[Federal Register Volume 61, Number 225 (Wednesday, November 20, 1996)]
[Rules and Regulations]
[Pages 59142-59166]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 96-29452]
[[Page 59141]]
_______________________________________________________________________
Part II
Environmental Protection Agency
_______________________________________________________________________
40 CFR Part 75
Acid Rain Program; Continuous Emission Monitoring Rule Technical
Revisions; Final Rule
Federal Register / Vol. 61, No. 225 / Wednesday, November 20, 1996 /
Rules and Regulations
[[Page 59142]]
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 75
[FRL-5650-7]
RIN 2060-AF58
Acid Rain Program; Continuous Emission Monitoring Rule Technical
Revisions
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule.
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SUMMARY: Title IV of the Clean Air Act (CAA or the Act), as amended by
the Clean Air Act Amendments of 1990, authorizes the Environmental
Protection Agency (EPA or Agency) to establish the Acid Rain Program.
The Acid Rain Program and the provisions in today's final rule benefit
the environment by preventing the serious, adverse effects of acidic
deposition on natural resources, ecosystems, materials, visibility, and
public health. The program does this by setting emissions limitations
to reduce acidic deposition precursor emissions. On January 11, 1993,
the Agency promulgated final rules, including the final continuous
emission monitoring (CEM) rule under title IV. On May 17, 1995, the
Agency published a direct final rule to make the implementation of the
program simpler. Furthermore, on May 17, 1995 the Agency published an
interim final rule and took comment on the provisions in the interim
final rule.
In this final rule, EPA is amending certain provisions of the CEM
regulations in response to public comments received on the direct final
and interim final rules. These amendments will streamline the rule and
increase implementation flexibility for the affected industry.
DATES: Effective Date. This final rule shall become effective on
December 20, 1996.
Incorporation by Reference. The incorporation by reference of
certain publications listed in the rule is approved by the Director of
the Federal Register as of December 20, 1996.
ADDRESSES: Docket No. A-94-16, containing supporting information used
in developing the final rule, is available for public inspection and
copying at the following address: Air and Radiation Docket and
Information Center (6102), U.S. Environmental Protection Agency, 401 M
Street SW, Washington, DC 20460. The docket is located in Room M-1500,
Waterside Mall (ground floor) and may be inspected from 8:30 a.m. to
noon, and from 1 to 3 p.m., Monday through Friday. Copies of
information in the docket may be obtained by request from the Air
Docket by calling (202) 260-7548. A reasonable fee may be charged for
copying docket materials.
FOR FURTHER INFORMATION CONTACT: Jennifer Macedonia, Acid Rain Division
(6204J), U.S. Environmental Protection Agency, 401 M Street SW,
Washington, DC 20460, telephone number (202) 233-9180.
SUPPLEMENTARY INFORMATION: The EPA is revising the CEM provisions as a
final rule because the Agency has already taken comment on the
provisions that are being revised. The information in this preamble is
organized as follows:
I. Regulated Entities
II. Background and Summary of the Final Rule
III. Rationale
A. Revising the Daily Assessment Procedures Set Forth in the
Interim Final Rule
1. Unit Operation During Daily Calibration Error Tests
2. Unit Operation During Daily Flow Monitor Interference Checks
3. Quality Assurance of Data Following Daily Calibration Error
Tests
4. Quality Assurance of Data Following Daily Flow Interference
Checks
5. Summary of Structure and Regulatory Changes to Section 2 of
Appendix B
B. Revising the Monitoring Methods for Units with SO2 CEMS
During Hours When the Unit is Only Burning Gaseous Fuels
1. SO2 Monitoring During Combustion of Gas for Units with
SO2 CEMS
2. SO2 Concentration Missing Data During Gas Combustion
C. Clarifying the Procedures for Performing Cycle Time Tests
D. Revising the Reporting of Scrubber Parameters and Missing
Data for Add-on Emission Controls
E. Clarifying the Procedures Dealing with the Use of Method 9
Instead of Continuous Opacity Monitors on Bypass Stacks
F. Addressing Minor Comments on the Direct Final Rule
1. Use of AGA Report No. 7
2. Provisions for Reporting and Monitoring of Subtracted
Emissions at a Common Stack
3. Heat Input Apportionment at Common Stacks
4. Recertification of Opacity Monitoring Systems
G. Addressing Comments on RATA Notifications
IV. Impact Analyses
A. Executive Order 12866
B. Unfunded Mandates Act
C. Paperwork Reduction Act
D. Regulatory Flexibility Act
E. Small Business Regulatory Enforcement Fairness Act
I. Regulated Entities
Entities potentially regulated by this action are fossil fuel-fired
utility boilers and turbines that serve a generator which generates
electricity for sale. Regulated categories and entities include:
------------------------------------------------------------------------
Examples of regulated
Category entities
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Industry.................................. Electric Utility Boilers and
Turbines.
------------------------------------------------------------------------
This table is not intended to be exhaustive, but rather provides a
guide for readers regarding entities likely to be regulated by this
action. This table lists the types of entities that 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 criteria in
Secs. 72.6, 72.7 and 72.8 of title 40 of the Code of Federal
Regulations. 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.
II. Background and Summary of the Final Rule
Title IV of the Act requires the EPA to establish an Acid Rain
Program to reduce the adverse effects of acidic deposition. On January
11, 1993, the Agency promulgated final rules implementing the program,
including the General Provisions of the Permits Regulation and the CEM
rule (58 FR 3590-3766). Technical corrections were published on June
23, 1993 (58 FR 34126) and July 30, 1993 (58 FR 40746-40752). A notice
of direct final rulemaking and a notice of interim final rulemaking
making further changes to the regulations were published on May 17,
1995 (60 FR 26510 and 60 FR 26560, respectively). There are several
provisions in the interim final rule that will expire on January 1,
1997. Therefore, this final rule addresses these provisions that will
expire, reaffirms several provisions of the interim final rule that are
not changing and revises sections of the interim final rule based on
comments. The final rule also modifies a few provisions of the direct
final rule on which the Agency received comments.
The issues addressed by this final rule are: (1) Revising the daily
assessment procedures set forth in the interim final rule, (2) revising
the monitoring methods for units with sulfur dioxide (SO2)
continuous emission monitoring systems (CEMS) during hours when the
unit is only burning gaseous fuels, (3) clarifying the procedures for
performing
[[Page 59143]]
cycle time tests (appendix A, section 6.4), (4) revising the reporting
of scrubber parameter ranges in the monitoring plan, (5) clarifying the
procedures dealing with the use of Reference Method 9 instead of
continuous opacity monitoring systems (COMS) on bypass stacks, (6)
addressing minor comments on the direct final rule and (7) addressing
comments on RATA notifications.
This final rule addresses the following sections. Section 75.6,
``Incorporation by reference,'' is revised to incorporate the American
Gas Association (AGA) ``AGA Report Number 7.'' This change is being
made in response to comments received on the direct final rule and
petitions received and approved by the Agency to use ``AGA Report
Number 7.''
Sections 75.11 (e) and (g), ``Specific provisions for monitoring
SO2 emissions (SO2 and flow monitors),'' as established by
the interim final rule, expire on January 1, 1997. The provisions in
Sec. 75.11(a) were suspended from July 17, 1995 through December 31,
1996. In this final rule, Secs. 75.11 (a), (d), and (e) are being
revised and Sec. 75.11(g) is being removed based on comments on the
interim final rule.
Section 75.16, ``Special provisions for monitoring emissions from
common, bypass and multiple stacks for SO2 emissions and heat
input determinations,'' Sec. 75.18, ``Specific provisions for
monitoring emissions from common and bypass stacks for opacity,'' and
Sec. 75.20, ``Certification and recertification requirements,'' are
being revised in response to comments received on the direct final
rule.
Section 75.21(f), ``Quality assurance and quality control
requirements,'' as established by the interim final rule, expires
January 1, 1997. The provisions in Sec. 75.21(a) were suspended from
July 17, 1995 through December 31, 1996. In this final rule,
Sec. 75.21(a) is revised and Sec. 75.21(f) is deleted based on comments
on the interim final rule. Section 75.21(d), ``Notification for
periodic relative accuracy test audits,'' is added based on comments
received on the direct final rule.
Section 75.30(d), ``General provisions,'' is revised based on
comments received on this section from the interim final rule. Section
75.30(e) remains in effect from the interim final rule with no changes.
Section 75.32(a)(4), ``Determination of monitoring data
availability for standard missing data procedure,'' as established by
the interim final rule, expires January 1, 1997. The provisions in
Sec. 75.32(a)(3) were suspended from July 17, 1995 through December 31,
1996. In this final rule, Sec. 75.32(a)(3) is revised and
Sec. 75.32(a)(4) is deleted based on comments on the interim final
rule.
Sections 75.34 (a), (b), (c), and (d), ``Units with add-on emission
controls,'' Sec. 75.53(d), ``Monitoring plan,'' Secs. 75.55 (b) and
(e), ``General recordkeeping provisions for specific situations,''
Secs. 75.56 (a), (c), and (d), ``Certification, quality assurance and
quality control record provisions,'' and Sec. 75.66(f), ``Petitions to
the Administrator,'' are revised based on comments on the interim final
rule. Section 75.61(a)(5), ``Periodic relative accuracy test audits,''
is added based on comments received on the direct final rule. Sections
75.64 and 75.66(e) remain in effect from the interim final rule with no
changes.
Sections 6.3.3 and 6.3.4 in appendix A of part 75, ``Pollutant
concentration monitor and CO2 or O2 monitor 7-day calibration
error test'' and ``Flow monitor 7-day calibration error test,''
respectively, as established by the interim final rule, expire January
1, 1997. The provisions in sections 6.3.1 and 6.3.2 of appendix A were
suspended from July 17, 1995 through December 31, 1996. In this final
rule, sections 6.3.1 and 6.3.2 of appendix A are deleted, section 6.3.3
is revised, and sections 6.3.3 and 6.3.4 of appendix A of the interim
final rule are redesignated as sections 6.3.1 and 6.3.2.
Section 6.4.1 of appendix A, ``Cycle time test,'' as established by
the interim final rule, expires January 1, 1997. The provisions in
section 6.4 of appendix A were suspended from July 17, 1995 through
December 31, 1995. In this final rule, section 6.4 of appendix A is
revised and section 6.4.1 of appendix A is deleted based on comments on
the interim final rule.
Appendix B to part 75 is amended by adding section 1.6,
``Parametric monitoring for units with add-on emission controls''. This
addition is based on comments received on the interim final rule.
Section 2.1.7 of appendix B, ``Daily assessments,'' as established
by the interim final rule, expires January 1, 1997. The provisions in
section 2.1 of appendix B were suspended from July 17, 1995 through
December 31, 1995. In this final rule, sections 2.1 and 2.1.1 of
appendix B are revised, sections 2.1.1.1 and 2.1.1.2 are added, section
2.1.2 is deleted, section 2.1.3 is redesignated as section 2.1.2, the
new section 2.1.2 is revised, sections 2.1.4 and 2.1.5 are redesignated
as sections 2.1.3 and 2.1.4, respectively; sections 2.1.5, 2.1.5.1 and
2.1.5.2 are added, and section 2.1.7 of appendix B is deleted based on
comments on the interim final rule.
Appendix D of part 75, ``Optional SO2 emissions data protocol
for gas-fired and oil-fired units,'' is amended by revising section
2.1.5.1 based on comments on the direct final rule.
Section 7 of appendix F of part 75, ``Procedures for SO2 mass
emissions at units with SO2 continuous emission monitoring systems
during the combustion of gaseous fuel,'' is revised based on comments
received on the interim final rule.
III. Rationale
A. Revising the Daily Assessment Procedures Set Forth in the Interim
Final Rule
This section addresses several issues related to the frequency of
performing daily assessments (i.e., daily calibration error tests and
flow interference checks) for the purpose of quality assuring data from
CEMS and flow monitoring systems. Based on comments received on the May
17, 1995 interim final rule, section 2 of appendix B is revised in
today's rule with respect to four main issues. The first issue deals
with unit operation during daily calibration error tests of gas and
flow monitoring systems and is discussed in section A.1 below. The
second issue deals with unit operation during interference checks of
flow monitoring systems and is addressed in section A.2 below. The
third issue deals with quality assurance of data with respect to daily
calibration error tests and is described in section A.3 below. The
final issue deals with quality assurance of data with respect to daily
flow interference checks and is discussed in section A.4 below. In
addition, the structural and regulatory changes that have been made to
section 2 of appendix B are described in detail in section A.5 below.
1. Unit Operation During Daily Calibration Error Tests
Background: This issue is related to the daily calibration error
tests required for CEMS and flow monitoring systems under section 2 of
appendix B of part 75. The following provisions of the January 11, 1993
final rule required the affected unit to be operating during daily
calibration error tests: section 2.1.1 of appendix B and sections 6.1
and 6.3.2 of appendix A. The May 17, 1995 interim final rule
reaffirmed, both in the preamble at 60 FR 26564-65 and in section 2.1.7
of appendix B, the requirement to perform daily calibration error tests
of gas monitors and flow monitors while the unit is operating.
Calibration error tests are required to be performed while the unit
is operating because readings from the CEMS and flow monitoring systems
are affected by temperature and pressure conditions
[[Page 59144]]
(See Docket A-96-16, Item II-D-39, Log of telephone conversation
between Jon Konings, WEPCo, and M. Sheppard, EPA, on EPA's calibration
error test policy, April 13, 1994.) Section 6.3.1 of appendix A of the
January 11, 1993 final rule and section 6.3.3 of appendix A of the May
17, 1995 interim final rule both affirm that the calibration error test
of a CEMS is to be a test of the entire monitoring system, not just a
test of the analyzer. At least a portion of the sampling interface of a
CEMS is directly exposed to stack conditions. Since there is a
significant variation in stack temperature and pressure, depending on
whether or not the unit is in operation, CEMS readings can vary
accordingly. Therefore, to ensure accurate CEMS measurements,
calibration error tests should be performed under the same or similar
conditions as when emission data are collected by the CEMS.
Issue: During the public comment period for the interim final rule,
some commenters raised concerns about the requirement to perform daily
calibration error tests while the unit is operating. (See Docket A-94-
16, Items V-D-04, V-D-07, V-D-09, V-D-11, V-D-13, V-D-14, and V-D-15.)
Commenters mentioned that monitoring technologies exist which are
capable of minimizing the effects of pressure and temperature
regardless of unit operation. Therefore, for some monitoring systems,
calibration error test results should not be affected by the operation
or non-operation of the unit. The commenters requested that, to assist
them in meeting the part 75 quality assurance requirements, and to
minimize the loss of concentration and flow data, EPA allow daily
calibration error tests to be performed while the unit is not
operating. Some commenters provided data showing a history of
successful off-line calibrations. Other commenters mentioned specific
monitoring technologies capable of performing valid off-line
calibration error tests (e.g., fully extractive systems with
measurement on a dry basis, and dilution extractive systems with heated
probes and pressure compensation).
J.A. Jahnke, PhD, an authority on CEM technology, identified the
following technologies which, if used properly, could minimize the
effects of temperature and pressure: (1) fully extractive dry systems
in which the calibration gas is not injected prior to an external probe
filter, (2) ex-situ dilution systems with an accurate pressure
compensation algorithm, and (3) in-stack dilution systems with a heated
probe maintained at constant temperature and with accurate pressure
compensation. (See Docket A-94-16, Item II-C-7, ``Further comments on
Continuous Emission Monitoring (CEM) System Calibration Error Checks
for Unit Off-line/On-line Conditions,'' J.A. Jahnke, PhD, Source
Technology Associates.)
Response: The EPA agrees with the commenters that some types of
CEMS are capable of minimizing the effects of temperature and pressure
upon the CEMS measurements, and are therefore capable of performing a
valid calibration error test while the unit is not operating. However,
there are also CEMS and flow monitoring systems in use which clearly do
not have this capability. For example, in-situ electro-optical systems
can experience alignment problems when used on a hot stack after being
calibrated on a cold stack. Also, a dilution probe system without a
probe heater and without temperature and pressure compensation can
underestimate pollutant concentrations in hot flue gas after being
calibrated off-line. In addition, the effectiveness of some monitoring
system technologies varies with the specific installation or with the
ambient conditions. For instance, temperature and pressure compensation
algorithms are often site-specific and may be difficult to apply
properly; or a dilution extractive system with a probe heater may only
be able to perform valid off-line calibrations during the warmer spring
and summer months. Therefore, in some instances, using the results of
an off-line calibration error test to validate data from a monitoring
system could result in an underestimation of emissions. (See Docket A-
94-16, Item II-C-7, ``Further comments on Continuous Emission
Monitoring (CEM) System Calibration Error Checks for Unit Off-line/On-
line Conditions,'' J.A. Jahnke, PhD, Source Technology Associates; Item
II-C-8, EPRI, 1994; and Item II-D-94, Phone log between Margaret
Sheppard and City of Hamilton.)
The EPA agrees with the conclusions of Dr. Jahnke and several of
the commenters, that in some instances, off-line calibration error
tests may be appropriate to provide affected units more flexibility in
meeting the quality assurance testing requirements of appendix B of
part 75. The EPA also agrees with the commenters who stated that more
flexibility would be especially helpful to small peaking units that
operate infrequently and routinely alternate between operation and non-
operation. Therefore, section 2.1.1.2 of appendix B of today's rule
allows limited use of off-line calibration error tests to validate CEM
data.
Section 2.1.1.1 of appendix B of today's rule retains the
requirement that on-line calibration error tests must be done for all
monitoring systems. However, to give owners or operators greater
flexibility in complying with the quality assurance requirements of
part 75, an exception has been provided in section 2.1.1.2 of appendix
B, which allows some off-line calibrations to be done. The Agency has
decided not to allow the unqualified use of off-line calibration error
tests for the following reasons: (a) accurate monitoring system
temperature corrections may not be possible for units that undergo
large swings in temperature, e.g., cycling (peaking) units; (b) for
dilution systems (even with heaters), inaccurate readings may occur if
the dilution air flow does not reach equilibrium with stack
temperature; and (c) temperature correction equations may be site-
specific and therefore, may not be applied correctly. (See Docket A-94-
16, Item II-C-8, ``Pressure and Temperature Effects in Dilution
Extractive Continuous Emission Monitoring Systems,'' EPRI TR-104700,
December 1994.)
In developing the final off-line calibration error test provision,
EPA considered two implementation approaches: (1) a technology-specific
approach that would allow certain monitoring technologies to perform
off-line calibration error tests to validate data; and (2) a
performance-based approach, in which any monitoring system that passed
a performance test would be allowed to use occasional off-line
calibration error tests to validate data.
Although some monitoring technologies may be capable of performing
valid off-line calibration error tests, EPA has several concerns
regarding a technology-specific approach. First, the effectiveness of
many monitoring system technologies is site-specific (e.g., temperature
and pressure compensation algorithms, heated dilution probes).
Therefore, a global endorsement of a particular technology is not
prudent. Second, a technology-specific approach may not cover all
possible candidate monitoring systems, and thus may not be equitable to
all monitoring system vendors. Finally, because monitoring technologies
change over time, frequent rule revisions would be needed to ensure
continued fairness to the CEMS vendors. For these reasons, EPA decided
against a technology-specific approach.
The EPA concluded that a performance-based approach would better
ensure a ``level playing field'' for all monitoring technologies by
establishing a demonstration which could be attempted by any candidate
[[Page 59145]]
monitoring system capable of compensating for the effects of
temperature and pressure. Occasional off-line calibration error tests
for data validation would then be allowed for any monitoring system
that successfully performed the demonstration. Frequent rule revisions
would not be required with a performance-based approach because it can
accommodate changing technology.
For these reasons, today's rule allows occasional off-line
calibration error tests to be used for data validation, for any
monitoring system that passes a one-time performance test designed to
demonstrate the validity of an off-line calibration error test. The
performance test, referred to as the ``Off-line Calibration
Demonstration,'' is found at section 2.1.1.2 of appendix B of today's
rule. The demonstration requires a candidate monitoring system to pass
a calibration error test while the unit is not operating and then,
within 26 clock hours, to pass a calibration error test while the unit
is operating. Both of these calibration error tests must meet the
performance specification in section 3.1 of appendix A. The EPA
selected the 26 clock hours separation time between the calibration
error tests to be consistent with the usual length of time of
prospective data validation from a calibration error test. Routine
calibration adjustments are allowed following the off-line calibration
error test; these adjustments must be toward the true calibration gas
or reference signal value.
The performance demonstration is not intended to establish
unqualified equivalence between off-line and on-line calibration error
tests, but rather to screen out monitoring systems that are clearly
incapable of performing a valid calibration error test while the unit
is not operating. The EPA remains concerned that even if a monitoring
system has passed the off-line calibration demonstration, it may be
miscalibrated based on an off-line calibration and subsequently it may
underestimate emissions. In that instance, the CEMS would most likely
fail the next on-line calibration. The EPA considered incorporating a
proposal by one commenter to address this concern. The proposal would
have required retrospective invalidation of data whenever an on-line
calibration error test is failed following an off-line calibration.
However, EPA did not incorporate this suggestion because of the
complexity of programming, for both utilities and the EPA, involved in
implementing retrospective invalidation. Instead, EPA may propose
additional limitations on the use of off-line calibration error tests
in a future rulemaking to ensure that off-line calibrations are only
performed where appropriate. This will give the public opportunity to
comment on the additional provisions.
Whenever possible, calibration error tests should be scheduled and
performed while the unit is operating. If a unit operates infrequently
(i.e., a peaking unit or a cycling unit) consideration should be given
to scheduling automatic calibration at a time the unit is most likely
to be operating. The provisions in today's rule allowing some off-line
calibration error tests are meant to provide additional flexibility in
special circumstances and thus minimize the need to use missing data
routines. Off-line calibration error tests are not intended to replace
on-line calibration error tests. Therefore, section 2.1.1.2 of appendix
B of today's rule requires that an on-line calibration error test be
performed within 26 unit operating hours of any off-line calibration
error test used to validate data. If, for a particular CEMS or flow
monitoring system, an on-line calibration error test is not performed
within 26 unit operating hours of an off-line calibration error test
used to validate data, section 2.1.3.1 of appendix B requires missing
data to be substituted beginning in the 27th unit operating hour. To
allow time for these new missing data requirements to be incorporated
in data acquisition and handling system (DAHS) software, the new
missing data requirements become effective on January 1, 1999. Prior to
January 1. 1999, the owner or operator may elect to comply with the new
missing data requirements.
Although today's rule allows off-line daily calibration error tests
in specific circumstances, the Agency is retaining the requirement in
sections 6.3.1 and 6.3.2 of appendix A for the initial 7-day
calibration error test of pollutant and diluent monitoring systems and
flow monitoring systems to be performed while the unit is operating.
The EPA has decided to retain the requirement to perform the 7-day
calibration error test on-line for two reasons. First, the 7-day
calibration error test must only be performed for the initial
certification of a monitoring system and occasionally for
recertification; the test is not part of the periodic quality assurance
requirements in appendix B. Second, for the reasons stated previously,
the Agency considers on-line calibration error tests to have a higher
probability of indicating the true accuracy of the monitoring system.
2. Unit Operation During Daily Flow Monitor Interference Checks
Background: The January 11, 1993 final rule did not specifically
address the issue of unit operation during daily interference checks of
flow monitors. However, section 2.1.7 of appendix B of the May 17, 1995
interim final rule required all daily assessments, including flow
monitoring system interference checks, to be performed while the unit
is operating. The requirement to perform daily assessments while the
unit is operating was promulgated so that the test would be performed
under the same conditions as when emissions measurements are recorded.
Issue: No comments were received on the issue of unit operation
during daily flow interference checks.
Response: Because no comments were received on this issue, the
provision requiring flow monitoring system interference checks to be
performed on-line is adopted as final. Section 2.1.7 of appendix B has
been removed from today's rule. The requirement to perform on-line flow
interference checks has been moved to section 2.1.3.
3. Quality Assurance of Data Following Daily Calibration Error Tests
Background: Section 2.1 of appendix B of the January 11, 1993 final
rule (incorporated unchanged into the May 17, 1995 interim final rule)
required daily assessments of monitoring system accuracy, such as
calibration error tests and flow interference checks, to be performed
during each day in which a unit combusts any fuel (i.e. each operating
day) or, for a monitoring system on a bypass stack or duct, during each
day that emissions pass through the bypass stack or duct. In addition,
section 2.1.1 of appendix B of the January 11, 1993 final rule stated
that pollutant concentration and carbon dioxide (CO2) or oxygen
(O2) monitors were required to conduct calibration error checks,
to the extent practicable, approximately 24 hours apart.
In March 1995, EPA published a policy in Update #5 of the ``Acid
Rain Program Policy Manual''. (See Docket A-94-16, Item II-D-95) which
interprets sections 2.1 and 2.1.1 of appendix B. The policy (which is
outlined in the answer to Question 10.13) states that ``a passed
calibration test prospectively validates data for that monitoring
system beginning with the hour in which the test is passed for 26 clock
hours''. This policy allows a 2-hour grace period beyond a 24-hour
``day'' as an interpretation of the provision in section 2.1.1 of
appendix B
[[Page 59146]]
to perform the tests ``approximately 24 hours apart''. The policy
includes a ``grace'' period of up to 8 clock hours for data validation
during start-up events. The start-up grace period was included as part
of the interpretation of the daily calibration provisions in response
to utility concerns that if a unit is shut down or in an unstable
start-up condition when a daily calibration error test is due, it might
be impossible to perform a valid daily calibration for several hours,
until stable temperature and pressure conditions are achieved.
The preamble to the May 17, 1995 interim final rule discussed
quality assurance of data following daily calibration error tests at 60
FR 26564. Section 2.1.7 of appendix B was added in the May 17, 1995
interim final rule to address the situation in which a unit
discontinues operation or the use of the bypass stack or duct is
discontinued prior to the performance of a daily calibration error
test; the new section added flexibility for that situation so that data
from the monitoring system are considered quality-assured prospectively
for up to 24 consecutive clock hours following a successful daily test.
However, the May 17, 1995 interim final rule did not provide for an 8-
hour start-up grace period.
Issue: During the public comment period for the interim final rule,
EPA received comments on the added section 2.1.7 of appendix B. One
commenter declared that section 2.1.7 of appendix B may require units,
particularly peaking units, to operate unnecessarily and at higher load
levels than they would otherwise operate. The commenter stated that
this will result in unnecessary emissions, contrary to the intent of
the law and proposed a solution to provide a grace period that excuses
calibrations for start-up situations. (See Docket A-94-16, Item V-D-
11). Another commenter expressed concern that section 2.1.7 of appendix
B provided a validation period of only 24 hours and did not allow for
an 8-hour grace period. The commenter urged EPA to incorporate the
language from Question 10.13 in the ``Acid Rain Program Policy Manual''
into the final rule provisions. (See Docket A-94-16, Item V-D-17).
Similarly, other commenters expressed support for the more flexible
approach provided in the manual as it allows for quality assurance of
data under more real-life operating scenarios. (See Docket A-94-16,
Item V-D-07). The commenters requested that the rule be revised to be
consistent with the data validation policy in Question 10.13 of the
manual. (See Docket A-94-16, Items V-D-13, V-D-15.)
Response: The EPA agrees with the commenters that requiring a unit
to operate and produce emissions solely for the purpose of performing a
test on time does not meet the intent of the regulation. In addition,
EPA agrees that a prospective data validation period of 26 clock hours
and a start-up grace period of 8 clock hours provides additional
flexibility to units, particularly peaking and cycling units, in order
to meet the requirements to perform daily assessments. Therefore,
today's rule revises section 2 of appendix B as described in the
summary in section A.5 below to incorporate the 26-hour validation
period and 8-hour start-up grace period for daily assessments. For
monitoring systems that have passed the Off-line Calibration
Demonstration, the 8-hour grace period does not apply if an off-line
calibration error test has been performed since the last on-line
calibration error test.
4. Quality Assurance of Data Following Daily Flow Interference Checks
Background: Section 2.1 of appendix B of the January 11, 1993 final
rule (incorporated unchanged into the May 17, 1995 interim final rule)
addressed the requirements for daily assessments of monitoring system
accuracy, such as daily calibration error tests for gas and flow
monitoring systems and daily interference checks for flow monitoring
systems.
Section 2.1.7 of appendix B, entitled ``Daily Assessments,'' was
added in the May 17, 1995 interim final rule to address the situation
where a unit discontinues operation or where the use of the bypass
stack or duct is discontinued prior to the performance of a daily
assessment. However, the rule language mentions only the daily
calibration error test, not the flow monitor interference check.
In November 1995, EPA published an answer in Update #7 of the
``Acid Rain Program Policy Manual.'' (See Docket A-94-16, Item II-D-97)
which interprets sections 2.1 and 2.1.7 of appendix B. The answer to
Question 10.18 states that the data validation policy for daily
calibration error tests also applies to daily interference checks for
flow monitors.
Issue: A commenter requested that the interim final rule be revised
so that the prospective data validation policy for daily calibration
error tests, proposed in section 2.1.7 of appendix B and Question 10.13
in the ``Acid Rain Program Policy Manual,'' be extended to include
daily flow monitor interference checks as well. (See Docket A-94-16,
Item V-D-18).
Response: The EPA agrees with the commenter that the prospective
data validation policy for daily flow interference checks should be
consistent with the provision for daily calibration error tests. In
fact, the original intent was for section 2.1.7 of appendix B of the
interim final rule to apply to all daily assessments, both calibration
error tests and flow interference checks. Therefore, today's rule
revises section 2 of appendix B, as described in the summary in section
A.5 below, to incorporate the 26-hour validation period and 8-hour
start-up grace period for all daily assessments, including flow monitor
interference checks.
5. Summary of Structure and Regulatory Changes to Section 2 of Appendix
B
In order to incorporate revisions to section 2 of appendix B, some
of the subsections are structured differently in today's rule than in
the May 17, 1995 interim final rule and the January 11, 1993 final
rule. First, section 2.1.2, which addresses daily calibration error
tests for flow monitoring systems, is removed, and section 2.1.1 is
revised to address daily calibration error tests for both gas
concentration and flow monitoring systems. Secondly, sections 2.1,
2.1.1, and 2.1.3 of appendix B of the interim final rule are revised by
removing the requirement to perform daily assessments every unit
operating day. Instead, the new sections 2.1.3 and 2.1.3.1 of today's
rule describe the 26-hour prospective data validation from a passed
daily assessment and the invalidation of data resulting when a daily
assessment is not performed. Also, the new section 2.1.3.2 in today's
rule describes the 8-hour start-up grace period for daily assessments.
Third, section 2.1.3 of the interim final rule is redesignated as
section 2.1.2 in today's rule; the new section 2.1.2 is also revised to
add the requirement to perform flow interference checks on-line
(previously in section 2.1.7) and to remove the requirement to perform
flow interference checks every unit operating day. Instead, the
provisions for quality assuring data with respect to daily flow
interference checks are addressed with the requirements for all daily
assessments in the new sections 2.1.5, 2.1.5.1, and 2.1.5.2 of today's
rule. Fourth, sections 2.1.4 and 2.1.5 are redesignated as sections
2.1.3 and 2.1.4, respectively. Finally, section 2.1.7 of appendix B of
the interim final rule is removed. The provisions for unit operation
during tests and prospective validation following tests which were
addressed in section 2.1.7 are now addressed in sections 2.1.1.1,
2.1.1.2, 2.1.2, 2.1.5, 2.1.5.1, and 2.1.5.2. Section
[[Page 59147]]
2.1.1.1 addresses the basic requirement to perform daily calibration
error tests on-line; section 2.1.1.2 addresses the exception that
allows some daily calibration error tests to be performed off-line.
B. Revising the Monitoring Methods for Units With SO2 CEMS During
Hours When the Unit is Only Burning Gaseous Fuels
1. Determination of SO2 Mass Emissions During Combustion of
Gaseous Fuel, for Units With SO2 CEMS
Background: All of the coal-fired units, many of the oil-fired
units, and some of the gas-fired units subject to part 75 requirements
currently use an SO2 CEMS and a flow monitoring system to account
for their SO2 mass emissions. By definition, affected gas-fired
units with SO2 CEMS must derive at least 90 percent of their heat
input from the combustion of gaseous fuel. (See definition of ``gas-
fired'' in 40 CFR 72.2.) Generally, the fuel is pipeline natural gas.
Many of the coal and oil-fired units with SO2 CEMS derive their
heat input exclusively from coal or oil; however, a significant number
of the coal and oil-fired units with SO2 CEMS also combust natural
gas (or other gaseous fuel with a sulfur content no greater than
natural gas), either as backup fuel or solely during unit startup.
Natural gas has a very low sulfur content and will produce extremely
low SO2 concentrations when combusted alone. Typically, SO2
concentrations from the combustion of natural gas will range from about
0 to 5 parts per million (ppm) for ``sweetened'' pipeline natural gas
to about 20 to 30 ppm for ``sour'' natural gas.
It is difficult for most SO2 monitors to accurately measure
the low SO2 concentrations associated with the combustion of
natural gas. It is also difficult to quality-assure SO2 monitoring
data at such low concentrations. Protocol 1 calibration gases at these
low concentrations are either not available or are very expensive, and
relative accuracy test audits (RATAs) of the SO2 monitor are of
questionable value because gas-fired SO2 concentrations are
generally at, near or below the limit of detectability of both the CEMS
and the reference method.
Issue: Sections 75.11(a) and 75.11(d) of the January 11, 1993 final
rule required owners or operators of coal-fired units and allowed
owners or operators of oil-fired and gas-fired units to account for
SO2 emissions using an SO2 monitoring system. No conditions
were placed upon the use of the SO2 monitor, either for coal-
fired, oil-fired or gas-fired units. No distinction was made between
SO2 monitoring during the combustion of gaseous fuel and SO2
monitoring during hours in which higher-sulfur fuel such as coal or oil
is combusted. In the preamble to the May 17, 1995 interim final rule,
however, EPA expressed concern about the difficulty of obtaining
accurate, quality-assured SO2 emission data from an SO2 CEMS
when natural gas is combusted. (See 60 FR 26561.) The Agency decided
that it was inappropriate to use an SO2 CEMS during hours in which
only natural gas (or gaseous fuel with a sulfur content no greater than
natural gas) is combusted in an affected unit. Therefore, under
Sec. 75.11(e) of the interim final rule, beginning on January 1, 1997,
owners or operators of affected units with SO2 CEMS would no
longer be permitted to use an SO2 CEMS to account for SO2
emissions during gas-fired hours. Instead, SO2 emissions during
gas-fired hours were to be determined in one of two ways: (1) by
certifying and quality-assuring an excepted monitoring system in
accordance with appendix D of part 75; or (2) for pipeline natural gas
combustion, by using the heat input derived from flow monitor and
diluent monitor measurements, in conjunction with the default emission
rate of 0.0006 pounds per million British thermal unit (lb/mmBtu) for
pipeline natural gas, from EPA publication AP-42. (See ``Compilation of
Air Pollutant Emission Factors: Stationary Point and Area Sources,''
volume I, fourth edition, Office of Air Quality Planning and Standards,
September 1985.) Either of these two compliance options requires
additional programming of the DAHS.
The May 17, 1995 interim final rule also amended the quality
assurance provisions of Sec. 75.21 to be consistent with the two
proposed SO2 compliance options for gas-fired hours. Owners or
operators were exempted from daily calibration assessments of the
SO2 monitoring system on any day when only gas was burned in the
affected unit, and from quarterly linearity tests of the SO2
monitoring system in quarters when only gas was fired. Also, ``gas-
only'' quarters were not to be counted toward determination of the next
RATA deadline for the SO2 monitoring system, but a RATA of the
monitoring system was still required at least once every 2 years.
Several commenters objected to the provisions in Sec. 75.11(e) of
the interim final rule, arguing that the requirements were too complex
and costly to implement because of the additional DAHS programming and
did not provide any environmental benefit. (See Docket A-94-16, Items
V-D-01, V-D-02, V-D-07, V-D-09, V-D-13 and V-D-16.) A number of
commenters also indicated that the requirements were especially
burdensome to coal and oil-fired units in which natural gas is burned
only during unit startup. (See Docket A-94-16, Items V-D-01, V-D-02, V-
D-07, V-D-13, V-D-15 and V-D-18).
Several commenters submitted data to demonstrate the ``de minimis''
nature of gas-fired SO2 emissions during unit startups. (See
Docket A-94-16, Items V-D-01, V-D-08 and V-D-16.) One commenter
provided calculations to show that the SO2 concentration during
gas-fired startup events is, typically, 2 ppm or less when pipeline
natural gas is burned. (See Docket A-94-16, Item V-D-08). A second
commenter's data indicate that historically only about 0.20 tons per
year (tpy) of SO2 have been emitted from his four affected coal-
fired units during gas-fired startup events. (See Docket A-94-16, Item
V-D-16). A third commenter used the default emission factor for
SO2 to estimate that about 0.005 tpy of SO2 are emitted from
his affected facility during gas-fired startups. The third commenter
also provided a cost estimate of approximately $10,000 for that same
facility to reprogram the DAHS to comply with the requirements of the
interim final rule. (See Docket A-94-16, Item V-D-01).
Several commenters recommended that, in addition to the two
SO2 compliance options for gas-fired hours presented in the May
17, 1995 interim final rule, EPA should, in the final rule, reinstate
the use of an SO2 monitoring system and a flow monitoring system
as a third compliance option. (See Docket A-94-16, Items V-D-07, V-D-
09, V-D-16 and V-D-17.) One commenter suggested that EPA could place
certain restrictions and conditions on the use of the SO2 monitor
during gas-fired hours, rather than excluding its use. (See Docket A-
94-16, Item V-D-17). Another commenter stated that for gas-firing, EPA
could require the use of a calibration gas with a concentration of 0.0
percent of span for the daily calibration error tests, to verify that
the monitoring system can accurately read SO2 concentrations at or
near zero ppm. (See Docket A-94-16, Item V-D-09). Another commenter,
attempting to address EPA's concern about the ability of an SO2
monitor to accurately read the low SO2 concentrations associated
with natural gas firing, submitted 328 hours of data recorded by his
SO2 monitoring system during gas-fired hours. The data
[[Page 59148]]
appear to substantiate that an SO2 monitor can detect variations
in SO2 concentration, even at very low ppm levels; most of the
measured concentrations were between 1 and 5 ppm, with occasional
readings above 10 ppm. The commenter also compared the SO2
emissions measured by the CEMS in the 328-hour period to the emissions
that would have been reported if the default emission factor for
pipeline natural gas plus the CEMS-based heat input had been used. The
emissions measured by the SO2 monitor were found to be
significantly higher than the emissions predicted by the default
emission factor. (See Docket A-94-16, Item V-D-16). Another commenter
recommended that EPA consider specifying some type of ``default''
SO2 concentration, perhaps based on the maximum sulfur content of
pipeline natural gas, to be used when reporting data from an SO2
CEMS during gas-fired hours. (See Docket A-94-16, Item IV-D-13.) For
example, whenever the CEMS recorded an hourly average below the default
value, the default value would be reported for that hour. Finally, one
commenter requested that EPA add a qualifying statement to the
exemption from the requirement to perform daily calibration error tests
and linearity tests of SO2 monitors during ``gas only'' days and
``gas only'' calendar quarters. The qualifying statement would affirm
that SO2 monitors which ``* * * meet the applicable performance
specification for a daily calibration error test or quarterly linearity
check while firing natural gas only, do not require a subsequent re-
test should the unit change from firing only gaseous fuel to a
nongaseous fuel within the respective daily or quarterly timeframe * *
*'' In other words, the owner or operator may, at his discretion,
continue to perform calibration error tests and linearity tests when
natural gas is combusted, to keep the SO2 monitor ready for use.
The results of such tests would be considered valid. The commenter
recommended that this statement be added to the rule to address two
unanticipated situations that might ``trigger'' the SO2 monitor
quality assurance requirements: (1) when gas is combusted for most of a
day, but peak electrical demand necessitates the co-firing of oil and
gas; and (2) when natural gas is the primary fuel burned during a
quarter, but emergency electrical demand necessitates that some oil be
burned. (See Docket A-94-16, Item V-D-28).
Response: The Agency has reconsidered the provisions of the May 17,
1995 interim final rule in view of the comments received and has
decided to allow three SO2 compliance options, rather than two,
for units with SO2 CEMS during hours in which only natural gas (or
gaseous fuel with a sulfur content no greater than natural gas) is
burned. These options are set forth in Sec. 75.11(e) of today's rule.
The first two compliance options for hours in which the unit
combusts only natural gas or gaseous fuel with a sulfur content no
greater than natural gas are located at Secs. 75.11 (e)(1) and (e)(2).
These provisions have changed very little from Sec. 75.11(e) of the
interim final rule. The owner or operator may account for SO2
emissions, in lieu of using the SO2 CEMS, by either: (1) For
pipeline natural gas, determining the heat input using flow and diluent
monitors, and then using the default SO2 emission rate factor of
0.0006 lb/mmBtu to calculate SO2 mass emissions, in accordance
with Equation F-23 in section 7 of appendix F of part 75; or (2)
certifying an excepted monitoring system in accordance with appendix D
to part 75 and using the fuel sampling and analysis procedures in
section 2.3.1 of appendix D. Section 75.11(e)(2) of today's rule
clarifies that when the appendix D fuel sampling procedures are used,
the unit heat input reported under Sec. 75.54(b)(5) must be based upon
hourly averages from the installed flow and diluent monitors, rather
than basing it on the fuel flow rate and gross calorific value as
specified in section 3 of appendix D and section 5.5 of appendix F.
This ensures consistency in the reported heat input data for all hours
of unit operation; irrespective of the type of fuel combusted in the
unit, the reported heat input values will be based on CEMS data.
The third compliance option, located at Sec. 75.11(e)(3), allows
the owner or operator to use the SO2 monitoring system and a flow
monitoring system to determine SO2 mass emissions. However, the
use of the SO2 monitoring system is subject to several conditions
and restrictions: (a) a calibration gas with a concentration of 0.0
percent of span must be used for daily calibration error tests of the
CEMS; (b) the response of the monitoring system to the 0.0 percent
calibration gas must be adjusted to read exactly 0.0 ppm each time that
a daily calibration error test is passed; (c) any hourly average of
less than 2.0 ppm recorded by the SO2 monitor (including zero and
negative averages) must be reported as a default value of 2.0 ppm; and
(d) if a unit combusts only natural gas (or gaseous fuel with a sulfur
content no greater than natural gas) and never combusts any other type
of fuel, the SO2 monitor span must be set to a value not exceeding
200 ppm. Note that conditions (a) and (b) are optional for units that
combust natural gas only during unit startup. Compliance with
conditions (a) through (d) is required by January 1, 1999. Prior to
January 1, 1999, owners or operators may either continue to use the
SO2 CEMS without the additional restrictions or may opt to comply
voluntarily with conditions (a) through (d). The January 1, 1999
compliance deadline allows owners or operators sufficient time to
incorporate the new requirements into their quality assurance programs
and to program the 2.0 ppm default SO2 concentration into their
DAHS.
The requirement to use a 0.0 percent calibration gas for daily
calibrations and to adjust the response to 0.0 ppm maximizes the chance
of obtaining meaningful SO2 readings at the low concentrations
associated with gas-firing. However, despite this extra quality
assurance provision, it is likely (particularly when pipeline natural
gas is fired) that the CEMS will give some hourly average SO2
concentrations of zero ppm and may give an occasional negative hourly
average, if the monitor readings drift. Therefore, today's rule
requires a 2.0 ppm ``default'' concentration value to be reported
whenever hourly averages from the CEMS fall below 2 ppm. The 2.0 ppm
value is consistent with the average gas-fired SO2 concentration
of 1 to 2 ppm during unit startup, as estimated by one of the
commenters, using the default emission rate of 0.0006 lb/mmBtu for
pipeline natural gas. (See Docket A-94-16, Item V-D-08). Use of the 2.0
ppm default SO2 concentration value minimizes the chance of
underestimating gas-fired SO2 emissions and ensures that a
negative or zero SO2 hourly average will not be reported for any
hour in which fuel is combusted in the unit.
For units that sometimes fire gas and at other times burn higher-
sulfur fuel, Sec. 75.11(e)(3)(iv) of today's rule specifies that dual-
range capability is not required for the SO2 monitoring system;
rather, the SO2 span and range associated with the higher-sulfur
fuel also may be used during gas-fired hours. However, for units that
burn only natural gas (or gaseous fuel with a sulfur content no greater
than natural gas) and do not combust any other fuel,
Sec. 75.11(e)(3)(iv) requires that the owner or operator set the span
of the SO2 monitor to a value not exceeding 200 ppm. This span
requirement supersedes the provisions in section 2.1.1.1 of appendix A,
which would, in this case, require the SO2 monitor span to be set
unrealistically low (e.g., to a value of 5 ppm or less for pipeline
natural gas).
[[Page 59149]]
As explained in the preamble to the interim final rule, EPA has
little or no confidence in the results of RATAs for SO2 monitors
when natural gas is burned in an affected unit. (See 60 FR 26561.)
First, the low SO2 concentrations associated with natural gas
combustion (typically 0.5 to 5.0 ppm for pipeline natural gas) are
either at, near or below the sensitivity limit of the analytical
method, both for the installed SO2 monitor and for the reference
test method (Method 6C in appendix A to 40 CFR part 60). Second,
passing an SO2 RATA when gas is combusted does not necessarily
demonstrate that the monitor is accurate. The criterion in section
3.3.1 of appendix A to part 75 for passing the SO2 RATA (when
emission levels are below 250 ppm) is that the average CEMS and average
reference method values must agree to within 15.0 ppm. To illustrate,
suppose that the average reference method value for a gas-fired RATA of
an SO2 monitor is 10.0 ppm and the average CEMS value is 0.0 ppm.
The RATA would be considered to be ``passed'', according to the 15.0
ppm criterion. However, since the CEMS readings averaged 0.0 ppm, the
monitor could actually have been malfunctioning or completely
inoperative during the RATA test period and still have passed the RATA.
In view of these considerations, Sec. 75.21(a)(5) of today's rule
specifies that for units with installed SO2 monitoring systems,
SO2 RATAs are not to be done when natural gas (or gaseous fuel
with a sulfur content no greater than natural gas) is fired; rather,
SO2 RATAs are to be conducted only when higher-sulfur fuels (e.g.,
oil or coal) are combusted. In keeping with this requirement,
Sec. 75.21(a)(6) of today's rule exempts from the SO2 RATA
requirements of part 75 any unit that burns only natural gas (or
fuel(s) with a sulfur content no greater than natural gas), and does
not burn any other fuel. For such units, only daily calibrations and
quarterly linearity tests of the SO2 monitor, which ensure that
the monitor is operational by checking its response to different
concentrations of calibration gas, are required. Section 75.21(a)(7) of
today's rule specifies that for a unit that sometimes burns natural gas
as a primary or backup fuel and at other times burns higher-sulfur fuel
as primary or backup fuel, any calendar quarter in which the unit
combusts only natural gas (or fuel with a sulfur content equivalent to
natural gas) is to be excluded in determining the deadline for the next
RATA of the SO2 monitoring system. This provision of
Sec. 75.21(a)(7) is not substantively different from the corresponding
provision in Sec. 75.21(f) of the interim final rule; however, as
revised, Sec. 75.21(a)(7) extends the benefit of reduced RATA frequency
requirements to include the combustion of other types of fuels (whether
gaseous and non-gaseous) with a sulfur content no greater than that of
natural gas. Finally, Sec. 75.21(a)(7) specifies that if, as a result
of extending the RATA deadline of an SO2 monitor by excluding
quarters in which only natural gas (or equivalent) is combusted, eight
calendar quarters elapse after a RATA without a subsequent RATA of the
SO2 monitor having been performed, a RATA is then required in the
next calendar quarter in which a fuel with a higher sulfur content than
natural gas is combusted in the unit. This differs slightly from the
provision in Sec. 75.21(f) of the interim final rule, which, in similar
circumstances, required an SO2 RATA at least once every 2 calendar
years. These less burdensome RATA requirements for SO2 monitors in
Secs. 75.21(a)(5) through (a)(7) will ensure that owners or operators
do not have to burn higher sulfur fuels merely to perform quality
assurance testing of the CEMS. The Agency believes that the less
stringent RATA requirements will also encourage owners and operators to
burn more low-sulfur fuels in their affected units, thus resulting in a
net environmental benefit while ensuring continued high quality of
emissions data.
If, for a particular unit with an SO2 CEMS, the owner or
operator selects one of the other two SO2 compliance options for
gas-fired hours, in lieu of using the SO2 monitoring system (i.e.,
either using appendix D fuel flow meter and fuel sampling procedures or
using the default emission factor for pipeline natural gas and Equation
F-23 in appendix F), Sec. 75.21(a)(4) of today's rule specifies that no
daily calibration error tests of the SO2 monitoring system are
required on ``gas-only'' operating days and no quarterly linearity
tests are required in ``gas-only'' operating quarters. While these
tests are not required, they are allowed and will be considered valid
tests for other requirements of this rule. These quality assurance
requirements are waived on days and in quarters when only gas is
combusted in the unit, because when the appendix D compliance option or
the Equation F-23 compliance option is used, hourly averages from the
SO2 CEMS are not included in the historical CEMS data stream,
either for emission reporting, missing data substitutions, or monitor
availability calculations. Therefore, the hourly averages from the
SO2 monitor do not require quality assurance on ``gas-only'' days
or in ``gas-only'' quarters. These requirements are essentially
identical to the corresponding provisions in Sec. 75.21(f) of the
interim final rule. The Agency notes, however, that although the daily
and quarterly assessments of the SO2 CEMS are not required in
these instances, Sec. 75.21(a)(4) of today's rule allows the tests to
continue to be done at the discretion of the owner or operator. If the
tests are passed, they are considered to be valid tests of the CEMS. If
a test is failed, the CEMS is considered out-of-control until a
subsequent test of the same type has been passed. This provision
addresses the commenter's concern about the unpredictability of the
fuel type(s) that are used during periods of peak electrical demand.
2. SO2 Concentration Missing Data During Gas Combustion
Background: For an affected unit that sometimes combusts natural
gas (or gaseous fuel with a sulfur content no higher than natural gas)
and sometimes burns higher sulfur fuel, such as coal or oil, the
SO2 emissions during gas-fired hours are several orders of
magnitude smaller than during hours in which coal or oil is combusted.
When such a unit uses an SO2 monitor to account for its SO2
emissions, then, for each clock hour in which the monitor fails to
provide quality-assured SO2 concentration data, a substitute data
value for SO2 concentration must be reported to EPA, in accordance
with the standard missing data procedures of Sec. 75.33. The method
required for calculating the substitute data under Sec. 75.33 depends
on several factors, such as the overall monitor availability and the
duration of the monitor outage. In many cases, the substitute data
value, which is reported for each clock hour of the missing data
period, is the arithmetic average of the SO2 readings before and
after the missing data period. In other cases, the substitute data
value may be either the 90th (or 95th) percentile value from the last
720 quality-assured monitor operating hours or simply the maximum value
recorded in the last 720 quality-assured monitor operating hours.
Provided that the sulfur content of the fuel burned in an affected
unit remains relatively constant, the standard missing data procedures
will generally provide representative substitute data. However, when a
unit burns two or more fuels whose sulfur contents differ greatly
(e.g., coal and natural gas), using the standard missing data
procedures can sometimes cause significant underestimation, and at
other times,
[[Page 59150]]
significant overestimation of the SO2 emissions during missing
data periods. This is most likely to occur when an SO2 missing
data period either coincides with or occurs around the time of a fuel-
switch.
Issues: In the May 17, 1995 interim final rule, EPA revised the
standard SO2 missing data procedures and the SO2 data
availability calculation procedures, to address the issue of units that
have SO2 monitors and sometimes burn natural gas and at other
times combust higher-sulfur fuels. Under Sec. 75.11(e) of the interim
final rule, beginning on January 1, 1997, owners or operators would no
longer be permitted to use an SO2 CEMS to account for SO2
mass emissions during hours in which only natural gas (or gaseous fuel
with a sulfur content no greater than natural gas) is burned in an
affected unit. Therefore, Sec. 75.30(d)(3) specified that the
historical CEM data used to derive the SO2 substitute data values
for the standard missing data procedures would consist only of SO2
concentrations measured by the CEMS during the combustion of higher-
sulfur fuels such as coal or oil. Also, Sec. 75.32(a)(4) specified that
the percent SO2 data availability would be calculated only from
the hours in which the higher-sulfur fuels were burned. Section
75.21(f) specified that during natural gas-fired hours, the owner or
operator would neither be required to operate nor to quality-assure
data from the SO2 CEMS. Rather, during all gas-fired hours,
Sec. 75.11(e) specified that SO2 emissions would be accounted for
in one of two ways: (1) By using an excepted monitoring system, in
accordance with the requirements of appendix D to part 75; or (2) for
pipeline natural gas combustion, by determining the heat input from a
flow monitor and diluent monitor and then using the default SO2
emission rate of 0.0006 lb/mmBtu for pipeline natural gas to calculate
the SO2 mass emission rate, in accordance with Equation F-23 in
appendix F. Sections 75.30 (d)(1) and (d)(2) of the interim final rule
specified that missing data for option (1) would be filled in using the
missing data procedures in appendix D to part 75; for option (2), the
procedures in Sec. 75.36 for missing heat input data would be followed.
Several commenters objected to these provisions of the interim
final rule, stating that EPA should not prohibit the use of an SO2
monitor during natural gas-fired hours, but should allow the CEMS to be
used as a third compliance option. (See Docket A-94-16, Items V-D-07,
V-D-09, V-D-16 and V-D-17.) Two other commenters stated that use of the
standard SO2 missing data procedures and SO2 data
availability calculation procedures should be allowed, without
modification, particularly for units that burn natural gas only during
unit startup. (See Docket A-94-16, Items V-D-07 and V-D-15.)
Response: As discussed above, for hours in which only natural gas
(or gaseous fuel with a sulfur content no greater than natural gas) is
combusted, EPA has decided to revise Sec. 75.11(e) to allow units that
have SO2 monitoring systems and sometimes burn natural gas and at
other times burn higher-sulfur fuels to use the SO2 CEMS (subject
to certain conditions and restrictions) as a third compliance option,
in addition to the two compliance options presented in the interim
final rule.
Today's rule, at Sec. 75.30(d)(4), allows an owner or operator who,
pursuant to Sec. 75.11(e)(3), selects the SO2 monitoring system as
the compliance option for gas-fired hours to use both the standard
SO2 missing data procedures and the SO2 data availability
calculation procedures, without modification. This is conditioned on
the owner or operator keeping records on-site, suitable for inspection,
indicating the type of fuel burned during each SO2 missing data
period and the number of hours during the missing data period that each
type of fuel was burned. This recordkeeping requirement, located at
Sec. 75.55(e)(2) of today's rule, does not apply if natural gas (or
gaseous fuel with a sulfur content no greater than natural gas) is the
only type of fuel burned in the unit, or if such fuel is burned only
during unit startup.
For several reasons, the Agency believes that allowing units which
combust both high and low-sulfur fuels to use the standard missing data
procedures will probably not, over time, result in any significant
underestimation of SO2 emissions. First, if a unit maintains high
SO2 data availability (90 to 95 percent), then only a few percent
of the SO2 readings in the data stream will be substitute data
values. Second, many missing data periods will not occur at or near the
time of a fuel switch, and for those missing data periods, the
substitute data values will be representative of the fuel burned.
Third, over long periods of time, it is likely that, statistically, the
effects of occasionally underestimating and overestimating SO2
substitute data values will tend to balance out. Nevertheless, to
ensure that these things are true, the recordkeeping requirement in
Sec. 75.55(e)(2) has been added. This will allow EPA, State, and local
government auditors to assess, over time, the appropriateness of the
SO2 substitute data values that are used to fill in missing data
periods for units that burn both high and low-sulfur fuels,
particularly when fuel-switching occurs. Based on this assessment, EPA
may revisit this issue in a future rulemaking, if necessary.
Regarding the calculation of percent SO2 data availability,
Sec. 75.11(e)(3)(iii) of today's rule specifies that when an SO2
monitor is used to account for SO2 emissions during gas-fired
hours, all valid hourly averages from the CEMS are counted as quality-
assured data. This includes clock hours in which the default value of
2.0 ppm has been substituted because the hourly averages from the CEMS
fall below 2.0 ppm, provided that the monitor is operating and is not
out-of-control with respect to any of its required quality assurance
tests (i.e., daily calibration, linearity and RATA).
If, for a particular unit with an SO2 CEMS, the owner or
operator selects one of the other two SO2 compliance options for
gas-fired hours, in lieu of using the SO2 monitor (i.e., either
using the default emission factor for pipeline natural gas or using
appendix D procedures, in accordance with Sec. 75.11 (e)(1) or (e)(2),
respectively), Sec. 75.30(d) of today's rule specifies that CEMS
readings obtained during gas-fired hours are to be excluded from the
historical CEMS data banks, for purposes of providing substitute data.
In addition, today's rule amends Sec. 75.32(a)(3) to state that gas-
fired hours are to be excluded from the calculation of percent SO2
data availability for the CEMS when the SO2 compliance option in
Sec. 75.11 (e)(1) or (e)(2) is selected. These provisions are not
substantially different from the provisions in Sec. 75.30(d) and
Sec. 75.32(a)(4), respectively, of the interim final rule.
C. Clarifying the Procedures for Performing Cycle Time Tests
Background: The cycle time test is a certification test that
measures the amount of time it takes for a CEMS to respond to step
changes in concentration. The original cycle time test in section 6.4
of appendix A in the January 11, 1993 final rule measured the length of
time necessary for a monitor to achieve 95 percent of the step change
in pollutant concentration between stack emissions and a calibration
gas, beginning when the calibration gas is released from the cylinder.
The May 17, 1995 interim final rule changed the procedures for
conducting a cycle time test to eliminate the time it takes the
calibration gas to travel from the cylinder to the probe tip of the
CEMS. This time period was eliminated in
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order to achieve more representative cycle time test results. (See 60
FR 26565.)
In the original January 11, 1993 rule, the purpose of the cycle
time test was to measure the amount of time it takes for a monitor to
achieve 95 percent of the step change in concentration going from
measured stack emissions to a high-level or low-level calibration gas.
The cycle time test procedure in the interim final rule was reversed in
that it measures the amount of time it takes the monitor to achieve 95
percent of the step change in concentration when going from a high-
level calibration gas (downscale test) or low-level calibration gas
(upscale test) to a stable measured emissions reading.
In order to implement the revised requirements, section 6.4 of
appendix A in the interim final rule specified that the cycle time test
procedures be performed and evaluated as follows:
1. Inject a high scale or low scale calibration gas into the probe
tip of the monitoring system until a stable response is achieved.
2. After a stable response is achieved, stop the calibration gas
flow and record the time.
3. Allow the monitor to stabilize while reading the stack
emissions. (The monitor is determined to be stable when either the
measured reading deviates less than 1 percent of span for 30 seconds or
if the measured concentration reading deviates less than 5 percent of
the measured average concentration for a 5 minute interval.)
4. Calculate 95 percent of the step change in concentration and
determine the time at which 95 percent of the step change is achieved.
5. Repeat the procedure with the other calibration gas.
6. The response time must be achieved in under 15 minutes for both
the downscale and upscale tests.
7. The longest 95 percent step change time from either the low
scale or high scale test is the component's cycle time.
8. For the NOX-diluent CEMS and SO2-diluent CEMS test,
record and report the longer cycle time of the two component analyzers
as the system cycle time.
9. For time shared systems, this procedure must be done for all
probe locations that will be polled within the same 15-minute period
during monitoring system operations.
10. For monitors with dual ranges, perform the test on the range
giving the longest cycle time.
Issue: In response to the cycle time test procedures established in
the interim final rule, the Agency received significant comments. One
commenter noted that the stabilization criteria cited in the May 17,
1995 interim final rule do not allow monitoring systems that record
data in 1-minute or 3-minute intervals sufficient time to record data
to document a stable concentration reading. (See Docket A-94-16, Item
V-D-18.) The commenter also recommended that the procedures for
calculating 95 percent of the step change in concentration be
clarified. EPA also received comments concerning the order in which
calibration gases are introduced during the cycle time test. Some
commenters were satisfied with the test in the interim final rule which
requires the source to initiate the cycle time test by injecting a zero
level or high level calibration gas and then allowing the monitor to
stabilize while reading stack emissions. (See Docket A-94-16 Item V-D-
02). Other commenters stated that the cycle time test in the interim
rule is problematic because the stable ending value is difficult to
determine. (See Docket A-94-16 Item V-D-12).
Response: In response to the comments received, today's rule
revises the criteria used to determine when the stack emissions have
stabilized after a downscale or upscale test, in order to accommodate
monitoring systems that record concentration data in 1-minute or 3-
minute intervals. (See Docket A-94-16, Item V-D-18.) The EPA concurs
that monitoring systems that store data in 1-minute or 3-minute
intervals cannot record a sufficient number of data points to meet the
stabilization criteria cited in section 6.4 of appendix A in the May
17, 1995 interim final rule. Therefore, in today's rule concentration
data readings are considered to be stable after a downscale or upscale
test if the analyzer reading deviates by less than 2 percent of the
analyzer's span value for a minimum of 2 minutes or if the analyzer's
measured concentration reading deviates less than 6 percent from the
average measured concentration for 6 minutes. Owners and operators of
CEMS that do not record concentrations in 1-minute or 3-minute
intervals may petition the Administrator under Sec. 75.66 for
permission to use alternative cycle time test stabilization criteria.
Today's rule adds a diagram and narrative explanation of the cycle time
test procedure to section 6.4 of appendix A to provide additional
guidance on how to calculate 95 percent of the step change in
concentration and how to calculate the cycle time. EPA concurs with the
commenters who stated that the cycle time test in today's rule does not
present a burden to the source. The Agency maintains that the cycle
time test in today's rule will provide more representative cycle
response time; therefore, EPA has not changed the order in which the
calibration gases are injected into the probe during a cycle time test.
D. Revising the Reporting of Scrubber Parameters and Missing Data for
Add-On Emission Controls
Background: Section 75.34(a)(1) of the January 11, 1993 rule
allowed the owner or operator of a unit with add-on emission controls
to use standard missing data procedures in Secs. 75.31 and 75.33 when
outlet SO2 or NOX CEMS are out of service and the parametric
data shows that the add-on emission controls for the unit are operating
properly. The May 17, 1995 interim final rule amended this section by
requiring the owner or operator of a unit that uses the standard
missing data procedures to demonstrate that the emission control device
operating parameters were maintained within certain ranges indicative
of normal, stable control device operation. In addition, the designated
representative must certify proper operation of the add-on emission
controls during missing data periods. Section 75.34 (a)(1) of the
interim final rule required the parameter ranges to be part of the
monitoring plan for the unit (60 FR 26562; May 17, 1995).
Issue: One commenter expressed the concern that if operating
parameter ranges are required to be included in the part 75 monitoring
plan, title V permitting authorities might include the operating
parameters in the title V operating permit. (See Docket A-94-16, Item
V-D-13.) This could result in the normal operating parameter ranges
becoming permit conditions, the violation of which could result in an
enforcement action.
Response: In order to assure that emissions are not underestimated,
and to allow the use of standard missing data procedures, it is
essential to verify proper operation of the add-on emission controls
during missing data periods. Therefore, today's rule maintains the
requirement to establish operating parameter ranges representative of
periods of proper operation of the add-on emission controls. The EPA
notes that the determination of whether parameters should be referenced
in a title V operating permit is up to the permitting authority under
title V, which will generally be a State or local agency. Since, for
purposes of the Acid Rain Program, this information will most likely be
used in field audits, EPA believes that it is reasonable to keep this
information on-site in the QA/QC plan
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rather than including it in the part 75 monitoring plan to be submitted
to EPA and the State. In addition, by no longer requiring the
information in the monitoring plan that is sent to EPA, this approach
reduces the burden on utilities. Therefore, today's rule requires that
the parameter ranges be kept on-site as a part of the QA/QC program
required in section 1 of appendix B of part 75. This information must
be available to EPA and to State and local agencies upon request or
during a field audit.
Issue: A comment was received on Sec. 75.34(d). The commenter
stated that the requirement for parametric monitoring will
unnecessarily increase the owner or operator's administrative costs and
workload. (See Docket A-94-16, Items V-D-13 and V-D-07.) The commenter
stated that obtaining the data will increase data collection and
paperwork for data storage since some affected units do not have
continuous electronic data collection for many of the add-on emission
control operating parameters.
Response: The EPA believes that verification of proper operation of
add-on emission controls generally requires monitoring and recording of
various operating parameters. The January 11, 1993 final rule and the
May 17, 1995 interim final rule required that the data be recorded on a
continuous basis. The January 11, 1993 final rule and the May 17, 1995
interim final rule also required utilities to keep records of the
parametric data corresponding to missing data periods for a period of
three years. Since this requirement did not change from the original
January 11, 1993 final rule, this is not an increased recordkeeping
burden. The EPA does recognize the recordkeeping burden imposed on the
source when the data is required to be recorded and reported on a
continuous basis, but believes this is reasonable in light of the
importance of having an objective basis for determining whether the
add-on controls are operating properly.
In today's rule, the add-on control parameter recordkeeping
provisions are as follows. As in the January 11, 1993 final rule, if an
owner or operator wants to use the standard missing data procedures, he
must record and keep the parametric monitoring data for each missing
data period. This data, which must be in an accessible form and kept
for three years from the creation of the record, must show that the
controls are operating within the parameter ranges. In addition, the
designated representative must certify that the add-on controls were
operating properly.
The EPA notes that the final rule preserves the following
alternative provisions: (1) Using maximum potential concentration or
maximum inlet readings from the previous 720 hours of quality-assured
data during missing data periods; or (2) using backup CEMS to reduce
the number of missing data periods. Either of these approaches will
reduce the recordkeeping burden associated with maintaining parametric
data for each hour of missing CEMS data.
E. Clarifying the Procedures Dealing With the Use of Reference Method 9
Instead of Continuous Opacity Monitors on Bypass Stacks
Background: This issue concerns whether Method 9 in appendix A of
part 60 can be used for monitoring opacity on a bypass stack. Section
75.18(3)(b) of the January 11, 1993 final rule required an owner or
operator to install and operate a COMS on a bypass stack. The May 17,
1995 direct final rule relaxed this requirement by allowing the use of
Method 9 on bypass stacks. The EPA received a significant adverse
comment on Sec. 75.18(b)(3); therefore, this section of the rule was
withdrawn as required. Today's rule reinstates Sec. 75.18(b)(3).
Issue: The EPA received significant adverse comments on
Sec. 75.18(b)(3) of the direct final rule. (See Docket A-94-16, Item V-
D-18.) The EPA also received a comment in support of using Method 9
instead of a COMS on bypass stacks. (See Docket A-94-16, Item V-D-21.)
One commenter expressed concern that Method 9 is not equivalent to
installing a COMS and suggested that Sec. 75.18(b)(3) be removed. The
commenter noted that EPA has not specified how often Method 9 has to be
performed and suggests Sec. 75.18(b)(3) be revised to require
continuous or subsequent visual opacity readings. The commenter also
noted that Method 9 cannot be used at night or during inclement weather
and that EPA does not address what an owner or operator should do
during these times. The commenter suggested that EPA should not allow
the owner or operator to have emissions pass through the bypass stack
during periods when Method 9 cannot be performed.
Response: The EPA agrees with the commenter that Method 9 is as
effective as continuous opacity monitoring. However, Method 9 tends to
yield a positive observation error and therefore would not result in
underestimation of opacity when taken. Since bypass stacks operate
infrequently, and generally only in emergency situations, it is an
unnecessary economic burden for the sources to install and maintain a
COMS. For the purpose of the Acid Rain Program, opacity is not required
for all hours of operation. Thus, there are no missing data procedures
for COMS and Method 9 is an acceptable method of monitoring opacity for
bypass stacks which are seldom used. Therefore, EPA has concluded that
the utility should have the flexibility allowed under Sec. 75.18(b)(3).
Today's rule reinstates the provision allowing Method 9 to be used to
monitor opacity on a bypass stack whenever emissions pass though the
bypass stack. Section 75.18(b)(3) of today's rule specifies that the
utility must conduct Method 9 in accordance with applicable State
regulations for visual observations of opacity. This would include
State requirements for the frequency of performing Method 9 and for
procedures to follow when it is not possible to perform Method 9. EPA
expects to target for audit units that use the bypass stacks for
greater than 5% of the time. If the agency finds a pattern of excessive
use of the bypass stacks, EPA may revisit the issue of allowing Method
9 for bypass stacks. States have the authority to require COMS.
F. Addressing Minor Comments on the Direct Final Rule
The EPA received a number of minor comments on the May 17, 1995
direct final rule. In some cases, the commenters asked for
clarification of provisions or terms used in the direct final rule. In
other cases, commenters requested that EPA take policies from the
``Acid Rain CEM (Part 75) Policy Manual'' (Docket A-94-16, Items II-D-
54 and V-A-1) related to provisions in the direct final rule and
incorporate these policies into part 75. These provisions include:
allowing the use of ``AGA Report No. 7'' for calibration of turbine
fuel flowmeters; clarifying reporting provisions for a common stack
monitoring situation where emissions may be subtracted; and specifying
means for apportioning heat input from a common stack to its
constituent units. In addition, a commenter pointed out a case where
the direct final rule's requirements for recertification of COMS might
be more extensive than necessary.
1. Use of AGA Report No. 7
Background: Appendices D and E of part 75 allow the use of fuel
flowmeters, in addition to other data such as sulfur content or gross
calorific value of fuel samples or stack testing data, to determine
SO2 mass emissions, NOX emission rate, and heat input from
certain gas-fired and oil-fired units instead of requiring monitoring
with CEMS. Utilities choosing to use fuel flowmeter monitoring systems
instead of CEMS must demonstrate that the fuel
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flowmeters can accurately measure fuel flow rate. This requires an
initial calibration and periodic (annual) quality assurance testing.
In general, EPA accepts industry standards for calibration of fuel
flowmeters, such as those from the AGA or the American Society of
Mechanical Engineers (ASME). Because these industry standards for fuel
flowmeters are used to transfer fuel for sale, the standards are
written to provide for the accurate calibration and measurement of fuel
flow. The EPA considers this level of accuracy sufficient for the Acid
Rain Program.
Issue: The AGA requested that EPA allow the use of ``AGA Report No.
7'' for calibration of turbine flowmeters for use in appendices D and E
of part 75. (See Docket A-94-16, Item V-D-5.)
Response: The EPA had previously approved use of ``AGA Report No.
7'' as an alternative to the prescribed ASME calibration methods
through a petition from a utility under Sec. 75.66. Then, the Agency
announced that this was an acceptable method for calibration in
Question 10.12 in Update 6 of the ``Acid Rain CEM (Part 75) Policy
Manual''. (See Docket A-94-16, Item V-A-1.) Consequently, EPA agrees
with the commenter and today's rule incorporates this method by
reference in Sec. 75.6 for use in Sec. 75.20(g) and appendix D of part
75. The Agency notes that the specific section for calibration
requirements is section 8 of ``AGA Report No. 7''.
2. Provisions for Reporting and Monitoring of Subtracted Emissions at a
Common Stack
Background: Section 75.16 contains provisions for the monitoring of
SO2 mass emissions and heat input in cases where more than one
unit uses the same stack. This is referred to as a ``common stack''.
The EPA revised these provisions in the May 17, 1995 direct final rule
to allow more options for monitoring in this type of situation. (See
section C(4)(a) of the ``Technical Support Document'', Docket A-94-16,
Item II-F-2.) The options of Secs. 75.16(a)(2)(ii)(B) and (a)(2)(ii)(C)
allow the owner or operator to install SO2 and flow monitoring
systems at the common stack and at some of the individual units using
the common stack to monitor SO2 mass emissions at each location.
The owner or operator would then calculate the SO2 mass emissions
from the remaining units by subtracting the SO2 mass emissions
measured at the individual units from the SO2 mass emissions
measured at the common stack. For example, if a Phase II unit and a
Phase I unit share a common stack, the utility could monitor SO2
mass emissions from flow and SO2 monitoring systems at the common
stack, monitor SO2 mass emissions from flow and SO2
monitoring systems in the ducts from the Phase I unit, and then
subtract the SO2 mass emissions of the Phase I unit from the
common stack SO2 mass emissions to determine the mass emissions
from the Phase II unit.
Issue: One commenter mentioned a potential problem with the options
of Secs. 75.16(a)(2)(ii)(B) and (a)(2)(ii)(C). The commenter was
familiar with such installations and mentioned that this method may
sometimes produce a negative value for SO2 emissions or heat input
if the SO2 or flow monitoring system in the duct has a bias
adjustment factor. (See Docket A-94-16, Item V-D-18.) The commenter
recommended that EPA clarify in Secs. 75.16(a)(2)(ii)(B) and
(a)(2)(ii)(C) that negative emission and heat input values be set to
zero in this case.
Response: The EPA agrees with the commenter and has clarified these
provisions in today's action. Negative emission values do not exist in
reality and reporting negative SO2 mass emission values makes no
sense. Therefore, the revised provision indicates that SO2 mass
emission values shall not be reported as a value less than zero. This
is also similar to provisions in the ``CEMS Submission Instructions''
(Docket A-94-16, Item II-D-99), which require utilities to adjust
negative concentration, flow, heat input or emission values to a value
of zero (0). In addition, today's rule makes the same revision to the
parallel provision in Sec. 75.16(b)(2)(ii)(B), for a situation where
affected Phase II units share a common stack with one or more non-
affected units, and SO2 mass emissions from the non-affected units
are subtracted from SO2 mass emissions on the common stack.
3. Heat Input Apportionment at Common Stacks
Background: Another issue related to common stacks concerns heat
input. Heat input can be determined using a flow monitor and a CO2
or O2 diluent monitor. In order to determine if a utility system
(or dispatch system) has underutilization during Phase I under part 72
(Secs. 72.91 and 72.92, in particular), and if so, how many allowances
should be surrendered, it is necessary to have heat input on an
individual unit basis. Individual unit heat input is still necessary,
even in the case where units share a common stack and heat input is
measured by monitors on the common stack. In Sec. 75.16(e) of the May
17, 1995 direct final rule, EPA clarified this requirement. (See
section C(4)(a) of the ``Technical Support Document,'' Docket A-94-16,
Item II-F-2.) In Question 17.5 of the ``Acid Rain CEM (Part 75) Policy
Manual,'' EPA approved two methods for apportioning heat input to
individual units that feed into a common stack, where all units combust
the same type of fuel. (See Docket A-94-16, Item IV-D-54.) These
methods apportion total heat input measured at the common stack by
using the ratio of the individual unit usage to the usage of all the
units using the common stack. For most plants, the measure of unit
usage is electrical generation in megawatts (MWe), and for other
plants, the measure of unit usage for the apportionment is the flow of
steam associated with each unit.
Issue: A commenter requested that EPA incorporate these
apportionment methods into part 75. (See Docket A-94-16, Item V-D-18.)
Response: The EPA agrees with the commenter and today's rule has
incorporated this heat input apportionment methodology in
Sec. 75.16(e)(5). The Agency has already accepted this apportionment
method through policy as sufficiently accurate for heat input, provided
that all units use the same kind of fuel. Because different fuels have
different combustion characteristics and their emission calculation
formulas will use a different combustion ratio, called the ``F-
factor,'' this heat input apportionment methodology is not appropriate
if different fuels with a different F-factor are used. Incorporating
the heat input apportionment provision allows utilities to implement
this apportionment without going through a formal petition approval
process. An apportionment methodology based upon the ratio of
electrical generation or steam flow is already incorporated in part 75
for fuel flow measured by flowmeters on common pipes in section 2.1.2.2
of appendix D. For these reasons, EPA is incorporating the heat input
methodology in Sec. 75.16(e)(5).
4. Recertification of Opacity Monitoring Systems
Background: Section 75.20(b) contains requirements for
recertification of CEMS and COMS. This paragraph requires
recertification whenever a significant change is made to a monitoring
system or to the conditions under which it is monitoring that will
affect the ability of the monitoring system to accurately measure,
record and report emissions or opacity. An example of a significant
change to a monitoring system's conditions for monitoring is if the
ductwork to a stack
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is modified so that a new unit emits through the stack, in addition to
the existing units. In this case, the change to the flue gas handling
system could significantly change the flow and concentration profiles
in the stack, thus affecting the ability of the monitor to measure,
record and report emissions.
In general, the Acid Rain Program is designed to be as consistent
as possible with State requirements for monitoring opacity. Although
section 412 of the Act requires installation of opacity monitors for
all affected units, the Act does not provide for a standard or
limitation on opacity for the Acid Rain Program. In order to make use
of opacity monitoring data from affected units, part 75 requires that
opacity data be reported to State agencies in the format specified by
the State. In addition, if a State agency certifies an opacity
monitoring system to the requirements of Performance Specification 1 in
appendix B of part 60, that certification also applies to the Acid Rain
Program.
Issue: A commenter also noted that Sec. 75.20(b) of the May 17,
1995 direct final rule requires recertification of a COMS due to
changes in unit operation. The commenter suggested that the results of
the certification tests for opacity monitoring systems are not
significantly affected by changes in pollutant emission levels, and
therefore, the requirement for recertification upon a change in unit
opacity should be deleted.
Response: The EPA agrees with the commenter that changes in
emissions, such as from a fuel change, do not significantly affect, and
so should not require recertification, of the opacity monitoring
system. Today's rule removes this requirement from Sec. 75.20(b).
For similar reasons, EPA is also removing the requirement for
recertification of opacity monitoring systems due to modifications in
the flue gas handling system, except for those modifications to
ductwork that change the path length of the opacity monitoring system.
After further consideration of opacity recertification requirements,
the Agency has determined that only these modifications would
significantly affect the opacity monitoring system's ability to
monitor, record and report opacity. The EPA notes that a utility must
still meet any State requirements for recertification of an opacity
monitoring system.
G. Addressing Comments on RATA Notifications
Background: The May 17, 1995 direct final rule included provisions
requiring notification of the date on which periodic Relative Accuracy
Test Audits (RATAs) will be performed in Secs. 75.21(d) and
75.61(a)(5). The direct final provisions require submission of written
notification to the Administrator, the appropriate EPA Regional Office,
and the applicable State or local air pollution control agency at least
21 days before the scheduled date of a RATA. The date may be
rescheduled if written or oral notice is provided to EPA and to the
appropriate State or local air quality agency at least seven days
before the earlier of the original scheduled date or the new test date.
The Texas Subgroup commented adversely upon the requirements in
Secs. 75.21(d) and 75.51(a)(5) for notifications of the date on which
periodic RATAs will be performed. These provisions were removed from
part 75 in a May 22, 1996 amendment to part 75 (60 FR 25580-25585). As
part of the document in the Federal Register, EPA took public comment
for an additional 15 days.
Public comment focused upon five main issues related to the
notifications for periodic RATAs: need for the notification provision;
the agencies or offices to which a notification should be sent; whether
agencies or offices could grant a waiver from the testing notification;
how the time periods for notification could be changed to allow greater
flexibility to utilities; and the means by which or form in which a
notification could be transmitted to an agency. Comments were received
from three utility commentors and from four State or local air
pollution agencies (See Docket A-94-16 Items V-D-25 through V-D-27 and
V-D-29 through V-D-32).
Issue: One of the utility commentors felt that the RATA
notification provision was not that critical. This utility commentor
expressed concern over lack of flexibility (See Docket A-94-16 Item V-
D-26). The State and local agencies all supported having a RATA
notification (See Docket A-94-16 Items V-D-29 through V-D-32).
Response: As stated in the Federal Register (60 FR 25581), EPA
believes it is critical for EPA, State, and local agency personnel to
be able to observe periodic RATAs in order to ensure the quality of
monitored data for the Acid Rain Program. In addition, the EPA believes
that advance notification of the date of periodic RATA testing allows
the cost-effective use of agency resources by coordinating auditing of
monitor performance with regularly scheduled quality assurance testing
and by coordinating field observations at multiple locations. Thus, EPA
is reinstating the requirements for notification of the date of
periodic RATA testing.
Issue: Two related issues concerned to which agencies notifications
should be sent, and whether agencies or offices could grant a waiver
from the testing notification. In the Federal Register document
requesting comment on the periodic RATA notification, EPA specifically
requested comment on removing the requirement that notifications be
provided to the Administrator (received by EPA's Acid Rain Division)
and allowing a State or local air pollution control agency or EPA
regional office to waive the notification requirement. One utility
commentor felt that the RATA notification might be necessary for its
State agency, but not for the Federal EPA (See Docket A-94-16 Item V-D-
25). One State agency supported the idea of allowing a region to
determine to which agency should be notified (See Docket A-94-16 Item
V-D-29). A utility supported allowing a State or local agency or EPA
regional office to issue a waiver (See Docket A-94-16 Item V-D-27).
Response: EPA considered the comment requesting that notifications
go only to State agencies. However, some EPA Regional offices are
active in observing RATA testing. Therefore, EPA is retaining the
requirement to send notifications of periodic RATA testing to EPA.
Based upon the public comments, EPA is creating a provision that
would allow a state or local agency, an EPA regional office, or the
Administrator's delegatee (EPA's Acid Rain Division) to waive the
requirement for periodic RATA notification for a unit or a group of
units. In general, a state or local agency could waive the requirement
for notification to its own office, but could not waive the requirement
for notification to the EPA. Similarly, an EPA Regional office could
waive the requirement for notification to its office, but could not
waive the requirement for notification to a State or local agency or to
the Administrator's delegatee. The waiver should specify the units for
which the periodic RATA notification requirement is waived and the test
or period of time for which the periodic RATA notification requirement
is waived. For example, a regional EPA office might send a letter to
the designated representatives of several utilities specifying that the
designated representative or owner or operator would not be required to
submit notice until and unless the regional office sends another letter
specifying that notification is requested. A State agency
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might grant a waiver from the testing requirement for one particular
unit in that state for its RATA testing in the first quarter of 1997.
EPA's Acid Rain Division could issue a policy statement through the
Acid Rain Program Policy Manual if it wanted to waive the requirement
for notification to the Administrator indefinitely.
Today's rule also specifies that a state agency or EPA may
discontinue the waiver from the periodic RATA notification. However,
the periodic RATA notification requirement would only resume for any
future testing; a utility would never retroactively be required to
provide notification. The state agency or EPA would need to send
another written statement specifying for which units or groups of units
the waiver no longer applies. Thus, if an agency's priorities for
observing testing change over time, the agency would be able to grant
case-by-case waivers, grant long-term waivers or discontinue long-term
waivers to be consistent with those new priorities for observing. EPA
believes that allowing this flexibility will encourage States and
regional EPA offices to issue waivers in cases where they are certain
they will not be observing tests for a unit or group of units for a
year or more.
Issue: An issue of great concern to commentors was revising the
time limits for notification to allow greater flexibility. One utility
commentor felt that putting any time limit for providing notification
was problematic, since a utility could be in violation of that time
limit. This commentor suggested that if notification were necessary at
all, the notification should be a general schedule of testing provided
ahead of time (See Docket A-94-16 Item V-D-26). Another utility
commenter expressed concern that the requirement for 21 days advance
notification under the Acid Rain Program is different from their State
agency requirement for a 30-day notification, and that coordinating the
different requirements is difficult (See Docket A-94-16 Item V-D-25).
State agencies supported having an initial notification requirement of
21 days (See Docket A-94-16 Items V-D-29, V-D-30, V-D-32) or 30 days
(See Docket A-94-16 Item V-D-31). One state felt that a 21-day advance
notification was reasonable because utilities generally plan at least
this far in advance for periodic RATAs (See Docket A-94-16 Item V-D-
29).
Several State agencies were sensitive to utility's need for greater
flexibility for sending notification where testing has been
rescheduled. Some States suggested that it would be sufficient for a
utility to notify them as late as twenty-four hours before the new date
of the test (See Docket A-94-16 Items V-D-31 and V-D-32), in order to
allow utilities greater flexibility in rescheduling. Another state
suggested that there should be different requirements for notification,
depending on whether the scheduled date is changed by less than three
days or changed by three days or greater. In the first case, a two-day
notification would not be appropriate, but in the latter case it would
be appropriate. This state also commented that in some cases, an
observer might already be on site when a test needs to be postponed
until the next day (See Docket A-94-16 Item V-D-30). In this case,
notification should not be required.
Response: For the initial notification of the date of periodic RATA
testing, EPA has decided to retain the requirement for advance
notification of at least twenty-one days. EPA agreed with the commentor
who felt this requirement was reasonable. EPA notes that twenty-one
days advance notification is sufficiently far in advance that agencies
can schedule an observer, which is the primary purpose of requiring
notification. Although the Agency understands the concerns of utilities
with having a time limit, the Agency believes there must be some time
limit established in order for the notification to meet its purpose of
allowing agencies to observe testing.
Also, EPA would like to clarify that this requirement is for
notification no later than twenty-one days in advance. Thus, if a state
agency has a requirement for notification thirty days in advance, a
utility could send notification both to the State and to EPA thirty
days in advance. Furthermore, if a utility wanted to send a schedule of
testing for all of its units during the next calendar quarter in a
single notification, it could do so. In either case, the minimum
information that must be present in the notification is as follows: (1)
the name of the plant and unit at which RATA testing will be performed;
(2) the ORISPL number for the plant; and (3) the date or dates for
which RATA testing is scheduled for that unit. It would not be
necessary to use the optional EPA form for RATA testing notifications
if the schedule letter or State notification letter contained the above
information.
EPA also agrees with the commentors who suggest that twenty-four
hours is sufficient advance notification when a test is rescheduled,
where rescheduling is done shortly before the original test date. If
the utility knows the rescheduled test date earlier, it should notify
agencies when it knows this date. However, the twenty-four hour notice
is a minimum requirement. This should prevent any situations where a
utility might be required to wait before starting testing or else risk
a technical violation. Using a single time period of twenty-four hours
(the calendar day before) would also be more straightforward than
having different notification requirements, depending upon how many
days the test date is changed. In addition, today's rule includes a
provision allowing for waivers of the notification requirement where an
observer is on-site. If an observer were actually already on site and
testing were postponed, then the observer could choose to waive the
notification requirement for that test for all agencies (state, local,
EPA regional office and the EPA Administrator's delegatee).
Issue: EPA also received comments on the means by which or the form
in which a notification could be transmitted to an agency. The May 17,
1995 direct final rule contained a provision requiring an initial
written notification of the date of testing, and notification again if
a test is rescheduled either ``in writing or by telephone or other
means.'' In the May 22, 1996 Federal Register notice requesting public
comment, EPA requested comment on using means of notification such as
telephone, facsimile, or electronic mail notification for a test that
is rescheduled. One utility commentor suggested that they would prefer
to send a notification by electronic mail, either for initial
notification or in case of rescheduling, and eliminate paper
notifications altogether (See Docket A-94-16 Item V-D-25). State
commentors felt that notifications could be submitted either by letter,
electronic mail or telephone (See Docket A-94-16 Item V-D-29); others
explicitly stated that these means were appropriate for a notification
where a testing date is rescheduled, but not for the original
notification (See Docket A-94-16 Items V-D-30 and V-D-32).
Response: Based upon the comments received, EPA is retaining the
provisions that initial notification of the testing date must be
provided in writing. However, EPA is clarifying in today's rule that a
written notification may be provided in the mail (U.S. mail or
overnight mail carrier) or via facsimile. In addition, an agency may
choose to accept electronic mail to meet the requirement for an initial
written notification. Notification in case of rescheduled testing may
be provided in writing, by telephone, or by other means that is
acceptable to the agency receiving the notification. Because the
[[Page 59156]]
initial notification is most critical for an agency that wants to
schedule test observations, it is still required to be submitted in
writing, rather than over the telephone. If a utility wishes to use
electronic mail or some other form of notification not explicitly
mentioned in part 75, it should contact its state or local agency and
EPA Regional office to determine if this is acceptable. The agency may
request additional safeguards be used when electronic mail notice is
provided (e.g., requiring procedures for confirmation of receipt or a
follow-up letter in the mail later).
IV. Impact Analyses
A. 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.
Pursuant to the terms of Executive Order 12866, it has been
determined that this rule is a ``significant regulatory action''
because the rule seems to raise novel legal or policy issues. As such,
this action was submitted to OMB for review. Any written comments from
OMB to EPA, any written EPA response to those comments, and any changes
made in response to OMB suggestions or recommendations are included in
the docket. The docket is available for public inspection at the EPA's
Air Docket Section.
B. Unfunded Mandates Act
Section 202 of the Unfunded Mandates Reform Act of 1995 (``Unfunded
Mandates Act'') requires that the Agency prepare a budgetary impact
statement before promulgating a rule that includes a Federal mandate
that may result in expenditure by State, local, and tribal governments,
in aggregate, or by the private sector, of $100 million or more in any
one year. Section 203 requires the Agency to establish a plan for
obtaining input from and informing, educating, and advising any small
governments that may be significantly or uniquely affected by the rule.
Under section 205 of the Unfunded Mandates Act, the Agency must
identify and consider a reasonable number of regulatory alternatives
before promulgating a rule for which a budgetary impact statement must
be prepared. The Agency must select from those alternatives the least
costly, most cost-effective, or least burdensome alternative that
achieves the objectives of the rule, unless the Agency explains why
this alternative is not selected or the selection of this alternative
is inconsistent with law.
Because this final rule is estimated to result in the expenditure
by State, local, and tribal governments or the private sector of less
than $100 million in any one year, the Agency has not prepared a
budgetary impact statement or specifically addressed the selection of
the least costly, most cost-effective, or least burdensome alternative.
Because small governments will not be significantly or uniquely
affected by this rule, the Agency is not required to develop a plan
with regard to small governments. However, as discussed in this
preamble, the rule has the net effect of reducing the burden of part 75
of the Acid Rain regulations on regulated entities that have add-on
emission controls, including both investor-owned and municipal
utilities.
C. Paperwork Reduction Act
Today's final rule does not add any additional information
collection requirements to the current information collection
requirements in the existing part 75. Therefore an Information
Collection Request was not prepared for today's final rule.
The information collection requirements for the existing part 75
rule have been approved by the OMB under the Paperwork Reduction Act,
44 U.S.C. 3501 et seq., and have been assigned control number 2060-
0258.
The information collection requirements in today's final rule do
not increase the estimated reporting burden. In fact, today's final
rule slightly reduces the reporting burden by allowing utilities which
have units with add-on emission controls which want to use the missing
data procedures described in this final rule to keep the parametric
data ranges on site rather than to report it to EPA. Since the
reduction is voluntary and only affects units with add-on emission
controls, it is difficult to determine the specific amount of the
reduction in burden overall.
Send comments regarding the burden estimate or any other aspect of
this collection of information, including suggestions for reducing this
burden to Director, OPPE Regulatory Information Division; U.S.
Environmental Protection Agency; 401 M Street SW (Mail Code 2136);
Washington, DC 20460; and to the Office of Information and Regulatory
Affairs, Office of Management and Budget, 725 17th Street NW;
Washington, DC 20503, marked ``Attention: Desk Officer for EPA.''
D. Regulatory Flexibility Act
The Regulatory Flexibility Act, 5 U.S.C. 601, et seq., requires
federal agencies to consider potential impacts of proposed regulations
on small business entities. If a preliminary analysis indicates that a
proposed regulation would have a significant adverse economic impact on
a substantial number of small business entities, then a regulatory
flexibility analysis must be prepared. An action which has a
predominantly deregulatory or beneficial economic effect on small
business does not need a regulatory flexibility analysis.
EPA has determined that it is not necessary to prepare a regulatory
flexibility analysis in connection with this final rule. This rule will
reduce regulatory burdens on small business entities because the
provisions in today's final rule increase the implementation
flexibility and slightly relieve the regulatory burden for all
utilities affected by this rule, including small utilities. Therefore,
EPA has determined that this rule will have no significant adverse
economic effect on a substantial number of small business entities.
E. Small Business Regulatory Enforcement Fairness Act
Under 5 U.S.C. 801(a)(1)(A) as added by the Small Business
Regulatory Enforcement Fairness Act of 1996, EPA submitted a report
containing this rule and other required information to the U.S. Senate,
the U.S. House of Representatives and the Comptroller General of the
General Accounting Office prior to publication of the rule in today's
Federal Register. This rule is not a ``major rule'' as defined by 5
U.S.C. 804(2).
[[Page 59157]]
List of Subjects in 40 CFR Part 75
Environmental protection, Air pollution control, Carbon dioxide,
Continuous emission monitors, Electric utilities, Incorporation by
reference, Nitrogen oxides, Reporting and recordkeeping requirements,
Sulfur dioxide.
Dated: November 5, 1996.
Carol M. Browner,
Administrator.
The interim final rule (59 FR 26560, May 17, 1995) is adopted as
final with the following changes. For the reasons set out in the
preamble, part 75 of title 40, chapter I, of the Code of Federal
Regulations is amended as follows:
PART 75--CONTINUOUS EMISSION MONITORING
1. The authority citation for part 75 continues to read as follows:
Authority: 42 U.S.C. 7601 and 7651k.
2. Section 75.6 is amended by revising paragraph (e) to read as
follows:
Sec. 75.6 Incorporation by reference.
* * * * *
(e) The following materials are available for purchase from the
following address: American Gas Association, 1515 Wilson Boulevard,
Arlington VA 22209:
(1) American Gas Association Report No. 3: Orifice Metering of
Natural Gas and Other Related Hydrocarbon Fluids, Part 1: General
Equations and Uncertainty Guidelines (October 1990 Edition), Part 2:
Specification and Installation Requirements (February 1991 Edition) and
Part 3: Natural Gas Applications (August 1992 Edition), for Sec. 75.20
and appendices D and E of this part.
(2) American Gas Association Transmission Measurement Committee
Report No. 7: Measurement of Gas by Turbine Meters (1985 Edition), for
Sec. 75.20 and appendix D of this part.
3. Section 75.11 is amended by revising paragraphs (a), (d), and
(e); and by removing paragraph (g) to read as follows:
Sec. 75.11 Specific provisions for monitoring SO2 emissions
(SO2 and flow monitors).
(a) Coal-fired units. The owner or operator shall meet the general
operating requirements in Sec. 75.10 for an SO2 continuous
emission monitoring system and a flow monitoring system for each
affected coal-fired unit while the unit is combusting coal and/or any
other fuel, except as provided in paragraph (e) of this section, in
Sec. 75.16, and in subpart E of this part. During hours in which only
natural gas or gaseous fuel with a sulfur content no greater than
natural gas (i.e., >20 grains per 100 standard cubic feet (gr/100 scf)
is combusted in the unit, the owner or operator shall comply with the
applicable provisions of paragraph (e)(1), (e)(2), or (e)(3) of this
section.
* * * * *
(d) Gas-fired and oil-fired units. The owner or operator of an
affected unit that qualifies as a gas-fired or oil-fired unit, as
defined in Sec. 72.2 of this chapter, based on information submitted by
the designated representative in the monitoring plan, shall measure and
record SO2 emissions:
(1) By meeting the general operating requirements in Sec. 75.10 for
an SO2 continuous emission monitoring system and flow monitoring
system. If this option is selected, the owner or operator shall comply
with the applicable provisions in paragraph (e)(1), (e)(2), or (e)(3)
of this section during hours in which the unit combusts only natural
gas (or gaseous fuel with a sulfur content no greater than natural
gas); or
(2) By providing other information satisfactory to the
Administrator using the applicable procedures specified in appendix D
of this part for estimating hourly SO2 mass emissions. Appendix D
shall not, however, be used when the unit combusts gaseous fuel with a
sulfur content greater than natural gas (i.e., 20 gr/100
scf); when such fuel is burned, the owner or operator shall comply with
the provisions of paragraph (e)(4) of this section.
(e) Units with SO2 continuous emission monitoring systems
during the combustion of gaseous fuel. The owner or operator of an
affected unit with an SO2 continuous emission monitoring system
shall, during any hours in which the unit combusts only gaseous fuel,
determine SO2 emissions in accordance with paragraph (e)(1),
(e)(2), (e)(3) or (e)(4) of this section, as applicable.
(1) When pipeline natural gas is burned in the unit, the owner or
operator may, in lieu of operating and recording data from the SO2
monitoring system, determine SO2 emissions by using the heat input
calculated using a certified flow monitoring system and a certified
diluent monitor, in conjunction with the default SO2 emission rate
for pipeline natural gas from section 2.3.2 of appendix D of this part,
and Equation F-23 in appendix F of this part. When this option is
chosen, the owner or operator shall perform the necessary data
acquisition and handling system tests under Sec. 75.20(c), and shall
meet all quality control and quality assurance requirements in appendix
B of this part for the flow monitor and the diluent monitor.
(2) When gaseous fuel with a sulfur content no greater than natural
gas (i.e., 20 gr/100 scf) is combusted in the unit, the
owner or operator may, in lieu of operating and recording data from the
SO2 monitoring system, determine SO2 emissions by certifying
an excepted monitoring system in accordance with Sec. 75.20 and with
appendix D of this part, by following the fuel sampling and analysis
procedures in section 2.3.1 of appendix D of this part, by meeting the
recordkeeping requirements of Sec. 75.55, and by meeting all quality
control and quality assurance requirements for fuel flowmeters in
appendix D of this part. If this compliance option is selected, the
hourly unit heat input reported under Sec. 75.54(b)(5) shall be
determined using a certified flow monitoring system and a certified
diluent monitor, in accordance with the procedures in section 5.2 of
appendix F of this part. The flow monitor and diluent monitor shall
meet all of the applicable quality control and quality assurance
requirements of appendix B of this part.
(3) When gaseous fuel with a sulfur content no greater than natural
gas (i.e., 20 gr/100 scf) is burned in the unit, the owner
or operator may determine SO2 mass emissions by using a certified
SO2 continuous monitoring system, in conjunction with a certified
flow rate monitoring system. However, on and after January 1, 1999, the
SO2 monitoring system shall be subject to the following
provisions; prior to January 1, 1999, the owner or operator may comply
with these provisions:
(i) When conducting the daily calibration error tests of the
SO2 monitoring system, as required by section 2.1.1 in appendix B
of this part, the zero-level calibration gas shall have an SO2
concentration of 0.0 percent of span. This restriction does not apply
if gaseous fuel is burned in the affected unit only during unit
startup.
(ii) The zero-level calibration response of the SO2 monitoring
system shall be adjusted, either automatically or manually, to read
exactly 0.0 ppm SO2 following each successful daily calibration
error test conducted in accordance with section 2.1.1 in appendix B of
this part. This calibration adjustment is optional if gaseous fuel is
burned in the affected unit only during unit startup.
(iii) Any hourly average SO2 concentration of less than 2.0
ppm recorded by the SO2 monitoring system shall be adjusted to a
default value of 2.0 ppm, for reporting purposes. Such adjusted hourly
averages shall be considered to be quality-assured data, provided that
the monitoring system is operating and is not out-of-control with
[[Page 59158]]
respect to any of the quality assurance tests required by appendix B of
this part (i.e., daily calibration error, linearity and relative
accuracy test audit).
(iv) Notwithstanding the requirements of sections 2.1.1.1 and
2.1.1.2 of appendix A of this part, a second, low-scale measurement
range is not required for units that sometimes burn natural gas (or
gaseous fuel with a sulfur content no greater than natural gas) and at
other times burn higher-sulfur fuel(s) such as coal or oil. For units
that burn only natural gas (or gaseous fuel with a sulfur content no
greater than natural gas) and burn no other type(s) of fuel(s), the
owner or operator shall set the span of the SO2 monitoring system
to a value no greater than 200 ppm.
(4) During any hours in which a unit combusts only gaseous fuel(s)
with a sulfur content greater than natural gas (i.e., > 20 gr/100 scf),
the owner or operator shall meet the general operating requirements in
Sec. 75.10 for an SO2 continuous emission monitoring system and a
flow monitoring system.
* * * * *
4. Section 75.16 is amended by revising paragraphs (a)(2)(ii)(B),
(a)(2)(ii)(C), and (b)(2)(ii)(B) and by adding paragraph (e)(5) to read
as follows:
Sec. 75.16 Special provisions for monitoring emissions from common,
bypass, and multiple stacks for SO2 emissions and heat input
determinations.
(a) * * *
(2) * * *
(ii) * * *
(B) Install, certify, operate, and maintain an SO2 continuous
emission monitoring system and flow monitoring system in the duct from
each Phase II or nonaffected unit; calculate SO2 mass emissions
from the Phase I units as the difference between SO2 mass
emissions measured in the common stack and SO2 mass emissions
measured in the ducts of the Phase II and nonaffected units; record and
report the calculated SO2 mass emissions from the Phase I units,
not to be reported as an hourly average value less than zero; and
combine emissions for the Phase I units for compliance purposes; or
(C) Install, certify, operate, and maintain an SO2 continuous
emission monitoring system and flow monitoring system in the duct from
each Phase I or nonaffected unit; calculate SO2 mass emissions
from the Phase II units as the difference between SO2 mass
emissions measured in the common stack and SO2 mass emissions
measured in the ducts of the Phase I and nonaffected units, not to be
reported as an hourly average value less than zero; and combine
emissions for the Phase II units for recordkeeping and compliance
purposes; or
* * * * *
(b) * * *
(2) * * *
(ii) * * *
(B) Install, certify, operate, and maintain an SO2 continuous
emission monitoring system and flow monitoring system in the duct from
each nonaffected unit; determine SO2 mass emissions from the
affected units as the difference between SO2 mass emissions
measured in the common stack and SO2 mass emissions measured in
the ducts of the nonaffected units, not to be reported as an hourly
average value less than zero; and combine emissions for the Phase I and
Phase II affected units for recordkeeping and compliance purposes; or
* * * * *
(e) * * *
(5) The owner or operator of an affected unit with a diluent
monitor and a flow monitor installed on a common stack to determine
heat input at the common stack may choose to apportion the heat input
from the common stack to each affected unit utilizing the common stack
by using either of the following two methods, provided that all of the
units utilizing the common stack are combusting fuel with the same F-
factor found in section 3 of appendix F of this part. The heat input
may be apportioned either by using the ratio of load (in MWe) for each
individual unit to the total load for all units utilizing the common
stack or by using the ratio of steam flow (in 1000 lb/hr) for each
individual unit to the total steam flow for all units utilizing the
common stack.
5. Section 75.18 is amended by adding paragraph (b)(3) to read as
follows:
Sec. 75.18 Specific provisions for monitoring emissions from common
and bypass stacks for opacity.
* * * * *
(b) * * *
(3) The owner or operator monitors opacity using Method 9 of
appendix A of part 60 of this chapter whenever emissions pass through
the bypass stack. Method 9 shall be used in accordance with the
applicable State regulations.
6. Section 75.20 is amended by revising the introductory text of
paragraph (b) and by revising paragraph (g)(1)(i) to read as follows:
Sec. 75.20 Certification and recertification procedures.
* * * * *
(b) Recertification approval process. Whenever the owner or
operator makes a replacement, modification, or change in the certified
continuous emission monitoring system or continuous opacity monitoring
system (which includes the automated data acquisition and handling
system, and, where applicable, the CO2 continuous emission
monitoring system), that significantly affects the ability of the
system to measure or record the SO2 concentration, volumetric gas
flow, SO2 mass emissions, NOX emission rate, CO2
concentration, or opacity, or to meet the requirements of Sec. 75.21 or
appendix B of this part, the owner or operator shall recertify the
continuous emission monitoring system, continuous opacity monitoring
system, or component thereof according to the procedures in this
paragraph. Examples of changes which require recertification include:
replacement of the analytical method, including the analyzer; change in
location or orientation of the sampling probe or site; rebuilding of
the analyzer or all monitoring system equipment; and replacement of an
existing continuous emission monitoring system or continuous opacity
monitoring system. In addition, if a continuous emission monitoring
system is not operating for more than 2 calendar years, then the owner
or operator shall recertify the continuous emission monitoring system.
The Administrator may determine whether a replacement, modification or
change in a monitoring system significantly affects the ability of the
monitoring system to measure or record the SO2 concentration,
volumetric gas flow, SO2 mass emissions, NOX emission rate,
CO2 concentration, or opacity. Furthermore, whenever the owner or
operator makes a replacement, modification, or change to the flue gas
handling system or the unit operation that significantly changes the
flow or concentration profile of monitored emissions, the owner or
operator shall recertify the continuous emission monitoring system or
component thereof according to the procedures in this paragraph. The
owner or operator shall recertify a continuous opacity monitoring
system whenever the monitor path length changes or as required by an
applicable State or local regulation or permit. Recertification is not
required prior to use of a non-redundant backup continuous emission
monitoring system in cases where all of the following conditions have
been met: the non-redundant backup continuous emission monitoring
system has been certified at the same sampling location within the
previous two calendar years; all components of the non-redundant
[[Page 59159]]
backup continuous emissions monitoring system have previously been
certified; and component monitors of the non-redundant backup
continuous emission monitoring system pass a linearity check (for
pollutant concentration monitors) or a calibration error test (for flow
monitors) prior to their use for monitoring of emissions or flow. In
addition, changes resulting from routine or normal corrective
maintenance and/or quality assurance activities do not require
recertification, nor do software modifications in the automated data
acquisition and handling system, where the modification is only for the
purpose of generating additional or modified reports for the State
Implementation Plan, internal company uses, or for reporting
requirements under subpart G of this part.
* * * * *
(g) * * *
(1) * * *
(i) When the optional SO2 mass emissions estimation procedure
in appendix D of this part or the optional NOX emissions
estimation protocol in appendix E of this part is used, the owner or
operator shall provide data from a calibration test for each fuel
flowmeter according to the appropriate calibration procedures using one
of the following standard methods: ASME MFC-3M-1989 with September 1990
Errata, ``Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and
Venturi'', ASME MFC-4M-1986 (Reaffirmed 1990) ``Measurement of Gas Flow
by Turbine Meters'', ASME MFC-5M-1985, ``Measurement of Liquid Flow in
Closed Conduits Using Transit-Time Ultrasonic Flowmeters'', ASME MFC-
6M-1987 with June 1987 Errata, ``Measurement of Fluid Flow in Pipes
Using Vortex Flow Meters'', ASME MFC-7M-1987 (Reaffirmed 1992),
``Measurement of Gas Flow by Means of Critical Flow Venturi Nozzles'',
ASME MFC-9M-1988 with December 1989 Errata, ``Measurement of Liquid
Flow in Closed Conduits by Weighing Method'', ISO 8316: 1987(E)
``Measurement of Liquid Flow in Closed Conduits--Method by Collection
of the Liquid in a Volumetric Tank'', Section 8, Calibration from
American Gas Association Transmission Measurement Committee Report No.
7: Measurement of Gas by Turbine Meters (1985 Edition) or American Gas
Association Report No. 3: Orifice Metering of Natural Gas and Other
Related Hydrocarbon Fluids Part 1: General Equations and Uncertainty
Guidelines (October 1990 Edition), Part 2: Specification and
Installation Requirements (February 1991 Edition) and Part 3: Natural
Gas Applications (August 1992 Edition), excluding the modified
calculation procedures of Part 3, as required by appendices D and E of
this part (all methods incorporated by reference under Sec. 75.6). The
Administrator may also approve other procedures that use equipment
traceable to National Institute of Standards of Technology (NIST)
standards. The designated representative shall document the procedure
and the equipment used in the monitoring plan for the unit and in a
petition submitted in accordance with Sec. 75.66(c).
* * * * *
7. Section 75.21 is amended by revising paragraph (a); by adding
paragraph (d); and by removing paragraph (f) to read as follows:
Sec. 75.21 Quality assurance and quality control requirements.
(a) Continuous emission monitoring systems. The owner or operator
of an affected unit shall operate, calibrate and maintain each
continuous emission monitoring system used to report emission data
under the Acid Rain Program as follows:
(1) The owner or operator shall operate, calibrate and maintain
each primary and redundant backup continuous emission monitoring system
according to the quality assurance and quality control procedures in
appendix B of this part.
(2) The owner or operator shall ensure that each non-redundant
backup continuous emission monitoring system complies with the daily
and quarterly quality assurance and quality control procedures in
appendix B of this part for each day and quarter that the system is
used to report data.
(3) The owner or operator shall perform quality assurance upon a
reference method backup monitoring system according to the requirements
of Method 2, 6C, 7E, or 3A in appendix A of part 60 of this chapter
(supplemented, as necessary, by guidance from the Administrator),
instead of the procedures specified in appendix B of this part.
(4) When a unit combusts only natural gas or gaseous fuel with a
sulfur content no greater than natural gas and SO2 emissions are
determined in accordance with Secs. 75.11(e)(1) or (e)(2), the owner or
operator of a unit with an SO2 continuous emission monitoring
system is not required to perform the daily or quarterly assessments of
the SO2 monitoring system under appendix B of this part on any day
or in any calendar quarter in which only natural gas (or gaseous fuel
with a sulfur content no greater than natural gas) is combusted in the
unit. Notwithstanding, the results of any daily calibration error test
and linearity test of the SO2 monitoring system performed while
the unit is combusting only natural gas (or gaseous fuel with a sulfur
content no greater than natural gas) shall be considered valid. If any
such test is failed, the SO2 monitoring system shall be considered
to be out-of-control until a subsequent test of the same type has been
successfully completed.
(5) For a unit with an SO2 continuous monitoring system, in
which natural gas (or gaseous fuel with a sulfur content no greater
than natural gas) is sometimes burned as a primary and/or backup fuel,
and in which higher-sulfur fuel(s) such as oil or coal are, at other
times, burned as primary or backup fuel(s), the owner or operator shall
perform the relative accuracy test audits of the SO2 monitoring
system (as required by section 6.5 in appendix A of this part and
section 2.3.1 in appendix B of this part) only when the higher-sulfur
fuel is combusted in the unit, and shall not perform SO2 relative
accuracy test audits when gaseous fuel is the only fuel being
combusted.
(6) If a unit with an SO2 monitoring system burns only fuel(s)
with a sulfur content no greater than that of natural gas and never
combusts other fuel(s) with a sulfur content greater than natural gas,
the SO2 monitoring system is exempted from the relative accuracy
test audit requirements in appendices A and B of this part.
(7) In determining the deadline for the next semiannual or annual
relative accuracy test audit of an SO2 monitoring system, any
calendar quarter during which a unit combusts only fuel(s) with a
sulfur content no greater than natural gas shall be excluded in
determining the calendar quarter, bypass operating quarter, or unit
operating quarter when the next relative accuracy test audit must be
performed for the SO2 monitoring system. If, however, as a result
of such exclusion of calendar quarters, eight calendar quarters elapse
after a relative accuracy test audit, without a subsequent relative
accuracy test audit of an SO2 monitoring system having been
performed, the owner or operator shall ensure that a relative accuracy
test audit is performed in the next calendar quarter in which a fuel
with a sulfur content greater than natural gas is burned in the unit.
(8) The owner or operator who, in accordance with Sec. 75.11(e)(1),
uses a certified flow monitor and a certified diluent monitor and
Equation F-23 in appendix F of this part to calculate SO2
emissions during hours in which a unit combusts only pipeline natural
gas,
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shall meet all quality control and quality assurance requirements in
appendix B of this part for the flow monitor and the diluent monitor.
* * * * *
(d) Notification for periodic relative accuracy test audits. The
owner or operator or the designated representative shall submit a
written notice of the dates of relative accuracy testing as specified
in Sec. 75.61.
* * * * *
8. Section 75.30 is amended by revising paragraph (d) to read as
follows:
Sec. 75.30 General provisions.
* * * * *
(d) The owner or operator shall comply with the applicable
provisions of this paragraph during hours in which a unit with an
SO2 continuous emission monitoring system combusts only natural
gas or gaseous fuel with a sulfur content no greater than natural gas.
(1) Whenever a unit with an SO2 continuous emission monitoring
system combusts only pipeline natural gas and the owner or operator is
using the procedures in section 7 of appendix F of this part to
determine SO