[Federal Register Volume 67, Number 113 (Wednesday, June 12, 2002)]
[Rules and Regulations]
[Pages 40394-40476]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 02-11450]



[[Page 40393]]

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Part II





Environmental Protection Agency





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40 CFR Parts 72 and 75



Revisions to the Definitions and the Continuous Emission Monitoring 
Provisions of the Acid Rain Program and the NOX Budget Trading Program; 
Final Rule

  Federal Register / Vol. 67, No. 113 / Wednesday, June 12, 2002 / 
Rules and Regulations  

[[Page 40394]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 72 and 75

[FRL-7207-4]
RIN 2060-AJ43


Revisions to the Definitions and the Continuous Emission 
Monitoring Provisions of the Acid Rain Program and the NOX Budget 
Trading Program

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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SUMMARY: In this action, EPA is taking final action on the portions of 
the June 13, 2001 proposed rule revisions that modify the existing 
requirements for sources affected by the Acid Rain Program and by the 
NOX Budget Trading Program under the October 27, 1998 
NOX SIP Call. Certain changes to the proposed rule revisions 
have been made based on the public comments received. EPA is not 
finalizing the proposed changes at this time to the Appeal Procedures 
or to the Findings of Significant Contribution and Rulemaking on 
Section 126 Petitions for Purposes of Reducing Interstate Ozone 
Transport. Today's final rule establishes additional flexibility and 
options for sources in meeting the continuous emission monitoring 
system (CEMS) requirements under programs to reduce sulfur dioxide and 
nitrogen oxides emissions. These revisions may apply to sources that 
monitor and report emissions only during the ozone season, as well as 
to sources that monitor and report emissions for the entire year. The 
provisions in this final rule benefit the environment by ensuring that 
sulfur dioxide (S02), nitrogen oxides (NOX), and 
carbon dioxide (CO2) emissions are accurately monitored and 
reported, even as they benefit the affected industrial sources by 
creating opportunities to adopt cost saving procedures.

DATES: The effective date of this rule is July 12, 2002. However, 
regulated entities will have additional time to implement certain 
requirements, as described in Section V, Rule Implementation, and in 
the rule.

ADDRESSES: Docket. Supporting information, including public comments, 
used in developing the regulations is contained in Docket No. A-2000-
33. This docket is available for public inspection and photocopying 
between 8:00 a.m. and 5:30 p.m. Monday through Friday, excluding 
government holidays, and is located at: EPA Air Docket (MC 6102), Room 
M-1500, Waterside Mall, 401 M Street, SW, Washington, DC 20460. A 
reasonable fee may be charged for photocopying.

FOR FURTHER INFORMATION CONTACT: Gabrielle Stevens, Clean Air Markets 
Division (6204N), U.S. Environmental Protection Agency, 1200 
Pennsylvania Avenue, NW, Washington, DC 20460, telephone number (202) 
564-2681 or the Acid Rain Hotline at (202) 564-9620. This document and 
technical support documents can be accessed through the EPA Web site 
at: http://www.epa.gov/airmarkets.

SUPPLEMENTARY INFORMATION: A redline/strikeout version of 40 CFR parts 
72 and 75 as amended by this final rule is available in the Docket and 
on the EPA Web site referenced above. The contents of the preamble are 
listed in the following outline:

I. Regulated Entities
II. Background and Summary of Final Rule
III. Statutory Authority, Regulatory History, and Stakeholder 
Involvement
IV. Summary of Major Comments and Responses
    A. Missing Data
    1. What changes to the CEMS missing data procedures of 
Secs. 75.31 through 75.37 are finalized?
    2. How are the CEMS missing data provisions of subpart H 
affected by today's rule?
    3. What CEMS missing data provisions are finalized for units 
that do not produce electrical or thermal output?
    4. Will today's rule affect the way in which load ranges (or 
``bins'') are established for missing data purposes?
    B. Low Mass Emissions Units
    1. Does today's rule change the qualification requirements for 
low mass emissions units?
    2. How does today's rule change the certification application 
procedures and requirements for low mass emissions units?
    3. How will today's rule affect the way in which fuel- and unit-
specific NOX emission rates are determined for low mass 
emissions units?
    4. Does today's rule allow testing to be done at fewer than four 
load levels to determine fuel- and unit-specific NOX 
emission rates for low mass emissions units?
    C. Quality Assurance/Quality Control
    1. What changes to the method of determining the NOX 
MPC, MEC, span, and range are finalized in today's rule?
    2. What changes to the 7-day calibration error test are 
finalized?
    3. What changes to the QA/QC requirements for low-emitting 
sources are finalized?
    4. What changes to the stack flow-to-load ratio test are 
finalized?
    5. What special QA provisions are finalized for units that do 
not produce electrical output or steam load?
    D. Appendix D
    1. What changes to the definitions of ``pipeline natural gas'' 
and ``natural gas'' are finalized?
    2. How does today's rule change the method by which a gaseous 
fuel qualified as ``pipeline natural gas'' or ``natural gas''?
    3. How does today's rule change the fuel sampling and data 
reporting requirements for gaseous fuels other than pipeline natural 
gas and natural gas?
    4. What changes to the appendix D missing data procedures are 
finalized?
    E. Other Highlights and Changes
    1. What changes to the compliance dates and timelines for 
monitor certification in Sec. 75.4 are finalized in today's rule?
    2. Does today's rule change the way in which unit and stack 
operating hours are counted?
    3. Does today's rule change the notification requirements for 
monitor certifications and recertifications?
    4. Does today's rule affect the way in which emissions are 
monitored and reported for units with bypass stacks?
    5. What other noteworthy provisions are finalized in today's 
rule?
    F. Streamlining Changes
V. Rule Implementation
VI. Administrative Requirements
    A. Executive Order 12866: Regulatory Planning and Review
    B. Unfunded Mandates Reform Act
    C. Paperwork Reduction Act
    D. Regulatory Flexibility Act
    E. National Technology Transfer and Advancement Act
    F. Executive Order 13045: Protection of Children from 
Environmental Health Risks and Safety Risks
    G. Executive Order 13132: Federalism
    H. Executive Order 13175: Consultation and Coordination with 
Indian Tribal Governments
    I. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use
    J. Congressional Review Act

I. Regulated Entities

    Entities regulated by this action are fossil fuel-fired boilers, 
turbines, and combined cycle units that serve electric generators, 
produce steam, or cogenerate electricity and steam. While part 75 of 
title 40 of the Code of Federal Regulations (40 CFR) primarily 
regulates the electric utility industry, certain State and Federal 
NOX mass emissions programs also rely on 40 CFR part 75 
(subpart H), and those programs may include boilers, turbines, and 
combined cycle units from other industries. Regulated categories and 
entities include:

------------------------------------------------------------------------
             Category                  Examples of Regulated Entities
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Industry..........................  (1) Electric service providers.
                                    (2) Process sources with large
                                     boilers and turbines where
                                     emissions exhaust through a stack.
------------------------------------------------------------------------

    This table is not intended to be exhaustive, but rather to provide 
a guide

[[Page 40395]]

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 the table could also be regulated. To determine whether your 
facility, company, business, or organization is regulated by this 
action, you should carefully examine the applicability provisions in 40 
CFR 72.6, 72.7, and 72.8 and 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 of this preamble.

II. Background and Summary of Final Rule

    Today's action modifies existing monitoring and reporting 
requirements in 40 CFR parts 72 and 75. These requirements support 
emission control programs that use the monitoring and reporting 
provisions of part 75, such as the Acid Rain Program, and the 
NOX Budget Trading Program developed under the October 27, 
1998, NOX SIP Call. The emphasis of these revisions is 
three-fold: (1) To streamline the rule by eliminating outdated 
sections; (2) to make technical corrections and clarifications to the 
rule; and (3) to add flexibility to the monitoring and reporting 
requirements. The most substantive changes finalized are as follows: 
the definitions of ``pipeline natural gas'' and ``natural gas'' in 
Sec. 72.2 are finalized as proposed to remove all references to the 
H2S content of the fuel and instead be based on total sulfur 
content, along with corresponding changes appendix D to part 75; the 
low mass emissions (LME) units provisions in Sec. 75.19 are clarified 
and expanded and, for units with certain types of NOX 
emission controls, qualification as a LME unit is made easier; the CEMS 
missing data procedures are revised to allow fuel-specific missing data 
substitution; the missing data procedures in subpart H of part 75 are 
expanded and clarified for sources that are non-load based and/or 
report emission data only in the ozone season; the NOX span 
and range provisions in appendix A are revised to make them easier to 
implement for combustion turbines; and the alternate calibration error 
limit for daily operation is changed from 10 ppm to 5 ppm for units 
with span values of 50 ppm or less.
    EPA has developed a Response to Comment document (see Docket No. A-
2000-33, Item V-C-1) as a supplement to this preamble, which addresses 
all the comments received on the proposed rule revisions. Comments that 
were raised and are not addressed in this preamble are responded to in 
this supplemental document.

III. Statutory Authority, Regulatory History, and Stakeholder 
Involvement

    In accordance with titles I and IV of the Clean Air Act (CAA, or 
the Act), with today's action EPA is promulgating revisions to rules 
implementing programs that the Agency has established to mitigate 
interstate transport of nitrogen oxides, as well as to reduce the 
acidic deposition precursor emissions of sulfur dioxide and nitrogen 
oxides. EPA originally promulgated 40 CFR parts 72 and 75 on January 
11, 1993, to implement the Acid Rain Program as authorized by title IV 
of the Act. EPA has subsequently promulgated several final rules 
revising CEMS requirements in part 75 and relevant definitions in part 
72 (see below).
    Section 110 of the Act requires that State Implementation Plans 
(SIPs) prohibit sources from contributing significantly to 
nonattainment or maintenance of attainment in another State. On October 
27, 1998, EPA issued the NOX SIP Call, a final rule under 
section 110 requiring certain States to revise their SIPs to meet 
NOX emission budgets to prevent such significant 
contribution to ozone nonattainment. States may adopt in their SIPs a 
NOX Budget Trading Program for large electric generating 
units (EGUs) and large non-electric generating units (non-EGUs) and 
require such units to monitor under part 75. Further, section 126 of 
the Act authorizes EPA to directly regulate, and require reductions of 
NOX emissions from, sources that emit in violation of the 
prohibition in section 110 against significantly contributing to ozone 
nonattainment or maintenance problems in a downwind State. On January 
18, 2000, EPA published a finding that large EGUs and certain large 
non-EGUs in particular States named in petitions filed by several 
northeastern States emit NOX in violation of Section 126 of 
the CAA (65 FR 2674). In that same notice, the EPA finalized the 
Federal NOX Budget Trading Program in part 97 as the control 
remedy and required that these units monitor under part 75.
    In today's rule, the provisions of parts 72 and 75 are revised to 
modify the requirements for sources under the Acid Rain Program, the 
NOX SIP Call, and the Federal NOX Budget Trading 
Program.
    As noted above, the Agency first promulgated parts 72 and 75 under 
title IV on January 11, 1993. On May 17, 1995 and November 20, 1996, 
the Agency revised parts 72 and 75 to make implementation simpler (60 
FR 26510 and 61 FR 59142). On May 21, 1998, the Agency proposed 
additional revisions to parts 72 and 75 to make implementation easier 
and more efficient, to improve quality assurance requirements, and to 
create new alternative monitoring options (63 FR 28032). EPA 
promulgated final rule revisions addressing some of these additional 
proposed revisions, based on comments received, when EPA promulgated 
the NOX SIP Call (63 FR 57356). On May 26, 1999, EPA issued 
final rule revisions addressing the remaining May 21, 1998 proposed 
revisions (64 FR 28564). On June 13, 2001, EPA proposed further 
revisions to parts 72, 75, 78, and 97 (66 FR 31978). The revisions to 
parts 72 and 75 are being finalized in today's rule, while the changes 
to parts 78 and 97 will be addressed in a later rulemaking.
    Throughout the implementation of the Acid Rain Program, 
particularly since 1995, EPA has worked and continues to work on a 
regular basis with stakeholders, the regulated community, the public, 
other state and local agencies, and environmental groups and 
consultants. Internally, EPA holds frequent policy meetings to discuss 
many of the questions and problems that affected sources raise to their 
Regional contact in EPA. Many of the changes in today's rule result 
from industry petitions to the Agency as well as comments, phone calls, 
and dialogues during conferences and workshops. Most recently, EPA 
conducted two conferences in July (Louisville, KY) and September 
(Alexandria, VA) of 2001, and then initiated five regional workshops 
targeted at the regulated community and state agencies to support the 
Acid Rain Program and assist in implementing the NOX Budget 
Trading Program. EPA is committed to this ongoing interaction with 
stakeholders across all spectra.

IV. Summary of Major Comments and Responses

    EPA responded to all comments received by the close of the extended 
comment period, August 20, 2001, regarding the current proposal. EPA's 
responses are summarized in this section of the preamble and are 
available in their entirety in the Response to Comment document in the 
rule docket (see Docket No. A-2000-33, Item V-C-1). The majority of 
comments related to parts 72 and 75; therefore, this section addresses 
those issues. Revisions to part 78 received no comments, and revisions 
to part 97 received only two comments, both of which are addressed in 
the Response to

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Comment document. As noted above, EPA intends to finalize changes to 
part 78 and 97 in a separate rulemaking. The major topics in part 75 
that EPA is focusing on in this section are: missing data; LME units; 
quality assurance and quality control (QA/QC); appendix D; other 
highlights and changes; and streamlining changes.

A. Missing Data

1. What Changes to the CEMS Missing Data Procedures of Secs. 75.31 
Through 75.37 Are Finalized?
Background
a. What is Currently Required?
    The part 75 CEMS missing data procedures in Secs. 75.31 through 
75.37 require the use of substitute data values for each unit operating 
hour in which quality-assured data are not obtained, either from a 
certified CEMS, a reference method, or an approved alternative 
monitoring system. The method of determining the appropriate substitute 
data values depends principally on two things: (1) the length of the 
missing data period; and (2) the percent monitor data availability at 
the end of the missing data period.
    Existing part 75 missing data procedures do not take into 
consideration the type of fuel combusted. Rather, a single database of 
quality-assured monitor operating hours is maintained for each 
monitored parameter (e.g., SO2, NOX, flow rate) 
in order to provide substitute data values when a historical lookback 
is required.
    For units with add-on SO2 or NOX emission 
controls, Sec. 75.34 allows two principal missing data options. The 
owner or operator may either: (1) Report maximum potential values or, 
if the controls are documented to be operating properly, report the 
standard missing data procedures; or (2) petition the Administrator to 
develop and use site-specific parametric monitoring procedures for 
missing data substitution in lieu of using the standard missing data 
procedures. Section 75.34(a)(2) also allows the owner or operator to 
petition the Administrator for permission to report the maximum 
controlled emission rate recorded in the previous 720 quality-assured 
monitor operating hours (without regard to control operational status), 
in cases where the standard missing data routines would require the 
maximum value in the lookback period to be reported.
b. What Changes Were Proposed?
    On June 13, 2001, EPA proposed to revise the part 75 missing data 
procedures to allow the standard missing data substitution in 
Sec. 75.33 to be done on a fuel-specific basis. The proposed revisions 
would allow the owner or operator to create and maintain separate 
databases for missing data purposes for each type of fuel combusted in 
the unit. Substitute data values would be derived from the appropriate 
database, depending on the type of fuel being burned during the missing 
data period.
    For units with add-on SO2 or NOX emission 
controls, EPA further proposed to remove the petition provision from 
Sec. 75.34(a)(2) and replace it with a new missing data option, based 
on the operating status of the emission controls. The owner or operator 
of a unit with add-on SO2 or NOX emission 
controls would be allowed to create and maintain two separate 
databases, controlled and uncontrolled, for missing data purposes. Any 
hour in which the add-on controls were documented to be operating 
(i.e., on) would be included in the controlled database. Any hour in 
which the controls were not operating (i.e., off) would be included in 
the uncontrolled database. The appropriate substitute data value for 
each hour of a missing data period would be taken from either the 
controlled or uncontrolled database, depending on whether the emission 
controls were documented (by means of parametric data) to be operating 
properly during the hour.
    EPA also proposed to change the way in which parametric data are 
used to document proper operation of add-on emission controls during 
periods of missing SO2 or NOX data. Proposed 
Sec. 75.34(d) would require the owner or operator to establish a 
demonstrable correlation between the parametric data and control device 
removal efficiency, as part of the QA/QC program for the unit. The 
correlation would be based on a minimum of 720 hours of parametric data 
recorded during unit operation, when the add-on controls are in-service 
and the SO2 or NOX monitor at the control device 
outlet is providing quality-assured data. The correlation would serve 
as the basis for determining whether substitute data values should be 
taken from the controlled database or from the uncontrolled database 
during periods of missing SO2 or NOX data.
c. What Changes Is EPA Finalizing?
    Today's rule finalizes the fuel-specific missing data option, with 
some editorial changes including new language addressing the co-firing 
of fuels (see Discussion, below). However, based on comments received, 
EPA is not adopting the other proposed missing data option, which would 
have allowed the owners or operators of units with add-on emission 
controls to separate their data into controlled and uncontrolled 
databases. The final rule replaces, in response to these comments, the 
proposed option with a provision that accomplishes a similar objective 
with respect to seasonally operated control devices, without requiring 
control device operational status to be documented. The replacement 
provision allows subpart H sources that report data on a year-round 
basis to separate their quality-assured NOX emission data 
into ozone season data and non-ozone season data for missing data 
purposes. The final rule also retains the provision in Sec. 75.34 which 
allows sources to petition to report the maximum controlled emission 
rate in a 720-hour lookback period.
Discussion
    Two commenters were supportive of the proposed fuel-specific 
missing data option (Utility Air Regulatory Group (UARG); Clean Energy 
Group). However, another commenter asked EPA to explain what it means 
to create and maintain a ``separate database'' for each fuel or blend, 
and also asked how a ``blend'' is determined (KVB-Enertec (KVB)). Two 
commenters questioned how these proposed missing data procedures would 
be implemented for units that sometimes co-fire different types of fuel 
(UARG, KVB). Specifically, the commenters expressed concern about 
having to maintain an extra database for co-fired hours. One of the 
commenters suggested keeping only single-fuel databases and pro-rating 
the missing data values during co-fired hours (UARG).
    Based on these comments, EPA incorporates the fuel-specific missing 
data option into today's rule, although the final rule language is 
somewhat modified from the proposal. The final rule differs from the 
proposal in that it provides for greater flexibility in how to 
implement the new missing data option. Paragraphs (b)(6) and (c)(8) in 
Sec. 75.33 give more general implementation guidelines, rather than 
providing detailed instructions. Regarding the comments about co-
firing, while EPA agrees that it is desirable to maintain as few 
databases as possible, the Agency did not incorporate the commenter's 
suggested approach because the commenter did not provide an adequate 
explanation of how it would work. However, today's rule provides an 
alternative to maintaining separate databases for co-fired hours for 
units that co-fire fuels and elect to use the fuel-specific missing 
data option. The final rule allows the owner or operator to keep 
single-fuel databases, provided

[[Page 40397]]

that the database for the fuel with the higher emission rate is used to 
provide substitute data values during co-fired hours.
    Regarding the Agency's proposal to provide a control status-
specific missing data option for units with add-on SO2 and 
NOX emission controls, two commenters supported the concept 
of this option (UARG, Clean Energy Group). However, strenuous 
objections were raised to the proposed method of documenting proper 
operation of the add-on controls (UARG; Robert Machaver (Machaver)). In 
particular, the commenters objected to the potential high cost of 
developing complex correlations between parametric data and control 
device removal efficiency and questioned the usefulness and reliability 
of such correlations. One commenter also objected to removing the 
petition provision from Sec. 75.34(a)(2), which would allow the source 
to report the maximum controlled value in a 720-hour lookback period 
(UARG).
    After careful consideration of the comments, EPA replaces the 
proposed missing data option with a procedure that will achieve the 
objective of the proposal for seasonally operated controls, without 
being dependent on the operational status of the add-on emission 
controls. The Agency also is not adopting the requirement to develop a 
correlation between control device removal efficiency and parametric 
data to demonstrate proper operation of the add-on emission controls, 
principally in response to the objections of the commenters to the cost 
and level of effort needed to develop correlations between parametric 
data and control device removal efficiency. The original rule language 
in Sec. 75.34(d) is retained, requiring sources to specify in the 
quality assurance (QA) plan for the unit the essential parameters and 
ranges needed to verify proper operation of the add-on emission 
controls.
    It should be noted that one of the principal reasons EPA proposed 
the control status-specific missing data option in Sec. 75.34(a)(2) for 
units with add-on emission controls was to accommodate units that are 
subject to the Federal NOX Budget Trading Program (which is 
being implemented as a result of the NOX SIP Call). In 
particular, many units required to report NOX emissions data 
on a year-round basis will operate their add-on NOX emission 
controls only during the ozone season, in order to comply with the 
NOX emission reduction requirements of the NOX 
SIP Call. The proposed missing data option would have allowed these 
sources to separate their uncontrolled and controlled emission data, 
thereby providing a more equitable scheme for missing data 
substitution.
    After further consideration, taking into account the supportive 
comments for the concept of the proposed missing data option, EPA 
believes that the objective of the option can be accomplished in a 
different way, without requiring separate controlled and uncontrolled 
databases to be maintained or that any parametric correlations be 
developed. Accordingly, Sec. 75.34(a)(2) of today's rule allows the 
owner or operator to separate the historical, quality-assured 
NOX emissions data into ozone season and non-ozone season 
NOX data, for missing data purposes. Use of this missing 
data option is limited to units that report NOX mass 
emissions data on a year-round basis under subpart H of part 75, and 
that operate their NOX emission controls only during the 
ozone season, or in a less efficient manner outside the ozone season. 
During periods of NOX missing data, revised Sec. 75.34(a)(2) 
specifies that the appropriate substitute data values are to be drawn 
from one database or the other, depending on whether the missing data 
period is inside or outside the ozone season. Missing data periods that 
begin outside the ozone season and continue into the ozone season are 
treated as two separate missing data incidents, one ending on April 30, 
hour 23, and one beginning on May 1, hour 00. Further, the standard 
NOX missing data algorithms may be applied at all times 
during the non-ozone season missing data periods, without any 
requirement to record parametric data to verify proper operation of 
add-on controls.
2. How Are the CEMS Missing Data Provisions of Subpart H Affected by 
Today's Rule?
Background
a. What Is Currently Required?
    The missing data procedures for units which are subject to a State 
or Federal NOX mass emissions reduction program and must 
monitor NOX mass emissions according to subpart H of part 75 
are specified in Secs. 75.70(f) and 75.74(c)(7). Section 75.70(f) 
requires the initial and standard missing data procedures of 
Secs. 75.31 through 75.37 to be used for sources that report emission 
data on a year-round basis. Section 75.74(c)(7) requires subpart H 
sources that report data on an ozone season-only basis to use the 
missing data procedures of Secs. 75.31 through 75.37 also, except that 
only data from within the ozone season are to be used in the historical 
lookbacks.
b. What Changes Were Proposed?
    On June 13, 2001, EPA proposed to revise Sec. 75.74(c)(7) by adding 
a new paragraph (iii), with subparagraphs (A) through (M), explaining 
how to apply the part 75 missing data procedures in Secs. 75.31 through 
75.37 on an ozone season-only basis. EPA proposed adding these 
provisions to subpart H because the part 75 missing data routines are 
designed for sources that report emission data on a year-round basis. 
Thus, for all of the part 75 standard missing data routines that use 
720 or 2,160 hour historical lookbacks to determine the appropriate 
substitute data values, the databases for the lookbacks include all of 
the quality-assured CEMS data that have been recorded throughout the 
year. Also, the percent monitor data availability (PMA) calculations 
described in Sec. 75.32, which are always based on a particular number 
of unit operating hours, include unit operating hours from all four 
calendar quarters of the year.
    Proposed Sec. 75.74(c)(7)(iii) would modify the initial and 
standard part 75 missing data procedures in Secs. 75.31 through 75.37 
to adapt them to sources that report emission data only during the 
ozone season. The missing data instructions for ozone season-only 
reporters were written in a parallel manner to the missing data 
procedures for year-round reporters.
c. What Changes Is EPA Finalizing?
    Today's rule finalizes the changes to Sec. 75.74(c)(7) as proposed, 
except that for both PMA calculations and historical missing data 
lookbacks, the lookback periods would be limited to three years (26,280 
clock hours) prior to the missing data period, rather than three ozone 
seasons as proposed.
    EPA further notes that the fuel-specific missing data option 
described above in question 1 of this section is available to all 
subpart H sources, and the option to create and maintain separate ozone 
season and non-ozone season databases for missing data purposes is 
available to subpart H sources that report emissions data on a year-
round basis.
Discussion
    EPA received only one comment on the proposed missing data 
revisions to Sec. 75.74(c)(7). The commenter recommended that the 
lookback period be limited to three years prior to each missing data 
period rather than three ozone seasons as proposed (Environmental 
Systems Corporation (ESC)). Another commenter questioned similar 
language found in proposed

[[Page 40398]]

Sec. 75.33(c)(9), i.e., the parenthetical expression ``(or three ozone 
seasons)'' next to the words, ``three years'', referring to missing 
data lookbacks (Monitor Labs (Monitor)). EPA agrees with the commenters 
that for the purposes of missing data lookbacks, consistency is 
essential. For both year-round reporters and sources that report 
emissions on an ozone season-only basis, no data recorded more than 
three years prior to the missing data period should be used in the 
historical lookbacks. Therefore, in today's rule, all references in 
Sec. 75.33, Sec. 75.74(c)(7)(iii), and elsewhere to data recorded in 
the previous three ozone seasons are removed and replaced with 
references to the previous three years.
3. What CEMS Missing Data Provisions Are Finalized for Units That Do 
Not Produce Electrical or Thermal Output?
Background
    One of the main objectives of the June 13, 2001, proposed rule was 
to modify the existing monitoring and reporting sections of parts 72 
and 75 that apply to NOX emission reduction programs, such 
as the Federal NOX Budget Trading Program developed in 
response to the October 27, 1998 SIP call. Under the NOX SIP 
call, States have the flexibility to include stationary sources other 
than EGUs in their NOX reduction plans. Some of these non-
EGUs (such as cement kilns and refinery process heaters) do not produce 
electrical or thermal output, i.e., ``load.''
a. What Is Currently Required?
    EPA examined the part 75 missing data provisions to assess whether 
those provisions are adequate for determining NOX mass 
emissions from non-EGUs. As a result of this assessment, EPA concluded 
that for industrial boilers which produce steam load and which are very 
similar to electric utility boilers, no significant changes to the 
missing data provisions of part 75 would be required. However, for 
cement kilns and refinery process heaters which do not produce 
electricity or steam load, EPA concluded that modifications to the 
missing data routines for NOX concentration, NOX 
emission rate, stack flow rate, and fuel flow rate would be necessary, 
since these missing data routines are load-dependent.
b. What Changes Were Proposed?
    On June 13, 2001, EPA proposed non-load-based missing data routines 
which are modeled after, and are much the same as, the existing 
routines for load-based units, with one important difference: the owner 
or operator of a non-load-based unit would have a choice to define and 
use ``operational bins'' to segregate the quality-assured emissions 
data, or not to use operational bins at all.
    The reason EPA proposed allowing the use of operational bins was to 
give affected facilities the flexibility to customize their missing 
data routines, based on plant operational parameters and conditions 
that affect NOX emissions, stack flow rate, or fuel flow 
rate. The procedures and requirements for defining operational bins 
were proposed as new sections 3 and 4 of appendix C to part 75. These 
new provisions would require the owner or operator to provide a 
complete description of each operational bin in the hardcopy portion of 
the monitoring plan and to monitor the operating conditions used to 
define the operational bin.
c. What Changes Is EPA Finalizing?
    Today's rule finalizes the missing data provisions for units that 
do not produce electrical or steam load. The final rule differs from 
the proposal in the following ways: (1) In Table 3, the algorithms 
requiring a comparison of the average value in a 2,160 lookback period 
against the 90th (or 95th) percentile value have been simplified to 
require that just the percentile value be reported (the reasons for 
this change are given in the Discussion immediately below); and (2) 
proposed section 4 of appendix C, which would have allowed the use of 
operational bins for fuel flow rate missing data, is not adopted (the 
reasons for not finalizing that option are explained in detail in the 
Discussion in Section IV. D.4. of this preamble).
Discussion
    EPA received comments on the proposed missing data provisions for 
non-load-based units from only two commenters (KVB; American Portland 
Cement Alliance (APCA)). The first commenter stated that the rule 
should provide a clear way of defining ``operational bins'' (KVB). The 
second commenter fully supported the proposed operational bin 
provisions, but objected to the use of 90th percentile, 95th 
percentile, and maximum values in the missing data lookback periods for 
NOX and flow rate, claiming that these percentile values, 
which may be reasonable for EGUs, are unfairly punitive for the 
affected units in the commenter's industry (APCA). The second commenter 
included supplementary data previously presented to EPA in 1999 (see 
Docket No. A-2000-33, Item II-C-2) and proposed an alternate missing 
data protocol, using a ``percent-above-average'' approach in lieu of 
using the 90th percentile, 95th percentile, and maximum values. The 
commenter asked EPA to revisit the Agency's prior data analysis, 
claiming that EPA's previous analysis had overstated the variability of 
EGU emission data by not taking certain factors into consideration. EPA 
declines to adopt the commenter's percent-above-average proposal, and 
concludes that no additional data analysis is necessary in order to 
support an appropriate missing data routine for non-load units.
    The most significant reason that EPA rejects the commenter's 
proposal is because the proposal rests on a fundamental 
misunderstanding of the basis and purpose of the missing data 
procedures. As stated in previous meetings and conversations with the 
commenter and in EPA's detailed written response, sent to the commenter 
on November 22, 2000 (see Docket No. A-2000-33, Item II-C-3), the key 
issue is the following: the missing data procedure in 40 CFR part 75 is 
designed to provide substitute values strictly relative to a unit's own 
emissions history, not compared to the emissions history of the 
universe of all units, as would be the case using the proposed percent-
above-average multiplier.
    The missing data procedure strictly pertains to the monitoring of 
emissions, not to the operation of a unit. It implements Section 412(d) 
of the CAA which mandates EPA's Administrator to prescribe a means to 
calculate emission values during periods when data from the certified 
monitor is unavailable. The purpose is to substitute a value that is 
not lower than the unknown actual value for an improperly operated 
monitor. This means that a comparison of the variability of one unit's 
emission data to another unit's emission data (or to a class of other 
units' emission data), or a comparison of emission levels at one unit 
relative to another unit (or class of units), is not relevant in 
assessing the applicability of the missing data procedure. This can be 
seen both in the regulatory history and the structure of the missing 
data procedure.
    As stated in the preamble to the original 40 CFR part 75 
regulations published in the Federal Register on January 11, 1993 (58 
FR 3635), the primary intent in developing the missing data procedure 
was to provide a ``substantial incentive to improve monitor 
availability'' (58 FR 3637). To provide this substantial incentive, the 
Agency originally considered proposals to use only the maximum previous 
value recorded and the average of the five highest previously recorded 
values,

[[Page 40399]]

and finally settled on the current tiered approach. All of the 
approaches, contemplated and adopted, were premised on providing an 
incentive to keep monitors operational by requiring substitution of 
either the maximum value previously recorded at each specific facility 
or a value higher than at least 90 percent (for shorter monitor 
outages) or 95 percent (for longer monitor outages) of the values 
previously recorded at the specific unit. None of the approaches 
offered variations based on differences in emission variability or 
emission levels encountered at different units. To do so would have 
been contrary to the goal of providing, for each and every unit, a 
``substantial incentive to improve monitor availability'' (58 FR 3637, 
January 11, 1993).
    The commenter, on the other hand, proposes using a multiplier which 
is based on the averaged emissions history of a different set of units, 
that of utility units, which in aggregate would not display the high 
emissions excursions that are typical of cement kilns. The commenter 
does not dispute the need for a missing data procedure as an important 
component of a monitoring program; just its application during times of 
long monitor outage and low monitor availability--exactly the times 
that the missing data routine was designed to limit. Their proposal 
suggests using the ``percent above the average for each percentile as 
calculated from the electric utility boiler data to the cement kiln 
data.'' This proposal underscores the commenter's misunderstanding 
about the purpose of missing data.
    Use of the commenter's proposed percentage-above-average multiplier 
would mean that even in situations of substantial monitor outages 
(representing as much as 20 percent of a monitoring year), kilns whose 
own emission history displayed frequent excursions into high emission 
levels (as illustrated, for example, in commenter's Figure 1, page 2 of 
the attachment to Docket No. A-2000-33, Item IV-D-2) would substitute 
values substantially below these high excursions. The proposed 
procedure could have an effect completely contrary to the regulatory 
intent of the missing data procedure, i.e., providing an incentive to 
improve monitor availability. In fact, EPA believes this approach, were 
it to be employed, would cause a reverse incentive to turn off monitors 
at affected facilities. The commenter acknowledges that the 
NOX emitted from their facilities is thermal NOX, 
which is a critical aspect of the product's quality control. Because 
temperatures are product-related, they are carefully monitored. 
Operators may be able to predict, therefore, when emissions are high. 
Because of the market value of emissions, the percent-above-average 
multiplier approach may encourage sources to turn off monitors at 
higher fuel flow rates or higher kiln temperatures when NOX 
emissions might increase. EPA experienced similar concerns with the 
utility industry in the early 1990s, when a diverse array of commenters 
recommended that EPA provide sufficiently punitive procedures to ensure 
that there would be an ``effective deterrent to deliberate shutdowns of 
CEMS during period of high emissions' (58 FR 3637, January 11, 1993). 
These concerns were a factor in the final approach that was adopted.
    The commenter's methodology is inconsistent with the purpose of 
missing data. The commenter misconstrues the concept of missing data 
substitution and its implementation by stating that missing data 
routines were created to encourage three activities: maintaining CEMS; 
getting malfunctioning CEMS back on line quickly; and operating power 
plants efficiently so as to avoid NOX spikes. While the 
first two points are correct, the third ``activity'' has never been a 
purpose of missing data. Rather, it is a consequence of efficient plant 
operations which has some ancillary benefits. Operating bins, discussed 
later, afford similar benefits to kiln operators. In fact, there are 
numerous options available to kiln operators, as there are for EGUs, to 
minimize the need for and impacts of missing data routines. For 
instance, in the early years of monitoring, some utilities that were 
initially concerned about missing data protocols installed redundant 
backup systems so that if one monitor went down, another was available 
and no missing data period would be incurred. Others bought ``like-kind 
replacement analyzers'' that were also available should the primary 
monitor not perform. However, over time, many of these sources have 
found that these options were not necessary because, through proper 
maintenance of the CEMS, performance is usually not an issue. The 
commenter's analysis does not consider these options.
    The commenter also claims that ``facilities with less reliable 
CEMS'' need tailored missing data protocols ``to represent the 
realities of cement manufacturing.'' EPA does not believe that this 
comment presents a relevant issue. The commenter has provided no 
evidence to demonstrate any basis for monitors to perform less reliably 
on cement kilns. The NOX concentration monitor and stack 
flow monitor (critical CEMS components) that are installed on a cement 
kiln stack are no different from those that might be installed at a 
coal-fired utility boiler. APCA indicates that most of its companies 
burn coal as fuel in their cement making process. The result of burning 
coal, just like in a utility boiler, is a gas that exits the kiln 
through a stack. The CEMS samples that gas on minute-by-minute 
intervals in order to come up with a quality assured operating hour of 
data, which is banked in a data acquisition and handling system (DAHS). 
The only time the owner or operator of a cement kiln will have to use 
the missing data substitution protocol is when the CEMS is out of order 
or not operating properly. Utilities are currently maintaining CEMS at 
above 99 percent availability, up from around 95 percent when CEMS were 
first installed on utility boilers under the Acid Rain Program in the 
mid 1990s.
    The commenter has also suggested that the standard missing data 
procedure creates an equity issue, and that EPA is penalizing the 
cement industry unfairly because of its high variability. EPA disagrees 
with the commenter. EPA requires that all continuous emission monitors 
be continuously maintained and operated and has created an incentive 
structure, in the form of missing data procedures, to ensure this. 
Studies have demonstrated variability, comparable to that which APCA 
claims for cement kilns, for utility units in the pre- and post-control 
mode (see Docket No. A-92-15, Item II-I-26). EPA has demonstrated in 
previous data analyses and correspondence with the commenter (see 
Docket No. A-2000-33, Items II-C-2 and II-C-3) that there are many EGUs 
with variability of NOX emission rate comparable to that for 
the cement kilns. EPA examined data from more than 1,000 utility 
boilers and compared it to the limited data submitted by the commenter 
for seven cement kilns out of the approximately 200 kilns operating in 
the U.S.. EPA's intent in performing the data analysis was to show 
that, even taken at face value, the commenter's contention is without 
merit: a statistical analysis of the data showed that there are EGUs 
with just as much emission rate variability (reflected as relative 
standard deviation). Consequently, EPA does not accept the premise of 
the commenter's concern.
    Further, it is important to note that many utilities have done an 
exceptional job, over time, of reducing emission variability. EPA would 
also note that the cement industry data analysis did not

[[Page 40400]]

reflect data stratification into operational bins. At the commenter's 
suggestion, EPA has proposed the use of ``operational bins'' which 
allow emissions data to be sub-categorized for missing data purposes 
(e.g., for mid-kiln injection of fuel, a bin for injection system on 
and a bin for injection system off). These operational bins are 
analogous to the load bins available to EGUs, and will allow non-load 
units to avoid unnecessarily reporting the highest missing data value, 
if they can show that during the time CEMS are not operational the unit 
was in an operating bin for which a ``lower'' highest missing data 
value applies. The Agency is confident that application of the 
operating bin concept will reduce the conservatism of missing data 
procedures for kilns.
    The commenter also suggests that EPA's proposal to remove the hour 
before/hour after (HB/HA) algorithm from the missing data routine for 
non-load based units suggests that the Agency concedes that kilns are 
more variable than EGUs. To the contrary, the purpose of the HB/HA 
option, as applied to load based units, is to capture the fact that 
units may be operated for extended periods at peak load. In such a 
case, a unit at its maximum load and maximum emissions may actually 
have greater than the 95th percentile emissions (i.e., the 95th 
percentile may be too low a number under such conditions to substitute 
for the unknown value). So the HB/HA provision was developed to 
potentially capture such incidents by providing, during periods of long 
outages, a substitute value which is the greater of the HB/HA or the 
90th (or 95th) percentile in a 2,160 hour lookback period. Based on 
commenter-provided data for seven cement kilns, EPA initially suspected 
that short-term variability could cause the application of HB/HA to be 
punitive. However, although the Agency has concerns relating to the 
representation of industry data, we believe that there is little risk 
in deferring applicability of the provision until such time as 
sufficient information is available on an operating bin basis to assess 
the effectiveness of percentile based data substitution. EPA reserves 
the right to examine cement kiln data that is reported in the future 
and reconsider whether or not this decision is appropriate.
    As an alternative, in the June 13, 2001 proposed rule revisions, 
EPA proposed to replace the HB/HA criterion with the average value in a 
2,160-hour lookback period in the NOX missing data 
algorithms in Table 3. The commenter has correctly pointed out in 
comments on the proposal that EPA's proposed replacement for the HB/HA 
criterion in Table 3 (i.e., comparison of the average in the 2,160 hour 
lookback period and 90th or 95th percentile value of the same set of 
data) is technically unsound. The proposed replacement algorithms that 
require the ``higher of'' the 90th (or 95th) percentile value or the 
average value to be reported are meaningless, since the 90th or 95th 
percentile values will always be higher than the average for the same 
data set. Therefore, in the interest of regulatory clarification, Table 
3 has been modified to eliminate the required comparison of averages 
and higher percentiles, simply leaving in place the percentile 
requirement.
    In view of the these considerations, in today's rule EPA finalizes 
the missing data provisions as proposed for both load-based and non-
load-based units, save for the revision to Table 3 that removes the 
requirement for the average versus percentile value comparisons.
4. Will Today's Rule Affect the Way in Which Load Ranges (or ``Bins'') 
Are Established for Missing Data Purposes?
Background
a. What Is Currently Required?
    Section 2 of appendix C to part 75 provides a procedure for 
establishing missing data load ranges (``bins'') for NOX 
emission rate, NOX concentration, stack flow rate and fuel 
flow rate. The procedure consists of establishing 10 (or, in some 
cases, 20) load ranges, which are defined as percentages of the maximum 
hourly gross load of the unit.
b. What Changes Were Proposed?
    EPA proposed to revise section 2.2.1 of appendix C, particularly 
the method of determining the maximum hourly average gross load (MHGL) 
for cogeneration units or other units for which some portion of the 
heat input is not used to produce electricity. The MHGL for such units 
would be determined by converting the maximum rated hourly heat input 
of the unit to an equivalent electrical output in megawatts. The 
maximum rated hourly unit heat input would include the maximum 
potential heat input from auxiliary combustion sources, such as duct 
burners or auxiliary boilers. The efficiency of the unit would be used 
in conjunction with the maximum unit heat input to calculate the MHGL. 
Having established the maximum hourly gross load, the missing data load 
ranges would then be determined as percentages of the MHGL.
c. What Changes Is EPA Finalizing?
    EPA is not adopting these proposed changes, based on the comments 
received. Today's final rule retains the existing text of section 2.2.1 
of appendix C.
Discussion
    EPA received significant adverse comments on the proposed changes 
to section 2.2.1 of appendix C. Two commenters objected to the proposed 
removal of the option to use hourly gross steam load to establish the 
load bins (UARG, Machaver). The commenters also raised technical 
questions and issues. Concerns were expressed that the proposed method 
of converting heat input to equivalent electrical output would 
underestimate the electrical output of the steam turbine for combined 
cycle units, and that the method does not provide a means of accounting 
for hourly load contributions from the duct burner during fuel flowrate 
missing data periods (UARG, Machaver). After consideration of these 
comments, EPA is not finalizing the proposed changes to section 2.2.1 
and retains the existing rule text.
B. Low Mass Emissions Units
1. Does Today's Rule Change the Qualification Requirements for Low Mass 
Emissions Units?
Background
a. What Is Currently Required?
    In October, 1998, EPA promulgated the low mass emissions (LME) 
methodology in Sec. 75.19, which provides certain qualifying units an 
alternative means of complying with part 75 without installing 
continuous monitoring systems. For an Acid Rain Program unit to qualify 
to use the LME methodology, Sec. 75.19(a) states that the unit must be 
oil- or gas-fired, combusting only natural gas or fuel oil, and must 
demonstrate that its emissions do not exceed 25 tons of SO2 
and 50 tons of NOX per year. This demonstration must 
consider both actual (or projected) emissions and emissions calculated 
as set forth in Sec. 75.19. For a non-Acid Rain unit subject to a State 
or Federal NOX emissions reduction program that adopts the 
monitoring provisions of subpart H of part 75, if the unit reports 
NOX mass emission data only during the ozone season, 
Sec. 75.74(c)(10) states that the unit can qualify for LME status if it 
demonstrates that its emissions do not exceed 25 tons of NOX 
per ozone season. The existing text of part 75 does not specify a LME 
NOX emission

[[Page 40401]]

threshold for non-Acid Rain subpart H units that report emissions data 
on a year-round basis.
b. What Changes Were Proposed?
    On June 13, 2001, EPA proposed to revise paragraph (a) of 
Sec. 75.19 to more clearly state the LME applicability criteria for 
Acid Rain Program units and non-Acid Rain subpart H units. The 
revisions would make a distinction between sources that report emission 
data on a year-round basis and those that report data only during the 
ozone season. These changes were proposed to help owners and operators 
of non-Acid Rain Program units to more easily determine whether a unit 
can qualify for LME status. EPA proposed to clarify what the LME 
thresholds are for Acid Rain Program units and subpart H units.
    EPA also proposed to make a minor revision to the definition of a 
LME unit in Sec. 75.19(a)(1) by removing from the definition the terms 
``gas-fired'' and ``oil-fired'' and adding a parenthetical, ``(i.e., 
diesel fuel or residual oil)'' after the words, ``fuel oil''. The 
Agency did not propose to expand the use of LME methodology beyond 
units that burn fuel oil and natural gas.
c. What Changes Is EPA Finalizing?
    EPA received substantive comments on the proposed clarification of 
the applicability of the LME methodology, requesting that the criteria 
to qualify for LME status be made less restrictive. In response to 
these comments, today's rule increases the NOX low mass 
emissions threshold for year-round reporters from 50 to less than 100 
tons per year and increases the NOX low mass emissions 
threshold for ozone season-only reporters from 25 to 50 tons per ozone 
season. For units that choose to (or are required to) report emissions 
data on a year-round basis, no more than 50 tons of the annual 
NOX limit may be emitted during the ozone season. Today's 
rule also revises the definition of a ``low mass emissions unit'' in 
Sec. 72.2 , expanding the applicability of the LME provisions to 
include units that burn gaseous fuels other than natural gas.
Discussion
    Two commenters requested that EPA raise the NOX emission 
thresholds for LME qualification (KeySpan Corporation (KeySpan); PSEG 
Fossil LLC (PSEG)). One commenter recommended raising the annual 
NOX threshold to 100 tons per year, noting that many peaking 
units emit less than 100 tons of NOX per year and that such 
units are often unmanned, making it difficult to properly maintain and 
operate continuous monitoring systems (KeySpan). Another commenter 
asked EPA to consider raising the LME threshold for ozone season-only 
reporters to 100 tons per ozone season (PSEG). In response to these 
recommended rule changes, EPA performed additional data analysis to see 
if raising the LME thresholds for NOX could be justified, 
consistent with the principles EPA articulated in the 1998 rule for 
limiting eligibility to use LME. The results of that data analysis 
showed that raising the annual NOX threshold from 50 to 
under 100 tons per year and increasing the ozone season threshold from 
25 to 50 tons per ozone season are both defensible and consistent with 
the Agency's original intent, and accomplish Clean Air Act objectives. 
In the October 27, 1998 final rule, Finding of Significant Contribution 
and Rulemaking for Certain States in the Ozone Transport Assessment 
Group (OTAG) Region for Purposes of Reducing Regional Transport of 
Ozone (63 FR 57485), EPA laid out the applicability criteria for LMEs 
and initially concluded that NOX thresholds as high as those 
adopted today would result in inappropriate types of sources being able 
to use LME, and in too many tons of NOX emissions being 
exempted from CEMS. However, based on the extensive data EPA has 
subsequently collected under the Acid Rain Program and the Ozone 
Transport Commission (OTC) NOX Budget Program, and in 
response to numerous persuasive source-specific petitions as well as 
comments on the proposed rulemaking, EPA has re-assessed its position 
in 1998, and now concludes that a cutoff of less than 100 tons 
NOX per year, no more than 50 tons of which may be emitted 
in any ozone season, is both defensible and reasonable, as discussed 
below.
    There are a number of reasons that the Agency is electing to reopen 
this issue at this time. First, a considerable number of units that 
currently are not subject to the Acid Rain Program (ARP), and thus part 
75 monitoring, will be required to continuously monitor their emissions 
under part 75 as a result of the implementation of the NOX 
SIP Call. These units include a number of smaller existing units that 
Congress explicitly exempted from the Acid Rain Program under title IV 
of the Act. Some of these turbines currently monitor under the 
provisions of the OTC NOX Budget Program, generally by using 
default monitoring approaches, while others are located in other 
NOX SIP Call States. In addition, these units include units 
less than 25 MWe that some OTC States have included in their 
NOX SIP Call programs, as well as non-EGUs that are covered 
by the NOX SIP Call. In some States, these units become 
subject to part 75 monitoring as early as the 2002 ozone season as part 
of the States' implementation of their NOX SIP Call-related 
programs. These non-Acid Rain Program units face the expenditure of 
considerable resources to measure a rather limited portion of the total 
NOX emissions.
    Also, many new units being built to fulfill increased electricity 
demand are unmanned, gas-fired turbines with low NOX burner 
technology. These units, in many cases, will be required to account for 
emissions under State implementation plans to reduce NOX in 
the NOX SIP Call regions of the eastern United States. 
Unlike units with add-on technologies (such as selective catalytic 
reduction (SCR)) where continual oversight is required to maintain low 
emissions performance, these units reliably operate at a low and 
consistent emissions level. Consequently, the degree of confidence the 
Agency can have in the attainment of overall program goals has 
increased, while the risks associated with underestimation of emissions 
from these units appears less significant. For unmanned sites, the use 
of CEMS provides additional challenges for owners and operators and 
these concerns are an additional reason for the Agency to evaluate the 
LME provisions.
    In evaluating the LME provisions, the Agency has established a de 
minimis test as an internal program check to assure that only a de 
minimis level of emissions from all regulated sources are allowed to 
use exemptions from the Acid Rain Program or monitoring methods under 
Part 75 (including the new unit exemption, appendix E and LME 
provisions). In the October 27, 1998 Federal Register, when the Agency 
last considered this issue (63 FR 57486), the de minimis evaluation was 
based on, among other things, projections of the cumulative effect of 
the new National Ambient Air Quality Standards (NAAQS) for ozone (O3), 
NOX SIP Call, Phase II of the ARP, and other State and 
regional programs (such as the OTC). The 1998 preamble established a 
one percent de minimis threshold of about 20,000 tons per year, 
covering all CEMS-exempted methods, on the basis of preliminary 
information which indicated that future NOX emissions after 
implementation of these various CAA programs would be approximately two 
million tons per year. This de minimis threshold constituted a revision 
of the approximately 40,000 ton level EPA had originally discussed in

[[Page 40402]]

the 1993 rule for CEMS-exempted methods.
    Since that time, the Agency has developed updated information on 
projected year 2010 emissions from the utility sector. First, in 1999, 
pursuant to the CAA Amendments EPA published its section 812 
prospective study of benefits under the CAA (Final Report to Congress 
on Benefits and Costs of the Clean Air Act, 1990 to 2010, EPA 410-R-99-
001). This document estimates that total utility emissions would be 
approximately 3.7 million tons per year in 2010. The analysis assumes 
implementation of the NOX SIP Call in the entire OTAG 
modeling domain. In fact, the SIP Call covers only a portion of the 
OTAG region (excluding States in EPA Region 1 (ME, NH, and VT), Region 
4 (FL and MS), Region 5 (MN and WI), Region 6 (AR, LA, OK, and TX), 
Region 7 (IA, KS, NE), and Region 8 (ND and SD). Since that report, EPA 
has updated its estimates for 2010 post-CAA implementation 
NOX emissions, and, as of October 2001, estimates 
approximately 4.3 million tons of NOX per year after 
implementing major CAA programs such as Phase II of the Acid Rain 
Program and the NOX SIP Call (see Docket No. A-2000-33, Item 
IV-A-7). As a result of this updated information, EPA believes that the 
de minimis analysis should reflect current projections and start with a 
one percent target level of 43,000 total tons for CEMS-exempted 
methods.
    As indicated in the 1998 rulemaking, the Agency's determination of 
the appropriate level of NOX emissions to be considered de 
minimis needs to be based on ``all units that may be covered by the de 
minimis exceptions from the requirement to use CEMS, i.e. all units 
using the new unit exemption, appendix E, and the new low mass 
emissions methodology'' (63 FR 57486). Because considerably more 
information on these regulated sources is now available, the Agency 
undertook a reevaluation of the potential number of various units that 
may choose excepted methodologies to account for their emissions rather 
than installing CEMS (see Docket No. A-2000-33, Item IV-A-6).
    EPA's recent analysis (Docket No. A-2000-33, Item IV-A-6) shows 
that as of December 2001, there were 763 exempt new units. This total 
is significantly higher than the 1998 projection of 278 units. These 
units, based on EPA's tons per unit estimate developed in 1993 for the 
new unit exemption (see 58 FR 3590, January 11, 1993), have estimated 
emissions of approximately 8,700 tons. Exempt units are those new units 
under the Acid Rain Program that are less than or equal to 25 MWe and 
burn clean fuel with low sulfur content.
    The next class of units subject to the de minimis threshold are 
units that monitor based on appendix E of part 75. These appendix E 
units are gas-or oil-fired peaking units. At the end of the year 2000, 
there were 263 appendix E units, and those units emitted slightly more 
than 14,000 tons of NOX per year. In the 1998 preamble, EPA 
used 1997 data to show that there were approximately 235 units that 
used appendix E and that these units had approximately 11,000 tons of 
NOX per year.
    Finally, we examined the number of units that could potentially 
qualify for LME status under the new NOX thresholds. We 
conducted the analysis for both ARP units and non-ARP units that will 
become subject to part 75 under the NOX SIP Call. For this 
analysis, we used emissions data from the ARP and OTC programs and data 
from the NOX SIP Call baseline inventories to evaluate 
multiple years of emissions data for each unit. We assumed that units' 
actual rates would be comparable to their fuel- and unit-specific 
tested emissions rates as allowed for under the LME provisions except 
for units with rates less than 0.15 lb/mmBtu, where we used 0.15 lb/
mmBtu as a default given the requirements in Sec. 75.19. The other 
assumptions and details of the analysis are included in Docket Item IV-
A-6.
    For Acid Rain Program units only, the change from a 50 to 100 tons 
of NOX per year threshold would increase the number of 
existing units that could qualify by about 50 units with a total of 
3,000 tons. This excludes appendix E units that already qualify for de 
minimis monitoring. This increase in potential LME units, taken 
together with emissions from appendix E units and exempt new units, 
would result in approximately 27,000 tons of NOX per year 
subject to the de minimis target level.
    For the NOX SIP call, the increase from a threshold of 
25 tons of NOX per ozone season to 50 tons per ozone season could 
increase the total number of existing non-ARP units that may qualify 
for LME by slightly more than 200 units. About 70 of those units are 
units in the OTC region that are under 25 MWe and currently monitor 
using default values under the OTC NOX Budget Program. These 
units generally would also qualify for appendix E monitoring if the 
NOX threshold was not increased. The total increase in tons 
that may be monitored using appendix E or LME provisions under an 
increased ozone season NOX threshold would be approximately 
2,000 tons per ozone season (an increase from about 5,500 to 7,500 tons 
per ozone season from these non-ARP units). Together with the estimated 
total of 27,000 tons per year NOX from the ARP units, the 
total amount of emissions from units within the group under the de 
minimis concept conservatively represents approximately 35,000 tons of 
emissions. This total remains below the 43,000 tons target level based 
on one percent of projected year 2010 emissions and allows for future 
growth of new units that qualify for LME, appendix E, or the new unit 
exemption. It is also important to remember that the LME analysis 
accounts for units that could potentially qualify for LME monitoring 
requirements; not all units that potentially qualify will necessarily 
use the LME provisions. For example, the 1998 preamble (63 FR 57487) 
estimated that 224 units would qualify at the LME thresholds 
promulgated at that time. In the year 2000, two units used the LME 
provisions. Since that time, the number has increased quickly, 
primarily because of new turbine units that likely also would qualify 
for the appendix E methodology.
    It is important to note that units electing alternative 
methodologies such as LME status and appendix E are still accountable 
for all their emissions using default emissions values or conservative 
test results. What they are relieved from is installing CEMS. The 
Agency was able to evaluate the long term (quarterly) emission rates 
for a number of units that had switched from the use of appendix E to 
the use of CEMS over the past few years. That study (see Docket No. A-
2000-33, Item IV-A-8) examined 41 ARP units, and paired quarters from 
similar seasons with a minimum number of operating hours. While the 
lack of data from simultaneous time periods limits the ability to draw 
precise conclusions from this analysis, the analysis did show that the 
quarterly emission rates were, on average, slightly higher when units 
measured with appendix E rather than CEMS (approximately 4 percent). 
Because the appendix E and LME provisions rely on the same basic test 
procedures to establish a fuel- and unit-specific default rate, this 
analysis is relevant to the LME provisions as well. The Agency believes 
this analysis also supports the change in the LME thresholds that EPA 
is finalizing in this rulemaking by indicating that significant under-
reporting of emissions should not occur as a result of using the LME 
provisions. We also think it provides further support for the 
reliability of estimates in

[[Page 40403]]

our de minimis analysis that is based primarily on existing CEMS data 
for estimating the tonnage from potential LME units.
    At the same time, the analysis did indicate that in particular 
situations, appendix E values could be below reported CEMS values. In 
light of this finding that appendix E (and by extension LME) monitoring 
will not always produce conservative values, use of alternative methods 
of monitoring should remain constrained by the de minimis threshold EPA 
has established. This finding also suggests that these monitoring 
methods may not be appropriate alternatives to CEMS in other programs 
(such as trading programs with much lower caps, or programs with short 
term emission limits such as Best Available Control Technology (BACT) 
or Lowest Achievable Emission Rate (LAER) requirements established 
through New Source Review permits).
    Cumulatively, the data indicate that if the LME threshold were 
raised to 50 tons per ozone season, it would allow 95 percent of the 
numerous small units in the OTC NOX Budget Program that 
currently use non-CEMS methodologies (which are, in many cases, similar 
to LME) to qualify as LME units under the NOX Budget Trading 
Program. If the threshold were not raised, only about 65 percent of 
these same small units could qualify as LME units. EPA considers a less 
burdensome transition for these smaller units from the OTC Program to 
the larger NOX Budget Trading Program to be highly 
desirable. Allowing these units to use LME methodologies under part 75 
(which are similar to methodologies currently used under the OTC 
Program), rather than CEMS requirements under part 75, will reduce 
economic and administrative burden for both the affected sources and 
the regulatory agencies. Further, LME methodologies are reasonably 
accurate methods given the small amount of emissions contributed by 
this class of units. In view of these considerations, EPA has concluded 
that there are distinct benefits, and no significant environmental 
risks, in raising the LME qualifying NOX thresholds to 50 
tons per ozone season and less than 100 tons per year, respectively. 
Therefore, these higher emission threshold values are promulgated in 
today's rule. However, note that for units subject to the 
NOX Budget Trading Program, the final rule places a 
constraint on the 100 tons per year NOX limit: no more than 
50 of the 100 tons per year may be emitted during the ozone season. EPA 
has added this constraint for purposes of consistency, so that all 
NOX Budget units using the LME methodology will be limited 
to 50 tons of NOX emissions per ozone season, whether data 
are reported on a year-round basis or only during the ozone season. In 
addition, should cost of monitors go down, or if the ceiling turns out 
to be much lower than that which we have projected herein, the Agency 
reserves the right to re-assess any and all of these exceptions in the 
future if the need arises.
    Regarding the definition of a LME unit as presented in Sec. 72.2 
and in Sec. 75.19(a), one commenter questioned why the definition 
appears to restrict LME qualification to units that burn only fuel oil 
and natural gas (UARG). The commenter suggested that the broader terms 
``gas-fired'' and ``oil-fired'' be used as the criteria for determining 
LME applicability so that units burning ``other'' gaseous fuels, such 
as landfill gas, would also be allowed to use the LME methodology. 
After careful consideration of these comments, EPA agrees that there is 
no compelling reason for excluding other types of gaseous fuels from 
LME applicability. Further, the Agency believes that this change will 
reduce the administrative burden on both the sources and the regulatory 
agencies, by providing a way for low-emitting sources that burn 
``other'' gaseous fuels to meet part 75 requirements without having to 
submit special petitions under Sec. 75.66. Therefore, today's rule 
expands the applicability of the LME methodology to include units that 
burn gaseous fuels other than natural gas.
    In order for a unit that burns one of these ``other'' gaseous fuels 
to qualify as a LME unit, fuel- and unit-specific default emission 
rates would have to be established. If the unit is Acid Rain-affected, 
Sec. 75.19(a)(1)(i)(C) of today's rule requires the sulfur content of 
the fuel to be characterized by performing the 720-hour demonstration 
described in revised section 2.3.6 of appendix D, before the unit can 
qualify for LME status. The results of that demonstration may be used 
to determine a default SO2 emission rate for the fuel, 
unless the fuel is found to have both a high sulfur content and a high 
sulfur variability (i.e., variability with a standard deviation of 
greater than 5.0 grains per 100 scf); should that occur, the unit would 
be ineligible for LME status. To derive a default CO2 
emission factor for the fuel, revised Sec. 75.19(c)(1)(iii) requires 
Equation G-4 in appendix G to be used, in conjunction with a carbon-
based F-factor calculated from the results of fuel sampling and 
analysis. To determine the default NOX emission rate for the 
gaseous fuel, revised Sec. 75.19(c)(1)(ii) requires fuel- and unit-
specific emission testing to be performed.
2. How Does Today's Rule Change the Certification Application 
Procedures and Requirements for Low Mass Emissions Units?
Background
a. What Is Currently Required?
    In response to concerns raised by both regulated entities and other 
regulatory agencies, EPA examined the administrative procedures in part 
75 pertaining to LME units, especially the certification application 
procedures. It was determined that these procedures could be clarified 
to simplify program implementation and to make the LME requirements as 
consistent as possible with other sections of part 75.
b. What Changes Were Proposed?
    On June 13, 2001, EPA proposed requiring the electronic portion of 
the LME certification application be sent to the Administrator and the 
hardcopy portion to the appropriate Region and State. The Agency also 
proposed requiring that LME certification applications be submitted no 
less than 45 days prior to the date on which use of the methodology is 
projected to commence; and the projected commencement date be indicated 
in the application.
    In addition, EPA proposed clarifications to the requirements for 
new or newly affected units and the extent to which a LME applicability 
demonstration could rely on projected emissions instead of actual, 
historical data. Finally, EPA proposed clearer definitions for the date 
of provisional certification for LME units.
c. What Changes Is EPA Finalizing?
    Today's rule finalizes the provisions requiring submission of the 
LME certification application at least 45 days before the methodology 
is projected to be used and specification of the projected commencement 
date in the application. The final rule also clarifies that the 
methodology is considered to be provisionally certified as of the date 
of submittal of the certification application, but may not be used to 
report data prior to the projected commencement date.
    In response to substantive comments regarding the initial LME 
certification application procedures, in particular the manner in which 
actual historical emissions data, projected emissions, and calculated 
emissions are used to demonstrate that a unit qualifies for LME status, 
today's rule adds significant flexibility to the way in which a unit

[[Page 40404]]

can initially qualify. The final rule allows existing units to claim 
LME status using projected emissions rather than historical data, if a 
Federally enforceable permit restriction is taken which limits unit 
operation, or if the owner or operator has recently installed emission 
controls on the unit.
    Today's rule also simplifies the application procedure by removing 
from Sec. 75.19(a)(2) the requirement that the certification 
application must include calculated emissions for the previous three 
years in addition to the actual historical data for those years. For 
purposes of the initial certification application, the final rule 
allows the owner or operator of a new unit to use conservatively high 
default NOX emission rates other than the values listed in 
Table LM-2 to project the unit's emissions.
Discussion
    EPA received no comments on the proposed changes and clarifications 
to the LME administrative processes. Therefore, these provisions have 
been finalized, with only minor editorial changes for added clarity and 
consistency. However, two commenters objected to the manner in which an 
existing unit qualifies for LME status, believing it to be overly 
restrictive (West Virginia Manufacturers Association, PSEG). The rule 
requires three years or ozone seasons of historical data to demonstrate 
that the unit is a LME. The commenters objected to this provision 
because it automatically excludes units if their recent historical 
NOX emissions have been above the LME thresholds, even if 
the source owner or operator is willing to take an enforceable permit 
restriction on the number of operating hours in future years. Both 
commenters recommended that Sec. 75.19 be revised to conditionally 
allow existing units to qualify for LME status prospectively, rather 
than retrospectively. A third commenter objected to the apparent 
requirement in Sec. 75.19(a)(2)(i) for new units to use the generic 
NOX default emission rates from Table LM-2 to project the 
unit's NOX emissions in the initial certification 
application (Machaver). The commenter recommended that EPA allow the 
use of a conservative but more realistic estimate of the unit's 
emissions (e.g., the permitted NOX emission limit or 0.15 
lb/mmBtu for units with add-on controls) for the purpose of the initial 
certification application.
    After consideration of these comments, EPA has revised the 
requirements for a unit to initially qualify as a LME unit. The 
revisions to Sec. 75.19(a) affect both new and existing units. The 
final rule allows the owner or operator to claim LME status for a unit 
in the following ways:
    1. Using three years (or ozone seasons) of actual data from 
electronic data reporting (EDR) submittals under part 75 or under the 
OTC NOX Budget Program or, if such reports are unavailable, 
using estimates of the actual emissions from other sources of 
information (including default emission rates, emission rates derived 
from stack testing or part 60 CEMS, fuel sampling results, fuel usage 
records); or
    2. Based on three years (or ozone seasons) of projected emissions 
for new units with no actual, historical data; or
    3. Using a combination of actual and projected emissions totaling 
three years (or ozone seasons), if :
    (a) Three years (or ozone seasons) of actual emissions data cannot 
be provided (e.g., for a unit that has been in operation for only one 
or two years); or
    (b) An existing unit takes a Federally enforceable permit 
restriction on unit operating hours in order to stay below the LME 
emission thresholds; or
    (c) The emissions during any of the three previous years (or ozone 
seasons) are not representative of present or future emissions because 
the owner or operator has recently installed emission controls on the 
unit.
     Section 75.19(a)(4) of today's rule also allows the owner or 
operator of a new unit to use default NOX emission rates 
other than the ones in Table LM-2 to project the unit's emissions in 
the initial certification application. The final rule allows the use of 
estimated NOX emission rates which are lower than the Table 
LM-2 values, provided that the estimates are still conservatively high 
with respect to the expected actual emission rates. For instance, for a 
new gas-fired turbine that uses selective catalytic reduction (SCR) to 
control NOX emissions, an estimated emission rate of 0.15 
lb/mmBtu could be used in lieu of the Table LM-2 generic default of 0.7 
lb/mmBtu. For units that use water/steam injection or dry low-
NOX (DLN) technology, an emission rate based on the permit 
limit could be used. For units without NOX emission 
controls, the emission rate estimate could be based on historical 
emission test data. However, Sec. 75.19(a)(4) makes it clear that these 
estimated NOX emission rates are to be used only for the 
purposes of the initial certification application. The estimated 
emission rates may not be used for reporting purposes in the time 
period extending from the first hour in which the LME methodology is 
used to the date and hour in which the actual emission rate is 
established by fuel- and unit-specific emission testing. During that 
interval, either the Table LM-2 value or the maximum potential emission 
rate must be reported. EPA believes that these new provisions in 
Sec. 75.19(a)(4) will ensure that new units are not unfairly excluded 
from using the LME methodology and will also provide a strong incentive 
to the owners or operators to perform the NOX emission rate 
testing in a timely manner.
    EPA notes that when the initial estimate of NOX emission 
rate for the LME certification application is derived from historical 
emission test data, it may be prudent to base the estimate on data 
collected under process operating conditions (e.g., heat input rate, 
unit load.) comparable to those at which the highest NOX 
emission rates are expected to occur during the four-load appendix E 
test. This will help to ensure that the unit's LME status is not 
jeopardized since the estimated NOX emission rate will 
likely be close to the actual default emission rate that is derived 
from the appendix E testing and used for emissions reporting.
3. How Will Today's Rule Affect the Way in Which Fuel- and Unit-
Specific NOX Emission Rates Are Determined for Low Mass 
Emissions Units?
Background
a. What Is Currently Required?
    The low mass emissions methodology in Sec. 75.19 provides two 
options for determining the appropriate default NOX emission 
rate for a unit. The owner or operator may either use a generic default 
emission rate from Table LM-2, or determine a fuel- and unit-specific 
default NOX emission rate by performing emission testing, 
using appendix E test methodology. If the testing option is selected, 
Sec. 75.19(c) specifies how to determine the default emission rate. For 
uncontrolled units, the default emission rate is the highest rate 
obtained from the emission testing, multiplied by 1.15. The reason for 
the 1.15 multiplier is to prevent underestimation of emissions, since 
the NOX emission rate can vary at a given load. For units 
with NOX emission controls of any kind, the default emission 
rate is the higher of: (a) the highest rate from the emission testing 
multiplied by 1.15; or (b) 0.15 lb/mmBtu. The reason for specifying a 
``floor'' emission rate value of 0.15 lb/mmBtu for units with 
NOX emission controls is principally to ensure that large 
units with a high potential to emit and with controls such as SCR and 
selective non-catalytic reduction (SNCR) would not use the LME 
provisions to estimate emissions. Units with these

[[Page 40405]]

controls can achieve emissions rates much lower than 0.15 lb/mmBtu and 
therefore would not want to use the 0.15 lb/mmBtu floor under the LME 
provisions to report their emissions. EPA believes that for units with 
such controls, continuous NOX emission monitoring is the 
preferred way to determine that a unit achieves its target control 
level. This is because the NOX emission reductions achieved 
with these controls can vary significantly with the manner in which the 
controls are operated and the manner of proper operation is difficult 
to document and demonstrate.
    After promulgating the LME provisions on October 27, 1998, EPA 
continued to investigate the causes of variability in NOX 
emission rates in combustion turbines by reviewing literature, 
reviewing test results, analyzing CEMS data for turbines, and 
discussing turbine operation with turbine and utility experts (see 
Docket A-2000-33, Item II-B-1). The result of the investigation was 
confirmation that temperature, pressure, and, in particular, humidity 
affect the NOX emission rate in combustion turbines. The 
investigation revealed that several empirically-derived mathematical 
algorithms have been developed to correct a measured NOX 
concentration to a theoretical NOX concentration at a 
different temperature, pressure, and humidity, including the equation 
in subpart GG, Standards of Performance for Stationary Gas Turbines (40 
CFR 60.335).
    EPA also investigated the claims of industry representatives who 
asked the Agency to consider allowing the use of controlled fuel- and 
unit-specific NOX emission rates below the 0.15 lb/mmBtu 
minimum for turbines with water injection, steam injection, or water/
fuel emulsion. The representatives had stated that if the water-to-fuel 
ratio were monitored each hour, the use of a fuel- and unit-specific 
default for times when the water-to-fuel ratio was within acceptable 
limits would not underestimate emissions. To substantiate these claims, 
EPA reviewed data from CEMS installed at turbines with water-and-steam 
injection and water/fuel emulsion. As a result of this review, EPA 
concluded that if the water-to-fuel ratio is monitored, effective and 
constant control of NOX will be achieved, with little chance 
of underestimation of NOX emissions (see Docket A-2000-33, 
Item II-B-1).
b. What Changes Were Proposed?
    As a result of these two investigations, EPA proposed the following 
revisions to Sec. 75.19(c) on June 13, 2001. First, EPA proposed adding 
a new requirement for certain turbines to correct measured 
NOX concentrations to ambient conditions of temperature, 
pressure, and relative humidity at the time of the emission test. This 
proposed correction (Equation LM-1a in Sec. 75.19(c)(1)(iv)(A)(4)) 
would apply only to uncontrolled diffusion flame style turbines. It 
would compensate for temperature and humidity effects on NOX 
formation by correcting the measured NOX concentrations at 
the test conditions to the average annual temperature, atmospheric 
pressure, and humidity at the location of the turbine. It also would 
prevent underestimation or overestimation of NOX emissions 
for uncontrolled diffusion flame turbines and would remove the 
requirement to multiply the measured NOX emission rates for 
such turbines by 1.15.
    Second, EPA proposed revising Sec. 75.19(c)(1)(iv)(H)(1) to allow 
the use of measured fuel- and unit-specific NOX emission 
rates for units with water or steam injection (and no other type(s) of 
add-on NOX controls), even if the measured emission rates 
are below 0.15 lb/mmBtu. This proposed change would remove the current 
rule requirement that all tested emission rates below 0.15 lb/mmBtu 
must be adjusted upward to a default value of 0.15 lb/mmBtu. The 
proposed change would require units with steam or water injection to 
monitor the water-to-fuel or steam-to-fuel ratio in order to give 
assurance that the emission controls are operating properly.
c. What Changes is EPA Finalizing?
    EPA received numerous substantive comments on the proposed changes 
to Sec. 75.19(c). Based on these comments, the Agency finalizes the 
proposed revisions to Sec. 75.19(c)(1)(iv)(A)(4) with only minor 
editorial changes, but modifies the proposed changes to 
Sec. 75.19(c)(1)(iv)(H)(1). Today's rule requires fuel- and unit-
specific NOX emission rates for uncontrolled diffusion flame 
turbines to be corrected to ISO standard conditions, and removes the 
requirement to multiply the tested emission rates by 1.15. The final 
rule also allows units that use steam (or water) injection and have no 
other add-on controls, or DLN technology and have no other add-on 
controls, to use the highest tested emission rate for reporting 
purposes during controlled hours instead of reporting 0.15 lb/mmBtu. 
Units equipped with SCR or SNCR controls still must report the 
``floor'' NOX emission rate of 0.15 lb/mmBtu if it is higher 
than the tested emission rates, with one exception: if the unit uses 
steam (or water) injection or DLN technology in addition to the SCR or 
SNCR controls, then the highest tested emission rate may be reported 
for controlled hours in lieu of reporting 0.15 lb/mmBtu, provided that 
the emission testing is performed either upstream of the SCR (or SNCR) 
or at a time when the SCR (or SNCR) is not in operation.
Discussion
    Two commenters objected to the provision requiring units that use 
NOX emission controls other than water or steam injection to 
adjust their tested emission rates upward to 0.15 lb/mmBtu (Clean Air 
Energy; Exelon Corporation (Exelon)). In particular, the commenters 
noted that for combustion turbines using DLN control technology, the 
0.15 lb/mmBtu ``floor'' emission rate is several orders of magnitude 
higher than the guaranteed emission levels from such units. One of the 
commenters recommended that EPA treat turbines with DLN control in the 
same manner as turbines that use water or steam injection (Exelon). 
That is, EPA should allow the highest tested emission rate to be 
reported during hours in which parametric data are available to 
document proper operation of the DLN controls. The commenter provided 
supplementary information, suggesting parameters that could be 
monitored to ensure that the DLN is operating in the low-
NOX, or premixed, mode.
    Based on the supplementary information provided by the commenter 
and discussions with turbine experts (see Docket A-2000-33, Item IV-A-
1), EPA has decided to incorporate the commenter's suggestion to treat 
LME units with DLN technology in the same manner as LME units with 
water-and-steam injection. Today's rule allows the highest emission 
rate from the appendix E tests to be reported as the default 
NOX emission rate for the unit, if proper operation of the 
emission controls is documented. Section 75.19(c)(1)(iv)(H) of the 
final rule specifies that for DLN technology, ``proper operation'' of 
the emission controls means that the unit is in the low-NOX 
or premixed combustion mode and fired with natural gas. Evidence of 
operation in the low-NOX or premixed mode is provided by 
monitoring the appropriate turbine operating parameters. These 
parameters may include percentage of full load, turbine exhaust 
temperature, combustion reference temperature, compressor discharge 
pressure, fuel and air valve positions, dynamic pressure pulsations, 
internal guide vane (IGV) position, and flame detection or flame 
scanner condition. The acceptable values and ranges for all parameters

[[Page 40406]]

monitored must be specified in the monitoring plan for the unit, and 
the parameters must be monitored during each unit operating hour. If 
one or more of these parameters is not within the acceptable range or 
at an acceptable value in a given operating hour, or if the unit is 
fired with oil, the fuel- and unit-specific NOX emission 
rate may not be used for that hour and the appropriate default 
NOX emission rate from Table LM-2 must be reported, instead.
    Two commenters recommended that EPA revise 
Secs. 75.19(c)(1)(iv)(C)(4) and (c)(1)(iv)(C)(6) to allow units with 
NOX emission controls of any kind to use the Federally-
enforceable permit limit to determine the default NOX 
emission rate for an LME unit, and then to use the required periodic 
testing under title V of the CAA to verify that the emission limit is 
being met (Class of `85 Regulatory Response Group (Class of `85); 
Reliant Energy (Reliant)). EPA did not incorporate the commenters' 
suggested approach, although the Agency notes that today's rule 
provides some relief to controlled units from the requirement to use 
0.15 lb/mmBtu as the default emission rate when the tested 
NOX emission rates are less than 0.15 lb/mmBtu. In the final 
rule, that requirement applies only to units that use SCR or SNCR for 
NOX emission control. In all other cases, LME units with 
NOX emission controls may use their highest tested emission 
rate as the default value during controlled hours.
    For add-on controls such as SCR or SNCR, proper operation of the 
controls depends on whether the desired chemical reaction necessary to 
reduce NOX emissions is actually occurring which, in turn, 
depends on many factors (e.g., whether the catalyst is active, whether 
the reagent injection rates are appropriate). Other than direct 
measurement of emissions using a CEMS or reference method, there is no 
known way to ensure that the catalyst or injected reagents are 
producing the expected emission reductions. Periodic title V emission 
testing, as recommended by the commenter, would not provide adequate 
assurance that the SCR or SNCR controls are operating properly on a 
continuous basis; because the test is ``periodic,'' at best it shows 
these controls are working when the test is being performed. Therefore, 
the final rule retains the requirement to use the 0.15 lb/mmBtu 
``floor'' NOX emission rate for units equipped with SCR or 
SNCR. EPA notes, however, that if a unit uses SCR (or SNCR) and steam/
water injection, the final rule allows the highest tested emission rate 
(provided it is less than 0.15 lb/mmBtu) to be used in lieu of 0.15 lb/
mmBtu, if the steam/water injection is operational during the emission 
testing and if the testing is either performed upstream of the SCR (or 
SNCR) or with the SCR (or SNCR) not operating. Similarly, for a unit 
that controls NOX emissions using DLN technology and SCR (or 
SNCR), the highest tested emission rate may be used provided that it is 
less than 0.15 lb/mmBtu, and the testing is performed when DLN 
technology is in use and the SCR (or SNCR) is not operating (see 
Secs. 75.19(c)(1)(iv)(C)(7) and 75.19(c)(1)(iv)(C)(8)).
4. Does Today's Rule Allow Testing To Be Done at Fewer Than Four Load 
Levels To Determine Fuel- and Unit-Specific NOX Emission 
Rates for Low Mass Emissions Units?
Background
a. What Is Currently Required?
    The current LME provisions in Sec. 75.19(c)(1)(iv)(A) require 
testing at four load levels, using the test methodology in appendix E 
of part 75, for all units which opt to determine a default fuel- and 
unit-specific NOX emission rate. Industry representatives 
have asked that this requirement be waived for units which operate at a 
single load only.
b. What Changes Were Proposed?
    In the June 13, 2001 proposed rule, EPA proposed and solicited 
comments on two options as alternatives to the four load testing 
requirement for LME units. Option 1 would require the first appendix E 
test to be performed at four loads, with future single load re-tests at 
the load level at which the highest emission rate was found. Option 2 
would allow single-load testing for units that provide a demonstration 
that the unit operates at a single load level.
    In the preamble to the proposed rule, EPA expressed a preference 
for Option 2. Therefore, the Agency proposed adding a new section, (I), 
to Sec. 75.19(c)(1)(iv) which is consistent with Option 2. The proposed 
revisions would conditionally allow single-load testing to be performed 
if the owner or operator demonstrates that the unit has operated at a 
single load level for at least 85 percent of the time in the three 
years prior to the emission test. Turbines that operate at a set-point 
temperature and not at a particular load level would also be 
conditionally allowed to perform single level testing, if it can be 
demonstrated that the unit has operated within  10 percent 
of the set-point temperature for at least 85 percent of the time in the 
three years prior to the emission test. EPA also proposed in 
Sec. 75.19(c)(1)(iv)(I) that for a set-point turbine which normally 
operates at base load but is capable of operating at a higher (peak) 
load level, if the emission testing is only performed at base load, 
then the fuel- and unit-specific NOX emission rate obtained 
from the testing would have to be adjusted upward during peak load 
operation by using a multiplier of 1.15 to ensure that emissions are 
not underestimated.
c. What Changes Is EPA Finalizing?
    EPA received numerous substantive comments on the proposed options 
for reducing the number of required load levels at which testing is 
required to determine fuel- and unit-specific NOX emission 
rates for LME units. After carefully considering these comments, the 
Agency has decided to incorporate both of the proposed Options 1 and 2 
into the final rule. These provisions are found in 
Secs. 75.19(c)(1)(iv)(I) and (J) of today's rule. EPA notes that Option 
2 has been modified somewhat from the proposal. The final rule allows 
testing of LME units to be performed at either one, two, or three loads 
instead of four, based on the results of a historical load analysis for 
the previous three years (or three ozone seasons for sources that 
report emissions data only for the ozone season). The testing is 
required at however many load levels cumulatively represent at least 85 
percent of the unit operating hours in the previous three years (or 
ozone seasons).
Discussion
    One commenter supported proposed Option 2, but requested that EPA 
allow the demonstration of single-load operation to be made using only 
ozone season data for sources that report data on an ozone season-only 
basis (Massachusetts Department of Environmental Protection 
(Massachusetts DEP)). Another commenter favored Option 1 over Option 2, 
because Option 2, although ``reasonable,'' could only be used by a 
subset of LME units (NorthWestern Energy & Communications Solutions 
(NorthWestern)). Two commenters recommended that EPA allow testing to 
be done at two loads if historical load data for the unit demonstrate 
consistent operation at two load levels for at least 85 percent of the 
time (Massachusetts DEP, Machaver).
    EPA has decided to include both proposed Options 1 and 2 in today's 
rule. The Agency believes that this provides sufficient flexibility for 
the various types of LME units to allow them to qualify for reduced 
testing requirements. The final rule incorporates the suggestion of the

[[Page 40407]]

commenters to allow the 85 percent criterion to be applied on a 
cumulative operating load basis, i.e., perform the testing at the 
number of load levels that cumulatively account for 85 percent of the 
unit operating hours in the three years prior to the emission test. 
Today's rule also allows the historical load analysis to include only 
ozone season data for sources that report emissions on an ozone season-
only basis. These new rule provisions are found in 
Secs. 75.19(c)(1)(iv)(I) and (J).

C. Quality Assurance/Quality Control

1. What Changes to the Method of Determining the NOX MPC, 
MEC, Span, and Range Are Finalized in Today's Rule?
Background
a. What Is Currently Required?
    In recent years EPA has received many questions, pertaining 
especially to new combustion turbines, about the way in which the 
maximum potential concentration (MPC) and maximum expected 
concentration (MEC) are determined for NOX and how the 
instrument span and range values are set for NOX monitors. 
Some of the questioners have requested additional options for MPC and 
MEC determinations and claim that part 75 does not address dry low-
NOX (DLN) control technology, which is being used on many 
new turbines. Others have questioned the appropriateness of the default 
NOX MPC value of 50 ppm in Table 2-2 of appendix A for new 
oil- and gas-fired combustion turbines.
b. What Changes Were Proposed?
    On June 13, 2001, EPA proposed to add new options for determining 
the NOX MPC and MEC values, principally with combustion 
turbines in view. The proposed rule would allow the owner or operator 
to use a reliable estimate of the unit's uncontrolled emissions 
obtained from the manufacturer as the MPC value. For units that have 
add-on emission controls or that use DLN technology, the Federally-
enforceable permit limit could be used as the MEC.
    EPA also proposed replacing the 50 ppm default NOX MPC 
value in Table 2-2 for new combustion turbines with two new values: (a) 
150 ppm for units that are permitted to fire only natural gas; and (b) 
200 ppm for units permitted to fire both gas and oil. EPA believes, 
based on a preliminary data analysis of emissions from new combustion 
turbines, that these values are much more representative of actual 
NOX emissions from turbines during unit startup and periods 
when the emission controls are not operational (see Docket A-2000-33, 
Item II-B-1).
c. What Changes Is EPA Finalizing?
    EPA received no adverse comments on these proposed rule changes. 
Therefore, today's rule finalizes as proposed the new options for 
determining NOX MPC and MEC, and the 150 ppm and 200 ppm 
default MPC values for new combustion turbines. The final rule also 
incorporates two important changes to the general approach for 
determining MPC, MEC, span, and range based on recommendations made by 
the commenters. First, today's rule allows CEMS data from a monitor 
certified under 40 CFR part 60 or under a State program to be used to 
make the initial MPC or MEC determinations. Second, for units with a 
dual span requirement for SO2 or NOX, the final 
rule places an upper limit on the full-scale range setting of the low-
scale analyzer in cases where the owner or operator selects the default 
high range option in lieu of operating and maintaining a high monitor 
range. Today's rule restricts the full-scale range of the low-scale 
analyzer to five times the MEC value (where the MEC is rounded upward 
to the next highest multiple of 10 ppm).
Discussion
    Two commenters supported the proposed new option to allow the use 
of a reliable manufacturer's estimate of a unit's uncontrolled 
emissions as the MPC value (UARG; Dynegy, Inc. (Dynegy)). No comments 
were received on the proposal to use the permit limit as the MEC for a 
unit with emission controls, and no comments were received on the 
proposed default MPC values for new combustion turbines. Therefore, in 
the absence of adverse comments these provisions are finalized for the 
reasons stated in the proposal. While these rule changes could require 
owners and operators of combustion turbines currently using the 50 ppm 
NOX MPC value from Table 2-2 of appendix A to change their 
MPC and span values, the Agency believes that many have already done so 
in their required annual re-evaluations of span, range, MPC, and MEC 
values for each monitor. In other words, the owners and operators of 
new combustion turbines using the 50 ppm MPC value from Table 2-2 have 
likely found, upon analysis of actual data, that the value is 
unrealistically low and requires upward adjustment. The Agency expects 
that this rule change will primarily affect new units, rather than 
existing units. However, since there may be some existing units still 
using the 50 ppm MPC value, and since span changes may require new 
calibration gases to be purchased and, in some instances, may 
necessitate analyzer replacement, EPA has provided additional time in 
the rule language from the effective date of today's rule for owners 
and operators to implement the new MPC provision (see Section V., Rule 
Implementation, of this preamble).
    EPA received additional comments on the span and range provisions 
of part 75. Two of these, provided by the same commenter (Machaver), 
are incorporated into the final rule. The commenter asked EPA to 
consider expanding the range of methods for establishing an initial MPC 
or MEC value. The commenter stated that especially for newly-affected 
units, the use of ``reasonable, relevant, and appropriate'' data, such 
as CEMS data from a part 60 monitor or historical emission test data, 
should be allowed. EPA believes that this suggestion has merit, 
particularly in view of the many sources that will soon be required to 
implement the monitoring provisions of part 75 under the NOX 
SIP Call. Therefore, today's rule allows any available quality-assured 
CEMS data (whether from a part 75 monitor, a part 60 monitor, or one 
that meets State requirements) to be used for the initial MPC and MEC 
determinations. In as much as these initial determinations are self-
correcting (i.e., appendix A Secs. 2.1.1.5 and 2.1.2.5 require an 
annual review) and there are sufficient incentives to ensure proper 
specification (i.e., exceeding a full-scale range necessitates 
substitution of conservative emissions factors under appendix A 
Sec. 2.1.2.5(b)), the Agency sees no harm introduced by providing this 
additional flexibility. The new rule provision is found in sections 
2.1.1.1(b), 2.1.1.2(c), 2.1.2.1(e), and 2.1.2.2(c) of appendix A. 
Application of these data is limited to these initial MPC and MER 
determinations. Continuous emission monitoring systems used for part 75 
reporting must meet the certification and ongoing quality assurance 
requirements of part 75.
    The commenter also recommended that EPA set an upper limit on the 
low-scale measurement range for dual span units using the ``default 
high range'' option. For sources that elect to use the default high 
range option, it is advantageous to set the range of the low 
measurement scale as high as possible to capture emission ``spikes'' 
and to minimize reporting the default high range value of twice the 
MPC. However, if the low range is set inappropriately high, this will 
result in the majority of the data being recorded at the bottom

[[Page 40408]]

end of the measurement scale during normal, controlled, unit operation. 
Data accuracy suffers at the low end of a measurement scale due to a 
poor signal-to-noise ratio. To help ensure that this does not happen, 
the commenter recommended capping the low-scale range at five times the 
MEC, where the MEC is rounded to the nearest 10 ppm. EPA concurs with 
this suggested approach. Today's rule adds the provision to sections 
2.1.1.4(g) and 2.1.2.4(f) of appendix A.
2. What Changes to the 7-Day Calibration Error Test Are Finalized?
Background
a. What Is Currently Required?
    The 7-day calibration error test described in sections 6.3.1 and 
6.3.2 of appendix A of part 75 is required only for initial 
certification, recertification, and occasionally as a diagnostic test. 
It is not a routine, required, periodic quality assurance (QA) test. 
The current rule specifies that the 7-day calibration error test data 
must be recorded while the unit is operating. For peaking units, the 
requirement for the unit to be operating during the test can be 
problematic. Because of the sometimes infrequent or unpredictable 
nature of peaking unit operation, the 7-day test may take weeks or even 
months to complete.
b. What Changes Were Proposed?
    On June 13, 2001, EPA proposed revising the 7-day calibration error 
test requirement for monitors installed on peaking units, requiring 
data to be recorded with the unit operating for only three of the seven 
test days. The unit would not be required to be operating for the other 
four days of the test.
c. What Changes Is EPA Finalizing?
    EPA received numerous comments on the proposed revisions to the 7-
day calibration error test procedure. After carefully considering the 
comments, the Agency has decided to remove the 7-day calibration error 
test requirement for peaking units and for SO2 and 
NOX monitors with span values of 50 ppm or less. If a unit 
should lose its peaking status, it would also lose its 7-day 
calibration error test exemption. The owner or operator would then be 
required to perform diagnostic 7-day calibration error tests of all 
installed monitors by December 31 of the following year. Today's rule 
reflects these changes, in sections 6.3.1 and 6.3.2 of appendix A and 
in Sec. 75.20(c).
Discussion
    EPA received comments from five different commenters on the 
proposed revisions to the 7-day calibration error test. Four of the 
commenters found the scope of the proposed change to be too narrow as 
it only applies to peaking units (UARG, Dynegy, KVB, Machaver). One 
commenter stated the opinion that part 75 data quality would not be 
jeopardized if the 7-day calibration error test were eliminated for 
peaking units, if not for all units (Dominion). Two other commenters 
provided the following suggestions: (1) Eliminate the 7-day calibration 
error test for all units; or (2) allow combustion turbines to perform 
the test off-line for all 7 days; or (3) restrict the test to zero-
level calibrations for combustion turbines (UARG, Dynegy). Finally, two 
commenters noted that many monitoring systems cannot pass the 7-day 
test using the proposed methodology, i.e., using a combination of off-
line and on-line calibrations, because of differences in temperature 
and pressure between off-line and on-line conditions (UARG, Machaver).
    EPA rejected the commenters' suggestion to eliminate the 7-day 
calibration error test for all affected units. The Agency believes that 
the test has value for frequently operated units, and the test can, in 
most instances, be completed in seven consecutive calendar days. The 
purpose of the 7-day test is to ensure that from day-to-day, a 
continuous emission monitor does not drift excessively while it is 
measuring emissions at stack conditions (e.g., stack pressure and 
temperature). The test provides a one-time demonstration that a monitor 
is capable of consistently passing daily calibrations at a 
specification twice as stringent as the allowable calibration error for 
daily monitor operation. Monitors that cannot meet this requirement are 
disqualified for use under part 75. When the test can be completed in 
seven consecutive days, it achieves its purpose.
    EPA considered removing the 7-day calibration error test 
requirement for all combustion turbines, as suggested by the 
commenters. However, the Agency did not incorporate the commenters' 
recommendation since many combustion turbines are operated as base-load 
or cycling units. Because such units operate frequently, the 7-day 
calibration error test is appropriate and must be performed.
    EPA rejected the commenter's suggestion to allow combustion 
turbines to perform the 7-day calibration error test while the unit is 
off-line. Performing the test off-line defeats the purpose of the test, 
which, as previously noted, is to assess the calibration drift of a 
monitor over a 7-day period while it is in thermal equilibrium with its 
stack environment. The Agency also rejected the commenter's 
recommendation to perform only a calibration with zero-level gas on 
each day of the test. EPA does not believe that it is technically 
justifiable to perform only half of the normal daily calibration 
sequence and to omit the other half. However, EPA does agree with the 
commenters who pointed out that performing the 7-day test using a 
combination of off-line and on-line calibrations would not be a viable 
solution for many monitoring systems.
    In view of these considerations, EPA has decided to remove the 7-
day calibration error test requirement for peaking units and also for 
SO2 and NOX monitors with span values of 50 ppm 
or less. With regard to peaking units, the Agency's decision is based 
principally on the difficulties associated with performing the 7-day 
calibration error test in a timely manner for such units. Because 
peaking units operate infrequently, it is often difficult to complete a 
7-day calibration error test within a reasonable time since the test 
must be done with the unit in operation. In cases where a 7-day 
calibration error test may take several weeks or months to complete, 
the test loses its meaning. Today's rule specifies that a peaking unit 
remains exempt from the 7-day calibration error test requirement as 
long as it continues to re-qualify as a peaking unit from year-to-year 
or from ozone season-to-ozone season. However, if at the end of a 
particular year or ozone season peaking unit status is lost, the owner 
or operator must then perform diagnostic 7-day calibration error tests 
of all continuous emission monitors installed on the unit by December 
31 of the following year.
    EPA's decision to exempt SO2 and NOX monitors 
with span values of 50 ppm or less from the 7-day calibration error 
test is consistent with changes made in today's rule to section 
2.1.4(a) of appendix B. As discussed below, the final rule lowers the 
allowable calibration error for daily monitor operation to 5 ppm for 
SO2 and NOX monitors with span values less than 
or equal to 50 ppm. Since the alternate performance specification in 
section 3.1 of appendix A for the 7-day calibration error test of 
SO2 and NOX monitors is also 5 ppm, the changes 
to appendix B will, in effect, require SO2 and 
NOX monitors with span values less than or equal to 50 ppm 
to meet the 7-day calibration error test specification every day. This 
makes it unnecessary to

[[Page 40409]]

perform 7-day calibration error testing on these monitors.
3. What Changes to the QA/QC Requirements for Low-Emitting Sources Are 
Finalized?
Background
a. What Is Currently Required?
    Part 75 requires owners and operators of units with SO2 
and NOX monitors to perform daily calibration error tests of 
these monitors. The allowable calibration error is currently 5 percent 
of the span value. However, section 2.1.4(a) in appendix B of part 75 
provides an alternate daily calibration specification for low emitters 
of SO2 and NOX. The alternate low-emitter 
specification (for span values less than 200 ppm) is 10 ppm, based on 
the absolute value of the difference between the tag value of the 
calibration gas and the instrument response. For most low-emitting 
sources, the alternate 10 ppm specification is reasonable and provides 
relief from the 5 percent of span requirement, which is often too 
stringent at low span values. However, for very low span values, the 10 
ppm alternate specification needs to be tightened. This is especially 
important because many new gas turbines are being built and these units 
have very low NOX emissions, often in the 0-10 ppm range.
b. What Changes Were Proposed?
    On June 13, 2001, EPA proposed to modify the alternate calibration 
error specification in section 2.1.4(a) of appendix B for daily 
operation of SO2 and NOX monitors. The 10 ppm 
alternate specification would be retained for span values between 50 
and 200 ppm. However, for span values less than or equal to 50 ppm, the 
alternate specification would be lowered to 5 ppm. EPA believes that a 
daily calibration error limit of 5 ppm is both reasonable and 
achievable in view of the measurement capability of today's gas 
analyzers. Also, 5 ppm is the alternate calibration error performance 
specification in section 3.1(b) of appendix A for initial certification 
of SO2 and NOX monitors.
c. What Changes Is EPA Finalizing?
    EPA received only one comment on the proposed modification of the 
alternate calibration error specification. The comment was supportive 
(Clean Energy Group). Therefore, today's rule finalizes the proposed 
change to section 2.1.4(a) of appendix B lowering the daily calibration 
error specification to 5 ppm for SO2 and NOX 
monitors with span values of 50 ppm or less.
4. What Changes to the Stack Flow-to-Load Ratio Test Are Finalized?
Background
a. What Is Currently Required?
    In the May 26, 1999 rule revisions, EPA added a new quarterly QA 
test for flow monitors to part 75: the flow-to-load ratio test. Since 
promulgation, EPA has received many questions about the test 
methodology relating both to the procedural aspects of how the data 
analysis is done and to the consequences when the test is failed. As a 
result, EPA believes it is necessary to clarify the test procedures and 
to re-evaluate the issue of data validation when the test is failed.
b. What Changes Were Proposed?
    On June 13, 2001, EPA proposed revising the flow-to-load test 
methodology by allowing the data exclusions listed in section 2.2.5(c) 
of appendix B to be taken before analyzing the quarterly flow-to-load 
data. The current rule appears to require an initial data analysis with 
no exclusions and to allow owners and operators to claim the data 
exclusions only when the first analysis results in a failed test. 
Proposed section 2.2.5(c) also would clarify the issue of co-firing as 
it pertains to data exclusions. Units that co-fire different fuels as 
part of normal operation could claim flow-to-load test data exclusions 
for hours in which fuels were not co-fired, if the reference flow 
relative accuracy test audit (RATA) at normal load was done while co-
firing. Conversely, if the reference flow RATA was done while firing a 
single fuel, flow-to-load test data exclusions could be claimed for 
hours in which fuels were co-fired. The proposed rule would also add a 
statement to section 6.5(a) of appendix A requiring that units which 
co-fire fuels as the predominant mode of operation perform RATAs while 
co-firing.
    The proposal would change the method of data validation following a 
flow-to-load ratio test failure. Section 2.2.5(c)(8) of appendix B 
would allow the flow rate data to be declared conditionally valid, 
rather than invalid, when a flow-to-load test is failed, pending the 
results of a follow-up investigation and/or a RATA. This would allow 
data validation in case a false positive is obtained with the flow-to-
load test. If the investigation fails to reveal a problem and a 
confirming RATA is passed hands-off, no data loss would be incurred. 
The timeline for investigating a flow-to-load test failure would also 
be changed from within 2 weeks to within 14 unit operating days.
    The proposal would also clarify the instructions for multiple stack 
configurations and allow the data to be analyzed in one of two ways: 
(1) using combined flow and average unit load; or (2) using the flow in 
each stack and the corresponding unit load. Finally, section 7.8 in 
appendix A of part 75 would be revised to exempt non-load-based units 
(i.e., units that do not produce electrical output or steam load) from 
the flow-to-load ratio test.
c. What Changes Is EPA Finalizing?
    EPA received supportive comments from one commenter on the proposed 
revisions to the flow-to-load ratio test methodology (UARG). No adverse 
comments were received. Therefore, today's rule finalizes the changes 
for the reasons stated in the proposal.
5. What Special QA Provisions Are Finalized for Units That Do Not 
Produce Electrical Output or Steam Load?
Background
a. What Is Currently Required?
    Units subject to the monitoring and reporting requirements of part 
75 must account for their emissions on a continuous basis. Most units 
use CEMS for this purpose. Part 75 requires periodic RATAs of all CEMS 
to demonstrate that the data recorded by the monitoring systems 
accurately represent the SO2, NOX, and 
CO2 emissions from the affected unit. RATAs of gas and flow 
monitors are required for initial certification and either semiannually 
or annually thereafter.
    Section 6.5.1 of appendix A to part 75 requires that RATAs of gas 
monitors be done at a single ``normal'' load level. Section 6.5.2 of 
appendix A and section 2.3.1.3 of appendix B specify the load levels 
for flow RATAs. In general, flow monitor RATAs are performed at 
multiple load levels (either two or three) with a few exceptions (e.g., 
for flow monitors installed on peaking units, only single-load RATAs 
are required). For multiple-load flow RATAs, at least one of the tested 
load levels must be the ``normal'' load level.
    The method of establishing the normal load level is found in 
section 6.5.2.1 of appendix A. First, the owner or operator must 
determine the ``range of operation'' for the unit or stack. The range 
of operation extends from the minimum safe, stable load to the maximum 
sustainable load. Next, the range of operation is divided into three 
load levels. The first 30 percent of the range of operation is 
considered to be the ``low'' load level, the next 30 percent of the 
range is the ``mid'' load level, and the remaining 40 percent of

[[Page 40410]]

the range is the ``high'' load level. The ``normal'' load level is 
determined by performing an analysis of at least four quarters of 
representative historical load data. From these data a distribution 
graph, such as a histogram, is constructed showing the percentage of 
the time that each load level has been used historically. The most 
frequently used load level (low, mid, or high) is automatically 
designated as the normal load level. The owner or operator may opt to 
designate the next most frequently used load level as a second normal 
load. Thus, the appropriate load levels for the required RATAs of the 
gas and flow monitors are established.
    Under the NOX SIP Call, some sources that do not produce 
electrical output or steam load, such as cement kilns or refinery 
process heaters, become subject to the monitoring and reporting 
requirements of part 75. Consequently, these sources will be required 
to perform periodic RATAs of their gas and flow monitors. Because these 
sources do not produce electrical or steam load, the concept of 
performing ``normal load'' RATAs cannot be applied to them. Therefore, 
an alternative RATA approach is needed for these non-load-based units.
b. What Changes Were Proposed?
    On June 13, 2001, EPA proposed to revise section 6.5.2.1 of 
appendix A to part 75 by adding a method of establishing the proper 
operating levels at which to perform RATAs for units that do not 
produce electrical output or steam load (e.g., cement kilns and process 
heaters).
    The proposed RATA approach for units that do not produce electrical 
or steam load would be based on an ``operating level'' concept, rather 
than a ``load level'' concept. The method of determining the normal 
operating level for a non-load-based unit would be much the same as the 
previously described method for determining the normal load level for a 
load-based unit. The owner or operator would determine the range of 
operation, divide it into three operating levels, and perform a data 
analysis to establish the ``normal'' (i.e., most frequently used) 
operating level. The only significant difference between the load-based 
and non-load-based methodologies is that instead of defining the range 
of operation in units of electrical or steam load (i.e., in megawatts 
or klb/hr of steam), the range of operation of the non-load-based unit 
would be defined in units of stack gas velocity in ft/sec. The range of 
operation would extend from the minimum expected velocity to the 
maximum potential velocity. These minimum and maximum gas velocities 
could either be determined from reference method test data or by using 
Equation A-3a or A-3b (as applicable) in section 2.1.4.1 of appendix A 
to part 75.
    Once the boundaries of the range of operation are established and 
the normal operating load level has been identified, the owner or 
operator of a non-load-based unit would perform the required gas and 
flow RATAs in essentially the same manner as for a load-based unit. The 
only difference is that in many sections of part 75 the term 
``operating level'' would replace the term ``load'' or ``load level.'' 
The proposed rule would modify the text in several sections of part 75 
(e.g., by adding a parenthetical expression such as ``(or normal 
operating level)'' after the term ``normal load'') to indicate that the 
provisions apply to both load-based and non-load-based units.
c. What Changes Is EPA Finalizing?
    EPA received adverse comments on the proposed approach to 
determining the range of operation, normal operating level, and flow 
RATA requirements for non-load-based units, i.e., units that do not 
produce electrical output or steam load. After careful consideration of 
these comments, EPA has modified the proposed approach. The requirement 
to define the range of operation and the low, mid, and high operating 
levels in terms of stack gas velocity (ft/sec) is being finalized in 
this action, with only one minor change: the owner or operator may use 
0.0 ft/sec as the ``minimum potential velocity.'' However, EPA is not 
adopting the proposed requirement to perform a historical analysis of 
flow rate data to establish the ``normal'' operating level. Instead, 
today's final rule specifies that the normal operating level for a non-
load-based unit is determined using sound engineering judgment and 
operating experience with the unit and process, and supported with 
documentation in the monitoring plan. In addition, new section 6.5.2(e) 
of today's rule allows the owner or operator of a non-load-based unit 
to obtain relief from three-load flow RATA testing, if an acceptable 
technical justification is provided in the monitoring plan. If the 
owner or operator can satisfactorily demonstrate that the process 
operates only at one level, then only single-level flow RATAs would be 
required for certification and on-going quality assurance. If the 
process is demonstrated to operate at two distinct levels, then two-
level flow RATAs would be required.
Discussion
    EPA received comments from only one commenter regarding the 
proposed method of determining range of operation, normal operating 
level, and the appropriate operating levels for flow RATAs (APCA). The 
commenter stated two objections to the proposed rule provisions: (1) 
that the ``maximum potential velocity'' approach is not applicable to 
cement kilns; and (2) that since cement kilns operate at one level, 
only single-level flow RATAs should be required.
    EPA does not agree with the commenter's claim that the concept of 
maximum potential velocity cannot be applied to a cement kiln. The 
Agency notes that the commenter did not explain why the proposed 
methodology will not work for cement kilns. EPA believes that for any 
non-load-based unit, an estimate of the highest stack gas velocity 
during normal operation should be easily obtainable, using EPA Method 2 
(see 40 CFR 60, Appendix A). However, EPA has reconsidered the proposed 
approach to determining the normal operating level and establishing the 
RATA levels for flow monitors installed on such units. For industrial 
processes, such as cement manufacturing, which often have only one 
distinct operating level, it may not be appropriate to require a 
historical data analysis to establish the normal operating level, or to 
require three-level flow RATAs to be performed.
    In view of these considerations, today's rule finalizes the 
requirement for non-load-based units to define the range of operation 
in terms of stack gas velocity as proposed. However, the velocity 
information is only used to define the operating range and the low, 
mid, and high operating levels. EPA is not adopting the proposed 
requirement for non-load-based units to determine the normal operating 
level by analyzing historical flow rate data. Instead, today's rule 
requires that the normal operating level be established using sound 
engineering judgment and process operating experience. Regarding the 
appropriate number of levels for flow RATAs, today's rule requires non-
load-based units to perform flow RATA testing at the same number of 
load levels as are specified for load-based units in section 2.3.1.3(c) 
of appendix B (i.e., three levels for certification, two levels for 
routine quality-assurance) unless the owner or operator submits a 
technical justification to the permitting authority with the hardcopy 
of the initial monitoring plan for the unit, demonstrating that the 
unit operates at only one level. Today's rule adds this

[[Page 40411]]

option in a new paragraph, (e), to section 6.5.2 of appendix A. The 
technical justification must include appropriate documentation and data 
to demonstrate that the process operates at only one level. If the 
justification is acceptable to the permitting authority, then only 
single-level flow RATAs would be required for initial certification, 
recertification, and on-going quality assurance. For non-load-based 
processes that operate at only two distinct levels, section 6.5.2(e) 
allows a similar justification to be submitted as an option to the 
three-level flow RATA testing.

D. Appendix D

1. What Changes to the Definitions of ``Pipeline Natural Gas'' and 
``Natural Gas'' Are Finalized?
Background
a. What Is Currently Required?
    The definitions of ``pipeline natural gas'' and ``natural gas'' in 
Sec. 72.2 state that a gaseous fuel must meet a two-fold requirement to 
qualify as one of these fuels: the fuel must meet a hydrogen sulfide 
(H2S) content limit (0.3 gr/100 scf for pipeline natural gas 
and 1.0 gr/100 scf for natural gas) and the H2S must 
constitute at least 50 percent of the fuel's total sulfur content. 
Appendix D of part 75 does not explain how to comply with the second of 
these two requirements (i.e., the H2S as a percentage of 
total sulfur). Further, industry members have expressed concern that 
this requirement cannot be implemented in a fair and consistent manner. 
For example, a very clean fuel with 0.1 gr/100 scf of H2S 
and 0.3 gr/100 scf of total sulfur would not qualify as pipeline 
natural gas, because H2S is less than 50 percent of the 
total sulfur content, but a fuel with three times more H2S 
and twice as much total sulfur (0.3 gr/100 scf of H2S and 
over 0.6 gr/100 scf of total sulfur) would qualify as pipeline natural 
gas under the current rule.
    In response to the industry's concerns over the definitions of 
pipeline natural gas and natural gas, EPA issued interim guidance on 
June 12, 2000, discussing how sources could demonstrate compliance with 
the existing definitions (see Docket A-2000-33, Item IV-A-5). As 
explained in the guidance, through its authority under Sec. 75.66, EPA 
would allow owners or operators to comply by meeting a total sulfur 
limit (0.6 gr/100 scf for pipeline natural gas or 2.0 gr/100 scf for 
natural gas), in lieu of documenting that H2S constitutes at 
least 50 percent of the total sulfur content.
b. What Changes Were Proposed?
    On June 13, 2001, EPA proposed revising the definitions of 
``pipeline natural gas'' and ``natural gas'' in Sec. 72.2. All 
references to H2S content would be removed and these fuels 
would be defined in terms of total sulfur content. The proposed total 
sulfur content values would be 0.5 gr/100 scf for pipeline natural gas 
and 20.0 gr/100 scf for natural gas. The value of 20.0 gr/100 scf is 
the maximum total sulfur content allowed under most contracts for 
transmitting pipeline natural gas and allowed under most tariffs 
established with the Federal Energy Regulatory Commission.
    For fuels that qualify as pipeline natural gas, a default 
SO2 emission rate of 0.0006 lb/mmBtu would be used to 
quantify SO2 emissions, and for fuels that qualify as 
natural gas, a default SO2 emission rate would be calculated 
based on Equation D-1h in appendix D. Equation D-1h would be revised 
and based upon the total sulfur content of the fuel, rather than the 
H2S content.
c. What Changes Is EPA Finalizing?
    EPA received no adverse comments on the proposed revisions to the 
definitions of pipeline natural gas and natural gas. Therefore, today's 
rule finalizes the revised definitions as proposed.
Discussion
    EPA received comments from four commenters on the proposed 
revisions to the definitions of pipeline natural gas and natural gas 
(Class of `85, XCEL Energy, Clean Energy Group, UARG). All four 
commenters favored the proposed changes. One commenter noted that 
eliminating the hydrogen sulfide content limit would make the use of 
appendix D more attractive and would reduce the risk of unintentional 
violations of the monitoring requirements (Class of `85). In view of 
these supportive comments, EPA finalizes the proposed definitions of 
pipeline natural gas and natural gas without modification.
2. How Does Today's Rule Change the Method by Which a Gaseous Fuel 
Qualifies As ``Pipeline Natural Gas'' or ``Natural Gas''?
Background
a. What Is Currently Required?
    The part 75 requirements for demonstrating that a particular 
gaseous fuel qualifies as pipeline natural gas or natural gas are found 
in sections 2.3.1.4 and 2.3.2.4 of appendix D. Compliance with the 
hydrogen sulfide content limit must be documented through one of five 
sources of information: (1) a fuel purchase or pipeline transportation 
contract; (2) vendor certification based on fuel sampling; (3) one year 
of monthly sampling; (4) one year of sampling each shipment or lot of 
fuel (for fuels delivered in shipments or lots); or (5) a demonstration 
consisting of 720 hours of sampling.
b. What Changes Were Proposed?
    As discussed in the previous question, on June 13, 2001, EPA 
proposed revising the definitions of pipeline natural gas and natural 
gas by removing the specified limits on the hydrogen sulfide content of 
the fuel and replacing them with limits on total sulfur content.
    EPA also proposed revisions to sections 2.3.1.4 and 2.3.2.4 of 
appendix D, which would change the way of documenting that a fuel 
qualifies as pipeline natural gas or natural gas. An initial compliance 
demonstration and periodic sampling of the total sulfur content of the 
fuel would be required. Initial compliance with the total sulfur limit 
would be documented either: (1) using a fuel purchase or pipeline 
transportation contract; or (2) using the results of all available fuel 
sampling results for the previous 12 months; or (3) using the results 
of a 720-hour demonstration; or (4) by obtaining and analyzing a sample 
of the fuel in the absence of a contract or historical fuel sampling 
data. Once a fuel initially qualified as pipeline natural gas or 
natural gas, periodic, on-going sampling for total sulfur content would 
be required. The proposed sampling frequency was semiannual and 
whenever ``it is reasonable to believe that the fuel composition has 
changed significantly.''
c. What Changes Is EPA Finalizing?
    EPA received numerous comments on both the proposed method by which 
a fuel qualifies as pipeline natural gas or natural gas and the 
proposed semiannual total sulfur sampling requirement. In view of the 
comments, EPA has modified these rule provisions. In today's rule, 
revised sections 2.3.1.4 and 2.3.2.4 of appendix D specify three 
methods by which a fuel may initially qualify as pipeline natural gas 
or natural gas: (1) by a fuel contract or tariff sheet with a maximum 
total sulfur specification that meets the definition of pipeline 
natural gas or natural gas; (2) based on historical fuel sampling and 
analysis data from the previous twelve months; or (3) in the absence of 
a satisfactory contract specification or historical sampling data, by 
obtaining a sample (or samples) of the fuel. For a

[[Page 40412]]

fuel that qualifies using a contract or tariff sheet specification, no 
additional on-going sampling of the total sulfur content is required, 
provided that the contract or tariff sheet is current, valid, and 
representative of the fuel combusted in the unit. For a fuel that 
initially qualifies as pipeline natural gas or natural gas based on 
fuel sampling and analysis, total sulfur sampling is required annually 
and whenever the fuel supply changes. The annual total sulfur sampling 
requirement has an effective date of January 1, 2003.
Discussion
    One commenter supported the proposed provision to allow a fuel to 
initially qualify as pipeline natural gas or natural gas based on a 
single fuel sample, and also supported the proposed semiannual total 
sulfur sampling requirement (Reliant). Another commenter expressed 
concern that for sources using the historical fuel sampling option, the 
language requiring that ``all available fuel samples'' from the past 
twelve months be used could require an exhaustive search of all 
possible sources of sample results and might lead to allegations that a 
source had excluded relevant samples (UARG). The commenter suggested 
that EPA should consider using alternate language, such as 
``representative fuel samples from the past twelve months'', and that 
the Agency should also allow averaging of sample results. The commenter 
also stated that if a source has followed EPA's June 12, 2000 guidance 
and has obtained the total sulfur sample(s) to document that the fuel 
being combusted qualifies as pipeline natural gas or natural gas, re-
qualification is unnecessary and the source should only be subject to 
the on-going semiannual fuel sampling requirements.
    Three commenters objected to the proposed requirement to sample the 
total sulfur content of pipeline natural gas and natural gas 
semiannually (UARG, Class of '85, XCEL Energy). One of these commenters 
suggested that annual, rather than semiannual, sampling would be more 
appropriate, and that for sources relying on a contract specification, 
the on-going sampling should not be required at all (UARG). The other 
two commenters recommended deleting the semiannual sampling requirement 
and requiring re-sampling only if the fuel supply changes (Class of 
`85, XCEL Energy). Several commenters stated that EPA should allow 
immediate re-sampling to be performed if the results of a periodic 
sulfur sample analysis are believed to be anomalous or suspect (Class 
of `85, XCEL Energy, Machaver).
    After considering these comments, EPA has revised both the 
requirements for a fuel to initially qualify as pipeline natural gas or 
natural gas, and the on-going total sulfur sampling requirements. In 
today's rule, revised sections 2.3.1.4 and 2.3.2.4 of appendix D 
provide three methods by which a fuel may qualify: (1) By a total 
sulfur specification in a fuel contract or tariff sheet; (2) based on 
historical fuel sampling data from the previous twelve months; or (3) 
in the absence of a contract specification or historical sampling data, 
a sample of the fuel's total sulfur content must be obtained and 
analyzed. Note that EPA has removed the fourth option of performing the 
720-hour demonstration described in section 2.3.6 of appendix D to 
qualify, believing it to be unnecessary in light of the third option 
allowing use of a sample. The 720-hour demonstration has been reserved 
for characterizing the sulfur content of gaseous fuels other than 
pipeline natural gas and natural gas.
    Today's rule states that when the owner or operator relies on the 
specifications in a fuel contract or tariff sheet for a fuel to 
initially qualify as pipeline natural gas or natural gas, no initial or 
on-going sampling of the total sulfur content is required, provided 
that the contract or tariff sheet is current, valid, and representative 
of the fuel combusted in the unit. For a fuel that initially qualifies 
as pipeline natural gas or natural gas based on fuel sampling and 
analysis, total sulfur sampling is required annually and whenever the 
fuel supply changes. The annual total sulfur sampling requirement has 
an effective date of January 1, 2003.
    EPA believes that most sources are likely to use fuel sampling to 
demonstrate that the fuel qualifies as pipeline natural gas or natural 
gas, rather than relying on contract specifications. This is because 
the maximum total sulfur content specified in most contracts for 
transmitting pipeline natural gas, and under most tariffs established 
with the Federal Energy Regulatory Commission, is 20.0 gr per 100 scf, 
whereas the actual total sulfur content of natural gas is generally 10 
to 100 times lower. In the absence of actual fuel sampling data, Table 
D-5 in appendix D requires the maximum total sulfur content specified 
in the contract or tariff to be used to calculate the default 
SO2 emission rate. Therefore, EPA believes that most sources 
combusting natural gas will elect to perform fuel sampling, rather than 
using the specifications in a fuel contract or tariff sheet, in order 
to avoid significantly overestimating SO2 emissions.
    The final rule further states that when historical fuel sampling 
results are used to qualify, only those fuel samples taken by or 
provided to the owner or operator in the past twelve months need be 
considered. If multiple fuel samples are used to qualify, each sample 
must meet the applicable total sulfur limit. Also, if a single fuel 
supply serves many affected units, it is not necessary to obtain a 
separate sample for each unit, provided that no other gaseous fuel is 
mixed with the fuel in transporting it from the sampling location to 
the affected units. For fuels that qualify as natural gas, if multiple 
samples are taken, the results may be averaged before using Equation D-
1h to calculate the default emission rate.
    If the results of any required fuel sampling and analysis fail to 
demonstrate that a fuel qualifies as pipeline natural gas or natural 
gas, but the results are suspect or believed to be anomalous, the owner 
or operator may document the reasons for believing this in the 
monitoring plan and additional sampling may be initiated immediately. 
In such cases, at least three additional samples are required and each 
sample analysis must meet the applicable total sulfur limit for 
pipeline natural gas or natural gas.
    Finally, EPA notes that affected facilities currently relying on 
total sulfur samples obtained in accordance with the June 12, 2000 
guidance to meet the definition of pipeline natural gas or natural gas 
are not required to perform any additional sampling to re-qualify, 
provided that the fuel supply source has not changed since the samples 
were taken. These facilities are subject only to the on-going, annual 
total sulfur sampling requirement which takes effect in 2003.
3. How Does Today's Rule Change the Fuel Sampling and Data Reporting 
Requirements for Gaseous Fuels Other Than Pipeline Natural Gas and 
Natural Gas?
Background
a. What Is Currently Required?
    Appendix D of part 75 may be used for ``other'' gaseous fuels 
besides pipeline natural gas and natural gas. For these other gaseous 
fuels, appendix D does not allow SO2 emissions to be 
quantified using a default SO2 emission rate. Rather, hourly 
sampling of the total sulfur content of the fuel is required using 
manual sampling methods or an on-line gas chromatograph, although 
section 2.3.6 in appendix D provides a

[[Page 40413]]

720-hour demonstration procedure whereby some relief from hourly sulfur 
sampling can be obtained. The demonstration requires 720 hours of 
sampling to characterize the fuel's total sulfur content and 
variability. If the results of the demonstration show that the fuel has 
a low sulfur variability, then the owner or operator may sample the 
fuel's sulfur content daily instead of hourly.
b. What Changes Were Proposed?
    In the June 13, 2001 proposed rule, EPA proposed clarifying that 
the 720-hour demonstration procedure in section 2.3.6 of appendix D is 
optional and that it may be used to show that the sulfur content of a 
particular gaseous fuel is within the limits for pipeline natural gas 
or natural gas. However, the Agency received a significant comment on 
section 2.3.6, requesting that EPA allow the demonstration procedure to 
be used to determine default SO2 emission factors for 
gaseous fuels such as refinery gas and producer gas, so that units 
burning these fuels would be able to obtain relief from the hourly or 
daily sulfur sampling requirements.
c. What Changes Is EPA Finalizing?
    EPA believes that the commenter's suggestion has merit, and has 
incorporated it into the final rule. Today's rule conditionally allows 
the owner or operator of an Acid Rain Program unit that combusts a 
gaseous fuel other than pipeline natural gas or natural gas to 
determine a fuel-specific default SO2 emission rate using 
the results of the 720-hour demonstration in section 2.3.6 of appendix 
D. The default emission rate could be used in conjunction with the 
hourly heat input rate to quantify hourly SO2 emissions in 
the same manner as is done for pipeline natural gas or natural gas. The 
only exception to this would be if the results of the 720-hour 
demonstration indicate that the gaseous fuel has both a high sulfur 
content and high sulfur variability (i.e., greater than 5.0 grains per 
100 scf, standard deviation). In that case, the more rigorous hourly 
sulfur sampling would be required.
Discussion
    EPA received one comment on the proposed changes to section 2.3.6 
of appendix D (UARG). The commenter requested that EPA add language to 
section 2.3.6 stating that for ``other'' low-sulfur gaseous fuels (such 
as producer gas, refinery gas, and landfill gas), the results of the 
720-hour demonstration in section 2.3.6 may be used to determine a 
fuel-specific default SO2 emission rate such as is 
determined for natural gas by using Equation D-1h. The principal reason 
for this recommended rule revision would be to provide regulatory 
relief from the current appendix D requirement to perform either hourly 
or daily sulfur sampling for these ``other'' gaseous fuels.
    EPA finds the commenter's request to be reasonable and believes 
that the 720-hour demonstration is sufficiently representative to 
support the desired regulatory relief with little risk of 
underestimating SO2 emissions. Therefore, today's rule adds 
the requested language to section 2.3.6 of appendix D. In the final 
rule, revised section 2.3.6 conditionally allows ``other'' gaseous 
fuels (e.g., refinery gas or producer gas) to use default 
SO2 emission rates to quantify SO2 mass emissions 
rather than performing daily or hourly sampling for total sulfur. If 
the 720-hour demonstration described in section 2.3.6 is performed for 
the gaseous fuel, the results of that demonstration may be used to 
determine a default SO2 emission rate, provided that the 
fuel is not found to have both a high sulfur content (more than 20 
grains per 100 scf) and a high sulfur variability (more than 5 grains 
per 100 scf, standard deviation). If the fuel qualifies to use a 
default SO2 emission rate, then Equation D-1h in appendix D 
may be used to calculate the emission rate in the same manner that a 
default emission rate would be calculated for natural gas. The exact 
value of the fuel's total sulfur content used to calculate the default 
emission rate depends on whether the fuel is found to have a low or 
high sulfur variability (i.e., variability with a standard deviation of 
greater than 5.0 grains per 100 scf) during the 720-hour demonstration. 
If the sulfur variability is low, the 90th percentile value from the 
demonstration is used in the calculation. If the sulfur variability is 
high, the maximum value from the demonstration is used to calculate the 
default SO2 emission rate.
    Today's rule requires periodic on-going total sulfur sampling for 
other gaseous fuels that use the demonstration in section 2.3.6 to 
determine a default SO2 emission rate. The required sampling frequency 
is annual. For reporting purposes, the default emission rate derived 
from the 720-hour demonstration is used unless a higher sulfur content 
is obtained in an annual sample, in which case the higher sampled value 
would be reported.
    The Agency notes that the 720-hour demonstration in section 2.3.6 
may also be used to derive fuel-specific default SO2 
emission rates for Acid Rain Program units seeking to qualify as low 
mass emissions units under Sec. 75.19 (see Docket A-2000-33, Item V-C-1 
for further discussion).
4. What Changes to the Appendix D Missing Data Procedures Are 
Finalized?
Background
a. What Is Currently Required?
    Appendix D requires the owner or operator to report substitute data 
for any hour in which quality-assured fuel flow rate data is not 
obtained and whenever a sample of the fuel sulfur content, gross 
calorific value, or density has not been obtained and analyzed as 
required. The load-based missing data procedures for fuel flow rate are 
found in section 2.4 of appendix D. The appropriate substitute data 
values for fuel sulfur content, gross calorific value, and density are 
given in Table D-6.
b. What Changes Were Proposed?
    On June 13, 2001, EPA proposed revising the appendix D missing data 
procedures. The load-based fuel flow rate missing data procedures in 
section 2.4.2 would be clarified but not substantively changed. New 
fuel flow rate missing data procedures would be added for units that do 
not produce electrical output or steam load. The missing data 
requirements for the sulfur content of gaseous fuels in Table D-6 would 
also be changed, as follows: (1) Substitute data values for pipeline 
natural gas and natural gas would be expressed in terms of the total 
sulfur content of the gas instead of the hydrogen sulfide content; (2) 
for pipeline natural gas, the substitute data value would be 0.002 lb/
mmBtu; (3) for natural gas, the substitute data value would be an 
emission rate (in lb/mmBtu) calculated from Equation D-1h using the 
lesser of the maximum total sulfur content specified in the fuel 
contract or 1.5 times the highest total sulfur value from the previous 
year's samples; (4) for gaseous fuels sampled daily, the substitute 
data value would be 1.5 times the highest total sulfur content obtained 
in the previous 30 daily samples; and (5) for gaseous fuels sampled 
hourly, the substitute data value would be the highest total sulfur 
content from the previous 720 hourly samples.
c. What Changes Is EPA Finalizing?
    Today's rule finalizes the revisions to the appendix D missing data 
procedures. The final rule provisions have been modified somewhat from 
the proposal to be consistent with changes that have been made to other 
sections of appendix D based on comments received. The fuel flow rate 
missing data

[[Page 40414]]

procedures for non-load-based units have also been simplified to make 
them easier to implement. EPA has provided additional time in the rule 
language from the effective date of today's rule for owners and 
operators to implement these new missing data routines (see Section V., 
Rule Implementation, of this preamble).
Discussion
    EPA received comments on the proposed revisions to the appendix D 
missing data routines from only one commenter (UARG). The commenter was 
generally supportive of the proposed changes to the gas sulfur content 
substitute data values in Table D-6 and to the missing data routines 
for fuel flow rate. However, the commenter expressed concern that the 
changes would require significant reprogramming of the data acquisition 
and handling system (DAHS) software and requested that EPA allow 
sufficient time to implement the new missing data routines.
    In view of the supportive comments received, the proposed revisions 
are finalized with only minor changes. These changes to the proposal 
are deemed necessary for purposes of consistency. Other sections of 
appendix D have been modified based on comments received, and some of 
the changes to those sections impact the missing data routines. The 
most significant change was made to the substitute data value for 
natural gas combustion. The proposed rule would have required the 
substitute data value to be the lesser of: (a) the maximum sulfur 
content specified in the fuel contract; or (b) 1.5 times the highest 
sulfur content from the previous year's samples. The final rule 
requires the substitute data value to be 1.5 times the default value of 
sulfur content which is in effect at the time of the missing data 
period. According to revised Table D-5, the default value ``in effect'' 
will be either the maximum sulfur content specified in the fuel 
contract or the sulfur content from the most recent sample. Since the 
required sampling frequency for natural gas is annual, only one sample 
is required each year. Thus, there is little difference in meaning 
between the proposed rule language, i.e., ``highest sulfur content from 
the previous year's samples'' and the final rule language, i.e., 
``sulfur content from the most recent sample.''
    Today's rule finalizes the proposed fuel flow rate missing data 
routines both for load-based units and for units that do not produce 
electrical or steam load. The load-based provisions are finalized as 
proposed; however, for ease of implementation the proposed non-load-
based routines have been simplified. In the final rule, the substitute 
data value for non-load-based units is simply the arithmetic average of 
the quality-assured flow rates in a 720-hour lookback period. EPA is 
not finalizing the proposed option that would have allowed the data to 
be sorted into operating bins, nor the associated text in section 4 of 
appendix C. The Agency believes that separating fuel flow data into 
operating bins unnecessarily complicates the missing data routines. EPA 
expects that not finalizing this proposed missing data option will have 
little or no impact since, at present, there are no non-load-based oil 
and gas-fired units required to use part 75 monitoring. However, it is 
possible that such units may be included in a future program such as 
the Federal NOX Budget Trading Program. Should the owners or 
operators of such units elect to use appendix D and decide that 
operational bins are needed for fuel flow rate missing data purposes, 
EPA will consider allowing that missing data approach through the 
petition process under Sec. 75.66.

E. Other Highlights and Changes

1. What Changes to the Compliance Dates and Timelines for Monitor 
Certification in Sec. 75.4 Are Finalized in Today's Rule?
Background
a. What Is Currently Required?
    Part 75 specifies different monitor certification timelines in 
Sec. 75.4 for new units, new stacks, and deferred units. New units must 
certify their monitors within 90 calendar days after the unit commences 
commercial operation. Similarly, for newly affected units, owners or 
operators have 90 calendar days from the date on which they become Acid 
Rain-affected units to certify monitors. Also, when a new stack or flue 
gas desulfurization system (FGD) is constructed, the owner or operator 
has 90 calendar days from the date on which emissions first exit to the 
atmosphere through the new stack or FGD to install and certify 
continuous monitoring systems. However, for deferred units (affected 
units that were in cold-storage on their compliance deadline), owners 
or operators have either 45 operating days or 180 calendar days 
(whichever occurs first) to certify monitors after recommencing 
operation. The 90 calendar day timeline has proven to be problematic, 
particularly for new units that experience mechanical problems when 
they first begin operating. The deferred unit timeline provides greater 
flexibility.
b. What Changes Were Proposed?
    On June 13, 2001, EPA proposed to harmonize all of the timelines 
for deferred units, new units, new stacks, and newly affected units. In 
all cases, the certification deadline would be the earlier of 90 unit 
operating days or 180 calendar days after the unit commences commercial 
operation or recommences operation. Paragraphs (b), (c), (d), and (e) 
of Sec. 75.4 would be revised to incorporate this change. Corresponding 
changes would be made to 40 CFR 97.70, the monitoring and reporting 
sections of the January 18, 2000, section 126 final rule in order to 
make the certification timelines in parts 75 and 97 consistent.
c. What Changes Is EPA Finalizing?
    Today's rule finalizes the proposed changes to the certification 
timelines in parts 75 with one exception. For newly-affected Acid Rain 
Program units under Sec. 75.4(c), the certification timeline would 
begin with the first hour of operation of the unit after the date on 
which it becomes an Acid Rain-affected unit, rather than the first hour 
after the unit becomes Acid Rain-affected.
Discussion
    EPA received numerous comments on the proposed changes to the 
certification timelines in Sec. 75.4 (Reliant, Clean Energy Group, 
Dominion, UARG, Class of '85, Dynegy). All of the commenters were 
supportive of the proposed revisions. However, one commenter requested 
that Sec. 75.4(c) be revised further (Dominion). The commenter 
recommended that the timeline for newly-affected Acid Rain Program 
units be modified so that the ``clock'' starts with the first hour of 
commercial operation of the unit after it becomes affected, rather than 
starting from the date and hour on which the unit becomes affected. The 
commenter indicated that this would provide the utility with the option 
of not operating a newly-acquired unit, thereby allowing time to 
acquire the necessary CEMS equipment. EPA agrees that this added 
flexibility in the certification timeline for newly-affected units is 
desirable and incorporates the commenter's suggestion into the final 
rule.

[[Page 40415]]

2. Does Today's Rule Change the Way in Which Unit and Stack Operating 
Hours Are Counted?
Background
 a. What Is Currently Required?
    Part 75 allows quality-assurance (QA) test exemptions and deadline 
extensions for continuous emission monitors based on the amount of unit 
operation. Grace periods are also allowed to complete missed QA tests. 
To qualify for QA test extensions and exemptions, an owner or operator 
must determine whether there are at least 168 unit or stack operating 
hours in the quarter (so that the quarter meets the definition of a 
``QA operating quarter''). The length of grace periods is also 
determined on a unit or stack operating hour basis. The rule defines 
``unit operating hour'' and ``stack operating hour'' in such a way that 
partial operating hours are counted as full hours. This is not the way 
that source operators normally count operating hours. They normally 
count cumulative operating time so that 30 minutes of operation equals 
0.5 operating hours, not 1.0 hours.
b. What Changes Were Proposed?
    On June 13, 2001, EPA proposed to add two new definitions, 
``cumulative stack operating hours'' and ``cumulative unit operating 
hours'', to Sec. 72.2. The definitions of ``QA operating quarter'' and 
``fuel flowmeter QA operating quarter'' would be revised to put them in 
terms of cumulative unit or stack operating hours. Finally, all 
references to the length of grace periods would be changed to be in 
terms of cumulative unit operating hours or cumulative stack operating 
hours. These proposed changes would effectively remove the requirement 
to count partial operating hours as full hours when determining the 
source operating time and the length of the grace period.
c. What Changes Is EPA Finalizing?
    EPA is finalizing neither of the proposed definitions of 
``cumulative stack operating hours'' and ``cumulative unit operating 
hours'' nor the proposed changes to the way in which unit and stack 
operating hours are counted.
Discussion
    EPA received input from four commenters on the proposed changes to 
the method of counting unit and stack operating hours (Class of '85, 
Dynegy, UARG, XCEL Energy). None of the commenters supported the 
changes without reservation. All of them indicated that EPA should make 
the changes optional, not mandatory. All of the commenters stated that 
the changes would require significant, potentially costly changes to 
the DAHS software. The commenters also noted that for many utilities, 
the increase in rule flexibility associated with the changes would not 
be great enough to justify the expense.
    In the absence of fully supportive comments, EPA has decided not to 
adopt the proposed revisions. The Agency considered incorporating the 
commenters' suggestion to allow two options for calculating source 
operating time, i.e., one based on unit operating hours and one based 
on ``cumulative'' unit operating hours. However, EPA rejected this 
approach because it would seriously complicate program oversight. It 
also would require significant re-programming of EPA's data checking 
software and would require structural changes to several EDR record 
types. In this case, the Agency concludes that the relatively small 
benefit of allowing a second method of calculating source operating 
time does not justify the associated cost.
3. Does Today's Rule Change the Notification Requirements for Monitor 
Certifications and Recertifications?
Backround
    For the initial certification of continuous monitoring systems, 
part 75 requires the owner or operator to provide a minimum of 45 days 
advance notice before the first date of scheduled testing. For 
recertifications, at least 45 days of advance notice is required when 
all recertification tests are required (full recertification), but only 
7 days notice is required when all of the tests are not required 
(partial recertification).
    On June 13, 2001, EPA proposed revising Secs. 75.20 and 75.61, to 
make a single notification requirement of 21 days for initial 
certifications and for all recertifications, regardless of whether all 
of the tests are required. EPA believed the existing 7-day notice for 
partial recertifications provided too little time for State and local 
agency personnel and EPA personnel to schedule site visits to observe 
the recertification testing. Conversely, the Agency believed that 45 
days notice was too far in advance of the testing. Test observation is 
a critical component of agency oversight of the Acid Rain Program 
monitoring requirements, and the 21-day test notification requirement 
would ensure that the agencies can successfully fulfill this 
responsibility.
    Based on comments received, EPA is finalizing the 21-day 
certification test notification requirement as proposed, but has 
modified the proposed recertification test notification provisions. 
Today's rule makes a clearer distinction between full and partial 
recertifications and the notification requirements for each type. The 
final rule reduces the notification requirement for full 
recertifications from 45 to 21 days as proposed, but retains the 7-day 
advance notice requirement for partial recertifications. An emergency 
provision for unplanned full recertifications has also been added to 
Sec. 75.61(a)(1)(i).
Discussion
    EPA received comments from five commenters on the proposed changes 
to the certification and recertification test notification requirements 
(Dominion, Dynegy, UARG, Class of '85, ESC). The commenters did not 
object to reducing the test notification time for initial 
certifications from 45 to 21 days. However, four of the commenters 
objected to the proposal to require 21 days advance notice for 
recertifications (Dominion, Dynegy, UARG, ESC), and the fifth commenter 
objected to the 7-day notification requirement when the scheduled RATA 
is performed on a different date (Class of '85). The commenters 
perceive the 21-day notification requirement for recertifications as 
being an increase from the 7-day requirement of the current rule. For 
reasons discussed in greater detail in the ``Response to Comments'' 
document supporting this rulemaking (see Docket No. A-2000-33, Item V-
C-1), this perception is not entirely correct. The proposed 21-day 
notification requirement represents an increase in notification time 
only for partial recertifications (where a full battery of tests is not 
required). For full recertifications, where all of the tests are 
required, 21 days notice actually is a reduction from the 45-day 
notification requirement of the current rule.
    The commenters' main objection to the 21-day notification 
requirement for recertifications centers around emergency (unplanned) 
events that require recertification. The commenters expressed concern 
that requiring such a long advance notice would require sources in 
emergency situations to postpone testing in order to give observers the 
opportunity to schedule site visits. The commenters stated that this 
could result in sources having to use the missing data routines for 
long periods of time which is inconsistent with the part 75 goal of 
keeping monitors operating and reducing missing data episodes.
    After consideration of these comments, EPA is finalizing the 21-day 
test notification requirement for initial certifications and for full

[[Page 40416]]

recertifications. The text of Sec. 75.61(a)(1)(i) is revised to be 
consistent with Sec. 75.20(b)(2) and to make it clear that the 21-day 
requirement applies to full recertifications as well as initial 
certifications. A typographical error in Sec. 75.20(b) is also 
corrected. The proposed 21-day notification for partial 
recertifications is not adopted, and the 7-day requirement, with the 
associated emergency provision, is retained.
    To address the commenters' concern about emergency 
recertifications, Sec. 75.61(a)(1)(i) of today's rule provides an 
emergency provision for unplanned events beyond the source operator's 
control which require a full battery of recertification tests to be 
performed. The emergency provision is the same as the one in 
Sec. 75.61(a)(1)(ii) for partial recertifications.
4. Does Today's Rule Affect the Way in Which Emissions Are Monitored 
and Reported for Units With Bypass Stacks?
Background
    For an exhaust configuration consisting of a main stack and a 
bypass stack, if the use of the bypass stack is limited by regulation 
or permit to emergency malfunctions of the flue gas desulfurization 
system, Sec. 75.16 allows the maximum potential SO2 
concentration to be reported during the malfunction in lieu of 
installing monitors on the bypass stack. For NOX, however, 
the rule has no corresponding provision. Rather, it appears that 
monitoring of the bypass stack or monitoring of the duct(s) leading to 
the bypass stack are the only available options.
    On June 13, 2001, EPA proposed clarified and expanded instructions 
for SO2 and NOX monitoring of multiple and bypass 
stack configurations in Secs. 75.16(c) and 75.17(c), and in 
Sec. 75.72(c) and (d). EPA proposed a new provision to Secs. 75.17(c) 
and 75.72(c) for configurations consisting of a main stack and a bypass 
stack, allowing the maximum potential NOX emission rate to 
be reported when the bypass stack is used.
    EPA also proposed revisions to the language in Sec. 75.16(c)(3) 
which restricts the reporting of the maximum potential SO2 
concentration (MPC) to emergency situations in which the flue gas 
desulfurization (FGD) system is bypassed. Proposed Sec. 75.16(c)(3) 
would allow the MPC to be reported in lieu of monitoring at the bypass 
stack, provided that the use of the bypass stack is limited to unit 
startups, emergency situations, and routine maintenance of the FGD 
system and the main stack.
    Today's rule finalizes the proposed bypass stack monitoring and 
reporting revisions with minor editorial changes.
Discussion
    Two commenters supported the proposed revisions to the bypass stack 
monitoring provisions (UARG, Reliant). However, one of the commenters 
objected to the proposed language in Secs. 75.16(c) and 75.17(c) 
addressing the reporting of parameters other than SO2 or 
NOX during bypass hours, stating that the proposed language 
``creates confusion and conflict'' (UARG).
    After consideration of these comments, EPA is finalizing the bypass 
stack monitoring provisions as proposed, except that the references in 
Secs. 75.16(c) and 75.17(c) to the reporting of other parameters, such 
as CO2, are not adopted because EPA believes that these 
requirements are adequately addressed in other sections of the rule and 
do not need to be re-stated here.
5. What Other Noteworthy Provisions Are Finalized in Today's Rule?
    EPA notes that no negative comment was received on the following 
significant revisions to part 75 that are finalized for the reasons 
stated in the proposed rule:
     The proposal to remove the restriction in section 2.1.2 of 
appendix D prohibiting apportionment of measured hourly heat input at a 
common pipe to the individual units (for units using the provisions of 
subpart H of part 75 to monitor NOX mass emissions) is 
finalized. Common pipe heat input apportionment is now allowed for 
subpart H units, provided that the units served by the pipe are all 
affected units with similar efficiencies (e.g., all boilers or all 
turbines).
     The proposed revisions to the appendix E missing data 
procedures are finalized.
     The proposed revisions to appendix E, section 2.2, 
requiring retesting once every 5 years (20 calendar quarters) and 
removing the requirement to retest every 3,000 operating hours are 
finalized.
     The proposal to expand the use of Equation G-4 in appendix 
G to oil-fired units is finalized.

F. Streamlining Changes

Background
    A number of rule sections in part 75 have expired either on 
December 31, 1999, or on March 31, 2000. For some, but not all, of 
these expired rule provisions, part 75 contains new (replacement) 
provisions, having effective dates of January 1, 2000, or April 1, 
2000, respectively. The expired provisions are a potential source of 
confusion to both the regulated community and to regulators in 
assessing compliance with part 75. For instance, the rule contains two 
sets of recordkeeping and reporting provisions, one of which expired on 
March 31, 2000, and the other which became effective on April 1, 2000. 
Removing the expired sections would greatly facilitate part 75 
implementation and compliance.
    On June 13, 2001, EPA proposed streamlining part 75 by eliminating 
outdated language in the rule and by removing a number of references 
throughout part 75 to sections of the rule that are no longer 
effective. This streamlining would occur in several places in the rule. 
The Agency proposed to remove from part 75 all of the rule sections 
that expired on April 1, 2000, and all textual references to those 
sections. This includes the recordkeeping and reporting sections, 
Secs. 75.54, 75.55, and 75.56; the monitoring plan provisions in 
Sec. 75.53(c) and (d); and the CO2 missing data provisions 
in Sec. 75.35(c).
    EPA also proposed removing rule sections that only applied to Phase 
I Acid Rain Program units and are now inapplicable, and to remove all 
textual references to those sections. For instance, the 15 percent 
relative accuracy specification for flow monitors expired at the end of 
Phase I (on December 31, 1999) and was replaced on January 1, 2000, by 
the current 10 percent standard. The proposed rule would revise 
appendix A, section 3.3.4; appendix B, sections 2.3.1.2(b) and (c); and 
Figure 2 of appendix B to reflect this.
    Today's rule finalizes the streamlining changes as proposed. EPA 
has prepared a technical support document (see Docket No. A-2000-33, 
Item IV-A-9) that identifies in tabular form all of the streamlining 
changes made to part 75.
Discussion
    EPA received comments from only one commenter on the proposed 
streamlining changes to part 75 (UARG). The commenter agreed that the 
cited rule provisions are obsolete and did not object to their removal. 
Therefore, EPA finalizes the changes as proposed.

V. Rule Implementation

    This final rule becomes effective July 12, 2002. However, EPA is 
aware that while some affected sources may choose to take advantage of 
options provided immediately, others will require more time for 
implementation. Therefore, EPA has specified in this final rule where 
additional time is permitted for

[[Page 40417]]

full compliance with new mandatory requirements.
    The rule provisions that provide alternative compliance dates are 
as follows: Appendix A paragraph 2.1.2.1(a); Appendix D Table D-6 under 
Gas Total Sulfur Content; and Appendix E paragraph 2.5.2.
    EPA is aware that some non-load based units are required under 
their State's SIP to start monitoring NOX mass emissions 
according to part 75 in the 2002 ozone season. EPA will continue to 
work with the affected sources and the State to resolve any conflicts 
imposed on the sources by the timing of today's rule.
    Some aspects of the final rule that will require attention concern 
reporting requirements and mechanisms. While EPA is prepared to accept 
electronic data reports in the proscribed format, regulated sources 
will require time to review the final rule and make any adjustments or 
changes in software that may result. With this in mind, EPA is updating 
the EDR version 2.1 Instructions to accompany this final rule. EPA has 
identified in the rule language any deadlines for compliance that are 
different from the effective date of this rule, as applicable. If you 
have questions regarding the implementation of this final rule, consult 
the person listed in the preceding FOR FURTHER INFORMATION CONTACT 
section of this preamble.

VI. Regulatory Assessment Requirements

A. Executive Order 12866: Regulatory Planning and Review

    Under Executive Order 12866 (58 FR 51735, October 4, 1993), the 
Agency must determine whether the regulatory action is ``significant'' 
and therefore subject to Office of Management and Budget (OMB) review 
and the requirements of the Executive Order. The Order defines 
``significant regulatory action'' as one that is likely to result in a 
rule that may:
    (1) Have an annual effect on the economy of $100 million or more or 
adversely affect in a material way the economy, a sector of the 
economy, productivity, competition, jobs, the environment, public 
health or safety, or State, local, or tribal governments or 
communities;
    (2) Create a serious inconsistency or otherwise interfere with an 
action taken or planned by another agency;
    (3) Materially alter the budgetary impact of entitlements, grants, 
user fees, or loan programs or the rights and obligations of recipients 
thereof; or
    (4) Raise novel legal or policy issues arising out of legal 
mandates, the President's priorities, or the principles set forth in 
the Executive Order.
    This final rule is not expected to have an annual effect on the 
economy of $100 million or more. It has been determined that this rule 
is not a ``significant regulatory action'' under the terms of Executive 
Order 12866 and it is therefore not subject to OMB review.

B. 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.
    Today's rule is not expected to result in expenditures of $100 
million or more for State, local, and tribal governments, in the 
aggregate, or the private sector in any one year and, as such, is not 
subject to sections 202 and 205 of the UMRA. As discussed in section 
III., above, EPA will continue to use its outreach efforts related to 
part 75 implementation, including guidance documents and a policy 
manual that is updated regularly, to inform, educate, and advise all 
potentially impacted governments about compliance with part 75.

C. Paperwork Reduction Act

    The Office of Management and Budget (OMB) has approved the 
information collection requirements contained in this rule under the 
provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et. seq. and 
has assigned OMB control numbers 2060-0258 and 2060-0445.
    The information collection requirements in 40 CFR parts 72 and 75 
affect two EPA programs, the Acid Rain Program and the Federal 
NOX Budget Trading Program. There are two program ICRs 
currently in place that account for the basic recordkeeping and 
reporting burdens associated with 40 CFR parts 72 and 75. First, the 
Acid Rain Program ICR (ICR 1633.12, OMB No. 2060-0258) addresses the 
costs for units affected by the Acid Rain Program. The NOX 
SIP Call ICR (ICR 1857.02, OMB No. 2060-0445) addresses the costs, 
including NOX mass monitoring costs, by both Acid Rain 
Program (ARP) units and non-ARP units in the NOX Budget 
Trading Program.
    Most of the changes associated with this rulemaking provide 
additional flexibilities to existing regulations in response to issues 
raised during the ongoing implementation of part 75. Thus, they do not 
significantly affect the burden estimates included in the two existing 
ICRs. Table 1, below, categorizes the changes finalized in parts 72 and 
75, as recordkeeping and reporting burden/cost neutral or as burden/
cost reducing; none of the changes is expected to significantly 
increase burdens or costs. (The remaining changes do not affect 
recordkeeping and reporting requirements.)
    Further, the Agency expects the changes to have minimal impact on 
existing program ICRs because many of the changes merely serve to make 
additional flexibilities feasible. For example, many of the rule 
revisions to the LME section clarify how the rule applies to non-ARP 
SIP Call units that use part 75 for NOX mass monitoring. The 
changes make use of the LME provisions feasible for non-ARP units so 
that the scope of applicability to non-ARP units is not expected to be 
significantly different from that for ARP units.
    The SIP Call ICR assumed none of the non-ARP units would take 
advantage of the reduced burdens and costs associated with the LME 
provisions

[[Page 40418]]

because those estimates only related to burden incurred through the 
year 2002. In future years, as LMEs avail themselves of the proposed 
provisions, it is estimated that there will be burden reductions. These 
reductions will be reflected in the next revisions to the SIP Call ICR.

          Table 1.--Summary of Impacts of Major Rule Revisions
------------------------------------------------------------------------
 
-------------------------------------------------------------------------
           A. Rule Revisions Assumed to Be Cost/Burden Neutral
 Pipeline natural gas definition revision, and other definition
 clarifications
 Standardization of deadlines for various activities/reports/
 notices
 Data validation clarifications
 Span/range clarifications
 Bypass monitoring flexibility changes
 Clarifications for Subpart H missing data
 General LME clarifications
 Missing data options relating to fuel type, degree of control,
 and non-load based units
 Alternative bypass stack monitoring options
 Other miscellaneous changes
           B. Rule Revisions Assumed to Decrease Costs/Burdens
 Expanded clarification and applicability of LME for Subpart H
 monitoring
------------------------------------------------------------------------

    Although not indicated in Table 1, there are two primary ways in 
which the parts 72 and 75 revisions could result in some increased 
burden or cost. First, the regulated industry and State and local 
agencies involved with part 75 monitoring will have to review the 
revised regulation to understand the changes. The existing ARP and SIP 
Call ICRs have accounted for this increase in a line item for ongoing 
rule review. Nevertheless, it is important to note that new units just 
initiating part 75 monitoring in response to the NOX SIP 
Call will experience less burden as a consequence of the numerous 
clarifications, the specific changes to address NOX mass 
monitoring issues, and the removal of outdated sections. Taken as a 
whole, EPA does not believe that the regulatory review burdens will be 
significant.
    The second type of burden or cost increase would be associated with 
any required DAHS software changes that may be necessary to the extent 
the rule revisions affect recording and reporting data in the required 
electronic data formats. Generally, EPA has attempted to minimize any 
DAHS impacts associated with these revisions. There are some optional 
elements of the rule revisions that could require DAHS software 
changes, but only if the owner or operator decides to take advantage of 
the option for its circumstances. EPA believes many sources will only 
avail themselves of these types of changes as part of other routine 
monitoring system component upgrades. As noted in Section V., Rule 
Implementation, of this preamble, sources regulated under part 75 will 
have additional time to comply with certain provisions. Consequently, 
the expected impact associated with DAHS changes is also expected to be 
minimal.
    In the proposed rule, the Agency specifically requested comment on 
its assessment of information burden imposed by these requirements and 
received no comments on the subject. 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 
purpose of collecting, validating, and verifying information; process 
and maintain information and disclose and provide information; adjust 
the existing ways to comply with any previously applicable instructions 
and requirements; train personnel to respond to a collection of 
information; search existing 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 valid 
OMB control number. The OMB control numbers for EPA's regulations are 
listed in 40 CFR part 9 and 48 CFR chapter 15.

D. Regulatory Flexibility Act (RFA) as Amended by the Small Business 
Regulatory Enforcement Fairness Act of 1996 (SBREFA), 5 U.S.C. 601 et. 
seq.

    The 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.
    After considering the economic impacts of today's final 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 a 
substantial number of small entities, the impact of concern is any 
significant adverse economic impact on small entities, since the 
primary purpose of the regulatory flexibility analyses is to identify 
and address regulatory alternatives ``which minimize any significant 
economic impact of the proposed 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 
effect on the small entities subject to the rule. Today's final action 
adds flexibility to the existing procedures for monitoring and 
reporting and makes other streamlining improvements and clarifications 
to the existing regulations. The EPA has therefore concluded that 
today's final rule will have no adverse impacts on small entities and 
may relieve burden in some cases.

E. National Technology Transfer and Advancement Act

    As noted in the proposed rule, section 12(d) of the National 
Technology Transfer and Advancement Act of 1995 (``NTTAA''), Public Law 
No. 104-113 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

[[Page 40419]]

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 rulemaking involves environmental monitoring or measurement. 
Consistent with the Agency's Performance Based Measurement System 
(``PBMS''), part 75 sets forth criteria that allow the use of 
alternative methods to the ones identified in part 75. The PBMS 
approach is intended to be more flexible and cost effective for the 
regulated community; it is also intended to encourage innovation in 
analytical technology and improved data quality.
    EPA specifically requested public comment on any other voluntary 
consensus standards which may be appropriate for the part 75 rule 
revisions and no such comments were received. The EPA is not precluding 
the use of any method, whether it constitutes a voluntary consensus 
standard or not, as long as it meets the performance criteria 
specified; however, any alternative methods must be approved through 
the petition process under Sec. 75.66(c) before they may be used under 
part 75.

F. Executive Order 13045: Protection of Children From Environmental 
Health Risks and Safety Risks

    Executive Order 13045, entitled ``Protection of Children from 
Environmental Health Risks and Safety Risks'' (62 FR 19885, April 23, 
1997), applies to any rule that: (1) Is determined to be ``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.
    Today's rule is not subject to Executive Order 13045 because it is 
not economically significant as defined in Executive Order 12866, and 
because the Agency does not have reason to believe the environmental 
health or safety risks addressed by this action present a 
disproportionate risk to children.

G. 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.''
    Today's action does not have federalism implications. It will not 
have substantial direct effects on the States, on the relationship 
between the national government and the States, or on the distribution 
of power and responsibilities among the various levels of government, 
as specified in Executive Order 13132. This final rule does not create 
a mandate upon State, local, or tribal governments, except to the 
extent such governments own or operate an affected source. Even in 
those cases, the proposed rule revisions do not have federalism 
implications and do not impose significant compliance costs beyond the 
costs already incurred under part 75. Thus, Executive Order 13132 does 
not apply to this rule.
    As discussed above in Section III. and in the spirit of Executive 
Order 13132, and consistent with EPA policy to promote communications 
between EPA and State and local governments, EPA specifically worked 
with and solicited comment on the proposed rule from State and local 
officials.

H. 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 6, 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.'' ``Policies that have tribal 
implications'' is defined in the Executive Order to include regulations 
that have ``substantial direct effects on one or more Indian tribes, on 
the relationship between the Federal government and the Indian tribes, 
or on the distribution of power and responsibilities between the 
Federal government and Indian tribes.''
    This final rule does not have tribal implications. It will not have 
substantial direct effects on tribal governments, on the relationship 
between the Federal government and Indian tribes, or on the 
distribution of power and responsibilities between the Federal 
government and Indian tribes, as specified in Executive Order 13175. 
Thus, Executive Order 13175 does not apply to this rule.
    Moreover, as discussed above in Section III. and in the spirit of 
Executive Order 13175, and consistent with EPA policy to promote 
communications between EPA and tribal governments, EPA specifically 
solicited comment on the proposed rule from tribal officials.

I. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use

    This 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. Further, 
we have concluded that this rule is not likely to have any adverse 
energy effects.

J. Congressional Review Act

    The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the 
Small Business Regulatory Enforcement Fairness Act of 1996, generally 
provides that before a rule may take effect, the agency promulgating 
the rule must submit a rule report, which includes a copy of the rule, 
to each House of the Congress and to the Comptroller General of the 
United States. EPA will submit a report containing this rule and other 
required information to the U.S. Senate, the U.S. House of 
Representatives, and the Comptroller General of the United States prior 
to publication of the rule in the Federal Register. This rule will take 
affect July 12, 2002.

List of Subjects

40 CFR Part 72

    Environmental protection, Acid rain, Administrative practice and 
procedure, Air pollution control, Continuous emission monitoring, 
Electric utilities, Nitrogen oxides, NOX Budget Trading 
Program, Reporting and recordkeeping requirements, Sulfur oxides.

40 CFR Part 75

    Environmental protection, Acid rain, Administrative practice and 
procedure, Air pollution control, Carbon dioxide, Continuous emission 
monitoring (CEM), Electric generating units (EGUs), Electric utilities, 
Nitrogen oxides, Non-electric generating units (Non-EGUs), Non-load 
based units, NOX Budget Trading Program, Reporting and 
recordkeeping requirements, Subpart H, Sulfur oxides.


[[Page 40420]]


    Dated: May 1, 2002.
Christine Todd Whitman,
Administrator.

    For the reasons set out in the preamble, title 40 chapter I of the 
Code of Federal Regulations is amended 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.

    2. Section 72.2 is amended by:
    a. Revising the definitions of ``Cogeneration unit'', ``Continuous 
emission monitoring system or CEMS'', ``Low mass emissions unit'', 
``Missing data period'', ``Pipeline natural gas'', ``Stack operating 
hour'', and ``Unit operating hour'';
    b. In the definition of ``Automated data acquisition and handling 
system'' by adding the words ``moisture monitors,'' before the word 
``opacity'';
    c. In the definition of ``By-pass stack'' by removing the hyphen 
from the word ``Bypass'';
    d. In paragraph (1) of the definition of ``Calibration error'' by 
adding the word ``a'' before the words ``gaseous monitor'';
    e. In the definition of ``Compliance plan'' by adding a closing 
parenthesis after the second instance of the words ``part 76 of this 
chapter'';
    f. In the definition of ``Continuous opacity monitoring system or 
COMS'' by revising the words ``systems are component parts'' in the 
second sentence to read ``components are'', and in paragraph (2) by 
revising the word ``A'' to read ``An automated'';
    g. Revising paragraph (2) of the definition of ``Emergency fuel'';
    h. In the definition of ``Fuel flowmeter QA operating quarter'' by 
removing the words ``or more'' at the end of the definition;
    i. Removing the definition of ``Heat input'' and adding in its 
place a new definition ``Heat input rate'';
    j. Removing the definition of ``Hour before and after'' and adding 
in its place a new definition of ``Hour before and Hour after'';
    k. Removing the definition of ``Maximum potential NOX 
emission rate'' and adding in its place ``Maximum potential 
NOX emission rate or MER'';
    l. Removing the definition of ``Maximum rated hourly heat input'' 
and adding in its place the definition for ``Maximum rated hourly heat 
input rate'';
    m. In the definition for ``monitor accuracy'' by removing the words 
``or by one of its component parts'';
    n. In the definition of ``Natural gas'' by revising the second 
sentence, and by removing the word ``meet'' and revising the ``%'' 
symbol to read ``percent'' in the third sentence;
    o. In the definition of ``Peaking unit'' by adding a new paragraph 
(4);
    p. In the definition of ``Relative accuracy'' by adding the words 
``or moisture'' after the words ``between the pollutant'' and by adding 
the words ``or moisture monitor'' after the words ``flow monitor'';
    q. Adding new definitions for ``Common pipe'', ``Common pipe 
operating time'', ``Diluent cap value'', ``Fuel flowmeter system'', 
``Fuel usage time'', ``Multiple stack configuration'', ``Stack 
operating time'', and ``Unit operating time''.
    The revisions and additions read as follows:


Sec. 72.2  Definitions.

* * * * *
    Cogeneration unit means a unit that produces electric energy and 
useful thermal energy for industrial, commercial, or heating or cooling 
purposes, through the sequential use of the original fuel energy.
* * * * *
    Common pipe means an oil or gas supply line through which the same 
type of fuel is distributed to two or more affected units.
    Common pipe operating time means the portion of a clock hour during 
which fuel flows through a common pipe. The common pipe operating time, 
in hours, is expressed as a decimal fraction, with valid values ranging 
from 0.00 to 1.00.
* * * * *
    Continuous emission monitoring system or CEMS means the equipment 
required by part 75 of this chapter used to sample, analyze, measure, 
and provide, by means of readings recorded at least once every 15 
minutes (using an automated data acquisition and handling system 
(DAHS)), a permanent record of SO2, NOX, or 
CO2 emissions or stack gas volumetric flow rate. The 
following are the principal types of continuous emission monitoring 
systems required under part 75 of this chapter. Sections 75.10 through 
75.18 and Sec. 75.71(a) of this chapter indicate which type(s) of CEMS 
is required for specific applications:
    (1) A sulfur dioxide monitoring system, consisting of an 
SO2 pollutant concentration monitor and an automated DAHS. 
An SO2 monitoring system provides a permanent, continuous 
record of SO2 emissions in units of parts per million (ppm);
    (2) A flow monitoring system, consisting of a stack flow rate 
monitor and an automated DAHS. A flow monitoring system provides a 
permanent, continuous record of stack gas volumetric flow rate, in 
units of standard cubic feet per hour (scfh);
    (3) A nitrogen oxides (NOX) emission rate (or 
NOX-diluent) monitoring system, consisting of a 
NOX pollutant concentration monitor, a diluent gas 
(CO2 or O2) monitor, and an automated DAHS. A 
NOX-diluent monitoring system provides a permanent, 
continuous record of: NOX concentration in units of parts 
per million (ppm), diluent gas concentration in units of percent 
O2 or CO2 (% O2 or CO2), 
and NOX emission rate in units of pounds per million British 
thermal units (lb/mmBtu);
    (4) A nitrogen oxides concentration monitoring system, consisting 
of a NOX pollutant concentration monitor and an automated 
DAHS. A NOX concentration monitoring system provides a 
permanent, continuous record of NOX emissions in units of 
parts per million (ppm). This type of CEMS is used only in conjunction 
with a flow monitoring system to determine NOX mass 
emissions (in lb/hr) under subpart H of part 75 of this chapter;
    (5) A carbon dioxide monitoring system, consisting of a 
CO2 pollutant concentration monitor (or an oxygen monitor 
plus suitable mathematical equations from which the CO2 
concentration is derived) and the automated DAHS. A carbon dioxide 
monitoring system provides a permanent, continuous record of 
CO2 emissions in units of percent CO2 (% 
CO2); and
    (6) A moisture monitoring system, as defined in Sec. 75.11(b)(2) of 
this chapter. A moisture monitoring system provides a permanent, 
continuous record of the stack gas moisture content, in units of 
percent H2O (% H2O)
* * * * *
    Diluent cap value means a default value of percent CO2 
or O2 which may be used to calculate the hourly 
NOX emission rate, CO2 mass emission rate, or 
heat input rate, when the measured hourly average percent 
CO2 is below the default value or when the measured hourly 
average percent O2 is above the default value. The diluent 
cap values for boilers are 5.0 percent CO2 and 14.0 percent 
O2. For combustion turbines, the diluent cap values are 1.0 
percent CO2 and 19.0 percent O2.
* * * * *
     Emergency fuel means either:
    (1) * * *
    (2) For purposes of the requirement for stack testing for an 
excepted

[[Page 40421]]

monitoring system under appendix E of part 75 of this chapter, the fuel 
identified in a federally-enforceable permit for a plant and identified 
by the designated representative in the unit's monitoring plan as the 
fuel which is combusted only during emergencies where the primary fuel 
is not available.
* * * * *
    Fuel flowmeter system means an excepted monitoring system (as 
defined in this section) which provides a continuous record of the flow 
rate of fuel oil or gaseous fuel, in accordance with appendix D to part 
75 of this chapter. A fuel flowmeter system consists of one or more 
fuel flowmeter components, all necessary auxiliary components (e.g., 
transmitters, transducers, etc.), and a data acquisition and handling 
system (DAHS).
* * * * *
    Fuel usage time means the portion of a clock hour during which a 
unit combusts a particular type of fuel. The fuel usage time, in hours, 
is expressed as a decimal fraction, with valid values ranging from 0.00 
to 1.00.
* * * * *
    Heat input rate means the product (expressed in mmBtu/hr) of the 
gross calorific value of the fuel (expressed in mmBtu/mass of fuel) and 
the fuel feed rate into the combustion device (expressed in mass of 
fuel/hr) and does not include the heat derived from preheated 
combustion air, recirculated flue gases, or exhaust from other sources.
    Hour before and hour after means, for purposes of the missing data 
substitution procedures of part 75 of this chapter, the quality-assured 
hourly SO2 or CO2 concentration, hourly flow 
rate, hourly NOX concentration, hourly moisture, hourly 
O2 concentration, or hourly NOX emission rate (as 
applicable) recorded by a certified monitor during the unit or stack 
operating hour immediately before and the unit or stack operating hour 
immediately after a missing data period.
* * * * *
    Low mass emissions unit means an affected unit that is ``gas-
fired'' or ``oil-fired'' (as defined in this section), and that 
qualifies to use the low mass emissions excepted methodology in 
Sec. 75.19 of this chapter.
* * * * *
    Maximum potential NOX emission rate or MER means the 
emission rate of nitrogen oxides (in lb/mmBtu) calculated in accordance 
with section 3 of appendix F to part 75 of this chapter, using the 
maximum potential nitrogen oxides concentration (MPC), as defined in 
section 2.1.2.1 of appendix A to part 75 of this chapter, and either 
the maximum oxygen concentration (in percent O2) or the 
minimum carbon dioxide concentration (in percent CO2) under 
all operating conditions of the unit except for unit start-up, 
shutdown, and upsets. The diluent cap value, as defined in this 
section, may be used in lieu of the maximum O2 or minimum 
CO2 concentration to calculate the MER. As a second 
alternative, when the NOX MPC is determined from emission 
test results or from historical CEM data, as described in section 
2.1.2.1 of appendix A to part 75 of this chapter, quality-assured 
diluent gas (i.e., O2 or CO2) data recorded 
concurrently with the MPC may be used to calculate the MER. For the 
purposes of Secs. 75.4(f), 75.19(b)(3), and 75.33(c)(7) in part 75 of 
this chapter and section 2.5 in appendix E to part 75 of this chapter, 
the MER is specific to the type of fuel combusted in the unit.
    Maximum rated hourly heat input rate means a unit-specific maximum 
hourly heat input rate (mmBtu/hr) which is the higher of the 
manufacturer's maximum rated hourly heat input rate or the highest 
observed hourly heat input rate.
    Missing data period means the total number of consecutive hours 
during which any certified CEMS or approved alternative monitoring 
system is not providing quality-assured data, regardless of the reason.
* * * * *
    Multiple stack configuration refers to an exhaust configuration in 
which the flue gases from a particular unit discharge to the atmosphere 
through two or more stacks. The term also refers to a unit for which 
emissions are monitored in two or more ducts leading to the exhaust 
stack, in lieu of monitoring at the stack.
* * * * *
    Natural gas means * * * Natural gas contains 20.0 grains or less of 
total sulfur per 100 standard cubic feet. * * *
* * * * *
    Peaking unit means: * * *
    (4) A unit required to comply with the provisions of subpart H of 
part 75 of this chapter, under a State or Federal NOX mass 
emissions reduction program, may, pursuant to Sec. 75.74(c)(11) in part 
75 of this chapter, qualify as a peaking unit on an ozone season basis 
rather than an annual basis, if the owner or operator reports 
NOX mass emissions and heat input data only during the ozone 
season.
* * * * *
    Pipeline natural gas means a naturally occurring fluid mixture of 
hydrocarbons (e.g., methane, ethane, or propane) produced in geological 
formations beneath the Earth's surface that maintains a gaseous state 
at standard atmospheric temperature and pressure under ordinary 
conditions, and which is provided by a supplier through a pipeline. 
Pipeline natural gas contains 0.5 grains or less of total sulfur per 
100 standard cubic feet. Additionally, pipeline natural gas must either 
be composed of at least 70 percent methane by volume or have a gross 
calorific value between 950 and 1100 Btu per standard cubic foot.
* * * * *
    Stack operating hour means a clock hour during which flue gases 
flow through a particular stack or duct (either for the entire hour or 
for part of the hour) while the associated unit(s) are combusting fuel.
    Stack operating time means the portion of a clock hour during which 
flue gases flow through a particular stack or duct while the associated 
unit(s) are combusting fuel. The stack operating time, in hours, is 
expressed as a decimal fraction, with valid values ranging from 0.00 to 
1.00.
* * * * *
    Unit operating hour means a clock hour during which a unit combusts 
any fuel, either for part of the hour or for the entire hour.
* * * * *
    Unit operating time means the portion of a clock hour during which 
a unit combusts any fuel. The unit operating time, in hours, is 
expressed as a decimal fraction, with valid values ranging from 0.00 to 
1.00.
* * * * *

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.


Sec. 75.1  [Amended].

    4. Section 75.1 is amended by adding the words ``[the Act]'' at the 
end of the first sentence of paragraph (a).

    5. Section 75.4 is amended by:
    a. In paragraphs (b)(2) and (c)(2) by revising the words ``Not 
later than 90'' to read ``The earlier of 90 unit operating days or 180 
calendar'', and, in paragraph (c)(2), by revising the word ``becomes'' 
to read ``first operates after becoming'';
    b. In the first sentence of paragraph (d) by revising the words 
``the earlier of 45'' to read ``90'', adding the words ``(whichever 
occurs first)'' following the words ``180 calendar days'', and

[[Page 40422]]

removing the words ``of the affected unit'' after the words 
``recommences commercial operation'';
    c. Revising paragraphs (d)(1), (f) introductory text, (f)(1), 
(i)(2) and (i)(3);
    d. In paragraph (e) introductory text, by revising the words ``90 
calendar days'' to read ``90 unit operating days or 180 calendar days 
(whichever occurs first)'', by removing the word ``or'' in each 
instance that it occurs between ``flue, or flue gas'' or ``flue or flue 
gas'', by adding a comma between the words ``flue'' and ``flue gas'' in 
the second sentence, and by adding ``or add-on NOX emission 
controls'' after each occurrence of ``desulfurization system'';
    e. Removing and reserving paragraph (h);
    f. In paragraph (i)(1), by removing the word ``or''; and
    g. Adding paragraph (j).
    The revisions and additions read as follows:


Sec. 75.4  Compliance dates.

* * * * *
    (d) * * *
    (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, or the maximum potential CO2 
concentration, as defined in section 2.1.3.1 of appendix A to this 
part;
* * * * *
    (f) In accordance with Sec. 75.20, the owner or operator of an 
affected gas-fired or oil-fired peaking unit, if planning to use 
appendix E of this part, shall ensure that the required certification 
tests for excepted monitoring systems under appendix E are completed 
for backup fuel, as defined in Sec. 72.2 of this chapter, no later than 
90 unit operating days or 180 calendar days (whichever occurs first) 
after the date that the unit first combusts the backup fuel following 
the certification testing with the primary fuel. If the required 
testing is completed by this deadline, the appendix E correlation curve 
derived from the test results may be used for reporting data under this 
part beginning with the first date and hour that the backup fuel is 
combusted, provided that the fuel flowmeter for the backup fuel was 
certified as of that date and hour. If the required appendix E testing 
has not been successfully completed by the compliance date in this 
paragraph, then, until the testing is completed, the owner or operator 
shall report NOX emission rate data for all unit operating 
hours that the backup fuel is combusted using either:
    (1) The fuel-specific maximum potential NOX emission 
rate, as defined in Sec. 72.2 of this chapter; or
* * * * *
    (h) [Reserved]
    (i) * * *
    (2) For a new affected unit which has not commenced commercial 
operation by January 2, 2000, 90 unit operating days or 180 calendar 
days (whichever occurs first) after the date the unit commences 
commercial operation; or
    (3) For an existing unit that is shutdown and is not yet operating 
by April 1, 2000, 90 unit operating days or 180 calendar days 
(whichever occurs first) after the date that the unit recommences 
commercial operation.
    (j) If the certification tests required under paragraph (b) or (c) 
of this section have not been completed by the applicable compliance 
date, the owner or operator shall determine and report SO2 
concentration, NOX emission rate, CO2 
concentration, and flow rate data for all unit operating hours after 
the applicable compliance date in this paragraph until all 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, or the maximum potential CO2 
concentration, as defined in section 2.1.3.1 of appendix A to this 
part;
    (2) Reference methods under Sec. 75.22(b); or
    (3) Another procedure approved by the Administrator pursuant to a 
petition under Sec. 75.66.


Sec. 75.6  [Amended]

    6. Section 75.6 is amended in paragraphs (a)(17), (a)(18), (a)(19), 
(a)(26) and (a)(35) by removing the words ``Sec. 75.15 and''.
    7. Section 75.10 is amended by:
    a. In paragraph (a)(1) by revising the first occurrence of the word 
``The'' in the first sentence to read ``To determine SO2 
emissions, the'', and by revising the words ``the automated'' to read 
``an automated'';
    b. In paragraph (a)(2) by revising the word ``The'' in the first 
sentence to read ``To determine NOX emissions, the''; by 
adding the word ``-diluent'' after the first occurrence of the word 
``NOX'' in the first sentence; and by revising the words 
``the automated'' to read ``an automated'';
    c. In paragraph (a)(3)(i) by revising the words ``the automated'' 
to read ``an automated'';
    d. In paragraph (a)(3)(iii) by revising the words ``using an 
O2 concentration monitor in order'' to read ``that uses an 
O2 concentration monitor,'' and by revising the words 
``using the procedures in appendix F of this part with the automated'' 
to read ``(according to the procedures in appendix F of this part) with 
an automated'';
    e. Removing ``and'' at the end of paragraph (a)(3)(iii) and 
removing the period at the end of paragraph (a)(4) and adding ``; and'' 
in its place;
    f. Adding new paragraph (a)(5);
    g. In paragraph (c) by adding the word ``Rate'' after the words 
``Heat Input'' in the heading and by adding the words ``rate, in units 
of mmBtu/hr,'' after the words ``record the heat input'';
    h. In paragraph (d)(1) by removing the words ``and component 
thereof'' from the first sentence, removing the words ``SO2 
emission rate in lb/mmBtu (if applicable),'' from the second sentence, 
and by adding the word ``or'' after the words ``of this part,'' in the 
fourth sentence;
    i. In paragraph (d)(3) by revising the words ``flow monitor, or 
NOX'' in the first sentence to read ``NOX 
concentration monitor, flow monitor, moisture monitor, or 
NOX-diluent'', by revising the words ``An hourly average 
NOX or SO2'' in the second sentence to read ``For 
a NOX-diluent monitoring system, an hourly average 
NOX'', by adding the word ``NOX'' before the word 
``pollutant'' and by removing the words ``(NOX or 
SO2)'' in the second sentence, and by revising in the fourth 
sentence the words ``Except for SO2 emission rate data in 
lb/mmBtu, if'' to read ``If'';
    j. In paragraph (f) by removing the words ``and component 
thereof''; and
    k. Revising the heading of paragraph (g) from ``Minimum Recording 
and Recordkeeping Requirements'' to ``Minimum recording and 
recordkeeping requirements''.
    The revisions and additions read as follows:


Sec. 75.10  General operating requirements.

    (a) * * *
    (5) A single certified flow monitoring system may be used to meet 
the requirements of paragraphs (a)(1) and (a)(3) of this section. A 
single certified diluent monitor may be used to meet the requirements 
of paragraphs (a)(2) and (a)(3) of this section. A single automated 
data acquisition and handling system may be used to meet the 
requirements of paragraphs (a)(1) through (a)(4) of this section.
* * * * *

[[Page 40423]]

Sec. 75.11  [Amended]

    8. Section 75.11 is amended by:
    a. Revising the word ``psychometric'' in paragraph (b)(2) to read 
``psychrometric'';
    b. In the second sentence of paragraph (e)(1) by adding the words 
``(according to the applicable equation in section 5.2 of appendix F to 
this part)'' after the word ``monitor'', and by removing the words ``, 
and equation D-5 in appendix D to this part'';
    c. In paragraph (e)(2) by revising in the first sentence the words 
``Sec. 75.55 or Sec. 75.58, as applicable,'' to read ``Sec. 75.58,'', 
and by, in the second sentence, adding the word ``rate'' after ``heat 
input'' and revising the words ``Sec. 75.54(b)(5) or Sec. 75.57(b)(5), 
as applicable'' to read Sec. 75.57(b)(5)'';
    d. In paragraph (e)(3), by removing the third sentence, removing 
the period at the end of the second sentence and adding a colon, 
removing the words ``then on and after April 1, 2000,'' in the second 
sentence, and by revising the words ``be subject to'' to read ``meet'' 
in the second sentence; and
    e. In the first sentence of paragraph (e)(3)(iii) by adding the 
words ``bias-adjusted'' before the words ``hourly average''.

    9. Section 75.12 is amended by:
    a. Revising the section heading;
    b. In paragraph (a) by adding the word ``(CEMS)'' after the words 
``continuous emission monitoring system'' in the first sentence and by 
revising the words ``NOX continuous emission monitoring 
system'' to read `` NOX-diluent CEMS'' in the second 
sentence;
    c. In paragraph (d)(2) by adding the word ``-diluent'' after 
NOX in the second sentence, and by adding a new third 
sentence; and
    d. In paragraph (e) by revising the reference to ``(c)'' to read 
``(d)''.
    The revisions and additions read as follows:


Sec. 75.12  Specific provisions for monitoring NOX emission 
rate (NOX-diluent monitoring systems).

* * * * *
    (d) * * *
    (2) * * * If the required CEMS has not been installed and certified 
by that date, the owner or operator shall report the maximum potential 
NOX emission rate (MER) (as defined in Sec. 72.2 of this 
chapter) for each unit operating hour, starting with the first unit 
operating hour after the deadline and continuing until the CEMS has 
been provisionally certified.
* * * * *


Sec. 75.13  [Amended]

    10. Section 75.13 is amended by:
    a. In paragraph (b), by revising in the heading the words 
``Appendix G of'' to read ``appendix G to'', and by revising in the 
first sentence the words ``may provide information satisfactory to the 
Administrator'' to read ``shall follow the procedures in appendix G to 
this part''; and
    b. In paragraph (c) by revising in the first sentence the word 
``may'' to read ``shall'' and the words ``dry basis'' to read ``dry 
basis (or where Equation F-14b in appendix F to this part is used to 
determine CO2 concentration), either'', and by revising the 
comma after the reference to ``Sec. 75.11(b)(1)'' to a semicolon.


Sec. 75.15  [Reserved]

    11. Section 75.15 is removed and reserved.

    12. Section 75.16 is amended by:
    a. Removing the hyphen from the word ``by-pass'' in the section 
heading;
    b. Removing and reserving paragraph (a);
    c. Revising paragraph (b) heading and introductory text;
    d. Revising paragraph (c);
    e. Amending paragraphs (e) heading, (e) introductory text, (e)(2), 
(e)(3), and (e)(4) by adding the word ``rate'' after each occurrence of 
the words ``heat input'';
    f. In paragraph (e)(1) by revising in the first sentence the words 
``choose to install'' to read ``use the flow rate and diluent'', by 
removing in the first sentence the words ``wherever flow and diluent 
monitor measurements are used to determine the heat input,'', by 
revising the words ``(a) through (d)'' to read ``(b) through (d)'' in 
the first sentence, by revising the words ``(a)(1)(ii), (a)(2)(ii), 
(b)(1)(ii),'' to read ``(b)(1)(ii)'', and by adding at the end of the 
paragraph the words ``, according to paragraph (e)(3) of this 
section'';
    g. In paragraph (e)(2) by revising the words ``appendix F of'' to 
read ``appendix F to''; and
    h. In paragraph (e)(3) by adding in the second sentence the words 
``, in conjunction with the appropriate unit and stack operating 
times'' after the words ``total steam flow for all units utilizing the 
common stack''.
    The revisions and additions read as follows:


Sec. 75.16  Special provisions for monitoring emissions from common, 
bypass, and multiple stacks for SO2 emissions and heat input 
determinations.

    (a) [Reserved]
    (b) Common stack procedures. The following procedures shall be used 
when more than one unit uses a common stack:
* * * * *
    (c) Unit with bypass stack. Whenever any portion of the flue gases 
from an affected unit can be routed through a bypass stack so as to 
avoid the installed SO2 continuous emission monitoring 
system and flow monitoring system, the owner or operator shall either:
    (1) Install, certify, operate, and maintain separate SO2 
continuous emission monitoring systems and flow monitoring systems on 
the main stack and the bypass stack and calculate SO2 mass 
emissions for the unit as the sum of the SO2 mass emissions 
measured at the two stacks; or
    (2) Monitor SO2 mass emissions at the main stack using 
SO2 and flow rate monitoring systems and measure 
SO2 mass emissions at the bypass stack using the reference 
methods in Sec. 75.22(b) for SO2 and flow rate and calculate 
SO2 mass emissions for the unit as the sum of the emissions 
recorded by the installed monitoring systems on the main stack and the 
emissions measured by the reference method monitoring systems; or
    (3) Install, certify, operate, and maintain SO2 and flow 
rate monitoring systems only on the main stack. If this option is 
chosen, report the following values for each hour during which 
emissions pass through the bypass stack: the maximum potential 
concentration of SO2 as determined under section 2.1.1.1 of 
appendix A to this part (or, if available, the SO2 
concentration measured by a certified monitor located at the control 
device inlet may be reported instead), and the hourly volumetric flow 
rate value that would be substituted for the flow monitor installed on 
the main stack or flue under the missing data procedures in subpart D 
of this part if data from the flow monitor installed on the main stack 
or flue were missing for the hour. The maximum potential SO2 
concentration may be specific to the type of fuel combusted in the unit 
during the bypass (see Sec. 75.33(b)(5)). The option in this paragraph, 
(c)(3), may only be used if use of the bypass stack is limited to unit 
startup, emergency situations (e.g., malfunction of a flue gas 
desulfurization system), and periods of routine maintenance of the flue 
gas desulfurization system or maintenance 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 SO2 or any other 
parameter that is monitored only at the main stack. Calculate 
SO2 mass emissions for the unit as the sum of the emissions 
calculated with the substitute values and the emissions recorded by the 
SO2

[[Page 40424]]

and flow monitoring systems installed on the main stack.
* * * * *

    13. Section 75.17 is amended by:
    a. Removing the hyphen from the word ``by-pass'' in the section 
heading;
    b. In the introductory text by revising the words ``and (c)'' to 
read ``(c), and (d)'';
    c. In paragraph (b)(1) by revising the word ``NOX'' to 
read ``NOX-diluent'';
    d. Revising the paragraph heading and first sentence of paragraph 
(c) introductory text;
    e. Revising paragraphs (c)(1) and (c)(2); and
    f. Adding new paragraph (d).
    The revisions and additions read as follows:


Sec. 75.17  Specific provisions for monitoring emissions from common, 
bypass, and multiple stacks for NOX emission rate.

* * * * *
    (c) Unit with multiple stacks or ducts. When the flue gases from an 
affected unit discharge to the atmosphere through two or more stacks or 
when flue gases from an affected unit utilize two or more ducts feeding 
into a single stack and the owner or operator chooses to monitor in the 
ducts rather than the stack, the owner or operator shall monitor the 
NOX emission rate in a way that is representative of each 
affected unit. * * *
    (1) Install, certify, operate, and maintain a NOX-
diluent continuous emission monitoring system and a flow monitoring 
system in each stack or duct and determine the NOX emission 
rate for the unit as the Btu-weighted average of the NOX 
emission rates measured in the stacks or ducts using the heat input 
estimation procedures in appendix F to this part. Alternatively, for 
units that are eligible to use the procedures of appendix D to this 
part, the owner or operator may monitor heat input and NOX 
emission rate at the unit level, in lieu of installing flow monitors on 
each stack or duct. If this alternative unit-level monitoring is 
performed, report, for each unit operating hour, the highest emission 
rate measured by any of the NOX-diluent monitoring systems 
installed on the individual stacks or ducts as the hourly 
NOX emission rate for the unit, and report the hourly unit 
heat input as determined under appendix D to this part. Also, when this 
alternative unit-level monitoring is performed, the applicable 
NOX missing data procedures in Secs. 75.31 or 75.33 shall be 
used for each unit operating hour in which a quality-assured 
NOX emission rate is not obtained for one or more of the 
individual stacks or ducts; or
    (2) Provided that the products of combustion are well-mixed, 
install, certify, operate, and maintain a NOX continuous 
emission monitoring system in one stack or duct from the affected unit 
and record the monitored value as the NOX emission rate for 
the unit. The owner or operator shall account for NOX 
emissions from the unit during all times when the unit combusts fuel. 
Therefore, this option shall not be used if the monitored stack or duct 
can be bypassed (e.g., by using dampers). Follow the procedure in 
Sec. 75.17(d) for units with bypass stacks. Further, this option shall 
not be used unless the monitored NOX emission rate truly 
represents the NOX emissions discharged to the atmosphere 
(e.g., the option is disallowed if there are any additional 
NOX emission controls downstream of the monitored location).
    (d) Unit with a main stack and bypass stack configuration. For an 
affected unit with a discharge configuration consisting of a main stack 
and a bypass stack, the owner or operator shall either:
    (1) Follow the procedures in paragraph (c)(1) of this section; or
    (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, 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)).

    14. Section 75.19 is amended by:
    a. Revising the section heading, paragraph (a), and paragraphs 
(b)(1), (b)(2), (b)(3), (b)(4)(i), (b)(5), (c)(1)(i), (c)(1)(ii), 
(c)(1)(iii), (c)(1)(iv)(C), (c)(3)(ii)(C), (c)(3)(ii)(D) introductory 
text, (c)(3)(ii)(D)(1), (c)(3)(ii)(E), (c)(3)(ii)(F), (c)(3)(ii)(G), 
(c)(3)(ii)(H), and (e)(2);
    b. In paragraph (b)(4) introductory text by revising the words 
``unit commencing operation after January 1, 1997'' to read ``new or 
newly-affected unit'' and the words ``a low'' to read ``the low'';
    c. Amending paragraph (b)(4)(ii) by revising the words 
``NOX, and CO2'' to read ``CO2, and/or 
NOX'';
    d. Amending paragraph (b)(4)(iii) by revising the words ``and 
NOX'' in the first sentence to read ``and/or 
NOX'', revising the second sentence, and by revising the 
word ``The'' in the third sentence to read ``For Acid Rain Program LME 
units, the'';
    e. In paragraph (c)(1)(iv) introductory text by adding a new 
sentence after the second sentence;
    f. By revising in the first sentence of paragraph (c)(1)(iv)(A) the 
words ``(c)(1)(iv)(F) and (G) of this paragraph'' to read 
``(c)(1)(iv)(F), (c)(1)(iv)(G), and (c)(1)(iv)(I) of this section'' and 
by adding new paragraphs (c)(1)(iv)(A)(3) and (4) and Equation LM-1a;
    g. Removing and reserving paragraph (c)(1)(iv)(B)(3);
    h. Amending paragraph (c)(1)(iv)(B)(4) by revising the reference to 
``(c)(1)(iv)(B)(3)'' to read ``(c)(1)(iv)(B)(1)'';
    i. In paragraph (c)(1)(iv)(D) by revising in the first sentence the 
words ``, each unit in a group of units sharing a common fuel supply, 
or'' to read ``or group of'', by adding in the first sentence the words 
``(20 calendar quarters)'' after the words ``five years'', and by 
adding a new sentence after the second sentence;
    j. Amending paragraph (c)(1)(iv)(E) by removing the words ``, each 
low mass emission unit in a group of units combusting a common fuel,'';
    k. Revising the first and last sentences of (c)(1)(iv)(G);
    l. Amending the first sentence of (c)(1)(iv)(H) by revising the 
first occurrence of the words ``NOX emission controls,'' to 
read ``add-on NOX emission controls, and for units that use 
dry low-NOX technology,'';
    m. Amending the last sentence of (c)(1)(iv)(H)(1) by adding the 
words ``, and the appropriate default NOX emission rate from 
Table LM-2 shall be reported instead'' after the words ``that hour'';
    n. Redesignating existing paragraph (c)(1)(iv)(H)(2) as 
(c)(1)(iv)(H)(3), and adding the words ``, and the appropriate default 
NOX emission rate from Table LM-2 shall be reported 
instead'' after the words ``that hour'' and adding new paragraph 
(c)(1)(iv)(H)(2);
    o. Adding new paragraphs (c)(1)(iv)(I) and (c)(1)(iv)(J);
    p. In paragraph (c)(2) introductory text by adding the words ``, 
except that for unmanned facilities, the records may be kept at a 
central location, rather than on-site'' after the word ``inspection'';
    q. In paragraph (c)(2)(iii) by revising the word ``output'' to read 
``load'' and by adding the words ``per hour'' after the words ``pounds 
of steam'';
    r. In paragraph (c)(2)(iv) by adding the words ``add-on'' after the 
words ``unit with'' and adding the words ``and each unit that uses dry 
low-NOX technology'' after the words ``of any kind'';

[[Page 40425]]

    s. In paragraph (c)(3)(i)(A) by adding ``HIhr,'' after 
the words ``of this section,'' in the first sentence, by revising Eq. 
LM-1 in paragraph (c)(3)(i)(B) and the accompanying variable 
definitions, and by adding a new paragraph (c)(3)(i)(D);
    t. In paragraphs (c)(3)(ii)(I) and (c)(3)(ii)(J) by revising the 
definition of variables following Equations LM-7, LM-8, LM-7a, and LM-
8a;
    u. In paragraph (c)(4)(i)(A) by adding the words ``(Acid Rain 
Program units, only)'' after the word ``unit'' in the first sentence, 
by capitalizing the first letter of the word ``where'', and by revising 
the definition of variable ``EFSO2'' for Equation 
LM-9;
    v. In paragraph (c)(4)(ii)(A) by correcting the variables 
``WNOX'' and ``EFNOX'' to read 
``WNOX'' and ``EFNOX'';
    w. In paragraph (c)(4)(ii)(C) by adding a new sentence to the end 
of this paragraph;
    x. In paragraph (c)(4)(iii)(A) by adding the words ``(Acid Rain 
Program units, only)'' after the word ``unit'' in the first sentence 
and by revising the definition of the variable ``EFCO2'' under Equation 
LM-11;
    y. Amending paragraph (e)(5) by revising the words ``which have 
NOX emission controls of any kind'' to read ``which has add-
on NOX emission controls of any kind or uses dry low-
NOX technology'';
    z. Adding new paragraph (e)(6) between paragraph (e)(5) and table 
LM-1;
    aa. Amending Table LM-2 that follows paragraph (e) by revising the 
words ``Boiler type'' to read ``Unit type'' in heading for the first 
column;
    bb. Amending Table LM-3 that follows paragraph (e) by revising the 
words ``Natural Gas'' to read ``Pipeline (or other) Natural Gas'' in 
the first column; and
    cc. Amending Table LM-5 that follows paragraph (e) by adding the 
word ``Other'' before ``Natural Gas'' in the first column of the table.
    The revisions and additions read as follows:


Sec. 75.19  Optional SO2, NOX, and CO2 
emissions calculation for low mass emissions (LME) units.

    (a) Applicability and qualification. (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 excepted methodology in paragraph 
(c) of this section may be used in lieu of continuous emission 
monitoring systems or, if applicable, in lieu of excepted methods under 
appendix D or E to this part, for the purpose of determining hourly 
heat input and hourly NOX, SO2, and 
CO2 mass emissions under this part.
    (i) A low mass emissions unit is an affected unit that is gas-
fired, or oil-fired (as defined in Sec. 72.2 of this chapter), and for 
which:
    (A) An initial demonstration is provided, in accordance with 
paragraph (a)(2) of this section, which shows that the unit emits:
    (1) No more than 25 tons of SO2 annually and less than 
100 tons of NOX annually, for Acid Rain Program affected 
units. If the unit is also subject to the provisions of subpart H of 
this part, no more than 50 of the allowable annual tons of 
NOX may be emitted during the ozone season; or
    (2) Less than 100 tons of NOX annually and no more than 
50 tons of NOX during the ozone season, for non-Acid Rain 
Program units subject to the provisions of subpart H of this part, for 
which the owner or operator reports emissions data on a year-round 
basis, in accordance with Sec. 75.74(a) or Sec. 75.74(b); or
    (3) No more than 50 tons of NOX per ozone season, for 
non-Acid Rain Program units subject to the provisions of subpart H of 
this part, for which the owner or operator reports emissions data only 
during the ozone season, in accordance with Sec. 75.74(b); and
    (B) An annual demonstration is provided thereafter, using one of 
the allowable methodologies in paragraph (c) of this section, showing 
that the low mass emissions unit continues to emit no more than the 
applicable number of tons of SO2 and/or NOX 
specified in paragraph (a)(1)(i)(A) of this section.
    (C) This paragraph, (a)(1)(i)(C), applies only to a unit that is 
subject to an SO2 emission limitation under the Acid Rain 
Program, and that combusts a gaseous fuel other than pipeline natural 
gas or natural gas (as defined in Sec. 72.2 of this chapter). The owner 
or operator of such a unit must quantify the sulfur content and 
variability of the gaseous fuel by performing the demonstration 
described in section 2.3.6 of appendix D to this part, in order for the 
unit to qualify for LME unit status. If the results of that 
demonstration show that the gaseous fuel qualifies under paragraph (b) 
of section 2.3.6 to use a default SO2 emission rate to 
report SO2 mass emissions under this part, the unit is 
eligible for LME unit status.
    (ii) Each qualifying LME unit must start using the low mass 
emissions excepted methodology as follows:
    (A) For a unit that reports emission data on a year-round basis, 
begin using the methodology in the first unit operating hour in the 
calendar year designated in the certification application as the first 
year that the methodology will be used; or
    (B) For a unit that is subject to Subpart H of this part and that 
reports only during the ozone season according to Sec. 75.74(c), begin 
using the methodology in the first unit operating hour in the ozone 
season designated in the certification application as the first ozone 
season that the methodology will be used.
    (C) For a new or newly-affected unit, see paragraph (b)(4) of this 
section for additional guidance.
    (2) A unit may initially qualify as a low mass emissions unit if 
the designated representative submits a certification application to 
use the LME methodology (as described in Sec. 75.63(a)(1)(ii) and in 
this paragraph, (a)(2)) and the Administrator (or permitting authority, 
as applicable) certifies the use of such methodology. The certification 
application shall be submitted no later than 45 days prior to the date 
on which use of the low mass emissions methodology is expected to 
commence, and the application must contain:
    (i) A statement identifying the projected date on which the LME 
methodology will first be used. The projected commencement date shall 
be consistent with paragraphs (a)(1)(ii) and (b)(4) of this section, as 
applicable; and
    (ii) Either:
    (A) Actual SO2 and/or NOX mass emissions data 
(as applicable) for each of the three calendar years (or ozone seasons) 
prior to the calendar year in which the certification application is 
submitted demonstrating to the satisfaction of the Administrator or (if 
applicable) the permitting authority, that the unit emitted less than 
the applicable number of tons of SO2 and/or NOX 
specified in paragraph (a)(1)(i)(A) of this section. For the purposes 
of this paragraph, (a)(2)(ii)(A), the required actual SO2 or 
NOX mass emissions for each qualifying year or ozone season 
shall be determined using the SO2, NOX and heat 
input data reported to the Administrator in the electronic quarterly 
reports required under Sec. 75.64 or under the Ozone Transport 
Commission (OTC) NOX Budget Trading Program. Notwithstanding 
this requirement, in the absence of such electronic reports, an 
estimate of the actual emissions for each of the previous three years 
(or ozone seasons) shall be provided, using either the maximum rated 
heat input methodology described in paragraph (c)(3)(i) of this section 
or procedures consistent with the long term fuel flow heat input 
methodology described in paragraph (c)(3)(ii) of this section, in 
conjunction with the appropriate SO2 or NOX 
emission rate from paragraph

[[Page 40426]]

(c)(1)(i) of this section for SO2, and paragraph (c)(1)(ii) 
or (c)(1)(iv) of this section for NOX. Alternatively, the 
initial estimate of the NOX emission rate may be based on 
historical emission test data that is representative of operation at 
normal load or historical data from a CEMS certified under part 60 of 
this chapter or under a state CEM program; or
    (B) When the three full years (or ozone seasons) of actual SO2 
and NOX mass emissions data (or reliable estimates thereof) 
described under paragraph (a)(2)(ii)(A) of this section do not exist, 
the designated representative may submit an application to use the low 
mass emissions excepted methodology based upon a combination of actual 
historical SO2 and NOX mass emissions data and 
projected SO2 and NOX mass emissions, totaling 
three years (or ozone seasons). Except as provided in paragraph (a)(3) 
of this section, actual data must be used for any years (or ozone 
seasons) in which such data exists and projected data should be used 
for any remaining future years (or ozone seasons) needed to provide 
emissions data for three consecutive calender years (or ozone seasons). 
For example, if a unit commenced operation two years ago, the 
designated representative may submit actual, historical data for the 
previous two years and one year of projected emissions for the current 
calendar year or, for a new unit, the designated representative may 
submit three years of projected emissions, beginning with the current 
calendar year. Any actual or projected annual emissions must 
demonstrate to the satisfaction of the Administrator that the unit will 
emit less than the applicable number of tons of SO2 and/or 
NOX specified in paragraph (a)(1)(i)(A) of this section. 
Projected emissions shall be calculated using either the appropriate 
default emission rates from paragraphs (c)(1)(i) and (c)(1)(ii) of this 
section (or, alternatively for NOX, a conservative estimate 
of the NOX emission rate, as described in paragraph (a)(4) 
of this section), in conjunction with projections of unit operating 
hours or fuel type and fuel usage, according to one of the allowable 
calculation methodologies in paragraph (c) of this section; and
    (iii) A description of the methodology from paragraph (c) of this 
section that will be used to demonstrate on-going compliance under 
paragraph (b) of this section; and
    (iv) Appropriate documentation demonstrating that the unit is 
eligible to use projected emissions to qualify for LME status under 
paragraph (a)(3) of this section (if applicable).
    (3) In the following circumstances, projected emissions for a 
future year (or years) may be used in lieu of the actual emissions data 
from one (or more) of the three years (or ozone seasons) preceding the 
year of the certification application:
    (i) If the owner or operator takes an enforceable permit 
restriction on the number of annual or ozone season unit operating 
hours for the future year (or years), such that the unit will emit no 
more than the applicable number of tons of SO2 and/or 
NOX specified in paragraph (a)(1)(i)(A) of this section; or
    (ii) If the actual emissions for one (or more) of the three years 
(or ozone seasons) prior to the year of the certification application 
is not representative of the present and expected future emissions from 
the unit, because the owner or operator has recently installed emission 
controls on the unit.
    (4) When the owner or operator elects to demonstrate initial LME 
qualification and on-going compliance using a fuel-and-unit-specific 
NOX emission rate in accordance with paragraph (c)(1)(iv) of 
this section, there will be instances (e.g., for a new or newly-
affected unit) where it is not possible to determine that 
NOX emission rate prior to submitting the certification 
application. In such cases, if the generic default NOX 
emission rates in Table LM-2 of this section are inappropriately high 
for the unit, the owner or operator may use a more representative, but 
conservatively high estimate of the expected NOX emission 
rate, for the purposes of the initial monitoring plan submittal and to 
calculate the unit's projected annual or ozone season emissions under 
paragraph (a)(2)(ii)(B) of this section. For example, the 
NOX emission rate could, as described in paragraph 
(a)(2)(ii)(A) of this section, be estimated using historical CEM data 
or historical emission test data that is representative of operation at 
normal load. The NOX emission limit specified in the 
operating permit for the unit could also be used to estimate the 
NOX emission rate (except for units equipped with SCR or 
SNCR), or, consistent with paragraph (c)(1)(iv)(C)(4) of this section, 
for a unit that uses SCR or SNCR to control NOX emissions, 
an estimated default NOX emission rate of 0.15 lb/mmBtu 
could be used. However, these estimated NOX emission rates 
may not be used for reporting purposes in the time period extending 
from the first hour in which the LME methodology is used to the date 
and hour on which the fuel-and-unit-specific NOX emission 
rate testing is completed. Rather, in that interval, the owner or 
operator shall either report the appropriate default NOX 
emission rate from Table LM-2, or shall report the maximum potential 
NOX emission rate, calculated in accordance with Sec. 72.2 
of this chapter and section 2.1.2.1 of appendix A to this part. Then, 
beginning with the first unit operating hour after completion of the 
tests, the appropriate default NOX emission rate(s) obtained 
from the fuel-and-unit-specific testing shall be used for emissions 
reporting.
    (b) On-going qualification and disqualification. (1) Once a low 
mass emissions unit has qualified for and has started using the low 
mass emissions excepted methodology, an annual demonstration is 
required, showing that the unit continues to emit no more than the 
applicable number of tons of SO2 and/or NOX 
specified in paragraph (a)(1)(i)(A) of this section. The calculation 
methodology used for the annual demonstration shall be the methodology 
described in the certification application under paragraph (a)(2)(iii) 
of this section.
    (2) If any low mass emissions unit fails to provide the required 
annual demonstration under paragraph (b)(1) of this section, such that 
the calculated cumulative emissions for the unit exceed the applicable 
number of tons of SO2 and/or NOX specified in 
paragraph (a)(1)(i)(A) of this section at the end of any calendar year 
or ozone season, then:
    (i) The low mass emissions unit shall be disqualified from using 
the low mass emissions excepted methodology; and
    (ii) The owner or operator of the low mass emissions unit shall 
install and certify monitoring systems that meet the requirements of 
Secs. 75.11, 75.12, and 75.13, and shall report SO2 (Acid 
Rain Program units, only), NOX, and CO2 (Acid 
Rain Program units, only) emissions data and heat input data from such 
monitoring systems by December 31 of the calendar year following the 
year in which the unit exceeded the number of tons of SO2 
and/or NOX specified in paragraph (a)(1)(i)(A) of this 
section; and
    (iii) If the required monitoring systems have not been installed 
and certified by the applicable deadline in paragraph (b)(2)(ii) of 
this section, the owner or operator shall report the following values 
for each unit operating hour, beginning with the first operating hour 
after the deadline and continuing until the monitoring systems have 
been provisionally certified: the maximum potential hourly heat input 
for the unit, as defined in Sec. 72.2 of this chapter; the SO2 
emissions, in lb/hr, calculated using the applicable default SO2 
emission rate from paragraph (c)(1)(i) of this section and the maximum 
potential hourly unit heat input; the CO2

[[Page 40427]]

emissions, in tons/hr, calculated using the applicable default 
CO2 emission rate from paragraph (c)(1)(iii) of this section 
and the maximum potential hourly unit heat input; and the maximum 
potential NOX emission rate, as defined in Sec. 72.2 of this 
chapter.
    (3) If a low mass emissions unit that initially qualifies to use 
the low mass emissions excepted methodology under this section changes 
fuels, such that a fuel other than those allowed for use in the low 
mass emissions methodology is combusted in the unit, the unit shall be 
disqualified from using the low mass emissions excepted methodology as 
of the first hour that the new fuel is combusted in the unit. The owner 
or operator shall install and certify SO2 (Acid Rain Program 
units, only), NOX, and CO2 (Acid Rain Program 
units, only) and flow (if necessary) monitoring systems that meet the 
requirements of Secs. 75.11, 75.12, and 75.13 prior to a change to such 
fuel, and shall report emissions data from such monitoring systems 
beginning with the date and hour on which the new fuel is first 
combusted in the unit. If the required monitoring systems are not 
installed and certified prior to the fuel switch, the owner or operator 
shall report (as applicable) the maximum potential concentration of 
SO2, CO2 and NOX, the maximum 
potential NOX emission rate, the maximum potential flowrate, 
the maximum potential hourly heat input and the maximum (or minimum, if 
appropriate) potential moisture percentage, from the date and hour of 
the fuel switch until the monitoring systems are certified or until 
probationary calibration error tests of the monitors are passed and the 
conditional data validation procedures in Sec. 75.20(b)(3) begin to be 
used. All maximum and minimum potential values shall be specific to the 
new fuel and shall be determined in a manner consistent with section 2 
of appendix A to this part and Sec. 72.2 of this chapter. The owner or 
operator must notify the Administrator (or the permitting authority) in 
the case where a unit switches fuels without previously having 
installed and certified a SO2, NOX and 
CO2 monitoring system meeting the requirements of 
Secs. 75.11, 75.12, and 75.13.
    (4) * * *
    (i) Keep the records specified in paragraph (c)(2) of this section, 
beginning with the date and hour of commencement of commercial 
operation, for a new unit subject to an Acid Rain emission limitation, 
and beginning with the date and hour of the commencement of operation, 
for a new unit subject to a NOX mass reduction program under 
subpart H of this part. For newly-affected units, the records in 
paragraph (c)(2) of this section shall be kept as follows:
    (A) For Acid Rain Program units, begin keeping the records as of 
the first hour of commercial operation of the unit following the date 
on which the unit becomes affected; or
    (B) For units subject to a NOX mass reduction program 
under subpart H of this part, begin keeping the records as of the first 
hour of unit operation following the date on which the unit becomes an 
affected unit;
* * * * *
    (iii)* * * For example, use the default emission rates in table LM-
1, LM-2, and LM-3 of this section or use the fuel-and-unit-specific 
NOX emission rate determined according to paragraph 
(c)(1)(iv) of this section. * * *
    (5) A low mass emissions unit that has been disqualified from using 
the low mass emissions excepted methodology may subsequently submit an 
application to qualify again to use the low mass emissions methodology 
under paragraph (a)(2) of this section only if, following the non-
compliant year (or ozone season), at least three full years (or ozone 
seasons) of actual, monitored emissions data is obtained showing that 
the unit emitted no more than the applicable number of tons of SO2 
and/or NOX specified in paragraph (a)(1)(i)(A) of this 
section. Further, the designated representative or authorized account 
representative must certify in the application that the unit operation 
for the years or ozone seasons for which the emissions were monitored 
are representative of the projected future operation of the unit.
    (c) Low mass emissions excepted methodology, calculations, and 
values. (1) Determination of SO2, NOX, and 
CO2 emission rates.
    (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 (Acid Rain Program units, only). 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.
    (ii) If the unit combusts only natural gas and/or fuel oil, use 
either the appropriate NOX emission factor from Table LM-2 
of this section, or a fuel-and-unit-specific NOX emission 
rate determined according to paragraph (c)(1)(iv) of this section, to 
calculate hourly NOX mass emissions under this section. If 
the unit combusts a gaseous fuel other than pipeline natural gas or 
natural gas, the owner or operator shall determine a fuel-and-unit-
specific NOX emission rate according to paragraph (c)(1)(iv) 
of this section.
    (iii) If the unit combusts only natural gas and/or fuel oil, use 
Table LM-3 of this section to determine the appropriate CO2 
emission rate for use in calculating hourly CO2 mass 
emissions under this section (Acid Rain Program units, only). If the 
unit combusts a gaseous fuel other than pipeline natural gas or natural 
gas, the owner or operator shall determine a fuel-and-unit-specific 
CO2 emission rate for the fuel, as follows:
    (A) Derive a carbon-based F-factor for the fuel, using fuel 
sampling and analysis, as described in section 3.3.6 of appendix F to 
this part; and
    (B) Use Equation G-4 in appendix G to this part to derive the 
default CO2 emission rate. Rearrange the equation, solving 
it for the ratio of WCO2/H (this ratio will yield an 
emission rate, in units of tons/mmBtu). Then, substitute the carbon-
based F-factor determined in paragraph (c)(1)(iii)(A) of this section 
into the rearranged equation to determine the default CO2 
emission rate for the unit.
    (iv) * * * The testing must be completed in a timely manner, such 
that the test results are reported electronically no later than the end 
of the calendar year or ozone season in which the LME methodology is 
first used. * * *
    (A) * * *
    (3) When using Method 20 for turbines do not correct the 
NOX concentration to 15% O2.
    (4) If the testing is performed on an uncontrolled diffusion flame 
turbine, a correction to the observed average NOX 
concentration from each run of the Method 20 test must be applied using 
the following Equation LM-1a.

[[Page 40428]]

[GRAPHIC] [TIFF OMITTED] TR12JN02.000

Where:

NOXcorr = Corrected NOX concentration (ppm).
NOXobs = Average measured NOX concentration for 
each run of the Method 20 test (ppm).
Pr = Average annual atmospheric pressure (or average ozone 
season atmospheric pressure for a Subpart H unit that reports data only 
during the ozone season) at the nearest weather station (e.g., a 
standardized NOAA weather station located at the airport) for the year 
(or ozone season) prior to the year of the test (mm Hg).
Po = Observed atmospheric pressure during the test run (mm 
Hg).
Hr = Average annual atmospheric humidity ratio (or average 
ozone season humidity ratio for a Subpart H unit that reports data only 
during the ozone season) at the nearest weather station, for the year 
(or ozone season) prior to the year of the test (g H2O/g 
air).
Ho = Observed humidity ratio during the test run (g 
H2O/g air).
Tr = Average annual atmospheric temperature (or average 
ozone season atmospheric temperature for a Subpart H unit that reports 
data only during the ozone season) at the nearest weather station, for 
the year (or ozone season) prior to the year of the test ( deg. K).
Ta = Observed atmospheric temperature during the test run 
( deg. K).

    (B) * * *
    (3) [Reserved]
* * * * *
    (C) Based on the results of the part 75 appendix E testing, 
determine the fuel-and-unit-specific NOX emission rate as 
follows:
    (1) Except for LME units that use selective catalytic reduction 
(SCR) or selective non-catalytic reduction (SNCR) to control 
NOX emissions, the highest three-run average NOX 
emission rate obtained at any load in the appendix E test for a 
particular type of fuel shall be the fuel-and-unit-specific 
NOX emission rate, for that type of fuel.
    (2) [Reserved]
    (3) For a group of identical low mass emissions units (except for 
units that use SCR or SNCR to control NOX emissions), the 
fuel-and-unit-specific NOX emission rate for all units in 
the group, for a particular type of fuel, shall be the highest three-
run average NOX emission rate obtained at any tested load 
from any unit tested in the group, for that type of fuel.
    (4) Except as provided in paragraphs (c)(1)(iv)(C)(7) and 
(c)(1)(iv)(C)(8) of this section, for an individual low mass emissions 
unit which uses SCR or SNCR to control NOX emissions, the 
fuel-and-unit-specific NOX emission rate for each type of 
fuel combusted in the unit shall be the higher of:
    (i) The highest three-run average emission rate from any load of 
the appendix E test for that type of fuel; or
    (ii) 0.15 lb/mmBtu.
    (5) [Reserved]
    (6) Except as provided in paragraphs (c)(1)(iv)(C)(7) and 
(c)(1)(iv)(C)(8) of this section, for a group of identical low mass 
emissions units that are all equipped with SCR or SNCR to control 
NOX emissions, the fuel-and-unit-specific NOX 
emission rate for each unit in the group of units, for a particular 
type of fuel, shall be the higher of:
    (i) The highest three-run average NOX emission rate at 
any load from all appendix E tests of all tested units in the group, 
for that type of fuel; or
    (ii) 0.15 lb/mmBtu.
    (7) Notwithstanding the requirements of paragraphs (c)(1)(iv)(C)(4) 
and (c)(1)(iv)(C)(6) of this section, for a unit (or group of identical 
units) equipped with SCR (or SNCR) and water (or steam) injection to 
control NOX emissions:
    (i) If the appendix E testing is performed when the water (or steam 
) injection is in use and either upstream of the SCR or SNCR or during 
a time period when the SCR or SNCR is out of service; then
    (ii) The highest three-run average emission rate from the appendix 
E testing may be used as the fuel-and-unit-specific NOX 
emission rate for the unit (or, if applicable, for each unit in the 
group), for each unit operating hour in which the water-to-fuel ratio 
is within the acceptable range established during the appendix E 
testing.
    (8) Notwithstanding the requirements of paragraphs (c)(1)(iv)(C)(4) 
and (c)(1)(iv)(C)(6) of this section, for a unit (or group of identical 
units) equipped with SCR (or SNCR) and uses dry low-NOX 
technology to control NOX emissions:
    (i) If the appendix E testing is performed during a time period 
when the dry low-NOX controls are in use, but the SCR or 
SNCR is out of service; then
    (ii) The highest three-run average emission rate from the appendix 
E testing may be used as the fuel-and-unit-specific NOX 
emission rate for the unit (or, if applicable, for each unit in the 
group), for each unit operating hour in which the parametric data 
described in paragraph (c)(1)(iv)(H)(2) of this section demonstrate 
that the dry low-NOX controls are operating in the premixed 
or low-NOX mode.
    (9) For an individual combustion turbine (or a group of identical 
turbines) that operate principally at base load (or at a set point 
temperature), but are capable of operating at a higher peak load (or 
higher internal operating temperature), the fuel-and-unit-specific 
NOX emission rate for the unit (or for each unit in the 
group) shall be as follows:
    (i) If the testing is done only at base load, use the three-run 
average NOX emission rate for base load operating hours and 
1.15 times that emission rate for peak load operating hours; or
    (ii) If the testing is done at both base load and peak load, use 
the three-run average NOX emission rate from the base load 
testing for base load operating hours and the three-run average 
NOX emission rate from the peak load testing for peak load 
operating hours.
    (D) * * * Testing shall be done at the number of loads specified in 
paragraph (c)(1)(iv)(A) or (c)(1)(iv)(I) of this section, as 
applicable. * * *
* * * * *
    (G) Low mass emissions units for which at least 3 years of quality-
assured NOX emission rate data from a NOX-diluent 
CEMS and corresponding fuel usage data are available may determine 
fuel-and-unit-specific NOX emission rates from the actual 
data using the following procedure. * * * Use the 95th percentile value 
for each data set as the fuel-and-unit-specific NOX emission 
rate, except that for a unit that uses SCR or SNCR for NOX 
emission control, if the 95th percentile value is less than 0.15 lb/
mmBtu, a value of 0.15 lb/mmBtu shall be used as the fuel-and-unit-
specific NOX emission rate.
    (H) * * *
    (2) For a low mass emissions unit that uses dry low-NOX 
premix technology to control NOX emissions, proper operation 
of the emission controls means that the unit is in the low-
NOX or premixed combustion mode, and fired with natural gas. 
Evidence of operation in the low-NOX or premixed mode shall 
be provided by monitoring the appropriate turbine operating

[[Page 40429]]

parameters. These parameters may include percentage of full load, 
turbine exhaust temperature, combustion reference temperature, 
compressor discharge pressure, fuel and air valve positions, dynamic 
pressure pulsations, internal guide vane (IGV) position, and flame 
detection or flame scanner condition. The acceptable values and ranges 
for all parameters monitored shall be specified in the monitoring plan 
for the unit, and the parameters shall be monitored during each 
subsequent operating hour. If one or more of these parameters is not 
within the acceptable range or at an acceptable value in a given 
operating hour, the fuel-and-unit-specific NOX emission rate 
may not be used for that hour, and the appropriate default 
NOX emission rate from Table LM-2 shall be reported instead. 
When the unit is fired with oil the appropriate default value from 
Table LM-2 shall be reported.
* * * * *
    (I) Notwithstanding the requirements in paragraph (c)(1)(iv)(A) of 
this section, the appendix E testing to determine (or re-determine) the 
fuel-specific, unit-specific NOX emission rate for a unit 
(or for each unit in a group of identical units) may be performed at 
fewer than four loads, under the following circumstances:
    (1) Testing may be done at one load level if the data analysis 
described in paragraph (c)(1)(iv)(J) of this section is performed and 
the results show that the unit has operated (or all units in the group 
of identical units have operated) at a single load level for at least 
85.0 percent of all operating hours in the previous three years (12 
calendar quarters) prior to the calendar quarter of the appendix E 
testing. For combustion turbines that are operated to produce 
approximately constant output (in MW) but which use internal operating 
and exhaust temperatures and not the actual output in MW to control the 
operation of the turbine, the internal operating temperature set point 
may be used as a surrogate for load in demonstrating that the unit 
qualifies for single-load testing. If the data analysis shows that the 
unit does not qualify for single-load testing, testing may be done at 
two (or three) load levels if the unit has operated (or if all units in 
the group of identical units have operated) cumulatively at two (or 
three) load levels for at least 85.0 percent of all operating hours in 
the previous three years; or
    (2) If a multiple-load appendix E test was initially performed for 
a unit (or group of identical units) to determine the fuel-and-unit 
specific NOX emission rate, then the periodic retests 
required under paragraph (c)(1)(iv)(D) of this section may be single-
load tests, performed at the load level for which the highest average 
NOX emission rate was obtained in the initial test.
    (J) To determine whether a unit qualifies for testing at fewer than 
four loads under paragraph (c)(1)(iv)(I) of this section, follow the 
procedures in paragraph (c)(1)(iv)(J)(1) or (c)(1)(iv)(J)(2) of this 
section, as applicable.
    (1) Determine the range of operation of the unit, according to 
section 6.5.2.1 of appendix A to this part. Divide the range of 
operation into four equal load bands. For example, if the range of 
operation extends from 20 MW to 100 MW, the four equal load bands would 
be: band 1: from 20 MW to 40 MW; band 2: from 41 MW 
to 60 MW; band 3: from 61 MW to 80 MW; and band 4: 
from 81 to 100 MW. Then, perform a historical load analysis for all 
unit operating hours in the 12 calendar quarters preceding the quarter 
of the test. Alternatively, for sources that report emissions data only 
during the ozone season, the historical load analysis may be based on 
unit operation in the previous three ozone seasons, rather than unit 
operation in the previous 12 calendar quarters. Determine the 
percentage of the data that fall into each load band. For a unit that 
is not part of a group of identical units, if 85.0% or more of the data 
fall into one load band, single-load testing may be performed at any 
point within that load band. For a group of identical units, if each 
unit in the group meets the 85.0% criterion, then representative 
single-load testing within the load band may be performed. If the 85.0% 
criterion cannot be met to qualify for single-load testing but this 
criterion can be met cumulatively for two (or three) load levels, then 
testing may be performed at two (or three) loads instead of four.
    (2) For a combustion turbine that uses exhaust temperature and not 
the actual output in megawatts to control the operation of the turbine 
(or for a group of identical units of this type), the owner or operator 
must document that the unit (or each unit in the group) has operated 
within  10% of the set point temperature for 85.0% of the 
operating hours in the previous 12 calendar quarters to qualify for 
single-load testing. Alternatively, for sources that report emissions 
data only during the ozone season, the historical set point temperature 
analysis may be based on unit operation in the previous three ozone 
seasons, rather than unit operation in the previous 12 calendar 
quarters. When the set point temperature is used rather than unit load 
to justify single-load testing, the designated representative shall 
certify in the monitoring plan for the unit that this is the normal 
manner of unit operation and shall document the setpoint temperature.
* * * * *
    (3) Heat input. * * *
    (i) Maximum rated hourly heat input method. * * *
    (B) * * *
    [GRAPHIC] [TIFF OMITTED] TR12JN02.001
    
Where:

n = Number of unit operating hours in the quarter.
HIhr = Hourly heat input under paragraph (c)(3)(i)(A) of 
this section (mmBtu).
* * * * *
    (D) For a unit subject to the provisions of subpart H of this part, 
which is not required to report emission data on a year-round basis and 
elects to report only during the ozone season, the quarterly heat input 
for the second calendar quarter of the year shall, for compliance 
purposes, include only the heat input for the months of May and June, 
and the cumulative ozone season heat input shall be the sum of the heat 
input values for May, June and the third calendar quarter of the year.
    (ii) Long term fuel flow heat input method. * * *
    (C) Except as provided in paragraph (c)(3)(ii)(C)(3) of this 
section, for each fuel combusted during a quarter, the gross calorific 
value of the fuel shall be determined by either:
    (1) Using the applicable procedures for gas and oil analysis in 
sections 2.2 and 2.3 of appendix D to this part. If this option is 
chosen the highest gross calorific value recorded during the previous 
calendar year shall be used (or, for a new or newly-affected unit, if 
there are no sample results from the previous year, use the highest GCV 
from the samples taken in the current year); or
    (2) Using the appropriate default gross calorific value listed in 
Table LM-5 of this section.
    (3) For gaseous fuels other than pipeline natural gas or natural 
gas, the GCV sampling frequency shall be daily unless the results of a 
demonstration under section 2.3.5 of appendix D to this part show that 
the fuel has a low GCV variability and qualifies for monthly sampling. 
If daily GCV sampling is required, use the highest GCV obtained in the 
calendar quarter as GCVmax in Equation LM-3, of this 
section.

[[Page 40430]]

    (D) If Eq. LM-2 is used for heat input determination, the specific 
gravity of each type of fuel oil combusted during the quarter shall be 
determined either by:
    (1) Using the procedures in section 2.2.6 of appendix D to this 
part. If this option is chosen, use the highest specific gravity value 
recorded during the previous calendar year (or, for a new or newly-
affected unit, if there are no sample results from the previous year, 
use the highest specific gravity from the samples taken in the current 
year); or
* * * * *
    (E) The quarterly heat input from each type of fuel combusted 
during the quarter by a low mass emissions unit or group of low mass 
emissions units sharing a common fuel supply shall be determined using 
either Equation LM-2 or Equation LM-3 for oil (as applicable to the 
method used to quantify oil usage) and Equation LM-3 for gaseous fuels. 
For a unit subject to the provisions of subpart H of this part, which 
is not required to report emission data on a year-round basis and 
elects to report only during the ozone season, the quarterly heat input 
for the second calendar quarter of the year shall include only the heat 
input for the months of May and June.
[GRAPHIC] [TIFF OMITTED] TR12JN02.002

Where:

HIfuel-qtr = Quarterly total heat input from oil (mmBtu).
Mqtr = Mass of oil consumed during the quarter, determined 
as the product of the volume of oil under paragraph (c)(3)(ii)(B) of 
this section and the specific gravity under paragraph (c)(3)(ii)(D) of 
this section (lb).
GCVmax = Gross calorific value of oil, as determined under 
paragraph (c)(3)(ii)(C) of this section (Btu/lb)
10\6\ = Conversion of Btu to mmBtu.
[GRAPHIC] [TIFF OMITTED] TR12JN02.003

Where:

HIfuel-qtr = Quarterly heat input from gaseous fuel or fuel 
oil (mmBtu).
Qqtr = Volume of gaseous fuel or fuel oil combusted during 
the quarter, as determined under paragraph (c)(3)(ii)(B) of this 
section standard cubic feet (scf) or (gal), as applicable.
GCVmax = Gross calorific value of the gaseous fuel or fuel 
oil combusted during the quarter, as determined under paragraph 
(c)(3)(ii)(C) of this section (Btu/scf) or (Btu/gal), as applicable.
10\6\ = Conversion of Btu to mmBtu.
    (F) Use Eq. LM-4 to calculate HIqtr-total, the quarterly 
heat input (mmBtu) for all fuels. HIqtr-total, shall be the 
sum of the HIfuel-qtr values determined using Equations LM-2 
and LM-3.
[GRAPHIC] [TIFF OMITTED] TR12JN02.004

    (G) * * * For a unit subject to the provisions of subpart H of this 
part, which is not required to report emission data on a year-round 
basis and elects to report only during the ozone season, the cumulative 
ozone season heat input shall be the sum of the quarterly heat input 
values for the second and third calendar quarters of the year.
    (H) For each low mass emissions unit or each low mass emissions 
unit in an identical group of units, the owner or operator shall 
determine the cumulative quarterly unit load in megawatts or thousands 
of pounds of steam per hour. The quarterly cumulative unit load shall 
be the sum of the hourly unit load values recorded under paragraph 
(c)(2) of this section and shall be determined using Equations LM-5 or 
LM-6. For a unit subject to the provisions of subpart H of this part, 
which is not required to report emission data on a year-round basis and 
elects to report only during the ozone season, the quarterly cumulative 
load for the second calendar quarter of the year shall include only the 
unit loads for the months of May and June.
[GRAPHIC] [TIFF OMITTED] TR12JN02.005

[GRAPHIC] [TIFF OMITTED] TR12JN02.006

Where:

MWqtr =Sum of all unit operating loads recorded during the 
quarter by the unit (MW).
STfuel-qtr = Sum of all hourly steam loads recorded during 
the quarter by the unit (klb of steam/hr).
MW = Unit operating load for a particular unit operating hour (MW).
ST = Unit steam load for a particular unit operating hour (klb of 
steam/hr).

    (I) * * *

Where:

HIhr = Hourly heat input to the unit (mmBtu).
MWhr = Hourly operating load for the unit (MW).
SThr = Hourly steam load for the unit (klb of steam/hr).

    (J) * * *

Where:

HIhr = Hourly heat input to the individual unit (mmBtu).
MWhr = Hourly operating load for the individual unit (MW).
SThr = Hourly steam load for the individual unit (klb of 
steam/hr).

[[Page 40431]]

[]MWqtr = Sum 
of the quarterly operating
    all-units loads (from Eq. LM-5) for all units in the group (MW).
[]STqtr = Sum 
of the quarterly steam
    all-units loads (from Eq. LM-6) for all units in the group (klb of 
steam/hr)

    (4) Calculation of SO2, NOX and CO2 
mass emissions. * * *
    (i) SO2 mass emissions.
    (A) * * *

Where: * * *

EFSO2 = Either the SO2 emission factor from Table 
LM-1 of this section or the fuel-and-unit-specific SO2 
emission rate from paragraph (c)(1)(i) of this section (lb/mmBtu).
* * * * *
    (ii) NOX mass emissions.
* * * * *
    (C) * * * For a unit subject to the provisions of subpart H of this 
part, which is not required to report emission data on a year-round 
basis and elects to report only during the ozone season, the ozone 
season NOX mass emissions for the unit shall be the sum of 
the quarterly NOX mass emissions, as determined under 
paragraph (c)(4)(ii)(B) of this section, for the second and third 
calendar quarters of the year, and the second quarter report shall 
include emissions data only for May and June.
    (iii) CO2 Mass Emissions.
    (A) * * *

Where: * * *

EFCO2 = Either the fuel-based CO2 emission factor 
from Table LM-3 of this section or the fuel-and-unit-specific 
CO2 emission rate from paragraph (c)(1)(iii) of this section 
(tons /mmBtu). * * *
* * * * *
    (e) * * *
    (2) For low mass emissions units or groups of units which use the 
long term fuel flow methodology under paragraph (c)(3)(ii) of this 
section and which use one of the methods specified in paragraph 
(c)(3)(ii)(B)(2) of this section to determine fuel usage, the owner or 
operator shall keep, at the facility, a copy of the standard used and 
shall keep records, for three years, of all measurements obtained for 
each quarter using the methodology.
* * * * *
    (6) For unmanned facilities, the records required by paragraphs 
(e)(1), (e)(2) and (e)(4) of this section may be kept at a central 
location, rather than at the facility.
* * * * *

    15. Section 75.20 is amended by:
    a. Revising paragraphs (b)(3)(i), (c)(2)(ii), (c)(2)(iii), (c)(4) 
introductory text, (c)(4)(i) through (iii), (g)(2), (h)(1), (h)(3), 
(h)(4) introductory text, (h)(4)(i) and (h)(4)(ii);
    b. In the first sentence of paragraph (a) by removing the words ``, 
which includes the automated data acquisition and handling system, and, 
where applicable, the CO2 continuous emission monitoring 
system,'';
    c. In paragraph (a)(3) by revising in the first sentence the words 
``section for each continuous emission or opacity monitoring system or 
component thereof,'' to read ``section, each'', by removing the words 
``or component thereof'' in each of the two remaining occurrences of 
these words, and by adding the word ``conditional'' before the words 
``data validation'' in the last sentence;
    d. In paragraph (a)(4)(iii) by removing each occurrence of the 
words ``or component thereof'', by adding the word ``conditional'' 
immediately before each occurrence of ``data validation'', and by 
removing the words ``, until the date and time that the owner or 
operator completes subsequently approved initial certification or 
recertification tests'' that appear at the end of the second sentence;
    e. In paragraph (a)(4)(iv) by removing the words ``or component 
thereof,'';
    f. In the first sentence of paragraph (a)(5)(i) by removing the 
words ``or component thereof'' and by adding the words ``(or, if the 
conditional data validation procedures in paragraphs (b)(3)(ii) through 
(b)(3)(ix) of this section are used, until a probationary calibration 
error test is passed following corrective actions in accordance with 
paragraph (b)(3)(ii) of this section)'' after the words ``successfully 
completed'';
    g. In paragraph (b)(2) by removing the word ``not'' before the 
words ``required for certification'';
    h. In paragraph (b)(5) by revising the third and fourth sentences;
    i. In paragraph (c) introductory text by adding in the third 
sentence the word ``otherwise'' before the word ``specified,'' and the 
words ``and in sections 6.3.1 and 6.3.2 of appendix A to this part,'' 
after the words ``(b)(1), (d), & (e) of this section,'';
    j. Removing the second paragraph designated (c)(1)(v) and paragraph 
(h)(4)(iii);
    k. Adding new paragraphs (c)(2)(iv) and (h)(5);
    l. In paragraph (d)(2)(iii) by removing the words ``or 
SO2-diluent'' in the third sentence, by revising the last 
sentence, and by adding two new sentences at the end of the paragraph;
    m. In paragraph (d)(2)(v) by adding the words ``(or 720 hours in 
any ozone season, for sources that report emission data only during the 
ozone season, in accordance with Sec. 75.74(c))'' after the words ``one 
calendar year'' in the first sentence and by adding the words ``(or 
ozone season, as applicable)'' after the words ``per calendar year'' in 
the second sentence;
    n. In the third sentence of (d)(2)(vii) by revising the words 
``analyzer and specify'' to read ``analyzer, beginning with the letters 
``LK'' (e.g., ``LK1,'' ``LK2,'' etc.) and shall specify'';
    o. Adding a sentence to the end of paragraph (g)(1)(i);
    p. In paragraph (g)(5) by adding the words ``(or recertified)'' 
after both occurrences of the words ``provisionally certified'', by 
adding the words ``or for disapproval of a recertification request'' 
and ``or denial of a recertification request'' after, respectively, the 
first and second occurrence of the words ``loss of certification'' in 
the second sentence, and by removing the word ``either'' from the 
second sentence; and
    q. In paragraph (h)(2) by revising the reference to 
``Sec. 75.63(a)(1)(iii)'' to read ``Sec. 75.63(a)(1)(ii)''.
    The revisions and additions read as follows:


Sec. 75.20  Initial certification and recertification procedures.

* * * * *
    (b) * * *
    (3) * * *
    (i) The owner or operator shall use substitute data, according to 
the standard missing data procedures in Secs. 75.33 through 75.37 (or 
shall report emission data using a reference method or another 
monitoring system that has been certified or approved for use under 
this part), in the period extending from the hour of the replacement, 
modification or change made to a monitoring system that triggers the 
need to perform recertification testing, until either: the hour of 
successful completion of all of the required recertification tests; or 
the hour in which a probationary calibration error test (according to 
paragraph (b)(3)(ii) of this section) is performed and passed, 
following all necessary repairs, adjustments or reprogramming of the 
monitoring system. The first hour of quality-assured data for the 
recertified monitoring system shall either be the hour after all 
recertification tests have been completed or, if conditional data 
validation is used, the first quality-assured hour shall be determined 
in accordance with paragraphs (b)(3)(ii) through (b)(3)(ix) of this 
section. Notwithstanding these requirements, if the replacement, 
modification, or change requiring recertification of the CEMS is such 
that the historical data stream is no longer representative (e.g., 
where the SO2 concentration and stack flow rate change 
significantly after

[[Page 40432]]

installation of a wet scrubber), the owner or operator shall substitute 
for missing data as follows, in lieu of using the standard missing data 
procedures in Secs. 75.33 through 75.37: for a change that results in a 
significantly higher concentration or flow rate, substitute maximum 
potential values according to the procedures in paragraph (a)(5) of 
this section; or for a change that results in a significantly lower 
concentration or flow rate, substitute data using the standard missing 
data procedures. The owner or operator shall then use the initial 
missing data procedures in Sec. 75.31, beginning with the first hour of 
quality assured data obtained with the recertified monitoring system, 
unless otherwise provided by Sec. 75.34 for units with add-on emission 
controls.
* * * * *
    (5) * * * In the event that a recertification application is 
disapproved, data from the monitoring system are invalidated and the 
applicable missing data procedures in Secs. 75.31 or 75.33 shall be 
used from the date and hour of receipt of the disapproval notice back 
to the hour of the adjustment or change to the CEMS that triggered the 
need for recertification testing or, if the conditional data validation 
procedures in paragraphs (b)(3)(ii) through (b)(3)(ix) of this section 
were used, back to the hour of the probationary calibration error test 
that began the recertification test period. Data from the monitoring 
system remain invalid until all required recertification tests have 
been passed or until a subsequent probationary calibration error test 
is passed, beginning a new recertification test period. * * *
    (c) Initial certification and recertification procedures.
* * * * *
    (2) * * *
    (ii) Relative accuracy test audits, as follows:
    (A) A single-load (or single-level) RATA at the normal load (or 
level), as defined in section 6.5.2.1(d) of appendix A to this part, 
for a flow monitor installed on a peaking unit or bypass stack, or for 
a flow monitor exempted from multiple-level RATA testing under section 
6.5.2(e) of appendix A to this part;
    (B) For all other flow monitors, a RATA at each of the three load 
levels (or operating levels) corresponding to the three flue gas 
velocities described in section 6.5.2(a) of appendix A to this part;
    (iii) A bias test for the single-load (or single-level) flow RATA 
described in paragraph (c)(2)(ii)(A) of this section; and
    (iv) A bias test (or bias tests) for the 3-level flow RATA 
described in paragraph (c)(2)(ii)(B) of this section, at the following 
load or operational level(s):
    (A) At each load level designated as normal under section 
6.5.2.1(d) of appendix A to this part, for units that produce 
electrical or thermal output, or
    (B) At the operational level identified as normal in section 
6.5.2.1(d) of appendix A to this part, for units that do not produce 
electrical or thermal output.
* * * * *
    (4) For each CO2 pollutant concentration monitor, each 
CO2 monitoring system that uses an O2 monitor to 
determine CO2 concentration, and each diluent gas monitor 
used only to monitor heat input rate:
    (i) A 7-day calibration error test;
    (ii) A linearity check;
    (iii) A relative accuracy test audit, where, for an O2 
monitor used to determine CO2 concentration, the 
CO2 reference method shall be used for the RATA; and
* * * * *
    (d) * * *
    (2) * * *
    (iii) * * * However, if the linearity test is performed within 168 
unit or stack operating hours but is either failed or aborted due to a 
problem with the CEMS or like-kind replacement analyzer, then all of 
the conditionally valid data are invalidated back to the hour of the 
probationary calibration error test, and data from the non-redundant 
backup CEMS or from the primary monitoring system of which the like-
kind replacement analyzer is a part remain invalid until the hour of 
completion of a successful linearity test. Notwithstanding this 
requirement, the conditionally valid data status may be re-established 
after a failed or aborted linearity check, if corrective action is 
taken and a calibration error test is subsequently passed. However, in 
no case shall the use of conditional data validation extend for more 
than 168 unit or stack operating hours beyond the date and time of the 
original probationary calibration error test when the analyzer was 
brought into service.
* * * * *
    (g) * * *
    (1) * * *
    (i) * * * For orifice, nozzle, and venturi-type flowmeters, the 
results of primary element visual inspections and/or calibrations of 
the transmitters or transducers shall also be provided.
* * * * *
    (2) Initial certification, recertification, and QA testing 
notification. The designated representative shall provide initial 
certification testing notification, recertification testing 
notification, and routine periodic quality-assurance testing, as 
specified in Sec. 75.61. Initial certification testing notification, 
recertification testing notification, or periodic quality assurance 
testing notification is not required for an excepted monitoring system 
under appendix D to this part.
* * * * *
    (h) * * *
    (1) Monitoring plan. The designated representative shall submit a 
monitoring plan in accordance with Secs. 75.53 and 75.62.
* * * * *
    (3) Approval of certification applications. The provisions for the 
certification application formal approval process in the introductory 
text of paragraph (a)(4) and in paragraphs (a)(4)(i), (ii), and (iv) of 
this section shall apply, except that ``continuous emission or opacity 
monitoring system'' shall be replaced with ``low mass emissions 
excepted methodology.'' Provisional certification status for the low 
mass emissions methodology begins on the date of submittal (consistent 
with the definition of ``submit'' in Sec. 72.2 of this chapter) of a 
complete certification application, and the methodology is considered 
to be certified either upon receipt of a written approval notice from 
the Administrator or, if such notice is not provided, at the end of the 
Administrator's 120-day review period. However, in contrast to CEM 
systems or appendix D and E monitoring systems, a provisionally 
certified or certified low mass emissions excepted methodology may not 
be used to report data under the Acid Rain Program or in a 
NOX mass emissions reduction program under subpart H of this 
part prior to the applicable commencement date specified in 
Sec. 75.19(a)(2)(i).
    (4) Disapproval of low mass emissions unit certification 
applications. If the Administrator determines that the certification 
application for a low mass emissions unit does not demonstrate that the 
unit meets the requirements of Secs. 75.19(a) and (b), the 
Administrator shall issue a written notice of disapproval of the 
certification application within 120 days of receipt. By issuing the 
notice of disapproval, the provisional certification is invalidated by 
the Administrator, and any emission data reported using the excepted 
methodology during the Administrator's 120-day review period shall be 
considered invalid. The owner or operator shall use the following

[[Page 40433]]

procedures when a certification application is disapproved:
    (i) The owner or operator shall substitute the following values, as 
applicable, for each hour of unit operation in which data were reported 
using the low mass emissions methodology until such time, date, and 
hour as continuous emission monitoring systems or excepted monitoring 
systems, where applicable, are installed and provisionally certified: 
the maximum potential concentration of SO2, as defined in 
section 2.1.1.1 of appendix A to this part; the maximum potential fuel 
flowrate, as defined in section 2.4.2 of appendix D to this part; the 
maximum potential values of fuel sulfur content, GCV, and density (if 
applicable) in Table D-6 of appendix D 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; or the maximum potential CO2 
concentration as defined in section 2.1.3.1 of appendix A to this part. 
For a unit subject to a State or federal NOX mass reduction 
program where the owner or operator intends to monitor NOX 
mass emissions with a NOX pollutant concentration monitor 
and a flow monitoring system, substitute for NOX 
concentration using the maximum potential concentration of 
NOX, as defined in section 2.1.2.1 of appendix A to this 
part, and substitute for volumetric flow using the maximum potential 
flow rate, as defined in section 2.1.4.1 of appendix A to this part; 
and
    (ii) The designated representative shall submit a notification of 
certification test dates for the required monitoring systems, as 
specified in Sec. 75.61(a)(1)(i), and shall submit a certification 
application according to the procedures in paragraph (a)(2) of this 
section.
    (5) Recertification. Recertification of an approved low mass 
emissions excepted methodology is not required. Once the Administrator 
has approved the methodology for use, the owner or operator is subject 
to the on-going qualification and disqualification procedures in 
Sec. 75.19(b), on an annual or ozone season basis, as applicable.


Sec. 75.21  [Amended].

    16. Section 75.21 is amended by:
    a. In paragraph (a)(7) by adding the words ``only for infrequent, 
non-routine operations (e.g.,'' after the words ``higher sulfur 
fuel(s)'' in the first sentence, and by adding a closing parenthesis 
after the words ``short-term testing'' in the first sentence;
    b. In paragraph (a)(8) by removing the words ``On and after April 
1, 2000'' and by capitalizing the initial occurrence of the word 
``the'';
    c. In paragraph (a)(9) by revising in the first sentence the words 
``exempted under paragraphs (a)(6) or (a)(7) of this section from the 
SO2 RATA requirements of this part'' to read ``exempted from 
the SO2 RATA requirements of this part under paragraphs 
(a)(6) or (a)(7) of this section''; and
    d. In paragraph (e)(2) by revising the word ``another'' to read 
``other''.

    17. Section 75.22 is amended by:
    a. Removing the last sentence of paragraph (a) introductory text;
    b. In the last sentence of paragraph (a)(4) by revising the word 
``techniques'' to read ``wet bulb-dry bulb technique''; and
    c. Adding a sentence to the end of paragraph (a)(5).
    The revisions read as follows:


Sec. 75.22  Reference test methods.

    (a) * * *
    (5) * * * Alternatively, Method 20 may be used as the reference 
method for relative accuracy test audits of NOX CEMS 
installed on combustion turbines.
* * * * *

    18. Section 75.24 is amended by:
    a. Revising paragraph (a)(1); and
    b. In paragraph (c)(2) by removing the words ``or certified 
portable monitor or''.
    The revisions read as follows:


Sec. 75.24  Out-of-control periods and adjustment for system bias.

    (a) * * *
    (1) For daily calibration error tests, an out-of-control period 
occurs when the calibration error of a pollutant concentration monitor 
exceeds the applicable specification in section 2.1.4 of appendix B to 
this part.
* * * * *

    19. Section 75.30 is amended by:
    a. In paragraph (a)(6) by revising the period at the end of the 
paragraph to read ``; or'';
    b. Adding new paragraphs (a)(7) and (a)(8);
    c. In the first sentence of paragraph (b) by adding the words 
``percent moisture,'' after the words ``flow rate,''; and
    d. In paragraphs (d)(1) and (d)(2) by removing the words 
``Sec. 75.54(b)(5) or'' and the words ``as applicable,''.
    The revisions and additions read as follows:


Sec. 75.30  General provisions.

    (a) * * *
    (7) A valid, quality-assured hour of moisture data (in percent 
H2O) has not been measured or recorded for an affected unit, 
either by a certified moisture monitoring system or an approved 
alternative monitoring method under subpart E of this part. This 
requirement does not apply when a default percent moisture value, as 
provided in Secs. 75.11(b) or 75.12(b), is used to account for the 
hourly moisture content of the stack gas; or
    (8) A valid, quality-assured hour of heat input rate data (in 
mmBtu/hr) has not been measured and recorded for a unit from a 
certified flow monitor and a certified diluent (CO2 or 
O2) monitor or by an approved alternative monitoring system 
under subpart E of this part.
* * * * *

    20. Section 75.31 is amended by:
    a. Revising the first sentence of paragraph (a);
    b. Revising paragraph (c) heading introductory text, and paragraph 
(c)(1);
    c. Adding a new sentence to the beginning of paragraph (c)(2);
    d. In paragraph (c)(3) by adding the words ``(or for non-load-based 
units using operational bins, when no prior quality-assured data exist 
in the corresponding operational bin)'' after the words ``higher load 
range''; and
    e. Adding a new paragraph (d).
    The revisions and additions read as follows:


Sec. 75.31  Initial missing data procedures.

    (a) During the first 720 quality-assured monitor operating hours 
following initial certification of the required SO2, 
CO2, O2 or moisture monitoring system(s) at a 
particular unit or stack location (i.e., the date and time at which 
quality assured data begins to be recorded by CEMS(s) installed at that 
location), and during the first 2,160 quality-assured monitor operating 
hours following initial certification of the required NOX-
diluent, NOX concentration, or flow monitoring system(s) at 
the unit or stack location, the owner or operator shall provide 
substitute data required under this subpart according to the procedures 
in paragraphs (b) and (c) of this section. * * *
* * * * *
    (c) Volumetric flow and NOX emission rate or NOX 
concentration data (load ranges or operational bins used). The 
procedures in this paragraph apply to affected units for which load-
based ranges or non-load-based operational bins, as defined, 
respectively, in sections 2 and 3 of appendix C to this part are used 
to provide substitute NOX and flow rate data. For each hour 
of missing volumetric flow rate data, NOX emission rate 
data, or NOX

[[Page 40434]]

concentration data used to determine NOX mass emissions:
    (1) Whenever prior quality-assured data exist in the load range (or 
operational bin) corresponding to the operating load (or operating 
conditions) at the time of the missing data period, the owner or 
operator shall substitute, by means of the automated data acquisition 
and handling system, for each hour of missing data, the arithmetic 
average of all of the prior quality-assured hourly flow rates, 
NOX emission rates, or NOX concentrations in the 
corresponding load range (or operational bin) as determined using the 
procedure in appendix C to this part. When non-load-based operational 
bins are used, if essential operating or parametric data are 
unavailable for any hour in the missing data period, such that the 
operational bin cannot be determined, the owner or operator shall, for 
that hour, substitute (as applicable) the maximum potential flow rate 
as specified in section 2.1.4.1 of appendix A to this part or the 
maximum potential NOX emission rate or the maximum potential 
NOX concentration as specified in section 2.1.2.1 of 
appendix A to this part.
    (2) This paragraph (c)(2) does not apply to non-load-based units 
using operational bins. * * *
* * * * *
    (d) Non-load-based volumetric flow and NOX emission rate 
or NOX concentration data (operational bins not used). The 
procedures in this paragraph, (d), apply only to affected units that do 
not produce electrical output (in megawatts) or thermal output (in klb/
hr of steam) and for which operational bins are not used. For each hour 
of missing volumetric flow rate data, NOX emission rate 
data, or NOX concentration data used to determine 
NOX mass emissions:
    (1) Whenever prior quality-assured data exist at the time of the 
missing data period, the owner or operator shall substitute, by means 
of the automated data acquisition and handling system, for each hour of 
missing data, the arithmetic average of all of the prior quality-
assured hourly average flow rates or NOX emission rates or 
NOX concentrations.
    (2) Whenever no prior quality-assured flow rate, NOX 
emission rate, or NOX concentration data exist, the owner or 
operator shall, as applicable, substitute for each hour of missing 
data, the maximum potential flow rate as specified in section 2.1.4.1 
of appendix A to this part or the maximum potential NOX 
emission rate or the maximum potential NOX concentration as 
specified in section 2.1.2.1 of appendix A to this part.

    21. Section 75.32 is amended by:
    a. Revising paragraph (a) introductory text and paragraph (a)(2) 
(except for Equation 9);
    b. In paragraph (a)(1) by adding the words ``or stack'' after the 
word ``unit'' and revising the word ``equation'' to read ``Equation''; 
and
    c. In paragraph (a)(3) by revising the first three sentences.
    The revisions and additions read as follows:


Sec. 75.32  Determination of monitor data availability for standard 
missing data procedures.

    (a) Following initial certification of the required SO2, 
CO2, O2 or moisture monitoring system(s) at a 
particular unit or stack location (i.e., the date and time at which 
quality assured data begins to be recorded by CEMS(s) at that 
location), the owner or operator shall begin calculating the percent 
monitor data availability as described in paragraph (a)(1) of this 
section, and shall, upon completion of the first 720 quality-assured 
monitor operating hours, record, by means of the automated data 
acquisition and handling system, the percent monitor data availability 
for each monitored parameter. Similarly, following initial 
certification of the required NOX-diluent, NOX 
concentration, or flow monitoring system(s) at a unit or stack 
location, the owner or operator shall begin calculating the percent 
monitor data availability as described in paragraph (a)(1) of this 
section, and shall, upon completion of the first 2,160 quality-assured 
monitor operating hours, record, by means of the automated data 
acquisition and handling system, the percent monitor data availability 
for each monitored parameter. Notwithstanding these requirements, if 
three years (26,280 clock hours) have elapsed since the date and hour 
of initial certification and fewer than 720 (or 2,160, as applicable) 
quality-assured monitor operating hours have been recorded, the owner 
or operator shall begin recording the percent monitor data 
availability. The percent monitor data availability shall be calculated 
for each monitored parameter at each unit or stack location, as 
follows:
* * * * *
    (2) Upon completion of 8,760 unit (or stack) operating hours 
following initial certification and thereafter, the owner or operator 
shall, for the purpose of applying the standard missing data procedures 
of Sec. 75.33, use Equation 9 to calculate hourly, percent monitor data 
availability. Notwithstanding this requirement, if three years (26,280 
clock hours) have elapsed since initial certification and fewer than 
8,760 unit or stack operating hours have been accumulated, the owner or 
operator shall begin using a modified version of Equation 9, as 
described in paragraph (a)(3) of this section.
* * * * *
    (3) When calculating percent monitor data availability using 
Equation 8 or 9, the owner or operator shall include all unit operating 
hours, and all monitor operating hours for which quality-assured data 
were recorded by a certified primary monitor; a certified redundant or 
non-redundant backup monitor or a reference method for that unit; or by 
an approved alternative monitoring system under subpart E of this part. 
No hours from more than three years (26,280 clock hours) earlier shall 
be used in Equation 9. For a unit that has accumulated fewer than 8,760 
unit operating hours in the previous three years (26,280 clock hours), 
replace the words ``during previous 8,760 unit operating hours'' in the 
numerator of Equation 9 with ``in the previous three years'' and 
replace ``8,760'' in the denominator of Equation 9 with ``total unit 
operating hours in the previous three years.'' * * *
* * * * *

    22. Section 75.33 is amended by:
    a. Revising paragraph (a), removing Tables 1 and 2 after paragraph 
(a), and revising paragraph (c) introductory text;
    b. Adding paragraphs (b)(5), (b)(6), (b)(7), (c)(7), (c)(8), 
(c)(9), (d), and (e), including new Tables 3 and 4;
    c. In paragraph (c)(1) introductory text and paragraph (c)(2) 
introductory text by removing the words ``or continuous emission 
monitoring system'';
    d. In paragraphs (c)(1)(i), (c)(1)(ii)(A), (c)(2)(i), 
(c)(2)(ii)(A), and (c)(3) by adding the words ``or operational bin'' 
after each occurrence of the words ``unit load range'';
    e. In paragraph (c)(3) by removing the words ``section 2 of'';
    f. In paragraph (c)(4) by adding a sentence to the end of the 
paragraph;
    g. In paragraph (c)(5) by adding a new first sentence; and
    h. In paragraph (c)(6) by revising the words ``for either the 
corresponding load range or a higher load range'' to read ``at either 
the corresponding load range (or a higher load range) or at the 
corresponding operational bin''.
    The revisions and additions read as follows:


Sec. 75.33  Standard missing data procedures for SO2, 
NOX and flow rate.

    (a) Following initial certification of the required SO2, 
NOX, and flow rate monitoring system(s) at a particular unit

[[Page 40435]]

or stack location (i.e., the date and time at which quality assured 
data begins to be recorded by CEMS(s) at that location) and upon 
completion of the first 720 quality-assured monitor operating hours 
(for SO2) or the first 2,160 quality assured monitor 
operating hours (for flow, NOX emission rate, or 
NOX concentration), the owner or operator shall provide 
substitute data required under this subpart according to the procedures 
in paragraphs (b) and (c) of this section and depicted in Table 1 
(SO2) and Table 2 of this section (NOX, flow). 
The owner or operator may either implement the provisions of paragraphs 
(b) and (c) of this section on a non-fuel-specific basis, or may, as 
described in paragraphs (b)(5), (b)(6), (c)(7) and (c)(8) of this 
section, provide fuel-specific substitute data values. Notwithstanding 
these requirements, if three years (26,280 clock hours) have elapsed 
since the date and hour of initial certification, and fewer than 720 
(or 2,160, as applicable) quality assured monitor operating hours have 
been recorded, the owner or operator shall begin using the missing data 
procedures of this section. The owner or operator of a unit shall 
substitute for missing data using quality-assured monitor operating 
hours of data from no earlier than three years (26,280 clock hours) 
prior to the date and time of the missing data period.
    (b) * * *
    (5) For units that combust more than one type of fuel, the owner or 
operator may opt to implement the missing data routines in paragraphs 
(b)(1) through (b)(4) of this section on a fuel-specific basis. If this 
option is selected, the owner or operator shall document this in the 
monitoring plan required under Sec. 75.53.
    (6) Use the following guidelines to implement paragraphs (b)(1) 
through (b)(4) of this section on a fuel-specific basis:
    (i) Separate the historical, quality-assured SO2 
concentration data according to the type of fuel combusted;
    (ii) For units that co-fire different types of fuel, either group 
the co-fired hours with the historical data for the fuel with the 
highest SO2 emission rate (e.g., if diesel oil and pipeline 
natural gas are co-fired, count co-fired hours as oil-burning hours), 
or separate the co-fired hours from the single-fuel hours;
    (iii) For the purposes of providing substitute data under paragraph 
(b)(4) of this section, determine a separate, fuel-specific maximum 
potential SO2 concentration (MPC) value for each type of 
fuel combusted in the unit, in a manner consistent with section 2.1.1.1 
of appendix A to this part. For fuel that qualifies as pipeline natural 
gas or natural gas (as defined in Sec. 72.2 of this chapter), the owner 
or operator shall, for the purposes of determining the MPC, either 
determine the maximum total sulfur content and minimum gross calorific 
value (GCV) of the gas by fuel sampling and analysis or shall use a 
default total sulfur content of 0.05 percent by weight (dry basis) and 
a default GCV value of 950 Btu/scf. For co-firing, the MPC value shall 
be based on the fuel with the highest SO2 emission rate. The 
exact methodology used to determine each fuel-specific MPC value shall 
be documented in the monitoring plan for the unit or stack; and
    (iv) For missing data periods that require 720-hour (or, if 
applicable, 3-year) lookbacks, use historical data for the type of fuel 
combusted during each hour of the missing data period to determine the 
appropriate substitute data value for that hour. For co-fired missing 
data hours, if the historical data are separated into single-fuel and 
co-fired hours, use co-fired data to provide the substitute data 
values. Otherwise, use data for the fuel with the highest 
SO2 emission rate to provide substitute data values for co-
fired missing data hours.
    (7) Table 1 summarizes the provisions of paragraphs (b)(1) through 
(b)(6) of this section.
    (c) Volumetric flow rate, NOX emission rate and NOX 
concentration data. Use the procedures in this paragraph to provide 
substitute NOX and flow rate data for all affected units for 
which load-based ranges have been defined in accordance with section 2 
of appendix C to this part. For units that do not produce electrical or 
thermal output (i.e., non-load-based units), use the procedures in this 
paragraph only to provide substitute data for volumetric flow rate, and 
only if operational bins have been defined for the unit, as described 
in section 3 of appendix C to this part. Otherwise, use the applicable 
missing data procedures in paragraph (d) or (e) of this section for 
non-load-based units. For each hour of missing volumetric flow rate 
data, NOX emission rate data, or NOX 
concentration data used to determine NOX mass emissions:
* * * * *
    (4) * * * In addition, when non-load-based operational bins are 
used, the owner or operator shall substitute the maximum potential flow 
rate for any hour in the missing data period in which essential 
operating or parametric data are unavailable and the operational bin 
cannot be determined.
    (5) This paragraph, (c)(5), does not apply to non-load-based, 
affected units using operational bins. * * *
* * * * *
    (7) This paragraph (c)(7) does not apply to affected units using 
non-load-based operational bins. For units that combust more than one 
type of fuel, the owner or operator may opt to implement the missing 
data routines in paragraphs (c)(1) through (c)(6) of this section on a 
fuel-specific basis. If this option is selected, the owner or operator 
shall document this in the monitoring plan required under
    (8) This paragraph, (c)(8), does not apply to affected units using 
non-load-based operational bins. Use the following guidelines to 
implement paragraphs (c)(1) through (c)(6) of this section on a fuel-
specific basis:
    (i) Separate the historical, quality-assured NOX 
emission rate, NOX concentration, or flow rate data 
according to the type of fuel combusted;
    (ii) For units that co-fire different types of fuel, either group 
the co-fired hours with the historical data for the fuel with the 
highest NOX emission rate, NOX concentration or 
flow rate, or separate the co-fired hours from the single-fuel hours;
    (iii) For the purposes of providing substitute data under paragraph 
(c)(4) of this section, a separate, fuel-specific maximum potential 
concentration (MPC), maximum potential NOX emission rate 
(MER), or maximum potential flow rate (MPF) value (as applicable) shall 
be determined for each type of fuel combusted in the unit, in a manner 
consistent with Sec. 72.2 of this chapter and with section 2.1.2.1 or 
2.1.4.1 of appendix A to this part. For co-firing, the MPC, MER or MPF 
value shall be based on the fuel with the highest emission rate or flow 
rate (as applicable). The exact methodology used to determine each 
fuel-specific MPC, MER or MPF value shall be documented in the 
monitoring plan for the unit or stack.
    (iv) For missing data periods that require 2,160-hour (or, if 
applicable, 3-year) lookbacks, use historical data for the type of fuel 
combusted during each hour of the missing data period to determine the 
appropriate substitute data value for that hour. For co-fired missing 
data hours, if the historical data are separated into single-fuel and 
co-fired hours, use co-fired data to provide the substitute data 
values. Otherwise, use data for the fuel with the highest 
NOX emission rate, NOX concentration or flow rate 
(as applicable) to provide substitute data values for co-fired missing 
data hours. Tables 1 and 2 follow.

[[Page 40436]]



Table 1.--Missing Data Procedure for SO2 CEMS, CO2 CEMS, Moisture 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.........................  N  24                    Average...................  HB/HA.
                                     N  24         For SO2, CO2, and H2O **,
                                                               the greater of:.
                                                                Average.................  HB/HA.
                                                                90th percentile.........  720 hours *.
                                                              For O2 and H2Ox , the
                                                               lesser of:.
                                                                Average.................  HB/HA.
                                                                10th percentile.........  720 hours *.
90 or more, but below 95...........  N  8                     Average...................  HB/HA.
                                     N  8          For SO2, CO2, 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...........  N  0          For SO2, CO2, and H2O**,..
                                                                Maximum value \1\.......  720 hours *.
                                                              For O2 and H2Ox:..........
                                                                Minimum value \1\.......  720 hours *.
Below 80...........................  N  0          Maximum potential
                                                               concentration or % (for
                                                               SO2, CO2, 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 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 operating hours.
\2\ During unit operating hours.
\x\ Use this algorithm for moisture except when Equation 19-3, 19-4 or 19-8 in Method 19 in appendix A to part
  60 of this chapter is used for NOX emission rate.
**Use this algorithm for moisture only when Equation 19-3, 19-4 or 19-8 in Method 19 in appendix A to part 60 of
  this chapter is used for NOX emission rate.


   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             Method           Lookback  period     Load  ranges
           (percent)                (hours) \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.
                                N8       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 NOX emission    None.............  No.
                                                     rate; or maximum
                                                     potential NOX NOX
                                                     concentration; 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 720 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.


[[Page 40437]]

    (9) The load-based provisions of paragraphs (c)(1) through (c)(8) 
of this section are summarized in Table 2 of this section. The non-
load-based provisions for volumetric flow rate, found in paragraphs 
(c)(1) through (c)(4), and (c)(6) of this section, are presented in 
Table 4 of this section.
    (d) Non-load-based NO X emission rate and NOX 
concentration data. Use the procedures in this paragraph to provide 
substitute NOX data for affected units that do not produce 
electrical output (in megawatts) or thermal output (in klb/hr of 
steam). For each hour of missing NOX emission rate data, or 
NOX concentration data used to determine NOX mass 
emissions:
    (1) Whenever the monitor data availability is equal to or greater 
than 95.0 percent, the owner or operator shall calculate substitute 
data by means of the automated data acquisition and handling system for 
each hour of each missing data period according to the following 
procedures:
    (i) For a missing data period less than or equal to 24 hours, 
substitute, as applicable, for each missing hour, the arithmetic 
average of the NOX emission rates or NOX 
concentrations recorded by a monitoring system in a 2,160 hour lookback 
period. The lookback period may be comprised of either:
    (A) The previous 2,160 quality assured monitor operating hours, or
    (B) The previous 2,160 quality-assured monitor operating hours at 
the corresponding operational bin, if operational bins, as defined in 
section 3 of appendix C to this part, are used.
    (ii) For a missing data period greater than 24 hours, substitute, 
for each missing hour, the 90th percentile NOX emission rate 
or the 90th percentile NOX concentration recorded by a 
monitoring system during the previous 2,160 quality assured monitor 
operating hours (or during the previous 2,160 quality-assured monitor 
operating hours at the corresponding operational bin, if operational 
bins are used).
    (2) Whenever the monitor data availability is at least 90.0 percent 
but less than 95.0 percent, the owner or operator shall calculate 
substitute data by means of the automated data acquisition and handling 
system for each hour of each missing data period according to the 
following procedures:
    (i) For a missing data period of less than or equal to eight hours, 
substitute, as applicable, the arithmetic average of the hourly 
NOX emission rates or NOX concentrations recorded 
by a monitoring system during the previous 2,160 quality-assured 
monitor operating hours (or during the previous 2,160 quality-assured 
monitor operating hours at the corresponding operational bin, if 
operational bins are used).
    (ii) For a missing data period greater than eight hours, 
substitute, for each missing hour, the 95th percentile hourly flow rate 
or the 95th percentile NOX emission rate or the 95th 
percentile NOX concentration recorded by a monitoring system 
during the previous 2,160 quality-assured monitor operating hours (or 
during the previous 2,160 quality-assured monitor operating hours at 
the corresponding operational bin, if operational bins are used).
    (3) Whenever the monitor data availability is at least 80.0 percent 
but less than 90.0 percent, the owner or operator shall, by means of 
the automated data acquisition and handling system, substitute, as 
applicable, for each hour of each missing data period, the maximum 
hourly NOX emission rate or the maximum hourly 
NOX concentration recorded during the previous 2,160 
quality-assured monitor operating hours (or during the previous 2,160 
quality-assured monitor operating hours at the corresponding 
operational bin, if operational bins are used).
    (4) Whenever the monitor data availability is less than 80.0 
percent, the owner or operator shall substitute, as applicable, for 
each hour of each missing data period, the maximum NOX 
emission rate, as defined in Sec. 72.2 of this chapter, or the maximum 
potential NOX concentration, as defined in section 2.1.2.1 
of appendix A to this part. In addition, when operational bins are 
used, the owner or operator shall substitute (as applicable) the 
maximum potential NOX emission rate or the maximum potential 
NOX concentration for any hour in the missing data period in 
which essential operating or parametric data are unavailable and the 
operational bin cannot be determined.
    (5) If operational bins are used and no prior quality-assured 
NOX concentration data or NOX emission rate data 
exist for the corresponding operational bin, the owner or operator 
shall substitute, as applicable, either the maximum potential 
NOX emission rate, as defined in Sec. 72.2 of this chapter, 
or the maximum potential NOX concentration, as defined in 
section 2.1.2.1 of appendix A to this part.
    (6) Table 3 of this section summarizes the provisions of paragraphs 
(d)(1) through (d)(5) of this section.
    (e) Non-load-based volumetric flow rate data. (1) If operational 
bins, as defined in section 3 of appendix C to this part, are used for 
a unit that does not produce electrical or thermal output, use the 
missing data procedures in paragraph (c) of this section to provide 
substitute volumetric flow rate data for the unit.
    (2) If operational bins are not used, modify the procedures in 
paragraph (c) of this section as follows:
    (i) In paragraphs (c)(1) through (c)(3), the words ``previous 2,160 
quality-assured monitor operating hours'' shall apply rather than 
``previous 2,160 quality-assured monitor operating hours at the 
corresponding unit load range or operational bin, as determined using 
the procedure in appendix C to this part;''
    (ii) The last sentence in paragraph (c)(4) does not apply;
    (iii) Paragraphs (c)(5), (c)(7), and (c)(8) are not applicable; and
    (iv) In paragraph (c)(6), the words, ``for either the corresponding 
load range (or a higher load range) or at the corresponding operational 
bin'' do not apply.
    (3) Table 4 of this section summarizes the provisions of paragraphs 
(e)(1) and (e)(2) of this section. Tables 3 and 4 follow:

         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*

[[Page 40438]]

 
80 or more, but below 90............  N  0       Maximum value..............  2160 hours*
Below 80, or operational bin          N  0       Maximum NOX emission rate    None
 indeterminable.                                             or maximum potential NOX
                                                             concentration.
----------------------------------------------------------------------------------------------------------------
* 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.


                       Table 4.--Non-load-based Missing Data Procedure for Flow Rate 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      The greater of:............
                                                            Average....................  HB/HA
                                                            90th percentile............  2160 hours*
90 or more, but below 95............  N  8                  Average....................  2160 hours*
                                      N  8       The greater of:............
                                                            Average....................  HB/HA
                                                            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 flow rate  None
 indeterminable.
----------------------------------------------------------------------------------------------------------------
 If operational bins are used, the lookback period is the previous 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.


    23. Section 75.34 is amended by:
    a. Revising paragraph (a) introductory text, and paragraphs (a)(1) 
and (d);
    b. Redesignating paragraphs (a)(2) and (a)(3) as paragraphs (a)(3) 
and (a)(4), respectively;
    c. Adding a new paragraph (a)(2);
    d. In the second sentence of newly redesignated paragraph (a)(4) by 
removing the words ``Sec. 75.55(b) or'' and ``, as applicable''; and
    e. In paragraph (c) by revising the word ``NOX2'' to 
read ``NOX''.
    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 use one of 
the options in paragraphs (a)(1), (a)(2) or (a)(4) of this section for 
each hour in which quality-assured data from the outlet SO2 
and/or NOX monitoring system(s) are not obtained, and shall 
document which option is selected in the monitoring plan required under 
Sec. 75.53. If the option in paragraph (a)(1) or (a)(2) is selected, 
the owner or operator may also use the petition provision in paragraph 
(a)(3) of this section.
    (1) The owner or operator may use the missing data substitution 
procedures specified in Secs. 75.31 through 75.33 to provide substitute 
data for any missing data hour(s) in which the add-on emission 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, for each missing data period, record 
parametric data to verify the proper operation of the SO2 or 
NOX add-on emission controls during each hour, as described 
in paragraph (d) of this section. For any missing data hour(s) in which 
such parametric data are either not provided or, if provided, do not 
demonstrate that proper operation of the SO2 or 
NOX add-on emission controls has been maintained, the owner 
or operator shall substitute (as applicable) the maximum potential 
NOX concentration (MPC) as defined in section 2.1.2.1 of 
appendix A to this part, the maximum potential NOX emission 
rate, as defined in Sec. 72.2 of this chapter, or the maximum potential 
concentration for SO2, as defined by section 2.1.1.1. 
Alternatively, for SO2 or NOX, the owner or 
operator may substitute, if available, the hourly SO2 or 
NOX concentration recorded by a certified inlet monitor, in 
lieu of the MPC. For each hour in which data from an inlet monitor are 
reported, the owner or operator shall use a method of determination 
code (MODC) of ``22'' (see Table 4a in Sec. 75.57). In addition, under 
Sec. 75.64(c), the designated representative shall submit as part of 
each electronic quarterly report, a

[[Page 40439]]

certification statement, verifying the proper operation of the 
SO2 or NOX add-on emission control for each 
missing data period in which the missing data procedures of Secs. 75.31 
through 75.33 were applied; or
    (2) This paragraph, (a)(2), applies only to a unit which, as 
provided in Sec. 75.74(a) or Sec. 75.74(b)(1), reports NOX 
mass emissions on a year-round basis under a state or Federal 
NOX mass emissions reduction program that adopts the 
emissions monitoring provisions of this part. If the add-on 
NOX emission controls installed on such a unit are operated 
only during the ozone season or are operated in a more efficient manner 
during the ozone season than outside the ozone season, the owner or 
operator may implement the missing data provisions of paragraph (a)(1) 
of this section in the following alternative manner:
    (i) The historical, quality-assured NOX emission rate or 
NOX concentration data may be separated into two categories, 
i.e., data recorded inside the ozone season and data recorded outside 
the ozone season;
    (ii) For the purposes of the missing data lookback periods 
described under Secs. 75.33(c)(1), (c)(2) and (c)(3), the substitute 
data values shall be taken from the appropriate database, depending on 
the date(s) and hour(s) of the missing data period. That is, if the 
missing data period occurs inside the ozone season, the ozone season 
data shall be used to provide substitute data. If the missing data 
period occurs outside the ozone season, data from outside the ozone 
season shall be used to provide substitute data.
    (iii) A missing data period that begins outside the ozone season 
and continues into the ozone season shall be considered to be two 
separate missing data periods, one ending on April 30, hour 23, and the 
other beginning on May 1, hour 00;
    (iv) For missing data hours outside the ozone season, the 
procedures of Sec. 75.33 may be applied unconditionally, i.e, 
documentation of the operational status of the emission controls is not 
required in order to apply the standard missing data routines.
* * * * *
    (d) In order to implement the options in paragraphs (a)(1) and 
(a)(3) of this section, the owner or operator shall keep records of 
information as described in Sec. 75.58(b)(3) to verify the proper 
operation of all add-on SO2 or NOX emission 
controls, during all periods of SO2 or NOX 
emission missing data. If the owner or operator elects to implement the 
missing data option in paragraph (a)(2) of this section, the records in 
Sec. 75.58(b)(3) are required to be kept only for the ozone season. The 
owner or operator shall document in the quality assurance/quality 
control (QA/QC) program required by section 1 of appendix B to this 
part, the parameters monitored and (as applicable) the ranges and 
combinations of parameters that indicate proper operation of the 
controls. The owner or operator shall provide the information recorded 
under Sec. 75.58(b)(3) and the related QA/QC program information to the 
Administrator, to the EPA Regional Office, or to the appropriate State 
or local agency, upon request.

    24. Section 75.35 is revised to read as follows:


Sec. 75.35  Missing data procedures for CO2.

    (a) The owner or operator of a unit with a CO2 
continuous emission monitoring system for determining CO2 
mass emissions in accordance with Sec. 75.10 (or an O2 
monitor that is used to determine CO2 concentration in 
accordance with appendix F to this part) shall substitute for missing 
CO2 pollutant concentration data using the procedures of 
paragraphs (b) and (d) of this section.
    (b) During the first 720 quality assured monitor operating hours 
following initial certification at a particular unit or stack location 
(i.e., the date and time at which quality assured data begins to be 
recorded by a CEMS at that location), or (when implementing these 
procedures for a previously certified CO2 monitoring system) 
during the 720 quality assured monitor operating hours preceding 
implementation of the standard missing data procedures in paragraph (d) 
of this section, the owner or operator shall provide substitute 
CO2 pollutant concentration data or substitute 
CO2 data for heat input determination, as applicable, 
according to the procedures in Sec. 75.31(b).
    (c) [Reserved]
    (d) Upon completion of 720 quality assured monitor operating hours 
using the initial missing data procedures of Sec. 75.31(b), the owner 
or operator shall provide substitute data for CO2 
concentration or substitute CO2 data for heat input 
determination, as applicable, in accordance with the procedures in 
Sec. 75.33(b) except that the term ``CO2 concentration'' 
shall apply rather than ``SO2 concentration,'' the term 
``CO2 pollutant concentration monitor'' or ``CO2 
diluent monitor'' shall apply rather than ``SO2 pollutant 
concentration monitor,'' and the term ``maximum potential 
CO2 concentration, as defined in section 2.1.3.1 of appendix 
A to this part'' shall apply, rather than ``maximum potential 
SO2 concentration.''

    25. Section 75.36 is amended by:
    a. Revising the section heading;
    b. In paragraph (a) by adding the word ``rate'' after the words 
``hourly heat input'' in the first sentence, by adding the word 
``rate'' after the words ``heat input'' in the second and third 
sentences, by removing the words ``On and after April 1, 2000'' in the 
third sentence and capitalizing ``When'' to begin that sentence, and by 
removing the final sentence;
    c. Revising paragraph (b);
    d. Removing and reserving paragraph (c); and
    e. In paragraph (d) by adding the word ``rate'' after each 
occurrence of the word ``input''.
    The revisions and additions read as follows:


Sec. 75.36  Missing data procedures for heat input rate determinations.

* * * * *
    (b) During the first 720 quality assured monitor operating hours 
following initial certification at a particular unit or stack location 
(i.e., the date and time at which quality assured data begins to be 
recorded by a CEMS at that location), or (when implementing these 
procedures for a previously certified CO2 or O2 
monitor) during the 720 quality assured monitor operating hours 
preceding implementation of the standard missing data procedures in 
paragraph (d) of this section, the owner or operator shall provide 
substitute CO2 or O2 data, as applicable, for the 
calculation of heat input (under section 5.2 of appendix F to this 
part) according to Sec. 75.31(b).
    (c) [Reserved]
* * * * *

    26. Section 75.37 is amended by:
    a. In paragraph (a) by revising the words ``On and after April 1, 
2000, the'' to read ``The'' and by removing the second sentence;
    b. Revising paragraphs (c) and (d)(2)(i); and
    c. In paragraph (d) introductory text by removing the words ``of 
the moisture monitoring system''.
    The revisions and additions read as follows:


Sec. 75.37  Missing data procedures for moisture.

* * * * *
    (c) During the first 720 quality assured monitor operating hours 
following initial certification at a particular unit or stack location 
(i.e., the date and time at which quality assured data begins to be 
recorded by a moisture monitoring

[[Page 40440]]

system at that location), the owner or operator shall provide 
substitute data for moisture according to Sec. 75.31(b).
    (d) * * *
    (2) * * *
    (i) Provided that none of the following equations is used to 
determine SO2 emissions, CO2 emissions or heat 
input: Equation F-2, F-14b, F-16, F-17, or F-18 in appendix F to this 
part, or Equation 19-5 or 19-9 in Method 19 in appendix A to part 60 of 
this chapter, use the missing data procedures in Sec. 75.33(b), except 
that the term ``moisture percentage'' shall apply rather than 
``SO2 concentration,'' the term ``moisture monitoring 
system'' shall apply rather than ``SO2 pollutant 
concentration monitor,'' and the term ``maximum potential moisture 
percentage, as defined in section 2.1.6 of appendix A to this part'' 
shall apply, rather than ``maximum potential SO2 
concentration;'' or
* * * * *

    27. Section 75.41 is amended by:
    a. In paragraph (b)(2)(v)(B) by adding the words ``(Eq. 22)'' 
immediately before ``where''; and
    b. By revising Equation 27 in paragraph (c)(2)(ii).
    The revisions and additions read as follows:


Sec. 75.41  Precision criteria.

* * * * *
    (c) * * *
    (2) * * *
    (ii) * * *
    [GRAPHIC] [TIFF OMITTED] TR12JN02.007
    
* * * * *

    28. Section 75.53 is amended by:
    a. Removing and reserving paragraphs (c) and (d);
    b. Revising paragraphs (a)(1), (e)(1)(viii), and (f)(1)(i)(F);
    c. In paragraph (b) by adding the words ``, by the applicable 
deadline specified in Sec. 75.62 or elsewhere in this part'' prior to 
the period at the end of the paragraph;
    d. In paragraph (e)(1)(i) introductory text by adding the words 
``(or equivalent facility ID number assigned by EPA, if the facility 
does not have an ORISPL number)'' after the words ``Data Base'';
    e. In paragraph (e)(1)(i)(D) by adding the words ``/emergency/
startup'' after the words ``primary/secondary'';
    f. In paragraph (e)(1)(i)(E) by adding the words ``primary/
secondary controls indicator;'' after the words ``(if applicable);'';
    g. In paragraph (e)(1)(ix) by revising the words ``Part 75 
monitoring'' to read ``Monitoring'' and by revising the words 
``reporting year, and 767 reporting indicator'' to read ``ARP/Subpart H 
facility ID number or ORISPL number (as applicable), reporting year, 
and 767 reporting indicator (or equivalent)'';
    h. In paragraph (e)(1)(xii) introductory text by revising the words 
``For each unit or common stack (except for peaking units)'' to read 
``Unless otherwise specified in section 6.5.2.1 of appendix A to this 
part, for each unit or common stack'';
    i. In paragraph (e)(1)(xii)(A) and (B) by adding the words ``, or 
ft/sec (as applicable)'' to the end of each paragraph, and by adding a 
comma after ``megawatts'' in each paragraph;
    j. In paragraph (e)(1)(xii)(D) by revising the first occurrence of 
the word ``load'' to read ``data'' and by adding the words ``(or 
operating)'' after each other occurrence of the word ``load'' and in 
paragraphs (e)(1)(xii)(B), (C), and (E) by adding the words ``or 
operating'' after each occurence of the word ``load'';
    k. In paragraph (f)(2)(i)(F) by adding the word ``rate'' after the 
word ``input'' and the word ``emission'' after the word 
``NOX'';
    l. In paragraph (f)(2)(i)(H) by adding the words ``or ozone 
season'' after the word ``year'' and by revising the word ``part'' to 
read ``chapter'';
    m. In paragraph (f)(5) introductory text by adding the words ``that 
accompanies the initial certification application'' to the end of the 
paragraph;
    n. In paragraph (f)(5)(i) by revising the second sentence and by 
adding a third sentence and new paragraphs (f)(5)(i)(A) through (F);
    o. In paragraph (f)(5)(ii)(C) by revising the words ``natural gas 
or'' to read ``gaseous fuel(s) and/or'' in two occurrences: and
    p. In paragraph (f)(5)(ii)(E) by adding the words ``, estimated'' 
after the word ``actual''.
    The revisions and additions read as follows:


Sec. 75.53  Monitoring plan.

    (a) * * *
    (1) The owner or operator shall meet the requirements of paragraphs 
(a), (b), (e), and (f) of this section.
    (c) [Reserved]
    (d) [Reserved]
    (e) * * *
    (1) * * *
    (viii) Stack exit height (ft) above ground level and ground level 
elevation above sea level.
* * * * *
    (f) * * *
    (1) * * *
    (i) * * *
    (F) 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.
* * * * *
    (5) * * *
    (i) * * * 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 or ozone season measured, estimated or projected 
NOX mass emissions for years one, two, and three;
    (E) Annual measured, estimated or projected SO2 mass 
emissions for years one, two, and three; and
    (F) Annual or ozone season operating hours for years one, two, and 
three.
* * * * *


Sec. 75.54  [Reserved]

    29. Section 75.54 is removed and reserved.


Sec. 75.55  [Reserved]

    30. Section 75.55 is removed and reserved.


Sec. 75.56  [Reserved]

    31. Section 75.56 is removed and reserved.

    32. Section 75.57 is amended by:
    a. Revising the introductory paragraph;
    b. In paragraph (a)(3) by removing the words ``Sec. 75.55 or'' and 
``as applicable,'';
    c. In paragraph (a)(4) by removing both occurrences of the words 
``Sec. 75.56 or'';
    d. Revising Table 4a at the end of paragraph (c)(4)(iv);
    e. Amending paragraph (d)(6) and (d)(7) by removing the words 
``either'',

[[Page 40441]]

``hundredth or'', and ``prior to April 1, 2000 and rounded to the 
nearest thousandth on and after April 1, 2000''.
    The revisions read as follows:


Sec. 75.57  General recordkeeping provisions.

    The owner or operator shall meet all of the applicable 
recordkeeping requirements of this section.
* * * * *
    (c) * * *
    (4) * * *

     Table 4a.--Codes for Method of Emissions and Flow Determination
------------------------------------------------------------------------
                         Hourly emissions/flow measurement or estimation
         Code                                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....................  [Reserved]
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).
15....................  [Reserved]
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.
25....................  Maximum potential NOX emission rate (MER). (Use
                         only when a NOX concentration full-scale
                         exceedance occurs and the diluent monitor is
                         unavailable.)
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.
------------------------------------------------------------------------

* * * * *

    33. Section 75.58 is amended by:
    a. Revising the introductory paragraph;
    b. In paragraphs (b)(1)(i) and (c) introductory text by removing 
the words ``Sec. 75.54(c) or'';
    c. In paragraph (b)(1)(xi) and (b)(2)(vii) by removing the words 
``Codes 1-15 in Table 4 of Sec. 75.54 or'';
    d. Revising paragraph (b)(3) introductory text;
    e. In paragraph (b)(3)(i) by adding the words ``, for each hour of 
missing SO2 or NOX emission data,'' after the 
word ``demonstrate'';
    f. In paragraph (b)(3)(ii) by adding the words ``, for each hour of 
missing SO2 or NOX emission data,'' after the 
word ``indicating'';

[[Page 40442]]

    g. In paragraphs (b)(3)(iii) and (b)(3)(iv) by revising the 
reference to ``Sec. 75.34(a)(2)'' to read ``Sec. 75.34(a)(3)'';
    h. Adding a period to the end of paragraph (c)(7)(ii);
    i. In paragraph (d) introductory text by removing the words 
``paragraph Sec. 75.54(d) or'';
    j. In paragraph (e)(1) by removing the words ``Secs. 75.54(c)(1) 
and (c)(3) or'';
    k. In paragraph (f) introductory text by removing the words 
``Secs. 75.54(b) through (e) or''; and
    l. In paragraph (f)(1)(iii) by adding the words ``other gaseous 
fuel,'' after the words ``natural gas,''.
    The revisions read as follows:


Sec. 75.58  General recordkeeping provisions for specific situations.

    The owner or operator shall meet all of the applicable 
recordkeeping requirements of this section.
* * * * *
    (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) or (a)(3), the owner or operator 
shall record:
* * * * *

    34. Section 75.59 is amended by:
    a. Revising the introductory paragraph;
    b. In paragraph (a)(1)(vii), by revising ``Calibration'' to read 
``Reference signal or calibration'';
    c. In paragraph (a)(5)(ii)(E) by removing both occurrences of the 
word ``load'' and by adding the word ``operating'' before the word 
``levels'';
    d. In paragraph (a)(5)(ii)(F) by adding the words ``(or operating 
level)'' before the word ``indicator'';
    e. In paragraph (a)(5)(ii)(L) by adding the words ``, except for 
units that do not produce electrical or thermal output'' after the 
words ``lb/hr)'';
    f. In paragraph (a)(5)(iii)(E) by adding the words ``(or 
operating)'' before both of the two occurrences of the word ``level'' 
and by adding the words ``, or as otherwise specified by the 
Administrator, for units that do not produce electrical or thermal 
output'' after the words ``lb/hr'';
    g. In the second sentence of paragraph (a)(7) by adding the words 
``of this section'' after the words ``through (a)(7)(vi)'';
    h. In paragraph (a)(7)(ii)(A) by removing the word ``load'';
    i. Revising paragraphs (a)(7)(ii)(P) and (a)(7)(iii)(F);
    j. In paragraph (a)(10)(i)(E) by revising the reference to 
``(a)(7)(iii)(A)'' to read ``(a)(7)(iii)'';
    k. In paragraph (a)(12)(v) introductory text by adding the words 
``(or single-level)'' before the word ``flow'';
    l. In paragraphs (a)(12)(v)(C) and (E) by adding the words ``(or 
operating)'' before the word ``level'', and by, in paragraph (C), 
removing the period at the end of the paragraph and adding a semicolon 
in its place;
    m. In paragraph (a)(12)(v)(D) by adding the words ``(or operating 
level)'' before the word ``data'';
    n. In paragraph (b)(2)(v) by adding the word ``level'' after the 
word ``high'';
    o. In paragraph (b)(4)(ii)(K) by removing the word ``and'' after 
the semicolon;
    p. In paragraph (b)(4)(ii)(L) by removing the period and adding in 
its place ``; and'';
    q. Adding paragraph (b)(4)(ii)(M);
    r. In paragraph (c)(1) by removing the words ``Sec. 75.55(b) or'';
    s. In paragraph (d)(1) introductory text by revising the word 
``under'' to read ``using the procedures of'';
    t. In paragraph (d)(1)(xi) by adding the word ``and'' after the 
semicolon and in paragraph (d)(1)(xii) by removing the semicolon and 
adding a period in its place;
    u. Removing paragraphs (d)(1)(xiii) through (d)(1)(xvi);
    v. Redesignating existing paragraph (d)(2) as (d)(3) and adding a 
new paragraph (d)(2); and
    w. In newly designated paragraph (d)(3)(x) by revising the words 
``Secs. 75.19(c)(1)(iv)(B)(1) and (3)'' to read 
``Sec. 75.19(c)(1)(iv)(B)(1)''.
    The revisions and additions read as follows:


Sec. 75.59  Certification, quality assurance, and quality control 
record provisions.

    The owner or operator shall meet all of the applicable 
recordkeeping requirements of this section.
    (a) * * *
    (7) * * *
    (ii) * * *
    (P) Average stack flow rate, adjusted, if applicable, for wall 
effects (scfh, wet basis);
* * * * *
    (iii) * * *
    (F) Average velocity differential pressure at traverse point 
(inches of H2O) or the average of the square roots of the 
velocity differential pressures at the traverse point ((inches of 
H2O)1/2);
* * * * *
    (b) * * *
    (4) * * *
    (ii) * * *
    (M) Number of hours excluded due to co-firing.
* * * * *
    (d) * * *
    (2) For each single-load or multiple-load appendix E test, record 
the following:
    (i) The three-run average NOX emission rate for each 
load level;
    (ii) An indicator that the average NOX emission rate is 
the highest NOX average emission rate recorded at any load 
level of the test (if appropriate);
    (iii) The default NOX emission rate (highest three-run 
average NOX emission rate at any load level), multiplied by 
1.15, if appropriate;
    (iv) An indicator that the add-on NOX emission controls 
were operating or not operating during each run of the test; and
    (v) Parameter data indicating the use and efficacy of control 
equipment during the test.
* * * * *
    35. Section 75.60 is amended by:
    a. In paragraph (b)(6), adding the words ``in writing (or by 
electronic mail)'' after the words ``If requested''; and
    b. Adding paragraph (b)(7).
    The revisions and additions read as follows:


Sec. 75.60  General provisions.

* * * * *
    (b) * * *
    (7) Routine appendix E retest reports. 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 within 45 days 
after completing a required periodic retest according to section 2.2 of 
appendix E to this part, or within 15 days of receiving the request, 
whichever is later. The designated representative shall report the 
hardcopy information required by Sec. 75.59(b)(5) to the applicable EPA 
Regional Office, appropriate State, and/or appropriate local air 
pollution control agency that requested the hardcopy report.
* * * * *
    36. Section 75.61 is amended by:
    a. In paragraph (a)(1) introductory text by removing the words 
``and except for testing only of the data acquisition and handling 
system'' from the end of the first sentence, and by adding two new 
sentences to the end of the paragraph;
    b. In paragraph (a)(1)(i) by revising the heading and first 
sentence, and by adding a new sentence after the first sentence;
    c. In paragraph (a)(1)(ii) by revising the word ``and'' to read ``, 
and partial'' in the heading, and, in the first sentence, by adding the 
word

[[Page 40443]]

``required'' after the word ``retesting'', and revising the words 
``recertification under Sec. 75.20(b), notice of testing'' to read 
``partial recertification testing required under Sec. 75.20(b)(2), 
notice of the date of any required RATA testing or any required 
retesting under section 2.3 in appendix E to this part'';
    d. In paragraph (a)(1)(iii) by adding the words ``or 
recertification'' after each occurrence of the word ``certification'' 
and by adding the words ``must be aborted, or'' after the words ``was 
failed or'';
    e. In paragraph (a)(1)(iv) by revising both references to 
``(a)(1)'' to read ``(a)(1)(ii)'', by adding the words ``or other 
retests'' to the end of the first sentence, and by adding the words 
``(or other retests)'' after the words ``recertification tests'' in the 
second sentence;
    f. In the first sentence of paragraph (a)(2) introductory text by 
adding the words ``, or becomes affected,'' after the words 
``commercial operation'';
    g. In paragraph (a)(2)(i) by adding the words ``or becomes 
affected'' after the words ``commences commercial operation'';
    h. In paragraph (a)(2)(ii) by adding the words ``or becomes 
affected,'' after both occurrences of the words ``commences commercial 
operation'' and by removing the comma between the words ``or'' and 
``the date'';
    i. In paragraph (a)(4) by removing ``(a)'' after the second and 
third occurrences of ``Sec. 75.4'';
    j. Revising the heading and the first sentence of paragraph (a)(5) 
introductory text;
    k. In paragraph (a)(5)(ii) by adding the words ``, appendix E 
retest, or low mass emissions unit retest'' before the word 
``immediately''; and
    l. Revising paragraph (a)(6).
    The revisions and additions read as follows:


Sec. 75.61  Notifications.

    (a) * * *
    (1) * * * The owner or operator shall also provide written 
notification of testing performed under Sec. 75.19(c)(1)(iv)(A) to 
establish fuel-and-unit-specific NOX emission rates for low 
mass emissions units. Such notifications are not required, however, for 
initial certifications and recertifications of excepted monitoring 
systems under appendix D to this part.
    (i) Notification of initial certification testing and full 
recertification. Initial certification test notifications and 
notifications of full recertification testing under Sec. 75.20(b)(2) 
shall be submitted not later than 21 days prior to the first scheduled 
day of certification or recertification testing. In emergency 
situations when full recertification testing is required following an 
uncontrollable failure of equipment that results in lost data, notice 
shall be sufficient if provided within 2 business days following the 
date when testing is scheduled.
* * * * *
    (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, and of periodic retesting of 
low mass emissions units performed under Sec. 75.19(c)(1)(iv)(D), no 
later than 21 days prior to the first scheduled day of testing. * * *
* * * * *
    (6) Notice of combustion of emergency fuel under appendix D or E. 
The designated representative of an oil-fired unit or gas-fired unit 
using appendix D or E of this part shall, for each calendar quarter in 
which emergency fuel is combusted, provide notice of the combustion of 
the emergency fuel in the cover letter (or electronic equivalent) which 
transmits the next quarterly report submitted under Sec. 75.64. The 
notice shall specify the exact dates and hours during which the 
emergency fuel was combusted.
* * * * *
    37. Section 75.62 is amended by:
    a. Revising paragraph (a)(1); and
     b. In the third sentence of paragraph (a)(2) by adding the words 
``certification or'' before both occurrences of the word 
``recertification''.
    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 45 days prior to the 
initial certification tests; at the time of each certification or 
recertification application submission; in each electronic quarterly 
report; and whenever an update of the electronic monitoring plan 
information is required, either under Sec. 75.53(b) or elsewhere in 
this part.
* * * * *
    38. Section 75.63 is amended by:
    a. In the section heading by removing the word ``submittals'';
    b. Revising paragraphs (a)(1)(i) and (a)(1)(ii), and removing 
paragraph (a)(1)(iii);
    c. In paragraph (a)(2) heading by adding the words ``and diagnostic 
testing'';
    d. In paragraph (a)(2)(i) by adding the words ``under 
Sec. 75.20(b)'' after the words ``recertification tests'' and the words 
``of this section'' after the words ``paragraph (b)(1)'';
    e. In paragraph (a)(2)(ii) by adding, in the first sentence, the 
words ``under Sec. 75.20(b)'' after the word ``tests'' and the words 
``of this section'' after the words ``paragraph (b)(2)'', and by 
revising, in the second sentence, the words ``for submission to it of a 
hardcopy recertification'' to read ``to provide hardcopy 
recertification test data and results'';
    f. In paragraph (a)(2)(iii) by adding the words ``rather than 
recertification testing'' after the words ``are required'';
    g. In paragraph (b)(1)(i), by removing the words ``Secs. 75.53(c) 
and (d), or Sec. '' and ``as applicable,'';
    h. In paragraph (b)(1)(ii) by removing the words ``Sec. 75.56 or'' 
and ``as applicable,''; and
    i. In the first sentence of paragraph (b)(2)(i), by removing the 
words ``Secs. 75.53(c) and (d), or Sec. '' and ``as applicable,''.
    The revisions and additions read as follows:


Sec. 75.63  Initial certification or recertification application.

    (a) * * *
    (1) * * *
    (i) For CEM systems or excepted monitoring systems under appendix D 
or E to this part, within 45 days after completing all initial 
certification tests, submit:
    (A) To the Administrator, the electronic information required by 
paragraph (b)(1) of this section and a hardcopy certification 
application form (EPA form 7610-14). Except for subpart E applications 
for alternative monitoring systems or unless specifically requested by 
the Administrator, do not submit a hardcopy of the test data and 
results to the Administrator.
    (B) To the applicable EPA Regional Office and the appropriate State 
and/or local air pollution control agency, the hardcopy information 
required by paragraph (b)(2) of this section.
    (ii) For units for which the owner or operator is applying for 
certification

[[Page 40444]]

approval of the optional excepted methodology under Sec. 75.19 for low 
mass emissions units, submit, no later than 45 days prior to commencing 
use of the methodology:
    (A) To the Administrator, the electronic information required by 
Sec. 75.53(f)(5)(i) and paragraph (b)(1)(i) of this section, and a 
hardcopy cover letter identifying the submittal as a low mass emissions 
unit certification application; and
    (B) To the applicable EPA Regional Office and appropriate State 
and/or local air pollution control agency, the hardcopy information 
required by Sec. 75.19(a)(2) and Sec. 75.53(f)(5)(ii), the hardcopy 
results of any appendix E (of this part) tests or any CEMS data 
analysis used to derive a fuel-and-unit-specific default NOX 
emission rate.
* * * * *

    39. Section 75.64 is amended by:
    a. In paragraph (a) introductory text by revising the first 
sentence, and by adding in the third sentence the words ``or has been 
placed in long-term cold storage'' after the words ``Sec. 75.4(a)'';
    b. In paragraph (a)(2) introductory text by revising the words 
``Secs. 75.53 through 75.59'' to read Sec. 75.53 and Secs. 75.57 
through 75.59'';
    c. In paragraph (a)(2)(iii) by removing the words ``Sec. 75.54(f) 
or'';
    d. In paragraph (a)(2)(iv) by removing the words ``Sec. 75.55(b)(3) 
or'';
    e. In paragraph (a)(2)(vi) by removing the words ``Sec. 75.54(g) 
or'';
    f. In paragraph (a)(2)(vii) by removing the words ``Sec. 75.56 
or'';
    g. In paragraph (a)(2)(viii) by adding a comma after the word 
``coefficients'' and by removing the words ``Sec. 75.56(a)(5)(vii), 
Sec. 75.56(a)(5)(ix),'';
    h. In paragraph (a)(2)(xi) by removing the words ``Sec. 75.56(a)(7) 
or'';
    i. In paragraph (a)(4) by removing the words ``hundredth prior to 
April 1, 2000 and to the nearest'' and the words ``on and after April 
1, 2000'';
    j. Removing and reserving paragraphs (a)(2)(v), (a)(8), and (e);
    k. In paragraph (d) by revising the words ``electronic or 
hardcopy'' to read ``(unless otherwise approved by the Administrator) 
electronic''; and
    l. In paragraph (f) by removing the words ``modem and''.
    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). * * *
* * * * *


Sec. 75.65  [Amended].

    40. Section 75.65 is amended by removing the words ``Sec. 75.54(f) 
or'' and ``, as applicable,''.


Sec. 75.66  [Amended].

    41. Section 75.66 is amended by:
    a. In paragraph (e) by removing the words ``Sec. 75.55(b) or'' and 
``, as applicable,'';
    b. In paragraph (f) introductory text by revising the reference to 
``Sec. 75.34(a)(2)'' to ``Sec. 75.34(a)(3)''; and
    c. Removing and reserving paragraph (i).

    42. Section 75.70 is amended by:
    a. Adding a hyphen to the term ``non-affected'' in paragraph 
(a)(1);
    b. In paragraph (d)(1) by adding the words ``in Sec. 75.20'' after 
the words ``recertification procedures'';
    c. Revising paragraph (e);
    d. In paragraph (f) introductory text by revising the reference to 
``Sec. 75.74'' to read ``Sec. 75.74(c)(7)'';
    e. In paragraph (f)(1) introductory text by revising the words 
``missing data procedures in subpart D of this part'' to read 
``applicable missing data procedures in Secs. 75.31 through 75.37'';
    f. In paragraphs (f)(1)(i), (ii), and (iii) by adding a comma after 
the word ``valid'' and revising the words ``quality assured'' to read 
``quality-assured'';
    g. In paragraphs (f)(1)(ii) and (iii) by removing the word ``or'' 
from the end of each paragraph;
    h. In paragraph (f)(1)(iii) by adding the word ``rate'' after the 
first occurrence of the word ``input'', revising the word ``mmBtu'' to 
read ``mmBtu/hr'', and by removing the words ``or by an accepted 
monitoring system under appendix D to this part'';
    i. In paragraph (f)(1)(iv) by revising the words ``volumetric flow 
monitor, and without a diluent monitor'' to read ``flow monitor'', by 
adding a comma after the reference to ``Sec. 75.32'', and by removing 
the period and adding ``; or'' to the end of the paragraph;
    j. Adding new paragraph (f)(1)(v);
    k. In paragraph (g)(1) by adding the word ``rate'' after the words 
``and heat input'';
    l. In paragraph (g)(2) by revising the words ``of the unit under 
section 2.1 of Appendix A of'' to read ``, as defined in section 
2.1.4.1 of appendix A to''; and
    m. Revising paragraph (g)(6).
    The revisions and additions read as follows:


Sec. 75.70  NOX mass emissions provisions.

* * * * *
    (e) Quality assurance and quality control requirements. For units 
that use continuous emission monitoring systems to account for 
NOX mass emissions, the owner or operator shall meet the 
applicable quality assurance and quality control requirements in 
Sec. 75.21, appendix B to this part, and Sec. 75.74(c) for the 
NOX-diluent continuous emission monitoring systems, flow 
monitoring systems, NOX concentration monitoring systems, 
moisture monitoring systems, and diluent monitors required under 
Sec. 75.71. Units using the low mass emissions excepted methodology 
under Sec. 75.19 shall meet the applicable quality assurance 
requirements of that section, except as otherwise provided in 
Sec. 75.74(c). Units using excepted monitoring methods under appendices 
D and E to this part shall meet the applicable quality assurance 
requirements of those appendices.
    (f) * * *
    (1) * * *
    (v) A valid, quality-assured hour of moisture data (in percent 
H2O) has not been measured or recorded for an affected unit, 
either by a certified moisture monitoring system or an approved 
alternative monitoring method under subpart E of this part. This 
requirement does not apply when a default percent moisture value, as 
provided in Sec. 75.11(b) or Sec. 75.12(b), is used to account for the 
hourly moisture content of the stack gas.
* * * * *
    (g) * * *
    (6) For any unit using continuous emissions monitors, the 
conditional data validation procedures in Sec. 75.20(b)(3)(ii) through 
(b)(3)(ix).
* * * * *

    43. Section 75.71 is amended by:
    a. In paragraph (a)(1) by adding the word ``rate'' after the words 
``heat input'' and by removing the hyphen after each occurrence of the 
words ``O2'' and ``CO2'';
    b. In the second sentence of paragraph (a)(2) by removing the 
hyphens after the words ``O2'' and ``CO2'' and by 
revising the words ``heat input, or, if applicable, use the procedures 
in appendix D to this part'' to read ``heat input rate'';
    c. In paragraph (b)(1) by revising ``i.e.'' to read ``e.g.'' and by 
adding the words ``or to calculate the heat input rate'' before the 
words ``, the owner'';
    d. In paragraph (b)(3) by adding the word ``rate'' after the word 
``input'' and by adding a comma after the word ``maintain''; and
    e. In paragraph (c)(2) by adding the word ``rate'' to the end of 
the first

[[Page 40445]]

sentence and by revising the second sentence; and
    f. In paragraph (d)(2) by revising the second sentence, by revising 
the words ``paragraph (c) of this section or, if applicable, paragraph 
(e)'' to read ``paragraph (c)(1) or (c)(2)'' in the third sentence, and 
by adding a new sentence at the end of the paragraph.
    The revisions and additions read as follows:


Sec. 75.71  Specific provisions for monitoring NOX emission 
rate and heat input for the purpose of calculating NOX mass 
emissions.

* * * * *
    (c) * * *
    (2) * * * However, for a common pipe configuration, the heat input 
rate apportionment provisions in section 2.1.2 of appendix D to this 
part shall not be used to meet the NOX mass reporting 
provisions of this subpart, unless all of the units served by the 
common pipe are affected units and have similar efficiencies; or
* * * * *
    (d) * * *
    (2) * * * However, for a common pipe configuration, the heat input 
apportionment provisions in section 2.1.2 of appendix D to this part 
shall not be used to meet the NOX mass reporting provisions 
of this subpart unless all of the units served by the common pipe are 
affected units and have similar efficiencies. * * * If the required 
CEMS are not installed and certified by that date, the owner or 
operator shall report hourly NOX mass emissions as the 
product of the maximum potential NOX emission rate (MER) and 
the maximum hourly heat input of the unit (as defined in Sec. 72.2 of 
this chapter), starting with the first unit operating hour after the 
deadline and continuing until the CEMS are provisionally certified.
* * * * *

    44. Section 75.72 is amended by:
    a. In the introductory paragraph to the section by revising the 
words ``(in mmBtu/hr) and the hourly operating time (in hr)'' to read 
``rate (in mmBtu/hr) and the unit or stack operating time (as defined 
in Sec. 72.2)'';
    b. Revising paragraph (a)(1) introductory text and paragraph 
(a)(1)(i);
    c. Redesignating paragraph (a)(1)(ii) as paragraph (a)(1)(iii) and 
adding a new paragraph (a)(1)(ii);
    d. In the newly redesignated paragraph (a)(1)(iii)(A) by adding the 
word ``rate'' after the words ``heat input'';
    e. By adding the words ``and a diluent monitor'' after the word 
``system'' in the newly redesignated paragraph (a)(1)(iii)(B);
    f. In paragraph (a)(2) introductory text by adding the words ``, 
for purposes of heat input determination,'' after the words ``from each 
unit and'';
    g. In paragraph (a)(2)(ii)(A) by adding the word ``rate'' after the 
words ``heat input'';
    h. In paragraph (b)(1) introductory text by removing the semicolon 
and by adding the words ``, for purposes of heat input determination,'' 
at the end of the paragraph;
    i. Revising paragraph (b)(1)(ii)(A);
    j. In paragraph (b)(2)(ii)(B) by adding the word ``rate'' after the 
words ``heat input'' in the first sentence and by revising the second 
sentence;
    k. In paragraph (b)(2)(iii) by adding the words ``, in accordance 
with paragraph (a) of this section'' after the word ``purposes'';
    l. Revising paragraph (c);
    m. Revising paragraph (d);
    n. In paragraph (e) introductory text by revising the first 
sentence, revising the words ``appendix F of'' to read ``appendix F 
to'' in the second sentence, and adding a new sentence between the 
first and second sentences;
    o. In paragraph (e)(1) introductory text by revising the second 
sentence and adding a new third sentence;
    p. In paragraph (e)(1)(i) by adding the word ``rate'' after ``heat 
input'' and by revising the reference to ``Sec. 75.16(e)(5)'' to read 
``Sec. 75.16(e)(3)'';
    q. In paragraph (e)(2) by adding the word ``rate'' after the words 
``heat input'' in the first sentence and by removing the words ``or a 
common stack'' in the last sentence; and
    r. In paragraph (g) by removing the words ``the owner or operator 
should'' and by revising the reference to ``Sec. 75.16(e)(5)'' to read 
``Sec. 75.16(e)(3)''.
    The revisions and additions read as follows:


Sec. 75.72  Determination of NOX mass emissions.

* * * * *
    (a) * * *
    (1) Install, certify, operate, and maintain a NOX-
diluent continuous emissions monitoring system and a flow monitoring 
system in the common stack, record the combined NOX mass 
emissions for the units exhausting to the common stack, and, for 
purposes of determining the hourly unit heat input rates, 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, certify, operate, and maintain a flow monitoring 
system and diluent monitor in the duct to the common stack from each 
unit; or
* * * * *
    (b) * * *
    (1) * * *
    (ii) * * *
    (A) Use the procedures in appendix D to determine heat input for 
that unit; however, for a common pipe configuration, the heat input 
apportionment provisions in section 2.1.2 of appendix D to this part 
shall not be used to meet the NOX mass reporting provisions 
of this subpart unless all of the units served by the common pipe are 
affected units and have similar efficiencies; and
* * * * *
    (2) * * *
    (ii) * * *
    (B) * * * However, for a common pipe serving both affected and non-
affected units, the heat input rate apportionment provisions in section 
2.1.2 of appendix D to this part shall not be used to meet the 
NOX mass reporting provisions of this subpart. * * *
* * * * *
    (c) Unit with a main stack and a bypass stack. Whenever any portion 
of the flue gases from an affected unit can be routed through a bypass 
stack to avoid the installed NOX-diluent continuous 
emissions monitoring system or NOX concentration monitoring 
system, the owner and operator shall either:
    (1) Install, certify, operate, and maintain separate 
NOX-diluent continuous emissions monitoring systems and flow 
monitoring systems on the main stack and the bypass stack and calculate 
NOX mass emissions for the unit as the sum of the 
NOX mass emissions measured at the two stacks;
    (2) Monitor NOX mass emissions at the main stack using a 
NOX-diluent CEMS and a flow monitoring system and measure 
NOX mass emissions at the bypass stack using the reference 
methods in Sec. 75.22(b) for NOX concentration, flow rate, 
and diluent gas concentration, or NOX concentration and flow 
rate, and calculate NOX mass emissions for the unit as the 
sum of the emissions recorded by the installed monitoring systems on 
the main stack and the emissions measured by the reference method 
monitoring systems; or
    (3) Install, certify, operate, and maintain a NOX-
diluent CEMS and a flow monitoring system 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, since only the main stack is monitored. For 
each unit operating hour in which the bypass stack is used, report 
NOX mass

[[Page 40446]]

emissions as follows. If the unit heat input is determined using a flow 
monitor and a diluent monitor, report NOX mass emissions 
using the maximum potential NOX emission rate, the maximum 
potential flow rate, and either the maximum potential CO2 
concentration or the minimum potential O2 concentration (as 
applicable). 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)). If the unit heat input is determined using a 
fuel flowmeter, in accordance with appendix D to this part, report 
NOX mass emissions as the product of the maximum potential 
NOX emission rate and the actual measured hourly heat input 
rate.
    (d) Unit with multiple stack or duct configuration. When the flue 
gases from an affected unit discharge to the atmosphere through more 
than one stack, or when the flue gases from an affected unit utilize 
two or more ducts feeding into a single stack and the owner or operator 
chooses to monitor in the ducts rather than in the stack, the owner or 
operator shall either:
    (1) Install, certify, operate, and maintain a NOX-
diluent continuous emission monitoring system and a flow monitoring 
system in each of the multiple stacks and determine NOX mass 
emissions from the affected unit as the sum of the NOX mass 
emissions recorded for each stack. If another unit also exhausts flue 
gases into one of the monitored stacks, the owner or operator shall 
comply with the applicable requirements of paragraphs (a) and (b) of 
this section, in order to properly determine the NOX mass 
emissions from the units using that stack;
    (2) Install, certify, operate, and maintain a NOX-
diluent continuous emissions monitoring system and a flow monitoring 
system in each of the ducts that feed into the stack, and determine 
NOX mass emissions from the affected unit using the sum of 
the NOX mass emissions measured at each duct; or
    (3) If the unit is eligible to use the procedures in appendix D to 
this part and if the conditions and restrictions of Sec. 75.17(c)(2) 
are fully met, install, certify, operate, and maintain a 
NOX-diluent continuous emissions monitoring system in one of 
the ducts feeding into the stack or in one of the multiple stacks, (as 
applicable) in accordance with Sec. 75.17(c)(2), and use the procedures 
in appendix D to this part to determine heat input rate for the unit.
    (e) * * * The owner or operator may use a NOX 
concentration monitoring system and a flow monitoring system to 
determine NOX mass emissions for the cases described in 
paragraphs (a) through (c) of this section and in paragraph (d)(1) or 
paragraph (d)(2) of this section (in place of a NOX-diluent 
continuous emissions monitoring system and a flow monitoring system). 
However, this option may not be used for the case described in 
paragraph (d)(3) of this section. * * *
    (1) * * * In addition, the owner or operator must provide heat 
input rate values for each unit utilizing a common stack. The owner or 
operator may either:
* * * * *

    45. Section 75.73 is amended by:
    a. In the second sentence of paragraph (a) by adding the word 
``compliance'' before the word ``deadline'', and by revising the 
reference to ``Sec. 75.70'' to read ``Sec. 75.70(b)'';
    b. In paragraph (a)(6) introductory text by removing the word 
``following'', by revising the words ``this paragraph'' to read 
``Sec. 75.58(c)'', and by removing the colon at the end of the 
paragraph and adding a period in its place;
    c. Removing paragraphs (a)(6)(i) through (a)(6)(vi) and paragraphs 
(e)(1)(i) and (e)(1)(ii);
    d. Adding new paragraphs (a)(8), (d)(6), (f)(1)(vii), and 
(f)(1)(viii);
    e. Revising the second and third sentences of paragraph (c)(3) and 
adding a new last sentence;
    f. Revising paragraph (e)(1); and
    g. In paragraph (e)(2) by adding the words ``certification or'' 
before the words ``recertification application'' in the third sentence, 
and by adding a new sentence to the end of the paragraph.
    The revisions and additions read as follows:


Sec. 75.73  Recordkeeping and reporting.

    (a) * * *
    (8) Formulas from monitoring plan for total NOX mass.
* * * * *
    (c) * * *
    (3) * * * In addition, to the extent applicable, each monitoring 
plan shall contain the information in Sec. 75.53, paragraphs (f)(1)(i), 
(f)(2)(i), and (f)(4) in electronic format and the information in 
Sec. 75.53, paragraphs (f)(1)(ii) and (f)(2)(ii) in hardcopy format. 
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, paragraphs (f)(5)(i) and (f)(5)(ii). The 
monitoring plan also shall identify, in electronic format, the 
reporting schedule for the affected unit (ozone season or quarterly), 
the beginning and end dates for the reporting schedule, seasonal 
controls indicator, ozone season fuel switching flag, and whether year-
round reporting for the unit is required by a State or local agency.
    (d) * * *
    (6) Routine appendix E retest reports. If requested by the 
applicable EPA Regional Office, appropriate State, and/or appropriate 
local air pollution control agency, the designated representative shall 
submit a hardcopy report within 45 days after completing a required 
periodic retest according to section 2.2 of appendix E to this part, or 
within 15 days of receiving the request, whichever is later. The 
designated representative shall report the hardcopy information 
required by Sec. 75.59(b)(5) to the applicable EPA Regional Office, 
appropriate State, and/or appropriate local air pollution control 
agency that requested the hardcopy report.
    (e) * * *
    (1) Electronic submission. The designated representative for an 
affected unit shall submit to the Administrator a complete, electronic, 
up-to-date monitoring plan file for each affected unit or group of 
units monitored at a common stack and each non-affected unit under 
Sec. 75.72(b)(2)(ii), no later than 45 days prior to the initial 
certification test; at the time of a certification or recertification 
application submission; and whenever an update of the electronic 
monitoring plan is required, either under Sec. 75.53 or elsewhere in 
this part.
    (2) * * * Electronic submittal of all monitoring plan information, 
including hardcopy portions, is permissible provided that a paper copy 
of the hardcopy portions can be furnished upon request.
    (f) * * *
    (1) * * *
    (vii) Reporting period heat input.
    (viii) New reporting frequency and begin date of the new reporting 
frequency (if applicable).
* * * * *
    46. Section 75.74 is amended by:
    a. Revising paragraph (c)(2)(i)(D)(1);
    b. Adding a new second sentence to paragraph (c)(2)(ii) 
introductory text;
    c. In paragraph (c)(2)(ii)(A), adding the words ``(or operating 
level(s))'' after the words ``RATA load level(s)'';
    d. Revising paragraphs (c)(2)(ii)(C) and (c)(2)(ii)(H)(1);
    e. In paragraph (c)(3)(iii) by revising the first and second 
sentences;
    f. In paragraph (c)(3)(iv) by adding in the second sentence the 
word ``the'' after the word ``only'' and by revising the words 
``included when determining'' to read ``used to determine'';
    g. In paragraph (c)(3)(v) by adding a new second sentence;

[[Page 40447]]

    h. In paragraph (c)(3)(vi)(B) by removing the quotation marks 
around the words ``probationary calibration error test'' in the first 
sentence, by revising the reference to ``Sec. 75.20(b)(3)'' to read 
``Sec. 75.20(b)(3)(ii)'' in the first sentence, and by adding the words 
``(subject to the restrictions in paragraph (c)(3)(xii) of this 
section)'' after the words''Sec. 75.20(b)(3)'' in the third sentence;
    i. In paragraph (c)(3)(x) by adding the words ``, if applicable,'' 
after the words ``Sec. 75.20(b)(3) and'';
    j. In paragraph (c)(3)(xi) by adding a comma after each occurrence 
of the word ``diagnostic'', by revising the words ``Sec. 75.31 or 
Sec. 75.33'' in the third sentence to read `` Sec. 75.31, Sec. 75.33, 
or Sec. 75.37'', and by adding the words ``conditional data 
validation'' before the word ``provisions'' in the fifth sentence;
    k. In paragraphs (c)(3)(xii)(A) and (B) by revising each occurrence 
of the words ``Sec. 75.31 or Sec. 75.33'' to read ``Sec. 75.31, 
Sec. 75.33, or Sec. 75.37'', by adding a comma after the occurrence of 
the word ``diagnostic'' in each paragraph, and by adding the words 
``conditional data validation'' before the word ``provisions'' in the 
second sentence of paragraph (c)(3)(xii)(B).
    l. In paragraph (c)(4) by adding the word ``rate'' after the words 
``heat input'' in the first sentence and by adding a new third 
sentence;
    m. In paragraph (c)(5) by adding the word ``rate'' after the words 
``heat input'';
    n. Revising paragraphs (c)(6)(v), (c)(7)(ii), and (c)(8)(ii);
    o. Adding a new paragraph (c)(7)(iii);
    p. Revising paragraph (c)(10); and
    q. In the second sentence of paragraph (c)(11) by revising the word 
``calender'' to read ``calendar''.
    The revisions and additions read as follows:


Sec. 75.74  Annual and ozone season monitoring and reporting 
requirements.

* * * * *
    (c) * * *
    (2) * * *
    (i) * * *
    (D) * *  *
    (1) If the monitor passed a linearity check on or after January 1 
of the previous year and the unit or stack on which the monitor is 
located operated for fewer than 336 unit or stack operating hours (as 
defined in Sec. 72.2 of this chapter) in the previous ozone season, the 
owner or operator may have a grace period of up to 168 unit or stack 
operating hours to perform a linearity check, subject to the 
restrictions in this paragraph and in paragraph (c)(3)(xii) of this 
section, and the owner or operator may continue to submit quality 
assured data from that monitor as long as all other required quality 
assurance tests are passed. If the unit or stack operates for more than 
the allowable grace period of 168 unit or stack operating hours in the 
current ozone season without a linearity check of the monitor having 
been performed, the owner or operator of the unit shall either report 
data from a certified backup monitoring system or reference method or 
shall report substitute data using the missing data procedures under 
paragraph (c)(7) of this section, starting with the first unit or stack 
operating hour after the grace period expires and continuing until the 
successful completion of a linearity check. Note that the grace period 
shall not extend beyond the end of the third calendar quarter.
* * * * *
    (ii) * * * Notwithstanding this requirement, a pre-ozone season 
RATA need not be performed between October 1 and April 30, if a RATA 
was passed during the previous ozone season and if the conditions in 
paragraph (c)(3)(vii) of this section are met, thereby ensuring that 
the data from the CEMS are quality-assured at the beginning of the 
current ozone season.
* * * * *
    (C) For flow rate monitoring systems installed on peaking units or 
bypass stacks and for flow monitors exempted from multiple-level RATA 
testing under section 6.5.2(e) of appendix A to this part, a single-
load (or single-level) RATA is required. For all other flow rate 
monitoring systems, a 2-load (or 2-level) RATA is required at the two 
most frequently-used load or operating levels (as defined under section 
6.5.2.1 of appendix A to this part), with the following exceptions. 
Except for flow monitors exempted from 3-level RATA testing under 
section 6.5.2(e) of appendix A to this part, a 3-load flow RATA is 
required at least once every five years and is also required if the 
flow monitor polynomial coefficients or K factor(s) are changed prior 
to conducting the flow RATA required under this paragraph.
* * * * *
    (H) * * * (1) If the monitoring system passed a RATA on or after 
January 1 of the previous year and the unit or stack on which the 
monitor is located operated for fewer than 336 unit or stack operating 
hours (as defined in Sec. 72.2 of this chapter) in the previous ozone 
season, the owner or operator may have a grace period of up to 720 unit 
or stack operating hours to perform a RATA, subject to the restrictions 
in this paragraph and in paragraph (c)(3)(xii) of this section, and the 
owner or operator may continue to report quality assured data from that 
monitor as long as all other required quality assurance tests are 
passed. If the unit or stack operates for more than the allowable grace 
period of 720 unit or stack operating hours in the current ozone 
season, without a RATA of the monitoring system having been performed, 
the owner or operator of the unit or stack shall either report data 
from a certified backup monitoring system or reference method or shall 
report substitute data using the missing data procedures under 
paragraph (c)(7) of this section, starting with the first unit 
operating hour after the grace period expires and continuing until the 
successful completion of the RATA. Note that the grace period shall not 
extend beyond the end of the third calendar quarter.
* * * * *
    (3) * * *
    (iii) For each flow monitoring system required by this subpart, 
except for flow monitors installed on non-load-based units that do not 
produce electrical or thermal output, flow-to-load ratio tests are 
required in the second and third calendar quarters, in accordance with 
section 2.2.5 of appendix B to this part. If the flow-to-load ratio 
test for the second calendar quarter is failed, the owner or operator 
shall follow the procedures in section 2.2.5(c)(8) of appendix B to 
this part. * * *
* * * * *
    (v) * * * Automatic deadline extensions may be claimed for the two 
calendar quarters outside the ozone season (the first and fourth 
calendar quarters), since a fuel flow-to-load ratio test is not 
required in those quarters. * * *
* * * * *
    (4) * * * The owner or operator shall include all calendar quarters 
in the year when determining the deadline for visual inspection of the 
primary fuel flowmeter element, as specified in section 2.1.6(c) of 
appendix D to this part.
* * * * *
    (6) * * *
    (v) The results of RATAs (and any other quality assurance test(s) 
required under paragraph (c)(2) or (c)(3) of this section) which affect 
data validation for the current ozone season, but which were performed 
outside the ozone season (i.e., between October 1 of the previous 
calendar year and April 30 of the current calendar year), shall be 
reported in the quarterly report for the second quarter of the current 
calendar year (or in the report for the third calendar quarter of the 
current calendar

[[Page 40448]]

year, if the unit or stack does not operate in the second quarter).
    (7) * * *
    (ii) The applicable missing data procedures of Secs. 75.31 through 
75.37 shall be used, with one exception. When a fuel which has a 
significantly higher NOX emission rate than any of the 
fuel(s) combusted in prior ozone seasons is combusted in the unit, and 
no quality-assured NOX data have been recorded in the 
current, or any previous, ozone season while combusting the new fuel, 
the owner or operator shall substitute the maximum potential 
NOX emission rate, as defined in Sec. 72.2 of this chapter, 
from a NOX-diluent continuous emission monitoring system, or 
the maximum potential concentration of NOX, as defined in 
section 2.1.2.1 of appendix A to this part, from a NOX 
concentration monitoring system. The maximum potential value used shall 
be specific to the new fuel. The owner or operator shall substitute the 
maximum potential value for each hour of missing NOX data 
until the first hour that quality-assured NOX data are 
obtained while combusting the new fuel, and then shall resume use of 
the missing data routines in Secs. 75.31 through 75.37; and
    (iii) In order to apply the missing data routines described in 
Secs. 75.31 through 75.37 on an ozone season-only basis, the procedures 
in those sections shall be modified as follows:
    (A) The use of the initial missing data procedures in Sec. 75.31 
shall commence with the first unit operating hour in the first ozone 
season for which emissions data are required to be reported under 
Sec. 75.64.
    (B) In Sec. 75.31(a), the phrases ``During the first 720 quality-
assured monitor operating hours within the ozone season'' and ``during 
the first 2,160 quality-assured monitor operating hours within the 
ozone season'' apply respectively instead of the phrases ``During the 
first 720 quality-assured monitor operating hours'' and ``during the 
first 2,160 quality-assured monitor operating hours''.
    (C) In Sec. 75.32(a), the phrases ``the first 720 quality-assured 
monitor operating hours within the ozone season'' and ``the first 2,160 
quality-assured monitor operating hours within the ozone season'' 
apply, respectively, instead of the phrases ``the first 720 quality-
assured monitor operating hours'' and ``the first 2,160 quality-assured 
monitor operating hours''.
    (D) In Sec. 75.32(a)(1), the phrase ``Following initial 
certification, prior to completion of 3,672 unit (or stack) operating 
hours within the ozone season'' applies instead of the phrase ``Prior 
to completion of 8,760 unit (or stack) operating hours following 
initial certification''.
    (E) In Equation 8, the phrase ``Total unit operating hours within 
the ozone season'' applies instead of the phrase ``Total unit operating 
hours''.
    (F) In Sec. 75.32(a)(2), the phrase ``3,672 unit (or stack) 
operating hours within the ozone season'' applies instead of the phrase 
``8,760 unit (or stack) operating hours''.
    (G) In the numerator of Equation 9, the phrase ``Total unit 
operating hours within the ozone season'' applies instead of the phrase 
``Total unit operating hours'', and the phrase ``3,672 unit operating 
hours within the ozone season'' applies instead of the phrase ``8,760 
unit operating hours''. In the denominator of Equation 9, the number 
``3,672'' applies instead of ``8,760''.
    (H) Use the following instead of the first three sentences in 
Sec. 75.32(a)(3): ``When calculating percent monitor data availability 
using Equation 8 or 9, the owner or operator shall include all unit or 
stack operating hours within the ozone season, and all monitor 
operating hours within the ozone season for which quality-assured data 
were recorded by a certified primary monitor; a certified redundant or 
non-redundant backup monitor or a reference method for that unit; or by 
an approved alternative monitoring system under subpart E of this part. 
No hours from more than three years (26,280 clock hours) earlier shall 
be used in Equation 9. For a unit that has accumulated fewer than 3,672 
ozone season operating hours in the previous three years, use the 
following: in the numerator of Equation 9 use ``Total unit operating 
hours within the ozone season for which quality-assured data were 
recorded in the previous three years''; and in the denominator of 
Equation 9 use ``Total unit operating hours within the ozone season, in 
the previous three years'.''
    (I) In Sec. 75.33(a), the phrases ``the first 720 quality-assured 
monitor operating hours within the ozone season'' and ``the first 2,160 
quality-assured monitor operating hours within the ozone season'' 
apply, respectively, instead of the phrases ``the first 720 quality-
assured monitor operating hours'' and ``the first 2,160 quality-assured 
monitor operating hours''.
    (J) Instead of the last sentence of Sec. 75.33(a), use ``For the 
purposes of missing data substitution, the owner or operator of a unit 
shall use only quality-assured monitor operating hours of data that 
were recorded within the ozone season and no more than three years 
(26,280 clock hours) prior to the date and time of the missing data 
period.''
    (K) In Secs. 75.33(b), 75.33(c), 75.35, 75.36, and 75.37, the 
phrases ``720 quality-assured monitor operating hours within the ozone 
season'' and ``2,160 quality-assured monitor operating hours within the 
ozone season'' apply, respectively, instead of the phrases ``720 
quality-assured monitor operating hours'' and ``2,160 quality-assured 
monitor operating hours''.
    (L) In Sec. 75.34(a)(3), the phrase ``720 quality-assured monitor 
operating hours within the ozone season'' applies instead of ``720 
quality-assured monitor operating hours''.
    (8) * * *
    (ii) For units with add-on emission controls, using the missing 
data options in Sec. 75.34(a)(1) through Sec. 75.34(a)(4), the range of 
operating parameters for add-on emission controls, as described in 
Sec. 75.34(a) and information for verifying proper operation of the 
add-on emission controls during missing data periods, as described in 
Sec. 75.34(d).
* * * * *
    (10) Units may qualify to use the low mass emissions excepted 
monitoring methodology in Sec. 75.19 on an ozone season basis. In order 
to be allowed to use this methodology, a unit may not emit more than 50 
tons of NOX per ozone season, as provided in 
Sec. 75.19(a)(1)(i)(A)(3). If any low mass emissions unit fails to 
provide a demonstration that its ozone season NOX mass 
emissions are less than or equal to 50 tons, then the unit is 
disqualified from using the methodology. The owner or operator must 
install and certify any equipment needed to ensure that the unit is 
monitored using an acceptable methodology by December 31 of the 
following year.
* * * * *

Appendix A Section 1  [Amended]

    47. Appendix A to part 75 is amended by:
    a. In section heading 1.1 by revising the words ``Pollutant 
Concentration and CO2 or O2'' to read ``Gas'';
    b. In the second sentence of section 1.1 by revising the words 
``SO2 pollutant concentration monitor or NOX'' to 
read ``SO2, CO2, O2, or NOX 
concentration monitoring system or NOX-diluent'';
    c. In section heading 1.1.1 by removing the words ``Pollutant 
Concentration and CO2 or O2'';
    d. In section heading 1.1.2 by removing the words ``Pollutant 
Concentration and CO2 or O2 Gas'';
    e. In the fourth sentence of section 1.2 by revising the words 
``section 6.5.2'' to read ``section 6.5.2.1''; and
    f. Removing the first sentence of section 1.2.2.

[[Page 40449]]


    48. Appendix A to part 75 is amended by:
    a. Revising the second and third sentences of section 2.1;
    b. In the first sentence of section 2.1.1 by revising the words 
``this section 2'' to read ``sections 2.1.1.1 through 2.1.1.5 of this 
appendix'';
    c. Amending paragraph (a) of section 2.1.1.1 by adding two new 
sentences following the third sentence;
    d. Transferring Equations A-1a and A-1b and the variable equations 
and Note following them from paragraph (c) of section 2.1.1.1 to the 
end of paragraph (a) of section 2.1.1.1, and then revising the 
definition of the variable ``%S'' in Equation A-1b and adding a 
definition for the variable ``GCV'' after the definition of the 
variable ``%CO2w'' in Equation A-1b;
    e. Amending paragraph (b) of section 2.1.1.1 by adding a new 
sentence after the first sentence and by adding two new sentences to 
the end of the paragraph;
    f. Adding three sentences to the end of paragraph (a) of section 
2.1.1.2;
    g. Adding a new second sentence to paragraph (c) of section 2.1.1.2 
;
    h. Revising the definition of the variable ``MPC'' in Equation A-2 
of paragraph (c) of section 2.1.1.2;
    i. Revising the fifth and tenth sentences of section 2.1.1.3;
    j. In paragraph (c) of section 2.1.1.4 by adding a new second 
sentence;
    k. Removing the first sentence of paragraph (d) of section 2.1.1.4 
and adding three sentences in its place;
    l. Adding a new fifth sentence in paragraph (g) of section 2.1.1.4;
    m. In the first sentence of section 2.1.1.5, revising the words 
``paragraphs (a) and (b)'' to read ``paragraphs (a), (b), and (c)'';
    n. Removing the final sentence in paragraph (c) of section 2.1.1.5 
and adding a new final sentence;
    o. In section 2.1.2, revising the words ``section 2.1.2.1'' to read 
``sections 2.1.2.1 through 2.1.2.5 of this appendix'';
    p. In paragraph (a) of section 2.1.2.1 by adding a new second 
sentence, by revising the word ``part'' to read ``section'' in the 
first sentence of Option 1, by adding two new sentences at the end of 
Option 1, by adding a new sentence at the end of Option 2, by removing 
the word ``or'' from Option 3, by removing the period at the end of 
Option 4 and adding ``; or'' in its place; and by adding a new Option 
5;
    q. Adding a new final sentence to paragraph (b) of section 2.1.2.1;
    r. Adding two new sentences to the end of paragraph (c) of section 
2.1.2.1;
    s. Revising the first sentence of paragraph (d) of section 2.1.2.1;
    t. Revising paragraph (e) and Table 2-2 in section 2.1.2.1;
    u. Revising paragraph (a) of section 2.1.2.2;
    v. In the third sentence of paragraph (b) of section 2.1.2.2, 
adding the words ``(if applicable)'' after the words `` NOX 
emissions'';
    w. In paragraph (c) of section 2.1.2.2 by adding the words ``from 
the NOX component of a certified monitoring system,'' after 
the words ``quality assured data'' in the first sentence, by adding the 
words ``(for units with add-on NOX controls or turbines 
using dry low NOX technology)'' after the words 
``malfunction or'' in the second sentence, by adding the words ``(if 
applicable)'' after the words ``NOX emissions'' in the third 
sentence, and by adding a new second sentence after the first sentence;
    x. Revising the fourth sentence of paragraph (a) of section 
2.1.2.3;
    y. In the first sentence of paragraph (b) of section 2.1.2.3, 
revising the words ``requires a span'' to read ``requires or allows the 
use of a span value'';
    z. Revising the second sentence of paragraph (b) of section 2.1.2.4 
and adding a new sentence after the first sentence;
    aa. Removing the first sentence of paragraph (c) of section 2.1.2.4 
and adding three sentences in its place;
    bb. In paragraph (e) of section 2.1.2.4 by adding the words ``or, 
for units that use dry low NOX technology,'' after the word 
``SNCR),'';
    cc. Adding a new sentence after the fourth sentence in paragraph 
(f) of section 2.1.2.4;
    dd. In the third sentence of section 2.1.2.5, revising the words 
``paragraphs (a) and (b)'' to read ``paragraphs (a), (b), and (c)'';
    ee. In paragraph (c) of section 2.1.2.5, adding the word 
``diagnostic'' before the words ``linearity test'' in the fifth 
sentence and revising the final sentence;
    ff. Adding a sentence to the end of the section 2.1.3;
    gg. Adding two new sentences to the beginning of section 2.1.3.3;
    hh. Revising the third sentence of section 2.1.4.1;
    ii. In the fifth sentence of section 2.1.4.2, by adding the words 
``, as specified in section 2.2.2.1 of this appendix'' after the words 
``of the calibration span value'';
    jj. Adding a sentence to the end of section 2.1.6; and
    kk. Adding text to reserved section 2.2.
    The revisions and additions read as follows:

Appendix A to Part 75--Specifications and Test Procedures

* * * * *

2. Equipment Specifications

2.1  Instrument Span and Range

    * * * To meet these objectives, select the range such that the 
majority of the readings obtained during typical unit operation are 
kept, to the extent practicable, between 20.0 and 80.0 percent of 
the full-scale range of the instrument. These guidelines do not 
apply to: (1) SO2 readings obtained during the combustion 
of very low sulfur fuel (as defined in Sec. 72.2 of this chapter); 
(2) SO2 or NOX readings recorded on the high 
measurement range, for units with SO2 or NOX 
emission controls and two span values, unless the emission controls 
are operated seasonally (for example, only during the ozone season); 
or (3) SO2 or NOX readings less than 20.0 
percent of full-scale on the low measurement range for a dual span 
unit, provided that the maximum expected concentration (MEC), low-
scale span value, and low-scale range settings have been determined 
according to sections 2.1.1.2, 2.1.1.4(a), (b), and (g) of this 
appendix (for SO2), or according to sections 2.1.2.2, 
2.1.2.4(a) and (f) of this appendix (for NOX).

2.1.1  SO2 Pollutant Concentration Monitors

2.1.1.1  Maximum Potential Concentration

    (a) * * * If both the fuel sulfur content and the GCV are 
routinely determined from each fuel sample, the owner or operator 
may, as an alternative to using the highest individual percent 
sulfur and lowest individual GCV values in the MPC calculation, pair 
the sulfur content and GCV values from each sample analysis and 
calculate the ratio of percent sulfur to GCV (i.e., %S/GCV) for each 
pair of values. If this option is selected, the MPC shall be 
calculated using the highest %S/GCV ratio in Equation A-1a or A-1b.
* * * * *
(Eq. A-1b)
Where * * *

%S = Maximum sulfur content of fuel to be fired, wet basis, weight 
percent, as determined according to the applicable method in 
paragraph (c) of section 2.1.1.1.
* * * * *
GCV = Minimum gross calorific value of the fuel or blend to be 
combusted, based on historical fuel sampling and analysis data or, 
if applicable, based on the fuel contract specifications (Btu/lb). 
If based on fuel sampling and analysis, the GCV shall be determined 
according to the applicable method in paragraph (c) of section 
2.1.1.1.
* * * * *
    (b) * * * For the purposes of this section, 2.1.1.1, a 
``certified'' CEMS means a CEM system that has met the applicable 
certification requirements of either: This part, or part 60 of this 
chapter, or a State CEM program, or the source operating permit. * * 
* Note that the initial MPC value is subject to periodic review 
under section 2.1.1.5 of this appendix. If an MPC value is found to 
be either inappropriately high or low, the

[[Page 40450]]

MPC shall be adjusted in accordance with section 2.1.1.5, and 
corresponding span and range adjustments shall be made, if 
necessary.
* * * * *

2.1.1.2  Maximum Expected Concentration

    (a) * * * Each initial MEC value shall be documented in the 
monitoring plan required under Sec. 75.53. Note that each initial 
MEC value is subject to periodic review under section 2.1.1.5 of 
this appendix. If an MEC value is found to be either inappropriately 
high or low, the MEC shall be adjusted in accordance with section 
2.1.1.5, and corresponding span and range adjustments shall be made, 
if necessary.
* * * * *
    (c) * * * For the purposes of this section, 2.1.1.2, a 
``certified'' CEMS means a CEM system that has met the applicable 
certification requirements of either: This part, or part 60 of this 
chapter, or a State CEM program, or the source operating permit.
* * * * *
MPC = Maximum potential concentration (ppm), as determined by Eq. A-
1a or A-1b in section 2.1.1.1 of this appendix.
* * * * *

2.1.1.3  Span Value(s) and Range(s)

    * * * If the SO2 span concentration is s 500 ppm, the 
span value may either be rounded upward to the next highest multiple 
of 10 ppm, or to the next highest multiple of 100 ppm. * * * If an 
existing State, local, or federal requirement for span of an 
SO2 pollutant concentration monitor requires or allows 
the use of a span value lower than that required by this section or 
by section 2.1.1.4 of this appendix, the State, local, or federal 
span value may be used if a satisfactory explanation is included in 
the monitoring plan, unless span and/or range adjustments become 
necessary in accordance with section 2.1.1.5 of this appendix. * * *

2.1.1.4  Dual Span and Range Requirements

* * * * *
    (c) * * * Alternatively, if RATAs are performed and passed on 
both measurement ranges, the owner or operator may use two separate 
SO2 analyzers connected to separate probes and sample 
interfaces. * * *
    (d) The owner or operator shall designate the monitoring systems 
and components in the monitoring plan under Sec. 75.53 as follows: 
when a single probe and sample interface are used, either designate 
the low and high monitor ranges as separate SO2 
components of a single, primary SO2 monitoring system; 
designate the low and high monitor ranges as the SO2 
components of two separate, primary SO2 monitoring 
systems; designate the normal monitor range as a primary monitoring 
system and the other monitor range as a non-redundant backup 
monitoring system; or, when a single, dual-range SO2 
analyzer is used, designate the low and high ranges as a single 
SO2 component of a primary SO2 monitoring 
system (if this option is selected, use a special dual-range 
component type code, as specified by the Administrator, to satisfy 
the requirements of Sec. 75.53(e)(1)(iv)(D)). When two 
SO2 analyzers are connected to separate probes and sample 
interfaces, designate the analyzers as the SO2 components 
of two separate, primary SO2 monitoring systems. For 
units with SO2 controls, if the default high range value 
is used, designate the low range analyzer as the SO2 
component of a primary SO2 monitoring system. * * *
* * * * *
    (g) * * * However, if the default high range option in paragraph 
(f) of this section is selected, the full-scale of the low 
measurement range shall not exceed five times the MEC value (where 
the MEC is rounded upward to the next highest multiple of 10 ppm). * 
* *

2.1.1.5  Adjustment of Span and Range

* * * * *
    (c) * * * Use the data validation procedures in 
Sec. 75.20(b)(3), beginning with the hour in which the span is 
changed.

2.1.2  NOX Pollutant Concentration Monitors

* * * * *

2.1.2.1  Maximum Potential Concentration

    (a) * * * For the purposes of this section, 2.1.2.1, and section 
2.1.2.2 of this appendix, a ``blend'' means a frequently-used fuel 
mixture having a consistent composition (e.g., an oil and gas 
mixture where the relative proportions of the two fuels vary by no 
more than 10%, on average). * * *
    Option 1: * * * For cement kilns, use 2000 ppm as the MPC. For 
process heaters, use 200 ppm if the unit burns only gaseous fuel and 
500 ppm if the unit burns oil;
    Option 2: * * * For a new gas-fired or oil-fired combustion 
turbine, if a default MPC value of 50 ppm was previously selected 
from Table 2-2, that value may be used until March 31, 2003;
* * * * *
    Option 5: If a reliable estimate of the uncontrolled 
NOX emissions from the unit is available from the 
manufacturer, the estimated value may be used.
    (b) * * * As a second alternative, when the NOX MPC 
is determined from emission test results or from historical CEM 
data, as described in paragraphs (a), (d) and (e) of this section, 
quality-assured diluent gas (i.e., O2 or CO2) 
data recorded concurrently with the MPC may be used to calculate the 
MER.
    (c) * * * Note that whichever MPC option in paragraph 2.1.2.1(a) 
of this appendix is selected, the initial MPC value is subject to 
periodic review under section 2.1.2.5 of this appendix. If an MPC 
value is found to be either inappropriately high or low, the MPC 
shall be adjusted in accordance with section 2.1.2.5, and 
corresponding span and range adjustments shall be made, if 
necessary.
    (d) For units with add-on NOX controls (whether or 
not the unit is equipped with low-NOX burner technology), 
or for units equipped with dry low-NOX (DLN) technology, 
NOX emission testing may only be used to determine the 
MPC if testing can be performed either upstream of the add-on 
controls or during a time or season when the add-on controls are not 
in operation or when the DLN controls are not in the premixed (low-
NOX) mode. * * *
    (e) If historical CEM data are used to determine the MPC, the 
data must, for uncontrolled units or units equipped with low-
NOX burner technology and no other NOX 
controls, represent a minimum of 720 quality assured monitor 
operating hours from the NOX component of a certified 
monitoring system, obtained under various operating conditions 
including the minimum safe and stable load, normal load (including 
periods of high excess air at normal load), and maximum load. For 
the purposes of this section, 2.1.2.1, a ``certified'' CEMS means a 
CEM system that has met the applicable certification requirements of 
either: this part, or part 60 of this chapter, or a State CEM 
program, or the source operating permit. For a unit with add-on 
NOX controls (whether or not the unit is equipped with 
low-NOX burner technology), or for a unit equipped with 
dry low-NOX (DLN) technology, historical CEM data may 
only be used to determine the MPC if the 720 quality assured monitor 
operating hours of CEM data are collected upstream of the add-on 
controls or if the 720 hours of data include periods when the add-on 
controls are not in operation or when the DLN controls are not in 
the premixed (low-NOX mode). For units that do not 
produce electrical or thermal output, the data must represent the 
full range of normal process operation. The highest hourly 
NOX concentration in ppm shall be the MPC.
* * * * *

[[Page 40451]]

[GRAPHIC] [TIFF OMITTED] TR12JN02.008

2.1.2.2  Maximum Expected Concentration

    (a) Make an initial determination of the maximum expected 
concentration (MEC) of NOX during normal operation for 
affected units with add-on NOX controls of any kind 
(e.g., steam injection, water injection, SCR, or SNCR) and for 
turbines that use dry low-NOX technology. Determine a 
separate MEC value for each type of fuel (or blend) combusted in the 
unit, except for fuels that are only used for unit startup and/or 
flame stabilization. Calculate the MEC of NOX using 
Equation A-2, if applicable, inserting the maximum potential 
concentration, as determined using the procedures in section 2.1.2.1 
of this appendix. Where Equation A-2 is not applicable, set the MEC 
either by: (1) measuring the NOX concentration using the 
testing procedures in this section; (2) using historical CEM data 
over the previous 720 (or more) quality assured monitor operating 
hours; or (3) if the unit has add-on NOX controls or uses 
dry low NOX technology, and has a federally-enforceable 
permit limit for NOX concentration, the permit limit may 
be used as the MEC. Include in the monitoring plan for the unit each 
MEC value and the method by which the MEC was determined. Note that 
each initial MEC value is subject to periodic review under section 
2.1.2.5 of this appendix. If an MEC value is found to be either 
inappropriately high or low, the MEC shall be adjusted in accordance 
with section 2.1.2.5, and corresponding span and range adjustments 
shall be made, if necessary.
* * * * *
    (c) * * * For the purposes of this section, 2.1.2.2, a 
``certified'' CEMS means a CEM system that has met the applicable 
certification requirements of either: this part, or part 60 of this 
chapter, or a State CEM program, or the source operating permit. * * 
*

2.1.2.3 Span Value(s) and Range(s)

    (a) * * * If the NOX span concentration is s500 ppm, 
the span value may either be rounded upward to the next highest 
multiple of 10 ppm, or to the next highest multiple of 100 ppm. * * 
*
* * * * *

2.1.2.4  Dual Span and Range Requirements

* * * * *
    (b) * * * Two separate NOX analyzers connected to 
separate probes and sample interfaces may be used if RATAs are 
passed on both ranges. For units with add-on NOX emission 
controls (e.g., steam injection, water injection, SCR, or SNCR) or 
units equipped with dry low-NOX technology, the owner or 
operator may use a low range analyzer and a ``default high range 
value,'' as described in paragraph 2.1.2.4(e) of this section, in 
lieu of maintaining and quality assuring a high-scale range. * * *
    (c) The owner or operator shall designate the monitoring systems 
and components in the monitoring plan under Sec. 75.53 as follows: 
when a single probe and sample interface are used, either designate 
the low and high ranges as separate NOX components of a 
single, primary NOX monitoring system; designate the low 
and high ranges as the NOX components of two separate, 
primary NOX monitoring systems; designate the normal 
range as a primary monitoring system and the other range as a non-
redundant backup monitoring system; or, when a single, dual-range 
NOX analyzer is used, designate the low and high ranges 
as a single NOX component of a primary NOX 
monitoring system (if this option is selected, use a special dual-
range component type code, as specified by the Administrator, to 
satisfy the requirements of Sec. 75.53(e)(1)(iv)(D)). When two 
NOX analyzers are connected to separate probes and sample 
interfaces, designate the analyzers as the NOX components 
of two separate, primary NOX monitoring systems. For 
units with add-on NOX controls or units equipped with dry 
low-NOX technology, if the default high range value is 
used, designate the low range analyzer as the NOX 
component of the primary NOX monitoring system. * * *
* * * * *
    (f) * * * However, if the default high range option in paragraph 
(e) of this section is selected, the full-scale of the low 
measurement range shall not exceed five times the MEC value (where 
the MEC is rounded upward to the next highest multiple of 10 ppm). * 
* *

2.1.2.5  Adjustment of Span and Range

* * * * *
    (c) * * * Use the data validation procedures in 
Sec. 75.20(b)(3), beginning with the hour in which the span is 
changed.

2.1.3   CO2 and O2 Monitors

    * * * If a dual-range or autoranging diluent analyzer is 
installed, the analyzer may be represented in the monitoring plan as 
a single component, using a special component type code specified by 
the Administrator to satisfy the requirements of 
Sec. 75.53(e)(1)(iv)(D).
* * * * *

2.1.3.3  Adjustment of Span and Range

    The MPC and MEC values for diluent monitors are subject to the 
same periodic review as SO2 and NOX monitors 
(see sections 2.1.1.5 and 2.1.2.5 of this appendix). If an MPC or 
MEC value is found to be either inappropriately high or low, the MPC 
shall be adjusted and corresponding span and range adjustments shall 
be made, if necessary. * * *
* * * * *

2.1.4  Flow Monitors

* * * * *

2.1.4.1  Maximum Potential Velocity and Flow Rate

    * * * If using test values, use the highest average velocity 
(determined from the Method 2 traverses) measured at or near the 
maximum unit operating load (or, for units that do not produce 
electrical or thermal output, at the normal process operating 
conditions corresponding to the maximum stack gas flow rate). * * *
* * * * *

[[Page 40452]]

2.1.6  Maximum Potential Moisture Percentage

    * * * Alternatively, a default maximum potential moisture value 
of 15.0 percent H2O may be used.

2.2  Design for Quality Control Testing

2.2.1  Pollutant Concentration and CO2 or O2 
Monitors

    (a) Design and equip each pollutant concentration and 
CO2 or O2 monitor with a calibration gas 
injection port that allows a check of the entire measurement system 
when calibration gases are introduced. For extractive and dilution 
type monitors, all monitoring components exposed to the sample gas, 
(e.g., sample lines, filters, scrubbers, conditioners, and as much 
of the probe as practicable) are included in the measurement system. 
For in situ type monitors, the calibration must check against the 
injected gas for the performance of all active electronic and 
optical components (e.g. transmitter, receiver, analyzer).
    (b) Design and equip each pollutant concentration or 
CO2 or O2 monitor to allow daily 
determinations of calibration error (positive or negative) at the 
zero- and mid-or high-level concentrations specified in section 5.2 
of this appendix.

2.2.2  Flow Monitors

    Design all flow monitors to meet the applicable performance 
specifications.

2.2.2.1  Calibration Error Test

    Design and equip each flow monitor to allow for a daily 
calibration error test consisting of at least two reference values: 
Zero to 20 percent of span or an equivalent reference value (e.g., 
pressure pulse or electronic signal) and 50 to 70 percent of span. 
Flow monitor response, both before and after any adjustment, must be 
capable of being recorded by the data acquisition and handling 
system. Design each flow monitor to allow a daily calibration error 
test of the entire flow monitoring system, from and including the 
probe tip (or equivalent) through and including the data acquisition 
and handling system, or the flow monitoring system from and 
including the transducer through and including the data acquisition 
and handling system.

2.2.2.2  Interference Check

    (a) Design and equip each flow monitor with a means to ensure 
that the moisture expected to occur at the monitoring location does 
not interfere with the proper functioning of the flow monitoring 
system. Design and equip each flow monitor with a means to detect, 
on at least a daily basis, pluggage of each sample line and sensing 
port, and malfunction of each resistance temperature detector (RTD), 
transceiver or equivalent.
    (b) Design and equip each differential pressure flow monitor to 
provide an automatic, periodic back purging (simultaneously on both 
sides of the probe) or equivalent method of sufficient force and 
frequency to keep the probe and lines sufficiently free of 
obstructions on at least a daily basis to prevent velocity sensing 
interference, and a means for detecting leaks in the system on at 
least a quarterly basis (manual check is acceptable).
    (c) Design and equip each thermal flow monitor with a means to 
ensure on at least a daily basis that the probe remains sufficiently 
clean to prevent velocity sensing interference.
    (d) Design and equip each ultrasonic flow monitor with a means 
to ensure on at least a daily basis that the transceivers remain 
sufficiently clean (e.g., backpurging system) to prevent velocity 
sensing interference.

Appendix A to Part 75  [Amended]

    49. Appendix A to part 75 is amended by:
    a. Revising section heading and text of section 3.3.1;
    b. Revising paragraph (b) of section 3.3.2;
    c. In section heading 3.3.3 by removing the words ``Pollutant 
Concentration'';
    d. Revising the second sentence of section 3.3.3;
    e. Revising the section heading and text of section 3.3.4;
    f. Revising the second sentence of section 3.3.6; and
    g. Revising paragraph (b) of section 3.3.7.
    The revisions and additions read as follows:

3. Performance Specifications

* * * * *

3.3  Relative Accuracy

3.3.1  Relative Accuracy for SO2 Monitors

    (a) The relative accuracy for SO2 pollutant 
concentration monitors shall not exceed 10.0 percent except as 
provided in this section.
    (b) For affected units where the average of the reference method 
measurements of SO2 concentration during the relative 
accuracy test audit is less than or equal to 250.0 ppm, the 
difference between the mean value of the monitor measurements and 
the reference method mean value shall not exceed 15.0 
ppm, wherever the relative accuracy specification of 10.0 percent is 
not achieved.

3.3.2  Relative Accuracy for NOX-Diluent Continuous Emission 
Monitoring Systems

* * * * *
    (b) For affected units where the average of the reference method 
measurements of NOX emission rate during the relative 
accuracy test audit is less than or equal to 0.200 lb/mmBtu, the 
difference between the mean value of the continuous emission 
monitoring system measurements and the reference method mean value 
shall not exceed 0.020 lb/mmBtu, wherever the relative 
accuracy specification of 10.0 percent is not achieved.

3.3.3  Relative Accuracy for CO2 and O2 Monitors

    * * * The relative accuracy test results are also acceptable if 
the difference between the mean value of the CO2 or 
O2 monitor measurements and the corresponding reference 
method measurement mean value, calculated using equation A-7 of this 
appendix, does not exceed  1.0 percent CO2 or 
O2.

3.3.4  Relative Accuracy for Flow Monitors

    (a) The relative accuracy of flow monitors shall not exceed 10.0 
percent at any load (or operating) level at which a RATA is 
performed (i.e., the low, mid, or high level, as defined in section 
6.5.2.1 of this appendix).
    (b) For affected units where the average of the flow reference 
method measurements of gas velocity at a particular load (or 
operating) level of the relative accuracy test audit is less than or 
equal to 10.0 fps, the difference between the mean value of the flow 
monitor velocity measurements and the reference method mean value in 
fps at that level shall not exceed  2.0 fps, wherever 
the 10.0 percent relative accuracy specification is not achieved.
* * * * *

3.3.6  Relative Accuracy for Moisture Monitoring Systems

    * * * The relative accuracy test results are also acceptable if 
the difference between the mean value of the reference method 
measurements (in percent H2O) and the corresponding mean 
value of the moisture monitoring system measurements (in percent 
H2O), calculated using Equation A-7 of this appendix does 
not exceed  1.5 percent H2O.

3.3.7  Relative Accuracy for NOX Concentration Monitoring 
Systems

* * * * *
    (b) The relative accuracy for NOX concentration 
monitoring systems shall not exceed 10.0 percent. Alternatively, for 
affected units where the average of the reference method 
measurements of NOX concentration during the relative 
accuracy test audit is less than or equal to 250.0 ppm, the 
difference between the mean value of the continuous emission 
monitoring system measurements and the reference method mean value 
shall not exceed  15.0 ppm, wherever the 10.0 percent 
relative accuracy specification is not achieved.
* * * * *

Appendix A to Part 75  [Amended]

    50. Appendix A to part 75 is amended by:
    a. In the first paragraph of section 4, by adding a new second 
sentence; and
    b. In paragraph (3) of section 4, adding the words ``the 
appropriate'' before the word ``units'', removing the words ``of the 
standard'', and adding the word ``e.g.,'' before the words ``lb/hr''.
    The revisions and additions read as follows:

4. Data Acquisition and Handling Systems

    * * * These systems also shall have the capability of 
interpreting and converting the individual output signals from an 
SO2 pollutant concentration monitor, a flow monitor, a 
CO2 monitor, a NOX pollutant concentration 
monitor, and a NOX-diluent continuous emission monitoring 
system to produce a continuous readout of pollutant emission rates 
or pollutant mass emissions

[[Page 40453]]

(as applicable) in the appropriate units (e.g., lb/hr, lb/mmBtu, 
tons/hr).

* * * * *

Appendix A to Part 75  [Amended]

    51. Appendix A to part 75 is amended by:
    a. In the first sentence of paragraph (a) of section 6.2 by adding 
the word ``conditional'' before the words ``data validation 
procedures'';
    b. In section 6.3.1 by adding a new first sentence, by revising the 
word ``Measure'' in the new second sentence to read ``In all other 
cases, measure'', and by removing the word ``extended'' in the new 
third sentence;
    c. In the first sentence of paragraph (a) of section 6.3.1 by 
adding the word ``conditional'' before the words ``data validation 
procedures'';
    d. In section 6.3.2 by adding a new first sentence, by revising the 
word ``Perform'' in the new second sentence to read ``In all other 
cases, perform'', and by removing the word ``extended'' before the 
words ``unit outages'' in the new fifth sentence;
    e. In the first sentence of paragraph (a) of section 6.3.2 by 
adding the word ``conditional'' before the words ``data validation 
procedures'';
    f. Adding a new section 6.3.3;
    g. In the first sentence of paragraph (a) of section 6.4 by adding 
the word ``conditional'' before the words ``data validation 
procedures'';
    h. In the first sentence of section 6.5 by adding the word ``and'' 
after the words ``heat input,'' and by removing the words ``and each 
SO2-diluent continuous emission monitoring system'';
    i. Revising paragraphs (a) and (c) of section 6.5;
    j. In paragraph (b) of section 6.5 by adding the words ``(or 
operating)'' after the word ``load'';
    k. In the first sentence of paragraph (f)(1) of section 6.5 by 
adding the word ``conditional'' before the words ``data validation 
procedures'';
    l. In the second sentence of paragraph (g) of section 6.5 by 
removing the words ``SO2-diluent'';
    m. Revising paragraph (a) of section 6.5.1 and paragraph (a) of 
section 6.5.2;
    n. In paragraph (b) of section 6.5.2 by revising the words 
``section 6.5.2.1'' to read ``section 6.5.2.1(d)'';
    o. In paragraph (c) of section 6.5.2 by adding the words ``(or 
three operating levels)'' after the word ``level(s)'', and by adding 
the words ``or (e)'' after the words ``paragraph (b)'';
    p. In paragraph (d) of section 6.5.2 by adding the words ``(or 
operating levels)'' after the word ``level(s)'';
    q. Adding a new paragraph (e) to section 6.5.2;
    r. In section heading 6.5.2.1 by adding the words ``(or 
Operating)'' after the words ``Normal Load'';
    s. Revising paragraph (a) of section 6.5.2.1;
    t-v. In the first sentence of paragraph (b) of section 6.5.2.1 by 
revising the words ``30.0 to 60.0 percent'' to read `` 30.0 
percent, but s60.0 percent'' and revising the words ``60.0 to 100.0 
percent'' to read `` 60.0 percent'';
    w. Revising paragraphs (c) and (d) of section 6.5.2.1;
    x. Revising the first sentence of paragraph (e) of section 6.5.2.1;
    y. Revising section 6.5.2.2 section heading and text;
    z. Removing and reserving section 6.5.3;
    aa. In section 6.5.6 by removing the third sentence;
    bb. In paragraph (b)(2) of section 6.5.6 by revising the number 
``1.0'' to read ``1.2'';
    cc. Adding paragraph (b)(5) to section 6.5.6;
    dd. In the first sentence of paragraph (a) of sections 6.5.6.1 and 
6.5.6.2 by revising the words ``normal load'' to read ``the normal load 
level (or normal operating level)'';
    ee. In paragraph (c) of section 6.5.6.3 by removing the words 
``Sec. 75.56(a)(7) or'' and the words ``, as applicable'';
    ff. In paragraph (a) of section 6.5.7 by removing the words ``or 
SO2-diluent'' in the fourth sentence, by adding one sentence 
before, and two sentences after, the ninth sentence, and by removing 
the words ``Sec. 75.56(a)(5)(ix) and'' from the next to last sentence; 
and
    gg. In section 6.5.10 by adding a comma after the number ``7D'', 
and by adding a new sentence to the end of the paragraph.
    The revisions and additions read as follows:

6. Certification Tests and Procedures

* * * * *

6.3  7-Day Calibration Error Test

6.3.1  Gas Monitor 7-day Calibration Error Test

    The following monitors and ranges are exempted from the 7-day 
calibration error test requirements of this part: The 
SO2, NOX, CO2 and O2 
monitors installed on peaking units (as defined in Sec. 72.2 of this 
chapter); and any SO2 or NOX measurement range 
with a span value of 50 ppm or less. * * *
* * * * *

6.3.2  Flow Monitor 7-day Calibration Error Test

    Flow monitors installed on peaking units (as defined in 
Sec. 72.2 of this chapter) are exempted from the 7-day calibration 
error test requirements of this part. * * *
* * * * *
    6.3.3  For gas or flow monitors installed on peaking units, the 
exemption from performing the 7-day calibration error test applies 
as long as the unit continues to meet the definition of a peaking 
unit in Sec. 72.2 of this chapter. However, if at the end of a 
particular calendar year or ozone season, it is determined that 
peaking unit status has been lost, the owner or operator shall 
perform a diagnostic 7-day calibration error test of each monitor 
installed on the unit, by no later than December 31 of the following 
calendar year.
* * * * *

6.5  Relative Accuracy and Bias Tests (General Procedures)

* * * * *
    (a) Except as provided in Sec. 75.21(a)(5), perform each RATA 
while the unit (or units, if more than one unit exhausts into the 
flue) is combusting the fuel that is a normal primary or backup fuel 
for that unit (for some units, more than one type of fuel may be 
considered normal, e.g., a unit that combusts gas or oil on a 
seasonal basis). For units that co-fire fuels as the predominant 
mode of operation, perform the RATAs while co-firing. When relative 
accuracy test audits are performed on continuous emission monitoring 
systems installed on bypass stacks/ducts, use the fuel normally 
combusted by the unit (or units, if more than one unit exhausts into 
the flue) when emissions exhaust through the bypass stack/ducts.
* * * * *
    (c) For monitoring systems with dual ranges, perform the 
relative accuracy test on the range normally used for measuring 
emissions. For units with add-on SO2 or NOX 
controls that operate continuously rather than seasonally, or for 
units that need a dual range to record high concentration ``spikes'' 
during startup conditions, the low range is considered normal. 
However, for some dual span units (e.g., for units that use fuel 
switching or for which the emission controls are operated 
seasonally), provided that both monitor ranges are connected to a 
common probe and sample interface, either of the two measurement 
ranges may be considered normal; in such cases, perform the RATA on 
the range that is in use at the time of the scheduled test. If the 
low and high measurement ranges are connected to separate sample 
probes and interfaces, RATA testing on both ranges is required.
* * * * *

6.5.1  Gas Monitoring System RATAs (Special Considerations)

    (a) Perform the required relative accuracy test audits for each 
SO2 or CO2 pollutant concentration monitor, 
each CO2 or O2 diluent monitor used to 
determine heat input, each NOX-diluent continuous 
emission monitoring system, and each NOX concentration 
monitoring system used to determine NOX mass emissions, 
as defined in Sec. 75.71(a)(2), at the normal load level or normal 
operating level for the unit (or combined units, if common stack), 
as defined

[[Page 40454]]

in section 6.5.2.1 of this appendix. If two load levels or operating 
levels have been designated as normal, the RATAs may be done at 
either load level.
* * * * *

6.5.2  Flow Monitor RATAs (Special Considerations)

    (a) Except as otherwise provided in paragraph (b) or (e) of this 
section, perform relative accuracy test audits for the initial 
certification of each flow monitor at three different exhaust gas 
velocities (low, mid, and high), corresponding to three different 
load levels or operating levels within the range of operation, as 
defined in section 6.5.2.1 of this appendix. For a common stack/
duct, the three different exhaust gas velocities may be obtained 
from frequently used unit/load or operating level combinations for 
the units exhausting to the common stack. Select the three exhaust 
gas velocities such that the audit points at adjacent load or 
operating levels (i.e., low and mid or mid and high), in megawatts 
(or in thousands of lb/hr of steam production or in ft/sec, as 
applicable), are separated by no less than 25.0 percent of the range 
of operation, as defined in section 6.5.2.1 of this appendix.
* * * * *
    (e) For flow monitors installed on units that do not produce 
electrical or thermal output, the flow RATAs for initial 
certification or recertification may be done at fewer than three 
operating levels, if:
    (1) The owner or operator provides a technical justification in 
the hardcopy portion of the monitoring plan for the unit required 
under Sec. 75.53(e)(2), demonstrating that the unit operates at only 
one level or two levels during normal operation (excluding unit 
startup and shutdown). Appropriate documentation and data must be 
provided to support the claim of single-level or two-level 
operation; and
    (2) The justification provided in paragraph (e)(1) of this 
section is deemed to be acceptable by the permitting authority.
    6.5.2.1  Range of Operation and Normal Load (or Operating) 
Level(s)
    (a) The owner or operator shall determine the upper and lower 
boundaries of the ``range of operation'' as follows for each unit 
(or combination of units, for common stack configurations) 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:
    (1) For affected units that produce electrical output (in 
megawatts) or thermal output (in klb/hr of steam production), the 
lower boundary of the range of operation of a unit shall be the 
minimum safe, stable loads for any of the units discharging through 
the stack. Alternatively, for a group of frequently-operated units 
that serve a common stack, the sum of the minimum safe, stable loads 
for the individual units may be used as the lower boundary of the 
range of operation. The upper boundary of the range of operation of 
a unit shall be the maximum sustainable load. The ``maximum 
sustainable load'' is the higher of either: the nameplate or rated 
capacity of the unit, less any physical or regulatory limitations or 
other deratings; or the highest sustainable load, based on at least 
four quarters of representative historical operating data. For 
common stacks, the maximum sustainable load is the sum of all of the 
maximum sustainable loads of the individual units discharging 
through the stack, unless this load is unattainable in practice, in 
which case use the highest sustainable combined load for the units 
that discharge through the stack. Based on at least four quarters of 
representative historical operating data. The load values for the 
unit(s) shall be expressed either in units of megawatts of thousands 
of lb/hr of steam load; or
    (2) For affected units that do not produce electrical or thermal 
output, the lower boundary of the range of operation shall be the 
minimum expected flue gas velocity (in ft/sec) during normal, stable 
operation of the unit. The upper boundary of the range of operation 
shall be the maximum potential flue gas velocity (in ft/sec) as 
defined in section 2.1.4.1 of this appendix. The minimum expected 
and maximum potential velocities may be derived from the results of 
reference method testing or by using Equation A-3a or A-3b (as 
applicable) in section 2.1.4.1 of this appendix. If Equation A-3a or 
A-3b is used to determine the minimum expected velocity, replace the 
word ``maximum'' with the word ``minimum'' in the definitions of 
``MPV,'' ``Hf,'' ``% O2d,'' and ``% 
H2O,'' and replace the word ``minimum'' with the word 
``maximum'' in the definition of ``CO2d.'' Alternatively, 
0.0 ft/sec may be used as the lower boundary of the range of 
operation.
* * * * *
    (c) Units that do not produce electrical or thermal output are 
exempted from the requirements of this paragraph, (c). The owner or 
operator shall identify, for each affected unit or common stack 
(except for peaking units), the ``normal'' load level or levels 
(low, mid or high), based on the operating history of the unit(s). 
To identify the normal load level(s), the owner or operator shall, 
at a minimum, determine the relative number of operating hours at 
each of the three load levels, low, mid and high over the past four 
representative operating quarters. The owner or operator shall 
determine, to the nearest 0.1 percent, the percentage of the time 
that each load level (low, mid, high) has been used during that time 
period. A summary of the data used for this determination and the 
calculated results shall be kept on-site in a format suitable for 
inspection. For new units or newly-affected units, the data analysis 
in this paragraph may be based on fewer than four quarters of data 
if fewer than four representative quarters of historical load data 
are available. Or, if no historical load data are available, the 
owner or operator may designate the normal load based on the 
expected or projected manner of operating the unit. However, in 
either case, once four quarters of representative data become 
available, the historical load analysis shall be repeated.
    (d) Determination of normal load (or operating level)
    (1) Based on the analysis of the historical load data described 
in paragraph (c) of this section, the owner or operator shall, for 
units that produce electrical or thermal output, designate the most 
frequently used load level as the normal load level for the unit (or 
combination of units, for common stacks). The owner or operator may 
also designate the second most frequently used load level as an 
additional normal load level for the unit or stack. For peaking 
units, normal load designations are unnecessary; the entire 
operating load range shall be considered normal. If the manner of 
operation of the unit changes significantly, such that the 
designated normal load(s) or the two most frequently used load 
levels change, the owner or operator shall repeat the historical 
load analysis and shall redesignate the normal load(s) and the two 
most frequently used load levels, as appropriate. A minimum of two 
representative quarters of historical load data are required to 
document that a change in the manner of unit operation has occurred. 
Update the electronic monitoring plan whenever the normal load 
level(s) and the two most frequently-used load levels are 
redesignated.
    (2) For units that do not produce electrical or thermal output, 
the normal operating level(s) shall be determined using sound 
engineering judgment, based on knowledge of the unit and operating 
experience with the industrial process.
    (e) The owner or operator shall report the upper and lower 
boundaries of the range of operation for each unit (or combination 
of units, for common stacks), in units of megawatts or thousands of 
lb/hr of steam production or ft/sec (as applicable), in the 
electronic quarterly report required under Sec. 75.64. * * *

6.5.2.2  Multi-Load (or Multi-Level) Flow RATA Results

    For each multi-load (or multi-level) flow RATA, calculate the 
flow monitor relative accuracy at each operating level. If a flow 
monitor relative accuracy test is failed or aborted due to a problem 
with the monitor on any level of a 2-level (or 3-level) relative 
accuracy test audit, the RATA must be repeated at that load (or 
operating) level. However, the entire 2-level (or 3-level) relative 
accuracy test audit does not have to be repeated unless the flow 
monitor polynomial coefficients or K-factor(s) are changed, in which 
case a 3-level RATA is required (or, a 2-level RATA, for units 
demonstrated to operate at only two levels, under section 6.5.2(e) 
of this appendix).

6.5.3  [Reserved]

* * * * *

6.5.6  Reference Method Traverse Point Selection

* * * * *
    (b) * * *
    (5) If Method 7E is used as the reference method for the RATA of 
a NOX CEMS installed on a combustion turbine, the 
reference method measurements may be made at the sampling points 
specified in section 6.1.2 of Method 20 in appendix A to part 60 of 
this chapter.
* * * * *

[[Page 40455]]

6.5.7  Sampling Strategy

    (a) * * * Also, allow sufficient measurement time to ensure that 
stable temperature readings are obtained at each traverse point, 
particularly at the first measurement point at each sample port, 
when a probe is moved sequentially from port-to-port. * * * 
Alternatively, moisture measurements for molecular weight 
determination may be performed before and after a series of flow 
RATA runs at a particular load level (low, mid, or high), provided 
that the time interval between the two moisture measurements does 
not exceed three hours. If this option is selected, the results of 
the two moisture determinations shall be averaged arithmetically and 
applied to all RATA runs in the series. * * *
* * * * *

6.5.10  Reference Methods

    * * * Notwithstanding these requirements, Method 20 may be used 
as the reference method for relative accuracy test audits of 
NOX monitoring systems installed on combustion turbines.

Appendix A to part 75  [Amended]

    52. Appendix A to part 75 is amended by:
    a. In section heading 7.3 by revising the words ``SO2-
Diluent Continuous Emission'' to read ``O2 Monitors, 
NOX Concentration'';
    b. Revising the first sentence of section 7.3;
    c. Revising the variable
    [GRAPHIC] [TIFF OMITTED] TR12JN02.009
    
in the list of defined variables for Eq. A-7 to read
[GRAPHIC] [TIFF OMITTED] TR12JN02.010

and removing the final sentence of section 7.3.1;
    d. In the section heading and text of section 7.4 by revising the 
word ``NOX'' to read ``NOX-diluent'';
    e. In section heading 7.4.2 by removing the words ``(Monitoring 
System)'';
    f. In the second sentence of section 7.6.1 by adding the words ``or 
NOX'' after both occurrences of the word ``SO2'' 
and, in the last sentence, by revising the word'' NOX'' to 
read ``NOX-diluent'';
    g. Adding a new paragraph (g) to section 7.6.5;
    h. In paragraph (a) of section 7.7 by removing the fourth sentence;
    i. Revising paragraph (b) of section 7.7;
    j. In the variable ``(Heat Input)avg'' under Eq. A-13a 
in paragraph (c) of section 7.7 by adding a second and third sentence 
to the definition;
    k. In paragraph (d) of section 7.7 by adding the words ``(i.e., the 
arithmetic average of the diluent gas concentrations for all clock 
hours in which a RATA run was performed)'' to the end of the sentence;
    l. In section 7.8 by designating the existing text as paragraph 
(a), removing the first sentence, adding the words ``and section 2.2.5 
of appendix B to this part'' to the end of the second sentence, and 
adding a new paragraph (b); and
    m. Revising Figure 6.
    The revisions and additions read as follows:

7. Calculations

* * * * *

7.3  Relative Accuracy for SO2 and CO2 
Pollutant Concentration Monitors, O2 Monitors, 
NOX Concentration Monitoring Systems, and Flow Monitors

    Analyze the relative accuracy test audit data from the reference 
method tests for SO2 and CO2 pollutant 
concentration monitors, O2 monitors used only for heat 
input rate determination, NOX concentration monitoring 
systems used to determine NOX mass emissions under 
subpart H of this part, and flow monitors using the following 
procedures.* * *
* * * * *

7.6  Bias Test and Adjustment Factor

* * * * *
7.6.5  Bias Adjustment
* * * * *
    (g) For units that do not produce electrical or thermal output, the 
provisions of paragraphs (a) through (f) of this section apply, except 
that the terms, ``single-load'', ``2-load'', ``3-load'', and ``load 
level'' shall be replaced, respectively, with the terms, ``single-
level'', ``2-level'', ``3-level'', and ``operating level''.

7.7  Reference Flow-to-Load Ratio or Gross Heat Rate

* * * * *
    (b) In Equation A-13, for a common stack, determine Lavg 
by summing, for each RATA run, the operating loads of all units 
discharging through the common stack, and then taking the arithmetic 
average of the summed loads. For a unit that discharges its emissions 
through multiple stacks, either determine a single value of 
Qref for the unit or a separate value of Qref for 
each stack. In the former case, calculate Qref by summing, 
for each RATA run, the volumetric flow rates through the individual 
stacks and then taking the arithmetic average of the summed RATA run 
flow rates. In the latter case, calculate the value of Qref 
for each stack by taking the arithmetic average, for all RATA runs, of 
the flow rates through the stack. For a unit with a multiple stack 
discharge configuration consisting of a main stack and a bypass stack 
(e.g., a unit with a wet SO2 scrubber), determine 
Qref separately for each stack at the time of the normal 
load flow RATA. Round off the value of Rref to two decimal 
places.
    (c) * * *
Where:

    * * *
(Heat Input)avg=* * * For multiple stack configurations, if 
the reference GHR value is determined separately for each stack, use 
the hourly heat input measured at each stack. If the reference GHR is 
determined at the unit level, sum the hourly heat inputs measured at 
the individual stacks.
* * * * *

7.8  Flow-to-Load Test Exemptions

* * * * *

    (b) Units that do not produce electrical output (in megawatts) or 
thermal output (in klb of steam per hour) are exempted from the flow-
to-load ratio test requirements of section 7.7 of this appendix and 
section 2.2.5 of appendix B to this part.
* * * * *

[[Page 40456]]

[GRAPHIC] [TIFF OMITTED] TR12JN02.011

* * * * *

    53. Appendix B to part 75 is amended by:
    a. Adding a fourth sentence to section 1;
    b. Removing the word ``and'' before the words ``section 2.1.5.1'' 
in the second sentence of section 1.3.1; and

[[Page 40457]]

    c. Removing the words ``unit manufacturer's'' in the first sentence 
of section 1.3.6.
    The revisions and additions read as follows:

Appendix B to Part 75--Quality Assurance and Quality Control Procedures

1. Quality Assurance/Quality Control Program

    * * * Electronic storage of the information in the QA/QC plan is 
permissible, provided that the information can be made available in 
hardcopy upon request during an audit.

* * * * *

Appendix B to Part 75  [Amended]

    54. Appendix B to Part 75 is amended by:
    a. In paragraph (a) of section 2.1.4 by removing the words ``(or 
exceeds 10 ppm, for span values <200 ppm)'' in the first sentence, by 
adding the words ``of appendix A to this part'' after ``Equation A-6'' 
in the second sentence, and by adding a new third sentence after the 
second sentence;
    b. In the first sentence of section 2.2.1 by revising the word 
``Perform'' to read ``Unless a particular monitor (or monitoring range) 
is exempted under this paragraph or under section 6.2 of appendix A to 
this part, perform'';
    c. In section 2.2.2, by revising the words ``section 2.2.3(f)'' to 
read ``section 2.2.3(g)'';
    d. In paragraph (c) of section 2.2.3 by adding a third sentence;
    e. In the second sentence of paragraph (e) of section 2.2.3 by 
removing the words ``or SO2-diluent'';
    f. In paragraph (b) of section 2.2.4 by adding the words ``first 
unit operating'' before the words ``hour following'' in the first 
sentence;
    g. In paragraph (a) of section 2.2.5 by removing the first 
sentence, revising the words ``by an approved petition in accordance 
with'' in the second sentence to read ``from the flow-to-load ratio 
test under'', and by adding a final sentence before Eq. B-1;
    h. Revising the third sentence of paragraph (a)(1) of section 
2.2.5;
    i. In paragraph (a)(3) of section 2.2.5 by adding the word ``rate'' 
after the words ``heat input'';
    j. In paragraph (a)(4) of section 2.2.5 by adding the word 
``acceptable'' after each occurrence of the number ``168'', and by 
adding in the third sentence the words ``(i.e., at loads within 
 10 percent of Lavg)'' after the word ``rates'';
    k. Adding a sentence at the end of paragraph (b)(4) of section 
2.2.5;
    l. Revising the introductory text of paragraph (c) of section 
2.2.5;
    m. In paragraph (c)(1) of section 2.2.5 by removing the semicolon 
and adding in its place a period after the word ``sub-bituminous)'' and 
by adding a new third sentence;
    n. In paragraph (c)(8) of section 2.2.5 by removing the second 
sentence and adding two new sentences in its place;
    o. In the first sentence of the introductory paragraph to section 
2.2.5.1 by revising the words ``two weeks'' to read ``14 unit operating 
days'';
    p. Revising paragraph (b) of section 2.2.5.1;
    q. Revising section 2.2.5.2;
    r. In paragraph (a) of section 2.2.5.3 by adding the words ``either 
the hour in which the abbreviated flow-to-load test is passed, or'' 
after the word ``until'' in the second sentence, and by revising the 
word ``The'' at the beginning of the third sentence to read ``If the 
latter option is selected, the'';
    s. In the second sentence of paragraph (b) of section 2.2.5.3 by 
revising the number ``5.0'' to read ``10.0'';
    t. In paragraph (c) of section 2.2.5.3 by adding the words ``(if 
applicable)'' after the words ``flow-to-load test'' in the second 
sentence and after the words ``flow monitor'' in the third sentence;
    u. Removing and reserving paragraphs (b) and (g) of section 
2.3.1.2;
    v. Removing the words ``On and after January 1, 2000,'' and 
capitalizing the letter ``t'' in the first instance of ``the'' in 
paragraph (c) of section 2.3.1.2;
    w. In paragraph (d) of section 2.3.1.2 by adding the words ``, as 
measured by the reference method during the RATA'' after the words `` < 
10.0 fps'' and by removing the words ``(10.0 percent if prior to 
January 1, 2000)'';
    x. In paragraph (e) of section 2.3.1.2 by adding the words 
``reference method'' before the word ``concentrations'', and by adding 
the words ``) during the RATA'' after the words ``250 ppm'';
    y. In paragraph (f) of section 2.3.1.2 by adding the words 
``measured by the reference method during the RATA'' after the words 
``average NOX emission rate'';
    z. In section heading 2.3.1.3 by adding the words ``(or 
Operating)'' after the words ``RATA Load'';
    aa. In paragraph (a) of section 2.3.1.3 by adding the words ``(or 
operating level)'' after each instance of the words ``load level'', 
adding the words ``(or operating levels)'' after the words ``load 
levels'', and by revising the words ``section 6.5.2.1'' to read 
``section 6.5.2.1(d)'';
    bb. Revising paragraphs (b) and (c) of section 2.3.1.3;
    cc. In paragraph (c) of section 2.3.2 by adding a new third 
sentence;
    dd. In paragraph (d) of section 2.3.2 by adding the words ``(or 
single level)'' after the word ``single-load'' and adding the words 
``(or multiple level)'' after the word ``multiple-load'', and in 
paragraphs (d) and (f) of section 2.3.2 by adding the words ``(or 
operating levels(s))'' after the words ``load level(s)'', the words 
``(or 3-level)'' after the words ``3-load'', and the words ``, except 
as otherwise provided in section 2.3.1.3(c)(5) of this appendix'' 
immediately before the period at the end of each paragraph;
    ee. By revising paragraph (e) of section 2.3.2;
    ff. Revising paragraph (a) of section 2.3.3;
    gg. Revising paragraph (b) of section 2.4;
    hh. Revising footnote 2 of Figure 1 to Appendix B of Part 75; and
    ii. In Figure 2 to Appendix B of Part 75 by removing the entire 
entry for ``Flow (Phase I)'' and revising the phrase ``Flow (Phase 
II)'' in the first column to read ``Flow''.
    The revisions and additions read as follows:

2. Frequency of Testing

* * * * *

2.1  Daily Assessments

* * * * *

2.1.4  Data Validation

    (a) * * * In addition, an SO2 or NOX 
monitor for which the calibration error exceeds 5.0 percent of the 
span value shall not be considered out-of-control if 3R-A3 in 
Equation A-6 does not exceed 5.0 ppm (for span values s50 ppm), or 
if 3R-A3 does not exceed 10.0 ppm (for span values  50 
ppm, but s 200 ppm). * * *
* * * * *

2.2  Quarterly Assessments

* * * * *

2.2.3  Data Validation

* * * * *
    (c) * * * If a routine daily calibration error test is performed 
and passed just prior to a linearity test (or during a linearity 
test period) and a mathematical correction factor is automatically 
applied by the DAHS, the correction factor shall be applied to all 
subsequent data recorded by the monitor, including the linearity 
test data.
* * * * *

2.2.5  Flow-to-Load Ratio or Gross Heat Rate Evaluation

    (a) * * * Alternatively, for the reasons stated in paragraphs 
(c)(1) through (c)(6) of this section, the owner or operator may 
exclude from the data analysis certain hours within 10.0 
percent of Lavg and may calculate Rh values 
for only the remaining hours.
* * * * *
    (1) * * * For a unit that discharges its emissions through 
multiple stacks or that monitors its emissions in multiple

[[Page 40458]]

breechings, Qh will be either the combined hourly 
volumetric flow rate for all of the stacks or ducts (if the test is 
done on a unit basis) or the hourly flow rate through each stack 
individually (if the test is performed separately for each stack). * 
* *
* * * * *
    (b) * * *
    (4) * * * If Ef is above these limits, the owner or 
operator shall either: implement Option 1 in section 2.2.5.1 of this 
appendix; perform a RATA in accordance with Option 2 in section 
2.2.5.2 of this appendix; or (if applicable) re-examine the hourly 
data used for the flow-to-load or GHR analysis and recalculate 
Ef, after excluding all non-representative hourly flow 
rates, as provided in paragraph (c) of this section.
    (c) Recalculation of Ef. If the owner or operator did 
not exclude any hours within 10 percent of 
Lavg from the original data analysis and chooses to 
recalculate Ef, the flow rates for the following hours 
are considered non-representative and may be excluded from the data 
analysis:
    (1) * * * Also, for units that co-fire different types of fuels, 
if the reference RATA was done while co-firing, then hours in which 
a single fuel was combusted may be excluded from the data analysis 
as different fuel hours (and vice-versa for co-fired hours, if the 
reference RATA was done while combusting only one type of fuel);
* * * * *
    (8) * * * If, however, Ef is still above the 
applicable limit, data from the monitor shall be declared out-of-
control, beginning with the first unit operating hour following the 
quarter in which Ef exceeded the applicable limit. 
Alternatively, if a probationary calibration error test is performed 
and passed according to Sec. 75.20(b)(3)(ii), data from the monitor 
may be declared conditionally valid following the quarter in which 
Ef exceeded the applicable limit. * * *

2.2.5.1  Option 1

* * * * *
    (b) If a problem with the flow monitor is identified through the 
investigation (including the need to re-linearize the monitor by 
changing the polynomial coefficients or K factor(s)), data from the 
monitor are considered invalid back to the first unit operating hour 
after the end of the calendar quarter for which Ef was 
above the applicable limit. If the option to use conditional data 
validation was selected under section 2.2.5(c)(8) of this appendix, 
all conditionally valid data shall be invalidated, back to the first 
unit operating hour after the end of the calendar quarter for which 
Ef was above the applicable limit. Corrective actions 
shall be taken. All corrective actions (e.g., non-routine 
maintenance, repairs, major component replacements, re-linearization 
of the monitor, etc.) shall be documented in the operation and 
maintenance records for the monitor. The owner or operator then 
shall either complete the abbreviated flow-to-load test in section 
2.2.5.3 of this appendix, or, if the corrective action taken has 
required relinearization of the flow monitor, shall perform a 3-load 
RATA. The conditional data validation procedures in Sec. 75.20(b)(3) 
may be applied to the 3-load RATA.

2.2.5.2  Option 2

    Perform a single-load RATA (at a load designated as normal under 
section 6.5.2.1 of appendix A to this part) of each flow monitor for 
which Ef is outside of the applicable limit. If the RATA 
is passed hands-off, in accordance with section 2.3.2(c) of this 
appendix, no further action is required and the out-of-control 
period for the monitor ends at the date and hour of completion of a 
successful RATA, unless the option to use conditional data 
validation was selected under section 2.2.5(c)(8) of this appendix. 
In that case, all conditionally valid data from the monitor are 
considered to be quality-assured, back to the first unit operating 
hour following the end of the calendar quarter for which the 
Ef value was above the applicable limit. If the RATA is 
failed, all data from the monitor shall be invalidated, back to the 
first unit operating hour following the end of the calendar quarter 
for which the Ef value was above the applicable limit. 
Data from the monitor remain invalid until the required RATA has 
been passed. Alternatively, following a failed RATA and corrective 
actions, the conditional data validation procedures of 
Sec. 75.20(b)(3) may be used until the RATA has been passed. If the 
corrective actions taken following the failed RATA included 
adjustment of the polynomial coefficients or K-factor(s) of the flow 
monitor, a 3-level RATA is required, except as otherwise specified 
in section 2.3.1.3 of this appendix.
* * * * *

2.3  Semiannual and Annual Assessments

* * * * *

2.3.1  Relative Accuracy Test Audit (RATA)

* * * * *

2.3.1.3  RATA Load (or Operating) Levels and Additional RATA 
Requirements

* * * * *
    (b) For flow monitors installed on peaking units and bypass 
stacks, and for flow monitors that qualify to perform only single-
level RATAs under section 6.5.2(e) of appendix A to this part, all 
required semiannual or annual relative accuracy test audits shall be 
single-load (or single-level) audits at the normal load (or 
operating level), as defined in section 6.5.2.1(d) of appendix A to 
this part.
    (c) For all other flow monitors, the RATAs shall be performed as 
follows:
    (1) An annual 2-load (or 2-level) flow RATA shall be done at the 
two most frequently used load levels (or operating levels), as 
determined under section 6.5.2.1(d) of appendix A to this part, or 
(if applicable) at the operating levels determined under section 
6.5.2(e) of appendix A to this part. Alternatively, a 3-load (or 3-
level) flow RATA at the low, mid, and high load levels (or operating 
levels), as defined under section 6.5.2.1(b) of appendix A to this 
part, may be performed in lieu of the 2-load (or 2-level) annual 
RATA.
    (2) If the flow monitor is on a semiannual RATA frequency, 2-
load (or 2-level) flow RATAs and single-load (or single-level) flow 
RATAs at the normal load level (or normal operating level) may be 
performed alternately.
    (3) A single-load (or single-level) annual flow RATA may be 
performed in lieu of the 2-load (or 2-level) RATA if the results of 
an historical load data analysis show that in the time period 
extending from the ending date of the last annual flow RATA to a 
date that is no more than 21 days prior to the date of the current 
annual flow RATA, the unit (or combination of units, for a common 
stack) has operated at a single load level (or operating level) 
(low, mid, or high), for r 85.0 percent of the time. Alternatively, 
a flow monitor may qualify for a single-load (or single-level) RATA 
if the 85.0 percent criterion is met in the time period extending 
from the beginning of the quarter in which the last annual flow RATA 
was performed through the end of the calendar quarter preceding the 
quarter of current annual flow RATA.
    (4) A 3-load (or 3-level) RATA, at the low-, mid-, and high-load 
levels (or operating levels), as determined under section 6.5.2.1 of 
appendix A to this part, shall be performed at least once every five 
consecutive calendar years, except for flow monitors that are 
exempted from 3-load (or 3-level) RATA testing under section 
6.5.2(b) or 6.5.2(e) of appendix A to this part.
    (5) A 3-load (or 3-level) RATA is required whenever a flow 
monitor is re-linearized, i.e., when its polynomial coefficients or 
K factor(s) are changed, except for flow monitors that are exempted 
from 3-load (or 3-level) RATA testing under section 6.5.2(b) or 
6.5.2(e) of appendix A to this part. For monitors so exempted under 
section 6.5.2(b), a single-load flow RATA is required. For monitors 
so exempted under section 6.5.2(e), either a single-level RATA or a 
2-level RATA is required, depending on the number of operating 
levels documented in the monitoring plan for the unit.
    (6) For all multi-level flow audits, the audit points at 
adjacent load levels or at adjacent operating levels (e.g., mid and 
high) shall be separated by no less than 25.0 percent of the ``range 
of operation,'' as defined in section 6.5.2.1 of appendix A to this 
part.
* * * * *

2.3.2  Data Validation

* * * * *
    (c) * * * If a routine daily calibration error test is performed 
and passed just prior to a RATA (or during a RATA test period) and a 
mathematical correction factor is automatically applied by the DAHS, 
the correction factor shall be applied to all subsequent data 
recorded by the monitor, including the RATA test data. * * *
* * * * *
    (e) For a RATA performed using the option in paragraph (b)(1) or 
(b)(2) of this section, if the RATA is failed (that is, if the 
relative accuracy exceeds the applicable specification in section 
3.3 of appendix A to this part) or if the RATA is aborted prior to 
completion due to a problem with the CEMS, then the CEMS is out-of-
control and all emission data from the CEMS are invalidated 
prospectively from the hour in which the RATA is failed or aborted. 
Data from the CEMS remain invalid until the hour of completion of a 
subsequent RATA that meets the applicable specification in section 
3.3 of appendix A to

[[Page 40459]]

this part. If the option in paragraph (b)(3) of this section to use 
the data validation procedures and associated timelines in 
Secs. 75.20(b)(3)(ii) through(b)(3)(ix) has been selected, the 
beginning and end of the out-of-control period shall be determined 
in accordance with Sec. 75.20(b)(3)(vii)(A) and (B). Note that when 
a RATA is aborted for a reason other than monitoring system 
malfunction (see paragraph (h) of this section), this does not 
trigger an out-of-control period for the monitoring system.
* * * * *

2.3.3  RATA Grace Period

    (a) The owner or operator has a grace period of 720 consecutive 
unit operating hours, as defined in Sec. 72.2 of this chapter (or, 
for CEMS installed on common stacks or bypass stacks, 720 
consecutive stack operating hours, as defined in Sec. 72.2 of this 
chapter), in which to complete the required RATA for a particular 
CEMS whenever:
    (1) A required RATA has not been performed by the end of the QA 
operating quarter in which it is due; or
    (2) Five consecutive calendar years have elapsed without a 
required 3-load flow RATA having been conducted; or
    (3) For a unit which is conditionally exempted under 
Sec. 75.21(a)(7) from the SO2 RATA requirements of this 
part, an SO2 RATA has not been completed by the end of 
the calendar quarter in which the annual usage of fuel(s) with a 
sulfur content higher than very low sulfur fuel (as defined in 
Sec. 72.2 of this chapter) exceeds 480 hours; or
    (4) Eight successive calendar quarters have elapsed, following 
the quarter in which a RATA was last performed, without a subsequent 
RATA having been done, due either to infrequent operation of the 
unit(s) or frequent combustion of very low sulfur fuel, as defined 
in Sec. 72.2 of this chapter (SO2 monitors, only), or a 
combination of these factors.
* * * * *

2.4  Recertification, Quality Assurance, RATA Frequency and Bias 
Adjustment Factors (Special Considerations)

* * * * *
    (b) Except as provided in section 2.3.3 of this appendix, 
whenever a passing RATA of a gas monitor is performed, or a passing 
2-load (or 2-level) RATA or a passing 3-load (or 3-level) RATA of a 
flow monitor is performed (irrespective of whether the RATA is done 
to satisfy a recertification requirement or to meet the quality 
assurance requirements of this appendix, or both), the RATA 
frequency (semi-annual or annual) shall be established based upon 
the date and time of completion of the RATA and the relative 
accuracy percentage obtained. For 2-load (or 2-level) and 3-load (or 
3-level) flow RATAs, use the highest percentage relative accuracy at 
any of the loads (or levels) to determine the RATA frequency. The 
results of a single-load (or single-level) flow RATA may be used to 
establish the RATA frequency when the single-load (or single-level) 
flow RATA is specifically required under section 2.3.1.3(b) of this 
appendix or when the single-load (or single-level) RATA is allowed 
under section 2.3.1.3(c) of this appendix for a unit that has 
operated at one load level (or operating level) for r 85.0 percent 
of the time since the last annual flow RATA. No other single-load 
(or single-level) flow RATA may be used to establish an annual RATA 
frequency; however, a 2-load or 3-load (or a 2-level or 3-level) 
flow RATA may be performed at any time or in place of any required 
single-load (or single-level) RATA, in order to establish an annual 
RATA frequency.
* * * * *
    Figure 1 to Appendix B of Part 75--Quality Assurance Test 
Requirements
* * * * *
    \2\ For flow monitors installed on peaking units, bypass stacks, 
or units that qualify for single-level RATA testing under section 
6.5.2(e) of this appendix, conduct all RATAs at a single, normal 
load (or operating level). For other flow monitors, conduct annual 
RATAs at two load levels (or operating levels). Alternating single-
load and 2-load (or single-level and 2-level) RATAs may be done if a 
monitor is on a semiannual frequency. A single-load (or single-
level) RATA may be done in lieu of a 2-load (or 2-level) RATA if, 
since the last annual flow RATA, the unit has operated at one load 
level (or operating level) for r 85.0 percent of the time. A 3-level 
RATA is required at least once every five calendar years and 
whenever a flow monitor is re-linearized, except for flow monitors 
exempted from 3-level RATA testing under section 6.5.2(b) or 
6.5.2(e) of appendix A to this part.

* * * * *

    55. Appendix C to part 75 is amended by:
    a. In the section heading of section 2 by revising the word ``Load-
Based'' to read ``Load-based'' and by adding the words ``, 
NOX Concentration,'' after the words ``Flow Rate''; and
    b. Adding a new section 3.
    The revisions and additions read as follows:

Appendix C to Part 75--Missing Data Estimation Procedures

* * * * *

3. Non-load-based Procedure for Missing Flow Rate, NOX 
Concentration, and NOX Emission Rate Data (Optional)

3.1  Applicability

    For affected units that do not produce electrical output in 
megawatts or thermal output in klb/hr of steam, this procedure may 
be used in accordance with the provisions of this part to provide 
substitute data for volumetric flow rate (scfh), NOX 
emission rate (in lb/mmBtu) from NOX-diluent continuous 
emission monitoring systems, and NOX concentration data 
(in ppm) from NOX concentration monitoring systems used 
to determine NOX mass emissions.

3.2  Procedure

    3.2.1 For each monitored parameter (flow rate, NOX 
emission rate, or NOX concentration), establish at least 
two, but no more than ten operational bins, corresponding to various 
operating conditions and parameters (or combinations of these) that 
affect volumetric flow rate or NOX emissions. Include a 
complete description of each operational bin in the hardcopy portion 
of the monitoring plan required under Sec. 75.53(e)(2), identifying 
the unique combination of parameters and operating conditions 
associated with the bin and explaining the relationship between 
these parameters and conditions and the magnitude of the stack gas 
flow rate or NOX emissions. Assign a unique number, 1 
through 10, to each operational bin. Examples of conditions and 
parameters that may be used to define operational bins include unit 
heat input, type of fuel combusted, specific stages of an industrial 
process, or (for common stacks), the particular combination of units 
that are in operation.
    3.2.2  In the electronic quarterly report required under 
Sec. 75.64, indicate for each hour of unit operation the operational 
bin associated with the NOX or flow rate data, by 
recording the number assigned to the bin under section 3.2.1 of this 
appendix.
    3.2.3  The data acquisition and handling system must be capable 
of properly identifying and recording the operational bin number for 
each unit operating hour. The DAHS must also be capable of 
calculating and recording the following information (as applicable) 
for each unit operating hour of missing flow or NOX data 
within each identified operational bin during the shorter of:
    (a) The previous 2,160 quality assured monitor operating hours 
(on a rolling basis), or
    (b) All previous quality assured monitor operating hours in the 
previous 3 years:
    3.2.3.1  Average of the hourly flow rates reported by a flow 
monitor (scfh).
    3.2.3.2  The 90th percentile value of hourly flow rates (scfh).
    3.2.3.3  The 95th percentile value of hourly flow rates (scfh).
    3.2.3.4  The maximum value of hourly flow rates (scfh).
    3.2.3.5  Average of the hourly NOX emission rates, in 
lb/mmBtu, reported by a NOX-diluent continuous emission 
monitoring system.
    3.2.3.6  The 90th percentile value of hourly NOX 
emission rates (lb/mmBtu).
    3.2.3.7  The 95th percentile value of hourly NOX 
emission rates (lb/mmBtu).
    3.2.3.8  The maximum value of hourly NOX emission 
rates, in (lb/mmBtu).
    3.2.3.9  Average of the hourly NOX pollutant 
concentrations (ppm), reported by a NOX concentration 
monitoring system used to determine NOX mass emissions, 
as defined in Sec. 75.71(a)(2).
    3.2.3.10  The 90th percentile value of hourly NOX 
pollutant concentration (ppm).
    3.2.3.11  The 95th percentile value of hourly NOX 
pollutant concentration (ppm).
    3.2.3.12  The maximum value of hourly NOX pollutant 
concentration (ppm).
    3.2.4  When a bias adjustment is necessary for the flow monitor 
and/or the NOX-diluent continuous emission monitoring 
system (and/or the NOX concentration monitoring system), 
apply the bias adjustment factor to all data values placed in the 
operational bins.

[[Page 40460]]

    3.2.5  Calculate all CEMS data averages, maximum values, and 
percentile values determined by this procedure using bias-adjusted 
values.
    3.2.6  Use the calculated monitor or monitoring system data 
averages, maximum values, and percentile values to substitute for 
missing flow rate and NOX emission rate data (and where 
applicable, NOX concentration data) according to the 
procedures in subpart D of this part.

Appendix D Section 1 [Amended]

    56. Appendix D to Part 75 is amended by removing the final sentence 
of section 1.2.

    57. Appendix D to Part 75 is amended by:
    a. Revising sections 2.1.2, 2.1.2.1, and 2.1.2.2;
    b. Revising the first sentence of section 2.1.4.1;
    c. Revising section 2.1.4.3;
    d. In section 2.1.5 by revising the words ``calibrated fuel flow 
rate'' to read ``fuel flow rate measurable by the flowmeter'' in the 
first sentence, by adding the words ``(orifice, nozzle, and venturi-
type flowmeters, only)'' after the words ``by design'' in the second 
sentence, and by revising the words ``measurement against a NIST-
traceable reference method'' in the third sentence to read ``in-line 
comparison against a reference flowmeter'';
    e. In section 2.1.5.4 by revising the words ``using the following'' 
to read ``in a manner consistent with'';
    f. Revising paragraph (c) of section 2.1.6;
    g. In paragraph (d) of section 2.1.6 by removing the words ``where 
applicable,'' before the words ``those procedures'' and ``, where 
applicable'' after the second occurrence of the words ``element 
inspection'', and by adding ``(if applicable)'' after both occurrences 
of the words ``test or'';
    h. Adding new paragraphs (e) and (f) to section 2.1.6;
    i. In paragraph (a) of section 2.1.6.1 by adding the word 
``upscale'' after the word ``other'' in the second sentence and by 
adding a new third sentence;
    j. In section heading 2.1.6.2 by revising the words ``and Reporting 
of'' to read ``for'';
    k. In paragraph (a) of section 2.1.6.2 by removing the second and 
third sentences;
    l. Removing and reserving sections 2.1.6.2(b) and 2.1.6.2(c);
    m. In the final sentence of section 2.1.6.3 by removing the words 
``Sec. 75.56 or'' and ``, as applicable'';
    n. In the fourth sentence of paragraph (a) of section 2.1.6.4 by 
revising the words ``indicates that'' to read ``is failed (if'' and by 
adding a closing parenthesis after the word ``corroded'';
    o. In paragraph (a)(1) of section 2.1.6.4 by adding a new second 
sentence;
    p. In paragraphs (a)(2) and (b)(2) of section 2.1.6.4 by revising 
the word ``under'' to read ``, using'';
    q. In paragraph (b) of section 2.1.6.4 by removing the first 
sentence;
    r. In paragraph (b)(1) of section 2.1.6.4 by adding the words 
``and, if applicable, the transmitters have been successfully 
recalibrated'' to the end of the final sentence;
    s. In paragraph (c) of section 2.1.6.4 by revising the words ``this 
period'' to read ``each period of invalid fuel flowmeter data described 
in paragraph (b) of this section'';
    t. In section 2.1.7 by removing each occurrence of the words 
``where applicable,'' and ``as applicable,'', by removing the words 
``Sec. 75.54(a) or'', and by adding the words ``(if applicable) a'' and 
``(if applicable)'' after the two occurrences of ``test or'', 
respectively;
    u. In paragraph (a) of section 2.1.7.1 by revising the first 
occurrence of ``i.e.'' to read ``e.g.'', by revising the sixth 
sentence, and by adding the word ``Arithmetic'' before the word 
``average'' in the definitions of the variables ``Qbase'' 
and ``Lavg'' under Eq. D-1b;
    v. Revising paragraph (b) of section 2.1.7.1;
    w. In paragraph (c) of section 2.1.7.1 by adding the words 
``average fuel flow rate and the fuel GCV in the'' before the word 
``applicable'' in the definition of the variable ``(Heat 
Input)avg'' under Eq. D-1c;
    x. Adding a new paragraph (e) to section 2.1.7.1;
    y. In paragraph (a) of section 2.1.7.2 by adding a new third 
sentence;
    z. Revising paragraph (b) of section 2.1.7.2;
    aa. In the variable for ``(Heat Input)h'' under Eq. D-1e 
in paragraph (c) of section 2.1.7.2 by adding the words ``hourly fuel 
flow rate and the fuel GCV in the'' after the words ``using the'';
    bb. Revising paragraph (d) of section 2.1.7.2;
    cc. Adding a third sentence to paragraph (h) of section 2.1.7.2;
    dd. Revising paragraph (a) of section 2.1.7.3;
    ee. Adding a second sentence to paragraph (b) of section 2.1.7.3;
    ff. In the first sentence of paragraph (a) of section 2.1.7.4 by 
revising the reference to ``section 2.1.7.2'' to read ``section 
2.1.7.2(h)'';
    gg. In the final sentence of paragraph (b) of section 2.1.7.4 by 
adding the word ``fuel'' after the word ``two'' and by adding the words 
``(as defined in Sec. 72.2 of this chapter)'' after the word 
``quarters'';
    hh. Revising Table D-3 in section 2.1.7.5 and Table D-4 in section 
2.2;
    ii. In section 2.2.4.2 introductory text by adding the words ``and 
GCV value'' after the words ``Use the sulfur content'' in the fourth 
sentence, and by revising the reference to ``section 2.2.4.3'' to read 
``section 2.2.4.3(c)'';
    jj. Revising paragraph (b) of section 2.2.4.2;
    kk. In the second sentence of paragraph (c) of section 2.2.4.3 by 
revising the first and second occurrences of the words ``two following 
values'' to read, respectively, the words ``following conservative, 
assumed values'' and ``assumed values'';
    ll. Revising paragraph (d) of section 2.2.4.3;
    mm. Revising Table D-5 in paragraph (b) of section 2.3;
    nn. In section 2.3.1.3 by adding the words ``or Equation D-4 (if 
daily or hourly fuel sampling is used)'' at the end of the first 
sentence;
    oo. Revising sections 2.3.1.4, 2.3.2.4, and 2.3.6;
    pp. Revising section 2.3.2.1.1 and Equation D-1h;
    qq. Removing and reserving section 2.3.2.1.2;
    rr. Revising sections 2.3.3.1.1 and 2.3.3.2;
    ss. In section 2.3.4.3 by adding a new second sentence;
    tt. In section 2.3.4.3.1 by revising the fourth sentence;
    uu. Revising section 2.3.4.3.2;
    vv. Revising paragraph (a) of section 2.3.5;
    ww. Adding section 2.3.7;
    xx. In section 2.4.1 by removing a reference to ``2.3.3.1,'' in the 
first sentence, by removing the second sentence and adding two new 
sentences in its place, and by revising Table D-6;
    yy. Revising sections 2.4.2, 2.4.2.1, and 2.4.2.2; adding sections 
2.4.2.2.1 and 2.4.2.2.2; revising section 2.4.2.3; and adding sections 
2.4.2.3.1 through 2.4.2.3.4; and
    zz. In section 2.4.3 by adding a second sentence.
    The revisions and additions read as follows:

2. Procedure

2.1  Fuel Flowmeter Measurements

* * * * *
    2.1.2  Install and use fuel flowmeters meeting the requirements of 
this appendix in a pipe going to each unit, or install and use a fuel 
flowmeter in a common pipe header (as defined in Sec. 72.2). However, 
the use of a fuel flowmeter in a common pipe header and the provisions 
of sections 2.1.2.1 and 2.1.2.2 of this appendix shall not apply to any 
unit that is using the provisions of subpart H of this part to monitor,

[[Page 40461]]

record, and report NOX mass emissions under a State or 
federal NOX mass emission reduction program, unless both of 
the following are true: all of the units served by the common pipe are 
affected units, and all of the units have similar efficiencies. When a 
fuel flowmeter is installed in a common pipe header, proceed as 
follows:
    2.1.2.1  Measure the fuel flow rate in the common pipe, and combine 
SO2 mass emissions (Acid Rain Program units only) for the 
affected units for recordkeeping and compliance purposes; and
    2.1.2.2  Apportion the heat input rate measured at the common pipe 
to the individual units, using Equation F-21a, F-21b, or F-21d in 
appendix F to this part.
* * * * *
2.1.4.1  Start-up or Ignition Fuel
    For an oil-fired unit that uses gas solely for start-up or burner 
ignition, a gas-fired unit that uses oil solely for start-up or burner 
ignition, or an oil-fired unit that uses a different grade of oil 
solely for start-up or burner ignition, a fuel flowmeter for the start-
up fuel is permitted but not required. * * *
* * * * *
2.1.4.3  Emergency Fuel
    The designated representative of a unit that is restricted by its 
Federal, State or local permit to combusting a particular fuel only 
during emergencies where the primary fuel is not available is exempt 
from certifying a fuel flowmeter for use during combustion of the 
emergency fuel. During any hour in which the emergency fuel is 
combusted, report the hourly heat input to be the maximum rated heat 
input of the unit for the fuel. Use the maximum potential sulfur 
content for the fuel (from Table D-6 of this appendix) and the fuel 
flow rate corresponding to the maximum hourly heat input to calculate 
the hourly SO2 mass emission rate, using Equations D-2 
through D-4 (as applicable). Alternatively, if a certified fuel 
flowmeter is available for the emergency fuel, you may use the measured 
hourly fuel flow rates in the calculations. Also, if daily samples or 
weekly composite samples (fuel oil, only) of the fuel's total sulfur 
content, GCV, and (if applicable) density are taken during the 
combustion of the emergency fuel, as described in section 2.2 or 2.3 of 
this appendix, the sample results may be used to calculate the hourly 
SO2 emissions and heat input rates, in lieu of using maximum 
potential values. The designated representative shall also provide 
notice under Sec. 75.61(a)(6) for each period when the emergency fuel 
is combusted.
* * * * *
2.1.6  Quality Assurance
* * * * *
    (c) For orifice-, nozzle-, and venturi-type flowmeters, either 
perform the required flowmeter accuracy testing using the procedures in 
section 2.1.5.2 of this appendix or perform a transmitter accuracy test 
for the initial certification and once every four fuel flowmeter QA 
operating quarters thereafter. Perform a primary element visual 
inspection for the initial certification and once every 12 calendar 
quarters thereafter, according to the procedures in sections 2.1.6.1 
through 2.1.6.4 of this appendix for periodic quality assurance.
* * * * *
    (e) When accuracy testing of the orifice, nozzle, or venturi meter 
is performed according to section 2.1.5.2 of this appendix, record the 
information displayed in Table D-1 in this section. At a minimum, 
record the overall accuracy results for the fuel flowmeter at the three 
flow rate levels specified in section 2.1.5.2 of this appendix.
    (f) Report the results of all fuel flowmeter accuracy tests, 
transmitter or transducer accuracy tests, and primary element 
inspections, as applicable, in the emissions report for the quarter in 
which the quality assurance tests are performed, using the electronic 
format specified by the Administrator under Sec. 75.64.
2.1.6.1  Transmitter or Transducer Accuracy Test for Orifice-, Nozzle-, 
and Venturi-Type Flowmeters
    (a) * * * For temperature transmitters, the zero and upscale levels 
may correspond to fixed reference points, such as the freezing point or 
boiling point of water.
* * * * *
2.1.6.4  Primary Element Inspection
    (a) * * *
    (1) * * * If the primary element size is changed, also calibrate 
the transmitters or transducers, consistent with the new primary 
element size;
* * * * *
2.1.7  Fuel Flow-to-Load Quality Assurance Testing for Certified Fuel 
Flowmeters
* * * * *
2.1.7.1  Baseline Flow Rate-to-Load Ratio or Heat Input-to-Load Ratio
    (a) * * * For orifice-, nozzle-, and venturi-type fuel flowmeters, 
if the fuel flow-to-load ratio is to be used as a supplement both to 
the transmitter accuracy test under section 2.1.6.1 of this appendix 
and to primary element inspections under section 2.1.6.4 of this 
appendix, then the baseline data must be obtained after both procedures 
are completed and no later than the end of the fourth calendar quarter 
following the calendar quarter in which both procedures were completed. 
* * *
* * * * *
    (b) In Equation D-1b, for a fuel flowmeter installed on a common 
pipe header, Lavg is the sum of the operating loads of all 
units that received fuel through the common pipe header during the 
baseline period, divided by the total number of hours of fuel flow rate 
data collected during the baseline period. For a unit that receives the 
same type of fuel through multiple pipes, Qbase is the sum 
of the fuel flow rates during the baseline period from all of the 
pipes, divided by the total number of hours of fuel flow rate data 
collected during the baseline period. Round off the value of 
Rbase to the nearest tenth.
* * * * *
    (e) If a unit co-fires different fuels (e.g., oil and natural gas) 
as its normal mode of operation, the gross heat rate option in 
paragraph (c) of this section may be used to determine a value of 
(GHR)base, as follows. Derive the baseline data during co-
fired hours. Then, use Equation D-1c to calculate (GHR)base, 
making sure that each hourly unit heat input rate used to calculate 
(Heat Input)avg includes the contribution of each type of 
fuel.
2.1.7.2  Data Preparation and Analysis
    (a) * * * Alternatively, the owner or operator may exclude non-
representative hours from the data analysis, as described in section 
2.1.7.3 of this appendix, prior to calculating the values of 
Rh.
* * * * *
    (b) For a fuel flowmeter installed on a common pipe header, Lh 
shall be the sum of the hourly operating loads of all units that 
receive fuel through the common pipe header. For a unit that receives 
the same type of fuel through multiple pipes, Qh will be the 
sum of the fuel flow rates from all of the pipes. Round off each value 
of Rh to the nearest tenth.
* * * * *
    (d) Evaluate the calculated flow rate-to-load ratios (or gross heat 
rates) as follows.
    (1) Perform a separate data analysis for each fuel flowmeter system 
following the procedures of this section. Base each analysis on a 
minimum of 168

[[Page 40462]]

hours of data. If, for a particular fuel flowmeter system, fewer than 
168 hourly flow-to-load ratios (or GHR values) are available, or, if 
the baseline data collection period is still in progress at the end of 
the quarter and fewer than four calendar quarters have elapsed since 
the quarter in which the last successful fuel flowmeter system accuracy 
test was performed, a flow-to-load (or GHR) evaluation is not required 
for that flowmeter system for that calendar quarter. A one-quarter 
extension of the deadline for the next fuel flowmeter system accuracy 
test may be claimed for a quarter in which there is insufficient hourly 
data available to analyze or a quarter that ends with the baseline data 
collection period still in progress.
    (2) For a unit that normally co-fires different types of fuel 
(e.g., oil and natural gas), include the contribution of each type of 
fuel in the value of (Heat Input)h, when using Equation D-
1e.
* * * * *
    (h) * * * For units that normally co-fire different types of fuel, 
if the GHR option is used, apply the test results to each fuel 
flowmeter system used during the quarter.
2.1.7.3  Optional Data Exclusions
    (a) If Ef is outside the limits in section 2.1.7.2(h) of 
this appendix, the owner or operator may re-examine the hourly fuel 
flow rate-to-load ratios (or GHRs) that were used for the data analysis 
and may identify and exclude fuel flow-to-load ratios or GHR values for 
any non-representative hours, provided that such data exclusions were 
not previously made under section 2.1.7.2(a) of this appendix. 
Specifically, the Rh or (GHR)h values for the 
following hours may be considered non-representative:
    (1) For units that do not normally co-fire fuels, any hour in which 
the unit combusted another fuel in addition to the fuel measured by the 
fuel flowmeter being tested; or
    (2) Any hour for which the load differed by more than  
15.0 percent from the load during either the preceding hour or the 
subsequent hour; or
    (3) For units that normally co-fire different fuels, any hour in 
which the unit burned only one type of fuel; or
    (4) Any hour for which the unit load was in the lower 25.0 percent 
of the range of operation, as defined in section 6.5.2.1 of appendix A 
to this part (unless operation in the lower 25.0 percent of the range 
is considered normal for the unit).
    (b) * * * If fewer than 168 hourly fuel flow-to-load ratio or GHR 
values remain after the allowable data exclusions, a fuel flow-to-load 
ratio or GHR analysis is not required for that quarter, and a one-
quarter extension of the fuel flowmeter accuracy test deadline may be 
claimed.
* * * * *
2.1.7.5  Test Results
* * * * *
Table D-3.--Baseline Information and Test Results For Fuel Flow-to-Load 
Test

[[Page 40463]]

[GRAPHIC] [TIFF OMITTED] TR12JN02.012

2.2  Oil Sampling and Analysis

* * * * *

[[Page 40464]]

[GRAPHIC] [TIFF OMITTED] TR12JN02.013


[[Page 40465]]


* * * * *
2.2.4.2  Sampling from a Unit's Storage Tank
* * * * *
    (b) One of the conservative assumed values described in section 
2.2.4.3(c) of this appendix. Follow the applicable provisions in 
section 2.2.4.3(d) of this appendix, regarding the use of assumed 
values.
2.2.4.3  Sampling From Each Delivery
* * * * *
    (d) Continue using the assumed value(s), so long as the sample 
results do not exceed the assumed value(s). However, if the actual 
sampled sulfur content, gross calorific value, or density of an oil 
sample is greater than the assumed value for that parameter, then, 
consistent with section 2.3.7 of this appendix, begin to use the actual 
sampled value for sulfur content, gross calorific value, or density of 
fuel to calculate SO2 mass emission rate or heat input rate. Consider 
the sampled value to be the new assumed sulfur content, gross calorific 
value, or density. Continue using this new assumed value to calculate 
SO2 mass emission rate or heat input rate unless and until: it is 
superseded by a higher value from an oil sample; or (if applicable) it 
is superseded by a new contract in which case the new contract value 
becomes the assumed value at the time the fuel specified under the new 
contract begins to be combusted in the unit; or (if applicable) both 
the calendar year in which the sampled value exceeded the assumed value 
and the subsequent calendar year have elapsed.
* * * * *
2.3  SO2 Emissions from Combustion of Gaseous Fuels
* * * * *
    (b) * * *
    [GRAPHIC] [TIFF OMITTED] TR12JN02.014
    

[[Page 40466]]


[GRAPHIC] [TIFF OMITTED] TR12JN02.015


[[Page 40467]]


[GRAPHIC] [TIFF OMITTED] TR12JN02.016

2.3.1  Pipeline Natural Gas Combustion
* * * * *
2.3.1.4  Documentation that a Fuel is Pipeline Natural Gas
    (a) A fuel may initially qualify as pipeline natural gas, if 
information is provided in the monitoring plan required under 
Sec. 75.53, demonstrating that the definition of pipeline natural gas 
in Sec. 72.2 of this chapter has been met. The information must 
demonstrate that the fuel meets either the percent methane or GCV 
requirement and has a total sulfur content of 0.5 grains/100scf or 
less. The demonstration must be made using one of the following sources 
of information:
    (1) The gas quality characteristics specified by a purchase 
contract, tariff sheet, or by a pipeline transportation contract; or
* * * * *
    (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; or
    (3) If the requirements of paragraphs (a)(1) and (a)(2) of this 
section cannot be met, a fuel may initially qualify as pipeline natural 
gas if at least one representative sample of the fuel is obtained and 
analyzed for total sulfur content and for either the gross calorific 
value (GCV) or percent methane, and the results of the sample analysis 
show that the fuel meets the definition of pipeline natural gas in 
Sec. 72.2 of this chapter. Use the sampling methods specified in 
sections 2.3.3.1.2 and 2.3.4 of this appendix. The required fuel sample 
may be obtained and analyzed by the owner or operator, by an 
independent laboratory, or by the fuel supplier. If multiple samples 
are taken, each sample must meet the definition of pipeline natural gas 
in Sec. 72.2 of this chapter.
    (b) If the results of the fuel sampling under paragraph (a)(2) or 
(a)(3) of this section show that the fuel does not meet the definition 
of pipeline natural gas in Sec. 72.2 of this chapter, but those results 
are believed to be anomalous, the owner or operator may document the 
reasons for believing this in the monitoring plan for the unit, and may 
immediately perform additional sampling. In such cases, a minimum of 
three additional samples must be obtained and analyzed, and the results 
of each sample analysis must meet the definition of pipeline natural 
gas.
    (c) If several affected units are supplied by a common source of 
gaseous fuel, a single sampling result may be applied to all of the 
units and it is not necessary to obtain a separate sample for each 
unit, provided that the composition of the fuel is not altered by 
blending or mixing it with other gaseous fuel(s) when it is transported 
from the sampling location to the affected units. For the purposes of 
this paragraph, the term ``other gaseous fuel(s)'' excludes compounds 
such as mercaptans when they are added in trace quantities for safety 
reasons.
    (d) If the results of fuel sampling and analysis under paragraph 
(a)(2), (a)(3), or (b) of this section show that the fuel does not 
qualify as pipeline natural gas, proceed as follows:
    (1) If the fuel still qualifies as natural gas under section 
2.3.2.4 of this appendix, re-classify the fuel as natural gas and 
determine the appropriate default SO2 emission rate for the 
fuel, according to section 2.3.2.1.1 of this appendix; or
    (2) If the fuel does not qualify either as pipeline natural gas or 
natural gas, re-classify the fuel as ``other gaseous fuel'' and 
implement the procedures of section 2.3.3 of this appendix, within 180 
days of the end of the quarter in which the disqualifying sample was 
taken. In addition, the owner or operator shall use Equation D-1h in 
this appendix to calculate a default SO2 emission rate for 
the fuel, based on the results of the sample analysis that exceeded 20 
grains/100 scf of total sulfur, and shall use that default emission 
rate to report SO2 mass emissions under this part until 
section 2.3.3 of this appendix has been fully implemented.

[[Page 40468]]

    (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. The effective date of the annual total sulfur sampling 
requirement is January 1, 2003.
    (f) On-going sampling of the GCV of the pipeline natural gas is 
required under section 2.3.4.1 of this appendix.
    (g) For units that are required to monitor and report 
NOX mass emissions and heat input under subpart H of this 
part, but which are not affected units under the Acid Rain Program, the 
owner or operator is exempted from the requirements in paragraphs (a) 
and (e) of this section to document the total sulfur content of the 
pipeline natural gas.
2.3.2  Natural Gas Combustion
* * * * *
    2.3.2.1.1  In lieu of daily sampling of the sulfur content of the 
natural gas, the owner or operator may either use the total sulfur 
content specified in a contract or tariff sheet as the SO2 
default emission rate or may calculate the default SO2 
emission rate based on fuel sampling results, using Equation D-1h. In 
Equation D-1h, the total sulfur content and GCV values shall be 
determined in accordance with Table D-5 of this appendix. Round off the 
calculated SO2 default emission rate to the nearest 0.0001 
lb/mmBtu.
[GRAPHIC] [TIFF OMITTED] TR12JN02.017

Where:

ER = Default SO2 emission rate for natural gas combustion, 
lb/mmBtu.
Stotal = Total sulfur content of the natural gas, gr/100scf.
GCV = Gross calorific value of the natural gas, Btu/100scf.
7000 = Conversion of grains/100scf to lb/100scf.
2.0 = Ratio of lb SO2/lb S.
106 = Conversion factor (Btu/mmBtu).
2.3.2.1.2  [Reserved]
* * * * *
2.3.2.4  Documentation that a Fuel Is Natural Gas
    (a) A fuel may initially qualify as natural gas, if information is 
provided in the monitoring plan required under Sec. 75.53, 
demonstrating that the definition of natural gas in Sec. 72.2 of this 
chapter has been met. The information must demonstrate that the fuel 
meets either the percent methane or GCV requirement and has a total 
sulfur content of 20.0 grains/100 scf or less. This demonstration must 
be made using one of the following sources of information:
    (1) The gas quality characteristics specified by a purchase 
contract, tariff sheet, or by a transportation contract; or
    (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 natural gas in Sec. 72.2 of this chapter; or
    (3) If the requirements of paragraphs (a)(1) and (a)(2) of this 
section cannot be met, a fuel may initially qualify as natural gas if 
at least one representative sample of the fuel is obtained and analyzed 
for total sulfur content and for either the gross calorific value (GCV) 
or percent methane, and the results of the sample analysis show that 
the fuel meets the definition of natural gas in Sec. 72.2 of this 
chapter. Use the sampling methods specified in sections 2.3.3.1.2 and 
2.3.4 of this appendix. The required fuel sample may be obtained and 
analyzed by the owner or operator, by an independent laboratory, or by 
the fuel supplier. If multiple samples are taken, each sample must meet 
the definition of natural gas in Sec. 72.2 of this chapter.
    (b) If the results of the fuel sampling under paragraph (a)(2) or 
(a)(3) of this section show that the fuel does not meet the definition 
of natural gas in Sec. 72.2 of this chapter, but those results are 
believed to be anomalous, the owner or operator may document the 
reasons for believing this in the monitoring plan for the unit, and may 
immediately perform additional sampling. In such cases, a minimum of 
three additional samples must be obtained and analyzed, and the results 
of each sample analysis must meet the definition of natural gas.
    (c) If several affected units are supplied by a common source of 
gaseous fuel, a single sampling result may be applied to all of the 
units and it is not necessary to obtain a separate sample for each 
unit, provided that the composition of the fuel is not altered by 
blending or mixing it with other gaseous fuel(s) when it is transported 
from the sampling location to the affected units. For the purposes of 
this paragraph, the term ``other gaseous fuel(s)'' excludes compounds 
such as mercaptans when they are added in trace quantities for safety 
reasons.
    (d) If the results of fuel sampling and analysis under paragraph 
(a)(2), (a)(3), or (b) of this section show that the fuel does not 
qualify as natural gas, the owner or operator shall re-classify the 
fuel as ``other gaseous fuel'' and shall implement the procedures of 
section 2.3.3 of this appendix, within 180 days of the end of the 
quarter in which the disqualifying sample was taken. In addition, the 
owner or operator shall use Equation D-1h in this appendix to calculate 
a default SO2 emission rate for the fuel, based on the 
results of the sample analysis that exceeded 20 grains/100 scf of total 
sulfur, and shall use that default emission rate to report 
SO2 mass emissions under this part until section 2.3.3 of 
this appendix has been fully implemented.
    (e) If a fuel qualifies as 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 natural gas based on 
fuel sampling and analysis, the owner or operator shall sample the fuel 
for total sulfur content at least annually and when 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. The effective date of the annual total sulfur sampling 
requirement is January 1, 2003.
    (f) On-going sampling of the GCV of the natural gas is required 
under section 2.3.4.2 of this appendix.
    (g) For units that are required to monitor and report 
NOX mass emissions

[[Page 40469]]

and heat input under subpart H of this part, but which are not affected 
units under the Acid Rain Program, the owner or operator is exempted 
from the requirements in paragraphs (a) and (e) of this section to 
document the total sulfur content of the natural gas.
2.3.3  SO2 Mass Emissions From Any Gaseous Fuel
* * * * *
2.3.3.1  Sulfur Content Determination
    2.3.3.1.1  Analyze the total sulfur content of the gaseous fuel in 
grains/100 scf, at the frequency specified in Table D-5 of this 
appendix. That is: for fuel delivered in discrete shipments or lots, 
sample each shipment or lot. For fuel transmitted by pipeline, sample 
hourly unless a demonstration is provided under section 2.3.6 of this 
appendix showing that the gaseous fuel qualifies for less frequent 
(i.e., daily or annual) sampling. If daily sampling is required, 
determine the sulfur content using either manual sampling or a gas 
chromatograph. If hourly sampling is required, determine the sulfur 
content using a gas chromatograph. For units that are required to 
monitor and report NOX mass emissions and heat input under 
subpart H of this part, but which are not affected units under the Acid 
Rain Program, the owner or operator is exempted from the requirements 
of this section to document the total sulfur content of the gaseous 
fuel.
* * * * *
2.3.3.2  SO2 Mass Emission Rate
    Calculate the SO2 mass emission rate for the gaseous 
fuel, in lb/hr, using equation D-4 or D-5 (as applicable) in section 
3.3.1 of this appendix. Equation D-5 may only be used if a 
demonstration is performed under section 2.3.6 of this appendix, 
showing that the fuel qualifies to use a default SO2 
emission rate to account for SO2 mass emissions under this 
part. Use the appropriate sulfur content, in equation D-4 or D-5, as 
specified in Table D-5 of this appendix. If the fuel qualifies to use 
Equation D-5, the default SO2 emission rate shall be 
calculated using Equation D-1h in section 2.3.2.1.1 of this appendix, 
replacing the words ``natural gas'' in the equation nomenclature with 
the words, ``gaseous fuel''. In all cases, for reporting purposes, 
apply the results of the required periodic total sulfur samples in 
accordance with the provisions of section 2.3.7 of this appendix.
* * * * *
2.3.4  Gross Calorific Values for Gaseous Fuels
* * * * *
2.3.4.3  GCV of Other Gaseous Fuels
    * * * For reporting purposes, apply the results of the required 
periodic GCV samples in accordance with the provisions of section 2.3.7 
of this appendix.
    2.3.4.3.1  * * * For sampling from the tank after each delivery, 
use either the most recent GCV sample, the maximum GCV specified in the 
fuel contract or tariff sheet, or the highest GCV from the previous 
year's samples.
    2.3.4.3.2  For any gaseous fuel that does not qualify as pipeline 
natural gas or natural gas, which is not delivered in shipments or 
lots, and for which the owner or operator performs the 720 hour test 
under section 2.3.5 of this appendix, if the results of the test 
demonstrate that the gaseous fuel has a low GCV variability, determine 
the GCV at least monthly (as described in section 2.3.4.1 of this 
appendix). In calculations of hourly heat input for a unit, use either 
the most recent monthly sample, the maximum GCV specified in the fuel 
contract or tariff sheet, or the highest fuel GCV from the previous 
year's samples.
* * * * *
2.3.5  Demonstration of Fuel GCV Variability
    (a) This optional demonstration may be made for any fuel which does 
not qualify as pipeline natural gas or natural gas, and is not 
delivered only in shipments or lots. The demonstration data may be used 
to show that monthly sampling of the GCV of the gaseous fuel or blend 
is sufficient, in lieu of daily GCV sampling.
* * * * *
2.3.6  Demonstration of Fuel Sulfur Variability
    (a) This demonstration may be made for any fuel which does not 
qualify as pipeline natural gas or natural gas, and is not delivered 
only in shipments or lots. The results of the demonstration may be used 
to show that daily sampling for sulfur in the fuel is sufficient, 
rather than hourly sampling. The procedures in this section may also be 
used to demonstrate that a particular gaseous fuel qualifies to use a 
default SO2 emission rate (calculated using Equation D-1h in 
section 2.3.2.1.1 of this appendix) for the purpose of reporting hourly 
SO2 mass emissions under this part. To make this 
demonstration, proceed as follows. Provide a minimum of 720 hours of 
data, indicating the total sulfur content of the gaseous fuel (in gr/
100 scf). The demonstration data shall be obtained using either manual 
hourly sampling or an on-line gas chromatograph (GC) capable of 
determining fuel total sulfur content on an hourly basis. For gaseous 
fuel produced by a variable process, the data shall be representative 
of all process operating conditions including seasonal or annual 
variations which may affect fuel sulfur content.
    (b) If the data are collected with an on-line GC, reduce the data 
to hourly average values of the total sulfur content of the fuel. If 
manual hourly sampling is used, the results of each hourly sample 
analysis shall be the total sulfur value for that hour. Express all 
hourly average values of total sulfur content in units of grains/ 100 
scf. Use all of the hourly average values of total sulfur content in 
grains/100 scf to calculate the mean value and the standard deviation. 
Also determine the 90th percentile and maximum hourly values of the 
total sulfur content for the data set. If the standard deviation of the 
hourly values from the mean does not exceed 5.0 grains/100 scf, the 
fuel has a low sulfur variability. If the standard deviation exceeds 
5.0 grains/100 scf, the fuel has a high sulfur variability. Based on 
the results of this determination, establish the required sampling 
frequency and SO2 mass emissions methodology for the gaseous 
fuel, as follows:
    (1) If the gaseous fuel has a low sulfur variability (irrespective 
of the total sulfur content), the owner or operator may either perform 
daily sampling of the fuel's total sulfur content using manual sampling 
or a GC, or may report hourly SO2 mass emissions data using 
a default SO2 emission rate calculated by substituting the 
90th percentile value of the total sulfur content in Equation D-1h.
    (2) If the gaseous fuel has a high sulfur variability, but the 
maximum hourly value of the total sulfur content does not exceed 20 
grains/100 scf, the owner or operator may either perform hourly 
sampling of the fuel's total sulfur content using an on-line GC, or may 
report hourly SO2 mass emissions data using a default 
SO2 emission rate calculated by substituting the maximum 
value of the total sulfur content in Equation D-1h.
    (3) If the gaseous fuel has a high sulfur variability and the 
maximum hourly value of the total sulfur content exceeds 20 grains/100 
scf, the owner or operator shall perform hourly sampling of the fuel's 
total sulfur content, using an on-line GC.
    (4) Any gaseous fuel under paragraph (b)(1) or (b)(2) of this 
section, for which

[[Page 40470]]

the owner or operator elects to use a default SO2 emission 
rate for reporting purposes is subject to the annual total sulfur 
sampling requirement under section 2.3.2.4(e) of this appendix.
2.3.7  Application of Fuel Sampling Results
    For reporting purposes, apply the results of the required periodic 
fuel samples described in Tables D-4 and D-5 of this appendix as 
follows. Use Equation D-1h to recalculate the SO2 emission 
rate, as necessary.
    (a) For daily samples of total sulfur content or GCV:
    (1) If the actual value is to be used in the calculations, apply 
the results of each daily sample to all hours in the day on which the 
sample is taken; or
    (2) If the highest value in the previous 30 daily samples is to be 
used in the calculations, apply that value to all hours in the current 
day. If, for a particular unit, fewer than 30 daily samples have been 
collected, use the highest value from all available samples until 30 
days of historical sampling results have been obtained.
    (b) For annual samples of total sulfur content:
    (1) For pipeline natural gas, use the results of annual sample 
analyses in the calculations only if the results exceed 0.5 grains/100 
scf. In that case, if the fuel still qualifies as natural gas, follow 
the procedures in paragraph (b)(2) of this section. If the fuel does 
not qualify as natural gas, the owner or operator shall implement the 
procedures in section 2.3.3 of this appendix, in the time frame 
specified in sections 2.3.1.4(d) and 2.3.2.4(d) of this appendix;
    (2) For natural gas, apply the results of the most recent sample, 
beginning at the date of the sample;
    (3) For other gaseous fuels with an annual sampling requirement 
under section 2.3.6(b)(4) of this appendix, use the sample results in 
the calculations only if the results exceed the 90th percentile value 
or maximum value (as applicable) from the 720-hour demonstration of 
fuel sulfur content and variability under section 2.3.6 of this 
appendix.
    (c) For monthly samples of the fuel GCV:
    (1) If the actual value is to be used in the calculations, apply 
the results of the most recent sample, starting from the date on which 
the sample was taken; or
    (2) If an assumed value (contract maximum or highest value from 
previous year's samples) is to be used in the calculations, apply the 
assumed value to all hours in each month of the quarter unless a higher 
value is obtained in a monthly GCV sample. In that case, use the 
sampled value, starting from the date on which the sample was taken. 
Consider the sample results to be the new assumed value. Continue using 
the new assumed value unless and until it is superseded by a higher 
value from a subsequent monthly sample; or (if applicable) it is 
superseded by a new contract in which case the new contract value 
becomes the assumed value at the time the fuel specified under the new 
contract begins to be combusted in the unit; or (if applicable) both 
the calendar year in which the sampled value exceeded the assumed value 
and the subsequent calendar year have elapsed.
    (d) For samples of gaseous fuel delivered in shipments or lots:
    (1) If the actual value for the most recent shipment is to be used 
in the calculations, apply the results of the most recent sample, from 
the date on which the sample was taken until the date on which the next 
sample is taken; or
    (2) If an assumed value (contract maximum or highest value from 
previous year's samples) is to be used in the calculations, apply the 
assumed value unless a higher value is obtained in a sample of a 
shipment. In that case, use the sampled value, starting from the date 
on which the sample was taken. Consider the sample results to be the 
new assumed value. Continue using the new assumed value unless and 
until: it is superseded by a higher value from a sample of a subsequent 
shipment; or (if applicable) it is superseded by a new contract in 
which case the new contract value becomes the assumed value at the time 
the fuel specified under the new contract begins to be combusted in the 
unit; or (if applicable) both the calendar year in which the sampled 
value exceeded the assumed value and the subsequent calendar year have 
elapsed.
    (e) When the owner or operator elects to use assumed values in the 
calculations, the results of periodic samples of sulfur content and GCV 
which show that the assumed value has not been exceeded need not be 
reported. Keep these sample results on file, in a format suitable for 
inspection.
    (f) Notwithstanding the requirements of paragraphs (b) through (d) 
of this section, in cases where the sample results are provided to the 
owner or operator by the supplier of the fuel, the owner or operator 
shall begin using the sampling results on the date of receipt of those 
results, rather than on the date that the sample was taken.

2.4  Missing Data Procedures

* * * * *
2.4.1  Missing Data for Oil and Gas Samples
    * * * Except for the annual samples of fuel sulfur content required 
under sections 2.3.1.4(e), 2.3.2.4(e) and 2.3.6(b)(5) of this appendix, 
the missing data values in Table D-6 shall be reported whenever the 
results of a required sample of sulfur content, GCV or density is 
missing or invalid in the current calendar year, irrespective of which 
reporting option is selected (i.e., actual value, contract value or 
highest value from the previous year). For the annual samples of fuel 
sulfur content required under sections 2.3.1.4(e), 2.3.2.4(e) and 
2.3.6(b)(5) of this appendix, if a valid annual sample has not been 
obtained by the end of a particular calendar year, the appropriate 
missing data value in Table D-6 shall be reported, beginning with the 
first unit operating hour in the next calendar year. * * *

[[Page 40471]]

[GRAPHIC] [TIFF OMITTED] TR12JN02.018

    2.4.2  Missing Data Procedures for Fuel Flow Rate.
    Whenever data are missing from any primary fuel flowmeter system 
(as defined in Sec. 72.2 of this chapter) and there is no backup system 
available to record the fuel flow rate, use the procedures in sections 
2.4.2.2 and 2.4.2.3 of this appendix to account for the flow rate of 
fuel combusted at the unit for each hour during the missing data 
period. Alternatively, for a fuel flowmeter system used to measure the 
fuel combusted by a peaking unit, the simplified fuel flow missing data 
procedure in section 2.4.2.1 of this appendix may be used. Before using 
the procedures in sections 2.4.2.2 and 2.4.2.3 of this appendix, 
establish load ranges for the unit using the procedures of section 2 in 
appendix C to this part, except for units that do not produce 
electrical output (i.e., megawatts) or thermal output (e.g., klb of 
steam per hour). The owner or operator of a unit that does not produce 
electrical or thermal output shall either perform missing data 
substitution without segregating the fuel flow rate data into bins, or 
may petition the Administrator under Sec. 75.66 for permission to 
segregate the data into operational bins. When load ranges are used for 
fuel flow rate missing data purposes, separate, fuel-specific databases 
shall be created and maintained. A database shall be kept for each type 
of fuel combusted in the unit, for the hours in which the fuel is 
combusted alone in the unit. An additional database shall be kept for 
each type of fuel, for the hours in which it is co-fired with any other 
type(s) of fuel(s).
2.4.2.1  Simplified Fuel Flow Rate Missing Data Procedure for Peaking 
Units
    If no fuel flow rate data are available for a fuel flowmeter system 
installed on a peaking unit (as defined in Sec. 72.2 of this chapter), 
then substitute for each hour of missing data using the maximum 
potential fuel flow rate. The maximum potential fuel flow rate is the 
lesser of the following:
    (a) The maximum fuel flow rate the unit is capable of combusting or
    (b) The maximum flow rate that the fuel flowmeter can measure (i.e, 
the upper range value of the flowmeter).
2.4.2.2  Standard Missing Data Procedures--Single Fuel Hours
    For missing data periods that occur when only one type of fuel is 
being combusted, provide substitute data for each hour in the missing 
data period as follows.
    2.4.2.2.1  If load-based missing data procedures are used, 
substitute the arithmetic average of the hourly fuel flow rate(s) 
measured and recorded by a certified fuel flowmeter system at the 
corresponding operating unit load range during the previous 720 
operating hours in which the unit combusted only that same fuel. If no 
fuel flow rate data are available at the corresponding load range, use 
data from the next higher load range, if such data are available. If no 
quality-assured fuel flow rate data are available at either the 
corresponding load range or a higher load range, substitute the maximum 
potential fuel flow rate (as defined in section 2.4.2.1

[[Page 40472]]

of this appendix) for each hour of the missing data period.
    2.4.2.2.2  For units that do not produce electrical or thermal 
output and therefore cannot use load-based missing data procedures, 
provide substitute data for each hour of the missing data period as 
follows. Substitute the arithmetic average of the hourly fuel flow 
rates measured and recorded by a certified fuel flowmeter system during 
the previous 720 operating hours in which the unit combusted only that 
same fuel. If no quality-assured fuel flow rate data are available, 
substitute the maximum potential fuel flow rate (as defined in section 
2.4.2.1 of this appendix) for each hour of the missing data period.
2.4.2.3  Standard Missing Data Procedures--Multiple Fuel Hours
    For missing data periods that occur when two or more different 
types of fuel are being co-fired, provide substitute fuel flow rate 
data for each hour of the missing data period as follows.
    2.4.2.3.1  If load-based missing data procedures are used, 
substitute the maximum hourly fuel flow rate measured and recorded by a 
certified fuel flowmeter system at the corresponding load range during 
the previous 720 operating hours when the fuel for which the flow rate 
data are missing was co-fired with any other type of fuel. If no such 
quality-assured fuel flow rate data are available at the corresponding 
load range, use data from the next higher load range (if available). If 
no quality-assured fuel flow rate data are available for co-fired 
hours, either at the corresponding load range or a higher load range, 
substitute the maximum potential fuel flow rate (as defined in section 
2.4.2.1 of this appendix) for each hour of the missing data period.
    2.4.2.3.2  For units that do not produce electrical or thermal 
output and therefore cannot use load-based missing data procedures, 
provide substitute fuel flow rate data for each hour of the missing 
data period as follows. Substitute the maximum hourly fuel flow rate 
measured and recorded by a certified fuel flowmeter system during the 
previous 720 operating hours in which the fuel for which the flow rate 
data are missing was co-fired with any other type of fuel. If no 
quality-assured fuel flow rate data for co-fired hours are available, 
substitute the maximum potential fuel flow rate (as defined in section 
2.4.2.1 of this appendix) for each hour of the missing data period.
    2.4.2.3.3  If, during an hour in which different types of fuel are 
co-fired, quality-assured fuel flow rate data are missing for two or 
more of the fuels being combusted, apply the procedures in section 
2.4.2.3.1 or 2.4.2.3.2 of this appendix (as applicable) separately for 
each type of fuel.
    2.4.2.3.4  If the missing data substitution required in section 
2.4.2.3.1 or 2.4.2.3.2 causes the reported hourly heat input rate based 
on the combined fuel usage to exceed the maximum rated hourly heat 
input of the unit, adjust the substitute fuel flow rate value(s) so 
that the reported heat input rate equals the unit's maximum rated 
hourly heat input. Manual entry of the adjusted substitute data values 
is permitted.
    2.4.3  * * * In addition, for a new or newly-affected unit, until 
720 hours of quality-assured fuel flowmeter data are available for the 
lookback periods described in sections 2.4.2.2 and 2.4.2.3 of this 
appendix, use all of the available fuel flowmeter data to determine the 
appropriate substitute data values.


    58. Section 3 of Appendix D to Part 75 is amended by:
    a. In the definition of the variable ``%Soil'' in 
Equation D-2 in section 3.1.1 by removing the word ``measured'' and by 
revising the word ``sample'' to read ``oil'';
    b. Equation D-4 is revised;
    c. In the definition of the variable ``GCVgas'' in 
Equation D-6 in paragraph (b) of section 3.4.1 by revising the word 
``Btu/hr'' to read ``Btu/100 scf'';
    d. In the definition of the variable ``GCVoil'' in 
Equation D-8 in paragraph (a) of section 3.4.2 by adding the word 
``or'' after the word ``Btu/ton,'';
    e. Adding a new paragraph (c) to section 3.4.2;
    f. Removing the second sentence in paragraph (a) of section 3.4.3;
    g. In paragraph (b) in section 3.4.3 by revising the words 
``Equation D-10 or D-11'' to read ``Equation F-21a or F-21b in appendix 
F to this part'' in the third sentence and by removing and reserving 
Equations D-10 and D-11 and their variable respective definitions;
    h. In paragraph (c) of section 3.4.3 by revising the words 
``Equation D-10 or D-11'' to read ``Equation F-21a or F-21b'';
    i. Revising the section heading of section 3.5;
    j. In section heading 3.5.4 by adding the words ``Rate and Heat 
Input'' after the word ``Input'';
    k. Designating the existing text of section 3.5.4 as section 
3.5.4.1 and adding section 3.5.4.2 and Equation D-15a following the 
variable definitions for Equation D-15; and
    l. Revising Equation D-16 in section 3.5.5.
    The revisions and additions read as follows:

3. Calculations

* * * * *
[GRAPHIC] [TIFF OMITTED] TR12JN02.019


Where:
SO2rate-gas = Hourly mass rate of SO2 emitted due to 
combustion of gaseous fuel, lb/hr.
GASrate = Hourly metered flow rate of gaseous fuel combusted, 100 scf/
hr.
Sgas = Sulfur content of gaseous fuel, in grain/100 scf.
2.0 = Ratio of lb SO2/lb S.
7000 = Conversion of grains/100 scf to lb/100 scf.
* * * * *

3.4.2  Heat Input Rate from the Combustion of Oil

* * * * *
    (c) For affected units that are not subject to an Acid Rain 
emissions limitation, but are regulated under a State or Federal 
NOX mass emissions reduction program that adopts the 
requirements of subpart H of this part, the following alternative 
method may be used to determine the heat input rate from oil 
combustion, when the oil flowmeter measures the flow rate of oil 
volumetrically. In lieu of measuring the oil density and converting 
the volumetric oil flow rate to a mass flow rate, Equation D-8 may 
be applied on a volumetric basis. If this option is selected, 
express the terms OILrate and GCVoil in 
Equation D-8 in units of volume rather than mass. For example, the 
units of OILrate may be gal/hr and the units of 
GCVoil may be Btu/gal.
* * * * *

3.5  Conversion of Hourly Rates to Hourly, Quarterly, and Year-to-
Date Totals

* * * * *
    3.5.4  Hourly Total Heat Input Rate and Heat Input from the 
Combustion of all Fuels
    3.5.4.1
* * * * *
    3.5.4.2  For reporting purposes, determine the heat input rate 
to each unit, in mmBtu/hr, for each hour from the combustion of all 
fuels using Equation D-15a:

[[Page 40473]]

[GRAPHIC] [TIFF OMITTED] TR12JN02.020


Where:
HIrate-hr = Total heat input rate from all fuels 
combusted during the hour, mmBtu/hr.
HIrate-i = Heat input rate for each type of gas or oil 
combusted during the hour, mmBtu/hr.
ti = Time each gas or oil fuel was combusted for the hour 
(fuel usage time), 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).
tu = Unit operating time
* * * * *
[GRAPHIC] [TIFF OMITTED] TR12JN02.021


Where:
HIqtr = Total heat input from all fuels combusted during the 
quarter, mmBtu.
HIqtr = Hourly heat input determined using Equation D-15, mmBtu.
* * * * *

    59. Appendix E to Part 75 is amended by revising the second 
sentence of section 1.1, adding a sentence after the second sentence of 
section 1.1, and removing and reserving section 1.2.2 to read as 
follows:

Appendix E to Part 75--Optional NOX Emissions Estimation 
Protocol for Gas-Fired Peaking Units and Oil-Fired Peaking Units

1. Applicability

1.1  Unit Operation Requirements

    * * * If a unit's operations exceed the levels required to be a 
peaking unit, the owner or operator shall install and certify a 
NOX-diluent continuous emission monitoring system no 
later than December 31 of the following calendar year. If the 
required CEMS has not been installed and certified by that date, the 
owner or operator shall report the maximum potential NOX 
emission rate (MER) (as defined in Sec. 72.2 of this chapter) for 
each unit operating hour, starting with the first unit operating 
hour after the deadline and continuing until the CEMS has been 
provisionally certified. *  *  *

1.2  Certification

* * * * *
    1.2.2  [Reserved]

Appendix E to Part 75 [Amended]

    60. Appendix E to Part 75 is amended by:
    a. Revising sections 2.1.4, 2.2 and 2.5.2;
    b. In the second sentence of section 2.1.5 by revising the words 
``nearest 0.01 lb/mm/Btu'' to read ``nearest 0.001 lb/mmBtu'';
    c. In section 2.3 by revising the words ``10 unit'' to read ``30 
unit'' and the words ``section 2.1 of appendix B of this part'' with 
``Sec. 72.2 of this chapter'', and by revising the reference to 
``Sec. 75.60(a)'' to read ``Sec. 75.60'';
    d. In sections 2.3.1 and 2.3.2 by revising the first sentence, by 
revising the words ``manufacturer's recommended'' to read 
``acceptable'' in the third and fourth sentences, and by adding two new 
sentences after the first sentence, in each section;
    e. Revising the third sentence of 2.4.2;
    f. Adding a new second sentence in section 2.5; and
    g. Adding sections 2.5.2.1, 2.5.2.1.1, 2.5.2.1.2, 2.5.2.2, and 
2.5.2.3.
    The revisions and additions read as follows:

2. Procedure

* * * * *
    2.1.4  Emergency Fuel
    The designated representative of a unit that is restricted by 
its Federal, State or local permit to combusting a particular fuel 
only during emergencies where the primary fuel is not available may 
claim an exemption from the requirements of this appendix for 
testing the NOX emission rate during combustion of the 
emergency fuel. To claim this exemption, the designated 
representative shall include in the monitoring plan for the unit 
documentation that the permit restricts use of the fuel to 
emergencies only. When emergency fuel is combusted, report the 
maximum potential NOX emission rate for the emergency 
fuel, in accordance with section 2.5.2.3 of this appendix. The 
designated representative shall also provide notice under 
Sec. 75.61(a)(6) for each period when the emergency fuel is 
combusted.
* * * * *

2.2  Periodic NOX Emission Rate Testing

    Retest the NOX emission rate of the gas-fired peaking 
unit or the oil-fired peaking unit while combusting each type of 
fuel (or fuel mixture) for which a NOX emission rate 
versus heat input rate correlation curve was derived, at least once 
every 20 calendar quarters. If a required retest is not completed by 
the end of the 20th calendar quarter following the quarter of the 
last test, use the missing data substitution procedures in section 
2.5 of this appendix, beginning with the first unit operating hour 
after the end of the 20th calendar quarter. Continue using the 
missing data procedures until the required retest has been passed. 
Note that missing data substitution is fuel-specific (i.e., the use 
of substitute data is required only when combusting a fuel (or fuel 
mixture) for which the retesting deadline has not been met). Each 
time that a new fuel-specific correlation curve is derived from 
retesting, the new curve shall be used to report NOX 
emission rate, beginning with the first operating hour in which the 
fuel is combusted, following the completion of the retest. 
Notwithstanding this requirement, for non-Acid Rain Program units 
that report NOX mass emissions and heat input data only 
during the ozone season under Sec. 75.74(c), if the NOX 
emission rate testing is performed outside the ozone season, the new 
correlation curve may be used beginning with the first unit 
operating hour in the ozone season immediately following the 
testing.

2.3  Other Quality Assurance/Quality Control-Related NOX 
Emission Rate Testing

* * * * *
    2.3.1  For a stationary gas turbine, select at least four 
operating parameters indicative of the turbine's NOX 
formation characteristics, and define in the QA plan for the unit 
the acceptable ranges for these parameters at each tested load-heat 
input point. The acceptable parametric ranges should be based upon 
the turbine manufacturer's recommendations. Alternatively, the owner 
or operator may use sound engineering judgment and operating 
experience with the unit to establish the acceptable parametric 
ranges, provided that the rationale for selecting these ranges is 
included as part of the quality-assurance plan for the unit. * * *
    2.3.2  For a diesel or dual-fuel reciprocating engine, select at 
least four operating parameters indicative of the engine's 
NOX formation characteristics, and define in the QA plan 
for the unit the acceptable ranges for these parameters at each 
tested load-heat input point. The acceptable parametric ranges 
should be based upon the engine manufacturer's recommendations. 
Alternatively, the owner or operator may use sound engineering 
judgment and operating experience with the unit to establish the 
acceptable parametric ranges, provided that the rationale for 
selecting these ranges is included as part of the quality-assurance 
plan for the unit. * * *
* * * * *

2.4  Procedures for Determining Hourly NOX Emission Rate

* * * * *
    2.4.2  * * * Linearly interpolate to 0.1 mmBtu/hr heat input 
rate and 0.001 lb/mmBtu NOX. * * *
* * * * *

2.5  Missing Data Procedures

* * * For the purpose of providing substitute data, calculate the 
maximum potential NOX emission rate (as defined in 
Sec. 72.2 of this chapter) for each type of fuel combusted in the 
unit.

* * * * *
    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, and 2.5.2.3 of this appendix. Manual substitution 
of the missing data values required under sections 2.5.2.1 and 
2.5.2.2 of this appendix is permitted through March 31, 2003, after 
which these substitutions must be performed automatically by the 
data acquisition and handling system. Manual substitution of the 
missing data values required under section 2.5.2.3 of this appendix 
is permitted at all times.
    2.5.2.1  If the measured heat input rate during any unit 
operating hour is higher than the highest heat input rate from the 
baseline

[[Page 40474]]

correlation tests, the NOX emission rate for the hour is 
considered to be missing. Provide substitute data for each such 
hour, according to section 2.5.2.1.1 or 2.5.2.1.2 of this appendix, 
as applicable. Either:
    2.5.2.1.1  Substitute the higher of: the NOX emission 
rate obtained by linear extrapolation of the correlation curve, or 
the maximum potential NOX emission rate (MER) (as defined 
in Sec. 72.2 of this chapter), specific to the type of fuel being 
combusted. (For fuel mixtures, substitute the highest NOX 
MER value for any fuel in the mixture.) For units with 
NOX emission controls, the extrapolated NOX 
emission rate may only be used if the controls are documented (e.g., 
by parametric data) to be operating properly during the missing data 
period (see section 2.5.2.2 of this appendix); or
    2.5.2.1.2  Substitute 1.25 times the highest NOX 
emission rate from the baseline correlation tests for the fuel (or 
fuel mixture) being combusted in the unit, not to exceed the MER for 
that fuel (or mixture). For units with NOX emission 
controls, the option to report 1.25 times the highest emission rate 
from the correlation curve may only be used if the controls are 
documented (e.g., by parametric data) to be operating properly 
during the missing data period (see section 2.5.2.2 of this 
appendix).
    2.5.2.2  For a unit with add-on NOX emission controls 
(e.g., steam or water injection, selective catalytic reduction), if, 
for any unit operating hour, the emission controls are either not in 
operation or if appropriate parametric data are unavailable to 
ensure proper operation of the controls, the NOX emission 
rate for the hour is considered to be missing. Substitute the fuel-
specific MER (as defined in Sec. 72.2 of this chapter) for each such 
hour.
    2.5.2.3  When emergency fuel (as defined in Sec. 72.2) is 
combusted in the unit, report the fuel-specific NOX MER 
for each hour that the fuel is combusted, unless a NOX 
correlation curve has been derived for the fuel.
* * * * *

Appendix E Part 75 [Amended]

    61. Appendix E to Part 75 is amended by, in section 4 introductory 
text and section 4.1 by removing the words ``unit manufacturer's'', and 
in section 4.2 by removing the word ``manufacturer's''.

    62. Appendix F to Part 75 is amended by revising Equation F-3 in 
section 2.3 to read as follows:

Appendix F to Part 75--Conversion Procedures

* * * * *

2. Procedures for SO2 Emissions

* * * * *
2.3 * * * 
[GRAPHIC] [TIFF OMITTED] TR12JN02.022

* * * * *

Appendix F to Part 75 [Amended]

    63. Appendix F to Part 75 is amended, in section 3.3.5, by removing 
the third sentence, and by revising section 3.5 to read as follows:

3. Procedures for NOX Emission Rate

* * * * *
    3.5 Round all NOX emission rates to the nearest 0.001 
lb/mmBtu.

Appendix F to Part 75 [Amended]

    64. Appendix F to Part 75 is amended by:
    a. In the definition of the variable ``Qg'' of Equation 
F-20 in section 5.5.2 by revising the words ``hundred cubic feet'' to 
read ``hundred standard cubic feet per hour''
    b. In the first sentence of sections 5.6.1, 5.6.2, and 5.7 by 
revising the word ``should'' to read ``shall''
    c. In Equations F-21a and F-21b in sections 5.6.1 and 5.6.2 by 
revising the words ``Operating time at a particular unit'' in the 
definition of variable ``ti'' to read ``Unit operating 
time'', by revising the words ``Operating time at common stack'' in the 
definition of variable ``tcs'' with ``Common stack or common 
pipe operating time'', and by adding the words ``or pipe'' to the end 
of the definition of variable ``n''
    d. Revising the definitions of variables 
``HIs'',''unit'', and ``ts'', and 
adding a new definition for ``s'' in the definition of variables of 
Equation F-21c in section 5.7; and
    e. Adding section 5.8.
    The revisions and additions read as follows:

5. Procedures for Heat Input

* * * * *

5.7 Heat Input Rate Summation for Units with Multiple Stacks or 
Pipes * * *

HIs = Heat input rate for the individual stack, duct, or 
pipe, mmBtu/hr.
tUnit = Unit operating time, hour or fraction of the hour 
(in equal increments that can range from one hundredth to one 
quarter of an hour, at the option of the owner or operator).
ts = Operating time for the individual stack or pipe, 
hour or fraction of the hour (in equal increments that can range 
from one hundredth to one quarter of an hour, at the option of the 
owner or operator).
s = Designation for a particular stack, duct, or pipe.

5.8 Alternate Heat Input Apportionment for Common Pipes

    As an alternative to using Equation F-21a or F-21b in section 
5.6 of this appendix, the owner or operator may apportion the heat 
input rate at a common pipe to the individual units served by the 
common pipe based on the fuel flow rate to the individual units, as 
measured by uncertified fuel flowmeters. This option may only be 
used if a fuel flowmeter system that meets the requirements of 
appendix D to this part is installed on the common pipe. If this 
option is used, determine the unit heat input rates using the 
following equation:

[GRAPHIC] [TIFF OMITTED] TR12JN02.023


Where:

HIi = Heat input rate for a unit, mmBtu/hr.
HICP = Heat input rate at the common pipe, mmBtu/hr.
FFi = Fuel flow rate to a unit, gal/min, 100 scfh, or 
other appropriate units
ti = Unit operating time, hour 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).
tCP = Common pipe operating time, hour 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).
n = Total number of units using the common pipe.
i = Designation of a particular unit.

Appendix F to Part 75 [Amended]

    65. Appendix F to Part 75 is amended by revising the definitions of 
variables ``Eh'' and ``HI'' of Equation F-23 in section 7 to 
read as follows:

7. Procedures for SO2 Mass Emissions at Units with 
SO2 Continuous Emission Monitoring Systems During the 
Combustion of Pipeline Natural Gas or Natural Gas

* * * * *

[[Page 40475]]

Eh = Hourly SO2 mass emission rate, lb/hr.
* * *
HI = Hourly heat input rate, as determined using the procedures of 
section 5.2 of this appendix, mmBtu/hr.

Appendix F to Part 75 [Amended]

    66. Appendix F to Part 75 is amended by:
    a. In the first sentence of section 8.1.1 by adding the word 
``rate'' after each occurrence of the words ``heat input''; and
    b. In section 8.1.2 by revising the definition of the variable 
``tcs'' of Equation F-25 and by adding definitions of the 
variables ``p'' and ``u'' to Equation F-25.
    The revisions and additions read as follows:

8. Procedures for NOX Mass Emissions

* * * * *
    8.1.2 * * *
tCS = Common stack 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). (For each hour, tcs is the total time during 
which one or more of the units which exhaust through the common 
stack operate.).
* * * * *
p = Number of units that exhaust through the common stack.
u = Designation of a particular unit.
* * * * *
    67. Appendix G to Part 75 is amended as follows:

    a. In the text following the variables in Equation G-1 (the first 
sentence of which begins with the phrase, ``Collect at least one fuel 
sample during each week that the unit combusts coal''), designate the 
first two sentences as section 2.1.1; designate the third sentence as 
section 2.1.2; and designate the fourth through last sentences as 
section 2.1.3;
    b. In newly designated section 2.1.2, revising the word 
``sampling'' to read ``sample''
    c. In section 2.2.3 designate the equation as ``(Eq. G-2).''; and
    d. Revising section 2.3, by revising the definition of variable 
``Fc'' of Equation G-4, and by adding a definition of the 
variable ``MWCO2'' in Equation G-4.
    The revisions and additions read as follows:

Appendix G to Part 75--Determination of CO2 Emissions

2. Procedures for Estimating CO2 Emissions from 
Combustion

* * * * *
    2.3  In lieu of using the procedures, methods, and equations in 
section 2.1 of this appendix, the owner or operator of an affected 
gas-fired or oil-fired unit (as defined under Sec. 72.2 of this 
chapter) may use the following equation and records of hourly heat 
input to estimate hourly CO2 mass emissions (in tons).
(Eq. G-4) * * *

MW CO2 = Molecular weight of carbon dioxide, 44.0 lb/lb-
mole.
Fc = Carbon based F-factor, 1040 scf/mmBtu for natural 
gas; 1,420 scf/mmBtu for crude, residual, or distillate oil; and 
calculated according to the procedures in section 3.3.5 of appendix 
F to this part for other gaseous fuels.

* * * * *

Appendix G to Part 75 [Amended]

    68. Appendix G to Part 75 is amended by revising the introductory 
text of section 3.1.2 and by revising the definition of ``%R'' in 
Equation G-7 to read as follows:

3. Procedures for Estimating CO2 Emissions from Sorbent

* * * * *
    3.1.2  In lieu of using equation G-5, any owner or operator who 
operates and maintains a certified SO2-diluent continuous 
emission monitoring system (consisting of an SO2 
pollutant concentration monitor and an O2 or 
CO2 diluent gas monitor), for measuring and recording 
SO2 emission rate (in lb/mmBtu) at the outlet to the 
emission controls and who uses the applicable procedures, methods, 
and equations such as those in EPA Method 19 in appendix A to part 
60 of this chapter to estimate the SO2 emissions removal 
efficiency of the emission controls, may use the following equations 
to estimate daily CO2 mass emissions from sorbent (in 
tons).
* * * * *
(Eq. G-7) * * *
%R = Overall percentage SO2 emissions removal efficiency, 
calculated using equations such as those in EPA Method 19 in 
appendix A to part 60 of this chapter, and using daily instead of 
annual average emission rates.

* * * * *

Appendix G to Part 75 [Amended]

    69. Appendix G to Part 75 is amended by:
    a. Removing and reserving sections 5.1 and 5.1.1;
    b. Revising section 5.2; and
    c. Revising Table G-1 in section 5.2.2.
    The revisions read as follows:

5. Missing Data Substitution Procedures for Fuel Analytical Data

* * * * *
    5.1  [Reserved]
    5.1.1  [Reserved]
* * * * *

5.2  Missing Carbon Content Data

    Use the following procedures to substitute for missing carbon 
content data.

* * * * *

[[Page 40476]]

[GRAPHIC] [TIFF OMITTED] TR12JN02.024

* * * * *

PART 75--[AMENDED]

    70. In part 75, revise all references to ``low mass emission unit'' 
to read ``low mass emissions unit''.

[FR Doc. 02-11450 Filed 6-11-02; 8:45 am]
BILLING CODE 6560-50-P