[Federal Register Volume 66, Number 114 (Wednesday, June 13, 2001)]
[Proposed Rules]
[Pages 31978-32049]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 01-13142]
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Part II
Environmental Protection Agency
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40 CFR Parts 72, 75, 78, and 97
Revisions to the Federal NOX Budget Trading Program, the
Emissions Monitoring Provisions, the Permits Regulation Provisions, and
the Appeal Procedures; Proposed Rule
Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 /
Proposed Rules
[[Page 31978]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 72, 75, 78, and 97
[FRL-6984-8]
RIN 2060-AJ43
Revisions to the Federal NOX Budget Trading Program,
the Emissions Monitoring Provisions, the Permits Regulation Provisions,
and the Appeal Procedures
AGENCY: Environmental Protection Agency (EPA).
ACTION: Proposed rule.
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SUMMARY: EPA is proposing rule revisions that would modify the existing
requirements for sources affected by the Federal NOX Budget
Trading Program, the Acid Rain Program, and the October 27, 1998
NOX SIP Call. The proposed revisions would streamline and
add flexibility to the monitoring and reporting requirements in
response to the significant changes that have occurred in power
generation in recent years due to deregulation and recent environmental
actions initiated by EPA to reduce nitrogen oxides emissions. This
proposed action would also make certain technical corrections, remove
outdated provisions, and correct printing, typographical, and
grammatical errors to correct or clarify cross references, and, in a
few instances, to ensure that the specific rule language is consistent
with the Agency's intent.
DATES: Comments. All public comments must be received on or before July
30, 2001.
Public Hearing. Anyone requesting a public hearing must contact EPA
no later than June 25, 2001. If a hearing is held, it will take place
June 27, 2001, beginning at 10 a.m.
ADDRESSES: Comments. Comments must be mailed (in duplicate if possible)
to: EPA Air Docket (6102), Attention: Docket No. A-2000-33, Room M-
1500, Waterside Mall, 401 M Street, SW., Washington, DC 20460.
Public Hearing. If a public hearing is requested, it will be held
at the Environmental Protection Agency, 401 M Street, SW., Washington,
DC 20460, in the Education Center Auditorium. Refer to the Clean Air
Markets homepage at www.epa.gov/airmarkets for more information or to
determine if a public hearing has been requested and will be held.
Docket. Docket No. A-2000-33, containing supporting information
used to develop the proposal, is available for public inspection and
copying from 8:00 a.m. to 5:30 p.m., Monday through Friday, excluding
legal holidays, at EPA's Air Docket Section at the above address.
FOR FURTHER INFORMATION CONTACT: Gabrielle Stevens, Clean Air Markets
Division (6204N), U.S. Environmental Protection Agency, Ariel Rios
Building, 1200 Pennsylvania Avenue, NW., Washington, DC 20460,
telephone number (202) 564-2681 or the Acid Rain Hotline at (202) 564-
9620. Electronic copies of this document and technical support
documents can be accessed through the EPA Web site at: http://www.epa.gov/airmarkets.
SUPPLEMENTARY INFORMATION: In accordance with titles I and IV of the
Clean Air Act (CAA or the Act), EPA is proposing rule revisions to
support previous actions the Agency has taken to mitigate interstate
transport of nitrogen oxides as well as to reduce the acidic deposition
precursor emissions of sulfur dioxide and nitrogen oxides
(NOX). Title I of the CAA, as amended by the Clean Air Act
Amendments of 1990, authorizes EPA, under section 126 of the Act, to
require reductions of NOX emissions from sources that emit
in violation of the CAA prohibition against significantly contributing
to ozone nonattainment or maintenance problems in a downwind State that
petitions EPA for relief. On January 18, 2000, EPA published a section
126 finding that a number of large electric generating units and large
industrial boilers and turbines named in petitions filed by several
northeastern States emit NOX in violation of the CAA. In
that same notice, the EPA finalized the Federal NOX Budget
Trading Program as the control remedy for sources affected by the rule.
EPA originally promulgated 40 CFR parts 72, 75, and 78 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
the January 11, 1993 rules. The most recent revisions were promulgated
on May 26, 1999. Finally, note that although today's proposal will not
revise the Finding of Significant Contribution and Rulemaking for
Certain States in the Ozone Transport Assessment Group for Purposes of
Reducing the Transport of Ozone ( NOX SIP call), promulgated
on October 27, 1998, under section 110 of the Act, the proposed changes
to the monitoring and reporting provisions of 40 CFR part 75 (and
related changes to certain definitions in 40 CFR part 72) will affect
sources that are subject to the NOX SIP call, since many of
these sources will be required to implement part 75 emissions
monitoring.
The provisions of 40 CFR parts 72, 75, 78, and 97 will be revised
to modify the existing requirements for sources affected by the Acid
Rain Program, the Federal NOX Budget Trading Program, and
the October 27, 1998, NOX SIP call. Today's proposal is
limited to the specific provisions in parts 72, 75, 78, and 97
identified and discussed here. EPA is not considering reopening or
requesting public comment on any other provisions of parts 72, 75, 78,
or 97 or of the section 126 or NOX SIP call rulemaking.
A redline/strikeout version of 40 CFR parts 72 and 75 as amended by
this proposed 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 the Proposed Rule
III. Detailed Discussion of Proposed Revisions
A. Rule Definitions
1. How does EPA propose to revise the definitions of pipeline
natural gas and natural gas in Sec. 72.2?
2. How does EPA propose to change the definitions of unit and
stack operating hours?
3. What other definitions would be revised or added to the rule?
B. Certification Timeline Issues
1. What is the deadline for an application for initial
certification?
2. For an appendix E peaking unit, when is initial certification
required while combusting the backup fuel?
3. What happens if a unit loses peaking, gas-fired, or LME
status?
C. Missing Data
1. How will the proposed rule affect the missing data procedures
in Secs. 75.31 through 75.37 for units that produce electrical or
thermal output?
2. How will subpart H missing data provisions be affected for
units that produce electrical or thermal output?
3. What are the missing data requirements for units that do not
produce electrical or thermal output?
4. How will today's proposed rule revise the procedures in
appendix C for establishing load ranges (or ``bins'') for missing
data purposes?
5. How will the maximum potential moisture provision be revised?
6. How will the proposed rule affect the method of determination
codes?
D. Low Mass Emissions (LME) Units
1. What are the certification requirements for low mass
emissions (LME) units?
2. How does the LME methodology apply to subpart H units?
3. When must the annual demonstration for LME units be
completed?
4. How should EPA Reference Method 20 be altered when
determining a fuel-and unit-specific NOX emission rate
for an LME unit?
5. What temperature and humidity corrections are required for
turbines
[[Page 31979]]
when unit-and fuel-specific NOX emission rates are
determined for LME units?
6. How is identical unit status demonstrated for a group of LME
units?
7. How is the fuel-and unit-specific NOX emission
rate determined for LME turbines equipped with water injection,
steam injection, or water/fuel emulsion, and no other type(s) of
add-on NOX controls?
8. What effect would today's proposed rule have on LME units
sharing a common fuel supply?
9. When would single load testing be allowed to determine unit-
and fuel-specific NOX emission rates for LME units?
10. How are unit-specific, fuel-specific NOX emission
rates for LME units determined from the individual test run data at
each load level?
11. Which mathematical equations are affected by the proposed
changes to Sec. 75.19?
E. Conditionally Valid Data--Mandatory Use
F. Quality Assurance/Quality Control (QA/QC)
1. What changes are proposed for CEMS span and range
evaluations?
2. Will EPA allow use of two separate CEM systems with separate
probes and sample interfaces to meet dual-range requirements?
3. What changes would the proposed rule make with regard to
determining NOX MPC, MEC, span, and range?
4. What revisions would be made to the 7-day calibration error
test for peaking units?
5. What changes would be made to QA/QC for units with very low
NOX concentrations?
6. When would EPA require the application of a calibration
correction factor to linearity or RATA test data?
7. What changes would be made to the flow-to-load ratio test?
8. When would three-load flow RATAs be allowed for routine
quality assurance?
9. What changes would be made to the data analysis time period
for single-load flow RATA claims?
10. For units that do not produce electrical output or steam
load, at what operating levels should gas and flow monitor RATAs be
performed?
G. Streamlining Changes
H. Monitoring Plan Information Submittal
1. What changes are proposed in the timeline for monitoring plan
updates?
2. Is EPA changing the process for electronic submittal of
monitoring plan updates and certification/recertification test
results?
I. Appendix D--Miscellaneous Issues
J. Reporting and Recordkeeping
1. Will certification and recertification test notice
requirements change?
2. Will EPA continue to accept hardcopy certification
statements?
3. Will EPA allow the electronic storage of quality assurance/
quality control plan information?
K. NOX Monitoring in Multiple Stacks/Common Stacks
L. Appendix E Issues
1. How will the proposed rule affect Appendix E test
notifications and submittal of hardcopy recertification test
results?
2. Will the frequency of retesting of Appendix E units be
changed?
3. How will the timeline for unscheduled Appendix E retests be
revised?
4. How will Appendix E missing data procedures be changed?
5. How will the Appendix E testing requirements for emergency
fuel be changed?
M. Reference Methods
1. Which Code of Federal Regulations versions of reference
methods are to be used?
2. Are there other changes to reference methods?
N. Appendix G Revisions
O. Technical Changes and Corrections
P. What other changes is EPA proposing to the Federal
NOX Budget Trading Program today?
IV. Administrative Requirements
A. Public Hearing
B. Public Docket
C. Executive Order 12866
D. Unfunded Mandates Reform Act
E. Paperwork Reduction Act
F. Regulatory Flexibility
G. National Technology Transfer and Advancement Act
H. Executive Order 13175
I. Executive Order 12898
J. Executive Order 13045
K. Executive Order 13132
I. Regulated Entities
Entities regulated by this action are fossil fuel-fired boilers,
turbines, and combined cycle units that serve generators which produce
electricity, generate steam, or cogenerate electricity and steam. While
part 75 primarily regulates the electric utility industry, certain
State and Federal NOX mass emission trading programs may
rely on subpart H of part 75, and those programs may include boilers,
turbines, and combined cycle units from other industries. Regulated
categories and entities include:
------------------------------------------------------------------------
Examples of regulated
Category 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 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, organization, etc., is regulated by
this action, you should carefully examine the applicability provisions
in Secs. 72.6, 72.7, and 72.8 of title 40 of the Code of Federal
Regulations and in 40 CFR parts 96 and 97. If you have questions
regarding the applicability of this action to a particular entity,
consult the person listed in the preceding FOR FURTHER INFORMATION
CONTACT section of this preamble.
II. Background and Summary of the Proposed Rule
Today's proposed action modifies existing monitoring and reporting
requirements in 40 CFR parts 72 and 75 that support emission control
programs that use the monitoring and reporting provisions of part 75
such as the Acid Rain Program and State NOX reduction
programs developed in response to 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 proposed changes are as follows: the definitions of
``pipeline natural gas'' and ``natural gas'' in Sec. 72.2 would be
revised to remove all references to the H2S content of the
fuel and would instead be based on total sulfur content (corresponding
changes would be made to appendix D to part 75); the compliance and
certification timelines for certifying monitoring systems would be made
the same for new units, newly affected units, deferred units, and new
stacks; the low mass emissions (LME) units provisions in Sec. 75.19
would be clarified; for units with certain types of NOX
emission controls, qualification as a LME unit would be made easier;
the CEMS missing data procedures would be revised to allow fuel-
specific missing data substitution as well as the use of a controlled
and uncontrolled database for units with add-on emission controls; the
missing data procedures in subpart H of part 75 would be expanded and
clarified for sources that report emission data only in the ozone
season; the NOX span and range provisions in appendix A
would be revised to make them more realistic and easier to implement
for combustion turbines; and the alternate calibration error limit for
daily operation would be tightened from 10 ppm to 5 ppm for units with
span values of 50 ppm or less. Many of the above changes to part 75
would affect the monitoring and reporting sections of
[[Page 31980]]
the part 97 rule. Therefore, today's proposed rule would also revise
certain sections of part 97 to make the monitoring and reporting
sections of the part 75 and part 97 rules consistent. In addition,
certain miscellaneous changes would be made to clarify or correct minor
errors in other sections of part 97 or to make the administrative
appeal procedures in part 78 applicable to decisions of the
Administrator under part 97.
III. Detailed Discussion of Proposed Revisions
A. Rule Definitions
EPA policy guidance and the instructions EPA has developed for
monitoring and electronic reporting under part 75 rely on many terms
that are used in part 75 but that are not defined in Sec. 72.2 (the
definitions section for all Acid Rain Program regulations). Also, some
of the existing definitions in Sec. 72.2 are incorrect or incomplete.
To address these concerns, the proposed revisions would add or modify
several definitions.
1. How Does EPA Propose To Revise the Definitions of Pipeline Natural
Gas and Natural Gas in Sec. 72.2?
Background. Following the May 26, 1999, rulemaking, a utility group
sued EPA over the definitions of ``pipeline natural gas'' and ``natural
gas'' contained in Sec. 72.2. The issue is that gaseous fuel must meet
a two-fold requirement to qualify as one of these fuels. In the current
rule, there is an H2S content limit (0.3 gr/100 scf for
pipeline natural gas and 1.0 gr/100 scf for natural gas) and a
requirement that H2S constitute more than 50 percent of the
total fuel sulfur content. Appendix D to the rule does not explain how
to comply with the second of these two requirements (the H2S
as a percentage of total sulfur requirement). Further, industry members
are concerned 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, EPA recently issued guidance on how to demonstrate
compliance with the H2S content limit. As explained in the
guidance, EPA also granted a petition allowing owners or operators to
meet total sulfur limits in lieu of the H2S percent of-
total-sulfur requirement.
Discussion of Proposed Changes. The proposed rule would revise 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. For
the purposes of determining SO2 emissions, it makes no
difference whether the fuel's sulfur is in the form of H2S
or any other form. The proposed total sulfur content values are 0.5 gr/
100 scf or less for pipeline natural gas and 20.0 gr/100 scf or less
for natural gas. EPA chose the value of 0.5 gr/100 scf for pipeline
natural gas so that typical supplies of pipeline natural gas that have
an average sulfur content of 0.2 to 0.3 gr/100 scf will consistently
yield samples below this cutoff of 0.5 gr/100 scf. In addition,
SO2 emission rates calculated using this value will not be
much higher than the rate of 0.0006 lb SO2 /mmBtu for
pipeline natural gas that EPA used to compute allocations for sources
combusting pipeline natural gas. The value of 20.0 gr/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.
In addition, appendix D, sections 2.3.1.4 and 2.3.2.4 would be
revised to require initial and periodic sampling to document the total
sulfur content of the fuel. The revised rule would require periodic
sampling on a semiannual basis, as well as whenever it is reasonable to
believe that the composition of the fuel supply has changed. For fuels
that qualify as pipeline natural gas, the 0.0006 lb/mmBtu default
SO2 emission rate would be used, and for fuels that qualify
as natural gas, an SO2 emission rate would be calculated
based on Equation D-1h in appendix D. Note that Equation D-1h would be
revised to be based upon the total sulfur content of the fuel, rather
than the H2S content.
2. How Does EPA Propose To Change the Definitions of Unit and Stack
Operating Hours?
Background. The current rule 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 counterintuitive to 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.
Discussion of Proposed Changes. Definitions of ``cumulative stack
operating hours'' and ``cumulative unit operating hours'' would be
added 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.
3. What Other Definitions Would Be Revised or Added to the Rule?
Background. There are several definitions in Sec. 72.2 that are
either unclear or inconsistent with the way in which part 75 has been
implemented. In addition, some terms that are used in the Acid Rain
Program Policy Manual and the EDR v2.1 Instructions are not defined in
the rule.
Discussion of Proposed Changes. Under the proposal, EPA would add
definitions of ``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.'' These terms are all used in part 75 and the
accompanying guidance materials, but are not defined in Sec. 72.2. EPA
believes these terms should be defined because they are terms of art as
used in various sections of part 75.
Finally, the definitions of ``continuous emission monitoring system
or CEMS,'' ``emergency fuel,'' ``heat input,'' ``hour before and
after,'' ``maximum potential NOX emission rate,'' ``maximum
rated hourly heat input,'' ``missing data period,'' ``monitor
accuracy,'' ``stack operating hour,'' and ``unit operating hour'' would
be revised. See the technical support document (Docket A-2000-33, Item
II-A-2) for an explanation of these technical changes.
B. Certification Timeline Issues
1. What Is the Deadline for an Application for Initial Certification?
Background. The current rule specifies different monitor
certification timelines in Sec. 75.4, for new units, new
[[Page 31981]]
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 has greater
flexibility.
Discussion of Proposed Changes. EPA proposes to make all of the
timelines the same 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, final
section 126 rule, in order to make the certification timelines in parts
75 and 97 consistent.
2. For an Appendix E Peaking Unit, When Is Initial Certification
Required While Combusting the Backup Fuel?
Background. The current rule specifies in Sec. 75.4(f) that for an
appendix E unit for which certification testing prior to the applicable
deadline has been done only while combusting the primary fuel,
certification tests using backup fuel must be completed within 30 unit
operating days after the backup fuel is first combusted following the
certification deadline.
Discussion of Proposed Changes. The proposal would revise
Sec. 75.4(f) to state that certification is required within the earlier
of 90 unit operating days or 180 calendar days after the backup fuel is
first burned following the initial certification deadline. This revised
timeline is consistent with the changes to the timelines in Sec. 75.4,
paragraphs (b), (c), (d), and (e) in today's proposed rule.
3. What Happens if a Unit Loses Peaking, Gas-Fired, or LME Status?
Background. Under the current rule, when an appendix E unit loses
its status as a peaking unit, a NOX CEMS must be installed
by December 31 of the following calendar year. Similarly, loss of gas-
fired unit status requires (in some cases) installation of a COMS by
December 31 of the following year. Loss of low mass emissions (LME)
unit status under Sec. 75.19 requires monitoring systems to be
installed within two quarters after the quarter in which LME status is
lost. The LME requirement appears to be inconsistent with the others in
that it contains a shorter timeline to install and certify monitoring
systems. In addition, when peaking unit or LME status is lost, the rule
does not provide specific instructions regarding what emission values
to report if the deadline for certifying monitors is not met.
Discussion of Proposed Changes. For units that lose their LME
status, EPA proposes to change the deadline in Sec. 75.19(b)(2) for
monitor certification to December 31 of the year after the year in
which the unit exceeded the LME applicability threshold(s), thus making
the monitor certification timeline the same as the timelines in
Secs. 75.12(d)(2) and 75.14(c) for, respectively, loss of peaking unit
status and loss of gas-fired status. In the period from the time of
loss of LME status until the certification deadline, units would
continue to monitor and report in accordance with the provisions for
LME units.
Today's proposed rule also includes provisions in
Secs. 75.19(b)(2), 75.12(d)(2), 75.71(d), and appendix E, section 1.1
that would specify the emission reporting requirements when LME status
or peaking unit status is lost and the monitor certification deadline
is not met. For loss of peaking unit status, the maximum potential
NOX emission rate would be reported after the CEM
certification deadline. For loss of LME status, SO2 and
CO2 emissions would be reported after the deadline using the
applicable LME default emission rate and the maximum potential hourly
heat input, and NOX emissions would be reported using the
fuel specific maximum potential NOX emission rate.
C. Missing Data
1. How Will the Proposed Rule Affect the Missing Data Procedures in
Secs. 75.31 Through 75.37 for Units That Produce Electrical or Thermal
Output?
Background. 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. In some cases, the substitute data
value is simply the arithmetic average of the CEMS hourly averages
recorded before and after the missing data period. In other cases, the
substitute data value is either the 90th percentile value, the 95th
percentile value, or the maximum value in a historical lookback period
consisting of a certain number of quality-assured monitor operating
hours (the previous 720 hours of quality-assured data for
SO2, CO2, and moisture, and the previous 2,160
hours of quality-assured data in a particular load range (``load bin'')
for NOX and flow rate). Finally, if, at the time of the
missing data period, the percent monitor data availability is below 80
percent, the appropriate maximum potential value must be reported for
each hour of the missing data period.
The 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 (SO2, NOX, flow rate, etc.) in order to
provide substitute data values when a historical lookback is required.
For a unit that combusts different types of fuel having significantly
different emission levels for a particular parameter (e.g., for a unit
which can burn either coal or natural gas, the SO2 emissions
are much higher when coal is burned), the substitute data values
obtained in a historical lookback may not be representative of the
actual emissions during the missing data period.
For units with add-on SO2 or NOX emission
controls, Sec. 75.34 in the current rule allows three missing data
options. The owner or operator may either: (1) Use the standard missing
data procedures, if the controls are documented to be operating
properly, or otherwise use maximum potential
[[Page 31982]]
values; or (2) petition the Administrator to use the maximum controlled
emission rate recorded in the previous 720 quality-assured monitor
operating hours, if the percent monitor data availability is below 90
percent and if the controls are documented to be operating properly
during the missing data period; or (3) petition the Administrator to
use site-specific parametric monitoring procedures for missing data
substitution. These missing data options have proven to be difficult to
implement and lack flexibility. The representativeness of the
substitute data values derived from these procedures, particularly for
Options (1) and (3), is also uncertain.
Option (1) requires parametric data to be recorded during missing
data periods to document proper operation of the add-on emission
controls, in order to justify using the standard missing data
procedures. The parameters selected and the acceptable ranges for the
parameters must be documented in the QA plan for the unit. The
designated representative must submit a certification statement in the
electronic quarterly report, affirming that the emission controls
operated within the acceptable parametric ranges during each missing
data period and that use of the standard missing data procedures is
appropriate. This approach to missing data substitution is problematic
because currently there are no clear guidelines, either in the rule or
in EPA policy guidance, for selecting the appropriate parameters or the
acceptable parametric ranges. Therefore, it is difficult to establish
whether the emission controls are actually working properly during a
missing data period, even if parametric data have been recorded and are
available for auditing purposes. Further, when the standard missing
data procedures are used, the substitute data values derived from
historical lookbacks may not be representative of the actual emissions
during the missing data period, because the historical databases used
for the lookbacks include all quality-assured CEMS data, for both
controlled and uncontrolled operation.
Option (2), above, is difficult to implement administratively,
because it requires a petition every time the owner or operator wants
to use a missing data value based solely on data recorded during hours
when the emission controls were working, instead of using the standard
missing data routines. Use of this missing data option could therefore
require a petition to be submitted to and answered by EPA every
quarter.
To date, no units in the Acid Rain Program have petitioned to use
Option (3), above.
Discussion of Proposed Changes. Today's proposed rule would revise
the part 75 missing data procedures to allow missing data substitution
to be done on a fuel-specific basis. Also, for units with add-on
SO2 or NOX emission controls, EPA proposes to
revise Sec. 75.34 to include a new missing data option, based on the
operating status of the emission controls. Note that the use of these
new rule provisions would be optional. Therefore, sources using the
missing data provisions in the current rule could continue to do so.
Today's proposed rule would add fuel-specific missing data
provisions to Sec. 75.33, in five new paragraphs, (b)(5), (b)(6),
(c)(7), (c)(8), and (c)(9). These provisions would allow the owner or
operator to create and maintain separate databases for each type of
fuel combusted in the unit, for missing data purposes. Substitute data
values would be derived from the appropriate database, depending on the
type of fuel being burned during the missing data period. To use these
new provisions, the owner or operator would be required to determine
fuel-specific maximum potential values for concentration, emission
rate, or flow rate (as applicable).
The owner or operator would be allowed to switch to the new fuel-
specific missing data procedures at any time. Until the requisite
number of hours of quality-assured fuel-specific data were recorded for
the lookback periods (either 720 or 2,160 hours), the owner or operator
would use all available data in the databases for the lookbacks.
For units with add-on controls, the proposed rule would retain the
missing data option in Sec. 75.34(a)(3), allowing the owner or operator
to petition to use a site-specific parametric missing data substitution
procedure. The owner or operator could also continue using the missing
data option in Sec. 75.34(a)(1), which allows the standard missing data
procedures to be used for hours in which proper operation of the
emission controls is documented by means of parametric data, and
requires maximum potential values to be reported for all other missing
data hours. Note, however, that the proposed rule would expand and
clarify the way in which parametric data are used to document proper
operation of the add-on emission controls, as explained below in the
discussion of the changes to Sec. 75.34(a)(2).
Today's proposed rule would significantly revise Sec. 75.34(a)(2),
to allow the owner or operator of a unit with add-on SO2 or
NOX emission controls (including units equipped with dry
low- NOX technology) to create and maintain two separate
databases, controlled and uncontrolled, for missing data purposes. Any
hour in which the add-on controls are documented to be operating (on)
would be included in the controlled database. Any hour in which the
controls are not operating (off) would be included in the uncontrolled
database. For units with more than one type of add-on controls (e.g.,
steam injection plus SCR), hours in which any of the add-on controls
operate would be included in the controlled database. Alternatively,
the uncontrolled database could consist of either: (a) quality-assured
data recorded by a certified monitor at the control device inlet; or
(b) for a unit with a main stack and a bypass stack, quality-assured
data recorded by a certified monitoring system installed on the bypass
stack.
If the proposed missing data option in Sec. 75.34(a)(2) were
selected, then, whenever a historical lookback was required, the
substitute data value for each hour of the missing data period would be
taken from the appropriate database (controlled or uncontrolled),
depending on whether the emission controls are documented (by means of
parametric data) to be operating properly during the hour. For the
SO2 missing data algorithms in Sec. 75.33, paragraphs
(b)(1)(i) and (b)(2)(i), which require the hour before and hour after
average value to be reported rather than performing a historical
lookback, proposed Sec. 75.34(a)(2) would restrict the use of the hour
before and hour after value to missing data hours in which the emission
controls are documented to be operating properly; otherwise, the
maximum uncontrolled value recorded in the previous 720 hours would be
reported. The owner or operator would be required, under
Sec. 75.58(b)(3), to keep records of the operational status (on or off)
of the emission controls for all unit operating hours, and to keep
records of the parametric data recorded during periods of missing
SO2 or NOX data. The designated representative
would also be required to submit a certification statement in the
quarterly report, verifying that the add-on controls were operating
properly during each missing data hour in which substitute values from
the controlled database were reported, or, for SO2, each
missing data hour in which the average of the hour before and hour
after values was reported.
The owner or operator of a unit with add-on emission controls would
be allowed to switch to the missing data
[[Page 31983]]
procedures in Sec. 75.34(a)(2) at any time. If, at the time of the
change, the standard missing data procedures of Sec. 75.33 are already
in use, and if hourly calculation of percent monitor data availability
(PMA) is being performed according to Sec. 75.32, it would not be
necessary to repeat the initial missing data procedures of Sec. 75.31.
Rather, calculation of the PMA could continue uninterrupted and the two
emission databases (controlled and uncontrolled) could be created
prospectively. Alternatively, the databases could be created from
historical CEM data, if records are available to document the operating
status (on or off) of the add-on controls during each quality-assured
monitor operating hour. Until the requisite number of hours of quality-
assured data for the lookback periods are recorded (i.e., either 720 or
2,160 hours), the owner or operator would use all available data in
each database for the lookbacks.
Section 75.34(d) of the proposed rule would expand and clarify 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. According to Sec. 75.58(b)(3)(ii) of the current
rule, ``proper operation'' of the controls means that parametric data
were recorded during the missing data period, indicating that, ``all
parameters * * * [were] * * * within the ranges specified in the
quality assurance/quality control program.'' EPA believes that in view
of today's proposed substantive changes to Sec. 75.34, this regulatory
language is inadequate, because it gives no guidelines concerning which
parameters to monitor or how to determine the acceptable parametric
ranges.
EPA therefore proposes to revise Sec. 75.34(d), as follows. The
owner or operator of a unit with add-on controls would, for missing
data purposes, still be required (as in the current rule) to document
in the QA/QC program for the unit the parameter(s) monitored and the
acceptable parametric ranges and combinations of parameters which
indicate proper operation of the emission controls. However, for units
that use a control method involving injection of water, steam, or
chemical reagents into the combustion chamber or flue gas stream (e.g.,
limestone injection, limestone scrubbing, water injection, steam
injection, SCR, or SNCR) today's proposed rule would require at least
one key parameter to be monitored during missing data periods, to
document proper emission control operation. A key parameter would be
one that has a direct relationship to control device removal
efficiency, such as the water-to-fuel ratio, the ammonia injection
rate, or the slurry flow rate.
Further, 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 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 be derived
from a minimum of 720 hours of data, obtained at various load levels,
representing the range of operation of the unit. 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. Finally, the owner or operator would be required to provide to
EPA or to the State, upon request, either the parametric data recorded
during missing data periods or the related QA/QC program information
(or both).
EPA believes that the new proposed missing data option in
Sec. 75.34(a)(2), which conditionally allows the use of substitute data
values taken from a controlled database, would be sufficiently
protective of the environment, for two reasons. First, if the add-on
controls were not working properly when flagged as being on, emissions
would be higher than normal. These high emission values would be
recorded by the CEMS and would become part of the controlled database.
This would result in conservatively high substitute data values being
obtained from the historical lookbacks and applied to controlled
missing data hours. Second, the proposed revisions to Sec. 75.34(d),
requiring the owner or operator to monitor key parameters for certain
types of controls and to develop an actual correlation between the
parametric data and the removal efficiency of the control device, would
provide reasonable assurance that the emission controls are operating
properly during missing data periods.
2. How Will Subpart H Missing Data Provisions Be Affected for Units
That Produce Electrical or Thermal Output?
Background. The missing data procedures for subpart H units are
specified in Secs. 75.70(f) and 75.74(c)(7). Section 75.70(f) requires
the missing data procedures in subpart D of part 75 (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) also requires subpart H sources
that report data on an ozone season-only basis to use the missing data
procedures of subpart D, except that: (1) Only data from within the
ozone season are to be used in the historical lookbacks; and (2) when a
fuel combusted in the current ozone season has a higher NOX
emission rate than the fuel(s) burned in the previous ozone season, or
when a unit's add-on controls are not working properly (as indicated by
recorded parametric data), the maximum potential NOX
emission rate (MER) must be reported.
Discussion of Proposed Changes. Because owners and operators of
subpart H units are required to use the initial and standard missing
data procedures in Secs. 75.31 through 75.37, all of today's proposed
changes to those sections would apply to subpart H units. Therefore,
the owner or operator of a subpart H unit could elect to use either the
new fuel-specific missing data procedures in Sec. 75.33 or, for units
with add-on emission controls, the new missing data procedure in
proposed Sec. 75.34(a)(2).
Today's proposed rule would also revise Sec. 75.74(c)(7), the
section which provides the missing data procedures for subpart H
sources that report emission data only during the ozone season, rather
than on a year-round basis. EPA proposes to make three substantive
revisions to that section.
First, Sec. 75.74(c)(7)(ii) would be revised to require reporting
of the MER only when sufficient, prior quality-assured NOX
emission data are not available for combustion of a new fuel that has a
higher NOX emission rate than any fuel burned in the
previous ozone seasons. Once sufficient quality-assured emission data
are obtained for the new fuel, it would no longer be necessary or
appropriate to report the MER, as NOX emission data for the
new fuel would be in the missing data banks, and the standard,
historical lookbacks could be used to provide representative substitute
data values.
Second, EPA proposes to remove from Sec. 75.74(c)(7)(ii) the
requirement to report the MER when the NOX emission controls
are not working properly, as indicated by parametric data recorded
under Sec. 75.74(c)(8). The requirement to report the MER when the
emission controls are not working properly is associated with the
missing data option in Sec. 75.34(a)(1) and is found in that section.
Therefore, it is unnecessary to restate the requirement in subpart H.
Since proposed Sec. 75.74(c)(7)(ii) requires subpart H units that
report data on an ozone season-only basis to use the missing data
procedures in Secs. 75.31
[[Page 31984]]
through 75.37, owners and operators of such units must follow the
missing data provisions in Sec. 75.34 if the units have add-on
NOX emission controls. This includes the provision in
Sec. 75.34(a)(1), if that missing data option is selected, requiring
the MER to be reported when proper operation of the NOX
emission controls cannot be documented.
Third, today's proposed rule would add a new paragraph (iii), with
subparagraphs (A) through (M), to Sec. 75.74(c)(7), explaining how to
apply the initial and standard part 75 missing data procedures in
Secs. 75.31 through 75.37 on an ozone season-only basis. EPA is 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. For example, 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
consist of quality-assured CEMS data that have been recorded throughout
the year. Also, the percent monitor data availability (PMA)
calculations described in Sec. 75.32 are always based on a particular
number of unit operating hours, either the number of unit operating
hours since initial certification, or the number of unit operating
hours in the past three years, or the previous 8,760 unit operating
hours. The number of unit operating hours used in the PMA calculations
includes operating hours from all four calendar quarters of the year.
Section 75.74, paragraph (c)(7)(i) clearly states that for subpart
H sources that report data on an ozone season-only basis, only data
from within the ozone season are to be included in the missing data
routines. Thus, as written, the missing data procedures in subpart D of
part 75, which use data from all twelve months of the year, are
incompatible with the requirements of Sec. 75.74(c)(7)(i). Despite
this, EPA believes that there is a relatively simple way to resolve
this inconsistency in the rule, as discussed in the following
paragraphs.
Section 75.74, paragraph (c)(7)(iii) in today's proposed rule 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. This adaptation is possible because
there is a commonality between year-round reporting and ozone season-
only reporting--in both cases there is a discrete time period used for
compliance determination. For year-round reporters, that time period is
the calendar year, and for ozone season-only reporters, the compliance
time period is the ozone season. This commonality allows the missing
data instructions for ozone season-only reporters to be written in a
parallel manner to the missing data procedures for year-round
reporters.
Paragraphs (A) through (M) in proposed Sec. 75.74(c)(7)(iii)
provide the necessary parallel rule language to adapt the missing data
provisions in Secs. 75.31 through 75.37 to ozone season-only reporters.
The following is a summary of the essential elements of these proposed
rule provisions:
Use of the initial missing data procedures in Sec. 75.31
would commence with the first operating hour in the first ozone season
for which emission reporting is required.
For initial missing data purposes and for the historical
data lookbacks required under Sec. 75.33, phrases such as ``720
quality-assured monitor operating hours'' would be replaced with
phrases such as ``720 quality-assured monitor operating hours within
the ozone season.''
For PMA calculations, phrases such as ``total unit
operating hours'' would be replaced with ``total unit operating hours
within the ozone season.'' Also, ``8,760 unit operating hours'' (the
number of hours in a calendar year) would be replaced with ``3,672 unit
operating hours'' (the number of hours in an ozone season).
For both PMA calculations and historical lookbacks, the
phrase ``three years (26,280 clock hours)'' would be replaced with
``three ozone seasons.''
3. What Are the Missing Data Requirements for Units That Do not Produce
Electrical or Thermal Output?
Background. Today's proposed rule would add missing data procedures
to part 75 for units that do not generate electricity or produce steam
load. The new missing data provisions would be added to Secs. 75.31 and
75.33, to appendix C of part 75, and to section 2.4 of appendix D. The
rationale for these new provisions and a discussion of the provisions
are presented in the following paragraphs.
As stated in Section II of this preamble, one of the main
objectives of today's proposed rule is to modify the existing
monitoring and reporting sections of parts 72 and 75 which support
emission control programs that use the monitoring and reporting
provisions of part 75, such as State NOX reduction programs
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 electric generating units in their
NOX reduction plans. For example, the State of New York has
proposed regulation 204 to control emissions of nitrogen oxides from
stationary sources. The sources affected by this regulation include EGU
and non-EGU sources, such as industrial boilers and cement kilns. To
comply with sections 204-8 of this regulation, all of the affected
units must monitor and report NOX mass emissions according
to subpart H of 40 CFR part 75, beginning on May 1, 2002. Other States,
including New Jersey, Pennsylvania, Maryland, Delaware, and
Massachusetts have proposed, or may be proposing, similar rules which
require some non-electric generating units to monitor according to
subpart H of part 75. To date, EPA has identified three non-EGU source
categories that would likely be subject to part 75 monitoring and
reporting under the various State rules: industrial boilers, refinery
process heaters, and cement kilns.
At the request of the New York State Department of Environmental
Conservation, EPA examined the part 75 monitoring provisions to assess
whether these provisions are adequate for determining NOX
mass emissions from non-electric generating units. As a result of this
assessment, EPA concluded that for industrial boilers, which produce
thermal output (i.e., steam load) and which are very similar to
electric utility boilers, no significant changes to the monitoring and
reporting provisions of part 75 would be required. However, for cement
kilns and refinery process heaters, which do not produce electricity or
steam load, EPA has identified three key areas where modifications to
the existing part 75 monitoring provisions would be necessary to allow
full and complete monitoring of NOX mass emissions. These
areas are:
Determination of the maximum potential concentration (MPC)
for NOX;
The missing data routines for NOX
concentration, NOX emission rate, stack flow rate, and fuel
flow rate; and
RATA load level requirements.
Discussion of Proposed Changes. To address the first issue
(NOX MPC determination), EPA is proposing to add default MPC
values for process heaters and cement kilns to part 75. The selected
MPC values and the rationale for them are found in section III.F.3 of
this preamble. The third issue (RATA load level requirements) is
discussed in detail in section III.F.10 of this preamble. To address
the second issue (missing data routines), EPA is proposing to add non-
load-based missing data procedures to part 75, as previously noted.
[[Page 31985]]
The missing data procedures in part 75 for NOX, stack
flow rate, and fuel flow rate are load-based. That is, all of the
quality-assured hourly data recorded by part 75 NOX
monitors, flow monitors, and fuel flowmeters are segregated into load
ranges (or ``bins''). The purpose of using the load bin approach is to
ensure that representative substitute data values are provided during
periods of monitor downtime (i.e., for each missing data hour, the
appropriate substitute data value is taken from the corresponding load
bin). However, for units that do not produce electrical or thermal
output, the current part 75 missing data procedures for NOX,
stack flow rate, and fuel flow rate are inadequate.
The missing data procedures for non-load-based units in today's
proposed rule are the result of discussions between EPA and
representatives of the cement industry. The Agency had received a
letter on August 20, 1999, from the American Portland Cement Alliance
(APCA) (see Docket A-2000-33, Item II-D-1), containing a proposed
methodology for performing missing data substitution for NOX
and flow rate at cement kilns. EPA responded to this draft proposal in
a letter to APCA dated April 24, 2000 (see Docket A-2000-33, Item II-C-
2). In that response letter, the Agency expressed agreement with some,
but not all, of the provisions of APCA's proposal. The missing data
approach outlined in today's proposed rule for non-load-based units
reflects EPA's stated position in the April 24, 2000, letter to APCA.
The proposed non-load-based missing data routines are modeled
after, and are much the same as, the existing routines for load-based
units. However, there are two important differences:
The owner or operator of a non-load-based unit would have
the choice of either not using bins at all or using ``operational
bins'' to segregate the quality-assured NOX, stack flow
rate, or fuel flow rate data; and
For a non-load-based unit, the arithmetic average of the
previous 2,160 quality-assured hours of NOX concentration or
NOX emission rate (as applicable) would be used in the
standard NOX missing data routines, instead of the
arithmetic average of the values from the hour before and hour after
the missing data period.
The reason for allowing the use of operational bins is 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 are found
in proposed new sections 3 and 4 of appendix C to part 75. The owner or
operator would be required to provide a complete description of each
operational bin in the hardcopy portion of the monitoring plan required
under Secs. 75.53(e)(2) (for NOX and stack flow rate) or
75.53(f)(1)(ii) (for fuel flow rate). The description of each
operational bin would include the unique combination of parameters and
operating conditions associated with the bin and an explanation of the
relationship between these parameters and conditions and the magnitude
of the NOX emissions, stack flow rates, or fuel flow rates.
When using operational bins, it would be necessary to monitor the
parameter(s) and operating conditions used to define the operational
bin. For any hour in which essential operating or parametric data are
unavailable and the operational bin could not be determined, the
proposed non-load-based provisions in Secs. 75.31 and 75.33 and section
2.4 of appendix D would require maximum potential values to be
reported.
In response to a recommendation by the cement industry, EPA
proposes to use the average of the previous 2,160 quality-assured hours
of NOX data in the standard missing data routines for non-
load-based units instead of using the average of the hour before and
hour after values. APCA advocated this approach in the previously
mentioned missing data proposal that was sent to EPA on August 20,
1999. EPA agrees with APCA's position that hour-to-hour variability of
NOX emissions from a cement kiln is high, and using the hour
before and hour after average could cause significant underestimation
or overestimation of emissions.
4. How Will Today's Proposed Rule Revise the Procedures in Appendix C
for Establishing Load Ranges (or ``bins'') for Missing Data Purposes?
Background and Discussion of Proposed Changes. Today's proposed
rule will revise section 2.2.1 of appendix C to clarify 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. If the actual
efficiency of a particular combustion source is unknown, a default
efficiency of 50 percent would be used for a combustion turbine, and 33
percent for any other type of combustion source. Having established the
maximum hourly gross load, the missing data load ranges would then be
determined as percentages of the MHGL.
5. How Will the Maximum Potential Moisture Provision Be Revised?
Background. For units for which you continuously account for the
stack gas moisture content with a moisture monitoring system,
substitute data must be reported whenever an hourly moisture reading is
missing. When a moisture monitoring system is uncertified, and when the
percent monitor data availability for moisture drops below 80 percent,
the maximum potential moisture percentage or the minimum potential
moisture percentage must be reported (depending upon which emission and
heat input rate equations are used). For the minimum potential moisture
percentage, the rule specifies that the value may be determined from
quality-assured CEM data or a default value of 3 percent H2O
may be used. However, to determine the maximum potential moisture
percentage, the rule requires quality-assured CEM data to be used--no
default value is specified.
Discussion of Proposed Changes. The proposal would add a second
option to section 2.1.6 of appendix A, allowing the use of a default
maximum potential moisture value of 16 percent H2O. This
revision would treat maximum and minimum potential moisture values on a
consistent basis for substitute data purposes.
6. How Will the Proposed Rule Affect the Method of Determination Codes?
Background. Two method of determination codes, MODC values ``13''
and ``15'' from Table 4a under Sec. 75.57, became inactive as of
January 1, 2000. Also, today's proposed rule would add provisions that
require new MODCs that do not appear in the current version of Table
4a.
Discussion of Proposed Changes. EPA proposes to add three new MODC
codes, ``21,'' ``22,'' and ``23'' to Table 4a in Sec. 75.57 for use in
the electronic data reporting (EDR) format, and to designate the
inactive codes ``13'' and ``15'' as ``Reserved.'' MODC 21 would be used
when replacing a negative hourly concentration, emission rate, or
percent moisture value with zero. MODC 22 would be used when an hourly
average
[[Page 31986]]
SO2 or NOX concentration is reported from a
certified monitor at the inlet to an emission control device. MODC 23
would be used when the maximum potential SO2 concentration,
CO2 concentration, NOX concentration,
NOX emission rate, or flow rate, or when the minimum
potential moisture percentage is reported for an hour in which flue
gases are discharged through an unmonitored bypass stack. These changes
will make the specific electronic data reporting format elements
consistent with the rule.
D. Low Mass Emissions (LME) Units
1. What Are the Certification Requirements for Low Mass Emissions (LME)
Units?
Background. In response to concerns raised by both regulated
entities and other regulatory agencies, EPA examined the administrative
procedures pertaining to LME units in part 75. It was determined that
some provisions should be clarified to simplify program implementation
and insure that the LME requirements are consistent with other sections
of part 75.
Discussion of Proposed Changes. The proposed revisions require the
electronic portion of the LME certification application to be sent to
EPA Headquarters (the Clean Air Markets Division) and the hardcopy
portion to the appropriate Region and State. The proposal would also
require LME applications to be submitted no less than 45 days prior to
the date on which use of the methodology will commence.
In addition, EPA proposes to remove the references to January 1,
1997, in Secs. 75.19(a)(2)(ii), 75.19(b)(4), and 75.20(h)(3), as this
date has no regulatory or statutory significance. Instead, the use of
these provisions would depend upon whether a unit is a new or newly
affected unit and to what extent the LME applicability demonstration
relies on the use of projected data, instead of actual, historical
data. The proposal would also clarify the period of provisional
certification for LME units in Sec. 75.20(h)(3), the date on which a
qualifying unit begins using the methodology in Sec. 75.19(a)(1)(ii),
and the certification application submittal process in
Sec. 75.63(a)(1).
2. How Does the LME Methodology Apply to Subpart H Units?
Background. In its current form Sec. 75.19 contains only a limited
explanation of the requirements for units subject to subpart H of part
75 (and not covered under the Acid Rain Program) that are using the LME
methodology to account for emissions. Note that some of these
requirements for subpart H units are the same as those for Acid Rain
Program units.
Discussion of Proposed Changes. Paragraphs (a), (b), and (c) of
Sec. 75.19 would be revised to distinguish the applicability, on-going
qualification, and reporting requirements for Acid Rain Program units
and non-Acid Rain Program, subpart H units. The revisions would make a
clear distinction between sources that report emission data on a year-
round basis and those that report data only during the ozone season.
These changes would help owners and operators of non-Acid Rain Program
units understand how to comply with the LME requirements. Language was
added to clarify that non-Acid Rain Program units using the LME
methodology and the provisions of subpart H of part 75 (to comply with
the monitoring and reporting requirements of a NOX mass
trading program) must submit NOX mass emission data, but are
not required to submit SO2 mass emissions data. In addition,
language was added to clearly state the initial and ongoing
qualification criteria for non-Acid Rain Program units. Specifically,
non-Acid Rain Program units for which you choose to report data year
round under the LME methodology must emit no more than 50 tons of
NOX annually, while units for which you choose to report
only ozone season NOX mass emission data must emit no more
than 25 tons of NOX each ozone season.
3. When Must the Annual Demonstration for LME Units be Completed?
Background. The current rule does not specifically state the
deadline for performing the annual demonstration of LME qualification.
EPA believes that a consistent standard should be used for all units
every year.
Discussion of Proposed Changes. For a unit to continue to qualify
as a LME unit, certain mass emission thresholds must be met on an on-
going basis. These thresholds are: 25 tons SO2 and 50 tons
NOX annually for an Acid Rain Program unit; 50 tons
NOX annually for a non-Acid Rain Program, subpart H unit
reporting on a year-round basis; and 25 tons per ozone season for a
non-Acid Rain Program, subpart H unit reporting on an ozone season
basis only. The owner or operator must demonstrate annually that the
unit does not exceed the applicable mass emissions threshold(s). The
proposed rule would add language to Sec. 75.19(b)(1) to expressly state
that the annual demonstration will be considered complete only when the
official data reconciliation process is complete. More specifically,
only the final emissions data record for the year or ozone season
(i.e., the final accounting of emissions, after data have been fully
reconciled and any necessary quarterly report resubmittals have been
made) will be used to determine whether a unit has met the applicable
mass emissions threshold and satisfied the LME qualification
requirements.
4. How Should EPA Reference Method 20 Be Altered When Determining a
Fuel-and Unit-Specific NOX Emission Rate for an LME Unit?
Background. The Method 20 test procedures require the measured
NOX concentrations to be corrected to 15 percent O2. For
units simply determining the NOX emission rate, this
correction is unnecessary because the measured fuel- and unit-specific
NOX emission rate will be the same whether or not the
concentration is corrected to 15 percent O2.
Discussion of Proposed Changes. Today's proposal would remove the
requirement from Sec. 75.19(c)(1)(iv)(A) that a unit must correct
NOX concentration values to 15 percent O2 when performing
Method 20 testing.
5. What Temperature and Humidity Corrections are Required for Turbines
When Unit- and Fuel-Specific NOX Emission Rates are
Determined for LME Units?
Background. Beginning in the 1999 ozone season, the Ozone Transport
Commission (OTC) NOX Budget Program required monitoring and
reporting of NOX mass emissions for use in a regional
NOX trading program. Each State participating in the program
required monitoring and reporting to be performed according to the
``Guidance for Implementation of Emissions Monitoring Requirements for
the NOX Budget Program'' and the `` NOX Budget
Program Monitoring Certification and Reporting Instructions.'' These
documents required reporting of emissions data in the Electronic Data
Reporting (EDR) version 2.0 format. Under this program, a large number
of small peaking turbines were required to begin monitoring and
reporting data in the EDR v2.0 format. This group of units contains
simple combustion peaking turbines of 15 to approximately 75 MWh
capacity. These units have historically been exempt from the Acid Rain
Program monitoring and reporting under either Sec. 72.6(b)(1), an
exemption for simple turbines built prior to November 15, 1990, or
Sec. 72.7, the new unit exemption. The monitoring and
[[Page 31987]]
reporting options allowed for these type of units in the OTC
NOX Budget Program guidance documents are similar to the
monitoring and reporting provisions under Sec. 75.19 with some key
differences, including the use of a multiplier of 1.15 to all fuel- and
unit-specific NOX emission rates determined using the
testing procedures of appendix E. In the preamble to the May 1999 final
revisions to part 75, EPA states that the reason for the 1.15
multiplier is that the NOX emission rate may vary at a given
load for any particular unit. In particular, EPA was concerned with
possible underestimation of emissions using the results of appendix E
testing to determine fuel- and unit-specific NOX emission
rates.
EPA anticipates that the majority of the simple peaking turbine
units described above will be required to begin monitoring and
reporting data according to the LME provisions under Sec. 75.19 in the
future as part of a larger NOX trading program. Several
utilities asked that the LME requirements under Sec. 75.19 be modified
to allow removal of the 1.15 multiplier to fuel and unit-specific
NOX emission rates. They argued that the requirement to use
a 1.15 multiplier would result in a high overestimation of
NOX emission rates under some circumstances. EPA
investigated the causes of variability in NOX emission rates
in turbines by reviewing literature, reviewing test results, analyzing
CEMS data for turbines, and by 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 (Sec. 60.335).
Discussion of Proposed Changes. The proposal would add a new
requirement for certain turbines to correct measured NOX
concentrations using an equation similar to the equation in subpart GG
of the New Source Performance Standards (40 CFR part 60), for
correcting to the International Organization for Standardization (ISO)
standard ambient conditions. This correction, in
Sec. 75.19(c)(1)(iv)(A)(4), would apply only to uncontrolled diffusion
flame style turbines and 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. If a unit (including an Acid Rain Program unit) is
subject to an ozone season-based NOX mass emission reduction
program, average ozone season values of temperature, atmospheric
pressure, and humidity would be used instead of average annual values.
The proposed rule suggests (but does not require) using National
Oceanic and Atmospheric Administration temperature and humidity data
from the weather station at the nearest airport. This provision would
prevent underestimation or overestimation of NOX emissions
for uncontrolled diffusion flame turbines. Today's proposal also
removes the requirement to multiply the measured NOX
emission rates for such turbines by 1.15, as the new correction
equation would make use of the multiplier unnecessary.
6. How Is Identical Unit Status Demonstrated for a Group of LME Units?
Background. The rule currently requires, in
Sec. 75.19(c)(1)(iv)(B)(1), that to be considered identical a group of
LME units must be of the same manufacturer, model, and size, have the
same history of modifications (e.g., the same controls installed), and
have similar outlet temperatures under similar operating conditions.
Section 75.19(c)(1)(iv)(B)(3) further requires that if there are more
than two identical units in the group, the NOX emission rate
of each unit tested must be within 10 percent of the average emission
rate for all units tested, at each load level.
Discussion of Proposed Changes. The proposal would delete from
Sec. 75.19(c)(1)(iv)(B)(3) the requirement that the emission rate for
each unit must be within 10 percent of the group average rate in order
for a particular unit to be considered an identical unit. These
proposed identical unit provisions in part 75 are based in large part
on comparable provisions used under the Ozone Transport Commission
(OTC) NOX Budget Program. Because the OTC requirements for
identical units have been effective and have minimized the compliance
burdens on LME units, EPA believes that it is appropriate to eliminate
the ten percent requirement from the part 75 LME provisions. The
criteria in Sec. 75.19(c)(1)(iv)(B)(1) for identifying identical units
would be retained, however.
7. How Is the Fuel- and Unit-Specific NOX Emission Rate
Determined for LME Turbines Equipped With Water Injection, Steam
Injection, or Water/Fuel Emulsion, and no Other Type(s) of add-on
NOX Controls?
Background. The current LME provisions in Sec. 75.19 include a
provision which restricts the use of fuel- and unit-specific
NOX emission rates to be no less than 0.15 lb/mmBtu for
units with any type of NOX emission controls. Use of the
0.15 value ensures that large, highly controlled units would not use
the LME provisions for estimating emissions. EPA believes that the LME
provisions are inappropriate for units with such controls as SCR or
SNCR and that NOX emission monitoring is the only effective
way to determine that a unit achieves its target control level.
Industry representatives have asked EPA 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 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 were
within acceptable limits would not underestimate emissions.
EPA investigated the claims of the industry representatives. EPA
reviewed data from CEMS installed at turbines with water and steam
injection and water/fuel emulsion. Based on results of the
investigation, EPA believes that if the water-to-fuel ratio is
monitored, then effective and constant control of NOX is
achieved with little chance of underestimation of NOX
emissions (see Docket A-2000-33, Item II-B-1).
Discussion of Proposed Changes. The proposal would revise
Sec. 75.19(c)(1)(iv)(H)(1) to allow the use of measured NOX
emission rates for units with water or steam injection or water/fuel
emulsion (and no other type(s) of add-on NOX controls) even
if the emission rates are below 0.15 lb/mmBtu. This removes the current
rule requirement that all tested emission rates below 0.15 lb/mmBtu be
adjusted upward to a default value of 0.15 lb/mmBtu. The proposed
action requires 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, making it unnecessary to
use the default value.
[[Page 31988]]
8. What Effect Would Today's Proposed Rule Have on LME Units Sharing a
Common Fuel Supply?
Background. The current LME provisions require that where a group
of units shares a common fuel supply, use the long term fuel flow
(LTFF) methodology for heat input, and use a fuel-and unit-specific
default NOX emission rate, the group of units must perform
the required testing and use the highest tested NOX emission
rate for all units. EPA has reviewed the requirement for taking the
highest NOX emission rate for all units, found it to be
unnecessary, and is proposing to remove the requirement.
Discussion of Proposed Changes. Today's proposal would delete and
reserve Secs. 75.19(c)(1)(iv)(C)(2) and 75.19(c)(1)(iv)(C)(5). These
sections describe unnecessary restrictions for groups of units sharing
a common fuel supply and using the long term fuel flow heat input
approach. It is highly unlikely that an incorrectly apportioned heat
input for units with different efficiencies could lead to improper
estimation of emissions. Therefore, EPA proposes to remove these
restrictions from the rule. In addition, a source would use the highest
rate at each individual unit to calculate emissions from that unit,
rather than using the highest NOX emission rate from the
entire group of units.
9. When Would Single Load Testing Be Allowed to Determine Unit- and
Fuel-Specific NOX Emission Rates for LME Units?
Background. The current LME provisions require four load testing
for all units which opt to determine a default fuel- and unit-specific
NOX emission rate. Several industry representatives asked
that this requirement be waived for units which operate at a single
load only. EPA considered two options as alternatives to the four load
testing requirement.
Option 1. Require the first appendix E test to be performed at all
four loads, then allow future testing to be performed at the load at
which the highest NOX emission rate was found.
Option 2. Allow single load testing for units which submit a
demonstration that a unit operates at a single load.
EPA considers option 2 to be preferable. It allows single load
testing to be performed as of the first test and can save time and
effort, consistent with the intent of the LME provisions to be cost
effective and simple to use. EPA solicits comment on these methods or
other methods suitable for allowing single load testing to be used for
determining fuel- and unit-specific NOX emission rates.
Discussion of Proposed Changes. EPA proposes to add a new provision
to the rule, Sec. 75.19(c)(1)(iv)(I), which would conditionally allow
single load testing for a unit which the owner or operator can
demonstrate has operated at a single load level for at least 85 percent
of the time in the three years prior to the emission test. In addition,
the new section would conditionally allow turbines, that operate to a
set point temperature and not a given load, to perform single load
testing. If a set point turbine is tested at base load, but the unit is
capable of operating at a higher (peak) load and is not tested at peak
load, the fuel- and unit-specific NOX emission rate obtained
from the base load testing would be adjusted upward using a
conservative multiplier of 1.15 to ensure that emissions are not
underestimated when the unit operates at peak load.
10. How Are Unit-Specific, Fuel-Specific NOX Emission Rates
for LME Units Determined From the Individual Test Run Data at Each Load
Level?
Background. The current LME provisions require the use of the
highest emission rate from the appendix E test. This language is not
clear in describing whether the value used was the highest reading of
any run during the test or the average of the required three runs
during the test. In this rulemaking EPA is clarifying its intent that
the three run average from a test is the value used as the fuel- and
unit-specific default emission rate.
Discussion of Proposed Changes. Today's proposal would revise
Sec. 75.19(c)(1)(iv)(C) to clarify the way in which the fuel- and unit-
specific NOX emission rates are calculated for LME units
when four load emission tests are performed. The proposal would add new
language to that section, explaining how to determine the appropriate
NOX emission rates when single load testing is performed.
For four load testing of an individual LME unit, the appropriate
NOX emission rate would be the highest three-run average
obtained at any load level tested. For single load testing, the
NOX emission rate would simply be the three-run average at
the load level tested. For four load testing of a group of identical
LME units, the appropriate NOX emission rate would be the
highest three-run average obtained for any unit in the group, at any
load level tested. For single load testing of a group of identical LME
units, the NOX emission rate would be the highest three-run
average obtained for any tested unit.
11. Which Mathematical Equations Are Affected by the Proposed Changes
to Sec. 75.19?
Background. Today's proposal would correct several equations
pertaining to LME units. These revisions are necessary to correct one
equation and to clarify the nomenclature of several other equations.
Discussion of Proposed Changes. The proposed revisions will correct
Equation LM-1 and clarify the nomenclature for Equations LM-3, LM-5,
LM-6, LM-7, LM-7a, LM-8, and LM-8a.
E. Conditionally Valid Data--Mandatory Use
Background. In the May 26, 1999, revisions to part 75, new CEM data
validation provisions were promulgated. One such provision in
Sec. 75.20(b)(3) addresses the use of conditional data validation. For
recertification testing and diagnostic tests, Sec. 75.20(b)(3) requires
that sources use conditional data validation. For initial
certifications and routine quality assurance, the rule allows, but does
not require, conditional data validation.
Discussion of Proposed Changes. To address the inconsistency in the
rule, Sec. 75.20(b)(3) would be revised to make the use of conditional
data validation optional in all cases. Appendix A, sections 2.1.1.5(c)
and 2.1.2.5(c) and appendix B, sections 2.2.5, would also be revised to
reference the amended Sec. 75.20(b)(3).
F. Quality Assurance/Quality Control (QA/QC)
1. What Changes Are Proposed for CEMS Span and Range Evaluations?
Background. Part 75 requires periodic evaluations (at least
annually) of the spans and ranges of all required continuous monitors
to ensure that the proper span and range values are being used. To
perform the annual span/range evaluation, a review of the emission data
from the past year is required. The results are acceptable if the data
meet the guidelines in section 2.1 of appendix A. The basic requirement
of that section is for the majority of the data to be between 20 and 80
percent of the full-scale range, with certain allowable exceptions.
With the increased emphasis in recent years on reducing
NOX emissions, many new combustion turbines are being built.
The span/range evaluation guideline in section 2.1 of appendix A does
not fully address the issues raised by this type of unit. These units
typically have NOX controls capable of reducing emissions to
very low levels (e.g., 20 ppm or less for oil-firing and
[[Page 31989]]
less than 10 ppm for gas-firing) and are often required by part 75 to
have two measurement ranges (low and high). Some of these units operate
their emission controls only on a seasonal basis, rather than year-
round. One span and range issue for these units is that when natural
gas is combusted, the majority of the NOX emissions may not
meet the 20 to 80 percent guideline of section 2.1 if, for example, the
low-scale measurement range is set at 25 ppm based on oil-firing, in
accordance with section 2.1.2.3 of appendix A. Further, if gas is the
primary fuel in this example and the NOX emissions are
typically 5 ppm or less during gas combustion, one might erroneously
conclude during the annual span/range evaluation that the low range
needs to be adjusted or that a third monitoring range (e.g., 0-10 ppm)
is necessary to measure the gas-fired emissions, in order to meet the
section 2.1 guideline. A second issue is that under appendix A, section
2.1, for dual-span units with add-on emission controls, SO2 or
NOX data recorded on the high monitor range are exempted
from meeting the 20 to 80 percent guideline. However, this exemption is
not appropriate for units with seasonally operated emission controls.
Discussion of Proposed Changes. To address the first issue
described above, the proposed rule would clearly state that for dual-
span units low-range readings below 20 percent of full-scale are
exempted from the 20 to 80 percent guideline, provided that the maximum
expected concentration (MEC) and the low-scale span and range values
have been determined according to the applicable provisions of appendix
A. In the example cited in the Background section above, if the low
measurement range of 25 ppm (based on oil-burning) was properly set
according to section 2.1.2.3 of appendix A, then re-ranging the low
measurement scale would not be appropriate, even if the majority of the
data do not fall between 20 and 80 percent of the range when natural
gas is combusted. This is because the unit is capable of burning oil,
and a low-scale range of 25 ppm, if set according to section 2.1.2.3 of
appendix A, is a good choice for that fuel. Nor would it be necessary
to establish a third monitoring range. Part 75 was never intended to
require more than two monitoring ranges.
To address the second issue described above, the proposed rule
would require units that operate their emission controls seasonally to
meet the 20 to 80 percent guideline on the high measurement range. The
Agency believes it is appropriate for units using their emission
controls seasonally (such as a unit that uses SCR during the summer
only) to meet the 20 to 80 percent guideline on the high range because
emissions data will be recorded on that range for extended periods of
time during the year. This is unlike the case in which controls are
used year-round, where the source is likely to operate without the
controls only on occasion and relatively few readings are recorded on
the high scale.
2. Will EPA Allow Use of Two Separate CEM Systems With Separate Probes
and Sample Interfaces To Meet Dual-Range Requirements?
Background. For units required to have two spans and ranges for
NOX or SO2, the current rule disallows the use of two
separate CEM systems with separate probes and sample interfaces. This
option was excluded because dual-span units often use add-on controls
and have very low emissions. In many cases, the add-on controls are
used year-round, so the emissions remain low virtually all the time.
The low emission levels can make it difficult to perform and pass a
RATA on the high range. Despite this, EPA has received two petitions
requesting permission to use separate systems with separate probes and
interfaces to meet a dual-range requirement (see Docket A-2000-33;
Items II-C-1 and II-D-13). To date, one of these petitions has been
approved, for a unit that operates its NOX controls
seasonally.
Discussion of Proposed Changes. Today's proposal would revise
appendix A, section 2.1 to conditionally allow the use of separate CEMS
with separate probes and interfaces to satisfy dual-range requirements.
The condition is that RATAs of both ranges must be performed and
passed. The revised rule would also state that the two CEMS should be
designated as separate monitoring systems in the monitoring plan.
3. What Changes Would the Proposed Rule Make With Regard to Determining
NOX MPC, MEC, Span, and Range?
Background. EPA receives many questions about the way in which the
MPC, MEC, span, and range are determined for NOX, especially
for new combustion turbines. Some of the questioners have requested
additional options for MPC and MEC determinations and claim that the
rule does not address dry, low-NOX control technology, which
is being used on many new turbines. Others have questioned the
appropriateness of the 50 ppm default value for the MPC of new turbines
in Table 2-2 of appendix A.
Discussion of Proposed Changes. The proposed rule would clarify the
definition of MPC for NOX, making a distinction between
uncontrolled units and units with low NOX burner technology.
The proposal would also revise appendix A, section 2.1 to add a new
option for NOX MPC determination: use of a reliable estimate
of the unit's uncontrolled emissions obtained from the manufacturer. A
new option for MEC would also be added: use of the federally-
enforceable permit limit. The new MEC option could only be used for
units that have add-on emission controls or that use dry, low-
NOX technology.
The 50 ppm default MPC value for new turbines in Table 2-2 would be
removed and replaced 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. These values are much more
representative of actual NOX emissions from turbines during
unit startup and periods when the emission controls are not
operational. EPA requests comment on whether the new values are
representative (see Docket A-2000-33, Item II-B-2).
Finally, default MPC values would be added to the rule for two
categories of non-load-based units: cement kilns and process heaters.
As discussed in more detail under section III.C of this preamble,
certain States are likely to require these two source categories to
report NOX mass emissions under the NOX SIP call.
For cement kilns, an MPC value of 2,000 ppm is proposed; for process
heaters, an MPC value of 200 ppm is proposed for gas-fired units, and
500 ppm for oil-fired heaters. The default MPC value for cement kilns
was determined using NOX emissions data sent to EPA during
pre-proposal discussions between the Agency, representatives of cement
kilns located in New York, and the Portland Cement Association.
NOX emissions data for seven cement kilns were submitted for
review. The data represented more than one year of hourly
NOX concentration values for each of the kilns. EPA selected
2,000 ppm as an appropriate MPC for cement kilns based on the maximum
values reported for these units (see Docket A-2000-33, Item II-I-3).
For process heaters, the Agency evaluated NOX emissions data
submitted in quarterly EDR reports for six process heater units
regulated under the OTC NOX Budget Program. EPA selected the
200 and 500 ppm MPC values based on the maximum NOX
concentration values reported for these units (see Docket A-2000-33,
Item II-I-3). EPA is proposing the default NOX
[[Page 31990]]
MPC values for cement kilns and process heaters principally because an
MPC value would be required in the initial monitoring plan submittal if
these units were to become regulated under the NOX SIP call.
None of the default NOX MPC values in appendix A, section
2.1.2.1 of the current rule are considered to be appropriate for either
cement kilns or process heaters, and emission test results or
historical CEMS data might not be available at the time of initial
monitoring plan submittals from these sources. Therefore, EPA has
proposed default NOX MPC values that can be used for the
initial MPC determinations for cement kilns and process heaters.
4. What Revisions Would Be Made to the 7-day Calibration Error Test for
Peaking Units?
Background. For gas monitors, the 7-day calibration error test is
required only for initial certification, recertification, and
occasionally as a diagnostic test. It is not a routine, required
periodic 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 infrequent and unpredictable
nature of peaking unit operation, the 7-day test may take weeks or even
months to complete.
Discussion of Proposed Changes. Today's proposal would revise the
7-day calibration error test requirement for gas monitors installed on
peaking units in appendix A, section 6.3.1, to require data to be
recorded for only three of the seven test days with the unit operating.
The unit would not be required to operate for the other four days of
the test.
5. What Changes Would Be Made to QA/QC for Units With Very low
NOX Concentrations?
Background. The current rule requires owners and operators of units
with very low SO2 and NOX concentrations to perform RATAs
and daily calibrations on their CEMS. They are required to perform
linearity checks unless the span value is 30 ppm or less (see appendix
A, section 6.2). Appendix B to part 75 provides an alternate daily
calibration specification for low emitters of SO2 and
NOX.
With respect to the daily calibrations of SO2 and
NOX monitors, the allowable calibration error is currently 5
percent of the span value. However, appendix B to part 75 provides an
alternate daily calibration specification for low emitters of SO2
and NOX. The alternative specification for units with low
concentrations (for span values less than 200 ppm) is 10 ppm or less
(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 is not stringent enough and needs to be
tightened. This is especially important because many of the new Acid
Rain-affected gas turbines that are being built have very low
NOX emissions. To illustrate, suppose that for a very low
span value of 10 ppm, the upscale calibration gas for daily
calibrations is 9 ppm. When the 10 ppm alternate calibration error
specification is applied, the monitor could actually be inoperative,
read 0 ppm, and the calibration would still be passed.
Discussion of Proposed Changes. Today's proposal would 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 greater than 50 ppm but less than 200 ppm. 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. The Agency notes that 5 ppm is also the
alternate low-emitter performance specification in section 3.1(b) of
appendix A, for initial certification of SO2 and
NOX monitors.
6. When Would EPA Require the Application of a Calibration Correction
Factor to Linearity or RATA Test Data?
Background. After a routine daily calibration error test, many Data
Acquisition and Handling Systems (DAHSs) apply a mathematical
correction to the subsequent emission data in order to account for the
calibration error. When a linearity check or RATA is initiated after a
daily calibration, the current rule does not specify whether the
mathematical correction factor should be applied to the monitor
readings recorded during the linearity test or RATA.
Discussion of Proposed Changes. EPA proposes to add language to
sections 2.2.3(c) and 2.3.2(c) of appendix B, requiring that if a
mathematical correction factor (calibration adjustment) is applied by
the DAHS following a daily calibration error test, the correction
factor would be applied to all subsequent data recorded by the monitor
until the next calibration error test is performed, including any
linearity test or RATA data recorded in that time interval.
7. What Changes Would Be Made to the Flow-to-Load Ratio Test?
Background. In the May 26, 1999, revisions to part 75, a new
quarterly QA test for flow monitors was promulgated: the flow-to-load
ratio test. Since promulgation, EPA has received many questions about
the 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.
Discussion of Proposed Changes. The proposed rule would allow you
to take the data exclusions listed in section 2.2.5(c) of appendix B
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
clarifies the issue of co-firing as it pertains to data exclusions. For
units that co-fire different fuels as part of their normal operation,
you could claim flow-to-load test data exclusions for hours in which
fuels were not co-fired if the reference flow 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
[[Page 31991]]
weeks'' to ``within 14 unit operating days.''
The proposal would clarify the instructions for multiple stack
configurations and allow you to do the data analysis 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.
8. When Would Three-Load Flow RATAs Be Allowed for Routine Quality
Assurance?
Background. The current rule specifies that an annual two-load flow
RATA is required for routine quality assurance of a flow monitor. The
rule appears to require two-load testing and to disallow three-load
tests for routine QA.
Discussion of Proposed Changes. Today's proposal would clarify in
section 2.3.1.3(c) of appendix B that you may perform a three-load RATA
in lieu of any required two-load flow RATA.
9. What Changes Would Be Made to the Data Analysis Time Period for
Single-Load Flow RATA Claims?
Background. In the May 26, 1999 revisions to part 75, a new
provision was promulgated, allowing annual flow RATAs to be done at a
single load level. To qualify for the single-load option the source
must have operated at one load level (low, mid, or high) for at least
85% of the time since the last annual flow RATA. A historical load
analysis must be done to confirm this, extending from the date and hour
of completion of the last annual flow RATA to a date no less than seven
days prior to the date of the current annual flow RATA. Some utilities
have asked if EPA would consider changing this timeline. Two
suggestions have been offered: (1) Make the end date of the analysis 21
days ahead of the scheduled RATA date; and (2) include in the analysis
all data from the quarter of the last RATA and exclude all data from
the quarter of the current RATA.
Discussion of Proposed Changes. EPA believes that the suggested
revisions are appropriate and would increase the amount of time
available to conduct test planning. The proposal would modify the
timeline for the data analysis in section 2.3.1.3(c) of appendix B, to
allow data to be analyzed from either: (a) The date/hour of the last
annual flow RATA to a date no more than 21 days prior to the current
flow RATA; or (b) the beginning of the quarter in which the last annual
flow RATA was done, through the end of the calendar quarter preceding
the quarter of this year's annual flow RATA.
10. For Units That Do Not Produce Electrical Output or Steam Load, at
What Operating Levels Should Gas and Flow Monitor RATAs Be Performed?
Background. For units that do not produce electrical or thermal
output (e.g., cement kilns and process heaters), today's proposed rule
would provide a method by which to establish the proper ``operating
levels'' (as opposed to ``load levels'') at which to perform relative
accuracy test audits (RATAs). The proposed methodology is found in
section 6.5.2.1 of appendix A. The rationale for, and a discussion of,
these proposed rule provisions is presented in the following
paragraphs.
Units subject to the monitoring and reporting requirements of part
75 must account for their emissions on a continuous basis. Most units
use continuous emission monitoring systems (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 (if the relative accuracy
obtained on the previous RATA was 7.5 percent) annually
thereafter.
Section 6.5.1 of appendix A to part 75 requires that RATAs of gas
monitors be done at the ``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 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.
Discussion of Proposed Changes. As previously discussed in section
III.C of this preamble, EPA anticipates that under the NOX
SIP call, sources such as cement kilns or refinery process heaters,
which do not produce electrical or thermal output, will 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. Today's proposed rule would revise section
6.5.2.1 of appendix A to provide the necessary alternative methodology.
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.
[[Page 31992]]
EPA is aware that for new or newly-affected units, four quarters of
historical load data (for load-based units) or flow rate data (for non-
load-based units) may not be initially available to establish the two
most frequently-used operating loads (or levels) and the normal
operating load (or level). Also, for a non-load-based unit which is not
required to install a flow monitor, the necessary flow rate data for
the determinations will neither be available initially nor at some
point in the future. Therefore, a revision to section 6.5.2.1 (c) of
appendix A is proposed, which would allow the initial determinations to
be made as follows: (1) For load-based units or for non-load-based
units with installed flow monitors, the determinations could be based
on less than four quarters of data, or, if no representative historical
data are available, projections of how the unit will be operated could
be used. Note, however, that as soon as four representative quarters of
load or flow rate data are obtained, the determination of the two most
frequently-used operating loads (or levels) and the normal operating
load(s) (or level(s)) would have to be repeated; or (2) for non-load-
based units without installed flow monitors, sound engineering judgment
(based on a combination of knowledge of the unit, operating experience,
and actual stack gas velocity measurements using EPA Method 2) would be
used to make the operating level determinations.
Once the boundaries of the range of operation are established and
the normal operating level(s) 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.''
Today's 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. The
affected rule sections are: Sec. 75.20(c)(2), sections 6.5.1, 6.5.2,
6.5.6.1(a), and 6.5.6.2(a) of appendix A, and sections 2.3.1.3,
2.3.2(d), 2.3.2(f), 2.4(b), and Figure 1 of appendix B.
G. Streamlining Changes
Background. There are a number of rule sections in part 75 that
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.
EPA notes that the removal of expired provisions will not change
the fact that those provisions were in effect up to their respective
expiration dates. EPA intends to take appropriate enforcement action
against violations of those provisions that occurred before the time of
expiration.
Discussion of Proposed Changes. Today's proposed changes would
streamline 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 May 26, 1999 revisions to part 75 became effective on June 25,
1999. However, the regulatory language in certain sections of the rule
specified that compliance with those sections would not be required
until a later date, April 1, 2000. The reason for the later effective
date of certain provisions was to allow adequate time for development
of the necessary reporting software associated with the rule changes.
For instance, on May 26, 1999, revised recordkeeping and reporting
sections were added to the rule as new Secs. 75.57, 75.58, and 75.59,
to replace the previous recordkeeping and reporting Secs. 75.54, 75.55,
and 75.56, as of April 1, 2000. However, due to the April 1, 2000
effective date of the new sections, the old sections could not be
deleted from part 75, because this would have left a regulatory gap
extending from June 25, 1999 (the effective date of the May 26, 1999
revisions) until April 1, 2000, during which there would have been no
part 75 recordkeeping and reporting requirements in effect. So, the old
sections were left in the rule and language was added to them to
indicate that they were in effect only until April 1, 2000, and could
no longer be used on and after that date.
Other rule sections with April 1, 2000 expiration dates and
effective dates include the monitoring plan provisions (Sec. 75.53,
paragraphs (e) and (f) replaced Sec. 75.53, paragraphs (c) and (d) on
April 1, 2000) and the CO2 missing data provisions
(Sec. 75.35, paragraphs (b) and (d) replaced Sec. 75.35(c) on April 1,
2000). Today's proposal would remove from part 75 all of the rule
sections that expired on April 1, 2000, and all textual references to
those sections.
Rule sections that only applied to Phase I units and are now
inapplicable and textual references to those sections would also be
removed by today's proposal. For example, 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. Today's 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.
EPA has prepared a technical support document (see Docket A-2000-
33, Item II-A-2) that identifies in tabular form each of the
streamlining revisions in the proposed revisions to part 75.
H. Monitoring Plan Information Submittal
1. What Changes Are Proposed in the Timeline for Monitoring Plan
Updates?
Background. In several places part 75 requires the monitoring plan
to be updated following a particular change or event (such as a span
adjustment). For example, Sec. 75.62(a)(2) requires submittal of
updated hardcopy portions of the monitoring plan within 30 days of the
event associated with a change. However, for events that require
updating of the electronic monitoring plan, in many cases no similar
deadline for submitting the changes is specified in part 75.
Discussion of Proposed Changes. Today's proposed rule would add
parallel requirements to Secs. 75.62(a)(1) and 75.73(e) for electronic
monitoring plan updates. It would require the updated electronic
monitoring plan to be submitted within 30 days of the event associated
with a change, unless otherwise specified in part 75.
2. Is EPA Changing the Process for Electronic Submittal of Monitoring
Plan Updates and Certification/Recertification Test Results?
Background. The current rule requires that you submit the complete,
up-to-date electronic monitoring plan to EPA at least 45 days prior to
initial certification, with each certification or recertification
application, and in each quarterly report. The rule also requires an
electronic version of the test results of all monitor certifications
and recertifications to be submitted to EPA.
[[Page 31993]]
To best handle the data, EPA has decided to develop a consistent
process for transmitting and receiving the information.
Discussion of Proposed Changes. Today's proposal would add language
to Secs. 75.62(a)(1), 75.63(c), and 75.73(e)(1), requiring monitoring
plan updates and certification or recertification data to be submitted
electronically by a method specified by EPA. The Agency's goal is to
develop a process by which the required electronic monitoring plan
information and test data could be submitted at any time and the
database would be automatically updated. Until the final goal is
achieved, EPA may use short-term, interim methods, such as email, to
receive the information. The language in today's proposed rule, ``* * *
by a method specified by the Administrator,'' is sufficiently general
to allow the use of such interim methods until the goal is reached.
I. Appendix D--Miscellaneous Issues
Background. In addition to the revisions of the definitions of
pipeline natural gas and natural gas described above in section C of
this preamble, EPA believes that there are a number of other changes
and clarifications that would improve implementation of the excepted
method allowed under appendix D to part 75.
Discussion of Proposed Changes. The proposed rule would modify
section 2.1.2 of appendix D, as follows. EPA proposes to relax the
restriction in section 2.1.2 which prohibits units using the provisions
of subpart H of part 75 to monitor and report NOX mass
emissions (i.e., units subject to a State or federal NOX
emission reduction program) from apportioning the measured hourly heat
input at a common pipe to the individual units served by the pipe. For
subpart H units, revised section 2.1.2 would conditionally allow
apportionment of the common pipe heat input, provided that: (1) All of
the units served by the common pipe are affected units; and (2) all of
the units served by the pipe have similar efficiencies (i.e., they are
all boilers or all combustion turbines). Section 2.1.2 would be further
revised by removing the text from subsection 2.1.2.2 which describes a
petition process for obtaining permission to apportion SO2
emissions to the individual units served by a common pipe. This
petition process is considered to be superfluous, because section 2.1.2
assumes that a certified appendix D fuel flowmeter has been installed
on the common pipe. For SO2 emissions accounting purposes,
it is sufficient to report the combined SO2 emissions for
the units served by the common pipe, based on fuel flow rate
measurements made at the pipe. Thus, revised section 2.1.2 would simply
state that if you install a fuel flowmeter on a common pipe, you should
report combined SO2 emissions from the units served by the
pipe and you should apportion the common pipe heat input to the
individual units using the appropriate equation from appendix F to part
75 (e.g., Equation F-21a or F-21b).
The proposed rule would revise section 2.1.4.1 of appendix D to
exempt oil-fired units that use a different grade of oil only for unit
startup from using a certified fuel flowmeter. This exemption parallels
the existing exemption for oil-fired units that use gas fuel only for
unit startup.
The proposed rule would also revise section 2.1.4.3 of appendix D
to clarify the reporting requirements when emergency fuel is burned.
The owner or operator would have the option during emergency fuel
combustion to either: (1) Use and report maximum potential values for
heat input rate, fuel sulfur content, GCV, and density; or (2) to use
measured values if a certified fuel flowmeter is installed for the
emergency fuel and/or if fuel sampling and analysis of the fuel is
performed.
For temperature transmitter calibrations, EPA would revise section
2.1.6.1(a) of appendix D to allow fixed reference points (such as the
freezing point or boiling point of water) to be used for the zero and
upscale calibrations.
For a subpart H unit for which you report data only during the
ozone season and for which you use an orifice, nozzle, or venturi-type
appendix D fuel flowmeter to determine heat input rate, the proposal
would clarify that the owner or operator still would have to use all
calendar quarters in the year to determine the deadline for the next
visual inspection of the primary element (see Sec. 75.74(c)(4)). This
clarification is appropriate because the 12 calendar quarter time
interval for conducting these visual inspections is not dependent on
the reporting schedule.
For the optional fuel flow-to-load ratio test in section 2.1.7,
minor errors in the instructions for common pipe and multiple pipe
configurations would be corrected. Also, for the optional fuel flow-to-
load ratio test, the proposal would allow data exclusions to be taken
before analyzing the data. The current rule appears to require an
initial data analysis with no exclusions, and allows the data
exclusions to be claimed only when the first analysis results in a
failed test. This was not the original intent when EPA adopted this
provision.
For units using the fuel flow-to-load ratio test to extend the fuel
flowmeter accuracy test deadline, the proposal would clarify the
various reasons for which owners or operators could claim a one-quarter
extension of the fuel flowmeter accuracy test deadline.
Today's proposal would clarify in Tables D-4, D-5, and elsewhere in
the text that owners and operators could not continue to use an assumed
sulfur content or GCV value, such as a contract specification or the
maximum value from the previous year, if a sampled value exceeded the
assumed value. In these circumstances the sampled value would become
the new assumed value.
Guidelines would be added to section 2.3.2.1.2, explaining how to
apply the results of periodic sulfur and GCV samples. Owners and
operators would have to begin using the new values as of the date when
the sample results were received (not retroactively to the date the
sample was taken).
A clarification would be added that the demonstrations of sulfur
content and GCV variability described in sections 2.3.5 and 2.3.6 are
options, not requirements, for units that combust other gaseous fuels
(fuels that do not qualify as either pipeline natural gas or natural
gas) and choose not to perform daily GCV sampling and hourly fuel
sulfur content sampling, respectively. Also, these sections would be
revised to make clear that, as stated in sections 2.3.1.4 and 2.3.2.4,
the 720-hour demonstration methodology may be used to demonstrate that
a particular fuel meets the appropriate GCV and/or sulfur content
requirements to qualify as pipeline natural gas or natural gas.
The missing data requirements for the sulfur content of gaseous
fuels in Table D-6 would be changed. All of the missing data values
would be based on the total sulfur content of the gas. For pipeline
natural gas, a missing data value of 0.002 lb/mmBtu is proposed. For
natural gas, the missing data value would be an emission rate (in lb/
mmBtu) calculated from Equation D-1h, using the lesser of: (a) The
maximum total sulfur content specified in the fuel contract; or (b) 1.5
times the highest total sulfur value from the previous year's samples.
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. For gaseous fuels sampled hourly, the missing data value
would be the highest total sulfur content from the previous 720 hourly
samples. The reason for selecting the 0.002 lb/mmBtu value for pipeline
natural gas (which exceeds the lb/mmBtu equivalent of the 0.5 gr/100
scf total
[[Page 31994]]
sulfur limit in the definition of pipeline natural gas) and for using
the 1.5 multipliers is to ensure that the missing data values will be
higher than the values normally used in the calculations from Table D-
5.
Equations D-10 and D-11 would be removed from section 3.4.3(b).
These equations are not needed because they are redundant with
equations F-21a and F-21b in appendix F. A new equation, D-15a, which
gives the unit heat input rate when multiple fuels are burned during
the hour, would be added to section 3.5.4.
Sections 2.3.1.4(b) and 2.3.2.4(b) of appendix D would be revised
to require initial and periodic sampling of pipeline natural gas and
natural gas for documenting the total sulfur content of fuel. The
proposed sampling frequency is semiannual and whenever ``it is
reasonable to believe that the fuel composition has changed
significantly.'' EPA solicits comment on the acceptability of this
rather subjective ``reasonability'' criterion for determining when an
additional sample is required. For compliance purposes, more precise
language such as, ``Take an additional sample whenever there is any
change to the contract or fuel supply to the unit, such that the latest
sample is no longer representative of the fuel currently being
combusted,'' may be more appropriate.
For fuels that qualify as pipeline natural gas, the 0.0006 lb/mmBtu
default SO2 emission rate would continue to be used. For
natural gas, revised Equation D-1h would be used to calculate the
SO2 emission rate, based on the total sulfur content
sampling results.
Two new sections, 2.3.1.4(c) and 2.3.2.4(c), would be added to
appendix D, to state that if the results of periodic sampling show
exceedances of the applicable total sulfur limits, the fuel would have
to be reclassified.
Finally, as previously noted under section III.C.3 of this
preamble, fuel flow rate missing data provisions for non-load-based
units (such as cement kilns and process heaters) would be added to
section 2.4 of appendix D. Guidelines for creating and using optional
``operational bins'' for determining appropriate fuel flow rate missing
data values for non-load-based units would be added to appendix C of
part 75, as new section 4.
J. Reporting and Recordkeeping
1. Will Certification and Recertification Test Notice Requirements
Change?
Background. For initial certifications, the current rule requires
at least 45 days notice before the first date of scheduled testing. For
recertifications, 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). This raises two questions: (1) Whether the
notification requirements should be the same for both certifications
and recertifications; and (2) how much advance notice is actually
needed.
Discussion of Proposed Changes. The proposed rule changes would
revise 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. Based on the
experience to date in implementing part 75, EPA believes the existing
seven day notice provides too little time for State and local agency
personnel and EPA personnel to schedule site visits to observe the
recertification testing. Conversely, the Agency believes that 45 days
notice is too far in advance, especially for recertifications. 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.
2. Will EPA Continue to Accept Hardcopy Certification Statements?
Background. The current rule allows either electronic or hardcopy
signatures and certification statements for quarterly report
submittals. This creates unnecessary extra work for the EPA analysts
who must document the receipt of all compliance certifications.
Discussion of Proposed Changes. Today's proposal would revise
Sec. 75.64(d) to eliminate the option to submit hardcopy compliance
certifications and would, instead, require electronic submittal.
Because of the electronic reporting requirements for all other
quarterly report elements, all designated representatives will have the
technical capability to submit electronic certifications. This rule
change should therefore reduce the reporting burdens on both the
regulated entities and EPA staff.
3. Will EPA Allow the Electronic Storage of Quality Assurance/Quality
Control Plan Information?
Background. Section 1 of appendix B requires you to develop a
quality assurance/quality control (QA/QC) program for all approved
monitoring systems at a facility. The QA/QC program must include a
written plan that provides detailed procedures and operations for
certain activities, such as preventive maintenance and quality
assurance test procedures. You must make this information and any
ancillary supporting information from the monitor manufacturer (for
example, maintenance manuals) available to auditors upon request. EPA
has received a request from one utility to allow the QA/QC plan
information to be stored electronically rather than in hardcopy.
Discussion of Proposed Changes. Today's proposal would revise
appendix B, section 1, to allow QA/QC plan information to be stored
electronically, provided that the information can be made available in
hardcopy to inspectors or auditors upon request. Part 75 already allows
electronic storage of hardcopy monitoring plan information, if the
information can be furnished in hardcopy upon request during an audit
(see Sec. 75.53(e)). The proposed rule revision would use an approach
for QA/QC plans that is consistent with this existing monitoring plan
provision.
K. NOX Monitoring in Multiple Stacks/Common 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 of the current rule 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.
Also, the current multiple stack and bypass stack provisions for
NOX (see Secs. 75.17(c) and 75.72, paragraphs (c) and (d))
are not particularly clear or consistent.
Discussion of Proposed Changes. EPA would clarify and expand the
instructions for SO2 and NOX monitoring in
multiple and bypass stacks in Secs. 75.16(c) and 75.17(c), and in
Sec. 75.72, paragraphs (c) and (d) in this proposal. EPA would also add
a new provision to Secs. 75.17(c) and 75.72(c), for configurations
consisting of a main stack and a bypass stack, that allows the maximum
potential NOX emission rate to be reported when the bypass
stack is used. Instructions would also be provided for reporting other
parameters (i.e., SO2, CO2, flow rate, moisture,
heat input rate) during hours when the bypass stack is used.
Today's proposed rule would revise the language in Sec. 75.16(c)(3)
which
[[Page 31995]]
restricts the reporting of the maximum potential SO2
concentration (MPC) to emergency situations in which the flue gas
desulfurization (FGD) system is bypassed. Today's rule 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. Instructions would also be provided for reporting other
parameters (i.e., NOX , CO2, flow rate, moisture,
heat input rate) during hours when the bypass stack is used.
L. Appendix E Issues
1. How Will the Proposed Rule Affect Appendix E Test Notifications and
Submittal of Hardcopy Recertification Test Results?
Background. For routine appendix E retests and recertification
testing, the rule is currently unclear regarding the test notification
requirements and submittal of the hardcopy test results.
Discussion of Proposed Changes. The proposal would add a
requirement to Sec. 75.61(a)(5) to provide notice of routine appendix E
retesting at least 21 days prior to the start of the testing. It would
also add a requirement to Sec. 75.61(a)(1)(ii) to provide notice of
appendix E recertification testing. Finally, the proposed rule would
add a requirement to Secs. 75.60(b) and 75.73(d) to submit the results
of routine appendix E retest results in hardcopy to the appropriate
Region and State, upon request. This is exactly analogous to the
requirement in Secs. 75.60(b)(6) and 75.73(d)(4) to provide hardcopy
RATA results.
2. Will the Frequency of Retesting of Appendix E Units Be Changed?
Background. Section 2.2 of appendix E requires periodic retesting
for quality assurance purposes. The timeline for retesting is every
3,000 operating hours or the five year anniversary of the operating
permit, whichever is sooner. These requirements are difficult to
implement and to track. The permit anniversary date is not a good
reference point. Also, the rule does not indicate whether the 3,000
operating hours are fuel-specific.
Discussion of Proposed Changes. Today's proposal would revise
appendix E, section 2.2, to require retesting for all fuels, once every
20 calendar quarters. The quarter of the last test would serve as the
reference point, similar to the methodology used for setting RATA and
fuel flowmeter accuracy test deadlines. Fuel-specific missing data
procedures would be used when a retest is not completed by the
deadline. For each fuel, the new correlation curve obtained in a retest
would be used for reporting, beginning with the first operating hour in
which the fuel is combusted after completion of the retest. This is
analogous to the part 75 requirement to apply CEMS bias adjustment
factors beginning with the first operating hour after completion of a
RATA.
3. How Will the Timeline for Unscheduled Appendix E Retests Be Revised?
Background. Section 2.3 of appendix E requires retesting within 10
unit operating days or 180 calendar days (whichever occurs first)
whenever the monitored operating parameters are exceeded for more than
16 consecutive hours or the data availability, since the last test, is
less than 90 percent. For many units, 10 operating days is not a
sufficient amount of time to schedule a retest and perform the testing.
Discussion of Proposed Changes. EPA proposes to revise appendix E,
section 2.3, to change the 10 unit operating day requirement to 30 unit
operating days. This change would provide sufficient time to schedule
and perform the tests and to meet the applicable test notification
requirements.
4. How Will Appendix E Missing Data Procedures Be Changed?
Background. For missing data purposes, appendix E prescribes that
the highest NOX emission rate from the most recent set of
baseline correlation tests be reported for each hour of the missing
data period. There are three situations for which this missing data
scheme may be inappropriate: (1) When the measured hourly heat input
rate is higher than the highest heat input rate from the baseline
correlation tests; (2) for a unit with add-on NOX controls,
if the controls are not in operation or it is not possible to document
that the controls are operating properly; and (3) when emergency fuel
is combusted.
Discussion of Proposed Changes. To address the concerns about
situations in which the current missing data procedures may be
inappropriate, the proposed rule would add to section 2.5 of appendix E
a requirement to calculate a fuel-specific maximum potential
NOX emission rate (MER) for each type of fuel combusted by
the unit and would add three new sections, 2.5.2.1, 2.5.2.2, and
2.5.2.3, to require reporting of the fuel-specific NOX MER
for cases (2), and (3), described above. For fuel mixtures, EPA would
require substitution of the highest MER value for the fuels in the
mixture.
For case (1) described above, two reporting options would be
allowed. Whenever the heat input rate for a given unit operating hour
exceeds the highest heat input rate from the baseline correlation
tests, the owner or operator could either: (a) Report the hourly
NOX emission rate as the higher of the linear extrapolation
of the correlation curve or the fuel-specific MER; or (b) report 1.25
times the highest NOX emission rate on the correlation
curve, not to exceed the fuel-specific MER. Note that for units with
NOX emission controls, the use of an extrapolated
NOX emission rate under (a), above, and the use of 1.25
times the highest value on the correlation curve under (b), above,
would be disallowed, and the MER would have to be reported for any hour
in which the emission controls could not be documented to be in proper
operation.
5. How Will the Appendix E Testing Requirements for Emergency Fuel Be
Changed?
Background. The current rule allows the designated representative
for an appendix E unit to petition the Administrator for an exemption
from appendix E testing for emergency fuel. Many Phase II Acid Rain
units submitted such petitions with their initial certification
applications, and the petitions were approved.
Discussion of Proposed Changes. Today's proposed rule would revise
section 2.1.4 of appendix E to remove the requirement to petition the
Administrator to obtain an exemption from appendix E testing for
emergency fuel. EPA believes that the petition process is unnecessary,
provided that the unit has a federally enforceable permit which
restricts the combustion of a particular fuel to emergency situations.
Therefore, the proposed rule would exempt emergency fuel from appendix
E testing if the unit has the necessary permit and if documentation is
provided in the monitoring plan for the unit.
M. Reference Methods
1. Which Code of Federal Regulations Versions of Reference Methods Are
To Be Used?
Background. In the May 26, 1999 revisions to part 75, EPA specified
that only particular versions of Reference Methods 6C, 7E, and 3A (the
methods used for gas RATAs) be used. Those versions are the 1995, 1996,
and 1997 Code of Federal Regulations versions of the methods. This
provision was added
[[Page 31996]]
to the rule because EPA at that time had proposed substantive revisions
to these methods for the New Source Performance Standards (NSPS)
Program that were not appropriate for the Acid Rain Program. However,
the revisions to the reference methods were never finalized, therefore
the reference to particular versions is no longer needed. Removing the
caveat will eliminate confusion because these reference methods have
been basically the same in all versions of the Code of Federal
Regulations, from 1988 through 1999.
Discussion of Proposed Changes. Today's proposal would revise
Sec. 75.22(a) and appendix A, section 6.5.6, to remove from the rule
all references to the 1995, 1996, and 1997 Code of Federal Regulations
versions of Reference Methods 6C, 7E, and 3A.
2. Are There Other Changes to Reference Methods?
Background. Three issues have arisen regarding the part 60
reference test methods used to certify and quality assure part 75 CEMS.
First, when measurement of the stack gas moisture content is required
to determine the stack gas molecular weight, Sec. 75.22(a)(4) allows
the source to use any of the alternative moisture techniques listed in
section 1.2 of Method 4. This includes, among other things, ``previous
experience.'' Second, when an automated version of Method 2 is used for
flow RATA testing, often all four available sample ports are occupied
simultaneously with velocity probes which are bolted in place. This can
make it difficult to obtain a moisture sample once every three runs or
once every clock hour, as required in section 6.5.7 of appendix A.
Third, questions have arisen regarding the manner in which
NOX compliance tests and RATAs are performed for combustion
turbines.
Discussion of Proposed Changes. Today's proposed rule would revise
Sec. 75.22(a)(4), to clarify that for purposes of determining the stack
gas molecular weight during a part 75 flow RATA, the only acceptable
alternative moisture methodology listed in section 1.2 of Method 4 is
the wet bulb-dry bulb measurement technique. The other methodologies
listed (``drying tubes,'' ``condensation techniques,'' ``stoichiometric
calculations,'' and ``previous experience'') are not defined precisely
enough to approve their use. In contrast, the wet bulb-dry bulb
technique is well-established and is generally familiar to emission
testers.
Today's proposal would also revise section 6.5.7 of appendix A to
allow, for purposes of determining stack gas molecular weight during
part 75 flow RATAs, moisture measurements to be made before and after a
series of RATA runs at a particular load level (low, mid, or high), in
lieu of measuring moisture every three runs or once every clock hour,
as required by the current rule. The results of the before and after
moisture measurements would be averaged arithmetically, and the average
value would be applied to all RATA runs in the series. Note, however,
that this moisture measurement option could only be used if the before
and after runs were performed no more than three hours apart. Section
6.5.7 would be further revised by clarifying that sufficient
measurement time must be allowed at each traverse point of a flow RATA
to ensure that stable temperature readings are obtained, particularly
for the first point at which data are taken after a probe is moved from
one port to the next.
Finally, today's proposed rule would revise Sec. 75.22 and section
6.5.10 of appendix A, to allow the use of EPA Method 20, as an
alternative to Method 7E, for relative accuracy test audits (RATAs) of
NOX monitoring systems installed on combustion turbines.
Further, the proposed rule would revise section 6.5.6(b) of appendix A,
to allow the reference method measurement points specified in section
6.1.2 of Method 20 to be used for a Method 7E RATA of a NOX
monitoring system installed on a combustion turbine. EPA believes these
added flexibilities will simplify certification and quality assurance
testing for combustion turbines. The rationale for these two new
provisions follows.
Many utilities are constructing new gas turbines. Almost
invariably, NOX monitoring systems will be installed on
these units. EPA Method 20 is the NOX compliance test method
for new gas turbines, under subpart GG of 40 CFR part 60, the New
Source Performance Standards (NSPS) for stationary sources. Method 7E
is the method currently prescribed by part 75 as the reference method
for NOX RATAs. Today's proposed rule would allow Method 20
data to be used for a dual purpose, that is, as compliance test data
for NSPS and as reference method test data for the RATA of the part 75
NOX monitoring system. This would make a second reference
method test using Method 7E unnecessary.
EPA believes that for a Method 7E RATA of a NOX
monitoring system installed on a combustion turbine, allowing the
Method 20 sample points to be used as the reference method measurement
points is potentially beneficial, particularly if the stack or duct
being tested is rectangular. The provisions in section 3.2 of
Performance Specification No. 2 (PS No. 2) in appendix B of 40 CFR part
60 specify the required reference method measurement points for gas
monitor RATAs. However, section 3.2 of PS No. 2 only addresses the
point layout for circular stacks. There are no clear guidelines for
rectangular stacks or ducts. On the other hand, section 6.1.2 of Method
20 does have a procedure for selecting reference method measurement
points which applies to both circular and rectangular stacks or ducts.
N. Appendix G Revisions
Background and Discussion of Proposed Changes. Today's proposed
rule would revise section 2.3 of appendix G to expand the applicability
of Equation G-4 to oil-fired units. Currently, section 2.3 restricts
the use of Equation G-4 to gas-fired units (as defined in Sec. 72.2).
There is no technical reason to prohibit the use of this equation by
oil-fired units. Many gas-fired units that currently use Equation G-4
occasionally combust fuel oil. During the oil-burning hours, Equation
G-4 is still used to report CO2 emissions, except that an
FC factor of 1,420 scf/mmBtu (for oil) instead of the usual
FC factor of 1,040 scf/mmBtu for natural gas is used.
Allowing the use of Equation G-4 for oil-fired units would enable the
owner or operator to report hourly CO2 emissions in tons per
hour, instead of using Equation G-1, which requires CO2
reporting on a tons per day basis. This option would not only simplify
emission reporting for oil-fired units but would enable EPA to perform
meaningful electronic audits of the reported CO2 emissions,
as the hourly heat input (i.e., the term ``H'' in Equation G-4) is the
only variable in Equation G-4 and is required to be reported each hour
in the EDR. However, the cumbersome term WC (i.e., lbs of
carbon burned per day) in Equation G-1 is not reported anywhere in the
EDR.
O. Technical Changes and Corrections
Background. An important objective of this proposed rulemaking is
to make technical changes and corrections to part 75. These changes and
corrections are necessary to eliminate printing, typographical, and
grammatical errors, to correct or clarify cross references, and, in a
few instances, to ensure that the specific rule language is consistent
with the Agency's intent. None of these technical corrections and
changes adds new requirements or substantively
[[Page 31997]]
affects the obligations of the entities that must comply with part 75
requirements.
The technical changes and corrections fall into several categories.
In the first category are efforts to rewrite rule provisions to
increase clarity and to accord with other provisions of part 75. In the
second category are corrections and clarifications of equations,
including the definitions of certain variables. The final category of
technical changes consists of corrections of printing, typographical,
and grammatical errors. Included in this category are repetitive words
and phrases, misspelled words, and misplaced punctuation.
Discussion of Proposed Changes. The technical support document
(Docket A-2000-33, Item II-A-2) provides a specific description for
each of these technical changes and corrections.
P. What Other Changes is EPA Proposing to the Federal NOX
Budget Trading Program Today?
Background and Discussion of Proposed Changes. We are proposing a
number of minor changes to the Federal NOX Budget Trading
Program in part 97 to correct errors or clarify provisions. For
example, one proposed change is to correct the definition of ``percent
monitor data availability'' in Sec. 97.2. This definition is used to
allow units to qualify for early reduction credits in Sec. 97.43(a)(1)
or to qualify to use data as a baseline for allowance allocations for
opt-in units under Sec. 97.84(b). EPA intended to make this definition
consistent with the term's use in the part 75 monitoring rule, except
that ``percent monitor data availability'' would apply only for an
ozone season instead of for a year's worth of data on a rolling basis.
Some companies have pointed out that the current definition is
inconsistent because hours when the unit does not operate are still
used in the calculation. This means that a unit might not be able to
meet the required 90 percent monitor data availability simply because
the unit does not operate for many hours during the ozone season. EPA
is proposing to revise the definition so that it refers to the
percentage of unit operating hours with valid, quality-assured data
during an ozone season, rather than the percentage of all 3,672 hours
during an ozone season.
As a further example of changes to part 97, the definition of ``
NOX allowance'' in Sec. 97.2 provides that the term includes
NOX allowances from an approved State NOX Budget
Trading Program, except for purposes of certain listed sections
relating to allocations. Section 97.40, defining the trading program
budget, is added to that list of sections. In addition, EPA is
correcting the reference in Sec. 97.42(e)(2) to allowances ``deducted
under paragraph (c)(1) of this section'' to refer instead to
``paragraph (e)(1) of this section.'' Other proposed changes to part 97
are addressed in a technical support document (Technical Support
Document, Docket A-2000-33, Item II-A-2). EPA believes these minor
changes may reduce confusion and improve consistency within part 97.
Finally, EPA is proposing a number of other minor changes to part
78 to make existing administrative appeal procedures applicable to
decisions of the Administrator under part 97. The changes to part 78
are addressed in a technical support document (Technical Support
Document, Docket A-2000-33, Item II-A-2).
IV. Administrative Requirements
A. Public Hearing
If requested as specified in the DATES section of this document, a
public hearing will be held to discuss the proposed regulations.
Persons wishing to make oral presentations at the public hearing should
contact EPA at the address given in the ADDRESSES section of this
document. If necessary, oral presentations will be limited to 15
minutes each. Any member of the public may file a written statement
with EPA before, during, or within 30 days of the hearing. Written
statements should be addressed to the Air Docket address given in the
ADDRESSES section of this document.
A verbatim transcript of the public hearing, if held, and all
written statements will be available for public inspection and copying
during normal working hours at EPA's Air Docket in Washington, DC (see
the ADDRESSES section of this document).
B. Public Docket
The Docket for this regulatory action is A-2000-33. The docket is
an organized and complete file of all the information submitted to or
otherwise considered by EPA in the development of this proposed
rulemaking. The principal purposes of the docket are: (1) To allow
interested parties a means to identify and locate documents so that
they can effectively participate in the rulemaking process, and (2) to
serve as the record in case of judicial review. The docket is available
for public inspection at EPA's Air Docket, which is listed under the
ADDRESSES section of this document.
C. Executive Order 12866
Under Executive Order 12866 (58 FR 51735, October 4, 1993), the
Administrator 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 proposed rule is not expected to have an annual effect on the
economy of $100 million or more. However, pursuant to the terms of
Executive Order 12866, it has been determined that this proposed rule
is a significant action because it raises novel policy issues. As such,
the proposed rule has been submitted for OMB review. Any written
comments from OMB and any EPA response to OMB comments are in the
public docket for this proposal.
D. Unfunded Mandates Reform Act
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public
Law 104-4, establishes requirements for federal agencies to assess the
effects of their regulatory actions on State, local, and tribal
governments and the private sector. Under section 202 of the UMRA, EPA
generally must prepare a written statement, including a cost-benefit
analysis, for proposed and final rules with ``federal mandates'' that
may result in expenditures to State, local, and tribal governments, in
the aggregate, or to the private sector, of $100 million or more in any
one year. Before promulgating an EPA rule for which a written statement
is needed, section 205 of the UMRA generally requires EPA to identify
and consider a reasonable number of regulatory alternatives and adopt
the least costly, most cost-effective, or least burdensome alternative
that achieves the objectives of the rule. The provisions of section
[[Page 31998]]
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.
This proposed rule is not expected to result in expenditures of
more than $100 million in any one year and, as such, is not subject to
section 202 of the UMRA. EPA will continue to use its outreach efforts
related to part 75 implementation, including a policy manual that is
updated regularly, to inform, educate, and advise all potentially
impacted small governments about compliance with part 75.
E. Paperwork Reduction Act
The information collection requirements in 40 CFR parts 72, 75, 78
and 97 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, 75, 78 and 97.
First, the Acid Rain Program ICR1633.12, (OMB No. 2060-0258) addresses
the costs for units affected by the Acid Rain Program. The
NOX SIP Call ICR1857.02, (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 are aimed at
fine tuning the 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 proposed changes to parts 72 and 75, and
proposed associated changes to part 97, 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 to parts 72, 78, and 97 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 proposed
rule revisions to the LME section will clarify how the rule applies to
non-ARP SIP Call units that use part 75 for NOX mass
monitoring. The existing rule language is unclear for these non-ARP
units. 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 than 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 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 of LME for Subpart H monitoring
Although not indicated in Table 1, there are two primary ways in
which the proposed parts 72, 75 and 97 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
affected significantly.
The second type of burden or cost increase would be associated with
any required data acquisition and handling system (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 proposed
revisions that would 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. Consequently, the expected impact in this area is
also expected to be minimal. 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.
The Agency requests comment on its assessment of information burden
imposed by these requirements. An ICR amendment was not prepared
because the changes were anticipated to be minimal in the context of
the two existing ICRs. Send comments on the ICRs to the Director,
Collection Strategies Division; U.S. Environmental Protection Agency
(2822); 1200 Pennsylvania Ave., NW, Washington, DC 20460; and to the
Office of Information and Regulatory Affairs, Office of Management and
Budget, 725 17th St., NW, Washington, DC 20503, marked ``Attention:
Desk Officer for EPA.'' Include the ICR in any correspondence.
Additional information in support of the Agency's estimate is contained
in the docket for this proposed rulemaking.
F. Regulatory Flexibility
The Regulatory Flexibility Act (RFA), 5 U.S.C. 601, et seq.,
generally requires an agency to conduct 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
[[Page 31999]]
entities. Small entities include small businesses, small not-for-profit
enterprises, and governmental jurisdictions.
The EPA has determined that it is not necessary to prepare a
regulatory flexibility analysis in connection with this proposed
action. For the Acid Rain Program, these proposed revisions would not
result in increased impacts to small entities.
For these reasons, I certify that today's proposed rule would not
have a significant, economic impact on a substantial number of small
entities.
G. National Technology Transfer and Advancement Act
Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (``NTTAA''), Public Law 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, business practices, etc.) that are developed or adopted by
voluntary consensus standards bodies. The NTTAA requires EPA to provide
Congress, through OMB, explanations when the Agency decides not to use
available and applicable voluntary consensus standards.
EPA invites public comment on the voluntary consensus standards
which are proposed to be incorporated by reference for use in part 75.
EPA has not identified any additional voluntary consensus standards
which might be applicable to this rulemaking. This does not indicate
that other applicable standards do not exist or that any other
standards should not be allowed. Therefore, EPA also invites public
comment on any other voluntary consensus standards which may be
appropriate for the proposed regulatory action. Further, if additional
applicable voluntary consensus standards are identified in the future,
the designated representative may petition under Sec. 75.66(c) to use
an alternative to any standard incorporated by reference and prescribed
in this part.
H. Executive Order 13175
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 proposed 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.
In the spirit of Executive Order 13175, and consistent with EPA
policy to promote communications between EPA and tribal governments,
EPA specifically solicits additional comment on this proposed rule from
tribal officials.
I. Executive Order 12898
Executive Order 12898 requires that each federal agency make
achieving environmental justice part of its mission by identifying and
addressing, as appropriate, disproportionately high and adverse human
health or environmental effects of its programs, policies, and
activities on minorities and low-income populations. The technical
revisions in this proposed rule to various monitoring and other
requirements would have no impact on emission levels or the location of
emission reductions. Thus, the proposed rule revisions would not have a
disproportionately high and adverse impact on minorities or low-income
populations.
J. Executive Order 13045
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 the Agency determines (1) is
``economically significant'' as defined under Executive Order 12866 and
(2) concerns an environmental health or safety risk that EPA has reason
to believe may have a disproportionate effect on children.
Today's proposed rule is not subject to Executive Order 13045
because it is not expected to have an annual effect on the economy of
$100 million or more. Further, EPA does not have reason to believe that
the environmental health risks or safety risks addressed by this action
present a disproportionate risk to children.
K. Executive Order 13132
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'' are 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.''
Under section 6 of Executive Order 13132, EPA may not issue a
regulation that has federalism implications, that imposes substantial
direct compliance costs, and that is not required by statute, unless
the Federal government provides the funds necessary to pay the direct
compliance costs incurred by State and local governments, or EPA
consults with State and local officials early in the process of
developing the proposed regulation. EPA also may not issue a regulation
that has federalism implications and that preempts State law, unless
the Agency consults with State and local officials early in the process
of developing the proposed regulation.
The rule revisions in this proposed action 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 proposed action 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.
In the spirit of Executive Order 13132, and consistent with EPA
policy to promote communications between EPA and State and local
governments, EPA specifically solicits comment on this proposed rule
from State and local officials.
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, Reporting and
[[Page 32000]]
recordkeeping requirements, Sulfur oxides.
40 CFR Part 75
Environmental protection, Acid rain, Administrative practice and
procedure, Air pollution control, Carbon dioxide, Continuous emission
monitoring, Electric utilities, Nitrogen oxides, Reporting and
recordkeeping requirements, Sulfur oxides.
40 CFR Part 78
Environmental protection, Acid rain, Administrative practice and
procedure, Air pollution control, Continuous emission monitoring,
Electric utilities, Nitrogen oxides, Reporting and recordkeeping
requirements, Sulfur oxides.
40 CFR Part 97
Environmental protection, Administrative practice and procedure,
Air pollution control, Continuous emission monitoring, Electric
utilities, NOX Budget Program, Reporting and recordkeeping
requirements.
Dated: May 16, 2001.
Christine Todd Whitman,
Administrator.
For the reasons set out in the preamble, title 40 chapter I of the
Code of Federal Regulations is proposed to be 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'', ``Hour before and after'',
``Maximum potential NOX emission rate'', ``Missing data
period'', ``Monitor accuracy'', ``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
adding the word ``cumulative'' after the words ``at least 168'' and
removing the words ``or more'' at the end of the definition;
i. Remove the definition of ``Heat input'' and add in its place a
new definition ``Heat input rate'';
j. Remove the definition of ``Maximum rated hourly heat input'' and
add in its place the definition for ``Maximum rated hourly heat input
rate'';
k. In the definition of ``Natural gas'' by revising the second
sentence and by removing the word ``meet'', and replacing the ``%''
symbol with the word ``percent'' in the third sentence;
l. In the definition of ``QA operating quarter'' by adding the word
``cumulative'' after each occurrence of the words ``at least 168'';
m. 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'';
n. Adding in alphabetical order new definitions for ``Common
pipe'', ``Common pipe operating time'', ``Cumulative stack operating
hours'', ``Cumulative unit operating hours'', ``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 (percent 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 (percent
CO2); and
(6) A moisture monitoring system, as defined in Sec. 75.11(b)(2) of
this chapter. A moisture monitoring system provides
[[Page 32001]]
a permanent, continuous record of the stack gas moisture content, in
units of percent H2O (percent H2O).
* * * * *
Cumulative stack operating hours means the sum of the stack
operating times (as defined in this section) for a series of
consecutive stack operating hours (as defined in this section), rounded
to the nearest hour.
Cumulative unit operating hours means the sum of the unit operating
times (as defined in this section) for a series of consecutive unit
operating hours (as defined in this section), rounded to the nearest
hour.
* * * * *
Diluent cap value means a default CO2 or O2
concentration which may be used to calculate the hourly NOX
emission rate, CO2 mass emission rate, or heat input rate,
when the measured hourly average CO2 or O2
concentration is below the default value. The diluent cap values for
boilers are 5 percent CO2 and 14 percent O2. For
combustion turbines, the diluent cap values are 1 percent
CO2 and 19 percent O2.
* * * * *
Emergency fuel means:
* * * * *
(2) For purposes of the requirement for stack testing for an
excepted 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.
* * * * *
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 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.
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.
Monitor accuracy means the closeness of the measurement made by a
CEMS to the reference value of the emissions or volumetric flow being
measured, expressed as the difference between the measurement and the
reference value.
* * * * *
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 * * * Natural gas contains 20.0 grains or less of total
sulfur per 100 standard cubic feet. * * *
* * * * *
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 and 7651k.
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 paragraph (b) introductory text by adding the word
``moisture,'' after the word ``opacity,'';
b. In paragraphs (b)(2) and (c)(2) by revising the words ``Not
later than 90''
[[Page 32002]]
to read ``The earlier of 90 unit operating days or 180 calendar'';
c. Remove ``or'' at the end of paragraphs (b)(1) and (c)(1) and
remove the period at the end of paragraphs (b)(2) and (c)(2) and add
``; or'' in its place;
d. Adding paragraphs (b)(3) and (c)(3);
e. 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 removing
the words ``of the affected unit'' after the words ``recommences
commercial operation'';
f. In the first sentence of paragraph (e) introductory text by
revising the words ``90 calendar days'' to read ``90 unit operating
days or 180 calendar days (whichever occurs first)'';
g. Revising paragraphs (f) introductory text and (f)(1);
h. Removing and reserving paragraphs (g) and (h); and
i. In paragraph (i) by removing the word ``or'' in paragraph (i)(1)
and by revising paragraphs (i)(2) and (i)(3).
The revisions and additions read as follows:
Sec. 75.4 Compliance dates.
* * * * *
(b) * * *
(3) The owner or operator shall determine and report SO2
concentration, NOX emission rate, CO2
concentration, and flow data for all unit operating hours after the
applicable compliance date in this paragraph until all required
certification tests are successfully completed using either:
(i) The maximum potential concentration of SO2, the
maximum potential NOX emission rate, as defined in section
2.1.2.1 of appendix A to this part, 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;
(ii) Reference methods under Sec. 75.22(b); or
(iii) Another procedure approved by the Administrator pursuant to a
petition under Sec. 75.66.
(c) * * *
(3) The owner or operator shall determine and report SO2
concentration, NOX emission rate, CO2
concentration, and flow data for all unit operating hours after the
applicable compliance date in this paragraph until all required
certification tests are successfully completed using either:
(i) The maximum potential concentration of SO2, the
maximum potential NOX emission rate, as defined in section
2.1.2.1 of appendix A to this part, 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;
(ii) Reference methods under Sec. 75.22(b); or
(iii) Another procedure approved by the Administrator pursuant to a
petition under Sec. 75.66.
* * * * *
(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. Until all required
certification tests are successfully 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;
* * * * *
(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.
Sec. 75.6 [Amended].
6. In Sec. 75.6 amend paragraphs (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 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
revising the words ``the automated'' to read ``an automated''; and by
revising the first occurrence of the word `` NOX'' in the
first sentence to read `` NOX-diluent'';
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) 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'' 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, 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 capitalization in the title 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.
* * * * *
Sec. 75.11 [Amended].
8. Section 75.11 is amended by:
[[Page 32003]]
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 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 semicolon,
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 revising the word `` NOX'' to
read `` NOX-diluent'' 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. For each unit operating hour in which the
MER is reported, the MER shall be specific to the type of fuel being
combusted in the unit.
* * * * *
10. Section 75.13 is amended by:
a. Revising the heading and first sentence of paragraph (b); and
b. Revising the first sentence of paragraph (c).
The revisions and additions read as follows:
Sec. 75.13 Specific provisions for monitoring CO2
emissions.
* * * * *
(b) Determination of CO2 emissions using appendix G to
this part. If the owner or operator chooses to use the appendix G
method, then the owner or operator shall follow the procedures in
appendix G to this part for estimating daily CO2 mass
emissions based on the measured carbon content of the fuel and the
amount of fuel combusted. * * *
(c) Determination of CO2 mass emissions using an
O2 monitor according to appendix F to this part. The owner
or operator shall determine hourly CO2 concentration and
mass emissions with a flow monitoring system; a continuous
O2 concentration monitor; fuel F and FC factors;
and, where O2 concentration is measured on a dry basis (or
where Equation F-14b in appendix F to this part is used to determine
CO2 concentration), either a continuous moisture monitoring
system, as specified in Sec. 75.11(b)(2), or a fuel-specific default
moisture percentage (if applicable), as defined in Sec. 75.11(b)(1);
and by using the methods and procedures specified in appendix F to this
part. * * *
* * * * *
Sec. 75.15 [ Reserved].
11. Section 75.15 is removed and reserved.
12. Section 75.16 is amended by:
a. Removing and reserving all of paragraph (a);
b. Revising paragraph (b) heading and introductory text and
paragraph (c);
c. Amending paragraphs (e) heading and introductory text, (e)(1),
(e)(2), (e)(3), and (e)(4) by adding the word ``rate'' after each
occurrence of the words ``heat input'' except for the last occurrence
in paragraph (e)(1);
d. In paragraph (e)(1) by revising the reference to ``(a)'' to read
``(b)'' in the first sentence, and by removing ``(a)(1)(ii),
(a)(2)(ii),'' and the comma after ``(b)(1)(ii)'' in the third sentence;
e. In paragraph (e)(2) by revising the words ``appendix F of this
part'' to read ``appendix F to this part''; and
f. In paragraph (e)(3) by adding the words ``, in conjunction with
the appropriate unit and stack operating times'' after the words
``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.
* * * * *
(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), and the maximum potential flow rate, as defined in
section 2.1.4.1 of appendix A to this part. If the bypass stack is also
unmonitored for NOX, CO2, or moisture, report the
following values for each hour in which the bypass stack is used: the
maximum potential CO2 concentration, as defined in section
2.1.3.1 of appendix A to this part, the maximum potential
NOX emission rate, as defined in section 2.1.2.1(b) of
appendix A to this part, the minimum potential moisture percentage, as
defined in section 2.1.5 of appendix A to this part, and, if
O2 concentration is used to determine the hourly heat input
rate, report the minimum potential O2 concentration (as
defined in section 2.1.3.2 of appendix A to this part). The maximum
potential SO2 concentration and the maximum potential
NOX
[[Page 32004]]
emission rate shall be specific to the type of fuel combusted in the
unit during the bypass (see Sec. 75.33(b)(5)). This option 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, flow rate, or any other parameter that
is monitored only at 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 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 shall be specific to the type of
fuel combusted in the unit during the bypass (see Sec. 75.33(c)(8)). In
addition, if SO2, CO2, flow rate, or (if
applicable) moisture monitoring systems are installed only on the main
stack and not on the bypass stack, report the following values for each
hour in which the bypass stack is used: The maximum potential values of
SO2 concentration, CO2 concentration, and stack
gas flow rate, as defined in section 2 of appendix A to this part, the
minimum potential moisture percentage, as defined in section 2.1.5 of
appendix A to this part, and, if O2 concentration is used to
determine the hourly heat input rate, report the minimum potential
O2 concentration (as defined in section 2.1.3.2 of appendix
A to this part). If SO2 emissions and the unit heat input
are determined using a fuel flowmeter in accordance with appendix D to
this part and if CO2 emissions are estimated using the
procedures in appendix G to this part, report SO2 emissions
and CO2 emissions in accordance with appendices D and G to
this part, and report the actual measured heat input rate for each hour
in which the bypass stack is used.
14. Section 75.19 is amended by:
a. Revising paragraphs (a)(1)(i), (a)(1)(ii), (a)(2)(i),
(a)(2)(ii), (b)(1), (b)(2), (b)(3), (c)(1)(iv)(A), (c)(1)(iv)(C), and
(c)(3)(ii)(H);
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'';
c. In paragraph (b)(4)(ii) by revising the words `` NOX,
and CO2'' to read ``CO2, and/or NOX'';
d. In paragraph (b)(4)(iii) by revising the words ``and
NOX'' in the first sentence to read ``and/or
NOX'' and by revising the words ``tables 1, 2 and 3'' to
read ``tables LM-1, LM-2, and LM-3'' in the second sentence;
e. Removing and reserving paragraph (c)(1)(iv)(B)(3);
f. In paragraph (c)(1)(iv)(B)(4) by revising the reference to
``(c)(1)(iv)(B)(3)'' to read ``(c)(1)(iv)(B)(1)'';
g. In the first sentence of paragraph (c)(1)(iv)(D) by revising the
words ``, each unit in a group of units sharing a common fuel supply,
or'' to read ``or group of'';
h. In paragraph (c)(1)(iv)(E) by removing the words ``, each low
mass emission unit in a group of units combusting a common fuel,'';
i. Revising the first and last sentences of (c)(1)(iv)(G);
j. In the first sentence of (c)(1)(iv)(H) by adding the words
``(including units that use dry low-NOX technology),'' after
the first occurrence of the words ``NOX emission controls'';
k. In 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 ``for that hour'';
l. Adding new paragraph (c)(1)(iv)(I);
[[Page 32005]]
m. In paragraph (c)(2)(iii) by revising the word ``output'' to read
``load'' and adding the words ``per hour'' after the words ``pounds of
steam'';
n. In paragraph (c)(2)(iv) by adding the words ``add-on'' after the
words ``unit with'' and adding the words ``(including dry low-
NOX technology)'' after the words ``of any kind'';
o. In paragraph (c)(3)(i) by adding ``HIhr,'' after the
words ``of this section,'' in the first sentence, by revising Eq. LM-1
and the accompanying variable definitions, and by adding a new
paragraph (c)(3)(i)(D);
p. Removing the word ``use'' in the second sentence of paragraph
(c)(3)(ii)(D)(1);
q. Adding a sentence following the first sentence of paragraphs
(c)(3)(ii)(E), (c)(3)(ii)(G), and (c)(4)(ii)(C);
r. In the definition of Mqtr in Equation LM-2 in
paragraph (c)(3)(ii)(E) by removing the word ``entire'';
s. In the definition of Qg in Equation LM-3 in paragraph
(c)(3)(ii)(E) by revising the word ``Value'' to read ``Volume'' and
adding parentheses around the words ``standard cubic feet (scf)'';
t. In paragraph (c)(3)(ii)(F) by adding the words ``, using
Equation LM-4'' after the reference to ``LM-3'';
u. Revising the definition of variables following Equations LM-7
and LM-8 in paragraph (c)(3)(ii)(I), the definition of variables
following Equations LM-7a and LM-8a in paragraph (c)(3)(ii)(J), and the
definitions of the first two variables following Equation LM-10 in
paragraph (c)(4)(ii)(A);
v. In the definition of variable ``EFSO2'' for Equation
LM-9 in paragraph (c)(4)(i) by revising the reference ``table 1'' to
read ``table LM-1'';
w. In paragraph (e)(5) by revising the words ``which have
NOX emission controls of any kind'' to read ``which have
add-on NOX emission controls of any kind (including dry low-
NOX technology)''; and
x. In Table LM-5 that follows paragraph (e) by adding the word
``Other'' before ``Natural Gas'' in the first column of the second
entry of the table.
The revisions and additions read as follows:
Sec. 75.19 Optional SO2, NOX, and CO2
emissions calculation for low mass emissions units.
(a) * * *
(1) * * *
(i) A low mass emissions unit is an affected unit that burns only
natural gas or fuel oil (i.e., diesel fuel or residual oil) and for
which:
(A) An initial demonstration is provided, in accordance with
paragraph (a)(2) of this section, which shows that the unit emits no
more than:
(1) 25 tons of SO2 annually and 50 tons of
NOX annually, for Acid Rain Program affected units
(including units which are also subject to the provisions of subpart H
of this part),
(2) 50 tons of NOX annually, for units which are subject
to the provisions of subpart H of this part and which report emissions
data on a year-round basis, in accordance with Sec. 75.74(b), or
(3) 25 tons of NOX per ozone season, for units which are
subject to the provisions of subpart H of this part and which report
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 emission 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.
(ii) Any qualifying 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 in which the unit (as indicated in the certification
application) will first qualify as a low mass emissions unit; 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 in which the unit (as indicated in the certification
application) will first qualify as a low mass emissions unit.
(2) * * *
(i) If the designated representative submits a certification
application to use the low mass emissions excepted methodology and the
Administrator (or permitting authority) 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
excepted methodology will commence. The certification application must
contain, as applicable, the information in paragraph (a)(2)(i)(A),
(a)(2)(i)(B), or (a)(2)(i)(C) of this section.
(A) Acid Rain Program affected units. For affected units under the
Acid Rain Program (including units which are also subject to the
provisions of subpart H of this part), the certification application
shall contain:
(1) Actual SO2 and NOX mass emissions data
for each of the three calendar years prior to the calendar year in
which the unit will first qualify as a low mass emissions unit,
demonstrating to the satisfaction of the Administrator that the unit
emits no more than 25 tons of SO2 and no more than 50 tons
of NOX annually; and
(2) Calculated SO2 and NOX mass emissions,
for each of the three calendar years prior to the calendar year in
which the unit will first qualify as a low mass emissions unit,
demonstrating to the satisfaction of the Administrator that the unit
emits no more than 25 tons of SO2 and no more than 50 tons
of NOX annually. The calculated emissions for each year
shall be determined using either the maximum rated heat input
methodology described in paragraph (c)(3)(i) of this section or the
long term fuel flow heat input methodology described in paragraph
(c)(3)(ii) of this section, in conjunction with the appropriate
emission rate from paragraph (c)(1)(i) of this section for
SO2 and paragraph (c)(1)(ii) or (c)(1)(iv) of this section
for NOX.
(B) Non-Acid Rain subpart H units reporting on a year-round basis.
For units that are not affected under the Acid Rain Program, but are
subject to the provisions of subpart H of this part, and which report
emissions data on a year-round basis, the certification application
shall contain:
(1) Actual NOX mass emissions data for each of the three
calendar years prior to the calendar year in which the unit will first
qualify as a low mass emissions unit, demonstrating to the satisfaction
of the Administrator (or the permitting authority if subpart H is used
under a State approved SIP) that the unit emits no more than 50 tons of
NOX annually; and
(2) Calculated NOX mass emissions, for each of the three
calendar years prior to the calendar year in which the unit will first
qualify as a low mass emissions unit, demonstrating to the satisfaction
of the Administrator that the unit emits no more than 50 tons of
NOX annually. The calculated emissions for each year shall
be determined using either the maximum rated heat input methodology
described in paragraph (c)(3)(i) of this section or the long term fuel
flow heat input methodology described in paragraph (c)(3)(ii) of this
section, in conjunction with the appropriate NOX emission
rate from paragraph (c)(1)(ii) or (c)(1)(iv) of this section.
(C) Non-Acid Rain subpart H units, reporting ozone season data
only. For units that are not affected under the Acid Rain Program, but
are subject to the provisions of subpart H of this part, and which
report emissions data only
[[Page 32006]]
during the ozone season, the certification application shall contain:
(1) Actual NOX mass emissions data for each of the three
ozone seasons prior to the ozone season in which the unit will first
qualify as a low mass emissions unit, demonstrating to the satisfaction
of the Administrator (or the permitting authority if subpart H is used
under a State approved SIP) that the unit emits no more than 25 tons of
NOX per ozone season; and
(2) Calculated NOX mass emissions, for each of the three
ozone seasons prior to the ozone season in which the unit will first
qualify as a low mass emissions unit, demonstrating to the satisfaction
of the Administrator that the unit emits no more than 25 tons of
NOX per ozone season. The calculated emissions for each
ozone season shall be determined using either the maximum rated heat
input methodology described in paragraph (c)(3)(i) of this section or
the long term fuel flow heat input methodology described in paragraph
(c)(3)(ii) of this section, in conjunction with the appropriate
NOX emission rate from paragraph (c)(1)(ii) or (c)(1)(iv) of
this section.
(ii) When the three full years (or, if applicable, three full ozone
seasons) of actual, historical SO2 and/or NOX
mass emissions data required under paragraph (a)(2)(i) of this section
are not available, the designated representative may submit an
application to use the low mass emissions excepted methodology based
upon a combination of historical SO2 and NOX mass
emissions data and projected SO2 and/or NOX mass
emissions, totaling three years (or ozone seasons). Historical data
must be used for any years (or ozone seasons) in which historical data
exists and projected data should be used for any remaining future years
(or ozone seasons). For example, if an Acid Rain Program 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 (or
newly-affected) unit for which no actual historical data are available,
the designated representative may submit three years of projected
emissions, beginning with the current calendar year. Any actual or
projected annual (or ozone season) 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 default emission rates
in tables LM-1, LM-2, and LM-3 of this section, or, for NOX
emission rate, a fuel-and-unit-specific NOX emission rate
determined in accordance with the testing procedures in paragraph
(c)(1)(iv) 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.
(b) * * *
(1) Once a low mass emission 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
same methodology, from paragraph (c) of this section, by which the unit
initially qualified to use the low mass emissions excepted methodology.
The annual demonstration will be based upon the emissions data which
the Administrator used to determine whether the unit held sufficient
allowances for the calendar year or ozone season.
(2) If any low mass emission 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 emission unit shall be disqualified from using the
low mass emissions excepted methodology as of December 31 of the
following calendar year (for sources that report emission data on a
year-round basis) or as of December 31 of the calendar year in which
the unit exceeds the number of tons of NOX specified in
paragraph (a)(1)(i)(A)(3) of this section (for sources that report
emission data only during the ozone season); and
(ii) The owner or operator of the low mass emission unit shall
install, certify, and report SO2 (Acid Rain Program units
only), NOX, and CO2 (Acid Rain Program units
only) emissions from monitoring systems that meet the requirements of
Secs. 75.11, 75.12, and 75.13 by December 31 of the year after the unit
exceeded the number of tons of SO2 and/or NOX
specified in paragraph (a)(1)(i)(A)(1) or paragraph (a)(1)(i)(A)(2) of
this section (for sources that report emission data on a year-round
basis) or by May 1 of the year after the unit exceeds the number of
tons of NOX specified in paragraph (a)(1)(i)(A)(3) of this
section (for sources that report emission data only during the ozone
season). If the required monitoring systems have not been installed and
certified by the applicable deadline, 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
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 in Table LM-1 in this
section and the maximum hourly unit heat input; the CO2
emissions, in tons/hr, calculated using the applicable default CO2
emission rate in Table LM-3 in this section and the maximum hourly unit
heat input; and the fuel-specific maximum potential NOX
emission rate, as defined in Sec. 72.2 of this chapter.
(3) If a low mass emission 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 (i.e., natural gas, diesel fuel, or residual
oil) 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, certify, and report SO2 (Acid Rain Program units
only), NOX, and CO2 (Acid Rain Program units
only) from monitoring systems that meet the requirements of
Secs. 75.11, 75.12, and 75.13 prior to a change to such fuel. 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,
[[Page 32007]]
NOX and CO2 monitoring system meeting the
requirements of Secs. 75.11, 75.12, and 75.13.
* * * * *
(c) * * *
(1) * * *
(iv) * * *
(A) Except as otherwise provided in this paragraph or in paragraphs
(c)(1)(iv)(F) and (G) of this section, determine a fuel-and-unit-
specific NOX emission rate by conducting a four load
NOX emission rate test procedure as specified in section 2.1
of appendix E to this part, for each type of fuel combusted in the
unit. For a group of units sharing a common fuel supply, the appendix E
testing must be performed on each individual unit in the group, unless
some or all of the units in the group belong to an identical group of
units, as defined in paragraph (c)(1)(iv)(B) of this section, in which
case, representative testing may be conducted on units in the identical
group of units, as described in paragraph (c)(1)(iv)(B) of this
section. For a unit or group of identical units that qualify under
Sec. 75.19(c)(1)(iv)(I), single load testing is allowed in lieu of the
four load testing. For the purposes of this section, make the following
modifications to the appendix E test procedures:
(1) Do not measure the heat input as required under section 2.1.3
of appendix E to this part.
(2) Do not plot the test results as specified under section 2.1.6
of appendix E to this part.
(3) When using method 20 for turbines do not correct the
NOX concentration to 15 percent O2.
(4) If the test is performed on an uncontrolled diffusion flame
turbine (i.e., any turbine not using dry low NOX lean
premixed combustion technology or any turbine without steam or water
injection) a correction to the observed average NOX
concentration from each run of the Method 20 test must be applied using
the following equation:
[GRAPHIC] [TIFF OMITTED] TP13JN01.000
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 (in Hg).
Po = Observed atmospheric pressure during the test run (in
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 (lb moisture/lb air).
Ho = Observed humidity ratio during the test run (lb
moisture/lb 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.R).
Ta = Observed atmospheric temperature during the test run
( deg.R).
(B) * * *
* * * * *
(C) Based on the results of the part 75 appendix E testing,
determine the fuel-and-unit-specific NOX emission rate as
follows:
(1) If a four-load test is performed for an individual low mass
emission unit with no NOX emissions controls of any kind or
for a turbine with water injection, steam injection, or water/fuel
emulsion and no other type of add-on NOX controls, the
highest three run average NOX emission rate obtained at any
load in the part 75 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) If representative four-load testing is performed according to
paragraph (c)(1)(iv)(B)(2) of this section for a group of identical low
mass emission units with no NOX controls of any kind on any
of the units, or for a group of identical turbines with water
injection, steam injection, or water/fuel emulsion on all units and no
other type of add-on NOX controls, 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 load from any unit tested
in the group, for that type of fuel.
(4) If a four-load test is performed for an individual low mass
emission unit which has add-on NOX emission controls (except
for a turbine that uses water injection, steam injection, or water/fuel
emulsion and has no other type of add-on NOX controls), 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 emission rate from any load of the appendix E test
for that type of fuel; or
(ii) 0.15 lb/mmBtu.
(5) [Reserved]
(6) If representative four-load testing is performed according to
paragraph (c)(1)(iv)(B)(2) of this section for a group of identical low
mass emission units having identical add-on NOX controls
(except for a group of identical turbines with water injection, steam
injection, or water fuel emulsion and no other type of add-on
NOX controls), 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 NOX emission rate from all appendix E
tests of all tested units in the group, for that type of fuel; or
(ii) 0.15 lb/mmBtu.
(7) If a single-load test is performed according to
Sec. 75.19(c)(1)(iv)(I) for an individual low mass emission unit with
no NOX emissions controls of any kind or for a turbine with
water injection, steam injection, or water/fuel emulsion and no other
type of add-on NOX controls, the fuel-and-unit-specific
NOX emission rate for a particular type of fuel combusted in
the unit shall be either:
(i) The three run average NOX emission rate obtained in
the appendix E test for that type of fuel; or
(ii) For an uncontrolled turbine which is tested only at base load
and which is capable of operating at a higher load or higher internal
operating temperature, the three run average NOX emission
rate obtained in the appendix E tests for that type of fuel, multiplied
by 1.15.
(8) If representative single-load testing is performed according to
Sec. 75.19(c)(1)(iv)(I) for a group of identical low mass emission
units with no NOX controls of any kind on any of the units,
or an identical group of turbines with water injection, steam
[[Page 32008]]
injection, or water/fuel emulsion and no other type of add-on
NOX controls, the fuel-and-unit-specific NOX
emission rate for all units in the group, for a particular type of fuel
shall be:
(i) The highest three run average NOX emission rate
obtained for that type of fuel in any of the appendix E tests; or
(ii) For a group of uncontrolled turbines which are tested only at
base load and which are capable of operating at a higher peak load or
higher internal operating temperature, the highest three run average
NOX emission rate obtained in any of the appendix E tests
for that type of fuel, multiplied by 1.15.
* * * * *
(G) Low mass emission 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 with add-on NOX emission
controls (excluding turbines with water injection, steam injection, or
water/fuel emulsion and no other type of add-on NOX
controls), 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.
* * * * *
(I) Notwithstanding the requirements in paragraph (c)(1)(iv)(A) of
this section, for a unit (or group of identical units) with no
NOX controls of any kind or for a turbine (or group of
identical turbines) with water injection, steam injection, water/fuel
emulsion, and no other type of add-on NOX controls, single-
load appendix E testing at the normal operating load may be performed
instead of a four load test, if the unit has operated (or if 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 test. To determine whether a unit qualifies for single-load
testing, proceed as follows. 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: 20 MW to 40 MW; band #2: 41 MW to 60 MW; band
#3: 61 MW to 80 MW; and band #4: 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. Determine the
percentage of the data that fall in each load band. For a unit which is
not part of a group of identical units, if 85.0 percent or more of the
data fall within one load band, this is the normal load level for the
unit and 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 percent criterion, then representative single-load
testing within the normal load band(s) may be performed. 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 operation of the turbine, the
internal operating temperature setpoint may be used as a surrogate for
load in demonstrating that the unit qualifies for single-load testing.
To qualify for single load testing, the owner or operator must document
that the unit has operated within 10 percent of the
setpoint temperature for 85.0 percent of the unit operating hours in
the previous 12 calendar quarters. If the setpoint temperature rather
than unit load is used to justify single-load testing, the designated
representative must certify in the monitoring plan for the unit that
this is the manner of operation and must document the setpoint
temperature. If the unit normally operates at a base load setpoint
temperature but is capable of operating in a higher output peak load
when demand requires, then the test must either be performed at peak
load or a multiplier of 1.15 shall be used to adjust a base load test
result to approximate a peak load test result.
* * * * *
(3) * * *
(i) * * *
(B) * * *
[GRAPHIC] [TIFF OMITTED] TP13JN01.030
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 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 quarterly heat input values for the
second and third calendar quarters of the year.
(ii) * * *
(E) * * * 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. * * *
* * * * *
(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 emission unit or each low mass emission 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 Equation 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.
[[Page 32009]]
[GRAPHIC] [TIFF OMITTED] TP13JN01.031
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) * * *
(Eq LM-8 for steam output) * * *
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) * * *
(Eq LM-8a for steam output) * * *
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).
MWqtr all-units = Sum of the quarterly operating
loads (from Eq. LM-5) for all units in the group (MW).
STqtr all-units = Sum of the quarterly steam loads
(from Eq. LM-6) for all units in the group (klb of steam/hr).
(4) * * *
(ii) * * *
(A) * * *
(Eq LM-10) * * *
WNOX = Hourly NOX mass emissions (lbs).
EFNOX = Either the NOX emission factor from Table
LM-2 of this section or the fuel- and unit-specific NOX
emission rate determined under paragraph (c)(1)(iv) of this section
(lb/mmBtu). * * *
* * * * *
(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.
* * * * *
15. Section 75.20 is amended by:
a. Revising paragraphs (b)(2), (b)(3)(i), (c)(2)(ii), (c)(2)(iii),
(c)(4) introductory text, (c)(4)(i) through (iii), (g)(2), (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 the first sentence of paragraph (a)(3) by revising the words
``section for each continuous emission or opacity monitoring system or
component thereof,'' to read ``section, each'', removing the words ``or
component thereof'' after each of the two additional occurrences of the
words ``opacity monitoring system'' in paragraph (a)(3), and 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 paragraphs (b)(3)(iv)(A), (b)(3)(iv)(B), and (b)(3)(vii)(A)
by revising each occurrence of the word ``consecutive'' to read
``cumulative'';
h. Revising the third and fourth sentences of paragraph (b)(5);
i. Removing the second paragraph labeled (c)(1)(v) and paragraph
(h)(4)(iii);
j. Adding new paragraphs (c)(2)(iv) and (h)(5);
k. In paragraph (d)(2)(iii) by removing the words ``or
SO2-diluent'' in the third sentence and by adding the word
``cumulative'' after ``168'' in the fifth sentence;
l. 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;
m. In the third sentence of (d)(2)(vii) by adding the words ``,
beginning with the letters ``LK'' (e.g., ``LK1,'' ``LK2,'' etc.)''
after the words ``replacement analyzer'' and by adding the word
``shall'' before the word ``specify'';
n. Adding a sentence to the end of paragraph (g)(1)(i);
o. In paragraph (g)(5) by adding the words ``(or recertified)''
after the word ``certified'' in the first sentence, 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, removing the word ``either'' from the second sentence, adding
the words ``(or recertified)'' after the word ``certified'' in the
final sentence; and
p. In the last sentence of paragraph (h)(1) by adding the word
``acceptable'' before the word ``water-to-fuel''.
The revisions and additions read as follows:
Sec. 75.20 Initial certification and recertification procedures.
* * * * *
(b) * * *
(2) Notification of recertification test dates. The owner, operator
or designated representative shall submit notice of testing dates for
recertification under this paragraph as specified in
Sec. 75.61(a)(1)(ii).
(3) * * *
(i) The owner or operator shall either use substitute data,
according to the
[[Page 32010]]
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 the hour of successful completion of all
of the required recertification tests. Alternatively, if conditional
data validation is used, as provided in paragraphs (b)(3)(ii) through
(b)(3)(ix) of this section, the owner or operator shall either use
substitute data or shall report data from a certified CEMS or reference
method, beginning with the hour of the replacement, modification, or
change made to the monitoring system until the hour in which a
probationary calibration error test (according to paragraph (b)(3)(ii)
of this section) is passed. Notwithstanding this requirement, 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 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. 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.
* * * * *
(5) Approval or disapproval of request for recertification. * * *
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) * * *
(2) * * *
(ii) Relative accuracy test audits, as follows:
(A) For a flow monitor installed on a peaking unit or bypass stack,
a single-load RATA at the normal load level, as defined in section
6.5.2.1(d) of appendix A to this part; or
(B) For all other flow monitors, a RATA at each of the three load
levels (or operational 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 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
* * * * *
(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 retesting notification for an
excepted monitoring system under appendix E to this part 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) * * *
* * * * *
(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 when a complete certification
application is received, 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)(1)(ii).
(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 32011]]
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)(ii), 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)(1), on an annual basis.
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 operation (e.g.,'' after the words ``higher sulfur
fuel(s)'' in the first sentence, by adding a closing parenthesis after
the words ``short-term testing'' in the first sentence, and by revising
in the last sentence the words ``720 unit (or stack) operating hour
grace period'' to read ``grace period of 720 cumulative unit or stack
operating hours'';
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 by revising in the last
sentence the words ``720 unit (or stack) operating hour grace period''
to read ``grace period of 720 cumulative unit or stack operating
hours''; and
d. In paragraph (e)(2) by removing the word ``another''.
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 and additions 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 removing the period at the end of the
paragraph and replacing it with ``; 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 paragraphs (c) introductory text and (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
[[Page 32012]]
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 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 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;
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. Revising paragraph (a)(2) and the first three sentences of
paragraph (a)(3).
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, upon completion of the first
720 quality-assured monitor operating hours, calculate and record, by
means of the automated data acquisition and handling system, the
percent monitor data availability for the SO2 pollutant
concentration monitor, the CO2 pollutant concentration
monitor, the O2 or CO2 diluent monitor used to
calculate heat input, and the moisture monitoring system (as
applicable). 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, upon completion of the first 2,160 quality-assured monitor
operating hours, calculate and record, by means of the automated data
acquisition and handling system, the percent monitor data availability
for the flow monitor, the NOX-diluent monitoring system, and
the NOX concentration monitoring system (as applicable).
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
calculating and 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.
[GRAPHIC] [TIFF OMITTED] TP13JN01.032
(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 or stack operating hours in the previous three years (26,280 clock
hours), use the words ``in the previous three years'' instead of
``during previous 8,760 unit or stack operating hours'' in Equation 9,
and use ``total unit or stack operating
[[Page 32013]]
hours in the previous three years'' instead of ``8,760.'' * * *
* * * * *
22. Section 75.33 is amended by:
a. Revising paragraphs (a) and (c) introductory text;
b. Adding paragraphs (b)(5), (b)(6), (b)(7), (c)(7), (c)(8),
(c)(9), (c)(10), (d), and (e);
c. In paragraphs (c)(1) introductory text and (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 by adding
the words ``recording during the previous 2,160 quality-assured monitor
operating hours'' before the words ``at the next'';
h. In paragraph (c)(6) by revising the words ``or a higher load
range'' to read ``(or a higher load range) or for the corresponding
operational bin''; and
i. Redesignating Tables 1 and 2 from paragraph to follow paragraph
(c)(9) and revising them.
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
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).
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) The owner or operator may, for units that combust more than one
type of fuel, elect 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. To implement
this option, the owner or operator shall create and maintain a separate
SO2 concentration database for each type of fuel (or blend),
in order to obtain the appropriate substitute data values when that
fuel (or blend) is combusted. Also, for the purposes of providing
substitute data under paragraph (b)(4) of this section, a separate,
fuel-specific maximum potential SO2 concentration (MPC)
value shall be determined for each type of fuel (or blend) 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. The exact methodology used to determine each
fuel-specific MPC value shall be documented in the monitoring plan for
the unit or stack.
(6) If the owner or operator elects to switch from non-fuel-
specific missing data routines to fuel-specific routines (as described
in paragraph (b)(5) of this section) and if, at the time of the change,
the initial missing data procedures of Sec. 75.31 have previously been
completed on a non-fuel-specific basis and the calculation of percent
monitor data availability and use of the standard missing data
procedures has begun in accordance with Secs. 75.32 and 75.33, the
owner or operator need not repeat the initial missing data procedures
on a fuel-specific basis. Rather, the calculation of percent monitor
data availability may continue uninterrupted, and the fuel-specific
SO2 concentration databases may be created prospectively,
beginning at the time of the change. Alternatively, the databases may
be created from historical CEM data, if records are available
documenting the type of fuel combusted during each quality-assured
monitor operating hour. If, at the time of the missing data period,
there is at least one, but fewer than 720 quality-assured monitor
operating hours of fuel-specific SO2 concentration data in a
particular database, use whatever data are in the database, for the
purposes of the lookback periods described in Sec. 75.33, paragraphs
(b)(1)(ii)(A), (b)(2)(ii)(A), and (b)(3). If there are no quality-
assured monitor operating hours of fuel-specific SO2
concentration data in a particular database, report the fuel-specific
MPC value determined under paragraph (b)(5) of this section for each
hour of the missing data period.
(7) Table 1 of this section 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 (as applicable) 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 does not apply to non-load-based affected units
using operational bins. * * *
* * * * *
(7) If there are fewer than 2,160 quality-assured monitor operating
hours in a load range or operational bin, use whatever data are in the
load range or bin for purposes of the lookback periods described in
paragraphs (c)(1)(i), (c)(1)(ii)(A), (c)(2)(i), (c)(2)(ii)(A), (c)(3),
and (c)(5) of this section.
(8) This paragraph (c) (8) does not apply to affected units using
non-load-based operational bins. The owner or operator may, for units
that combust more than one type of fuel, elect to implement the missing
data routines in paragraphs (c)(1) through (c)(7) of this section on a
fuel-specific basis. If this option is selected, the owner or operator
[[Page 32014]]
shall document this in the monitoring plan required under Sec. 75.53.
To implement this option, the owner or operator shall (as applicable)
create and maintain a separate flow rate, NOX emission rate,
or NOX concentration database for each type of fuel, in
order to obtain the appropriate substitute data values when that fuel
is combusted. Also, 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 section 2.1.2.1 or 2.1.4.1 of
appendix A to this part. The exact methodology used to determine each
fuel-specific MPC, MPF, or MER value shall be documented in the
monitoring plan for the unit or stack.
(9) This paragraph (c)(9) does not apply to affected units using
non-load-based operational bins. If the owner or operator elects to
switch from non-fuel-specific missing data routines to fuel-specific
routines (as described in paragraph (b)(8) of this section) and if, at
the time of the change, the initial missing data procedures of
Sec. 75.31 have previously been completed on a non-fuel-specific basis
and the calculation of percent monitor data availability and use of the
standard missing data procedures has begun in accordance with
Secs. 75.32 and 75.33, the owner or operator need not repeat the
initial missing data procedures on a fuel-specific basis. Rather, the
calculation of percent monitor data availability may continue
uninterrupted, and the fuel-specific NOX or flow rate
databases may be created prospectively, beginning at the time of the
change. Alternatively, the databases may be created from historical CEM
data, if records are available documenting the type of fuel combusted
during each quality-assured monitor operating hour. If, at the time of
the missing data period, there is at least one, but fewer than 2,160
quality-assured monitor operating hours of fuel-specific NOX
or flow rate data in a particular load range, use whatever data are in
the load range, for the purposes of the lookback periods described in
paragraphs (c)(1)(i), (c)(1)(ii)(A), (c)(2)(i), (c)(2)(ii)(A), and
(c)(3) of this section. If there are no quality-assured monitor
operating hours of fuel-specific NOX or flow rate data in a
particular load range (or a higher range), report the appropriate fuel-
specific maximum potential value determined under paragraph
(c)(2)(ii)(B)(8) of this section. Tables 1 and 2 follow:
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.................... \y\ HB/HA
N > 24................ For SO2, CO2, and H2O**, ......................
the greater of.
Average.................... HB/HA.
90th percentile \1\........ *720 hours.
For O2 and H2O\x\, the ......................
lesser of.
Average.................... HB/HA.
10th percentile............ *720 hours.
90 or more, but below 95........... N 8....... Average.................... \y\ HB/HA
N > 8................. For SO2, CO2, and H2O**,
the greater of:.
Average.................... HB/HA.
95th percentile \1\........ *720 hours.
For O2 and H2O \x\, the
lesser of:.
Average.................... HB/HA.
5th percentile............. *720 hours.
80 or more, but below 90........... N > 0................. For SO2, CO2, and H2O **, *720 hours.
Maximum value \1\.
For O2 and H2O \x\: Minimum *720 hours.
value \1\.
Below 80........................... N > 0................. Maximum potential None.
concentration \3\ or %
(for SO2, CO2, and H2O **)
or Minimum potential
concentration or % (for O2
and H2O \x\).
----------------------------------------------------------------------------------------------------------------
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 (or ozone seasons)
prior to the missing data period.
\1\ For units with add-on SO2 emission controls, the owner or operator may maintain separate databases of
controlled and uncontrolled emissions and provide substitute data from the appropriate database according to
whether the add-on controls are documented to be operating properly during the missing data period.
\2\ During unit operating hours.
\3\ For units with add-on SO2 controls, you may (if available) report the SO2 concentration from a certified
inlet monitor, in lieu of reporting the MPC.
\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.
\y\ For units with add-on SO2 controls, if the missing data procedures of Sec. 75.34(a)(2) are used, report the
maximum SO2 concentration in the previous 720 quality-assured monitor operating hours in the uncontrolled
database in lieu of HB/HA average value, for each missing data hour in which the add-on controls are not
documented to be operating properly.
[[Page 32015]]
Table 2.--Missing Data Procedure for NOX-Diluent CEMS, NOX Concentration CEMS and Flow Rate CEMS
----------------------------------------------------------------------------------------------------------------
Trigger conditions Calculation routines
----------------------------------------------------------------------------------------------------------------
Duration (N) of Lookback
Monitor data availability CEMS outage Method period (in Load ranges
(percent) (hours) \2\ hours)
----------------------------------------------------------------------------------------------------------------
95 or more..................... N 24.. Average................ 2160 Yes.
N > 24............ The greater of:
Average................ HB/HA No.
90th percentile........ *2160 Yes.
90 or more, but below 95....... N 8... Average................ *2160 Yes.
N > 8............. The greater of:
Average................ HB/HA No.
95th percentile........ *2160 Yes.
80 or more, but below 90....... N > 0............. Maximum value \1\...... *2160 Yes.
Below 80....................... N > 0............. Maximum NOX emission None No.
rate; or maximum
potential NOX
concentration \3\; or
maximum potential flow
rate.
----------------------------------------------------------------------------------------------------------------
HB/HA = hour before and hour after the CEMS outage.
*Quality-assured, monitor operating hours, in the corresponding load range (``load bin'') for each hour of the
missing data period. May be either fuel-specific or non-fuel-specific. If there are 2,160 hours of data in
the load bin, use all data in the bin for the lookback. 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 (or ozone seasons) prior to the missing data period.
\1\ For units with add-on NOX emission controls, the owner or operator may maintain separate databases of
controlled and uncontrolled emissions and provide substitute data from the appropriate database according to
whether the add-on controls are documented to be operating properly during the missing data period.
\2\ During unit operating hours.
\3\ For units with add-on NOX controls, you may report the NOX concentration from a certified inlet monitor (if
available) in lieu of reporting the MPC.
(10) The load-based provisions of paragraphs (c)(1) through (c)(9)
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), (c)(6), and (c)(7) of this section, are
presented in Table 4 of this section.
(d) Non-load-based NOX 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,
as applicable, for each missing hour, the greater of:
(A) 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), or
(B) 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).
(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, as applicable, for each missing hour, the greater of:
(A) 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), or
(B) 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).
(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
[[Page 32016]]
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 section 2.1.2.1 of appendix A to this
part, 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 or the maximum potential NOX
concentration, as defined in section 2.1.2.1 of appendix A to this
part.
(6) If operational bins are used and there is at least one, but
fewer than 2,160 quality-assured monitor operating hours of
NOX emission rate or NOX concentration data in a
particular operational bin, use whatever data are in the bin, for the
purposes of the lookback periods described in paragraphs (d)(1)(i)(B),
(d)(1)(ii)(A), (d)(1)(ii)(B), (d)(2)(i), (d)(2)(ii)(A), (d)(2)(ii)(B),
and (d)(3) of this section.
(7) Table 3 of this section summarizes the provisions of paragraphs
(d)(1) through (d)(6) 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 non-load-based unit, 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 for a non-load-based unit,
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), (c)(8), and (c)(9) are not
applicable; and
(iv) In paragraph (c)(6), the words, ``for either the corresponding
load range (or a higher load range) or for 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
----------------------------------------------------------------------------------------------------------------
Lookback
Monitor data availability (percent) Duration (N) of CEMS Method period (in
outage (hours) \1\ hours)
----------------------------------------------------------------------------------------------------------------
95 or more............................ N24........... Average...................... *2160
The greater of:
N>24..................... Average...................... *2160
90th percentile.............. *2160
90 or more, but below 95.............. N8............ Average...................... *2160
N>8...................... The greater of:
Average...................... *2160
95th percentile.............. *2160
80 or more, but below 90.............. N>0...................... Maximum value................ *2160
Below 80, or operational bin N>0...................... Maximum NOX emission rate or None
indeterminable. maximum potential NOX
concentration.
----------------------------------------------------------------------------------------------------------------
* If operational bins are used, the lookback period is 2,160 quality-assured, monitor operating hours in the
corresponding operational bin. If there are 2,160 hours of data in the operational bin, use all data in the
bin for the lookback. If operational bins are not used, the lookback period is the previous 2,160 quality-
assured monitor operating hours. For units for which data are reported 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 (or ozone seasons) prior to the missing data period.
\1\ During unit operating hours.
Table 4.--Non-Load-Based Missing Data Procedure for Flow Rate CEMS
----------------------------------------------------------------------------------------------------------------
Trigger conditions Calculation routines
----------------------------------------------------------------------------------------------------------------
Monitor data availability Duration (N) of CEMS Lookback period (in
(percent) outage (hours) \1\ Method hours)
----------------------------------------------------------------------------------------------------------------
95 or more......................... N24........ Average.................... *2160
N>24.................. The greater of:
Average.................... HB/HA
90th percentile............ *2160
[[Page 32017]]
90 or more, but below 95........... N8......... Average.................... *2160
N>8................... The greater of:
Average.................... HB/HA.
95th percentile............ *2160
80 or more, but below 90........... N>0................... Maximum value.............. *2160
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 in the corresponding operational bin. If there are 2,160 hours of data in the operational bin, use all
data in the bin for the lookback. 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 (or ozone seasons) prior to the missing data period.
\1\ During unit operating hours.
23. Section 75.34 is amended by:
a. Revising paragraphs (a) introductory text, (a)(1), (a)(2), and
(d);
b. Redesignating paragraph (a)(3) as (a)(4) and adding new
paragraph (a)(3);
c. In the second sentence of newly redesignated paragraph (a)(4) by
removing the words ``Sec. 75.55(b) or'' and ``, as applicable''; and
d. 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 (including
turbines that use dry low- NOX (DLN) technology) shall use
one of the following options 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:
*(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 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) The owner or operator may use the missing data procedures in
Secs. 75.31 through 75.33 for all missing data hours if:
(i) For purposes of the data lookback periods described in
Sec. 75.33, two separate historical databases are created and
maintained. The first (controlled) database shall consist of quality-
assured monitor operating hours of SO2 concentration,
NOX concentration, or NOX emission rate (as
applicable) recorded downstream of the add-on emission controls, when
the add-on controls are in operation (i.e., on). For a unit with more
than one type of add-on controls (e.g., a unit with steam injection and
SCR), the emission data for any hour(s) in which any of the add-on
controls are operating shall be included in the controlled database.
The second (uncontrolled) database shall consist of quality-assured
monitor operating hours of SO2 concentration, NOX
concentration, or NOX emission rate (as applicable) recorded
when none of the add-on emission controls are in operation (i.e., off).
Alternatively, the uncontrolled database may consist of quality-assured
monitor operating hours of data recorded by a certified monitoring
system located at the control device inlet or by a certified monitoring
system installed on a bypass stack (for exhaust configurations in which
the flue gases are occasionally routed through an auxiliary stack,
bypassing the add-on emission controls);
(ii) For each hour of each missing data period, when the
appropriate mathematical algorithm from Table 1 or Table 2 in
Sec. 75.33 requires a lookback for the 90th percentile value, or the
95th percentile value, or the maximum value from the previous 720 (or
2,160) quality-assured monitor operating hours, the value is obtained
from the appropriate database (i.e., from the controlled database if
the add-on controls are documented to be operating properly during the
hour or from the uncontrolled database if the add-on controls are
either not in operation or not documented to be operating properly
during the hour). To provide the necessary documentation, the owner or
operator shall, for each missing data period, record parametric data,
as described in paragraph (d) of this section;
(iii) For SO2, when substitution of the average of the
hour-before and hour-after values is required under
Secs. 75.33(b)(1)(i) or (b)(2)(i), the maximum SO2
concentration recorded in the previous 720 quality-assured monitoring
hours in the uncontrolled database is substituted in lieu of the hour-
before and hour-after value, for each hour of the missing data period
in
[[Page 32018]]
which the add-on controls are either not in operation or are not
documented to be operating properly;
(iv) When the percent monitor data availability (calculated
according to Sec. 75.32) is 80 percent, the maximum potential
SO2 or NOX concentration or the maximum potential
NOX emission rate (as applicable) is substituted for each
hour of the missing data period, in accordance with Sec. 75.33(b)(4)
and (c)(4); and
(v) The designated representative, in accordance with
Sec. 75.64(c), submits as part of each electronic quarterly report a
certification statement verifying the proper operation of the
SO2 or NOX add-on emission controls during each
missing data hour in which substitute data values from the first
(controlled) database are reported, and (if applicable) for
SO2, during each missing data hour in which the average of
the hour before and hour after values is reported.
(3) If the owner or operator elects to switch from the missing data
option in paragraph (a)(1) of this section to the option in paragraph
(a)(2) of this section, and if, at the time of the change, the initial
missing data procedures in Sec. 75.31 have been previously completed
and use of the standard missing data procedures of Sec. 75.33 has
begun, the owner or operator need not repeat the initial missing data
procedures. Rather, calculation of the percent monitor data
availability may continue uninterrupted and the two databases
(controlled and uncontrolled) may be created prospectively, beginning
at the time of the change. Alternatively, the databases may be created
from historical CEM data, if records are available documenting the
operational status (i.e., on or off) of the emission controls during
each quality-assured monitor operating hour. If, at the time of the
missing data period, there are no quality-assured monitor operating
hours of SO2 or NOX data in the appropriate
database for the lookback periods described in Sec. 75.33(b)(1)(ii)(A),
(b)(2)(ii)(A), (b)(3), (c)(1)(i), (c)(1)(i)(A), (c)(2)(i),
(c)(2)(ii)(A), and (c)(3), report the appropriate maximum potential
SO2 or NOX concentration or the maximum potential
NOX emission rate (as applicable) for each hour of the
missing data period. If there is at least one, but fewer than the
requisite number of quality-assured monitor operating hours of
SO2 or NOX data in the appropriate database for
the lookback periods (i.e., either 720 or 2,160 hours, as applicable)
the owner or operator shall use all available data in the database for
the lookbacks.
* * * * *
(d) In order to implement the option in paragraphs (a)(1) and
(a)(2) of this section, the owner or operator shall keep records of
information as described in Sec. 75.58(b)(3)(i) to verify the proper
operation of all add-on SO2 or NOX emission
controls (including dry low- NOX technology), during all
periods of SO2 or NOX emission missing data. 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. If any of the following control methods are used: wet or dry
limestone scrubbing, limestone injection, steam or water injection,
selective catalytic or non-catalytic reduction (i.e., SCR or SNCR), or
any other control method involving injection of water, steam, or
chemical reagents into the combustion chamber or flue gas stream, at
least one key parameter directly related to the control device removal
efficiency shall be monitored. Examples of such key parameters include
the water-to-fuel ratio, the ammonia injection rate, and the slurry
flow rate. Irrespective of which specific parameter(s) are monitored, a
demonstrable correlation between the parametric data and control device
removal efficiency shall be established, as part of the QA/QC program.
The correlation shall be based on parametric data recorded during unit
operation, with the add-on controls in-service and the SO2
or NOX monitor (as applicable) at the control device outlet
providing quality-assured data. EPA recommends that the correlation be
based on a minimum of 720 hours of such data, obtained at various load
levels, covering the range of operation of the unit. The correlation
shall serve as the basis for determining whether to use substitute data
values from the controlled database or from the uncontrolled database,
during periods of missing SO2 or NOX data. 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 an auditor from EPA or
from 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 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 data 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, removing the words ``On and after April 1, 2000,'' in the
third sentence and capitalizing ``When'' to begin that sentence, and by
removing the last 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:
[[Page 32019]]
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).
* * * * *
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'' in the first sentence 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 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 adding the words ``(Eq. 22)''
immediately before ``where,'' in paragraph (b)(2)(v)(B) and by revising
Equation 27 in paragraph (c)(2)(ii) to read as follows:
Sec. 75.41 Precision criteria.
* * * * *
(c) * * *
(2) * * *
(ii) * * *
[GRAPHIC] [TIFF OMITTED] TP13JN01.001
28. Section 75.53 is amended by:
a. Removing and reserving paragraphs (c) and (d);
b. Revising paragraphs (a)(1), (e)(1)(viii), (f)(1)(i)(F), and
(f)(2)(i)(H);
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)(D) by adding the words ``emergency/
startup'' after the words ``primary/secondary'';
e. In paragraph (e)(1)(i)(E) by adding the words ``primary/
secondary controls indicator;'' after the words ``(if applicable);'';
f. In paragraph (e)(1)(ix) by revising the words ``Part 75
monitoring'' to read ``Monitoring'', adding the words ``ARP/Subpart H
facility ORISPL number,'' after the words ``boiler identification
number,'', and adding the words ``(or equivalent)'' after the words
``reporting indicator'';
g. In paragraph (f)(2)(i)(F) by adding the word ``rate'' after the
word ``input'' and the word ``emission'' after the word ``
NOX'';
h. Adding a sentence to the end of paragraph (f)(5)(i); and
i. Adding paragraphs (f)(5)(i)(A) through (H).
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.
* * * * *
(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 daily fuel sampling for sulfur content, if
applicable.
* * * * *
(2) * * *
(i) * * *
(H) To document the unit qualifies as a peaking unit, current
calendar year or ozone season, capacity factor data as specified in the
definition of peaking unit in Sec. 72.2 of this chapter, and an
indication of whether the data are actual, projected, or operating
data.
* * * * *
(5) * * *
(i) * * * 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 or projected NOX
mass emissions for years one, two, and three;
(E) Annual or ozone season NOX mass calculated from
emission factors for years one, two, and three;
(F) Annual measured or projected SO2 mass emissions for
years one, two, and three;
(G) Annual SO2 mass calculated from emission factors for
years one, two, and three; and
(H) 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.
[[Page 32020]]
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);
e. Revising paragraph (d)(6); and
f. Revising the first sentence of paragraph (d)(7).
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
----------------------------------------------------------------------------------------------------------------
Code Hourly emissions/flow measurement or estimation method
----------------------------------------------------------------------------------------------------------------
1........................................... Certified primary emission/flow monitoring system.
2........................................... Certified backup emission/flow monitoring system.
3........................................... Approved alternative monitoring system.
4........................................... Reference method:
SO2: Method 6C.
Flow: Method 2 or its allowable alternatives under appendix A to
part 60 of this chapter.
NOX: Method 7E.
CO2 or O2: Method 3A.
5........................................... For units with add-on SO2 and/or NOX emission controls: SO2
concentration or NOX emission rate estimate from Agency
preapproved parametric monitoring method.
6........................................... Average of the hourly SO2 concentrations, CO2 concentrations, O2
concentrations, NOX concentrations, flow rates, moisture
percentages or NOX emission rates for the hour before and the
hour following a missing data period.
7........................................... Average of the hourly SO2 concentration, CO2 concentration, O2
concentration, NOX concentration, moisture percentage, flow rate,
or NOX emission rate for the hour before and the hour following a
missing data period, using initial missing data procedures.
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 (or, if applicable, a higher
load range), for the applicable lookback period, using the
initial missing data procedures.
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 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 or NOX
emission rate or flow rate, 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.
----------------------------------------------------------------------------------------------------------------
(d) * * *
(6) Hourly average NOX emission rate (for
NOX-diluent monitoring systems only, in units of lb/mmBtu,
rounded to the nearest thousandth);
(7) Hourly average NOX emission rate (for
NOX-diluent monitoring systems only, in units of lb/mmBtu,
rounded to the nearest thousandth), adjusted for bias if bias
adjustment factor is required, as provided in Sec. 75.24(d). * * *
* * * * *
33. Section 75.58 is amended by:
a. Revising the introductory paragraph;
b. In paragraphs (b)(1)(i) and (c) 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'';
[[Page 32021]]
d. Revising paragraph (b)(3);
e. Adding a period to the end of paragraph (c)(7)(ii);
f. In paragraph (d) by removing the words ``paragraph 75.54(d)
or'';
g. In paragraph (e)(1) by removing the words ``Secs. 75.54(c)(1)
and (c)(3) or''; and
h. In paragraph (f) by removing the words ``Secs. 75.54(b) through
(e) or''.
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) For units with add-on SO2 or NOX emission
controls following the provisions of Sec. 75.34(a)(1) or (a)(2), the
owner or operator shall record:
(i) Parametric data which demonstrate, for each hour of missing
SO2 or NOX emission data, the proper operation of
the add-on emission controls, as described in the quality assurance/
quality control program for the unit. The parametric data shall be
maintained on site and shall be submitted, upon request, to the
Administrator, EPA Regional office, State, or local agency;
(ii) A flag indicating, for each hour of missing SO2 or
NOX emission data, either that the add-on emission controls
are operating properly, as described in the quality assurance/quality
control program, or that the add-on emission controls are not operating
properly; and
(iii) For the purposes of creating the controlled and uncontrolled
databases described under Sec. 75.34(a)(2), a flag indicating whether
the add-on emission controls are operating (on) or not operating (off)
during each unit operating hour.
* * * * *
34. Section 75.59 is amended by:
a. Revising the introductory paragraph;
b. Revising paragraphs (a)(1)(vii), (a)(7)(ii)(P) and
(a)(7)(iii)(F);
c. In the second sentence of paragraph (a)(7) by adding the words
``of this section'' after the words ``through (a)(7)(vi)'';
d. In paragraph (a)(10)(i)(E) by revising the reference to
``(a)(7)(iii)(A)'' to read ``(a)(7)(iii)'';
e. In paragraph (b)(2)(v) by adding the word ``level'' after the
word ``high'';
f. In paragraphs (b)(4)(ii)(K) and (b)(5)(i)(N) by removing the
word ``and'' after the semicolon;
g. In paragraph (b)(4)(ii)(L) by removing the period and adding in
its place ``; and'';
h. In paragraph (b)(5)(i)(O) by removing the period and adding in
its place a semicolon;
i. Adding paragraphs (b)(4)(ii)(M), (b)(5)(i)(P), and (b)(5)(i)(Q);
j. In paragraph (c)(1) by removing the words ``Sec. 75.55(b) or'';
k. In paragraph (d)(1) by revising the word ``under'' to read
``using the procedures of'';
l. Adding the word ``and'' at the end of paragraph (d)(1)(xi);
m. Removing paragraphs (d)(1)(xiii) through (d)(1)(xvi);
n. Redesignating existing paragraph (d)(2) as (d)(3) and adding a
new paragraph (d)(2); and
o. In newly designated paragraph (d)(3)(x) by removing the words
``and (3)''.
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) * * *
(1) * * *
(vii) Reference signal or calibration gas level;
* * * * *
(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.
* * * * *
(5) * * *
(i) * * *
(P) Flag to indicate highest NOX emission rate for unit-
specific, fuel-specific NOX emission rate testing; and
(Q) Adjusted NOX default rate (for low mass emission
unit default testing).
* * * * *
(d) * * *
(2) For each single-load or four-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 adding paragraph (b)(7) to read as
follows:
Sec. 75.60 General provisions.
* * * * *
(b) * * *
(7) 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.
* * * * *
36. Section 75.61 is amended by:
a. In paragraph (a)(1) by removing the words ``and except for
testing only of the data acquisition and handling system'' from the end
of that paragraph, by adding a period to 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 number ``45'' to read
``21'';
c. Revising paragraphs (a)(1)(ii) and (a)(1)(iii);
d. 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;
e. In the first sentence of paragraph (a)(2) introductory text by
adding the words ``, or will become affected,'' after the words
``commercial operation'';
f. In paragraph (a)(4) by removing ``(a)'' after the second and
third occurrences of ``Sec. 75.4'';
g. Revising the first sentence of paragraph (a)(5) introductory
text;
h. In paragraph (a)(5)(ii) by adding the words ``, appendix E
retest, or low mass
[[Page 32022]]
emissions unit retest'' after the words ``relative accuracy test''; and
i. 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.
* * * * *
(ii) Notification of certification retesting, recertification
testing, and retesting of low mass emissions units. For retesting
required following a loss of certification under Sec. 75.20(a)(5), for
recertification testing required under Sec. 75.20(b), or for retesting
required under Sec. 75.19(c)(1)(iv)(D), notice of the date of any
required RATA testing, any required retesting under section 2.3 in
appendix E to this part, or any required retesting to determine new
fuel and unit-specific NOX emission rates for low mass
emissions units shall be submitted either in writing or by telephone at
least 21 days prior to the first scheduled day of testing. Testing may
be performed on a date other than that already provided in a notice
under this paragraph (a)(1)(ii) as long as notice of the new date is
provided by telephone or other means at least 7 days prior to the
original scheduled test date or the revised test date, whichever is
earlier.
(iii) Repeat of testing without notice. Notwithstanding the above
notice requirements, the owner or operator may elect to repeat a
certification or recertification test or low mass emissions unit retest
immediately, without advance notification, whenever the owner or
operator has determined during the certification or recertification
testing or low mass emissions unit retesting that a test was failed or
must be aborted, or that a second test is necessary in order to attain
a reduced relative accuracy test frequency.
* * * * *
(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 and'' after the words ``with any'' and the words
``certification or'' after the words ``associated with the''.
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, by a method specified by 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 (for such required updates,
submit the updated electronic monitoring plan within 30 days of the
event with which the monitoring plan change is associated, unless
otherwise specified in this part).
* * * * *
38. Section 75.63 is amended by:
a. Revising paragraphs (a)(1)(i) and (ii), and removing paragraph
(a)(1)(iii);
b. 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)'';
c. Revising the first and second sentences of paragraph (a)(2)(ii);
d. In paragraph (a)(2)(iii) by adding the words ``rather than
certification testing'' after the words ``are required'';
e. Revising paragraph (b)(1)(i);
f. In paragraph (b)(1)(ii) by removing the words ``Sec. 75.56 or''
and ``as applicable,''; and
g. Revising the first sentence of paragraphs (b)(2)(i) and (c).
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). The results of the certification
tests shall also be included in the appropriate electronic quarterly
report submittal under Sec. 75.64. 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 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
paragraph (b)(1)(i) of this section, and a hardcopy certification
application form (EPA form 7610-14); 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), 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, and the
hardcopy information in paragraphs (b)(2)(i), (iii), and (iv) of this
section.
(2) * * *
(ii) Within 45 days after completing all recertification tests
under Sec. 75.20(b), submit the hardcopy information required by
paragraph (b)(2) of this section to the applicable EPA Regional
[[Page 32023]]
Office and the appropriate State and/or local air pollution control
agency. The applicable EPA Regional Office or appropriate State or
local air pollution control agency may waive the requirement to provide
hardcopy recertification test data and results. * * *
* * * * *
(b) * * *
(1) * * *
(i) A complete, up-to-date version of the electronic portion of the
monitoring plan, according to Sec. 75.53(e) and (f), in the format
specified in Sec. 75.62(c).
* * * * *
(2) * * *
(i) Any changed portions of the hardcopy monitoring plan
information required under Sec. 75.53(e) and (f). * * *
* * * * *
(c) Format. The electronic portion of each certification or
recertification application shall be submitted in a format to be
specified by the Administrator and by a method specified by the
Administrator. * * *
39. Section 75.64 is amended by:
a. Revising the first and third sentences of paragraph (a)
introductory text and revising paragraph (a)(2) introductory text;
b. In paragraph (a)(2)(iii) by removing the words ``Sec. 75.54(f)
or'';
c. In paragraph (a)(2)(iv) by removing the words ``Sec. 75.55(b)(3)
or'';
d. In paragraph (a)(2)(vi) by removing the words ``Sec. 75.54(g)
or'';
e. In paragraph (a)(2)(vii) by removing the words ``Sec. 75.56
or'';
f. In paragraph (a)(2)(viii) by removing the words
``Sec. 75.56(a)(5)(vii), Sec. 75.56(a)(5)(ix),'';
g. In paragraph (a)(2)(xi) by removing the words ``Sec. 75.56(a)(7)
or'';
h. 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'';
i. Removing and reserving paragraphs (a)(2)(v), (a)(8), and (e);
j. In paragraph (d) by removing the words ``or hardcopy''; and
k. In paragraph (f) by removing the words ``modem and''.
The revisions 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). * * * For an affected unit
subject to Sec. 75.4(d) that is shutdown on the relevant compliance
date in Sec. 75.4(a) or has been placed in long-term cold storage, the
owner or operator shall submit quarterly reports for the unit beginning
with the data from the quarter in which the unit recommences commercial
operation (where the initial quarterly report contains hourly data
beginning with the first hour of recommenced commercial operation of
the unit). * * *
* * * * *
(2) The information and hourly data required in Sec. 75.53 and
Secs. 75.57 through 75.59, excluding the following:
* * * * *
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,''; and
b. 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 paragraphs (e), (f) introductory text, and (f)(1)
introductory text;
d. 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'';
e. In paragraphs (f)(1)(ii) and (iii) by removing the word ``or''
from the end of each paragraph;
f. In paragraph (f)(1)(iii) by adding the word ``rate'' before the
word ``data'', revising the word ``mmBtu'' to read ``mmBtu/hr'', and
revising the word ``accepted'' to read ``excepted'';
g. 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;
h. Adding new paragraph (f)(1)(v);
i. In paragraph (g)(1) by adding the word ``rate'' after the words
``and heat input'';
j. In paragraph (g)(2) by revising the words ``of the unit under
section 2.1'' to read ``, as defined in section 2.1.4.1''; and
k. 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) Missing data procedures. Except as provided in
Sec. 75.74(c)(7), the owner or operator shall provide substitute data
from monitoring systems required under Sec. 75.71 for each affected
unit as follows:
(1) For an owner or operator using a continuous emissions
monitoring system, substitute for missing data in accordance with the
applicable missing data procedures in Secs. 75.31 through 75.37
whenever the unit combusts fuel and:
* * * * *
(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 Secs. 75.11(b) or 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 adding the word
``rate'' after
[[Page 32024]]
the words ``measure heat input'', by removing the word ``use'' after
the words ``if applicable,'', and by adding the words ``may be used''
after the words ``appendix D to this part'';
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'';
e. In the first and second sentences of paragraph (c)(2) by adding
the word ``rate'' after the words ``heat input''; and
f. In paragraph (d)(2) by removing the words ``or, if applicable,
paragraph (e) of this section'', by revising the reference in
``paragraph (c)'' to read ``paragraph (c)(1) or (c)(2)'', and by adding
two new sentences to the end of the paragraph.
The revisions and additions read as follows:
Sec. 75.71 Specific provisions for monitoring NOX and heat
input for the purpose of calculating NOX mass emissions.
* * * * *
(d) * * *
(2) * * * 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. For each unit operating hour in which the MER
is used for NOX mass reporting, the MER shall be specific to
the type of fuel being combusted in the unit.
* * * * *
44. Section 75.72 is amended by:
a. Revising the first sentence of the introductory paragraph to the
section;
b. Revising paragraphs (a)(1) introductory text and (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'' and by adding the words
``and a diluent monitor'' after the word ``system'' in newly
redesignated paragraph (a)(1)(iii)(B);
e. In paragraph (a)(2) introductory text by adding the words ``,
for purposes of heat input determination,'' after the words ``from each
unit and'';
f. In paragraph (a)(2)(ii)(A) by adding the word ``rate'' after the
words ``heat input'';
g. In paragraph (b)(1) introductory text by removing the semicolon
and adding the words ``, for purposes of heat input determination,'' at
the end of the paragraph;
h. In paragraph (b)(2)(ii)(B) by adding the word ``rate'' after the
words ``heat input'' in the first sentence;
i. In paragraph (b)(2)(iii) by adding the words ``, in accordance
with paragraph (a) of this section'' after the word ``purposes'';
j. Revising paragraph (c);
k. Revising paragraph (d);
l. In paragraph (e) introductory text by revising the first
sentence, adding a new second sentence, and revising the words
``appendix F of `` to read ``appendix F to'' in the third sentence;
m. In paragraph (e)(1) introductory text by revising the second
sentence and adding a new third sentence;
n. 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)'';
o. In paragraph (e)(2) by adding the word ``rate'' after the words
``heat input'' in the first sentence; and
p. 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.
Except as provided in paragraphs (e) and (f) of this section, the
owner or operator of an affected unit shall calculate hourly
NOX mass emissions (in lbs) by multiplying the hourly
NOX emission rate (in lbs/mmBtu) by the hourly heat input
rate (in mmBtu/hr) and the unit or stack operating time (as defined in
Sec. 72.2). * * *
(a) * * *
(1) Install, certify, operate, and maintain a NOX-
diluent continuous emissions monitoring system and a flow monitoring
system and diluent monitor in the common stack, record the combined
NOX mass emissions for the units exhausting to the common
stack, and, for the 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);
(ii) Install, certify, operate, and maintain a flow monitoring
system and diluent monitor in the duct to the common stack from each
unit; or
* * * * *
(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 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 shall 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 fuel-specific
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
[[Page 32025]]
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) Units using a NOX concentration monitoring system
and a flow monitoring system to determine NOX mass. 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. Revising paragraph (a)(6) introductory text;
c. Adding new paragraphs (a)(8), (a)(9), (d)(6), (f)(1)(vii), and
(f)(1)(viii);
d. Revising all of paragraph (c)(3) except for the heading and the
first sentence;
e. Revising paragraph (e)(1); and
f. 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) * * *
(6) Specific heat input record provisions for gas-fired or oil-
fired units using the procedures in appendix D to this part. In lieu of
the information required in Sec. 75.57(c)(2), the owner or operator
shall record the information in Sec. 75.58(c) for each affected gas-
fired or oil-fired unit and each non-affected gas-or oil-fired unit
under Sec. 75.72(b)(2)(ii) for which the owner or operator is using the
procedures in appendix D to this part for estimating heat input.
* * * * *
(8) Total NOX mass emissions for the hour.
(9) 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, by a method specified
by the Administrator, a complete, electronic, up-to-date monitoring
plan file (except for hardcopy portions identified in paragraph (e)(2)
of this section) 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) to
the permitting authority, 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. Submit the updated electronic monitoring plan within 30 days
of the event with which the monitoring plan is associated, unless
otherwise specified 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.
* * * * *
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);
c. In the third sentence of paragraph (c)(2)(ii)(C) by revising the
words ``in every period of five consecutive calendar'' to read ``every
five'';
d. Revising paragraph (c)(2)(ii)(H)(1);
e. Revising the second sentence of paragraph (c)(3)(iii);
f. In the second sentence of paragraph (c)(3)(iv) by adding the
words ``the cumulative'' 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;
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;
[[Page 32026]]
i. In paragraph (c)(3)(viii) by adding the word ``cumulative''
after the number ``168'';
j. In paragraph (c)(3)(x) by adding the words ``, if applicable,''
after the words ``Sec. 75.20(b)(3) and'';
k. 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;
l. 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).
m. 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;
n. In paragraph (c)(5) by adding the word ``rate'' after the words
``heat input'';
o. Revising paragraphs (c)(6)(v), (c)(7)(ii), and (c)(8)(ii);
p. Adding a new paragraph (c)(7)(iii);
q. In the second sentence of paragraph (c)(10)(ii) by revising the
word ``monitoring'' to read ``monitored''; and
r. 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 cumulative 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
cumulative 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 cumulative
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 (a)(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.
* * * * *
(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 cumulative 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 cumulative
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 cumulative 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) * * * 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 year, if the unit or stack does not operate in the
second quarter).
(7) * * *
(ii) The standard 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 standard missing data routines, either on a fuel-specific or non-
fuel-specific basis; and
(iii) In order to apply the missing data routines described in
Secs. 75.31 through
[[Page 32027]]
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) The sentence, ``The owner or operator of a unit shall use these
procedures for no longer than three ozone seasons following initial
certification'' applies instead of the last sentence of Sec. 75.31(a).
(D) In Sec. 75.32(a), the phrases ``the first 720 quality-assured
monitor operating hours within the ozone season,'' ``the first 2,160
quality-assured monitor operating hours within the ozone season,'' and
``three ozone seasons'' apply, respectively, instead of the phrases
``the first 720 quality-assured monitor operating hours,'' ``the first
2,160 quality-assured monitor operating hours,'' and ``three years
(26,280 clock hours).''
(E) In Sec. 75.32(a)(1), the phrase ``Following initial
certification, prior to completion of 3,672 unit operating hours within
the subsequent ozone season(s)'' applies instead of the phrase ``Prior
to completion of 8,760 unit operating hours following initial
certification.''
(F) In Equation 8, the phrase ``Total unit operating hours within
the ozone season'' applies instead of the phrase ``Total unit operating
hours.''
(G) In Sec. 75.32(a)(2), phrase, ``3,672 unit operating hours
within the ozone season,'' applies instead of the phrase, ``8,760 unit
operating hours'', and the phrase, ``three ozone seasons'' applies
instead of the phrase, ``three years (26,280 clock hours).''
(H) 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.''
(I) 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
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 ozone seasons earlier shall be used in
Equation 9.'' For a unit that has accumulated fewer than 3,672 unit
operating hours in the previous three ozone seasons, use the following
in the numerator of Equation 9, ``Total unit operating hours for which
quality-assured data were recorded in the previous three ozone
seasons'', and in the denominator of Equation 9 use ``Total unit
operating hours in the previous three ozone seasons.''
(J) In Sec. 75.33(a), the phrases ``the first 720 quality-assured
monitor operating hours within the ozone season,'' ``the first 2,160
quality-assured monitor operating hours within the ozone season,'' and
``three ozone seasons'' apply, respectively, instead of the phrases
``the first 720 quality-assured monitor operating hours,'' ``the first
2,160 quality-assured monitor operating hours,'' and ``three years
(26,280 clock hours).''
(K) 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 not use quality-assured monitor operating hours of data that were
recorded more than three ozone seasons prior to the ozone season in
which the missing data period occurs.''
(L) 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.''
(M) In Sec. 75.34(a)(2), the phrases, ``720 (or 2,160) quality-
assured monitor operating hours within the ozone season,'' ``previous
720 quality-assured monitor operating hours recorded within the ozone
season in the uncontrolled database,'' and ``the requisite number of
quality-assured monitor operating hours of SO2 or
NOX data recorded within the ozone season in the appropriate
database for the lookback periods,'' apply respectively instead of
``720 (or 2,160) quality-assured monitor operating hours,'' ``previous
720 quality-assured monitor operating hours in the uncontrolled
database,'' and ``the requisite number of quality-assured monitor
operating hours of SO2 or NOX data in the
appropriate database for the lookback periods.''
(8) * * *
(ii) For units with add-on emission controls, using the missing
data option in Sec. 75.34(a)(1), 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). For units using
the missing data option in Sec. 75.34(a)(2), information documenting
the operating status of the add-on emission controls during unit
operation, as described in Sec. 75.34(d).
* * * * *
Appendix A Section 1 [Amended].
47. Section 1 of 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.
48. Section 2 of 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. Moving 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;
d. Revising the definition of the variable ``%S'' in Equation A-1b
of paragraph (a) of section 2.1.1.1;
e. Adding a definition for the variable ``GCV'' after the
definition of the variable ``%CO2W'' in Equation A-1b in
paragraph (a) of section 2.1.1.1;
f. Adding two sentences to the end of paragraph (b) of section
2.1.1.1;
[[Page 32028]]
g. Adding three sentences to the end of paragraph (a) of section
2.1.1.2;
h. In the definition of MPC in Equation A-2 in paragraph (c) of
section 2.1.1.2 by adding the words ``in section 2.1.1.1 of this
appendix'' after the words ``as determined by Eq. A-1a or A-1b'';
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 sentence after
the first sentence;
k. Removing the first sentence of paragraph (d) of section 2.1.1.4
and adding three sentences in its place;
l. In the first sentence of section 2.1.1.5 by revising the words
``paragraphs (a) and (b)'' to read ``paragraphs (a), (b), and (c)'';
m. In paragraph (c) of section 2.1.1.5 by revising the final
sentence;
n. In section 2.1.2 by revising the words ``section 2.1.2.1'' to
read ``sections 2.1.2.1 through 2.1.2.5 of this appendix'';
o. In paragraph (a) of section 2.1.2.1 by adding two new sentences
at the end of Option 1, by removing the word ``or'' from Option 3, by
revising the period at the end of Option 4 to read ``; or'', and by
adding a new Option 5;
p. Adding two new sentences to the end of paragraph (c) of section
2.1.2.1;
q. Revising the first sentence of paragraph (d) of section 2.1.2.1;
r. Revising the second sentence of paragraph (e) and Table 2-2 in
section 2.1.2.1;
s. Revising paragraph (a) of section 2.1.2.2;
t. In the third sentence of paragraph (b) of section 2.1.2.2 by
adding the words ``(if applicable)'' after the words `` NOX
emissions'';
u. Revising the second and third sentences of paragraph (c) of
section 2.1.2.2;
v. Revising the fourth sentence of paragraph (a) of section
2.1.2.3;
w. In the first sentence of paragraph (b) of section 2.1.2.3 by
revising the words ``requires a span'' to read ``requires or allows the
use of a span value'';
x. Revising the second sentence of paragraph (b) of section 2.1.2.4
and adding a new sentence after the first sentence;
y. Removing the first sentence of paragraph (c) of section 2.1.2.4
and adding three sentences in its place;
z. In the third sentence of section 2.1.2.5 by revising the words
``paragraphs (a) and (b)'' to read ``paragraphs (a), (b), and (c)'';
aa. In paragraph (c) of section 2.1.2.5 by adding the word
``diagnostic'' before the words ``linearity test'' in the fifth
sentence and by revising the final sentence;
bb. Amending section 2.1.3 by adding a sentence to the end of the
section;
cc. In section 2.1.3.3 by adding two new sentences to the beginning
of the section;
dd. 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'';
ee. In section 2.1.6 by adding a sentence to the end of that
section; and
ff. Revising 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) * * *
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) * * * 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 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.
* * * * *
2.1.1.3 Span Value(s) and Range(s)
* * * If the SO2 span concentration is
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. * * *
* * * * *
2.1.1.5 Adjustment of Span and Range
* * * * *
[[Page 32029]]
(c) * * * Use the data validation procedures in
Sec. 75.20(b)(3), beginning with the hour in which the span is
changed.
* * * * *
2.1.2.1 Maximum Potential Concentration
(a) * * *
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 5: If a reliable estimate of the uncontrolled
NOX emissions from the unit is available from the
manufacturer, the estimated value may be used.
* * * * *
(c) * * * Note that whichever MPC option in section 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 or DLN
are not in operation. * * *
(e) * * * 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 or DLN are
not in operation. * * *
Table 2-2.--Maximum Potential Concentration for NOX--Gas- and Oil-Fired
Units
------------------------------------------------------------------------
Maximum
potential
Unit type concentration
for NOX (ppm)
------------------------------------------------------------------------
Tangentially-fired dry bottom............................ 380
Wall-fired dry bottom.................................... 600
Roof-fired (vertically-fired) dry bottom, arch-fired..... 550
Existing combustion turbine.............................. 200
New combustion turbine, permitted to fire either oil or 200
natural gas.............................................
New combustion turbine, permitted to fire only natural 150
gas.....................................................
Others................................................... (\1\)
------------------------------------------------------------------------
\1\ As approved by the Administrator.
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. Also determine
the MEC for uncontrolled units and units that use only low
NOX burners (LNB) for NOX control, if more
than one type of fuel is combusted in the unit. 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 and except for the fuel or blend that was used to
determine the MPC under section 2.1.2.1 of this appendix. 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) * * * The data base for the MEC shall not include any CEM
data recorded during unit startup, shutdown, or malfunction or (for
units with add-on NOX controls or turbines using dry low
NOX technology) during any NOX control device
malfunctions or outages. All NOX control devices and
methods used to reduce NOX emissions (if applicable) must
be operating properly during each hour. * * *
2.1.2.3 Span Value(s) and Range(s)
(a) * * * If the NOX span concentration is
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. * * *
* * * * *
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 section 2.1.2.4(e) of this appendix, 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. * * *
* * * * *
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. * * *
* * * * *
2.1.6 Maximum Potential Moisture Percentage
* * * Alternatively, a default maximum potential moisture value
of 15 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
[[Page 32030]]
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:
(1) Zero to 20 percent of span or an equivalent reference value
(e.g., pressure pulse or electronic signal) and (2) 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 (1) the entire flow monitoring
system, from and including the probe tip (or equivalent) through and
including the data acquisition and handling system, or (2) 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 (1) 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 (2) 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. Section 3 of Appendix A to Part 75 is amended by:
a. In section heading 3.3.1 by adding the word ``Monitors'' after
the word ``SO2'';
b. Revising section 3.3.1;
c. Revising paragraph (a) of section 3.3.2;
d. In the first sentence of paragraph (b) of section 3.3.2 by
revising the words ``not exceed'' to read ``be within'';
e. In section heading 3.3.3 by removing the words ``Pollutant
Concentration'';
f. In paragraph 3.3.3 by adding ``'' before the words
``1.0 percent'';
g. In section heading 3.3.4 by adding the word ``Monitors'' after
the word ``Flow'';
h. Revising section 3.3.4;
i. In the second sentence of section 3.3.6 by revising the words
``appendix are'' to read ``appendix is''; and
j. Revising the second sentence of 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 below 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 mean
value of the monitor measurements shall be within 15.0
ppm of the reference method mean value wherever the relative
accuracy specification of 10.0 percent is not achieved.
3.3.2 Relative Accuracy for NOX-Diluent Continuous
Monitoring Systems
(a) The relative accuracy for NOX-diluent continuous
emission monitoring systems shall not exceed 10.0 percent at any
load level at which a RATA is performed (the low, mid, or high load
level, as defined in section 6.5.2.1 of this appendix).
* * * * *
3.3.4 Relative Accuracy for Flow Monitors
(a) The relative accuracy of flow monitors shall not exceed 10.0
percent at any load level at which a RATA is performed (the low,
mid, or high load 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 level of
the relative accuracy test audit is less than or equal to 10.0 fps,
the mean value of the flow monitor velocity measurements shall be
within 2.0 fps of the reference method mean value in fps
at that load level, wherever the 10.0 percent relative accuracy
specification is not achieved.
* * * * *
3.3.7 Relative Accuracy for NOX Concentration Monitoring
Systems
* * * * *
(b) * * * 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 mean value of the continuous emission monitoring
system measurements shall be within 15.0 ppm of the
reference method mean value.
* * * * *
50. Section 4 of Appendix A to Part 75 is amended by:
a. Revising the second sentence of the first paragraph of section
4;
b. Removing the last sentence of the first paragraph of section 4;
and
c. In subparagraph (3) of section 4 by adding the words ``the
appropriate'' before the word ``units'', by removing the words ``of the
standard'', and by 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 mass emission
rates in the appropriate units (e.g., lb/hr, lb/mmBtu, tons/hr). * *
*
* * * * *
Appendix A to Part 75 [Amended]
51. Section 6 of 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 removing the word ``extended'' before the
words ``unit outages'' in the second sentence, and by adding a new
sentence after the second 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 the fourth sentence of section 6.3.2 by removing the word
``extended'' before the words ``unit outages'', and by adding a new
sentence after the fourth 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. In the first sentence of paragraph (a) of section 6.4 by adding
the word ``conditional'' before the words ``data validation
procedures'';
g. 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'';
[[Page 32031]]
h. Revising paragraphs (a) and (c) of section 6.5;
i. In the first sentence of paragraph (f)(1) of section 6.5 by
adding the word ``conditional'' before the words ``data validation
procedures'';
j. In the second sentence of paragraph (g) of section 6.5 by
removing the words ``SO2-diluent'';
k. Revising paragraph (a) of section 6.5.1 and paragraph (a) of
section 6.5.2;
l. 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)'';
m. In paragraph (c) of section 6.5.2 by adding the words ``(or
three operating levels)'' after the word ``level(s)'';
n. In paragraph (d) of section 6.5.2 by adding the words ``(or
operating levels)'' after the word ``level(s)'';
o. In section heading 6.5.2.1 by adding the words ``(or
Operating)'' after the words ``Normal Load'';
p. Revising paragraph (a) of section 6.5.2.1;
q. 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 60.0 percent'' and revising the words ``60.0 to 100.0
percent'' to read ``> 60.0 percent'';
r. Revising paragraphs (c) and (d) of section 6.5.2.1;
s. Revising the first sentence of paragraph (e) of section 6.5.2.1;
t. Removing and reserving section 6.5.3;
u. Amending section 6.5.6 by removing the third sentence;
v. In paragraph (b)(2) of section 6.5.6 by revising the number
``1.0'' To read ``1.2'';
w. Adding paragraph (b)(5) to section 6.5.6;
x. 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)'';
y. In paragraph (c) of section 6.5.6.3 by removing the words
``Sec. 75.56(a)(7) or'' and the words ``, as applicable'';
z. 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
aa. In section 6.5.10 by adding a comma after the number ``7D'',
and by adding a new third sentence.
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
* * * Notwithstanding this requirement, for a peaking unit (as
defined in Sec. 72.2 of this chapter), only 3 of the 7 days in the
test need be unit operating days. * * *
* * * * *
6.3.2 Flow Monitor 7-Day Calibration Error Test
* * * Notwithstanding these requirements, for a peaking unit (as
defined in Sec. 72.2 of this chapter), only 3 of the 7 days in the
test need be unit operating days. * * *
* * * * *
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 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 for flow monitors on bypass stacks/ducts and peaking
units, 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.
* * * * *
6.5.2.1 Range of Operation and Normal Load (or Operating) Load
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 load. For common stacks, the minimum safe,
stable load shall be the lowest of 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 unit 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 or thousands
of lb/hr of steam load; or
[[Page 32032]]
(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'' to read ``minimum'' in the definitions of ``MPV,''
``Hf,'' ``% O2d,'' and ``%
H2O,'' and replace the word ``minimum'' to read
``maximum'' in the definition of ``CO2d.''
* * * * *
(c) Analysis of historical load or operating level data. (1) For
units that produce electrical or thermal output, 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.
(2) If the affected unit does not produce electrical or steam
load, follow the procedures in paragraph (c)(1) of this section,
except that:
(i) The words ``load level'' shall read ``operating level;'' and
(ii) If the unit does not have an installed flow monitor, the
historical data analysis described in paragraph (c)(1) of this
section is not required.
(d) Determination of normal load. (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,
follow the procedures in paragraph (d)(1) of this section, except
that:
(i) The words ``load'' and ``load level'' shall read ``operating
level;'' and
(ii) If the unit does not have an installed flow monitor, the
two most frequently-used operating levels and the normal operating
level(s) shall be determined using sound engineering judgment, in
lieu of performing a historical data analysis. The operating level
determinations shall be based on knowledge of the unit, operating
experience with the unit, and actual stack gas velocity measurements
using EPA Method 2 in appendix A to part 60 of this chapter (or its
allowable alternatives).
(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. * * *
* * * * *
6.5.6 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.
* * * * *
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 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. Section 7 of 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] TP13JN01.002
in the list of defined variables for Eq. A-7 to be
[GRAPHIC] [TIFF OMITTED] TP13JN01.003
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 the third sentence by revising the word `` NOX'' to read
``NOXdiluent'';
g. In paragraph (a) of section 7.7 by removing the fourth sentence;
h. In paragraph (b) of section 7.7 by removing the first two
sentences and adding four new sentences;
i. 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;
j. 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;
k. In section 7.8 by designating the existing text as paragraph
(a), removing
[[Page 32033]]
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
l. 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, and flow monitors using the following procedures. * * *
* * * * *
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. * * *
(c) * * *
(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.
* * * * *
[GRAPHIC] [TIFF OMITTED] TP13JN01.004
* * * * *
53. Section 1 of Appendix B to Part 75 is amended by:
a. Adding a fourth sentence to section 1; and
b. Removing the word ``and'' before the words ``section
2.1.5.1'' in the second sentence of section 1.3.1.
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.
* * * * *
54. Section 2 of Appendix B to Part 75 is amended by:
a. In paragraph (a) of section 2.1.4 by revising the words `` 200
ppm'' in the first sentence to read ``> 50.0 ppm but 200
ppm, or exceeds 5.0 ppm for span values 50.0 ppm'';
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 paragraph (c) of section 2.2.3 by adding a third sentence;
d. In the second sentence of paragraph (e) of section 2.2.3 by
removing the words ``or SO2-diluent'';
e. In the second sentence of paragraph (f) of section 2.2.3 by
revising the words ``168 unit operating hour or stack operating hour
grace period'' to read ``grace period of 168 cumulative unit or stack
operating hours'';
f. In paragraph (a) of section 2.2.4 by revising both occurrences
of the word ``consecutive'' to read ``cumulative'';
g. In the first sentence of paragraph (b) of section 2.2.4 by
adding the word ``cumulative'' after the number ``168'' and the words
``first unit operating'' before the words ``hour following'';
h. 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;
i. Revising the third sentence of paragraph (a)(1) of section
2.2.5;
j. In paragraph (a)(3) of section 2.2.5 by adding the word ``rate''
after the words ``heat input'';
k. 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'';
l. Revising the last sentence of paragraph (b) of section 2.2.5;
m. Revising the introductory text of paragraph (c) of section
2.2.5;
n. Adding a new third sentence in paragraph (c)(1) of section
2.2.5;
[[Page 32034]]
o. In paragraph (c)(8) of section 2.2.5 by removing the second
sentence and adding two new sentences in its place;
p. 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'';
q. Revising paragraph (b) of section 2.2.5.1;
r. Revising section 2.2.5.2;
s. Revising the second and third sentences of paragraph (a) of
section 2.2.5.3;
t. In the second sentence of paragraph (b) of section 2.2.5.3 by
changing the number ``5.0'' to ``10.0'';
u. 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;
v. In the fourth sentence of paragraph (a) of section 2.3.1.1 by
revising the words ``720 unit (or stack) operating hour grace period''
to read ``grace period of 720 cumulative unit or stack operating
hours'';
w. Removing and reserving paragraph (b) of section 2.3.1.2;
x. 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;
y. 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)'';
z. 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'';
aa. 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'';
bb. Removing and reserving paragraph (g) of section 2.3.1.2;
cc. In section heading 2.3.1.3 by adding the words ``(or
Operating)'' after the words ``RATA Load'';
dd. 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)'';
ee. In paragraph (b) of section 2.3.1.3 by revising the words
``section 6.5.2.1'' to read ``section 6.5.2.1(d)'';
ff. Revising paragraphs (c)(1) through (c)(6) of section 2.3.1.3;
gg. In paragraph (c) of section 2.3.2 by adding a new third
sentence;
hh. In paragraphs (d) and (f) of section 2.3.2 by adding the words
``(or operating level)'' after each occurrence of the words ``load
level'', the words ``(or single-level)'' after the word ``single-
load'', the words ``(or multiple-level)'' after the word ``multiple-
load'', the words ``(or operating level(s))'' after the words ``load
level(s)'', and the words ``(or 3-level)'' after the words ``3-load'';
ii. Revising paragraph (e) of section 2.3.2;
jj. In paragraph (a) of section 2.3.3 by revising the first two
instances of the word ``consecutive'' to read ``cumulative'', removing
the word ``or'' after the first two semicolons, and by removing the
words ``consecutive calendar'' after the word ``five'';
kk. In the first sentence of paragraph (c) of section 2.3.3 by
adding the word ``cumulative'' after the number ``720'';
ll. Revising paragraph (b) of section 2.4;
mm. Revising footnote 2 of Figure 1 to Appendix B of Part 75; and
nn. In Figure 2 to Appendix B of Part 75 by removing the row for
``Flow (Phase I)'', renaming the row for ``Flow (Phase II)'' as
``Flow'', by revising the word ``H2O2'' in the
final row to read ``H2O2'', and by adding the
word ``cumulative'' after both occurrences of the number ``168'' in
footnote 1 to Figure 2.
The revisions and additions read as follows:
2. Frequency of Testing
* * * * *
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) Applicability and methodology. * * * 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
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) * * * 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
[[Page 32035]]
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.
2.2.5.3 Abbreviated Flow-to-Load Test
(a) * * * Data from the monitoring system are considered invalid
from the hour of commencement of the repair, replacement, or
maintenance until either the hour in which the abbreviated flow-to-
load test is passed, or the hour in which a probationary calibration
error test is passed following completion of the repair,
replacement, or maintenance and any associated adjustments to the
monitor. If the latter option is selected, the abbreviated flow-to-
load test shall be completed within 168 cumulative unit operating
hours of the probationary calibration error test (or, for peaking
units, within 30 unit operating days, if that is less restrictive).
* * *
* * * * *
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
* * * * *
(c) * * *
(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.
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 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.
(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 installed on
peaking units and bypass stacks. For peaking units and bypass
stacks, a single-load RATA at the normal load is required.
(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 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.
* * * * *
2.4 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 flow RATA is
specifically required under section 2.3.1.3(b) of this appendix (for
flow monitors installed on peaking units and bypass stacks) 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 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 and bypass
stacks, conduct all RATAs at a single, normal load. For other flow
monitors, conduct annual RATAs at two load levels (or operating
levels). Alternating single-level and 2-level RATAs may be done if a
monitor is on a semiannual frequency. A single-level RATA may be
done in lieu of a 2-level RATA if, since the last annual flow RATA,
the unit has operated at one load level (or operating level) for
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.
* * * * *
55. Appendix C to Part 75 is amended by:
a. Revising the section heading of section 2;
b. Revising the fifth sentence in section 2.2.1 and adding a new
sentence after that fifth sentence;
c. Revising in section 2.2.3.9 the reference ``75.51(a)(2)'' to
read ``75.71(a)(2)''; and
[[Page 32036]]
d. Adding new sections 3 and 4.
The revisions and additions read as follows:
Appendix C to Part 75--Missing Data Estimation Procedures
* * * * *
2. Load-Based Procedure for Missing Flow Rate, NOX
Concentration, and NOX Emission Rate Data
* * * * *
2.2 Procedure
2.2.1 * * * For a cogenerating unit or other unit at which some
portion of the heat input is not used to produce electricity or for
a unit for which hourly average gross load in MWge is not recorded
separately, determine the maximum hourly average gross load for the
unit by converting the maximum rated hourly unit heat input
(including heat input from auxiliary firing, if applicable) to an
equivalent gross megawatt value, using the percentage efficiencies
of the main combustion source and (if applicable) any auxiliary
combustion sources. If the actual percentage efficiency of a
particular combustion source is unknown, use a default value of 50
percent for a combustion turbine and 33 percent for any other type
of combustion source. * * *
* * * * *
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 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:
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 rate, 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. 75.51(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.
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.
4. Non-Load-Based Procedure for Missing Fuel Flowmeter Data
(Optional)
4.1 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 fuel flow rate.
4.2 Procedure
4.2.1 Establish at least two, but no more than ten operational
bins, corresponding to various operating conditions and parameters
(or combinations of these) related to the fuel flow rate. Include a
complete description of each operational bin in the hardcopy portion
of the monitoring plan required under Sec. 75.53(f)(1)(ii),
identifying the parameters and operating conditions associated with
the bin and explaining the relationship between these parameters and
conditions and the magnitude of the fuel flow rate. Assign a unique
number, 1 through 10, to each operational bin.
4.2.2 In the electronic quarterly report required under
Sec. 75.64, indicate for each hour of unit operation the operational
bin associated with the fuel flow rate data, by recording the number
assigned to the bin under section 4.2.1 of this appendix.
4.2.3 The data acquisition and handling system (DAHS) 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 for each unit
operating hour of missing fuel flow rate data within each identified
operational bin during the previous 720 operating hours (on a
rolling basis):
4.2.3.1 Arithmetic average of the hourly fuel flow rates
reported by a certified fuel flowmeter system, in appropriate units
of fuel flow rate.
4.2.3.2 The maximum value of hourly fuel flow rates reported by
a certified fuel flowmeter system, in appropriate units of fuel flow
rate.
4.2.4 The DAHS shall also be capable of separating the recorded
fuel flow rate data on the basis of the type of fuel combusted in
the unit. A separate database shall be created and maintained for
each type of fuel when it is combusted alone in the unit. If
different types of fuel are co-fired in the unit, an additional
database shall be created and maintained for each type of fuel, for
hours in which it is co-fired with any other type(s) of fuel(s).
4.3 Use the calculated average and maximum values to substitute
for missing fuel flow rate data according to the applicable
procedures in sections 2.4.2 and 2.4.3 in appendix D to this part.
Appendix D Section 1 [Amended].
56. Section 1 of Appendix D to Part 75 is amended by removing the
final sentence of section 1.2.
57. Section 2 of 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
[[Page 32037]]
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. In paragraph (c) of section 2.1.6 by removing the words
``2.1.5.1 or'';
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 the second sentence of paragraph (a) of section 2.1.6.1 by
adding the word ``upscale'' after the word ``other'' 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. In paragraph (a) of section 2.1.7.2 by adding a new third
sentence;
y. Revising paragraph (b) of section 2.1.7.2;
z. 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'';
aa. In paragraph (d) of section 2.1.7.2 by revising the third
sentence and by adding a new fourth sentence;
bb. Revising the first sentence of paragraph (a) of section
2.1.7.3;
cc. Adding a second sentence to paragraph (b) of section 2.1.7.3;
dd. 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)'';
ee. 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'';
ff. Revising Table D-4 in section 2.2;
gg. 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)'';
hh. Revising paragraph (b) of section 2.2.4.2;
ii. 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'' with, respectively, the words ``following conservative,
assumed values'' and ``assumed values'';
jj. Revising paragraph (d) of section 2.2.4.3;
kk. Revising Table D-5 in section 2.3(b);
ll. Revising all of section 2.3.1.4 except for the section heading
and paragraph (a)(1);
mm. In section 2.3.2.1.1 by adding a new second sentence and by
revising Equation D-1h and the definitions of variables for Equation D-
1h;
nn. Revising sections 2.3.2.1.2 and 2.3.2.4;
oo. In section 2.3.3.2 by revising the third sentence and adding a
new fourth sentence;
pp. In section 2.3.4.3 by adding a new second sentence;
qq. Revising the fourth sentence of section 2.3.4.3.1;
rr. Revising section 2.3.4.3.2 and paragraph (a) of section 2.3.5;
ss. In paragraph (a) of section 2.3.6 by revising the first,
second, fourth, and fifth sentences and by adding a new sentence after
the second sentence;
tt. In the first sentence of paragraph (b) of section 2.3.6 by
removing the words ``(and hydrogen sulfide content, if applicable)'';
uu. In the first sentence of section 2.4.1 by removing the
reference ``2.3.3.1.2,'';
vv. Revising Table D-6 in section 2.4.1 and sections 2.4.2,
2.4.2.1(b) and heading, 2.4.2.2, and 2.4.2.3; and
ww. In section 2.4.3 by adding a new sentence to the end of that
section.
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 of
this chapter). 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, 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. For the purposes of this section,
units served by a common pipe have similar efficiencies (e.g., if
all of the units are boilers or if all of the units are combustion
turbines). 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 Situations in Which Certified Flowmeter Is Not Required
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 a
federally-enforceable permit
[[Page 32038]]
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 of this appendix
(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
* * * * *
(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.
* * * * *
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) * * * If, for a particular fuel flowmeter, 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 accuracy
test was performed, a flow-to-load (or GHR) evaluation is not
required for that flowmeter for that calendar quarter. A one-quarter
extension of the deadline for the next fuel flowmeter 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.
* * * * *
2.1.7.3 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. * * *
(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.
* * * * *
2.2 Oil Sampling and Analysis
* * * * *
Table D-4.--Oil Sampling Methods and Sulfur, Density and Gross Calorific Value Used in Calculations
----------------------------------------------------------------------------------------------------------------
Parameter Sampling technique/frequency Value used in calculations
----------------------------------------------------------------------------------------------------------------
Oil Sulfur Content........................... Daily manual sampling........... 1. Highest sulfur content from
previous 30 daily samples; or
2. Actual daily value.
Flow proportional/weekly Actual measured value.
composite.
In storage tank (after addition 1. Actual measured value; or
of fuel to tank).
2. Highest of all sampled
values in previous calendar
year, unless a higher sample
value is obtained; \1\ or
3. Maximum value allowed by
contract, unless a higher
sample value is obtained.\1\
As delivered (in delivery truck 1. Highest of all sampled
or barge).\1\ values in previous calendar
year, unless a higher sample
value is obtained; \1\ or
2. Maximum value allowed by
contract, unless a higher
sample value is obtained.\1\
Oil Density.................................. Daily manual sampling........... 1. Use the highest density from
the previous 30 daily samples;
or
2. Actual measured value.
[[Page 32039]]
Flow proportional/weekly Actual measured value.
composite.
In storage tank (after addition 1. Actual measured value; or
of fuel to tank).
2. Highest of all sampled
values in previous calendar
year, unless a higher sample
value is obtained; \1\ or
3. Maximum value allowed by
contract, unless a higher
sample value is obtained.\1\
As delivered (in delivery truck 1. Highest of all sampled
or barge).\1\ values in previous calendar
year, unless a higher sample
value is obtained; \1\ or
2. Maximum value allowed by
contract, unless a higher
sample value is obtained.\1\
Oil GCV...................................... Daily manual sampling........... 1. Highest fuel GCV from the
previous 30 daily samples; or
2. Actual measured value.
Flow proportional/weekly Actual measured value.
composite.
In storage tank (after addition 1. Actual measured value; or
of fuel to tank).
2. Highest of all sampled
values in previous calendar
year, unless a higher sample
value is obtained; \1\ or
3. Maximum value allowed by
contract, unless a higher
sample value is obtained.\1\
As delivered (in delivery truck 1. Highest of all sampled
or barge).\1\ values in previous calendar
year, unless a higher sample
value is obtained; \1\ or
2. Maximum value allowed by
contract, unless a higher
sample value is obtained.\1\
----------------------------------------------------------------------------------------------------------------
\1\ Assumed values may only be used if sulfur content, gross calorific value, or density of each sample is no
greater than the assumed value used to calculate emissions or heat input. If a higher sample value is
obtained, use the results of that sample analysis as the new assumed value.
* * * * *
2.2.4 Manual Sampling
* * * * *
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,
beginning on the date of receipt of the results of the sample
analysis, 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
* * * * *
Table D-5.--Gas Sulfur and GCV Values Used in Calculations for Various Fuel Types
----------------------------------------------------------------------------------------------------------------
Value used in calculations
Parameter Fuel type and sampling frequency (except for missing data hours)
----------------------------------------------------------------------------------------------------------------
Gas Sulfur Content........................... Pipeline Natural Gas with total 0.0006 lb/mmBtu.
sulfur content less than or
equal to 0.5 grains/100scf
(when using the provisions of
section 2.3.1 to determine SO2
mass emissions)--Sample
semiannually and whenever fuel
composition changes
significantly.
Natural Gas with total sulfur Default SO2 emission rate
content less than or equal to calculated from Eq. D-1h,
20.0 grains/100scf (when using using either:
the provisions of section 2.3.2 1. The fuel contract maximum
to determine SO2 mass total sulfur content, unless a
emissions)--Sample semiannually higher value is obtained in a
and whenever fuel composition semiannual sample;\1\
changes significantly. 2. The maximum total sulfur
content from the previous
year's samples, unless a
higher value is obtained in a
semiannual sample;\1\ or
3. The actual total sulfur
content from the most recent
semiannual sample.
[[Page 32040]]
Any gaseous fuel delivered in 1. Actual total sulfur content
shipments or lots--Sample each from most recent shipment;
lot or shipment. 2. Highest total sulfur content
from previous year's samples,
unless a higher value is
obtained in a sample;\1\ or
3. Maximum total sulfur content
value allowed by contract,
unless a higher value is
obtained in a sample.\1\
Any gaseous fuel transmitted by 1. Actual total sulfur content
pipeline and having a from daily sample; or
demonstrated ``low sulfur 2. Highest total sulfur content
variability'' using the from previous 30 daily
provisions of section 2.3.6-- samples.
Sample daily.
Any gaseous fuel--Sample hourly. Actual hourly total sulfur
content of the gas.
Gas GCV...................................... Pipeline Natural Gas--Sample 1. GCV from most recent monthly
monthly. sample (with 48
operating hours in the month);
2. Maximum GCV from contract,
unless a higher value is
obtained in a monthly
sample;\1\ or
3. Highest GCV from previous
year's samples, unless a
higher value is obtained in a
monthly sample.\1\
Natural Gas--Sample monthly..... 1. GCV from most recent monthly
sample (with 48
operating hours in the month);
2. Maximum GCV from
contract;\1\ or
3. Highest GCV from previous
year's samples.\1\
Any gaseous fuel delivered in 1. Actual GCV from most recent
shipments or lots--Sample each shipment or lot;
lot or shipment. 2. Highest GCV from previous
year's samples, unless a
higher value is obtained in a
sample;\1\ or
3. Maximum GCV value allowed by
contract, unless a higher
value is obtained in a
sample.\1\
Any gaseous fuel transmitted by 1. GCV from most recent monthly
pipeline and having a sample (with 48
demonstrated ``low GCV operating hours in the month);
variability'' using the or
provisions of section 2.3.5-- 2. Highest GCV from previous
Sample monthly. year's samples, unless a
higher value is obtained in a
monthly sample.\1\
Any other gaseous fuel not Actual daily or hourly GCV of
having a ``low GCV the gas.
variability''--Sample daily or
hourly. (Note that the use of
an on-line GCV calorimeter or
gas chromatograph is allowed).
----------------------------------------------------------------------------------------------------------------
\1\ Assumed sulfur content and GCV values (i.e., contract values or highest values from previous year) may only
continue to be used if the sulfur content or GCV of each sample is no greater than the assumed value used to
calculate SO2 emissions or heat input. If a higher sample value is obtained, use the results of that sample
analysis as the new assumed value.
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 less than or equal to
0.5 grains/100scf. The demonstration must be made using one of the
following sources of information:
* * * * *
(2) The results of all available fuel sample analyses from the
past 12 months, documenting the total sulfur content of the fuel and
the percentage by weight of methane and/or GCV of the fuel. The fuel
samples may be obtained and analyzed by the owner or operator, by an
independent laboratory, or by the supplier of the gaseous fuel;
(3) Data from a 720-hour demonstration conducted using the
procedures of sections 2.3.5 and 2.3.6 of this appendix, documenting
the total sulfur content of the fuel and the percentage by weight of
methane and/or the GCV of the fuel, and using comparable procedures
to document the percentage by weight of methane; or
(4) If historical fuel sampling results or data from a 720-hour
demonstration are not available, a fuel may initially qualify as
pipeline natural gas if a sample of the fuel is obtained and
analyzed for total sulfur content and for percent methane or GCV,
and if the results of the sample analysis show that the total sulfur
content and percentage methane or GCV meet the definition of
pipeline natural gas in Sec. 72.2 of this chapter.
(b) After a fuel initially qualifies as pipeline natural gas
under paragraph (a) of this section, the owner or operator shall
sample the fuel for total sulfur content at least semiannually and
whenever it is reasonable to believe that the fuel composition has
changed significantly. The owner or operator shall also sample the
GCV of the fuel at the frequency specified in section 2.3.4.1 of
this appendix.
(c) If the results of a sample under paragraph (b) of this
section show that the total sulfur content of the fuel exceeds
0.5gr/100 scf, the fuel no longer qualifies as pipeline natural gas.
When this occurs:
(1) If the sample results show that the fuel still qualifies as
natural gas under section 2.3.2.4 of this appendix, discontinue
using the 0.0006 lb/mmBtu default SO2 emission rate under
2.3.1.1, as of the date on which the sample results are received.
Determine a new default SO2 emission rate according to
section 2.3.2.1.1 of this appendix and use the new SO2
emission rate, beginning with the date of receipt of the sample
results; or
(2) If the sample results show that the fuel no longer qualifies
either as pipeline natural gas or natural gas, the owner or operator
shall implement the procedures of section 2.3.3.1 of this appendix
(for sulfur content determination) and section 2.3.4.3 of this
appendix (for GCV determination), no later than 90 days after the
end of the quarter in which the sample results are received.
2.3.2 Natural Gas Combustion
* * * * *
2.3.2.1 SO2 Emission Rate
* * * * *
2.3.2.1.1 * * * In Equation D-1h, the total sulfur content and GCV
values shall be determined in accordance with the allowable options
shown in Table D-5 of this appendix. * * *
[[Page 32041]]
[GRAPHIC] [TIFF OMITTED] TP13JN01.005
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.
10\6\ = Conversion factor (Btu/mmBtu).
2.3.2.1.2 For reporting purposes, apply the results of the
required periodic fuel samples described in Table 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 semiannual samples of total sulfur content:
(1) If the actual value is to be used in the calculations, apply
the results of the most recent sample, until the date on which the
results of the next sample are received; 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 the quarter unless a higher value
is obtained in a semiannual fuel sample. In that case, use the
sampled value, beginning with the date of receipt of the sample
results. 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 quarterly 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.
(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, until the date on which the
results of the next sample are received; 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, beginning with the date of receipt of the sample
results. 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, until the date on which the results of the next sample are
received; 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, beginning with the
date of receipt of the sample results. 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.
* * * * *
2.3.2.4 Documentation that a Fuel is a 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 less than or equal to 20.0 grains/100 scf.
This demonstration must be made using one of the following sources
of information:
(1) The gas quality characteristics specified by a purchase
contract or by a transportation contract;
(2) The results of all available fuel sample analyses from the
past 12 months, documenting the total sulfur content of the fuel and
the percentage by weight of methane and/or GCV of the fuel. The fuel
samples may be obtained and analyzed by the owner or operator, by an
independent laboratory, or by the supplier of the gaseous fuel;
(3) Data from a 720-hour demonstration conducted using the
procedures of section 2.3.6 of this appendix, documenting the total
sulfur content of the fuel and the percentage by weight of methane
and/or the GCV of the fuel, and using comparable procedures to
document the percentage by weight of methane; or
(4) If historical fuel sampling results or data from a 720-hour
demonstration are not available, a fuel may initially qualify as
natural gas if a sample of the fuel is obtained and analyzed for
total sulfur content and for percent methane or GCV, and if the
results of the sample analyses show that the total sulfur content
and percentage methane or GCV meet the definition of natural gas in
Sec. 72.2 of this chapter.
(b) After a fuel initially qualifies as natural gas under
paragraph (a) of this section, the owner or operator shall sample
the fuel for total sulfur content at least semiannually and whenever
it is reasonable to believe that the fuel composition has changed
significantly. The owner or operator shall also sample the GCV of
the fuel at the frequency specified in section 2.3.4.2 of this
appendix.
(c) If the results of a periodic sample required under paragraph
(b) of this section show that the total sulfur content of the fuel
exceeds 20.0 gr/100 scf, the fuel no longer qualifies as natural
gas. In that case, the owner or operator shall implement the
procedures of section 2.3.3.1 of this appendix (for sulfur content
determination) and section 2.3.4.3 of this appendix (for GCV
determination), no later than 90 days after the end of the quarter
in which the sample results are received.
2.3.3 SO2 Mass Emissions From Any Gaseous Fuel
* * * * *
2.3.3.2 SO2 Mass Emission Rate
* * * That is, for fuels delivered by pipeline which demonstrate
a low sulfur variability (under section 2.3.6 of this appendix) use
either the daily sample value or the highest value in the previous
30 daily samples or for fuels requiring hourly sulfur content
sampling with a gas chromatograph use the actual hourly sulfur
content). For fuels delivered in shipments or lots, use either the
actual sulfur content from the most recent shipment or an assumed
value (contract maximum or highest value from the previous year's
samples). In all cases, for reporting purposes, apply the results of
the required periodic total sulfur samples in accordance with the
provisions of section 2.3.2.1.2 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
2.3.2.1.2 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 the highest GCV from the previous year's
samples.
[[Page 32042]]
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 which performs the required 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. 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 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. The procedures
in this section may also be used to demonstrate that the GCV of a
particular gaseous fuel is within the range of GCV values for
pipeline natural gas or natural gas, as defined in Sec. 72.2 of this
chapter.
* * * * *
2.3.6 Demonstration of Fuel Sulfur 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 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 the total
sulfur content of a particular gaseous fuel is within the limits for
pipeline natural gas or natural gas, as defined in Sec. 72.2 of this
chapter. * * * Provide a minimum of 720 hours of data, indicating
the total sulfur content of the gaseous fuel or blend (in gr/100
scf). The demonstration data shall be obtained using either manual
hourly sampling or an on-line gas chromatograph capable of
determining fuel total sulfur content on an hourly basis. * * *
* * * * *
2.4 Missing Data Procedures
* * * * *
2.4.1 Missing Data for Oil and Gas Samples
* * * * *
Table D-6.--Missing Data Substitution Procedures for Sulfur, Density,
and Gross Calorific Value Data
------------------------------------------------------------------------
Missing data substitution maximum
Parameter potential value
------------------------------------------------------------------------
Oil Sulfur Content........... 3.5 percent for residual oil, or 1.0
percent for diesel fuel.
Oil Density.................. 8.5 lb/gal for residual oil, or 7.4 lb/
gal for diesel fuel.
Oil GCV...................... 19,500 Btu/lb for residual oil, or 20,000
Btu/lb for diesel fuel.
Gas Total Sulfur Content..... 1. 0.002 lb/mmBtu for pipeline natural
gas;
2. For natural gas for which semiannual
sampling is performed, a default
emission rate calculated from Equation D-
1h, using the lesser of: (a) The maximum
total sulfur content specified in the
fuel contract; or (b) 1.5 times the
highest total sulfur content from the
previous year's samples;
3. For any gaseous fuel sampled daily,
1.5 times the highest total sulfur
content value from the previous 30 days
on which valid samples were obtained; or
4. For any gaseous fuel sampled hourly,
the highest total sulfur content value
from the previous 720 hourly samples
Gas GCV/Heat Content......... 1100 Btu/scf for pipeline natural gas,
natural gas or landfill gas.
1500 for butane or refinery gas.
2100 Btu/scf for propane or any other
gaseous fuel.
------------------------------------------------------------------------
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 (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 may either establish
operational bins for the unit, as described in section 4 of appendix
C to this part, or may perform missing data substitution without
segregating the fuel flow rate data into bins. When load ranges or
operational bins 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 * * *
(b) The maximum flow rate that the fuel flowmeter can measure
(i.e, the upper range value of the flowmeter).
2.4.2.2 Missing Data Procedures for Non-peaking Units--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, apply the same mathematical algorithm to, and use the same
lookback period for, the 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 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.
2.4.2.2.2.1 If operational bins (as defined in section 4 of
appendix C to this part) are used, substitute the arithmetic average
of the hourly fuel flow rates measured and recorded by a certified
fuel flowmeter system at the corresponding operational bin 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 at the corresponding operational bin, or, if essential
operating or parametric data are unavailable and the operational bin
cannot be determined, 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.
2.4.2.2.2.2 If operational bins are not used, 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
[[Page 32043]]
of this appendix) for each hour of the missing data period.
2.4.2.3 Missing Data Procedures for Non-peaking Units--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, apply the same mathematical algorithm to,
and use the same lookback period for, the 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.
2.4.2.3.2.1 If operational bins (as defined in section 4 of
appendix C to this part) are used, substitute the maximum hourly
fuel flow rate measured and recorded by a certified fuel flowmeter
system at the corresponding operational bin, during the previous 720
operating hours in which the unit 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 at the
corresponding operational bin, or, if essential operating or
parametric data are unavailable and the operational bin cannot be
determined, 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.
2.4.2.3.2.2 If operational bins are not used, 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, if there is at least one hour, but
fewer than 720 hours of quality-assured fuel flowmeter data
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.
Appendix D to Part 75 [Amended]
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. In the numerator of Equation D-4 in section 3.3.1 by revising
the number ``2'' with the number ``2.0'';
c. In the definition of the variable ``GCVgas'' in
Equation D-6 in 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 section 3.4.2 by adding the word ``or'' after the word
``Btu/ton,'';
e. 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 equations and
variable definitions for Equations D-10 and D-11;
f. 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'';
g. Revising the section heading of section 3.5;
h. In section heading 3.5.4 by adding the words ``Rate and Heat
Input'' after the word ``Input''; and
i. In section 3.5.4 by adding the subsection number ``3.5.4.1''
before the existing text of the section and adding new subsection
3.5.4.2 following the variable definitions for Equation D-15.
The revisions and additions read as follows:
3. Calculations
* * * * *
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
* * * * *
3.5.4.2 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:
[GRAPHIC] [TIFF OMITTED] TP13JN01.033
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
* * * * *
59. Section 1 of Appendix E to Part 75 is amended by revising the
second sentence of section 1.1 and adding two sentences after that
second sentence 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. For each unit operating hour in which the
MER is reported, the MER shall be specific to the type of fuel being
combusted in the unit. * * *
* * * * *
60. Section 2 of 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 of
each section, adding a new sentence after each first sentence, and
revising each occurrence of the words
[[Page 32044]]
``manufacturer's recommended'' to read ``acceptable'';
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:
Appendix E to Part 75--Optional NOX Emissions Estimation
Protocol for Gas-Fired Peaking Units and Oil-Fired Peaking Units
* * * * *
2. Procedure
2.1 Initial Performance Testing
* * * * *
2.1.4 Emergency Fuel
The designated representative of a unit that has a federally-
enforceable permit restricting the combustion of a particular fuel to
emergencies where the primary fuel is not available is exempted from
the requirements of this appendix for testing the NOX
emission rate during combustion of the emergency fuel. 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 unit, 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.
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. * * *
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. * * *
* * * * *
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 paragraphs
2.5.2.1, 2.5.2.2, and 2.5.2.3 of this section.
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
correlation tests, the NOX emission rate for the hour is
considered to be missing. Provide substitute data for each such hour,
as follows.
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 option to report 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.
* * * * *
61. Section 2 of 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 SO 2 Emissions
* * * * *
2.3 * * *
[GRAPHIC] [TIFF OMITTED] TP13JN01.006
where: * * *
* * * * *
Appendix F Section 3 [Amended]
62. Section 3 of Appendix F to Part 75 is amended by removing the
third sentence from section 3.3.5.
63. Section 5 of Appendix F to Part 75 is amended by:
[[Page 32045]]
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 the definitions for the variables ``ti,'' and
``tcs,'' and ``n'' of 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'',
``tunit'', 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 5.6.3.
The revisions and additions read as follows:
5. Procedures for Heat Input
* * * * *
5.6 Heat Input Rate Apportionment for Units Sharing a Common Stack
or Pipe
* * * * *
5.6.3 As an alternative to using Equation F-21a or F-21b, 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] TP13JN01.034
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.
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.
Appendix F to Part 75 [Amended]
64. Section 7 of 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
* * * * *
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]
65. Section 8 of 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'';
b. Revising the definition of the variable ``tcs'' of
Equation F-25 in section 8.1.2; and
c. Adding definitions of the variables ``p'' and ``u'' to Equation
F-25 of section 8.1.2.
The revisions and additions read as follows:
8. Procedures for NOX Mass Emissions
* * * * *
8.1 * * *
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.
* * * * *
66. Section 2 of Appendix G to Part 75 is amended by:
a. Amending section 2.1 to designate the first two sentences
following the variables in Equation G-1 as section 2.1.1, the third
sentence as section 2.1.2, and the remaining text as section 2.1.3;
b. Revising the first sentence of section 2.3; and
c. Revising the definition of variable ``Fc'' of
Equation G-4 in section 2.3.
The revisions 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) * * *
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]
67. Section 5 of Appendix G to Part 75 is amended by:
[[Page 32046]]
a. Removing and reserving sections 5.1 and 5.1.1;
b. Revising the section heading and introductory text of 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
* * * * *
5.2 Missing Carbon Content Data
Use the procedures of this section to substitute for missing
carbon content data.
* * * * *
Table G-1.--Missing Data Substitution Procedures for Missing Carbon
Content Data
------------------------------------------------------------------------
Parameter Missing data value
------------------------------------------------------------------------
Oil and coal carbon content.. Most recent, previous carbon content
value available for that type of coal,
grade of oil, or default value, in this
table.
Gas carbon content........... Most recent, previous carbon content
value available for that type of gaseous
fuel, or default value, in this table.
Default coal carbon content.. Anthracite: 90.0 percent.
Bituminous: 85.0 percent.
Sub-bituminous/Lignite: 75.0 percent.
Default oil carbon content... 90.0 percent.
Default gas carbon content... Natural gas: 75.0 percent.
Other gaseous fuels: 90.0 percent.
------------------------------------------------------------------------
* * * * *
PART 78--APPEAL PROCEDURES FOR ACID RAIN PROGRAM
68. The authority citation for part 78 continues to read as
follows:
Authority: 42 U.S.C. 7401, 7403, 7410, 7426, 7601, and 7651, et
seq.
69. Section 78.1 is amended by removing from paragraph (a)(1) the
words ``parts 72, 73, 74, 75, 76, and 77 of this chapter'' and adding
in their place ``parts 72, 73, 74, 75, 76, or 77 of this chapter or
part 97 of this chapter''; and adding a new paragraph (b)(6) to read as
follows:
Sec. 78.1 Purpose and scope.
(b) * * *
(6) Under part 97 of this chapter,
(i) The adjustment of the information in a compliance certification
or other submission and the deduction or transfer of NOX
allowances based on the information, as adjusted, under Sec. 97.31;
(ii) The decision on the allocation of NOX allowances to
a NOX Budget unit under Sec. 97.41(b), (c), (d), or (e);
(iii) The decision on the allocation of NOX allowances
to a NOX Budget unit from the compliance supplement pool
under Sec. 97.43;
(iv) The decision on the deduction of NOX allowances
under Sec. 97.54;
(v) The decision on the transfer of NOX allowances under
Sec. 97.61;
(vi) The decision on a petition for approval of an alternative
monitoring system;
(vii) The approval or disapproval of a monitoring system
certification or recertification under Sec. 97.71;
(viii) The finalization of control period emissions data, including
retroactive adjustment based on audit;
(ix) The approval or disapproval of a petition under Sec. 97.75;
(x) The determination of the sufficiency of the monitoring plan for
a NOX Budget opt-in unit;
(xi) The decision on a request for withdrawal of a NOX
Budget opt-in unit from the NOX Budget Trading Program under
Sec. 97.86;
(xii) The decision on the deduction of NOX allowances
under Sec. 97.87; and (xiii) The decision on the allocation of
NOX allowances to a NOX Budget opt-in unit under
Sec. 97.88.
* * * * *
Sec. 78.2 [Amended].
70. Section 78.2 is amended by removing the words ``shall apply to
this part'' and adding to their place ``shall apply to appeals of any
final decision of the Administrator under parts 72, 73, 74, 75, 76, 77,
or 78 of this chapter''.
71. Section 78.3 is amended by:
a. Amending paragraph (b)(3)(i) by adding, after the word
``petitioner)'', the words ``or the NOX authorized account
representative under paragraph (a)(3) of this section (unless the
NOX authorized account representative is the petitioner)'';
b. In paragraph (c)(7) by adding, after the words ``title IV of the
Act'', the words ``or part 97 of this chapter, as appropriate'';
c. In paragraph (d)(2) by adding, after the words ``Acid Rain
Program'' the words ``or on an account certificate of representation
submitted by a NOX authorized account representative or an
application for a general account submitted by a NOX
authorized account representative under the NOX Budget
Trading Program'';
d. Redesignating paragraphs (d)(2) and (d)(3) as paragraphs (d)(3)
and (d)(4) respectively; and
e. Adding new paragraphs (a)(3) and (d)(2).
The additions and revisions read as follows:
Sec. 78.3 Petition for administrative review and request for
evidentiary hearing.
(a) * * *
(3) The following persons may petition for administrative review of
a decision of the Administrator that is made under part 97 of this
chapter and that is appealable under Sec. 78.1(a) of this part:
(i) The NOX authorized account representative for the
unit or any NOX Allowance Tracking System account covered by
the decision; or
(ii) Any interested person.
* * * * *
(d) * * *
(2) Any provision or requirement of part 97 of this chapter,
including the standard requirements under Sec. 97.6 of this chapter and
any emission monitoring or reporting requirements under part 97 of this
chapter.
* * * * *
72. Section 78.4 is amended by adding two new sentences after the
third sentence in paragraph (a) to read as follows:
Sec. 78.4 Filings.
(a) * * * Any filings on behalf of owners and operators of a
NOX Budget unit or source shall be signed by the
NOX authorized account representative. Any filings on behalf
of persons with an interest in NOX allowances in a general
account shall be signed by the NOX authorized account
representative. * * *
* * * * *
Sec. 78.12 [Amended]
73. Section 78.12 is amended by adding, after the words ``was
properly issued or should be issued'' in paragraph (a)(2), the words
``or that a
[[Page 32047]]
NOX Budget permit or other federally enforceable permit was
properly issued or should be issued''.
PART 97--FEDERAL NOX BUDGET TRADING PROGRAM
74. The authority citation for part 97 continues to read as
follows:
Authority: 42 U.S.C. 7401, 7403, 7426, and 7601.
75. Section 97.2 is amended by:
a. Revising the definition of ``continuous emission monitoring
system or CEMS'';
b. In the definition of ``Most stringent State or Federal
NOX emissions limitation'' by removing the words ``, with
regard to a NOX Budget opt-in unit,'';
c. In the third sentence of the definition of ``NOX
allowance'' by adding the reference ``Sec. 97.40,'' after the word
``except'';
d. In the definition of ``NOX Budget unit'' by removing
the words ``Trading Program'';
e. In the definition of ``owner'' by adding the word ``the'' before
the final occurrence of the word ``NOX'' in paragraph (4) of
the definition; and
f. In the definition of ``Percent monitor data availability'' by
revising the words ``3,672 hours per'' to read ``the total number of
unit operating hours in the'', and by revising the symbol ``%'' to read
``percent''.
The revisions and additions read as follows:
Sec. 97.2 Definitions.
* * * * *
Continuous emission monitoring system or CEMS means the equipment
required under subpart H of this part to sample, analyze, measure, and
provide, by means of readings taken at least once every 15 minutes
(using an automated data acquisition and handling system (DAHS), a
permanent record of nitrogen oxides (NOX) emissions, stack
gas volumetric flow rate or stack gas moisture content (as applicable),
in a manner consistent with part 75 of this chapter. The following are
the principal types of continuous emission monitoring systems required
under subpart H of this part:
(1) 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);
(2) 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);
(3) A nitrogen oxides 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 concentration
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); and
(4) 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).
* * * * *
Sec. 97.4 [Amended]
76. Section 97.4(b) is amended by:
a. Amending the first sentence of paragraph (b)(1) by adding, after
the words ``federally enforceable permit that'', the words ``restricts
the unit to combusting only natural gas or fuel oil (as defined in
Sec. 75.2 of this chapter) during a control period and'';
b. In paragraph (b)(4)(i) by adding, after the words ``with the
restriction on'', the words ``fuel use and''; and
c. In paragraph (b)(4)(vi)(B) by adding, after the words ``the
restriction on'', the words ``fuel use or''.
77. Section 97.5 is amended by:
a. In the third sentence of paragraph (b)(2) by adding, after the
word ``submit'', the words ``such a statement or'';
b. In paragraph (c)(6)(ii) by removing the period and replacing it
with ``; or''; and
c. Adding a new paragraph (c)(6)(iii).
The revisions and additions read as follows:
Sec. 97.5 Retired unit exemption.
* * * * *
(c) * * *
(6) * * *
(iii) The date on which the unit resumes operation, if the unit is
not required to submit a NOX permit application.
* * * * *
Sec. 97.40 [Amended]
78. Section 97.40 is amended by removing the word ``program''.
Sec. 97.43 [Amended]
79. Section 97.43 is amended by removing paragraph (c)(8).
Sec. 97.51 [Amended]
80. Section 97.51 is amended by amending paragraph (b)(1)(i)(D) by
adding, after the words ``with respect to'', the word ``
NOX''.
81. Section 97.54 is amended in paragraph (f) introductory text by
revising the colon after the words ``as follows'' with a period and by
adding a new sentence to the end of the paragraph to read as follows:
Sec. 97.54 Compliance.
* * * * *
(f) * * * For each State NOX Budget Trading Program that
is established, and approved and administered by the Administrator
pursuant to Sec. 51.121 of this chapter, the terms ``compliance
account'' or ``compliance accounts'', ``overdraft account'' or
``overdraft accounts'', ``general account'' or ``general accounts'',
``States'', and ``trading program budgets under Sec. 97.40'' in
paragraphs (f)(1) through (f)(3) of this section shall be read to
include respectively: a compliance account or compliance accounts
established under such State NOX Budget Trading Program; an
overdraft account or overdraft accounts established under such State
NOX Budget Trading Program; a general account or general
accounts established under such State NOX Budget Trading
Program; the State or portion of a State covered by such State
NOX Budget Trading Program; and the trading program budget
of the State or portion of a State covered by such State NOX
Budget Trading Program.
* * * * *
Sec. 97.61 [Amended]
82. Section 97.61 is amended in paragraph (b) by revising the words
``same year as'' to read ``third year after the year of''.
83. Section 97.70 is amended by:
a. In paragraph (a)(1) by revising the words ``Secs. 75.72 and
Secs. 75.76'' to read ``Secs. 75.71 and 75.72'';
b. Revising paragraph (b)(3);
c. Revising paragraph (b)(4);
d. Removing paragraphs (b)(5) and (b)(6);
e. Redesignating paragraphs (b)(7), (b)(8) and (b)(9) as paragraphs
(b)(5), (b)(6), and (b)(7), respectively;
f. Revising newly redesignated paragraphs (b)(5) and (b)(6); and
g. Revising paragraph (c).
The revisions and additions read as follows:
Sec. 97.70 General requirements.
* * * * *
(b) * * *
(3) For the owner or operator of a NOX Budget unit under
Sec. 97.4(a) that
[[Page 32048]]
commences operation on or after January 1, 2002 and that reports on an
annual basis under Sec. 97.74(d) by the following dates:
(i) The earlier of 90 unit operating days after the date on which
the unit commences commercial operation or 180 calendar days after the
date on which the unit commences commercial operation; or (ii) May 1,
2002, if the compliance date under paragraph (b)(3)(i) of this section
is before May 1, 2002.
(4) For the owner or operator of a NOX Budget unit under
Sec. 97.4(a) that commences operation on or after January 1, 2002 and
that reports on a control period basis under Sec. 97.74(d)(2)(ii), by
the following dates:
(i) The earlier of 90 unit operating days or 180 calendar days
after the date on which the unit commences commercial operation,
provided that this compliance date is during a control period; or (ii)
May 1 immediately following the compliance date under paragraph
(b)(4)(i) of this section, if such compliance date is not during a
control period.
(5) For the owner or operator of a NOX Budget unit that
has a new stack or flue for which construction is completed after the
applicable deadline under paragraph (b)(1), (b)(2), (b)(3), or (b)(4)
of this section or under subpart I of this part and that reports on an
annual basis under Sec. 97.74(d), by the earlier of 90 unit operating
days or 180 calendar days after the date on which emissions first exit
to the atmosphere through the new stack or flue.
(6) For the owner or operator of a NOX Budget unit that
has a new stack or flue for which construction is completed after the
applicable deadline under paragraph (b)(1), (b)(2), (b)(3), or (b)(4)
of this section or under subpart I of this part and that reports on a
control period basis under Sec. 97.74(d)(2)(ii), by the following
dates:
(i) The earlier of 90 unit operating days or 180 calendar days
after the date on which emissions first exit to the atmosphere through
the new stack or flue, provided that this compliance date is during a
control period; or
(ii) May 1 immediately following the compliance date under
paragraph (b)(6)(i) of this section, if such compliance date is not
during a control period.
* * * * *
(c) Commencement of data reporting. (1) The owner or operator of
NOX Budget units under paragraph (b)(1) or (b)(2) of this
section shall determine, record and report NOX mass
emissions, heat input rate, and any other values required to determine
NOX mass emissions (e.g., NOX emission rate and
heat input rate, or NOX concentration and stack flow rate)
in accordance with Sec. 75.70(g) of this chapter, beginning on the
first hour of the applicable compliance deadline in paragraph (b)(1) or
(b)(2) of this section.
(2) The owner or operator of a NOX Budget unit under
paragraph (b)(3) or (b)(4) of this section shall determine, record and
report NOX mass emissions, heat input rate, and any other
values required to determine NOX mass emissions (e.g.,
NOX emission rate and heat input rate, or NOX
concentration and stack flow rate) and electric and thermal output in
accordance with Sec. 75.70(g) of this chapter, beginning on:
(i) The date and hour on which the unit commences operation, if the
date and hour on which the unit commences operation is during a control
period; or
(ii) The first hour on May 1 of the first control period after the
date and hour on which the unit commences operation, if the date and
hour on which the unit commences operation is not during a control
period.
(3) Notwithstanding paragraphs (c)(2)(i) and (c)(2)(ii) of this
section, the owner or operator may begin reporting NOX mass
emission data and heat input data before the date and hour under
paragraph (c)(2)(i) or (c)(2)(ii) of this section if the unit reports
on an annual basis and if the required monitoring systems are certified
before the applicable date and hour under paragraph (c)(1) or (c)(2) of
this section.
* * * * *
84. Section 97.71 is amended by:
a. Revising paragraph (a) introductory text;
b. In paragraphs (b)(1), (b)(2), and (b)(3)(ii) by adding the word
``emission'' before the words ``monitoring system'' in each occurrence
in paragraph (b)(1), in both occurrences in the first sentence of
paragraph (b)(2), and in the one occurrence in paragraph (b)(3)(ii);
and by revising the word ``a'' to read ``an'' after the word
``installs'' in the second sentence of paragraph (b)(1);
c. In paragraphs (b)(3)(iii) and (b)(3)(iv)(C) by removing each
occurrence of the words ``or component thereof''; and
d. Revising the second sentence of paragraph (c), adding two new
sentences to the end of paragraph (c), and removing paragraphs (c)(i)
through (iii).
The revisions and additions read as follows:
Sec. 97.71 Initial certification and recertification procedures.
(a) The owner or operator of a NOX Budget unit that is
subject to an Acid Rain emissions limitation shall comply with the
initial certification and recertification procedures of part 75 of this
chapter for NOX-diluent CEMS, flow monitors, NOX
concentration CEMS, or excepted monitoring systems under appendix E of
part 75 of this chapter for NOX, under appendix D for heat
input, or under Sec. 75.19 for NOX and heat input, except
that:
* * * * *
(c) * * * The owner or operator of such a unit shall also meet the
applicable certification and recertification procedures of paragraph
(b) of this section, except that the excepted methodology shall be
deemed provisionally certified for use under the NOX Budget
Trading Program as of the date on which the certification application
is received by the Administrator. The methodology shall be considered
to be certified either upon receipt of a written notice of approval
from the Administrator or, if such notice is not provided, at the end
of the Administrator's 120 day review period. However, a provisionally
certified or certified low mass emissions excepted methodology shall
not be used to report data under the NOX Budget Trading
Program prior to the applicable commencement date specified in
Sec. 75.19(a)(1)(ii) of this chapter.
* * * * *
85. Section 97.72 is amended by:
a. In paragraph (a) by adding the word ``emission'' before the
words ``monitoring system'' and the words ``subpart H,'' before
``appendix D''; and
b. In paragraph (b) by adding the word ``emission'' before
``monitoring system'' in the first sentence, by removing each
occurrence of the words ``or component'' in the paragraph, and by
adding a new final sentence.
The revisions and additions read as follows:
Sec. 97.72 Out of control periods.
* * * * *
(b) * * * The owner or operator shall follow the initial
certification or recertification procedures in Sec. 97.71 for each
disapproved system.
86. Section 97.74 is amended by revising paragraphs (a)(1), (d)(1),
and (d)(2)(ii); to read as follows:
Sec. 97.74 Recordkeeping and reporting.
(a) * * *
(1) The NOX authorized account representative shall
comply with all recordkeeping and reporting requirements in this
section, with the
[[Page 32049]]
recordkeeping and reporting requirements under Sec. 75.73 of this
chapter, and with the requirements of Sec. 97.10(e)(1).
* * * * *
(d) * * *
(1) If a unit is subject to an Acid Rain emission limitation or if
the owner or operator of the NOX budget unit chooses to meet
the annual reporting requirements of this subpart H, the NOX
authorized account representative shall submit a quarterly report,
documenting the NOX mass emissions from the unit, for each
calendar quarter beginning with:
(i) For a unit for which the owner or operator intends to apply or
applies for the early reduction credits under Sec. 97.43, the calendar
quarter that covers May 1, 2000 through June 30, 2000. NOX
mass emission data shall be recorded and reported from the first hour
on May 1, 2000; or
(ii) For a unit that commences operation before January 1, 2002 and
that is not subject to paragraph (d)(1)(i) of this section, the
calendar quarter covering May 1, 2002 through June 30, 2002.
NOX mass emission data shall be recorded and reported from
the first hour on May 1, 2002; or
(iii) For a unit that commences operation on or after January 1,
2002:
(A) The calendar quarter in which the unit commences operation, if
unit operation commences during a control period. NOX mass
emission data shall be recorded and reported from the date and hour
when the unit commences operation; or
(B) The calendar quarter which includes May 1 through June 30 of
the first control period following the date on which the unit commences
operation, if the unit does not commence operation during a control
period. NOX mass emission data shall be recorded and
reported from the first hour on May 1 of that control period; or
(iv) A calendar quarter before the quarter specified in paragraph
(d)(1)(i), (d)(1)(ii), or (d)(1)(iii)(B) of this section, if the owner
or operator elects to begin reporting early under Sec. 97.70(c)(3).
(2) * * *
(ii) Submit quarterly reports, documenting NOX mass
emissions from the unit, only for the period from May 1 through
September 30 of each year and including the data described in
Sec. 75.74(c)(6) of this chapter. The NOX authorized account
representative shall submit such quarterly reports, beginning with:
(A) For a unit for which the owner or operator intends to apply or
applies for early reduction credits under Sec. 97.43, the calendar
quarter covering May 1, 2000 through June 30, 2000. NOX mass
emission data shall be recorded and reported from first hour on May 1,
2000;
(B) For a unit that commences operation before January 1, 2002 and
that is not subject to paragraph (d)(2)(ii)(A)of this section, the
calendar quarter covering May 1 through June 30, 2002. NOX
mass emission data shall be recorded and reported from the first hour
of May 1, 2002;
(C) For a unit that commences operation on or after January 1, 2002
and during a control period, the calendar quarter in which the unit
commences operation. NOX mass emission data shall be
reported from the date and hour corresponding to when the unit
commences operation; or (D) For a unit that commences operation on or
after January 1, 2002 and not during a control period, the calendar
quarter which includes May 1 through June 30 of the first control
period after the unit commences operation. NOX mass emission
data shall be recorded and reported from the first hour on May 1 of the
first control period after the unit commences operation.
* * * * *
Sec. 97.87 [Amended]
87. Section 97.87 is amended in second sentence of paragraph
(b)(1)(iii)(A) by adding the word ``be'' after the words ``shall not''.
88. Subpart J consisting of Sec. 97.90 is added to read as follows:
Subpart J--Appeal Procedures
Sec. 97.90 Appeal Procedures.
The appeal procedures for the NOX Budget Trading Program
are set forth in part 78 of this chapter.
[FR Doc. 01-13142 Filed 6-12-01; 8:45 am]
BILLING CODE 6560-50-P