-fired electric utility 

steam generating unit other than an 

integrated gasification combined cycle 

(IGCC) electric utility steam generating 

unit, on and after the date on which the 

initial performance test required to be 

conducted under § 60.8 is completed, no 

owner or operator subject to the 

provisions of this subpart shall cause to 

be discharged into the atmosphere from 

any affected facility for which 

construction or reconstruction 

commenced after January 30, 2004, any 

gases which contain mercury (Hg) 

emissions in excess of each Hg 

emissions limit in paragraphs (a)(1) 

through (5) of this section that applies 

to you. The Hg emissions limits in 

paragraphs (a)(1) through (5) of this 

section are based on a 12-month rolling 

average using the procedures in 

§ 60.50a(h). 

(1) For each coal-fired electric utility 

steam generating unit that burns only 

bituminous coal, you must not 

discharge into the atmosphere any gases 

from a new affected source which 

contain Hg in excess of 21 × 10¥6 pound 

per megawatt hour (lb/MWh) or 0.021 

lb/gigawatt-hour (GWh) on an output 

basis. The International System of Units 

(SI) equivalent is 0.0026 nanograms per 

joule (ng/J). 

(2) For each coal-fired electric utility 

steam generating unit that burns only 

subbituminous coal: 

(i) If you utilize wet FGD technology 

to limit SO2 emissions from your steam 

generating unit, you must not discharge 

into the atmosphere any gases from a 

new affected source which contain Hg 

in excess of 42 × 10¥6 lb/MWh or 0.042 

lb/GWh on an output basis. The SI 

equivalent is 0.0053 ng/J. 

(ii) If you utilize dry FGD technology 

to limit SO2 emissions from your steam 

generating unit, you must not discharge 

into the atmosphere any gases from a 

new affected source which contain Hg 

in excess of 78 × 10¥6 lb/MWh or 0.078 

lb/GWh on an output basis. The SI 

equivalent is 0.0098 ng/J. 

(3) For each coal-fired electric utility 

steam generating unit that burns only 

lignite, you must not discharge into the 

atmosphere any gases from a new 

affected source which contain Hg in 

excess of 145 × 10¥6 lb/MWh or 0.145 

lb/GWh on an output basis. The SI 

equivalent is 0.0183 ng/J.

(4) For each coal-burning electric 

utility steam generating unit that burns 

only coal refuse, you must not discharge 

into the atmosphere any gases from a 

new affected source which contain Hg 

in excess of 1.4 × 10¥6 lb/MWh or 

0.0014 lb/GWh on an output basis. The 

SI equivalent is 0.00018 ng/J. 

(5) For each coal-fired electric utility 

steam generating unit that burns a blend 

of coals from different coal ranks (i.e., 

bituminous coal, subbituminous coal, 

lignite) or a blend of coal and coal 

refuse, you must not discharge into the 

atmosphere any gases from a new 

affected source that contain Hg in excess 

of the monthly unit-specific Hg 

emissions limit established according to 

paragraph (a)(5)(i) or (ii) of this section, 

as applicable to the affected unit. 

(i) If you operate a coal-fired electric 

utility steam generating unit that burns 

a blend of coals from different coal 

ranks or a blend of coal and coal refuse, 

you must not discharge into the 

atmosphere any gases from a new 

affected source that contain Hg in excess 

of the computed weighted Hg emissions 

limit based on the proportion of energy 

output (in British thermal units, Btu) 

contributed by each coal rank burned 

during the compliance period and its 

applicable Hg emissions limit in 

paragraphs (a)(1) through (4) of this 

section as determined using Equation 1 

of this section. You must meet the 

weighted Hg emissions limit calculated 

using Equation 1 of this section by 

calculating the unit emission rate based 

on the total Hg loading of the unit and 

the total Btu or megawatt hours 

contributed by all fuels burned during 

the compliance period.

ELb = (Eq. 1)

EL HH

HH

i i

i

n

i

i

n

( ) =

=

∑

∑

1

1

Where:

ELb = Total allowable Hg in lb/MWh 

that can be emitted to the 

atmosphere from any affected 

source being averaged under the 

blending provision. 

ELi = Hg emissions limit for the 

subcategory i (coal rank) that 

applies to affected source, lb/MWh. 

HHi = Electricity output from affected 

source during the production 

period related to use of the 

corresponding subcategory i (coal 

rank) that falls within the 

compliance period, gross MWh 

generated by the electric utility 

steam generating unit. 

n = Number of subcategories (coal 

ranks) being averaged for an 

affected source.

(ii) If you operate a coal-fired electric 

utility steam generating unit that burns 

a blend of coals from different coal 

ranks or a blend of coal and coal refuse 

together with one or more nonregulated, supplementary fuels, you 

must not discharge into the atmosphere 

any gases from the unit that contain Hg 

in excess of the computed weighted Hg 

emission limit based on the proportion 

of electricity output (in MWh) 

contributed by each coal rank burned 

during the compliance period and its 

applicable Hg emissions limit in 

paragraphs (a)(1) through (4) of this 

section as determined using Equation 1 

of this section. You must meet the 

weighted Hg emissions limit calculated 

using Equation 1 of this section by 

calculating the unit emission rate based 

on the total Hg loading of the unit and 

the total megawatt hours contributed by 

both regulated and nonregulated fuels 

burned during the compliance period. 

(b) For each IGCC electric utility 

steam generating unit, on and after the 

date on which the initial performance 

test required to be conducted under 

§ 60.8 is completed, no owner or 

operator subject to the provisions of this 

subpart shall cause to be discharged into 


ER18MY05.000</MATH>
28654 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

the atmosphere from any affected 

facility for which construction or 

reconstruction commenced after January 

30, 2004, any gases which contain Hg 

emissions in excess of 20 × 10¥6 lb/

MWh or 0.020 lb/GWh on an output 

basis. The SI equivalent is 0.0025 ng/J. 

This Hg emissions limit is based on a 

12-month rolling average using the 

procedures in § 60.50a(g).

§ 60.46a [Reserved]

■ 7. Newly redesignated § 60.48a is 

amended by:

■ a. Revising paragraph (c);

■ b. In paragraph (h) by revising the 

existing references from ‘‘§ 60.47a’’ to 

‘‘§ 60.49a’’;

■ c. In paragraph (i) by revising the 

existing references for ‘‘§§ 60.47a(c),’’

‘‘60.47a(l),’’ and ‘‘60.47a(k)’’ to 

‘‘§§ 60.49a(c),’’ ‘‘60.49a(l),’’ and 

‘‘60.49a(k),’’ respectively;

■ d. In paragraph (j)(2) by revising the 

existing references from ‘‘§ 60.47a’’ to 

‘‘§ 60.49a’’ twice;

■ e. In paragraph (k)(2)(ii) by revising the 

existing references from ‘‘§ 60.47a’’ and 

‘‘60.47a(l)’’ to ‘‘§ 60.49a’’ and 

‘‘60.49a(l),’’ respectively;

■ f. In paragraph (k)(2)(iii) by revising 

the existing references from 

‘‘§ 60.47a(k)’’ to ‘‘§ 60.49a(k)’’;

■ g. In paragraph (k)(2)(iv) by revising 

the existing references from ‘‘§ 60.47a(l)’’

to ‘‘§ 60.49a(l)’’; and

■ h. Adding new paragraph (l).

The revision and additions read as 

follows:

§ 60.48a Compliance provisions.

* * * * *

(c) The particulate matter emission 

standards under § 60.42a, the nitrogen 

oxides emission standards under 

§ 60.44a, and the Hg emission standards 

under § 60.45a apply at all times except 

during periods of startup, shutdown, or 

malfunction.

* * * * *

(l) Compliance provisions for sources 

subject to § 60.45a. The owner or 

operator of an affected facility subject to 

§ 60.45a (new sources constructed or 

reconstructed after January 30, 2004) 

shall calculate the Hg emission rate (lb/

MWh) for each calendar month of the 

year, using hourly Hg concentrations 

measured according to the provisions of 

§ 60.49a(p) in conjunction with hourly 

stack gas volumetric flow rates 

measured according to the provisions of 

§ 60.49a(l) or (m), and hourly gross 

electrical outputs, determined according 

to the provisions in § 60.49a(k). 

Compliance with the applicable 

standard under § 60.45a is determined 

on a 12-month rolling average basis.

■ 8. Newly redesignated § 60.49a is 

amended by:

■ a. In paragraph (c)(2) by revising the 

existing references from ‘‘§ 60.49a’’ to 

‘‘§ 60.51a’’ twice;

■ b. In paragraph (g) by revising the 

existing reference from ‘‘§ 60.46a’’ to 

‘‘§ 60.48a’’ and

■ c. Adding new paragraphs (p) through 

(s). 

The revision and additions read as 

follows:

§ 60.49a Emission monitoring.

* * * * *

(p) The owner or operator of an 

affected facility demonstrating 

compliance with an Hg limit in § 60.45a 

shall install and operate a continuous 

emissions monitoring system (CEMS) to 

measure and record the concentration of 

Hg in the exhaust gases from each stack 

according to the requirements in 

paragraphs (p)(1) through (p)(3) of this 

section. Alternatively, for an affected 

facility that is also subject to the 

requirements of subpart I of part 75 of 

this chapter, the owner or operator may 

install, certify, maintain, operate and 

quality-assure the data from a Hg CEMS 

according to § 75.10 of this chapter and 

appendices A and B to part 75 of this 

chapter, in lieu of following the 

procedures in paragraphs (p)(1) through 

(p)(3) of this section. 

(1) The owner or operator must 

install, operate, and maintain each 

CEMS according to Performance 

Specification 12A in appendix B to this 

part. 

(2) The owner or operator must 

conduct a performance evaluation of 

each CEMS according to the 

requirements of § 60.13 and 

Performance Specification 12A in 

appendix B to this part. 

(3) The owner or operator must 

operate each CEMS according to the 

requirements in paragraphs (p)(3)(i) 

through (iv) of this section. 

(i) As specified in § 60.13(e)(2), each 

CEMS must complete a minimum of one 

cycle of operation (sampling, analyzing, 

and data recording) for each successive 

15-minute period. 

(ii) The owner or operator must 

reduce CEMS data as specified in 

§ 60.13(h). 

(iii) The owner or operator shall use 

all valid data points collected during the 

hour to calculate the hourly average Hg 

concentration. 

(iv) The owner or operator must 

record the results of each required 

certification and quality assurance test 

of the CEMS.

(4) Mercury CEMS data collection 

must conform to paragraphs (p)(4)(i) 

through (iv) of this section. 

(i) For each calendar month in which 

the affected unit operates, valid hourly 

Hg concentration data, stack gas 

volumetric flow rate data, moisture data 

(if required), and electrical output data 

(i.e., valid data for all of these 

parameters) shall be obtained for at least 

75 percent of the unit operating hours 

in the month. 

(ii) Data reported to meet the 

requirements of this subpart shall not 

include hours of unit startup, shutdown, 

or malfunction. In addition, for an 

affected facility that is also subject to 

subpart I of part 75 of this chapter, data 

reported to meet the requirements of 

this subpart shall not include data 

substituted using the missing data 

procedures in subpart D of part 75 of 

this chapter, nor shall the data have 

been bias adjusted according to the 

procedures of part 75 of this chapter. 

(iii) If valid data are obtained for less 

than 75 percent of the unit operating 

hours in a month, you must discard the 

data collected in that month and replace 

the data with the mean of the individual 

monthly emission rate values 

determined in the last 12 months. In the 

12-month rolling average calculation, 

this substitute Hg emission rate shall be 

weighted according to the number of 

unit operating hours in the month for 

which the data capture requirement of 

§ 60.49a(p)(4)(i) was not met. 

(iv) Notwithstanding the requirements 

of paragraph (p)(4)(iii) of this section, if 

valid data are obtained for less than 75 

percent of the unit operating hours in 

another month in that same 12-month 

rolling average cycle, discard the data 

collected in that month and replace the 

data with the highest individual 

monthly emission rate determined in 

the last 12 months. In the 12-month 

rolling average calculation, this 

substitute Hg emission rate shall be 

weighted according to the number of 

unit operating hours in the month for 

which the data capture requirement of 

§ 60.49a(p)(4)(i) was not met. 

(q) As an alternative to the CEMS 

required in paragraph (p) of this section, 

the owner or operator may use a sorbent 

trap monitoring system (as defined in 

§ 72.2 of this chapter) to monitor Hg 

concentration, according to the 

procedures described in § 75.15 of this 

chapter and appendix K to part 75 of 

this chapter. 

(r) For Hg CEMS that measure Hg 

concentration on a dry basis or for 

sorbent trap monitoring systems, the 

emissions data must be corrected for the 

stack gas moisture content. A certified 

continuous moisture monitoring system 

that meets the requirements of § 75.11(b) 

of this chapter is acceptable for this 

purpose. Alternatively, the appropriate 

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28655

default moisture value, as specified in 

§ 75.11(b) or § 75.12(b) of this chapter, 

may be used.

(s) The owner or operator shall 

prepare and submit to the Administrator 

for approval a unit-specific monitoring 

plan for each monitoring system, at least 

45 days before commencing certification 

testing of the monitoring systems. The 

owner or operator shall comply with the 

requirements in your plan. The plan 

must address the requirements in 

paragraphs (s)(1) through (6) of this 

section. 

(1) Installation of the CEMS sampling 

probe or other interface at a 

measurement location relative to each 

affected process unit such that the 

measurement is representative of the 

exhaust emissions (e.g., on or 

downstream of the last control device); 

(2) Performance and equipment 

specifications for the sample interface, 

the pollutant concentration or 

parametric signal analyzer, and the data 

collection and reduction systems; 

(3) Performance evaluation 

procedures and acceptance criteria (e.g., 

calibrations, relative accuracy test 

audits (RATA), etc.); 

(4) Ongoing operation and 

maintenance procedures in accordance 

with the general requirements of 

§ 60.13(d) or part 75 of this chapter (as 

applicable); 

(5) Ongoing data quality assurance 

procedures in accordance with the 

general requirements of § 60.13 or part 

75 of this chapter (as applicable); and 

(6) Ongoing record keeping and 

reporting procedures in accordance with 

the requirements of this subpart.

■ 9. Newly redesignated § 60.50a is 

amended by:

■ a. In paragraph (c)(5) by revising the 

existing references from ‘‘§ 60.47a(b) and 

(d)’’ to ‘‘§ 60.49a(b) and (d)’’;

■ b. In paragraph (d)(2) by revising the 

existing references from ‘‘§ 60.47a(c) and 

(d)’’ to ‘‘§ 60.49a(c) and (d)’’;

■ c. In paragraph (e)(2) by revising the 

existing reference from ‘‘§ 60.46a(d)(1)’’

to ‘‘§ 60.48a(d)(1)’’; and

■ d. Adding new paragraphs (g) through 

(i). 

The additions read as follows:

§ 60.50a Compliance determination 

procedures and methods.

* * * * *

(g) For the purposes of determining 

compliance with the emission limits in 

§§ 60.45a and 60.46a, the owner or 

operator of an electric utility steam 

generating unit which is also a 

cogeneration unit shall use the 

procedures in paragraphs (g)(1) and (2) 

of this section to calculate emission 

rates based on electrical output to the 

grid plus half of the equivalent electrical 

energy in the unit’s process stream. 

(1) All conversions from Btu/hr unit 

input to MW unit output must use 

equivalents found in 40 CFR 60.40(a)(1) 

for electric utilities (i.e., 250 million 

Btu/hr input to a electric utility steam 

generating unit is equivalent to 73 MW 

input to the electric utility steam 

generating unit); 73 MW input to the 

electric utility steam generating unit is 

equivalent to 25 MW output from the 

boiler electric utility steam generating 

unit; therefore, 250 million Btu input to 

the electric utility steam generating unit 

is equivalent to 25 MW output from the 

electric utility steam generating unit). 

(2) Use Equation 1 below in lieu of 

Equation 5 in paragraph (h) of this 

section, to determine the monthly 

average Hg emission rates for a 

cogeneration unit.

ER M

V

V

2

(Eq. 1) cogen

grid

process

=

( ) + 



 



 











Where:

ERCOGEN = Cogeneration Hg emission 

rate for a particular month (lb/

MWh; 

M = Mass of Hg emitted from the stack 

over the same month, from 

Equation 2 or Equation 3 in 

paragraph h of this section (lb); 

Vgrid = Amount of energy sent to the grid 

over the same month (MWh); and 

Vprocess = Amount of energy converted to 

steam for process use over the same 

month (MWh).

(h) The owner or operator shall 

determine compliance with the Hg limit 

in § 60.45a according to the procedures 

in paragraphs (h)(1) through (3) of this 

section. 

(1) The initial performance test shall 

be commenced by the applicable date 

specified in § 60.8(a). The required 

continuous monitoring systems must be 

certified prior to commencing the test. 

The performance test consists of 

collecting hourly Hg emission data (lb/

MWh) with the continuous monitoring 

systems for 12 successive months of 

unit operation (excluding hours of unit 

startup, shutdown and malfunction). 

The average Hg emission rate is 

calculated for each month, and then the 

weighted, 12-month average Hg 

emission rate is calculated according to 

paragraph (h)(2) or (h)(3) of this section, 

as applicable. If, for any month in the 

initial performance test, the minimum 

data capture requirement in 

§ 60.49a(p)(4)(i) is not met, the owner or 

operator shall report a substitute Hg 

emission rate for that month, as follows. 

For the first such month, the substitute 

monthly Hg emission rate shall be the 

arithmetic average of all valid hourly Hg 

emission rates recorded to date. For any 

subsequent month(s) with insufficient 

data capture, the substitute monthly Hg 

emission rate shall be the highest valid 

hourly Hg emission rate recorded to 

date. When the 12-month average Hg 

emission rate for the initial performance 

test is calculated, for each month in 

which there was insufficient data 

capture, the substitute monthly Hg 

emission rate shall be weighted 

according to the number of unit 

operating hours in that month. 

Following the initial performance test, 

the owner or operator shall demonstrate 

compliance by calculating the weighted 

average of all monthly Hg emission rates 

(in lb/MWh) for each 12 successive 

calendar months, excluding data 

obtained during startup, shutdown, or 

malfunction.

(2) If a CEMS is used to demonstrate 

compliance, follow the procedures in 

paragraphs (h)(2)(i) through (iii) of this 

section to determine the 12-month 

rolling average. 

(i) Calculate the total mass of Hg 

emissions over a month (M), in pounds 

(lb), using either Equation 2 in 

paragraph (h)(2)(i)(A) of this section or 

Equation 3 in paragraph (h)(2)(i)(B) of 

this section, in conjunction with 

Equation 4 in paragraph (h)(2)(i)(C) of 

this section. 

(A) If the Hg CEMS measures Hg 

concentration on a wet basis, use 

Equation 2 below to calculate the Hg 

mass emissions for each valid hour:

E KC Q t h h hh = (Eq. 2)

Where:

Eh = Hg mass emissions for the hour, (lb) 

K = Units conversion constant, 6.24 ×

10¥11 lb-scm/μg-scf 

Ch = Hourly Hg concentration, wet basis, 

(μg/scm) 

Qh = Hourly stack gas volumetric flow 

rate, (scfh) 

th = Unit operating time, i.e., the fraction 

of the hour for which the unit 

operated. For example, th = 0.50 for 

a half-hour of unit operation and 

1.00 for a full hour of operation.

(B) If the Hg CEMS measures Hg 

concentration on a dry basis, use 

Equation 3 below to calculate the Hg 

mass emissions for each valid hour:

E KC Q t B h h h h ws = −( ) 1 (Eq. 3)

Where:

Eh = Hg mass emissions for the hour, (lb) 

K = Units conversion constant, 6.24 ×

10¥11 lb-scm/μg-scf 

Ch = Hourly Hg concentration, dry basis, 

(μg/dscm) 


ER18MY05.001</MATH> ER18MY05.020</MATH> ER18MY05.002</MATH>
28656 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

Qh = Hourly stack gas volumetric flow 

rate, (scfh) 

th = Unit operating time, i.e., the fraction 

of the hour for which the unit 

operated 

Bws = Stack gas moisture content, 

expressed as a decimal fraction 

(e.g., for 8 percent H2O, Bws = 0.08)

(C) Use Equation 4, below, to 

calculate M, the total mass of Hg 

emitted for the month, by summing the 

hourly masses derived from Equation 2 

or 3 (as applicable):

M Eh

h

n

=

=

∑

1

(Eq. 4)

Where:

M = Total Hg mass emissions for the 

month, (lb) 

Eh = Hg mass emissions for hour ‘‘h’’, 

from Equation 2 or 3 of this section, 

(lb) 

n = The number of unit operating hours 

in the month with valid CEM and 

electrical output data, excluding 

hours of unit startup, shutdown and 

malfunction

(ii) Calculate the monthly Hg 

emission rate on an output basis (lb/

MWh) using Equation 5, below. For a 

cogeneration unit, use Equation 1 in 

paragraph (g) of this section instead.

ER M

P = (Eq. 5)

Where:

ER = Monthly Hg emission rate, (lb/

MWh) 

M = Total mass of Hg emissions for the 

month, from Equation 4, above, (lb) 

P = Total electrical output for the 

month, for the hours used to 

calculate M, (MWh)

(iii) Until 12 monthly Hg emission 

rates have been accumulated, calculate 

and report only the monthly averages. 

Then, for each subsequent calendar 

month, use Equation 6 below to 

calculate the 12-month rolling average 

as a weighted average of the Hg 

emission rate for the current month and 

the Hg emission rates for the previous 

11 months, with one exception. 

Calendar months in which the unit does 

not operate (zero unit operating hours) 

shall not be included in the 12-month 

rolling average.

E

ER n

n

i i

i i

i

i i

avg = (Eq. 6)

( )

=

=

∑

∑

12

12

Where:

Eavg = Weighted 12-month rolling 

average Hg emission rate, (lb/MWh) 

(ER)i = Monthly Hg emission rate, for 

month ‘‘i’’, (lb/MWh) 

n = The number of unit operating hours 

in month ‘‘i’’ with valid CEM and 

electrical output data, excluding 

hours of unit startup, shutdown, 

and malfunction

(3) If a sorbent trap monitoring system 

is used in lieu of a Hg CEMS, as 

described in § 75.15 of this chapter and 

in appendix K to part 75 of this chapter, 

calculate the monthly Hg emission rates 

using Equations 3 through 5 of this 

section, except that for a particular pair 

of sorbent traps, Ch in Equation 3 shall 

be the flow-proportional average Hg 

concentration measured over the data 

collection period. 

(i) Daily calibration drift (CD) tests 

and quarterly accuracy determinations 

shall be performed for Hg CEMS in 

accordance with Procedure 1 of 

appendix F to this part. For the CD 

assessments, you may use either 

elemental mercury or mercuric chloride 

(Hg° or HgCl2) standards. The four 

quarterly accuracy determinations shall 

consist of one RATA and three 

measurement error (ME) tests using 

HgCl2 standards, as described in section 

8.3 of Performance Specification 12–A 

in appendix B to this part (note: Hg°

standards may be used if the Hg monitor 

does not have a converter). 

Alternatively, the owner or operator 

may implement the applicable daily, 

weekly, quarterly, and annual quality 

assurance (QA) requirements for Hg 

CEMS in appendix B to part 75 of this 

chapter, in lieu of the QA procedures in 

appendices B and F to this part. Annual 

RATA of sorbent trap monitoring 

systems shall be performed in 

accordance with appendices A and B to 

part 75 of this chapter, and all other 

quality assurance requirements 

specified in appendix K to part 75 of 

this chapter shall be met for sorbent trap 

monitoring systems.

■ 10. Newly redesignated § 60.51a is 

amended by:

■ a. Revising paragraph (a);

■ b. In paragraph (c) introductory text by 

revising the existing references from 

‘‘§ 60.47a’’ and ‘‘§ 60.46a(h)’’ to 

‘‘§ 60.49a’’ and ‘‘§ 60.48a(h),’’

respectively;

■ c. In paragraph (d)(1) by revising the 

existing reference from ‘‘§ 60.46a(d)’’ to 

‘‘§ 60.48a(d)’’; and

■ d. In paragraph (e)(1) by revising the 

existing reference from ‘‘§ 60.48a’’ to 

‘‘§ 60.50a.’’

■ e. Redesignating paragraphs (g),(h), (i), 

and (j) as paragraphs (h), (i), (j), and (k), 

respectively, and adding a new 

paragraph (g); and

■ f. Revising the first sentence of newly 

redesignated paragraph (k). 

The revisions and additions read as 

follows:

§ 60.51a Reporting requirements. 

(a) For sulfur dioxide, nitrogen 

oxides, particulate matter, and Hg 

emissions, the performance test data 

from the initial and subsequent 

performance test and from the 

performance evaluation of the 

continuous monitors (including the 

transmissometer) are submitted to the 

Administrator.

* * * * *

(g) For Hg, the following information 

shall be reported to the Administrator: 

(1) Company name and address; 

(2) Date of report and beginning and 

ending dates of the reporting period; 

(3) The applicable Hg emission limit 

(lb/MWh); and 

(4) For each month in the reporting 

period: 

(i) The number of unit operating 

hours; 

(ii) The number of unit operating 

hours with valid data for Hg 

concentration, stack gas flow rate, 

moisture (if required), and electrical 

output; 

(iii) The monthly Hg emission rate 

(lb/MWh); 

(iv) The number of hours of valid data 

excluded from the calculation of the 

monthly Hg emission rate, due to unit 

startup, shutdown and malfunction; and 

(v) The 12-month rolling average Hg 

emission rate (lb/MWh); and 

(5) The data assessment report (DAR) 

required by appendix F to this part, or 

an equivalent summary of QA test 

results if the QA of part 75 of this 

chapter are implemented.

* * * * *

(k) The owner or operator of an 

affected facility may submit electronic 

quarterly reports for SO2 and/or NOX

and/or opacity and/or Hg in lieu of 

submitting the written reports required 

under paragraphs (b), (g), and (i) of this 

section. * * *

■ 11. Section 60.52a is added to subpart 

Da to read as follows;

§ 60.52a Recordkeeping requirements. 

The owner or operator of an affected 

facility subject to the emissions 

limitations in § 60.45a or § 60.46a shall 

provide notifications in accordance with 

§ 60.7(a) and shall maintain records of 

all information needed to demonstrate 

compliance including performance 

tests, monitoring data, fuel analyses, 

and calculations, consistent with the 

requirements of § 60.7(f).


ER18my05.003</MATH> ER18my05.004</MATH> ER18my05.005</MATH>
Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28657

Subpart GGGG—[Added]

■ 12. Part 60 is amended by adding and 

reserving subpart GGGG to read as 

follows:

Subpart GGGG—[Reserved]

■ 13. Part 60 is amended by adding 

subpart HHHH to read as follows:

Subpart HHHH—Emission Guidelines 

and Compliance Times for Coal-Fired 

Electric Steam Generating Units 

Hg Budget Trading Program General 

Provisions

Sec. 

60.4101 Purpose. 

60.4102 Definitions. 

60.4103 Measurements, abbreviations, and 

acronyms. 

60.4104 Applicability. 

60.4105 Retired unit exemption. 

60.4106 Standard requirements. 

60.4107 Computation of time. 

60.4108 Appeal procedures. 

Hg Designated Representative for Hg Budget 

Sources 

60.4110 Authorization and responsibilities 

of Hg Designated Representative. 

60.4111 Alternate Hg Designated 

Representative. 

60.4112 Changing Hg Designated 

Representative and Alternate Hg 

Designated Representative; changes in 

owners and operators.

60.4113 Certificate of Representation. 

60.4114 Objections concerning Hg 

Designated Representative. 

Permits 

60.4120 General Hg budget trading program 

permit requirements. 

60.4121 Submission of Hg budget permit 

applications. 

60.4122 Information requirements for Hg 

budget permit applications. 

60.4123 Hg budget permit contents and 

term. 

60.4124 Hg budget permit revisions. 

60.4130 [Reserved] 

Hg Allowance Allocations 

60.4140 State trading budgets. 

60.4141 Timing requirements for Hg 

allowance allocations. 

60.4142 Hg allowance allocations. 

Hg Allowance Tracking System 

60.4150 [Reserved] 

60.4151 Establishment of accounts. 

60.4152 Responsibilities of Hg Authorized 

Account Representative. 

60.4153 Recordation of Hg allowance 

allocations. 

60.4154 Compliance with Hg budget 

emissions limitation. 

60.4155 Banking. 

60.4156 Account error. 

60.4157 Closing of general accounts. 

Hg Allowance Transfers 

60.4160 Submission of Hg allowance 

transfers. 

60.4161 EPA recordation. 

60.4162 Notification. 

Monitoring and Reporting 

60.4170 General requirements. 

60.4171 Initial certification and 

recertification procedures. 

60.4172 Out of control periods. 

60.4173 Notifications. 

60.4174 Recordkeeping and reporting. 

60.4175 Petitions. 

60.4176 Additional requirements to provide 

heat input data.

Hg Budget Trading Program General 

Provisions

§ 60.4101 Purpose. 

This subpart establishes the model 

rule comprising general provisions and 

the designated representative, 

permitting, allowance, and monitoring 

provisions for the State mercury (Hg) 

Budget Trading Program, under section 

111 of the Clean Air Act (CAA) and 

§ 60.24(h)(6), as a means of reducing 

national Hg emissions. The owner or 

operator of a unit or a source shall 

comply with the requirements of this 

subpart as a matter of Federal law only 

if the State with jurisdiction over the 

unit and the source incorporates by 

reference this subpart or otherwise 

adopts the requirements of this subpart 

in accordance with § 60.24(h)(6), the 

State submits to the Administrator one 

or more revisions of the State plan that 

include such adoption, and the 

Administrator approves such revisions. 

If the State adopts the requirements of 

this subpart in accordance with 

§ 60.24(h)(6), then the State authorizes 

the Administrator to assist the State in 

implementing the Hg Budget Trading 

Program by carrying out the functions 

set forth for the Administrator in this 

subpart.

§ 60.4102 Definitions. 

The terms used in this subpart shall 

have the meanings set forth in this 

section as follows: 

Account number means the 

identification number given by the 

Administrator to each Hg Allowance 

Tracking System account.

Acid rain emissions limitation means 

a limitation on emissions of sulfur 

dioxide or nitrogen oxides under the 

Acid Rain Program. 

Acid Rain Program means a multistate sulfur dioxide and nitrogen oxides 

air pollution control and emission 

reduction program established by the 

Administrator under title IV of the CAA 

and parts 72 through 78 of this chapter. 

Administrator means the 

Administrator of the United States 

Environmental Protection Agency or the 

Administrator’s duly authorized 

representative. 

Allocate or allocation means the 

determination by the permitting 

authority or the Administrator of the 

amount of Hg allowances to be initially 

credited to a Hg Budget unit or a new 

unit set-aside under §§ 60.4140 through 

60.4142. 

Allowance transfer deadline means, 

for a control period, midnight of March 

1, if it is a business day, or, if March 1 

is not a business day, midnight of the 

first business day thereafter 

immediately following the control 

period and is the deadline by which a 

Hg allowance transfer must be 

submitted for recordation in a Hg 

Budget source’s compliance account in 

order to be used to meet the source’s Hg 

Budget emissions limitation for such 

control period in accordance with 

§ 60.4154. 

Alternate Hg designated 

representative means, for a Hg Budget 

source and each Hg Budget unit at the 

source, the natural person who is 

authorized by the owners and operators 

of the source and all such units at the 

source in accordance with §§ 60.4110 

through 60.4114, to act on behalf of the 

Hg designated representative in matters 

pertaining to the Hg Budget Trading 

Program. 

Automated data acquisition and 

handling system or DAHS means that 

component of the continuous emission 

monitoring system (CEMS), or other 

emissions monitoring system approved 

for use under §§ 60.4170 though 

60.4176, designed to interpret and 

convert individual output signals from 

pollutant concentration monitors, flow 

monitors, diluent gas monitors, and 

other component parts of the monitoring 

system to produce a continuous record 

of the measured parameters in the 

measurement units required §§ 60.4170 

through 60.4176. 

Boiler means an enclosed fossil-or 

other fuel-fired combustion device used 

to produce heat and to transfer heat to 

recirculating water, steam, or other 

medium. 

Bottoming-cycle cogeneration unit

means a cogeneration unit in which the 

energy input to the unit is first used to 

produce useful thermal energy and at 

least some of the reject heat from the 

useful thermal energy application or 

process is then used for electricity 

production. 

CAIR NOX Annual Trading Program

means a multi-state nitrogen oxides air 

pollution control and emission 

reduction program approved and 

administered by the Administrator in 

accordance with subparts AA through II 

of part 96 of this chapter and § 51.123 

of this chapter, as a means of mitigating 

28658 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

interstate transport of fine particulates 

and nitrogen oxides. 

CAIR NOX Ozone Season Trading 

Program means a multi-state nitrogen 

oxides air pollution control and 

emission reduction program approved 

and administered by the Administrator 

in accordance with subparts AAAA 

through IIII of part 96 of this chapter 

and § 51.123 of this chapter, as a means 

of mitigating interstate transport of 

ozone and nitrogen oxides. 

CAIR SO2 Trading Program means a 

multi-state sulfur dioxide air pollution 

control and emission reduction program 

approved and administered by the 

Administrator in accordance with 

subparts AAA through III of part 96 of 

this chapter and § 51.124 of this chapter, 

as a means of mitigating interstate 

transport of fine particulates and sulfur 

dioxide. 

Clean Air Act or CAA means the 

Clean Air Act, 42 U.S.C. 7401, et seq.

Coal means any solid fuel classified as 

anthracite, bituminous, subbituminous, 

or lignite by the American Society of 

Testing and Materials (ASTM) Standard 

Specification for Classification of Coals 

by Rank D388–77, 90, 91, 95, 98a, or 99 

(Reapproved 2004)ε1 (incorporated by 

reference, see § 60.17). 

Coal-derived fuel means any fuel 

(whether in a solid, liquid, or gaseous 

state) produced by the mechanical, 

thermal, or chemical processing of coal.

Coal-fired means combusting any 

amount of coal or coal-derived fuel, 

alone or in combination with any 

amount of any other fuel, during any 

year. 

Cogeneration unit means a stationary, 

coal-fired boiler or stationary, coal-fired 

combustion turbine: 

(1) Having equipment used to produce 

electricity and useful thermal energy for 

industrial, commercial, heating, or 

cooling purposes through the sequential 

use of energy; and 

(2) Producing during the 12-month 

period starting on the date the unit first 

produces electricity and during any 

calendar year after which the unit first 

produces electricity: 

(i) For a topping-cycle cogeneration 

unit, 

(A) Useful thermal energy not less 

than 5 percent of total energy output; 

and 

(B) Useful power that, when added to 

one-half of useful thermal energy 

produced, is not less then 42.5 percent 

of total energy input, if useful thermal 

energy produced is 15 percent or more 

of total energy output, or not less than 

45 percent of total energy input, if 

useful thermal energy produced is less 

than 15 percent of total energy output. 

(ii) For a bottoming-cycle 

cogeneration unit, useful power not less 

than 45 percent of total energy input. 

Combustion turbine means:

(1) An enclosed device comprising a 

compressor, a combustor, and a turbine 

and in which the flue gas resulting from 

the combustion of fuel in the combustor 

passes through the turbine, rotating the 

turbine; and 

(2) If the enclosed device under 

paragraph (1) of this definition is 

combined cycle, any associated heat 

recovery steam generator and steam 

turbine. 

Commence commercial operation

means, with regard to a unit serving a 

generator: 

(1) To have begun to produce steam, 

gas, or other heated medium used to 

generate electricity for sale or use, 

including test generation, except as 

provided in § 60.4105. 

(i) For a unit that is a Hg Budget unit 

under § 60.4104 on the date the unit 

commences commercial operation as 

defined in paragraph (1) of this 

definition and that subsequently 

undergoes a physical change (other than 

replacement of the unit by a unit at the 

same source), such date shall remain the 

unit’s date of commencement of 

commercial operation. 

(ii) For a unit that is a Hg Budget unit 

under § 60.4104 on the date the unit 

commences commercial operation as 

defined in paragraph (1) of this 

definition and that is subsequently 

replaced by a unit at the same source 

(e.g., repowered), the replacement unit 

shall be treated as a separate unit with 

a separate date for commencement of 

commercial operation as defined in 

paragraph (1) or (2) of this definition as 

appropriate.

(2) Notwithstanding paragraph (1) of 

this definition and except as provided 

in § 60.4105, for a unit that is not a Hg 

Budget unit under § 60.4104 on the date 

the unit commences commercial 

operation as defined in paragraph (1) of 

this definition, the unit’s date for 

commencement of commercial 

operation shall be the date on which the 

unit becomes a Hg Budget unit under 

§ 60.4104. 

(i) For a unit with a date for 

commencement of commercial 

operation as defined in paragraph (2) of 

this definition and that subsequently 

undergoes a physical change (other than 

replacement of the unit by a unit at the 

same source), such date shall remain the 

unit’s date of commencement of 

commercial operation. 

(ii) For a unit with a date for 

commencement of commercial 

operation as defined in paragraph (2) of 

this definition and that is subsequently 

replaced by a unit at the same source 

(e.g., repowered), the replacement unit 

shall be treated as a separate unit with 

a separate date for commencement of 

commercial operation as defined in 

paragraph (1) or (2) of this definition as 

appropriate. 

Commence operation means: 

(1) To have begun any mechanical, 

chemical, or electronic process, 

including, with regard to a unit, start-up 

of a unit’s combustion chamber, except 

as provided in § 60.4105. 

(i) For a unit that is a Hg Budget unit 

under § 60.4104 on the date the unit 

commences operation as defined in 

paragraph (1) of this definition and that 

subsequently undergoes a physical 

change (other than replacement of the 

unit by a unit at the same source), such 

date shall remain the unit’s date of 

commencement of operation. 

(ii) For a unit that is a Hg Budget unit 

under § 60.4104 on the date the unit 

commences operation as defined in 

paragraph (1) of this definition and that 

is subsequently replaced by a unit at the 

same source (e.g., repowered), the 

replacement unit shall be treated as a 

separate unit with a separate date for 

commencement of operation as defined 

in paragraph (1) or (2) of this definition 

as appropriate. 

(2) Notwithstanding paragraph (1) of 

this definition and except as provided 

in § 60.4105, for a unit that is not a Hg 

Budget unit under § 60.4104 on the date 

the unit commences operation as 

defined in paragraph (1) of this 

definition, the unit’s date for 

commencement of operation shall be the 

date on which the unit becomes a Hg 

Budget unit under § 60.4104. 

(i) For a unit with a date for 

commencement of operation as defined 

in paragraph (2) of this definition and 

that subsequently undergoes a physical 

change (other than replacement of the 

unit by a unit at the same source), such 

date shall remain the unit’s date of 

commencement of operation. 

(ii) For a unit with a date for 

commencement of operation as defined 

in paragraph (2) of this definition and 

that is subsequently replaced by a unit 

at the same source (e.g., repowered), the 

replacement unit shall be treated as a 

separate unit with a separate date for 

commencement of operation as defined 

in paragraph (1) or (2) of this definition 

as appropriate. 

Common stack means a single flue 

through which emissions from 2 or 

more units are exhausted. 

Compliance account means a Hg 

Allowance Tracking System account, 

established by the Administrator for a 

Hg Budget source under §§ 60.4150 

through 60.4157, in which any Hg

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28659

allowance allocations for the Hg Budget 

units at the source are initially recorded 

and in which are held any Hg 

allowances available for use for a 

control period in order to meet the 

source’s Hg Budget emissions limitation 

in accordance with § 60.4154. 

Continuous emission monitoring 

system or CEMS means the equipment 

required under §§ 60.4170 through 

60.4176 to sample, analyze, measure, 

and provide, by means of readings 

recorded at least once every 15 minutes 

(using an automated data acquisition 

and handling system (DAHS)), a 

permanent record of Hg emissions, stack 

gas volumetric flow rate, stack gas 

moisture content, and oxygen or carbon 

dioxide concentration (as applicable), in 

a manner consistent with part 75 of this 

chapter. The following systems are the 

principal types of CEMS required under 

§§ 60.4170 through 60.4176:

(1) A flow monitoring system, 

consisting of a stack flow rate monitor 

and an automated data acquisition and 

handling system and providing a 

permanent, continuous record of stack 

gas volumetric flow rate, in units of 

standard cubic feet per hour (scfh); 

(2) A Hg concentration monitoring 

system, consisting of a Hg pollutant 

concentration monitor and an 

automated data acquisition and 

handling system and providing a 

permanent, continuous record of Hg 

emissions in units of micrograms per 

dry standard cubic meter (μg/dscm); 

(3) A moisture monitoring system, as 

defined in § 75.11(b)(2) of this chapter 

and providing a permanent, continuous 

record of the stack gas moisture content, 

in percent H2O. 

(4) A carbon dioxide monitoring 

system, consisting of a CO2

concentration monitor (or an oxygen 

monitor plus suitable mathematical 

equations from which the CO2

concentration is derived) and an 

automated data acquisition and 

handling system and providing a 

permanent, continuous record of CO2

emissions, in percent CO2; and 

(5) An oxygen monitoring system, 

consisting of an O2 concentration 

monitor and an automated data 

acquisition and handling system and 

providing a permanent, continuous 

record of O2, in percent O2. 

Control period means the period 

beginning January 1 of a calendar year 

and ending on December 31 of the same 

year, inclusive. 

Emissions means air pollutants 

exhausted from a unit or source into the 

atmosphere, as measured, recorded, and 

reported to the Administrator by the Hg 

designated representative and as 

determined by the Administrator in 

accordance with §§ 60.4170 through 

60.4176. 

Excess emissions means any ounce of 

mercury emitted by the Hg Budget units 

at a Hg Budget source during a control 

period that exceeds the Hg Budget 

emissions limitation for the source. 

General account means a Hg 

Allowance Tracking System account, 

established under § 60.4151, that is not 

a compliance account. 

Generator means a device that 

produces electricity. 

Gross electrical output means, with 

regard to a cogeneration unit, electricity 

made available for use, including any 

such electricity used in the power 

production process (which process 

includes, but is not limited to, any onsite processing or treatment of fuel 

combusted at the unit and any on-site 

emission controls). 

Heat input means, with regard to a 

specified period of time, the product (in 

MMBtu/time) of the gross calorific value 

of the fuel (in Btu/lb) divided by 

1,000,000 Btu/MMBtu and multiplied 

by the fuel feed rate into a combustion 

device (in lb of fuel/time), as measured, 

recorded, and reported to the 

Administrator by the Hg designated 

representative and determined by the 

Administrator in accordance with 

§§ 60.4170 through 60.4176 and 

excluding the heat derived from 

preheated combustion air, recirculated 

flue gases, or exhaust from other 

sources. 

Heat input rate means the amount of 

heat input (in MMBtu) divided by unit 

operating time (in hr) or, with regard to 

a specific fuel, the amount of heat input 

attributed to the fuel (in MMBtu) 

divided by the unit operating time (in 

hr) during which the unit combusts the 

fuel.

Hg allowance means a limited 

authorization issued by the permitting 

authority or the Administrator under 

§§ 60.4140 through 60.4142 to emit one 

ounce of mercury during a control 

period of the specified calendar year for 

which the authorization is allocated or 

of any calendar year thereafter under the 

Hg Budget Trading Program. An 

authorization to emit mercury that is not 

issued under the provisions of a State 

plan that adopt the requirements of this 

subpart and are approved by the 

Administrator in accordance with 

§ 60.24(h)(6) shall not be a ‘‘Hg 

allowance.’’

Hg allowance deduction or deduct Hg 

allowances means the permanent 

withdrawal of Hg allowances by the 

Administrator from a compliance 

account in order to account for a 

specified number of ounces of total 

mercury emissions from all Hg Budget 

units at a Hg Budget source for a control 

period, determined in accordance with 

§§ 60.4150 though 60.4157 and 

§§ 60.4170 through 60.4176, or to 

account for excess emissions. 

Hg allowances held or hold Hg 

allowances means the Hg allowances 

recorded by the Administrator, or 

submitted to the Administrator for 

recordation, in accordance with 

§§ 60.4150 through 60.4162, in a Hg 

Allowance Tracking System account. 

Hg Allowance Tracking System means 

the system by which the Administrator 

records allocations, deductions, and 

transfers of Hg allowances under the Hg 

Budget Trading Program. Such 

allowances will be allocated, held, 

deducted, or transferred only as whole 

allowances. 

Hg Allowance Tracking System 

account means an account in the Hg 

Allowance Tracking System established 

by the Administrator for purposes of 

recording the allocation, holding, 

transferring, or deducting of Hg 

allowances.

Hg authorized account representative

means, with regard to a general account, 

a responsible natural person who is 

authorized, in accordance with 

§ 60.4152, to transfer and otherwise 

dispose of Hg allowances held in the 

general account and, with regard to a 

compliance account, the Hg designated 

representative of the source. 

Hg Budget emissions limitation

means, for a Hg Budget source, the 

equivalent in ounces of the Hg 

allowances available for deduction for 

the source under § 60.4154(a) and (b) for 

a control period. 

Hg Budget permit means the legally 

binding and Federally enforceable 

written document, or portion of such 

document, issued by the permitting 

authority under §§ 60.4120 through 

60.4124, including any permit revisions, 

specifying the Hg Budget Trading 

Program requirements applicable to a 

Hg Budget source, to each Hg Budget 

unit at the source, and to the owners 

and operators and the Hg designated 

representative of the source and each 

such unit. 

Hg Budget source means a source that 

includes one or more Hg Budget units. 

Hg Budget Trading Program means a 

multi-state Hg air pollution control and 

emission reduction program approved 

and administered by the Administrator 

in accordance with this subpart and 

§ 60.24(h)(6), as a means of reducing 

national Hg emissions. 

Hg Budget unit means a unit that is 

subject to the Hg Budget Trading 

Program under § 60.4104. 

Hg designated representative means, 

for a Hg Budget source and each Hg 

28660 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

Budget unit at the source, the natural 

person who is authorized by the owners 

and operators of the source and all such 

units at the source, in accordance with 

§§ 60.4110 through 60.4114, to represent 

and legally bind each owner and 

operator in matters pertaining to the Hg 

Budget Trading Program. 

Life-of-the-unit, firm power 

contractual arrangement means a unit 

participation power sales agreement 

under which a utility or industrial 

customer reserves, or is entitled to 

receive, a specified amount or 

percentage of nameplate capacity and 

associated energy generated by any 

specified unit and pays its proportional 

amount of such unit’s total costs, 

pursuant to a contract: 

(1) For the life of the unit; 

(2) For a cumulative term of no less 

than 30 years, including contracts that 

permit an election for early termination; 

or 

(3) For a period no less than 25 years 

or 70 percent of the economic useful life 

of the unit determined as of the time the 

unit is built, with option rights to 

purchase or release some portion of the 

nameplate capacity and associated 

energy generated by the unit at the end 

of the period. 

Lignite means coal that is classified as 

lignite A or B according to the American 

Society of Testing and Materials 

(ASTM) Standard Specification for 

Classification of Coals by Rank D388–

77, 90, 91, 95, 98a, or 99 (Reapproved 

2004)ε1 (incorporated by reference, see 

§ 60.17). 

Maximum design heat input means, 

starting from the initial installation of a 

unit, the maximum amount of fuel per 

hour (in Btu/hr) that a unit is capable of 

combusting on a steady-state basis as 

specified by the manufacturer of the 

unit, or, starting from the completion of 

any subsequent physical change in the 

unit resulting in a decrease in the 

maximum amount of fuel per hour (in 

Btu/hr) that a unit is capable of 

combusting on a steady-state basis, such 

decreased maximum amount as 

specified by the person conducting the 

physical change. 

Monitoring system means any 

monitoring system that meets the 

requirements of §§ 60.4170 through 

60.4176, including a continuous 

emissions monitoring system, an 

alternative monitoring system, or an 

excepted monitoring system under part 

75 of this chapter. 

Nameplate capacity means, starting 

from the initial installation of a 

generator, the maximum electrical 

generating output (in MWe) that the 

generator is capable of producing on a 

steady-state basis and during 

continuous operation (when not 

restricted by seasonal or other deratings) 

as specified by the manufacturer of the 

generator or, starting from the 

completion of any subsequent physical 

change in the generator resulting in an 

increase in the maximum electrical 

generating output (in MWe) that the 

generator is capable of producing on a 

steady-state basis and during 

continuous operation (when not 

restricted by seasonal or other 

deratings), such increased maximum 

amount as specified by the person 

conducting the physical change. 

Operator means any person who 

operates, controls, or supervises a Hg 

Budget unit or a Hg Budget source and 

shall include, but not be limited to, any 

holding company, utility system, or 

plant manager of such a unit or source. 

Ounce means 2.84 × 107 micrograms. 

For the purpose of determining 

compliance with the Hg Budget 

emissions limitation, total ounces of 

mercury emissions for a control period 

shall be calculated as the sum of all 

recorded hourly emissions (or the mass 

equivalent of the recorded hourly 

emission rates) in accordance with 

§§ 60.4170 through 60.4176, but with 

any remaining fraction of an ounce 

equal to or greater than 0.50 ounces 

deemed to equal one ounce and any 

remaining fraction of an ounce less than 

0.50 ounces deemed to equal zero 

ounces. 

Owner means any of the following 

persons: 

(1) With regard to a Hg Budget source 

or a Hg Budget unit at a source, 

respectively: 

(i) Any holder of any portion of the 

legal or equitable title in a Hg Budget 

unit at the source or the Hg Budget unit; 

(ii) Any holder of a leasehold interest 

in a Hg Budget unit at the source or the 

Hg Budget unit; or 

(iii) Any purchaser of power from a 

Hg Budget unit at the source or the Hg 

Budget unit under a life-of-the-unit, firm 

power contractual arrangement; 

provided that, unless expressly 

provided for in a leasehold agreement, 

owner shall not include a passive lessor, 

or a person who has an equitable 

interest through such lessor, whose 

rental payments are not based (either 

directly or indirectly) on the revenues or 

income from such Hg Budget unit; or 

(2) With regard to any general 

account, any person who has an 

ownership interest with respect to the 

Hg allowances held in the general 

account and who is subject to the 

binding agreement for the Hg authorized 

account representative to represent the 

person’s ownership interest with respect 

to Hg allowances. 

Permitting authority means the State 

air pollution control agency, local 

agency, other State agency, or other 

agency authorized by the Administrator 

to issue or revise permits to meet the 

requirements of the Hg Budget Trading 

Program in accordance with §§ 60.4120 

through 60.4124 or, if no such agency 

has been so authorized, the 

Administrator. 

Potential electrical output capacity 

means 33 percent of a unit’s maximum 

design heat input, divided by 3,413 Btu/ 

kWh, divided by 1,000 kWh/MWh, and 

multiplied by 8,760 hr/yr. 

Receive or receipt of means, when 

referring to the permitting authority or 

the Administrator, to come into 

possession of a document, information, 

or correspondence (whether sent in hard 

copy or by authorized electronic 

transmission), as indicated in an official 

correspondence log, or by a notation 

made on the document, information, or 

correspondence, by the permitting 

authority or the Administrator in the 

regular course of business. 

Recordation, record, or recorded 

means, with regard to Hg allowances, 

the movement of Hg allowances by the 

Administrator into or between Hg 

Allowance Tracking System accounts, 

for purposes of allocation, transfer, or 

deduction. 

Reference method means any direct 

test method of sampling and analyzing 

for an air pollutant as specified in 

§ 75.22 of this chapter. 

Repowered means, with regard to a 

unit, replacement of a coal-fired boiler 

with one of the following coal-fired 

technologies at the same source as the 

coal-fired boiler: 

(1) Atmospheric or pressurized 

fluidized bed combustion; 

(2) Integrated gasification combined 

cycle; 

(3) Magnetohydrodynamics; 

(4) Direct and indirect coal-fired 

turbines; 

(5) Integrated gasification fuel cells; or 

(6) As determined by the 

Administrator in consultation with the 

Secretary of Energy, a derivative of one 

or more of the technologies under 

paragraphs (1) through (5) of this 

definition and any other coal-fired 

technology capable of controlling 

multiple combustion emissions 

simultaneously with improved boiler or 

generation efficiency and with 

significantly greater waste reduction 

relative to the performance of 

technology in widespread commercial 

use as of January 1, 2005. 

Serial number means, for a Hg 

allowance, the unique identification 

number assigned to each Hg allowance 

by the Administrator. 

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28661 

Sequential use of energy means: 

(1) For a topping-cycle cogeneration 

unit, the use of reject heat from 

electricity production in a useful 

thermal energy application or process; 

or 

(2) For a bottoming-cycle cogeneration 

unit, the use of reject heat from useful 

thermal energy application or process in 

electricity production. 

Source means all buildings, 

structures, or installations located in 

one or more contiguous or adjacent 

properties under common control of the 

same person or persons. For purposes of 

section 502(c) of the CAA, a ‘‘source,’’

including a ‘‘source’’ with multiple 

units, shall be considered a single 

‘‘facility.’’

State means: 

(1) For purposes of referring to a 

governing entity, one of the States in the 

United States, the District of Columbia, 

or, if approved for treatment as a State 

under part 49 of this chapter, the Navajo 

Nation or Ute Indian Tribe that adopts 

the Hg Budget Trading Program 

pursuant to § 60.24(h)(6); or 

(2) For purposes of referring to 

geographic areas, one of the States in the 

United States, the District of Columbia, 

the Navajo Nation Indian country, or the 

Ute Tribe Indian country. 

Subbituminous means coal that is 

classified as subbituminous A, B, or C, 

according to the American Society of 

Testing and Materials (ASTM) Standard 

Specification for Classification of Coals 

by Rank D388–77, 90, 91, 95, 98a, or 99 

(Reapproved 2004)ε1 (incorporated by 

reference, see § 60.17). 

Submit or serve means to send or 

transmit a document, information, or 

correspondence to the person specified 

in accordance with the applicable 

regulation: 

(1) In person; 

(2) By United States Postal Service; or 

(3) By other means of dispatch or 

transmission and delivery. Compliance 

with any ‘‘submission’’ or ‘‘service’’

deadline shall be determined by the 

date of dispatch, transmission, or 

mailing and not the date of receipt. 

Title V operating permit means a 

permit issued under title V of the CAA 

and part 70 or part 71 of this chapter. 

Title V operating permit regulations 

means the regulations that the 

Administrator has approved or issued as 

meeting the requirements of title V of 

the CAA and part 70 or 71 of this 

chapter. 

Topping-cycle cogeneration unit 

means a cogeneration unit in which the 

energy input to the unit is first used to 

produce useful power, including 

electricity, and at least some of the 

reject heat from the electricity 

production is then used to provide 

useful thermal energy. 

Total energy input means, with regard 

to a cogeneration unit, total energy of all 

forms supplied to the cogeneration unit, 

excluding energy produced by the 

cogeneration unit itself. 

Total energy output means, with 

regard to a cogeneration unit, the sum 

of useful power and useful thermal 

energy produced by the cogeneration 

unit. 

Unit means a stationary coal-fired 

boiler or a stationary coal-fired 

combustion turbine. 

Unit operating day means a calendar 

day in which a unit combusts any fuel. 

Unit operating hour or hour of unit 

operation means an hour in which a 

unit combusts any fuel. 

Useful power means, with regard to a 

cogeneration unit, electricity or 

mechanical energy made available for 

use, excluding any such energy used in 

the power production process (which 

process includes, but is not limited to, 

any on-site processing or treatment of 

fuel combusted at the unit and any onsite emission controls). 

Useful thermal energy means, with 

regard to a cogeneration unit, thermal 

energy that is: 

(1) Made available to an industrial or 

commercial process (not a power 

production process), excluding any heat 

contained in condensate return or 

makeup water; 

(2) Used in a heat application (e.g., 

space heating or domestic hot water 

heating); or 

(3) Used in a space cooling 

application (i.e., thermal energy used by 

an absorption chiller). 

Utility power distribution system 

means the portion of an electricity grid 

owned or operated by a utility and 

dedicated to delivering electricity to 

customers. 

§ 60.4103 Measurements, abbreviations, 

and acronyms. 

Measurements, abbreviations, and 

acronyms used in this part are defined 

as follows: 

Btu—British thermal unit. 

CO2—carbon dioxide. 

H2O—water. 

Hg—mercury. 

hr—hour. 

kW—kilowatt electrical. 

kWh—kilowatt hour. 

lb—pound. 

MMBtu—million Btu. 

MWe—megawatt electrical. 

MWh—megawatt hour. 

NOX—nitrogen oxides. 

O2—oxygen. 

ppm—parts per million. 

scfh—standard cubic feet per hour. 

SO2—sulfur dioxide. 

yr—year. 

§ 60.4104 Applicability. 

The following units in a State shall be 

Hg Budget units, and any source that 

includes one or more such units shall be 

a Hg Budget source, subject to the 

requirements of this subpart: 

(a) Except as provided in paragraph 

(b) of this section, a unit serving at any 

time, since the start-up of the unit’s 

combustion chamber, a generator with 

nameplate capacity of more than 25 

MWe producing electricity for sale. 

(b) For a unit that qualifies as a 

cogeneration unit during the 12-month 

period starting on the date the unit first 

produces electricity and continues to 

qualify as a cogeneration unit, a 

cogeneration unit 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. If a unit qualifies as a 

cogeneration unit during the 12-month 

period starting on the date the unit first 

produces electricity but subsequently no 

longer qualifies as a cogeneration unit, 

the unit shall be subject to paragraph (a) 

of this section starting on the day on 

which the unit first no longer qualifies 

as a cogeneration unit. 

§ 60.4105 Retired unit exemption. 

(a)(1) Any Hg Budget unit that is 

permanently retired shall be exempt 

from the Hg Budget Trading Program, 

except for the provisions of this section, 

§ 60.4102, § 60.4103, § 60.4104, 

§ 60.4106(c)(4) through (8), § 60.4107, 

and §§ 60.4150 through 60.4162. 

(2) The exemption under paragraph 

(a)(1) of this section shall become 

effective the day on which the Hg 

Budget unit is permanently retired. 

Within 30 days of the unit’s permanent 

retirement, the Hg designated 

representative shall submit a statement 

to the permitting authority otherwise 

responsible for administering any Hg 

Budget permit for the unit and shall 

submit a copy of the statement to the 

Administrator. The statement shall 

state, in a format prescribed by the 

permitting authority, that the unit was 

permanently retired on a specific date 

and will comply with the requirements 

of paragraph (b) of this section. 

(3) After receipt of the statement 

under paragraph (a)(2) of this section, 

the permitting authority will amend any 

permit under §§ 60.4120 through 

60.4124 covering the source at which 

the unit is located to add the provisions 

and requirements of the exemption 

28662 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

under paragraphs (a)(1) and (b) of this 

section. 

(b) Special provisions. (1) A unit 

exempt under paragraph (a) of this 

section shall not emit any mercury, 

starting on the date that the exemption 

takes effect. 

(2) The permitting authority will 

allocate Hg allowances under §§ 60.4140 

through 60.4142 to a unit exempt under 

paragraph (a) of this section. 

(3) For a period of 5 years from the 

date the records are created, the owners 

and operators of a unit exempt under 

paragraph (a) of this section shall retain 

at the source that includes the unit, 

records demonstrating that the unit is 

permanently retired. The 5-year period 

for keeping records may be extended for 

cause, at any time before the end of the 

period, in writing by the permitting 

authority or the Administrator. The 

owners and operators bear the burden of 

proof that the unit is permanently 

retired. 

(4) The owners and operators and, to 

the extent applicable, the Hg designated 

representative of a unit exempt under 

paragraph (a) of this section shall 

comply with the requirements of the Hg 

Budget Trading Program concerning all 

periods for which the exemption is not 

in effect, even if such requirements 

arise, or must be complied with, after 

the exemption takes effect. 

(5) A unit exempt under paragraph (a) 

of this section and located at a source 

that is required, or but for this 

exemption would be required, to have a 

title V operating permit shall not resume 

operation unless the Hg designated 

representative of the source submits a 

complete Hg Budget permit application 

under § 60.4122 for the unit not less 

than 18 months (or such lesser time 

provided by the permitting authority) 

before the later of January 1, 2010 or the 

date on which the unit resumes 

operation. 

(6) On the earlier of the following 

dates, a unit exempt under paragraph (a) 

of this section shall lose its exemption: 

(i) The date on which the Hg 

designated representative submits a Hg 

Budget permit application for the unit 

under paragraph (b)(5) of this section; 

(ii) The date on which the Hg 

designated representative is required 

under paragraph (b)(5) of this section to 

submit a Hg Budget permit application 

for the unit; or 

(iii) The date on which the unit 

resumes operation, if the Hg designated 

representative is not required to submit 

a Hg Budget permit application for the 

unit. 

(7) For the purpose of applying 

monitoring, reporting, and 

recordkeeping requirements under 

§§ 60.4170 through 60.4176, a unit that 

loses its exemption under paragraph (a) 

of this section shall be treated as a unit 

that commences operation and 

commercial operation on the first date 

on which the unit resumes operation.

§ 60.4106 Standard requirements. 

(a) Permit Requirements. (1) The Hg 

designated representative of each Hg 

Budget source required to have a title V 

operating permit and each Hg Budget 

unit required to have a title V operating 

permit at the source shall:

(i) Submit to the permitting authority 

a complete Hg Budget permit 

application under § 60.4122 in 

accordance with the deadlines specified 

in § 60.4121(a) and (b); and 

(ii) Submit in a timely manner any 

supplemental information that the 

permitting authority determines is 

necessary in order to review a Hg 

Budget permit application and issue or 

deny a Hg Budget permit. 

(2) The owners and operators of each 

Hg Budget source required to have a 

title V operating permit and each Hg 

Budget unit required to have a title V 

operating permit at the source shall 

have a Hg Budget permit issued by the 

permitting authority under §§ 60.4120 

through 60.4124 for the source and 

operate the source and the unit in 

compliance with such Hg Budget 

permit. 

(3) The owners and operators of a Hg 

Budget source that is not required to 

have a title V operating permit and each 

Hg Budget unit that is not required to 

have a title V operating permit are not 

required to submit a Hg Budget permit 

application, and to have a Hg Budget 

permit, under §§ 60.4120 through 

60.4124 for such Hg Budget source and 

such Hg Budget unit. 

(b) Monitoring, reporting, and 

recordkeeping requirements. (1) The 

owners and operators, and the Hg 

designated representative, of each Hg 

Budget source and each Hg Budget unit 

at the source shall comply with the 

monitoring, reporting, and 

recordkeeping requirements of 

§§ 60.4170 through 60.4176. 

(2) The emissions measurements 

recorded and reported in accordance 

with §§ 60.4170 through 60.4176 shall 

be used to determine compliance by 

each Hg Budget source with the Hg 

Budget emissions limitation under 

paragraph (c) of this section. 

(c) Mercury emission requirements. (1) 

As of the allowance transfer deadline for 

a control period, the owners and 

operators of each Hg Budget source and 

each Hg Budget unit at the source shall 

hold, in the source’s compliance 

account, Hg allowances available for 

compliance deductions for the control 

period under § 60.4154(a) in an amount 

not less than the ounces of total mercury 

emissions for the control period from all 

Hg Budget units at the source, as 

determined in accordance with 

§§ 60.4170 through 60.4176. 

(2) A Hg Budget unit shall be subject 

to the requirements under paragraph 

(c)(1) of this section starting on the later 

of January 1, 2010 or the deadline for 

meeting the unit’s monitor certification 

requirements under § 60.4170(b)(1) or 

(2). 

(3) A Hg allowance shall not be 

deducted, for compliance with the 

requirements under paragraph (c)(1) of 

this section, for a control period in a 

calendar year before the year for which 

the Hg allowance was allocated.

(4) Hg allowances shall be held in, 

deducted from, or transferred into or 

among Hg Allowance Tracking System 

accounts in accordance with §§ 60.4160 

through 60.4162. 

(5) A Hg allowance is a limited 

authorization to emit one ounce of 

mercury in accordance with the Hg 

Budget Trading Program. No provision 

of the Hg Budget Trading Program, the 

Hg Budget permit application, the Hg 

Budget permit, or an exemption under 

§ 60.4105 and no provision of law shall 

be construed to limit the authority of the 

State or the United States to terminate 

or limit such authorization. 

(6) A Hg allowance does not 

constitute a property right. 

(7) Upon recordation by the 

Administrator under §§ 60.4150 through 

60.4162, every allocation, transfer, or 

deduction of a Hg allowance to or from 

a Hg Budget unit’s compliance account 

is incorporated automatically in any Hg 

Budget permit of the source that 

includes the Hg Budget unit. 

(d) Excess emissions requirements. (1) 

If a Hg Budget source emits mercury 

during any control period in excess of 

the Hg Budget emissions limitation, 

then: 

(i) The owners and operators of the 

source and each Hg Budget unit at the 

source shall surrender the Hg 

allowances required for deduction 

under § 60.4154(d)(1) and pay any fine, 

penalty, or assessment or comply with 

any other remedy imposed, for the same 

violations, under the Clean Air Act or 

applicable State law; and 

(ii) Each ounce of such excess 

emissions and each day of such control 

period shall constitute a separate 

violation of this subpart, the Clean Air 

Act, and applicable State law. 

(2) [Reserved] 

(e) Recordkeeping and reporting 

requirements. (1) Unless otherwise 

provided, the owners and operators of 

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28663

the Hg Budget source and each Hg 

Budget unit at the source shall keep on 

site at the source each of the following 

documents for a period of 5 years from 

the date the document is created. This 

period may be extended for cause, at 

any time before the end of 5 years, in 

writing by the permitting authority or 

the Administrator. 

(i) The certificate of representation 

under § 60.4113 for the Hg designated 

representative for the source and each 

Hg Budget unit at the source and all 

documents that demonstrate the truth of 

the statements in the certificate of 

representation; provided that the 

certificate and documents shall be 

retained on site at the source beyond 

such 5-year period until such 

documents are superseded because of 

the submission of a new certificate of 

representation under § 60.4113 changing 

the Hg designated representative.

(ii) All emissions monitoring 

information, in accordance with 

§§ 60.4170 through 60.4176, provided 

that to the extent that §§ 60.4170 

through 60.4176 provides for a 3-year 

period for recordkeeping, the 3-year 

period shall apply. 

(iii) Copies of all reports, compliance 

certifications, and other submissions 

and all records made or required under 

the Hg Budget Trading Program. 

(iv) Copies of all documents used to 

complete a Hg Budget permit 

application and any other submission 

under the Hg Budget Trading Program 

or to demonstrate compliance with the 

requirements of the Hg Budget Trading 

Program. 

(2) The Hg designated representative 

of a Hg Budget source and each Hg 

Budget unit at the source shall submit 

the reports required under the Hg 

Budget Trading Program, including 

those under §§ 60.4170 through 60.4176. 

(f) Liability. (1) Each Hg Budget source 

and each Hg Budget unit shall meet the 

requirements of the Hg Budget Trading 

Program. 

(2) Any provision of the Hg Budget 

Trading Program that applies to a Hg 

Budget source or the Hg designated 

representative of a Hg Budget source 

shall also apply to the owners and 

operators of such source and of the Hg 

Budget units at the source. 

(3) Any provision of the Hg Budget 

Trading Program that applies to a Hg 

Budget unit or the Hg designated 

representative of a Hg Budget unit shall 

also apply to the owners and operators 

of such unit. 

(g) Effect on other authorities. No 

provision of the Hg Budget Trading 

Program, a Hg Budget permit 

application, a Hg Budget permit, or an 

exemption under § 60.4105 shall be 

construed as exempting or excluding the 

owners and operators, and the Hg 

designated representative, of a Hg 

Budget source or Hg Budget unit from 

compliance with any other provision of 

the applicable, approved State 

implementation plan, a Federally 

enforceable permit, or the CAA.

§ 60.4107 Computation of time. 

(a) Unless otherwise stated, any time 

period scheduled, under the Hg Budget 

Trading Program, to begin on the 

occurrence of an act or event shall begin 

on the day the act or event occurs. 

(b) Unless otherwise stated, any time 

period scheduled, under the Hg Budget 

Trading Program, to begin before the 

occurrence of an act or event shall be 

computed so that the period ends the 

day before the act or event occurs. 

(c) Unless otherwise stated, if the final 

day of any time period, under the Hg 

Budget Trading Program, falls on a 

weekend or a State or Federal holiday, 

the time period shall be extended to the 

next business day.

§ 60.4108 Appeal procedures. 

The appeal procedures for decisions 

of the Administrator under the Hg 

Budget Trading Program shall be the 

procedures set forth in part 78 of this 

chapter. The terms ‘‘subpart HHHH of 

this part,’’ ‘‘§ 60.4141(b)(2) or (c)(2),’’

‘‘§ 60.4154,’’ ‘‘§ 60.4156,’’ ‘‘§ 60.4161,’’

‘‘§ 60.4175,’’ ‘‘Hg allowances,’’ ‘‘Hg 

Allowance Tracking System Account,’’

‘‘Hg designated representative,’’ ‘‘Hg 

authorized account representative,’’ and 

‘‘§ 60.4106’’ apply instead of the terms 

‘‘subparts AA through II of part 96 of 

this chapter,’’ ‘‘§ 96.141(b)(2) or (c)(2),’’

‘‘§ 96.154,’’ ‘‘§ 96.156,’’ ‘‘§ 96.161,’’

‘‘§ 96.175,’’ ‘‘CAIR NOX allowances,’’

‘‘CAIR NOX Allowance Tracking System 

account,’’ ‘‘CAIR designated 

representative,’’ ‘‘CAIR authorized 

account representative,’’ and ‘‘§ 96.106.’’

Hg Designated Representative for Hg 

Budget Sources

§ 60.4110 Authorization and 

Responsibilities of Hg Designated 

Representative. 

(a) Except as provided under 

§ 60.4111, each Hg Budget source, 

including all Hg Budget units at the 

source, shall have one and only one Hg 

designated representative, with regard 

to all matters under the Hg Budget 

Trading Program concerning the source 

or any Hg Budget unit at the source. 

(b) The Hg designated representative 

of the Hg Budget source shall be 

selected by an agreement binding on the 

owners and operators of the source and 

all Hg Budget units at the source and 

shall act in accordance with the 

certification statement in 

§ 60.4113(a)(4)(iv). 

(c) Upon receipt by the Administrator 

of a complete certificate of 

representation under § 60.4113, the Hg 

designated representative of the source 

shall represent and, by his or her 

representations, actions, inactions, or 

submissions, legally bind each owner 

and operator of the Hg Budget source 

represented and each Hg Budget unit at 

the source in all matters pertaining to 

the Hg Budget Trading Program, 

notwithstanding any agreement between 

the Hg designated representative and 

such owners and operators. The owners 

and operators shall be bound by any 

decision or order issued to the Hg 

designated representative by the 

permitting authority, the Administrator, 

or a court regarding the source or unit. 

(d) No Hg Budget permit will be 

issued, no emissions data reports will be 

accepted, and no Hg Allowance 

Tracking System account will be 

established for a Hg Budget unit at a 

source, until the Administrator has 

received a complete certificate of 

representation under § 60.4113 for a Hg 

designated representative of the source 

and the Hg Budget units at the source. 

(e)(1) Each submission under the Hg 

Budget Trading Program shall be 

submitted, signed, and certified by the 

Hg designated representative for each 

Hg Budget source on behalf of which the 

submission is made. Each such 

submission shall include the following 

certification statement by the Hg 

designated representative: ‘‘I am 

authorized to make this submission on 

behalf of the owners and operators of 

the source or units for which the 

submission is made. I certify under 

penalty of law that I have personally 

examined, and am familiar with, the 

statements and information submitted 

in this document and all its 

attachments. Based on my inquiry of 

those individuals with primary 

responsibility for obtaining the 

information, I certify that the statements 

and information are to the best of my 

knowledge and belief true, accurate, and 

complete. I am aware that there are 

significant penalties for submitting false 

statements and information or omitting 

required statements and information, 

including the possibility of fine or 

imprisonment.’’

(2) The permitting authority and the 

Administrator will accept or act on a 

submission made on behalf of owner or 

operators of a Hg Budget source or a Hg 

Budget unit only if the submission has 

been made, signed, and certified in 

accordance with paragraph (e)(1) of this 

section.

28664 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

§ 60.4111 Alternate Hg Designated 

Representative. 

(a) A certificate of representation 

under § 60.4113 may designate one and 

only one alternate Hg designated 

representative, who may act on behalf of 

the Hg designated representative. The 

agreement by which the alternate Hg 

designated representative is selected 

shall include a procedure for 

authorizing the alternate Hg designated 

representative to act in lieu of the Hg 

designated representative. 

(b) Upon receipt by the Administrator 

of a complete certificate of 

representation under § 60.4113, any 

representation, action, inaction, or 

submission by the alternate Hg 

designated representative shall be 

deemed to be a representation, action, 

inaction, or submission by the Hg 

designated representative. 

(c) Except in this section and 

§§ 60.4102, 60.4110(a) and (d), 60.4112, 

60.4113, 60.4151, and 60.4174, 

whenever the term ‘‘Hg designated 

representative’’ is used in this subpart, 

the term shall be construed to include 

the Hg designated representative or any 

alternate Hg designated representative.

§ 60.4112 Changing Hg Designated 

Representative and Alternate Hg 

Designated Representative; changes in 

owners and operators. 

(a) Changing Hg designated 

representative. The Hg designated 

representative may be changed at any 

time upon receipt by the Administrator 

of a superseding complete certificate of 

representation under § 60.4113. 

Notwithstanding any such change, all 

representations, actions, inactions, and 

submissions by the previous Hg 

designated representative before the 

time and date when the Administrator 

receives the superseding certificate of 

representation shall be binding on the 

new Hg designated representative and 

the owners and operators of the Hg 

Budget source and the Hg Budget units 

at the source. 

(b) Changing alternate Hg designated 

representative. The alternate Hg 

designated representative may be 

changed at any time upon receipt by the 

Administrator of a superseding 

complete certificate of representation 

under § 60.4113. Notwithstanding any 

such change, all representations, 

actions, inactions, and submissions by 

the previous alternate Hg designated 

representative before the time and date 

when the Administrator receives the 

superseding certificate of representation 

shall be binding on the new alternate Hg 

designated representative and the 

owners and operators of the Hg Budget 

source and the Hg Budget units at the 

source. 

(c) Changes in owners and operators.

(1) In the event a new owner or operator 

of a Hg Budget source or a Hg Budget 

unit is not included in the list of owners 

and operators in the certificate of 

representation under § 60.4113, such 

new owner or operator shall be deemed 

to be subject to and bound by the 

certificate of representation, the 

representations, actions, inactions, and 

submissions of the Hg designated 

representative and any alternate Hg 

designated representative of the source 

or unit, and the decisions and orders of 

the permitting authority, the 

Administrator, or a court, as if the new 

owner or operator were included in 

such list. 

(2) Within 30 days following any 

change in the owners and operators of 

a Hg Budget source or a Hg Budget unit, 

including the addition of a new owner 

or operator, the Hg designated 

representative or any alternate Hg 

designated representative shall submit a 

revision to the certificate of 

representation under § 60.4113 

amending the list of owners and 

operators to include the change.

§ 60.4113 Certificate of Representation. 

(a) A complete certificate of 

representation for a Hg designated 

representative or an alternate Hg 

designated representative shall include 

the following elements in a format 

prescribed by the Administrator: 

(1) Identification of the Hg Budget 

source, and each Hg Budget unit at the 

source, for which the certificate of 

representation is submitted. 

(2) The name, address, e-mail address 

(if any), telephone number, and 

facsimile transmission number (if any) 

of the Hg designated representative and 

any alternate Hg designated 

representative. 

(3) A list of the owners and operators 

of the Hg Budget source and of each Hg 

Budget unit at the source. 

(4) The following certification 

statements by the Hg designated 

representative and any alternate Hg 

designated representative:

(i) ‘‘I certify that I was selected as the 

Hg designated representative or 

alternate Hg designated representative, 

as applicable, by an agreement binding 

on the owners and operators of the 

source and each Hg Budget unit at the 

source.’’

(ii) ‘‘I certify that I have all the 

necessary authority to carry out my 

duties and responsibilities under the Hg 

Budget Trading Program on behalf of the 

owners and operators of the source and 

of each Hg Budget unit at the source and 

that each such owner and operator shall 

be fully bound by my representations, 

actions, inactions, or submissions.’’

(iii) ‘‘I certify that the owners and 

operators of the source and of each Hg 

Budget unit at the source shall be bound 

by any order issued to me by the 

Administrator, the permitting authority, 

or a court regarding the source or unit.’’

(iv) ‘‘Where there are multiple holders 

of a legal or equitable title to, or a 

leasehold interest in, a Hg Budget unit, 

or where a customer purchases power 

from a Hg Budget unit under a life-ofthe-unit, firm power contractual 

arrangement, I certify that: I have given 

a written notice of my selection as the 

‘Hg designated representative’ or 

‘alternate Hg designated representative,’

as applicable, and of the agreement by 

which I was selected to each owner and 

operator of the source and of each Hg 

Budget unit at the source; and Hg 

allowances and proceeds of transactions 

involving Hg allowances will be deemed 

to be held or distributed in proportion 

to each holder’s legal, equitable, 

leasehold, or contractual reservation or 

entitlement, except that, if such 

multiple holders have expressly 

provided for a different distribution of 

Hg allowances by contract, Hg 

allowances and proceeds of transactions 

involving Hg allowances will be deemed 

to be held or distributed in accordance 

with the contract.’’

(5) The signature of the Hg designated 

representative and any alternate Hg 

designated representative and the dates 

signed. 

(b) Unless otherwise required by the 

permitting authority or the 

Administrator, documents of agreement 

referred to in the certificate of 

representation shall not be submitted to 

the permitting authority or the 

Administrator. Neither the permitting 

authority nor the Administrator shall be 

under any obligation to review or 

evaluate the sufficiency of such 

documents, if submitted.

§ 60.4114 Objections concerning Hg 

Designated Representative. 

(a) Once a complete certificate of 

representation under § 60.4113 has been 

submitted and received, the permitting 

authority and the Administrator will 

rely on the certificate of representation 

unless and until a superseding complete 

certificate of representation under 

§ 60.4113 is received by the 

Administrator. 

(b) Except as provided in § 60.4112(a) 

or (b), no objection or other 

communication submitted to the 

permitting authority or the 

Administrator concerning the 

authorization, or any representation, 

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28665

action, inaction, or submission, of the 

Hg designated representative shall affect 

any representation, action, inaction, or 

submission of the Hg designated 

representative or the finality of any 

decision or order by the permitting 

authority or the Administrator under the 

Hg Budget Trading Program. 

(c) Neither the permitting authority 

nor the Administrator will adjudicate 

any private legal dispute concerning the 

authorization or any representation, 

action, inaction, or submission of any 

Hg designated representative, including 

private legal disputes concerning the 

proceeds of Hg allowance transfers. 

Permits

§ 60.4120 General Hg budget trading 

program permit requirements. 

(a) For each Hg Budget source 

required to have a title V operating 

permit, such permit shall include a Hg 

Budget permit administered by the 

permitting authority for the title V 

operating permit. The Hg Budget 

portion of the title V permit shall be 

administered in accordance with the 

permitting authority’s title V operating 

permits regulations promulgated under 

part 70 or 71 of this chapter, except as 

provided otherwise by this section and 

§§ 60.4121 through 60.4124. 

(b) Each Hg Budget permit shall 

contain, with regard to the Hg Budget 

source and the Hg Budget units at the 

source covered by the Hg Budget permit, 

all applicable Hg Budget Trading 

Program requirements and shall be a 

complete and separable portion of the 

title V operating permit.

§ 60.4121 Submission of Hg budget permit 

applications. 

(a) Duty to apply. The Hg designated 

representative of any Hg Budget source 

required to have a title V operating 

permit shall submit to the permitting 

authority a complete Hg Budget permit 

application under § 60.4122 for the 

source covering each Hg Budget unit at 

the source at least 18 months (or such 

lesser time provided by the permitting 

authority) before the later of January 1, 

2010 or the date on which the Hg 

Budget unit commences operation. 

(b) Duty to Reapply. For a Hg Budget 

source required to have a title V 

operating permit, the Hg designated 

representative shall submit a complete 

Hg Budget permit application under 

§ 60.4122 for the source covering each 

Hg Budget unit at the source to renew 

the Hg Budget permit in accordance 

with the permitting authority’s title V 

operating permits regulations 

addressing permit renewal.

§ 60.4122 Information requirements for Hg 

budget permit applications.

A complete Hg Budget permit 

application shall include the following 

elements concerning the Hg Budget 

source for which the application is 

submitted, in a format prescribed by the 

permitting authority: 

(a) Identification of the Hg Budget 

source; 

(b) Identification of each Hg Budget 

unit at the Hg Budget source; and 

(c) The standard requirements under 

§ 60.4106.

§ 60.4123 Hg budget permit contents and 

term. 

(a) Each Hg Budget permit will 

contain, in a format prescribed by the 

permitting authority, all elements 

required for a complete Hg Budget 

permit application under § 60.4122. 

(b) Each Hg Budget permit is deemed 

to incorporate automatically the 

definitions of terms under § 60.4102 

and, upon recordation by the 

Administrator under §§ 60.4150 through 

60.4162, every allocation, transfer, or 

deduction of a Hg allowance to or from 

the compliance account of the Hg 

Budget source covered by the permit. 

(c) The term of the Hg Budget permit 

will be set by the permitting authority, 

as necessary to facilitate coordination of 

the renewal of the Hg Budget permit 

with issuance, revision, or renewal of 

the Hg Budget source’s title V operating 

permit.

§ 60.4124 Hg budget permit revisions. 

Except as provided in § 60.4123(b), 

the permitting authority will revise the 

Hg Budget permit, as necessary, in 

accordance with the permitting 

authority’s title V operating permits 

regulations addressing permit revisions.

§ 60.4130 [Reserved] 

Hg Allowance Allocations

§ 60.4140 State trading budgets. 

The State trading budgets for annual 

allocations of Hg allowances for the 

control periods in 2010 through 2017 

and in 2018 and thereafter are 

respectively as follows:

State 

State trading budget

(tons) 

2010–2017 2018 and

thereafter 

Alaska ............... 0.005 0.002 

Alabama ............ 1.289 0.509 

Arkansas ........... 0.516 0.204 

Arizona .............. 0.454 0.179 

California ........... 0.041 0.016 

Colorado ........... 0.706 0.279 

Connecticut ....... 0.053 0.021 

Delaware ........... 0.072 0.028 

State 

State trading budget

(tons) 

2010–2017 2018 and

thereafter 

District of Columbia ............ 0 0 

Florida ............... 1.233 0.487 

Georgia ............. 1.227 0.484 

Hawaii ............... 0.024 0.009 

Idaho ................. 0 0 

Iowa .................. 0.727 0.287 

Illinois ................ 1.594 0.629 

Indiana .............. 2.098 0.828 

Kansas .............. 0.723 0.285 

Kentucky ........... 1.525 0.602 

Louisiana .......... 0.601 0.237 

Massachusetts .. 0.172 0.068 

Maryland ........... 0.49 0.193 

Maine ................ 0.001 0.001 

Michigan ........... 1.303 0.514 

Minnesota ......... 0.695 0.274 

Missouri ............ 1.393 0.55 

Mississippi ........ 0.291 0.115 

Montana ............ 0.378 0.149 

Navajo Nation 

Indian country 0.601 0.237 

North Carolina .. 1.133 0.447 

North Dakota .... 1.564 0.617 

Nebraska .......... 0.421 0.166 

New Hampshire 0.063 0.025 

New Jersey ....... 0.153 0.06 

New Mexico ...... 0.299 0.118 

Nevada ............. 0.285 0.112 

New York .......... 0.393 0.155 

Ohio .................. 2.057 0.812 

Oklahoma ......... 0.721 0.285 

Oregon .............. 0.076 0.03 

Pennsylvania .... 1.78 0.702 

Rhode Island .... 0 0 

South Carolina .. 0.58 0.229 

South Dakota .... 0.072 0.029 

Tennessee ........ 0.944 0.373 

Texas ................ 4.657 1.838 

Utah .................. 0.506 0.2 

Ute Indian Tribe 

Indian country 0.06 0.024 

Virginia .............. 0.592 0.234 

Vermont ............ 0 0 

Washington ....... 0.198 0.078 

Wisconsin ......... 0.89 0.351 

West Virginia .... 1.394 0.55 

Wyoming ........... 0.952 0.376 

§ 60.4141 Timing requirements for Hg 

allowance allocations. 

(a) By October 31, 2006, the 

permitting authority will submit to the 

Administrator the Hg allowance 

allocations, in a format prescribed by 

the Administrator and in accordance 

with § 60.4142(a) and (b), for the control 

periods in 2010, 2011, 2012, 2013, and 

2014. 

(b)(1) By October 31, 2008 and 

October 31 of each year thereafter, the 

permitting authority will submit to the 

Administrator the Hg allowance 

allocations, in a format prescribed by 

the Administrator and in accordance 

with § 60.4142(a) and (b), for the control 

period in the sixth year after the year of 

28666 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

the applicable deadline for submission 

under this paragraph. 

(2) If the permitting authority fails to 

submit to the Administrator the Hg 

allowance allocations in accordance 

with paragraph (b)(1) of this section, the 

Administrator will assume that the 

allocations of Hg allowances for the 

applicable control period are the same 

as for the control period that 

immediately precedes the applicable 

control period, except that, if the 

applicable control period is in 2018, the 

Administrator will assume that the 

allocations equal the allocations for the 

control period in 2017, multiplied by 

the amount of ounces (i.e., tons 

multiplied by 32,000 ounces/ton) of Hg 

emissions in the applicable State trading 

budget under § 60.4140 for 2018 and 

thereafter and divided by such amount 

of ounces of Hg emissions for 2010 

through 2017. 

(c)(1) By October 31, 2010 and 

October 31 of each year thereafter, the 

permitting authority will submit to the 

Administrator the Hg allowance 

allocations, in a format prescribed by 

the Administrator and in accordance 

with § 60.4142(a), (c), and (d), for the 

control period in the year of the 

applicable deadline for submission 

under this paragraph.

(2) If the permitting authority fails to 

submit to the Administrator the Hg 

allowance allocations in accordance 

with paragraph (c)(1) of this section, the 

Administrator will assume that the 

allocations of Hg allowances for the 

applicable control period are the same 

as for the control period that 

immediately precedes the applicable 

control period, except that, if the 

applicable control period is in 2018, the 

Administrator will assume that the 

allocations equal the allocations for the 

control period in 2017, multiplied by 

the amount of ounces (i.e., tons 

multiplied by 32,000 ounces/ton) of Hg 

emissions in the applicable State trading 

budget under § 60.4140 for 2018 and 

thereafter and divided by such amount 

of ounces of Hg emissions for 2010 

through 2017 and except that any Hg 

Budget unit that would otherwise be 

allocated Hg allowances under 

§ 60.4142(a) and (b), as well as under 

§ 60.4142(a), (c), and (d), for the 

applicable control period will be 

assumed to be allocated no Hg 

allowances under § 60.4142(a), (c), and 

(d) for the applicable control period.

§ 60.4142 Hg allowance allocations. 

(a)(1) The baseline heat input (in 

MMBtu) used with respect to Hg 

allowance allocations under paragraph 

(b) of this section for each Hg Budget 

unit will be: 

(i) For units commencing operation 

before January 1, 2001, the average of 

the three highest amounts of the unit’s 

adjusted control period heat input for 

2000 through 2004, with the adjusted 

control period heat input for each year 

calculated as the sum of the following: 

(A) Any portion of the unit’s control 

period heat input for the year that 

results from the unit’s combustion of 

lignite, multiplied by 3.0; 

(B) Any portion of the unit’s control 

period heat input for the year that 

results from the unit’s combustion of 

subbituminous coal, multiplied by 1.25; 

and 

(C) Any portion of the unit’s control 

period heat input for the year that is not 

covered by paragraph (a)(1)(i)(A) or (B) 

of this section, multiplied by 1.0. 

(ii) For units commencing operation 

on or after January 1, 2001 and 

operating each calendar year during a 

period of 5 or more consecutive 

calendar years, the average of the 3 

highest amounts of the unit’s total 

converted control period heat input over 

the first such 5 years. 

(2)(i) A unit’s control period heat 

input for a calendar year under 

paragraphs (a)(1)(i) of this section, and 

a unit’s total ounces of Hg emissions 

during a calendar year under paragraph 

(c)(3) of this section, will be determined 

in accordance with part 75 of this 

chapter, to the extent the unit was 

otherwise subject to the requirements of 

part 75 of this chapter for the year, or 

will be based on the best available data 

reported to the permitting authority for 

the unit, to the extent the unit was not 

otherwise subject to the requirements of 

part 75 of this chapter for the year. The 

unit’s types and amounts of fuel 

combusted, under paragraph (a)(1)(i) of 

this section, will be based on the best 

available data reported to the permitting 

authority for the unit.

(ii) A unit’s converted control period 

heat input for a calendar year specified 

under paragraph (a)(1)(ii) of this section 

equals: 

(A) Except as provided in paragraph 

(a)(2)(ii)(B) or (C) of this section, the 

control period gross electrical output of 

the generator or generators served by the 

unit multiplied by 7,900 Btu/kWh and 

divided by 1,000,000 Btu/MMBtu, 

provided that if a generator is served by 

2 or more units, then the gross electrical 

output of the generator will be 

attributed to each unit in proportion to 

the unit’s share of the total control 

period heat input of such units for the 

year; 

(B) For a unit that is a boiler and has 

equipment used to produce electricity 

and useful thermal energy for industrial, 

commercial, heating, or cooling 

purposes through the sequential use of 

energy, the total heat energy (in Btu) of 

the steam produced by the boiler during 

the control period, divided by 0.8 and 

by 1,000,000 Btu/MMBtu; or 

(C) For a unit that is a combustion 

turbine and has equipment used to 

produce electricity and useful thermal 

energy for industrial, commercial, 

heating, or cooling purposes through the 

sequential use of energy, the control 

period gross electrical output of the 

enclosed device comprising the 

compressor, combustor, and turbine 

multiplied by 3,413 Btu/kWh, plus the 

total heat energy (in Btu) of the steam 

produced by any associated heat 

recovery steam generator during the 

control period divided by 0.8, and with 

the sum divided by 1,000,000 Btu/

MMBtu. 

(b)(1) For each control period in 2010 

and thereafter, the permitting authority 

will allocate to all Hg Budget units in 

the State that have a baseline heat input 

(as determined under paragraph (a) of 

this section) a total amount of Hg 

allowances equal to 95 percent for a 

control period in 2010 through 2014, 

and 97 percent for a control period in 

2015 and thereafter, of the amount of 

ounces (i.e., tons multiplied by 32,000 

ounces/ton) of Hg emissions in the 

applicable State trading budget under 

§ 60.4140 (except as provided in 

paragraph (d) of this section). 

(2) The permitting authority will 

allocate Hg allowances to each Hg 

Budget unit under paragraph (b)(1) of 

this section in an amount determined by 

multiplying the total amount of Hg 

allowances allocated under paragraph 

(b)(1) of this section by the ratio of the 

baseline heat input of such Hg Budget 

unit to the total amount of baseline heat 

input of all such Hg Budget units in the 

State and rounding to the nearest whole 

allowance as appropriate. 

(c) For each control period in 2010 

and thereafter, the permitting authority 

will allocate Hg allowances to Hg 

Budget units in the State that 

commenced operation on or after 

January 1, 2001 and do not yet have a 

baseline heat input (as determined 

under paragraph (a) of this section), in 

accordance with the following 

procedures: 

(1) The permitting authority will 

establish a separate new unit set-aside 

for each control period. Each new unit 

set-aside will be allocated Hg 

allowances equal to 5 percent for a 

control period in 2010 through 2014, 

and 3 percent for a control period in 

2015 and thereafter, of the amount of 

ounces (i.e., tons multiplied by 32,000 

ounces/ton) of Hg emissions in the 

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28667

applicable State trading budget under 

§ 60.4140. 

(2) The Hg designated representative 

of such a Hg Budget unit may submit to 

the permitting authority a request, in a 

format specified by the permitting 

authority, to be allocated Hg allowances, 

starting with the later of the control 

period in 2010 or the first control period 

after the control period in which the Hg 

Budget unit commences commercial 

operation and until the first control 

period for which the unit is allocated Hg 

allowances under paragraph (b) of this 

section. The Hg allowance allocation 

request must be submitted on or before 

July 1 of the first control period for 

which the Hg allowances are requested 

and after the date on which the Hg 

Budget unit commences commercial 

operation.

(3) In a Hg allowance allocation 

request under paragraph (c)(2) of this 

section, the Hg designated 

representative may request for a control 

period Hg allowances in an amount not 

exceeding the Hg Budget unit’s total 

ounces of Hg emissions during the 

control period immediately before such 

control period. 

(4) The permitting authority will 

review each Hg allowance allocation 

request under paragraph (c)(2) of this 

section and will allocate Hg allowances 

for each control period pursuant to such 

request as follows: 

(i) The permitting authority will 

accept an allowance allocation request 

only if the request meets, or is adjusted 

by the permitting authority as necessary 

to meet, the requirements of paragraphs 

(c)(2) and (3) of this section. 

(ii) On or after July 1 of the control 

period, the permitting authority will 

determine the sum of the Hg allowances 

requested (as adjusted under paragraph 

(c)(4)(i) of this section) in all allowance 

allocation requests accepted under 

paragraph (c)(4)(i) of this section for the 

control period. 

(iii) If the amount of Hg allowances in 

the new unit set-aside for the control 

period is greater than or equal to the 

sum under paragraph (c)(4)(ii) of this 

section, then the permitting authority 

will allocate the amount of Hg 

allowances requested (as adjusted under 

paragraph (c)(4)(i) of this section) to 

each Hg Budget unit covered by an 

allowance allocation request accepted 

under paragraph (c)(4)(i) of this section. 

(iv) If the amount of Hg allowances in 

the new unit set-aside for the control 

period is less than the sum under 

paragraph (c)(4)(ii) of this section, then 

the permitting authority will allocate to 

each Hg Budget unit covered by an 

allowance allocation request accepted 

under paragraph (c)(4)(i) of this section 

the amount of the Hg allowances 

requested (as adjusted under paragraph 

(c)(4)(i) of this section), multiplied by 

the amount of Hg allowances in the new 

unit set-aside for the control period, 

divided by the sum determined under 

paragraph (c)(4)(ii) of this section, and 

rounded to the nearest whole allowance 

as appropriate. 

(v) The permitting authority will 

notify each Hg designated representative 

that submitted an allowance allocation 

request of the amount of Hg allowances 

(if any) allocated for the control period 

to the Hg Budget unit covered by the 

request. 

(d) If, after completion of the 

procedures under paragraph (c)(4) of 

this section for a control period, any 

unallocated Hg allowances remain in 

the new unit set-aside for the control 

period, the permitting authority will 

allocate to each Hg Budget unit that was 

allocated Hg allowances under 

paragraph (b) of this section an amount 

of Hg allowances equal to the total 

amount of such remaining unallocated 

Hg allowances, multiplied by the unit’s 

allocation under paragraph (b) of this 

section, divided by 95 percent for 2010 

through 2014, and 97 percent for 2014 

and thereafter, of the amount of ounces 

(i.e., tons multiplied by 32,000 ounces/

ton) of Hg emissions in the applicable 

State trading budget under § 60.4140, 

and rounded to the nearest whole 

allowance as appropriate. 

Hg Allowance Tracking System

§ 60.4150 [Reserved]

§ 60.4151 Establishment of accounts. 

(a) Compliance accounts. Upon 

receipt of a complete certificate of 

representation under § 60.4113, the 

Administrator will establish a 

compliance account for the Hg Budget 

source for which the certificate of 

representation was submitted unless the 

source already has a compliance 

account. 

(b) General accounts. (1) Application 

for general account. (i) Any person may 

apply to open a general account for the 

purpose of holding and transferring Hg 

allowances. An application for a general 

account may designate one and only one 

Hg authorized account representative 

and one and only one alternate Hg 

authorized account representative who 

may act on behalf of the Hg authorized 

account representative. The agreement 

by which the alternate Hg authorized 

account representative is selected shall 

include a procedure for authorizing the 

alternate Hg authorized account 

representative to act in lieu of the Hg 

authorized account representative.

(ii) A complete application for a 

general account shall be submitted to 

the Administrator and shall include the 

following elements in a format 

prescribed by the Administrator: 

(A) Name, mailing address, e-mail 

address (if any), telephone number, and 

facsimile transmission number (if any) 

of the Hg authorized account 

representative and any alternate Hg 

authorized account representative; 

(B) Organization name and type of 

organization, if applicable; 

(C) A list of all persons subject to a 

binding agreement for the Hg authorized 

account representative and any alternate 

Hg authorized account representative to 

represent their ownership interest with 

respect to the Hg allowances held in the 

general account; 

(D) The following certification 

statement by the Hg authorized account 

representative and any alternate Hg 

authorized account representative: ‘‘I 

certify that I was selected as the Hg 

authorized account representative or the 

alternate Hg authorized account 

representative, as applicable, by an 

agreement that is binding on all persons 

who have an ownership interest with 

respect to Hg allowances held in the 

general account. I certify that I have all 

the necessary authority to carry out my 

duties and responsibilities under the Hg 

Budget Trading Program on behalf of 

such persons and that each such person 

shall be fully bound by my 

representations, actions, inactions, or 

submissions and by any order or 

decision issued to me by the 

Administrator or a court regarding the 

general account.’’

(E) The signature of the Hg authorized 

account representative and any alternate 

Hg authorized account representative 

and the dates signed. 

(iii) Unless otherwise required by the 

permitting authority or the 

Administrator, documents of agreement 

referred to in the application for a 

general account shall not be submitted 

to the permitting authority or the 

Administrator. Neither the permitting 

authority nor the Administrator shall be 

under any obligation to review or 

evaluate the sufficiency of such 

documents, if submitted. 

(2) Authorization of Hg authorized 

account representative. (i) Upon receipt 

by the Administrator of a complete 

application for a general account under 

paragraph (b)(1) of this section: 

(A) The Administrator will establish a 

general account for the person or 

persons for whom the application is 

submitted. 

(B) The Hg authorized account 

representative and any alternate Hg 

authorized account representative for 

28668 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

the general account shall represent and, 

by his or her representations, actions, 

inactions, or submissions, legally bind 

each person who has an ownership 

interest with respect to Hg allowances 

held in the general account in all 

matters pertaining to the Hg Budget 

Trading Program, notwithstanding any 

agreement between the Hg authorized 

account representative or any alternate 

Hg authorized account representative 

and such person. Any such person shall 

be bound by any order or decision 

issued to the Hg authorized account 

representative or any alternate Hg 

authorized account representative by 

the Administrator or a court regarding 

the general account. 

(C) Any representation, action, 

inaction, or submission by any alternate 

Hg authorized account representative 

shall be deemed to be a representation, 

action, inaction, or submission by the 

Hg authorized account representative. 

(ii) Each submission concerning the 

general account shall be submitted, 

signed, and certified by the Hg 

authorized account representative or 

any alternate Hg authorized account 

representative for the persons having an 

ownership interest with respect to Hg 

allowances held in the general account. 

Each such submission shall include the 

following certification statement by the 

Hg authorized account representative or 

any alternate Hg authorized account 

representative: ‘‘I am authorized to 

make this submission on behalf of the 

persons having an ownership interest 

with respect to the Hg allowances held 

in the general account. I certify under 

penalty of law that I have personally 

examined, and am familiar with, the 

statements and information submitted 

in this document and all its 

attachments. Based on my inquiry of 

those individuals with primary 

responsibility for obtaining the 

information, I certify that the statements 

and information are to the best of my 

knowledge and belief true, accurate, and 

complete. I am aware that there are 

significant penalties for submitting false 

statements and information or omitting 

required statements and information, 

including the possibility of fine or 

imprisonment.’’

(iii) The Administrator will accept or 

act on a submission concerning the 

general account only if the submission 

has been made, signed, and certified in 

accordance with paragraph (b)(2)(ii) of 

this section. 

(3) Changing Hg authorized account 

representative and alternate Hg 

authorized account representative; 

changes in persons with ownership 

interest. 

(i) The Hg authorized account 

representative for a general account may 

be changed at any time upon receipt by 

the Administrator of a superseding 

complete application for a general 

account under paragraph (b)(1) of this 

section. Notwithstanding any such 

change, all representations, actions, 

inactions, and submissions by the 

previous Hg authorized account 

representative before the time and date 

when the Administrator receives the 

superseding application for a general 

account shall be binding on the new Hg 

authorized account representative and 

the persons with an ownership interest 

with respect to the Hg allowances in the 

general account. 

(ii) The alternate Hg authorized 

account representative for a general 

account may be changed at any time 

upon receipt by the Administrator of a 

superseding complete application for a 

general account under paragraph (b)(1) 

of this section. Notwithstanding any 

such change, all representations, 

actions, inactions, and submissions by 

the previous alternate Hg authorized 

account representative before the time 

and date when the Administrator 

receives the superseding application for 

a general account shall be binding on 

the new alternate Hg authorized account 

representative and the persons with an 

ownership interest with respect to the 

Hg allowances in the general account. 

(iii)(A) In the event a new person 

having an ownership interest with 

respect to Hg allowances in the general 

account is not included in the list of 

such persons in the application for a 

general account, such new person shall 

be deemed to be subject to and bound 

by the application for a general account, 

the representation, actions, inactions, 

and submissions of the Hg authorized 

account representative and any alternate 

Hg authorized account representative of 

the account, and the decisions and 

orders of the Administrator or a court, 

as if the new person were included in 

such list.

(B) Within 30 days following any 

change in the persons having an 

ownership interest with respect to Hg 

allowances in the general account, 

including the addition of persons, the 

Hg authorized account representative or 

any alternate Hg authorized account 

representative shall submit a revision to 

the application for a general account 

amending the list of persons having an 

ownership interest with respect to the 

Hg allowances in the general account to 

include the change. 

(4) Objections concerning Hg 

authorized account representative. (i) 

Once a complete application for a 

general account under paragraph (b)(1) 

of this section has been submitted and 

received, the Administrator will rely on 

the application unless and until a 

superseding complete application for a 

general account under paragraph (b)(1) 

of this section is received by the 

Administrator. 

(ii) Except as provided in paragraph 

(b)(3)(i) or (ii) of this section, no 

objection or other communication 

submitted to the Administrator 

concerning the authorization, or any 

representation, action, inaction, or 

submission of the Hg authorized 

account representative or any 

alternative Hg authorized account 

representative for a general account 

shall affect any representation, action, 

inaction, or submission of the Hg 

authorized account representative or 

any alternative Hg authorized account 

representative or the finality of any 

decision or order by the Administrator 

under the Hg Budget Trading Program. 

(iii) The Administrator will not 

adjudicate any private legal dispute 

concerning the authorization or any 

representation, action, inaction, or 

submission of the Hg authorized 

account representative or any 

alternative Hg authorized account 

representative for a general account, 

including private legal disputes 

concerning the proceeds of Hg 

allowance transfers. 

(c) Account identification. The 

Administrator will assign a unique 

identifying number to each account 

established under paragraph (a) or (b) of 

this section.

§ 60.4152 Responsibilities of Hg 

Authorized Account Representative. 

Following the establishment of a Hg 

Allowance Tracking System account, all 

submissions to the Administrator 

pertaining to the account, including, but 

not limited to, submissions concerning 

the deduction or transfer of Hg 

allowances in the account, shall be 

made only by the Hg authorized account 

representative for the account.

§ 60.4153 Recordation of Hg allowance 

allocations. 

(a) By December 1, 2006, the 

Administrator will record in the Hg 

Budget source’s compliance account the 

Hg allowances allocated for the Hg 

Budget units at a source, as submitted 

by the permitting authority in 

accordance with § 60.4141(a), for the 

control periods in 2010, 2011, 2012, 

2013, and 2014.

(b) By December 1, 2008, the 

Administrator will record in the Hg 

Budget source’s compliance account the 

Hg allowances allocated for the Hg 

Budget units at the source, as submitted 

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28669

by the permitting authority or as 

determined by the Administrator in 

accordance with § 60.4141(b), for the 

control period in 2015. 

(c) In 2011 and each year thereafter, 

after the Administrator has made all 

deductions (if any) from a Hg Budget 

source’s compliance account under 

§ 60.4154, the Administrator will record 

in the Hg Budget source’s compliance 

account the Hg allowances allocated for 

the Hg Budget units at the source, as 

submitted by the permitting authority or 

determined by the Administrator in 

accordance with § 60.4141(b), for the 

control period in the sixth year after the 

year of the control period for which 

such deductions were or could have 

been made. 

(d) By December 1, 2010 and 

December 1 of each year thereafter, the 

Administrator will record in the Hg 

Budget source’s compliance account the 

Hg allowances allocated for the Hg 

Budget units at the source, as submitted 

by the permitting authority or 

determined by the Administrator in 

accordance with § 60.4141(c), for the 

control period in the year of the 

applicable deadline for recordation 

under this paragraph. 

(e) Serial numbers for allocated Hg 

allowances. When recording the 

allocation of Hg allowances for a Hg 

Budget unit in a compliance account, 

the Administrator will assign each Hg 

allowance a unique identification 

number that will include digits 

identifying the year of the control 

period for which the Hg allowance is 

allocated.

§ 60.4154 Compliance with Hg budget 

emissions limitation. 

(a) Allowance transfer deadline. The 

Hg allowances are available to be 

deducted for compliance with a source’s 

Hg Budget emissions limitation for a 

control period in a given calendar year 

only if the Hg allowances: 

(1) Were allocated for the control 

period in the year or a prior year; 

(2) Are held in the compliance 

account as of the allowance transfer 

deadline for the control period or are 

transferred into the compliance account 

by a Hg allowance transfer correctly 

submitted for recordation under 

§§ 60.4160 through 60.4162 by the 

allowance transfer deadline for the 

control period; and 

(3) Are not necessary for deductions 

for excess emissions for a prior control 

period under paragraph (d) of this 

section. 

(b) Deductions for compliance.

Following the recordation, in 

accordance with §§ 60.4160 through 

60.4162, of Hg allowance transfers 

submitted for recordation in a source’s 

compliance account by the allowance 

transfer deadline for a control period, 

the Administrator will deduct from the 

compliance account Hg allowances 

available under paragraph (a) of this 

section in order to determine whether 

the source meets the Hg Budget 

emissions limitation for the control 

period, as follows: 

(1) Until the amount of Hg allowances 

deducted equals the number of ounces 

of total Hg emissions, determined in 

accordance with §§ 60.4170 through 

60.4176, from all Hg Budget units at the 

source for the control period; or 

(2) If there are insufficient Hg 

allowances to complete the deductions 

in paragraph (b)(1) of this section, until 

no more Hg allowances available under 

paragraph (a) of this section remain in 

the compliance account. 

(c)(1) Identification of Hg allowances 

by serial number. The Hg authorized 

account representative for a source’s 

compliance account may request that 

specific Hg allowances, identified by 

serial number, in the compliance 

account be deducted for emissions or 

excess emissions for a control period in 

accordance with paragraph (b) or (d) of 

this section. Such request shall be 

submitted to the Administrator by the 

allowance transfer deadline for the 

control period and include, in a format 

prescribed by the Administrator, the 

identification of the Hg Budget source 

and the appropriate serial numbers. 

(2) First-in, first-out. The 

Administrator will deduct Hg 

allowances under paragraph (b) or (d) of 

this section from the source’s 

compliance account, in the absence of 

an identification or in the case of a 

partial identification of Hg allowances 

by serial number under paragraph (c)(1) 

of this section, on a first-in, first-out 

(FIFO) accounting basis in the following 

order: 

(i) Any Hg allowances that were 

allocated to the units at the source, in 

the order of recordation; and then 

(ii) Any Hg allowances that were 

allocated to any unit and transferred 

and recorded in the compliance account 

pursuant to §§ 60.4160 through 60.4162, 

in the order of recordation. 

(d) Deductions for excess emissions.

(1) After making the deductions for 

compliance under paragraph (b) of this 

section for a control period in a calendar 

year in which the Hg Budget source has 

excess emissions, the Administrator will 

deduct from the source’s compliance 

account an amount of Hg allowances, 

allocated for the control period in the 

immediately following calendar year, 

equal to 3 times the number of ounces 

of the source’s excess emissions. 

(2) Any allowance deduction required 

under paragraph (d)(1) of this section 

shall not affect the liability of the 

owners and operators of the Hg Budget 

source or the Hg Budget units at the 

source for any fine, penalty, or 

assessment, or their obligation to 

comply with any other remedy, for the 

same violation, as ordered under the 

Clean Air Act or applicable State law. 

(e) Recordation of deductions. The 

Administrator will record in the 

appropriate compliance account all 

deductions from such an account under 

paragraph (b) or (d) of this section. 

(f) Administrator’s action on 

submissions. (1) The Administrator may 

review and conduct independent audits 

concerning any submission under the 

Hg Budget Trading Program and make 

appropriate adjustments of the 

information in the submissions. 

(2) The Administrator may deduct Hg 

allowances from or transfer Hg 

allowances to a source’s compliance 

account based on the information in the 

submissions, as adjusted under 

paragraph (f)(1) of this section.

§ 60.4155 Banking. 

(a) Hg allowances may be banked for 

future use or transfer in a compliance 

account or a general account in 

accordance with paragraph (b) of this 

section. 

(b) Any Hg allowance that is held in 

a compliance account or a general 

account will remain in such account 

unless and until the Hg allowance is 

deducted or transferred under § 60.4154, 

§ 60.4156, or §§ 60.4160 through 

60.4162.

§ 60.4156 Account error. 

The Administrator may, at his or her 

sole discretion and on his or her own 

motion, correct any error in any Hg 

Allowance Tracking System account. 

Within 10 business days of making such 

correction, the Administrator will notify 

the Hg authorized account 

representative for the account.

§ 60.4157 Closing of general accounts. 

(a) The Hg authorized account 

representative of a general account may 

submit to the Administrator a request to 

close the account, which shall include 

a correctly submitted allowance transfer 

under § 60.4160 through 60.4162 for any 

Hg allowances in the account to one or 

more other Hg Allowance Tracking 

System accounts. 

(b) If a general account has no 

allowance transfers in or out of the 

account for a 12-month period or longer 

and does not contain any Hg 

allowances, the Administrator may 

notify the Hg authorized account 

28670 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

representative for the account that the 

account will be closed following 20 

business days after the notice is sent. 

The account will be closed after the 20-

day period unless, before the end of the 

20-day period, the Administrator 

receives a correctly submitted transfer of 

Hg allowances into the account under 

§ 60.4160 through 60.4162 or a 

statement submitted by the Hg 

authorized account representative 

demonstrating to the satisfaction of the 

Administrator good cause as to why the 

account should not be closed. 

Hg Allowance Transfers

§ 60.4160 Submission of Hg allowance 

transfers. 

An Hg authorized account 

representative seeking recordation of a 

Hg allowance transfer shall submit the 

transfer to the Administrator. To be 

considered correctly submitted, the Hg 

allowance transfer shall include the 

following elements, in a format 

specified by the Administrator: 

(a) The account numbers for both the 

transferor and transferee accounts; 

(b) The serial number of each Hg 

allowance that is in the transferor 

account and is to be transferred; and 

(c) The name and signature of the Hg 

authorized account representative of the 

transferor account and the date signed.

§ 60.4161 EPA recordation. 

(a) Within 5 business days (except as 

provided in paragraph (b) of this 

section) of receiving a Hg allowance 

transfer, the Administrator will record a 

Hg allowance transfer by moving each 

Hg allowance from the transferor 

account to the transferee account as 

specified by the request, provided that: 

(1) The transfer is correctly submitted 

under § 60.4160; and 

(2) The transferor account includes 

each Hg allowance identified by serial 

number in the transfer. 

(b) A Hg allowance transfer that is 

submitted for recordation after the 

allowance transfer deadline for a control 

period and that includes any Hg 

allowances allocated for any control 

period before such allowance transfer 

deadline will not be recorded until after 

the Administrator completes the 

deductions under § 60.4154 for the 

control period immediately before such 

allowance transfer deadline. 

(c) Where a Hg allowance transfer 

submitted for recordation fails to meet 

the requirements of paragraph (a) of this 

section, the Administrator will not 

record such transfer.

§ 60.4162 Notification. 

(a) Notification of recordation. Within 

5 business days of recordation of a Hg 

allowance transfer under § 60.4161, the 

Administrator will notify the Hg 

authorized account representatives of 

both the transferor and transferee 

accounts. 

(b) Notification of non-recordation.

Within 10 business days of receipt of a 

Hg allowance transfer that fails to meet 

the requirements of § 60.4161(a), the 

Administrator will notify the Hg 

authorized account representatives of 

both accounts subject to the transfer of: 

(1) A decision not to record the 

transfer, and 

(2) The reasons for such nonrecordation. 

(c) Nothing in this section shall 

preclude the submission of a Hg 

allowance transfer for recordation 

following notification of nonrecordation. 

Monitoring and Reporting

§ 60.4170 General requirements. 

The owners and operators, and to the 

extent applicable, the Hg designated 

representative, of a Hg Budget unit, 

shall comply with the monitoring, 

recordkeeping, and reporting 

requirements as provided in this 

section, §§ 60.4171 through 60.4176, 

and subpart I of part 75 of this chapter. 

For purposes of complying with such 

requirements, the definitions in 

§ 60.4102 and in § 72.2 of this chapter 

shall apply, and the terms ‘‘affected 

unit,’’ ‘‘designated representative,’’ and 

‘‘continuous emission monitoring 

system’’ (or ‘‘CEMS’’) in part 75 of this 

chapter shall be deemed to refer to the 

terms ‘‘Hg Budget unit,’’ ‘‘Hg designated 

representative,’’ and ‘‘continuous 

emission monitoring system’’ (or 

‘‘CEMS’’) respectively, as defined in 

§ 60.4102. The owner or operator of a 

unit that is not a Hg Budget unit but that 

is monitored under § 75.82(b)(2)(i) of 

this chapter shall comply with the same 

monitoring, recordkeeping, and 

reporting requirements as a Hg Budget 

unit. 

(a) Requirements for installation, 

certification, and data accounting. The 

owner or operator of each Hg Budget 

unit shall: 

(1) Install all monitoring systems 

required under this section and 

§§ 60.4171 through 60.4176 for 

monitoring Hg mass emissions and 

individual unit heat input (including all 

systems required to monitor Hg 

concentration, stack gas moisture 

content, stack gas flow rate, and CO2 or 

O2 concentration, as applicable, in 

accordance with §§ 75.81 and 75.82 of 

this chapter); 

(2) Successfully complete all 

certification tests required under 

§ 60.4171 and meet all other 

requirements of this section, §§ 60.4171 

through 60.4176, and subpart I of part 

75 of this chapter applicable to the 

monitoring systems under paragraph 

(a)(1) of this section; and

(3) Record, report, and quality-assure 

the data from the monitoring systems 

under paragraph (a)(1) of this section. 

(b) Compliance deadlines. The owner 

or operator shall meet the monitoring 

system certification and other 

requirements of paragraphs (a)(1) and 

(2) of this section on or before the 

following dates. The owner or operator 

shall record, report, and quality-assure 

the data from the monitoring systems 

under paragraph (a)(1) of this section on 

and after the following dates. 

(1) For the owner or operator of a Hg 

Budget unit that commences 

commercial operation before July 1, 

2008, by January 1, 2009. 

(2) For the owner or operator of a Hg 

Budget unit that commences 

commercial operation on or after July 1, 

2008, by the later of the following dates: 

(i) January 1, 2009; or 

(ii) 90 unit operating days or 180 

calendar days, whichever occurs first, 

after the date on which the unit 

commences commercial operation. 

(3) For the owner or operator of a Hg 

Budget unit for which construction of a 

new stack or flue or installation of addon Hg emission controls, a flue gas 

desulfurization system, a selective 

catalytic reduction system, or a compact 

hybrid particulate collector system is 

completed after the applicable deadline 

under paragraph (b)(1) or (2) of this 

section, by 90 unit operating days or 180 

calendar days, whichever occurs first, 

after the date on which emissions first 

exit to the atmosphere through the new 

stack or flue, add-on Hg emissions 

controls, flue gas desulfurization 

system, selective catalytic reduction 

system, or compact hybrid particulate 

collector system. 

(c) Reporting data. (1) Except as 

provided in paragraph (c)(2) of this 

section, the owner or operator of a Hg 

Budget unit that does not meet the 

applicable compliance date set forth in 

paragraph (b) of this section for any 

monitoring system under paragraph 

(a)(1) of this section shall, for each such 

monitoring system, determine, record, 

and report maximum potential (or, as 

appropriate, minimum potential) values 

for Hg concentration, stack gas flow rate, 

stack gas moisture content, and any 

other parameters required to determine 

Hg mass emissions and heat input in 

accordance with § 75.80(g) of this 

chapter. 

(2) The owner or operator of a Hg 

Budget unit that does not meet the 

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28671

applicable compliance date set forth in 

paragraph (b)(3) of this section for any 

monitoring system under paragraph 

(a)(1) of this section shall, for each such 

monitoring system, determine, record, 

and report substitute data using the 

applicable missing data procedures in 

subpart D of part 75 of this chapter, in 

lieu of the maximum potential (or, as 

appropriate, minimum potential) values, 

for a parameter if the owner or operator 

demonstrates that there is continuity 

between the data streams for that 

parameter before and after the 

construction or installation under 

paragraph (b)(3) of this section. 

(d) Prohibitions. (1) No owner or 

operator of a Hg Budget unit shall use 

any alternative monitoring system, 

alternative reference method, or any 

other alternative to any requirement of 

this section and §§ 60.4171 through 

60.4176 without having obtained prior 

written approval in accordance with 

§ 60.4175. 

(2) No owner or operator of a Hg 

Budget unit shall operate the unit so as 

to discharge, or allow to be discharged, 

Hg emissions to the atmosphere without 

accounting for all such emissions in 

accordance with the applicable 

provisions of this section, §§ 60.4171 

through 60.4176, and subpart I of part 

75 of this chapter. 

(3) No owner or operator of a Hg 

Budget unit shall disrupt the continuous 

emission monitoring system, any 

portion thereof, or any other approved 

emission monitoring method, and 

thereby avoid monitoring and recording 

Hg mass emissions discharged into the 

atmosphere, except for periods of 

recertification or periods when 

calibration, quality assurance testing, or 

maintenance is performed in accordance 

with the applicable provisions of this 

section, §§ 60.4171 through 60.4176, 

and subpart I of part 75 of this chapter.

(4) No owner or operator of a Hg 

Budget unit shall retire or permanently 

discontinue use of the continuous 

emission monitoring system, any 

component thereof, or any other 

approved monitoring system under this 

subpart, except under any one of the 

following circumstances: 

(i) During the period that the unit is 

covered by an exemption under 

§ 60.4105 that is in effect; 

(ii) The owner or operator is 

monitoring emissions from the unit with 

another certified monitoring system 

approved, in accordance with the 

applicable provisions of this section, 

§§ 60.4171 through 60.4176, and subpart 

I of part 75 of this chapter, by the 

permitting authority for use at that unit 

that provides emission data for the same 

pollutant or parameter as the retired or 

discontinued monitoring system; or 

(iii) The Hg designated representative 

submits notification of the date of 

certification testing of a replacement 

monitoring system for the retired or 

discontinued monitoring system in 

accordance with § 60.4171(c)(3)(i).

§ 60.4171 Initial certification and 

recertification procedures. 

(a) The owner or operator of a Hg 

Budget unit shall be exempt from the 

initial certification requirements of this 

section for a monitoring system under 

§ 60.4170(a)(1) if the following 

conditions are met: 

(1) The monitoring system has been 

previously certified in accordance with 

part 75 of this chapter; and 

(2) The applicable quality-assurance 

and quality-control requirements of 

§ 75.21 of this chapter and appendix B 

to part 75 of this chapter are fully met 

for the certified monitoring system 

described in paragraph (a)(1) of this 

section. 

(b) The recertification provisions of 

this section shall apply to a monitoring 

system under § 60.4170(a)(1) exempt 

from initial certification requirements 

under paragraph (a) of this section. 

(c) Except as provided in paragraph 

(a) of this section, the owner or operator 

of a Hg Budget unit shall comply with 

the following initial certification and 

recertification procedures for a 

continuous monitoring system (e.g., a 

continuous emission monitoring system 

and an excepted monitoring system 

(sorbent trap monitoring system) under 

§ 75.15) under § 60.4170(a)(1). The 

owner or operator of a unit that qualifies 

to use the Hg low mass emissions 

excepted monitoring methodology 

under § 75.81(b) of this chapter or that 

qualifies to use an alternative 

monitoring system under subpart E of 

part 75 of this chapter shall comply 

with the procedures in paragraph (d) or 

(e) of this section respectively.

(1) Requirements for initial 

certification. The owner or operator 

shall ensure that each monitoring 

system under § 60.4170(a)(1) (including 

the automated data acquisition and 

handling system) successfully 

completes all of the initial certification 

testing required under § 75.20 of this 

chapter by the applicable deadline in 

§ 60.4170(b). In addition, whenever the 

owner or operator installs a monitoring 

system to meet the requirements of this 

subpart in a location where no such 

monitoring system was previously 

installed, initial certification in 

accordance with § 75.20 of this chapter 

is required. 

(2) Requirements for recertification.

Whenever the owner or operator makes 

a replacement, modification, or change 

in any certified continuous emission 

monitoring system, or an excepted 

monitoring system (sorbent trap 

monitoring system) under § 75.15, under 

§ 60.4170(a)(1) that may significantly 

affect the ability of the system to 

accurately measure or record Hg mass 

emissions or heat input rate or to meet 

the quality-assurance and qualitycontrol requirements of § 75.21 of this 

chapter or appendix B to part 75 of this 

chapter, the owner or operator shall 

recertify the monitoring system in 

accordance with § 75.20(b) of this 

chapter. Furthermore, whenever the 

owner or operator makes a replacement, 

modification, or change to the flue gas 

handling system or the unit’s operation 

that may significantly change the stack 

flow or concentration profile, the owner 

or operator shall recertify each 

continuous emission monitoring system, 

and each excepted monitoring system 

(sorbent trap monitoring system) under 

§ 75.15, whose accuracy is potentially 

affected by the change, in accordance 

with § 75.20(b) of this chapter. 

Examples of changes to a continuous 

emission monitoring system that require 

recertification include replacement of 

the analyzer, complete replacement of 

an existing continuous emission 

monitoring system, or change in 

location or orientation of the sampling 

probe or site. 

(3) Approval process for initial 

certification and recertification.

Paragraphs (c)(3)(i) through (iv) of this 

section apply to both initial certification 

and recertification of a continuous 

monitoring system under 

§ 60.4170(a)(1). For recertifications, 

apply the word ‘‘recertification’’ instead 

of the words ‘‘certification’’ and ‘‘initial 

certification’’ and apply the word 

‘‘recertified’’ instead of the word 

‘‘certified,’’ and follow the procedures 

in § 75.20(b)(5) of this chapter in lieu of 

the procedures in paragraph (c)(3)(v) of 

this section. 

(i) Notification of certification. The Hg 

designated representative shall submit 

to the permitting authority, the 

appropriate EPA Regional Office, and 

the Administrator written notice of the 

dates of certification testing, in 

accordance with § 60.4173. 

(ii) Certification application. The Hg 

designated representative shall submit 

to the permitting authority a 

certification application for each 

monitoring system. A complete 

certification application shall include 

the information specified in § 75.63 of 

this chapter. 

28672 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

(iii) Provisional certification date. The 

provisional certification date for a 

monitoring system shall be determined 

in accordance with § 75.20(a)(3) of this 

chapter. A provisionally certified 

monitoring system may be used under 

the Hg Budget Trading Program for a 

period not to exceed 120 days after 

receipt by the permitting authority of 

the complete certification application 

for the monitoring system under 

paragraph (c)(3)(ii) of this section. Data 

measured and recorded by the 

provisionally certified monitoring 

system, in accordance with the 

requirements of part 75 of this chapter, 

will be considered valid quality-assured 

data (retroactive to the date and time of 

provisional certification), provided that 

the permitting authority does not 

invalidate the provisional certification 

by issuing a notice of disapproval 

within 120 days of the date of receipt of 

the complete certification application by 

the permitting authority. 

(iv) Certification application approval 

process. The permitting authority will 

issue a written notice of approval or 

disapproval of the certification 

application to the owner or operator 

within 120 days of receipt of the 

complete certification application under 

paragraph (c)(3)(ii) of this section. In the 

event the permitting authority does not 

issue such a notice within such 120-day 

period, each monitoring system that 

meets the applicable performance 

requirements of part 75 of this chapter 

and is included in the certification 

application will be deemed certified for 

use under the Hg Budget Trading 

Program. 

(A) Approval notice. If the 

certification application is complete and 

shows that each monitoring system 

meets the applicable performance 

requirements of part 75 of this chapter, 

then the permitting authority will issue 

a written notice of approval of the 

certification application within 120 

days of receipt. 

(B) Incomplete application notice. If 

the certification application is not 

complete, then the permitting authority 

will issue a written notice of 

incompleteness that sets a reasonable 

date by which the Hg designated 

representative must submit the 

additional information required to 

complete the certification application. If 

the Hg designated representative does 

not comply with the notice of 

incompleteness by the specified date, 

then the permitting authority may issue 

a notice of disapproval under paragraph 

(c)(3)(iv)(C) of this section. The 120-day 

review period shall not begin before 

receipt of a complete certification 

application.

(C) Disapproval notice. If the 

certification application shows that any 

monitoring system does not meet the 

performance requirements of part 75 of 

this chapter or if the certification 

application is incomplete and the 

requirement for disapproval under 

paragraph (c)(3)(iv)(B) of this section is 

met, then the permitting authority will 

issue a written notice of disapproval of 

the certification application. Upon 

issuance of such notice of disapproval, 

the provisional certification is 

invalidated by the permitting authority 

and the data measured and recorded by 

each uncertified monitoring system 

shall not be considered valid qualityassured data beginning with the date 

and hour of provisional certification (as 

defined under § 75.20(a)(3) of this 

chapter). The owner or operator shall 

follow the procedures for loss of 

certification in paragraph (c)(3)(v) of 

this section for each monitoring system 

that is disapproved for initial 

certification. 

(D) Audit decertification. The 

permitting authority may issue a notice 

of disapproval of the certification status 

of a monitor in accordance with 

§ 60.4172(b). 

(v) Procedures for loss of certification.

If the permitting authority issues a 

notice of disapproval of a certification 

application under paragraph (c)(3)(iv)(C) 

of this section or a notice of disapproval 

of certification status under paragraph 

(c)(3)(iv)(D) of this section, then: 

(A) The owner or operator shall 

substitute the following values, for each 

disapproved monitoring system, for 

each hour of unit operation during the 

period of invalid data specified under 

§ 75.20(a)(4)(iii), or § 75.21(e) of this 

chapter and continuing until the 

applicable date and hour specified 

under § 75.20(a)(5)(i) of this chapter: 

(1) For a disapproved Hg pollutant 

concentration monitors and 

disapproved flow monitor, respectively, 

the maximum potential concentration of 

Hg and the maximum potential flow 

rate, as defined in sections 2.1.7.1 and 

2.1.4.1 of appendix A to part 75 of this 

chapter; and 

(2) For a disapproved moisture 

monitoring system and disapproved 

diluent gas monitoring system, 

respectively, the minimum potential 

moisture percentage and either the 

maximum potential CO2 concentration 

or the minimum potential O2

concentration (as applicable), as defined 

in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of 

appendix A to part 75 of this chapter. 

(3) For a disapproved excepted 

monitoring system (sorbent trap 

monitoring system) under § 75.15 and 

disapproved flow monitor, respectively, 

the maximum potential concentration of 

Hg and maximum potential flow rate, as 

defined in sections 2.1.7.1 and 2.1.4.1 of 

appendix A to part 75 of this chapter. 

(B) The Hg designated representative 

shall submit a notification of 

certification retest dates and a new 

certification application in accordance 

with paragraphs (c)(3)(i) and (ii) of this 

section. 

(C) The owner or operator shall repeat 

all certification tests or other 

requirements that were failed by the 

monitoring system, as indicated in the 

permitting authority’s notice of 

disapproval, no later than 30 unit 

operating days after the date of issuance 

of the notice of disapproval. 

(d) Initial certification and 

recertification procedures for units 

using the Hg low mass emission 

excepted methodology under § 75.81(b) 

of this chapter. The owner or operator 

of a unit qualified to use the Hg low 

mass emissions (HgLME) excepted 

methodology under § 75.81(b) of this 

chapter shall meet the applicable 

certification and recertification 

requirements in § 75.81(c) through (f) of 

this chapter. 

(e) Certification/recertification 

procedures for alternative monitoring 

systems. The Hg designated 

representative of each unit for which the 

owner or operator intends to use an 

alternative monitoring system approved 

by the Administrator and, if applicable, 

the permitting authority under subpart E 

of part 75 of this chapter shall comply 

with the applicable notification and 

application procedures of § 75.20(f) of 

this chapter.

§ 60.4172 Out of control periods. 

(a) Whenever any monitoring system 

fails to meet the quality-assurance and 

quality-control requirements or data 

validation requirements of part 75 of 

this chapter, data shall be substituted 

using the applicable missing data 

procedures in subpart D of part 75 of 

this chapter. 

(b) Audit decertification. Whenever 

both an audit of a monitoring system 

and a review of the initial certification 

or recertification application reveal that 

any monitoring system should not have 

been certified or recertified because it 

did not meet a particular performance 

specification or other requirement under 

§ 60.4171 or the applicable provisions of 

part 75 of this chapter, both at the time 

of the initial certification or 

recertification application submission 

and at the time of the audit, the 

permitting authority will issue a notice 

of disapproval of the certification status 

of such monitoring system. For the 

purposes of this paragraph, an audit 

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28673

shall be either a field audit or an audit 

of any information submitted to the 

permitting authority or the 

Administrator. By issuing the notice of 

disapproval, the permitting authority 

revokes prospectively the certification 

status of the monitoring system. The 

data measured and recorded by the 

monitoring system shall not be 

considered valid quality-assured data 

from the date of issuance of the 

notification of the revoked certification 

status until the date and time that the 

owner or operator completes 

subsequently approved initial 

certification or recertification tests for 

the monitoring system. The owner or 

operator shall follow the applicable 

initial certification or recertification 

procedures in § 60.4171 for each 

disapproved monitoring system.

§ 60.4173 Notifications. 

The Hg designated representative for 

a Hg Budget unit shall submit written 

notice to the permitting authority and 

the Administrator in accordance with 

§ 75.61 of this chapter, except that if the 

unit is not subject to an Acid Rain 

emissions limitation, the notification is 

only required to be sent to the 

permitting authority.

§ 60.4174 Recordkeeping and reporting. 

(a) General provisions. (1) The Hg 

designated representative shall comply 

with all recordkeeping and reporting 

requirements in this section and the 

requirements of § 60.4110(e)(1). 

(2) If a Hg Budget unit is subject to an 

Acid Rain emission limitation or the 

CAIR NOX Annual Trading Program, 

CAIR SO2 Trading Program, or CAIR 

NOX Ozone Season Trading Program, 

and the Hg designated representative 

who signed and certified any 

submission that is made under subpart 

F or G of part 75 of this chapter and that 

includes data and information required 

under this section, §§ 60.4170 through 

60.4173, § 60.4175, § 60.4176, or subpart 

I of part 75 of this chapter is not the 

same person as the designated 

representative or alternative designated 

representative, or the CAIR designated 

representative or alternate CAIR 

designated representative, for the unit 

under part 72 of this chapter and the 

CAIR NOX Annual Trading Program, 

CAIR SO2 Trading Program, or CAIR 

NOX Ozone Season Trading Program, 

then the submission must also be signed 

by the designated representative or 

alternative designated representative, or 

the CAIR designated representative or 

alternate CAIR designated 

representative, as applicable. 

(b) Monitoring plans. The owner or 

operator of a Hg Budget unit shall 

comply with requirements of § 75.84(e) 

of this chapter. 

(c) Certification applications. The Hg 

designated representative shall submit 

an application to the permitting 

authority within 45 days after 

completing all initial certification or 

recertification tests required under 

§ 60.4171, including the information 

required under § 75.63 of this chapter. 

(d) Quarterly reports. The Hg 

designated representative shall submit 

quarterly reports, as follows: 

(1) The Hg designated representative 

shall report the Hg mass emissions data 

and heat input data for the Hg Budget 

unit, in an electronic quarterly report in 

a format prescribed by the 

Administrator, for each calendar quarter 

beginning with: 

(i) For a unit that commences 

commercial operation before July 1, 

2008, the calendar quarter covering 

January 1, 2009 through March 31, 2009; 

or 

(ii) For a unit that commences 

commercial operation on or after July 1, 

2008, the calendar quarter 

corresponding to the earlier of the date 

of provisional certification or the 

applicable deadline for initial 

certification under § 60.4170(b), unless 

that quarter is the third or fourth quarter 

of 2008, in which case reporting shall 

commence in the quarter covering 

January 1, 2009 through March 31, 2009. 

(2) The Hg designated representative 

shall submit each quarterly report to the 

Administrator within 30 days following 

the end of the calendar quarter covered 

by the report. Quarterly reports shall be 

submitted in the manner specified in 

§ 75.84(f) of this chapter. 

(3) For Hg Budget units that are also 

subject to an Acid Rain emissions 

limitation or the CAIR NOX Annual 

Trading Program, CAIR SO2 Trading 

Program, or CAIR NOX Ozone Season 

Trading Program, quarterly reports shall 

include the applicable data and 

information required by subparts F 

through H of part 75 of this chapter as 

applicable, in addition to the Hg mass 

emission data, heat input data, and 

other information required by this 

section, §§ 60.4170 through 60.4173, 

§ 60.4175, and § 60.4176. 

(e) Compliance certification. The Hg 

designated representative shall submit 

to the Administrator a compliance 

certification (in a format prescribed by 

the Administrator) in support of each 

quarterly report based on reasonable 

inquiry of those persons with primary 

responsibility for ensuring that all of the 

unit’s emissions are correctly and fully 

monitored. The certification shall state 

that:

(1) The monitoring data submitted 

were recorded in accordance with the 

applicable requirements of this section, 

§§ 60.4170 through 60.4173, § 60.4175, 

§ 60.4176, and part 75 of this chapter, 

including the quality assurance 

procedures and specifications; and 

(2) For a unit with add-on Hg 

emission controls, a flue gas 

desulfurization system, a selective 

catalytic reduction system, or a compact 

hybrid particulate collector system and 

for all hours where Hg data are 

substituted in accordance with 

§ 75.34(a)(1) of this chapter, the Hg addon emission controls, flue gas 

desulfurization system, selective 

catalytic reduction system, or compact 

hybrid particulate collector system were 

operating within the range of parameters 

listed in the quality assurance/quality 

control program under appendix B to 

part 75 of this chapter, or qualityassured SO2 emission data recorded in 

accordance with part 75 of this chapter 

document that the flue gas 

desulfurization system, or qualityassured NOX emission data recorded in 

accordance with part 75 of this chapter 

document that the selective catalytic 

reduction system, was operating 

properly, as applicable, and the 

substitute data values do not 

systematically underestimate Hg 

emissions.

§ 60.4175 Petitions. 

The Hg designated representative of a 

Hg unit may submit a petition under 

§ 75.66 of this chapter to the 

Administrator requesting approval to 

apply an alternative to any requirement 

of §§ 60.4170 through 60.4174 and 

§ 60.4176. Application of an alternative 

to any requirement of §§ 60.4170 

through 60.4174 and § 60.4176 is in 

accordance with this section and 

§§ 60.4170 through 60.4174 and 

§ 60.4176 only to the extent that the 

petition is approved in writing by the 

Administrator, in consultation with the 

permitting authority.

§ 60.4176 Additional requirements to 

provide heat input data. 

The owner or operator of a Hg Budget 

unit that monitors and reports Hg mass 

emissions using a Hg concentration 

monitoring system and a flow 

monitoring system shall also monitor 

and report heat input rate at the unit 

level using the procedures set forth in 

part 75 of this chapter.

■ 14. Appendix B to part 60 is amended 

by adding in numerical order new 

Performance Specification 12A to read as 

follows:

28674 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

Appendix B to Part 60—Performance 

Specifications

* * * * *

PERFORMANCE SPECIFICATION 12A—

SPECIFICATIONS AND TEST PROCEDURES 

FOR TOTAL VAPOR PHASE MERCURY 

CONTINUOUS EMISSION MONITORING 

SYSTEMS IN STATIONARY SOURCES

1.0 Scope and Application 

1.1 Analyte.

Analyte CAS No. 

Mercury (Hg) ............................... 7439–97–6 

1.2 Applicability.

1.2.1 This specification is for evaluating 

the acceptability of total vapor phase Hg 

continuous emission monitoring systems 

(CEMS) installed on the exit gases from fossil 

fuel fired boilers at the time of or soon after 

installation and whenever specified in the 

regulations. The Hg CEMS must be capable 

of measuring the total concentration in μg/m3

(regardless of speciation) of vapor phase Hg, 

and recording that concentration on a wet or 

dry basis. Particle bound Hg is not included 

in the measurements. 

This specification is not designed to 

evaluate an installed CEMS’s performance 

over an extended period of time nor does it 

identify specific calibration techniques and 

auxiliary procedures to assess the CEMS’s 

performance. The source owner or operator, 

however, is responsible to calibrate, 

maintain, and operate the CEMS properly. 

The Administrator may require, under Clean 

Air Act (CAA) section 114, the operator to 

conduct CEMS performance evaluations at 

other times besides the initial test to evaluate 

the CEMS performance. See § 60.13(c). 

1.2.2 For an affected facility that is also 

subject to the requirements of subpart I of 

part 75 of this chapter, the owner or operator 

may conduct the performance evaluation of 

the Hg CEMS according to § 75.20(c)(1) of 

this chapter and section 6 of appendix A to 

part 75 of this chapter, in lieu of following 

the procedures in this performance 

specification. 

2.0 Summary of Performance Specification. 

Procedures for measuring CEMS relative 

accuracy, measurement error and drift are 

outlined. CEMS installation and 

measurement location specifications, and 

data reduction procedures are included. 

Conformance of the CEMS with the 

Performance Specification is determined. 

3.0 Definitions.

3.1 Continuous Emission Monitoring 

System (CEMS) means the total equipment 

required for the determination of a pollutant 

concentration. The system consists of the 

following major subsystems: 

3.2 Sample Interface means that portion 

of the CEMS used for one or more of the 

following: sample acquisition, sample 

transport, sample conditioning, and 

protection of the monitor from the effects of 

the stack effluent. 

3.3 Hg Analyzer means that portion of the 

Hg CEMS that measures the total vapor phase 

Hg mass concentration and generates a 

proportional output. 

3.4 Data Recorder means that portion of 

the CEMS that provides a permanent 

electronic record of the analyzer output. The 

data recorder may provide automatic data 

reduction and CEMS control capabilities. 

3.5 Span Value means the upper limit of 

the intended Hg concentration measurement 

range. The span value is a value equal to two 

times the emission standard. Alternatively, 

for an affected facility that is also subject to 

the requirements of subpart I of part 75 of 

this chapter, the Hg span value(s) may be 

determined according to section 2.1.7 of 

appendix A to part 75 of this chapter. 

3.6 Measurement Error (ME) means the 

absolute value of the difference between the 

concentration indicated by the Hg analyzer 

and the known concentration generated by a 

reference gas, expressed as a percentage of 

the span value, when the entire CEMS, 

including the sampling interface, is 

challenged. An ME test procedure is 

performed to document the accuracy and 

linearity of the Hg CEMS at several points 

over the measurement range. 

3.7 Upscale Drift (UD) means the absolute 

value of the difference between the CEMS 

output response and an upscale Hg reference 

gas, expressed as a percentage of the span 

value, when the entire CEMS, including the 

sampling interface, is challenged after a 

stated period of operation during which no 

unscheduled maintenance, repair, or 

adjustment took place. 

3.8 Zero Drift (ZD) means the absolute 

value of the difference between the CEMS 

output response and a zero-level Hg reference 

gas, expressed as a percentage of the span 

value, when the entire CEMS, including the 

sampling interface, is challenged after a 

stated period of operation during which no 

unscheduled maintenance, repair, or 

adjustment took place. 

3.9 Relative Accuracy (RA) means the 

absolute mean difference between the 

pollutant concentration(s) determined by the 

CEMS and the value determined by the 

reference method (RM) plus the 2.5 percent 

error confidence coefficient of a series of tests 

divided by the mean of the RM tests. 

Alternatively, for low concentration sources, 

the RA may be expressed as the absolute 

value of the difference between the mean 

CEMS and RM values. 

4.0 Interferences. [Reserved] 

5.0 Safety. 

The procedures required under this 

performance specification may involve 

hazardous materials, operations, and 

equipment. This performance specification 

may not address all of the safety problems 

associated with these procedures. It is the 

responsibility of the user to establish 

appropriate safety and health practices and 

determine the applicable regulatory 

limitations prior to performing these 

procedures. The CEMS user’s manual and 

materials recommended by the RM should be 

consulted for specific precautions to be 

taken. 

6.0 Equipment and Supplies. 

6.1 CEMS Equipment Specifications. 

6.1.1 Data Recorder Scale. The Hg CEMS 

data recorder output range must include zero 

and a high level value. The high level value 

must be approximately two times the Hg 

concentration corresponding to the emission 

standard level for the stack gas under the 

circumstances existing as the stack gas is 

sampled. A lower high level value may be 

used, provided that the measured values do 

not exceed 95 percent of the high level value. 

Alternatively, for an affected facility that is 

also subject to the requirements of subpart I 

of part 75 of this chapter, the owner or 

operator may set the full-scale range(s) of the 

Hg analyzer according to section 2.1.7 of 

appendix A to part 75 of this chapter. 

6.1.2 The CEMS design should also 

provide for the determination of calibration 

drift at a zero value (zero to 20 percent of the 

span value) and at an upscale value (between 

50 and 100 percent of the high-level value). 

6.2 Reference Gas Delivery System. The 

reference gas delivery system must be 

designed so that the flowrate of reference gas 

introduced to the CEMS is the same at all 

three challenge levels specified in Section 7.1 

and at all times exceeds the flow 

requirements of the CEMS. 

6.3 Other equipment and supplies, as 

needed by the applicable reference method 

used. See Section 8.6.2. 

7.0 Reagents and Standards. 

7.1 Reference Gases. Reference gas 

standards are required for both elemental and 

oxidized Hg (Hg and mercuric chloride, 

HgCl2). The use of National Institute of 

Standards and Technology (NIST)-certified or 

NIST-traceable standards and reagents is 

required. The following gas concentrations 

are required. 

7.1.1 Zero-level. 0 to 20 percent of the 

span value.

7.1.2 Mid-level. 50 to 60 percent of the 

span value. 

7.1.3 High-level. 80 to 100 percent of the 

span value. 

7.2 Reference gas standards may also be 

required for the reference methods. See 

Section 8.6.2. 

8.0 Performance Specification (PS) Test 

Procedure. 

8.1 Installation and Measurement 

Location Specifications. 

8.1.1 CEMS Installation. Install the CEMS 

at an accessible location downstream of all 

pollution control equipment. Since the Hg 

CEMS sample system normally extracts gas 

from a single point in the stack, use a 

location that has been shown to be free of 

stratification for SO2 and NOX through 

concentration measurement traverses for 

those gases. If the cause of failure to meet the 

RA test requirement is determined to be the 

measurement location and a satisfactory 

correction technique cannot be established, 

the Administrator may require the CEMS to 

be relocated. 

Measurement locations and points or paths 

that are most likely to provide data that will 

meet the RA requirements are listed below. 

8.1.2 Measurement Location. The 

measurement location should be (1) at least 

two equivalent diameters downstream of the 

nearest control device, point of pollutant 

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28675

generation or other point at which a change 

of pollutant concentration may occur, and (2) 

at least half an equivalent diameter upstream 

from the effluent exhaust. The equivalent 

duct diameter is calculated as per 40 CFR 

part 60, appendix A, Method 1. 

8.1.3 Hg CEMS Sample Extraction Point. 

Use a sample extraction point (1) no less than 

1.0 meter from the stack or duct wall, or (2) 

within the centroidal velocity traverse area of 

the stack or duct cross section. 

8.2 RM Measurement Location and 

Traverse Points. Refer to PS 2 of this 

appendix. The RM and CEMS locations need 

not be immediately adjacent. 

8.3 ME Test Procedure. The Hg CEMS 

must be constructed to permit the 

introduction of known concentrations of Hg 

and HgCl2 separately into the sampling 

system of the CEMS immediately preceding 

the sample extraction filtration system such 

that the entire CEMS can be challenged. 

Sequentially inject each of the three reference 

gases (zero, mid-level, and high level) for 

each Hg species. Record the CEMS response 

and subtract the reference value from the 

CEMS value, and express the absolute value 

of the difference as a percentage of the span 

value (see example data sheet in Figure 12A–

1). For each reference gas, the absolute value 

of the difference between the CEMS response 

and the reference value shall not exceed 5 

percent of the span value. If this specification 

is not met, identify and correct the problem 

before proceeding.

8.4 UD Test Procedure. 

8.4.1 UD Test Period. While the affected 

facility is operating at more than 50 percent 

of normal load, or as specified in an 

applicable subpart, determine the magnitude 

of the UD once each day (at 24-hour 

intervals, to the extent practicable) for 7 

consecutive unit operating days according to 

the procedure given in Sections 8.4.2 through 

8.4.3. The 7 consecutive unit operating days 

need not be 7 consecutive calendar days. Use 

either Hg° or HgCl2 standards for this test. 

8.4.2 The purpose of the UD 

measurement is to verify the ability of the 

CEMS to conform to the established CEMS 

response used for determining emission 

concentrations or emission rates. Therefore, 

if periodic automatic or manual adjustments 

are made to the CEMS zero and response 

settings, conduct the UD test immediately 

before these adjustments, or conduct it in 

such a way that the UD can be determined. 

8.4.3 Conduct the UD test at either the 

mid-level or high-level point specified in 

Section 7.1. Introduce the reference gas to the 

CEMS. Record the CEMS response and 

subtract the reference value from the CEMS 

value, and express the absolute value of the 

difference as a percentage of the span value 

(see example data sheet in Figure 12A–1). For 

the reference gas, the absolute value of the 

difference between the CEMS response and 

the reference value shall not exceed 5 percent 

of the span value. If this specification is not 

met, identify and correct the problem before 

proceeding. 

8.5 ZD Test Procedure. 

8.5.1 ZD Test Period. While the affected 

facility is operating at more than 50 percent 

of normal load, or as specified in an 

applicable subpart, determine the magnitude 

of the ZD once each day (at 24-hour intervals, 

to the extent practicable) for 7 consecutive 

unit operating days according to the 

procedure given in Sections 8.5.2 through 

8.5.3. The 7 consecutive unit operating days 

need not be 7 consecutive calendar days. Use 

either nitrogen, air, Hg° , or HgCl2 standards 

for this test. 

8.5.2 The purpose of the ZD measurement 

is to verify the ability of the CEMS to 

conform to the established CEMS response 

used for determining emission 

concentrations or emission rates. Therefore, 

if periodic automatic or manual adjustments 

are made to the CEMS zero and response 

settings, conduct the ZD test immediately 

before these adjustments, or conduct it in 

such a way that the ZD can be determined. 

8.5.3 Conduct the ZD test at the zero level 

specified in Section 7.1. Introduce the zero 

gas to the CEMS. Record the CEMS response 

and subtract the zero value from the CEMS 

value and express the absolute value of the 

difference as a percentage of the span value 

(see example data sheet in Figure 12A–1). For 

the zero gas, the absolute value of the 

difference between the CEMS response and 

the reference value shall not exceed 5 percent 

of the span value. If this specification is not 

met, identify and correct the problem before 

proceeding. 

8.6 RA Test Procedure. 

8.6.1 RA Test Period. Conduct the RA test 

according to the procedure given in Sections 

8.6.2 through 8.6.6 while the affected facility 

is operating at normal full load, or as 

specified in an applicable subpart. The RA 

test may be conducted during the ZD and UD 

test period. 

8.6.2 RM. Unless otherwise specified in 

an applicable subpart of the regulations, use 

either Method 29 in appendix A to this part, 

or American Society of Testing and Materials 

(ASTM) Method D 6784–02 (incorporated by 

reference, see § 60.17) as the RM for Hg 

concentration. Alternatively, an instrumental 

RM may be used, subject to the approval of 

the Administrator. Do not include the 

filterable portion of the sample when making 

comparisons to the CEMS results. When 

Method 29 or ASTM D6784–02 is used, 

conduct the RM test runs with paired or 

duplicate sampling systems. When an 

approved instrumental method is used, 

paired sampling systems are not required. If 

the RM and CEMS measure on a different 

moisture basis, data derived with Method 4 

in appendix A to this part shall also be 

obtained during the RA test. 

8.6.3 Sampling Strategy for RM Tests. 

Conduct the RM tests in such a way that they 

will yield results representative of the 

emissions from the source and can be 

compared to the CEMS data. It is preferable 

to conduct moisture measurements (if 

needed) and Hg measurements 

simultaneously, although moisture 

measurements that are taken within an hour 

of the Hg measurements may be used to 

adjust the Hg concentrations to a consistent 

moisture basis. In order to correlate the 

CEMS and RM data properly, note the 

beginning and end of each RM test period for 

each paired RM run (including the exact time 

of day) on the CEMS chart recordings or 

other permanent record of output.

8.6.4 Number and length of RM Tests. 

Conduct a minimum of nine RM test runs. 

When Method 29 or ASTM D6784–02 is 

used, only test runs for which the data from 

the paired RM trains meet the relative 

deviation (RD) criteria of this PS shall be 

used in the RA calculations. In addition, for 

Method 29 and ASTM D 6784–02, use a 

minimum sample run time of 2 hours.

Note: More than nine sets of RM tests may 

be performed. If this option is chosen, paired 

RM test results may be excluded so long as 

the total number of paired RM test results 

used to determine the CEMS RA is greater 

than or equal to nine. However, all data must 

be reported, including the excluded data.

8.6.5 Correlation of RM and CEMS Data. 

Correlate the CEMS and the RM test data as 

to the time and duration by first determining 

from the CEMS final output (the one used for 

reporting) the integrated average pollutant 

concentration for each RM test period. 

Consider system response time, if important, 

and confirm that the results are on a 

consistent moisture basis with the RM test. 

Then, compare each integrated CEMS value 

against the corresponding RM value. When 

Method 29 or ASTM D6784–02 is used, 

compare each CEMS value against the 

corresponding average of the paired RM 

values. 

8.6.6 Paired RM Outliers. 

8.6.6.1 When Method 29 or ASTM 

D6784–02 is used, outliers are identified 

through the determination of relative 

deviation (RD) of the paired RM tests. Data 

that do not meet this criteria should be 

flagged as a data quality problem. The 

primary reason for performing paired RM 

sampling is to ensure the quality of the RM 

data. The percent RD of paired data is the 

parameter used to quantify data quality. 

Determine RD for two paired data points as 

follows:

RD C C C C =× − 100 / (Eq. 12A-1) ( ) ab a b ( ) +

where Ca and Cb are concentration values 

determined from each of the two samples 

respectively. 

8.6.6.2 A minimum performance criteria 

for RM Hg data is that RD for any data pair 

must be ≤10 percent as long as the mean Hg 

concentration is greater than 1.0 μg/m3. If the 

mean Hg concentration is less than or equal 

to 1.0 μg/m3, the RD must be ≤20 percent. 

Pairs of RM data exceeding these RD criteria 

should be eliminated from the data set used 


ER18MY05.021</MATH>
28676 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

to develop a Hg CEMS correlation or to assess 

CEMS RA. 

8.6.7 Calculate the mean difference 

between the RM and CEMS values in the 

units of micrograms per cubic meter (μg/m3), 

the standard deviation, the confidence 

coefficient, and the RA according to the 

procedures in Section 12.0. 

8.7 Reporting. At a minimum (check with 

the appropriate EPA Regional Office, State or 

local Agency for additional requirements, if 

any), summarize in tabular form the results 

of the RD tests and the RA tests or alternative 

RA procedure, as appropriate. Include all 

data sheets, calculations, charts (records of 

CEMS responses), reference gas 

concentration certifications, and any other 

information necessary to confirm that the 

performance of the CEMS meets the 

performance criteria. 

9.0 Quality Control. [Reserved] 

10.0 Calibration and Standardization. 

[Reserved] 

11.0 Analytical Procedure. 

Sample collection and analysis are 

concurrent for this PS (see Section 8.0). Refer 

to the RM employed for specific analytical 

procedures. 

12.0 Calculations and Data Analysis. 

Summarize the results on a data sheet 

similar to that shown in Figure 2–2 for PS 2. 

12.1 Consistent Basis. All data from the 

RM and CEMS must be compared in units of 

μg/m3, on a consistent and identified 

moisture and volumetric basis (STP = 20°C, 

760 millimeters (mm) Hg).

12.1.1 Moisture Correction (as 

applicable). If the RM and CEMS measure Hg 

on a different moisture basis, use Equation 

12A–2 to make the appropriate corrections to 

the Hg concentrations.

Concentration

Concentration

(Eq. 12A-2) (dry)

(wet)

ws

= ( ) 1 B−

In Equation 12–A–2, Bws is the moisture 

content of the flue gas from Method 4, 

expressed as a decimal fraction (e.g., for 8.0 

percent H2O, Bws = 0.08). 

12.2 Arithmetic Mean. Calculate the 

arithmetic mean of the difference, d, of a data 

set as follows:

d

n

di

i

n

=

=

∑

1

1

(Eq. 12A-3)

Where:

n = Number of data points. 

12.3 Standard Deviation. Calculate the 

standard deviation, Sd, as follows:

S

d

d

n

n

d

i

i

i

n

i

n

=

−





 





−













































=

=

∑

∑ 2 1

2

1

1

2

1 (Eq. 12A-4)

Where:

d d i i

i

n

=

=

∑ Algebraic summation of the individual differences .

1

12.4 Confidence Coefficient (CC). 

Calculate the 2.5 percent error confidence 

coefficient (one-tailed), CC, as follows:

CC t S

n

d = 0 975 . (Eq. 12A-5)

12.5 RA. Calculate the RA of a set of data 

as follows:

RA

d CC

RM = [ ] +

× 100 (Eq. 12A-6)

Where:

d Absolute v

CC Absolute v

RM Average RM

=

=

=

alue of the mean differences (from Equation 12A-3).

alue of the confidence coefficient (from Equation 12A- ). 

 value.

5

13.0 Method Performance. 

13.1 ME. ME is assessed at zero-level, 

mid-level and high-level values as given 

below using standards for both Hg0 and 

HgCl2. The mean difference between the 

indicated CEMS concentration and the 

reference concentration value for each 

standard shall be no greater than 5 percent 

of the span value. 

13.2 UD. The UD shall not exceed 5 

percent of the span value on any of the 7 

days of the UD test. 

13.3 ZD. The ZD shall not exceed 5 

percent of the span value on any of the 7 

days of the ZD test. 

13.4 RA. The RA of the CEMS must be no 

greater than 20 percent of the mean value of 

the RM test data in terms of units of μg/m3. 

Alternatively, if the mean RM is less than 5.0 

μg/m3, the results are acceptable if the 

absolute value of the difference between the 

mean RM and CEMS values does not exceed 

1.0 μg/m3. 

14.0 Pollution Prevention. [Reserved] 

15.0 Waste Management. [Reserved] 

16.0 Alternative Procedures. [Reserved] 

17.0 Bibliography. 

17.1 40 CFR part 60, appendix B, 

‘‘Performance Specification 2—Specifications 

and Test Procedures for SO2 and NOX

Continuous Emission Monitoring Systems in 

Stationary Sources.’’


ER18MY05.006</MATH> ER18MY05.007</MATH> ER18MY05.008</MATH> ER18MY05.009</MATH> ER18MY05.010</MATH> ER18MY05.011</MATH> ER18MY05.032</MATH>
Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28677

17.2 40 CFR part 60, appendix A, 

‘‘Method 29—Determination of Metals 

Emissions from Stationary Sources.’’

17.3 ASTM Method D6784–02, ‘‘Standard 

Test Method for Elemental, Oxidized, 

Particle-Bound and Total Mercury in Flue 

Gas Generated from Coal-Fired Stationary 

Sources (Ontario Hydro Method).’’

18.0 Tables and Figures.

TABLE 12A–1.—T-VALUES

na t0.975 na t0.975 na t0.975

2 ................................................................................................................................... 12.706 7 2.447 12 2.201 

3 ................................................................................................................................... 4.303 8 2.365 13 2.179 

4 ................................................................................................................................... 3.182 9 2.306 14 2.160 

5 ................................................................................................................................... 2.776 10 2.262 15 2.145 

6 ................................................................................................................................... 2.571 11 2.228 16 2.131 

aThe values in this table are already corrected for n–1 degrees of freedom. Use n equal to the number of individual values. 

FIGURE 12A–1.—ME, ZD AND UD DETERMINATION

Date Time Reference

Gas value μg/m3

CEMS

measured

value μg/m3

Absolute

difference 

Drift or

measurement

error (% of span 

value) 

Zero level ....

Mid level ......

High level ....

* * * * *

PART 72—PERMITS REGULATION

■ 15. The authority citation for part 72 

continues to read as follows:

Authority: 42 U.S.C. 7601 and 7651, et seq.

■ 16. Section 72.2 is amended in the 

definition of ‘‘Continuous emission 

monitoring system or CEMS’’ by revising 

the introductory text and adding 

paragraph (7); and by adding, in 

alphabetical order, a new definition for 

‘‘sorbent trap monitoring system,’’ to 

read as follows:

§ 72.2 Definitions

* * * * *

Continuous emission monitoring 

system or CEMS means the equipment 

required by part 75 of this chapter used 

to sample, analyze, measure, and 

provide, by means of readings recorded 

at least once every 15 minutes (using an 

automated data acquisition and 

handling system (DAHS)), a permanent 

record of SO2, NOX, Hg, or CO2

emissions or stack gas volumetric flow 

rate. The following are the principal 

types of continuous emission 

monitoring systems required under part 

75 of this chapter. Sections 75.10 

through 75.18, § 75.71(a) and 75.81 of 

this chapter indicate which type(s) of 

CEMS is required for specific 

applications:

* * * * *

(7) A Hg concentration monitoring 

system, consisting of a Hg pollutant 

concentration monitor and an 

automated DAHS. A Hg concentration 

monitoring system provides a 

permanent, continuous record of Hg 

emissions in units of micrograms per 

standard cubic meter (μg/scm).

* * * * *

Sorbent trap monitoring system

means the equipment required by part 

75 of this chapter for the continuous 

monitoring of Hg emissions, using 

paired sorbent traps containing 

iodinized charcoal (IC) or other suitable 

reagent(s). This excepted monitoring 

system consists of a probe, the paired 

sorbent traps, a heated umbilical line, 

moisture removal components, an airtight sample pump, a dry gas meter, and 

an automated data acquisition and 

handling system. The monitoring 

system samples the stack gas at a rate 

proportional to the stack gas volumetric 

flow rate. The sampling is a batch 

process. Using the sample volume 

measured by the dry gas meter and the 

results of the analyses of the sorbent 

traps, the average Hg concentration in 

the stack gas for the sampling period is 

determined, in units of micrograms per 

dry standard cubic meter (μg/dscm). 

Mercury mass emissions for each hour 

in the sampling period are calculated 

using the average Hg concentration for 

that period, in conjunction with 

contemporaneous hourly measurements 

28678 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

of the stack gas flow rate, corrected for 

the stack gas moisture content.

* * * * *

PART 75—CONTINUOUS EMISSION 

MONITORING

■ 17. The authority citation for Part 75 

continues to read as follows:

Authority: 42 U.S.C. 7601, 7651k, and 

7651k note.

■ 18. Section 75.2 is amended by adding 

paragraph (d), to read as follows:

§ 75.2 Applicability.

* * * * *

(d) The provisions of this part apply 

to sources subject to a State or Federal 

mercury (Hg) mass emission reduction 

program, to the extent that these 

provisions are adopted as requirements 

under such a program.

* * * * *

■ 19. Section 75.6 is amended as follows:

■ a. In the introductory text, by removing 

‘‘1916 Race Street, Philadelphia, 

Pennsylvania 19103;’’ and adding ‘‘100 

Barr harbor Drive, P.O. Box C–700, West 

Conshohocken, Pennsylvania 19428–

2959;’’ in its place;

■ b. Redesignate paragraphs (a)(38) 

through (a)(41) as (a)(39) through (a)(42);

■ c. Add new paragraphs (a)(38), (a)(43), 

and (a)(44); and

■ d. Revise paragraphs (b), (c), (d), and 

(e) to read as follows:

§ 75.6 Incorporation by Reference.

* * * * *

(a) * * *

(38) ASTM D4840–99 (reapproved 

2004), ‘‘Standard Guide for Sample 

Chain-of-Custody Procedures,’’ for 

appendix K of this part, section 7.2.9.

* * * * *

(43) ASTM D6784–02, ‘‘Standard Test 

Method for Elemental, Oxidized, 

Particle-Bound and Total Mercury in 

Flue Gas Generated from Coal-Fired 

Stationary Sources (Ontario Hydro 

Method),’’ for § 75.22(a)(7) and (b)(5). 

(44) ASTM D6911–03, ‘‘Guide for 

Packaging and Shipping Environmental 

Samples for Laboratory Analysis,’’ for 

appendix K of this part, section 7.2.8.

* * * * *

(b) The following materials are 

available for purchase from the 

American Society of Mechanical 

Engineers (ASME), 22 Law Drive, P.O. 

Box 2900, Fairfield, New Jersey 07007–

2900:

* * * * *

(c) The following materials are 

available for purchase from the 

American National Standards Institute 

(ANSI), 25 West 43rd Street, Fourth 

Floor, New York, New York 10036: 

(1) ISO 8316: 1987(E) Measurement of 

Liquid Flow in closed Conduits-Method 

by Collection of the Liquid in a 

Volumetric Tank, for appendices D and 

E of this part. 

(2) [Reserved]

* * * * *

(d) The following materials are 

available for purchase from the 

following address: Gas Processors 

Association (GPA), 6526 East 60th 

Street, Tulsa, Oklahoma 74143:

* * * * *

(e) The following American Gas 

Association materials are available for 

purchase from the following address: ILI 

Infodisk, 610 Winters Avenue, Paramus, 

New Jersey 07652:

* * * * *

■ 20. Section 75.10 is amended by 

revising the second sentence of 

paragraph (d)(1) and revising the first 

sentence of paragraph (d)(3) to read as 

follows:

§ 75.10 General operating requirements.

* * * * *

(d) * * *

(1) * * * The owner or operator shall 

reduce all SO2 concentrations, 

volumetric flow, SO2 mass emissions, 

CO2 concentration, O2 concentration, 

CO2 mass emissions (if applicable), NOX

concentration, NOX emission rate, and 

Hg concentration data collected by the 

monitors to hourly averages. * * *

* * * * *

(3) Failure of an SO2, CO2, or O2

emissions concentration monitor, NOX

concentration monitor, Hg 

concentration monitor, flow monitor, 

moisture monitor, or NOX-diluent 

continuous emission monitoring system 

to acquire the minimum number of data 

points for calculation of an hourly 

average in paragraph (d)(1) of this 

section shall result in the failure to 

obtain a valid hour of data and the loss 

of such component data for the entire 

hour. * * *

* * * * *

■ 21. Section 75.15 is added to read as 

follows:

§ 75.15 Special provisions for measuring 

Hg mass emissions using the excepted 

sorbent trap monitoring methodology. 

For an affected coal-fired unit under 

a State or Federal Hg mass emission 

reduction program that adopts the 

provisions of subpart I of this part, if the 

owner or operator elects to use sorbent 

trap monitoring systems (as defined in 

§ 72.2 of this chapter) to quantify Hg 

mass emissions, the guidelines in 

paragraphs (a) through (j) of this section 

shall be followed for this excepted 

monitoring methodology: 

(a) For each sorbent trap monitoring 

system (whether primary or redundant 

backup), the use of paired sorbent traps, 

as described in appendix K to this part, 

is required; 

(b) Each sorbent trap shall have both 

a main section, a backup section, and a 

third section to allow spiking with a 

calibration gas of known Hg 

concentration, as described in appendix 

K to this part; 

(c) A certified flow monitoring system 

is required; 

(d) Correction for stack gas moisture 

content is required, and in some cases, 

a certified O2 or CO2 monitoring system 

is required (see § 75.81(a)(4)); 

(e) Each sorbent trap monitoring 

system shall be installed and operated 

in accordance with appendix K to this 

part. The automated data acquisition 

and handling system shall ensure that 

the sampling rate is proportional to the 

stack gas volumetric flow rate. 

(f) At the beginning and end of each 

sample collection period, and at least 

once in each unit operating hour during 

the collection period, the dry gas meter 

reading shall be recorded. 

(g) After each sample collection 

period, the mass of Hg adsorbed in each 

sorbent trap (in all three sections) shall 

be determined according to the 

applicable procedures in appendix K to 

this part. 

(h) The hourly Hg mass emissions for 

each collection period are determined 

using the results of the analyses in 

conjunction with contemporaneous 

hourly data recorded by a certified stack 

flow monitor, corrected for the stack gas 

moisture content. For each pair of 

sorbent traps analyzed, the average of 

the two Hg concentrations shall be used 

for reporting purposes under § 75.84(f). 

Notwithstanding this requirement, if, 

due to circumstances beyond the control 

of the owner or operator, one of the 

paired traps is accidentally lost, 

damaged, or broken and cannot be 

analyzed, the results of the analysis of 

the other trap, if valid, may be used for 

reporting purposes.

(i) All unit operating hours for which 

valid Hg concentration data are obtained 

with the primary sorbent trap 

monitoring system (as verified using the 

quality assurance procedures in 

appendix K to this part) shall be 

reported in the electronic quarterly 

report under § 75.84(f). For hours in 

which data from the primary monitoring 

system are invalid, the owner or 

operator may report valid Hg 

concentration data from a certified 

redundant backup CEMS or sorbent trap 

monitoring system or from an applicable 

reference method under § 75.22. If no 

quality-assured Hg concentration are 

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28679

available for a particular hour, the 

owner or operator shall report the 

appropriate substitute data value in 

accordance with § 75.39. 

(j) Initial certification requirements 

and additional quality-assurance 

requirements for the sorbent trap 

monitoring systems are found in 

§ 75.20(c)(9), in section 6.5.7 of 

appendix A to this part, in sections 1.5 

and 2.3 of appendix B to this part, and 

in appendix K to this part.

■ 22. Section 75.20 is amended by:

■ a. Revising paragraph (a)(5)(i);

■ b. Revising the first sentence of 

paragraph (b) introductory text;

■ c. Revising paragraph (c)(1);

■ d. Redesignating existing paragraphs 

(c)(9) and (c)(10) as paragraphs (c)(10) 

and (c)(11), respectively;

■ e. Adding a new paragraph (c)(9); and

■ f. Revising paragraph (d)(2)(v).

The revisions and additions read as 

follows:

§ 75.20 Initial certification and 

recertification procedures. 

(a) * * *

(5) * * *

(i) Until such time, date, and hour as 

the continuous emission monitoring 

system can be adjusted, repaired, or 

replaced and certification tests 

successfully completed (or, if the 

conditional data validation procedures 

in paragraphs (b)(3)(ii) through (b)(3)(ix) 

of this section are used, until a 

probationary calibration error test is 

passed following corrective actions in 

accordance with paragraph (b)(3)(ii) of 

this section), the owner or operator shall 

substitute the following values, as 

applicable, for each hour of unit 

operation during the period of invalid 

data specified in paragraph (a)(4)(iii) of 

this section or in § 75.21: The maximum 

potential concentration of SO2, as 

defined in section 2.1.1.1 of appendix A 

to this part, to report SO2 concentration; 

the maximum potential NOX emission 

rate, as defined in § 72.2 of this chapter, 

to report NOX emissions in lb/MMBtu; 

the maximum potential concentration of 

NOX, as defined in section 2.1.2.1 of 

appendix A to this part, to report NOX

emissions in ppm (when a NOX

concentration monitoring system is used 

to determine NOX mass emissions, as 

defined under § 75.71(a)(2)); the 

maximum potential concentration of Hg, 

as defined in section 2.1.7 of appendix 

A to this part, to report Hg emissions in 

μg/scm (when a Hg concentration 

monitoring system or a sorbent trap 

monitoring system is used to determine 

Hg mass emissions, as defined under 

§ 75.81(b)); the maximum potential flow 

rate, as defined in section 2.1.4.1 of 

appendix A to this part, to report 

volumetric flow; the maximum potential 

concentration of CO2, as defined in 

section 2.1.3.1 of appendix A to this 

part, to report CO2 concentration data; 

and either the minimum potential 

moisture percentage, as defined in 

section 2.1.5 of appendix A to this part 

or, if Equation 19–3, 19–4 or 19–8 in 

Method 19 in appendix A to part 60 of 

this chapter is used to determine NOX

emission rate, the maximum potential 

moisture percentage, as defined in 

section 2.1.6 of appendix A to this part; 

and

* * * * *

(b) Recertification approval process. 

Whenever the owner or operator makes 

a replacement, modification, or change 

in a certified continuous emission 

monitoring system or continuous 

opacity monitoring system that may 

significantly affect the ability of the 

system to accurately measure or record 

the SO2 or CO2 concentration, stack gas 

volumetric flow rate, NOX emission rate, 

NOX concentration, Hg concentration, 

percent moisture, or opacity, or to meet 

the requirements of § 75.21 or appendix 

B to this part, the owner or operator 

shall recertify the continuous emission 

monitoring system or continuous 

opacity monitoring system, according to 

the procedures in this paragraph. * * *

* * * * *

(c) * * *

(1) For each SO2 pollutant 

concentration monitor, each NOX

concentration monitoring system used 

to determine NOX mass emissions, as 

defined under § 75.71(a)(2), each Hg 

concentration monitoring system, and 

each NOX-diluent continuous emission 

monitoring system: 

(i) A 7-day calibration error test, 

where, for the NOX -diluent continuous 

emission monitoring system, the test is 

performed separately on the NOX

pollutant concentration monitor and the 

diluent gas monitor; 

(ii) A linearity check, where, for the 

NOX-diluent continuous emission 

monitoring system, the test is performed 

separately on the NOX pollutant 

concentration monitor and the diluent 

gas monitor. For Hg monitors, perform 

this check with elemental Hg standards; 

(iii) A relative accuracy test audit. For 

the NOX-diluent continuous emission 

monitoring system, the RATA shall be 

done on a system basis, in units of lb/

MMBtu. For the NOX concentration 

monitoring system, the RATA shall be 

done on a ppm basis. For the Hg 

concentration monitoring system, the 

RATA shall be done on a μg/scm basis; 

(iv) A bias test;

(v) A cycle time test; and 

(vi) For Hg monitors only, a 3-level 

system integrity check, using a NISTtraceable source of oxidized Hg, as 

described in section 6.2 of appendix A 

to this part. This test is not required for 

an Hg monitor that does not have a 

converter.

* * * * *

(9) For each sorbent trap monitoring 

system, perform a RATA, on a μg/dscm 

basis, and a bias test.

* * * * *

(d) * * *

(2) * * *

(v) For each parameter monitored (i.e., 

SO2, CO2, O2, NOX, Hg or flow rate) at 

each unit or stack, a regular nonredundant backup CEMS may not be 

used to report data at that affected unit 

or common stack for more than 720 

hours in any one calendar year (or 720 

hours in any ozone season, for sources 

that report emission data only during 

the ozone season, in accordance with 

§ 75.74(c)), unless the CEMS passes a 

RATA at that unit or stack. For each 

parameter monitored at each unit or 

stack, the use of a like-kind replacement 

non-redundant backup analyzer (or 

analyzers) is restricted to 720 

cumulative hours per calendar year (or 

ozone season, as applicable), unless the 

owner or operator redesignates the likekind replacement analyzer(s) as 

component(s) of regular non-redundant 

backup CEMS and each redesignated 

CEMS passes a RATA at that unit or 

stack.

* * * * *

■ 23. Section 75.21 is amended by 

revising paragraph (a)(3) to read as 

follows:

§ 75.21 Quality assurance and quality 

control requirements. 

(a) * * *

(3) The owner or operator shall 

perform quality assurance upon a 

reference method backup monitoring 

system according to the requirements of 

method 2, 6C, 7E, or 3A in appendix A 

of part 60 of this chapter 

(supplemented, as necessary, by 

guidance from the Administrator), or 

one of the Hg reference methods in 

§ 75.22, as applicable, instead of the 

procedures specified in appendix B of 

this part.

* * * * *

■ 24. Section 75.22 is amended by 

adding new paragraphs (a)(7) and (b)(5), 

to read as follows:

§ 75.22 Reference test methods. 

(a) * * *

(7) ASTM D6784–02, ‘‘Standard Test 

Method for Elemental, Oxidized, 

Particle-Bound, and Total Mercury in 

Flue Gas Generated from Coal-Fired 

Stationary Sources’’ (also known as the 

28680 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

Ontario Hydro Method) (incorporated 

by reference, see § 75.6) is the reference 

method for determining Hg 

concentration. When this method is 

used, paired sampling trains are 

required, and to validate a RATA run, 

the relative deviation (RD), calculated 

according to section 11.7 of appendix K 

to this part, must not exceed 10 percent. 

If the RD criterion is met, use the 

average Hg concentration measured by 

the two trains (vapor phase Hg, only) in 

the relative accuracy calculations. 

Alternatively, an instrumental reference 

method capable of measuring total 

vapor phase Hg may be used, subject to 

the approval of the Administrator. 

(b) * * *

(5) ASTM D6784–02, ‘‘Standard Test 

Method for Elemental, Oxidized, 

Particle-Bound, and Total Mercury in 

Flue Gas Generated from Coal-Fired 

Stationary Sources’’ (also known as the 

Ontario Hydro Method and incorporated 

by reference, see § 75.6) for determining 

Hg concentration. Alternatively, an 

instrumental reference method capable 

of measuring total vapor phase Hg may 

be used, subject to the approval of the 

Administrator.

* * * * *

■ 25. Section 75.24 is amended by 

revising paragraph (d), to read as follows:

§ 75.24 Out-of-control periods and 

adjustment for system bias.

* * * * *

(d) When the bias test indicates that 

an SO2 monitor, a flow monitor, a NOXdiluent continuous emission monitoring 

system, a NOX concentration monitoring 

system used to determine NOX mass 

emissions, as defined in § 75.71(a)(2), a 

Hg concentration monitoring system or 

a sorbent trap monitoring system is 

biased low (i.e., the arithmetic mean of 

the differences between the reference 

method value and the monitor or 

monitoring system measurements in a 

relative accuracy test audit exceed the 

bias statistic in section 7 of appendix A 

to this part), the owner or operator shall 

adjust the monitor or continuous 

emission monitoring system to 

eliminate the cause of bias such that it 

passes the bias test or calculate and use 

the bias adjustment factor as specified 

in section 2.3.4 of appendix B to this 

part.

* * * * *

■ 26. Section 75.31 is amended by:

■ a. Revising the first sentence of 

paragraph (a);

■ b. Revising paragraph (b) introductory 

text; and

■ c. Revising paragraphs (b)(1) and (b)(2).

The revisions read as follows:

§ 75.31 Initial missing data procedures. 

(a) During the first 720 qualityassured monitor operating hours 

following initial certification of the 

required SO2, CO2, O2, Hg 

concentration, or moisture monitoring 

system(s) at a particular unit or stack 

location (i.e., the date and time at which 

quality-assured data begins to be 

recorded by CEMS(s) installed at that 

location), and during the first 2,160 

quality-assured monitor operating hours 

following initial certification of the 

required NOX-diluent, NOX

concentration, or flow monitoring 

system(s) at the unit or stack location, 

the owner or operator shall provide 

substitute data required under this 

subpart according to the procedures in 

paragraphs (b) and (c) of this section. 

***

* * * * *

(b) SO2, CO2, or O2 concentration 

data, Hg concentration data, and 

moisture data. For each hour of missing 

SO2, Hg, or CO2 emissions concentration 

data (including CO2 data converted from 

O2 data using the procedures in 

appendix F of this part), or missing O2

or CO2 diluent concentration data used 

to calculate heat input, or missing 

moisture data, the owner or operator 

shall calculate the substitute data as 

follows: 

(1) Whenever prior quality-assured 

data exist, the owner or operator shall 

substitute, by means of the data 

acquisition and handling system, for 

each hour of missing data, the average 

of the hourly SO2, CO2, Hg, or O2

concentrations, or moisture percentages 

recorded by a certified monitor for the 

unit operating hour immediately before 

and the unit operating hour 

immediately after the missing data 

period. 

(2) Whenever no prior quality assured 

SO2, CO2, Hg, or O2 concentration data, 

or moisture data exist, the owner or 

operator shall substitute, as applicable, 

for each hour of missing data, the 

maximum potential SO2 concentration 

or the maximum potential CO2

concentration or the minimum potential 

O2 concentration or (unless Equation 

19–3, 19–4 or 19–8 in Method 19 in 

appendix A to part 60 of this chapter is 

used to determine NOX emission rate) 

the minimum potential moisture 

percentage, or the maximum potential 

Hg concentration, as specified, 

respectively, in sections 2.1.1.1, 2.1.3.1, 

2.1.3.2, 2.1.5, and 2.1.7 of appendix A 

to this part. If Equation 19–3, 19–4 or 

19–8 in Method 19 in appendix A to 

part 60 of this chapter is used to 

determine NOX emission rate, substitute 

the maximum potential moisture 

percentage, as specified in section 2.1.6 

of appendix A to this part.

* * * * *

■ 27. Section 75.32 is amended by 

revising the first sentence of paragraph 

(a) introductory text to read as follows:

§ 75.32 Determination of monitor data 

availability for standard missing data 

procedures. 

(a) Following initial certification of 

the required SO2, CO2, O2, or Hg 

concentration, or moisture monitoring 

system(s) at a particular unit or stack 

location (i.e., the date and time at which 

quality-assured data begins to be 

recorded by CEMS(s) at that location), 

the owner or operator shall begin 

calculating the percent monitor data 

availability as described in paragraph 

(a)(1) of this section, and shall, upon 

completion of the first 720 qualityassured monitor operating hours, 

record, by means of the automated data 

acquisition and handling system, the 

percent monitor data availability for 

each monitored parameter. * * *

* * * * *

■ 28. Table 1 in § 75.33 is revised as 

follows:

§ 75.33 Standard missing data procedures 

for SO2, NOX, and flow rate.

* * * * *

TABLE 1.—MISSING DATA PROCEDURE FOR SO2 CEMS, CO2 CEMS, MOISTURE CEMS, HG CEMS, AND DILUENT (CO2

OR O2) MONITORS FOR HEAT INPUT DETERMINATION

Trigger conditions Calculation routines 

Monitor data availability

(percent) 

Duration (N) of 

CEMS outage 

(hours) 2

Method Lookback period 

95 or more (90 or more for Hg) ............................... N ≤ 24 ................ Average ................................................................... HB/HA. 

N > 24 ................ For SO2, CO2, Hg, and H2O **,the greater of: 

Average ................................................................... HB/HA. 

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28681

TABLE 1.—MISSING DATA PROCEDURE FOR SO2 CEMS, CO2 CEMS, MOISTURE CEMS, HG CEMS, AND DILUENT (CO2

OR O2) MONITORS FOR HEAT INPUT DETERMINATION—Continued

Trigger conditions Calculation routines 

Monitor data availability

(percent) 

Duration (N) of 

CEMS outage 

(hours) 2

Method Lookback period 

90th percentile ......................................................... 720 hours *. 

For O2 and H2O x, the lesser of: 

Average ................................................................... HB/HA. 

10th percentile ......................................................... 720 hours *. 

90 or more, but below 95 (≥ 80 but < 90 for Hg) .... N ≤ 8 .................. Average ................................................................... HB/HA. 

N > 8 .................. For SO2, CO2, Hg, and H2O **, the greater of: 

Average ................................................................... HB/HA. 

95th percentile ......................................................... 720 hours *. 

For O2 and H2O x, the lesser of: 

Average ................................................................... HB/HA. 

5th percentile ........................................................... 720 hours *. 

80 or more, but below 90 (≥70 but < 80 for Hg) ..... N > 0 .................. For SO2, CO2, Hg, and H2O **, 

Maximum value 1 ..................................................... 720 hours *. 

For O2 and H2O x: 

Minimum value 1 ...................................................... 720 hours*. 

Below 80 (Below 70 for Hg) ..................................... N > 0 .................. Maximum potential concentration or % (for SO2, 

CO2, Hg, and H2O **) or Minimum potential concentration or % (for O2 and H2O x).

None 

HB/HA = hour before and hour after the CEMS outage. 

*Quality-assured, monitor operating hours, during unit operation. May be either fuel-specific or non-fuel-specific. For units that report data only 

for the ozone season, include only quality assured monitor operating hours within the ozone season in the lookback period. Use data from no 

earlier than 3 years prior to the missing data period. 1Where a unit with add-on SO2 or Hg emission controls can demonstrate that the controls are operating properly, as provided in § 75.34, the 

unit may, upon approval, use the maximum controlled emission rate from the previous 720 operating hours. 2 During unit operating hours. 

x Use this algorithm for moisture except when Equation 19–3, 19–4 or 19–8 in Method 19 in appendix A to part 60 of this chapter is used for 

NOX emission rate. ** Use this algorithm for moisture only when Equation 19–3, 19–4 or 19–8 in Method 19 in appendix A to part 60 of this chapter is used for 

NOX emission rate. 

* * * * *

■ 29. Subpart D is further amended by 

adding two new sections, § 75.38 and 

§ 75.39, to read as follows:

§ 75.38 Standard missing data procedures 

for Hg CEMS. 

(a) Once 720 quality assured monitor 

operating hours of Hg concentration 

data have been obtained following 

initial certification, the owner or 

operator shall provide substitute data 

for Hg concentration in accordance with 

the procedures in §§ 75.33(b)(1) through 

(b)(4), except that the term ‘‘Hg 

concentration’’ shall apply rather than 

‘‘SO2 concentration,’’ the term ‘‘Hg 

concentration monitoring system’’ shall 

apply rather than ‘‘SO2 pollutant 

concentration monitor,’’ and the term 

‘‘maximum potential Hg concentration, 

as defined in section 2.1.7 of appendix 

A to this part’’ shall apply, rather than 

‘‘maximum potential SO2

concentration.’’

(b) For a unit equipped with a flue gas 

desulfurization (FGD) system that 

significantly reduces the concentration 

of Hg emitted to the atmosphere 

(including circulating fluidized bed 

units that use limestone injection), or 

for a unit equipped with add-on Hg 

emission controls (e.g., carbon 

injection), the standard missing data 

procedures in paragraph (a) of this 

section may only be used for hours in 

which the SO2 or Hg emission controls 

are documented to be operating 

properly, as described in § 75.58(b)(3). 

For any hour(s) in the missing data 

period for which this documentation is 

unavailable, the owner or operator shall 

report, as applicable, the maximum 

potential Hg concentration, as defined 

in section 2.1.7 of appendix A to this 

part. In addition, under § 75.64(c), the 

designated representative shall submit 

as part of each electronic quarterly 

report, a certification statement, 

verifying the proper operation of the 

SO2 or Hg emission controls for each 

missing data period in which the 

procedures in paragraph (a) of this 

section are applied.

(c) For units with FGD systems or 

add-on Hg controls, when the percent 

monitor data availability is less than 

80.0 percent, and a missing data period 

occurs, the owner or operator may 

petition to report the maximum 

controlled Hg concentration in the 

previous 720 quality-assured monitor 

operating hours, consistent with 

§ 75.34(a)(3).

§ 75.39 Missing data procedures for 

sorbent trap monitoring systems. 

(a) If a sorbent trap monitoring system 

has not been certified by the applicable 

compliance date specified under a State 

or Federal Hg mass emission reduction 

program that adopts the requirements of 

subpart I of this part, the owner or 

operator shall report the maximum 

potential Hg concentration, as defined 

in section 2.1.7 of appendix A to this 

part, until the system is certified. 

(b) For a certified sorbent trap system, 

a missing data period will occur 

whenever: 

(1) A gas sample is not extracted from 

the stack (e.g. during a monitoring 

system malfunction or when the system 

undergoes maintenance); or 

(2) The results of the Hg analysis for 

the paired sorbent traps are missing or 

invalid (as determined using the quality 

assurance procedures in appendix K to 

this part). The missing data period 

begins with the hour in which the 

paired sorbent traps for which the Hg 

analysis is missing or invalid were put 

into service. The missing data period 

ends at the first hour in which valid Hg 

concentration data are obtained with 

another pair of sorbent traps (i.e., the 

hour at which this pair of traps was 

placed in service). 

28682 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

(c) Initial missing data procedures.

Use these missing data procedures until 

720 hours of quality-assured data have 

been collected with the sorbent trap 

monitoring system(s), following initial 

certification. For each hour of the 

missing data period, the substitute data 

value for Hg concentration shall be the 

average Hg concentration from all valid 

sorbent trap analyses to date, including 

data from the initial certification test 

runs. 

(d) Standard missing data procedures.

Once 720 quality-assured hours of data 

have been obtained with the sorbent 

trap system(s), begin reporting the 

percent monitor data availability in 

accordance with § 75.32 and switch 

from the initial missing data procedures 

in paragraph (c) of this section to the 

following standard missing data 

procedures: 

(1) If the percent monitor data 

availability (PMA) is ≥ 90.0 percent, 

report the average Hg concentration for 

all valid sorbent trap analyses in the 

previous 12 months. 

(2) If the PMA is ≥ 80.0 percent, but 

< 90.0 percent, report the 95th 

percentile Hg concentration obtained 

from all of the valid sorbent trap 

analyses in the previous 12 months. 

(3) If the PMA is ≥ 70.0 percent, but 

< 80.0 percent, report the maximum Hg 

concentration obtained from all of the 

valid sorbent trap analyses in the 

previous 12 months. 

(4) If the PMA is < 70.0 percent, report 

the maximum potential Hg 

concentration, as defined in section 

2.1.7 of appendix A to this part. 

(5) For the purposes of paragraphs 

(d)(1), (d)(2), and (d)(3) of this section, 

if fewer than 12 months have elapsed 

since initial certification, use whatever 

valid sorbent trap analyses are available 

to determine the appropriate substitute 

data values. 

(e) Notwithstanding the requirements 

of paragraphs (c) and (d) of this section, 

if the unit has add-on Hg emission 

controls or is equipped with a flue gas 

desulfurization system that significantly 

reduces Hg emissions, the owner or 

operator shall report the maximum 

potential Hg concentration, as defined 

in section 2.1.7 of appendix A to this 

part, for any hour(s) in the missing data 

period for which proper operation of the 

Hg emission controls or FGD system is 

not documented according to 

§ 75.58(b)(3).

■ 30. Section 75.53 is amended by:

■ a. Revising paragraph (e)(1)(i)(E);

■ b. Revising paragraph (e)(1)(iv) 

introductory text; and

■ c. Revising paragraph (e)(1)(x).

The revisions read as follows:

§ 75.53 Monitoring plan.

* * * * *

(e) * * * 

(1) * * * 

(i) * * * 

(E) Type(s) of emission controls for 

SO2, NOX, Hg, and particulates installed 

or to be installed, including 

specifications of whether such controls 

are pre-combustion, post-combustion, or 

integral to the combustion process; 

control equipment code, installation 

date, and optimization date; control 

equipment retirement date (if 

applicable); primary/secondary controls 

indicator; and an indicator for whether 

the controls are an original installation;

* * * * *

(iv) Identification and description of 

each monitoring component (including 

each monitor and its identifiable 

components, such as analyzer and/or 

probe) in the CEMS (e.g., SO2 pollutant 

concentration monitor, flow monitor, 

moisture monitor; NOX pollutant 

concentration monitor, Hg monitor, and 

diluent gas monitor), the sorbent trap 

monitoring system, the continuous 

opacity monitoring system, or the 

excepted monitoring system (e.g., fuel 

flowmeter, data acquisition and 

handling system), including:

* * * * *

(x) For each parameter monitored: 

Scale, maximum potential concentration 

(and method of calculation), maximum 

expected concentration (if applicable) 

(and method of calculation), maximum 

potential flow rate (and method of 

calculation), maximum potential NOX

emission rate, span value, full-scale 

range, daily calibration units of 

measure, span effective date/hour, span 

inactivation date/hour, indication of 

whether dual spans are required, default 

high range value, flow rate span, and 

flow rate span value and full scale value 

(in scfh) for each unit or stack using 

SO2, NOX, CO2, O2, Hg, or flow 

component monitors.

* * * * *

■ 31. Section 75.57 is amended by 

adding new paragraphs (i) and (j), to read 

as follows:

§ 75.57 General recordkeeping provisions.

* * * * *

(i) Hg emission record provisions 

(CEMS). The owner or operator shall 

record for each hour the information 

required by this paragraph for each 

affected unit using Hg CEMS in 

combination with flow rate, and (in 

certain cases) moisture, and diluent gas 

monitors, to determine Hg mass 

emissions and (if applicable) unit heat 

input under a State or Federal Hg mass 

emissions reduction program that 

adopts the requirements of subpart I of 

this part. 

(1) For Hg concentration during unit 

operation, as measured and reported 

from each certified primary monitor, 

certified back-up monitor, or other 

approved method of emissions 

determination:

(i) Component-system identification 

code, as provided in § 75.53; 

(ii) Date and hour; 

(iii) Hourly Hg concentration (μg/scm, 

rounded to the nearest tenth). For a 

particular pair of sorbent traps, this will 

be the flow-proportional average 

concentration for the data collection 

period; 

(iv) The bias-adjusted hourly average 

Hg concentration (μg/scm, rounded to 

the nearest hundredth) if a bias 

adjustment factor is required, as 

provided in § 75.24(d); 

(v) Method of determination for 

hourly Hg concentration using Codes 1–

55 in Table 4a of this section; and 

(vi) The percent monitor data 

availability (to the nearest tenth of a 

percent), calculated pursuant to § 75.32. 

(2) For flue gas moisture content 

during unit operation (if required), as 

measured and reported from each 

certified primary monitor, certified 

back-up monitor, or other approved 

method of emissions determination 

(except where a default moisture value 

is used in accordance with § 75.11(b), 

§ 75.12(b), or approved under § 75.66): 

(i) Component-system identification 

code, as provided in § 75.53; 

(ii) Date and hour; 

(iii) Hourly average moisture content 

of flue gas (percent, rounded to the 

nearest tenth). If the continuous 

moisture monitoring system consists of 

wet- and dry-basis oxygen analyzers, 

also record both the wet- and dry-basis 

oxygen hourly averages (in percent O2, 

rounded to the nearest tenth); 

(iv) Percent monitor data availability 

(recorded to the nearest tenth of a 

percent) for the moisture monitoring 

system, calculated pursuant to § 75.32; 

and 

(v) Method of determination for 

hourly average moisture percentage, 

using Codes 1–55 in Table 4a of this 

section. 

(3) For diluent gas (O2 or CO2) 

concentration during unit operation (if 

required), as measured and reported 

from each certified primary monitor, 

certified back-up monitor, or other 

approved method of emissions 

determination: 

(i) Component-system identification 

code, as provided in § 75.53; 

(ii) Date and hour; 

(iii) Hourly average diluent gas (O2 or 

CO2) concentration (in percent, rounded 

to the nearest tenth); 

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28683

(iv) Method of determination code for 

diluent gas (O2 or CO2) concentration 

data using Codes 1–55, in Table 4a of 

this section; and 

(v) The percent monitor data 

availability (to the nearest tenth of a 

percent) for the O2 or CO2 monitoring 

system (if a separate O2 or CO2

monitoring system is used for heat input 

determination), calculated pursuant to 

§ 75.32. 

(4) For stack gas volumetric flow rate 

during unit operation, as measured and 

reported from each certified primary 

monitor, certified back-up monitor, or 

other approved method of emissions 

determination, record the information 

required under paragraphs (c)(2)(i) 

through (c)(2)(vi) of this section. 

(5) For Hg mass emissions during unit 

operation, as measured and reported 

from the certified primary monitoring 

system(s), certified redundant or nonredundant back-up monitoring 

system(s), or other approved method(s) 

of emissions determination: 

(i) Date and hour; 

(ii) Hourly Hg mass emissions 

(ounces, rounded to three decimal 

places); 

(iii) Hourly Hg mass emissions 

(ounces, rounded to three decimal 

places), adjusted for bias if a bias 

adjustment factor is required, as 

provided in § 75.24(d); and 

(iv) Identification code for emissions 

formula used to derive hourly Hg mass 

emissions from Hg concentration, flow 

rate and moisture data, as provided in 

§ 75.53. 

(j) Hg emission record provisions 

(sorbent trap systems). The owner or 

operator shall record for each hour the 

information required by this paragraph, 

for each affected unit using sorbent trap 

monitoring systems in combination with 

flow rate, moisture, and (in certain 

cases) diluent gas monitors, to 

determine Hg mass emissions and (if 

required) unit heat input under a State 

or Federal Hg mass emissions reduction 

program that adopts the requirements of 

subpart I of this part. 

(1) For Hg concentration during unit 

operation, as measured and reported 

from each certified primary monitor, 

certified back-up monitor, or other 

approved method of emissions 

determination: 

(i) Component-system identification 

code, as provided in § 75.53; 

(ii) Date and hour; 

(iii) Hourly Hg concentration (μg/

dscm, rounded to the nearest tenth). For 

a particular pair of sorbent traps, this 

will be the flow-proportional average 

concentration for the data collection 

period; 

(iv) The bias-adjusted hourly average 

Hg concentration (μg/dscm, rounded to 

the nearest tenth) if a bias adjustment 

factor is required, as provided in 

§ 75.24(d); 

(v) Method of determination for 

hourly average Hg concentration using 

Codes 1–55 in Table 4a of this section; 

and 

(vi) Percent monitor data availability 

(recorded to the nearest tenth of a 

percent), calculated pursuant to § 75.32;

(2) For flue gas moisture content 

during unit operation, as measured and 

reported from each certified primary 

monitor, certified back-up monitor, or 

other approved method of emissions 

determination (except where a default 

moisture value is used in accordance 

with § 75.11(b), § 75.12(b), or approved 

under § 75.66), record the information 

required under paragraphs (i)(2)(i) 

through (i)(2)(v) of this section; 

(3) For diluent gas (O2 or CO2) 

concentration during unit operation (if 

required for heat input determination), 

record the information required under 

paragraphs (i)(3)(i) through (i)(3)(v) of 

this section. 

(4) For stack gas volumetric flow rate 

during unit operation, as measured and 

reported from each certified primary 

monitor, certified back-up monitor, or 

other approved method of emissions 

determination, record the information 

required under paragraphs (c)(2)(i) 

through (c)(2)(vi) of this section. 

(5) For Hg mass emissions during unit 

operation, as measured and reported 

from the certified primary monitoring 

system(s), certified redundant or nonredundant back-up monitoring 

system(s), or other approved method(s) 

of emissions determination, record the 

information required under paragraph 

(i)(5) of this section. 

(6) Record the average flow rate of 

stack gas through each sorbent trap (in 

appropriate units, e.g., liters/min, cc/

min, dscm/min). 

(7) Record the dry gas meter reading 

(in dscm, rounded to the nearest 

hundredth), at the beginning and end of 

the collection period and at least once 

in each unit operating hour during the 

collection period. 

(8) Calculate and record the ratio of 

the bias-adjusted stack gas flow rate to 

the sample flow rate, as described in 

section 11.2 of appendix K to this part.

■ 32. Section 75.58 is amended by 

revising paragraphs (b)(3) introductory 

text, (b)(3)(i), and (b)(3)(ii), to read as 

follows:

§ 75.58 General recordkeeping provisions 

for specific situations.

* * * * *

(b) * * * 

(3) Except as otherwise provided in 

§ 75.34 (d), for units with add-on SO2 or 

NOX emission controls following the 

provisions of § 75.34(a)(1), (a)(2) or 

(a)(3), or for units with add-on Hg 

emission controls, the owner or operator 

shall record: 

(i) Parametric data which 

demonstrate, for each hour of missing 

SO2, Hg, or NOX emission data, the 

proper operation of the add-on emission 

controls, as described in the quality 

assurance/quality control program for 

the unit. The parametric data shall be 

maintained on site and shall be 

submitted, upon request, to the 

Administrator, EPA Regional office, 

State, or local agency. Alternatively, for 

units equipped with flue gas 

desulfurization (FGD) systems, the 

owner or operator may use qualityassured data from a certified SO2

monitor to demonstrate proper 

operation of the emission controls 

during periods of missing Hg data; 

(ii) A flag indicating, for each hour of 

missing SO2, Hg, or NOX emission data, 

either that the add-on emission controls 

are operating properly, as evidenced by 

all parameters being within the ranges 

specified in the quality assurance/

quality control program, or that the addon emission controls are not operating 

properly;

* * * * *

■ 33. Section 75.59 is amended by:

■ a. Revising the introductory text of 

paragraphs (a)(1), (a)(3), (a)(5), (a)(5)(ii), 

(a)(6), and (a)(9);

■ b. Adding paragraphs (a)(7)(vii), 

(a)(7)(viii), and (a)(14);

■ c. Revising paragraph (a)(9)(vi); and

■ d. Revising the introductory text of 

paragraph (c). 

The revisions read as follows:

§ 75.59 Certification, quality assurance, 

and quality control record provisions.

* * * * *

(a) * * * 

(1) For each SO2 or NOX pollutant 

concentration monitor, flow monitor, 

CO2 emissions concentration monitor 

(including O2 monitors used to 

determine CO2 emissions), Hg monitor, 

or diluent gas monitor (including wetand dry-basis O2 monitors used to 

determine percent moisture), the owner 

or operator shall record the following 

for all daily and 7-day calibration error 

tests, all daily system integrity checks 

(Hg monitors, only), and all off-line 

calibration demonstrations, including 

any follow-up tests after corrective 

action:

* * * * *

(3) For each SO2 or NOX pollutant 

concentration monitor, CO2 emissions 

28684 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

concentration monitor (including O2

monitors used to determine CO2

emissions), Hg concentration monitor, 

or diluent gas monitor (including wetand dry-basis O2 monitors used to 

determine percent moisture), the owner 

or operator shall record the following 

for the initial and all subsequent 

linearity check(s) and 3-level system 

integrity checks (Hg monitors with 

converters, only), including any followup tests after corrective action:

* * * * *

(5) For each SO2 pollutant 

concentration monitor, flow monitor, 

each CO2 emissions concentration 

monitor (including any O2

concentration monitor used to 

determine CO2 mass emissions or heat 

input), each NOX-diluent continuous 

emission monitoring system, each NOX

concentration monitoring system, each 

diluent gas (O2 or CO2) monitor used to 

determine heat input, each moisture 

monitoring system, each Hg 

concentration monitoring system, each 

sorbent trap monitoring system, and 

each approved alternative monitoring 

system, the owner or operator shall 

record the following information for the 

initial and all subsequent relative 

accuracy test audits:

* * * * *

(ii) Individual test run data from the 

relative accuracy test audit for the SO2

concentration monitor, flow monitor, 

CO2 emissions concentration monitor, 

NOX-diluent continuous emission 

monitoring system, SO2-diluent 

continuous emission monitoring system, 

diluent gas (O2 or CO2) monitor used to 

determine heat input, NOX

concentration monitoring system, 

moisture monitoring system, Hg 

concentration monitoring system, 

sorbent trap monitoring system, or 

approved alternative monitoring system, 

including:

* * * * *

(6) For each SO2, NOX, Hg, or CO2

emissions concentration monitor, NOXdiluent continuous emission monitoring 

system, NOX concentration monitoring 

system, or diluent gas (O2 or CO2) 

monitor used to determine heat input, 

the owner or operator shall record the 

following information for the cycle time 

test:

* * * * *

(7) * * * 

(vii) For each RATA run using the 

Ontario Hydro Method to determine Hg 

concentration: 

(A) Percent CO2 and O2 in the stack 

gas, dry basis;

(B) Moisture content of the stack gas 

(percent H2O); 

(C) Average stack temperature (°F); 

(D) Dry gas volume metered (dscm); 

(E) Percent isokinetic; 

(F) Particle-bound Hg collected by the 

filter, blank, and probe rinse (μg); 

(G) Oxidized Hg collected by the KCl 

impingers (μg); 

(H) Elemental Hg collected in the 

HNO3/H2O2 impinger and in the 

KMnO4/H2SO4 impingers (μg); 

(I) Total Hg, including particle-bound 

Hg (μg); and 

(J) Total Hg, excluding particle-bound 

Hg (μg) 

(viii) Data elements for instrumental 

Hg reference method. [Reserved]

* * * * *

(9) When hardcopy relative accuracy 

test reports, certification reports, 

recertification reports, or semiannual or 

annual reports for gas or flow rate 

CEMS, Hg CEMS, or sorbent trap 

monitoring systems are required or 

requested under § 75.60(b)(6) or § 75.63, 

the reports shall include, at a minimum, 

the following elements (as applicable to 

the type(s) of test(s) performed:

* * * * *

(vi) Laboratory calibrations of the 

source sampling equipment. For sorbent 

trap monitoring systems, the laboratory 

analyses of all sorbent traps, and 

information documenting the results of 

all leak checks and other applicable 

quality control procedures.

* * * * *

(14) For the sorbent traps used in 

sorbent trap monitoring systems to 

quantify Hg concentration under 

subpart I of this part (including sorbent 

traps used for relative accuracy testing), 

the owner or operator shall keep records 

of the following: 

(i) The ID number of the monitoring 

system in which each sorbent trap was 

used to collect Hg; 

(ii) The unique identification number 

of each sorbent trap; 

(iii) The beginning and ending dates 

and hours of the data collection period 

for each sorbent trap; 

(iv) The average Hg concentration (in 

μg/dscm) for the data collection period; 

(v) Information documenting the 

results of the required leak checks; 

(vi) The analysis of the Hg collected 

by each sorbent trap; and 

(vii) Information documenting the 

results of the other applicable quality 

control procedures in § 75.15 and in 

appendices B and K to this part.

* * * * *

(c) Except as otherwise provided in 

§ 75.58(b)(3)(i), units with add-on SO2

or NOX emission controls following the 

provisions of § 75.34(a)(1) or (a)(2), and 

for units with add-on Hg emission 

controls, the owner or operator shall 

keep the following records on-site in the 

quality assurance/quality control plan 

required by section 1 of appendix B to 

this part: * * *

* * * * *

■ 34. Part 75 is amended by adding 

Subpart I, to read as follows:

Subpart I—Hg Mass Emission Provisions 

Sec. 

75.80 General provisions. 

75.81 Monitoring of Hg mass emissions and 

heat input at the unit level. 

75.82 Monitoring of Hg mass emissions and 

heat input at common and multiple 

stacks. 

75.83 Calculation of Hg mass emissions and 

heat input rate. 

75.84 Recordkeeping and reporting.

Subpart I—Hg Mass Emission 

Provisions

§ 75.80 General provisions. 

(a) Applicability. The owner or 

operator of a unit shall comply with the 

requirements of this subpart to the 

extent that compliance is required by an 

applicable State or Federal Hg mass 

emission reduction program that 

incorporates by reference, or otherwise 

adopts the provisions of, this subpart. 

(1) For purposes of this subpart, the 

term ‘‘affected unit’’ shall mean any 

coal-fired unit (as defined in § 72.2 of 

this chapter) that is subject to a State or 

Federal Hg mass emission reduction 

program requiring compliance with this 

subpart. The term ‘‘non-affected unit’’

shall mean any unit that is not subject 

to such a program, the term ‘‘permitting 

authority’’ shall mean the permitting 

authority under an applicable State or 

Federal Hg mass emission reduction 

program that adopts the requirements of 

this subpart, and the term ‘‘designated 

representative’’ shall mean the 

responsible party under the applicable 

State or Federal Hg mass emission 

reduction program that adopts the 

requirements of this subpart.

(2) In addition, the provisions of 

subparts A, C, D, E, F, and G and 

appendices A through G of this part 

applicable to Hg concentration, flow 

rate, moisture, diluent gas 

concentration, and heat input, as set 

forth and referenced in this subpart, 

shall apply to the owner or operator of 

a unit required to meet the requirements 

of this subpart by a State or Federal Hg 

mass emission reduction program. The 

requirements of this part for SO2, NOX, 

CO2 and opacity monitoring, 

recordkeeping and reporting do not 

apply to units that are subject only to a 

State or Federal Hg mass emission 

reduction program that adopts the 

requirements of this subpart, but are not 

affected units under the Acid Rain 

Program or under a State or Federal 

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28685

NOX mass emission reduction program 

that adopts the requirements of subpart 

H of this part. 

(b) Compliance dates. The owner or 

operator of an affected unit shall meet 

the compliance deadlines established by 

an applicable State or Federal Hg mass 

emission reduction program that adopts 

the requirements of this subpart. 

(c) Prohibitions. (1) No owner or 

operator of an affected unit or a nonaffected unit under § 75.82(b)(2)(ii) shall 

use any alternative monitoring system, 

alternative reference method, or any 

other alternative for the required 

continuous emission monitoring system 

without having obtained prior written 

approval in accordance with paragraph 

(h) of this section. 

(2) No owner or operator of an 

affected unit or a non-affected unit 

under § 75.82(b)(2)(ii) shall operate the 

unit so as to discharge, or allow to be 

discharged emissions of Hg to the 

atmosphere without accounting for all 

such emissions in accordance with the 

applicable provisions of this part. 

(3) No owner or operator of an 

affected unit or a non-affected unit 

under § 75.82(b)(2)(ii) shall disrupt the 

continuous emission monitoring system, 

any portion thereof, or any other 

approved emission monitoring method, 

and thereby avoid monitoring and 

recording Hg mass emissions discharged 

into the atmosphere, except for periods 

of recertification or periods when 

calibration, quality assurance testing, or 

maintenance is performed in accordance 

with the provisions of this part 

applicable to monitoring systems under 

§ 75.81. 

(4) No owner or operator of an 

affected unit or a non-affected unit 

under § 75.82(b)(2)(ii) shall retire or 

permanently discontinue use of the 

continuous emission monitoring system, 

any component thereof, or any other 

approved emission monitoring system 

under this part, except under any one of 

the following circumstances:

(i) During the period that the unit is 

covered by a retired unit exemption that 

is in effect under the State or Federal Hg 

mass emission reduction program that 

adopts the requirements of this subpart; 

or 

(ii) The owner or operator is 

monitoring Hg mass emissions from the 

affected unit with another certified 

monitoring system approved, in 

accordance with the provisions of 

paragraph (d) of this section; or 

(iii) The designated representative 

submits notification of the date of 

certification testing of a replacement 

monitoring system in accordance with 

§ 75.61. 

(d) Initial certification and 

recertification procedures. (1) The 

owner or operator of an affected unit 

that is subject to the Acid Rain Program 

or to a State or Federal NOX mass 

emission reduction program that adopts 

the requirements of subpart H of this 

part shall comply with the applicable 

initial certification and recertification 

procedures in § 75.20 and § 75.70(d), 

except that the owner or operator shall 

meet any additional requirements for Hg 

concentration monitoring systems, 

sorbent trap monitoring systems (as 

defined in § 72.2 of this chapter), flow 

monitors, CO2 monitors, O2 monitors, or 

moisture monitors, as set forth under 

§ 75.81, under the common stack 

provisions in § 75.82, or under an 

applicable State or Federal Hg mass 

emission reduction program that adopts 

the requirements of this subpart. 

(2) The owner or operator of an 

affected unit that is not subject to the 

Acid Rain Program or to a State or 

Federal NOX mass emission reduction 

program that adopts the requirements of 

subpart H of this part shall comply with 

the initial certification and 

recertification procedures established by 

an applicable State or Federal Hg mass 

emission reduction program that adopts 

the requirements of this subpart. 

(e) Quality assurance and quality 

control requirements. For units that use 

continuous emission monitoring 

systems to account for Hg mass 

emissions, the owner or operator shall 

meet the applicable quality assurance 

and quality control requirements in 

§ 75.21 and appendix B to this part for 

the flow monitoring systems, Hg 

concentration monitoring systems, 

moisture monitoring systems, and 

diluent monitors required under § 75.81. 

Units using sorbent trap monitoring 

systems shall meet the applicable 

quality assurance requirements in 

§ 75.15, appendix K to this part, and 

sections 1.5 and 2.3 of appendix B to 

this part. 

(f) Missing data procedures. Except as 

provided in § 75.38(b) and paragraph (g) 

of this section, the owner or operator 

shall provide substitute data from 

monitoring systems required under 

§ 75.81 for each affected unit as follows:

(1) For an owner or operator using an 

Hg concentration monitoring system, 

substitute for missing data in 

accordance with the applicable missing 

data procedures in §§ 75.31 through 

75.38 whenever the unit combusts fuel 

and: 

(i) A valid, quality-assured hour of Hg 

concentration data (in μg/scm) has not 

been measured and recorded, either by 

a certified Hg concentration monitoring 

system, by an appropriate EPA reference 

method under § 75.22, or by an 

approved alternative monitoring method 

under subpart E of this part; or 

(ii) A valid, quality-assured hour of 

flow rate data (in scfh) has not been 

measured and recorded for a unit either 

by a certified flow monitor, by an 

appropriate EPA reference method 

under § 75.22, or by an approved 

alternative monitoring system under 

subpart E of this part; or 

(iii) A valid, quality-assured hour of 

moisture data (in percent H2O) has not 

been measured or recorded for an 

affected unit, either by a certified 

moisture monitoring system, by an 

appropriate EPA reference method 

under § 75.22, or an approved 

alternative monitoring method under 

subpart E of this part. This requirement 

does not apply when a default percent 

moisture value, as provided in 

§ 75.11(b) or § 75.12(b), is used to 

account for the hourly moisture content 

of the stack gas, or when correction of 

the Hg concentration for moisture is not 

necessary; or 

(iv) A valid, quality-assured hour of 

heat input rate data (in MMBtu/hr) has 

not been measured and recorded for a 

unit, either by certified flow rate and 

diluent (CO2 or O2) monitors, by 

appropriate EPA reference methods 

under § 75.22, or by approved 

alternative monitoring systems under 

subpart E of this part, where heat input 

is required for allocating allowances 

under the applicable State or Federal Hg 

mass emission reduction program that 

adopts the requirements of this subpart. 

(2) For an owner or operator using a 

sorbent trap monitoring system to 

quantify Hg mass emissions, substitute 

for missing data in accordance with the 

missing data procedures in § 75.39. 

(g) Reporting data prior to initial 

certification. If, by the applicable 

compliance date under the State or 

Federal Hg mass emission reduction 

program that adopts the requirements of 

this subpart, the owner or operator of an 

affected unit has not successfully 

completed all required certification tests 

for any monitoring system(s), he or she 

shall determine, record and report 

hourly data prior to initial certification 

using one of the following procedures, 

for the monitoring system(s) that are 

uncertified: 

(1) For Hg concentration and flow 

monitoring systems, report the 

maximum potential concentration of Hg 

as defined in section 2.1.7 of appendix 

A to this part and the maximum 

potential flow rate, as defined in section 

2.1.4.1 of appendix A to this part; or

(2) For any unit, report data from the 

reference methods under § 75.22; or 

28686 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

(3) For any unit that is required to 

report heat input for purposes of 

allocating allowances, report (as 

applicable) the maximum potential flow 

rate, as defined in section 2.1.4.1 of 

appendix A to this part, the maximum 

potential CO2 concentration, as defined 

in section 2.1.3.1 of appendix A to this 

part, the minimum potential O2

concentration, as defined in section 

2.1.3.2 of appendix A to this part, and 

the minimum potential percent 

moisture, as defined in section 2.1.5 of 

appendix A to this part. 

(h) Petitions. (1) The designated 

representative of an affected unit that is 

also subject to the Acid Rain Program 

may submit a petition to the 

Administrator requesting an alternative 

to any requirement of this subpart. Such 

a petition shall meet the requirements of 

§ 75.66 and any additional requirements 

established by the applicable State or 

Federal Hg mass emission reduction 

program that adopts the requirements of 

this subpart. Use of an alternative to any 

requirement of this subpart is in 

accordance with this subpart and with 

such State or Federal Hg mass emission 

reduction program only to the extent 

that the petition is approved in writing 

by the Administrator, in consultation 

with the permitting authority. 

(2) Notwithstanding paragraph (h)(1) 

of this section, petitions requesting an 

alternative to a requirement concerning 

any additional CEMS required solely to 

meet the common stack provisions of 

§ 75.82 shall be submitted to the 

permitting authority and the 

Administrator and shall be governed by 

paragraph (h)(3) of this section. Such a 

petition shall meet the requirements of 

§ 75.66 and any additional requirements 

established by an applicable State or 

Federal Hg mass emission reduction 

program that adopts the requirements of 

this subpart. 

(3) The designated representative of 

an affected unit that is not subject to the 

Acid Rain Program may submit a 

petition to the permitting authority and 

the Administrator requesting an 

alternative to any requirement of this 

subpart. Such a petition shall meet the 

requirements of § 75.66 and any 

additional requirements established by 

the applicable State or Federal Hg mass 

emission reduction program that adopts 

the requirements of this subpart. Use of 

an alternative to any requirement of this 

subpart is in accordance with this 

subpart only to the extent that it is 

approved in writing by the 

Administrator, in consultation with the 

permitting authority.

§ 75.81 Monitoring of Hg mass emissions 

and heat input at the unit level. 

The owner or operator of the affected 

coal-fired unit shall either: 

(a) Meet the general operating 

requirements in § 75.10 for the 

following continuous emission monitors 

(except as provided in accordance with 

subpart E of this part): 

(1) A Hg concentration monitoring 

system (as defined in § 72.2 of this 

chapter) or a sorbent trap monitoring 

system (as defined in § 72.2 of this 

chapter) to measure Hg concentration; 

and 

(2) A flow monitoring system; and 

(3) A continuous moisture monitoring 

system (if correction of Hg 

concentration for moisture is required), 

as described in § 75.11(b) or § 75.12(b). 

Alternatively, the owner or operator 

may use the appropriate fuel-specific 

default moisture value provided in 

§ 75.11 or § 75.12, or a site-specific 

moisture value approved by petition 

under § 75.66; and 

(4) If heat input is required to be 

reported under the applicable State or 

Federal Hg mass emission reduction 

program that adopts the requirements of 

this subpart, the owner or operator also 

must meet the general operating 

requirements for a flow monitoring 

system and an O2 or CO2 monitor to 

measure heat input rate; or 

(b) For an affected unit that emits 464 

ounces (29 lb) of Hg per year or less, use 

the following excepted monitoring 

methodology. To implement this 

methodology for a qualifying unit, the 

owner or operator shall meet the general 

operating requirements in § 75.10 for the 

continuous emission monitors described 

in paragraphs (a)(2) and (a)(4) of this 

section, and perform Hg emission 

testing for initial certification and ongoing quality-assurance, as described in 

paragraphs (c) through (e) of this 

section. 

(c) To determine whether an affected 

unit is eligible to use the monitoring 

provisions in paragraph (b) of this 

section: 

(1) The owner or operator must 

perform Hg emission testing prior to the 

compliance date in § 75.80(b), to 

determine the Hg concentration (i.e., 

total vapor phase Hg) in the effluent. 

The testing shall be performed using 

one of the Hg reference methods listed 

in § 75.22, and shall consist of a 

minimum of 3 runs at the normal unit 

operating load. The minimum time per 

run shall be 1 hour if an instrumental 

reference method is used. If the Ontario 

Hydro Method is used, the test runs 

must be long enough to ensure that 

sufficient Hg is collected to analyze. If 

the unit is equipped with flue gas 

desulfurization or add-on Hg emission 

controls, the controls must be operating 

normally during the testing, and, for the 

purpose of establishing proper operation 

of the controls, the owner or operator 

shall record parametric data or SO2

concentration data in accordance with 

§ 75.58(b)(3)(i). 

(2) Based on the results of the 

emission testing, Equation 1 of this 

section shall be used to provide a 

conservative estimate of the annual Hg 

mass emissions from the unit:

Where:

E = Estimated annual Hg mass 

emissions from the affected unit, 

(ounces/year) 

K = Units conversion constant, 9.978 ×

10¥10 oz-scm/μg-scf 

8760 = Number of hours in a year 

CHg = The highest Hg concentration (μg/

scm) from any of the test runs or 

0.50 μg/scm, whichever is greater 

Qmax = Maximum potential flow rate, 

determined according to section 

2.1.4.1 of appendix A to this part, 

(scfh)

Equation 1 of this section assumes that 

the unit operates year-round at its 

maximum potential flow rate. Also, note 

that if the highest Hg concentration 

measured in any test run is less than 

0.50 μg/scm, a default value of 0.50 μg/

scm must be used in the calculations. 

(3) If the estimated annual Hg mass 

emissions from paragraph (c)(2) of this 

section are 464 ounces per year or less, 

then the unit is eligible to use the 

monitoring provisions in paragraph (b) 

of this section, and continuous 

monitoring of the Hg concentration is 

not required (except as otherwise 

provided in paragraphs (e) and (f) of this 

section). 

(d) If the owner or operator of an 

eligible unit under paragraph (c)(3) of 

this section elects not to continuously 

monitor Hg concentration, then the 

following requirements must be met: 

(1) The results of the Hg emission 

testing performed under paragraph (c) of 

this section shall be submitted as a 

certification application to the 

Administrator and to the permitting 

authority, no later than 45 days after the 

testing is completed. The calculations 

demonstrating that the unit emits 464 

ounces (or less) per year of Hg shall also 

be provided, and the default Hg 

concentration that will be used for 

reporting under § 75.84 shall be 

specified in both the electronic and hard 

copy portions of the monitoring plan for 

the unit. The methodology is considered 

to be provisionally certified as of the 

date and hour of completion of the Hg 

emission testing.

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28687

E KC Q = 8760 Hg max (Eq. 1)

(2) Following initial certification, the 

same default Hg concentration value 

that was used to estimate the unit’s 

annual Hg mass emissions under 

paragraph (c) of this section shall be 

reported for each unit operating hour, 

except as otherwise provided in 

paragraph (d)(6) of this section. The 

default Hg concentration value shall be 

updated as appropriate, according to 

paragraph (d)(5) of this section. 

(3) The hourly Hg mass emissions 

shall be calculated according to section 

9.1.3 in appendix F to this part. 

(4) The Hg emission testing described 

in paragraph (c) of this section shall be 

repeated periodically, for the purposes 

of quality-assurance, as follows: 

(i) If the results of the certification 

testing under paragraph (c) of this 

section show that the unit emits 144 

ounces (9 lb) of Hg per year or less, the 

first retest is required by the end of the 

fourth QA operating quarter (as defined 

in § 72.2 of this chapter) following the 

calendar quarter of the certification 

testing; or 

(ii) If the results of the certification 

testing under paragraph (c) of this 

section show that the unit emits more 

than 144 ounces of Hg per year, but less 

than or equal to 464 ounces per year, the 

first retest is required by the end of the 

second QA operating quarter (as defined 

in § 72.2 of this chapter) following the 

calendar quarter of the certification 

testing; and 

(iii) Thereafter, retesting shall be 

required either semiannually or 

annually (i.e., by the end of the second 

or fourth QA operating quarter 

following the quarter of the previous 

test), depending on the results of the 

previous test. To determine whether the 

next retest is due within two or four QA 

operating quarters, substitute the 

highest Hg concentration from the 

current test or 0.50 μg/scm (whichever 

is greater) into the equation in 

paragraph (c)(2) of this section. If the 

estimated annual Hg mass emissions 

exceeds 144 ounces, the next test is due 

within two QA operating quarters. If the 

estimated annual Hg mass emissions is 

144 ounces or less, the next test is due 

within four QA operating quarters. 

(5) The default Hg concentration used 

for reporting under § 75.84 shall be 

updated after each required retest. The 

updated value shall either be the highest 

Hg concentration measured in any of the 

test runs or 0.50 μg/scm, whichever is 

greater. The updated default value shall 

be applied beginning with the first unit 

operating hour after completion of the 

retest. 

(6) If the unit is equipped with a flue 

gas desulfurization system or add-on Hg 

controls, the owner or operator shall 

record the information required under 

§ 75.58(b)(3) for each unit operating 

hour, to document proper operation of 

the emission controls. For any operating 

hour in which this documentation is 

unavailable, the maximum potential Hg 

concentration, as defined in section 

2.1.7 of appendix A to this part, shall be 

reported. 

(e) For units with common stack and 

multiple stack exhaust configurations, 

the use of the monitoring methodology 

described in paragraphs (b) through (d) 

of this section is restricted as follows: 

(1) The methodology may not be used 

for reporting Hg mass emissions at a 

common stack unless all of the units 

using the common stack are affected 

units and each individual unit is 

demonstrated to emit 464 ounces of Hg 

per year, or less, in accordance with 

paragraphs (c) and (d) of this section. If 

these conditions are met, the default Hg 

concentration used for reporting at the 

common stack shall either be the 

highest value obtained in any test run 

for any of the units serving the common 

stack or 0.50 μg/scm, whichever is 

greater.

(2) For units with multiple stack or 

duct configurations, Hg emission testing 

must be performed separately on each 

stack or duct, and the sum of the 

estimated annual Hg mass emissions 

from the stacks or ducts must not 

exceed 464 ounces of Hg per year. For 

reporting purposes, the default Hg 

concentration used for each stack or 

duct shall either be the highest value 

obtained in any test run for that stack or 

0.50 μg/scm, whichever is greater. 

(3) For units with a main stack and 

bypass stack configuration, Hg emission 

testing shall be performed only on the 

main stack. For reporting purposes, the 

default Hg concentration used for the 

main stack shall either be the highest 

value obtained in any test run for that 

stack or 0.50 μg/scm, whichever is 

greater. Whenever the main stack is 

bypassed, the maximum potential Hg 

concentration, as defined in section 

2.1.7 of appendix A to this part, shall be 

reported. 

(f) At the end of each calendar year, 

if the cumulative annual Hg mass 

emissions from an affected unit have 

exceeded 464 ounces, then the owner 

shall install, certify, operate, and 

maintain a Hg concentration monitoring 

system or a sorbent trap monitoring 

system no later than 180 days after the 

end of the calendar year in which the 

annual Hg mass emissions exceeded 464 

ounces. For common stack and multiple 

stack configurations, installation and 

certification of a Hg concentration or 

sorbent trap monitoring system on each 

stack (except for bypass stacks) is 

likewise required within 180 days after 

the end of the calendar year, if: 

(1) The annual Hg mass emissions at 

the common stack have exceeded 464 

ounces times the number of affected 

units using the common stack; or 

(2) The sum of the annual Hg mass 

emissions from all of the multiple stacks 

or ducts has exceeded 464 ounces; or 

(3) The sum of the annual Hg mass 

emissions from the main and bypass 

stacks has exceeded 464 ounces. 

(g) For an affected unit that is using 

a Hg concentration CEMS or a sorbent 

trap system under § 75.81(a) to 

continuously monitor the Hg mass 

emissions, the owner or operator may 

switch to the methodology in § 75.81(b), 

provided that the applicable conditions 

in paragraphs (c) through (f) of this 

section are met.

§ 75.82 Monitoring of Hg mass emissions 

and heat input at common and multiple 

stacks. 

(a) Unit utilizing common stack with 

other affected unit(s). When an affected 

unit utilizes a common stack with one 

or more affected units, but no nonaffected units, the owner or operator 

shall either: 

(1) Install, certify, operate, and 

maintain the monitoring systems 

described in § 75.81(a) at the common 

stack, record the combined Hg mass 

emissions for the units exhausting to the 

common stack. Alternatively, if, in 

accordance with § 75.81(e), each of the 

units using the common stack is 

demonstrated to emit less than 464 

ounces of Hg per year, the owner or 

operator may install, certify, operate and 

maintain the monitoring systems and 

perform the Hg emission testing 

described under § 75.81(b). If reporting 

of the unit heat input rate is required, 

determine the hourly unit heat input 

rates either by: 

(i) Apportioning the common stack 

heat input rate to the individual units 

according to the procedures in 

§ 75.16(e)(3); or 

(ii) Installing, certifying, operating, 

and maintaining a flow monitoring 

system and diluent monitor in the duct 

to the common stack from each unit; or 

(2) Install, certify, operate, and 

maintain the monitoring systems and (if 

applicable) perform the Hg emission 

testing described in § 75.81(a) or 

§ 75.81(b) in the duct to the common 

stack from each unit. 

(b) Unit utilizing common stack with 

nonaffected unit(s). When one or more 

affected units utilizes a common stack 


ER18my05.022</GPH>
28688 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

with one or more nonaffected units, the 

owner or operator shall either: 

(1) Install, certify, operate, and 

maintain the monitoring systems and (if 

applicable) perform the Hg emission 

testing described in § 75.81(a) or 

§ 75.81(b) in the duct to the common 

stack from each affected unit; or 

(2) Install, certify, operate, and 

maintain the monitoring systems 

described in § 75.81(a) in the common 

stack; and

(i) Install, certify, operate, and 

maintain the monitoring systems and (if 

applicable) perform the Hg emission 

testing described in § 75.81(a) or 

§ 75.81(b) in the duct to the common 

stack from each non-affected unit. The 

designated representative shall submit a 

petition to the permitting authority and 

the Administrator to allow a method of 

calculating and reporting the Hg mass 

emissions from the affected units as the 

difference between Hg mass emissions 

measured in the common stack and Hg 

mass emissions measured in the ducts 

of the non-affected units, not to be 

reported as an hourly value less than 

zero. The permitting authority and the 

Administrator may approve such a 

method whenever the designated 

representative demonstrates, to the 

satisfaction of the permitting authority 

and the Administrator, that the method 

ensures that the Hg mass emissions from 

the affected units are not 

underestimated; or 

(ii) Count the combined emissions 

measured at the common stack as the Hg 

mass emissions for the affected units, 

for recordkeeping and compliance 

purposes, in accordance with paragraph 

(a) of this section; or 

(iii) Submit a petition to the 

permitting authority and the 

Administrator to allow use of a method 

for apportioning Hg mass emissions 

measured in the common stack to each 

of the units using the common stack and 

for reporting the Hg mass emissions. 

The permitting authority and the 

Administrator may approve such a 

method whenever the designated 

representative demonstrates, to the 

satisfaction of the permitting authority 

and the Administrator, that the method 

ensures that the Hg mass emissions from 

the affected units are not 

underestimated. 

(c) Unit with a main stack and a 

bypass stack. Whenever any portion of 

the flue gases from an affected unit can 

be routed through a bypass stack to 

avoid the Hg monitoring system(s) 

installed on the main stack, the owner 

and operator shall either: 

(1) Install, certify, operate, and 

maintain the monitoring systems 

described in § 75.81(a) on both the main 

stack and the bypass stack and calculate 

Hg mass emissions for the unit as the 

sum of the Hg mass emissions measured 

at the two stacks; 

(2) Install, certify, operate, and 

maintain the monitoring systems 

described in § 75.81(a) at the main stack 

and measure Hg mass emissions at the 

bypass stack using the appropriate 

reference methods in § 75.22(b). 

Calculate Hg mass emissions for the unit 

as the sum of the emissions recorded by 

the installed monitoring systems on the 

main stack and the emissions measured 

by the reference method monitoring 

systems; or 

(3) Install, certify, operate, and 

maintain the monitoring systems and (if 

applicable) perform the Hg emission 

testing described in § 75.81(a) or 

§ 75.81(b) only on the main stack. If this 

option is chosen, it is not necessary to 

designate the exhaust configuration as a 

multiple stack configuration in the 

monitoring plan required under § 75.53, 

since only the main stack is monitored. 

For each unit operating hour in which 

the bypass stack is used, report, as 

applicable, the maximum potential Hg 

concentration (as defined in section 

2.1.7 of appendix A to this part), and the 

appropriate substitute data values for 

flow rate, CO2 concentration, O2

concentration, and moisture (as 

applicable), in accordance with the 

missing data procedures of §§ 75.31 

through 75.37. 

(d) Unit with multiple stack or duct 

configuration. When the flue gases from 

an affected unit discharge to the 

atmosphere through more than one 

stack, or when the flue gases from an 

affected unit utilize two or more ducts 

feeding into a single stack and the 

owner or operator chooses to monitor in 

the ducts rather than in the stack, the 

owner or operator shall either: 

(1) Install, certify, operate, and 

maintain the monitoring systems and (if 

applicable) perform the Hg emission 

testing described in § 75.81(a) or 

§ 75.81(b) in each of the multiple stacks 

and determine Hg mass emissions from 

the affected unit as the sum of the Hg 

mass emissions recorded for each stack. 

If another unit also exhausts flue gases 

into one of the monitored stacks, the 

owner or operator shall comply with the 

applicable requirements of paragraphs 

(a) and (b) of this section, in order to 

properly determine the Hg mass 

emissions from the units using that 

stack; or

(2) Install, certify, operate, and 

maintain the monitoring systems and (if 

applicable) perform the Hg emission 

testing described in § 75.81(a) or 

§ 75.81(b) in each of the ducts that feed 

into the stack, and determine Hg mass 

emissions from the affected unit using 

the sum of the Hg mass emissions 

measured at each duct, except that 

where another unit also exhausts flue 

gases to one or more of the stacks, the 

owner or operator shall also comply 

with the applicable requirements of 

paragraphs (a) and (b) of this section to 

determine and record Hg mass 

emissions from the units using that 

stack.

§ 75.83 Calculation of Hg mass emissions 

and heat input rate. 

The owner or operator shall calculate 

Hg mass emissions and heat input rate 

in accordance with the procedures in 

sections 9.1 through 9.3 of appendix F 

to this part.

§ 75.84 Recordkeeping and reporting. 

(a) General recordkeeping provisions.

The owner or operator of any affected 

unit shall maintain for each affected 

unit and each non-affected unit under 

§ 75.82(b)(2)(ii) a file of all 

measurements, data, reports, and other 

information required by this part at the 

source in a form suitable for inspection 

for at least 3 years from the date of each 

record. Except for the certification data 

required in § 75.57(a)(4) and the initial 

submission of the monitoring plan 

required in § 75.57(a)(5), the data shall 

be collected beginning with the earlier 

of the date of provisional certification or 

the compliance deadline in § 75.80(b). 

The certification data required in 

§ 75.57(a)(4) shall be collected 

beginning with the date of the first 

certification test performed. The file 

shall contain the following information: 

(1) The information required in 

§§ 75.57(a)(2), (a)(4), (a)(5), (a)(6), (b), 

(c)(2), (g) (if applicable), (h), and (i) or 

(j) (as applicable). For the information in 

§ 75.57(a)(2), replace the phrase ‘‘the 

deadline in § 75.4(a), (b) or (c)’’ with the 

phrase ‘‘the applicable certification 

deadline under the State or Federal Hg 

mass emission reduction program’’; 

(2) The information required in 

§ 75.58(b)(3), for units with flue gas 

desulfurization systems or add-on Hg 

emission controls; 

(3) For affected units using Hg CEMS 

or sorbent trap monitoring systems, for 

each hour when the unit is operating, 

record the Hg mass emissions, 

calculated in accordance with section 9 

of appendix F to this part. 

(4) Heat input and Hg methodologies 

for the hour; and 

(5) Formulas from monitoring plan for 

total Hg mass emissions and heat input 

rate (if applicable);

(b) Certification, quality assurance 

and quality control record provisions.

The owner or operator of any affected 

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28689

unit shall record the applicable 

information in § 75.59 for each affected 

unit or group of units monitored at a 

common stack and each non-affected 

unit under § 75.82(b)(2)(ii). 

(c) Monitoring plan recordkeeping 

provisions. (1) General provisions. The 

owner or operator of an affected unit 

shall prepare and maintain a monitoring 

plan for each affected unit or group of 

units monitored at a common stack and 

each non-affected unit under 

§ 75.82(b)(2)(ii). The monitoring plan 

shall contain sufficient information on 

the continuous monitoring systems and 

the use of data derived from these 

systems to demonstrate that all the 

unit’s Hg emissions are monitored and 

reported. 

(2) Updates. Whenever the owner or 

operator makes a replacement, 

modification, or change in a certified 

continuous monitoring system or 

alternative monitoring system under 

subpart E of this part, including a 

change in the automated data 

acquisition and handling system or in 

the flue gas handling system, that affects 

information reported in the monitoring 

plan (e.g., a change to a serial number 

for a component of a monitoring 

system), then the owner or operator 

shall update the monitoring plan. 

(3) Contents of the monitoring plan.

Each monitoring plan shall contain the 

information in § 75.53(e)(1) in electronic 

format and the information in 

§ 75.53(e)(2) in hardcopy format. 

(d) General reporting provisions. (1) 

The designated representative for an 

affected unit shall comply with all 

reporting requirements in this section 

and with any additional requirements 

set forth in an applicable State or 

Federal Hg mass emission reduction 

program that adopts the requirements of 

this subpart. 

(2) The designated representative for 

an affected unit shall submit the 

following for each affected unit or group 

of units monitored at a common stack 

and each non-affected unit under 

§ 75.82(b)(2)(ii): 

(i) Initial certification and 

recertification applications in 

accordance with § 75.80(d); 

(ii) Monitoring plans in accordance 

with paragraph (e) of this section; and 

(iii) Quarterly reports in accordance 

with paragraph (f) of this section. 

(3) Other petitions and 

communications. The designated 

representative for an affected unit shall 

submit petitions, correspondence, 

application forms, and petition-related 

test results in accordance with the 

provisions in § 75.80(h). 

(4) Quality assurance RATA reports. If 

requested by the permitting authority, 

the designated representative of an 

affected unit shall submit the quality 

assurance RATA report for each affected 

unit or group of units monitored at a 

common stack and each non-affected 

unit under § 75.82(b)(2)(ii) by the later 

of 45 days after completing a quality 

assurance RATA according to section 

2.3 of appendix B to this part or 15 days 

of receiving the request. The designated 

representative shall report the hardcopy 

information required by § 75.59(a)(9) to 

the permitting authority. 

(5) Notifications. The designated 

representative for an affected unit shall 

submit written notice to the permitting 

authority according to the provisions in 

§ 75.61 for each affected unit or group 

of units monitored at a common stack 

and each non-affected unit under 

§ 75.82(b)(2)(ii). 

(e) Monitoring plan reporting. (1) 

Electronic submission. The designated 

representative for an affected unit shall 

submit to the Administrator a complete, 

electronic, up-to-date monitoring plan 

file for each affected unit or group of 

units monitored at a common stack and 

each non-affected unit under 

§ 75.82(b)(2)(ii), as follows: No later 

than 45 days prior to the 

commencement of initial certification 

testing; at the time of a certification or 

recertification application submission; 

and whenever an update of the 

electronic monitoring plan is required, 

either under § 75.53 or elsewhere in this 

part.

(2) Hardcopy submission. The 

designated representative of an affected 

unit shall submit all of the hardcopy 

information required under § 75.53, for 

each affected unit or group of units 

monitored at a common stack and each 

non-affected unit under § 75.82(b)(2)(ii), 

to the permitting authority prior to 

initial certification. Thereafter, the 

designated representative shall submit 

hardcopy information only if that 

portion of the monitoring plan is 

revised. The designated representative 

shall submit the required hardcopy 

information as follows: no later than 45 

days prior to the commencement of 

initial certification testing; with any 

certification or recertification 

application, if a hardcopy monitoring 

plan change is associated with the 

recertification event; and within 30 days 

of any other event with which a 

hardcopy monitoring plan change is 

associated, pursuant to § 75.53(b). 

Electronic submittal of all monitoring 

plan information, including hardcopy 

portions, is permissible provided that a 

paper copy of the hardcopy portions can 

be furnished upon request. 

(f) Quarterly reports. (1) Electronic 

submission. Electronic quarterly reports 

shall be submitted, beginning with the 

calendar quarter containing the 

compliance date in § 75.80(b), unless 

otherwise specified in the final rule 

implementing a State or Federal Hg 

mass emissions reduction program that 

adopts the requirements of this subpart. 

The designated representative for an 

affected unit shall report the data and 

information in this paragraph (f)(1) and 

the applicable compliance certification 

information in paragraph (f)(2) of this 

section to the Administrator quarterly. 

Each electronic report must be 

submitted to the Administrator within 

30 days following the end of each 

calendar quarter. Each electronic report 

shall include the date of report 

generation and the following 

information for each affected unit or 

group of units monitored at a common 

stack. 

(i) The facility information in 

§ 75.64(a)(1); and 

(ii) The information and hourly data 

required in paragraph (a) of this section, 

except for: 

(A) Descriptions of adjustments, 

corrective action, and maintenance; 

(B) Information which is incompatible 

with electronic reporting (e.g., field data 

sheets, lab analyses, quality control 

plan); 

(C) For units with flue gas 

desulfurization systems or with add-on 

Hg emission controls, the parametric 

information in § 75.58(b)(3); 

(D) Information required by § 75.57(h) 

concerning the causes of any missing 

data periods and the actions taken to 

cure such causes; 

(E) Hardcopy monitoring plan 

information required by § 75.53 and 

hardcopy test data and results required 

by § 75.59; 

(F) Records of flow polynomial 

equations and numerical values 

required by § 75.59(a)(5)(vi); 

(G) Stratification test results required 

as part of the RATA supplementary 

records under § 75.59(a)(7); 

(H) Data and results of RATAs that are 

aborted or invalidated due to problems 

with the reference method or 

operational problems with the unit and 

data and results of linearity checks that 

are aborted or invalidated due to 

operational problems with the unit; 

(I) Supplementary RATA information 

required under § 75.59(a)(7)(i) through 

§ 75.59(a)(14), as applicable, except that: 

The data under § 75.59(a)(7)(ii)(A) 

through (T) and the data under 

§ 75.59(a)(7)(iii)(A) through (M) shall, as 

applicable, be reported for flow RATAs 

in which angular compensation 

(measurement of pitch and/or yaw 

angles) is used and for flow RATAs in 

which a site-specific wall effects 

28690 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

adjustment factor is determined by 

direct measurement; and the data under 

§ 75.59(a)(7)(ii)(T) shall be reported for 

all flow RATAs in which a default wall 

effects adjustment factor is applied; 

(J) For units using sorbent trap 

monitoring systems, the hourly dry gas 

meter readings taken between the initial 

and final meter readings for the data 

collection period; and 

(iii) Ounces of Hg emitted during 

quarter and cumulative ounces of Hg 

emitted in the year-to-date (rounded to 

the nearest thousandth); and

(iv) Unit or stack operating hours for 

quarter, cumulative unit or stack 

operating hours for year-to-date; and 

(v) Reporting period heat input (if 

applicable) and cumulative, year-to-date 

heat input. 

(2) Compliance certification. (i) The 

designated representative shall certify 

that the monitoring plan information in 

each quarterly electronic report (i.e., 

component and system identification 

codes, formulas, etc.) represent current 

operating conditions for the affected 

unit(s) 

(ii) The designated representative 

shall submit and sign a compliance 

certification in support of each quarterly 

emissions monitoring report based on 

reasonable inquiry of those persons with 

primary responsibility for ensuring that 

all of the unit’s emissions are correctly 

and fully monitored. The certification 

shall state that: 

(A) The monitoring data submitted 

were recorded in accordance with the 

applicable requirements of this part, 

including the quality assurance 

procedures and specifications; and 

(B) With regard to a unit with an FGD 

system or with add-on Hg emission 

controls, that for all hours where data 

are substituted in accordance with 

§ 75.38(b), the add-on emission controls 

were operating within the range of 

parameters listed in the qualityassurance plan for the unit (or that 

quality-assured SO2 CEMS data were 

available to document proper operation 

of the emission controls), and that the 

substitute values do not systematically 

underestimate Hg emissions. 

(3) Additional reporting requirements.

The designated representative shall also 

comply with all of the quarterly 

reporting requirements in §§ 75.64(d), 

(f), and (g).

■ 35. Appendix A to part 75 is amended 

by revising the title of section 1.1 and 

revising the second sentence of section 

1.1 introductory text, to read as follows:

Appendix A to Part 75—Specifications and 

Test Procedures 

1. Installation and Measurement Location. 

1.1 Gas and Hg Monitors 

* * * Select a representative measurement 

point or path for the monitor probe(s) (or for 

the path from the transmitter to the receiver) 

such that the SO2, CO2, O2, and NOX

concentration monitoring system or NOXdiluent CEMS (NOX pollutant concentration 

monitor and diluent gas monitor), Hg 

concentration monitoring system, or sorbent 

trap monitoring system will pass the relative 

accuracy test (see section 6 of this appendix).

* * * * *

■ 36. Appendix A to part 75 is further 

amended by adding new sections 2.1.7 

through 2.1.7.4 and 2.2.3, to read as 

follows:

Appendix A to Part 75—Specification and 

Test Procedures 

2. Equipment Specifications.

* * * * *

2.1.7 Hg Monitors 

Determine the appropriate span and range 

value(s) for each Hg pollutant concentration 

monitor, so that all expected Hg 

concentrations can be determined accurately. 

2.1.7.1 Maximum Potential Concentration 

(a) The maximum potential concentration 

depends upon the type of coal combusted in 

the unit. For the initial MPC determination, 

there are three options: 

(1) Use one of the following default values: 

9 μg/scm for bituminous coal; 10 μg/scm for 

sub-bituminous coal; 16 μg/scm for lignite, 

and 1 μg/scm for waste coal, i.e., anthracite 

culm or bituminous gob. If different coals are 

blended, use the highest MPC for any fuel in 

the blend; or 

(2) You may base the MPC on the results 

of site-specific emission testing using the one 

of the Hg reference methods in § 75.22, if the 

unit does not have add-on Hg emission 

controls or a flue gas desulfurization system, 

or if you test upstream of these control 

devices. A minimum of 3 test runs are 

required, at the normal operating load. Use 

the highest total Hg concentration obtained 

in any of the tests as the MPC; or

(3) You may base the MPC on 720 or more 

hours of historical CEMS data or data from 

a sorbent trap monitoring system, if the unit 

does not have add-on Hg emission controls 

or a flue gas desulfurization system (or if the 

CEMS or sorbent trap system is located 

upstream of these control devices) and if the 

Hg CEMS or sorbent trap system has been 

tested for relative accuracy against one of the 

Hg reference methods in § 75.22 and has met 

a relative accuracy specification of 20.0% or 

less. 

(b) For the purposes of missing data 

substitution, the fuel-specific or site-specific 

MPC values defined in paragraph (a) of this 

section apply to units using sorbent trap 

monitoring systems. 

2.1.7.2 Maximum Expected Concentration 

For units with FGD systems that 

significantly reduce Hg emissions (including 

fluidized bed units that use limestone 

injection) and for units equipped with addon Hg emission controls (e.g., carbon 

injection), determine the maximum expected 

Hg concentration (MEC) during normal, 

stable operation of the unit and emission 

controls. To calculate the MEC, substitute the 

MPC value from section 2.1.7.1 of this 

appendix into Equation A–2 in section 

2.1.1.2 of this appendix. For units with addon Hg emission controls, base the percent 

removal efficiency on design engineering 

calculations. For units with FGD systems, use 

the best available estimate of the Hg removal 

efficiency of the FGD system. 

2.1.7.3 Span and Range Value(s) 

(a) For each Hg monitor, determine a high 

span value, by rounding the MPC value from 

section 2.1.7.1 of this appendix upward to 

the next highest multiple of 10 μg/scm. 

(b) For an affected unit equipped with an 

FGD system or a unit with add-on Hg 

emission controls, if the MEC value from 

section 2.1.7.2 of this appendix is less than 

20 percent of the high span value from 

paragraph (a) of this section, and if the high 

span value is 20 μg/scm or greater, define a 

second, low span value of 10 μg/scm. 

(c) If only a high span value is required, 

set the full-scale range of the Hg analyzer to 

be greater than or equal to the span value. 

(d) If two span values are required, you 

may either: 

(1) Use two separate (high and low) 

measurement scales, setting the range of each 

scale to be greater than or equal to the high 

or low span value, as appropriate; or 

(2) Quality-assure two segments of a single 

measurement scale. 

2.1.7.4 Adjustment of Span and Range 

For each affected unit or common stack, 

the owner or operator shall make a periodic 

evaluation of the MPC, MEC, span, and range 

values for each Hg monitor (at a minimum, 

an annual evaluation is required) and shall 

make any necessary span and range 

adjustments, with corresponding monitoring 

plan updates. Span and range adjustments 

may be required, for example, as a result of 

changes in the fuel supply, changes in the 

manner of operation of the unit, or 

installation or removal of emission controls. 

In implementing the provisions in 

paragraphs (a) and (b) of this section, data 

recorded during short-term, nonrepresentative process operating conditions 

(e.g., a trial burn of a different type of fuel) 

shall be excluded from consideration. The 

owner or operator shall keep the results of 

the most recent span and range evaluation 

on-site, in a format suitable for inspection. 

Make each required span or range adjustment 

no later than 45 days after the end of the 

quarter in which the need to adjust the span 

or range is identified, except that up to 90 

days after the end of that quarter may be 

taken to implement a span adjustment if the 

calibration gas concentrations currently being 

used for calibration error tests, system 

integrity checks, and linearity checks are 

unsuitable for use with the new span value 

and new calibration materials must be 

ordered. 

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28691

(a) The guidelines of section 2.1 of this 

appendix do not apply to Hg monitoring 

systems. 

(b) Whenever a full-scale range exceedance 

occurs during a quarter and is not caused by 

a monitor out-of-control period, proceed as 

follows: 

(1) For monitors with a single 

measurement scale, report 200 percent of the 

full-scale range as the hourly Hg 

concentration until the readings come back 

on-scale and if appropriate, make 

adjustments to the MPC, span, and range to 

prevent future full-scale exceedances; or

(2) For units with two separate 

measurement scales, if the low range is 

exceeded, no further action is required, 

provided that the high range is available and 

is not out-of-control or out-of-service for any 

reason. However, if the high range is not able 

to provide quality assured data at the time of 

the low range exceedance or at any time 

during the continuation of the exceedance, 

report the MPC until the readings return to 

the low range or until the high range is able 

to provide quality assured data (unless the 

reason that the high-scale range is not able 

to provide quality assured data is because the 

high-scale range has been exceeded; if the 

high-scale range is exceeded follow the 

procedures in paragraph (b)(1) of this 

section). 

(c) Whenever changes are made to the 

MPC, MEC, full-scale range, or span value of 

the Hg monitor, record and report (as 

applicable) the new full-scale range setting, 

the new MPC or MEC and calculations of the 

adjusted span value in an updated 

monitoring plan. The monitoring plan update 

shall be made in the quarter in which the 

changes become effective. In addition, record 

and report the adjusted span as part of the 

records for the daily calibration error test and 

linearity check specified by appendix B to 

this part. Whenever the span value is 

adjusted, use calibration gas concentrations 

that meet the requirements of section 5.1 of 

this appendix, based on the adjusted span 

value. When a span adjustment is so 

significant that the calibration gas 

concentrations currently being used for 

calibration error tests, system integrity 

checks and linearity checks are unsuitable for 

use with the new span value, then a 

diagnostic linearity or 3-level system 

integrity check using the new calibration gas 

concentrations must be performed and 

passed. Use the data validation procedures in 

§ 75.20(b)(3), beginning with the hour in 

which the span is changed. 

2.2 Design for Quality Control Testing

* * * * *

2.2.3 Mercury Monitors. 

Design and equip each mercury monitor to 

permit the introduction of known 

concentrations of elemental Hg and HgCl2

separately, at a point immediately preceding 

the sample extraction filtration system, such 

that the entire measurement system can be 

checked. If the Hg monitor does not have a 

converter, the HgCl2 injection capability is 

not required.

* * * * *

■ 37. Appendix A to part 75 is further 

amended by:

■ a. Adding a new paragraph (c) to 

section 3.1;

■ b. Adding a new paragraph (3) to 

section 3.2; and

■ c. Adding new sections 3.3.8 and 3.4.3.

The revisions and additions read as 

follows:

Appendix A to Part 75—Specifications and 

Test Procedures

* * * * *

3. Performance Specifications. 

3.1 Calibration Error

* * * * *

(c) The calibration error of a Hg 

concentration monitor shall not deviate from 

the reference value of either the zero or 

upscale calibration gas by more than 5.0 

percent of the span value, as calculated using 

Equation A–5 of this appendix. Alternatively, 

if the span value is 10 μg/scm, the calibration 

error test results are also acceptable if the 

absolute value of the difference between the 

monitor response value and the reference 

value, |R–A| in Equation A–5 of this 

appendix, is ≤ 1.0 μg/scm. 

3.2 Linearity Check

* * * * *

(3) For Hg monitors: 

(i) The error in linearity for each 

calibration gas concentration (low-,

mid-, and high-levels) shall not exceed or 

deviate from the reference value by more 

than 10.0 percent as calculated using 

equation A–4 of this appendix; or 

(ii) The absolute value of the difference 

between the average of the monitor response 

values and the average of the reference 

values, |R–A| in equation A–4 of this 

appendix, shall be less than or equal to 1.0 

μg/scm, whichever is less restrictive. 

(iii) For the 3-level system integrity check 

required under § 75.20(c)(1)(vi), the system 

measurement error shall not exceed 5.0 

percent of the span value at any of the three 

gas levels. 

3.3 Relative Accuracy

* * * * *

3.3.8 Relative Accuracy for Hg Monitoring 

Systems 

The relative accuracy of a Hg concentration 

monitoring system or a sorbent trap 

monitoring system shall not exceed 20.0 

percent. Alternatively, for affected units 

where the average of the reference method 

measurements of Hg concentration during the 

relative accuracy test audit is less than 5.0 

μg/scm, the test results are acceptable if the 

difference between the mean value of the 

monitor measurements and the reference 

method mean value does not exceed 1.0 μg/

scm, in cases where the relative accuracy 

specification of 20.0 percent is not achieved. 

3.4 Bias

* * * * *

3.4.3 Hg Monitoring Systems 

Mercury concentration monitoring systems 

and sorbent trap monitoring systems shall 

not be biased low as determined by the test 

procedure in section 7.6 of this appendix.

* * * * *

■ 38. Appendix A to part 75 is further 

amended by revising the second 

sentence in the first paragraph of the 

introductory text of section 4 and 

revising the second paragraph of the 

introductory text of section 4, to read as 

follows:

Appendix A to Part 75—Specifications and 

Test Procedures 

4. Data Acquisition and Handling Systems. 

* * * These systems also shall have the 

capability of interpreting and converting the 

individual output signals from an SO2

pollutant concentration monitor, a flow 

monitor, a CO2 monitor, an O2 monitor, a 

NOX pollutant concentration monitor, a NOXdiluent CEMS, a moisture monitoring system, 

a Hg concentration monitoring system, and a 

sorbent trap monitoring system, to produce a 

continuous readout of pollutant emission 

rates or pollutant mass emissions (as 

applicable) in the appropriate units (e.g., lb/

hr, lb/MMBtu, ounces/hr, tons/hr). 

Data acquisition and handling systems 

shall also compute and record monitor 

calibration error; any bias adjustments to 

SO2, NOX, and Hg pollutant concentration 

data, flow rate data, Hg emission rate data, 

or NOX emission rate data; and all missing 

data procedure statistics specified in subpart 

D of this part.

* * * * *

■ 39. Appendix A to part 75 is further 

amended by adding new section 5.1.9, to 

read as follows:

Appendix A to Part 75—Specifications and 

Test Procedures

* * * * *

5. Calibration Gas.

* * * * *

5.1.9 Mercury Standards. 

For 7-day calibration error tests of Hg 

concentration monitors and for daily 

calibration error tests of Hg monitors, either 

elemental Hg standards or a NIST-traceable 

source of oxidized Hg may be used. For 

linearity checks, elemental Hg standards 

shall be used. For 3-level and single-point 

system integrity checks under 

§ 75.20(c)(1)(vi), sections 6.2(g) and 6.3.1 of 

this appendix, and sections 2.1.1, 2.2.1 and 

2.6 of appendix B to this part, a NISTtraceable source of oxidized Hg shall be used. 

Alternatively, other NIST-traceable standards 

may be used for the required checks, subject 

to the approval of the Administrator.

* * * * *

■ 40. Appendix A to part 75 is further 

amended by:

■ a. Revising the first sentence of the 

introductory text to section 6.2;

■ b. Adding new paragraph (g) to section 

6.2;

■ c. Revising the second sentence of 

section 6.3.1 and adding a new third 

sentence;

28692 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

■ d. Revising the first sentence of section 

6.5;

■ e. Revising section 6.5(a);

■ f. Revising the second sentence of 

section 6.5(c);

■ g. Revising section 6.5(g);

■ h. Revising section 6.5.1(a);

■ i. Revising section 6.5.1(b);

■ j. Adding new paragraph (c) to section 

6.5.6;

■ k. Revising the first sentence and 

adding three sentences at the end of 

section 6.5.7(a); and

■ l. Revising sections 6.5.7(b) and 6.5.10.

The revisions read as follows:

Appendix A to Part 75—Specifications and 

Test Procedures

* * * * *

6. Certification Tests and Procedures.

* * * * *

6.2 Linearity Check (General Procedures) 

Check the linearity of each SO2, NOX, CO2, 

Hg, and O2 monitor while the unit, or group 

of units for a common stack, is combusting 

fuel at conditions of typical stack 

temperature and pressure; it is not necessary 

for the unit to be generating electricity during 

this test. * * *

* * * * *

(g) For Hg monitors, follow the guidelines 

in section 2.2.3 of this appendix in addition 

to the applicable procedures in this section 

6.2 when performing the 3-level system 

integrity checks described in § 75.20(c)(1)(vi) 

and section 2.6 of appendix B to this part. 

6.3 7-Day Calibration Error Test 

6.3.1 Gas Monitor 7-day Calibration Error 

Test 

* * * In all other cases, measure the 

calibration error of each SO2 monitor, each 

NOX monitor, each Hg concentration 

monitor, and each CO2 or O2 monitor while 

the unit is combusting fuel (but not 

necessarily generating electricity) once each 

day for 7 consecutive operating days 

according to the following procedures. For 

Hg monitors, you may perform this test using 

either elemental Hg standards or a NISTtraceable source of oxidized Hg. * * *

* * * * *

6.5 Relative Accuracy and Bias Tests 

(General Procedures) 

Perform the required relative accuracy test 

audits (RATAs) as follows for each CO2

emissions concentration monitor (including 

O2 monitors used to determine CO2

emissions concentration), each SO2 pollutant 

concentration monitor, each NOX

concentration monitoring system used to 

determine NOX mass emissions, each flow 

monitor, each NOX-diluent CEMS, each O2 or 

CO2 diluent monitor used to calculate heat 

input, each Hg concentration monitoring 

system, each sorbent trap monitoring system, 

and each moisture monitoring system. * * *

* * * * *

(a) Except as otherwise provided in this 

paragraph or in § 75.21(a)(5), perform each 

RATA while the unit (or units, if more than 

one unit exhausts into the flue) is combusting 

the fuel that is a normal primary or backup 

fuel for that unit (for some units, more than 

one type of fuel may be considered normal, 

e.g., a unit that combusts gas or oil on a 

seasonal basis). For units that co-fire fuels as 

the predominant mode of operation, perform 

the RATAs while co-firing. For Hg 

monitoring systems, perform the RATAs 

while the unit is combusting coal. When 

relative accuracy test audits are performed on 

CEMS installed on bypass stacks/ducts, use 

the fuel normally combusted by the unit (or 

units, if more than one unit exhausts into the 

flue) when emissions exhaust through the 

bypass stack/ducts.

* * * * *

(c) * * * For units with add-on SO2 or 

NOX controls or add-on Hg controls that 

operate continuously rather than seasonally, 

or for units that need a dual range to record 

high concentration ‘‘spikes’’ during startup 

conditions, the low range is considered 

normal. * * *

* * * * *

(g) For each SO2 or CO2 emissions 

concentration monitor, each flow monitor, 

each CO2 or O2 diluent monitor used to 

determine heat input, each NOX

concentration monitoring system used to 

determine NOX mass emissions, as defined in 

§ 75.71(a)(2), each moisture monitoring 

system, each NOX-diluent CEMS, each Hg 

concentration monitoring system, and each 

sorbent trap monitoring system, calculate the 

relative accuracy, in accordance with section 

7.3 or 7.4 of this appendix, as applicable. In 

addition (except for CO2, O2, or moisture 

monitors), test for bias and determine the 

appropriate bias adjustment factor, in 

accordance with sections 7.6.4 and 7.6.5 of 

this appendix, using the data from the 

relative accuracy test audits. 

6.5.1 Gas and Hg Monitoring System 

RATAs (Special Considerations) 

(a) Perform the required relative accuracy 

test audits for each SO2 or CO2 emissions 

concentration monitor, each CO2 or O2

diluent monitor used to determine heat 

input, each NOX-diluent CEMS, each NOX

concentration monitoring system used to 

determine NOX mass emissions, as defined in 

§ 75.71(a)(2), each Hg concentration 

monitoring system, and each sorbent trap 

monitoring system at the normal load level 

or normal operating level for the unit (or 

combined units, if common stack), as defined 

in section 6.5.2.1 of this appendix. If two 

load levels or operating levels have been 

designated as normal, the RATAs may be 

done at either load level. 

(b) For the initial certification of a gas or 

Hg monitoring system and for recertifications 

in which, in addition to a RATA, one or more 

other tests are required (i.e., a linearity test, 

cycle time test, or 7-day calibration error 

test), EPA recommends that the RATA not be 

commenced until the other required tests of 

the CEMS have been passed.

* * * * *

6.5.6 Reference Method Traverse Point 

Selection

* * * * *

(c) For Hg monitoring systems, use the 

same traverse points that are used for the gas 

monitor RATAs.

* * * * *

6.5.7 Sampling Strategy 

(a) Conduct the reference method tests so 

they will yield results representative of the 

pollutant concentration, emission rate, 

moisture, temperature, and flue gas flow rate 

from the unit and can be correlated with the 

pollutant concentration monitor, CO2 or O2

monitor, flow monitor, and SO2, Hg, or NOX

CEMS measurements. * * * 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 time per run must be long enough to 

collect a sufficient mass of Hg to analyze. For 

the RATA of a sorbent trap monitoring 

system, use the same-size trap that is used for 

daily operation of the monitoring system. 

Spike the third section of each sorbent trap 

with elemental Hg, as described in section 

7.1.2 of appendix K to this part. Install a new 

pair of sorbent traps prior to each test run. 

For each run, the sorbent trap data shall be 

validated according to the quality assurance 

criteria in section 8 of appendix K to this 

part. 

(b) To properly correlate individual SO2, 

Hg, or NOX CEMS data (in lb/MMBtu) and 

volumetric flow rate data with the reference 

method data, annotate the beginning and end 

of each reference method test run (including 

the exact time of day) on the individual chart 

recorder(s) or other permanent recording 

device(s).

* * * * *

6.5.10 Reference Methods 

The following methods from appendix A to 

part 60 of this chapter or their approved 

alternatives are the reference methods for 

performing relative accuracy test audits: 

Method 1 or 1A for siting; Method 2 or its 

allowable alternatives in appendix A to part 

60 of this chapter (except for Methods 2B and 

2E) for stack gas velocity and volumetric flow 

rate; Methods 3, 3A, or 3B for O2 or CO2; 

Method 4 for moisture; Methods 6, 6A, or 6C 

for SO2; Methods 7, 7A, 7C, 7D, or 7E for 

NOX, excluding the exception in section 5.1.2 

of Method 7E; and the Ontario Hydro Method 

or an approved instrumental method for Hg 

(see § 75.22). When using Method 7E for 

measuring NOX concentration, total NOX, 

both NO and NO2, must be measured. 

Notwithstanding these requirements, Method 

20 may be used as the reference method for 

relative accuracy test audits of NOX

monitoring systems installed on combustion 

turbines.

* * * * *

■ 41. Appendix A to part 75 is further 

amended by:

■ a. Revising the title of section 7.3 and 

the first sentence of the introductory text 

of section 7.3;

■ b. Revising the introductory text of 

section 7.6;

■ c. Revising the first sentence in 

paragraph (b) of section 7.6.5 and adding 

a sentence at the end of paragraph (b); 

and

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28693

■ d. Revising paragraph (f) in section 

7.6.5. 

The revisions and additions read as 

follows:

Appendix A to Part 75—Specifications and 

Test Procedures

* * * * *

7. Calculations.

* * * * *

7.3 Relative Accuracy for SO2 and CO2

Emissions Concentration Monitors, O2

Monitors, NOX Concentration Monitoring 

Systems, Hg Monitoring Systems, and Flow 

Monitors 

Analyze the relative accuracy test audit 

data from the reference method tests for SO2

and CO2 emissions concentration monitors, 

CO2 or O2 monitors used only for heat input 

rate determination, NOX concentration 

monitoring systems used to determine NOX

mass emissions under subpart H of this part, 

Hg monitoring systems used to determine Hg 

mass emissions under subpart I of this part, 

and flow monitors using the following 

procedures. * * *

* * * * *

7.6 Bias Test and Adjustment Factor 

Test the following relative accuracy test 

audit data sets for bias: SO2 pollutant 

concentration monitors; flow monitors; NOX

concentration monitoring systems used to 

determine NOX mass emissions, as defined in 

§ 75.71(a)(2); NOX-diluent CEMS, Hg 

concentration monitoring systems, and 

sorbent trap monitoring systems, using the 

procedures outlined in sections 7.6.1 through 

7.6.5 of this appendix. For multiple-load flow 

RATAs, perform a bias test at each load level 

designated as normal under section 6.5.2.1 of 

this appendix.

* * * * *

7.6.5 Bias Adjustment

* * * * *

(b) For single-load RATAs of SO2 pollutant 

concentration monitors, NOX concentration 

monitoring systems, NOX-diluent monitoring 

systems, Hg concentration monitoring 

systems, and sorbent trap monitoring 

systems, and for the single-load flow RATAs 

required or allowed under section 6.5.2 of 

this appendix and sections 2.3.1.3(b) and 

2.3.1.3(c) of appendix B to this part, the 

appropriate BAF is determined directly from 

the RATA results at normal load, using 

Equation A–12. * * * Similarly, for Hg 

concentration and sorbent trap monitoring 

systems, where the average Hg concentration 

during the RATA is < 5.0 μg/dscm, if the 

monitoring system meets the normal or the 

alternative relative accuracy specification in 

section 3.3.8 of this appendix but fails the 

bias test, the owner or operator may either 

use the bias adjustment factor (BAF) 

calculated from Equation A–12 or may use a 

default BAF of 1.250 for reporting purposes 

under this part.

* * * * *

(f) Use the bias-adjusted values in 

computing substitution values in the missing 

data procedure, as specified in subpart D of 

this part, and in reporting the concentration 

of SO2 or Hg, the flow rate, the average NOX

emission rate, the unit heat input, and the 

calculated mass emissions of SO2 and CO2

during the quarter and calendar year, as 

specified in subpart G of this part. In 

addition, when using a NOX concentration 

monitoring system and a flow monitor to 

calculate NOX mass emissions under subpart 

H of this part, or when using a Hg 

concentration or sorbent trap monitoring 

system and a flow monitor to calculate Hg 

mass emissions under subpart I of this part, 

use bias-adjusted values for NOX (or Hg) 

concentration and flow rate in the mass 

emission calculations and use bias-adjusted 

NOX (or Hg) concentrations to compute the 

appropriate substitution values for NOX (or 

Hg) concentration in the missing data 

routines under subpart D of this part.

* * * * *

■ 42. Appendix B to part 75 is amended 

by adding sections 1.5 through 1.5.6, to 

read as follows:

Appendix B to Part 75—Quality Assurance 

and Quality Control Procedures

* * * * *

1.5 Requirements for Sorbent Trap 

Monitoring Systems 

1.5.1 Sorbent Trap Identification and 

Tracking 

Include procedures for inscribing or 

otherwise permanently marking a unique 

identification number on each sorbent trap, 

for tracking purposes. Keep records of the ID 

of the monitoring system in which each 

sorbent trap is used, and the dates and hours 

of each Hg collection period. 

1.5.2 Monitoring System Integrity and Data 

Quality 

Explain the procedures used to perform the 

leak checks when a sorbent trap is placed in 

service and removed from service. Also 

explain the other QA procedures used to 

ensure system integrity and data quality, 

including, but not limited to, dry gas meter 

calibrations, verification of moisture removal, 

and ensuring air-tight pump operation. In 

addition, the QA plan must include the data 

acceptance and quality control criteria in 

section 8 of appendix K to this part. 

1.5.3 Hg Analysis 

Explain the chain of custody employed in 

packing, transporting, and analyzing the 

sorbent traps (see sections 7.2.8 and 7.2.9 in 

appendix K to this part). Keep records of all 

Hg analyses. The analyses shall be performed 

in accordance with the procedures described 

in section 10 of appendix K to this part. 

1.5.4 Laboratory Certification 

The QA Plan shall include documentation 

that the laboratory performing the analyses 

on the carbon sorbent traps is certified by the 

International Organization for 

Standardization (ISO) to have a proficiency 

that meets the requirements of ISO 17025. 

Alternatively, if the laboratory performs the 

spike recovery study described in section 

10.3 of appendix K to this part and repeats 

that procedure annually, ISO certification is 

not required. 

1.5.5 Data Collection Period 

State, and provide the rationale for, the 

minimum acceptable data collection period 

(e.g., one day, one week, etc.) for the size of 

sorbent trap selected for the monitoring. 

Include in the discussion such factors as the 

Hg concentration in the stack gas, the 

capacity of the sorbent trap, and the 

minimum mass of Hg required for the 

analysis. 

1.5.6 Relative Accuracy Test Audit 

Procedures 

Keep records of the procedures and details 

peculiar to the sorbent trap monitoring 

systems that are to be followed for relative 

accuracy test audits, such as sampling and 

analysis methods.

* * * * *

■ 43. Appendix B to part 75 is further 

amended by:

■ a. Revising the first sentence in section 

2.1.1 and adding a new second sentence;

■ b. Revising paragraph (a) of section 

2.1.4;

■ c. Revising section 2.2.1;

■ d. Revising the first sentence of 

paragraph (a) of section 2.3.1.1 and 

adding a new second sentence to 

paragraph (a);

■ e. Revising paragraph (a) of section 

2.3.1.3;

■ f. Revising paragraph (i) of section 

2.3.2;

■ g. Revising section 2.3.4;

■ h. Adding new section 2.6 before 

Figure 1;

■ i. Revising Figure 1 and the first two 

footnotes to Figure 1 (footnotes 1 and 2 

remain unchanged);

■ j. Revising Figure 2;

The revisions and additions read as 

follows:

Appendix B to Part 75—Quality Assurance 

and Quality Control Procedures

* * * * *

2. Frequency of Testing.

* * * * *

2.1.1 Calibration Error Test 

Except as provided in section 2.1.1.2 of 

this appendix, perform the daily calibration 

error test of each gas monitoring system 

(including moisture monitoring systems 

consisting of wet- and dry-basis O2 analyzers) 

and each Hg monitoring system according to 

the procedures in section 6.3.1 of appendix 

A to this part, and perform the daily 

calibration error test of each flow monitoring 

system according to the procedure in section 

6.3.2 of appendix A to this part. For Hg 

monitors, the daily assessments may be made 

using either elemental Hg standards or a 

NIST-traceable source of oxidized Hg. * * *

* * * * *

2.1.4 Data Validation 

(a) An out-of-control period occurs when 

the calibration error of an SO2 or NOX

pollutant concentration monitor exceeds 5.0 

percent of the span value, when the 

28694 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

calibration error of a CO2 or O2 monitor 

(including O2 monitors used to measure CO2

emissions or percent moisture) exceeds 1.0 

percent CO2 or O2, or when the calibration 

error of a flow monitor or a moisture sensor 

exceeds 6.0 percent of the span value, which 

is twice the applicable specification of 

appendix A to this part. Notwithstanding, a 

differential pressure-type flow monitor for 

which the calibration error exceeds 6.0 

percent of the span value shall not be 

considered out-of-control if |R–A|, the 

absolute value of the difference between the 

monitor response and the reference value in 

Equation A–6 of appendix A to this part, is 

< 0.02 inches of water. In addition, an SO2

or NOX monitor for which the calibration 

error exceeds 5.0 percent of the span value 

shall not be considered out-of-control if |RA|

in Equation A–6 does not exceed 5.0 ppm 

(for span values ≤ 50 ppm), or if |R–A| does 

not exceed 10.0 ppm (for span values > 50 

ppm, but ≤ 200 ppm). For a Hg monitor, an 

out-of-control period occurs when the 

calibration error exceeds 5.0% of the span 

value. Notwithstanding, the Hg monitor shall 

not be considered out-of-control if |R–A| in 

Equation A–6 does not exceed 1.0 μg/scm. 

The out-of-control period begins upon failure 

of the calibration error test and ends upon 

completion of a successful calibration error 

test. Note, that if a failed calibration, 

corrective action, and successful calibration 

error test occur within the same hour, 

emission data for that hour recorded by the 

monitor after the successful calibration error 

test may be used for reporting purposes, 

provided that two or more valid readings are 

obtained as required by § 75.10. A NOXdiluent CEMS is considered out-of-control if 

the calibration error of either component 

monitor exceeds twice the applicable 

performance specification in appendix A to 

this part. Emission data shall not be reported 

from an out-of-control monitor.

* * * * *

2.2.1 Linearity Check 

Unless a particular monitor (or monitoring 

range) is exempted under this paragraph or 

under section 6.2 of appendix A to this part, 

perform a linearity check, in accordance with 

the procedures in section 6.2 of appendix A 

to this part, for each primary and redundant 

backup SO2, Hg, and NOX pollutant 

concentration monitor and each primary and 

redundant backup CO2 or O2 monitor 

(including O2 monitors used to measure CO2

emissions or to continuously monitor 

moisture) at least once during each QA 

operating quarter, as defined in § 72.2 of this 

chapter. For Hg monitors, perform the 

linearity checks using elemental Hg 

standards. Alternatively, you may perform 3-

level system integrity checks at the same 

three calibration gas levels (i.e., low, mid, 

and high), using a NIST-traceable source of 

oxidized Hg. If you choose this option, the 

performance specification in section 3.2(c)(3) 

of appendix A to this part must be met at 

each gas level. For units using both a low and 

high span value, a linearity check is required 

only on the range(s) used to record and report 

emission data during the QA operating 

quarter. Conduct the linearity checks no less 

than 30 days apart, to the extent practicable. 

The data validation procedures in section 

2.2.3(e) of this appendix shall be followed.

* * * * *

2.3.1.1 Standard RATA Frequencies 

(a) Except for Hg monitoring systems and 

as otherwise specified in § 75.21(a)(6) or 

(a)(7) or in section 2.3.1.2 of this appendix, 

perform relative accuracy test audits 

semiannually, i.e., once every two successive 

QA operating quarters (as defined in § 72.2 of 

this chapter) for each primary and redundant 

backup SO2 pollutant concentration monitor, 

flow monitor, CO2 emissions concentration 

monitor (including O2 monitors used to 

determine CO2 emissions), CO2 or O2 diluent 

monitor used to determine heat input, 

moisture monitoring system, NOX

concentration monitoring system, NOXdiluent CEMS, or SO2-diluent CEMS. For 

each primary and redundant backup Hg 

concentration monitoring system and each 

sorbent trap monitoring system, RATAs shall 

be performed annually, i.e., once every four 

successive QA operating quarters (as defined 

in § 72.2 of this chapter). * * *

* * * * *

2.3.1.3 RATA Load (or Operating) Levels 

and Additional RATA Requirements 

(a) For SO2 pollutant concentration 

monitors, CO2 emissions concentration 

monitors (including O2 monitors used to 

determine CO2 emissions), CO2 or O2 diluent 

monitors used to determine heat input, NOX

concentration monitoring systems, Hg 

concentration monitoring systems, sorbent 

trap monitoring systems, moisture 

monitoring systems, and NOX-diluent 

monitoring systems, the required semiannual 

or annual RATA tests shall be done at the 

load level (or operating level) designated as 

normal under section 6.5.2.1(d) of appendix 

A to this part. If two load levels (or operating 

levels) are designated as normal, the required 

RATA(s) may be done at either load level (or 

operating level).

* * * * *

2.3.2 Data Validation

* * * * *

(i) Each time that a hands-off RATA of an 

SO2 pollutant concentration monitor, a NOXdiluent monitoring system, a NOX

concentration monitoring system, a Hg 

concentration monitoring system, a sorbent 

trap monitoring system, or a flow monitor is 

passed, perform a bias test in accordance 

with section 7.6.4 of appendix A to this part. 

Apply the appropriate bias adjustment factor 

to the reported SO2, Hg, NOX, or flow rate 

data, in accordance with section 7.6.5 of 

appendix A to this part.

* * * * *

2.3.4 Bias Adjustment Factor

Except as otherwise specified in section 

7.6.5 of appendix A to this part, if an SO2

pollutant concentration monitor, flow 

monitor, NOX CEMS, NOX concentration 

monitoring system used to calculate NOX

mass emissions, Hg concentration monitoring 

system, or sorbent trap monitoring system 

fails the bias test specified in section 7.6 of 

appendix A to this part, use the bias 

adjustment factor given in Equations A–11 

and A–12 of appendix A to this part, or the 

allowable alternative BAF specified in 

section 7.6.5(b) of appendix A to this part, to 

adjust the monitored data.

* * * * *

2.6 System Integrity Checks for Hg Monitors 

For each Hg concentration monitoring 

system (except for a Hg monitor that does not 

have a converter), perform a single-point 

system integrity check weekly, i.e., at least 

once every 168 unit or stack operating hours, 

using a NIST-traceable source of oxidized Hg. 

Perform this check using a mid- or high-level 

gas concentration, as defined in section 5.2 

of appendix A to this part. The performance 

specification in section 3.2(c)(3) of appendix 

A to this part must be met, otherwise the 

monitoring system is considered out-ofcontrol until a subsequent system integrity 

check is passed. This weekly check is not 

required if the daily calibration assessments 

in section 2.1.1 of this appendix are 

performed using a NIST-traceable source of 

oxidized Hg.

FIGURE 1 TO APPENDIX B OF PART 75—QUALITY ASSURANCE TEST REQUIREMENTS

Test 

QA test frequency requirements* 

Daily Weekly Quarterly Semiannual Annual 

Calibration Error or System Integrity Check** (2 pt.) .............................. .................... .................... .................... .................... ....................

Interference Check (flow) ......................................................................... .................... .................... .................... .................... ....................

Flow-to-Load Ratio ................................................................................... .................... .................... .................... .................... ....................

Leak Check (DP flow monitors) ............................................................... .................... .................... .................... .................... ....................

Linearity Check or System Integrity Check** (3-point) ............................ .................... .................... .................... .................... ....................

Single-point System Integrity Check** ..................................................... .................... .................... .................... .................... ....................

RATA (SO2, NOX, CO2, O2, H2O) 1 ......................................................... .................... .................... .................... .................... ....................

RATA (all Hg monitoring systems) .......................................................... .................... .................... .................... .................... ....................

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28695

FIGURE 1 TO APPENDIX B OF PART 75—QUALITY ASSURANCE TEST REQUIREMENTS—Continued

Test 

QA test frequency requirements* 

Daily Weekly Quarterly Semiannual Annual 

RATA (flow ) 1,2 ........................................................................................ .................... .................... .................... .................... ....................

* ‘‘Daily’’ means operating days, only. ‘‘Weekly’’ means once every 168 unit or stack operating hours. ‘‘Quarterly’’ means once every QA operating quarter. ‘‘Semiannual’’ means once every two QA operating quarters. ‘‘Annual’’ means once every four QA operating quarters. **The system integrity check applies only to Hg monitors with converters. The single-point weekly check is not required if daily system integrity 

checks are performed using a NIST-traceable source of oxidized Hg. 

* * * * *

FIGURE 2 TO APPENDIX B OF PART 75—RELATIVE ACCURACY TEST FREQUENCY INCENTIVE SYSTEM

RATA Semiannual W (percent) Annual W

SO2 or NOX y ....................... 7.5% < RA ≤ 10.0% or ± 15.0 ppmX .............................. RA ≤ 7.5% or ± 12.0 ppmX. 

SO2-diluent ........................... 7.5% < RA ≤ 10.0% or ± 0.030 lb/MMBtuX .................... RA ≤ 7.5% or ±0. 025 lb/MMBtuX. 

NOX-diluent .......................... 7.5% < RA ≤ 10.0% or ± 0.020 lb/MMBtuX .................... RA ≤ 7.5% or ±0. 015 lb/MMBtuX. 

Flow ...................................... 7.5% < RA ≤ 10.0% or ± 1.5 fpsX .................................. RA ≤ 7.5%. 

CO2 or O2 ............................. 7.5% < RA ≤ 10.0% or ± 1.0% CO2/O2

X ........................ RA ≤ 7.5% or ± 0.7% CO2/O2x

HgX ...................................... .......................................................................................... RA < 20.0% or ± 1.0 μg/dscmX. 

Moisture ............................... 7.5% < RA ≤ 10.0% or ± 1.5% H2OX ............................. RA ≤ 7.5% or ± 1.0% H2OX. 

W The deadline for the next RATA is the end of the second (if semiannual) or fourth (if annual) successive QA operating quarter following the 

quarter in which the CEMS was last tested. Exclude calendar quarters with fewer than 168 unit operating hours (or, for common stacks and bypass stacks, exclude quarters with fewer than 168 stack operating hours) in determining the RATA deadline. For SO2 monitors, QA operating 

quarters in which only very low sulfur fuel as defined in § 72.2, is combusted may also be excluded. However, the exclusion of calendar quarters 

is limited as follows: the deadline for the next RATA shall be no more than 8 calendar quarters after the quarter in which a RATA was last performed. X The difference between monitor and reference method mean values applies to moisture monitors, CO2, and O2 monitors, low emitters of 

SO2, NOX, or Hg, and low flow, only. The specifications for Hg monitors also apply to sorbent trap monitoring systems. Y A NOX concentration monitoring system used to determine NOX mass emissions under § 75.71. 

■ 44. Appendix F to part 75 is amended 

by adding section 9, to read as follows:

Appendix F to Part 75—Conversion 

Procedures

* * * * *

9. Procedures for Hg Mass Emissions. 

9.1 Use the procedures in this section to 

calculate the hourly Hg mass emissions (in 

ounces) at each monitored location, for the 

affected unit or group of units that discharge 

through a common stack. 

9.1.1 To determine the hourly Hg mass 

emissions when using a Hg concentration 

monitoring system that measures on a wet 

basis and a flow monitor, use the following 

equation:

M KC Q t h h hh = (Eq. F-28)

Where:

Mh = Hg mass emissions for the hour, 

rounded off to three decimal places, 

(ounces). 

K = Units conversion constant, 9.978 x 10¥10

oz-scm/μg-scf 

Ch = Hourly Hg concentration, wet basis, 

adjusted for bias if the bias-test 

procedures in appendix A to this part 

show that a bias-adjustment factor is 

necessary, (μg/wscm). 

Qh = Hourly stack gas volumetric flow rate, 

adjusted for bias, where the bias-test 

procedures in appendix A to this part 

shows a bias-adjustment factor is 

necessary, (scfh) 

th = Unit or stack operating time, as defined 

in § 72.2, (hr)

9.1.2 To determine the hourly Hg mass 

emissions when using a Hg concentration 

monitoring system that measures on a dry 

basis or a sorbent trap monitoring system and 

a flow monitor, use the following equation:

M KC Q t B h h h h ws = −( ) 1 (Eq. F-29)

Where:

Mh = Hg mass emissions for the hour, 

rounded off to three decimal places, 

(ounces). 

K = Units conversion constant, 9.978 x 10¥10

oz-scm/μg-scf 

Ch = Hourly Hg concentration, dry basis, 

adjusted for bias if the bias-test 

procedures in appendix A to this part 

show that a bias-adjustment factor is 

necessary, (μg/dscm). For sorbent trap 

systems, a single value of Ch (i.e., a flowproportional average concentration for 

the data collection period), is applied to 

each hour in the data collection period, 

for a particular pair of traps. 

Qh = Hourly stack gas volumetric flow rate, 

adjusted for bias, where the bias-test 

procedures in appendix A to this part 

shows a bias-adjustment factor is 

necessary, (scfh) 

Bws = Moisture fraction of the stack gas, 

expressed as a decimal (equal to % H2O 

100) 

th = Unit or stack operating time, as defined 

in § 72.2, (hr)

9.1.3 For units that are demonstrated 

under § 75.81(d) to emit less than 464 ounces 

of Hg per year, and for which the owner or 

operator elects not to continuously monitor 

the Hg concentration, calculate the hourly Hg 

mass emissions using Equation F–28 in 

section 9.1.1 of this appendix, except that 

‘‘Ch’’ shall be the applicable default Hg 

concentration from § 75.81(c), (d), or (e), 

expressed in μg/scm. Correction for the stack 

gas moisture content is not required when 

this methodology is used. 

9.2 Use the following equation to 

calculate quarterly and year-to-date Hg mass 

emissions in ounces:

M Mh

h

n

time period = (Eq. F-30)

=

∑

1

Where:

Mtime period = Hg mass emissions for the given 

time period i.e., quarter or year-to-date, 

rounded to the nearest thousandth, 

(ounces). 

Mh = Hg mass emissions for the hour, 

rounded to three decimal places, 

(ounces). 

n = The number of hours in the given time 

period (quarter or year-to-date).

9.3 If heat input rate monitoring is 

required, follow the applicable procedures 

for heat input apportionment and summation 

in sections 5.3, 5.6 and 5.7 of this appendix.

■ 45. Part 75 is amended by adding 

Appendix K, to read as follows:

Appendix K to Part 75—Quality Assurance 

and Operating Procedures for Sorbent Trap 

Monitoring Systems 

1.0 Scope and Application 

This appendix specifies sampling, and 

analytical, and quality-assurance criteria and 


ER18MY05.023</MATH> ER18MY05.024</MATH> ER18MY05.025</MATH>
28696 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

procedures for the performance-based 

monitoring of vapor-phase mercury (Hg) 

emissions in combustion flue gas streams, 

using a sorbent trap monitoring system (as 

defined in § 72.2 of this chapter). The 

principle employed is continuous sampling 

using in-stack sorbent media coupled with 

analysis of the integrated samples. The 

performance-based approach of this 

appendix allows for use of various suitable 

sampling and analytical technologies while 

maintaining a specified and documented 

level of data quality through performance 

criteria. Persons using this appendix should 

have a thorough working knowledge of 

Methods 1, 2, 3, 4 and 5 in appendices A–

1 through A–3 to part 60 of this chapter, as 

well as the determinative technique selected 

for analysis.

1.1 Analytes.

The analyte measured by these procedures 

and specifications is total vapor-phase Hg in 

the flue gas, which represents the sum of 

elemental Hg (Hg0, CAS Number 7439–97–6) 

and oxidized forms of Hg, in mass 

concentration units of micrograms per dry 

standard cubic meter (μg/dscm). 

1.2 Applicability.

These performance criteria and procedures 

are applicable to monitoring of vapor-phase 

Hg emissions under relatively low-dust 

conditions (i.e., sampling in the stack after all 

pollution control devices), from coal-fired 

electric utility steam generators which are 

subject to subpart I of this part. Individual 

sample collection times can range from 30 

minutes to several days in duration, 

depending on the Hg concentration in the 

stack. The monitoring system must achieve 

the performance criteria specified in Section 

8 of this appendix and the sorbent media 

capture ability must not be exceeded. The 

sampling rate must be maintained at a 

constant proportion to the total stack flowrate 

to ensure representativeness of the sample 

collected. Failure to achieve certain 

performance criteria will result in invalid Hg 

emissions monitoring data. 

2.0 Principle.

Known volumes of flue gas are extracted 

from a stack or duct through paired, in-stack, 

pre-spiked sorbent media traps at an 

appropriate nominal flow rate. Collection of 

Hg on the sorbent media in the stack 

mitigates potential loss of Hg during 

transport through a probe/sample line. Paired 

train sampling is required to determine 

measurement precision and verify 

acceptability of the measured emissions data. 

The sorbent traps are recovered from the 

sampling system, prepared for analysis, as 

needed, and analyzed by any suitable 

determinative technique that can meet the 

performance criteria. A section of each 

sorbent trap is spiked with Hg0 prior to 

sampling. This section is analyzed separately 

and the recovery value is used to correct the 

individual Hg sample for measurement bias. 

3.0 Clean Handling and Contamination.

To avoid Hg contamination of the samples, 

special attention should be paid to 

cleanliness during transport, field handling, 

sampling, recovery, and laboratory analysis, 

as well as during preparation of the sorbent 

cartridges. Collection and analysis of blank 

samples (field, trip, lab) is useful in verifying 

the absence of contaminant Hg. 

4.0 Safety.

4.1 Site hazards.

Site hazards must be thoroughly 

considered in advance of applying these 

procedures/specifications in the field; 

advance coordination with the site is critical 

to understand the conditions and applicable 

safety policies. At a minimum, portions of 

the sampling system will be hot, requiring 

appropriate gloves, long sleeves, and caution 

in handling this equipment. 

4.2 Laboratory safety policies.

Laboratory safety policies should be in 

place to minimize risk of chemical exposure 

and to properly handle waste disposal. 

Personnel shall wear appropriate laboratory 

attire according to a Chemical Hygiene Plan 

established by the laboratory. 

4.3 Toxicity or carcinogenicity.

The toxicity or carcinogenicity of any 

reagents used must be considered. Depending 

upon the sampling and analytical 

technologies selected, this measurement may 

involve hazardous materials, operations, and 

equipment and this appendix does not 

address all of the safety problems associated 

with implementing this approach. It is the 

responsibility of the user to establish 

appropriate safety and health practices and 

determine the applicable regulatory 

limitations prior to performance. Any 

chemical should be regarded as a potential 

health hazard and exposure to these 

compounds should be minimized. Chemists 

should refer to the Material Safety Data Sheet 

(MSDS) for each chemical used. 

4.4 Wastes.

Any wastes generated by this procedure 

must be disposed of according to a hazardous 

materials management plan that details and 

tracks various waste streams and disposal 

procedures. 

5.0 Equipment and Supplies.

The following list is presented as an 

example of key equipment and supplies 

likely required to perform vapor-phase Hg 

monitoring using a sorbent trap monitoring 

system. It is recognized that additional 

equipment and supplies may be needed. 

Collection of paired samples is required. Also 

required are a certified stack gas volumetric 

flow monitor that meets the requirements of 

§ 75.10 and an acceptable means of correcting 

for the stack gas moisture content, i.e., either 

by using data from a certified continuous 

moisture monitoring system or by using an 

approved default moisture value (see 

§§ 75.11(b) and 75.12(b)). 

5.1 Sorbent Trap Monitoring System.

A typical sorbent trap monitoring system is 

shown in Figure K–1. The monitoring system 

shall include the following components: 

BILLING CODE 6560–50–P

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28697

BILLING CODE 6560–50–C 

5.1.1 Sorbent Traps.

The sorbent media used to collect Hg must 

be configured in a trap with three distinct 

and identical segments or sections, 

connected in series, that are amenable to 

separate analyses. Section 1 is designated for 

primary capture of gaseous Hg. Section 2 is 

designated as a backup section for 

determination of vapor-phase Hg 

breakthrough. Section 3 is designated for QA/

QC purposes where this section shall be 

spiked with an known amount of gaseous Hg0

prior to sampling and later analyzed to 

determine recovery efficiency. The sorbent 

media may be any collection material (e.g., 

carbon, chemically-treated filter, etc.) capable 

of quantitatively capturing and recovering for 

subsequent analysis, all gaseous forms of Hg 

for the intended application. Selection of the 

sorbent media shall be based on the 

material’s ability to achieve the performance 

criteria contained in Section 8 of this 

appendix as well as the sorbent’s vaporphase Hg capture efficiency for the emissions 

matrix and the expected sampling duration at 

the test site. The sorbent media must be 

obtained from a source that can demonstrate 

the quality assurance and control necessary 

to ensure consistent reliability. The paired 

sorbent traps are supported on a probe (or 

probes) and inserted directly into the flue gas 

stream.

5.1.2 Sampling Probe Assembly.

Each probe assembly shall have a leak-free 

attachment to the sorbent trap(s). Each 

sorbent trap must be mounted at the entrance 

of or within the probe such that the gas 

sampled enters the trap directly. Each probe/

sorbent trap assembly must be heated to a 

temperature sufficient to prevent liquid 

condensation in the sorbent trap(s). Auxiliary 

heating is required only where the stack 

temperature is too low to prevent 

condensation. Use a calibrated thermocouple 

to monitor the stack temperature. A single 

probe capable of operating the paired sorbent 

traps may be used. Alternatively, individual 

probe/sorbent trap assemblies may be used, 

provided that the individual sorbent traps are 

co-located to ensure representative Hg 

monitoring and are sufficiently separated to 

prevent aerodynamic interference. 

5.1.3 Moisture Removal Device.

A robust moisture removal device or 

system, suitable for continuous duty (such as 

a Peltier cooler), shall be used to remove 

water vapor from the gas stream prior to 

entering the dry gas meter. 

5.1.4 Vacuum Pump.

Use a leak-tight, vacuum pump capable of 

operating within the candidate system’s flow 

range. 

5.1.5 Dry Gas Meter.

A dry gas meter shall be used to determine 

total sample volume. The meter must be 

sufficiently accurate to measure the total 

sample volume within 2 percent, must be 

calibrated at the selected flow rate and 

conditions actually encountered during 

sampling, and shall be equipped with a 

temperature sensor capable of measuring 

typical meter temperatures accurately to 

within 3 °C for correcting final sample 

volume. 

5.1.6 Sample Flow Rate Meter and 

Controller.

Use a flow rate indicator and controller for 

maintaining necessary sampling flow rates. 

5.1.7 Temperature Sensor.

Same as Section 6.1.1.7 of Method 5 in 

appendix A–3 to part 60 of this chapter. 

5.1.8 Barometer.

Same as Section 6.1.2 of Method 5 in 

appendix A–3 to part 60 of this chapter. 

5.1.9 Data Logger (Optional).

Device for recording associated and 

necessary ancillary information (e.g., 

temperatures, pressures, flow, time, etc.).

5.2 Gaseous Hg0 Sorbent Trap Spiking 

System. 

A known mass of gaseous Hg0 must be 

spiked onto section 3 of each sorbent trap 

prior to sampling. Any approach capable of 

quantitatively delivering known masses of 

Hg0 onto sorbent traps is acceptable. Several 

technologies or devices are available to meet 

this objective. Their practicality is a function 

of Hg mass spike levels. For low levels, NISTcertified or NIST-traceable gas generators or 

tanks may be suitable, but will likely require 

long preparation times. A more practical, 

alternative system, capable of delivering 

almost any mass required, makes use of 

NIST-certified or NIST-traceable Hg salt 

solutions (e.g., Hg(NO3)2). With this system, 

an aliquot of known volume and 

concentration is added to a reaction vessel 

containing a reducing agent (e.g., stannous 

chloride); the Hg salt solution is reduced to 

Hg0 and purged onto section 3 of the sorbent 

trap using an impinger sparging system. 

5.3 Sample Analysis Equipment. 

Any analytical system capable of 

quantitatively recovering and quantifying 

total gaseous Hg from sorbent media is 

acceptable provided that the analysis can 

meet the performance criteria in Section 8 of 

this procedure. Candidate recovery 


ER18MY05.019</GPH>
28698 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

techniques include leaching, digestion, and 

thermal desorption. Candidate analytical 

techniques include ultraviolet atomic 

fluorescence (UV AF); ultraviolet atomic 

absorption (UV AA), with and without gold 

trapping; and in situ X-ray fluorescence 

(XRF) analysis. 

6.0 Reagents and Standards. 

Only NIST-certified or NIST-traceable 

calibration gas standards and reagents shall 

be used for the tests and procedures required 

under this appendix. 

7.0 Sample Collection and Transport. 

7.1 Pre-Test Procedures. 

7.1.1 Selection of Sampling Site. 

Sampling site information should be 

obtained in accordance with Method 1 in 

appendix A–1 to part 60 of this chapter. 

Identify a monitoring location representative 

of source Hg emissions. Locations shown to 

be free of stratification through measurement 

traverses for gases such as SO2 and NOX may 

be one such approach. An estimation of the 

expected stack Hg concentration is required 

to establish a target sample flow rate, total 

gas sample volume, and the mass of Hg0 to 

be spiked onto section 3 of each sorbent trap. 

7.1.2 Pre-sampling Spiking of Sorbent 

Traps. 

Based on the estimated Hg concentration in 

the stack, the target sample rate and the target 

sampling duration, calculate the expected 

mass loading for section 1 of each sorbent 

trap (for an example calculation, see section 

11.1 of this appendix). The pre-sampling 

spike to be added to section 3 of each sorbent 

trap shall be within ± 50 percent of the 

expected section 1 mass loading. Spike 

section 3 of each sorbent trap at this level, 

as described in section 5.2 of this appendix. 

For each sorbent trap, keep an official record 

of the mass of Hg0 added to section 3. This 

record shall include, at a minimum, the ID 

number of the trap, the date and time of the 

spike, the name of the analyst performing the 

procedure, the mass of Hg0 added to section 

3 of the trap (μg), and the supporting 

calculations. This record shall be maintained 

in a format suitable for inspection and audit 

and shall be made available to the regulatory 

agencies upon request. 

7.1.3 Pre-test Leak Check. 

Perform a leak check with the sorbent traps 

in place. Draw a vacuum in each sample 

train. Adjust the vacuum in the sample train 

to ∼15′′ Hg. Using the dry gas meter, 

determine leak rate. The leakage rate must 

not exceed 4 percent of the target sampling 

rate. Once the leak check passes this 

criterion, carefully release the vacuum in the 

sample train then seal the sorbent trap inlet 

until the probe is ready for insertion into the 

stack or duct. 

7.1.4 Determination of Flue Gas 

Characteristics. 

Determine or measure the flue gas 

measurement environment characteristics 

(gas temperature, static pressure, gas velocity, 

stack moisture, etc.) in order to determine 

ancillary requirements such as probe heating 

requirements (if any), initial sample rate, 

proportional sampling conditions, moisture 

management, etc. 

7.2 Sample Collection.

7.2.1 Remove the plug from the end of 

each sorbent trap and store each plug in a 

clean sorbent trap storage container. Remove 

the stack or duct port cap and insert the 

probe(s). Secure the probe(s) and ensure that 

no leakage occurs between the duct and 

environment. 

7.2.2 Record initial data including the 

sorbent trap ID, start time, starting dry gas 

meter readings, initial temperatures, setpoints, and any other appropriate 

information. 

7.2.3 Flow Rate Control. 

Set the initial sample flow rate at the target 

value from section 7.1.1 of this appendix. 

Record the initial dry gas meter reading, 

stack temperature, meter temperatures, etc. 

Then, for every operating hour during the 

sampling period, record the date and time, 

the sample flow rate, the gas meter reading, 

the stack temperature, the flow meter 

temperatures, temperatures of heated 

equipment such as the vacuum lines and the 

probes (if heated), and the sampling system 

vacuum readings. Also record the stack gas 

flow rate, as measured by the certified flow 

monitor, and the ratio of the stack gas flow 

rate to the sample flow rate. Adjust the 

sampling flow rate to maintain proportional 

sampling, i.e., keep the ratio of the stack gas 

flow rate to sample flow rate constant, to 

within ±25 percent of the reference ratio from 

the first hour of the data collection period 

(see section 11 of this appendix). 

7.2.4 Stack Gas Moisture Determination. 

Determine stack gas moisture using a 

continuous moisture monitoring system, as 

described in § 75.11(b) or § 75.12(b). 

Alternatively, the owner or operator may use 

the appropriate fuel-specific moisture default 

value provided in § 75.11 or § 75.12, or a sitespecific moisture default value approved by 

petition under § 75.66. 

7.2.5 Essential Operating Data. 

Obtain and record any essential operating 

data for the facility during the test period, 

e.g., the barometric pressure must be 

obtained for correcting sample volume to 

standard conditions. At the end of the data 

collection period, record the final dry gas 

meter reading and the final values of all other 

essential parameters. 

7.2.6 Post Test Leak Check. 

When sampling is completed, turn off the 

sample pump, remove the probe/sorbent trap 

from the port and carefully re-plug the end 

of each sorbent trap. Perform a leak check 

with the sorbent traps in place, at the 

maximum vacuum reached during the 

sampling period. Use the same general 

approach described in section 7.1.3 of this 

appendix. Record the leakage rate and 

vacuum. The leakage rate must not exceed 4 

percent of the average sampling rate for the 

data collection period. Following the leak 

check, carefully release the vacuum in the 

sample train. 

7.2.7 Sample Recovery. 

Recover each sampled sorbent trap by 

removing it from the probe, sealing both 

ends. Wipe any deposited material from the 

outside of the sorbent trap. Place the sorbent 

trap into an appropriate sample storage 

container and store/preserve in appropriate 

manner. 

7.2.8 Sample Preservation, Storage, and 

Transport. 

While the performance criteria of this 

approach provide for verification of 

appropriate sample handling, it is still 

important that the user consider, determine, 

and plan for suitable sample preservation, 

storage, transport, and holding times for 

these measurements. Therefore, procedures 

in ASTM D6911–03 ‘‘Standard Guide for 

Packaging and Shipping Environmental 

Samples for Laboratory Analysis’’

(incorporated by reference, see § 75.6) shall 

be followed for all samples. 

7.2.9 Sample Custody. 

Proper procedures and documentation for 

sample chain of custody are critical to 

ensuring data integrity. The chain of custody 

procedures in ASTM D4840–99 (reapproved 

2004) ‘‘Standard Guide for Sample Chain-ofCustody Procedures’’ (incorporated by 

reference, see § 75.6) shall be followed for all 

samples (including field samples and 

blanks). 

8.0 Quality Assurance and Quality Control. 

Table K–1 summarizes the QA/QC 

performance criteria that are used to validate 

the Hg emissions data from sorbent trap 

monitoring systems, including the relative 

accuracy test audit (RATA) requirement (see 

§ 75.20(c)(9), section 6.5.7 of appendix A to 

this part, and section 2.3 of appendix B to 

this part). Except as provided in § 75.15(h) 

and as otherwise indicated in Table K–1, 

failure to achieve these performance criteria 

will result in invalidation of Hg emissions 

data.

TABLE K–1.—QUALITY ASSURANCE/QUALITY CONTROL CRITERIA FOR SORBENT TRAP MONITORING SYSTEMS

QA/QC test or specification Acceptance criteria Frequency Consequences if not met 

Pre-test leak check ........................ ≤4% of target sampling rate ......... Prior to sampling .......................... Sampling shall not commence 

until the leak check is passed. 

Post-test leak check ...................... ≤4% of average sampling rate ..... After sampling ............................... Sample invalidated.** 

Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 28699

TABLE K–1.—QUALITY ASSURANCE/QUALITY CONTROL CRITERIA FOR SORBENT TRAP MONITORING SYSTEMS—Continued

QA/QC test or specification Acceptance criteria Frequency Consequences if not met 

Ratio of stack gas flow rate to 

sample flow rate.

Maintain within ± 25% of initial 

ratio from first hour of data collection period.

Every hour throughout data collection period.Case-by-case evaluation. 

Sorbent trap section 2 breakthrough.≤ 5% of Section 1 Hg mass ......... Every sample ................................ Sample invalidated.** 

Paired sorbent trap agreement ...... ≤10% Relative Deviation (RD) ..... Every sample ................................ Sample invalidated.** 

Spike recovery study ..................... Average recovery between 85% 

and 115% for each of the 3 

spike concentration levels.

Prior to analyzing field samples 

and prior to use of new sorbent 

media.

Field samples shall not be analyzed until the percent recovery 

criteria has been met. 

Multipoint analyzer calibration ....... Each analyzer reading within ±

10% of true value and r2 ≥0.99.

On the day of analysis, before 

analyzing any samples.

Recalibrate until successful. 

Analysis of independent calibration 

standard.

Within ± 10% of true value ........... Following daily calibration, prior to 

analyzing field samples.

Recalibrate and repeat independent standard analysis until 

successful. 

Spike recovery from section 3 of 

sorbent trap.

75–125% of spike amount ............ Every sample ................................ Sample invalidated.** 

RATA ............................................. RA ≤ 20.0% or Mean difference ≤

1.0 μg/dscm for low emitters.

For initial certification and annually thereafter.Data from the system are invalidated until a RATA is passed. 

Dry gas meter calibration (At 3 orifice initially, and 1 setting thereafter).Calibration factor (Y) within ± 5% 

of average value from the initial 

(3-point) calibration.

Prior to initial use and at least 

quarterly thereafter.

Recalibrate the meter at three orifice settings to determine a new 

value of Y. 

Temperature sensor calibration ..... Absolute temperature measured 

by sensor within ± 1.5% of a 

reference sensor.

Prior to initial use and at least 

quarterly thereafter.

Recalibrate. Sensor may not be 

used until specification is met. 

Barometer calibration ..................... Absolute pressure measured by 

instrument within ± 10 mm Hg 

of reading with a mercury barometer.

Prior to initial use and at least 

quarterly thereafter.

Recalibrate. Instrument may not 

be used until specification is 

met. 

And data from the pair of sorbent traps are also invalidated 

9.0 Calibration and Standardization. 

9.1 Only NIST-certified and NISTtraceable calibration standards (i.e., 

calibration gases, solutions, etc.) shall be 

used for the spiking and analytical 

procedures in this appendix.

9.2 Dry Gas Meter Calibration. 

Prior to its initial use, perform a full 

calibration of the metering system at three 

orifice settings to determine the average dry 

gas meter coefficient (Y), as described in 

section 10.3.1 of Method 5 in appendix A–

3 to part 60 of this chapter. Thereafter, 

recalibrate the metering system quarterly at 

one intermediate orifice setting, as described 

in section 10.3.2 of Method 5 in appendix A–

3 to part 60 of this chapter. If a quarterly 

recalibration shows that the value of Y has 

changed by more than 5 percent, repeat the 

full calibration of the metering system to 

determine a new value of Y. 

9.3 Thermocouples and Other Temperature 

Sensors. 

Use the procedures and criteria in Section 

10.3 of Method 2 in appendix A–1 to part 60 

of this chapter to calibrate in-stack 

temperature sensors and thermocouples. Dial 

thermometers shall be calibrated against 

mercury-in-glass thermometers. Calibrations 

must be performed prior to initial use and at 

least quarterly thereafter. At each calibration 

point, the absolute temperature measured by 

the temperature sensor must agree to within 

± 1.5 percent of the temperature measured 

with the reference sensor, otherwise the 

sensor may not continue to be used. 

9.4 Barometer. 

Calibrate against a mercury barometer. 

Calibration must be performed prior to initial 

use and at least quarterly thereafter. At each 

calibration point, the absolute pressure 

measured by the barometer must agree to 

within ± 10 mm Hg of the pressure measured 

by the mercury barometer, otherwise the 

barometer may not continue to be used. 

9.5 Other Sensors and Gauges. 

Calibrate all other sensors and gauges 

according to the procedures specified by the 

instrument manufacturer(s). 

9.6 Analytical System Calibration. 

See section 10.1 of this appendix. 

10.0 Analytical Procedures. 

The analysis of the Hg samples may be 

conducted using any instrument or 

technology capable of quantifying total Hg 

from the sorbent media and meeting the 

performance criteria in section 8 of this 

appendix. 

10.1 Analyzer System Calibration. 

Perform a multipoint calibration of the 

analyzer at three or more upscale points over 

the desired quantitative range (multiple 

calibration ranges shall be calibrated, if 

necessary). The field samples analyzed must 

fall within a calibrated, quantitative range 

and meet the necessary performance criteria. 

For samples that are suitable for aliquotting, 

a series of dilutions may be needed to ensure 

that the samples fall within a calibrated 

range. However, for sorbent media samples 

that are consumed during analysis (e.g.,

thermal desorption techniques), extra care 

must be taken to ensure that the analytical 

system is appropriately calibrated prior to 

sample analysis. The calibration curve 

range(s) should be determined based on the 

anticipated level of Hg mass on the sorbent 

media. Knowledge of estimated stack Hg 

concentrations and total sample volume may 

be required prior to analysis. The calibration 

curve for use with the various analytical 

techniques (e.g., UV AA, UV AF, and XRF) 

can be generated by directly introducing 

standard solutions into the analyzer or by 

spiking the standards onto the sorbent media 

and then introducing into the analyzer after 

preparing the sorbent/standard according to 

the particular analytical technique. For each 

calibration curve, the value of the square of 

the linear correlation coefficient, i.e., r2, must 

be ≥ 0.99, and the analyzer response must be 

within ± 10 percent of reference value at each 

upscale calibration point. Calibrations must 

be performed on the day of the analysis, 

before analyzing any of the samples. 

Following calibration, an independently 

prepared standard (not from same calibration 

stock solution) shall be analyzed. The 

measured value of the independently 

prepared standard must be within ± 10 

percent of the expected value. 

10.2 Sample Preparation. 

Carefully separate the three sections of 

each sorbent trap. Combine for analysis all 

materials associated with each section, i.e.,

any supporting substrate that the sample gas 

passes through prior to entering a media 

section (e.g., glass wool, polyurethane foam, 

etc.) must be analyzed with that segment.

28700 Federal Register / Vol. 70, No. 95 / Wednesday, May 18, 2005 / Rules and Regulations 

10.3 Spike Recovery Study. 

Before analyzing any field samples, the 

laboratory must demonstrate the ability to 

recover and quantify Hg from the sorbent 

media by performing the following spike 

recovery study for sorbent media traps spiked 

with elemental mercury. 

Using the procedures described in sections 

5.2 and 11.1 of this appendix, spike the third 

section of nine sorbent traps with gaseous 

Hg0, i.e., three traps at each of three different 

mass loadings, representing the range of 

masses anticipated in the field samples. This 

will yield a 3 x 3 sample matrix. Prepare and 

analyze the third section of each spiked trap, 

using the techniques that will be used to 

prepare and analyze the field samples. The 

average recovery for each spike concentration 

must be between 85 and 115 percent. If 

multiple types of sorbent media are to be 

analyzed, a separate spike recovery study is 

required for each sorbent material. If multiple 

ranges are calibrated, a separate spike 

recovery study is required for each range. 

10.4 Field Sample Analyses. 

Analyze the sorbent trap samples following 

the same procedures that were used for 

conducting the spike recovery study. The 

three sections of the sorbent trap must be 

analyzed separately (i.e., section 1, then 

section 2, then section 3). Quantify the mass 

of total Hg for each section based on 

analytical system response and the 

calibration curve from section 10.1 of this 

appendix. Determine the spike recovery from 

sorbent trap section 3. Pre-sampling spike 

recoveries must be between 75 and 125 

percent. To report final Hg mass, normalize 

the data for sections 1 and 2 based on the 

sample-specific spike recovery, and add the 

normalized masses together. 

11.0 Calculations and Data Analysis. 

11.1 Calculation of Pre-Sampling Spiking 

Level. 

Determine sorbent trap section 3 spiking 

level using estimates of the stack Hg 

concentration, the target sample flow rate, 

and the expected sample duration. First, 

calculate the expected Hg mass that will be 

collected in section 1 of the trap. The presampling spike must be within ± 50 percent 

of this mass. Example calculation: For an 

estimated stack Hg concentration of 5 μg/m3, 

a target sample rate of 0.30 L/min, and a 

sample duration of 5 days:

(0.30 L/min) (1440 min/day) (5 days) (10¥3

m3/liter) (5μg/m3) = 10.8 μg

A pre-sampling spike of 10.8 μg ± 50 percent 

is, therefore, appropriate. 

11.2 Calculations for Flow-Proportional 

Sampling. 

For the first hour of the data collection 

period, determine the reference ratio of the 

stack gas volumetric flow rate to the sample 

flow rate, as follows:

Rref

ref

ref

KQ

F = (Eq. K-1)

Where:

Rref = Reference ratio of hourly stack gas flow 

rate to hourly sample flow rate 

Qref = Average stack gas volumetric flow rate 

for first hour of collection period, 

adjusted for bias, if necessary, according 

to section 7.6.5 of appendix A to this 

part, (scfh) 

Fref = Average sample flow rate for first hour 

of the collection period, in appropriate 

units (e.g., liters/min, cc/min, dscm/min) 

K = Power of ten multiplier, to keep the value 

of Rref between 1 and 100. The 

appropriate K value will depend on the 

selected units of measure for the sample 

flow rate.

Then, for each subsequent hour of the data 

collection period, calculate ratio of the stack 

gas flow rate to the sample flow rate using 

the equation K–2:

R KQ

F h

h

h

= (Eq. K-2)

Where:

Rh = Ratio of hourly stack gas flow rate to 

hourly sample flow rate 

Qh = Average stack gas volumetric flow rate 

for the hour, adjusted for bias, if 

necessary, according to section 7.6.5 of 

appendix A to this part, (scfh) 

Fh = Average sample flow rate for the hour, 

in appropriate units (e.g., liters/min, cc/

min, dscm/min) 

K = Power of ten multiplier, to keep the value 

of Rh between 1 and 100. The 

appropriate K value will depend on the 

selected units of measure for the sample 

flow rate and the range of expected stack 

gas flow rates.

Maintain the value of Rh within ± 25 percent 

of Rref throughout the data collection period. 

11.3 Calculation of Spike Recovery. 

Calculate the percent recovery of each 

section 3 spike, as follows:

%R M

Ms

= × 3 100 (Eq. K-3)

Where:

%R = Percentage recovery of the presampling spike 

M3 = Mass of Hg recovered from section 3 of 

the sorbent trap, (μg) 

Ms = Calculated Hg mass of the pre-sampling 

spike, from section 7.1.2 of this 

appendix, (μg) 

11.4 Calculation of Breakthrough. 

Calculate the percent breakthrough to the 

second section of the sorbent trap, as follows:

%B M

M

= × 2

1

100 (Eq. K-4)

Where:

%B = Percent breakthrough 

M2 = Mass of Hg recovered from section 2 of 

the sorbent trap, (μg) 

M1 = Mass of Hg recovered from section 1 of 

the sorbent trap, (μg)

11.5 Normalizing Measured Hg Mass for 

Section 3 Spike Recoveries. 

Based on the results of the spike recovery 

in section 12.3 of this appendix, normalize 

the Hg mass collected in sections 1 and 2 of 

the sorbent trap, as follows:

M

M MM

M

* s = ( ) 1 2 +

3

(Eq. K-5)

Where:

M* = Normalized total mass of Hg recovered 

from sections 1 and of the sorbent trap, 

(μg) 

M1 = Mass of Hg recovered from section 1 of 

the sorbent trap, unadjusted, (μg) 

M2 = Mass of Hg recovered from section 2 of 

the sorbent trap, unadjusted, (μg) 

Ms = Calculated Hg mass of the pre-sampling 

spike, from section 7.1.2 of this 

appendix, (μg) 

M3 = Mass of Hg recovered from section 3 of 

the sorbent trap, (μg)

11.6 Calculation of Hg Concentration. 

Calculate the Hg concentration for each 

sorbent trap, using the following equation:

C M

Vt

=

*

(Eq. K-6)

Where:

C = Concentration of Hg for the collection 

period, (μg/dscm) 

M* = Normalized total mass of Hg recovered 

from sections 1 and 2 of the sorbent trap, 

(μg) 

Vt = Total volume of dry gas metered during 

the collection period, (dscm). For the 

purposes of this appendix, standard 

temperature and pressure are defined as 

20° C and 760 mm Hg, respectively.

11.7 Calculation of Paired Trap Agreement. 

Calculate the relative deviation (RD) 

between the Hg concentrations measured 

with the paired sorbent traps:

RD

C C

C C

a b

a b

= −

+

× 100 7 (Eq. K- )

Where:

RD = Relative deviation between the Hg 

concentrations from traps ‘‘a’’ and ‘‘b’’

(percent) 

Ca = Concentration of Hg for the collection 

period, for sorbent trap ‘‘a’’ (μg/dscm) 

Cb = Concentration of Hg for the collection 

period, for sorbent trap ‘‘b’’ (μg/dscm)

11.8 Calculation of Hg Mass Emissions. 

To calculate Hg mass emissions, follow the 

procedures in section 9.1.2 of appendix F to 

this part. Use the average of the two Hg 

concentrations from the paired traps in the 

calculations, except as provided in 

§ 75.15(h). 

12.0 Method Performance.

These monitoring criteria and procedures 

have been applied to coal-fired utility boilers 

(including units with post-combustion 

emission controls), having vapor-phase Hg 

concentrations ranging from 0.03 μg/dscm to 

100 μg/dscm.

[FR Doc. 05–8447 Filed 5–17–05; 8:45 am] 

BILLING CODE 6560–50–P


ER18MY05.012</MATH> ER18MY05.013</MATH> ER18MY05.014</MATH> ER18MY05.015</MATH> ER18MY05.016</MATH> ER18MY05.017</MATH> ER18MY05.018</MATH>