Tuesday, 

August 22, 2006 

Part III 

Environmental 

Protection Agency 

40 CFR Parts 72 and 75 

Revisions to the Continuous Emissions 

Monitoring Rule for the Acid Rain 

Program, NOX Budget Trading Program, 

the Clean Air Interstate Rule, and the 

Clean Air Mercury Rule; Proposed Rule 


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49254 Federal Register / Vol. 71, No. 162 / Tuesday, August 22, 2006 / Proposed Rules 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Parts 72 and 75 

[OAR–2005–0132; FRL–8208–1] 

Revisions to the Continuous 

Emissions Monitoring Rule for the 

Acid Rain Program, NOX Budget 

Trading Program, the Clean Air 

Interstate Rule, and the Clean Air 

Mercury Rule 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Proposed rule. 

SUMMARY: EPA is proposing rule 

revisions that would modify existing 

requirements for sources affected by the 

federally administered emission trading 

programs including the NOX Budget 

Trading Program, the Acid Rain 

Program, the Clean Air Interstate Rule, 

and the Clean Air Mercury Rule. 

The proposed revisions are prompted 

primarily by changes being 

implemented by EPA’s Clean Air 

Markets Division in its data systems in 

order to utilize the latest modern 

technology for the submittal of data by 

affected sources. Other revisions 

address issues that have been raised 

during program implementation, fix 

specific inconsistencies in rule 

provisions, or update sources 

incorporated by reference. These 

revisions would not impose significant 

new requirements upon sources with 

regard to monitoring or quality 

assurance activities. 

DATES: All public comments must be 

received on or before October 23, 2006. 

ADDRESSES: Submit your comments, 

identified by Docket ID No. EPA–HQ– 

OAR–2005–0132, by one of the 

following methods: 

• Federal eRulemaking Portal: http:// 

www.regulations.gov. Follow the on-line 

instructions for submitting comments. 

• E-mail: a-and-r-docket@epa.gov. 

• Fax: (202) 566–1741. 

• Hand Delivery: Air and Radiation 

Docket, Environmental Protection 

Agency, 1301 Constitution Avenue, 

NW., Room B–108, Washington, DC 

20014. Such deliveries are accepted 

only during the Docket’s normal hours 

of operation and special arrangements 

should be made for deliveries of boxed 

information. 

• Mail: EPA Docket Center (EPA/DC), 

Environmental Protection Agency, 

Mailcode 6102T, 1200 Pennsylvania 

Avenue, NW., Washington, DC 20460. 

Please include a total of two copies. We 

request that a separate copy also be sent 

to the contact person identified below 

(see FOR FURTHER INFORMATION CONTACT). 

Instructions: Direct your comments to 

Docket ID No. EPA–HQ–OAR–2005– 

0132. EPA’s policy is that all comments 

received will be included in the public 

docket without change and may be 

made available online at http:// 

www.regulations.gov including any 

personal information provided, unless 

the comment includes information 

claimed to be Confidential Business 

Information (CBI) or other information 

whose disclosure is restricted by statute. 

Do not submit information that you 

consider to be CBI or otherwise 

protected through http:// 

www.regulations.gov or e-mail. The 

http://www.regulations.gov Web site is 

an ‘‘anonymous access’’ system, which 

means EPA will not know your identity 

or contact information unless you 

provide it in the body of your comment. 

If you send an e-mail comment directly 

to EPA without going through http:// 

www.regulations.gov, your e-mail 

address will be automatically captured 

and included as part of the comment 

that is placed in the public docket and 

made available on the Internet. If you 

submit an electronic comment, EPA 

recommends that you include your 

name and other contact information in 

the body of your comment with a disk 

or CD–ROM you submit. If EPA cannot 

read your comment due to technical 

difficulties and cannot contact you for 

clarification, EPA may not be able to 

consider your comment. Electronic files 

should avoid the use of special 

characters, any form of encryption, and 

be free of any defects or viruses. Docket: 

All documents in the docket are listed 

in the http://www.regulations.gov index. 

Although listed in the index, some 

information is not publicly available, 

e.g., CBI or other information whose 

disclosure is restricted by statute. 

Certain other material, such as 

copyrighted material, will be publicly 

available only in hard copy. Publicly 

available docket materials are available 

either electronically in http:// 

www.regulations.gov 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: 

Matthew Boze, Clean Air Markets 

Division, U.S. Environmental Protection 

Agency, Clean Air Markets Division, MC 

6204J, Ariel Rios Building, 1200 

Pennsylvania Ave., NW., Washington, 

DC 20460, telephone (202) 343–9211, email at boze.matthew@epa.gov. 

Electronic copies of this document can 

be accessed through the EPA Web site 

at: http://www.epa.gov/airmarkets. 

SUPPLEMENTARY INFORMATION: Regulated 

Entities. Entities regulated by this action 

primarily are fossil fuel-fired boilers, 

turbines, and combined cycle units that 

serve generators that produce electricity, 

generate steam, or cogenerate electricity 

and steam. Some trading programs 

include process sources, such as process 

heaters or cement kilns. Although Part 

75 primarily regulates the electric utility 

industry, certain State and Federal NOX

mass emission trading programs rely on 

subpart H of Part 75, and those 

programs may include boilers, turbines, 

combined cycle, and certain process 

units from other industries. Regulated 

categories and entities include: 

Category NAICS code Examples of potentially regulated industries 

Industry ............................................ 221112 and others ........................ Electric service providers Process sources with large boilers, turbines, combined cycle units, process heaters, or cement kilns 

where emissions exhaust through a stack. 

This table is not intended to be 

exhaustive, but rather to provide a guide 

for readers regarding entities likely to be 

regulated by this action. This table lists 

the types of entities which EPA is now 

aware could potentially be regulated by 

this action. Other types of entities not 

listed in this table could also be 

regulated. To determine whether your 

facility, company, business, 

organization, etc., is regulated by this 

action, you should carefully examine 

the applicability provisions in §§ 72.6, 

72.7, and 72.8 of title 40 of the Code of 

Federal Regulations and in 40 CFR Parts 

96 and 97. If you have questions 

regarding the applicability of this action 

to a particular entity, consult the person 

listed in the preceding FOR FURTHER

INFORMATION CONTACT section. 


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Federal Register / Vol. 71, No. 162 / Tuesday, August 22, 2006 / Proposed Rules 49255 

Submitting CBI. Do not submit this 

information to EPA through http:// 

www.regulations.gov or e-mail. Clearly 

mark the part or all of the information 

that you claim to be CBI. For CBI 

information on a disk or CD–ROM that 

you mail to EPA, mark the outside of the 

disk or CD–ROM as CBI and then 

identify electronically within the disk or 

CD–ROM the specific information that 

is claimed as CBI. In addition to one 

complete version of the comment that 

includes information claimed as CBI, a 

copy of the comment that does not 

contain the information claimed as CBI 

must be submitted for inclusion in the 

public docket. Information so marked 

will not be disclosed except in 

accordance with procedures set forth in 

40 CFR part 2. 

World Wide Web (WWW). In addition 

to being available in the docket, an 

electronic copy of the proposed rule is 

also available on the WWW through the 

Technology Transfer Network Web site 

(TTN Web). Following signature, a copy 

of the proposed 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. 

Outline: 

I. Detailed Discussion of Proposed Rule 

Revisions 

A. Rule Definitions 

B. General Monitoring Provisions 

C. Certification Requirements 

D. Missing Data Substitution 

E. Recordkeeping and Reporting 

F. Subpart H (NOX Mass Emissions) 

G. Subpart I (Hg Mass Emissions) 

H. Appendix A 

I. Appendix B 

J. Appendix D 

K. Appendix E 

L. Appendix F 

M. Appendix G 

N. Appendix K 

II. Administrative Requirements 

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 That 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer and 

Advancement Act 

I. Detailed Discussion of Proposed Rule 

Revisions 

EPA is in the process of reengineering the data systems associated 

with the collection and processing of 

emissions, monitoring plan, quality 

assurance, and certification data. The reengineering project includes the 

creation of a client tool, provided by 

EPA that sources will use to evaluate 

and submit their Part 75 monitoring 

data. This process change will enable 

sources to assess the quality of their 

data prior to submitting the data using 

EPA established checking criteria. The 

process will also allow sources to report 

their data directly to a database. Having 

the data in a true database will allow the 

Agency to implement and assess the 

program more efficiently and will 

streamline access to the data. Also, this 

database structure will enable EPA to 

implement process changes that will 

reduce the redundant reporting of 

certain types of data. The re-engineered 

systems will be supported by a new 

extensible markup language (XML) data 

format that will replace the record type/ 

column format currently used by EPA to 

collect electronic data. EPA intends to 

transition existing sources to the new 

XML electronic data report (XML–EDR) 

format during the 2008 reporting year. 

For sources reporting in 2008 for the 

first time, the new XML–EDR format 

should be used. All sources will be 

required to use the new process 

beginning 2009. 

A. Rule Definitions 

The proposed changes to Part 72 

include adding a definition for ‘‘longterm cold storage’’ to mean ‘‘the 

complete shutdown of a unit intended 

to last for an extended period of time (at 

least two calendar years) where notice 

for long-term cold storage is provided 

under § 75.61(a)(7). See Section II.E.4 of 

this preamble for further discussion. 

EPA also proposes to modify the 

definition of ‘‘capacity factor’’ so that 

the Agency can use the reported 

maximum hourly gross load, as 

currently reported in the electronic 

monitoring plan, to determine whether 

a unit qualifies for peaking unit status, 

by recalculating the capacity factor. This 

is important because the maximum 

hourly gross load can be greater than the 

nameplate capacity. Also, when using 

heat input to define capacity factor, the 

definition would be revised to refer to 

maximum rated hourly heat input rate, 

which is defined in § 72.2. 

The proposed changes to § 72.2 would 

also modify the definition of ‘‘EPA 

Protocol Gas,’’ and add a definition of 

‘‘EPA Protocol Gas Verification 

Program’’, to support the proposed 

calibration gas audit program. EPA is 

also proposing to expand the definition 

of ‘‘excepted monitoring system’’ to 

include the sorbent trap and low mass 

emissions (LME) excepted 

methodologies for Hg. Finally, today’s 

proposed rule would add definitions of 

‘‘Air Emission Testing Body (AETB)’’

and ‘‘Qualified Individual’’, to support 

the proposed stack tester accreditation 

program. See Sections II.H.2 and II.H.3 

of this preamble for a discussion of 

these proposed programs. 

B. General Monitoring Provisions 

1. Update of Incorporation by Reference 

(§ 75.6) 

Section 75.6 identifies a number of 

methods and other standards that are 

incorporated by reference into Part 75. 

This section includes standards 

published by the American Society for 

Testing and Materials (ASTM), the 

American Society of Mechanical 

Engineers (ASME), the American 

National Standards Institute (ANSI), the 

Gas Processors Association (GPA), and 

the American Petroleum Institute (API). 

Changes in § 75.6 would reflect the need 

to incorporate recent updates for many 

of the referenced standards. The 

proposed revisions would recognize or 

adhere to these newer standards by 

updating references for the standards 

listed in §§ 75.6(a) through 75.6(f). 

Additionally, new §§ 75.6(a)(45) 

through 75.6(a)(48) and 75.6(f)(4) would 

incorporate by reference additional 

ASTM and API standards that are 

relevant to Part 75 implementation. 

2. Default Emission Rates for Low Mass 

Emissions (LME) Units 

Today’s proposed rule revisions 

would allow LME units to use sitespecific default SO2 emission rates for 

fuel oil combustion, in lieu of using the 

‘‘generic’’ default SO2 emission rates 

specified in Table LM–1 of § 75.19. To 

use this option, a federally enforceable 

permit condition would have to be in 

place for the unit, limiting the sulfur 

content of the oil. This revision would 

allow more representative, yet still 

conservatively high, SO2 emissions data 

to be reported from oil-burning LME 

units. The site-specific default SO2

emission rate would be calculated using 

an equation from EPA publication AP–

42. The sulfur content used in the 

calculations would be the maximum 

weight percent sulfur allowed by the 

federally-enforceable permit. Sources 

choosing to implement this option 

would be required to perform periodic 

oil sampling using one of the four 

methodologies described in Section 2.2 


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of Appendix D to Part 75, and would be 

required to keep records documenting 

the sulfur content of the fuel. 

Today’s proposed rule would also 

revise § 75.19(c)(1)(iv)(G) to clarify that 

fuel-and-unit-specific default NOX

emission rates for LME units may be 

determined using data from a 

Continuous Emissions Monitoring 

System (CEMS) that has been qualityassured according to either Appendix B 

of Part 75 or Appendix F of Part 60, or 

comparably quality-assured under a 

State CEMS program. The current rule 

simply states that 3 years (or 3 ozone 

seasons, if applicable) of quality-assured 

CEMS data may be used for this 

purpose, but it does not specify the 

acceptable level of QA required. 

3. Default Moisture Value for Natural 

Gas 

EPA is proposing to allow gas-fired 

boilers equipped with CEMS to use 

default moisture values in lieu of 

continuously monitoring the stack gas 

moisture content. Two default values 

are proposed: 14.0% H2O under 

§ 75.11(b), and 18.0% H2O under 

§ 75.12(b). The higher default value 

would apply only when Equation 19–3, 

19–4, or 19–8 (from Method 19 in 

appendix A of Part 60) is used to 

determine the NOX emission rate. These 

proposed default values are based on 

supplemental moisture data provided to 

the Agency in a December 13, 2004 

petition from a gas-fired industrial 

source and moisture data collected 

during EPA’s development of flow rate 

reference Methods 2F and 2G at two gasfired facilities. (See Docket A–99–14; 

Items II–A–1 and II–A–7). 

EPA selected the 10th and 90th 

percentile values from these data, 

rounded to the nearest whole number, 

as the proposed natural gas default 

moisture values. The selection of 

conservative 90th or 10th percentile 

values from representative moisture 

data sets is consistent with the approach 

that the Agency has approved in 

response to past petition under § 75.66 

requesting to use site-specific default 

moisture values. 

4. Expanded Use of Equation F–23 

Today’s proposed rule would revise 

§ 75.11(e)(1) to remove the current 

restrictions on the use of Equation F–23 

to determine the SO2 mass emission 

rate. The current rule restricts the use of 

this equation to units equipped with 

SO2 monitors and to hours when only 

fuel that meets the Part 72 definition of 

‘‘pipeline natural gas’’ or ‘‘natural gas’’

is being combusted. EPA proposes to 

allow Equation F–23 to be used whether 

or not the unit has an SO2 monitor and 

to expand its use to fuels other than 

natural gas. 

Section 75.11(e) would be re-titled as 

‘‘Special considerations during the 

combustion of gaseous fuels’’, and the 

introductory text of the section would 

be revised, so that the section would no 

longer apply exclusively to units with 

SO2 monitors. Rather, it would apply to 

units that use certified flow rate and 

diluent gas monitors to quantify heat 

input. Such units would be required to 

implement the provisions of either 

revised § 75.11(e)(1) or revised 

§ 75.11(e)(3) when gaseous fuel is the 

only fuel combusted in the unit. Section 

75.11(e)(2) would be removed and 

reserved, as the use of Appendix D 

methodology during gaseous fuel 

combustion is not appropriate for a unit 

that uses flow and diluent monitors to 

measure heat input. This is because 

only one heat input methodology is 

allowed for each unit. 

Revised § 75.11(e)(1) would expand 

the use of Equation F–23 beyond natural 

gas combustion to include the 

combustion of any gaseous fuel that 

qualifies for a default SO2 emission rate 

under Section 2.3.6(b) of Appendix D. 

The proposed revisions to § 75.11(e)(3) 

would be relatively minor. The option 

to use a certified SO2 monitor during 

hours of gaseous fuel combustion would 

be retained. 

A new paragraph (e)(4) would also be 

added to § 75.11(e). This new provision 

would allow Equation F–23 to be used 

for the combustion of liquid and solid 

fuels that meet the definition of ‘‘very 

low sulfur fuel’’ in § 72.2, if a petition 

for a fuel-specific default SO2 emission 

rate is submitted to the Administrator 

under § 75.66 and the Administrator 

approves the petition. Similar petitions 

would also be accepted for the 

combustion of mixtures of these fuels 

and for the co-firing of these fuels with 

gaseous fuel. 

EPA believes that expanding the use 

of Equation F–23 will benefit certain 

units that are subject to the Acid Rain 

Program or to the SO2 provisions of the 

Clean Air Interstate Rule (CAIR). In 

particular, the requirement to operate 

and maintain an SO2 CEMS could be 

waived for units that burn low-sulfur 

solid fuels such as wood waste. Also, for 

units that combust non-traditional 

gaseous fuels, Equation F–23 would 

provide an alternative way of 

quantifying SO2 mass emissions that 

does not require either an SO2 CEMS or 

a certified fuel flowmeter. 

5. Calculation of NOX Emission Rate—

LME Units 

According to §§ 75.58(f), 75.64(a)(4), 

and 75.64(a)(9), oil and gas-fired units 

in the Acid Rain Program that qualify to 

use the low mass emissions (LME) 

methodology in § 75.19 are required to 

report both NOX mass emissions (lb or 

tons, as applicable) and NOX emission 

rate (lb/mmBtu) on an hourly, quarterly 

and annual basis. However, the 

mathematics in § 75.19(c)(4)(ii) pertains 

only to NOX mass emissions, not NOX

emission rate. This is most likely 

because the criterion for initial and ongoing LME qualification is based on the 

total tons of NOX emitted the calendar 

year, rather than on the NOX emission 

rate. 

Today’s rule would re-title 

§ 75.19(c)(4)(ii) as ‘‘NOX mass emissions 

and NOX emission rate’’, and would add 

a new subparagraph (D) to § 75.19 

(c)(4)(ii), providing instructions for 

determining quarterly and cumulative 

NOX emission rates for an LME unit. 

The NOX emission rate for each hour 

(lb/mmBtu) would simply be the 

appropriate generic or unit-specific 

default NOX emission rate defined in 

the monitoring plan for the type of fuel 

being combusted and (if applicable) the 

NOX emission control status. The 

quarterly NOX emission rate would be 

determined by averaging all of the 

hourly NOX emission rates and the 

cumulative (year-to-date) NOX emission 

rate would be the arithmetic average of 

the quarterly values. 

6. LME Units—Scope of Applicability 

Today’s rule would revise 

§ 75.19(a)(1) to clarify that the low mass 

emissions (LME) methodology is a 

stand-alone alternative to a CEMS and/ 

or the ‘‘excepted’’ monitoring 

methodologies in Appendices D, E, and 

G. In other words, if a unit qualifies for 

LME status, the owner or operator 

would be required either to use the LME 

methodology for all parameters or not to 

use the method at all. No mixing-andmatching of other monitoring 

methodologies with LME would be 

permitted. For example, the owner or 

operator of a qualifying LME unit in the 

Acid Rain Program would either be 

required to follow the provisions of 

§ 75.19 for all parameters (i.e., SO2 and 

CO2 mass emissions, NOX emission rate, 

and unit heat input) or to monitor these 

parameters using a CEMS, Appendices 

D, E, and G, or a combination of these 

other methods. EPA has always 

intended for the LME methodology to be 

applied this way, but this was not 

explicitly stated in § 75.19 and in other 

sections of the rule. In fact, 

§§ 75.11(d)(3), 75.12(e)(3), and 

75.13(d)(3)) suggest that mixing other 

monitoring methodologies with LME 

might not be prohibited. Today’s rule 

would also make parallel revisions to 


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these other sections, consistent with the 

changes to § 75.19(a)(1), to clarify the 

Agency’s intent. 

7. Use of maximum controlled NOX

emission rate when using bypass stacks 

Today’s proposed rule would revise 

§ 75.17(d)(2) to allow for the calculation 

and use of a maximum controlled NOX

emission rate (MCR) instead of the 

maximum potential NOX emission rate 

(MER) whenever an unmonitored 

bypass stack is used, provided that the 

add-on controls are not bypassed and 

are documented to be operating 

properly. Documentation of proper addon control operation for such hours of 

operation would be required as 

described in § 75.34(d). The MCR would 

be calculated in a manner similar to the 

calculation of the MER, except that the 

maximum expected NOX concentration 

(MEC) would be used instead of the 

maximum potential NOX concentration 

(MPC). EPA believes that this proposal 

would more fairly account for 

controlled emissions when unmonitored 

bypass stacks are used. The rule 

currently requires the use of the MER 

regardless of the operation and usage of 

add-on controls. When § 75.17(d)(2) was 

originally promulgated, EPA assumed 

that the add-on controls would be 

bypassed whenever a bypass stack is 

used. EPA is now aware that there are 

situations where this is not the case. An 

example would be a coal-fired unit 

equipped with FGD and SCR add-on 

emission controls. If the SCR is 

documented to be working during an 

FGD malfunction and the effluent gases 

are routed through an unmonitored 

bypass stack after passing through the 

SCR, then the MEC, rather than the 

MER, would be the more appropriate 

NOX emission rate to report for the 

bypass hour(s). 

C. Certification Requirements 

1. Alternative Monitoring System 

Certification 

The proposed rule would delete 

§§ 75.20(f)(1) and (2) from the rule, 

thereby removing the requirement for 

the Administrator to publish each 

request for certification of an alternative 

monitoring system in the Federal 

Register, with an associated 60-day 

public comment period. This rule 

provision is considered unnecessary, in 

view of the Agency’s authority under 

Subpart E to approve alternative 

monitoring systems and the rigorous 

requirements that alternative monitoring 

systems must meet in order to be 

certified. 

2. Part 60 Reference Test Methods 

On May 15, 2006, EPA promulgated 

final revisions to EPA reference test 

methods 6C, 7E, and 3A, which are 

found in Appendix A of 40 CFR Part 60. 

(See 71 FR 28082, May 15, 2006). 

Today’s proposed rule would update, 

(as necessary), various section 

references to these reference methods, 

as well as specify certain options that 

are not to be applied to RATA testing 

under Part 75. Specifically, the 

following provisions are not permitted 

unless specific approval is granted by 

the Administrator of Part 75: 

(1) § 7.1 of the revised EPA Method 7E 

allowing for use of prepared calibration 

gas mixtures that are produced in 

accordance with Method 205 in 

Appendix M of 40 CFR Part 51. EPA 

maintains that for RATA testing under 

Part 75, that reference gases be selected 

in accordance with § 5.1 of Appendix A 

of 40 CFR Part 75. 

(2) § 8.4 of the revised EPA Method 7E 

allowing for the use of a multi-hole 

probe to satisfy the multipoint traverse 

requirement of the method. 

(3) § 8.6 of the revised EPA Method 7E 

allowing for the use of ‘‘Dynamic 

Spiking’’ as an alternative to the 

interference and system bias checks of 

the method. This proposed rule would 

allow for dynamic spiking to be 

conducted (optionally) as an additional 

quality assurance check for Part 75 

applications. 

3. Mercury Reference Methods 

Today’s proposed rule would add an 

alternative acceptance criterion for the 

results of mercury (Hg) emission data 

collected with the Ontario Hydro (OH) 

reference method and would allow the 

use of alternative reference methods for 

RATAs and for the low mass Hg 

emission testing described in § 75.81(c). 

On May 18, 2005, EPA published the 

Clean Air Mercury Rule (CAMR). That 

rule requires coal-fired electric 

generating units (EGUs) to reduce Hg 

emissions, starting in 2010, and to 

continuously monitor Hg mass 

emissions according to Subpart I of Part 

75, beginning in 2009. 

Relative accuracy test audits (RATAs) 

of all continuous Hg monitoring systems 

are required under CAMR, and Hg 

emission testing is required for units 

seeking to qualify as low mass emitters 

under § 75.81(c). The principal 

reference method specified for the 

RATAs and the emission testing is the 

OH method. Alternatively, an 

instrumental method approved by the 

Administrator may be used. When the 

OH method is performed, § 75.22(a)(7) 

requires paired sampling trains for each 

test run, and the relative deviation (RD) 

of the results from the two trains must 

not exceed 10 percent. 

As part of the May 18, 2005 

rulemaking, EPA also promulgated 

revisions to Subpart Da of the New 

Source Performance Standards (NSPS) 

regulations, requiring continuous Hg 

emission monitoring for new coal-fired 

electric utility units constructed after 

January 1, 2004. Along with the Subpart 

Da revisions, a performance 

specification, PS–12A, for certifying the 

required continuous Hg monitors was 

published. PS–12A, like Part 75, 

requires RATA testing of all Hg 

monitoring systems, using paired 

reference method sampling trains; 

however, note that PS 12–A allows EPA 

Method 29 (from Appendix A–8 of 40 

CFR Part 60) to be used as an alternative 

to the OH method, whereas Part 75 does 

not. 

The principal acceptance criterion in 

Section 8.6.6.2 of PS 12–A for the data 

from the paired reference method trains 

(10 percent RD) is the same as in 

§ 75.22(a)(7). However, PS 12–A 

includes an alternative acceptance 

criterion for sources with low Hg 

emissions. If the average Hg 

concentration during the RATA is 1.0 

μg/m3 or less, the RD specification is 20 

percent. In view of this, today’s 

proposed rule would revise 

§ 75.22(a)(7), to include this same 20 

percent alternative RD specification for 

low-emitters. This would harmonize the 

Part 60 and Part 75 RATA provisions for 

Hg monitors, thereby facilitating 

compliance for sources subject to both 

sets of regulations. 

EPA is also proposing revisions to 

§§ 75.22(a)(7) and 75.81(c)(1) which 

would allow EPA Method 29 to be used 

as an alternative to the OH method, both 

for RATA testing and for periodic 

emission testing of units with low Hg 

mass emissions (≤ 29 lb/yr). Method 29 

is an established test procedure that 

uses atomic absorption spectroscopy to 

determine the concentration of various 

metals, including Hg, in the stack gas. 

This method is more familiar to 

emission testers than the OH method, 

and Method 29 data have been accepted 

for compliance purposes by the State. 

Method 29 and the OH method both 

measure the total vapor phase Hg in the 

effluent. The main difference between 

the two methods is that the OH method 

performs ‘‘speciation’’ of the vapor 

phase Hg, i.e., it quantifies the elemental 

and ionic portions of the vapor phase 

Hg separately, whereas Method 29 does 

not. However, the CAMR rule does not 

require speciation of the vapor phase 

Hg. Therefore, Method 29 could be used 

instead of the OH method. 


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There would be two caveats on the 

use of Method 29. First, sources electing 

to use Method 29 would be required to 

use paired sampling trains (i.e., two 

trains sampling the source effluent 

simultaneously), and the relative 

deviation specification in § 75.22(a)(7) 

would have to be met for each run. The 

test results for each valid run would be 

based on the Hg collected in the back 

half of each sampling train (i.e., the 

impinger catch), and the results from 

the two trains would be averaged 

arithmetically. 

Second, certain analytical and QA 

procedures in the OH method (ASTM 

D6784–02) would be followed instead of 

the corresponding procedures in 

Method 29. Specifically, testers would 

be required to replace the procedures in 

sections 7.5.33 and 11.1.3 of Method 29 

with the corresponding procedures in 

sections 13.4.1.1 through 13.4.1.3 of 

ASTM D6784–02, and to perform the 

QA/QC procedures in section 13.4.2 of 

the OH method instead of the 

procedures in section 9.2.3 of Method 

29. EPA believes that implementing 

these sections of the OH method in lieu 

of the corresponding Method 29 

provisions will improve the quality of 

the data, because the analytical and QA/ 

QC requirements of the OH method are 

more detailed and rigorous than those in 

Method 29. 

EPA is also proposing to allow several 

of the sample recovery and preparation 

procedures in the OH method to be 

followed instead of the Method 29 

procedures. In particular: (a) Sections 

13.2.9.1 through 13.2.9.3 of the OH 

method could be followed instead of 

sections 8.2.8 and 8.2.9.1 of RM 29; (b) 

sections 13.2.10.1 through 13.2.10.4 of 

the OH method could be followed 

instead of sections 8.2.9.2 and 8.2.9.3 of 

RM 29; (c) section 8.3.4 of RM 29 could 

be replaced with section 13.3.4 or 13.3.6 

of the OH method (as appropriate); and 

(d) section 8.3.5 of RM 29 could be 

replaced with section 13.3.5 or 13.3.6 of 

the OH method (as appropriate). Use of 

these alternative procedures would 

increase the accuracy of moisture 

content determinations (by using a 

gravimetric rather than a volumetric 

technique), and would eliminate of the 

need for two separate analyses of the 

KMnO4 fraction. 

Revisions to § 75.59 and to Sections 

6.5.10 and 7.6.1 of Appendix A to Part 

75 are also being proposed, for purposes 

of consistency with the proposed 

changes to §§ 75.22(a)(7) and 

75.81(c)(1). 

Finally, the Agency is soliciting 

comment on the use of sorbent traps for 

reference method testing. At the 2006 

Electric Utility Environmental 

Conference (EUEC) in Tucson, Arizona, 

a stakeholder meeting was held to 

discuss mercury monitoring issues. 

Many of the participants expressed an 

interest in using portable sorbent trap 

monitoring systems for Hg reference 

method testing, as an alternative to the 

OH method. After much internal 

discussion, EPA believes that a sorbent 

trap system could potentially serve as 

an alternative reference method for Hg 

emission testing and RATA 

applications, if it can be adequately 

demonstrated that the method does not 

have an inherent measurement bias 

when compared to the OH method, and 

if sufficiently rigorous quality-assurance 

(QA) procedures are developed and 

followed when the system is used in the 

field. In view of this, EPA requests 

comment on how such a demonstration 

might be made and what QA procedures 

would be appropriate. In anticipation 

that a viable reference method using 

sorbent trap technology may be 

developed in the near future, the 

Agency is also proposing to add 

language to § 75.22(a)(7), which would 

allow an ‘‘other suitable’’ reference 

method approved by the Administrator 

to be used for Hg emission testing and 

RATAs. 

D. Missing Data Substitution 

1. Block Versus Step-Wise Approach 

During periods of missing CEMS data, 

Part 75 requires substitute data to be 

reported. Special mathematical 

algorithms are used to determine the 

appropriate substitute data values. As 

the length of a missing data period 

increases, the percent monitor data 

availability (PMA) decreases, and the 

required substitute data values become 

increasingly conservative each time that 

a particular PMA ‘‘cut point’’ is reached. 

The cut points are 95%, 90%, and 80% 

PMA for all parameters except Hg. For 

Hg, the cut points are slightly lower, i.e., 

at 90%, 80% and 70% PMA. 

Historically, EPA’s policy has 

required sources to use a ‘‘block’’

approach for missing data substitution. 

The PMA at the end of the missing data 

period has been used to determine 

which mathematical algorithm applies, 

and the substitute data value or values 

prescribed by that one algorithm have 

been reported for each hour of the 

missing data period. 

However, EPA has recently revised its 

missing substitution data policy. The 

revised policy guidance (see ‘‘Part 75 

Emission Monitoring Policy Manual’’, 

Question 15.5) allows sources to apply 

the missing data algorithms in a 

stepwise manner instead of using the 

block approach. Under the stepwise 

methodology, the various missing data 

algorithms are applied sequentially. 

That is, the least conservative algorithm 

is applied to the missing data hours 

until the PMA drops below 95%. Then, 

the next algorithm is applied until the 

PMA has dropped below 90%, and so 

on. 

Part 75 is not clear about which of the 

two methods should be used for missing 

data substitution. Today’s proposed rule 

would revise the text of certain 

paragraphs in §§ 75.33 and 75.32(b), to 

clarify that the stepwise, hour-by-hour 

method (which is the least stringent 

approach) is the preferred one. The 

Agency favors this approach because it 

prevents sources from being penalized 

by the retroactive application of more 

stringent missing data algorithms to 

hours where the hourly PMA merits the 

use of less conservative algorithms. EPA 

intends that only the new stepwise, 

hour-by-hour method be used after 

January 1, 2009, or whenever emissions 

data are to be submitted in XML–format. 

Until this time, either method will be 

accepted. 

2. Substitute Data Values for Controlled 

Units 

For units with add-on emission 

controls, § 75.34(a)(3) provides that the 

designated representative (DR) may 

petition the Administrator under § 75.66 

to report alternative substitute data 

values in certain instances. Specifically, 

when the percent monitor data 

availability (PMA) for SO2 or NOX is 

below 90.0 percent, the DR may petition 

to replace the maximum emission rate 

recorded in the last 720 quality-assured 

monitor operating hours with the 

maximum controlled emission rate 

recorded during that same lookback 

period, for each missing data hour in 

which the add-on controls are 

documented to be operating properly. 

Until recently, this petition provision 

applied only to units with add-on SO2

or NOX emission controls. However, 

revisions to Part 75 on May 18, 2005, 

extended it to include units with addon Hg controls (see § 75.38(c)). 

For several reasons, EPA believes it is 

appropriate to revise § 75.34(a)(3). First, 

the 720 hour lookback is only 

appropriate for SO2 and Hg. For NOX, 

the lookback should be 2,160 hours and 

should also be load-based. Second, for 

SO2, Hg, and NOX concentration 

monitoring systems, the terms 

‘‘maximum emission rate’’ and 

‘‘maximum controlled emission rate’’

are not appropriate and should be 

replaced by ‘‘maximum concentration’’

and ‘‘maximum controlled 

concentration’’, respectively. Third, the 

petition provision, as written, applies to 


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all PMA values below 90.0 percent (that 

was the intent when it was originally 

written), but in light of subsequent 

revisions to Part 75, it should be 

restricted to a narrower range of PMA 

values. Fourth, and most important, 

after more than ten years of 

implementing the Acid Rain Program, 

EPA no longer believes that special 

petitions are necessary to use maximum 

controlled values for missing data 

substitution, because sources with addon controls are required to implement a 

quality assurance/quality control (QA/ 

QC) program that includes the recording 

of parametric data to document the 

hourly operating status of the emission 

controls. This parametric information 

must be made available to inspectors 

and auditors upon request. Therefore, 

any claim that the emission controls 

were operating properly during a 

particular missing data period can be 

easily verified through the audit 

process. 

At the time the petition provision in 

§ 75.34(a)(3) was written, there were 

only three missing data tiers in 

existence, i.e., for PMA values: (1) ≥ 95.0 

percent; (2) ≥ 90.0 percent, but < 95.0 

percent: and (3) < 90.0 percent. The 

provision was associated with the third 

tier (PMA < 90.0 percent), for which the 

required substitute data value is the 

maximum value recorded in a specified 

lookback period. However, on May 26, 

1999, EPA added a fourth CEMS 

missing data tier to Part 75. The May 

1999 rule revisions did not change the 

missing data algorithms for the third 

tier, but the PMA ‘‘cut off’’ point for the 

third tier was set at 80.0 percent, and 

below 80.0 percent PMA, reporting of 

the maximum potential concentration 

(MPC) or the maximum potential NOX

emission rate (MER) was required for a 

missing data period of any length. 

Today’s proposed rule would remove 

from § 75.34(a)(3) and § 75.66(f) the 

requirement to petition the 

Administrator to use the maximum 

controlled SO2 or NOX concentration (or 

maximum controlled NOX emission 

rate) from the applicable lookback 

period. The proposed revisions would 

simply allow the maximum controlled 

values to be reported whenever 

parametric data are available to 

document that the emission controls are 

operating properly. The proposed rule 

would further clarify that this reporting 

option applies only to the third missing 

data tier, when the PMA is greater than 

or equal to 80.0 percent, but less than 

90.0 percent. 

EPA is also proposing to add a new 

paragraph (a)(5) to § 75.34, which would 

allow units with add-on emission 

controls to report alternative substitute 

data values for missing data periods in 

the fourth tier, when the PMA is below 

80.0 percent. Proposed § 75.34(a)(5) 

would allow the owner or operator to 

replace the maximum potential SO2 or 

NOX concentration (MPC) or the 

maximum potential NOX emission rate 

(MER) with a less conservative 

substitute data value, for missing data 

hours where parametric data, (as 

described in §§ 75.34(d) and 75.58(b)) 

are available to verify proper operation 

of the add-on controls. Specifically, for 

SO2 and NOX concentration, the 

replacement value for the MPC would 

be the greater of: (a) The maximum 

expected concentration (MEC); or (b) 

1.25 times the maximum controlled 

value in the standard missing data 

lookback period. For NOX emission rate, 

the replacement value for the MER 

would be the greater of: (a) The 

maximum controlled NOX emission rate 

(MCR); or (b) 1.25 times the maximum 

controlled value in the standard missing 

data lookback period. The NOX MCR 

would be calculated in the same manner 

as the NOX MER (see Appendix A, 

section 2.1.2.1(b)), except that the MEC, 

rather than the MPC, would be used in 

the calculation. 

Finally, today’s proposed rule would 

revise § 75.38(c) to extend the 

alternative missing data options for the 

third and fourth tiers to mercury (Hg) 

concentration, and § 75.58(b)(3) would 

be revised to be consistent with the 

proposed revisions to §§ 75.34(a)(3), 

75.34(a)(5), and 75.38(c). 

EPA believes that for missing data 

hours in which the emission controls 

are working properly, these proposed 

rule revisions will prevent gross 

overestimation of emissions during 

hours when the source is operating its 

emission controls in a manner that is 

protective of the environment. When the 

emission controls are working properly, 

there can be as much as a tenfold 

difference between the MPC, MER, or 

maximum value in a lookback period 

and the actual source emissions. The 

proposed alternative substitute data 

values in §§ 75.34(a)(3) and (a)(5), 

though much closer to the actual 

emissions, would still be conservatively 

high and would provide the owner or 

operator with a strong incentive to keep 

the CEMS operational. The Agency also 

believes that the proposed alternative 

data substitution methodology in 

§ 75.34(a)(5) ensures that the substitute 

data values for the fourth tier will 

always be higher than the corresponding 

substitute data values for the third tier. 

3. Substitute Data Values for Hg 

EPA is also proposing to revise the Hg 

missing data procedures. First, for Hg 

CEMS, the text of § 75.38(a) would be 

amended to make it consistent with 

Table 1 in § 75.33. Proposed § 75.38(a) 

clarifies that the percent monitor data 

availability (PMA) ‘‘trigger conditions’’

for Hg monitoring systems are different 

from the trigger conditions for all other 

parameters. For all parameters except 

Hg, the trigger points that define the 

boundaries of the four missing data tiers 

are 95 percent, 90 percent, and 80 

percent PMA. However, for Hg the 

corresponding trigger points are 90 

percent, 80 percent and 70 percent, 

respectively. 

Second, EPA proposes to completely 

revise the missing data provisions in 

§ 75.39 for sorbent trap monitoring 

systems. In the current rule, the missing 

data routines for sorbent trap systems 

are substantially different from those for 

Hg CEMS. At the time of publication of 

the Part 75 Hg monitoring provisions, 

the Agency believed that a different 

approach to missing data substitution 

was appropriate for sorbent traps, 

because unlike the Hg CEMS, a sorbent 

trap system does not provide real-time 

hourly average emissions data. 

Consequently, EPA prescribed a 12- 

month missing data ‘‘lookback’’ period 

for the sorbent trap systems. That is, the 

substitute data values are based on a 

lookback through the previous 12 

months of sorbent trap sample results, 

instead of looking back through 720 

quality-assured monitor operating 

hours, as is done for the Hg CEMS. 

EPA has reconsidered the sorbent trap 

missing data methodology and has 

concluded that it is unnecessarily 

complex and will likely be difficult to 

implement and audit. In view of this, 

the Agency proposes to amend the 

missing data procedures for sorbent trap 

systems, to make them the same as for 

Hg CEMS. Section 75.39 would be 

revised to require that the initial 

missing data procedures of § 75.31(b) 

and the standard Hg missing data 

provisions of § 75.38 be followed for 

sorbent trap systems. EPA believes that 

this missing data approach can work 

because for the purposes of Part 75 

reporting, the average Hg concentration 

measured by a sorbent trap system is 

‘‘back-filled’’ into each hour of the data 

collection period to simulate hour-byhour concentration measurements (see 

§ 75.57(j)(1)(iii)). Thus, the hourly Hg 

concentration data stream from a 

sorbent trap system will look essentially 

the same as the data stream from a 

CEMS, except that the Hg concentration 

will ‘‘flat-line’’ (i.e., will not change) 

during each data collection period. 

Therefore, the required missing data 

lookbacks through 720 hours of qualityassured data could be done on the 


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sorbent trap data stream, although in 

some cases, because of the flat-line 

effect, when the 720 hours of data are 

arranged in rank order, the 90th 

percentile, 95th percentile, and 

maximum values in the lookback might 

be identical. 

Finally, a new paragraph ‘‘(f)’’ would 

be added to § 75.39 to address the case 

in which the owner or operator elects to 

use a primary Hg CEMS and a 

redundant backup sorbent trap system 

(or vice-versa). In that case, separate Hg 

concentration data streams would be 

recorded and maintained for the two 

systems. For reporting purposes, data 

from the primary monitoring system 

would be reported whenever that 

system is able to provide qualityassured data (see § 75.10(e)), and 

quality-assured data from the redundant 

backup system (if available) could be 

reported during primary monitoring 

system outages. However, when both 

the primary and redundant backup 

monitoring systems are down and 

quality-assured data from a reference 

method or approved alternative 

monitoring system are also unavailable, 

proposed § 75.39(f) would require the 

appropriate substitute data values to be 

derived from a lookback through the 

previous 720 hours of quality-assured 

data reported in the electronic quarterly 

report, irrespective of the source of 

those data, i.e., whether they were from 

the primary system, the redundant 

backup system, a reference method, or 

an approved alternative monitoring 

system. 

4. Correction of Cross-References 

For sources in the NOX Budget 

Program that report emissions data only 

during the ozone season (i.e., May 

through September), the quality 

assurance requirements for the 

continuous emission monitoring 

systems are found in § 75.74(c). In 

§§ 75.74(c)(3)(xi) and (c)(3)(xii), data 

validation rules are provided for 

situations in which required qualityassurance tests of the CEMS are due by 

the end of the second or third calendar 

quarter, but are not completed on time. 

In some cases, these rule provisions 

require the use of missing data 

substitution, and refer to the 

‘‘appropriate missing data routine in 

§ 75.31, § 75.33 or § 75.37’’. These 

references to specific missing data 

sections are inadequate, because they 

only cover initial missing data (for all 

parameters) and the standard missing 

data procedures for NOX , flow rate, and 

moisture. Sections 75.34 through 75.36 

are not referenced, which address 

missing data substitution for units with 

add-on emission controls and for 

diluent gas (O2 or CO2) data used for 

heat input rate determination. Many 

NOX Budget Program units are equipped 

with add-on NOX emission controls, and 

a great number use data from a CO2 or 

O2 monitor to determine the hourly heat 

input rate. In view of this, today’s rule 

would revise §§ 75.74(c)(3)(xi) and 

(c)(3)(xii) by replacing each of the crossreferences to specific missing data 

sections with a more general reference 

to the entire block of CEMS missing data 

sections, i.e., §§ 75.31 through 75.37. 

E. Recordkeeping and Reporting 

1. Revisions to the General Monitoring 

Plan Recordkeeping Requirements 

EPA proposes to revise the monitoring 

plan recordkeeping requirements in 

§ 75.53, to accommodate its new, reengineered XML reporting format, 

which will replace the current 

electronic data reporting (EDR) format 

in 2009. The Subpart H monitoring plan 

record keeping provisions in 

§ 75.73(c)(3) (for sources reporting NOX

mass emissions) and the Subpart I 

monitoring plan record keeping 

provisions in § 75.84 (for sources 

reporting Hg mass emissions) would be 

similarly revised to reflect the transition 

to XML format. 

EPA proposes to add two new 

paragraphs, (g) and (h), to § 75.53, 

which describe the required monitoring 

plan data elements in EPA’s reengineered XML data structure. 

Proposed § 75.53(a)(1) would require all 

affected units to follow the provisions of 

paragraphs (g) and (h) instead of the 

existing recordkeeping requirements of 

paragraphs (e) and (f), on and after 

January 1, 2009. However, early 

implementation of the XML format 

would be allowed or, in some cases, 

required. In 2008, existing sources 

would be allowed to choose between the 

EDR format and XML, and new sources 

reporting for the first time in 2008 

would be required to use XML. 

Table 1 summarizes the data elements 

or requirements in § 75.53 that would be 

removed, replaced or added as a result 

of transitioning from the current EDR to 

XML EDR format. 

TABLE 1.—MONITORING PLAN CHANGES ASSOCIATED WITH XML FORMAT

Data element(s) or requirement(s) Proposed action(s) Comments 

• Facility short name ........................................................

• Unit program classification 

• Unit boiler type 

• Date of commence operation (Subpart H units) 

• Date of commence commercial operation (Acid Rain 

units) 

• Unit retirement date 

• Program code 

• Reporting frequency 

• Program participation date 

• State regulation code 

• State or local agency code 

• EIA cross-reference information. 

Remove .............................. These data elements would be collected and maintained through the Certificate of Representation form, 

the CAMD Business System, or internally by EPA. 

• Recording and reporting of information associated 

with monitoring system certification, recertification, and 

other events.

Relocate ............................. Relocate the requirement to record and report this information to § 75.59, the quality-assurance recordkeeping section. 

• Fuel classification for boiler ..........................................

• Primary/secondary control indicator 

• Type of fuel associated with each monitoring methodology 

• Primary/secondary methodology indicator 

• Appendix E correlation curve segment data. 

Remove .............................. These data elements are deemed unnecessary for the 

new XML reporting format. 


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TABLE 1.—MONITORING PLAN CHANGES ASSOCIATED WITH XML FORMAT—Continued 

Data element(s) or requirement(s) Proposed action(s) Comments 

• Component status .........................................................

• Formula status 

• Submission status of fuel flowmeter data. 

Replace .............................. In § 75.53(g), use activation date/hour and deactivation 

date/hour instead of status codes to better track updates to monitoring components, formulas, and fuel 

flowmeter information. 

• Indicator of exemption from multi-load flow RATAs .....

• Shape of stack or duct cross-section 

• Stack/duct material of construction 

• Flag to indicate that a monitored location is a duct 

• Indicator of non-load based units. 

Add ..................................... These new data elements are needed to properly assess specific Part 75 quality assurance/quality control 

(QA/QC) requirements and exemptions. 

• Analyzer range code .....................................................

• Moisture measurement basis. 

Add ..................................... Provide the measurement range (high, low, dual) and 

moisture basis (wet or dry) for each CEMS component type (SO2, NOX, CO2, etc.) 

• Provide the monitoring methodologies for each individual unit.

• Represent bypass stack monitoring as a separate 

methodology. 

Replace .............................. For each parameter, associate the monitoring methodology with the monitored lcoation (unit, stack or duct). 

Integrate bypass stack monitoring with other methodologies. Only one monitoring methodology per 

paramter would be allowed. 

• For dual-range applications, indicate the trigger point 

at which the component switches from the normal 

measurement scale to the secondary scale.

Add ..................................... Many times data begin to be recorded on the high 

scale at a certain ‘‘trigger point’’, before the full-scale 

of the low range is reached. EPA needs this information to determine when certain QA tests of the highscale are required. 

• Require operating range and normal load information 

to be reported for units with CEMS and units using 

optional fuel flow-to-load ratio test.

Revise ................................ In § 75.53(g), require operating range and maximum 

load information for all affected units. Require normal 

load determination for all except peaking units. Separate the date of historical load analysis from activation date of the operating range and load information. 

• Duct width at test section ..............................................

• Duct depth at test section 

• WAF 

• Method of determining WAF 

• WAF effective date and hour 

• WAF no longer effective date and hour 

• WAF determination date 

• Number of WAF test runs 

• Number of Method 1 traverse points in WAF test 

• Number of test ports in WAF test 

• Number of Method 1 traverse points in reference flow 

RATA. 

Add ..................................... Add data elements to § 75.53(e) and (g), describing 

monitoring plan requirements for units with rectangular ducts that apply a wall effects adjustment factor 

(WAF) to their flow rate data. (See Section II.E.2 for 

further discussion.) 

2. Discussion of Wall Effects 

Adjustment Requirements for 

Rectangular Ducts 

In 1999, EPA published a new 

reference method, Method 2H, in 

Appendix A of 40 CFR Part 60. Method 

2H allows the owner or operator of a 

unit with an installed flow monitor to 

correct the measured gas flow rates for 

velocity decay near the stack wall (i.e., 

‘‘wall effects’’). Applying Method 2H 

greatly reduces the possibility of overreporting SO2 and NOX mass emissions, 

which are directly proportional to the 

stack flow rate. However, Method 2H 

applies only to circular stacks. 

Consequently, Acid Rain and NOX

Budget Program units with flow 

monitors installed on rectangular stacks 

or ducts (estimated at about 10 percent 

of the affected units with flow monitors) 

were unable to benefit from the use of 

a wall effects adjustment factor (WAF). 

To remedy this situation, a wall 

effects correction method for rectangular 

stacks and ducts was developed. The 

method, known as CTM–041, has been 

adopted as a conditional test method by 

EPA. A conditional test method differs 

from a reference method in that it is not 

in the Code of Federal Regulations, but 

it is recognized as having technical 

merit. Sources interested in using a 

conditional method in a particular 

program must obtain permission from 

the regulatory agency administering the 

program. 

Since 2004, when CTM–041 was 

adopted as a conditional EPA test 

method, many Acid Rain and NOX

Budget Program sources have requested 

(and received) permission from EPA to 

use it for Part 75 monitoring. As a 

condition of these approvals, the 

sources were asked to report the 

essential wall effects information in 

their quarterly electronic data reports 

(EDRs). However, EPA had not 

developed the necessary electronic 

record types (RTs) to accommodate the 

rectangular duct WAF information. 

Therefore, the Agency issued guidance, 

instructing the sources to use existing 

EDR record type 910 to report the WAF 

data. But record 910, unlike the other 

EDR record types, has no fixed data 

elements or fields. This created 

problems when the WAF information 

began to be reported. Even though 

detailed examples were provided in the 

EPA guidance, a significant portion of 

the WAF data were being entered into 

the wrong columns of the 910 records, 

making it difficult to perform electronic 

audits of the information. 

In view of this, EPA created two new 

EDR record types, RT 532 and RT 617, 

to handle the rectangular duct WAF 

data. Record type 532, which is a 

monitoring plan record, summarizes the 

results of each WAF determination. 

Record type 617 is a quality-assurance 

record and is submitted along with the 

results of each flow RATA performed at 

a rectangular stack or duct, when EPA 

Method 2 is used and a wall effects 

correction is applied. 

The Agency provided a mechanism 

(the ‘‘Monitoring Data Checking’’ (MDC) 

Software) by which a source could 


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create the new EDR records and add 

them to the quarterly report, without 

having to upgrade the data acquisition 

and handling system (DAHS). To date, 

use of the new record types has been 

voluntary, and the affected sources have 

been cooperative. Nevertheless, today’s 

rule would make mandatory the 

recording and reporting of the key 

rectangular duct WAF data elements 

using these record types. The proposed 

requirements to record and report the 

results of the WAF determinations in 

the monitoring plan are found in 

§§ 75.53(e) and (g) and in § 75.64. For a 

discussion of the proposed requirement 

to record and report the RATA support 

data, see Section II.E.5.k, below. 

3. Revisions to General Recordkeeping 

Provisions for Specific Situations 

Today’s proposed rule would make a 

series of modifications to § 75.58 to 

support the new XML data structure. 

These are summarized in Table 2. 

TABLE 2.—PROPOSED CHANGES TO THE GENERAL RECORDKEEPING REQUIREMENTS IN § 75.58 

Data element(s) or requirement(s) Proposed action(s) Comments 

• For Appendix D units, report ID numbers of formulas 

used to calculate SO2 mass emissions and heat input 

rate.

Add to § 75.58(c) ................ This would be required on and after January 1, 2009. 

• For Appendix E units, report the heat input rate formula ID for each unit operating hour.Add to § 75.58(d) ................ This would be required on and after January 1, 2009. 

• For LME units that combust more than one type of 

fuel, report the fuel type that produces the highest 

NOX emission rate.

Revise § 75.58(f) ................ Report the fuel type that produces the highest emission 

rate for each parameter individually (i.e., for SO2, 

NOX, and CO2, as applicable). 

• For LME units under § 75.19(c)(1)(iv)(C)(9), indicate 

whether unit is operating at base or peak load, each 

hour.

Add to § 75.58(f) ................. This flag is needed to ensure that the proper NOX

emission factor is being applied. 

• For LME units, flag each hour in which multiple fuels 

are combusted.

Add to § 75.58(f) ................. This flag is needed to ensure that the proper emission 

factors are used for multiple-fuel hours. 

• For LME units using long-term fuel flow, report the 

component and system ID codes.

Revise § 75.58(f) ................ Require only the system ID. Long-term fuel flow systems have only one component. 

4. Proposed Revisions to the QA/QC 

Recordkeeping Provisions 

EPA is proposing to make a series of 

revisions and additions to the quality 

assurance and quality control 

recordkeeping provisions in § 75.59, in 

support of the XML data format. These 

are summarized in Table 3. 

TABLE 3.—PROPOSED CHANGES TO THE QA/QC RECORDKEEPING PROVISIONS OF § 75.59 

Data element(s) or requirement(s) Proposed action(s) Comments 

• Describe each recertification event, and the date 

and type of each recertification test.

Revise § 75.59(a)(8) ........................... Expand to include events that require certification 

and diagnostic testing. Add requirement to report conditional data validation begin date (if applicable). Corresponds to current EDR record 

type 556. 

• Record component and system ID codes for 

daily calibrations, 7-day calibration error tests, 

cycle time tests, linearity checks, flow monitor 

leak checks and interference tests, and fuel flowmeter accuracy tests.

Revise §§ 75.59(a) and (b) ................. Require only the component ID for these tests. 

This requirement would be effective on and after 

January 1, 2009. The cycle time test for NOXdiluent systems would be simplified. 

• Record the test number and reason for test, for 

daily calibrations and 7-day calibration error tests.

Revise § 75.59(a)(1)(viii) ..................... Clarify that test number and reason for test code 

apply only to 7-day calibration error tests, not to 

daily calibrations. 

• Report the span value with the results of each 

linearity check.

Remove from § 75.59(a)(3)(ii) ............. The span value in the monitoring plan records will 

be used to evaluate the linearity checks. 

• Provide an on-line or off-line indicator flag for all 

calibration error tests.

Add to § 75.59(a)(1) ............................ This flag is needed to properly assess the hourby-hour quality-assurance status of CEMS following calibration error tests. 

• For flow-to-load tests of multiple stack configurations, indicate whether separate reference ratios 

are calculated for each stack.

Add, as § 75.59(a)(4)(vii)(M) ............... This addition is needed for consistency with the 

flow-to-load test reporting instructions (current 

EDR record type 605). 

• Report sufficient information to validate all grace 

period claims.

Remove and reserve 

§ 75.59(a)(12)(iii).

EPA’s checking software no longer needs this information to evaluate grace periods. 

• Record the component and system ID codes for 

each fuel flow-to-load ratio test.

Revise § 75.59(b)(4)(i)(A) ................... On and after January 1, 2009, record only the system ID for these tests. 

• Report Appendix E correlation curve test data on 

a monitoring system basis.

Revise § 75.59(b)(5) ........................... On and after January 1, 2009, report this data on 

a component basis. 

• Report the type(s) of fuel(s) combusted during 

each run of an Appendix E correlation curve test.

Remove § 75.59(b)(5)(i)(H) ................. This information is not needed in the new XML 

format and would not be reported after December 31, 2008. 

• Report the monitoring system ID code with reference fuel flow-to-load ratio test data.Add, as § 75.59(b)(4)(ii)(N) ................. This requirement is consistent with the reporting 

instructions for the reference fuel flow-to-load 

ratio (current EDR record type 629). 


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TABLE 3.—PROPOSED CHANGES TO THE QA/QC RECORDKEEPING PROVISIONS OF § 75.59—Continued 

Data element(s) or requirement(s) Proposed action(s) Comments 

• For LME units, indicate which test runs are used 

to calculate fuel-and-unit-specific NOX emission 

rates.

Add, as § 75.59(d)(1)(xiii) ................... This requirement is consistent with the reporting 

instructions for NOX emission testing of LME 

units (current EDR version 2.2, record type 

650). 

• For LME units, multiply the tested NOX emission 

rate by 1.15, if applicable.

Revise § 75.59(d)(2)(iii) and add new 

§§ 75.59(d)(2)(vi) and (vii).

This requirement applies only to turbines that operate only at base or peak load. Consistent with 

the reporting instructions (current EDR version 

2.2, record type 650), reporting of an hourly 

base or peak load indicator and the default NOX

emission rate for peak load operation would be 

required. 

• Record the date and hour of completion of all required DAHS verifications, whether for initial certification, recertification, or other events.Add § 75.59(f) ..................................... This requirement would be effective on and after 

January 1, 2009. EPA needs this information to 

properly establish provisional certification or recertification dates. Proposed changes to 

§ 75.63(a)(2)(iii) would allow this information to 

be reported electronically as part of the certification or recertification application. 

• Record the appropriate reference method data 

elements for Hg emission tests of low-emitting 

units.

Add § 75.59(e) .................................... For periodic testing of low mass emission units, 

recording of the reference method data elements in either § 75.59(a)(7)(vii), (viii), or (x) 

would be required, depending on which reference method is used for the testing. 

• Monitoring system ID 

• Test number 

• Operating level 

• RATA end date and time 

• Number of Method 1 traverse points 

• Wall effects adjustment factor 

Add, as § 75.59(a)(7)(ix) ..................... Recording of certain data elements and test results would be required for units with rectangular ducts/stacks that apply a wall effects adjustment factor (WAF) to correct their flow rate 

data. These data elements would be required 

for each flow RATA. 

• Percent CO2 and O2 in the stack gas, dry basis 

• Moisture content of the stack gas (percent H2O) 

• Average stack gas temperature (°F) 

• Dry gas volume metered (dscm) 

• Percent isokinetic 

• Particulate Hg collected in the front half of the 

sampling train, corrected for the front-half blank 

value (μg) 

• Total vapor phase Hg collected in the back half 

of the sampling train, corrected for the back-half 

blank value (μg) 

Add, as § 75.59(a)(7)(x) ...................... Recording of certain data elements would be required when using Method 29 for the RATA of a 

Hg monitoring system. These data elements 

would be required for each RATA run. 

5. Other Reporting Issues 

a. Long-Term Cold Storage and Deferred 

Units 

The proposed changes to Part 75 

would clarify the issue of ‘‘long-term 

cold storage (LTCS)’’. First, as 

previously noted, a definition of ‘‘longterm cold storage’’ would be added to 

§ 72.2. LTCS would mean that the unit 

has been completely shut down and 

placed in storage and that the shutdown 

is intended to last for an extended 

period of time (at least two calendar 

years). Second, a new paragraph, (a)(7), 

would be added to § 75.61. Proposed 

§ 75.61(a)(7) would require the owner or 

operator to provide notifications when a 

unit is placed in LTCS and when the 

unit re-commences operation. Third, 

§ 75.20(b) would be modified to require 

recertification of all monitoring systems 

when a unit re-commences operations 

after a period of long-term cold storage. 

If a source claiming LTCS status recommenced operation sooner than two 

years after being placed in LTCS, the 

notification and recertification 

requirements would apply. Fourth, the 

proposed rule would exempt a unit in 

LTCS from quarterly emissions 

reporting under § 75.64 until the unit 

recommences operation. Parallel rule 

provisions and appropriate crossreferences regarding quarterly reporting 

requirements for Subpart H and Subpart 

I units would be added to §§ 75.73(f)(1) 

and 75.84(f)(1), respectively. Finally, 

EPA notes that these proposed LTCS 

provisions are not intended to apply to 

periods of non-operation of units that 

are ‘‘on-call’’ and available for dispatch. 

EPA also proposes to revise the 

provisions of §§ 75.4(d) and 75.61(a)(3) 

pertaining to ‘‘deferred’’ units, i.e., units 

for which a planned or unplanned 

outage prevents the required continuous 

monitoring systems from being certified 

by the compliance date. The scope of 

§ 75.4(d) would be broadened beyond 

the Acid Rain Program to include units 

in a State or Federal pollutant mass 

emissions reduction program that 

adopts the monitoring and reporting 

provisions of Part 75. Examples of such 

programs include the Clean Air 

Interstate Regulation (CAIR), which is 

scheduled to begin in 2008 and the 

Clean Air Mercury Regulation (CAMR), 

which goes into effect in 2009. The 

revisions to §§ 75.4(d) and 75.61(a)(3) 

are deemed necessary because the CAIR 

and CAMR rules do not address 

deferred units. 

Revised § 75.4(d) would require the 

owner or operator of a deferred unit to 

provide notice of unit shutdown and 

recommencement of commercial 

operation, either according to 

§ 75.61(a)(3) (for planned shutdowns 

such as scheduled maintenance outages 

and for unplanned, forced unit outages) 

or § 75.61(a)(7) (for units in long-term 

cold storage). For all of these 

circumstances involving deferred units, 

the Part 75 continuous monitoring 

systems would have to be certified 

within 90 unit operating days or 180 


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calendar days (whichever comes first) of 

the date that the unit recommences 

commercial operation. In the time 

interval between the unit re-start and 

the completion of the required 

certification tests, the owner or operator 

would be required to report emissions 

data, using either: (1) Maximum 

potential values; (2) the conditional data 

validation procedures of § 75.20(b)(3); 

(3) EPA reference methods; or (4) 

another procedure approved by petition 

to the Administrator under § 75.66. 

Today’s proposed rule would revise 

the notification requirements of 

§ 75.61(a)(3) to be consistent with the 

changes to § 75.4(d). For planned unit 

outages, the owner or operator would be 

required to provide notice of shutdown 

at least 21 days prior to the compliance 

date. For unplanned outages, notice 

would be provided within 7 days after 

the shutdown. For both planned and 

unplanned outages, notice of the date on 

which the unit is expected to resume 

operation would be provided at least 21 

days prior to that date. Proposed 

§ 75.61(a)(3) also includes provisions to 

address situations in which there are 

changes to any of the planned or 

projected dates. 

b. Notice of Initial Certification 

Deadline 

EPA proposes to revise § 75.61(8) to 

require new and newly-affected sources 

to notify EPA when the monitoring 

system certification deadline is reached. 

Depending on the program(s) to which 

the unit is subject and whether the unit 

is new or newly-affected, this date will 

be the earlier of 90 unit operating days 

or 180 calendar days after the unit: (a) 

Commences commercial operation; (b) 

commences operation; or (c) becomes an 

affected unit. The Agency must know 

this date to correctly assess when to 

begin counting emissions against 

allowances pursuant to § 72.9. Knowing 

this date also confirms that the 

monitoring systems either have or have 

not been certified by the legal deadline. 

c. Monitoring Plan Submittal Deadline 

Today’s proposed rule would change 

the submittal deadline for the initial 

monitoring plan for new and newlyaffected units from 45 days to 21 days 

prior to the initial certification testing. 

This proposed revision would 

synchronize the initial monitoring plan 

submittal with the initial test notice (see 

proposed changes to §§ 75.62(a)(1) and 

(2), §§ 75.73(e)(1) and (2) for Subpart H 

units, and §§ 75.84(e)(1) and (e)(2) for 

Subpart I units). 

EPA also proposes to remove the 

requirement in § 75.62(a)(1) that the 

monitoring plan must be submitted ‘‘in 

each electronic quarterly report’’. 

Rather, inclusion of the monitoring plan 

in the report would be optional, and 

monitoring plan updates would be made 

either prior to or concurrent with (but 

not later than) the date of submission of 

the quarterly report. These proposed 

revisions would allow sources to 

maintain their monitoring plan 

information separate from the quarterly 

report. However, this flexibility would 

only be available to sources reporting in 

the new XML–EDR format under the reengineered data submission process. 

Until re-engineering of the data systems 

is complete, EPA will continue to 

collect and process all electronic 

monitoring plan data submitted in 

quarterly reports in the current EDR 

format. 

d. EPA Form 7610–14 

For each certification and 

recertification application, §§ 75.63(a)(1) 

and (a)(2) require hardcopy EPA form 

7610–14 to be submitted to the 

Administrator along with the 

certification or recertification test 

results in EDR format. However, 

significant upgrades to EPA’s data 

systems have been made in recent years, 

and Form 7610–14 is no longer needed 

to process the applications. Therefore, 

§§ 75.63(a)(1)(i)(A) and (a)(2)(i) would 

be revised to remove the requirement to 

submit Form 7610–14 to the 

Administrator. 

e. LME Applications 

EPA is proposing to remove the 

requirement from § 75.63(a)(1)(ii)(A) for 

a hardcopy LME certification 

application to be submitted to the 

Administrator. Only the electronic 

portion of the application, including the 

monitoring plan and LME qualification 

records, would be sent to EPA. The 

hardcopy portion of the LME 

application would be sent to the State 

and to the EPA Regional Office. 

f. Reporting Test Data for Diagnostic 

Events 

EPA proposes to revise 

§ 75.63(a)(2)(iii) to make the reporting of 

the results of diagnostic tests more 

flexible. Rather than requiring these test 

results to be reported in the electronic 

quarterly report for the quarter in which 

the tests are performed, they could 

either be submitted prior to or 

concurrent with that quarterly report. 

However, this flexibility in the reporting 

of diagnostic test results would only be 

available to sources reporting in the new 

XML–EDR format under the reengineered data submission process. 

Until re-engineering of the data systems 

is complete, EPA will continue to 

collect and process all diagnostic test 

results submitted in quarterly reports in 

the current EDR format. 

g. Modifications to § 75.64 

As part of its data systems reengineering effort, EPA proposes to 

revise § 75.64(a) to incorporate language 

describing the transition from the 

current reporting requirements of 

paragraphs (a)(1), (a)(2) and (a)(8) 

through (a)(15) to the new requirements 

of paragraphs (a)(3) through (a)(15). 

Note that only the requirements of 

paragraphs (a)(1) and (a)(2) of the 

current rule would be replaced, by the 

requirements of paragraphs (a)(3) 

through (a)(7). Proposed paragraphs 

(a)(3) through (a)(7) better describe the 

separation of the monitoring plan and 

quality assurance test information from 

the quarterly emissions report. Current 

paragraphs (a)(3) through (a)(7) and 

(a)(9) through (a)(11) would remain 

unchanged, but would be renumbered 

as paragraphs (a)(8) through (a)(15). 

Current paragraph (a)(8) would be 

removed. 

h. Steam Load Reporting 

Historically, Part 75 has required 

units that produce electrical or thermal 

output to report unit load either in 

megawatts or in thousands of pounds 

per hour of steam. Today’s proposed 

rule would add a third option, i.e., to 

report load in units of mmBtu/hr of 

steam thermal output. This option is 

needed to accommodate emissions 

trading programs in which allowance 

allocations are made on an electrical or 

thermal output basis, rather than a heat 

input basis. Certain units in these 

programs (e.g., industrial boilers) do not 

produce electrical output and would 

have to report thermal output instead. In 

the current rule, steam load is expressed 

only in thousands of pounds per hour, 

which does not provide the necessary 

thermal output information. EPA 

therefore proposes to add text to the 

following sections of Part 75, describing 

the new thermal output reporting 

option: §§ 75.16(e)(3), 75.57(b)(3), 

75.59(b)(4)(ii); Appendix A, Sections 

7.7(a) and 7.7(c); Appendix B, Sections 

2.2.5(a) and 2.2.5(a)(2); Appendix D, 

Sections 2.1.7.1(a), 2.1.7.1(c), 2.1.7.2(a), 

and 2.1.7.2(c); and Appendix E, Section 

2.4.1. 

i. Test Notification Requirements—Hg 

Low Mass Emission Units 

Section 75.61(a)(5) of the current rule 

requires the owner or operator or the 

designated representative to provide 21- 

day advance notice for various periodic 

quality-assurance tests. In particular, 

this notice must be provided to the 


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Administrator, to the appropriate EPA 

Regional Office and to the State or local 

agency (unless a particular agency 

issues a waiver from the requirement) 

for the semiannual or annual relative 

accuracy tests of CEMS, and for re-tests 

of both Appendix E peaking units and 

low mass emissions (LME) units. 

Under Subpart I of Part 75, certain 

low-emitting units covered by CAMR 

may qualify under §§ 75.81(b) through 

(d) to perform periodic (semiannual or 

annual) Hg emission testing in lieu of 

operating and maintaining continuous 

Hg monitoring systems. Today’s 

proposed rule would expand 

§ 75.61(a)(5) and add corresponding 

introductory text to § 75.61(a)(1) to 

require the owner or operator or the 

designated representative to provide 21 

day notice of these periodic Hg emission 

tests to EPA and to the State. 

j. Hardcopy Reports for Retests of Hg 

Low Mass Emission Units 

Sections 75.60(b)(6) and (b)(7) of the 

current rule require the designated 

representative (DR) to submit the results 

of certain periodic quality-assurance 

tests to the appropriate EPA Regional 

Office or to the State or local agency, 

when the test results are requested in 

writing (or by electronic mail). In 

particular, the results of semiannual or 

annual RATAs of CEMS and the routine 

re-tests of Appendix E units may be 

requested. If requested, the test results 

must be submitted within 45 days after 

the test is completed or within 15 days 

of the request, whichever is later. 

Today’s rule would add a new 

paragraph (b)(8) to § 75.60, requiring the 

DR to provide, upon request from EPA 

or the State, the results of the 

semiannual or annual mercury emission 

tests required under § 75.81(d)(4) for 

low-emitting units covered by CAMR. 

The time frame for submitting these Hg 

emission test results would be the same 

as for the RATAs and Appendix E retests. 

k. Wall Effects Adjustment Factors 

As previously discussed in Section 

II.E.2 of this preamble, today’s rule 

would require sources with flow 

monitors installed on rectangular stacks 

or ducts to report the results of wall 

effects adjustment factor (WAF) 

determinations in the monitoring plan, 

whenever Conditional Method CTM–

041 is used to adjust the measured stack 

gas flow rates for the effects of velocity 

decay near the stack wall. 

For sources with flow monitors 

installed on circular stacks, reporting of 

wall effects information is currently 

required when Method 2H is used in 

conjunction with Method 2, 2F or 2G 

(see §§ 75.64(a)(2)(xiii), 75.73(f)(1)(ii)(K) 

and 75.84(f)(1)(ii)(I)). The wall effects 

data elements that must be reported are 

found in §§ 75.59(a)(7)(ii) and (a)(7)(iii). 

These data are not reported in the 

monitoring plan, but are submitted 

along with flow RATA results, as 

supplementary information. 

For rectangular stacks and ducts, 

some of the same supporting data 

elements in §§ 75.59(a)(7)(ii) and 

(a)(7)(iii) are needed for flow RATAs 

performed using Method 2F or 2G, 

when wall effects corrections are 

applied. Additional supporting data 

elements, not in the current rule, are 

also needed for Method 2 flow RATAs 

when wall effects adjustments are made. 

In view of this, today’s rule would 

revise the text of §§ 75.64(a)(2)(xiii), 

75.73(f)(1)(ii)(K) and 75.84(f)(1)(ii)(I) 

and would add RATA support data 

elements to a new paragraph, (vii), in 

§ 75.59(a)(7). EPA believes that these 

proposed changes will clarify which 

wall effects data elements must be 

reported for circular stacks, which ones 

are reported for rectangular stacks and 

ducts, and which data elements must be 

reported for both types of stacks. 

F. Subpart H (NOX Mass Emissions) 

1. Subpart H Diluent Monitoring 

Systems 

For coal-fired Subpart H units that 

calculate NOX mass emissions as the 

product of NOX concentration and flow 

rate and are required to monitor and 

report the unit heat input, § 75.71(a)(2) 

requires the installation of an ‘‘O2 or 

CO2 diluent gas monitor’’. Consistent 

with the definition of a CEMS in § 72.2, 

this diluent monitor, which is only used 

for the heat input determination, should 

be described as an ‘‘O2 or CO2

monitoring system’’. Today’s proposed 

rule would revise the text of 

§ 75.71(a)(2) accordingly. 

2. Identifying a NOX Mass Methodology 

EPA is proposing to revise § 75.72 to 

clarify that only one NOX mass 

emissions methodology may be 

identified in the monitoring plan at any 

given time. Designation of primary and 

secondary NOX mass calculation 

methodologies would no longer be 

allowed. EPA believes that one 

methodology for NOX mass emissions is 

sufficient. If a source is subject to both 

Subpart H and to the Acid Rain Program 

(ARP) and is concerned about losing 

NOX data when the diluent component 

of the NOX emission rate system is outof-control, that source should choose 

the NOX concentration times flow rate 

calculation method as the NOX mass 

calculation methodology. This would 

require a NOX concentration system to 

be identified in the monitoring plan, in 

addition to the NOX emission rate 

system. The NOX concentration system 

would be used only to determine NOX

mass emissions, and the NOX emission 

rate system would be used only to meet 

the ARP requirement to report NOX in 

lb/mmBtu. 

Although it is possible with the 

current EDR format to identify multiple 

methodologies for a parameter, this was 

intended for ARP applications, not for 

NOX mass emission measurement. 

Multiple methodology records for SO2

are sometimes necessary when a bypass 

stack is used. However, as discussed in 

Section II.E.1 of this preamble, the 

reporting of monitoring methodologies 

is being restructured as part of EPA’s reengineering effort. Bypass stack 

methods are being integrated with other 

monitoring methods and will no longer 

be considered stand-alone 

methodologies. 

3. Reporting of Subpart H Facility 

Information 

Consistent with the proposed 

revisions to § 75.64, EPA proposes to 

revise § 75.73(f)(1), to phase out the 

requirement of § 75.73(f)(1)(i)(B) to 

include facility location information in 

each quarterly report. 

4. Linearity Check Requirements for 

Ozone Season-Only Reporters 

For Subpart H sources that report 

emissions data on an ozone season-only 

(OSO) basis, today’s proposed rule 

would revise the linearity check 

provisions in §§ 75.74(c)(2), (c)(2)(i), 

(c)(2)(ii), (c)(3)(ii), (c)(3)(vi), and 

(c)(3)(viii). Currently, OSO reporters are 

required to do a pre-season linearity 

check, an in-season second quarter 

linearity check (in May or June, if the 

unit operates for ≥168 hours in May and 

June), and a third quarter linearity 

check, if the unit operates for ≥168 

hours in that quarter. Many sources 

have misunderstood these rule 

provisions, particularly the requirement 

to perform an in-season linearity check 

in the second quarter. 

Since the beginning of the NOX

Budget Program, there have been a 

number of instances where sources have 

performed pre-season linearity checks 

in April, but have not done the required 

in-season linearity checks in May or 

June. In some cases, this has resulted in 

CEMS out-of-control periods and has 

required the use of missing data 

substitution. These sources apparently 

believed that the April tests were 

sufficient to satisfy both the pre-season 

and second quarter linearity check 

requirements because for year-round 


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reporters, linearity checks are required 

only once per quarter. 

The current rule also requires OSO 

reporters to operate and maintain each 

CEMS and to perform daily calibration 

error tests, in the time period extending 

from the hour of completion of the preseason linearity check through April 30. 

EPA has found that this rule provision 

is not well-understood by the affected 

sources. It is also difficult for the 

Agency to assess compliance with the 

provision, since sources are not required 

to report the results of any off-season 

calibration error tests done prior to 

April. Further, when pre-season 

linearity checks are done several 

months before the ozone season, the 

quality of the data at the start of the 

ozone season is somewhat questionable. 

In view of these considerations, 

today’s proposed rule would revise 

§ 75.74(c)(2) to restrict the time period 

in which pre-season linearity checks 

may be conducted. EPA proposes to 

require the pre-season linearity checks 

to be done in the month of April. All 

references to performing the pre-season 

linearity checks at other times would be 

deleted, along with the requirement to 

keep the off-season daily calibration 

error tests in a format suitable for 

inspection. 

Today’s proposed rule would also 

revise § 75.74(c)(2)(i)(D) by removing 

the conditional grace period provision 

and adding a cross-reference to 

proposed § 75.74(c)(3)(ii)(E), which 

addresses data validation. If the April 

linearity check is not completed prior to 

the start of the ozone season, data from 

the monitor would be considered 

invalid as of May 1, unless the 

conditional data validation procedures 

of § 75.20(b)(3) are applied. Proposed 

§ 75.74(c)(3)(ii)(E) would allow a 

probationary calibration error test to be 

done, to begin a period of conditional 

data validation. Then, the linearity 

check would be done ‘‘hands-off’’

within a 168 unit operating hour period 

following the calibration error test. If the 

linearity check is passed within the 

allotted time, the conditionally valid 

data would be considered qualityassured, back to the hour of the 

probationary calibration error test. If the 

linearity check is failed, all data from 

the monitor would be invalidated back 

to the beginning of the ozone season and 

would remain invalid until a linearity 

check is passed. If the linearity check is 

done after the 168-hour period expires, 

data validation would be done 

according to § 75.20(b)(3)(viii), subject 

to the restrictions of § 75.74(c)(3)(xii). 

Today’s proposed rule would add a 

new paragraph (F) to § 75.74(c)(3)(ii), 

stating that a pre-season linearity check 

done in April fulfills the second quarter 

linearity check requirement. Related 

Section 75.74(c)(3)(viii) would be 

removed and reserved. Further, 

proposed § 75.74(c)(3)(ii)(B) would 

require the third quarter linearity check 

to be conducted either by July 30 or 

within a 168 operating hour period of 

conditional data validation thereafter. 

Finally, proposed § 75.74(c)(3)(ii)(G) 

would address the case where a unit 

operates infrequently and the 168 

operating hour conditional data 

validation period associated with the 

April linearity check extends through 

the second quarter, into the third 

quarter. In that case, if the linearity 

check is performed and passed in the 

third quarter, before the 168 operating 

hour window expires, then that one 

linearity check would satisfy all three of 

the ozone season linearity check 

requirements, i.e., for the pre-season, for 

the second quarter, and for the third 

quarter. 

EPA believes that the proposed 

linearity check schedule for OSO 

reporters would ensure that the gas 

monitors’ response is linear throughout 

the ozone season and would simplify 

the regulation by reducing the number 

of required linearity checks from three 

to two (and in some cases, one) per 

season. 

5. RATA Requirements for Ozone 

Season Only Reporters 

For OSO reporters, Part 75 requires, 

for quality-assurance purposes, that at 

the start of each ozone season each 

required CEMS must be within the 

‘‘window’’ of data validation of a 

current, non-expired RATA. Section 

75.74(c)(2)(ii) states that this 

requirement can be met either by 

performing a RATA in the pre-season 

(between October 1 and April 30) or, in 

some instances, by relying on the results 

of a RATA done in the previous ozone 

season. For example, if a RATA was 

performed inside the ozone season, in 

the 3rd quarter of last year, the window 

of data validation for the test would 

extend through the 3rd quarter of this 

year, provided that the RATA results 

show that the CEMS qualifies for an 

‘‘annual’’ RATA frequency. However, if 

a ‘‘semiannual’’ test frequency is 

obtained, the data validation window 

would expire at the end of the first 

quarter of this year, and the RATA 

could not be used to validate data in the 

current ozone season. Therefore, a preseason RATA would be required. 

The rule further requires each CEMS 

to be operated, calibrated and 

maintained in the time period extending 

from the completion of the RATA, 

through April 30. This means that if the 

RATA being used for data validation in 

the current ozone season was performed 

during the last ozone season, the CEMS 

would have to be operated, calibrated 

and maintained for the entire off-season 

from October 1 through April 30. 

Compliance with this type of 

requirement is difficult for EPA to 

assess, as previously explained in 

paragraph 4 of this section. Also, many 

sources choosing the OSO reporting 

option find this operation and 

maintenance (O&M) requirement to be 

counter-intuitive, because they expect to 

be required to meet Part 75 monitoring 

obligations only during the ozone 

season. If it were discovered during an 

audit that this O&M requirement had 

not been met, a facility could incur 

substantial data loss. Further, if a CEMS 

is not maintained in a manner 

consistent with normal operating 

practices for an extended period of time 

following a RATA that was done long 

before the ozone season, the results of 

that RATA may not be a true indicator 

of the CEMS data quality at the start of 

the ozone season. 

In view of these considerations, EPA 

is proposing to restrict the window of 

time in which pre-season RATAs may 

be performed. Proposed § 75.74(c)(2)(ii) 

would require the RATAs to be done 

either in the first quarter of the year or 

in the month of April. This restriction 

would prohibit RATAs done in the 

previous year from being used to 

validate data in the current ozone 

season. 

Section 75.74(c)(2)(ii)(F) would be 

revised to address data validation. The 

proposed data validation rules for 

RATAs would be similar to those 

proposed for linearity checks, i.e., a 

period of conditional data validation 

(720 operating hours) would be allowed 

when the pre-season RATA is not 

completed by the April 30 deadline. 

Consistent with these revisions, today’s 

proposed rule would delete the data 

validation and conditional grace period 

provisions in §§ 75.74(c)(2)(ii)(G) and 

(c)(2)(ii)(H) and would remove and 

reserve §§ 75.74(c)(3)(vi), (vii), and 

(viii). 

Note that EPA is not modifying the 

provisions of § 75.74(c)(3)(xii), which 

allows the results of required quality 

assurance tests that are completed early 

in the fourth quarter, within a window 

of conditional data validation, to be 

submitted with the electronic data 

report for the third quarter. This 

provision provides sources with a ‘‘last 

chance’’ opportunity to complete the 

required quality assurance tests before 

the final ozone season reports for the 

NOX Budget program are due. 


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6. Determining Peaking Status for Ozone 

Season Only Reporters 

EPA proposes to revise § 75.74(c)(11) 

to clarify that when peaking unit status 

for ozone season-only reporters is 

determined, 3,672 hours (i.e., the 

number of hours in the ozone season) 

should be used instead of 8,760 hours 

in the capacity factor equation. This 

clarification is supported by Question 

27.1 in the ‘‘Part 75 Emissions 

Monitoring Policy Manual’’. 

7. Calculation of Ozone Season NOX

Mass Emissions—LME Units 

Today’s rule would correct an 

organizational error in Subpart H of Part 

75. Section 75.72(f), which describes 

ozone season NOX mass calculations for 

units using the low mass emission 

(LME) methodology under § 75.19, 

would be removed, and its basic content 

would be relocated to § 75.71(e). The 

LME provision in § 75.72 appears to 

have been inadvertently placed in that 

section. The monitoring provisions of 

§ 75.72 apply to common and multiple 

stack configurations, whereas § 75.71 

addresses unit-level monitoring. LME is 

a unit-level monitoring methodology. 

G. Subpart I (Hg Mass Emissions) 

1. Heat Input Provisions for Common 

and Multiple Stacks 

Subpart I of Part 75 provides the basic 

procedures for monitoring Hg mass 

emissions and heat input from affected 

units under CAMR. However, due to an 

apparent oversight, the heat input 

monitoring provisions for certain 

monitoring configurations were 

inadvertently omitted from the final 

rule. In particular, the heat input 

methodology for common stacks shared 

by affected and non-affected units, and 

the methodology for multiple stack or 

duct configurations are missing. Today’s 

rule would add three new paragraphs, 

(b)(3), (c)(4) and (d)(3) to § 75.82 to 

correct this deficiency. 

For the common stack shared by 

affected and non-affected units, 

proposed § 75.82(b)(3) would require 

the owner or operator to either measure 

the total heat input rate at the common 

stack and apportion it to the individual 

units by load, according to § 75.16(e)(3), 

or to determine the heat input rate at the 

individual units by installing a flow 

monitor and a diluent monitor on the 

duct leading from each unit to the 

common stack. For multiple stack 

configurations, proposed §§ 75.82(c)(4) 

and (d)(3) would require the owner or 

operator to determine the hourly unit 

heat input by measuring the hourly heat 

input rate (mmBtu/hr) at each stack, 

multiplying each stack heat input rate 

by the stack operating time (hr) to 

convert it to heat input (mmBtu), and 

then summing the hourly stack heat 

input values. 

2. Low Mass Emission Alternative 

Section 75.81(b) of Subpart I provides 

an alternative (‘‘excepted’’) monitoring 

methodology for units with low Hg mass 

emissions. To qualify to use this 

methodology, emission testing is 

required to demonstrate that the unit 

has the potential to emit no more than 

29 lb (464 ounces) of Hg per year. Once 

a unit qualifies, periodic retesting 

(semiannual or annual, depending on 

the emission level) is required to 

demonstrate that the unit is actually 

emitting less than 29 lb/yr of Hg. 

Section 75.81(e) allows the low mass 

emission alternative to be used for 

common stacks, provided that the units 

sharing the stack are tested individually 

and each one qualifies as a low-emitter. 

Though not explicitly stated in the rule, 

it is implied that the periodic retests for 

common stack configurations would 

also have to be done at the unit level. 

EPA is reconsidering this approach, for 

two reasons: (1) With respect to the 

initial certification testing, it appears to 

be overly restrictive for at least one 

particular configuration; and (2) the 

Agency believes that for the retests it 

may be unnecessarily difficult and 

costly to implement. 

Therefore, with one exception 

(discussed below), EPA is proposing to 

revise § 75.81(e) to require Hg testing of 

the individual units that share the 

common stack only for the initial 

demonstration that the units 

individually qualify as low emitters. 

Once this has been satisfactorily 

demonstrated, the required semiannual 

or annual retests could then be done at 

the common stack, at a normal load 

level for the configuration. 

The proposed revisions to § 75.81(e) 

would also allow the initial low mass 

emitter qualification for a group of 

identical units sharing a common stack 

to be based on emission testing of a 

subset of those units. To exercise this 

option, the units would first have to 

qualify as identical under 

§ 75.19(c)(1)(iv)(B). Then, the number of 

units required to be tested would be 

determined from Table LM–4 in § 75.19. 

The proposed rule would allow one 

exception to the requirement to test the 

individual units sharing a common 

stack, in order to demonstrate that the 

units qualify for low mass emitter 

status. In the case where the gas streams 

from the individual units are combined 

together and routed through emission 

controls that reduce the Hg 

concentration (e.g., a wet scrubber) 

before entering the common stack, the 

only way to measure the controlled Hg 

concentration from the individual units 

would be to operate them one at a time 

rather than concurrently. EPA believes 

that for many such configurations, this 

manner of unit operation is abnormal 

and potentially problematic. Therefore, 

the revisions to § 75.81(e) would allow 

both the initial and ongoing low mass 

emission testing to be done at the 

common stack in cases where the 

individual unit effluent gas streams are 

combined together upstream of a control 

device that removes Hg before entering 

the common stack. Owners or operators 

electing to use this option would be 

required to perform the testing with all 

of the units that share the stack in 

operation, and the combined load 

during the testing would be ‘‘normal’’, 

as defined in Section 6.5.2.1 of 

Appendix A. 

Today’s proposed rule would also 

revise § 75.81(c)(1), to clarify the time 

frame in which to perform the initial 

certification testing for the low mass 

emission option. The current rule 

simply states that this testing must be 

done ‘‘prior to the compliance date in 

§ 75.80(b)’’, but does not specify how far 

in advance of that date the testing may 

be done and still be considered 

acceptable. Further, § 75.81(d)(1) 

requires the test results to be submitted 

as a certification application, no later 

than 45 days after completing the 

testing. And § 75.81(d)(4) requires 

periodic Hg retesting to commence 

within two or four ‘‘QA operating 

quarters’’ after the quarter of the 

certification testing. 

This approach to implementing the 

low mass emission alternative should 

work reasonably well, provided that the 

certification test date is close in time to 

the compliance date. However if there is 

too long a gap between the certification 

testing and the start of the program, it 

becomes problematic. For instance, if 

the testing is done too early, the 

requirement to submit a certification 

application within 45 days could result 

in applications being submitted long 

before the regulatory agencies are ready 

to receive and process them. Also, the 

periodic retesting requirements of 

§ 75.81(d)(4), which become active on 

the certification test date, could result in 

several Hg retests being done before the 

program begins. This is clearly contrary 

to the purpose of the retests, which, like 

the periodic relative accuracy tests of 

CEMS, are intended to commence after 

the compliance date, when Hg 

emissions reporting has begun. It also 

raises questions about which default 

emission rate to use for the initial 

reporting. In view of these 


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considerations, EPA is proposing to 

revise § 75.81(c)(1), to require that the 

Hg testing for initial certification be 

done no more than 1 year before the 

compliance date. Sections 75.81(d)(2) 

and 75.81(d)(5) would also be revised, 

to address the case where a retest may 

be required before the compliance date 

(e.g., when § 75.81(d)(4) requires a retest 

within two QA operating quarters, 

following a certification test that was 

done 9 to 12 months before the 

compliance date). In such cases, the 

default Hg emission rate used at the 

beginning of the program would be the 

value that was obtained in the retest. 

Finally, EPA proposes to amend 

§ 75.81(d)(4) to address the emission 

testing requirements when the fuel 

supply is changed. Revised § 75.81(d)(4) 

would require additional Hg retesting 

within 720 unit operating hours, 

following a change in the fuel supply. 

The results of this retest would be 

applied retrospectively, back to the time 

of the fuel switch. Section 75.81(c)(1) 

would also be revised to require that the 

fuel combusted during the initial 

certification testing be from the same 

source of supply as the fuel combusted 

when the program starts. The Agency 

believes these rule provisions are 

necessary to ensure that the default Hg 

concentration used for Part 75 reporting 

is representative of the fuel being 

combusted in the unit. However, note 

that the proposed revisions only address 

the emission testing and reporting 

requirements for one case, i.e., where 

the source of supply for the primary fuel 

(assumed to be coal) changes. Cases 

where the coal supply does not change, 

but the unit sometimes burns other 

types of fuel besides coal or co-fires 

mixtures of coal and other fuels, are not 

addressed. In view of this, EPA also 

solicits comments and suggestions on 

how to apply the Hg low mass emitter 

option in these situations (i.e., what 

emission testing and reporting 

requirements might be appropriate). 

3. Harmonization of Subpart I With 

Other Proposed Rule Revisions 

Subpart I of Part 75 also contains a 

recordkeeping and reporting section 

(§ 75.84). Section 75.84 contains a few 

stand-alone provisions, but for the most 

part, it cross-references the primary 

monitoring plan, recordkeeping, 

notification and reporting sections of 

the rule (i.e., §§ 75.53, 75.57 through 

75.59, 75.61, and 75.64) and other 

sections of Subpart I. 

As discussed in detail in Section E of 

this preamble, today’s rule would make 

substantial revisions to the monitoring 

plan, recordkeeping and reporting 

sections of Part 75, in support of EPA’s 

data systems re-engineering effort. To 

make Subpart I consistent with these 

proposed revisions and with the other 

proposed changes in today’s rule, a 

number of minor adjustments would 

also be made to the text of 

§§ 75.84(c)(3), (e)(1), (e)(2), and (f)(1). 

H. Appendix A 

1. CO2 Span Values 

EPA proposes to revise Section 2.1.3 

of Appendix A, to allow the use of CO2

spans less than 6.0 percent CO2 if a 

technical justification is provided in the 

hardcopy monitoring plan. This added 

flexibility in the CO2 span value mirrors 

a similar provision in Section 2.1.3 for 

O2 span values. 

2. Protocol Gas Audit Program 

EPA is responsible for implementing 

air quality programs that rely on 

accurate calibration gases. Under these 

programs, calibration gases are used to 

calibrate EPA reference methods which, 

in turn, are used to perform stack tests 

or to calibrate installed pollutant 

continuous emissions monitoring 

systems (CEMs) that are used by 

regulated sources to report emissions to 

EPA. If the reference methods are low 

by 20%, then emissions may be 

underreported by 20%. Calibration 

gases are also used to ensure that 

ambient air quality analyzers provide 

accurate results. Accurate calibrations 

gases are critical in helping to ensure 

that the Clean Air Act-mandated 

emission reductions are achieved. 

Section 2.1.10 of ‘‘EPA Traceability 

Protocol for Assay and Certification of 

Gaseous Calibration Standards’’

(Protocol Procedures), September 1997 

(EPA–600/R–97/121) states that EPA 

will periodically assess the accuracy of 

calibration gases and publish the 

results. Between 1978 and 1996, EPA 

conducted several performance audits of 

calibration gases from various 

manufacturers. These audits had two 

goals, to provide a quality check for gas 

vendors and to connect users with gas 

vendors. One notable result in the most 

recent five consecutive years of audits is 

a steady, significant reduction in failure 

rate of the calibration gases, from about 

27% in 1992 down to 5% in 1996. In 

2003, EPA conducted a ‘‘surprise’’ audit 

of 14 national specialty gas producers 

and found that the failure rate had risen 

to 11%. 

Today’s proposed rule would require 

that EPA Protocol Gases being used for 

40 CFR Part 75 purposes be obtained 

from those specialty gas producers who 

participate in the audit program. Under 

the proposed rule, only audit 

participants may market these gas 

standards as ‘‘EPA Protocol Gases’’, 

although there will be no requirement 

for participants’ audited standards to 

meet an accuracy acceptance criterion. 

The costs of the audits will be borne by 

the gas producers who elect to 

participate in the audits. Although it 

may take several years to revise all of 

the EPA monitoring regulations in 40 

CFR Parts 58 and 60, today’s proposed 

rule would ensure that under Part 75, 

any specialty gas producers who do not 

participate in the program will not have 

a price advantage (due to the lack of 

audit program costs) over those 

producers who do participate. An EPAmaintained web site will list the 

participants and the audit results, which 

will provide calibration gas users with 

detailed information about the quality of 

EPA Protocol Gases. 

To clarify the calibration gas 

requirements in section 5.1 of appendix 

A to this part, a definition for ‘‘specialty 

gas producer’’ has been added to section 

72.2. EPA believes that most of the gas 

standards and reference materials 

identified in section 5.1 of appendix A 

of this part are expensive and not used 

in practice by Part 75 affected units. 

Therefore, today’s proposed rule also 

deletes several calibration gas options 

and definitions, and consolidates the 

remaining calibration gas descriptions 

under section 5.1 of appendix A to this 

part. 

EPA is also requesting comment on 

the appropriate accuracy specification 

to apply to Hg cylinder gases and other 

Hg calibration standards (e.g., gases 

from NIST-traceable generators). 

Currently, EPA requires that accuracy of 

EPA Protocol gases be within 2 percent 

of the certified tag values. 

3. Requirements for Air Emission 

Testing Bodies 

Since the inception of the Acid Rain 

Program, field audits of Part 75-affected 

facilities have brought to EPA’s 

attention a number of improperlyperformed RATAs and other QA/QC 

tests. When the proper test procedures 

are not followed, this can adversely 

affect the quality of the emissions data, 

and, in some cases, may call into 

question a unit’s compliance with the 

requirement to hold allowances 

covering its emissions. In view of this, 

today’s proposed rule would revise 

Section 6.1 of Appendix A to require all 

individuals who perform the emission 

tests and CEMS performance 

evaluations required by Part 75 to 

demonstrate conformance with ASTM 

D7036–04 ‘‘Standard Practice for 

Competence of Air Emission Testing 

Bodies’’. ASTM D7036–04 specifies the 

general requirements for demonstrating 


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that an air emission testing body (AETB) 

is competent to perform emission tests 

of stationary sources. ASTM D7036–04 

covers testing and calibration performed 

using standard methods, non-standard 

methods and methods developed by the 

AETB. 

Proposed Section 6.1.2 of Appendix A 

and revisions to Section 2.1 of 

Appendix E and to Section 1 of 

Appendix B would make it clear that 

this requirement applies only to AETBs 

that perform RATAs, NOX emission 

tests of Appendix E and LME units, or 

Hg emission tests of low-emitting units. 

It would not be applicable to the daily 

operation, daily QA/QC (daily 

calibration error check, daily flow 

interference check, etc.), weekly QA/QC 

(i.e., Hg system integrity checks), 

quarterly QA/QC (linearity checks, etc.), 

and routine maintenance of the CEMS. 

ASTM D7036–04 would be 

incorporated by reference in 

§ 75.6(a)(45), and a definition of ‘‘Air 

Emission Testing Body’’ would be 

added to § 72.2. 

4. Linearity Requirements for Dual-Span 

Applications 

Section 6.2 in Appendix A and 

Section 2.2 in Appendix B require the 

owner or operator of affected units with 

installed gas monitors to perform 

periodic linearity checks of the 

monitors. The basic linearity check 

requirements are to perform the test for 

initial certification and then, for 

ongoing quality assurance (QA), to 

repeat the test quarterly. In the original 

Part 75 regulations (published on 

January 11, 1993), there were no 

exceptions to these requirements. 

However, in May 1999, EPA revised 

the linearity check provisions of Part 75 

as follows. First, Section 6.2 of 

Appendix A was revised to exempt SO2

and NOX span values of 30 ppm or less 

from performing linearity checks. 

Second, revisions to Section 2.2 of 

Appendix B reduced the ongoing 

linearity check requirement from once 

per calendar quarter to once every ‘‘QA 

operating quarter’’ (i.e., a calendar 

quarter in which the unit operates for at 

least 168 hours). 

Since the May 1999 revisions became 

effective, the regulated sources appear 

to have understood the ‘‘QA operating 

quarter’’ concept in Section 2.2 of 

Appendix B, but there has been some 

confusion about the meaning of the 

linearity exemption in Appendix A. 

Some have questioned whether the 

linearity exemption applies only to 

ongoing QA or whether it applies also 

to initial certification. Others have 

asked whether the exemption applies 

only to a particular measurement range 

or to all of the linearity check 

requirements for a monitoring system. 

The misunderstanding appears to center 

around two sentences in Section 6.2. 

The first sentence states that 

‘‘Notwithstanding these requirements, if 

the SO2 or NOX span value for a 

particular range is ≤ 30 ppm, that range 

is exempted from the linearity test 

requirements of this part.’’ Since the 

phrase ‘‘of this part’’ refers to Part 75, 

this seems to exempt ranges of 30 ppm 

or less from all Part 75 linearity 

requirements, including initial 

certification and ongoing QA. However, 

the second sentence states that ‘‘For 

units using emission controls and other 

units using both a high and a low span, 

perform a linearity check on both the 

low- and high-scales for initial 

certification.’’ Thus, for dual span 

applications, this statement appears to 

require linearity checks of both 

measurement scales for initial 

certification regardless of the span 

values, which does not harmonize with 

the 30 ppm exemption. 

EPA believes that the key to 

understanding and reconciling these 

rule texts is the chronological order of 

the two sentences. The second sentence 

is from the original 1993 rule and the 

first sentence was added in 1999. 

Therefore, the 30 ppm linearity check 

exemption in the first sentence takes 

precedence over the low scale linearity 

check requirement of the second, and 

there is no actual contradiction. 

However, to eliminate any doubt as to 

the Agency’s intended meaning, today’s 

rule would revise Section 6.2 of 

Appendix A to make it clear that the 30 

ppm linearity exemption: (1) Is rangespecific; (2) covers both initial 

certification and ongoing QA; (3) does 

not remove the requirement to perform 

linearity checks of the high range (if > 

30 ppm) for dual span applications; and 

(4) does not take away the linearity 

check requirements for the diluent 

monitor component of a NOX-diluent 

monitoring system. 

5. Dual Span Applications—Data 

Validation 

Today’s proposed rule would revise 

Sections 2.1.1.5 (b)(2) and 2.1.2.5(b)(2) 

of Appendix A to clarify the 

relationship between the qualityassured (QA) status of the low and high 

ranges of a gas monitor in a dual-span 

application. The changes would be 

consistent with the proposed revisions 

to Appendix B (see Section II.I.3, 

below). 

In the current rule, Sections 

2.1.1.5(b)(2) and 2.1.2.5(b)(2) of 

Appendix A provide instructions for 

reporting SO2 and NOX concentration 

data when the full-scale range of the 

monitor is exceeded. For single-range 

applications, a value of 200 percent of 

the maximum potential concentration 

(MPC) must be reported when a fullscale exceedance occurs. For dual range 

applications, if the low range is 

exceeded, no special reporting is 

necessary, provided that the high range 

is ‘‘available and not out-of-control or 

out-of-service for any reason’’. However, 

if the high range is ‘‘not able to provide 

quality-assured data’’ during the lowrange exceedance, then the MPC must 

be reported. 

EPA believes that for dual range 

applications, the two phrases used to 

describe the QA status of the high range 

during low-scale exceedances, i.e., 

‘‘available and not out-of-control or outof-service for any reason’’ and ‘‘not able 

to provide quality assured data’’, are too 

general and do not adequately address 

the possible scenarios associated with 

dual range monitoring. Today’s rule 

would revise these rule texts by defining 

the QA status of the high range in terms 

of its most recent calibration error and 

linearity checks. Provided that both of 

these QA tests are still ‘‘active’’, i.e., 

their windows of data validation have 

not expired, the high range would be 

considered in-control and able to 

provide quality-assured data. However 

if either of the tests has expired, data 

recorded on the high range would be 

considered invalid until the expired test 

was repeated and passed. The MPC 

would have to be reported until the 

expired high-range test is redone or 

until the data return to the low scale. 

These revisions would clarify that 

when the low range is up-to-date on its 

QA tests but the high range is not, the 

QA statuses of the two ranges are 

evaluated separately and may be 

different. However, as explained in 

greater detail in Section II.I.3, below, the 

QA statuses of the low and high ranges 

are not necessarily independent when a 

calibration error test or a linearity check 

on one of the ranges is failed. 

6. Cycle Time Test—Stability Criteria 

The cycle time test described in 

Section 6.4 of Appendix A is required 

for the initial certification and 

recertification of gas monitoring 

systems, and occasionally as a 

diagnostic test. The ‘‘upscale’’ portion of 

the test consists of injecting a zero-level 

calibration gas, allowing the reading to 

stabilize, recording it, and then stopping 

the calibration gas flow, waiting until a 

stable reading of the source emissions is 

obtained, and recording it. The 

‘‘downscale’’ portion of the test is 

performed in like manner, except that a 


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high-level calibration gas is used instead 

of the zero-level gas. 

Section 6.4 currently specifies criteria 

for determining when a stable reading 

has been obtained. The reading is 

considered stable if it changes by less 

than 2.0 percent of the span value for 2 

minutes or less than 6.0 percent from 

the average concentration over 6 

minutes. These criteria are reasonable 

when the source effluent concentrations 

are moderate or high. However, when 

concentrations are very low, the criteria 

are quite stringent and can be very 

difficult to meet. For example, if the 

span value of a NOX analyzer is 10 ppm 

and the average measured source 

emissions are 3 ppm, the source 

emissions would have to remain 

constant within about 0.2 ppm for the 

specified amount of time to meet the 

stability criteria. 

In recent years, hundreds of new 

combustion turbines (CTs) have been 

built. The vast majority are subject to 

Part 75, are equipped with NOX

monitoring systems, and have NOX

permit limits less than 10 ppm. 

Therefore, the 0.2 ppm cycle time 

stability criterion in the example above 

is realistic and applies to many of these 

new CTs. To provide a measure of relief 

for these low-emitting sources, today’s 

rule would add alternative stability 

criteria to Section 6.4 of Appendix A. 

By the alternative criteria, an SO2 or 

NOX reading would be considered stable 

if it changed by no more than 0.5 ppm 

for 2 minutes or, for a diluent monitor, 

if it changed by no more than 0.2% CO2

or O2 for 2 minutes. EPA believes these 

alternative stability criteria are needed 

to ensure that minor temporal variations 

in the concentration of the source 

effluent do not cause testers to 

overestimate the amount of time it takes 

to achieve stable readings, resulting in 

‘‘false positive’’ failures of the cycle 

time test. 

7. System Integrity and Linearity Checks 

of Hg CEMS 

Subpart I of Part 75 includes 

certification test procedures and 

performance specifications for Hg 

CEMS. The required certification tests 

for a Hg CEMS include a 3-level system 

integrity check, using a NIST-traceable 

source of oxidized Hg and a 3-level 

linearity check, using elemental Hg 

standards. The performance 

specification for the system integrity 

check, which is found in paragraph 

(3)(iii) of Appendix A, Section 3.2, 

states that the system measurement 

error must not exceed 5.0 percent of the 

span value at any of the three 

calibration gas levels. However no 

explanation of how to calculate the 

measurement error is provided. Today’s 

proposed rule would restructure 

paragraph (3) of Section 3.2 (as 

described in the next paragraph) and 

add the necessary mathematical 

procedure. 

EPA is also proposing to make the 

linearity and system integrity check 

specifications for Hg monitors the same. 

The principal linearity error 

specification in Section 3.2(3)(i) is 

currently 10.0 percent of the reference 

gas tag value at each calibration 

concentration, when calculated 

according to Equation A–4. The 

alternative specification in Section 

3.2(3)(ii) allows an absolute difference 

of up to 1.0 μg/m3 between the average 

reference gas and monitor values at each 

calibration gas level. Today’s proposed 

rule would replace the principal 

linearity error specification with a 

specification of 5.0 percent of the span 

value, and would lower the alternative 

specification to 0.6 μg/m3. Further, the 

same 0.6 μg/m3 alternative specification 

would be added to the rule for the 

system integrity check. 

The reason for making these changes 

is that nearly all Hg monitors are 

equipped with a converter and measure 

the total vapor phase Hg (i.e., oxidized 

plus elemental) as elemental Hg. 

Therefore, the performance specification 

for the linearity check, which is done 

with elemental Hg, should be at least as 

stringent as the performance for the 

system integrity check, which is done 

with oxidized Hg. Because the current 

linearity specifications are less stringent 

than the specification for the system 

integrity check, EPA proposes to revise 

and restructure paragraph (3) in Section 

3.2 of Appendix A, to make the 

performance specifications the same for 

linearity checks and system integrity 

checks of Part 75 Hg monitors (this 

includes both the 3-level and singlelevel system integrity checks). The 

alternative performance specification is 

deemed necessary for low (10 μg/m3 Hg 

span values, where the principal 

specification of 5.0% of span may be 

overly stringent. 

8. Correction of Hg Calibration Gas 

Concentrations for Moisture 

When calibration error tests and 

linearity checks of SO2, NOX, and 

diluent gas monitors are performed, 

EPA protocol gases are used. The 

protocol gases are essentially moisturefree. However, when mercury monitors 

are calibrated, moisture may be added to 

the calibration gas. This creates a 

potential source of error in the 

calculations, if the Hg monitoring 

system measures on a dry basis. In view 

of this, EPA proposes to revise the 

calibration error procedures in section 

6.3.1 of Appendix A, to require that 

when moisture is added to the Hg 

calibration gas, the moisture content of 

the gas must be accounted for if the Hg 

monitor measures on a dry basis. The 

proposed revisions would also require 

the calibration gas concentration to be 

converted to a dry basis for purposes of 

the calibration error calculations. 

Parallel language would be added to 

Section 6.2 of Appendix A, in a new 

paragraph ‘‘(h)’’, to address this issue for 

the linearity checks and system integrity 

checks of Hg monitors. The Agency 

believes that adoption of these proposed 

revisions will prevent many ‘‘false 

positive’’ failures of Hg monitor 

calibration error tests, linearity checks, 

and system integrity checks. 

9. Correction of Cross-References 

Today’s proposed rule would correct 

a number of cross-references in 

Appendix A, Sections 6.2(g), 6.5.6(b)(3) 

and 6.5.6.3. Regarding the system 

integrity checks of Hg monitors, Section 

6.2(g) of Appendix A incorrectly only 

refers to Section 2.6 of Appendix B, 

which only describes weekly, singlelevel system integrity checks. The 

proposed revisions would also refer to 

Sections 2.1.1 and 2.2.1 of Appendix B, 

which describe the 3-level system 

integrity checks. Also, the references in 

Sections 6.5.6(b)(3) and 6.5.6.3 of 

Appendix A to Section 3.2 of 40 CFR 

Part 60, Appendix B, Performance 

Specification No. 2 (PS2) are incorrect. 

The correct section number in PS2 is 

8.1.3, not 3.2. 

I. Appendix B 

1. 3-Load Flow RATA Frequency and 

RATA Grace Period 

On May 26, 1999, EPA revised 

Appendix B of Part 75, to reduce the 

required frequency of 3-load flow 

RATAs from annually to ‘‘at least once 

every 5 consecutive calendar years’’. 

However, as written, the rule actually 

allows more than five years (20 calendar 

quarters) to elapse between 3-load flow 

RATAs. For instance, if a 3-load flow 

RATA was performed in the1st quarter 

of 2001 and the next one is done in the 

4th quarter of 2006, the rule 

requirement would be met, but there 

would be 23 calendar quarters between 

the successive tests. 

In light of this, EPA is proposing to 

revise Section 2.3.1.3(c)(4) of Appendix 

B, to require 3-load flow RATAs to be 

done at least once every 20 calendar 

quarters. This is consistent with the 

other 5-year testing requirements in Part 

75, i.e., for Appendix E and LME units. 

It is also consistent with the maximum 


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allowable interval between successive 

accuracy tests of Appendix D fuel 

flowmeters. 

EPA is also proposing to revise the 

RATA grace period provisions in 

Section 2.3.3. In recent years many new 

combustion turbines have been built 

and most of them have NOX-diluent 

CEMS. A great number of these turbines 

have been operated infrequently due to 

the high price of natural gas. Because of 

this, a unit may go for a very long period 

of time without performing a RATA of 

the NOX monitoring system because the 

unit seldom, if ever, has a ‘‘QA 

operating quarter’’ (so the extended 

deadline for the next RATA is often 8 

calendar quarters from the previous 

test), and then it may be several quarters 

or even years before the allowable 720 

operating hour grace period expires. 

The grace period provisions in 

Section 2.3.3 were proposed in 1998 

and promulgated in May 1999, before 

the influx of new, infrequently-operated 

combustion turbines. Consequently, 

these rule provisions are often very 

difficult to track and apply to such 

units. Therefore, EPA proposes to 

modify the grace period methodology so 

that it is more understandable and userfriendly, particularly in cases where a 

unit seldom operates. 

Today’s proposal would move the 

requirements for determining the 

deadline for the next RATA after a grace 

period test from paragraph (c) of Section 

2.3.3 to a new paragraph (d). Paragraph 

(c) currently addresses both RATA 

deadlines and the data validation 

requirements for the case where a RATA 

is not completed by the end of the 720 

operating hour grace period. Creating a 

new paragraph (d) would make Section 

2.3.3 clearer, by treating the RATA 

deadline requirement as a distinct and 

separate issue. 

Proposed paragraph (d) would change 

the methodology for determining RATA 

deadlines without changing the end 

result. The intent of Section 2.3.3 has 

always been for the source to return to 

its original RATA schedule following a 

grace period test, in order to prevent the 

grace period provisions from being 

abused. For instance, if the source did 

not return to its original RATA 

schedule, the grace period could be 

used to extend the interval between 

successive annual RATAs from four QA 

operating quarters to five. 

The current language in Section 2.3.3 

works well enough for base load units 

that operate most of the time. For these 

units, the grace period almost invariably 

begins and ends within one calendar 

quarter of the RATA deadline, making it 

easy to return to the original RATA 

schedule. For instance, suppose that a 

base load unit is on a 2nd quarter RATA 

schedule and a grace period RATA is 

done in the 3rd quarter. If annual 

frequency is obtained, the deadline for 

the next RATA is reckoned from the 2nd 

quarter, when the RATA was due, rather 

than the 3rd quarter when the grace 

period test was actually done. 

Therefore, the next RATA would be 

required in the 2nd quarter of the 

following year, i.e., ‘‘back on schedule’’. 

However, for infrequently operated 

combustion turbines, the grace period 

sometimes spans across many calendar 

quarters, which effectively eliminates 

the possibility of establishing a 

meaningful relationship between the 

original RATA due date and the 

deadline for the next test. 

In view of these considerations, EPA 

is proposing a simplified methodology 

for determining RATA deadlines that 

will work for both base load units and 

combustion turbines that seldom 

operate. The deadline for the next 

RATA following a grace period test 

would be expressed as a certain number 

of QA operating quarters after the 

quarter of the grace period RATA, rather 

than referring back to the quarter in 

which the RATA was originally due 

(which could have been several quarters 

in the past). 

The deadline for the next RATA 

would be determined by first 

establishing whether the grace period 

RATA qualifies for the standard 

(semiannual) RATA frequency or the 

reduced (annual) frequency. If the grace 

period RATA does not qualify for the 

annual frequency, the deadline for the 

next RATA would be simply set at two 

QA operating quarters after the quarter 

of the grace period test. If the RATA 

qualifies for the annual frequency then 

the deadline for the next RATA would 

be set at three QA operating quarters 

after the quarter of the grace period test. 

There would be one exception to these 

rules. Regardless of the number of QA 

operating quarters that have elapsed 

following the grace period test, the 

interval between a grace period RATA 

and the deadline for the next required 

RATA could be no greater than eight 

calendar quarters. This provision is 

consistent with Section 2.3.1.1(a) of 

Appendix B. 

Finally, EPA is proposing to amend 

paragraph (c) of Section 2.3.3, to clarify 

that when a RATA is performed after 

the expiration of a grace period, the 

‘‘clock’’ is reset, and the next RATA 

would simply be due in two QA 

operating quarters (for semiannual 

frequency) or four QA operating 

quarters (for annual frequency), not to 

exceed eight calendar quarters. 

EPA believes that the proposed 

revisions to Section 2.3.3 of Appendix 

B would greatly simplify 

implementation of the grace period 

provisions and would enhance the 

Agency’s ability to track RATA 

deadlines and to provide meaningful 

feedback to the affected sources. 

2. RATA Requirement for Shared 

Components 

Today’s proposed rule would amend 

paragraph (g) in section 2.3.2 of 

Appendix B to specify the consequences 

of a failed RATA, in the case where a 

particular NOX pollutant concentration 

monitor is a component of both a NOX

concentration monitoring system and a 

NOX-diluent monitoring system. An 

example would be a coal-fired source 

that is subject to both the Acid Rain and 

NOX Budget Programs, for which the 

owner or operator elects to use a NOX

concentration system to quantify NOX

mass emissions, while using the NOXdiluent system to satisfy the Acid Rain 

Program requirement to monitor and 

report NOX emission rate in lb/mmBtu. 

In such cases, if the NOX concentration 

system RATA is failed, both the NOX

concentration monitoring system and 

the associated NOX-diluent monitoring 

system would be considered out-ofcontrol. Successful RATAs of both 

monitoring systems would be required 

to get them back in-control. 

3. AETB Requirements 

Appendix B would be further revised 

by adding a new Section, 1.1.4, to 

require that an Air Emissions Testing 

Body (AETB) that performs emission 

testing or RATAs for on-going qualityassurance under Part 75 must conform 

to ASTM D7036–04. 

4. Calibration Error Tests and Linearity 

Checks—Dual Range Applications 

Today’s rule would revise Sections 

2.1.1, 2.1.1.2, 2.1.5.1 and 2.2.3(e) of 

Appendix B, to clarify the data 

validation requirements for daily 

calibration error tests and linearity 

checks of gas monitors when two span 

values and two measurement ranges are 

required for a particular parameter (e.g., 

SO2 or NOX). 

Section 2.1.1 of Appendix B would be 

revised to require that sufficient 

calibration error tests be performed on 

the low and high monitor ranges to 

validate the data recorded on each 

range. The provisions of Section 2.1.5 of 

Appendix B would be used to determine 

whether ‘‘sufficient’’ calibration error 

tests have been done. A new paragraph 

(3) would also be added to Section 

2.1.5.1 of Appendix B to clarify how the 

QA status of the low and high ranges is 


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determined when: (a) A calibration error 

test on one of the ranges is failed; or (b) 

the most recent calibration error test of 

one of the ranges has expired. In the 

case where separate analyzers are used 

for the two ranges, a failed or expired 

calibration error test on one of the 

ranges would not affect the QA status of 

the other range. For a dual-range 

analyzer (i.e., a single analyzer with two 

scales), a failed calibration error test on 

either range would result in an out-ofcontrol period, and data from the 

monitor would remain invalid until 

corrective actions are taken, followed by 

successful ‘‘hands-off’’ calibrations of 

both ranges. However, if the most recent 

calibration error test on one range of a 

dual-range analyzer was successful, but 

its data validation window has expired, 

this would have no effect on the QA 

status of the other range. 

In the current rule, Section 2.2.3(e) in 

Appendix B states that when linearity 

checks are performed on both scales of 

a dual-range analyzer, an out-of-control 

period occurs if either of the two 

linearity checks is failed or aborted due 

to a problem with the monitor. 

However, it is not clear whether only 

one range or both ranges must be 

retested to get back in-control. Today’s 

rule would revise Section 2.2.3(e) to 

require ‘‘hands-off’’ linearity checks of 

both ranges of a dual-range analyzer 

whenever a linearity check on either 

range is failed or aborted (unless, of 

course, a particular range is exempted 

from linearity checks under Section 6.2 

of Appendix A). 

5. Off-Line Calibration Error Tests 

Part 75 requires calibration error tests 

of all CEMS to be done while the unit 

is combusting fuel (see Appendix B, 

Section 2.1.1 and Appendix A, Sections 

6.3.1 and 6.3.2). However, Section 

2.1.1.2 of Appendix B allows the owner 

or operator to make limited use of offline calibration error tests to validate 

data if an off-line calibration 

demonstration test is performed and 

passed. If the off-line calibration error 

demonstration is successful, then offline calibrations may be used to validate 

up to 26 unit operating hours of data 

before an on-line calibration error test is 

required. 

The off-line calibration provisions in 

Appendix B have not been wellunderstood by many affected sources. 

Through the years, EPA has received 

numerous requests for a more detailed 

explanation and/or examples of how to 

apply these rule provisions. Today’s 

rule would revise Sections 2.1.1.2 and 

2.1.5.1 of Appendix B to clarify the data 

validation rules for off-line calibration 

error tests. 

The Agency believes that main reason 

why there have been so many questions 

about the use of off-line calibration error 

tests is that paragraph (2) of Section 

2.1.1.2 is not clear. Paragraph (2) states 

that ‘‘a successful on-line calibration 

error test of the monitoring system must 

be completed no later than 26 unit 

operating hours after each off-line 

calibration error test used for data 

validation.’’ This statement can be 

easily misinterpreted. It could be 

understood to mean that a single off-line 

calibration error test can be used to 

validate 26 unit operating hours of data, 

regardless of the number of clock hours 

it takes to accumulate the 26 unit 

operating hours. However, this is not 

the intended meaning because it would 

directly contradict the statement, in 

Section 2.1.5 of Appendix B, that the 

window of data validation from a 

passed calibration error test extends for 

only 26 clock hours. 

To clarify EPA’s intent regarding the 

use of off-line calibration error tests to 

validate CEM data, today’s rule would 

revise Sections 2.1.1.2 and 2.1.5.1 of 

Appendix B. First, paragraph (2) in 

Section 2.1.1.2 would be revised to state 

that sources may make limited use of 

off-line calibrations if the off-line 

calibration demonstration has been 

performed and passed. Revised 

paragraph (2) of Section 2.1.5.1 would 

explain what ‘‘limited use’’ of off-line 

calibrations means. Off-line calibrations 

could be used to validate up to 26 

consecutive unit operating hours of data 

before an on-line test is required. Each 

individual off-line calibration would be 

valid only for 26 clock hours, and if the 

sequence of consecutive operating hours 

validated by off-line calibrations is 

broken before reaching the 26th 

consecutive unit operating hour, data 

from the monitor would become invalid 

until an on-line calibration is performed 

and passed. The sequence of 

consecutive valid hours would be 

considered broken whenever a unit 

operating hour is not contained within 

the 26 clock hour data validation 

window of a passed off-line calibration 

error test. 

6. Weekly System Integrity Check—Data 

Validation 

For a Hg CEMS that is equipped with 

a converter and that uses elemental Hg 

for daily calibrations, Section 2.6 of Part 

75, Appendix B requires a weekly 

system integrity check, using a NISTtraceable source of oxidized Hg. This 

‘‘weekly’’ test is required once every 168 

unit operating hours. However, Section 

2.6 does not explain the consequences 

of either failing the test or failing to 

perform the test on schedule. Today’s 

rule would add data validation rules for 

the weekly system integrity check to 

Section 2.6 of Appendix B. If the test is 

failed, it would trigger an out-of-control 

period until a subsequent system 

integrity check is passed. Also, if the 

test is not performed within 168 unit 

operating hours of the previous 

successful system integrity check, data 

from the CEMS would become invalid, 

starting with the 169th unit operating 

hour and continuing until a system 

integrity check is passed. 

Today’s rule would also correct a 

typographical error in Section 2.6 of 

Appendix B. The performance 

specification for the weekly system 

integrity check is incorrectly referenced 

in the current rule as Section 3.2 (c)(3) 

of Appendix A. The correct citation is 

Appendix A, Section 3.2, paragraph 

(3)(iii). 

7. Correction of Hg Units of Measure—

Figure 2 

Today’s rule would correct a minor 

error in the units of measure for Hg 

concentration in Figure 2 of Appendix 

B. The units of micrograms per dry 

standard cubic meter (μg/dscm) would 

be changed to micrograms per standard 

cubic meter (μg/scm). This change is 

necessary because not all Hg monitoring 

systems measure Hg concentration on a 

dry basis. 

J. Appendix D 

1. Update of Incorporation by Reference 

As discussed in Section II.B.1of this 

preamble, EPA proposes to update the 

list of test methods, sampling and 

analysis procedures, and other items 

that are incorporated by reference in 

Part 75. As such, this proposal also 

includes the necessary updates to the 

references in Appendix D. 

EPA is also proposing to add to 

Section 2.1.5.1 of Appendix D, the 

American Petroleum Institute’s (API) 

Manual of Petroleum Measurement 

Standards Chapter 22—Testing Protocol: 

Section 2—Differential Pressure Flow 

Measurement Devices (First Edition, 

August 2005) as a new standard 

procedure for verifying flowmeter 

accuracy. 

2. Pipeline Natural Gas—Method of 

Qualification and Monthly GCV Values 

For a unit which combusts a fuel that 

meets the definition of ‘‘pipeline natural 

gas’’ (PNG) in § 72.2, Section 2.3.1.1 of 

Appendix D allows the owner or 

operator to estimate the unit’s SO2 mass 

emissions using a default SO2 emission 

rate of 0.0006 lb/mmBtu. To qualify to 

use this SO2 emission rate, the owner or 

operator must document in the 


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monitoring plan for the unit that the 

natural gas has a total sulfur content of 

0.5 grains per 100 standard cubic foot or 

less. Section 2.3.1.4 describes three 

ways to initially demonstrate that the 

gas meets this total sulfur requirement: 

(1) Based on the gas quality 

characteristics specified in a purchase 

contract, tariff sheet, or pipeline 

transportation contract; or (2) based on 

historical fuel sampling data from the 

previous 12 months; or (3) based on at 

least one representative sample of the 

gas, if the requirements of (1) or (2) 

cannot be met. When fuel sampling data 

are used to qualify, each individual 

sample result must meet the total sulfur 

limit. Once a fuel has qualified as 

pipeline natural gas, Section 2.3.1.4(e) 

of Appendix D requires annual 

sampling of the total sulfur content to 

demonstrate that the fuel still meets the 

definition of PNG. At least one sample 

per year must be taken and if multiple 

samples are taken, each one must meet 

the 0.5 gr/100 scf total sulfur limit. 

The criteria for documenting the total 

sulfur content of PNG were promulgated 

on June 12, 2002, and the annual total 

sulfur requirement became effective on 

January 1, 2003. Since then, EPA has 

learned that many suppliers of natural 

gas regularly sample the total sulfur 

content of the gas (in many cases, daily) 

and will provide that data to their 

customers upon request. Sources 

desiring to use this data to meet the 

initial or ongoing total sulfur sampling 

requirements of Appendix D have 

approached EPA, asking whether the gas 

would be disqualified from using the 

0.0006 lb/mmBtu SO2 emission rate if 

the total sulfur content of one of these 

daily samples exceeded 0.5 gr/100 scf. 

Thus far, the Agency has addressed 

these requests on a case-by-case basis. 

Generally, in cases where the number of 

total sulfur samples far exceeds the 

requirements of Appendix D, EPA has 

allowed the sources to reduce the data 

to monthly averages. Then, if all of the 

monthly averages are below the 0.5 gr/ 

100 scf , the fuel would be allowed to 

continue using the 0.0006 lb/mmBtu 

default SO2 emission rate. 

EPA believes that the current rule 

requirements for documenting the sulfur 

content of pipeline natural gas are too 

restrictive and need to be revised. For 

example, a source that takes only one or 

perhaps a handful of sulfur samples 

each year is allowed to use the 0.0006 

lb/mmBtu default emission rate without 

question if all samples have ≤ 0.5 gr/100 

scf of total sulfur. However, a source 

with hundreds of total sulfur sample 

results could possibly be disqualified 

from using the default emission rate if 

one sample exceeded the 0.5 gr/100 scf 

limit. To correct this inequitable 

situation, today’s rule would revise 

Sections 2.3.1.4(a)(2) and (e) of 

Appendix D. 

For the initial documentation that the 

gas meets the 0.5 gr/100 scf total sulfur 

limit, proposed Section 2.3.1.4(a)(2) 

would allow sources whose fuel 

suppliers have provided them with at 

least 100 daily (or more frequent) total 

sulfur samples from the previous 12 

months to reduce the data to monthly 

averages. If all monthly averages meet 

the 0.5 gr/100 scf limit, the fuel would 

qualify as pipeline natural gas, and the 

source could use the 0.0006 lb/mmBtu 

default SO2 emission rate. Alternatively, 

if at least 98 percent of the 100 (or more) 

samples have a total sulfur content of 

0.5 gr/100 scf or less, the fuel would 

qualify as pipeline natural gas. 

The revisions to Section 2.3.1.4(e) 

would allow this same calculation 

methodology to be used for the annual 

total sulfur sampling requirement. That 

is, each year, if at least 100 total sulfur 

samples from the past 12 months are 

provided by the fuel supplier, the data 

could either be reduced to monthly 

averages, or the percentage of the 

samples that meet the 0.5 gr/100 scf 

limit could be determined. 

EPA is also proposing to clarify the 

GCV sampling requirements for pipeline 

natural gas in Section 2.3.4.1 of 

Appendix D. The current rule requires 

monthly GCV sampling for PNG. 

However, Section 2.3.4.1 refers only to 

the ‘‘monthly sample’’ (singular), 

whereas affected sources may collect 

and analyze multiple GCV samples each 

month, or may receive the results of 

multiple GCV samples from the fuel 

supplier each month. In view of this, 

revised Section 2.3.4.1 would require 

that a monthly average GCV value be 

used for Part 75 reporting, for any 

month in which multiple samples are 

taken and analyzed. To implement this 

provision, whenever Section 2.3.7(c) of 

Appendix D requires the results of a 

monthly GCV sample to be applied 

‘‘starting from the date on which the 

sample was taken’’, the owner or 

operator would apply the monthly 

average GCV value, starting from the 

latest date of any of the individual GCV 

samples used to calculate the monthly 

average. EPA believes that monthly 

averaging of the available GCV samples 

will ensure that representative robust 

GCV values are used in the Appendix D 

heat input calculations. 

3. Requirement To Split Oil Samples 

For affected units that combust fuel 

oil and use the Appendix D ‘‘excepted’’

methodology to quantify SO2 mass 

emissions and/or unit heat input, 

Section 2.2 of Appendix D requires the 

owner or operator to perform periodic 

sampling of the sulfur content, gross 

calorific value and (if necessary) density 

of the oil. There are four basic oil 

sampling options described in Section 

2.2: (a) Daily sampling; (b) flow 

proportional sampling (composite 

sample, up to 7 days); (c) sampling from 

a unit’s storage tank after each addition 

of oil to the tank; and (d) sampling of 

each fuel lot (either upon receipt of the 

lot or sampling from supplier’s storage 

tank prior to delivery). Regardless of 

which sampling option is selected, 

Section 2.2.5 of Appendix D requires 

each oil sample to be split and a portion 

(at least 200 cc) of it to be maintained 

for at least 90 days after the end of the 

allowance accounting period. 

The requirement to split and maintain 

a portion of each oil sample has been in 

Appendix D since it was first 

promulgated on January 11, 1993. At 

that time, on-site fuel oil sampling was 

required on every day that the unit 

combusted oil. Later, on May 17, 1995, 

an option to sample each shipment 

upon delivery was added for diesel fuel. 

Then, on May 26, 1999, the four basic 

oil sampling options in the current rule 

were put in place. However, the 

requirement to split and maintain a 

portion of each sample has remained 

unchanged through all of these 

rulemakings. 

EPA believes that the requirement to 

split and maintain oil samples should 

only apply to samples that are taken at 

the affected facility. Today’s rule would 

revise Section 2.2.5 of Appendix D to 

limit this requirement to samples that 

are taken on-site. Therefore, sources 

using the fourth sampling option in 

Section 2.2 of Appendix D, i.e., 

sampling from each fuel lot, would no 

longer be required to split and maintain 

oil samples in the case where the 

samples are taken off-site, from the fuel 

supplier’s storage container. 

K. Appendix E 

1. AETB Requirements 

EPA proposes to revise Section 2.1 of 

Appendix E to require that any Air 

Emissions Testing Body (AETB) 

performing emission measurements to 

develop an Appendix E correlation 

curve or to derive a default emission 

rate for an LME unit, would have to 

conform to ASTM D7036–04. 

2. Reporting Data When the Correlation 

Curve Expires 

For oil and gas-fired peaking units 

using the Appendix E ‘‘excepted’’

methodology to estimate NOX

emissions, the owner or operator is 


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required, for each fuel type, to perform 

four-load emission testing for initial 

certification in order to develop a 

correlation curve of NOX emission rate 

versus heat input rate. Each correlation 

curve is programmed into the data 

acquisition and handling system 

(DAHS), and retesting is required every 

five years (20 calendar quarters) to 

develop a new curve. 

If the 20 calendar quarter test 

deadline passes without a retest having 

been performed, the previous 

correlation curve expires and is no 

longer valid. Ordinarily, when data from 

a Part 75 monitoring system become 

invalid, missing data substitution 

procedures are applied. Section 2.5 of 

Appendix E contains missing data 

provisions that address the following 

situations: (a) When the monitored QA 

parameters are unavailable or invalid; 

(b) when the measured heat input rate 

is higher than the highest heat input rate 

on the correlation curve; (c) when NOX

emission controls are either not 

operating or not documented to be 

working properly; and (d) when 

emergency fuel is burned. 

Conspicuously absent from Section 

2.5 is a missing data procedure to follow 

when a correlation curve expires. To 

address this deficiency, today’s rule 

would add a new Section, 2.5.2.4, to 

Appendix E, requiring the fuel-specific 

maximum potential NOX emission rate 

(MER) to be reported when a baseline 

correlation curve expires. The MER 

would continue to be reported until a 

new correlation curve is generated. 

L. Appendix F 

1. NOX Mass Calculations 

EPA proposes to revise the manner in 

which NOX mass data are collected 

under the XML–EDR format that will be 

required in 2009 as part of EPA’s effort 

to re-engineer the Agency’s data 

collection systems. Under the current 

reporting requirements, sources are 

required to report hourly NOX mass 

emissions (lb) and then to sum these 

hourly records and divide by 2000 lb/ 

ton to determine the quarterly NOX

mass emissions (tons). This is 

inconsistent with the manner in which 

SO2 and CO2 mass emissions data are 

reported and aggregated. For SO2 and 

CO2, the hourly values are reported as 

mass emission rates (lb/hr). The 

quarterly cumulative mass emissions are 

calculated by multiplying each reported 

hourly mass emission rate by the 

corresponding unit or stack operating 

time, summing these products, and then 

dividing the sum by 2000 lb/ton to get 

tons of SO2 or CO2. 

Today’s proposed rule seeks to 

harmonize the reporting formats by 

requiring the reporting of hourly NOX

mass emission rate (lb/hr) instead of 

hourly NOX mass emission (lb), when 

the source transition from the current 

EDR reporting format to the XML–EDR 

reporting format. As previously 

discussed, sources may use either the 

existing EDR format or the new XML–

EDR reporting format in 2008, but will 

be required to use the new XMLreporting format, only, in 2009. 

Requiring the reporting of hourly NOX

mass emission rate (lb/hr) necessitates 

the modification of Equations F–24, and 

F–27 in Appendix F of Part 75 and the 

removal of Equation F–26. However, 

since the current EDR reporting format 

will continue to be supported through 

2008, EPA must retain these equations 

in the rule until the transition to XML–

EDR is complete. Therefore, EPA is 

proposing to revise Section 8 of 

Appendix F, by adding Equation F–24a 

for the reporting of hourly NOX mass 

emission rate (lb/hr). Equation F–24a is 

a modified version of F–24, in which 

the operating time variable is removed. 

The use of Equation F–24a would be 

mandatory in the new XML–EDR 

format. Likewise, Equation F–27a would 

be added, which is a modified form of 

Equation F–27 that includes the 

operating time variable. In the XML–

EDR format, cumulative NOX mass 

emissions would be calculated using 

Equation F–27a. 

Since both EDR reporting formats 

currently in use (i.e., EDR versions 2.1 

and 2.2) require reporting of hourly NOX

mass emissions (lb), the current versions 

of Equations F–24 and F–27 would 

remain in the rule. However, these 

equations would no longer be applicable 

in 2009, when the use of XML–EDR 

format is required for all affected 

sources. 

Today’s proposal also would revise 

Section 8.2 of Appendix F, by splitting 

it into two subsections, 8.2.1 and 8.2.2. 

Section 8.2 of the current rule describes 

a procedure for calculating the NOX

mass emission rate in lb/hr, when NOX

mass emissions are determined using a 

NOX concentration monitoring system 

and a flow monitor. Section 8.2 crossreferences other parts of the rule, rather 

than showing the actual equations used. 

Today’s proposed rule would add 

Equation F–26a to proposed subsection 

8.2.1 and Equation F–26b to proposed 

subsection 8.2.2, clearly showing how 

the NOX mass emission rate is 

calculated on a wet and dry basis. 

Equation F–26 in Section 8.3 would be 

re-numbered as Equation F–26c. 

Proposed Equations F–26a and F–26b 

are currently used by sources to 

calculate NOX mass emissions under 

Subpart H of Part 75. These equations 

are represented in the EDR reporting 

instructions, as Equations N–1 and N–

2 respectively. EPA believes that it is 

appropriate to add these equations to 

the rule at this time. 

2. Use of the Diluent Cap 

Today’s proposed rule would restrict 

the use of the diluent cap to NOX

emission rate calculations. The original 

purpose for implementing the diluent 

cap was to keep calculated NOX

emission rates from approaching 

infinity during periods of unit startup 

and shutdown, where the diluent gas 

(CO2 or O2) concentration is close to the 

level in the ambient air. However, the 

current rule allows the diluent cap to be 

used for heat input rate calculations, 

CO2 mass emission calculations, and 

calculation of hourly CO2 concentration 

from measured O2 concentrations, in 

addition to being used for NOX emission 

rate. Sources are also allowed to use the 

cap value for some of these calculations 

and not others. This greatly complicates 

the data collection process. EPA has 

also found that using the diluent cap for 

other parameters besides NOX emission 

rate always leads to over-reporting of 

these parameters, which is clearly 

contrary to the intended purpose of the 

diluent cap. Therefore, today’s proposed 

rule would remove all of the references 

in Sections 4 and 5 of Appendix F 

which allow the diluent cap to be used 

for other parameters besides NOX

emission rate 

3. Negative Emission Values 

EPA proposes to provide special 

reporting instructions to account for 

situations where the equations 

prescribed by the rule yield negative 

values. First, when Equation 19–3 or 

19–5 (from EPA Method 19 in 40 CFR 

Part 60, Appendix A) is used to 

calculate NOX emission rate, modified 

forms of these equations, designated as 

Equations 19–3D and 19–5D, would be 

used whenever the diluent cap is 

applied. Second, for any hour where 

Equation F–14b results in a negative 

hourly average CO2 value, EPA proposes 

to require 0.0% CO2 to be reported as 

the average CO2 value for that hour. 

Third, EPA proposes to require a default 

heat input rate value of 1 mmBtu/hr to 

be reported for any hour in which 

Equation F–17 results in a negative 

hourly heat input rate. These changes 

would be accomplished by modifying 

Sections, 3.3.4, 4.4.1, and 5.2.3 of 

Appendix F. 


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4. Calculation of Stack Gas Moisture 

Content 

Today’s proposed rule would add 

Equation F–31 to a new Section 10 of 

Appendix F. This equation is used to 

calculate stack gas moisture values from 

wet and dry oxygen measurements, as 

described in Appendix A, Section 

6.5.7(a). The equation is currently 

represented in the EDR reporting 

instructions as Equation M–1. 

5. Site-Specific F-Factors (Single Fuel) 

For units that use CEMS to measure 

the NOX emission rate in lb/mmBtu 

and/or the unit heat input rate in 

mmBtu/hr, an equation from Appendix 

F of Part 75 or from Method 19 of 40 

CFR Part 60 is required to convert the 

raw CEMS data into the proper units of 

measure. Each of these equations 

contains an F-factor, which represents 

either the total volume of flue gas or the 

volume of CO2 generated per million 

Btu of heat input. The F-factor is fuelspecific. 

Sections 3.3.5 and 3.3.6 of Appendix 

F allow the owner or operator to use 

either a default F-factor from Table 1 in 

Appendix F, or use Equation F–7a or F–

7b in Appendix F to calculate a sitespecific F-factor, based on the 

composition of the fuel. However, 

Appendix F neither specifies how much 

fuel sampling data is required to 

develop a site-specific F-factor, nor how 

often the F-factor must be updated. 

To address this issue, today’s rule 

would revise the introductory text of 

Appendix F, Section 3.3.6 to require 

each site-specific F-factor to be based on 

a minimum of 9 samples of the fuel. 

Fuel samples taken during the 9 runs of 

an annual RATA would be acceptable 

for this purpose. Further, redetermination of the F-factor would be 

required at least annually, and the value 

from the most recent determination 

would be used in the emission 

calculations. 

6. Prorated F-Factors 

For affected units that co-fire 

combinations of fossil fuels or fossil 

fuels and wood residue and that use 

CEMS to monitor the NOX emission rate 

or unit heat input rate, Section 3.3.6.4 

of Appendix F requires a prorated Ffactor to be used in the emission 

calculations. The prorated F-factor is 

calculated using Equation F–8 in 

Appendix F. In applying Equation F–8, 

the F-factor for each type of fuel is 

weighted according to the fraction of the 

total heat input contributed by the fuel. 

However, Equation F–8 fails to specify 

how the total unit heat input and the 

fraction of the heat input contributed by 

each fuel are determined. Data from the 

CEMS cannot be used for this purpose 

because the prorated F-factor must be 

known before the unit heat input rate 

can be calculated. 

Through the years, in response to 

inquiries about this, EPA has advised 

sources to use the best available 

auxiliary process data, such as fuel feed 

rates and measured GCV values, to 

provide heat input estimates for 

calculating the prorated F-factor, but no 

official Agency policy guidance has 

been issued. To correct this situation, 

today’s rule would revise the definition 

of ‘‘Xi’’ (the fraction of the total heat 

input derived from each fuel) in the 

Equation F–8 nomenclature. The revised 

definition would require sources to 

determine Xi from the best available 

information on the quantity of each fuel 

combusted and its GCV value over a 

specified time period. The value of Xi

would be updated periodically, either 

hourly, daily, weekly, or monthly, and 

the prorated F-factor used in the 

emission calculations would be derived 

from the Xi values from the most recent 

update. The owner or operator would be 

required to document in the hard copy 

portion of the monitoring plan the 

method used to determine the Xi values. 

7. Default F-Factors 

EPA proposes to add default F-factors 

for petroleum coke and tire derived 

fuels to Table 1 in Section 3.3.5 of 

Appendix F. The proposed values are 

9,832 dscf/mmBtu for Fd and 1,853 scf 

CO2/mmBtu for Fc for petroleum coke 

and 10,261 dscf/mmBtu for Fd and 1,803 

scf CO2/mmBtu for Fc for tire derived 

fuels. These F-factors are needed 

because petroleum coke and tires are 

being used as a fuel by a number of 

units. EPA is also proposing 9,819 dscf/ 

mmBtu for Fd and 1,840 scf CO2/mmBtu 

for Fc as F-factors for sub-bituminous 

coal. These F-factors were calculated 

using Part 75, Appendix F, Equations F–

7a and F–7b and representative 

composition and gross calorific value 

(GCV) data for each fuel. 

8. Revisions to Equation F–23 

Consistent with the proposed changes 

to § 75.11(e), expanding the 

applicability of Equation F–23 (which 

are discussed in detail in Section II.B.4 

of this preamble), modifications would 

be made to Section 7 of Appendix F 

(introductory text), and to the Equation 

F–23 nomenclature. 

M. Appendix G 

Consistent with the changes to other 

parts of the rule, EPA proposes to 

update the current ASTM standards 

listed in Sections 2.1.2, 2.2.1, and 2.2.2, 

of Appendix G, citing the newer 

versions. 

N. Appendix K 

Today’s proposed rule addresses 

several issues regarding the use of 

sorbent trap monitoring systems for the 

measurement and reporting of Hg mass 

emissions. When this monitoring option 

is selected, the current rule requires the 

use of paired sorbent traps to measure 

the effluent Hg concentration. If the two 

Hg concentrations measured by the 

paired traps meet the required relative 

deviation (RD) specification in 

Appendix K of Part 75, and if each trap 

individually meets certain other QA 

requirements of Appendix K, then the 

two Hg concentrations are averaged 

arithmetically and the average value is 

used to determine the Hg mass 

emissions in each hour of the data 

collection period. However, in cases 

where either or both of the traps fails to 

meet the acceptance criteria, § 75.15(h) 

and Table K–1 of Appendix K specify 

consequences of varying severity. As 

discussed in the following paragraphs, 

EPA has reconsidered these rule 

provisions and has concluded that some 

of the consequences are too lenient 

while others are unnecessarily harsh. 

The Agency is therefore proposing to 

revise them to make them more 

consistent and equitable. 

Section 75.15(h) currently provides a 

measure of relief to the affected sources 

whenever one of the paired traps is 

accidentally lost, damaged, or broken 

and cannot be analyzed. In such cases, 

the owner or operator is allowed to use 

the remaining trap to determine the Hg 

concentration for the data collection 

period, provided that the remaining trap 

meets all of the QA requirements of 

Appendix K. But the rule does not 

require any adjustment of the data to 

compensate for the loss of one of the 

samples. In view of this, EPA is 

proposing to revise § 75.15(h) to require 

that the Hg concentration measured by 

the remaining valid trap be multiplied 

by a ‘‘single trap adjustment factor’’

(STAF) of 1.222. The STAF represents 

the maximum amount by which the Hg 

concentration from the lost, damaged or 

broken trap could have exceeded the 

concentration measured by the valid 

trap and still met the 10% RD 

specification. 

The Agency is also proposing to 

revise Table K–1 in Appendix K, to 

extend the use of the STAF to cases 

where one of the paired sorbent traps 

either: (a) Fails a post-test leak check; 

(b) has excessive breakthrough in the 

second section; or (c) is unable to meet 

the required percent recovery of the 

third section elemental Hg spike. In all 


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three of these cases, provided that the 

other trap meets all Appendix K 

requirements, rather than invalidating 

the sorbent trap system data for the 

entire collection period, the Hg 

concentration measured by the valid 

trap, multiplied by the STAF, could be 

used for Part 75 reporting. 

Section 7.2.3 of Appendix K requires 

that for each hour of the data collection 

period, the ratio of the stack gas flow 

rate to the sample flow rate through 

each sorbent trap must be maintained 

within 25 percent of the initial ratio 

established in the first hour of the data 

collection period. However, the current 

rule does not say what to do if this 

criterion is not met. Rather, Table K–1 

indicates that the appropriate 

consequences are to be determined on a 

‘‘case-by-case’’ basis. EPA has 

reconsidered this approach and is 

proposing to revise it, because it opens 

the door to inconsistent application of 

the sorbent trap monitoring 

methodology. Therefore, Table K–1 

would be revised to specify that a 

sample is invalidated if either: (a) More 

than 5 percent of the hourly ratios; or 

(b) more than 5 hourly ratios in the data 

collection period (whichever is less 

restrictive) fail to meet the ±25 percent 

acceptance criterion. Further, if only 

one of the paired traps is able to meet 

the specification, provided that it also 

meets the rest of the Appendix K QA 

criteria, the valid trap could be used for 

Part 75 reporting, if the single trap 

adjustment factor of 1.222 is applied to 

the measured Hg concentration. 

Appendix K currently requires that 

the data from a sorbent trap monitoring 

system be invalidated whenever the 

relative deviation between the Hg 

concentrations measured by the paired 

traps is greater than 10 percent. EPA 

proposes to revise this requirement, to 

allow sources to report the higher of the 

two Hg concentrations measured by a 

pair of sorbent traps whenever the RD 

specification is not met, rather than 

invalidating the sorbent trap system 

data for the entire collection period. 

EPA is also proposing, for consistency 

with the proposed changes § 75.22(a) 

(which are discussed in Section II.C.3 of 

this preamble), to revise Table K–1 to 

include an alternative relative deviation 

specification of 20 percent for paired 

sorbent traps, where low effluent 

concentrations of Hg (≤ 1 μg/m3) are 

encountered. 

Today’s proposed rule would add two 

new paragraphs, (k) and (l), to § 75.15. 

Proposed § 75.15(k) would require that 

whenever the RATA of a sorbent trap 

system is performed, the sorbent traps 

used to collect the RATA run data must 

be the same size as the traps used for 

daily operation of the monitoring 

system. Likewise, the sorbent material 

must be the same type that is used for 

daily operation. Proposed § 75.15(l) 

would require a diagnostic RATA of the 

sorbent trap system whenever the size of 

the sorbent traps or the type of sorbent 

material is changed. Data from the 

modified sorbent trap system would not 

be acceptable for Part 75 reporting until 

the RATA is passed, with one 

exception, i.e., data collected during a 

successful diagnostic RATA test period 

could be reported as quality-assured. 

EPA is proposing to add these 

requirements because the relative 

accuracy and bias of a sorbent trap 

monitoring system are dependent upon 

both the trap design and the type of 

sorbent material used. 

Finally, today’s proposed rule would 

revise section 7.2.3 of Appendix K to 

require that the sample flow rate 

through a sorbent trap monitoring 

system must be zero when the unit is 

not operating. This clarification is 

needed to prevent the system from 

sampling ambient air during periods 

when the combustion unit is off-line. 

Sampling ambient air when the unit is 

not in operation would artificially lower 

the Hg concentrations measured by the 

sorbent traps, resulting in underreporting of Hg mass emissions. 

II. Administrative Requirements 

A. Executive Order 12866—Regulatory 

Planning and Review 

This action is not a ‘‘significant 

regulatory action’’ under the terms of 

Executive Order (EO) 12866 (58 FR 

51735, October 4, 1993) and is therefore 

not subject to review under the EO. 

B. Paperwork Reduction Act 

The information collection 

requirements in the proposed rule have 

been submitted for approval to OMB 

under the Paperwork Reduction Act, 44 

U.S.C. 3501 et seq. The Information 

Collection Request (ICR) document 

prepared by EPA has been assigned EPA 

ICR number 2203.01. The information 

requirements are based on the proposed 

revisions to the monitoring, 

recordkeeping, and reporting 

requirements in 40 CFR Part 75, which 

are mandatory for all sources subject to 

the Acid Rain Program under Title IV of 

the Clean Air Act and certain other 

emissions trading programs 

administered by EPA. 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 Part 2, subpart B. The existing 

Part 75 rule requirements are covered by 

existing ICRs for the Acid Rain Program 

(EPA ICR number 1633.13; OMB control 

number 2060–0258), the NOX SIP Call 

(EPA ICR number 1857.03; OMB 

number 2060–0445), and the Clean Air 

Interstate Rule (EPA ICR number 

2152.01). The separate ICR for the 

proposed rule revisions addresses the 

one time costs necessary for sources to 

review the rule revisions and adapt their 

recordkeeping and reporting systems to 

the revised requirements. The EPA 

believes that the long term implications 

of the proposed rule revisions will be to 

reduce the ongoing burdens and costs 

associated with Part 75 compliance, but 

those impacts will be addressed as EPA 

renews the individual program ICRs. 

The annual monitoring, reporting, and 

recordkeeping burden for this collection 

(averaged over the first 3 years after the 

effective date of the final rule) is 

estimated to be 124,976 labor hours per 

year at a total annual cost of $8,581,420. 

This estimate includes burdens for rule 

review, recordkeeping and reporting 

software upgrades, and software 

debugging activities, as well as the 

capital costs of upgrading recordkeeping 

and reporting software. 

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. 

To comment on the Agency’s need for 

this information, the accuracy of the 

provided burden estimates, and any 

suggested methods for minimizing 

respondent burden, including the use of 

automated collection techniques, EPA 

has established a public docket for this 

rule, which includes this ICR, under 

Docket ID number OAR–2005–0132. 

Submit any comments related to the ICR 

for this proposed rule to EPA and OMB. 


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See ADDRESSES section at the beginning 

of this notice for where to submit 

comments to EPA. Send comments to 

OMB at the Office of Information and 

Regulatory Affairs, Office of 

Management and Budget, 725 17th 

Street, NW., Washington, DC 20503, 

Attention: Desk Office for EPA. Since 

OMB is required to make a decision 

concerning the ICR between 30 and 60 

days after August 22, 2006, a comment 

to OMB is best assured of having its full 

effect if OMB receives it by September 

21, 2006. The final rule will respond to 

any OMB or public comments on the 

information collection requirements 

contained in this proposal. 

C. Regulatory Flexibility Act 

The Regulatory Flexibility Act (RFA) 

generally requires an agency to prepare 

a regulatory flexibility analysis of any 

rule subject to notice and comment 

rulemaking requirements under the 

Administrative Procedure Act or any 

other statute unless the agency certifies 

that the rule will not have a significant 

economic impact on a substantial 

number of small entities. Small entities 

include small businesses, small 

organizations, and small governmental 

jurisdictions. 

For purposes of assessing the impacts 

of today’s proposed rule on small 

entities, small entity is defined as: (1) A 

small business as defined by the Small 

Business Administration’s (SBA) 

regulations at 13 CFR 121.201; (2) a 

small governmental jurisdiction that is a 

government of a city, county, town, 

school district or special district with a 

population of less than 50,000; or (3) a 

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

owned and operated and is not 

dominant in its field. 

After considering the economic 

impacts of today’s proposed rule on 

small entities, I certify that this action 

will not have a significant economic 

impact on a substantial number of small 

entities. In determining whether a rule 

has a significant economic impact on 

small entities, the impact of concern is 

any significant adverse economic 

impact on small entities, since the 

primary purpose of the regulatory 

flexibility analysis is to identify and 

address regulatory alternatives ‘‘which 

minimize any significant economic 

impact of the rule on small entities.’’ 5 

U.S.C. 603 and 604. Thus, an agency 

may certify that a rule will not have a 

significant economic impact on a 

substantial number of small entities if 

the rule relieves regulatory burden or 

otherwise has a positive economic effect 

on all of the small entities subject to the 

rule. The proposed rule revisions 

represent minor changes to existing 

monitoring requirements used in EPA 

emission trading programs. Although 

there will be some small level of up 

front costs to reprogram existing 

electronic data reporting software used 

under this program, the long term 

effects of these proposed revisions is to 

allow continued efficient electronic data 

submittals that should act to relieve 

some of the long term reporting burdens 

for affected sources, which include 

some small entities. 

We continue to be interested in the 

potential impacts of the proposed rule 

on small entities and welcome 

comments on issues related to such 

impacts. 

D. Unfunded Mandates Reform Act 

Title II of the Unfunded Mandates 

Reform Act of 1995 (UMRA), Public 

Law 104–4, establishes requirements for 

Federal agencies to assess the effects of 

their regulatory actions on State, local, 

and tribal governments and the private 

sector. Under Section 202 of the UMRA, 

EPA generally must prepare a written 

statement, including a cost-benefit 

analysis, for proposed and final rules 

with ‘‘Federal mandates’’ that may 

result in expenditures to State, local, 

and tribal governments, in the aggregate, 

or to the private sector, of $100 million 

or more in any one year. Before 

promulgating an EPA rule for which a 

written statement is needed, Section 205 

of the UMRA generally requires EPA to 

identify and consider a reasonable 

number of regulatory alternatives and 

adopt the least costly, most costeffective, or least burdensome 

alternative that achieves the objectives 

of the rule. The provisions of Section 

205 do not apply when they are 

inconsistent with applicable law. 

Moreover, Section 205 allows EPA to 

adopt an alternative other than the least 

costly, most cost-effective, or least 

burdensome alternative if the 

Administrator publishes with the final 

rule an explanation why that alternative 

was not adopted. Before EPA establishes 

any regulatory requirements that may 

significantly or uniquely affect small 

governments, including tribal 

governments, it must have developed 

under Section 203 of the UMRA a small 

government agency plan. The plan must 

provide for notifying potentially 

affected small governments, enabling 

officials of affected small governments 

to have meaningful and timely input in 

the development of EPA regulatory 

proposals with significant Federal 

intergovernmental mandates, and 

informing, educating, and advising 

small governments on compliance with 

the regulatory requirements. 

EPA has determined that this 

proposed rule does not contain a 

Federal mandate that may result in 

expenditures of $100 million or more 

for State, local, and tribal governments, 

in the aggregate, or in the private sector 

in any one year. Thus, today’s proposed 

rule is not subject to the requirements 

of Sections 202 and 205 of the UMRA. 

EPA has determined that this rule 

contains no regulatory requirements that 

might significantly or uniquely affect 

small governments. The revisions 

primarily would make certain changes 

EPA has determined are necessary as 

part of upgrading the data systems used 

to manage data submitted under the 

program and to streamline the methods 

for sources to report their information. 

The revisions also would clarify certain 

issues that have been raised during 

ongoing implementation of the existing 

rule and would update the information 

on various voluntary consensus 

standards incorporated by reference in 

the rule. Some States do have programs 

that rely on the monitoring provisions 

in 40 CFR Part 75, and States may incur 

some costs associated with reviewing 

the proposed modifications to Part 75, 

but the rule revisions and the impact on 

the States would not be significant. 

E. Executive Order 13132—Federalism 

Executive Order 13132, entitled 

‘‘Federalism’’ (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 Executive Order 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.’’

This proposed rule does not have 

federalism implications. This proposed 

rule 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 Executive Order 13132. 

These proposed rule revisions represent 

minor adjustments to existing 

regulations. The revisions primarily 

would make certain changes EPA has 

determined are necessary as part of 

upgrading the data systems used to 

manage data submitted under the 

program and to streamline the methods 

for sources to report their information. 

The revisions also would clarify certain 


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issues that have been raised during 

ongoing implementation of the existing 

rule and would update the information 

on various voluntary consensus 

standards incorporated by reference in 

the rule. Some States do have programs 

that rely on the monitoring provisions 

in 40 CFR Part 75, and States may incur 

some costs associated with reviewing 

the proposed modifications to Part 75, 

but the rule revisions and the impact on 

the States would not be significant. 

Thus, Executive Order 13132 does not 

apply to this proposed rule. In the spirit 

of Executive Order 13132, and 

consistent with EPA policy to promote 

communications between EPA and State 

and local governments, EPA specifically 

solicits comment on this proposed rule 

from State and local officials. 

F. Executive Order 13175—Consultation 

and Coordination With Indian Tribal 

Governments 

Executive Order 13175, entitled 

‘‘Consultation and Coordination with 

Indian Tribal Governments’’ (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.’’ This proposed rule does 

not have tribal implications, as specified 

in Executive Order 13175. The proposed 

action makes minor revisions to existing 

rule requirements. Thus, Executive 

Order 13175 does not apply to this 

proposed rule. The EPA specifically 

solicits additional comment on the 

proposed rule from tribal officials. 

G. Executive Order 13045—Protection of 

Children From Environmental Health 

and Safety Risks 

Executive Order 13045, ‘‘Protection of 

Children from Environmental Health 

Risks and Safety Risks’’ (62 FR 19885, 

April 23, 1997), applies to any rule that: 

(1) Is ‘‘economically significant’’ as 

defined under Executive Order 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, the Agency 

must 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. 

This proposed rule is not subject to 

the Executive Order because it is not 

economically significant as defined in 

Executive Order 12866, and because the 

Agency does not have reason to believe 

the proposed revisions to certain 

monitoring and reporting requirements 

implicate any environmental health or 

safety risks, including any specific risks 

that present a disproportionate risk to 

children. The public is invited to submit 

or identify peer-reviewed studies and 

data, of which the agency may not be 

aware, that are relevant to the 

environmental health or safety risks to 

children that could be implicated by 

this proposed action. 

H. Executive Order 13211—Actions 

That Significantly Affect Energy Supply, 

Distribution, or Use 

This proposed rule is not a 

‘‘significant energy action’’ as defined in 

Executive Order 13211, ‘‘Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use’’ (66 FR 28355, May 

22, 2001), because it is not likely to have 

a significant adverse effect on the 

supply, distribution, or use of energy. 

I. National Technology Transfer and 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (‘‘NTTAA’’), Public Law 

104–113, 12(d) (15 U.S.C. 272 note), 

directs EPA to use voluntary consensus 

standards in its regulatory 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, and business practices) that 

are developed or adopted by voluntary 

consensus standards bodies. The 

NTTAA directs EPA to provide 

Congress, through OMB, explanations 

when the Agency decides not to use 

available and applicable voluntary 

consensus standards. This proposed 

rule includes updated information on a 

number of voluntary consensus 

standards previously included in 40 

CFR Part 75, as well as the proposed 

addition of certain other voluntary 

consensus standards. The EPA 

welcomes comments on this aspect of 

the proposed rulemaking and 

specifically invites the public to identify 

other potentially applicable voluntary 

consensus standards and to explain why 

such standards should be used in this 

regulation. 

List of Subjects in 40 CFR Parts 72 and 

75 

Environmental protection, Acid rain, 

Administrative practice and procedure, 

Air pollution control, Carbon dioxide, 

Electric utilities, Nitrogen oxides, 

Reporting and recordkeeping 

requirements, Sulfur oxides. 

Dated: August 4, 2006. 

Stephen L. Johnson, 

Administrator. 

For the reasons set forth in the 

preamble, EPA proposes to amend 

chapter I of title 40 of the Code of 

Federal Regulations as follows: 

PART 72—PERMITS REGULATION 

1. The authority citation for Part 72 

continues to read as follows: 

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

Subpart A—Acid Rain Program 

General Provisions 

2. Section 72.2 is amended as follows: 

a. In the definition of ‘‘Capacity 

factor’’, by adding the words ‘‘(or 

maximum observed hourly gross load 

(in MWe/hr) if greater than the 

nameplate capacity)’’ after the word 

‘‘capacity’’ in paragraph (1), by 

removing the word ‘‘design’’ and adding 

in its place the words ‘‘rated hourly’’ in 

paragraph (2), and by adding the word 

‘‘rate’’ after the new phrase ‘‘rated 

hourly heat input’’ in paragraph (2); 

b. In the definition of ‘‘Diluent cap’’, 

by removing the words ‘‘, CO2 mass 

emission rate, or heat input rate,’’ after 

the words ‘‘NOX emission rate’’; 

c. In the definition of ‘‘EPA protocol 

gas’’, by adding a new sentence to the 

end of the definition; 

d. Revising the definition of 

‘‘Excepted monitoring system’’; 

e. Adding the new definitions in 

alphabetical order for ‘‘Air Emission 

Testing Body (AETB)’’, ‘‘EPA Protocol 

Gas Verification Program’’, ‘‘Long-term 

cold storage’’, ‘‘Qualified Individual’’, 

and ‘‘Specialty gas producer’’; and 

f. Removing the definitions for 

‘‘Calibration gas’’, ‘‘Gas manufacturer’s 

intermediate standard (GMIS)’’, ‘‘NIST/ 

EPA-approved certified reference 

material or NIST/EPA-approved CRM’’, 

‘‘NIST traceable reference material 

(NTRM)’’, ‘‘Research gas material 

(RGM)’’, ‘‘Research gas mixture (RGM)’’, 

‘‘Standard reference material or SRM’’, 

‘‘Standard reference material-equivalent 

compressed gas primary reference 

material (SRM-equivalent PRM)’’, and 

‘‘Zero air material’’. 

The revisions and additions read as 

follows: 

§ 72.2 Definitions. 

* * * * * 

Air Emission Testing Body (AETB) 

means a company or other entity that 

conducts Air Emissions Testing as 

described in ASTM D7036–04. 

* * * * * 

EPA protocol gas * * * Vendors 

advertising certification with the EPA 


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Traceability Protocol or distributing 

gases as ‘‘EPA Protocol Gas’’ must 

participate in the EPA Protocol Gas 

Verification Program. Non-participating 

vendors may not use ‘‘EPA’’ in any form 

of advertising for these products, unless 

approved by the Administrator. 

* * * * * 

EPA Protocol Gas Verification 

Program means the EPA Protocol Gas 

audit program described in Section 

2.1.10 of the ‘‘EPA Traceability Protocol 

for Assay and Certification of Gaseous 

Calibration Standards,’’ September 

1997, EPA–600/R–97/121 (EPA Protocol 

Procedure) or such revised procedure as 

approved by the Administrator. 

* * * * * 

Excepted monitoring system means a 

monitoring system that follows the 

procedures and requirements of § 75.15 

of this chapter, § 75.19 of this chapter, 

§ 75.81(b) of this chapter or of appendix 

D, or E to part 75 for approved 

exceptions to the use of continuous 

emission monitoring systems. 

* * * * * 

Long-term cold storage means the 

complete shut down of a unit intended 

to last for an extended period of time (at 

least two calendar years) where notice 

for long-term cold storage is provided 

under § 75.61(a)(7). 

* * * * * 

Qualified Individual means an 

individual who meets the requirements 

as described in ASTM D7036–04. 

* * * * * 

Specialty gas producer means an 

organization that prepares and analyzes 

compressed gas mixtures for use as 

calibration gases and that offers the 

mixtures for sale to end users or to 

third-party vendors for resale to end 

users. 

* * * * * 

PART 75—CONTINUOUS EMISSION 

MONITORING 

3. The authority citation for Part 75 

continues to read as follows: 

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

7651k note. 

Subpart A—General 

4. Section 75.4 is amended by revising 

paragraph (d) to read as follows: 

§ 75.4 Compliance dates. 

* * * * * 

(d) This paragraph, (d), applies to 

affected units under the Acid Rain 

Program and to units subject to a State 

or Federal pollutant mass emissions 

reduction program that adopts the 

emission monitoring and reporting 

provisions of this part. In accordance 

with § 75.20, for an affected unit which, 

on the applicable compliance date, is 

either in long-term cold storage (as 

defined in § 72.2 of this chapter) or is 

shutdown as the result of a planned 

outage or a forced outage, thereby 

preventing the required continuous 

monitoring system certification tests 

from being completed by the 

compliance date, the owner or operator 

shall provide notice of such unit storage 

or outage in accordance with 

§ 75.61(a)(3) or § 75.61(a)(7), as 

applicable. For the planned and 

unplanned unit outages described in 

this paragraph, the owner or operator 

shall ensure that all of the continuous 

monitoring systems for SO2, NOX, CO2, 

Hg, opacity, and volumetric flow rate 

required under this part (or under the 

applicable State or Federal mass 

emissions reduction program) are 

installed and that all required 

certification tests are completed no later 

than 90 unit operating days or 180 

calendar days (whichever occurs first) 

after the date that the unit recommences 

commercial operation, notice of which 

date shall be provided under 

§ 75.61(a)(3) or § 75.61(a)(7), as 

applicable. The owner or operator shall 

determine and report SO2 concentration, 

NOX emission rate, CO2 concentration, 

Hg concentration, and flow rate data (as 

applicable) for all unit operating hours 

after the applicable compliance date 

until all of the required certification 

tests are successfully completed, using 

either: 

(1) The maximum potential 

concentration of SO2 (as defined in 

section 2.1.1.1 of appendix A to this 

part), the maximum potential NOX

emission rate, as defined in § 72.2 of 

this chapter, the maximum potential 

flow rate, as defined in section 2.1.4.1 

of appendix A to this part, the 

maximum potential Hg concentration, 

as defined in section 2.1.7.1 of appendix 

A to this part, or the maximum potential 

CO2 concentration, as defined in section 

2.1.3.1 of appendix A to this part; or 

(2) The conditional data validation 

provisions of § 75.20(b)(3); or 

(3) Reference methods under 

§ 75.22(b); or 

(4) Another procedure approved by 

the Administrator pursuant to a petition 

under § 75.66. 

* * * * * 

5. Section 75.6 is amended by: 

a. Removing ‘‘D129–91’’ and adding 

in its place ‘‘D129–00’’, in paragraph 

(a)(1); 

b. Removing ‘‘D240–87’’ and adding 

in its place ‘‘D240–00’’, in paragraph 

(a)(2); 

c. Removing ‘‘D287–82 (Reapproved 

1987)’’ and adding in its place ‘‘D287–

92 (2000)e1’’, in paragraph (a)(3); 

d. Removing ‘‘D388–92’’ and adding 

in its place ‘‘D388–99e1’’, in paragraph 

(a)(4); 

e. Removing and reserving paragraph 

(a)(5); 

f. Adding the phrase ‘‘(1999)’’ at the 

end of ‘‘D1072–90’’, in paragraph (a)(6); 

g. Removing ‘‘D1217–91’’ and adding 

in its place ‘‘D1217–93 (1998)’’, in 

paragraph (a)(7); 

h. Adding the phrase ‘‘(1997)e1’’ at 

the end of D1250–80, and by removing 

the phrase ‘‘(Reapproved 1990)’’, in 

paragraph (a)(8); 

i. Removing the phrase ‘‘D1298–85 

(Reapproved 1990)’’ and adding in its 

place ‘‘D1298–99’’, in paragraph (a)(9); 

j. Removing ‘‘D1480–91’’ and adding 

in its place ‘‘D1480–93 (1997)’’, in 

paragraph (a)(10); 

k. Removing ‘‘D1481–91’’ and adding 

in its place ‘‘D1481–93 (1997)’’, in 

paragraph (a)(11); 

l. Removing ‘‘D1552–90’’ and adding 

in its place ‘‘D1552–01’’, in paragraph 

(a)(12); 

m. Removing ‘‘D1826–88’’ and adding 

in its place ‘‘D1826–94 (1998)’’, in 

paragraph (a)(13); 

n. Removing ‘‘D1945–91’’ and adding 

in its place ‘‘D1945–96 (2001)’’, in 

paragraph (a)(14); 

o. Adding the phrase ‘‘(2000)’’ after 

‘‘D1946–90’’, in paragraph (a)(15); 

p. Removing and reserving paragraph 

(a)(16); 

q. Removing ‘‘D2013–86’’ and adding 

in its place ‘‘D2013–01’’, in paragraph 

(a)(17); 

r. Removing and reserving paragraph 

(a)(18); 

s. Removing ‘‘D2234–89’’ and adding 

in its place ‘‘D2234–00e1’’, in paragraph 

(a)(19); 

t. Removing and reserving paragraph 

(a)(20); 

u. Removing ‘‘D2502–87’’ and adding 

in its place ‘‘D2502–92 (1996)’’, in 

paragraph (a)(21); 

v. Removing ‘‘D2503–82 (Reapproved 

1987)’’ and adding in its place ‘‘D2503–

92 (1997)’’, in paragraph (a)(22); 

w. Removing ‘‘D2622–92’’ and adding 

in its place ‘‘D2622–98’’, in paragraph 

(a)(23); 

x. Removing ‘‘D3174–89’’ and adding 

in its place ‘‘D3174–00’’, in paragraph 

(a)(24); 

y. Adding the phrase ‘‘(1997)e1’’ after 

‘‘D3176–89’’, in paragraph (a)(25); 

z. Adding the phrase ‘‘(1997)’’ after 

‘‘D3177–89’’, in paragraph (a)(26); 

aa. Adding the phrase ‘‘(1997)’’ after 

‘‘D3178–89’’, in paragraph (a)(27); 

bb. Removing ‘‘D3238–90’’ and 

adding in its place ‘‘D3238–95 

(2000)e1’’, in paragraph (a)(28); 


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cc. Removing ‘‘D3246–81 

(Reapproved 1987)’’ and adding in its 

place ‘‘D3246–96’’, in paragraph (a)(29); 

dd. Removing and reserving 

paragraph (a)(30); 

ee. Removing ‘‘D3588–91’’ and adding 

in its place ‘‘D3588–98’’, in paragraph 

(a)(31); 

ff. Removing ‘‘D4052–91’’ and adding 

in its place ‘‘D4052–96 (2002)e1’’, in 

paragraph (a)(32); 

gg. Removing ‘‘D4057–88’’ and adding 

in its place ‘‘D4057–95 (2000)’’, in 

paragraph (a)(33); 

hh. Removing ‘‘D4177–82 

(Reapproved 1990)’’ and adding in its 

place ‘‘D4177–95 (2000)’’, in paragraph 

(a)(34) 

ii. Removing ‘‘D4239–85’’ and adding 

in its place ‘‘D4239–02’’, in paragraph 

(a)(35); 

jj. Removing ‘‘D4294–90’’ and adding 

in its place ‘‘D4294–98’’, in paragraph 

(a)(36); 

kk. Removing the phrase 

‘‘(Reapproved 1989)’’ and adding in its 

place the phrase ‘‘(2000)’’, in paragraph 

(a)(37); 

ll. Adding the phrase ‘‘(2001)’’ after 

‘‘D4891–89’’, in paragraph (a)(39); 

mm. Removing ‘‘D5291–92’’ and 

adding in its place ‘‘D5291–01’’, in 

paragraph (a)(40); 

nn. Adding the phrase ‘‘(1997)’’ after 

‘‘D5373–93’’, in paragraph (a)(41); 

oo. Removing ‘‘D5504–94’’ and 

adding in its place ‘‘D5504–01’’, in 

paragraph (a)(42); 

pp. Adding new paragraphs (a)(45), 

(a)(46), (a)(47), and (a)(48); 

qq. Removing the phrase ‘‘with 

September 1990 Errata’’ and adding in 

its place the phrase ‘‘(Reaffirmed 

1995)’’, in paragraph (b)(1); 

rr. Removing the date ‘‘1990’’ and 

adding in its place the date ‘‘1997’’ in 

the parenthetical, in paragraph (b)(2); 

ss. Adding the phrase ‘‘(Reaffirmed 

2001)’’ after ‘‘ASME–MFC–5M–1985’’, 

in paragraph (b)(3); 

tt. Removing the phrase ‘‘1987 with 

June 1987 Errata’’ and adding in its 

placethe number ‘‘1998’’ at the end of 

‘‘MFC–6M-’’, in paragraph (b)(4); 

uu. Removing the date ‘‘1992’’ and 

adding in its place the date ‘‘2001’’ in 

the parenthetical, in paragraph (b)(5); 

vv. Removing the phrase ‘‘with 

December 1989 Errata’’ and adding in its 

place the phrase ‘‘(Reaffirmed 2001)’’, in 

paragraph (b)(6); 

ww. Removing the number ‘‘86’’ and 

adding in its place the number ‘‘1996’’

at the end of ‘‘GPA Standard 2172-’’, in 

paragraph (d)(1); 

xx. Removing the number ‘‘90’’ and 

adding in its place the number ‘‘1999’’

at the end of ‘‘GPA Standard 2261-’’, in 

paragraph (d)(2); 

yy. Adding the phrase ‘‘(1st edition)’’

after the date ‘‘December 1994’’, 

removing the phrase ‘‘April 1992 

(reaffirmed January 1997)’’ and adding 

in its place the phrase ‘‘June 2001’’, 

adding the phrase ‘‘(Reaffirmed 

September 2000)’’ after the date 

‘‘September 1995’’, adding the phrase 

‘‘(1st Edition)’’ after the date ‘‘June 

1996’’, adding the phrase ‘‘(1st Edition)’’

after the date ‘‘April 1995’’, and adding 

the phrase ‘‘(1st Edition)’’ after the date 

‘‘March 1997’’, in paragraph (f)(1); 

zz. Adding the phrase ‘‘Manual of 

Measurement Standards, Chapter 4:’’

after the phrase ‘‘(API)’’, adding the 

phrase ‘‘(Provers Accumulating at Least 

10,000 Pulses), Measurement 

Coordination (Second Edition, March 

2001)’’, after the words ‘‘Conventional 

Pipe Provers’’, adding the phrase ‘‘(First 

Edition)’’ after the words ‘‘Small 

Volume Provers’’, adding the phrase 

‘‘Measurement Coordination (Second 

Edition, May 2000)’’ after the phrase 

‘‘Master-Meter Provers,’’ and removing 

the phrase ‘‘from Chapter 4 of the 

Manual of Petroleum Measurement 

Standards, October 1988 (Reaffirmed 

1993)’’, in paragraph (f)(3); and 

aaa. Adding new paragraph (f)(4). 

The revisions and additions read as 

follows: 

§ 75.6 Incorporation by reference. 

(a) * * * 

(45) ASTM D6667–04, Standard Test 

Method for Determination of Total 

Volatile Sulfur in Gaseous 

Hydrocarbons and Liquified Petroleum 

Gases by Ultraviolet Fluorescence, for 

appendix D of this part. 

(46) ASTM D4809–00, ‘‘Standard Test 

Method for Heat of Combustion of 

Liquid Hydrocarbon Fuels by Bomb 

Calorimeter (Precision Method), for 

appendices D and F of this part. 

(47) ASTM D5865–01ae1, ‘‘Standard 

Test Method for Gross Calorific Value of 

Coal and Coke’’, for appendices A, D, 

and F of this part. 

(48) ASTM D7036–04, ‘‘Standard 

Practice for Competence of Air Emission 

Testing Bodies’’, for appendices A, B, 

and E of this part. 

* * * * * 

(f) * * * 

(4) American Petroleum Institute 

(API) Manual of Petroleum 

Measurement Standards, Chapter 22—

Testing Procedures: Section 2—

Differential Pressure Flow Measurement 

Devices (First Edition, August 2005) for 

Appendix D to this part. 

6. Section 75.11 is amended by: 

a. Revising the heading of the section; 

b. Adding the phrase ‘‘and 14.0% for 

natural gas (boilers, only)’’ after the 

word ‘‘wood’’, in paragraph (b)(1); 

c. Revising paragraph (d)(3); 

d. Revising paragraph (e) introductory 

text, (e)(1) and (e)(3) introductory text; 

e. Removing and reserving paragraph 

(e)(2); and 

f. Revising paragraph (f). 

The revisions and additions read as 

follows: 

§ 75.11 Specific provisions for monitoring 

SO2 emissions. 

* * * * * 

(d) * * * 

(3) By using the low mass emissions 

excepted methodology in § 75.19(c) for 

estimating hourly SO2 mass emissions if 

the affected unit qualifies as a low mass 

emissions unit under § 75.19(a) and (b). 

If this option is selected for SO2, the 

LME methodology must also be used for 

NOX and CO2 when these parameters 

are required to be monitored by 

applicable program(s). 

(e) Special considerations during the 

combustion of gaseous fuels. The owner 

or operator of an affected unit that uses 

a certified flow monitor and a certified 

diluent gas (O2 or CO2) monitor to 

measure the unit heat input rate shall, 

during any hours in which the unit 

combusts only gaseous fuel, determine 

SO2 emissions in accordance with 

paragraph (e)(1) or (e)(3) of this section, 

as applicable. 

(1) If the gaseous fuel qualifies for a 

default SO2 emission rate under Section 

2.3.1.1, 2.3.2.1.1, or 2.3.6(b) of appendix 

D to this part, the owner or operator 

may determine SO2 emissions by using 

Equation F–23 in appendix F to this 

part. Substitute into Equation F–23 the 

hourly heat input, calculated using the 

certified flow monitoring system and 

the certified diluent monitor (according 

to the applicable equation in section 5.2 

of appendix F to this part), in 

conjunction with the appropriate 

default SO2 emission rate from section 

2.3.1.1, 2.3.2.1.1, or 2.3.6(b) of appendix 

D to this part. When this option is 

chosen, the owner or operator shall 

perform the necessary data acquisition 

and handling system tests under 

§ 75.20(c), and shall meet all quality 

control and quality assurance 

requirements in appendix B to this part 

for the flow monitor and the diluent 

monitor; or 

(2) [Reserved] 

(3) The owner or operator may 

determine SO2 mass emissions by using 

a certified SO2 continuous monitoring 

system, in conjunction with the certified 

flow rate monitoring system. However, 

if the gaseous fuel is very low sulfur fuel 

(as defined in § 72.2 of this chapter), the 

SO2 monitoring system shall meet the 

following quality assurance provisions 


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when the very low sulfur fuel is 

combusted: 

* * * * * 

(4) The provisions in paragraph (e)(1) 

of this section, may also be used for the 

combustion of a solid or liquid fuel that 

meets the definition of very low sulfur 

fuel in § 72.2 of this chapter, mixtures 

of such fuels, or combinations of such 

fuels with gaseous fuel, if the owner or 

operator submits a petition under 

§ 75.66 for a default SO2 emission rate 

for each fuel, mixture or combination, 

and if the Administrator approves the 

petition. 

(f) Other units. The owner or operator 

of an affected unit that combusts wood, 

refuse, or other material in addition to 

oil or gas shall comply with the 

monitoring provisions for coal-fired 

units specified in paragraph (a) of this 

section, except where the owner or 

operator has an approved petition to use 

the provisions of paragraph (e)(1) of this 

section. 

7. Section 75.12 is amended by: 

a. Revising the section heading; 

b. Removing the word ‘‘and’’ before 

the number ‘‘15.0%’’, and by adding the 

phrase ‘‘; and 18.0% for natural gas 

(boilers, only)’’ after the word ‘‘wood’’, 

in paragraph (b); and 

c. Revising paragraph (e)(3). 

The revisions read as follows: 

§ 75.12 Specific provisions for monitoring 

NOX emission rate. 

* * * * * 

(e) * * * 

(3) Use the low mass emissions 

excepted methodology in § 75.19(c) for 

estimating hourly NOX emission rate 

and hourly NOX mass emissions, if 

applicable under § 75.19(a) and (b). If 

this option is selected for NOX, the LME 

methodology must also be used for SO2

and CO2 when these parameters are 

required to be monitored by applicable 

program(s). 

* * * * * 

8. Section 75.13 is amended by 

revising paragraph (d)(3) to read as 

follows: 

§ 75.13 Specific provisions for monitoring 

CO2 emissions. 

* * * * * 

(d) * * * 

(3) Use the low mass emissions 

excepted methodology in § 75.19(c) for 

estimating hourly CO2 mass emissions, 

if applicable under § 75.19(a) and (b). If 

this option is selected for CO2, the LME 

methodology must also be used for NOX

and SO2 when these parameters are 

required to be monitored by applicable 

program(s). 

9. Section 75.15 is amended by: 

a. Removing the reference ‘‘(j)’’ and 

adding the reference ‘‘(l)’’ in its place, 

in the introductory paragraph; 

b. Revising paragraph (h); and 

c. Adding paragraphs (k) and (l). 

The revisions and additions read as 

follows: 

§ 75.15 Special provisions for measuring 

Hg mass emissions using the excepted 

sorbent trap monitoring methodology. 

* * * * * 

(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 may be used for reporting 

purposes, provided that: 

(1) The other trap has met all of the 

applicable quality-assurance 

requirements of this part; and 

(2) The Hg concentration measured by 

the other trap is multiplied by a factor 

of 1.222. 

* * * * * 

(k) When a sorbent trap monitoring 

system is tested for relative accuracy, 

both the size of the sorbent traps and the 

type of sorbent material used by the 

traps shall be the same as for daily 

operation of the system. 

(l) Whenever the size of the sorbent 

traps or the type of sorbent material 

used by the traps is changed, the owner 

or operator shall conduct a diagnostic 

RATA of the sorbent trap monitoring 

system. The modified system shall not 

be used to report Hg emissions under 

this part until the RATA has been 

performed and passed. Notwithstanding 

this requirement, Hg concentrations 

measured by the modified system 

during a successful RATA may be 

reported as quality-assured data under 

this part. 

10. Section 75.16 is amended by: 

a. Revising paragraph (b)(1)(ii); 

b. Adding the word ‘‘rate’’ after the 

phrase ‘‘report heat input’’ in the last 

sentence, in paragraph (e)(1); and 

c. Replacing both occurrences of the 

phrase ‘‘steam flow’’ with the phrase 

‘‘steam load’’ and adding the phrase ‘‘or 

mmBtu/hr thermal output’’ inside the 

parentheses, after the phrase ‘‘in 1000 

lb/hr’’, in paragraph (e)(3). 

The revisions read as follows: 

§ 75.16 Special provisions for monitoring 

emissions from common, bypass, and 

multiple stacks for SO2 emissions and heat 

input determinations. 

* * * * * 

(b) * * * 

(1) * * * 

(ii) Install, certify, operate, and 

maintain an SO2 continuous emission 

monitoring system and flow monitoring 

system in the common stack and 

combine emissions for the affected units 

for recordkeeping and compliance 

purposes. 

* * * * * 

11. Section 75.17 is amended by 

revising paragraph (d)(2) to read as 

follows: 

§ 75.17 Special provisions for monitoring 

emissions from common, bypass, and 

multiple stacks for NOX emission rate. 

* * * * * 

(d) * * * 

(2) Install, certify, operate, and 

maintain a NOX-diluent CEMS 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, with 

respect to NOX or any other parameter 

that is monitored only at the main stack. 

For each unit operating hour in which 

the bypass stack is used and the 

emissions are either uncontrolled (or the 

add-on controls are not documented to 

be operating properly), report the 

maximum potential NOX emission rate 

(as defined in § 72.2 of this chapter). 

The maximum potential NOX emission 

rate may be specific to the type of fuel 

combusted in the unit during the bypass 

(see § 75.33(c)(8)). Alternatively, for a 

unit with NOX add-on emission 

controls, for each unit operating hour in 

which the bypass stack is used and the 

emissions are controlled, the owner or 

operator may report the maximum 

controlled NOX emission rate (MCR) 

instead of the maximum potential NOX

emission rate provided that the add-on 

controls are documented to be operating 

properly, as described in the quality 

assurance/quality control program for 

the unit, required by section 1 in 

appendix B of this part. To provide the 

necessary documentation, the owner or 

operator shall record parametric data to 

verify the proper operation of the NOX

add-on emission controls as described 

in § 75.34(d). Furthermore, the owner or 

operator shall calculate the MCR using 

the procedure described in section 

2.1.2.1(b) of Appendix A to this part by 

replacing the words ‘‘maximum 

potential NOX emission rate (MER)’’

with the words ‘‘maximum controlled 

NOX emission rate (MCR)’’ in and by 


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using the NOX MEC instead of the NOX

MPC. 

12. Section 75.19 is amended by: 

a. Revising paragraph (a)(1); 

b. Revising paragraph (c)(1)(i); 

c. Adding the phrase, ‘‘that meets the 

quality assurance requirements of 

either: this part, or appendix F to part 

60 of this chapter, or a comparable State 

CEM program,’’ after the abbreviation 

‘‘CEMS’’, in paragraph (c)(1)(iv)(G); 

d. Adding the word ‘‘add-on’’ before 

the first instance of the phrase ‘‘NOX

controls’’, in paragraph (c)(1)(iv)(H)(3); 

e. Adding the phrase ‘‘(1st Edition)’’

after the date ‘‘December 1994’’, 

replacing the phrase ‘‘April 1992 

(reaffirmed January 1997)’’ with the date 

‘‘June 2001’’ after the phrase ‘‘Stationary 

Tanks by Automatic Tank Gauging,’’, 

adding the phrase ‘‘(Reaffirmed 

September 2000)’’ after the date 

‘‘September 1995’’, adding the phrase 

‘‘(1st Edition)’’ after the date ‘‘June 

1996’’, adding the phrase ‘‘(1st Edition)’’

after the date ‘‘April 1995’’, and adding 

the phrase ‘‘(1st Edition)’’ after the date 

‘‘March 1997’’, in paragraph 

(c)(3)(ii)(B)(2); 

f. Removing the words ‘‘from Table 

LM–1 of this section’’ from the first 

sentence of paragraph (c)(4)(i)(A); 

g. Revising the heading to paragraph 

(c)(4)(ii); and 

h. Adding paragraph (c)(4)(ii)(D). 

The revisions and additions read as 

follows: 

§ 75.19 Optional SO2, NOX, and CO2

emissions calculation for low mass 

emissions units. 

* * * * * 

(a) * * * 

(1) For units that meet the 

requirements of this paragraph (a)(1) 

and paragraphs (a)(2) and (b) of this 

section, the low mass emissions (LME) 

excepted methodology in paragraph (c) 

of this section may be used in lieu of 

continuous emission monitoring 

systems or, if applicable, in lieu of 

methods under appendices D, E, and G 

to this part, for the purpose of 

determining unit heat input, NOX, SO2,

and CO2 mass emissions, and NOX

emission rate under this part. If the 

owner or operator of a qualifying unit 

elects to use the LME methodology, it 

must be used for all parameters that are 

required to be monitored by the 

applicable program(s). For example, for 

an Acid Rain Program LME unit, the 

methodology must be used to estimate 

SO2, NOX, and CO2 mass emissions, 

NOX emission rate, and unit heat input. 

* * * * * 

(c) * * * 

(1) * * * 

(i) If the unit combusts only natural 

gas and/or fuel oil, use Table LM–1 of 

this section to determine the 

appropriate SO2 emission rate for use in 

calculating hourly SO2 mass emissions 

under this section. Alternatively, for 

fuel oil combustion, a lower, fuelspecific SO2 emission factor may be 

used in lieu of the applicable emission 

factor from Table LM–1, if a federally 

enforceable permit condition is in place 

that limits the sulfur content of the oil. 

If this alternative is chosen, the fuelspecific SO2 emission rate in lb/mmBtu 

shall be calculated by multiplying the 

fuel sulfur content limit (weight percent 

sulfur) by 1.01. In addition, the owner 

or operator shall periodically determine 

the sulfur content of the oil combusted 

in the unit, using one of the oil 

sampling and analysis options described 

in section 2.2 of Appendix D to this 

part, and shall keep records of these fuel 

sampling results in a format suitable for 

inspection and auditing. If the unit 

combusts gaseous fuel(s) other than 

natural gas, the owner or operator shall 

use the procedures in section 2.3.6 of 

appendix D to this part to document the 

total sulfur content of each such fuel 

and to determine the appropriate default 

SO2 emission rate for each such fuel. 

* * * * * 

(4) * * * 

(ii) NOX mass emissions and NOX

emission rate. * * * 

(D) The quarterly and cumulative 

NOX emission rate in lb/mmBtu (if 

required by the applicable program(s)) 

shall be determined as follows. 

Calculate the quarterly NOX emission 

rate by taking the arithmetic average of 

all of the hourly EFNOx values. Calculate 

the cumulative (year-to-date) NOX

emission rate by taking the arithmetic 

average of the quarterly NOX emission 

rates. 

* * * * * 

13. Section 75.20 is amended by: 

a. Adding a new sentence after the 

third sentence of paragraph (b) 

introductory text; 

b. Revising paragraph (c)(1)(v); and 

c. Removing paragraphs (f)(1) and 

(f)(2). 

The revisions and additions read as 

follows: 

§ 75.20 Initial certification and 

recertification procedures. 

* * * * * 

(b) * * * The owner or operator shall 

also recertify the continuous emission 

monitoring systems for a unit that has 

recommenced commercial operation 

following a period of long-term cold 

storage as defined in § 72.2 of this 

chapter. * * * 

* * * * * 

(c) * * * 

(1) * * * 

(v) A cycle time 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); and 

* * * * * 

14. Section 75.21 is amended by 

removing the words ‘‘or (e)(2)’’ at the 

end of the first sentence of paragraph 

(a)(4). 

15. Section 75.22 is amended by 

revising paragraphs (a)(5) and (a)(7) to 

read as follows: 

§ 75.22 Reference test methods. 

(a) * * * 

(5) Methods 6, 6A, 6B or 6C, and 7, 

7A, 7C, 7D or 7E, as applicable, are the 

reference methods for determining SO2

and NOX pollutant concentrations. 

Alternatively, Method 20 may be used 

as the reference method for relative 

accuracy test audits of NOX CEMS 

installed on combustion turbines. 

(Methods 6A and 6B may also be used 

to determine SO2 emission rate in lb/ 

mmBtu.) Methods 7, 7A, 7C, 7D, or 7E 

must be used to measure total NOX

emissions, both NO and NO2, for 

purposes of this part. The owner or 

operator shall not use the following 

exceptions or options of method 7E: 

(i) Section 7.1 of the method allowing 

for use of prepared calibration gas 

mixtures that are produced in 

accordance with method 205 in 

Appendix M of 40 CFR Part 51; 

(ii) Paragraph (3) in section 8.4 of the 

method allowing for the use of a multihole probe to satisfy the multipoint 

traverse requirement of the method; 

(iii) Section 8.6 of the method 

allowing for the use of ‘‘Dynamic 

Spiking’’ as an alternative to the 

interference and system bias checks of 

the method. Dynamic spiking may be 

conducted (optionally) as an additional 

quality assurance check. 

* * * * * 

(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 

Ontario Hydro Method)(incorporated by 

reference, see § 75.6) is the reference 

method for determining Hg 

concentration. Alternatively, Method 29 

in appendix A–8 to part 60 of this 

chapter may be used, with these caveats: 

the procedures for preparation of Hg 

standards and sample analysis in 

sections 13.4.1.1 through 13.4.1.3 ASTM 

D6784–02 shall be followed instead of 

the procedures in sections 7.5.33 and 

11.1.3 of Method 29, and the QA/QC 


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procedures in section 13.4.2 of ASTM 

D6784–02 shall be performed instead of 

the procedures in section 9.2.3 of 

Method 29. The tester may also opt to 

use the sample recovery and preparation 

procedures in ASTM D6784–02 instead 

of the Method 29 procedures, as follows: 

sections 8.2.8 and 8.2.9.1 of Method 29 

may be replaced with sections 13.2.9.1 

through 13.2.9.3 of ASTM D6784–02 ; 

sections 8.2.9.2 and 8.2.9.3 of Method 

29 may be replaced with sections 

13.2.10.1 through 13.2.10.4 of ASTM 

D6784–02; section 8.3.4 of Method 29 

may be replaced with section 13.3.4 or 

13.3.6 of ASTM D6784–02 (as 

appropriate); and section 8.3.5 of 

Method 29 may be replaced with section 

13.3.5 or 13.3.6 of ASTM D6784–02 (as 

appropriate). Whenever ASTM D6784–

02 or Method 29 is used, paired 

sampling trains are required. 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, when the average 

concentration is greater than 1.0 μg/m3. 

If the average concentration is ≤ 1.0 μg/ 

m3, the RD must not exceed 20 percent. 

If the RD criterion is met, use the 

average Hg concentration measured by 

the two trains (vapor phase, only) in the 

relative accuracy calculations. As a 

second alternative, an instrumental 

reference method or other suitable 

reference method capable of measuring 

total vapor phase Hg may be used, 

subject to the approval of the 

Administrator. 

* * * * * 

16. Section 75.32 is amended by 

replacing the phrase ‘‘need not be 

calculated during the’’ with the phrase 

‘‘shall be calculated for each hour 

during each’’, by replacing the word 

‘‘last’’ with the word ‘‘each’’, and by 

removing the phrase ‘‘as the monitor 

availability used’’ after the words ‘‘data 

period’’, in paragraph (b). 

17. Section 75.33 is amended by: 

a. Replacing the word ‘‘Whenever’’

with the word ‘‘If’’, and by replacing the 

words ‘‘each hour of each’’ with the 

words ‘‘that hour of the’’, in paragraph 

(b)(1) introductory text; 

b. Replacing the word ‘‘Whenever’’

with the word ‘‘If’’, and by replacing the 

words ‘‘each hour of each’’ with the 

words ‘‘that hour of the’’, in paragraph 

(b)(2) introductory text; 

c. Replacing the word ‘‘Whenever’’

with the word ‘‘If’’, and by replacing the 

word ‘‘each’’ with the words ‘‘that hour 

of the’’, in paragraphs (b)(3) and (b)(4); 

d. Replacing the word ‘‘Whenever’’

with the word ‘‘If’’, and by replacing the 

words ‘‘each hour of each’’ with the 

words ‘‘that hour of the’’, in paragraphs 

(c)(1) introductory text, (c)(2) 

introductory text, (c)(3), and (c)(4); 

e. Revising Tables 1 and 2 in 

paragraph (c)(8)(iv); 

f. Revising Table 3 in paragraph (e)(3); 

and 

h. Replacing the word ‘‘Whenever’’

with the word ‘‘If’’, and by replacing the 

words ‘‘each hour of each’’ with the 

words ‘‘that hour of the’’, in paragraphs 

(d)(1), (d)(2), (d)(3), and (d)(4). 

The revisions and additions read as 

follows: 

§ 75.33 Standard missing data procedures 

for SO2, NOX, Hg, and flow rate. 

* * * * * 

(c) * * * 

(8) * * * 

(iv) * * * 

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 

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

For O2 and H2Ox, the lesser of: 

10th percentile ..................................... HB/HA 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 H2Ox, 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 value1 .................................. 720 hours * 

For O2 and H2Ox:.

Minimum value1 ................................... 720 hours * 

Below 80 (Below 70 for Hg) .................. N > 0 .................................................... Maximum potential concentration 3 or 

% (for SO2, CO2, Hg, and H2O **) or.

Minimum potential concentration or % 

(for O2 and H2Ox).

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 quality-assured monitor operating hours. 2 During unit operating hours. 


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3Alternatively, where 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 report the greater of: (a) The maximum expected SO2 or Hg concentration or (b) 1.25 times the maximum controlled value 

from the previous 720 quality-assured monitor 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. 

TABLE 2.—LOAD-BASED MISSING DATA PROCEDURE FOR NOX-DILUENT CEMS, NOX CONCENTRATION CEMS AND FLOW

RATE CEMS 

Trigger conditions Calculation routines 

Monitor data availability (percent) Duration (N) of CEMS outage 

(hours) 2 Method Lookback period Load ranges 

95 or more ................................ N ≤ 24 ....................................... Average .................................... 2160 hours * .............................. Yes 

N > 24 ....................................... The greater of: 

Average .................................... HB/HA ....................................... No 

90th percentile .......................... 2160 hours * .............................. Yes 

90 or more, but below 95 ......... N ≤ 8 ......................................... Average .................................... 2160 hours * .............................. Yes 

N > 8 ......................................... The greater of: 

Average .................................... HB/HA ....................................... No 

95th percentile .......................... 2160 hours * .............................. Yes 

80 or more, but below 90 ......... N > 0 ......................................... Maximum value 1 ...................... 2160 hours * .............................. Yes 

Below 80 ................................... N > 0 ......................................... Maximum potential NOX emission rate3; or maximum potential NOX concentration3; or 

maximum potential flow rate..

None ......................................... No 

HB/HA = hour before and hour after the CEMS outage. 

* Quality-assured, monitor operating hours, using data at the corresponding load range (‘‘load bin’’) for each hour of the missing data period. 

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 three years prior to the missing data period. 1Where a unit with add-on NOX 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 2160 quality-assured monitor operating hours. Alternatively, 

units with add-on controls that report NOX mass emissions on a year-round basis under subpart H of this part may use separate ozone season 

and non-ozone season databases to provide substitute data values, as described in § 75.34 (a)(2). 

2 During unit operating hours. 

3Alternatively, where a unit with add-on NOX emission controls can demonstrate that the controls are operating properly, as provided in 

§ 75.34, the unit may report the greater of: (a) The maximum expected NOX concentration (or maximum controlled NOX emission rate, as applicable); or (b) 1.25 times the maximum controlled value at the corresponding load bin, from the previous 2160 quality-assured monitor operating 

hours. 

* * * * * 

(e) * * * 

(3) * * * 

TABLE 3.—NON-LOAD-BASED MISSING DATA PROCEDURE FOR NOX-DILUENT CEMS AND NOX CONCENTRATION CEMS 

Trigger conditions Calculation routines 

Monitor data availability (percent) Duration (N) of CEMS outage (hours) 1 Method Lookback period 

95 or more ................................................ N ≤ 24 ..................................................... Average ................................................... 2160 hours * 

N > 24 ..................................................... 90th percentile ........................................ 2160 hours * 

90 or more, but below 95 ......................... N ≤ 8 ....................................................... Average ................................................... 2160 hours * 

N > 8 ....................................................... 95th percentile ........................................ 2160 hours * 

80 or more, but below 90 ......................... N > 0 ....................................................... Maximum value ....................................... 2160 hours * 

Below 80, or operational bin indeterminable.N > 0 ....................................................... Maximum potential NOX emission rate 2

or maximum potential NOX concentration 2.

None 

* If operational bins are used, the lookback period is 2,160 quality-assured, monitor operating hours, and data at the corresponding operational 

bin are used to provide substitute data values. If operational bins are not used, the lookback period is the previous 2,160 quality-assured monitor 

operating hours. 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 three years prior to the missing data period. 1 During unit operation. 

2Alternatively, where a unit with add-on NOX emission controls can demonstrate that the controls are operating properly, as provided in 

§ 75.34, the unit may report the greater of: (a) the maximum expected NOX concentration, (or maximum controlled NOX emission rate, as applicable); or (b) 1.25 times the maximum controlled value at the corresponding operational bin (if applicable), from the previous 2160 quality-assured monitor operating hours. 


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* * * * * 

18. Section 75.34 is amended by: 

a. Revising paragraph (a) introductory 

text; 

b. Amending paragraph (a)(2)(ii) by 

replacing the words ‘‘and (c)(3)’’ with ‘‘, 

(c)(3) and (c)(5), and § 75.38(c),’’; 

c. Revising paragraph (a)(3); 

d. Adding paragraph (a)(5); and 

e. Revising paragraph (d) by replacing 

the words ‘‘paragraphs (a)(1) and (a)(3)’’

with ‘‘paragraphs (a)(1), (a)(3) and 

(a)(5)’’. 

The revisions and additions read as 

follows: 

§ 75.34 Units with add-on emission 

controls. 

(a) The owner or operator of an 

affected unit equipped with add-on SO2

and/or NOX emission controls shall 

provide substitute data in accordance 

with paragraphs (a)(1), through (a)(5) of 

this section for each hour in which 

quality-assured data from the outlet SO2

and/or NOX monitoring system(s) are 

not obtained. 

* * * * * 

(3) For each missing data hour in 

which the percent monitor data 

availability for SO2 or NOX, calculated 

in accordance with § 75.32, is less than 

90.0 percent and is greater than or equal 

to 80.0 percent; and parametric data 

establishes that the add-on emission 

controls were operating properly (i.e. 

within the range of operating parameters 

provided in the quality assurance/ 

quality control program) during the 

hour, the owner or operator may: 

(i) Replace the maximum SO2

concentration recorded in the 720 

quality-assured monitor operating hours 

immediately preceding the missing data 

period, with the maximum controlled 

SO2 concentration recorded in the 

previous 720 quality-assured monitor 

operating hours; or 

(ii) Replace the maximum NOX

concentration(s) or NOX emission rate(s) 

from the appropriate load bin(s) (based 

on a lookback through the 2,160 qualityassured monitor operating hours 

immediately preceding the missing data 

period), with the maximum controlled 

NOX concentration(s) or emission rate(s) 

from the appropriate load bin(s) in the 

same 2,160 quality-assured monitor 

operating hour lookback period. 

* * * * * 

(5) For each missing data hour in 

which the percent monitor data 

availability for SO2 or NOX, calculated 

in accordance with § 75.32, is below 

80.0 percent and parametric data 

establish that the add-on emission 

controls were operating properly (i.e. 

within the range of operating parameters 

provided in the quality assurance/ 

quality control program), in lieu of 

reporting the maximum potential value, 

the owner or operator may substitute, as 

applicable, the greater of: 

(i) The maximum expected SO2

concentration or 1.25 times the 

maximum hourly controlled SO2

concentration recorded in the previous 

720 quality-assured monitor operating 

hours; 

(ii) The maximum expected NOX

concentration or 1.25 times the 

maximum hourly controlled NOX

concentration recorded in the previous 

2,160 quality-assured monitor operating 

hours at the corresponding unit load 

range or operational bin; 

(iii) The maximum hourly controlled 

NOX emission rate (MCR) or 1.25 times 

the maximum hourly controlled NOX

emission rate recorded in the previous 

2,160 quality-assured monitor operating 

hours at the corresponding unit load 

range or operational bin; 

(iv) For the purposes of implementing 

the missing data options in paragraphs 

(a)(5)(i) through (a)(5)(iii) of this section, 

the maximum expected SO2 and NOX

concentrations shall be determined, 

respectively, according to sections 

2.1.1.2 and 2.1.2.2 of appendix A to this 

part. The MCR shall be calculated 

according to the basic procedure 

described in section 2.1.2.1(b) of 

appendix A to this part, except that the 

words ‘‘maximum potential NOX

emission rate (MER)’’ shall be replaced 

with the words ‘‘maximum controlled 

NOX emission rate (MCR)’’ and the NOX

MEC shall be used instead of the NOX

MPC. 

* * * * * 

19. Section 75.38 is amended by 

revising paragraphs (a) and (c) 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,’’ 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’’, and the percent monitor 

data availability trigger conditions 

prescribed for Hg in Table 1 of § 75.33 

shall apply rather than the trigger 

conditions prescribed for SO2. 

* * * * * 

(c) For units with FGD systems or 

add-on Hg emission controls, when the 

percent monitor data availability is less 

than 80.0 percent and is greater than or 

equal to 70.0 percent, and a missing 

data period occurs, consistent with 

§ 75.34(a)(3), for each missing data hour 

in which the FGD or Hg emission 

controls are documented to be operating 

properly, the owner or operator may 

report the maximum controlled Hg 

concentration recorded in the previous 

720 quality-assured monitor operating 

hours. In addition, when the percent 

monitor data availability is less than 

70.0 percent and a missing data period 

occurs, consistent with § 75.34(a)(5), for 

each missing data hour in which the 

FGD or Hg emission controls are 

documented to be operating properly, 

the owner or operator may report the 

greater of the maximum expected Hg 

concentration (MEC) or 1.25 times the 

maximum controlled Hg concentration 

recorded in the previous 720 qualityassured monitor operating hours. The 

MEC shall be determined in accordance 

with section 2.1.7.1 of appendix A to 

this part. 

20. Section 75.39 is amended by: 

a. Revising paragraph (a); 

b. Revising paragraph (b); 

c. Revising paragraph (c); 

d. Revising paragraph (d); and 

e. Adding paragraph (f). 

The revisions and additions read as 

follows: 

§ 75.39 Missing data procedures for 

sorbent trap monitoring systems. 

(a) If a primary 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, and if quality-assured Hg 

concentration data from a certified 

backup Hg monitoring system, reference 

method, or approved alternative 

monitoring system are unavailable, 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 primary system 

is certified. 

(b) For a certified sorbent trap system, 

a missing data period will occur in the 

following circumstances, unless qualityassured Hg concentration data from a 

certified backup Hg CEMS, sorbent trap 

system, reference method, or approved 

alternative monitoring system are 

available: 

(1) A gas sample is not extracted from 

the stack during unit operation (e.g. 


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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), or with a certified 

backup Hg CEMS, reference method, or 

approved alternative monitoring system. 

(c) Initial missing data procedures. 

Use the missing data procedures in 

§ 75.31(b) until 720 hours of qualityassured Hg concentration data have 

been collected with the sorbent trap 

monitoring system(s), following initial 

certification. 

(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 

standard missing data procedures in 

§ 75.38. 

* * * * * 

(f) In cases where the owner or 

operator elects to use a primary Hg 

CEMS and a redundant backup sorbent 

trap monitoring system (or vice-versa), 

when both monitoring systems are outof-service and quality-assured Hg 

concentration data from a reference 

method or approved alternative 

monitoring system are unavailable, the 

previous 720 quality-assured monitor 

operating hours reported in the 

electronic quarterly report under § 75.64 

shall be used for the required missing 

data lookback, irrespective of whether 

these data were recorded by the Hg 

CEMS, the sorbent trap system, a 

reference method, or an approved 

alternative monitoring system. 

21. Section 75.53 is amended by: 

a. Revising paragraph (a)(1); 

b. Replacing the phrase ‘‘(d) or (f)’’

with the phrase ‘‘(f) or (h)’’ in the 

second sentence of paragraph (a)(2); 

c. Adding paragraph (e)(1)(xiv); and 

d. Adding paragraphs (g) and (h). 

The revisions and additions read as 

follows: 

§ 75.53 Monitoring plan. 

(a) * * * 

(1) The provisions of paragraphs (e) 

and (f) of this section shall remain in 

effect through December 31, 2008. The 

owner or operator shall meet the 

requirements of paragraphs (a), (b), (e), 

and (f) of this section through December 

31, 2008, except as otherwise provided 

in paragraph (g) of this section. On and 

after January 1, 2009, the owner or 

operator shall meet the requirements of 

paragraphs (a), (b), (g), and (h) of this 

section only. In addition, the provisions 

in paragraphs (g) and (h) of this section 

that support a regulatory option 

provided in another section of this part 

must be followed if the regulatory 

option is used prior to January 1, 2009. 

* * * * * 

(e) * * * 

(1) * * * 

(xiv) For each unit with a flow 

monitor installed on a rectangular stack 

or duct, if a wall effects adjustment 

factor (WAF) is determined and applied 

to the hourly flow rate data: 

(A) Stack or duct width at the test 

location, ft; 

(B) Stack or duct depth at the test 

location, ft; 

(C) Wall effects adjustment factor 

(WAF), to the nearest 0.0001; 

(D) Method of determining the WAF; 

(E) WAF Effective date and hour; 

(F) WAF no longer effective date and 

hour (if applicable; 

(G) WAF determination date; 

(H) Number of WAF test runs; 

(I) Number of Method 1 traverse 

points in the WAF test; 

(J) Number of test ports in the WAF 

test; and 

(K) Number of Method 1 traverse 

points in the reference flow RATA. 

* * * * * 

(g) Contents of the monitoring plan. 

The requirements of paragraphs (g) and 

(h) of this section shall be met on and 

after January 1, 2009. Notwithstanding 

this requirement, the provisions of 

paragraphs (g) and (h) of this section 

may be implemented prior to January 1, 

2009, as follows. In 2008, the owner or 

operator may opt to record and report 

the monitoring plan information in 

paragraphs (g) and (h) of this section, in 

lieu of recording and reporting the 

information in paragraphs (e) and (f) of 

this section. Each monitoring plan shall 

contain the information in paragraph 

(g)(1) of this section in electronic format 

and the information in paragraph (g)(2) 

of this section in hardcopy format. 

Electronic storage of all monitoring plan 

information, including the hardcopy 

portions, is permissible provided that a 

paper copy of the information can be 

furnished upon request for audit 

purposes. 

(1) Electronic. 

(i) The facility ORISPL number 

developed by the Department of Energy 

and used in the National Allowance 

Data Base (or equivalent facility ID 

number assigned by EPA, if the facility 

does not have an ORISPL number). Also 

provide the following information for 

each unit and (as applicable) for each 

common stack and/or pipe, and each 

multiple stack and/or pipe involved in 

the monitoring plan: 

(A) A representation of the exhaust 

configuration for the units in the 

monitoring plan. Provide the ID number 

of each unit and assign a unique ID 

number to each common stack, common 

pipe multiple stack and/or multiple 

pipe associated with the unit(s) 

represented in the monitoring plan. For 

common and multiple stacks and/or 

pipes, provide the activation date and 

deactivation date (if applicable) of each 

stack and/or pipe; 

(B) Identification of the monitoring 

system location(s) (e.g., at the unit-level, 

on the common stack, at each multiple 

stack, etc.). Provide an indicator (‘‘flag’’) 

if the monitoring location is at a bypass 

stack or in the ductwork (breeching); 

(C) The stack exit height (ft) above 

ground level and ground level elevation 

above sea level, and the inside crosssectional area (ft2) at the flue exit and at 

the flow monitoring location (for units 

with flow monitors, only). Also use 

appropriate codes to indicate the 

material(s) of construction and the 

shape(s) of the stack or duct crosssection(s) at the flue exit and (if 

applicable) at the flow monitor location; 

(D) The type(s) of fuel(s) fired by each 

unit. Indicate the start and (if 

applicable) end date of combustion for 

each type of fuel, and whether the fuel 

is the primary, secondary, emergency, or 

startup fuel; 

(E) The type(s) of emission controls 

that are used to reduce SO2, NOX, Hg, 

and particulate emissions from each 

unit. Also provide the installation date, 

optimization date, and retirement date 

(if applicable) of the emission controls, 

and indicate whether the controls are an 

original installation; 

(F) Maximum hourly heat input 

capacity of each unit; and 

(G) A non-load based unit indicator (if 

applicable) for units that do not produce 

electrical or thermal output. 

(ii) For each monitored parameter 

(e.g., SO2, NOX, flow, etc.) at each 

monitoring location, specify the 

monitoring methodology and the 

missing data approach for the 

parameter. If the unmonitored bypass 

stack approach is used for a particular 

parameter, indicate this by means of an 

appropriate code. Provide the activation 

date/hour, and deactivation date/hour 

(if applicable) for each monitoring 


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methodology and each missing data 

approach. 

(iii) For each required continuous 

emission monitoring system, each fuel 

flowmeter system, each continuous 

opacity monitoring system, and each 

sorbent trap monitoring system (as 

defined in § 72.2 of this chapter), 

identify and describe the major 

monitoring components in the 

monitoring system (e.g., gas analyzer, 

flow monitor, opacity monitor, moisture 

sensor, fuel flowmeter, DAHS software, 

etc.). Other important components in 

the system (e.g., sample probe, PLC, 

data logger, etc.) may also be 

represented in the monitoring plan, if 

necessary. Provide the following 

specific information about each 

component and monitoring system: 

(A) For each required monitoring 

system: 

(1) Assign a unique, 3-character 

alphanumeric identification code to the 

system; 

(2) Indicate the parameter monitored 

by the system; 

(3) Designate the system as a primary, 

redundant backup, non-redundant 

backup, data backup, or reference 

method backup system, as provided in 

§ 75.10(e); and 

(4) Indicate the system activation 

date/hour and deactivation date/hour 

(as applicable). 

(B) For each component of each 

monitoring system represented in the 

monitoring plan: 

(1) Assign a unique, 3-character 

alphanumeric identification code to the 

component; 

(2) Indicate the manufacturer, model 

and serial number; 

(3) Designate the component type; 

(4) For dual-span applications, 

indicate whether the analyzer 

component ID represents a high 

measurement scale, a low scale, or a 

dual range; 

(5) For gas analyzers, indicate the 

moisture basis of measurement; 

(6) Indicate the method of sample 

acquisition or operation, (e.g., extractive 

pollutant concentration monitor or 

thermal flow monitor); and 

(7) Indicate the component activation 

date/hour and deactivation date/hour 

(as applicable). 

(iv) Explicit formulas, using the 

component and system identification 

codes for the primary monitoring 

system, and containing all constants and 

factors required to derive the required 

mass emissions, emission rates, heat 

input rates, etc. from the hourly data 

recorded by the monitoring systems. 

Formulas using the system and 

component ID codes for backup 

monitoring systems are required only if 

different formulas for the same 

parameter are used for the primary and 

backup monitoring systems (e.g., if the 

primary system measures pollutant 

concentration on a different moisture 

basis from the backup system). Provide 

the equation number or other 

appropriate code for each emissions 

formula (e.g., use code F–1 if Equation 

F–1 in appendix F to this part is used 

to calculate SO2 mass emissions). Also 

identify each emissions formula with a 

unique three character alphanumeric 

code. The formula effective start date/ 

hour and inactivation date/hour (as 

applicable) shall be included for each 

formula. The owner or operator of a unit 

for which the optional low mass 

emissions excepted methodology in 

§ 75.19 is being used is not required to 

report such formulas. 

(v) For each parameter monitored 

with CEMS, provide the following 

information: 

(A) Measurement scale (high or low); 

(B) Maximum potential value (and 

method of calculation). If NOX emission 

rate in lb/mmBtu is monitored, calculate 

and provide the maximum potential 

NOX emission rate in addition to the 

maximum potential NOX concentration; 

(C) Maximum expected value (if 

applicable) and method of calculation; 

(D) Span value(s) and full-scale 

measurement range(s); 

(E) Daily calibration units of measure; 

(F) Effective date/hour, and (if 

applicable) inactivation date/hour of 

each span value; 

(G) An indication of whether dual 

spans are required; and 

(H) The default high range value (if 

applicable) and the maximum allowable 

low-range value for this option; 

(vi) If the monitoring system or 

excepted methodology provides for the 

use of a constant, assumed, or default 

value for a parameter under specific 

circumstances, then include the 

following information for each such 

value for each parameter: 

(A) Identification of the parameter; 

(B) Default, maximum, minimum, or 

constant value, and units of measure for 

the value; 

(C) Purpose of the value; 

(D) Indicator of use, i.e., during 

controlled hours, uncontrolled hours, or 

all operating hours; 

(E) Type of fuel; 

(F) Source of the value; 

(G) Value effective date and hour; 

(H) Date and hour value is no longer 

effective (if applicable); and 

(I) For units using the excepted 

methodology under § 75.19, the 

applicable SO2 emission factor. 

(vii) Unless otherwise specified in 

section 6.5.2.1 of appendix A to this 

part, for each unit or common stack on 

which hardware CEMS are installed: 

(A) Maximum hourly gross load (in 

MW, rounded to the nearest MW, or 

steam load in 1000 lb/hr (i.e., klb/hr), 

rounded to the nearest klb/hr, or 

thermal output in mmBtu/hr, rounded 

to the nearest mmBtu/hr), for units that 

produce electrical or thermal output; 

(B) The upper and lower boundaries 

of the range of operation (as defined in 

section 6.5.2.1 of appendix A to this 

part), expressed in megawatts, 

thousands of lb/hr of steam, mmBtu/hr 

of thermal output, or ft/sec (as 

applicable); 

(C) Except for peaking units, identify 

the most frequently and second most 

frequently used load (or operating) 

levels (i.e., low, mid, or high) in 

accordance with section 6.5.2.1 of 

appendix A to this part, expressed in 

megawatts, thousands of lb/hr of steam, 

mmBtu/hr of thermal output, or ft/sec 

(as applicable); 

(D) Except for peaking units, an 

indicator of whether the second most 

frequently used load (or operating) level 

is designated as normal in section 

6.5.2.1 of appendix A to this part; 

(E) The date of the data analysis used 

to determine the normal load (or 

operating) level(s) and the two most 

frequently-used load (or operating) 

levels (as applicable); and 

(F) Activation and deactivation dates 

and hours, when the maximum hourly 

gross load, boundaries of the range of 

operation, normal load (or operating) 

level(s) or two most frequently-used 

load (or operating) levels change and are 

updated. 

(viii) For each unit for which CEMS 

are not installed: 

(A) Maximum hourly gross load (in 

MW, rounded to the nearest MW, or 

steam load in klb/hr, rounded to the 

nearest klb/hr, or steam load in mmBtu/ 

hr, rounded to the nearest mmBtu/hr); 

(B) The upper and lower boundaries 

of the range of operation (as defined in 

section 6.5.2.1 of appendix A to this 

part), expressed in megawatts, mmBtu/ 

hr of thermal output, or thousands of lb/ 

hr of steam; 

(C) Except for peaking units and units 

using the low mass emissions excepted 

methodology under § 75.19, identify the 

load level designated as normal, 

pursuant to section 6.5.2.1 of appendix 

A to this part, expressed in megawatts, 

mmBtu/hr of thermal output, or 

thousands of lb/hr of steam; 

(D) The date of the load analysis used 

to determine the normal load level (as 

applicable); and 

(E) Activation and deactivation dates 

and hours, when the maximum hourly 

gross load, boundaries of the range of 


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operation, or normal load level change 

and are updated. 

(ix) For each unit with a flow monitor 

installed on a rectangular stack or duct, 

if a wall effects adjustment factor (WAF) 

is determined and applied to the hourly 

flow rate data: 

(A) Stack or duct width at the test 

location, ft; 

(B) Stack or duct depth at the test 

location, ft; 

(C) Wall effects adjustment factor 

(WAF), to the nearest 0.0001; 

(D) Method of determining the WAF; 

(E) WAF Effective date and hour; 

(F) WAF no longer effective date and 

hour (if applicable); 

(G) WAF determination date; 

(H) Number of WAF test runs; 

(I) Number of Method 1 traverse 

points in the WAF test; 

(J) Number of test ports in the WAF 

test; and 

(K) Number of Method 1 traverse 

points in the reference flow RATA. 

(2) Hardcopy. 

(i) Information, including (as 

applicable): identification of the test 

strategy; protocol for the relative 

accuracy test audit; other relevant test 

information; calibration gas levels 

(percent of span) for the calibration 

error test and linearity check; 

calculations for determining maximum 

potential concentration, maximum 

expected concentration (if applicable), 

maximum potential flow rate, maximum 

potential NOX emission rate, and span; 

and apportionment strategies under 

§§ 75.10 through 75.18. 

(ii) Description of site locations for 

each monitoring component in the 

continuous emission or opacity 

monitoring systems, including 

schematic diagrams and engineering 

drawings specified in paragraphs 

(e)(2)(iv) and (e)(2)(v) of this section and 

any other documentation that 

demonstrates each monitor location 

meets the appropriate siting criteria. 

(iii) A data flow diagram denoting the 

complete information handling path 

from output signals of CEMS 

components to final reports. 

(iv) For units monitored by a 

continuous emission or opacity 

monitoring system, a schematic diagram 

identifying entire gas handling system 

from boiler to stack for all affected units, 

using identification numbers for units, 

monitoring systems and components, 

and stacks corresponding to the 

identification numbers provided in 

paragraphs (g)(1)(i) and (g)(1)(iii) of this 

section. The schematic diagram must 

depict stack height and the height of any 

monitor locations. Comprehensive and/ 

or separate schematic diagrams shall be 

used to describe groups of units using 

a common stack. 

(v) For units monitored by a 

continuous emission or opacity 

monitoring system, stack and duct 

engineering diagrams showing the 

dimensions and location of fans, turning 

vanes, air preheaters, monitor 

components, probes, reference method 

sampling ports, and other equipment 

that affects the monitoring system 

location, performance, or quality control 

checks. 

(h) Contents of monitoring plan for 

specific situations. The following 

additional information shall be included 

in the monitoring plan for the specific 

situations described: 

(1) For each gas-fired unit or oil-fired 

unit for which the owner or operator 

uses the optional protocol in appendix 

D to this part for estimating heat input 

and/or SO2 mass emissions, or for each 

gas-fired or oil-fired peaking unit for 

which the owner/operator uses the 

optional protocol in appendix E to this 

part for estimating NOX emission rate 

(using a fuel flowmeter), the designated 

representative shall include the 

following additional information for 

each fuel flowmeter system in the 

monitoring plan: 

(i) Electronic. 

(A) Parameter monitored; 

(B) Type of fuel measured, maximum 

fuel flow rate, units of measure, and 

basis of maximum fuel flow rate (i.e., 

upper range value or unit maximum) for 

each fuel flowmeter; 

(C) Test method used to check the 

accuracy of each fuel flowmeter; 

(D) Monitoring system identification 

code; 

(E) The method used to demonstrate 

that the unit qualifies for monthly GCV 

sampling or for daily or annual fuel 

sampling for sulfur content, as 

applicable; and 

(F) Activation date/hour and (if 

applicable) inactivation date/hour for 

the fuel flowmeter system; 

(ii) Hardcopy. 

(A) A schematic diagram identifying 

the relationship between the unit, all 

fuel supply lines, the fuel flowmeter(s), 

and the stack(s). The schematic diagram 

must depict the installation location of 

each fuel flowmeter and the fuel 

sampling location(s). Comprehensive 

and/or separate schematic diagrams 

shall be used to describe groups of units 

using a common pipe; 

(B) For units using the optional 

default SO2 emission rate for ‘‘pipeline 

natural gas’’ or ‘‘natural gas’’ in 

appendix D to this part, the information 

on the sulfur content of the gaseous fuel 

used to demonstrate compliance with 

either section 2.3.1.4 or 2.3.2.4 of 

appendix D to this part; 

(C) For units using the 720 hour test 

under 2.3.6 of Appendix D of this part 

to determine the required sulfur 

sampling requirements, report the 

procedures and results of the test; and 

(D) For units using the 720 hour test 

under 2.3.5 of Appendix D of this part 

to determine the appropriate fuel GCV 

sampling frequency, report the 

procedures used and the results of the 

test. 

(2) For each gas-fired peaking unit 

and oil-fired peaking unit for which the 

owner or operator uses the optional 

procedures in appendix E to this part for 

estimating NOX emission rate, the 

designated representative shall include 

in the monitoring plan: 

(i) Electronic. Unit operating and 

capacity factor information 

demonstrating that the unit qualifies as 

a peaking unit, as defined in § 72.2 of 

this chapter for the current calendar 

year or ozone season, including: 

capacity factor data for three calendar 

years (or ozone seasons) as specified in 

the definition of peaking unit in § 72.2 

of this chapter; the method of 

qualification used; and an indication of 

whether the data are actual or projected 

data. 

(ii) Hardcopy. 

(A) A protocol containing methods 

used to perform the baseline or periodic 

NOX emission test; and 

(B) Unit operating parameters related 

to NOX formation by the unit. 

(3) For each gas-fired unit and dieselfired unit or unit with a wet flue gas 

pollution control system for which the 

designated representative claims an 

opacity monitoring exemption under 

§ 75.14, the designated representative 

shall include in the hardcopy 

monitoring plan the information 

specified under § 75.14(b), (c), or (d), 

demonstrating that the unit qualifies for 

the exemption. 

(4) For each unit using the low mass 

emissions excepted methodology under 

§ 75.19 the designated representative 

shall include the following additional 

information in the monitoring plan that 

accompanies the initial certification 

application: 

(i) Electronic. For each low mass 

emissions unit, report the results of the 

analysis performed to qualify as a low 

mass emissions unit under § 75.19(c). 

This report will include either the 

previous three years actual or projected 

emissions. The following items should 

be included: 

(A) Current calendar year of 

application; 

(B) Type of qualification; 

(C) Years one, two, and three; 

(D) Annual and/or ozone season 

measured, estimated or projected NOX


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mass emissions for years one, two, and 

three; 

(E) Annual measured, estimated or 

projected SO2 mass emissions (if 

applicable) for years one, two, and 

three; and 

(F) Annual or ozone season operating 

hours for years one, two, and three. 

(ii) Hardcopy. 

(A) A schematic diagram identifying 

the relationship between the unit, all 

fuel supply lines and tanks, any fuel 

flowmeter(s), and the stack(s). 

Comprehensive and/or separate 

schematic diagrams shall be used to 

describe groups of units using a 

common pipe; 

(B) For units which use the long term 

fuel flow methodology under 

§ 75.19(c)(3), the designated 

representative must provide a diagram 

of the fuel flow to each affected unit or 

group of units and describe in detail the 

procedures used to determine the long 

term fuel flow for a unit or group of 

units for each fuel combusted by the 

unit or group of units; 

(C) A statement that the unit burns 

only gaseous fuel(s) and/or fuel oil and 

a list of the fuels that are burned or a 

statement that the unit is projected to 

burn only gaseous fuel(s) and/or fuel oil 

and a list of the fuels that are projected 

to be burned; 

(D) A statement that the unit meets 

the applicability requirements in 

§§ 75.19(a) and (b); and 

(E) Any unit historical actual, 

estimated and projected emissions data 

and calculated emissions data 

demonstrating that the affected unit 

qualifies as a low mass emissions unit 

under §§ 75.19(a) and 75.19(b). 

(5) For qualification as a gas-fired 

unit, as defined in § 72.2 of this part, the 

designated representative shall include 

in the monitoring plan, in electronic 

format, the following: current calendar 

year, fuel usage data for three calendar 

years (or ozone seasons) as specified in 

the definition of gas-fired in § 72.2 of 

this part, the method of qualification 

used, and an indication of whether the 

data are actual or projected data. 

(6) For each monitoring location with 

a stack flow monitor that is exempt from 

performing 3-load flow RATAs (peaking 

units, bypass stacks, or by petition) the 

designated representative shall include 

in the monitoring plan an indicator of 

exemption from 3-load flow RATA 

using the appropriate exemption code. 

22. Section 75.57 is amended by: 

a. Adding the phrase ‘‘, or mmBtu/hr 

of thermal output, rounded to the 

nearest mmBtu/hr’’ after the phrase 

‘‘rounded to the nearest 1000 lb/hr’’, in 

paragraph (b)(3); and 

b. Revising Table 4a in paragraph 

(c)(4)(iv). 

The revisions and additions read as 

follows: 

§ 75.57 General recordkeeping provisions. 

* * * * * 

(c) * * * 

(4) * * * 

(iv) * * * 

TABLE 4A.—CODES FOR METHOD OF EMISSIONS AND FLOW DETERMINATION

Code Hourly emissions/flow measurement or estimation method 

1 ........................ Certified primary emission/flow monitoring system. 

2 ........................ Certified backup emission/flow monitoring system. 

3 ........................ Approved alternative monitoring system. 

4 ........................ Reference method: 

SO2: Method 6C. 

Flow: Method 2 or its allowable alternatives under appendix A to part 60 of this chapter. 

NOX: Method 7E. 

CO2 or O2: Method 3A. 

5 ........................ For units with add-on SO2 and/or NOX emission controls: SO2 concentration or NOX emission rate estimate from Agency 

preapproved parametric monitoring method. 

6 ........................ Average of the hourly SO2 concentrations, CO2 concentrations, O2 concentrations, NOX concentrations, flow rates, moisture 

percentages or NOX emission rates for the hour before and the hour following a missing data period. 

7 ........................ Initial missing data procedures used. Either: (a) The average of the hourly SO2 concentration, CO2 concentration, O2 concentration, or moisture percentage for the hour before and the hour following a missing data period; or (b) the arithmetic average of all NOX concentration, NOX emission rate, or flow rate values at the corresponding load range (or a higher load 

range), or at the corresponding operational bin (non-load-based units, only); or (c) the arithmetic average of all previous 

NOX concentration, NOX emission rate, or flow rate values (non-load-based units, only). 

8 ........................ 90th percentile hourly SO2 concentration, CO2 concentration, NOX concentration, flow rate, moisture percentage, or NOX

emission rate or 10th percentile hourly O2 concentration or moisture percentage in the applicable lookback period (moisture 

missing data algorithm depends on which equations are used for emissions and heat input). 

9 ........................ 95th percentile hourly SO2 concentration, CO2 concentration, NOX concentration, flow rate, moisture percentage, or NOX

emission rate or 5th percentile hourly O2 concentration or moisture percentage in the applicable lookback period (moisture 

missing data algorithm depends on which equations are used for emissions and heat input). 

10 ...................... Maximum hourly SO2 concentration, CO2 concentration, NOX concentration, flow rate, moisture percentage, or NOX emission 

rate or minimum hourly O2 concentration or moisture percentage in the applicable lookback period (moisture missing data 

algorithm depends on which equations are used for emissions and heat input). 

11 ...................... Average of hourly flow rates, NOX concentrations or NOX emission rates in corresponding load range, for the applicable 

lookback period. For non-load-based units, report either the average flow rate, NOX concentration or NOX emission rate in 

the applicable lookback period, or the average flow rate or NOX value at the corresponding operational bin (if operational 

bins are used). 

12 ...................... Maximum potential concentration of SO2, maximum potential concentration of CO2, maximum potential concentration of NOX

maximum potential flow rate, maximum potential NOX emission rate, maximum potential moisture percentage, minimum potential O2 concentration or minimum potential moisture percentage, as determined using § 72.2 of this chapter and section 

2.1 of appendix A to this part (moisture missing data algorithm depends on which equations are used for emissions and 

heat input). 

13 ...................... Maximum expected concentration of SO2, maximum expected concentration of NOX, maximum expected Hg concentration, or 

maximum controlled NOX emission rate. (See § 75.34(a)(5)). 

14 ...................... Diluent cap value (if the cap is replacing a CO2 measurement, use 5.0 percent for boilers and 1.0 percent for turbines; if it is 

replacing an O2 measurement, use 14.0 percent for boilers and 19.0 percent for turbines). 


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TABLE 4A.—CODES FOR METHOD OF EMISSIONS AND FLOW DETERMINATION—Continued 

Code Hourly emissions/flow measurement or estimation method 

15 ...................... 1.25 times the maximum hourly controlled SO2 concentration, Hg concentration, NOX concentration at the corresponding load 

or operational bin, or NOX emission rate at the corresponding load or operational bin, in the applicable lookback period 

(See § 75.34(a)(5)). 

16 ...................... SO2 concentration value of 2.0 ppm during hours when only ‘‘very low sulfur fuel’’, as defined in § 72.2 of this chapter, is combusted. 

17 ...................... Like-kind replacement non-redundant backup analyzer. 

19 ...................... 200 percent of the MPC; default high range value. 

20 ...................... 200 percent of the full-scale range setting (full-scale exceedance of high range). 

21 ...................... Negative hourly SO2 concentration, NOX concentration, percent moisture, or NOX emission rate replaced with zero. 

22 ...................... Hourly average SO2 or NOX concentration, measured by a certified monitor at the control device inlet (units with add-on emission controls only). 

23 ...................... Maximum potential SO2 concentration, NOX concentration, CO2 concentration, NOX emission rate or flow rate, or minimum 

potential O2 concentration or moisture percentage, for an hour in which flue gases are discharged through an unmonitored 

bypass stack. 

24 ...................... Maximum expected NOX concentration, or maximum controlled NOX emission rate for an hour in which flue gases are discharged downstream of the NOX emission controls through an unmonitored bypass stack, and the add-on NOX emission 

controls are confirmed to be operating properly. 

25 ...................... Maximum potential NOX emission rate (MER). (Use only when a NOX concentration full-scale exceedance occurs and the diluent monitor is unavailable.) 

26 ...................... 1.0 mmBtu/hr substituted for Heat Input Rate for an operating hour in which the calculated Heat Input Rate is zero or negative. 

32 ...................... Hourly Hg concentration determined from analysis of a single trap multiplied by a factor of 1.222 when one of the paired traps 

is invalidated or damaged (See Appendix K § 8). 

33 ...................... Hourly Hg concentration determined from the trap resulting in the higher Hg concentration when the relative deviation between the paired traps is greater than 10 percent (See Appendix K § 8). 

54 ...................... Other quality assured methodologies approved through petition. These hours are included in missing data lookback and are 

treated as unavailable hours for percent monitor availability calculations. 

55 ...................... Other substitute data approved through petition. These hours are not included in missing data lookback and are treated as 

unavailable hours for percent monitor availability calculations. 

* * * * * 

23. Section 75.58 is amended by: 

a. Revising paragraph (b)(3) 

introductory text; 

b. Removing paragraphs (b)(3)(iii) and 

(b)(3)(iv); 

c. Removing the word ‘‘and’’ from 

paragraph (c)(1)(xii); 

d. Replacing the period with a 

semicolon and adding the word ‘‘and’’

to the end of the paragraph, in 

paragraph (c)(1)(xiii); 

e. Adding paragraph (c)(1)(xiv); 

f. Replacing the period with a 

semicolon and adding the word ‘‘and’’

to the end of the paragraph, in 

paragraph (c)(4)(x); 

g. Adding paragraph (c)(4)(xi); 

h. Replacing the period with a 

semicolon and adding the word ‘‘and’’

to the end of the paragraph, in 

paragraph (d)(1)(x); 

i. Adding paragraph (d)(1)(xi); 

j. Replacing the period with a 

semicolon and adding the word ‘‘and’’

to the end of the paragraph, in 

paragraph (d)(2)(x); 

k. Adding paragraph (d)(2)(xi); 

l. Revising paragraph (f)(1)(iii); 

m. Removing the word ‘‘and’’ at the 

end of paragraph (f)(1)(xi); 

n. Replacing the period with a 

semicolon at the end of paragraph 

(f)(1)(xii); 

o. Adding paragraphs (f)(1)(xiii) and 

(f)(1)(xiv); and 

p. Replacing the word ‘‘Component’’

with the word ‘‘Monitoring’’, in 

paragraph (f)(2)(x). 

The revisions and additions 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), (a)(3) 

or (a)(5), and for units with add-on Hg 

emission controls, the owner or operator 

shall record: 

* * * * * 

(c) * * * 

(1) * * * 

(xiv) Heat input formula ID and SO2

Formula ID (required beginning January 

1, 2009). 

* * * * * 

(4) * * * 

(xi) Heat input formula ID and SO2

Formula ID (required beginning January 

1, 2009). 

* * * * * 

(d) * * * 

(1) * * * 

(xi) Heat input rate formula ID 

(required beginning January 1, 2009). 

(2) * * * 

(xi) Heat input rate formula ID 

(required beginning January 1, 2009). 

* * * * * 

(f) * * * 

(1) * * * 

(iii) Fuel type (pipeline natural gas, 

natural gas, other gaseous fuel, residual 

oil, or diesel fuel). If more than one type 

of fuel is combusted in the hour, either: 

(A) Indicate the fuel type which 

results in the highest emission factors 

for NOX (this option is in effect through 

December 31, 2008); or 

(B) Indicate the fuel type resulting in 

the highest emission factor for each 

parameter (SO2, NOX emission rate, and 

CO2) separately (this option is required 

on and after January 1, 2009); 

* * * * * 

(xiii) Base or peak load indicator (as 

applicable); and 

(xiv) Multiple fuel flag. 

* * * * * 

24. Section 75.59 is amended by: 

a. Adding the phrase ‘‘(on and after 

January 1, 2009, only the component 

identification code is required)’’ after 

the word ‘‘code’’, in paragraph (a)(1)(i); 

b. Revising paragraph (a)(1)(viii); 

c. Replacing the phrase ‘‘For the 

qualifying test for off-line calibration, 

the owner or operator shall indicate’’

with the phrase ‘‘Indication of’’, in 

paragraph (a)(1)(xi); 

d. Adding the phrase ‘‘(after January 

1, 2009, only the component 


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identification code is required)’’ after 

the word ‘‘code’’, in paragraph (a)(2)(i); 

e. Adding the phrase ‘‘(on and after 

January 1, 2009, only the component 

identification code is required)’’ after 

the word ‘‘code’’, in paragraph (a)(3)(i); 

f. Adding the phrase ‘‘(only span scale 

is required on and after January 1, 

2009)’’ after the word ‘‘scale’’, in 

paragraph (a)(3)(ii); 

g. Adding the phrase ‘‘(on and after 

January 1, 2009, only the system 

identification code is required)’’ after 

the word ‘‘code’’, in paragraph (a)(4)(i); 

h. Removing the word ‘‘and’’ after the 

semicolon at the end of paragraph 

(a)(4)(vi)(L); 

i. Replacing the period with a 

semicolon and adding the word ‘‘and’’

at the end of paragraph (a)(4)(vi)(M); 

j. Adding paragraph (a)(4)(vi)(N); 

k. Removing the word ‘‘and’’ after the 

semicolon, at the end of paragraph 

(a)(4)(vii)(K); 

l. Replacing the period with a 

semicolon and adding the word ‘‘and’’

at the end of paragraph (a)(4)(vii)(L); 

m. Adding paragraph (a)(4)(vii)(M); 

n. Revising paragraph (a)(6) 

introductory text; 

o. Adding the phrase ‘‘(on and after 

January 1, 2009, only the component 

identification code is required)’’ after 

the word ‘‘code’’, in paragraph (a)(6)(i); 

p. Replace the phrase ‘‘Cycle time 

result for the entire system’’ with the 

phrase ‘‘Total cycle time’’, in paragraph 

(a)(6)(ix); 

q. Adding paragraphs (a)(7)(ix) and 

(a)(7)(x); 

r. Revising paragraph (a)(8); 

s. Removing and reserving paragraph 

(a)(12)(iii); 

t. Removing the number ‘‘(2)’’ from 

the paragraph identifier ‘‘§ 75.64(a)(2)’’

in the second sentence of paragraph 

(a)(13); 

u. Adding the phrase ‘‘(on and after 

January 1, 2009, only the component 

identification code is required)’’ after 

the word ‘‘tested’’, in paragraphs 

(b)(1)(ii) and (b)(2)(i); 

v. Adding the phrase ‘‘(on and after 

January 1, 2009, only the monitoring 

system identification code is required)’’

after the word ‘‘code’’, in paragraph 

(b)(4)(i)(A); 

w. Removing the word ‘‘and’’ after the 

semicolon at the end of paragraph 

(b)(4)(i)(H); 

x. Replacing the period with a 

semicolon and adding the word ‘‘and’’

at the end of paragraph (b)(4)(i)(I); 

y. Adding paragraph (b)(4)(i)(J); 

z. Revising paragraphs (b)(4)(ii)(A), 

(b)(4)(ii)(B), and (b)(4)(ii)(F); 

aa. Removing the word ‘‘and’’ after 

the semicolon at the end of paragraph 

(b)(4)(ii)(L); 

bb. Replacing the period with a 

semicolon and adding the word ‘‘and’’

at the end of paragraph (b)(4)(ii)(M); 

cc. Adding paragraph (b)(4)(ii)(N); 

dd. Adding the phrase ‘‘(on and after 

January 1, 2009, component 

identification codes shall be reported in 

addition to the monitoring system 

identification code)’’ after the second 

occurrence of the word ‘‘system’’ in 

paragraphs (b)(5)(i)(B), (b)(5)(ii)(B), and 

(b)(5)(iii)(B); 

ee. Adding the phrase ‘‘This 

requirement remains in effect through 

December 31, 2008’’ after the word 

‘‘run’’, in paragraph (b)(5)(i)(H); 

ff. Adding the phrase ‘‘(as applicable). 

This requirement remains in effect 

through December 31, 2008’’ after the 

word ‘‘level’’, in paragraph (b)(5)(iv)(A); 

gg. Removing the word ‘‘and’’ after 

the semicolon at the end of paragraph 

(b)(5)(iv)(G); 

hh. Replacing the period with a 

semicolon and adding the word ‘‘and’’

at the end of paragraph (b)(5)(iv)(H); 

ii. Adding paragraph (b)(5)(iv)(I); 

jj. Removing the word ‘‘and’’ after the 

semicolon at the end of paragraph 

(d)(1)(xi); 

kk. Replacing the period with a 

semicolon and adding the word ‘‘and’’

at the end of paragraph (d)(1)(xii); 

ll. Adding paragraph (d)(1)(xiii); 

mm. Removing the phrase ‘‘, 

multiplied by 1.15, if appropriate’’ from 

paragraph (d)(2)(iii); 

nn. Removing the word ‘‘and’’ after 

the semicolon at the end of paragraph 

(d)(2)(iv); 

oo. Replacing the period with a 

semicolon at the end of paragraph 

(d)(2)(v); and 

pp. Adding paragraphs (d)(2)(vi), 

(d)(2)(vii), (e) and (f). 

The revisions and additions read as 

follows: 

§ 75.59 Certification, quality, assurance, 

and quality control record provisions. 

* * * * * 

(a) * * * 

(1) * * * 

(viii) For 7-day calibration error tests, 

a test number and reason for test; 

* * * * * 

(4) * * * 

(vi) * * * 

(N) Test number. 

(vii) * * * 

(M) An indicator (‘‘flag’’) if separate 

reference ratios are calculated for each 

multiple stack. 

* * * * * 

(6) For each SO2, NOX, Hg, or CO2

pollutant concentration monitor, each 

component of a NOX-diluent continuous 

emission monitoring system, and each 

CO2 or O2 monitor used to determine 

heat input, the owner or operator shall 

record the following information for the 

cycle time test: 

* * * * * 

(7) * * * 

(ix) For a unit with a flow monitor 

installed on a rectangular stack or duct, 

if a site-specific default or measured 

wall effects adjustment factor (WAF) is 

used to correct the stack gas volumetric 

flow rate data to account for velocity 

decay near the stack or duct wall, the 

owner or operator shall keep records of 

the following for each flow RATA 

performed with EPA Method 2, 

subsequent to the WAF determination: 

(A) Monitoring system ID; 

(B) Test number; 

(C) Operating level; 

(D) RATA end date and time; 

(E) Number of Method 1 traverse 

points; and 

(F) Wall effects adjustment factor 

(WAF), to the nearest 0.0001. 

(x) For each RATA run using Method 

29 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 gas temperature 

(°F); 

(D) Dry gas volume metered (dscm); 

(E) Percent isokinetic; 

(F) Particulate Hg collected in the 

front half of the sampling train, 

corrected for the front-half blank value 

(μg); and 

(G) Total vapor phase Hg collected in 

the back half of the sampling train, 

corrected for the back-half blank value 

(μg). 

(8) For each certified continuous 

emission monitoring system, continuous 

opacity monitoring system, excepted 

monitoring system, or alternative 

monitoring system, the date and 

description of each event which 

requires certification, recertification, or 

certain diagnostic testing of the system 

and the date and type of each test 

performed. If the conditional data 

validation procedures of § 75.20(b)(3) 

are to be used to validate and report 

data prior to the completion of the 

required certification, recertification, or 

diagnostic testing, the date and hour of 

the probationary calibration error test 

shall be reported to mark the beginning 

of conditional data validation. 

* * * * * 

(b) * * * 

(4) * * * 

(i) * * * 

(J) Test number. 

(ii) * * * 

(A) Completion date and hour of most 

recent primary element inspection or 


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test number of the most recent primary 

element inspection (as applicable); (on 

and after January 1, 2009, the test 

number of the most recent primary 

element inspection is required in lieu of 

the completion date and hour for the 

most recent primary element 

inspection); 

(B) Completion date and hour of most 

recent flow meter of transmitter 

accuracy test or test number of the most 

recent flowmeter or transmitter accuracy 

test (as applicable); (on and after 

January 1, 2009, the test number of the 

most recent flowmeter or transmitter 

accuracy test is required in lieu of the 

completion date and hour for the most 

recent flowmeter or transmitter accuracy 

test); 

* * * * * 

(F) Average load, in megawatts, 1000 

lb/hr of steam, or mmBtu/hr thermal 

output; 

* * * * * 

(N) Monitoring system identification 

code. * * * 

* * * * * 

(5) * * * 

(iv) * * * 

(I) Component identification code 

(required on and after January 1, 2009). 

* * * * * 

(d) * * * 

(1) * * * 

(xiii) An indicator (‘‘flag’’) if the run 

is used to calculate the highest 3-run 

average NOX emission rate at any load 

level. 

(2) * * * 

(vi) Indicator of whether the testing 

was done at base load, peak load or both 

(if appropriate); and 

(vii) The default NOX emission rate 

for peak load hours (if applicable). 

* * * * * 

(e) Excepted monitoring for Hg low 

mass emission units under § 75.81(b). 

For qualifying coal-fired units using the 

alternative low mass emission 

methodology under § 75.81(b), the 

owner or operator shall record the data 

elements described in § 75.59(a)(7)(vii), 

§ 75.59(a)(7)(viii), or § 75.59(a)(7)(x), as 

applicable, for each run of each Hg 

emission test and re-test required under 

§ 75.81(c)(1) or § 75.81(d)(4)(iii). 

(f) DAHS Verification. For each DAHS 

(missing data and formula) verification 

that is required for initial certification, 

recertification, or for certain diagnostic 

testing of a monitoring system, record 

the date and hour that the DAHS 

verification is successfully completed. 

(This requirement only applies to units 

that report monitoring plan data in 

accordance with § 75.53(g) and (h).) 

* * * * * 

25. Section 75.60 is amended by 

adding paragraph (b)(8) to read as 

follows: 

§ 75.60 General provisions. 

* * * * * 

(b) * * * 

(8) Routine retest reports for Hg low 

mass emissions units. If requested in 

writing (or by electronic mail) by the 

applicable EPA Regional Office, 

appropriate State, and/or appropriate 

local air pollution control agency, the 

designated representative shall submit a 

hardcopy report for a semiannual or 

annual retest required under 

§ 75.81(d)(4)(iii) for a Hg low mass 

emissions unit, within 45 days after 

completing the test or within 15 days of 

receiving the request, whichever is later. 

The designated representative shall 

report, at a minimum, the following 

hardcopy information to the applicable 

EPA Regional Office, appropriate State, 

and/or appropriate local air pollution 

control agency that requested the 

hardcopy report: A summary of the test 

results; the raw reference method data 

for each test run; the raw data and 

results of all pretest, post-test, and postrun quality-assurance checks of the 

reference method; the raw data and 

results of moisture measurements made 

during the test runs (if applicable); 

diagrams illustrating the test and sample 

point locations; a copy of the test 

protocol used; calibration certificates for 

the gas standards or standard solutions 

used in the testing; laboratory 

calibrations of the source sampling 

equipment; and the names of the key 

personnel involved in the test program, 

including test team members, plant 

contact persons, agency representatives 

and test observers. 

* * * * * 

26. Section 75.61 is amended by: 

a. Revising the first sentence of 

paragraph (a)(1) introductory text; 

b. Revising paragraph (a)(3); 

c. Revising the first sentence of 

paragraph (a)(5) introductory text; and 

d. Adding paragraphs (a)(7) and (a)(8) 

The revisions and additions read as 

follows: 

§ 75.61 Notifications. 

(a) * * * 

(1) Initial certification and 

recertification test notifications. The 

owner or operator or designated 

representative for an affected unit shall 

submit written notification of initial 

certification tests and revised test dates 

as specified in § 75.20 for continuous 

emission monitoring systems, for the 

excepted Hg monitoring methodology 

under § 75.81(b), for alternative 

monitoring systems under subpart E of 

this part, or for excepted monitoring 

systems under appendix E to this part, 

except as provided in paragraphs 

(a)(1)(iii), (a)(1)(iv) and (a)(4) of this 

section.* * * 

* * * * * 

(3) Unit shutdown and 

recommencement of commercial 

operation. For an affected unit that will 

be shutdown on the relevant 

compliance date specified in § 75.4 or in 

a State or Federal pollutant mass 

emissions reduction program that 

adopts the monitoring and reporting 

requirements of this part, if the owner 

or operator is relying on the provisions 

in § 75.4(d) to postpone certification 

testing, the designated representative for 

the unit shall submit notification of unit 

shutdown and recommencement of 

commercial operation as follows: 

(i) For planned unit shutdowns (e.g., 

extended maintenance outages), written 

notification of the planned shutdown 

date shall be provided at least 21 days 

prior to the applicable compliance date, 

and written notification of the planned 

date of recommencement of commercial 

operation shall be provided at least 21 

days in advance of unit restart. If the 

actual shutdown date or the actual date 

of recommencement of commercial 

operation differs from the planned date, 

written notice of the actual date shall be 

submitted no later than 7 days following 

the actual date of shutdown or of 

recommencement of commercial 

operation, as applicable; 

(ii) For unplanned unit shutdowns 

(e.g., forced outages), written 

notification of the actual shutdown date 

shall be provided no more than 7 days 

after the shutdown, and written 

notification of the planned date of 

recommencement of commercial 

operation shall be provided at least 21 

days in advance of unit restart. If the 

actual date of recommencement of 

commercial operation differs from the 

expected date, written notice of the 

actual date shall be submitted no later 

than 7 days following the actual date of 

recommencement of commercial 

operation. 

* * * * * 

(5) Periodic relative accuracy test 

audits, appendix E retests, and low 

mass emissions unit retests. The owner 

or operator or designated representative 

of an affected unit shall submit written 

notice of the date of periodic relative 

accuracy testing performed under 

section 2.3.1 of appendix B to this part, 

of periodic retesting performed under 

section 2.2 of appendix E to this part, of 

periodic retesting of low mass emissions 

units performed under 

§ 75.19(c)(1)(iv)(D), and of periodic 


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retesting of Hg low mass emissions units 

performed under § 75.81(d)(4)(iii), no 

later than 21 days prior to the first 

scheduled day of testing. * * * 

* * * * * 

(7) Long-term cold storage and 

recommencement of commercial 

operation. The designated 

representative for an affected unit that is 

placed into long-term cold storage that 

is relying on the provisions in § 75.4(d) 

or § 75.64(a), either to postpone 

certification testing or to discontinue 

the submittal of quarterly reports during 

the period of long-term cold storage, 

shall provide written notification of 

long-term cold storage status and 

recommencement of commercial 

operation as follows: 

(i) Whenever an affected unit has been 

placed into long-term cold storage, 

written notification of the date and hour 

that the unit was shutdown and a 

statement from the designated 

representative stating that the shutdown 

is expected to last for at least two years 

from that date, in accordance with the 

definition for long-term cold storage of 

a unit as provided in § 72.2. 

(ii) Whenever an affected unit that has 

been placed into long-term cold storage 

is expected to resume operation, written 

notification shall be submitted 45 

calendar days prior to the planned date 

of recommencement of commercial 

operation. If the actual date of 

recommencement of commercial 

operation differs from the expected date, 

written notice of the actual date shall be 

submitted no later than 7 days following 

the actual date of recommencement of 

commercial operation. 

(8) Certification deadline date for new 

or newly affected units. The designated 

representative of a new or newly 

affected unit shall provide notification 

of the date on which the relevant 

deadline for initial certification is 

reached, either as provided in § 75.4(b) 

or § 75.4(c), or as specified in a State or 

Federal SO2, NOX, or Hg mass emission 

reduction program that incorporates by 

reference, or otherwise adopts, the 

monitoring, recordkeeping, and 

reporting requirements of subpart F, G, 

H, or I of this part. The notification shall 

be submitted no later than 7 calendar 

days after the applicable certification 

deadline is reached. 

* * * * * 

27. Section 75.62 is amended by: 

a. Revising paragraph (a)(1); and 

b. Replacing the number ‘‘45’’ with 

the number ‘‘21’’ before the phrase 

‘‘days prior’’, in paragraph (a)(2). 

The revisions and additions read as 

follows: 

§ 75.62 Monitoring plan submittals. 

(a) * * * 

(1) Electronic. Using the format 

specified in paragraph (c) of this 

section, the designated representative 

for an affected unit shall submit a 

complete, electronic, up-to-date 

monitoring plan file (except for 

hardcopy portions identified in 

paragraph (a)(2) of this section) to the 

Administrator as follows: no later than 

21 days prior to the initial certification 

tests; at the time of each certification or 

recertification application submission; 

and (prior to or concurrent with) the 

submittal of the electronic quarterly 

report for a reporting quarter where an 

update of the electronic monitoring plan 

information is required, either under 

§ 75.53(b) or elsewhere in this part. 

* * * * * 

28. Section 75.63 is amended by: 

a. Removing the phrase ‘‘and a 

hardcopy certification application form 

(EPA form 7610–14)’’ from paragraph 

(a)(1)(i)(A); 

b. Revising paragraph (a)(1)(ii)(A); 

c. Adding the phrase ‘‘or 

§ 75.53(h)(4)(ii) (as applicable)’’ after the 

identifier ‘‘§ 75.53(f)(5)(ii)’’, in 

paragraph (a)(1)(ii)(B); 

d. Removing the phrase ‘‘and a 

hardcopy certification application form 

(EPA form 7610–14)’’ after the word 

‘‘section’’, in paragraph (a)(2)(i); 

e. Revising paragraph (a)(2)(iii); 

f. Removing and reserving paragraph 

(b)(2)(iii); 

g. Revising paragraph (b)(2)(iv) by 

adding the words ‘‘certifying the 

accuracy of the submission’’ after the 

word ‘‘signature’’. 

The revisions read as follows: 

§ 75.63 Initial Certification or 

Recertification Application. 

(a) * * * 

(1) * * * 

(ii) * * * 

(A) To the Administrator, the 

electronic low mass emission 

qualification information required by 

§ 75.53(f)(5)(i) or § 75.53(h)(4)(i) (as 

applicable) and paragraph (b)(1)(i) of 

this section; and 

* * * * * 

(2) * * * 

(iii) Notwithstanding the 

requirements of paragraphs (a)(2)(i) and 

(a)(2)(ii) of this section, for an event for 

which the Administrator determines 

that only diagnostic tests (see § 75.20(b)) 

are required rather than recertification 

testing, no hardcopy submittal is 

required; however, the results of all 

diagnostic test(s) shall be submitted 

prior to or concurrent with the 

electronic quarterly report required 

under § 75.64. Notwithstanding the 

requirement of § 75.59(e), for DAHS 

(missing data and formula) verifications, 

no hardcopy submittal is required; the 

owner or operator shall keep these test 

results on-site in a format suitable for 

inspection. 

* * * * * 

29. Section 75.64 is amended by: 

a. Revising paragraph (a) introductory 

text; 

b. Revising paragraph (a)(2)(xiv); 

c. Removing paragraph (a)(8); 

d. Redesignating paragraphs (a)(3) 

through (a)(7) as paragraphs (a)(8) 

through (a)(12), and redesignating 

paragraphs (a)(9) through (a)(11) as 

paragraphs (a)(13) through (a)(15); 

e. Adding new paragraphs (a)(3) 

through (a)(7); and 

f. Replacing the citation ‘‘§ 75.59’’, 

with ‘‘§ 75.58(f)(2)’’ at the end of newly 

designated paragraph (a)(14). 

The revisions and additions read as 

follows: 

§ 75.64 Quarterly reports. 

(a) Electronic submission. The 

designated representative for an affected 

unit shall electronically report the data 

and information in paragraphs (a), (b), 

and (c) of this section to the 

Administrator quarterly, beginning with 

the data from the earlier of the calendar 

quarter corresponding to the date of 

provisional certification or the calendar 

quarter corresponding to the relevant 

deadline for initial certification in 

§ 75.4(a), (b), or (c). The initial quarterly 

report shall contain hourly data 

beginning with the hour of provisional 

certification or the hour corresponding 

to the relevant certification deadline, 

whichever is earlier. For an affected unit 

subject to § 75.4(d) that is shutdown on 

the relevant compliance date in § 75.4(a) 

or has been placed in long-term cold 

storage (as defined in § 72.2 of this 

chapter), quarterly reports are not 

required. In such cases, the owner or 

operator shall submit quarterly reports 

for the unit beginning with the data 

from the quarter in which the unit 

recommences commercial operation 

(where the initial quarterly report 

contains hourly data beginning with the 

first hour of recommenced commercial 

operation of the unit). For units placed 

into long-term cold storage during a 

reporting quarter, the exemption from 

submitting quarterly reports begins with 

the calendar quarter following the date 

that the unit is placed into long-term 

cold storage. For any provisionallycertified monitoring system, 

§ 75.20(a)(3) shall apply for initial 

certifications, and § 75.20(b)(5) shall 

apply for recertifications. Each 

electronic report must be submitted to 


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the Administrator within 30 days 

following the end of each calendar 

quarter. Prior to January 1, 2008, each 

electronic report shall include for each 

affected unit (or group of units using a 

common stack), the information 

provided in paragraphs (a)(1), (a)(2), and 

(a)(8) through (a)(15) of this section. 

During the time period of January 1, 

2008 to January 1, 2009, each electronic 

report shall include either the 

information provided in paragraphs 

(a)(1), (a)(2), and (a)(8) through (a)(15) of 

this section or the information provided 

in paragraphs (a)(3) through (a)(15). On 

and after January 1, 2009, the owner or 

operator shall meet the requirements of 

paragraphs (a)(3) through (a)(15) of this 

section only. Each electronic report 

shall also include the date of report 

generation. 

* * * * * 

(2) * * * 

(xiii) Supplementary RATA 

information required under 

§ 75.59(a)(7), except that: 

(A) The applicable data elements 

under § 75.59(a)(7)(ii)(A) through (T) 

and under § 75.59(a)(7)(iii)(A) through 

(M) shall be reported for flow RATAs at 

circular or rectangular stacks (or ducts) 

in which angular compensation for yaw 

and/or pitch angles is used (i.e., Method 

2F or 2G), with or without wall effects 

adjustments; 

(B) The applicable data elements 

under § 75.59(a)(7)(ii)(A) through (T) 

and under § 75.59(a)(7)(iii)(A) through 

(M) shall be reported for any flow RATA 

run at a circular stack in which Method 

2 is used and a wall effects adjustment 

factor is determined by direct 

measurement; 

(C) The data under § 75.59(a)(7)(ii)(T) 

shall be reported for all flow RATAs at 

circular stacks in which Method 2 is 

used and a default wall effects 

adjustment factor is applied; and 

(D) The data under § 75.59(a)(7)(ix)(A) 

through (F) shall be reported for all flow 

RATAs at rectangular stacks or ducts in 

which Method 2 is used and a wall 

effects adjustment factor is applied. 

(3) Facility identification information, 

including: 

(i) Facility/ORISPL number; 

(ii) Calendar quarter and year for the 

data contained in the report; and 

(iii) Version of the electronic data 

reporting format used for the report. 

(4) In accordance with § 75.62(a)(1), if 

any monitoring plan information 

required in § 75.53 requires an update, 

either under § 75.53(b) or elsewhere in 

this part, submission of the electronic 

monitoring plan update shall be 

completed prior to or concurrent with 

the submittal of the quarterly electronic 

data report for the appropriate quarter in 

which the update is required. 

(5) Except for the daily calibration 

error test data, daily interference check, 

and off-line calibration demonstration 

information required in § 75.59(a)(1) 

and (2), which must always be 

submitted with the quarterly report, the 

certification, quality assurance, and 

quality control information required in 

§ 75.59 shall either be submitted prior to 

or concurrent with the submittal of the 

relevant quarterly electronic data report. 

(6) The information and hourly data 

required in §§ 75.57 through 75.59, and 

daily calibration error test data, daily 

interference check, and off-line 

calibration demonstration information 

required in § 75.59(a)(1) and (2). 

(7) Notwithstanding the requirements 

of paragraphs (a)(4) through (a)(6) of this 

section, the following information is 

excluded from electronic reporting: 

(i) Descriptions of adjustments, 

corrective action, and maintenance; 

(ii) Information which is incompatible 

with electronic reporting (e.g., field data 

sheets, lab analyses, quality control 

plan); 

(iii) Opacity data listed in § 75.57(f), 

and in § 75.59(a)(8); 

(iv) For units with SO2 or NOX addon emission controls that do not elect to 

use the approved site-specific 

parametric monitoring procedures for 

calculation of substitute data, the 

information in § 75.58(b)(3); 

(v) Information required by § 75.57(h) 

concerning the causes of any missing 

data periods and the actions taken to 

cure such causes; 

(vi) Hardcopy monitoring plan 

information required by § 75.53 and 

hardcopy test data and results required 

by § 75.59; 

(vii) Records of flow monitor and 

moisture monitoring system polynomial 

equations, coefficients, or ‘‘K’’ factors 

required by § 75.59(a)(5)(vi) or 

§ 75.59(a)(5)(vii); 

(viii) Daily fuel sampling information 

required by § 75.58(c)(3)(i) for units 

using assumed values under appendix 

D; 

(ix) Information required by 

§§ 75.59(b)(1)(vi), (vii), (viii), (ix), and 

(xiii), and (b)(2)(iii) and (iv) concerning 

fuel flowmeter accuracy tests and 

transmitter/transducer accuracy tests; 

(x) Stratification test results required 

as part of the RATA supplementary 

records under § 75.59(a)(7); 

(xi) 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 

problems unrelated to monitor 

performance; and 

(xii) Supplementary RATA 

information required under 

§ 75.59(a)(7)(i) through § 75.59(a)(7)(v), 

except that: 

(A) The applicable data elements 

under § 75.59(a)(7)(ii)(A) through (T) 

and under § 75.59(a)(7)(iii)(A) through 

(M) shall be reported for flow RATAs at 

circular or rectangular stacks (or ducts) 

in which angular compensation for yaw 

and/or pitch angles is used (i.e., Method 

2F or 2G), with or without wall effects 

adjustments; 

(B) The applicable data elements 

under § 75.59(a)(7)(ii)(A) through (T) 

and under § 75.59(a)(7)(iii)(A) through 

(M) shall be reported for any flow RATA 

run at a circular stack in which Method 

2 is used and a wall effects adjustment 

factor is determined by direct 

measurement; 

(C) The data under § 75.59(a)(7)(ii)(T) 

shall be reported for all flow RATAs at 

circular stacks in which Method 2 is 

used and a default wall effects 

adjustment factor is applied; and 

(D) The data under 

§ 75.59(a)(7)(vii)(A) through (F) shall be 

reported for all flow RATAs at 

rectangular stacks or ducts in which 

Method 2 is used and a wall effects 

adjustment factor is applied. 

* * * * * 

§ 75.66 [Amended] 

30. Section 75.66 is amended by 

removing and reserving paragraph (f). 

31. Section 75.71 is amended by: 

a. In paragraph (a)(1), by replacing the 

second occurrence of the phrase ‘‘CO2

diluent gas monitor’’ with the phrase 

‘‘CO2 diluent gas monitoring system’’; 

b. Replacing the phrase ‘‘O2 or CO2

diluent gas monitor’’ with the phrase 

‘‘O2 or CO2 monitoring system’’, in 

paragraph (a)(2); and 

c. Revising paragraph (e). 

The revision reads as follows: 

§ 75.71 Specific provisions for monitoring 

NOX and heat input for the purpose of 

calculating NOX mass emissions. 

* * * * * 

(e) Low mass emissions units. 

Notwithstanding the requirements of 

paragraphs (c) and (d) of this section, for 

an affected unit using the low mass 

emissions (LME) unit under § 75.19 to 

estimate hourly NOX emission rate, heat 

input and NOX mass emissions, the 

owner or operator shall calculate the 

ozone season NOX mass emissions by 

summing all of the estimated hourly 

NOX mass emissions in the ozone 

season, as determined under 


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§ 75.19(c)(4)(ii)(A), and dividing this 

sum by 2000 lb/ton. 

* * * * * 

32. Section 75.72 is amended by: 

a. Revising the section heading and 

the introductory text; and 

b. Removing and reserving paragraph 

(f). 

The revisions read as follows: 

§ 75.72 Determination of NOX mass 

emissions for common stack and multiple 

stack configurations. 

The owner or operator of an affected 

unit shall either: calculate hourly NOX

mass emissions (in lbs) by multiplying 

the hourly NOX emission rate (in lbs/ 

mmBtu) by the hourly heat input rate 

(in mmBtu/hr) and the unit or stack 

operating time (as defined in § 72.2); or, 

as provided in paragraph (e) of this 

section, calculate hourly NOX mass 

emissions from the hourly NOX

concentration (in ppm) and the hourly 

stack flow rate (in scfh). Only one 

methodology for determining NOX mass 

emissions shall be identified in the 

monitoring plan for each monitoring 

location at any given time. The owner 

or operator shall also calculate quarterly 

and cumulative year-to-date NOX mass 

emissions and cumulative NOX mass 

emissions for the ozone season (in tons) 

by summing the hourly NOX mass 

emissions according to the procedures 

in section 8 of appendix F to this part. 

* * * * * 

(f) [Reserved] 

* * * * * 

33. Section 75.73 is amended by: 

a. Revising paragraph (c)(3); 

b. Replacing the number ‘‘45’’ with 

the number ‘‘21’’ in paragraphs (e)(1) 

and (e)(2); 

c. Revising paragraph (f)(1) 

introductory text; 

d. Replacing the phrase ‘‘paragraph 

(a)’’ with the phrase ‘‘paragraphs (a) and 

(b)’’ in paragraph (f)(1)(ii) introductory 

text; and 

e. Revising paragraph (f)(1)(ii)(K). 

The revisions read as follows: 

§ 75.73 Recordkeeping and reporting. 

* * * * * 

(c) * * * 

(3) Contents of the monitoring plan 

for units not subject to an Acid Rain 

emissions limitation. Prior to January 1, 

2009, each monitoring plan shall 

contain the information in § 75.53(e)(1) 

or § 75.53(g)(1) in electronic format and 

the information in § 75.53(e)(2) or 

§ 75.53(g)(2) in hardcopy format. On and 

after January 1, 2009, each monitoring 

plan shall contain the information in 

§ 75.53(g)(1) in electronic format and the 

information in § 75.53(g)(2) in hardcopy 

format, only. In addition, to the extent 

applicable, prior to January 1, 2009, 

each monitoring plan shall contain the 

information in § 75.53(f)(1)(i), (f)(2)(i), 

and (f)(4) or § 75.53(h)(1)(i), and (h)(2)(i) 

in electronic format and the information 

in § 75.53(f)(1)(ii) and (f)(2)(ii) or 

§ 75.53(h)(1)(ii) and (h)(2)(ii) in 

hardcopy format. On and after January 

1, 2009, each monitoring plan shall 

contain the information in 

§ 75.53(h)(1)(i), and (h)(2)(i) in 

electronic format and the information in 

§ 75.53(h)(1)(ii) and (h)(2)(ii) in 

hardcopy format, only. For units using 

the low mass emissions excepted 

methodology under § 75.19, prior to 

January 1, 2009, the monitoring plan 

shall include the additional information 

in § 75.53(f)(5)(i) and (f)(5)(ii) or 

§ 75.53(h)(4)(i) and (h)(4)(ii). On and 

after January 1, 2009, for units using the 

low mass emissions excepted 

methodology under § 75.19 the 

monitoring plan shall include the 

additional information in § 75.53(h)(4)(i) 

and (h)(4)(ii), only. Prior to January 1, 

2008, the monitoring plan shall also 

identify, in electronic format, the 

reporting schedule for the affected unit 

(ozone season or quarterly), and the 

beginning and end dates for the 

reporting schedule. The monitoring plan 

also shall include a seasonal controls 

indicator, and an ozone season fuelswitching flag. 

* * * * * 

(f) * * * 

(1) Electronic submission. The 

designated representative for an affected 

unit shall electronically report the data 

and information in this paragraph (f)(1) 

and in paragraphs (f)(2) and (3) of this 

section to the Administrator quarterly, 

unless the unit has been placed in longterm cold storage (as defined in § 72.2 

of this chapter). For units placed into 

long-term cold storage during a 

reporting quarter, the exemption from 

submitting quarterly reports begins with 

the calendar quarter following the date 

that the unit is placed into long-term 

cold storage. In such cases, the owner or 

operator shall submit quarterly reports 

for the unit beginning with the data 

from the quarter in which the unit 

recommences operation (where the 

initial quarterly report contains hourly 

data beginning with the first hour of 

recommenced operation of the unit). 

Each electronic report must be 

submitted to the Administrator within 

30 days following the end of each 

calendar quarter. Except as otherwise 

provided in §§ 75.64(a)(4) and (a)(5), 

each electronic report shall include the 

information provided in paragraphs 

(f)(1)(i) through (1)(vi) of this section, 

and shall also include the date of report 

generation. Prior to January 1, 2009, 

each report shall include the facility 

information provided in paragraphs 

(f)(1)(i)(A) and (B), for each affected unit 

or group of units monitored at a 

common stack. On and after January 1, 

2009, only the facility identification 

information provided in paragraph 

(f)(1)(i)(A) is required. 

* * * * * 

(ii) * * * 

(K) Supplementary RATA information 

required under § 75.59(a)(7), except that: 

(1) The applicable data elements 

under § 75.59(a)(7)(ii)(A) through (T) 

and under § 75.59(a)(7)(iii)(A) through 

(M) shall be reported for flow RATAs at 

circular or rectangular stacks (or ducts) 

in which angular compensation for yaw 

and/or pitch angles is used (i.e., Method 

2F or 2G), with or without wall effects 

adjustments; 

(2) The applicable data elements 

under § 75.59(a)(7)(ii)(A) through (T) 

and under § 75.59(a)(7)(iii)(A) through 

(M) shall be reported for any flow RATA 

run at a circular stack in which Method 

2 is used and a wall effects adjustment 

factor is determined by direct 

measurement; 

(3) The data under § 75.59(a)(7)(ii)(T) 

shall be reported for all flow RATAs at 

circular stacks in which Method 2 is 

used and a default wall effects 

adjustment factor is applied; and 

(4) The data under § 75.59(a)(7)(ix)(A) 

through (F) shall be reported for all flow 

RATAs at rectangular stacks or ducts in 

which Method 2 is used and a wall 

effects adjustment factor is applied. 

* * * * * 

34. Section 75.74 is amended by: 

a. Replacing the phrase ‘‘In the time 

period to the start of the current ozone 

season (i.e., in the period extending 

from October 1 of the previous calendar 

year through April 30 of the current 

calendar year), the’’, with the word 

‘‘The’’, in paragraph (c)(2) introductory 

text; 

b. Adding the words ‘‘in the second 

calendar quarter no later than April 30’’

to the end of paragraph (c)(2)(i) 

introductory text; 

c. Removing the phrase ‘‘of the 

current calendar year’’ from the first 

sentence, and removing the last 

sentence of paragraph (c)(2)(i)(C); 

d. Revising paragraph (c)(2)(i)(D); 

e. Adding the words ‘‘in the first or 

second calendar quarter, but no later 

than April 30’’ to the end of the first 

sentence, and by removing the second 

sentence of paragraph (c)(2)(ii) 

introductory text; 

f. Removing the words ‘‘of the current 

calendar year’’ from paragraph 

(c)(2)(ii)(E); 


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g. Revising paragraph (c)(2)(ii)(F); 

h. Removing paragraphs (c)(2)(ii)(G) 

and (c)(2)(ii)(H); 

i. Revising paragraph (c)(3)(ii); 

j. Removing and reserving paragraphs 

(c)(3)(vi) through (viii); 

k. Replacing all occurrences of the 

words ‘‘§ 75.31, § 75.33, or § 75.37’’ with 

the words ‘‘§§ 75.31 through 75.37’’ in 

paragraphs (c)(3)(xi), (c)(3)(xii)(A), and 

(c)(3)(xii)(B); 

l. Revising paragraph (c)(6)(iii); 

m. Replacing the words ‘‘October 1 of 

the previous calendar year’’ with 

‘‘January 1’’ in paragraph (c)(6)(v); and 

n. Revising paragraph (c)(11). 

The revisions and additions read as 

follows: 

§ 75.74 Annual and ozone season 

monitoring and reporting requirements. 

* * * * * 

(c) * * * 

(2) * * * 

(i) * * * 

(D) If the linearity check is not 

completed by April 30, data validation 

shall be determined in accordance with 

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

(ii) * * * 

(F) Data Validation. For each RATA 

that is performed by April 30, data 

validation shall be done according to 

sections 2.3.2(a)–(j) of appendix B to 

this part. However, if a required RATA 

is not completed by April 30, data from 

the monitoring system shall be invalid, 

beginning with the first unit operating 

hour on or after May 1. The owner or 

operator shall continue to invalidate all 

data from the CEMS until either: 

(1) The required RATA of the CEMS 

has been performed and passed; or 

(2) A probationary calibration error 

test of the CEMS is passed in 

accordance with § 75.20(b)(3)(ii). Once 

the probationary calibration error test 

has been passed, the owner or operator 

shall perform the required RATA in 

accordance with the conditional data 

validation provisions and within the 

720 unit or stack operating hour time 

frame specified in § 75.20(b)(3) (subject 

to the restrictions in paragraph 

(c)(3)(xii) of this section), and the term 

‘‘quality assurance’’ shall apply instead 

of the term ‘‘recertification.’’ However, 

in lieu of the provisions in 

§ 75.20(b)(3)(ix), the owner or operator 

shall follow the applicable provisions in 

paragraphs (c)(3)(xi) and (c)(3)(xii) of 

this section. 

(3) * * * 

(ii) For each gas monitor required by 

this subpart, linearity checks shall be 

performed in the second and third 

calendar quarters, as follows: 

(A) For the second calendar quarter, 

the pre-ozone season linearity check 

required under paragraph (c)(2)(i) of this 

section shall be performed by April 30. 

(B) For the third calendar quarter, a 

linearity check shall be performed and 

passed no later than July 30. 

(C) Conduct each linearity check in 

accordance with the general procedures 

in section 6.2 of appendix A to this part, 

except that the data validation 

procedures in sections 6.2(a) through (f) 

of appendix A do not apply. 

(D) Each linearity check shall be done 

‘‘hands-off,’’ as described in section 

2.2.3(c) of appendix B to this part. 

(E) Data Validation. For second and 

third quarter linearity checks performed 

by the applicable deadline (i.e., April 30 

or July 30), data validation shall be done 

in accordance with sections 2.2.3(a), (b), 

(c), (e), and (h) of Appendix B to this 

part. However, if a required linearity 

check for the second calendar quarter is 

not completed by April 30, or if a 

required linearity check for the third 

calendar quarter is not completed by 

July 30, data from the monitoring 

system (or range) shall be invalid, 

beginning with the first unit operating 

hour on or after May 1 or July 31, 

respectively. The owner or operator 

shall continue to invalidate all data 

from the CEMS until either: 

(1) The required linearity check of the 

CEMS has been performed and passed; 

or 

(2) A probationary calibration error 

test of the CEMS is passed in 

accordance with § 75.20(b)(3)(ii). Once 

the probationary calibration error test 

has been passed, the owner or operator 

shall perform the required linearity 

check in accordance with the 

conditional data validation provisions 

and within the 168 unit or stack 

operating hour time frame specified in 

§ 75.20(b)(3) (subject to the restrictions 

in paragraph (c)(3)(xii) of this section), 

and the term ‘‘quality assurance’’ shall 

apply instead of the term 

‘‘recertification.’’ However, in lieu of the 

provisions in § 75.20(b)(3)(ix), the 

owner or operator shall follow the 

applicable provisions in paragraphs 

(c)(3)(xi) and (c)(3)(xii) of this section. 

(F) A pre-season linearity check 

performed and passed in April satisfies 

the linearity check requirement for the 

second quarter. 

(G) The third quarter linearity check 

requirement in paragraph (c)(3)(ii)(B) of 

this section is waived if: 

(1) Due to infrequent unit operation, 

the 168 operating hour conditional data 

validation period associated with a preseason linearity check extends into the 

third quarter; and 

(2) A linearity check is performed and 

passed within that conditional data 

validation period. 

* * * * * 

(6) * * * 

(iii) For the time periods described in 

paragraphs (c)(2)(i)(C) and (c)(2)(ii)(E) of 

this section, hourly emission data and 

the results of all daily calibration error 

tests and flow monitor interference 

checks shall be recorded. The results of 

all daily calibration error tests and flow 

monitor interference checks performed 

in the time period from April 1 through 

April 30 shall be reported. The owner or 

operator shall also report unit operating 

data recorded in the time period from 

April 1 through April 30 beginning with 

the day of the first required daily 

calibration error test or flow monitor 

interference check performed whenever 

the XML reporting format is used. The 

owner or operator may also report the 

hourly emission data in the time period 

from April 1 through April 30. However, 

only the emission data recorded in the 

time period from May 1 through 

September 30 shall be used for NOX

mass compliance determination; 

* * * * * 

(11) Units may qualify to use the 

optional NOX mass emissions 

estimation protocol for gas-fired and oilfired peaking units in appendix E to this 

part on an ozone season basis. In order 

to be allowed to use this methodology, 

the unit must meet the definition of 

‘‘peaking unit’’ in § 72.2 of this chapter, 

except that the words ‘‘year’’, ‘‘calendar 

year’’ and ‘‘calendar years’’ in that 

definition shall be replaced by the 

words ‘‘ozone season’’, ‘‘ozone season’’, 

and ‘‘ozone seasons’’, respectively. In 

addition, in the definition of the term 

‘‘capacity factor’’ in § 72.2 of this 

chapter, the word ‘‘annual’’ shall be 

replaced by the words ‘‘ozone season’’

and the number ‘‘8,760’’ shall be 

replaced by the number ‘‘3,672’’. 

35. Section 75.81 is amended by: 

a. Revising paragraph (a)(4); 

b. Revising paragraph (c)(1); 

c. Revising paragraph (c)(2); 

c. Removing Eq. 1 from paragraph 

(d)(1); 

d. Revising paragraph (d)(2); 

e. Adding paragraph (d)(4)(iv); and 

f. Revising paragraphs (d)(5) and 

(e)(1). 

The revisions and additions read as 

follows: 

§ 75.81 Monitoring of Hg mass emissions 

and heat input at the unit level. 

* * * * * 

(a) * * * 

(4) If heat input is required to be 

reported under the applicable State or 

Federal Hg mass emission reduction 


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program that adopts the requirements of 

this subpart, the owner or operator must 

meet the general operating requirements 

for a flow monitoring system and an O2

or CO2 monitoring system to measure 

heat input rate. 

* * * * * 

(c) * * * 

(1) The owner or operator must 

perform Hg emission testing one year or 

less before 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(a)(7), and shall 

consist of a minimum of 3 runs at the 

normal unit operating load, while 

combusting coal. The coal combusted 

during the testing must be from the 

same source of supply as the coal 

combusted at the start of the Hg mass 

emissions reduction program. The 

minimum time per run shall be 1 hour 

if an instrumental reference method is 

used. If Method 29 or the Ontario Hydro 

method is used, paired sampling trains 

are required for each test run and the 

run must be long enough to ensure that 

sufficient Hg is collected to analyze. 

When Method 29 or the Ontario Hydro 

method is used, the test results shall be 

based on the vapor phase Hg collected 

in the back-half of the sampling trains 

(i.e., the non-filterable impinger 

catches). For each Method 29 or Ontario 

Hydro method test run, the paired trains 

must meet the percent relative deviation 

(RD) requirement in § 75.22(a)(7). If the 

RD specification is met, the results of 

the two trains shall be averaged 

arithmetically. 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: 

E Q Eq = 8760 K C 1 Hg max ( ) .

Where: 

E = Estimated annual Hg mass 

emissions from the affected unit, 

(ounces/year) 

K = Units conversion constant, 9.978 × 

10¥10 oz-scm/[mu]g-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. 

* * * * * 

(d) * * * 

(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)(4)(iv) or (d)(6) of this 

section. The default Hg concentration 

value shall be updated as appropriate, 

according to paragraph (d)(5) of this 

section. 

* * * * * 

(4) * * * 

(iv) An additional retest is required 

when there is a change in the fuel 

supply. The retest shall be performed 

within 720 unit operating hours of the 

change. 

(5) The default Hg concentration used 

for reporting under § 75.84 shall be 

updated after each required retest. This 

includes retests that are required prior 

to the compliance date in § 75.80(b). 

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 value 

shall be applied beginning with the first 

unit operating hour in which Hg 

emissions data are required to be 

reported after completion of the retest, 

except as provided in paragraph 

(d)(4)(iv) of this section, where the need 

to retest is triggered by a change in the 

fuel supply. In that case, apply the 

updated default Hg concentration 

beginning with the first unit operating 

hour in which Hg emissions are 

required to be reported after the date 

and hour of the fuel switch. 

* * * * * 

(e) * * * 

(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 tested 

to demonstrate that its potential to emit 

does not exceed 464 ounces of Hg per 

year, in accordance with paragraphs (c) 

and (d) of this section. If the units 

sharing the common stack qualify as a 

group of identical units in accordance 

with § 75.19(c)(1)(iv)(B), the owner or 

operator may test a subset of the units 

in lieu of testing each unit individually. 

If this option is selected, the number of 

units required to be tested shall be 

determined from Table LM–4 in § 75.19. 

If the test results demonstrate that the 

units sharing the common stack qualify 

as low mass emitters, the default Hg 

concentration used for reporting Hg 

mass emissions at the common stack 

shall either be the highest value 

obtained in any test run for any of the 

tested units serving the common stack 

or 0.50 μg/scm, whichever is greater. 

Notwithstanding these requirements, 

the emission testing required under 

paragraphs (c) and/or (d)(3) of this 

section may be performed at the 

common stack in the following 

circumstances: 

(i) The initial certification testing 

required under paragraph (c) of this 

section may be performed at the 

common stack if all of the units using 

the stack are affected units and if, prior 

to entering the common stack, the 

effluent gas streams from the individual 

units are combined together upstream of 

an emission control device that reduces 

the Hg concentration. If this testing 

option is chosen: 

(A) The testing must be done at a 

combined load corresponding to the 

designated normal load level (low, mid, 

or high) for the units sharing the 

common stack, in accordance with 

section 6.5.2.1 of appendix A to this 

part; 

(B) All of the units that share the stack 

must be operating in a normal, stable 

manner and at typical load levels during 

the emission testing; 

(C) When calculating E, the estimated 

maximum potential annual Hg mass 

emissions from the stack, the maximum 

potential flow rate through the common 

stack (as defined in the monitoring plan) 

and the highest concentration from any 

test run (or 0.50 μg/scm, if greater) shall 

be substituted into Equation 1; 

(D) The calculated value of E shall be 

divided by the number of units sharing 

the stack. If the result, when rounded to 

the nearest ounce, does not exceed 464 

ounces, the units qualify to use the low 

mass emission methodology; and 

(E) If the units qualify to use the 

methodology, the default Hg 

concentration used for reporting at the 

common stack shall be the highest value 

obtained in any test run or 0.50 μg/scm, 

whichever is greater; or 

(ii) For all common stack 

configurations, the retests required 

under paragraph (d)(3) of this section 

may be done at the common stack. If 

this testing option is chosen, the testing 

shall be done at a combined load 

corresponding to the designated normal 


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load level (low, mid, or high) for the 

units sharing the common stack, in 

accordance with section 6.5.2.1 of 

appendix A to this part. The due date 

for the next retest shall be determined 

as follows: 

(A) To calculate E, the maximum 

potential flow rate for the common stack 

(as defined in the monitoring plan) and 

the highest Hg concentration from any 

test run (or 0.50 μg/scm, if greater) shall 

be substituted into Equation 1; 

(B) If the value of E obtained from 

Equation 1, rounded to the nearest 

ounce, is greater than 144 times the 

number of units sharing the common 

stack, but less than or equal to 464 times 

the number of units sharing the stack, 

the next retest is due in two QA 

operating quarters; 

(C) If the value of E obtained from 

Equation 1, rounded to the nearest 

ounce, is less than or equal to 144 times 

the number of units sharing the 

common stack, the next retest is due in 

four QA operating quarters. 

* * * * * 

36. Section 75.82 is amended by 

adding paragraphs (b)(3), (c)(4), and 

(d)(3) to read as follows: 

§ 75.82 Monitoring of Hg mass emissions 

and heat input at common and multiple 

stacks. 

* * * * * 

(b) * * * 

(3) If the monitoring option in 

paragraph (b)(2) of this section is 

selected, and 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 shall 

either: 

(i) Apportion the common stack heat 

input rate to the individual units 

according to the procedures in 

§ 75.16(e)(3); or 

(ii) Install a flow monitoring system 

and a diluent gas (O2 or CO2) monitoring 

system in the duct leading from each 

affected unit to the common stack, and 

measure the heat input rate in each 

duct, according to section 5.2 of 

appendix F to this part. 

(c) * * * 

(4) If the monitoring option in 

paragraph (c)(1) or (c)(2) of this section 

is selected, and 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 shall: 

(i) Use the installed flow and diluent 

monitors to determine the hourly heat 

input rate at each stack (mmBtu/hr), 

according to section 5.2 of appendix F 

to this part; and 

(ii) Calculate the hourly heat input at 

each stack (in mmBtu) by multiplying 

the measured stack heat input rate by 

the corresponding stack operating time; 

and 

(iii) Determine the hourly unit heat 

input by summing the hourly stack heat 

input values. 

(d) * * * 

(3) If the monitoring option in 

paragraph (d)(1) or (d)(2) of this section 

is selected, and 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 shall: 

(i) Use the installed flow and diluent 

monitors to determine the hourly heat 

input rate at each stack or duct (mmBtu/ 

hr), according to section 5.2 of appendix 

F to this part; and 

(ii) Calculate the hourly heat input at 

each stack or duct (in mmBtu) by 

multiplying the measured stack (or 

duct) heat input rate by the 

corresponding stack (or duct) operating 

time; and 

(iii) Determine the hourly unit heat 

input by summing the hourly stack (or 

duct) heat input values. 

37. Section 75.84 is amended by: 

a. Removing ‘‘§ 75.53(e)(1)’’ and 

‘‘§ 75.53(e)(2)’’ and adding in their place 

‘‘§ 75.53(g)(1)’’ and ‘‘§ 75.53(g)(2)’’, 

respectively, in paragraph (c)(3); 

b. Removing the number ‘‘45’’ and 

adding in its place the number ‘‘21’’ in 

paragraphs (e)(1) and (e)(2); 

c. Revising paragraph (f)(1) 

introductory text; 

d. Removing ‘‘§ 75.64(a)(1)’’ and 

adding in its place ‘‘§ 75.64(a)(3)’’ in 

paragraph (f)(1)(i); 

e. Replacing the phrase ‘‘paragraph 

(a)’’ with the phrase ‘‘paragraphs (a) and 

(b)’’ in paragraph (f)(1)(ii) introductory 

text; 

f. Revising paragraph (f)(1)(ii)(I). 

The revisions read as follows: 

§ 75.84 Recordkeeping and reporting. 

* * * * * 

(f) * * * 

(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, except as 

otherwise provided in § 75.64(a) for 

units in long-term cold storage. Each 

electronic report must be submitted to 

the Administrator within 30 days 

following the end of each calendar 

quarter. Except as otherwise provided in 

§§ 75.64(a)(4) and (a)(5), 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: 

* * * * * 

(ii) * * * 

(I) Supplementary RATA information 

required under § 75.59(a)(7), except that: 

(1) The applicable data elements 

under § 75.59(a)(7)(ii)(A) through (T) 

and under § 75.59(a)(7)(iii)(A) through 

(M) shall be reported for flow RATAs at 

circular or rectangular stacks (or ducts) 

in which angular compensation for yaw 

and/or pitch angles is used (i.e., Method 

2F or 2G), with or without wall effects 

adjustments; 

(2) The applicable data elements 

under § 75.59(a)(7)(ii)(A) through (T) 

and under § 75.59(a)(7)(iii)(A) through 

(M) shall be reported for any flow RATA 

run at a circular stack in which Method 

2 is used and a wall effects adjustment 

factor is determined by direct 

measurement; 

(3) The data under § 75.59(a)(7)(ii)(T) 

shall be reported for all flow RATAs at 

circular stacks in which Method 2 is 

used and a default wall effects 

adjustment factor is applied; and 

(4) The data under § 75.59(a)(7)(ix)(A) 

through (F) shall be reported for all flow 

RATAs at rectangular stacks or ducts in 

which Method 2 is used and a wall 

effects adjustment factor is applied. 

* * * * * 

38. Appendix A to Part 75 is amended 

by: 

a. Revising paragraph (c) of section 

2.1.1.1; 

b. Revising paragraph (b)(2) of section 

2.1.1.5; 

c. Revising paragraph (b)(2) of section 

2.1.2.5; and 

d. Adding a new fourth sentence after 

the third sentence of section 2.1.3. 

e. Revising paragraph (3) of section 

3.2; 

f. Replacing the phrase ‘‘continuous 

emission monitoring system(s)’’ with 

the phrase ‘‘monitoring component of a 

continuous emission monitoring system 

that is’’ in section 3.5; 

g. Revising section 5.1; 

h. Redesignating section 6.1 as section 

6.1.1; 

i. Adding new sections 6.1 and 6.1.2; 

j. Revising the second and third 

sentences and adding a new fourth 

sentence to section 6.2, introductory 

text; 


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k. Replacing the words ‘‘section 2.6’’

with the words ‘‘section 2.2.1’’, in 

paragraph (g) of section 6.2; 

l. Adding paragraph (h) to section 6.2; 

m. Adding a new fourth sentence to 

section 6.3.1, introductory text; 

n. Revising the introductory text of 

section 6.4; 

o. Removing the words ‘‘that uses 

CEMS to account for its emissions and 

for each unit that uses the optional fuel 

flow-to-load quality assurance test in 

section 2.1.7 of appendix D to this part’’

from paragraph (a) of section 6.5.2.1; 

p. Adding the words ‘‘or mmBtu/hr’’

after the words ‘‘klb/hr of steam 

production’’, and by adding the words 

‘‘or mmBtu/hr of thermal output’’ after 

the words ‘‘thousands of lb/hr of steam 

load’’ in paragraph (a)(1) of section 

6.5.2.1; 

q. Adding the words ‘‘and units using 

the low mass emissions (LME) excepted 

methodology under § 75.19’’ after the 

words ‘‘(except for peaking units’’ in the 

second sentence in paragraph (c) of 

section 6.5.2.1; 

r. Adding the words ‘‘and LME units’’

after the words ‘‘For peaking units’’ in 

the third sentence of paragraph (d)(1) of 

section 6.5.2.1; 

s. Replacing the words ‘‘quarterly 

report’’ in the first sentence with the 

words ‘‘monitoring plan’’, by adding the 

words ‘‘or mmBtu/hr’’ after the term 

‘‘lb/hr’’, by replacing the number 

‘‘75.64’’ with the number ‘‘75.53’’, by 

adding the words ‘‘and LME units’’ after 

the words ‘‘Except for peaking units’’, 

and by revising the words ‘‘electronic 

quarterly report (as part of the electronic 

monitoring plan)’’ to read ‘‘electronic 

monitoring plan’’ in paragraph (e) of 

section 6.5.2.1; 

t. Replacing all occurrences of the 

words ‘‘section 3.2’’ with the words 

‘‘section 8.1.3’’ in paragraph (b)(3) of 

section 6.5.6, paragraph (a) of section 

6.5.6.2, and paragraph (a) of section 

6.5.6.3; 

u. Adding the words ‘‘and the same 

type of sorbent material’’ after the words 

‘‘same-size trap’’ in the third-to-last 

sentence of section 6.5.7, paragraph (a); 

v. Revising section 6.5.10; 

w. Adding a sentence at the end of 

section 7.6.1; 

x. Revising the words ‘‘scfh/ 

megawatts or scfh/1000 lb/hr of steam’’

to read ‘‘scfh/megawatts, scfh/1000 lb/ 

hr of steam, or scfh/(mmBtu/hr of steam 

output)’’ at the end of the Rref variable 

definition, and by revising the words 

‘‘megawatts or 1000 lb/hr of steam,’’ to 

read ‘‘megawatts, 1000 lb/hr of steam, or 

mmBtu/hr thermal output’’ at the end of 

the Lavg variable definition in paragraph 

(a) of section 7.7; and 

y. Revising the words ‘‘Btu/kwh or 

Btu/lb steam load’’ to read ‘‘Btu/kwh, 

Btu/lb steam load, or mmBtu heat input/ 

mmBtu steam output’’ in the (GHR)ref

variable definition, and by revising the 

words ‘‘megawatts or 1000 lb/hr of 

steam’’ to read ‘‘megawatts, 1000 lb/hr 

of steam, or mmBtu/hr thermal output’’

at the end of the Lavg variable definition, 

in paragraph (c) of section 7.7. 

The revisions and additions read as 

follows: 

Appendix A to Part 75—Specifications 

and Test Procedures 

* * * * * 

2. Equipment Specifications 

2.1.1.1 Maximum Potential Concentration 

* * * * * 

(c) When performing fuel sampling to 

determine the MPC, use ASTM Methods: 

ASTM D3177–89 (1997), ‘‘Standard Test 

Methods for Total Sulfur in the Analysis 

Sample of Coal and Coke’’; ASTM D4239–02, 

‘‘Standard Test Methods for Sulfur in the 

Analysis Sample of Coal and Coke Using 

High Temperature Tube Furnace Combustion 

Methods’’; ASTM D4294–98, ‘‘Standard Test 

Method for Sulfur in Petroleum Products by 

Energy-Dispersive X-Ray Fluorescence 

Spectroscopy’’; ASTM D1552–01, ‘‘Standard 

Test Method for Sulfur in Petroleum 

Products (High Temperature Method)’’; 

ASTM D129–00, ‘‘Standard Test Method for 

Sulfur in Petroleum Products (General Bomb 

Method)’’; ASTM D2622–98, ‘‘Standard Test 

Method for Sulfur in Petroleum Products by 

X-Ray Spectrometry’’ for sulfur content of 

solid or liquid fuels; ASTM D3176–89 

(1997)e1, ‘‘Standard Practice for Ultimate 

Analysis of Coal and Coke’’; ASTM D240–00 

(Reapproved 1991), ‘‘Standard Test Method 

for Heat of Combustion of Liquid 

Hydrocarbon Fuels by Bomb Calorimeter’’; or 

ASTM D5865–01ae1, ‘‘Standard Test Method 

for Gross Calorific Value of Coal and Coke’’

(incorporated by reference under § 75.6). 

* * * * * 

2.1.1.5 * * * 

(b) * * * 

(2) For units with two SO2 spans and 

ranges, if the low range is exceeded, no 

further action is required, provided that the 

high range is available and its most recent 

calibration error test and linearity check have 

not expired. However, if either of these 

quality assurance tests has expired and 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 as the SO2 concentration 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). 

* * * * * 

2.1.2.5 * * * 

(b) * * * 

(2) For units with two NOX spans and 

ranges, if the low range is exceeded, no 

further action is required, provided that the 

high range is available and its most recent 

calibration error test and linearity check have 

not expired. However, if either of these 

quality assurance tests has expired and 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 as the NOX concentration 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). 

* * * * * 

2.1.3 CO2 and O2 Monitors 

* * * An alternative CO2 span value below 

6.0 percent may be used if an appropriate 

technical justification is included in the 

hardcopy monitoring plan. 

* * * * * 

3.2 * * * 

(3) For the linearity check and the 3-level 

system integrity check of an Hg monitor, 

which are required, respectively, under 

§§ 75.20(c)(1)(ii) and (c)(1)(vi), the 

measurement error shall not exceed 5.0 

percent of the span value at any of the three 

gas levels. To calculate the measurement 

error at each level, take the absolute value of 

the difference between the reference value 

and mean CEM response, divide the result by 

the span value, and then multiply by 100. 

Alternatively, the results at any gas level are 

acceptable if the absolute value of the 

difference between the average monitor 

response and the average reference value, i.e., 

| R¥A | in Equation A–4 of this appendix, 

does not exceed 0.6 μg/m3. The principal and 

alternative performance specifications in this 

section also apply to the single-level system 

integrity check described in section 2.6 of 

appendix B to this part. 

* * * * * 

5.1 Reference Gases. 

For the purpose of part 75, calibration 

gases include the following: 

5.1.1 EPA Protocol Gases 

(a) An EPA Protocol Gas is a calibration gas 

mixture prepared and analyzed according to 

Section 2 of the ‘‘EPA Traceability Protocol 

for Assay and Certification of Gaseous 

Calibration Standards,’’ September 1997, 

EPA–600/R–97/121 or such revised 

procedure as approved by the Administrator 

(EPA Traceability Protocol). 

(b) An EPA Protocol Gas must have a 

specialty gas producer-certified uncertainty 

(95-percent confidence interval) that must 

not be greater than 2.0 percent of the certified 

concentration (tag value) of the gas mixture. 

The uncertainty must be calculated using the 

statistical procedures (or equivalent 

statistical techniques) that are listed in 

Section 2.1.8 of the EPA Traceability 

Protocol. 


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(c) A specialty gas producer advertising 

calibration gas certification with the EPA 

Traceability Protocol or distributing 

calibration gases as ‘‘EPA Protocol Gas’’ must 

participate in the EPA Protocol Gas 

Verification Program (PGVP) described in 

Section 2.1.10 of the EPA Traceability 

Protocol or it cannot use ‘‘EPA’’ in any form 

of advertising for these products, unless 

approved by the Administrator. A specialty 

gas producer may not certify a calibration gas 

as an EPA Protocol Gas unless it participates 

in the PGVP, unless approved by the 

Administrator. 

(d) A copy of EPA–600/R–97/121 is 

available from the National Technical 

Information Service, 5285 Port Royal Road, 

Springfield, VA, 703–605–6585 or http:// 

www.ntis.gov, and from http://www.epa.gov/ 

ttn/emc/news.html or http://www.epa.gov/ 

appcdwww/tsb/index.html. 

5.1.2 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. 

5.1.3 Zero Air Material 

(a) A calibration gas certified by the 

specialty gas producer or vendor not to 

contain concentrations of SO2, NOX, or total 

hydrocarbons above 0.1 parts per million 

(ppm), a concentration of CO above 1 ppm, 

or a concentration of CO2 above 400 ppm; 

(b) Ambient air conditioned and purified 

by a CEMS for which the CEMS manufacturer 

or vendor certifies that the particular CEMS 

model produces conditioned gas that does 

not contain concentrations of SO2, NOX, or 

total hydrocarbons above 0.1 ppm, a 

concentration of CO above 1 ppm, or a 

concentration of CO2 above 400 ppm; 

(c) For dilution-type CEMS, conditioned 

and purified ambient air provided by a 

conditioning system concurrently supplying 

dilution air to the CEMS; or 

(d) A multi-component mixture certified by 

the supplier of the mixture that the 

concentration of the component being zeroed 

is less than or equal to the applicable 

concentration specified in paragraph (a) of 

this section, and that the mixture’s other 

components do not interfere with the CEM 

readings. 

* * * * * 

6.1 General Requirements 

* * * * * 

6.1.2 Requirements for Air Emission Testing 

Bodies 

(a) Any Air Emission Testing Body (AETB) 

conducting relative accuracy test audits of 

CEMS and sorbent trap monitoring systems 

under this part must conform to the 

requirements of ASTM D7036–04. This 

section is not applicable to daily operation, 

daily calibration error checks, daily flow 

interference checks, quarterly linearity 

checks or routine maintenance of CEMS. 

(b) The AETB shall provide to the affected 

source(s) certification that the AETB operates 

in conformance with, and that data submitted 

to the Agency has been collected in 

accordance with, the requirements of ASTM 

D7036–04. This certification may be 

provided in the form of: 

(1) A certificate of accreditation of relevant 

scope issued by a recognized, national 

accreditation body; or 

(2) A letter of certification signed by a 

member of the senior management staff of the 

AETB. 

(c) The AETB shall either provide a 

Qualified Individual on-site to conduct or 

shall oversee all relative accuracy testing 

carried out by the AETB as required in ASTM 

D7036–04. The Qualified Individual shall 

provide the affected source(s) with copies of 

the qualification credentials relevant to the 

scope of the testing conducted. 

* * * * * 

6.2 Linearity Check (General Procedures) 

* * * Notwithstanding these 

requirements, if the SO2 or NOX span value 

for a particular monitor range is ≤30 ppm, 

that range is exempted from the linearity 

check requirements of this part, both for 

initial certification and for on-going qualityassurance. For units with two measurement 

ranges (high and low) for a particular 

parameter, perform a linearity check on both 

the low scale (except for SO2 or NOX span 

values ≤30 ppm) and the high scale. Note that 

for a NOX-diluent monitoring system with 

two NOX measurement ranges, if the low 

NOX scale has a span value ≤30 ppm and is 

exempt from linearity checks, this does not 

exempt either the diluent monitor or the high 

NOX scale (if the span is >30 ppm) from 

linearity check requirements. 

* * * * * 

(g) For Hg monitors, follow the guidelines 

in section 2.2.3 of this appendix in addition 

to the applicable procedures in section 6.2 

when performing the system integrity checks 

described in § 75.20(c)(1)(vi) and in sections 

2.1.1, 2.2.1 and 2.6 of appendix B to this part. 

(h) For Hg concentration monitors, if 

moisture is added to the calibration gas 

during the required linearity checks or 

system integrity checks, and if the Hg 

monitor measures on a dry basis, the 

moisture content of the calibration gas must 

be accounted for. Under these circumstances, 

the dry basis concentration of the calibration 

gas shall be used to calculate the linearity 

error or measurement error (as applicable). 

* * * * * 

6.3.1 Gas Monitor 7-Day Calibration Error 

Test 

* * * Also for Hg monitors, if moisture is 

added to the calibration gas and the 

monitoring system measures Hg 

concentration on a dry basis, the added 

moisture must be accounted for and the drybasis concentration of the calibration gas 

shall be used to calculate the calibration 

error. 

* * * * * 

6.4 Cycle Time Test 

Perform cycle time tests for each pollutant 

concentration monitor and continuous 

emission monitoring system while the unit is 

operating, according to the following 

procedures (see also Figure 6 at the end of 

this appendix). Use a zero-level and a highlevel calibration gas (as defined in section 5.2 

of this appendix) alternately. To determine 

the upscale elapsed time, inject a zero-level 

concentration calibration gas into the probe 

tip (or injection port leading to the 

calibration cell, for in situ systems with no 

probe). Record the stable starting gas value 

and start time, using the data acquisition and 

handling system (DAHS). Next, allow the 

monitor to measure the concentration of flue 

gas emissions until the response stabilizes. 

Record the stable ending stack emissions 

value and the end time of the test using the 

DAHS. Determine the upscale elapsed time 

as the time it takes for 95.0 percent of the 

step change to be achieved between the 

stable starting gas value and the stable ending 

stack emissions value. Then repeat the 

procedure, starting by injecting the high-level 

gas concentration to determine the 

downscale elapsed time, which is the time it 

takes for 95.0 percent of the step change to 

be achieved between the stable starting gas 

value and the stable ending stack emissions 

value. End the downscale test by measuring 

the stable concentration of flue gas 

emissions. Record the stable starting and 

ending monitor values, the start and end 

times, and the downscale elapsed time for 

the monitor using the DAHS. A stable value 

is equivalent to a reading with a change of 

less than 2.0 percent of the span value for 2 

minutes, or a reading with a change of less 

than 6.0 percent from the measured average 

concentration over 6 minutes. Alternatively, 

the reading is considered stable if it changes 

by no more than 0.5 ppm or 0.2% CO2 or O2

(as applicable) for two minutes. (Owners or 

operators of systems which do not record 

data in 1-minute or 3-minute intervals may 

petition the Administrator under § 75.66 for 

alternative stabilization criteria). For 

monitors or monitoring systems that perform 

a series of operations (such as purge, sample, 

and analyze), time the injections of the 

calibration gases so they will produce the 

longest possible cycle time. Report the slower 

of the two elapsed times (upscale or 

downscale) as the cycle time for the analyzer. 

(See Figure 5 at the end of this appendix.) 

Prior to January 1, 2009 for the NOX-diluent 

continuous emission monitoring system test, 

either record and report the longer cycle time 

of the two component analyzers as the 

system cycle time or record the cycle time for 

each component analyzer separately (as 

applicable). On and after January 1, 2009, 

record the cycle time for each component 

analyzer separately. For time-shared systems, 

perform the cycle time tests at each probe 

locations that will be polled within the same 

15-minute period during monitoring system 

operations. To determine the cycle time for 

time-shared systems, at each monitoring 

location, report the sum of the cycle time 


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observed at that monitoring location plus the 

sum of the time required for all purge cycles 

(as determined by the continuous emission 

monitoring system manufacturer) at each of 

the probe locations of the time-shared 

systems. For monitors with dual ranges, 

report the test results from on the range 

giving the longer cycle time. Cycle time test 

results are acceptable for monitor or 

monitoring system certification, 

recertification or diagnostic testing if none of 

the cycle times exceed 15 minutes. The status 

of emissions data from a monitor prior to and 

during a cycle time test period shall be 

determined as follows: 

* * * * * 

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 and CO2; 

Method 4 for moisture; Methods 6, 6A or 6C 

for SO2; Methods 7, 7A, 7C, 7D or 7E for 

NOX, excluding the exceptions of Method 7E 

identified in § 75.22(a)(5); and either the 

Ontario Hydro Method, Method 29 in 

appendix A–8 to part 60 of this chapter, or 

an approved instrumental method for Hg (see 

§ 75.22). 

* * * * * 

7.6 Bias Test and Adjustment Factor 

* * * * * 

7.6.1 * * * To calculate bias for a Hg 

monitoring system when using the Ontario 

Hydro Method or Method 29 in appendix A–

8 to part 60 of this chapter, ‘‘d’’ is, for each 

data point, the difference between the 

average Hg concentration value (in μg/m3) 

from the paired Ontario Hydro or Method 29 

sampling trains and the concentration 

measured by the monitoring system. For 

sorbent trap monitoring systems, use the 

average Hg concentration measured by the 

paired traps in the calculation of ‘‘d’’. 

* * * * * 

39. Appendix B to Part 75 is amended 

by: 

a. adding section 1.1.4; 

b. Revising section 2.1.1; 

c. Revising paragraph (2) of section 

2.1.1.2; 

d. Revising paragraph (2) of section 

2.1.5.1; 

e. Adding paragraph (3) to section 

2.1.5.1; 

f. Adding a new fourth sentence to 

paragraph (e) of section 2.2.3; 

g. Revising the words ‘‘scfh/ 

megawatts or scfh/1000 lb/hr of steam 

load’’ to read ‘‘scfh/megawatts, scfh/ 

1000 lb/hr of steam load, or scfh/ 

(mmBtu/hr thermal output)’’ at the end 

of the Rh variable definition, and by 

revising the words ‘‘megawatts or 1000 

lb/hr of steam’’ to read ‘‘megawatts, 

1000 lb/hr of steam, or mmBtu/hr 

thermal output’’ in the Lh variable 

definition, in paragraph (a) of section 

2.2.5; 

h. Revising the words Btu/kwh or 

Btu/lb steam load’’ to read ‘‘Btu/kwh, 

Btu/lb steam load, mmBtu heat input/ 

mmBtu thermal output’’ in the (GHR)h

variable definition, and by revising the 

words ‘‘megawatts or 1000 lb/hr of 

steam’’ to read ‘‘megawatts, 1000 lb/hr 

of steam, or mmBtu/hr thermal output’’

in the Lh variable definition, in 

paragraph (a)(2) of section 2.2.5; 

i. Replacing the word ‘‘five’’ with the 

word ‘‘twenty’’, and by replacing the 

word ‘‘years’’ with the word ‘‘quarters’’, 

in paragraph (c)(4) of section 2.3.1.3; 

j. Revising paragraph (g) of section 

2.3.2; 

k. Revising paragraphs (a)(2) and (c) of 

section 2.3.3; 

l. Adding paragraph (d) to section 

2.3.3; 

m. Revising section 2.6; and 

n. Replacing the term ‘‘dscm’’ with 

‘‘scm’’ in Figure 2. 

The revisions and additions read as 

follows: 

Appendix B to Part 75—Quality 

Assurance and Quality Control 

Procedures 

1. Quality Assurance/Quality Control 

Program 

* * * * * 

1.1.4 The requirements in section 6.1.2 of 

appendix A to this part shall be met by any 

Air Emissions Testing Body (AETB) 

performing the semiannual/annual RATAs 

described in section 2.3 of this appendix and 

the periodic Hg emission tests described in 

§§ 75.81(c)(1) and 75.81(d)(4)(iii). 

* * * * * 

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) 

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. When two measurement ranges 

(low and high) are required for a particular 

parameter, perform sufficient calibration 

error tests on each range to validate the data 

recorded on that range, according to the 

criteria in section 2.1.5 of this appendix. 

* * * * * 

2.1.1.2 * * * 

(2) For each monitoring system that has 

passed the off-line calibration demonstration, 

off-line calibration error tests may be used on 

a limited basis to validate data, in accordance 

with paragraph (2) in section 2.1.5.1 of this 

appendix. 

2.1.5.1 * * * 

(2) For a monitor that has passed the offline calibration demonstration, off-line 

calibration error tests may be used to validate 

data from the monitor for up to 26 

consecutive unit or stack operating hours, 

after which data from the monitor become 

invalid until an on-line calibration error test 

of the monitor is passed. Once the required 

on-line calibration error test has been passed, 

another 26 operating hour cycle of data 

validation using off-line calibration error 

tests may begin. Each off-line calibration 

error test that is used for data validation has 

a prospective data validation window of 26 

clock hours, as described in section 2.1.5 of 

this appendix. If the sequence of consecutive 

operating hours validated by off-line 

calibrations is broken before reaching the 

26th consecutive unit or stack operating 

hour, data from the monitor become invalid 

and an on-line calibration error test must be 

passed to re-establish the quality-assured 

data status. The sequence is considered 

broken when a unit or stack operating hour 

is not contained within the 26 clock hour 

data validation window of a passed off-line 

calibration error test. 

(3) For units with two measurement ranges 

(low and high) for a particular parameter, 

when separate analyzers are used for the low 

and high ranges, a failed or expired 

calibration on one of the ranges does not 

affect the quality-assured data status on the 

other range. For a dual-range analyzer (i.e., a 

single analyzer with two measurement 

scales), a failed calibration error test on either 

the low or high scale results in an out-ofcontrol period for the monitor. Data from the 

monitor remain invalid until corrective 

actions are taken and ‘‘hands-off’’ calibration 

error tests have been passed on both ranges. 

However, if the most recent calibration error 

test on the high scale has expired, while the 

low scale is up-to-date on its calibration error 

test requirements (or vice-versa), the expired 

calibration error test does not affect the 

quality-assured status of the data recorded on 

the other scale. 

* * * * * 

2.2.3 * * * 

(e) * * * For a dual-range analyzer, 

‘‘hands-off’’ linearity checks must be passed 

on both measurement scales to end the outof-control period. 

* * * * * 

2.3.2 * * * 

(g) Data validation for failed RATAs for a 

CO2 pollutant concentration monitor (or an 

O2 monitor used to measure CO2 emissions), 

a NOX pollutant concentration monitor, and 

a NOX-diluent monitoring system shall be 

done according to paragraphs (g)(1) and (g)(2) 

of this section: 

(1) For a CO2 pollutant concentration 

monitor (or an O2 monitor used to measure 

CO2 emissions) which also serves as the 

diluent component in a NOX-diluent 

monitoring system, if the CO2 (or O2) RATA 

is failed, then both the O2 (or O2) monitor 

and the associated NOX-diluent system are 

considered out-of-control, beginning with the 

hour of completion of the failed CO2 (or O2) 

monitor RATA, and continuing until the 

hour of completion of subsequent hands-off 

RATAs which demonstrate that both systems 


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49302 Federal Register / Vol. 71, No. 162 / Tuesday, August 22, 2006 / Proposed Rules 

have met the applicable relative accuracy 

specifications in sections 3.3.2 and 3.3.3 of 

appendix A to this part, unless the option in 

paragraph (b)(3) of this section to use the data 

validation procedures and associated 

timelines in §§ 75.20(b)(3)(ii) through 

(b)(3)(ix) has been selected, in which case the 

beginning and end of the out-of-control 

period shall be determined in accordance 

with §§ 75.20(b)(3)(vii)(A) and (B). 

(2) This paragraph (g)(2) applies only to a 

NOX pollutant concentration monitor that 

serves both as the NOX component of a NOX

concentration monitoring system (to measure 

NOX mass emissions) and as the NOX

component in a NOX-diluent monitoring 

system (to measure NOX emission rate in lb/ 

mmBtu). If the RATA of the NOX

concentration monitoring system is failed, 

then both the NOX concentration monitoring 

system and the associated NOX-diluent 

monitoring system are considered out-ofcontrol, beginning with the hour of 

completion of the failed NOX concentration 

RATA, and continuing until the hour of 

completion of subsequent hands-off RATAs 

which demonstrate that both systems have 

met the applicable relative accuracy 

specifications in sections 3.3.2 and 3.3.7 of 

appendix A to this part, unless the option in 

paragraph (b)(3) of this section to use the data 

validation procedures and associated 

timelines in §§ 75.20(b)(3)(ii) through 

(b)(3)(ix) has been selected, in which case the 

beginning and end of the out-of-control 

period shall be determined in accordance 

with §§ 75.20(b)(3)(vii)(A) and (B). 

* * * * * 

2.3.3 RATA Grace Period 

(a) * * * 

(2) A required 3-load flow RATA has not 

been performed by the end of the calendar 

quarter in which it is due; or 

* * * * * 

(c) If, at the end of the 720 unit (or stack) 

operating hour grace period, the RATA has 

not been completed, data from the 

monitoring system shall be invalid, 

beginning with the first unit operating hour 

following the expiration of the grace period. 

Data from the CEMS remain invalid until the 

hour of completion of a subsequent hands-off 

RATA. The deadline for the next test shall be 

either two QA operating quarters (if a 

semiannual RATA frequency is obtained) or 

four QA operating quarters (if an annual 

RATA frequency is obtained) after the quarter 

in which the RATA is completed, not to 

exceed eight calendar quarters. 

* * * * * 

(d) When a RATA is done during a grace 

period in order to satisfy a RATA 

requirement from a previous quarter, the 

deadline for the next RATA shall be 

determined as follows: 

(1) If the grace period RATA qualifies for 

a reduced, (i.e., annual), RATA frequency the 

deadline for the next RATA shall be set at 

three QA operating quarters after the quarter 

in which the grace period test is completed. 

(2) If the grace period RATA qualifies for 

the standard, (i.e., semiannual), RATA 

frequency the deadline for the next RATA 

shall be set at two QA operating quarters after 

the quarter in which the grace period test is 

completed. 

(3) Notwithstanding these requirements, no 

more than eight successive calendar quarters 

shall elapse after the quarter in which the 

grace period test is completed, without a 

subsequent RATA having been conducted. 

* * * * * 

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 

specifications in paragraph (3) of section 3.2 

of appendix A to this part must be met, 

otherwise the monitoring system is 

considered out-of-control, from the hour of 

the failed check until a subsequent system 

integrity check is passed. If a required system 

integrity check is not performed and passed 

within 168 unit or stack operating hours of 

last successful check, the monitoring system 

shall also be considered out of control, 

beginning with the 169th unit or stack 

operating hour after the last successful check, 

and continuing 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. 

* * * * * 

40. Appendix D to Part 75 is amended 

by: 

a. Revising section 2.1.5.1; 

b. Removing all ‘‘±’’ symbols from 

paragraph (c) of section 2.1.6.1; 

c. Revising the Rbase and Lavg variable 

definitions in paragraph (a) of section 

2.1.7.1; 

d. Revising the words ‘‘Btu/kwh or 

Btu/lb steam load’’ to read ‘‘Btu/kwh, 

Btu/lb steam load, or mmBtu heat input/ 

mmBtu thermal output’’ in the (GHR)base

variable definition, and by revising the 

words ‘‘megawatts or 1000 lb/hr of 

steam’’ to read ‘‘megawatts, 1000 lb/hr 

of steam, or mmBtu/hr thermal output’’

in the Lavg variable definition, in 

paragraph (c) of section 2.1.7.1; 

e. Removing the word ‘‘or’’ and 

adding the phrase’’,100 scfh/(mmBtu/hr 

of steam load), or (lb/hr)/(mmBtu/hr 

thermal output )’’ at the end of the Rh

variable definition, and by replacing the 

phrase ‘‘megawatts or 1000 lb/hr of 

steam’’ with the phrase ‘‘megawatts, 

1000 lb/hr of steam, or mmBtu /hr 

thermal output’’ in the Lh variable 

definition, in paragraph (a) of section 

2.1.7.2; 

f. Replacing the phrase the ‘‘Btu/kwh 

or Btu/lb steam load’’ with the phrase 

‘‘Btu/kwh, Btu/lb steam load, or mmBtu 

heat input/mmBtu thermal output’’ in 

the (GHR)h variable definition; and by 

replacing the phrase ‘‘megawatts or 

1000 lb/hr of steam’’ with the phrase 

‘‘megawatts, 1000 lb/hr of steam, or 

mmBtu/hr thermal output’’ in the Lh

variable definition, in paragraph (c) of 

section 2.1.7.2; 

g. Replacing ‘‘D4177–82 (Reapproved 

1990)’’ with ‘‘D4177–95 (2000)’’, in the 

first sentence of section 2.2.3; 

h. Replacing ‘‘D4057–88’’ with 

‘‘D4057–95 (2000)’’, in sections 2.2.4.1 

and 2.2.4.2, and in paragraph (c) of 

section 2.2.4.3; 

i. Revising sections 2.2.5, 2.2.6, and 

2.2.7; 

j. Revising paragraphs (a)(2) and (e) of 

section 2.3.1.4; 

k. Revising section 2.3.3.1.2; 

l. Replacing the identifier ‘‘D1826–

88’’ with the identifier ‘‘D1826–94 

(1998)’’, by replacing the identifier 

‘‘D3588–91’’ with the identifier 

‘‘D3588–98’’, by adding the number 

‘‘(2001)’’ after the identifier ‘‘ASTM 

D4891–89’’, by replacing the numbers 

‘‘2172–86’’ with the numbers ‘‘2172–

1996’’, and by replacing the numbers 

‘‘2261–90’’ with the numbers ‘‘2261–

1999’’, in section 2.3.4; 

m. Adding two sentences at the end 

of section 2.3.4.1; 

n. Replacing the phrase ‘‘Gas Total 

Sulfur Content’’ in the ‘‘Parameter’’

column of Table D–6 with the phrase 

‘‘Gas Total Sulfur Content*’’, and 

adding the following footnote beneath 

the Table ‘‘ * Required no later than July 

1, 2003’’; and 

o. Replacing the words ‘‘(Reapproved 

1990)’’ with the words ‘‘(1997)e1’’ in 

section 3.2.2. 

The revisions and additions read as 

follows: 

Appendix D to Part 75—Optional SO2

Emissions Data Protocol for Gas-Fired 

and Oil-Fired Units. 

2. Procedure 

* * * * * 

2.1.5.1 Use the procedures in the 

following standards to verify flowmeter 

accuracy or design, as appropriate to the type 

of flowmeter: ASME MFC–3M–1989 

(Reaffirmed 1995) (‘‘Measurement of Fluid 

Flow in Pipes Using Orifice, Nozzle, and 

Venturi’’); ASME MFC–4M–1986 (Reaffirmed 

1990), ‘‘Measurement of Gas Flow by Turbine 

Meters;’’ American Gas Association Report 

No. 3, ‘‘Orifice Metering of Natural Gas and 

Other Related Hydrocarbon Fluids Part 1: 

General Equations and Uncertainty 

Guidelines’’ (October 1990 Edition), Part 2: 

‘‘Specification and Installation 

Requirements’’ (February 1991 Edition), and 

Part 3: ‘‘Natural Gas Applications’’ (August 

1992 edition) (excluding the modified flowcalculation method in part 3); Section 8, 

Calibration from American Gas Association 

Transmission Measurement Committee 

Report No. 7: Measurement of Gas by Turbine 

Meters (Second Revision, April 1996); ASME 


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MFC–5M–1985 (Reaffirmed 2001) 

(‘‘Measurement of Liquid Flow in Closed 

Conduits Using Transit-Time Ultrasonic 

Flowmeters’’); ASME MFC–6M–1998 

(‘‘Measurement of Fluid Flow in Pipes Using 

Vortex Flow Meters’’); ASME MFC–7M–1987 

(Reaffirmed 2001), ‘‘Measurement of Gas 

Flow by Means of Critical Flow Venturi 

Nozzles;’’ ISO 8316: 1987(E) ‘‘Measurement 

of Liquid Flow in Closed Conduits-Method 

by Collection of the Liquid in a Volumetric 

Tank;’’ American Petroleum Institute (API) 

Manual of Measurement Standards, Chapter 

4: Section 2, ‘‘Conventional Pipe Provers’’

(Provers Accumulating at Least 10,000 

Pulses), Measurement Coordination (Second 

Edition, March 2001), Section 3, ‘‘Small 

Volume Provers’’ (First Edition), and Section 

5, ‘‘Master-Meter Provers’’, Measurement 

Coordination (Second Edition, May 2000); 

API Manual of Petroleum Measurement 

Standards, Chapter 22—Testing Protocol: 

Section 2—Differential Pressure Flow 

Measurement Devices (First Edition, August 

2005); or ASME MFC–9M–1988 (Reaffirmed 

2001) (‘‘Measurement of Liquid Flow in 

Closed Conduits by Weighing Method’’), for 

all other flowmeter types (incorporated by 

reference under § 75.6). The Administrator 

may also approve other procedures that use 

equipment traceable to National Institute of 

Standards and Technology standards. 

Document such procedures, the equipment 

used, and the accuracy of the procedures in 

the monitoring plan for the unit, and submit 

a petition signed by the designated 

representative under § 75.66(c). If the 

flowmeter accuracy exceeds 2.0 percent of 

the upper range value, the flowmeter does 

not qualify for use under this part. 

* * * * * 

2.1.7.1(a) * * * 

Where: 

Rbase = Value of the fuel flow rate-to-load 

ratio during the baseline period; 100 scfh/ 

MWe, 100 scfh/klb per hour steam load, or 

100 scfh/mmBtu per hour thermal output 

for gas-firing; (lb/hr)/MWe, (lb/hr)/klb per 

hour steam load, or (lb/hr)/mmBtu per 

hour thermal output for oil-firing. 

* * * * * 

Lavg = Arithmetic average unit load during 

the baseline period, megawatts, 1000 lb/hr 

of steam, or mmBtu/hr thermal output. 

* * * * * 

2.2.5 For each oil sample that is taken onsite at the affected facility, split and label the 

sample and maintain a portion (at least 200 

cc) of it throughout the calendar year and in 

all cases for not less than 90 calendar days 

after the end of the calendar year allowance 

accounting period. This requirement does not 

apply to oil samples taken from the fuel 

supplier’s storage container, as described in 

section 2.2.4.3 of this appendix. Analyze oil 

samples for percent sulfur content by weight 

in accordance with ASTM D129–00, 

‘‘Standard Test Method for Sulfur in 

Petroleum Products (General Bomb 

Method),’’ ASTM D1552–01, ‘‘Standard Test 

Method for Sulfur in Petroleum Products 

(High Temperature Method),’’ ASTM D2622–

98, ‘‘Standard Test Method for Sulfur in 

Petroleum Products by X-Ray Spectrometry,’’

or ASTM D4294–98, ‘‘Standard Test Method 

for Sulfur in Petroleum Products by EnergyDispersive X-Ray Fluorescence 

Spectroscopy’’ (incorporated by reference 

under § 75.6). 

2.2.6 Where the flowmeter records 

volumetric flow rate rather than mass flow 

rate, analyze oil samples to determine the 

density or specific gravity of the oil. 

Determine the density or specific gravity of 

the oil sample in accordance with ASTM 

D287–92(2000)e1, ‘‘Standard Test Method for 

API Gravity of Crude Petroleum and 

Petroleum Products (Hydrometer Method),’’

ASTM D1217–93(1998), ‘‘Standard Test 

Method for Density and Relative Density 

(Specific Gravity) of Liquids by Bingham 

Pycnometer,’’ ASTM D1481–93 (1997), 

‘‘Standard Test Method for Density and 

Relative Density (Specific Gravity) of Viscous 

Materials by Lipkin Bicapillary,’’ ASTM 

D1480–93 (1997), ‘‘Standard Test Method for 

Density and Relative Density (Specific 

Gravity) of Viscous Materials by Bingham 

Pycnometer,’’ ASTM D1298–99, ‘‘Standard 

Practice for Density, Relative Density 

(Specific Gravity) or API Gravity of Crude 

Petroleum and Liquid Petroleum Products by 

Hydrometer Method,’’ or ASTM D4052–96 

(2002)e1, ‘‘Standard Test Method for Density 

and Relative Density of Liquids by Digital 

Density Meter’’ (incorporated by reference 

under § 75.6). 

2.2.7 Analyze oil samples to determine 

the heat content of the fuel. Determine oil 

heat content in accordance with ASTM 

D240–00 (Reapproved 1991), ‘‘Standard Test 

Method for Heat of Combustion of Liquid 

Hydrocarbon Fuels by Bomb Calorimeter,’’

ASTM D4809–00, ‘‘Standard Test Method for 

Heat of Combustion of Liquid Hydrocarbon 

Fuels by Bomb Calorimeter (Precision 

Method),’’ or ASTM D5865–01ae1, ‘‘Standard 

Test Method for Gross Calorific Value of Coal 

and Coke’’ (incorporated by reference under 

§ 75.6) or any other procedures listed in 

section 5.5 of appendix F of this part. 

* * * * * 

2.3.1.4 * * * 

(a) * * * 

(2) Historical fuel sampling data for the 

previous 12 months, documenting the total 

sulfur content of the fuel and the GCV and/ 

or percentage by volume of methane. The 

results of all sample analyses obtained by or 

provided to the owner or operator in the 

previous 12 months shall be used in the 

demonstration, and each sample result must 

meet the definition of pipeline natural gas in 

§ 72.2 of this chapter, except where the 

results of at least 100 daily (or more frequent) 

total sulfur samples are provided by the fuel 

supplier. In that case you may convert these 

data to monthly averages and then if, for each 

month, the average total sulfur content is 0.5 

grains/100 scf or less, and if the GCV or 

percent methane requirement is also met, the 

fuel qualifies as pipeline natural gas. 

Alternatively, the fuel qualifies as pipeline 

natural gas if the GCV or percent methane 

requirement is met and if ≥ 98 percent of the 

100 (or more) samples have a total sulfur 

content of 0.5 grains/100 scf or less; or 

* * * * * 

(e) If a fuel qualifies as pipeline natural gas 

based on the specifications in a fuel contract 

or tariff sheet, no additional, on-going 

sampling of the fuel’s total sulfur content is 

required, provided that the contract or tariff 

sheet is current, valid and representative of 

the fuel combusted in the unit. If the fuel 

qualifies as pipeline natural gas based on fuel 

sampling and analysis, on-going sampling of 

the fuel’s sulfur content is required annually 

and whenever the fuel supply source 

changes. For the purposes of this paragraph, 

(e), sampling ‘‘annually’’ means that at least 

one sample is taken in each calendar year. If 

the results of at least 100 daily (or more 

frequent) total sulfur samples have been 

provided by the fuel supplier since the last 

annual assessment of the fuel’s sulfur 

content, the data may be used to satisfy the 

annual sampling requirement for the current 

year. If this option is chosen, all of the data 

provided by the fuel supplier shall be used. 

First, convert the data to monthly averages. 

Then, if, for each month, the average total 

sulfur content is 0.5 grains/100 scf or less, 

and if the GCV or percent methane 

requirement is also met, the fuel qualifies as 

pipeline natural gas. Alternatively, the fuel 

qualifies as pipeline natural gas if the GCV 

or percent methane requirement is met and 

if the analysis of the 100 (or more) total 

sulfur samples since the last annual 

assessment shows that > 98 percent of the 

samples have a total sulfur content of 0.5 

grains/100 scf or less. The effective date of 

the annual total sulfur sampling requirement 

is January 1, 2003. 

* * * * * 

2.3.3.1.2 Use one of the following 

methods when using manual sampling (as 

applicable to the type of gas combusted) to 

determine the sulfur content of the fuel: 

ASTM D1072–90(1999), ‘‘Standard Test 

Method for Total Sulfur in Fuel Gases,’’

ASTM D4468–85 (2000) ‘‘Standard Test 

Method for Total Sulfur in Gaseous Fuels by 

Hydrogenolysis and Radiometric 

Colorimetry,’’ ASTM D5504–01 ‘‘Standard 

Test Method for Determination of Sulfur 

Compounds in Natural Gas and Gaseous 

Fuels by Gas Chromatography and 

Chemiluminescence,’’ ASTM D6667–04 

‘‘Standard Test Method for Determination of 

Total Volatile Sulfur in Gaseous 

Hydrocarbons and Liquified Petroleum Gases 

by Ultraviolet Fluorescence,’’ or ASTM 

D3246–96 ‘‘Standard Test Method for Sulfur 

in Petroleum Gas By Oxidative 

Microcoulometry’’ (incorporated by reference 

under § 75.6). 

* * * * * 

2.3.4.1 GCV of Pipeline Natural Gas 

* * * If multiple GCV samples are taken 

and analyzed in a particular month, the GCV 

values from all samples shall be averaged 

arithmetically to obtain the monthly GCV. 

Then, for the purposes of implementing 

paragraph (c) in section 2.3.7 of this 

appendix, consider the latest date of any of 

the individual GCV samples used in the 

monthly average to be the ‘‘date on which the 

sample was taken’’. 

* * * * * 

41. Appendix E to Part 75 is amended 

by: 

a. Adding a new sentence to the end 

of section 2.1; 


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b. Replacing the words ‘‘section 5.1’’

with the words ‘‘section 8.3.1’’ in 

section 2.1.2.1; 

c. Replacing the phrase ‘‘(MWge or 

steam load in 1000 lb/hr)’’ with the 

phrase ‘‘(MWge or steam load in 1000 

lb/hr, or mmBtu/hr thermal output)’’, in 

section 2.4.1; 

d. Revising section 2.5.2; and 

e. Adding section 2.5.2.4. 

The revisions and additions read as 

follows: 

Appendix E to Part 75—Optional NOX

Emissions Estimation Protocol for GasFired Peaking Units and Oil-Fired 

Peaking Units. 

* * * * * 

2.1 Initial Performance Testing 

* * * The requirements in section 6.1.2 of 

appendix A to this part shall be met by any 

Air Emissions Testing Body (AETB) 

performing O2 and NOX concentration 

measurements under this appendix, either for 

units using the excepted methodology in this 

appendix or for units using the low mass 

emissions excepted methodology in § 75.19. 

* * * * * 

2.5.2 Substitute missing NOX emission 

rate data using the highest NOX emission rate 

tabulated during the most recent set of 

baseline correlation tests for the same fuel or, 

if applicable, combination of fuels, except as 

provided in sections 2.5.2.1, 2.5.2.2, 2.5.2.3, 

and 2.5.2.4 of this section. 

* * * * * 

2.5.2.4 Whenever 20 full calendar 

quarters have elapsed following the quarter 

of the last baseline correlation test for a 

particular type of fuel (or fuel mixture), 

without a subsequent baseline correlation 

test being done for that type of fuel (or fuel 

mixture), substitute the fuel-specific NOX

MER (as defined in § 72.2 of this chapter) for 

each hour in which that fuel (or mixture) is 

combusted until a new baseline correlation 

test for that fuel (or mixture) has been 

successfully completed. For fuel mixtures, 

report the highest of the individual MER 

values for the components of the mixture. 

42. Appendix F to Part 75 is amended 

by: 

a. Removing the second and third 

sentences from the introductory text of 

section 2; 

b. Replacing the phrase ‘‘method 19 in 

appendix A of part 60 of this chapter’’

with the phrase ‘‘Method 19 in 

appendix A–7 to part 60 of this 

chapter’’, in the last sentence of section 

3.1 and in the last sentence of section 

3.2; 

c. Adding the phrase ‘‘, or (if 

applicable) in the equations in Method 

19 in appendix A–7 to part 60 of this 

chapter’’ after the words ‘‘of this 

appendix’’, in section 3.3; 

d. Removing the second and third 

sentences from section 3.3.4; 

e. Adding sections 3.3.4.1 and 3.3.4.2; 

f. Revising Table 1; 

g. Revising the text preceding 

Equation F–7a, in section 3.3.6; 

h. Adding ‘‘(1997)e1’’ after the 

identifier ‘‘D3176–89’’, by replacing the 

identifier ‘‘D5291–92’’ with the 

identifier ‘‘D5291–01’’, by replacing the 

identifier ‘‘D1945–91’’ with the 

identifier ‘‘D1945–96 (2001)’’, and by 

adding the number ‘‘(2000)’’ after the 

identifier ‘‘D1946–90’’, in section 

3.3.6.1; 

i. Revising section 3.3.6.2; 

j. Revising the definition of ‘‘Xi’’

under Equation F–8 in section 3.3.6.4; 

k. Adding the words ‘‘either measured 

directly with a CO2 monitor or 

calculated from wet-basis O2 data using 

Equation F–14b,’’ after the words ‘‘wet 

basis,’’ in the first sentence of the Ch

variable definition, and by removing the 

second and third sentences from the Ch

variable definition, in section 4.1; 

l. Revising section 4.4.1; 

m. Removing the second and third 

sentences from the %CO2w variable 

definition in 5.2.1; 

n. Removing the second and third 

sentences from the %CO2d variable 

definition in 5.2.2; 

o. Removing the second and third 

sentences from the %O2w variable 

definition, and by adding a new 

sentence at the end of the paragraph, in 

section 5.2.3; 

p. Removing the second and third 

sentences from the %O2d variable 

definition, in section 5.2.4; 

q. Replacing the identifier ‘‘D240–87’’

with the identifier ‘‘D240–00’’, by 

replacing the identifier ‘‘D2015–91’’

with the identifier ‘‘D5865–01ae1’’, and 

by replacing the identifier ‘‘D2382–88’’

with the identifier ‘‘D4809–00’’ in the 

GCVO variable definition, in section 

5.5.1; 

r. Replacing the identifier ‘‘D1826–

88’’ with the identifier ‘‘D1826–94 

(1998)’’, by replacing the identifier 

‘‘D3588–91’’ with the identifier 

‘‘D3588–98’’, by adding the number 

‘‘(2001)’’ after the identifier ‘‘D4891–

89’’, by replacing the numbers ‘‘2172–

86’’ with the numbers ‘‘2172–1996’’, 

and by replacing the numbers ‘‘2261–

90’’ with the numbers ‘‘2261–1999’’ in 

the GCVg variable definition, in section 

5.5.2; 

s. Replacing each identifier ‘‘D2234–

89’’ with the identifier ‘‘D2234–00e1’’, 

in section 5.5.3.1; 

t. Revising section 5.5.3.2; 

u. Revising the words ‘‘as measured 

by ASTM D3176–89, D1989–92, D3286–

91a, or D2015–91, Btu/lb’’ to read ‘‘as 

measured by ASTM D3176–89 (1997)e1, 

or D5865ae1, Btu/lb.’’ in the definition 

of the GCVc variable in Equation F–21; 

v. Revising the word ‘‘lb/hr’’ to read 

‘‘lb/hr, or mmBtu/hr’’ in the definition 

of the SF variable in Equation F–21b; 

w. Revising the title and text of 

section 7; 

x. Adding the words ‘‘of this 

appendix’’ after the words ‘‘section 8.1, 

8.2, or 8.3’’ and after the words ‘‘section 

8.4’’ in the introductory text for section 

8; 

y. Revising sections 8.1 and 8.1.1; 

z. Revising section 8.2; 

aa. Adding sections 8.2.1 and 8.2.2; 

bb. Revising section 8.3; 

cc. Revising section 8.4; and 

dd. Adding section 10. 

The revisions and additions read as 

follows: 

Appendix F to Part 75—Conversion 

Procedures 

* * * * * 

3.3.4 * * * 

3.3.4.1 For boilers, a minimum 

concentration of 5.0 percent CO2 or a 

maximum concentration of 14.0 percent O2

may be substituted for the measured diluent 

gas concentration value for any operating 

hour in which the hourly average CO2

concentration is <5.0 percent CO2 or the 

hourly average O2 concentration is >14.0 

percent O2. For stationary gas turbines, a 

minimum concentration of 1.0 percent CO2

or a maximum concentration of 19.0 percent 

O2 may be substituted for measured diluent 

gas concentration values for any operating 

hour in which the hourly average CO2

concentration is <1.0 percent CO2 or the 

hourly average O2 concentration is >19.0 

percent O2. 

3.3.4.2 If NOX emission rate is calculated 

using either Equation 19–3 or 19–5 in 

Method 19 in appendix A–7 to part 60 of this 

chapter, a variant of the equation shall be 

used whenever the diluent cap is applied. 

The modified equations shall be designated 

as Equations 19–3D and 19–5D, respectively. 

Equation 19–3D is structurally the same as 

Equation 19–3, except that the term ‘‘%O2w’’

in the denominator is replaced with the term 

‘‘%O2dc × [(100¥% H2O)/100]’’, where %O2dc

is the diluent cap value. The numerator of 

Equation 19–5D is the same as Equation 19–

5; however, the denominator of Equation 19–

5D is simply ‘‘20.9¥%O2dc’’, where %O2dc is 

the diluent cap value. 

* * * * * 


rwilkins on PROD1PC63 with PROPOSAL
Federal Register / Vol. 71, No. 162 / Tuesday, August 22, 2006 / Proposed Rules 49305 

TABLE 1.—F AND FC-FACTORS 1

Fuel F-factor 

(dscf/mmBtu) 

FC-factor 

(scf CO2/ 

mmBtu) 

Coal (as defined by ASTM D388–99e1): 

Anthracite .......................................................................................................................................................... 10,100 1,970 

Bituminous ........................................................................................................................................................ 9,780 1,800 

Sub-bituminous ................................................................................................................................................. 9,819 1,840 

Lignite ............................................................................................................................................................... 9,860 1,910 

Petroleum Coke ....................................................................................................................................................... 9,832 1,853 

Tire Derived Fuel 1 .................................................................................................................................................. 10,261 1,803 

Oil ............................................................................................................................................................................. 9,190 1,420 

Gas: 

Natural gas ....................................................................................................................................................... 8,710 1,040 

Propane ............................................................................................................................................................ 8,710 1,190 

Butane .............................................................................................................................................................. 8,710 1,250 

Wood: 

Bark .................................................................................................................................................................. 9,600 1,920 

Wood residue ................................................................................................................................................... 9,240 1,830 

1 Determined at standard conditions: 20 °C (68 °F) and 29.92 inches of mercury. 

* * * * * 

3.3.6 Equations F–7a and F–7b may be 

used in lieu of the F or Fc factors specified 

in Section 3.3.5 of this appendix to calculate 

a site-specific dry-basis F factor (dscf/ 

mmBtu) or a site-specific Fc factor (scf CO2/ 

mmBtu), on either a dry or wet basis. At a 

minimum, the site-specific F or Fc factor 

must be based on 9 samples of the fuel. Fuel 

samples taken during each run of a RATA are 

acceptable for this purpose. The site-specific 

F or Fc factor must be re-determined at least 

annually, and the value from the most recent 

determination must be used in the emission 

calculations. Alternatively, the previous F or 

Fc value may continue to be used if it is 

higher than the value obtained in the most 

recent determination. The owner or operator 

shall keep records of all site-specific F or Fc

determinations, active for at least 3 years. 

(Calculate all F- and Fc factors at standard 

conditions of 20 °C (68 °F) and 29.92 inches 

of mercury). 

* * * * * 

3.3.6.2 GCV is the gross calorific value 

(Btu/lb) of the fuel combusted determined by 

ASTM D5865–01ae1 ‘‘Standard Test Method 

for Gross Calorific Value of Coal and Coke’’, 

and ASTM D240–00 ‘‘Standard Test Method 

for Heat of Combustion of Liquid 

Hydrocarbon Fuels by Bomb Calorimeter’’, or 

ASTM D4809–00, ‘‘Standard Test Method for 

Heat of Combustion of Liquid Hydrocarbon 

Fuels by Bomb Calorimeter (Precision 

Method) for oil; and ASTM D3588–98 

‘‘Standard Practice for Calculating Heat 

Value, Compressibility Factor, and Relative 

Density (Specific Gravity) of Gaseous Fuels,’’

ASTM D4891–89 (2001) ‘‘Standard Test 

Method for Heating Value of Gases in Natural 

Gas Range by Stoichiometric Combustion,’’

GPA Standard 2172–1996 ‘‘Calculation of 

Gross Heating Value, Relative Density and 

Compressibility Factor for Natural Gas 

Mixtures from Compositional Analysis,’’

GPA Standard 2261–1999 ‘‘Analysis for 

Natural Gas and Similar Gaseous Mixtures by 

Gas Chromatography,’’ or ASTM D1826–94 

(1998), ‘‘Standard Test Method for Calorific 

(Heating) Value of Gases in Natural Gas 

Range by Continuous Recording Calorimeter’’

for gaseous fuels, as applicable. (These 

methods are incorporated by reference under 

§ 75.6). 

* * * * * 

3.3.6.4 * * * 

Xi = Fraction of total heat input derived from 

each type of fuel (e.g., natural gas, 

bituminous coal, wood). Each Xi value 

shall be determined from the best available 

information on the quantity of fuel 

combusted and the GCV value, over a 

specified time period. The owner or 

operator shall explain the method used to 

calculate Xi in the hardcopy portion of the 

monitoring plan for the unit. The Xi values 

may be determined and updated either 

hourly, daily, weekly, or monthly. In all 

cases, the prorated F-factor used in the 

emission calculations shall be determined 

using the Xi values from the most recent 

update. 

* * * * * 

4. Procedure for CO2 Mass Emissions 

* * * * * 

4.4.1 If the owner or operator elects to use 

data from an O2 monitor to calculate CO2

concentration, the appropriate F and FC

factors from section 3.3.5 of this appendix 

shall be used in one of the following 

equations (as applicable) to determine hourly 

average CO2 concentration of flue gases (in 

percent by volume) from the measured 

hourly average O2 concentration: 

CO F

F

O Eq d

c d

2

2 100 20 9 = − ( ) . . 20.9

 F-14a

Where: 

CO2d = Hourly average CO2 concentration 

during unit operation, percent by volume, 

dry basis. 

F, FC = F-factor or carbon-based Fc-factor 

from section 3.3.5 of this appendix. 

20.9 = Percentage of O2 in ambient air. 

O2d = Hourly average O2 concentration 

during unit operation, percent by volume, 

dry basis. 

CO F

F

H O O Eq w

c

2 w

2

2

100 20 9 100

100 =  −



 



 − 



 



 ( 20.9 . F-14b % . )

Where: CO2w = Hourly average CO2 concentration 

during unit operation, percent by volume, 

wet basis. 

O2w = Hourly average O2 concentration 

during unit operation, percent by volume, 

wet basis. 


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F, Fc = F-factor or carbon-based FC-factor 

from section 3.3.5 of this appendix. 

20.9 = Percentage of O2 in ambient air. 

%H2O = Moisture content of gas in the stack, 

percent. 

For any hour where Equation F–14b results 

in a negative hourly average CO2 value, 0.0% 

CO2w shall be recorded as the average CO2

value for that hour. 

* * * * * 

5. Procedures for Heat Input 

* * * * * 

5.2.3 * * * 

For any hour where Equation F–17 results 

in a negative hourly heat input rate, 1.0 

mmBtu/hr shall be recorded and reported as 

the heat input rate for that hour. 

* * * * * 

5.5.3.2 Use ASTM D2013–01, ‘‘Standard 

Method of Preparing Coal Samples for 

Analysis,’’ for preparation of a daily coal 

sample and analyze each daily coal sample 

for gross calorific value using ASTM D5865–

01ae1, ‘‘Standard Test Method for Gross 

Calorific Value of Coal and Coke’’ (All ASTM 

methods are incorporated by reference under 

§ 75.6 of this part.) 

On-line coal analysis may also be used if 

the on-line analytical instrument has been 

demonstrated to be equivalent to the 

applicable ASTM methods under §§ 75.23 

and 75.66. 

* * * * * 

7. Procedures for SO2 Mass Emissions, Using 

Default SO2 Emission Rates and Heat Input 

Measured by CEMS 

The owner or operator shall use Equation 

F–23 to calculate hourly SO2 mass emissions 

in accordance with § 75.11(e)(1) during the 

combustion of gaseous fuel, for a unit that 

uses a flow monitor and a diluent gas 

monitor to measure heat input, and that 

qualifies to use a default SO2 emission rate 

under section 2.3.1.1, 2.3.2.1.1, or 2.3.6(b) of 

appendix D to this part. Equation F–23 may 

also be applied to the combustion of solid or 

liquid fuel that meets the definition of very 

low sulfur fuel in § 72.2 of this chapter, 

combinations of such fuels, or mixtures of 

such fuels with gaseous fuel, if the owner or 

operator has received approval from the 

Administrator under § 75.66 to use a sitespecific default SO2 emission rate for the fuel 

or mixture of fuels. 

E ER HI Eq h = ( )( ) ( ) . F-23

Where: 

Eh = Hourly SO2 mass emission rate, lb/hr. 

ER = Applicable SO2 default emission rate for 

gaseous fuel combustion, from section 

2.3.1.1, 2.3.2.1.1, or 2.3.6(b) of appendix D 

to this part, or other default SO2 emission 

rate for the combustion of very low sulfur 

liquid or solid fuel, combinations of such 

fuels, or mixtures of such fuels with 

gaseous fuel, as approved by the 

Administrator under § 75.66, lb/mmBtu. 

HI = Hourly heat input rate, determined 

using the procedures in section 5.2 of this 

appendix, mmBtu/hr. 

* * * * * 

8. Procedures for NOX Mass Emissions 

* * * * * 

8.1 The owner or operator may use the 

hourly NOX emission rate and the hourly 

heat input rate to calculate the NOX mass 

emissions in pounds or the NOX mass 

emission rate in pounds per hour, (as 

required by the applicable reporting format), 

for each unit or stack operating hour, as 

follows: 

8.1.1 If both NOX emission rate and heat 

input rate are monitored at the same unit or 

stack level (e.g., the NOX emission rate value 

and the heat input rate value both represent 

all of the units exhausting to the common 

stack), then (as required by the applicable 

reporting format) either: 

(a) Use Equation F–24 to calculate the 

hourly NOX mass emissions (lb) 

M ER HI t Eq NO NO h h X h X h () () = ( ) . F-24

Where: 

M(NOX)h = NOX mass emissions in lbs for the 

hour. 

ER(NOX)h = Hourly average NOX emission rate 

for hour h, lb/mmBtu, from section 3 of 

this appendix, from method 19 of appendix 

A to part 60 of this chapter, or from section 

3.3 of appendix E to this part. (Include 

bias-adjusted NOX emission rate values, 

where the bias-test procedures in appendix 

A to this part shows a bias-adjustment 

factor is necessary.) 

HIh = Hourly average heat input rate for hour 

h, mmBtu/hr. (Include bias-adjusted flow 

rate values, where the bias-test procedures 

in appendix A to this part shows a biasadjustment factor is necessary.) 

th = Monitoring location operating time for 

hour h, in hours or fraction of an hour (in 

equal increments that can range from one 

hundredth to one quarter of an hour, at the 

option of the owner or operator). If the 

combined NOX emission rate and heat 

input are monitored for all of the units in 

a common stack, the monitoring location 

operating time is equal to the total time 

when any of those units was exhausting 

through the common stack; or 

(b) Use Equation F–24a to calculate the 

hourly NOX mass emission rate (lb/hr). 

E ER Eq NO h h X h () () = ( ) NOXHI F-24a .

Where: 

E(NOX)h = NOX mass emissions rate in lbs/hr 

for the hour. 

ER(NOX)h = Hourly average NOX emission rate 

for hour h, lb/mmBtu, from section 3 of 

this appendix, from method 19 of appendix 

A to part 60 of this chapter, or from section 

3.3 of appendix E to this part. (Include 

bias-adjusted NOX emission rate values, 

where the bias-test procedures in appendix 

A to this part shows a bias-adjustment 

factor is necessary.) 

HIh = Hourly average heat input rate for hour 

h, mmBtu/hr. (Include bias-adjusted flow 

rate values, where the bias-test procedures 

in appendix A to this part shows a biasadjustment factor is necessary.) 

* * * * * 

8.2 Alternatively, the owner or operator 

may use the hourly NOX concentration (as 

measured by a NOX concentration monitoring 

system) and the hourly stack gas volumetric 

flow rate to calculate the NOX mass emission 

rate (lb/hr) for each unit or stack operating 

hour, in accordance with section 8.2.1 or 

8.2.2 of this appendix (as applicable). If the 

hourly NOX mass emissions are to be 

reported in lb, Equation F–26c in section 8.3 

of this appendix shall be used to convert the 

hourly NOX mass emission rates to hourly 

NOX mass emissions (lb). 

8.2.1 When the NOX concentration 

monitoring system measures on a wet basis, 

first calculate the hourly NOX mass emission 

rate (in lb/hr) during unit (or stack) 

operation, using Equation F–26a. (Include 

bias-adjusted flow rate or NOX concentration 

values, where the bias-test procedures in 

appendix A to this part shows a biasadjustment factor is necessary.) 

E K Q Eq NO h X h ( ) = C F-26a hw ( ) .

Where: 

E(NOX)h = NOX mass emissions rate in lb/hr. 

K = 1.194 × 10¥7 for NOX, (lb/scf)/ppm. 

Chw = Hourly average NOX concentration 

during unit operation, wet basis, ppm. 

Qh = Hourly average volumetric flow rate 

during unit operation, wet basis, scfh. 

8.2.2 When NOX mass emissions are 

determined using a dry basis NOX

concentration monitoring system and a wet 

basis flow monitoring system, first calculate 

hourly NOX mass emission rate (in lb/hr) 

during unit (or stack) operation, using 

Equation F–26b. (Include bias-adjusted flow 

rate or NOX concentration values, where the 

bias-test procedures in appendix A to this 

part shows a bias-adjustment factor is 

necessary.) 

E KQ

H O

Eq NO h X h ( ) = ( ) −

( ) C F-26b hd ( ) 100

100

% 2 .

Where: 

E(NOX)h = NOX mass emissions rate, lb/hr. 

K = 1.194 x 10¥7 for NOX, (lb/scf)/ppm. 

Chd = Hourly average NOX concentration 

during unit operation, dry basis, ppm. 

Qh = Hourly average volumetric flow rate 

during unit operation, wet basis, scfh 


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Federal Register / Vol. 71, No. 162 / Tuesday, August 22, 2006 / Proposed Rules 49307 

%H2O = Hourly average stack moisture 

content during unit operation, percent by 

volume. 

8.3 When hourly NOX mass emissions are 

reported in pounds and are determined using 

a NOX concentration monitoring system and 

a flow monitoring system, calculate NOX

mass emissions (lb) for each unit or stack 

operating hour by multiplying the hourly 

NOX mass emission rate (lb/hr) by the unit 

operating time for the hour, as follows: 

M E t Eq NO h h X h ( ) = ( ) . F-26c

Where: 

M(NOx)h = NOX mass emissions for the hour, 

lb. 

Eh = Hourly NOX mass emission rate during 

unit (or stack) operation from Equation F–

26a in section 8.2.1 of this appendix or 

Equation F–26b in section 8.2.2 of this 

appendix (as applicable), lb/hr. 

th = Unit operating time or stack operating 

time (as defined in § 72.2 of this chapter) 

for hour ‘‘h’’, in hours or fraction of an 

hour (in equal increments that can range 

from one hundredth to one quarter of an 

hour, at the option of the owner or 

operator). 

8.4 Use the following procedures to 

calculate quarterly, cumulative ozone season, 

and cumulative yearly NOX mass emissions, 

in tons: 

(a) When hourly NOX mass emissions are 

reported in lb, use Eq. F–27. 

M

M

Eq NO

NO

h

p

X time

X h

( )

( ) = = ( )

∑

 period

 F-27 1

2000 .

Where: 

M(NOX)time period = NOX mass emissions in tons 

for the given time period (quarter, 

cumulative ozone season, cumulative yearto-date). 

M(NOX)h = NOX mass emissions in lb for the 

hour. 

p = The number of hours in the given time 

period (quarter, cumulative ozone season, 

cumulative year-to-date). 

(b) When hourly NOX mass emission rate 

is reported in lb/hr, use Eq. F–27a. 

M

E t

Eq NO

NO h

h

p

X time

X h

( )

( ) = = ( )

∑

 period

 F-27a 1

2000 .

Where: 

M(NOX)time period = NOX mass emissions in tons 

for the given time period (quarter, 

cumulative ozone season, cumulative yearto-date). 

E(NOX)h = NOX mass emission rate in lb/hr for 

the hour. 

p = The number of hours in the given time 

period (quarter, cumulative ozone season, 

cumulative year-to-date). 

th = Monitoring location operating time for 

hour h, in hours or fraction of an hour (in 

equal increments that can range from one 

hundredth to one quarter of an hour, at the 

option of the owner or operator). 

* * * * * 

10. Moisture Determination from Wet and 

Dry O2 Readings 

If a correction for the stack gas moisture 

content is required in any of the emissions 

or heat input calculations described in this 

appendix, and if the hourly moisture content 

is determined from wet- and dry-basis O2

readings, use Equation F–31 to calculate the 

percent moisture, unless a ‘‘K’’ factor or other 

mathematical algorithm is developed as 

described in section 6.5.7(a) of appendix A 

to this part: 

% . H O

O O

O Eq d w

d

2

2 2

2

= 100 ( ) − × ( ) F-31

Where: 

% H2O = Hourly average stack gas moisture 

content, percent H2O 

O2d = Dry-basis hourly average oxygen 

concentration, percent O2

O2w = Wet-basis hourly average oxygen 

concentration, percent O2

* * * * * 

43. Appendix G to Part 75—is 

amended by: 

a. Revising section 2.1.2; 

b. Replacing the identifier ‘‘D3174–

89’’ with the identifier ‘‘D3174–00’’ in 

section 2.2.1; and 

c. Adding the number ‘‘(1997)’’ after 

the identifier ‘‘D3178–89’’ in section 

2.2.2. 

The revisions and additions read as 

follows: 

Appendix G to Part 75—Determination 

of CO2 Emissions 

* * * * * 

2.1.2 Determine the carbon content of 

each fuel sample using one of the following 

methods: ASTM D3178–89 (1997) or ASTM 

5373–93 for coal; ASTM D5291–01 

‘‘Standard Test Methods for Instrumental 

Determination of Carbon, Hydrogen, and 

Nitrogen in Petroleum Products and 

Lubricants,’’ ultimate analysis of oil, or 

computations based upon ASTM D3238–95 

(2000)e1 and either ASTM D2502–92 (1996) 

or ASTM D2503–92 (1997) for oil; and 

computations based on ASTM D1945–96 

(2001) or ASTM D1946–90 (2000) for gas. 

* * * * * 

44. Appendix K to Part 75 is amended 

by: 

a. Adding a sentence to the end of 

section 7.2.3; and 

b. Revising Table K–1 of section 8. 

c. Adding the number ‘‘2’’ after the 

words ‘‘sections 1 and’’ in the definition 

of the variable M* in Equation K–5. 

The revisions and additions read as 

follows: 

Appendix K to Part 75—Quality 

Assurance and Operating Procedures 

for Sorbent Trap Monitoring Systems 

* * * * * 

7.2.3 * * * The sample flow rate through 

a sorbent trap monitoring system during any 

hour (or portion of an hour) in which the unit 

is not operating shall be zero. 

* * * * * 


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49308 Federal Register / Vol. 71, No. 162 / Tuesday, August 22, 2006 / Proposed Rules 

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 lead check is passed. 

Post-test leak check ...................... ≤4% of average sampling rate ..... After sampling ............................... Sample invalidated.** 

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.Sample invalidated if more than 

5% of the hourly ratios or 5 

hourly ratios (whichever is less 

restrictive) are not maintained 

within the acceptance criteria.** 

Sorbent trap section 2 breakthrough.≤5% of Section 1 Hg mass .......... Every sample ................................ Sample invalidated.** 

Paired sorbent trap agreement ...... ≤10% Relative Deviation (RD) if 

the average concentration is 

>1.0 μg/m3, and ≤20% RD if the 

average concentration is ≤1.0 

μg/m3.

Every sample ................................ Either invalidate the data from the 

paired traps or report the results from the trap resulting in 

the higher Hg concentration. 

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. 

** However, if only one of the paired samples fails to meet this specification and the other sample meets all of the applicable QA criteria, the 

results of the valid sample may be used for reporting under this part, provided that the measured Hg concentration is multiplied by a factor of 

1.222. If both samples are invalidated and quality-assured data from a certified backup monitoring system, reference method, or approved alternative monitoring system are unavailable, substitute data must be used. 

[FR Doc. 06–6819 Filed 8–21–06; 8:45 am] 

BILLING CODE 6560–50–P 


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