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