[Federal Register Volume 71, Number 162 (Tuesday, August 22, 2006)]
[Proposed Rules]
[Pages 49254-49308]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 06-6819]



[[Page 49253]]

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Part III





Environmental Protection Agency





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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

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

[[Page 49254]]


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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.

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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: [email protected].
     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, e-mail at 
[email protected]. 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:

------------------------------------------------------------------------
                                                        Examples of
           Category                 NAICS code     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 Sec. Sec.  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.

[[Page 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 re-engineering the data systems associated 
with the collection and processing of emissions, monitoring plan, 
quality assurance, and certification data. The re-engineering 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 
``long-term 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 Sec.  
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 
Sec.  72.2.
    The proposed changes to Sec.  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 (Sec.  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 Sec.  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 Sec. Sec.  75.6(a) through 75.6(f). 
Additionally, new Sec. Sec.  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 site-
specific default SO2 emission rates for fuel oil combustion, 
in lieu of using the ``generic'' default SO2 emission rates 
specified in Table LM-1 of Sec.  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 Sec.  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 quality-assured 
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 Sec.  75.11(b), and 18.0% H2O under 
Sec.  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 gas-fired 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 Sec.  75.66 requesting to use site-specific default 
moisture values.
4. Expanded Use of Equation F-23
    Today's proposed rule would revise Sec.  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 Sec.  75.11(e)(1) or revised Sec.  
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 Sec.  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 Sec.  
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 Sec.  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 Sec.  72.2, if a petition for a fuel-specific default 
SO2 emission rate is submitted to the Administrator under 
Sec.  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 Sec. Sec.  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 Sec.  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 Sec.  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 on-going 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 Sec.  75.19(c)(4)(ii) as 
``NOX mass emissions and NOX emission rate'', and 
would add a new subparagraph (D) to Sec.  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 Sec.  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-and-matching 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 Sec.  
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 Sec.  75.19 and in other sections of the rule. In fact, Sec. Sec.  
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

[[Page 49257]]

these other sections, consistent with the changes to Sec.  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 Sec.  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 add-on control operation for such 
hours of operation would be required as described in Sec.  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 Sec.  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 Sec. Sec.  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) Sec.  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 Sec.  5.1 of Appendix A of 40 CFR Part 75.
    (2) Sec.  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) Sec.  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 Sec.  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 Sec.  
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, Sec.  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 Sec.  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 [mu]g/m\3\ or less, 
the RD specification is 20 percent. In view of this, today's proposed 
rule would revise Sec.  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 Sec. Sec.  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.

[[Page 49258]]

    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 Sec.  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 Sec.  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 Sec. Sec.  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 Sec.  
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 Sec. Sec.  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, Sec.  75.34(a)(3) provides 
that the designated representative (DR) may petition the Administrator 
under Sec.  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 add-on Hg controls (see 
Sec.  75.38(c)).
    For several reasons, EPA believes it is appropriate to revise Sec.  
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

[[Page 49259]]

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 add-on 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 Sec.  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 Sec.  75.34(a)(3) and Sec.  
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 Sec.  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 Sec.  
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 Sec. Sec.  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 Sec.  75.38(c) to 
extend the alternative missing data options for the third and fourth 
tiers to mercury (Hg) concentration, and Sec.  75.58(b)(3) would be 
revised to be consistent with the proposed revisions to Sec. Sec.  
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 Sec. Sec.  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 Sec.  
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 Sec.  75.38(a) would be amended to make 
it consistent with Table 1 in Sec.  75.33. Proposed Sec.  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 Sec.  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 Sec.  75.31(b) and the 
standard Hg missing data provisions of Sec.  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-by-hour 
concentration measurements (see Sec.  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 quality-assured data could be done on 
the

[[Page 49260]]

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 Sec.  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 quality-assured data (see Sec.  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 Sec.  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 Sec.  75.74(c). In Sec. Sec.  
75.74(c)(3)(xi) and (c)(3)(xii), data validation rules are provided for 
situations in which required quality-assurance 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 Sec.  75.31, Sec.  75.33 or Sec.  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 Sec. Sec.  75.74(c)(3)(xi) and 
(c)(3)(xii) by replacing each of the cross-references to specific 
missing data sections with a more general reference to the entire block 
of CEMS missing data sections, i.e., Sec. Sec.  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 Sec.  75.53, to accommodate its new, re-engineered XML 
reporting format, which will replace the current electronic data 
reporting (EDR) format in 2009. The Subpart H monitoring plan record 
keeping provisions in Sec.  75.73(c)(3) (for sources reporting 
NOX mass emissions) and the Subpart I monitoring plan record 
keeping provisions in Sec.  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 Sec.  
75.53, which describe the required monitoring plan data elements in 
EPA's re-engineered XML data structure. Proposed Sec.  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 Sec.  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             Proposed
        requirement(s)              action(s)             Comments
------------------------------------------------------------------------
 Facility short name..  Remove...........  These data elements
 Unit program                               would be collected
 classification.                                    and maintained
 Unit boiler type.....                      through the
 Date of commence                           Certificate of
 operation (Subpart H units).                       Representation form,
 Date of commence                           the CAMD Business
 commercial operation (Acid                         System, or
 Rain units).                                       internally by EPA.
 Unit retirement date.
 Program code.........
 Reporting frequency..
 Program participation
 date.
 State regulation code
 State or local agency
 code.
 EIA cross-reference
 information..
 Recording and          Relocate.........  Relocate the
 reporting of information                           requirement to
 associated with monitoring                         record and report
 system certification,                              this information to
 recertification, and other                         Sec.   75.59, the
 events.                                            quality-assurance
                                                    recordkeeping
                                                    section.
 Fuel classification    Remove...........  These data elements
 for boiler.                                        are deemed
 Primary/secondary                          unnecessary for the
 control indicator.                                 new XML reporting
 Type of fuel                               format.
 associated with each
 monitoring methodology.
 Primary/secondary
 methodology indicator.
 Appendix E
 correlation curve segment
 data..

[[Page 49261]]

 
 Component status.....  Replace..........  In Sec.   75.53(g),
 Formula status.......                      use activation date/
 Submission status of                       hour and
 fuel flowmeter data..                              deactivation date/
                                                    hour instead of
                                                    status codes to
                                                    better track updates
                                                    to monitoring
                                                    components,
                                                    formulas, and fuel
                                                    flowmeter
                                                    information.
 Indicator of           Add..............  These new data
 exemption from multi-load                          elements are needed
 flow RATAs.                                        to properly assess
 Shape of stack or                          specific Part 75
 duct cross-section.                                quality assurance/
 Stack/duct material                        quality control (QA/
 of construction.                                   QC) requirements and
 Flag to indicate that                      exemptions.
 a monitored location is a
 duct.
 Indicator of non-load
 based units..
 Analyzer range code..  Add..............  Provide the
 Moisture measurement                       measurement range
 basis..                                            (high, low, dual)
                                                    and moisture basis
                                                    (wet or dry) for
                                                    each CEMS component
                                                    type (SO2, NOX, CO2,
                                                    etc.)
 Provide the            Replace..........  For each parameter,
 monitoring methodologies for                       associate the
 each individual unit.                              monitoring
 Represent bypass                           methodology with the
 stack monitoring as a                              monitored lcoation
 separate methodology..                             (unit, stack or
                                                    duct). Integrate
                                                    bypass stack
                                                    monitoring with
                                                    other methodologies.
                                                    Only one monitoring
                                                    methodology per
                                                    paramter would be
                                                    allowed.
 For dual-range         Add..............  Many times data begin
 applications, indicate the                         to be recorded on
 trigger point at which the                         the high scale at a
 component switches from the                        certain ``trigger
 normal measurement scale to                        point'', before the
 the secondary scale.                               full-scale of the
                                                    low range is
                                                    reached. EPA needs
                                                    this information to
                                                    determine when
                                                    certain QA tests of
                                                    the high-scale are
                                                    required.
 Require operating      Revise...........  In Sec.   75.53(g),
 range and normal load                              require operating
 information to be reported                         range and maximum
 for units with CEMS and units                      load information for
 using optional fuel flow-to-                       all affected units.
 load ratio test.                                   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     Add..............  Add data elements to
 section.                                           Sec.   75.53(e) and
 Duct depth at test                         (g), describing
 section.                                           monitoring plan
 WAF..................                      requirements for
 Method of determining                      units with
 WAF.                                               rectangular ducts
 WAF effective date                         that apply a wall
 and hour.                                          effects adjustment
 WAF no longer                              factor (WAF) to
 effective date and hour.                           their flow rate
 WAF determination                          data. (See Section
 date.                                              II.E.2 for further
 Number of WAF test                         discussion.)
 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..
------------------------------------------------------------------------

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 over-reporting 
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

[[Page 49262]]

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 Sec. Sec.  75.53(e) and (g) and in 
Sec.  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 Sec.  
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
                              Sec.   75.58
------------------------------------------------------------------------
      Data element(s) or             Proposed
        requirement(s)              action(s)             Comments
------------------------------------------------------------------------
 For Appendix D units,  Add to Sec.        This would be
 report ID numbers of formulas   75.58(c).          required on and
 used to calculate SO2 mass                         after January 1,
 emissions and heat input rate.                     2009.
 For Appendix E units,  Add to Sec.        This would be
 report the heat input rate      75.58(d).          required on and
 formula ID for each unit                           after January 1,
 operating hour.                                    2009.
 For LME units that     Revise Sec.        Report the fuel type
 combust more than one type of   75.58(f).          that produces the
 fuel, report the fuel type                         highest emission
 that produces the highest NOX                      rate for each
 emission rate.                                     parameter
                                                    individually (i.e.,
                                                    for SO2, NOX, and
                                                    CO2, as applicable).
 For LME units under    Add to Sec.        This flag is needed
 Sec.   75.19(c)(1)(iv)(C)(9),   75.58(f).          to ensure that the
 indicate whether unit is                           proper NOX emission
 operating at base or peak                          factor is being
 load, each hour.                                   applied.
 For LME units, flag    Add to Sec.        This flag is needed
 each hour in which multiple     75.58(f).          to ensure that the
 fuels are combusted.                               proper emission
                                                    factors are used for
                                                    multiple-fuel hours.
 For LME units using    Revise Sec.        Require only the
 long-term fuel flow, report     75.58(f).          system ID. Long-term
 the component and system ID                        fuel flow systems
 codes.                                             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 Sec.  
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 Sec.
                                   75.59
------------------------------------------------------------------------
      Data element(s) or             Proposed
        requirement(s)              action(s)             Comments
------------------------------------------------------------------------
 Describe each          Revise Sec.        Expand to include
 recertification event, and      75.59(a)(8).       events that require
 the date and type of each                          certification and
 recertification test.                              diagnostic testing.
                                                    Add requirement to
                                                    report conditional
                                                    data validation
                                                    begin date (if
                                                    applicable).
                                                    Corresponds to
                                                    current EDR record
                                                    type 556.
 Record component and   Revise Sec.  Sec.  Require only the
 system ID codes for daily         75.59(a) and     component ID for
 calibrations, 7-day             (b).               these tests. This
 calibration error tests,                           requirement would be
 cycle time tests, linearity                        effective on and
 checks, flow monitor leak                          after January 1,
 checks and interference                            2009. The cycle time
 tests, and fuel flowmeter                          test for NOX-diluent
 accuracy tests.                                    systems would be
                                                    simplified.
 Record the test        Revise Sec.        Clarify that test
 number and reason for test,     75.59(a)(1)(viii   number and reason
 for daily calibrations and 7-   ).                 for test code apply
 day calibration error tests.                       only to 7-day
                                                    calibration error
                                                    tests, not to daily
                                                    calibrations.
 Report the span value  Remove from Sec.   The span value in the
 with the results of each         75.59(a)(3)(ii).  monitoring plan
 linearity check.                                   records will be used
                                                    to evaluate the
                                                    linearity checks.
 Provide an on-line or  Add to Sec.        This flag is needed
 off-line indicator flag for     75.59(a)(1).       to properly assess
 all calibration error tests.                       the hour-by-hour
                                                    quality-assurance
                                                    status of CEMS
                                                    following
                                                    calibration error
                                                    tests.
 For flow-to-load       Add, as Sec.       This addition is
 tests of multiple stack         75.59(a)(4)(vii)   needed for
 configurations, indicate        (M).               consistency with the
 whether separate reference                         flow-to-load test
 ratios are calculated for                          reporting
 each stack.                                        instructions
                                                    (current EDR record
                                                    type 605).
 Report sufficient      Remove and         EPA's checking
 information to validate all     reserve Sec.       software no longer
 grace period claims.            75.59(a)(12)(iii   needs this
                                 ).                 information to
                                                    evaluate grace
                                                    periods.
 Record the component   Revise Sec.        On and after January
 and system ID codes for each    75.59(b)(4)(i)(A   1, 2009, record only
 fuel flow-to-load ratio test.   ).                 the system ID for
                                                    these tests.
 Report Appendix E      Revise Sec.        On and after January
 correlation curve test data     75.59(b)(5).       1, 2009, report this
 on a monitoring system basis.                      data on a component
                                                    basis.
 Report the type(s) of  Remove Sec.        This information is
 fuel(s) combusted during each   75.59(b)(5)(i)(H   not needed in the
 run of an Appendix E            ).                 new XML format and
 correlation curve test.                            would not be
                                                    reported after
                                                    December 31, 2008.
 Report the monitoring  Add, as Sec.       This requirement is
 system ID code with reference   75.59(b)(4)(ii)(   consistent with the
 fuel flow-to-load ratio test    N).                reporting
 data.                                              instructions for the
                                                    reference fuel flow-
                                                    to-load ratio
                                                    (current EDR record
                                                    type 629).

[[Page 49263]]

 
 For LME units,         Add, as Sec.       This requirement is
 indicate which test runs are    75.59(d)(1)(xiii   consistent with the
 used to calculate fuel-and-     ).                 reporting
 unit-specific NOX emission                         instructions for NOX
 rates.                                             emission testing of
                                                    LME units (current
                                                    EDR version 2.2,
                                                    record type 650).
 For LME units,         Revise Sec.        This requirement
 multiply the tested NOX         75.59(d)(2)(iii)   applies only to
 emission rate by 1.15, if       and add new Sec.   turbines that
 applicable.                      Sec.              operate only at base
                                 75.59(d)(2)(vi)    or peak load.
                                 and (vii).         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    Add Sec.           This requirement
 hour of completion of all       75.59(f).          would be effective
 required DAHS verifications,                       on and after January
 whether for initial                                1, 2009. EPA needs
 certification,                                     this information to
 recertification, or other                          properly establish
 events.                                            provisional
                                                    certification or
                                                    recertification
                                                    dates. Proposed
                                                    changes to Sec.
                                                    75.63(a)(2)(iii)
                                                    would allow this
                                                    information to be
                                                    reported
                                                    electronically as
                                                    part of the
                                                    certification or
                                                    recertification
                                                    application.
 Record the             Add Sec.           For periodic testing
 appropriate reference method    75.59(e).          of low mass emission
 data elements for Hg emission                      units, recording of
 tests of low-emitting units.                       the reference method
                                                    data elements in
                                                    either Sec.
                                                    75.59(a)(7)(vii),
                                                    (viii), or (x) would
                                                    be required,
                                                    depending on which
                                                    reference method is
                                                    used for the
                                                    testing.
 Monitoring system ID   Add, as Sec.       Recording of certain
 Test number..........   75.59(a)(7)(ix).   data elements and
 Operating level......                      test results would
 RATA end date and                          be required for
 time.                                              units with
 Number of Method 1                         rectangular ducts/
 traverse points.                                   stacks that apply a
 Wall effects                               wall effects
 adjustment factor.                                 adjustment factor
                                                    (WAF) to correct
                                                    their flow rate
                                                    data. These data
                                                    elements would be
                                                    required for each
                                                    flow RATA.
 Percent CO2 and O2 in  Add, as Sec.       Recording of certain
 the stack gas, dry basis        75.59(a)(7)(x).    data elements would
 Moisture content of                        be required when
 the stack gas (percent H2O).                       using Method 29 for
 Average stack gas                          the RATA of a Hg
 temperature ([deg]F).                              monitoring system.
 Dry gas volume                             These data elements
 metered (dscm).                                    would be required
 Percent isokinetic...                      for each RATA run.
 Particulate Hg
 collected in the front half
 of the sampling train,
 corrected for the front-half
 blank value ([mu]g).
 Total vapor phase Hg
 collected in the back half of
 the sampling train, corrected
 for the back-half blank value
 ([mu]g).
------------------------------------------------------------------------

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 
``long-term cold storage'' would be added to Sec.  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 Sec.  75.61. Proposed Sec.  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, Sec.  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 re-commenced 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 
Sec.  75.64 until the unit recommences operation. Parallel rule 
provisions and appropriate cross-references regarding quarterly 
reporting requirements for Subpart H and Subpart I units would be added 
to Sec. Sec.  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 Sec. Sec.  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 Sec.  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 Sec. Sec.  75.4(d) and 75.61(a)(3) are deemed necessary 
because the CAIR and CAMR rules do not address deferred units.
    Revised Sec.  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 Sec.  75.61(a)(3) (for 
planned shutdowns such as scheduled maintenance outages and for 
unplanned, forced unit outages) or Sec.  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

[[Page 49264]]

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 Sec.  75.20(b)(3); (3) EPA reference methods; 
or (4) another procedure approved by petition to the Administrator 
under Sec.  75.66.
    Today's proposed rule would revise the notification requirements of 
Sec.  75.61(a)(3) to be consistent with the changes to Sec.  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 Sec.  
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 Sec.  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 Sec.  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 newly-affected 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 Sec. Sec.  75.62(a)(1) 
and (2), Sec. Sec.  75.73(e)(1) and (2) for Subpart H units, and 
Sec. Sec.  75.84(e)(1) and (e)(2) for Subpart I units).
    EPA also proposes to remove the requirement in Sec.  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 re-
engineered 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, Sec. Sec.  
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, 
Sec. Sec.  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 Sec.  
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 Sec.  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 
re-engineered 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 Sec.  75.64
    As part of its data systems re-engineering effort, EPA proposes to 
revise Sec.  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: Sec. Sec.  
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

[[Page 49265]]

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 Sec. Sec.  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 Sec.  75.61(a)(5) and add corresponding 
introductory text to Sec.  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 Sec.  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 Sec.  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 
re-tests.
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 Sec. Sec.  
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 Sec. Sec.  
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 Sec. Sec.  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 Sec. Sec.  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 Sec.  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, Sec.  
75.71(a)(2) requires the installation of an ``O2 or 
CO2 diluent gas monitor''. Consistent with the definition of 
a CEMS in Sec.  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 Sec.  75.71(a)(2) accordingly.
2. Identifying a NOX Mass Methodology
    EPA is proposing to revise Sec.  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 out-of-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 re-engineering 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 Sec.  75.64, EPA proposes 
to revise Sec.  75.73(f)(1), to phase out the requirement of Sec.  
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 Sec. Sec.  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

[[Page 49266]]

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 pre-season 
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 
Sec.  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 Sec.  75.74(c)(2)(i)(D) by 
removing the conditional grace period provision and adding a cross-
reference to proposed Sec.  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 Sec.  75.20(b)(3) are applied. Proposed Sec.  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 quality-assured, 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 Sec.  75.20(b)(3)(viii), subject 
to the restrictions of Sec.  75.74(c)(3)(xii).
    Today's proposed rule would add a new paragraph (F) to Sec.  
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 Sec.  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 Sec.  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 pre-season 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 
Sec.  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 Sec. Sec.  
75.74(c)(2)(ii)(G) and (c)(2)(ii)(H) and would remove and reserve 
Sec. Sec.  75.74(c)(3)(vi), (vii), and (viii).
    Note that EPA is not modifying the provisions of Sec.  
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.

[[Page 49267]]

6. Determining Peaking Status for Ozone Season Only Reporters
    EPA proposes to revise Sec.  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 Sec.  75.19, would be removed, and its basic content 
would be relocated to Sec.  75.71(e). The LME provision in Sec.  75.72 
appears to have been inadvertently placed in that section. The 
monitoring provisions of Sec.  75.72 apply to common and multiple stack 
configurations, whereas Sec.  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 Sec.  75.82 to correct this deficiency.
    For the common stack shared by affected and non-affected units, 
proposed Sec.  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 Sec.  
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 Sec. Sec.  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 Sec.  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 Sec.  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 Sec.  75.19(c)(1)(iv)(B). Then, the number 
of units required to be tested would be determined from Table LM-4 in 
Sec.  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 Sec.  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 Sec.  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 
Sec.  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, 
Sec.  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 Sec.  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 Sec.  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

[[Page 49268]]

considerations, EPA is proposing to revise Sec.  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 Sec.  
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 Sec.  75.81(d)(4) to address the 
emission testing requirements when the fuel supply is changed. Revised 
Sec.  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 (Sec.  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., Sec. Sec.  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 Sec. Sec.  
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 EPA-maintained 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 
improperly-performed 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

[[Page 49269]]

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 Sec.  
75.6(a)(45), and a definition of ``Air Emission Testing Body'' would be 
added to Sec.  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 range-specific; (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 
quality-assured (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 full-scale 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 low-range 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 out-of-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

[[Page 49270]]

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 [mu]g/
m\3\ 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 [mu]g/m\3\. Further, the same 0.6 [mu]g/m\3\ 
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 single-level system integrity checks). The alternative performance 
specification is deemed necessary for low (10 [mu]g/m\3\ 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 
moisture-free. 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, single-level 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

[[Page 49271]]

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 user-friendly, 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 NOX-diluent 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-of-control. 
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 quality-assurance 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

[[Page 49272]]

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-of-
control 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 off-line 
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 off-line 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 
well-understood 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 NIST-traceable 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 ([mu]g/dscm) would be changed to 
micrograms per standard cubic meter ([mu]g/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 Sec.  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

[[Page 49273]]

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

[[Page 49274]]

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 XML-reporting 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 cross-references 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.

[[Page 49275]]

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 fuel-specific.
    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 site-specific 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, re-determination 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 F-factor 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 Sec.  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, Sec.  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 
Sec.  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

[[Page 49276]]

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 Sec.  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 [mu]g/
m3) are encountered.
    Today's proposed rule would add two new paragraphs, (k) and (l), to 
Sec.  75.15. Proposed Sec.  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 Sec.  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 under-
reporting 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.

[[Page 49277]]

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-for-profit 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 cost-effective, 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

[[Page 49278]]

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:


Sec.  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

[[Page 49279]]

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 Sec.  75.15 of this chapter, Sec.  
75.19 of this chapter, Sec.  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 Sec.  
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:


Sec.  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 Sec.  75.20, for 
an affected unit which, on the applicable compliance date, is either in 
long-term cold storage (as defined in Sec.  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 Sec.  75.61(a)(3) or Sec.  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 Sec.  
75.61(a)(3) or Sec.  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 Sec.  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 Sec.  
75.20(b)(3); or
    (3) Reference methods under Sec.  75.22(b); or
    (4) Another procedure approved by the Administrator pursuant to a 
petition under Sec.  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);

[[Page 49280]]

    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:


Sec.  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:


Sec.  75.11  Specific provisions for monitoring SO2 
emissions.

* * * * *
    (d) * * *
    (3) By using the low mass emissions excepted methodology in Sec.  
75.19(c) for estimating hourly SO2 mass emissions if the 
affected unit qualifies as a low mass emissions unit under Sec.  
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 
Sec.  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 
Sec.  72.2 of this chapter), the SO2 monitoring system shall 
meet the following quality assurance provisions

[[Page 49281]]

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 Sec.  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 Sec.  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:


Sec.  75.12  Specific provisions for monitoring NOX emission 
rate.

* * * * *
    (e) * * *
    (3) Use the low mass emissions excepted methodology in Sec.  
75.19(c) for estimating hourly NOX emission rate and hourly 
NOX mass emissions, if applicable under Sec.  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:


Sec.  75.13  Specific provisions for monitoring CO2 
emissions.

* * * * *
    (d) * * *
    (3) Use the low mass emissions excepted methodology in Sec.  
75.19(c) for estimating hourly CO2 mass emissions, if 
applicable under Sec.  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:


Sec.  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 Sec.  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:


Sec.  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:


Sec.  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 Sec.  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 Sec.  
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 Sec.  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 Sec.  
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

[[Page 49282]]

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:


Sec.  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, fuel-specific 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 fuel-specific 
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:


Sec.  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 
Sec.  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:


Sec.  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 multi-hole 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 Sec.  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

[[Page 49283]]

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 [mu]g/m\3\. If the average 
concentration is <= 1.0 [mu]g/m\3\, 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:


Sec.  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       Duration (N) of CEMS
             (percent)                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  N <= 8...............  Average..............  HB/HA
 < 90 for Hg).
                                    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  N > 0................  For SO2, CO2, Hg, and
 < 80 for Hg).                                              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      None
                                                            concentration or %
                                                            (for O2 and H2Ox).
----------------------------------------------------------------------------------------------------------------
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.
\1\ Where a unit with add-on SO2 or Hg emission controls can demonstrate that the controls are operating
  properly, as provided in Sec.   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.

[[Page 49284]]

 
\3\ Alternatively, where a unit with add-on SO2 or Hg emission controls can demonstrate that the controls are
  operating properly, as provided in Sec.   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
----------------------------------------------------------------------------------------------------------------
                                     Duration (N) of
    Monitor data availability      CEMS outage (hours)         Method          Lookback period      Load ranges
            (percent)                      \2\
----------------------------------------------------------------------------------------------------------------
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    None...............  No
                                                         NOX emission
                                                         rate3; or maximum
                                                         potential NOX
                                                         concentration3; or
                                                         maximum potential
                                                         flow rate..
----------------------------------------------------------------------------------------------------------------
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.
\1\ Where a unit with add-on NOX emission controls can demonstrate that the controls are operating properly, as
  provided in Sec.   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 Sec.   75.34 (a)(2).
 
\2\ During unit operating hours.
 
\3\ Alternatively, where a unit with add-on NOX emission controls can demonstrate that the controls are
  operating properly, as provided in Sec.   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
----------------------------------------------------------------------------------------------------------------
                                        Duration (N) of CEMS
 Monitor data availability (percent)     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          N > 0..................  Maximum potential NOX   None
 indeterminable.                                                emission rate \2\ or
                                                                maximum potential NOX
                                                                concentration \2\.
----------------------------------------------------------------------------------------------------------------
* 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.
\2\ Alternatively, where a unit with add-on NOX emission controls can demonstrate that the controls are
  operating properly, as provided in Sec.   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.


[[Page 49285]]

* * * * *
    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 Sec.  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:


Sec.  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 Sec.  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 quality-assured 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 Sec.  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.


Sec.  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 Sec.  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 Sec.  
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 Sec.  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 Sec.  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 quality-assured 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:


Sec.  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 quality-assured 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.

[[Page 49286]]

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 Sec.  75.31(b) until 720 hours of quality-assured 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 
Sec.  75.32 and switch from the initial missing data procedures in 
paragraph (c) of this section to the standard missing data procedures 
in Sec.  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 out-of-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 Sec.  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:


Sec.  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 cross-sectional 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 cross-section(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

[[Page 49287]]

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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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

[[Page 49288]]

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 Sec. Sec.  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 
Sec.  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 Sec.  
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 diesel-fired unit or unit with a 
wet flue gas pollution control system for which the designated 
representative claims an opacity monitoring exemption under Sec.  
75.14, the designated representative shall include in the hardcopy 
monitoring plan the information specified under Sec.  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 Sec.  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 Sec.  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

[[Page 49289]]

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 
Sec.  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 Sec. Sec.  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 Sec. Sec.  75.19(a) and 
75.19(b).
    (5) For qualification as a gas-fired unit, as defined in Sec.  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 Sec.  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:


Sec.  75.57  General recordkeeping provisions.

* * * * *
    (c) * * *
    (4) * * *
    (iv) * * *

     Table 4a.--Codes for Method of Emissions and Flow Determination
------------------------------------------------------------------------
                                  Hourly emissions/flow measurement or
             Code                          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 Sec.   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 Sec.   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).

[[Page 49290]]

 
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 Sec.   75.34(a)(5)).
16...........................  SO2 concentration value of 2.0 ppm during
                                hours when only ``very low sulfur
                                fuel'', as defined in Sec.   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 Sec.   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
                                Sec.   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:


Sec.  75.58  General recordkeeping provisions for specific situations.

* * * * *
    (b) * * *
    (3) Except as otherwise provided in Sec.  75.34(d), for units with 
add-on SO2 or NOX emission controls following the 
provisions of Sec.  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

[[Page 49291]]

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 
``Sec.  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:


Sec.  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 ([deg]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 ([mu]g); and
    (G) Total vapor phase Hg collected in the back half of the sampling 
train, corrected for the back-half blank value ([mu]g).
    (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 Sec.  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

[[Page 49292]]

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 Sec.  
75.81(b). For qualifying coal-fired units using the alternative low 
mass emission methodology under Sec.  75.81(b), the owner or operator 
shall record the data elements described in Sec.  75.59(a)(7)(vii), 
Sec.  75.59(a)(7)(viii), or Sec.  75.59(a)(7)(x), as applicable, for 
each run of each Hg emission test and re-test required under Sec.  
75.81(c)(1) or Sec.  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 Sec.  75.53(g) and (h).)
* * * * *
    25. Section 75.60 is amended by adding paragraph (b)(8) to read as 
follows:


Sec.  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 Sec.  
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 post-run 
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:


Sec.  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 Sec.  75.20 for continuous emission 
monitoring systems, for the excepted Hg monitoring methodology under 
Sec.  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 Sec.  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 Sec.  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 Sec.  75.19(c)(1)(iv)(D), and of 
periodic

[[Page 49293]]

retesting of Hg low mass emissions units performed under Sec.  
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 
Sec.  75.4(d) or Sec.  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 Sec.  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 Sec.  75.4(b) 
or Sec.  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:


Sec.  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 Sec.  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 Sec.  75.53(h)(4)(ii) (as applicable)'' 
after the identifier ``Sec.  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:


Sec.  75.63  Initial Certification or Recertification Application.

    (a) * * *
    (1) * * *
    (ii) * * *
    (A) To the Administrator, the electronic low mass emission 
qualification information required by Sec.  75.53(f)(5)(i) or Sec.  
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 Sec.  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 
Sec.  75.64. Notwithstanding the requirement of Sec.  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 ``Sec.  75.59'', with ``Sec.  
75.58(f)(2)'' at the end of newly designated paragraph (a)(14).
    The revisions and additions read as follows:


Sec.  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 Sec.  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 Sec.  
75.4(d) that is shutdown on the relevant compliance date in Sec.  
75.4(a) or has been placed in long-term cold storage (as defined in 
Sec.  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 
provisionally-certified monitoring system, Sec.  75.20(a)(3) shall 
apply for initial certifications, and Sec.  75.20(b)(5) shall apply for 
recertifications. Each electronic report must be submitted to

[[Page 49294]]

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 Sec.  
75.59(a)(7), except that:
    (A) The applicable data elements under Sec.  75.59(a)(7)(ii)(A) 
through (T) and under Sec.  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 Sec.  75.59(a)(7)(ii)(A) 
through (T) and under Sec.  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 Sec.  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 Sec.  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 Sec.  75.62(a)(1), if any monitoring plan 
information required in Sec.  75.53 requires an update, either under 
Sec.  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 Sec.  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 Sec.  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 Sec. Sec.  75.57 
through 75.59, and daily calibration error test data, daily 
interference check, and off-line calibration demonstration information 
required in Sec.  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 Sec.  75.57(f), and in Sec.  
75.59(a)(8);
    (iv) For units with SO2 or NOX add-on 
emission controls that do not elect to use the approved site-specific 
parametric monitoring procedures for calculation of substitute data, 
the information in Sec.  75.58(b)(3);
    (v) Information required by Sec.  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 Sec.  75.53 
and hardcopy test data and results required by Sec.  75.59;
    (vii) Records of flow monitor and moisture monitoring system 
polynomial equations, coefficients, or ``K'' factors required by Sec.  
75.59(a)(5)(vi) or Sec.  75.59(a)(5)(vii);
    (viii) Daily fuel sampling information required by Sec.  
75.58(c)(3)(i) for units using assumed values under appendix D;
    (ix) Information required by Sec. Sec.  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 Sec.  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 Sec.  
75.59(a)(7)(i) through Sec.  75.59(a)(7)(v), except that:
    (A) The applicable data elements under Sec.  75.59(a)(7)(ii)(A) 
through (T) and under Sec.  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 Sec.  75.59(a)(7)(ii)(A) 
through (T) and under Sec.  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 Sec.  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 Sec.  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.
* * * * *


Sec.  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:


Sec.  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 Sec.  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

[[Page 49295]]

Sec.  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:


Sec.  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 
Sec.  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:


Sec.  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 Sec.  75.53(e)(1) or 
Sec.  75.53(g)(1) in electronic format and the information in Sec.  
75.53(e)(2) or Sec.  75.53(g)(2) in hardcopy format. On and after 
January 1, 2009, each monitoring plan shall contain the information in 
Sec.  75.53(g)(1) in electronic format and the information in Sec.  
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 Sec.  75.53(f)(1)(i), (f)(2)(i), and (f)(4) 
or Sec.  75.53(h)(1)(i), and (h)(2)(i) in electronic format and the 
information in Sec.  75.53(f)(1)(ii) and (f)(2)(ii) or Sec.  
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 Sec.  
75.53(h)(1)(i), and (h)(2)(i) in electronic format and the information 
in Sec.  75.53(h)(1)(ii) and (h)(2)(ii) in hardcopy format, only. For 
units using the low mass emissions excepted methodology under Sec.  
75.19, prior to January 1, 2009, the monitoring plan shall include the 
additional information in Sec.  75.53(f)(5)(i) and (f)(5)(ii) or Sec.  
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 Sec.  75.19 the 
monitoring plan shall include the additional information in Sec.  
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 fuel-switching 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 
long-term cold storage (as defined in Sec.  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 Sec. Sec.  
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 Sec.  
75.59(a)(7), except that:
    (1) The applicable data elements under Sec.  75.59(a)(7)(ii)(A) 
through (T) and under Sec.  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 Sec.  75.59(a)(7)(ii)(A) 
through (T) and under Sec.  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 Sec.  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 Sec.  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);

[[Page 49296]]

    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 ``Sec.  75.31, Sec.  
75.33, or Sec.  75.37'' with the words ``Sec. Sec.  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:


Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  
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 pre-season 
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 oil-fired 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 Sec.  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 Sec.  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:


Sec.  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

[[Page 49297]]

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 Sec.  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 Sec.  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 Sec.  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 Sec.  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:
[GRAPHIC] [TIFF OMITTED] TP22AU06.050


Where:

E = Estimated annual Hg mass emissions from the affected unit, (ounces/
year)
K = Units conversion constant, 9.978 x 10-10 oz-scm/[mu]g-
scf
8760 = Number of hours in a year
CHg = The highest Hg concentration ([mu]g/scm) from any of 
the test runs or 0.50 [mu]g/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 
[mu]g/scm, a default value of 0.50 [mu]g/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 Sec.  
75.84 shall be updated after each required retest. This includes 
retests that are required prior to the compliance date in Sec.  
75.80(b). The updated value shall either be the highest Hg 
concentration measured in any of the test runs or 0.50 [mu]g/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 Sec.  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 Sec.  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 [mu]g/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 [mu]g/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 [mu]g/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

[[Page 49298]]

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 [mu]g/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:


Sec.  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 Sec.  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 ``Sec.  75.53(e)(1)'' and ``Sec.  75.53(e)(2)'' and 
adding in their place ``Sec.  75.53(g)(1)'' and ``Sec.  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 ``Sec.  75.64(a)(1)'' and adding in its place ``Sec.  
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:


Sec.  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 Sec.  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 Sec.  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 Sec. Sec.  
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 Sec.  
75.59(a)(7), except that:
    (1) The applicable data elements under Sec.  75.59(a)(7)(ii)(A) 
through (T) and under Sec.  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 Sec.  75.59(a)(7)(ii)(A) 
through (T) and under Sec.  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 Sec.  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 Sec.  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;

[[Page 49299]]

    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 Sec.  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 Sec.  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 
Sec. Sec.  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., 
[bond] R-A [bond] in Equation A-4 of this appendix, does not exceed 
0.6 [mu]g/m\3\. 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.

[[Page 49300]]

    (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 Sec.  
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 NIST-
traceable 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 quality-
assurance. 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 Sec.  
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 
dry-basis 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 high-level 
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 Sec.  
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

[[Page 49301]]

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 Sec.  
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 Sec.  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 [mu]g/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 
Sec. Sec.  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 off-line 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-of-control 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 out-of-
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

[[Page 49302]]

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 Sec. Sec.  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 Sec. Sec.  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-of-control, 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 
Sec. Sec.  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 Sec. Sec.  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 flow-calculation 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

[[Page 49303]]

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 Sec.  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 Sec.  
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 on-site 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 Energy-Dispersive X-Ray Fluorescence 
Spectroscopy'' (incorporated by reference under Sec.  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 
Sec.  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 Sec.  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 Sec.  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 Sec.  
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;

[[Page 49304]]

    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 Gas-Fired 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 Sec.  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 Sec.  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 x [(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.
* * * * *

[[Page 49305]]



                     Table 1.--F and FC-Factors \1\
----------------------------------------------------------------------
                                          F-factor (dscf/ FC-factor (scf
                  Fuel                        mmBtu)        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 [deg]C (68 [deg]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 [deg]C (68 [deg]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 Sec.  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:
[GRAPHIC] [TIFF OMITTED] TP22AU06.051

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.
[GRAPHIC] [TIFF OMITTED] TP22AU06.052

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.

[[Page 49306]]

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 Sec.  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 Sec. Sec.  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 Sec.  
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 
Sec.  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 Sec.  75.66 to use a 
site-specific default SO2 emission rate for the fuel or 
mixture of fuels.
[GRAPHIC] [TIFF OMITTED] TP22AU06.053

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 Sec.  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)
[GRAPHIC] [TIFF OMITTED] TP22AU06.054

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 bias-adjustment 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).
[GRAPHIC] [TIFF OMITTED] TP22AU06.055

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 bias-adjustment 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 bias-adjustment factor is 
necessary.)
[GRAPHIC] [TIFF OMITTED] TP22AU06.056

Where:

E(NOX)h = NOX mass emissions rate 
in lb/hr.
K = 1.194 x 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.)
[GRAPHIC] [TIFF OMITTED] TP22AU06.057

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

[[Page 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:
[GRAPHIC] [TIFF OMITTED] TP22AU06.058

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 Sec.  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.
[GRAPHIC] [TIFF OMITTED] TP22AU06.059

Where:

M(NOX)time period = NOX mass 
emissions in tons for the given time period (quarter, cumulative 
ozone season, cumulative year-to-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.
[GRAPHIC] [TIFF OMITTED] TP22AU06.060

Where:

M(NOX)time period = NOX mass 
emissions in tons for the given time period (quarter, cumulative 
ozone season, cumulative year-to-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:
[GRAPHIC] [TIFF OMITTED] TP22AU06.061

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.
* * * * *

[[Page 49308]]



           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  Prior to sampling......  Sampling shall not
                                        rate.                                             commence until the
                                                                                          lead check is passed.
Post-test leak check.................  <=4% of average          After sampling.........  Sample invalidated.**
                                        sampling rate.
Ratio of stack gas flow rate to        Maintain within  25% of initial    data collection period.  more than 5% of the
                                        ratio from first hour                             hourly ratios or 5
                                        of data collection                                hourly ratios
                                        period.                                           (whichever is less
                                                                                          restrictive) are not
                                                                                          maintained within the
                                                                                          acceptance criteria.**
Sorbent trap section 2 break-through.  <=5% of Section 1 Hg     Every sample...........  Sample invalidated.**
                                        mass.
Paired sorbent trap agreement........  <=10% Relative           Every sample...........  Either invalidate the
                                        Deviation (RD) if the                             data from the paired
                                        average concentration                             traps or report the
                                        is >1.0 [mu]g/m3, and                             results from the trap
                                        <=20% RD if the                                   resulting in the
                                        average concentration                             higher Hg
                                        is <=1.0 [mu]g/m3.                                concentration.
Spike Recovery Study.................  Average recovery         Prior to analyzing       Field samples shall not
                                        between 85% and 115%     field samples and        be analyzed until the
                                        for each of the 3        prior to use of new      percent recovery
                                        spike concentration      sorbent media.           criteria has been met.
                                        levels.
Multipoint analyzer calibration......  Each analyzer reading    On the day of analysis,  Recalibrate until
                                        within 10%   before analyzing any     successful.
                                        of true value and        samples.
                                        r2>=0.99.
Analysis of independent calibration    Within 10%   Following daily          Recalibrate and repeat
 standard.                              of true value.           calibration, prior to    independent standard
                                                                 analyzing field          analysis until
                                                                 samples.                 successful.
Spike recovery from section 3 of       75-125% of spike amount  Every sample...........  Sample invalidated.**
 sorbent trap.
RATA.................................  RA <=20.0% or Mean       For initial              Data from the system
                                        difference <=1.0 [mu]g/  certification and        are invalidated until
                                        dscm for low emitters.   annually thereafter.     a RATA is passed.
Dry gas meter calibration (At 3        Calibration factor (Y)   Prior to initial use     Recalibrate the meter
 orifice initially, and 1 setting       within 5%    and at least quarterly   at three orifice
 thereafter).                           of average value from    thereafter.              settings to determine
                                        the initial (3-point)                             a new value of Y.
                                        calibration.
Temperature sensor calibration.......  Absolute temperature     Prior to initial use     Recalibrate. Sensor may
                                        measured by sensor       and at least quarterly   not be used until
                                        within 1.5% of a
                                        reference sensor.
Barometer calibration................  Absolute pressure        Prior to initial use     Recalibrate. Instrument
                                        measured by instrument   and at least quarterly   may not be used until
                                        within 10    thereafter.              specification is met.
                                        mm Hg of reading with
                                        a mercury barometer.
----------------------------------------------------------------------------------------------------------------
** 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