[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]]

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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.

-----------------------------------------------------------------------

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          
------------------------------------------------------------------------
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

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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

[[Page 59151]]

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

[[Page 59152]]

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

[[Page 59153]]

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

[[Page 59154]]

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

[[Page 59155]]

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,

[[Page 59160]]

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 SO2 mass emissions pursuant to Sec. 75.11(e)(1), the 
owner or operator shall, for the purposes of reporting heat input data 
under Sec. 75.54(b)(5) and for the calculation of SO2 mass 
emissions using Equation F-23 in section 7 of appendix F of this part, 
substitute for missing data from a flow monitoring system, CO2 
diluent monitor or O2 diluent monitor using the missing data 
substitution procedures in Sec. 75.36.
    (2) Whenever a unit with an SO2 continuous emission monitoring 
system combusts gaseous fuel with a sulfur content no greater than 
natural gas (i.e.,  20 gr/100 scf) and the owner or operator 
uses the gas sampling and analysis and fuel flow procedures in appendix 
D of this part, to determine SO2 mass emissions pursuant to 
Sec. 75.11(e)(2), the owner or operator shall substitute for missing 
sulfur content, gross calorific value and fuel flow meter data using 
the missing data procedures in appendix D of this part and shall also, 
for the purposes of reporting heat input data under Sec. 75.54(b)(5), 
substitute for missing data from a flow monitoring system, CO2 
diluent monitor or O2 diluent monitor using the missing data 
substitution procedures in Sec. 75.36.
    (3) The owner or operator of a unit with an SO2 monitoring 
system shall not include hours when the unit combusts only natural gas 
(or a gaseous fuel with sulfur content no greater than that of natural 
gas) in the SO2 data availability calculations in Sec. 75.32, or 
in the calculations of substitute SO2 data using the procedures of 
either Secs. 75.31 or 75.33, when SO2 emissions are determined in 
accordance with Secs. 75.11 (e)(1) or (e)(2). For the purpose of the 
missing data and availability procedures for SO2 pollutant 
concentration monitors in Secs. 75.31 through 75.33 only, all hours 
during which the unit combusts only natural gas, or a gaseous fuel with 
a sulfur content no greater than natural gas, shall be excluded from 
the definition of ``monitor operating hour,'' ``quality-assured monitor 
operating hour,'' ``unit operating hour,'' and ``unit operating day'', 
when SO2 emissions are determined in accordance with Secs. 75.11 
(e)(1) or (e)(2).
    (4) During all 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) and the owner or 
operator uses the SO2 monitoring system to determine SO2 mass 
emissions pursuant to Sec. 75.11(e)(3), the owner or operator shall 
determine the percent monitor data availability for SO2 in 
accordance with Sec. 75.32 and shall use the standard SO2 missing 
data procedures of Sec. 75.33.
* * * * *
    9. Section 75.32 is amended by revising paragraph (a)(3) and by 
removing paragraph (a)(4) to read as follows:


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

    (a) * * *
    (3) The owner or operator shall include all unit operating hours, 
and all monitor operating hours for which quality-assured data were 
recorded by a certified primary monitor; a certified redundant or non-
redundant backup monitor or a reference method for that unit; or by an 
approved alternative monitoring system under subpart E of this part 
when calculating percent monitor data availability using Equation 8 or 
9. No hours from more than three years (26,280 clock hours) earlier 
shall be used in Equation 9. For a unit that has accumulated less than 
8,760 unit operating hours in the previous three years (26,280 clock 
hours), replace the words ``during previous 8,760 unit operating 
hours'' in Equation 9 with ``in the previous three years'' and replace 
``8,760'' with ``total unit operating hours in the previous three 
years.'' The owner or operator of a unit with an SO2 monitoring 
system shall, when SO2 emissions are determined in accordance with 
Secs. 75.11(e)(1) or (e)(2), exclude hours in which a unit combusts 
only natural gas (or gaseous fuel with a sulfur content no greater than 
natural gas) from calculations of percent monitor data availability for 
SO2 pollutant concentration monitors, as provided in 
Sec. 75.30(d).
 * * * * *
    10. Section 75.34 is amended by revising paragraphs (a), (b) 
introductory text, (b)(1), (c) introductory text, and (d) to read as 
follows:


Sec. 75.34   Units with add-on emission controls.

    (a) The owner or operator of an affected unit equipped with add-on 
SO2 and/or NOX emission controls shall use one of the 
following options for each hour in which quality-assured data from the 
outlet SO2 and/or NOX monitoring system(s) are not obtained:
    (1) The owner or operator may use the missing data substitution 
procedures as specified for all affected units in Secs. 75.31 through 
75.33 to substitute data for each hour in which the add-on emission 
controls are operating within the proper parametric ranges specified in 
the quality assurance/quality control program for the unit, required by 
section 1 in appendix B of this part. The designated representative 
shall document in the quality assurance/ quality control program the 
ranges of the add-on emission control operating parameters that 
indicate proper operation of the controls. The owner or operator shall, 
for each missing data period, record data to verify the proper 
operation of the SO2 or NOX add-on emission controls during 
each hour, as described in paragraph (d) of this section. In addition, 
under Sec. 75.64(c), the designated representative shall submit a 
certified verification of the proper operation of the SO2 or 
NOX add-on emission control for each missing data period at the 
end of each quarter.
    (2) The designated representative may petition the Administrator 
under Sec. 75.66 to replace the maximum recorded value in the last 720 
quality-assured monitor operating hours with a value corresponding to 
the maximum controlled emission rate (an emission rate recorded when 
the add-on emission controls were operating) recorded during the last 
720 quality-assured monitor operating hours. For such a petition, the 
designated representative must demonstrate that the following 
conditions are met: the monitor data availability, calculated in 
accordance with Sec. 75.32, for the affected unit is below 90.0 percent 
and parametric data establish that the add-on emission controls were 
operating properly (i.e., within the range of operating parameters 
provided in the quality assurance/

[[Page 59161]]

 quality control program) during the time period under petition.
    (3) The designated representative may petition the Administrator 
under Sec. 75.66 for approval of site-specific parametric monitoring 
procedure(s) for calculating substitute data for missing SO2 
pollutant concentration and NOX emission rate data in accordance 
with the requirements of paragraphs (b) and (c) of this section and 
appendix C of this part. The owner or operator shall record the data 
required in appendix C of this part, pursuant to Sec. 75.55(b).
    (b) For an affected unit equipped with add-on SO2 emission 
controls, the designated representative may petition the Administrator 
to approve a parametric monitoring procedure, as described in appendix 
C of this part, for calculating substitute SO2 concentration data 
for missing data periods. The owner or operator shall use the 
procedures in Secs. 75.31, 75.33, or 75.34(a) for providing substitute 
data for missing SO2 concentration data unless a parametric 
monitoring procedure has been approved by the Administrator.
    (1) Where the monitor data availability is 90.0 percent or more for 
an outlet SO2 pollutant concentration monitor, the owner or 
operator may calculate substitute data using an approved parametric 
monitoring procedure.
 * * * * *
    (c) For an affected unit with NOX add-on emission controls, 
the designated representative may petition the Administrator to approve 
a parametric monitoring procedure, as described in appendix C of this 
part, in order to calculate substitute NOX emission rate data for 
missing data periods. The owner or operator shall use the procedures in 
Secs. 75.31 or 75.33 for providing substitute data for missing NOX 
emission rate data prior to receiving the Administrator's approval for 
a parametric monitoring procedure.
 * * * * *
    (d) The owner or operator shall keep records of information as 
described in subpart F of this part to verify the proper operation of 
the SO2 or NOX emission controls during all periods of 
SO2 or NOX emission missing data. The owner or operator shall 
provide these records to the Administrator or to the EPA Regional 
Office upon request. Whenever such data are not provided or such data 
do not demonstrate that proper operation of the SO2 or NOX 
add-on emission controls has been maintained in accordance with the 
range of add-on emission control operating parameters reported in the 
quality assurance/quality control program for the unit, the owner or 
operator shall substitute the maximum potential NOX emission rate, 
as defined in Sec. 72.2 of this chapter, to report the NOX 
emission rate, and either the maximum hourly SO2 concentration 
recorded by the inlet monitor during the previous 720 quality-assured 
monitor operating hours, if available, or the maximum potential 
concentration for SO2, as defined by section 2.1.1.1. of appendix 
A of this part, to report SO2 concentration for each hour of 
missing data until information demonstrating proper operation of the 
SO2 or NOX emission controls is available.
    11. Section 75.53 is amended by revising the introductory text of 
paragraph (d) and removing paragraph (d)(4) to read as follows:


Sec. 75.53   Monitoring plan.

 * * * * *
    (d) Contents of monitoring plan for specific situations. The 
following additional information shall be included in the monitoring 
plan for gas-fired or oil-fired units:
 * * * * *
    12. Section 75.55 is amended by revising paragraphs (b)(3), 
introductory, (b)(3)(i), (b)(3)(ii), and (e) to read as follows:


Sec. 75.55   General recordkeeping provisions for specific situations.

 * * * * *
    (b) * * *
    (3) For units with add-on SO2 or NOX emission controls 
following the provisions of Secs. 75.34 (a)(1) or (a)(2), the owner or 
operator shall, for each hour of missing SO2 or NOX emission 
data, record:
    (i) Parametric data which demonstrate the proper operation of the 
add-on emission controls, as described in the quality assurance/quality 
control program for the unit. The parametric data shall be maintained 
on site, and shall be submitted upon request to the Administrator, an 
EPA Regional office, State, or local agency;
    (ii) A flag indicating either that the add-on emission controls are 
operating properly, as evidenced by all parameters being within the 
ranges specified in the quality assurance/quality control program, or 
that the add-on emission controls are not operating properly;
 * * * * *
    (e) Specific SO2 emission record provisions during the 
combustion of gaseous fuel.
    (1) If SO2 emissions are determined in accordance with the 
provisions in Sec. 75.11(e)(2) during hours in which only natural gas 
(or gaseous fuel with a sulfur content no greater than natural gas) is 
combusted in a unit with an SO2 continuous emission monitoring 
system, the owner or operator shall record the information in paragraph 
(c)(3) of this section in lieu of the information in Secs. 75.54 (c)(1) 
and (c)(3), for those hours.
    (2) The provisions of this paragraph apply to a unit which, in 
accordance with the provisions of Sec. 75.11(e)(3) uses an SO2 
continuous emission monitoring system to determine SO2 emissions 
during hours in which only natural gas or gaseous fuel with a sulfur 
content no greater than natural gas is combusted in the unit. If the 
unit sometimes burns only natural gas (or gaseous fuel with a sulfur 
content no greater than natural gas) as a primary and/or backup fuel, 
and at other times combusts higher-sulfur fuels such as coal or oil as 
primary and/or backup fuel(s), then the owner or operator shall keep 
records on-site, suitable for inspection, of the type(s) of fuel(s) 
burned during each period of missing SO2 data, and the number of 
hours that each type of fuel was combusted in the unit during each 
missing data period. This recordkeeping requirement does not apply to 
an affected unit that burns natural gas (or gaseous fuel with a sulfur 
content no greater than natural gas) exclusively, nor does it apply to 
a unit that burns such gaseous fuel(s) only during unit startup.
 * * * * *
    13. Section 75.56 is amended by revising paragraph (c); and by 
adding paragraph (d) to read as follows:


Sec. 75.56   Certification, quality assurance and, quality control 
record provisions.

* * * * *
    (c) For units with add-on SO2 and NOX emission controls 
following the provisions of Secs. 75.34(a)(1) or (a)(2), the owner or 
operator shall keep the following records on-site in the quality 
assurance/quality control plan required by section 1 in appendix B of 
this part:
    (1) A list of operating parameters for the add-on emission 
controls, including parameters in Sec. 75.55 (b), appropriate to the 
particular installation of add-on emission controls; and
    (2) The range of each operating parameter in the list that 
indicates the add-on emission controls are properly operating.
    (d) The owner or operator shall meet the requirements of paragraphs 
(a) and (b) of this section on and after January 1, 1996. The owner or 
operator shall meet the requirements of paragraph (c) of this section 
on and after January 1, 1998.
    14. Section 75.61 is amended by adding paragraph (a)(5) to read as 
follows:

[[Page 59162]]

Sec. 75.61   Notifications.

* * * * *
    (a) * * *
    (5) Periodic relative accuracy test audits. The owner or operator 
or designated representative of an affected unit shall submit written 
notice of the date of periodic relative accuracy testing performed 
under appendix B of this part no later than 21 days prior to the first 
scheduled day of testing. Testing may be performed on a date other than 
that already provided in a notice under this subparagraph as long as 
notice of the new date is provided either in writing or by telephone or 
other means acceptable to the respective State agency or office of EPA, 
and the notice is provided as soon as practicable after the new testing 
date is known, but no later than twenty-four (24) hours in advance of 
the new date of testing.
    (i) Written notification under paragraph (a) (5) of this section 
may be provided either by mail or by facsimile. In addition, written 
notification may be provided by electronic mail, provided that the 
respective State agency or office of EPA agrees that this is an 
acceptable form of notification.
    (ii) Notwithstanding the notice requirements under paragraph (a)(5) 
of this section, the owner or operator may elect to repeat a periodic 
relative accuracy test immediately, without additional notification 
whenever the owner or operator has determined that a test was failed, 
or that a second test is necessary in order to attain a reduced 
relative accuracy test frequency.
    (iii) Waiver from notification requirements. The Administrator, the 
appropriate EPA Regional Office, or the applicable State air pollution 
control agency may issue a waiver from the requirement of paragraph 
(a)(5) of this section to provide notice to the respective State agency 
or office of EPA for a unit or a group of units for one or more tests. 
The Administrator, the appropriate EPA Regional Office, or the 
applicable State air pollution control agency may also discontinue the 
waiver and reinstate the requirement of paragraph (a)(5) of this 
section to provide notice to the respective State agency or office of 
EPA for future tests for a unit or a group of units. In addition, if an 
observer from a State agency or EPA is present when a test is 
rescheduled, the observer may waive all notification requirements under 
paragraph (a)(5) of this section for the rescheduled test.
* * * * *
    15. Section 75.66 is amended by revising paragraph (f)(2) to read 
as follows:


Sec. 75.66   Petitions to the Administrator.

* * * * *
    (f) * * *
    (2) Data demonstrating that the add-on emission controls were 
operating properly during the time period under petition (i.e., 
operating parameters were within the ranges specified for proper 
operation of the add-on emission controls in the quality assurance/
quality control program for the unit);
* * * * *
    16. Appendix A to part 75 is amended as follows:
    a. by removing sections 6.3.1, 6.3.2 and 6.4.1;
    b. by revising section 6.4;
    c. by redesignating sections 6.3.3 and 6.3.4 as sections 6.3.1 and 
6.3.2 and revising newly designated section 6.3.1; and
    d. by adding figure 6 (with notes A through F) after figure 5 at 
the end of the appendix.

Appendix A to Part 75--Specifications and Test Procedures

* * * * *

6.3  7-day Calibration Error Test

6.3.1  Pollutant Concentration Monitor and CO2 or O2 Monitor 
7-day Calibration Error Test

    Measure the calibration error of each pollutant concentration 
monitor and CO2 or O2 monitor while the unit is operating 
once each day for 7 consecutive operating days according to the 
following procedures. (In the event that extended unit outages occur 
after the commencement of the test, the 7 consecutive unit operating 
days need not be 7 consecutive calendar days.) Units using dual span 
monitors must perform the calibration error test on both high- and 
low-scales of the pollutant concentration monitor.
    Do not make manual or automatic adjustments to the monitor 
settings until after taking measurements at both zero and high 
concentration levels for that day during the 7-day test. If 
automatic adjustments are made following both injections, conduct 
the calibration error test in a way that the magnitude of the 
adjustments can be determined and recorded. Record and report test 
results for each day using the unadjusted concentration measured in 
the calibration error test prior to making any manual or automatic 
adjustments (i.e. resetting the calibration).
    The calibration error tests should be approximately 24 hours 
apart, (unless the 7-day test is performed over non-consecutive 
days). Perform calibration error tests at two concentrations: (1) 
zero-level and (2) high-level, as specified in section 5.2 of this 
appendix. In addition, repeat the procedure for SO2 and 
NOX pollutant concentration monitors using the low-scale for 
units equipped with emission controls or other units with dual span 
monitors. Use only NIST traceable reference material, standard 
reference material, NIST/EPA-approved certified reference material, 
research gas material, Protocol 1 calibration gases certified by the 
vendor to be within 2 percent of the label value or zero air 
material for the zero level only.
    Introduce the calibration gas at the gas injection port, as 
specified in section 2.2.1 of this appendix. Operate each monitor in 
its normal sampling mode. For extractive and dilution type monitors, 
pass the audit gas through all filters, scrubbers, conditioners, and 
other monitor components used during normal sampling and through as 
much of the sampling probe as is practical. For in situ type 
monitors, perform calibration checking all active electronic and 
optical components, including the transmitter, receiver, and 
analyzer. Challenge the pollutant concentration monitors and 
CO2 or O2 monitors once with each gas. Record the monitor 
response from the data acquisition and handling system. Using 
Equation A-5 of this appendix, determine the calibration error at 
each concentration once each day (at approximately 24-hour 
intervals) for 7 consecutive days according to the procedures given 
in this section.
    Calibration error tests are acceptable for monitor or monitoring 
system certification if none of these daily calibration error test 
results exceed the applicable performance specifications in section 
3.1 of this appendix.
* * * * *

6.4  Cycle Time Test

    Perform cycle time tests for each pollutant concentration 
monitor, and continuous emission monitoring system while the unit is 
operating, according to the following procedures (see also Figure 6 
of this appendix).
    Use a zero-level and a high-level calibration gas (as defined in 
section 5.2 of this appendix) alternately. To determine the upscale 
elapsed time, inject a zero-level concentration calibration gas into 
the probe tip (or injection port leading to the calibration cell, 
for in situ systems with no probe). Record the stable starting gas 
value and start time, using the data acquisition and handling system 
(DAHS). Next, allow the monitor to measure the concentration of flue 
gas emissions until the response stabilizes. Record the stable 
ending stack emissions value and the end time of the test using the 
DAHS. Determine the upscale elapsed time as the time it takes for 
95.0 percent of the step change to be achieved between the stable 
starting gas value and the stable ending stack emissions value. Then 
repeat the procedure, starting by injecting the high-level gas 
concentration to determine the downscale elapsed time, which is the 
time it takes for 95.0 percent of the step change to be achieved 
between the stable starting gas value and the stable ending stack 
emissions value. End the downscale test by measuring the stable 
concentration of flue gas emissions. Record the stable starting and 
ending monitor values, the start and end times, and the downscale 
elapsed time for the monitor using the DAHS. A stable value is 
equivalent to a reading with a change of less than 2 percent of the 
span value for 2 minutes, or a reading with a change of less than 6 
percent from the measured average concentration over 6 minutes. 
(Owners or

[[Page 59163]]

operators of systems which do not record data in 1-minute or 3-
minute intervals may petition the Administrator under Sec. 75.66 for 
alternative stabilization criteria).
    For monitors or monitoring systems that perform a series of 
operations (such as purge, sample, and analyze), time the injections 
of the calibration gases so they will produce the longest possible 
cycle time. Report the slower of the two elapsed times (upscale or 
downscale) as the cycle time for the analyzer. (See Figure 5 of this 
appendix.) For the NOX-diluent continuous emission monitoring 
system test and SO2-diluent continuous emission monitoring 
system test, record and report the longer cycle time of the two 
component analyzers as the system cycle time.
    For time-shared systems, this procedure must be done at all 
probe locations that will be polled within the same 15-minute period 
during monitoring system operations. To determine the cycle time for 
time-shared systems, add together the longest cycle time obtained at 
each of the probe locations. Report the sum of the longest cycle 
time at each of the probe locations plus the sum of the time 
required for all purge cycles (as determined by the continuous 
emission monitoring system manufacturer) at each of the probe 
locations as the cycle time for each of the time-shared systems. For 
monitors with dual ranges, report the test results from on the range 
giving the longer cycle time. Cycle time test results are acceptable 
for monitor or monitoring system certification if none of the cycle 
times exceed 15 minutes.
* * * * *

BILLING CODE 6560-50-P

[[Page 59164]]

[GRAPHIC] [TIFF OMITTED] TR20NO96.000



BILLING CODE 6560-50-C

[[Page 59165]]

    A. To determine the downscale cycle time, inject a high level 
calibration gas into the port leading to the calibration cell or 
thimble.
    B. Allow the analyzer to stabilize. Record the stabilized value. 
Stop the calibration gas flow and allow the monitor to measure the 
flue gas emissions until the response stabilizes.
    C. Record the stabilized value. A stable reading is achieved 
when the concentration reading deviates less than 6% from the 
measured average concentration in 6 minutes or if it deviates less 
than 2% of the monitor's span value in 2 minutes. (Owners and 
operators of units that do not record data in 1 minute or 3 minute 
intervals may petition the Administrator under section 75.66 for 
alternative stabilization criteria.)
    D. Determine the step change. The step change is equal to the 
difference between the stabilized calibration gas value (Point B) 
and the final stable value (Point C). Take 95% of the step change 
value and subtract the result from the stabilized calibration gas 
value (Point B). Determine the time at which 95% of the step change 
occurred (Point D).
    E. Determine the cycle time. The cycle time is equal to the 
downscale elapsed time, i.e. the time at which 95% of the step 
change occurred (point D) minus the time at which the calibration 
gas flow was stopped (Point B). In this example, cycle 
time=(6.5-4)=2.5 minutes (Report as 3 minutes).
    F. To determine the cycle time for the upscale test, inject a 
zero scale calibration gas into the probe and repeat the procedures 
described above, except that 95% of the step change in concentration 
is added to the stabilized calibration gas value. Afterwards, 
compare the two cycle times achieved for both the upscale and 
downscale tests. The longer of these two times equals the cycle time 
for the analyzer.

    17. Appendix B to part 75 is amended as follows:
    a. by revising sections 2.1 and 2.1.1;
    b. by removing sections 2.1.2 and 2.1.7; redesignating section 
2.1.3 as section 2.1.2 and revising newly designated section 2.1.2;
    c. by redesignating sections 2.1.4 and 2.1.5 as 2.1.3 and 2.1.4, 
respectively; and
    d. by adding new sections 1.6, 2.1.1.1 and 2.1.1.2, 2.1.5, 2.1.5.1, 
and 2.1.5.2.

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

1. Quality Control Program

* * * * *

1.6  Parametric Monitoring for Units With Add-On Emission Controls

    The owner or operator shall keep a written (or electronic) 
record including a list of operating parameters for the add-on 
SO2 or NOX emission controls, including parameters in 
Sec. 75.55(b), and the range of each operating parameter that 
indicates the add-on emission controls are operating properly.
    The owner or operator shall keep a written (or electronic) 
record of the parametric monitoring data during each hour of each 
SO2 or NOX missing data period.
* * * * *

2. Frequency of Testing

* * * * *

2.1  Daily Assessments

    Perform the following daily assessments to quality-assure the 
hourly data recorded by the monitoring systems during each period of 
unit operation, or, for a bypass stack or duct, each period in which 
emissions pass through the bypass stack or duct. These requirements 
are effective as of the date when the monitor or continuous emission 
monitoring system completes certification testing.

2.1.1  Calibration Error Test

    Except as provided in section 2.1.1.2 of this appendix, perform 
the daily calibration error test of each gas monitoring system 
according to the procedure in section 6.3.1 of appendix A of this 
part and perform the daily calibration error test of each flow 
monitoring system according to the procedure in section 6.3.2 of 
appendix A of this part.
    For units with add-on emission controls and dual-span or auto-
ranging monitors, and other units that use the maximum expected 
concentration to determine calibration gas values, perform the daily 
calibration error tests on each scale that has been used since the 
previous calibration error test. For example, if the pollutant 
concentration has not exceeded the low-scale value (based on the 
maximum expected concentration) since the previous calibration error 
test, the calibration error test may be performed on the low-scale 
only. If, however, the concentration has exceeded the low-scale span 
value for one hour or longer since the previous calibration error 
test, perform the calibration error test on both the low- and high-
scales.
    2.1.1.1  On-line Daily Calibration Error Tests. Except as 
provided in section 2.1.1.2 of this appendix, all daily calibration 
error tests must be performed while the unit is in operation at 
normal, stable conditions (i.e. ``on-line'').
    2.1.1.2 Off-line Daily Calibration Error Tests. Daily 
calibrations may be performed while the unit is not operating (i.e., 
``off-line'') and may be used to validate data for a monitoring 
system that meets the following conditions:
    (1) An initial demonstration test of the monitoring system is 
successfully completed and the results are reported in the quarterly 
report required under Sec. 75.64 of this part. The initial 
demonstration test, hereafter called the ``off-line calibration 
demonstration'', consists of an off-line calibration error test 
followed by an on-line calibration error test. Both the off-line and 
on-line portions of the off-line calibration demonstration must meet 
the calibration error performance specification in section 3.1 of 
appendix A of this part. Upon completion of the off-line portion of 
the demonstration, the zero and upscale monitor responses may be 
adjusted, but only toward the true values of the calibration gases 
or reference signals used to perform the test and only in accordance 
with the routine calibration adjustment procedures specified in the 
quality control program required under section 1 of appendix B to 
this part. Once these adjustments are made, no further adjustments 
may be made to the monitoring system until after completion of the 
on-line portion of the off-line calibration demonstration. Within 26 
clock hours of the completion hour of the off-line portion of the 
demonstration, the monitoring system must successfully complete the 
first attempted calibration error test, i.e., the on-line portion of 
the demonstration.
    (2) For each monitoring system that has passed the off-line 
calibration demonstration, a successful on-line calibration error 
test of the monitoring system must be completed no later than 26 
unit operating hours after each off-line calibration error test used 
for data validation.

2.1.2  Daily Flow Interference Check

    Perform the daily flow monitor interference checks specified in 
section 2.2.2.2 of appendix A of this part while the unit is in 
operation at normal, stable conditions.
* * * * *
* * * * *

2.1.5  Quality Assurance of Data With Respect to Daily Assessments

    When a monitoring system passes a daily assessment (i.e., daily 
calibration error test or daily flow interference check), data from 
that monitoring system are prospectively validated for 26 clock 
hours (i.e., 24 hours plus a 2-hour grace period) beginning with the 
hour in which the test is passed, unless another assessment (i.e. a 
daily calibration error test, an interference check of a flow 
monitor, a quarterly linearity check, a quarterly leak check, or a 
relative accuracy test audit) is failed within the 26-hour period.
    2.1.5.1  Data Invalidation with Respect to Daily Assessments. 
The following specific rules apply to the invalidation of data with 
respect to daily assessments:
    (1) Data from a monitoring system are invalid beginning with the 
first hour following the expiration of a 26-hour data validation 
period or beginning with the first hour following the expiration of 
an 8-hour start-up grace period (as provided under section 2.1.3.2 
of this appendix) if the required subsequent daily assessment has 
not been conducted.
    (2) Beginning on January 1, 1999, for a monitoring system that 
has passed the off-line calibration demonstration, if an on-line 
daily calibration error test of the same monitoring system is not 
conducted and passed within 26 unit operating hours of an off-line 
calibration error test that is used for data validation, then data 
from that monitoring system are invalid, beginning with the 27th 
unit operating hour following that off-line calibration error test.
    2.1.5.2  Daily Assessment Start-Up Grace Period. For the purpose 
of quality assuring data with respect to a daily assessment (i.e. a 
daily calibration error test or a flow interference check), a start-
up grace period may apply when a unit begins to operate after

[[Page 59166]]

a period of non-operation. The start-up grace period for a daily 
calibration error test is independent of the start-up grace period 
for a daily flow interference check. To qualify for a start-up grace 
period for a daily assessment, there are two requirements:
    (1) The unit must have resumed operation after being in outage 
for 1 or more hours (i.e., the unit must be in a start-up condition) 
as evidenced by a change in unit operating time from zero in one 
clock hour to an operating time greater than zero in the next clock 
hour.
    (2) For the monitoring system to be used to validate data during 
the grace period, the previous daily assessment of the same kind 
must have been passed on-line within 26 clock hours prior to the 
last hour in which the unit operated before the outage. In addition, 
the monitoring system must be in-control with respect to quarterly 
and semi-annual or annual assessments.
    If both of the above conditions are met, then a start-up grace 
period of up to 8 clock hours applies, beginning with the first hour 
of unit operation following the outage. During the start-up grace 
period, data generated by the monitoring system are considered 
quality-assured. For each monitoring system, a start-up grace period 
for a calibration error test or flow interference check ends when 
either: (1) a daily assessment of the same kind (i.e., calibration 
error test or flow interference check) is performed; or (2) 8 clock 
hours have elapsed (starting with the first hour of unit operation 
following the outage), whichever occurs first.
* * * * *
    18. Appendix D of part 75 is amended by revising section 2.1.5.1 to 
read as follows:

Appendix D to Part 75--Optional SO2 Emissions Data Protocol for 
Gas-Fired and Oil-Fired Units

* * * * *

2.1  Flowmeter Measurements

* * * * *
    2.1.5.1  Use the procedures in the following standards for 
flowmeter calibration or flowmeter design, as appropriate to the 
type of flowmeter: 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,'' American Gas Association Report No. 3, 
``Orifice Metering of Natural Gas and Other Related Hydrocarbon 
Fluids Part 1: General Equations and Uncertainty Guidelines'' 
(October 1990 Edition), Part 2: ``Specification and Installation 
Requirements'' (February 1991 Edition) and Part 3: ``Natural Gas 
Applications`` (August 1992 edition), (excluding the modified flow-
calculation method in Part 3), Section 8, Calibration from American 
Gas Association Transmission Measurement Committee Report No. 7: 
Measurement of Gas by Turbine Meters (1985 Edition), 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,'' ISO 8316: 1987(E) 
``Measurement of Liquid Flow in Closed Conduits--Method by 
Collection of the Liquid in a Volumetric Tank,'' or MFC-9M-1988 with 
December 1989 Errata (``Measurement of Liquid Flow in Closed 
Conduits by Weighing Method'') for all other flow meter types 
(incorporated by reference under Sec. 75.6 of this part). The 
Administrator may also approve other procedures that use equipment 
traceable to National Institute of Standards and Technology 
standards. Document other procedures, the equipment used, and the 
accuracy of the procedures in the monitoring plan for the unit and a 
petition submitted by the designated representative under 
Sec. 75.66(c). If the flowmeter accuracy exceeds 2.0 
percent of the upper range value, the flowmeter does not qualify for 
use under this part.
* * * * *
    19. Appendix F of part 75 is amended by revising section 7 to read 
as follows:

Appendix F to Part 75--Conversion Procedures

* * * * *

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

    The owner or operator shall use the following equation to 
calculate hourly SO2 mass emissions as allowed for units with 
SO2 continuous emission monitoring systems if, during the 
combustion of pipeline natural gas, SO2 emissions are 
determined in accordance with Sec. 75.11(e)(1).

Eh=(0.0006) HI      (Eq. F-23)

Where,

Eh=Hourly SO2 mass emissions, lb/hr.
0.0006=Default SO2 emission rate for pipeline natural gas, lb/
mmBtu.
HI=Hourly heat input, as determined using the procedures of section 5.2 
of this appendix.

[FR Doc. 96-29452 Filed 11-19-96; 8:45 am]
BILLING CODE 6560-50-P