Acid Rain Program: Continuous Emission Monitoring Rule Technical Revisions

Note: EPA no longer updates this information, but it may be useful as a reference or resource.
 [Federal Register: May 17, 1995 (Volume 60, Number 95)]
[Rules and Regulations]
[Page 26560-26571]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]



ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 75
[FRL-5203-2]
 
Acid Rain Program: Continuous Emission Monitoring Rule Technical 
Revisions

AGENCY: Environmental Protection Agency (EPA).
ACTION: Interim final rule and request for comments.



SUMMARY: Title IV of the Clean Air Act (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 program sets emissions limitations to reduce acidic deposition and 
its serious, adverse effects on natural resources, ecosystems, 
materials, visibility, and public health. On January 11, 1993, the 
Agency promulgated final rules under title IV. Several parties filed 
petitions for review of the rules. On April 17, 1995, the EPA and the 
parties signed a settlement agreement addressing continuous emission 
monitoring (CEM) issues.
    In this interim final rule, EPA is amending certain provisions of 
the CEM regulations to allow industry to be in compliance in situations 
that were not contemplated in the original rulemaking. The interim 
final rule allows industry additional flexibility to implement new 
provisions immediately that address these unforeseen situations, 
reduces the possibility of underestimating emissions, and also allows 
the public to comment upon these new provisions.

DATES: Effective Dates. This interim final rule shall become effective 
on July 17, 1995. The provisions of Secs. 75.11(a), 75.21(a), and 
75.32(a)(3); sections 6.3.1, 6.3.2 and 6.4 of appendix A of part 75; 
and section 2.1 of appendix B of part 75 are suspended temporarily from 
July 17, 1995 through December 31, 1996. Sections 75.11 (e) and (g), 
75.21(f), 75.30 (d) and (e), 75.32(a)(4), 75.55(e), and 75.56(a)(6); 
Figure 5 and sections 6.3.3, 6.3.4 and 6.4.1 of appendix A of part 75; 
section 2.1.7 of appendix B of part 75; and section 7 of appendix F of 
part 75 are temporarily added and are effective from July 17, 1995 
through December 31, 1996.
    Comment Date. Comments on this interim final rule must be received 
on or before June 16, 1995.

ADDRESSES: Any written comments on these interim final rule revisions 
must be identified with the Docket No. A-94-16, must be identified as 
comments on the interim final rule, and must be submitted in duplicate 
to: EPA Air Docket (6102), Environmental Protection Agency, 401 M 
Street SW, Washington, DC 20460. The docket is available for public 
inspection and copying between 8:30 a.m. and 3:30 p.m., Monday through 
Friday, at the address given above. A reasonable fee may be charged for 
copying.

FOR FURTHER INFORMATION CONTACT: Margaret Sheppard, Acid Rain Division 
(6204J), U.S. Environmental Protection Agency, 401 M Street SW, 
Washington, DC 20460, telephone number (202) 233-9180.

SUPPLEMENTARY INFORMATION: All public comments received on the interim 
final rule will be addressed in a subsequent final rulemaking notice. 
The EPA will not institute a second comment period on this document. 
Any parties interested in commenting on this interim final rule should 
do so at this time.
    For additional information about further revisions to the Acid Rain 
monitoring provisions, see the direct final rule published elsewhere in 
this Federal Register.
    The EPA intends to publish a final rulemaking document as a followup 
to this interim final rule prior to January 1, 1997 that will 
incorporate provisions based upon public comments. At that time, the 
sections that are added temporarily by this interim final rule would be 
permanently added by the follow-up final rule. Provisions that are 
suspended temporarily in this interim final rule would be removed in 
the follow-up final rule. If EPA were not to publish a follow-up final 
rule prior to January 1, 1997, the sections temporarily added by the 
interim final rule would expire and the sections suspended temporarily 
by the interim final rule would be effective January 1, 1997.

I. Background

    Title IV of the Clean Air Act (CAA or the Act), as amended November 
15, 1990, requires the Environmental Protection Agency (EPA or Agency) 
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). This notice of interim final rulemaking, like 
the notice of direct final rulemaking published elsewhere in this issue 
of the Federal Register, contains additional technical corrections and 
other amendments to address various implementation issues that have 
come to light since the final rule was published on January 11, 1993. 
The effective date of these interim final amendments will be July 17, 
1995.
    The EPA has been engaged in settlement discussions with several 
parties who challenged certain provisions of the Acid Rain CEM rules 
promulgated on January 11, 1993. [See Environmental Defense Fund v. 
Browner, No. 93-1203 and consolidated cases, ``Complex'' (D.C. Cir., 
filed March 12, 1993.] Although the parties have been able to reach 
agreement on a number of issues, which are addressed in the direct 
final rule, some additional issues remain outstanding. These 
outstanding issues, unlike the noncontroversial and routine technical 
corrections addressed by the direct final rule, may not be considered 
noncontroversial and therefore are being addressed separately in this 
interim final rule. The issues addressed by this interim final rule 
are: (1) A requirement that units with SO₂ CEMS burning gaseous 
fuels only must use heat input and a default SO₂ emission rate or 
appendix D methods to determine SO₂ emissions instead of an 
SO₂ CEMS and a flow monitor [Sec. 75.11(e)], (2) the procedure for 
assigning proportional flow rates for emissions through multiple stacks 
or bypass stacks for purposes of substituting missing data 
[Sec. 75.30(e)], (3) the procedure for determining proper operation of 
units with add-on controls for purposes of substituting missing data 
(Sec. 75.34), (4) clarification of provisions in the January 11, 1993 
rule that the unit must be operating while performing certain quality 
assurance procedures (appendix A, sections 6.3.1 and 6.3.2; appendix B, 
section 2.1 Introductory Text), and (5) the procedures for performing 
cycle time tests (appendix A, section 6.4).
    In order to allow for necessary changes to the data acquisition and 
handling systems (DAHS) required by the revisions to Secs. 75.11(e) and 
75.30(e), owners or operators may choose to delay compliance with the 
revised provisions regarding use of heat input and a default SO₂ 
emission rate or appendix D methods for units with SO₂ CEMS when 
burning only gaseous fuels [Sec. 75.11(e)] or with the procedure for 
assigning proportional flow rates for emissions through multiple stacks 
or bypass stacks for purposes of missing data substitution 
[Sec. 75.30(e)] until January 1, 1997. The EPA believes that this will 
give utilities time to comment [[Page 26561]] on these issues and EPA 
time to respond to these issues in a final rulemaking before the 
provisions become required. Furthermore, EPA believes an optional 
delayed compliance date for these revised provisions is warranted 
because utilities may need time to incorporate these changes into their 
DAHS, emissions will be monitored under the current regulations until 
the changeover, and emissions affected by these provisions will be 
small.
II. EPA Action

    Under CAA Section 412(c), not later than January 1, 1995, owners 
and operators of Acid Rain affected units must install and operate 
CEMS, quality assure the data, and keep records and reports in 
accordance with the Acid Rain regulations. Because EPA believes the 
revisions published in this rule will improve and enhance the 
implementation of the Acid Rain monitoring program, EPA believes it is 
necessary that the revisions become effective as soon as possible. Many 
of the monitoring provisions in part 75 are interrelated and would be 
difficult to separate from other, related provisions and therefore 
these technical revisions to the monitoring provisions must be 
considered as a whole. For these reasons, EPA is publishing the 
noncontroversial revisions through a direct final rulemaking and is 
also publishing provisions that may be controversial and on which it 
may receive comment through this interim final rulemaking. Both the 
direct final rule and the interim final rule will become effective on 
the same date. Even though comments may be submitted on these interim 
final provisions, EPA believes that it is necessary to include the 
interim final revisions in the revised CEM regulation in order to 
assure an overall consistent and implementable Acid Rain monitoring 
program. Therefore, EPA is issuing these amendments to the CEM 
regulation effective at the same time as the direct final amendments 
and will take comment on both sets of revisions. Comments on the 
interim final provisions must be submitted to Air Docket A-94-16, which 
is also the docket for the direct final rulemaking published elsewhere 
in this issue of the Federal Register, and must be identified as 
comments on the interim final rule to distinguish them from comments on 
the direct final provisions. Because the provisions of the direct final 
rule and interim final rule are interrelated, the docket contains 
supporting material and relevant information for both rulemakings.
    As described in the notice of direct final rulemaking, if EPA 
receives significant adverse comments on the direct final rule, EPA 
will withdraw those portions of the direct final rule upon which 
comments are submitted, address the comments, and subsequently issue a 
final rule that addresses the withdrawn portions of the direct final 
rule. Except for certain specified subsections which will cease to be 
in effect as of January 1, 1997, the interim final rule will remain in 
effect until EPA publishes a subsequent final rule, following 
consideration of comments received in response to the notice of 
proposed rulemaking corresponding to this interim final rule. At the 
time of that future rulemaking, sections that are temporarily added in 
today's interim final rule would be permanently added and would replace 
provisions in the current rule that are temporarily suspended.
    The EPA has been addressing many technical issues during early 
implementation of the Acid Rain monitoring program through issuance of 
policy statements interpreting the monitoring provisions of the January 
11, 1993 rule, as well as by issuance of technical guidance. Many of 
the clarifying policy statements and technical guidance, which are to a 
large extent reflected in the direct final rule and interim final rule, 
are now being used by utilities for implementation guidance. Therefore, 
EPA believes it would be contrary to the public interest to delay the 
effectiveness of these monitoring provisions and believes these 
technical revisions should be effective immediately. Because EPA 
believes it is necessary to issue the technical corrections to the CEMS 
regulation as soon as possible and because the revised portions of the 
monitoring provisions are integrally interrelated, EPA believes it 
necessary for the full complement of revisions to take effect at the 
same time. The EPA is therefore invoking the good cause exception under 
the Administrative Procedure Act (APA) in not providing an opportunity 
for comment before this interim final rule takes effect.<SUP>1 [See 5 
U.S.C. 553(b)(B); see also 42 U.S.C. 7607(d)(1).] Under CAA Section 
307(d)(1), subsection 307(d) does not apply in the case of a rule for 
which the agency invokes the good cause exception of 5 U.S.C. 
553(b)(B). Therefore, CAA Section 307(d) does not apply to this interim 
final rule. The EPA believes that notice-and-comment rulemaking prior 
to the effective date of the interim final rule would be impracticable 
and contrary to the public interest because of the complex and 
interrelated nature of the monitoring provisions that make it necessary 
to revise all of the CEM provisions in a consistent and integrated way 
in order to avoid inconsistency in monitoring requirements and because 
of the need to make the technical corrections and amendments available 
for use by utilities as soon as possible.

    \1\ As previously noted however, EPA is providing the public 
with an opportunity to comment on EPA's direct final rule and will 
withdraw any portions of the direct final rule upon which 
significant adverse comments are submitted.
III. Rationale

A. SO₂ Monitoring During Combustion of Gas for Units With SO₂ 
CEMS

    Some coal-fired units and oil-fired units also combust pipeline 
natural gas. Natural gas has a very low sulfur content and will produce 
extremely low SO₂ concentrations when combusted alone. In order to 
monitor these low concentrations accurately, a utility would need to 
use an SO₂ monitor with a range of a few parts per million (ppm). 
At this range, there are no Protocol 1 gases available for 
calibrations. Furthermore, it is unlikely that the CEMS would be able 
to pass the relative accuracy test at such low levels because it is 
difficult to measure extremely small concentrations precisely with 
either the reference method or a CEMS. The EPA had concerns about the 
accuracy of the SO₂ concentration data when measuring natural gas 
alone, because of the extremely low concentrations and because of the 
difficulty in performing appropriate quality assurance testing. The EPA 
decided that it was inappropriate for units to use an SO₂ CEMS to 
measure emissions from natural gas only. However, a coal-fired, oilfired, 
or gas-fired unit could still use an SO₂ CEMS for measuring 
SO₂ when combusting fuels other than natural gas (or other gaseous 
fuel with a sulfur content no greater than natural gas) or when 
combusting a combination of fuels.
    In order to address this situation, some industry representatives 
requested to use the provisions of appendix D of part 75 for 
determination of SO₂ emissions from natural gas instead of use of 
an SO₂ CEMS. (See Docket Item II-D-29, Letter from B. Machaver to 
S. Jewett, November 30, 1993; Docket Item II-D-30, Log of telephone 
conversation on Questions Concerning 40 CFR Part 75 Regulations for 
Oil/Gas Fired Title IV Affected Units (Questions provided in November 
30, 1993 Memorandum to Susan Jewett), December 7, 1993.) After 
consideration, EPA agreed that this [[Page 26562]] would be an 
acceptable alternative to using the SO₂ CEMS during combustion of 
low sulfur gaseous fuel, so long as the utility certifies an excepted 
monitoring system under appendix D of part 75 for the measuring of gas. 
This requires accuracy testing of a gas flowmeter and testing of the 
DAHS. Furthermore, the utility must perform the procedures under 
appendix D, with the same fuel sampling, analysis, and fuel flowmeter 
quality assurance/quality control (QA/QC) requirements.
    Another variant suggested by a utility was to use the default 
SO₂ emission rate factor of 0.0006 pound per million British 
thermal units (lb/mmBtu) for pipeline natural gas that EPA previously 
discussed in a policy statement regarding the ``NADB emission rate'' in 
appendix D and the heat input calculated by a flow monitor and a 
diluent monitor. (See Docket Item II-D-54, Acid Rain CEM (Part 75) 
Policy Manual; Docket Item II-D-59, Letter from R. LaBorde, Central 
Louisiana Electric Company to J. Winkler, EPA Region VI Re: Requestion 
for Clarification, Rodemacher Power Station Unit-1, Rapides Parish, LA, 
August 3, 1994). After further consideration, EPA agreed that this also 
is acceptable. (See Docket Item II-D-67, Response to R. LaBorde, CLECO, 
from J. Hepola, EPA, August 25, 1994.) The owner or operator must 
certify the system using the flow monitoring system, the diluent 
monitor, and the DAHS as a system for monitoring SO₂ emissions. 
These monitors must be tested following the QA/QC requirements of 
appendix B of part 75. Both of these methods allow utilities to use 
provisions that are allowed for estimating the low SO₂ emissions 
due to combustion of gaseous fuels with a low sulfur content under 
appendix D of part 75. The EPA believes that these methods will allow 
SO₂ accounting with sufficient accuracy for the low emission rate 
from combustion of natural gas. These methods are not sufficiently 
accurate for combustion of oil or coal because of their higher sulfur 
content. Similarly, during periods of co-firing of oil, coal or other 
high sulfur fuels, the owner or operator must use the certified 
SO₂ CEMS.

B. Missing Data Substitution Provisions

 Missing Data Procedures for Units With Add-On Emission Controls
    Many utilities were uncertain of the requirements for substituting 
and reporting missing data for units with add-on emission controls. For 
instance, the regulation was not clear as to whether or not parametric 
data needed to be reported and recorded for these units. Industry also 
commented that the possible options for substituting missing data were 
unclear for these units. (See Docket Item II-D-3, Discussion Issues for 
TU Electric and EPA; Docket Item II-D-4, Draft Meeting Notes for EPATexas 
Utilities Teleconference, December 7, 1992 ). In response to 
these concerns, EPA prepared a policy statement to clarify missing data 
substitution procedures for units with add-on emission controls. (See 
Docket Item II-D-54, Acid Rain CEM (Part 75) Policy Manual). The EPA 
has amended part 75 in part to incorporate these interpretations.
    The amendments to part 75 allow four ways of substituting for 
missing data. The default option is to substitute the maximum potential 
concentration of SO₂ or the maximum potential NO_Xemission 
rate when no information on the emission controls is available. A unit 
with SO₂ add-on emission controls with an inlet monitor may 
instead use the maximum SO₂ concentration at the scrubber inlet 
during the previous 720 quality-assured monitor operating hours. This 
option may always be used by a source.
    Another option is to develop a site-specific correlation to 
determine the removal efficiency of the control equipment. The 
designated representative for a unit will petition the Administrator 
for use of this correlation instead of following standard missing data 
substitution procedures. The requirements for using this correlation as 
a missing data substitution method are located in appendix C of part 
 The correlation involves monitoring emission control parameters and 
electronically reporting this data for each missing data period to EPA 
each quarter. This correlation method may only be used if the 
availability or the CEMS at the outlet of the emission controls is 90.0 
percent or greater.
    A third option is to use the standard missing data procedures and 
to keep information on the emission controls at the site. The 
parameters listed in appendix C are a guideline of the types of 
information that are to be used to verify the add-on emission controls 
are operating properly. The EPA considers ``proper operation'' of the 
control equipment to require that the removal efficiency is equal to or 
greater than that when monitor data is available, such as during the 
hours before and after the missing data period. It is not enough to 
show that the control device simply is operating. The information that 
a utility should keep relates to site-specific equipment. Part 75 does 
not require that every single one of those parameters must be kept, nor 
does it prohibit the use of other information to verify proper 
operation of the emission controls. Also, these records do not have to 
be kept electronically. However, the designated representative must 
report in the monitoring plan for the unit the range of each parameter 
that indicates proper operation of the add-on emission controls. The 
EPA or a State air pollution control agency could request to look at 
the parametric records or to have them reported at any time to verify 
that the add-on emission controls are maintaining emission reductions 
and are operating properly, by comparing the data with the range of 
each parameter reported in the monitoring plan. In addition, a 
designated representative for a source must certify that the emission 
controls are properly operating and that the missing data procedures 
are not systematically underestimating emissions during the quarter 
where the utility uses the standard missing data procedures. This 
additional certification is to be reported as part of the designated 
representative's certification with each quarterly report.
    The fourth and final option for supplying missing data is to use 
the standard missing data procedures as in the third option, and then 
to petition the Administrator for use of a value more representative of 
actual emissions than the maximum SO₂ concentration in the 
previous 720 hours or the maximum NO_Xemission rate at the 
corresponding load range. As in the existing rule, this is only an 
option when monitor data availability is below 90.0 percent, where the 
most conservative missing data substitution procedures are required. A 
designated representative may petition to substitute with a more 
representative value that does not underestimate emissions if 
sufficient data exist to demonstrate that the maximum value is an 
extreme overestimate, based upon periods of improper operation or nonoperation 
of the emission controls. This demonstration requires 
information such as: CEM data from periods when the add-on emission 
controls are operating; unit operating load data; parametric data 
indicating proper operation of the add-on emission controls during the 
missing data period; and fuel sulfur content. The EPA expects a 
``representative value'' to be no less than the maximum hourly value 
from when the emission controls were operating during the same lookback 
period normally used for an SO₂ or NO_XCEMS.
    The EPA has also made minor changes to indicate that petitions are 
submitted by the designated [[Page 26563]] representative, rather than 
the owner or operator. This is consistent with the designated 
representative's role as the official contact person for EPA for all 
submissions.
 SO₂ Concentration Missing Data During Gas Combustion
    A utility noted that for a unit that combusts either natural gas 
and some oil or natural gas and some coal, SO₂ emissions due to 
gas combustion are several orders of magnitude smaller than emissions 
during combustion of either coal or oil (See II-D-16, Letter from David 
Rengert, Niagara Mohawk Power Corporation to Ann Zownir, EPA, May 21, 
1993). Therefore, if an SO₂ CEMS was not providing quality-assured 
data when the unit was combusting only natural gas, the standard 
missing data procedures might substitute vastly overestimate SO₂ 
concentration values from combustion of coal or oil. In addition, if 
the unit combusts primarily natural gas, these low SO₂ 
concentration values could potentially underestimate emissions when 
combusting oil or coal if the 90th percentile and 95th percentile (and 
possibly even the maximum value) during the previous 720 qualityassured 
monitor operating hours were substituted using all data 
collected from all fuels. To address this concern, EPA revised the 
missing data procedures to separate SO₂ emissions due to 
combustion of natural gas and other gaseous fuels with a sulfur content 
no greater than that of natural gas. SO₂ concentration values 
measured by an SO₂ monitoring system during combustion of natural 
gas only are not kept as part of the historical data that is used to 
substitute SO₂ concentration data. These values are not used to 
provide the average of the hour before and the hour after a missing 
data period and are not included in percentile calculations. As a 
result, substituted missing data will reflect the fuel being used 
during the missing data period.
    As was discussed under Section A above, as of January 1, 1997, 
SO₂ CEMS will no longer be allowed for measuring SO₂ during 
combustion of natural gas or other gaseous fuels with a sulfur content 
no greater than that of natural gas because of the difficulty of 
accurately measuring and quality assurance testing at such low 
concentrations.
    During those times, a utility will either use the heat input from 
the flow monitor and diluent monitor and the default SO₂ emission 
rate for pipeline natural gas of 0.0006 lb/mmBtu according to appendix 
F of part 75, or the fuel flow and daily sulfur content of the gaseous 
fuel according to appendix D of part 75. The utility should use the 
following to fill in missing data if a fuel flowmeter, a flow monitor 
or a diluent monitor is not providing quality-assured data. For units 
combusting pipeline natural gas using a flow monitor, a diluent monitor 
and the default SO₂ emission rate, the owner or operator should 
follow the missing data procedures for heat input found in Sec. 75.36 
of subpart D of part 75. For other units using gas sampling and 
analysis and fuel flowmeters, the owner or operator should substitute 
using the missing data procedures for sulfur content or fuel flow found 
in appendix D of part 75.
    Note that these revised procedures are not needed if a unit is cofiring 
a high sulfur fuel along with natural gas or other gaseous fuels 
with a sulfur content no greater than that of natural gas. In this 
case, the concentration will come predominantly from the higher-sulfur 
fuel, generally oil or coal. Thus, during periods of co-firing, the 
owner or operator should be using the SO₂ CEMS or the missing data 
procedures in Secs. 75.31 or 75.33 for an SO₂ CEMS.
 Missing Data for Multiple Stacks and Bypass Stacks
    The EPA has added a provision to account for missing data 
substitution of flow data in the case of multiple stacks or bypass 
stacks in Sec. 75.30(e) of today's interim final rule. First, this 
revision accounts for the fact that emissions may not flow through a 
particular stack during an hour when the unit combusts fuel. To account 
for this, EPA has added a provision to the missing data procedures such 
that only hours when emissions pass by the monitors on the stack are 
included as unit operating hours and as quality-assured monitor 
operating hours in calculations of availability and substitute values.
    A second provision accounts for the fact that some units may be 
able to shift flow between ducts or stacks. If flow from a unit can 
shift from one stack to another, such as when flue dampers are moved, 
then the correlation between load for the entire unit and flow rate 
measured on one stack is no longer accurate. It would be possible to 
underestimate flow rate and SO₂ mass emissions during use of the 
missing data procedures for flow, contrary to EPA's intent for these 
missing data procedures. In order to avoid this situation, EPA has 
added a provision in today's rule that requires using a substitute 
value of the maximum flow rate recorded by the flow monitoring system 
at the corresponding load range during the previous 2,160 hours of 
quality-assured monitor data when emissions passed through the stack if 
the proportion of flow between stacks has changed during that time. 
This will avoid potential underestimation that might occur when using 
an average flow rate in the corresponding load range. As discussed 
above in this notice, owners or operators may choose to delay 
compliance with this requirement until January 1, 1997 in order to make 
changes to their DAHS and to await implementation of these provisions 
until after EPA has addressed all comments on the interim final rule. 
In addition, EPA notes that if a utility never changes the flue dampers 
so that the proportion of flow is constant, then no changes to the 
standard missing data procedures or to their DAHS are necessary.

C. Certification and Quality Assurance Testing

 Calibration Error Test
    The EPA discovered that some CEMS testers were incorrectly 
performing the 7-day calibration error test. In the incorrect use of 
the procedure, the tester checked the calibration error at the zero 
calibration gas level, made automatic adjustments to the monitor data 
at that point, checked the calibration error at the high calibration 
gas level, and then again made adjustments to the data. The EPA 
clarified that a tester should check the calibration error both at the 
zero level and the high level before making any adjustments. Both in 
the preamble to part 75 (January 11, 1993) and in a public issue paper 
on the 7-day calibration error test, EPA stated that this second 
interpretation is the correct one. (See Docket Item II-D-27, Issue 
Paper on Part 75 Calibration Error Testing for Certification, October 
8, 1993; Letter from J. White to D. McNeal, and Response to J. White 
from S. Saile, EPA). The EPA has adopted this interpretation of testing 
both instrument levels together because instrument errors at the zero 
and high levels are not always independent of each other. These interim 
amendments to part 75 clarify this provision.
    Another related issue associated with the 7-day calibration error 
test concerned the kinds of adjustments that could be made. 
Requirements of the calibration error tests in 40 CFR part 75 and 40 
CFR part 60 could be interpreted as requiring either 7 successive daily 
tests or one cumulative 7-day test. The following statements in the 
January 11, 1993 rule imply that the 7-day test is cumulative:


    Do not make manual adjustments to the monitor setting during the 
7-day test. If automatic adjustments are made, conduct the 
calibration error test in a way that the [[Page 26564]] magnitude of 
the adjustments can be determined and recorded. (section 6.3.1 of 
appendix A.)

    However, EPA stated in Section V.G(4)(a) of its January 11, 1993 
preamble to part 75 that ``the 7-day calibration error test performed 
during certification is the same 2-point drift test as the daily 
calibration error test'' and referred to 40 CFR part 60, appendix B in 
Section V.G(4)(b) (58 FR 3641). Industry generally interprets the 
calibration drift test in 40 CFR part 60 to require 7 separate daily 
tests, rather than a cumulative test over 7 days. (See Docket Item I-C-
3, Jahnke, James A., Excerpt from Continuous Emission Monitoring, Van 
Nostrand Reinhold, New York.) The EPA now clarifies part 75 to state 
its original intention that the 7-day calibration error test is a 
series of 7 daily calibration error tests. On each day of the test, the 
monitor must meet the performance specification of a calibration error 
no greater than 2.5 percent of span. Because this is a series of tests, 
a tester may not adjust the monitor or monitor data, either manually or 
automatically, until the test has been completed at both levels on any 
given day. However, the tester may make adjustments between daily 
tests, once the previous day's test results have been recorded.
2. Quality Assurance of Data Following Daily Calibration Error Test
    During early implementation EPA began developing a series of 
policies in order to assist in its evaluation of the acceptability of 
data received in quarterly reports. Among these policies concerned the 
acceptability of data when a required daily test is not performed. The 
Agency initially decided that the absence of information on a test 
during a calendar day means that emissions data for that day are not 
considered quality-assured. Section 2.1 of appendix B requires daily 
assessments, such as calibration error tests and interference checks, 
to be performed on each calendar day. Based on this requirement, EPA 
initially interpreted data as invalid for a calendar day from midnight 
to the time of the next successful daily calibration error test if no 
test results were reported. (See Docket Items II-D-56, ETS User 
Bulletin #2 and II-D-50, Electronic Data Reporting Supplementary 
Instructions, June 29, 1994.)
    Some utilities expressed concern that a unit might stop operating 
during the middle of a day before the regularly scheduled time for 
performing an automated calibration. (See Docket Item II-D-60, Letter 
from Gary R. Cline, Pennsylvania Electric Co., to Margaret Sheppard, 
EPA, August 1, 1994.) Because the testing procedures require the unit 
to operate during all measurements, the utility would be unable to 
perform this test and its data would be invalidated beginning at 
midnight. Some suggestions from utilities included: allowing 
performance of the test while the unit is off-line, treating the data 
as quality assured until the time of the next test, and treating the 
data as quality-assured prospectively for 24 hours from the previous 
test.
    The EPA decided that the approach consistent with the regulatory 
language that would result in the greatest amount of quality-assured 
data while still preserving the requirement for a daily test is to 
retain the calendar day requirement for performing each daily test. 
However, if a unit stops operating during a calendar day, then data is 
still considered quality-assured for 24 clock hours from the previous 
day's test. For example, a unit with monitors that are normally 
calibrated at 8 a.m. performs the calibration error test at 8 a.m. on 
January 11. All 24 hours of data from the monitor for January 11 are 
quality-assured. If the unit suddenly ``trips'' and stops operating at 
6 a.m. on January 12, the data from midnight until 6 a.m. are also 
considered quality-assured. If the unit starts up again at 3 p.m. but 
the monitors are not tested between 3 p.m. and midnight, then that 
block of data is invalidated. As in the January 11, 1993 rule, today's 
rule still requires a calibration error test to be performed with the 
unit operating. This is because the readings from the CEMS are affected 
by temperature and pressure conditions. (See Docket Item II-D-39, Log 
of telephone conversation between Jon Konings, WEPCo, and M. Sheppard, 
EPA, on EPA's policy on conducting calibration error test, April 13, 
1994.) In order to ensure accurate CEMS measurements for the entire 
system and to ensure that this test is performed under controlled 
conditions, EPA requires the daily calibration error tests to be 
performed while the unit is operating for purposes of quality-assuring 
the data and testing the CEMS. (See Docket Item II-D-54, Acid Rain CEM 
(Part 75) Policy Manual.)
3. Unit Operation During Testing
    This issue is related to provisions of section 6 of appendix A of 
part 75 and to the tests performed under appendix B of part 75. Under 
the January 11, 1993 rule, section 6.1 of appendix A requires that a 
unit be operated during periods when measurements are made for 
certification testing. Similarly, section 6.2 indicates that when 
performing a linearity check, testers are to conduct each test by 
operating the monitor at its normal (unit) operating temperature and 
conditions. In this interim rule, EPA further clarifies provisions in 
the January 11, 1993 rule, providing that the unit must be operating, 
by adding language to sections 6.3.1, 6.3.2, and 6.4 for the 
calibration error test and for the cycle time test. These sections are 
later cited in appendix B. This language addition clarifies EPA's 
intent that a unit must be operating during all monitor testing, both 
for initial certification testing and for QA/QC testing.
    During the public comment period for the proposed part 75 
regulation, some commenters raised this issue. (See Docket A-90-51, 
Docket Item IV-D-303, Letter from Nicolson, Rober J., Vice President, 
Fossil & Hydro Operations, Consumers Power Company, Comments on Clean 
Air Act Amendments--Title IV Part 75 Continuous Emission Monitoring 
Rule and Docket A-91-69, Item IV-D-66, Letter from Sullivan, J.J., 
Executive Director, Environmental Programs, PSI Energy, Inc., Comments 
on the Proposed Acid Rain Program Rule: 40 CFR Part 72, 73, 75 and 77.) 
Under the new source performance standard for subpart Da of 40 CFR part 
60 and under the performance specifications in appendix B of 40 part 
60, EPA required a unit to operate for 168 hours in a row in order to 
perform the 7-day calibration error test for monitors. In part 75, EPA 
modified this to allow units to operate only during the periods when 
measurements were performed and by allowing operation on nonconsecutive 
days. This change was made to account for peaking units, which normally 
would not operate for every hour of every day. However, EPA still 
required the unit to be operating during testing so that the test will 
be performed under the same temperature and pressure conditions as when 
monitor readings are taken during the program. (See Docket A-90-69, 
Docket Items V-C-1 and V-C-2, Response to Comment Document.)
    The test procedures for linearity checks and for calibration error 
tests require the entire monitoring system to be tested, rather than 
just the analyzer. For example, sections 6.2 and 6.3.1 of appendix A 
requires introducing calibration gas through the gas injection port, 
which for most systems will be at the probe. The calibration gas must 
go through as much of the system as possible, including the probe, 
filters, scrubbers, conditioners, and other monitor components for 
extractive type monitoring systems, or including all active electronic 
and optical components for in situ type monitors. 
[[Page 26565]] Monitor responses must come from the DAHS. Thus, the 
test is a test of the complete continuous emission monitoring system. 
(See Docket Item II-D-68, Memorandum from B. Warren-Hicks, The Cadmus 
Group to M. Sheppard, EPA, September 6, 1994). In order to make the 
linearity check and calibration error test a true test of the entire 
monitoring system, the tests must be performed under the same unit 
operating conditions that prevail when the monitor reads emissions to 
include in certification test results and in quarterly emissions 
reports. The EPA has already stated this policy in question Number 
12.17 of its policy guidance manual. (See Docket Item II-D-54, Acid 
Rain CEM (Part 75) Policy Manual.) Utilities have also commented on the 
significant effects of temperature and pressure conditions upon monitor 
readings. (See Docket Items II-D-39, Conversation between J. Konings, 
WEPCo and M. Sheppard, EPA:ARD, on EPA's policy on conducting 
calibration error test, April 13, 1994; II-D-40, Meeting Notes from EPA 
Meeting with J. West of Metropolitan Edison and J. Jahnke of Source 
Technology Associates, April 18, 1994.).
    The procedures of the relative accuracy test and the cycle time 
test require continuous emission monitoring systems and flow monitors 
to measure the actual emissions at the stack. Therefore, these tests 
can only be performed while the unit is operating.
    The EPA does not consider test results to be valid if the test is 
performed while the unit is not operating.
    Thus, in this interim rule, EPA clarifies that a unit must be 
operating when a test is performed in order to provide acceptable 
results to meet requirements for certification testing or QA/QC 
testing. This is also consistent in a new provision in section 2.1 of 
appendix B of part 75. This provision allows data to be considered 
valid for 24 hours following the last passed calibration error test if 
a unit stops operating on a calendar day before the utility has 
performed a calibration error test on that day. However, if a daily 
calibration error test were failed or if the daily calibration error 
test were performed while the unit is not operating, the data after 
that test would not be considered valid.
4. Cycle Time Test
    Part 75 included a cycle time/response time test to determine if a 
CEMS was capable of drawing down and analyzing a sample frequently 
enough to provide an update at least four times an hour. A tester was 
required to perform this test on the SO₂ pollutant concentration 
monitor, the NO_XCEMS (in lb/mmBtu), and the CO<INF>2 pollutant 
concentration monitor. Some testers found the regulatory procedures 
unclear as to when a source tester samples stack gas. In addition, EPA 
staff realized that some CEMS cannot perform the cycle time/response 
time test simultaneously on the NO_Xand diluent gas components of 
the NO_XCEMS, because NO_Xand O<INF>2 cannot be kept in the 
same bottle for reasons of stability.
    As a result of these issues raised during implementation, EPA has 
revised the cycle time/response time test to be a cycle time test 
patterned after the response time test in Method 20 of appendix A of 40 
CFR part 60. A cycle time test is a test to determine the length of 
time it takes for a CEM system to draw down a sample of gas, analyze 
the sample, achieve a stable reading, and record the new concentration. 
More specifically, the cycle time test determines 95 percent of the 
length of time for the monitor to go from reading a known concentration 
of calibration gas to reading actual stack emissions. (The 95-percent 
margin allows for small amounts of error that will prevent a monitor 
from reading the labelled value of a calibration gas, even when the 
monitor reading is stable.) A tester starts by introducing calibration 
gas until the monitor reading is stable. Next, the tester switches the 
monitor to reading stack gas emissions. When the monitor response is 
stable, the tester notes the time. The DAHS records each value that the 
monitor reads and the time of the reading. Once the DAHS has recorded 
this stable value, the tester introduces the other calibration gas. The 
procedure is repeated, so that the monitor returns to a stable reading 
of stack gas and records it. This revised procedure will allow more 
time-share monitoring systems to pass the cycle time test than the 
earlier cycle time/response time test, because the revised test 
eliminates the time it takes for gas to travel from the calibration gas 
cylinder to the probe.
    Stability is considered to be achieved when the monitor reading 
changes by less than 5 percent from the average concentration over a 5-
minute period, or less than 1 percent of the monitor span over 30 
seconds. These values were adapted from the response time test found in 
Method 20 of appendix A, 40 CFR part 60 for testing of stationary gas 
turbines. The EPA made the definition of stability more flexible by 
lengthening the time period for averaging concentration from 2 minutes 
to 5 minutes, in order to apply to coal-fired boilers, which may 
experience less stable loads than stationary gas turbines. Based upon 
results from certification tests at Phase I units, EPA believes that 
coal-fired units can reliably achieve this definition of stability. 
(See Docket Item II-D-75, Analysis of Cycle Time/Response Time Data, 
October 3, 1994.)
    The longer of the two times going from calibration gas to stack gas 
is the cycle time of the component monitor. For a NO_Xor SO₂-
diluent monitoring system, the cycle time is the longer of the two 
cycle times for the NO_Xor SO₂ pollutant concentration 
monitor and the diluent monitor. Originally, testers were required to 
test both component monitors at the same time, which requires injecting 
both gases simultaneously. Testing the two component monitors 
separately simplifies performing the cycle time test, since calibration 
gases do not need to be injected simultaneously. This also resolves the 
issues raised during certification testing for Phase I units. In 
addition, the revision provides consistency with existing EPA 
regulations under 40 CFR part 60.
    The EPA has included recordkeeping provisions for this 
certification test in Sec. 75.56. Furthermore, the rule amendments 
contain an additional figure at the end of appendix A, to complement 
the figures for test data and results for other certification tests for 
CEMS.

IV. Impact Analyses

    The impact analyses required by Executive Orders 12866 and 12875 
and by the Regulatory Flexibility Act, the Unfunded Mandates Act and 
the Paperwork Reduction Act are found under the notice of direct final 
rulemaking in today's Federal Register.
    The control numbers assigned to collections of information in 
certain EPA regulations by the OMB have been consolidated under 40 CFR 
part 9. The EPA finds there is ``good cause'' under Sections 553(b)(B) 
and 553(d)(3) of the APA to amend the applicable table in 40 CFR part 9 
to display the OMB control number for this rule without prior notice 
and comment. Due to the technical nature of the table, further notice 
and comment would be unnecessary. For additional information, see 58 FR 
18014, April 7, 1993, and 58 FR 27472, May 10, 1993.
List of Subjects in 40 CFR Parts 75

    Environmental protection, Air pollution control, Carbon dioxide, 
Continuous emission monitors, Electric utilities, Incorporation by 
reference, Nitrogen oxides, Reporting and recordkeeping requirements, 
Sulfur dioxide.

    [[Page 26566]] Dated: April 28, 1995.
Carol M. Browner,
Administrator.

    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.-3. The authority citation for part 75 is revised to read as 
follows:

    Authority: 42 U.S.C. 7601 and 7651k.

    4. Section 75.11 is amended by adding a sentence to the end of 
paragraph (a) and by adding paragraphs (e) and (g) to read as follows:


Sec. 75.11  Specific provisions for monitoring SO₂ emissions 
(SO₂ and flow monitors).

    (a) * * * The provisions in this paragraph are suspended from July 
17, 1995 through December 31, 1996.

 * * * *
    (e) Units with SO₂ continuous emission monitoring systems 
during the combustion of gaseous fuel. On or after January 1, 1997, the 
owner or operator of a unit with an SO₂ continuous emission 
monitoring system shall, during any hours in which the unit combusts 
only pipeline natural gas or gaseous fuel with a sulfur content no 
greater than natural gas, calculate SO₂ emissions in accordance 
with the following procedures. Prior to January 1, 1997, the owner or 
operator of such a unit may calculate SO₂ emissions in accordance 
with the following procedures.
    (1) The owner or operator of a unit with an SO₂ continuous 
emission monitoring system shall, during any hours in which the unit 
combusts only pipeline natural gas, calculate SO₂ emissions using 
one of the following two methods in lieu of operating and recording 
data from the SO₂ continuous emission monitoring system:
    (i) By using the heat input calculated using a certified flow 
monitoring system and a certified diluent monitor, the default SO₂ 
emission rate for pipeline natural gas from appendix D of this part, 
and Equation F-23 in appendix F of this part and by certifying this as 
a system for monitoring SO₂ mass emissions by identification in 
the monitoring plan, by tests for the data acquisition and handling 
system under Sec. 75.20(c), and by meeting all quality control and 
quality assurance requirements in appendix B of this part for a flow 
monitor and a diluent monitor; or
    (ii) By certifying an excepted monitoring system under appendix D 
of this part under Sec. 75.20, by following the procedures for 
determining SO₂ emissions from combustion of gaseous fuels under 
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.
    (2) During any hours in which the unit combusts only gaseous fuel 
with a sulfur content no greater than natural gas other than pipeline 
natural gas, the owner or operator shall calculate SO₂ mass 
emissions by certifying an excepted monitoring system under appendix D 
of this part under Sec. 75.20, by using the gas sampling and analysis 
and fuel flow procedures 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.
 * * * *
    (g) 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 or any fuel 
other than natural gas or a gaseous fuel with a sulfur content no 
greater than natural gas, except as provided in Sec. 75.16 and in 
subpart E of this part.
 Section 75.21 is amended by adding a sentence to the end of 
paragraph (a) and by adding paragraph (f) to read as follows:

Sec. 75.21  Quality assurance and quality control requirements.

    (a) * * * The provisions in this paragraph are suspended from July 
17, 1995 through December 31, 1996.

 * * * *
    (f) Continuous emission monitoring systems. The owner or operator 
of an affected unit shall operate, calibrate, and maintain each primary 
and redundant backup continuous emission monitoring system used under 
the Acid Rain Program according to the quality assurance and quality 
control procedures in appendix B of this part. The owner or operator of 
an affected unit shall ensure that each non-redundant backup continuous 
emission monitoring system used under the Acid Rain Program 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. 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, instead of the procedures specified in 
appendix B of this part. Notwithstanding the provisions of appendix B 
of this part, the owner or operator of a unit with an SO₂ 
continuous emission monitoring system is not required to perform daily 
or quarterly assessments under appendix B of this part on any day or in 
any calendar quarter during which the unit combusts only natural gas or 
a gaseous fuel with a sulfur content no greater than natural gas. In 
addition, any calendar quarter during which the unit combusts only 
natural gas or a gaseous fuel 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 
continuous emission monitoring system, provided that a relative 
accuracy test audit is performed on that system at least once every two 
calendar years. The owner or operator of a unit using a certified flow 
monitor and a certified diluent monitor and Equation F-23 to calculate 
SO₂ emissions shall meet all quality control and quality assurance 
requirements in appendix B of this part for the flow monitor and the 
diluent monitor.
 Section 75.30 is amended by adding paragraphs (d) and (e) to 
read as follows:

Sec. 75.30  General provisions.

 * * * *
    (d) On or after January 1, 1997, the owner or operator shall comply 
with the provisions of this paragraph. Prior to January 1, 1997, the 
owner or operator may comply with the provisions of this paragraph (d) 
if also complying with the provisions of Sec. 75.11(e).
    (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), the owner 
or operator shall substitute for missing data from a flow monitoring 
system, CO<INF>2 diluent monitor or O<INF>2 diluent monitor using the 
missing data substitution procedures in Sec. 75.36.
    (2) Whenever a unit with an SO₂ continuous emission monitoring 
system combusts gas with a sulfur content no greater than natural gas 
or pipeline natural gas and the owner or operator is using 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), 
the owner or operator shall substitute for [[Page 26567]] missing data 
using the missing data procedures in appendix D of this part.
    (3) The owner or operator shall not use historical data from an 
SO₂ pollutant concentration monitor to account for SO₂ 
emissions due to combustion of gas during missing data periods. In 
addition, the owner or operator 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 availability calculations in 
Sec. 75.32, nor in the calculations of substitute data using the 
procedures of either Sec. 75.31 or Sec. 75.33. 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.''
    (e) On or after January 1, 1997, the owner or operator shall comply 
with the provisions of this paragraph. Prior to January 1, 1997, the 
owner or operator may comply with the provisions of this paragraph.
    (1) For monitoring of emissions at a unit with multiple stacks or a 
bypass stack, include only those hours when emissions are passing 
through the stack or duct in the definitions of ``unit operating hour'' 
and ``quality-assured monitor operating hour'' for purposes of applying 
the missing data and availability procedures in Secs. 75.31 through 
75.36 to the monitoring system on that stack or duct.
    (2) If the proportion of flow going to each stack from a unit with 
multiple stacks or the proportion of flow going to a bypass stack has 
changed during the previous 2,160 hours when emissions passed through 
that stack, then record the maximum flow rate recorded by the flow 
monitoring system at the corresponding load range during the previous 
2,160 hours of quality-assured monitor data when emissions passed 
through that stack, instead of the value calculated using the missing 
data substitution procedures in Sec. 75.31 or Sec. 75.33.
 Section 75.32 is amended by adding a sentence to the end of 
paragraph (a)(3) and adding paragraph (a)(4) to read as follows:



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

    (a) * * *
    (3) * * * The provisions in this paragraph (a)(3) are suspended 
from July 17, 1995 through December 31, 1996.
    (4) 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 nonredundant 
backup monitor, a reference method for that unit, and from an 
approved alternative monitoring system under subpart E of this part 
when calculating percent monitor data availability using Equation 8 or 
9. The owner or operator shall exclude hours when a unit combusted only 
natural gas (or gaseous fuel with the same sulfur content as natural 
gas) from calculations of percent monitor data availability for 
SO₂ pollutant concentration monitors, as provided in 
Sec. 75.30(d). No hours from more than three years (26,280 clock hours) 
earlier shall be used in Equation 8 or 9. When three years from 
certification have elapsed, replace the words ``since certification'' 
or ``during previous 8,760 unit operating hours'' with ``in the 
previous three years'' and replace ``8,760'' with ``total unit 
operating hours in the previous three years.''

 * * * *
 Section 75.34 is revised 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 NO_Xemission controls shall use at least one of 
the following options:
    (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 for substituting data for each hour where the add-on emission 
controls are operating within the proper operation range specified in 
the monitoring plan for the unit. The designated representative shall 
report the range of add-on emission control operating parameters that 
indicate proper operation in the unit's monitoring plan and the owner 
or operator shall record data to verify the proper operation of the 
SO₂ or NO_Xadd-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 NO_Xadd-on 
emission control for each missing data period at the end of each 
quarter.
    (2) In addition, 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 monitoring plan) 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 NO_Xemission 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. 75.51(b) until 
January 1, 1996, or 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 Sec. 75.31, Sec. 75.33, or Sec. 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 monitoring 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.
    (2) Where the monitor data availability for an outlet SO₂ 
pollutant concentration monitor is less than 90.0 percent, the owner or 
operator shall calculate substitute data using the procedures in 
Sec. 75.34(a) (1) or (2), even if the Administrator has approved a 
parametric monitoring procedure.
    (c) For an affected unit with NO_Xadd-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 NO_Xemission rate 
[[Page 26568]] data for missing data periods. The owner or operator 
shall use the procedures in Sec. 75.31 or Sec. 75.33 for providing 
substitute data for missing NO_Xemission rate data prior to 
receiving the Administrator's approval for a parametric monitoring 
procedure.
    (1) Where monitor data availability for a NO_Xcontinuous 
emission monitoring system is 90.0 percent or more, the owner or 
operator may calculate substitute data using an approved parametric 
monitoring procedure.
    (2) Where monitor data availability for a NO_Xcontinuous 
emission monitoring system is less than 90.0 percent, the owner or 
operator shall calculate substitute data using the procedure in 
Sec. 75.34(a) (1) or (2), even if the Administrator has approved 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 NO_Xemission controls during all periods of 
missing data. The owner or operator shall provide these records to the 
Administrator or to the EPA Regional Office upon request. Whenever such 
records are not provided or such records do not demonstrate that proper 
operation of the SO₂ or NO_Xadd-on emission controls has been 
maintained in accordance with the range of add-on emission control 
operating parameters reported in the monitoring plan for the unit, the 
owner or operator shall substitute the maximum potential NO_X
emission rate, as defined in Sec. 72.2 of this chapter, to report the 
NO_Xemission 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 NO_Xemission controls is available.
    9. Section 75.53 is amended by revising paragraph (d) introductory 
text and by adding 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 or for units with add-on emission 
controls:
 * * * *
    (4) For each unit with add-on emission controls:
    (i) A list of operating parameters for the add-on emission 
controls, including parameters from the list in Sec. 75.55 appropriate 
to the particular installation; and
    (ii) The range of each operating parameter in the list that 
indicates the add-on emission controls are properly operating.
 * * * *
 Section 75.55 is amended by adding paragraphs (b) and (e) to 
read as follows:



Sec. 75.55  General recordkeeping provisions for specific situations.

    (a) * * *
    (b) Specific parametric data record provisions for calculating 
substitute emissions data for units with add-on emission controls. In 
accordance with Sec. 75.34, the owner or operator of an affected unit 
with add-on emission controls shall either record the applicable 
information in paragraph (b)(3) of this section for each hour of 
missing SO₂ concentration data or NO_Xemission rate (in 
addition to other information), or shall record the information in 
paragraph (b)(1) of this section for SO₂ or paragraph (b)(2) of 
this section for NO_Xthrough an automated data acquisition and 
handling system, as appropriate to the type of add-on emission 
controls:
    (1) For units with add-on SO₂ emission controls petitioning to 
use or using the optional parametric monitoring procedures in appendix 
C of this part, for each hour of missing SO₂ concentration or 
volumetric flow data:
    (i) The information required in Sec. 75.54(b) for SO₂ 
concentration and volumetric flow if either one of these monitors is 
still operating;
    (ii) Date and hour;
    (iii) Number of operating scrubber modules;
    (iv) Total feedrate of slurry to each operating scrubber module 
(gal/min);
    (v) Pressure differential across each operating scrubber module 
(inches of water column);
    (vi) For a unit with a wet flue gas desulfurization system, an 
inline measure of absorber pH for each operating scrubber module;
    (vii) For a unit with a dry flue gas desulfurization system, the 
inlet and outlet temperatures across each operating scrubber module;
    (viii) For a unit with a wet flue gas desulfurization system, the 
percent solids in slurry for each scrubber module.
    (ix) For a unit with a dry flue gas desulfurization system, the 
slurry feed rate (gal/min) to the atomizer nozzle;
    (x) For a unit with SO₂ add-on emission controls other than 
wet or dry limestone, corresponding parameters approved by the 
Administrator;
    (xi) Method of determination of SO₂ concentration and 
volumetric flow, using Codes 1-15 in Table 3 of Sec. 75.54; and
    (xii) Inlet and outlet SO₂ concentration values recorded by an 
SO₂ continuous emission monitoring system and the removal 
efficiency of the add-on emission controls.
    (2) For units with add-on NO_Xemission controls petitioning to 
use or using the optional parametric monitoring procedures in appendix 
C of this part, for each hour of missing NO_Xemission rate data:
    (i) Date and hour;
    (ii) Inlet air flow rate (acfh, rounded to the nearest thousand);
    (iii) Excess O<INF>2 concentration of flue gas at stack outlet 
(percent, rounded to nearest tenth of a percent);
    (iv) Carbon monoxide concentration of flue gas at stack outlet 
(ppm, rounded to the nearest tenth);
    (v) Temperature of flue gas at furnace exit or economizer outlet 
duct ( deg.F); and
    (vi) Other parameters specific to NO_Xemission controls (e.g., 
average hourly reagent feedrate);
    (vii) Method of determination of NO_Xemission rate using Codes 
1-15 in Table 3 of Sec. 75.54; and
    (viii) Inlet and outlet NO_Xemission rate values recorded by a 
NO_Xcontinuous emission monitoring system and the removal 
efficiency of the add-on emission controls.
    (3) For units with add-on SO₂ or NO_Xemission controls 
following the provisions of Sec. 75.34(a) (1) or (2), for each hour of 
missing data record:
    (i) Parametric data which demonstrate the proper operation of the 
add-on emission controls, as described in the monitoring plan for the 
unit (to be maintained on site, and to be submitted upon request from 
the Administrator or by an EPA Regional office);
    (ii) A flag indicating that the add-on emission controls are 
operating with all parameters within the ranges specified in the 
monitoring plan or that the add-on emission controls are not operating 
properly;
    (iii) For units petitioning under Sec. 75.66 for substituting a 
representative SO₂ concentration during missing data periods, any 
available inlet and outlet SO₂ concentration values recorded by an 
SO₂ continuous emission monitoring system; and
    (iv) For units petitioning under Sec. 75.66 for substituting a 
representative NO_Xemission rate during missing data periods, any 
available inlet and outlet NO_Xemission rate values recorded by a 
[[Page 26569]] NO_Xcontinuous emission monitoring system.

 * * * *
    (e) Specific SO₂ emission record provisions during the 
combustion of gaseous fuel. In accordance with the provisions in 
Sec. 75.11(e), the owner or operator of a unit with an SO₂ 
continuous emission monitoring system may record the information in 
paragraph (c)(3) of this section in lieu of the information in 
Secs. 75.54(c)(1) and 75.54(c)(3), for those hours when only pipeline 
natural gas or a gaseous fuel with a sulfur content no greater than 
natural gas is combusted.
 * * * *
 Section 75.56 is amended by adding paragraph (a)(6) to read as 
follows:

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

    (a) * * *
    (6) For each SO₂, NO<INF>X, CO<INF>2, or O<INF>2 pollutant 
concentration monitor, NOx-diluent continuous emission monitoring 
system, or SO₂-diluent continuous emission monitoring system, the 
owner or operator shall record the following information for the cycle 
time test:
    (i) Component/system identification code;
    (ii) Date;
    (iii) Start and end times;
    (iv) Upscale and downscale cycle times for each component;
    (v) Stable start monitor value;
    (vi) Stable end monitor value;
    (vii) Reference value of calibration gas(es);
    (viii) Calibration gas level; and
    (ix) Cycle time result for the entire system.

 * * * *
 Section 75.64 is amended by revising paragraphs (a)(1) and (c) 
to read as follows:

Sec. 75.64   Quarterly reports.

    (a) * * *
    (1) The information and hourly data required in Secs. 75.50 through 
75.52 (or Secs. 75.54 through 75.56), no later than the quarterly 
report due April 30, 1996), excluding:
    (i) Descriptions of adjustments, corrective action, and 
maintenance;
    (ii) Information which is incompatible with electronic reporting 
(e.g., field data sheets, lab analyses, quality control plan);
    (iii) Opacity data listed in Sec. 75.50(f) or Sec. 75.54(f);
    (iv) For units with SO₂ or NO_Xadd-on emission controls 
that do not elect to use the approved site-specific parametric 
monitoring procedures for calculation of substitute data, the 
information in Sec. 75.55(b)(3); and
    (v) The information recorded under Sec. 75.56(a)(7) for the period 
prior to January 1, 1996.

 * * * *
    (c) Compliance certification. The designated representative shall 
submit a certification in support of each quarterly emissions 
monitoring report based on reasonable inquiry of those persons with 
primary responsibility for ensuring that all of the unit's emissions 
are correctly and fully monitored. The certification shall indicate 
whether the monitoring data submitted were recorded in accordance with 
the applicable requirements of this part including the quality control 
and quality assurance procedures and specifications of this part and 
its appendices, and any such requirements, procedures and 
specifications of an applicable excepted or approved alternative 
monitoring method. In the event of any missing data periods, the 
certification must describe the measures taken to cure the causes for 
the missing data periods. For a unit with add-on emission controls, the 
designated representative shall also include a certification for all 
hours where data are substituted following the provisions of 
Sec. 75.34(a)(1), that the add-on emission controls were operating 
within the range of parameters listed in the monitoring plan, and that 
the substitute values recorded during the quarter do not systematically 
underestimate SO₂ or NO_Xemissions, pursuant to Sec. 75.34.
 * * * *
 Section 75.66 is amended by revising paragraphs (e) and (f) to 
read as follows:

Sec. 75.66   Petitions to the Administrator.

 * * * *
    (e) Parametric monitoring procedure petitions. The designated 
representative for an affected unit may submit a petition to the 
Administrator, where each petition shall contain the information 
specified in Sec. 75.51(b) (or Sec. 75.55(b), no later than January 1, 
 for use of a parametric monitoring method. The Administrator will 
either:
    (1) Publish a notice in the Federal Register indicating receipt of 
a parametric monitoring procedure petition;, or
    (2) Notify interested parties of receipt of a parametric monitoring 
petition.
    (f) Missing data petitions for units with add-on emission controls. 
The designated representative for an affected unit may submit a 
petition to the Administrator for the use of the maximum controlled 
emission rate, which the Administrator will approve if the petition 
adequately demonstrates that all the requirements in Sec. 75.34(a)(2) 
are satisfied. Each petition shall contain the information listed below 
for the time period (or data gap) during which the affected unit 
experienced the monitor outage that would otherwise result in the 
substitution of an uncontrolled maximum value under the standard 
missing data procedures contained in subpart D of this part:
    (1) Data demonstrating that the affected unit's monitor data 
availability for the time period under petition was less than 90.0 
percent;
    (2) Data demonstrating that the add-on emission controls were 
operating properly during the time period under petition (i.e., within 
the range of operating parameters for the add-on emission controls in 
the monitoring plan for the unit);
    (3) A list of the average hourly values for the previous 720 
quality-assured monitor operating hours, highlighting both the maximum 
recorded value and the value corresponding to the maximum controlled 
emission rate; and
    (4) An explanation and information on operation of the add-on 
emission controls demonstrating that the selected historical SO₂ 
concentration or NO_Xemission rate does not underestimate the 
SO₂ concentration or NO_Xemission rate during the missing 
data period.
 * * * *
 Appendix A to Part 75, Section 6.3 is amended by adding a 
sentence to the last paragraph of sections 6.3.1 and 6.3.2 and by 
adding section 6.3.3 to read as follows:

Appendix A--Specifications and Test Procedures

 * * * *
 Certification Tests and Procedures
 * * * *
    6.3.1  * * * The provisions in this section are suspended from 
July 17, 1995 through December 31, 1996.
    6.3.2  * * * The provisions in this section are suspended from 
July 17, 1995 through December 31, 1996.

6.3.3  Pollutant Concentration Monitor and CO<INF>2 or O<INF>2 Monitor 
7-day Calibration Error Test

    Measure the calibration error of each pollutant concentration 
monitor and CO<INF>2 or O<INF>2 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 adjustments to the monitor settings until 
after taking measurements at both zero and high 
[[Page 26570]] concentration levels for that day during the 7-day 
test. If automatic adjustments are made, 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 or flow rate measured in the 
calibration error test prior to making any manual adjustment or 
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 
NO_Xpollutant 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 
CO<INF>2 or O<INF>2 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 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.

 * * * *
 Appendix A to part 75, section 6.3.4 is added to read as 
follows:

Appendix A--Specifications and Test Procedures

6. Certification Tests and Procedures

 * * * *

6.3.4  Flow Monitor 7-day Calibration Error Test

    Measure the calibration error of each flow monitor according to 
the following procedures.
    Introduce the reference signal corresponding to the values 
specified in section 2.2.2.1 of this appendix to the probe tip (or 
equivalent), or to the transducer. During the 7-day certification 
test period, conduct the calibration error test while the unit is 
operating once each unit operating day (as close to 24-hour 
intervals as practicable). In the event that extended unit outages 
occur after the commencement of the test, the 7 consecutive 
operating days need not be 7 consecutive calendar days. Record the 
flow monitor responses by means of the data acquisition and handling 
system. Calculate the calibration error using Equation A-6 of this 
appendix.
    Do not perform any corrective maintenance, repair, or 
replacement upon the flow monitor during the 7-day certification 
test period other than that required in the quality assurance/
quality control (QA/QC) plan required by appendix B of this part. Do 
not make adjustments between the zero and high reference level 
measurements on any day during the 7-day test. If the flow monitor 
operates within the calibration error performance specification 
(i.e., less than or equal to 3 percent error each day and requiring 
no corrective maintenance, repair, or replacement during the 7-day 
test period) the flow monitor passes the calibration error test 
portion of the certification test. Record all maintenance activities 
and the magnitude of any adjustments. Record output readings from 
the data acquisition and handling system before and after all 
adjustments. Record and report all calibration error test results 
using the unadjusted flow rate measured in the calibration error 
test prior to resetting the calibration. Record all adjustments made 
during the seven day period at the time the adjustment is made and 
report them in the certification application.

 * * * *
 Appendix A to part 75, is amended by adding a sentence to the 
end of section 6.4 and by adding section 6.4.1 to read as follows:

 Certification Tests and Procedures

 * * * *
    6.4  * * * The provisions in this section 6.4 are suspended from 
July 17, 1995 through December 31, 1996.

6.4.1  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.
    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 
monitor value and start time. Next, allow the monitor to measure the 
concentration of flue gas emissions until the response stabilizes. 
Determine the upscale elapsed time as the time at which 95.0 percent 
of the step change is achieved between the stable starting gas value 
and the stable ending monitor value. Record the stable ending 
monitor value, the end time, and the upscale elapsed time for the 
monitor using data acquisition and handling system output. Then 
repeat the procedure, starting by injecting the high-level gas 
concentration to determine the downscale elapsed time, which is the 
time at which 95.0 percent of the step change is achieved between 
the stable starting gas value and the stable ending monitor value. 
End the downscale test by measuring the 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 data acquisition and handling system output. A stable value is 
equivalent to a reading with a change of less than 1 percent of the 
span value for 30 seconds, or a reading with a change of less than 5 
percent from the measured average concentration over 5 minutes.
    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. Record the span, the zero and high gas concentrations, 
the start and end times, the stable starting and ending monitor 
values, and the upscale and downscale elapsed times. Report the 
slower of the two elapsed times as the cycle time for the analyzer. 
(See Figure 5 at the end of this appendix.) For the NO_X
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 for all 
probe locations that will be polled within the same 15-minute period 
during monitoring system operations. For cycle time results for a 
time-shared system, add together the longest cycle time obtained 
from each location. Report the sum of the cycle time at each 
location plus the time required for all purge cycles (as determined 
by the CEMS manufacturer) for each location as the cycle time for 
each and all of those systems. For monitors with dual ranges, 
perform the test on the range giving the longest cycle time.
    Cycle time test results are acceptable for monitor or monitoring 
system certification if none of the cycle times exceed 15 minutes.

 * * * *
 Appendix A to part 75 is amended by adding Figure 5 at the end 
of the appendix to read as follows:
 * * * *

Figure 5--Cycle Time
Date of test-----------------------------------------------------------
Component/system ID#:--------------------------------------------------
Analyzer type----------------------------------------------------------
Serial Number----------------------------------------------------------
High level gas concentration: ______ ppm/(circle one)
Zero level gas concentration: ______ ppm/(circle one)
Analyzer span setting: ______ ppm/(circle one)
Upscale:
    Stable starting monitor value: ______ ppm/(circle one)
    Stable ending monitor reading: ______ ppm/(circle one)
    Elapsed time: ______ seconds
Downscale:
    Stable starting monitor value: ______ ppm/(circle one) 
[[Page 26571]] 
    Stable ending monitor value: ______ ppm/(circle one)
    Elapsed time: ______ seconds
Component cycle time= ______ seconds
System cycle time= ______ seconds

 * * * *
 Appendix B to part 75 is amended by adding a sentence to the 
end of section 2.1 and by adding section 2.1.7 to read as follows:

Appendix B--Quality Assurance and Quality Control Procedures

 * * * *
 Frequency of Testing

    2.1 * * * The provisions in this section 2.1 are suspended from 
July 17, 1995 through December 31, 1996.

 * * * *

2.1.7  Daily Assessments

    For each monitor or continuous emission monitoring system, 
perform the following assessments during each day in which the unit 
combusts any fuel (hereafter referred to as a ``unit operating 
day''), or for a monitor on a bypass stack/duct, during each day 
that emissions pass through the by-pass stack or duct. If the unit 
discontinues operation or if use of the by-pass stack or duct is 
discontinued prior to performance of the calibration error test, 
data from the monitor or continuous emission monitoring system may 
be considered quality assured prospectively for 24 consecutive clock 
hours from the time of successful completion of the previous daily 
test performed while the unit is operating. These requirements are 
effective as of the date when the monitor or continuous emission 
monitoring system completes certification testing.

 * * * *

Appendix F to Part 75--Conversion Procedures

    19. Appendix F is amended by adding section 7 to read as follows:

 * * * *
 Procedures for SO₂ Mass Emissions at Units With SO₂ 
Continuous Emission Monitoring Systems During the Combustion of Gaseous 
Fuel

    Use the following equation to calculate hourly SO₂ mass 
emissions as allowed for units with SO₂ continuous emission 
monitoring systems during the combustion of pipeline natural gas 
under Sec. 75.11(e). These procedures are optional prior to January 
1, 1997 and are required on or after January 1, 1997.

E<INF>h=(0.0006) HI    (Eq. F-23)

where,

E<INF>h=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. 95-11497 Filed 5-10-95; 3:42 pm]
BILLING CODE 6560-50-P
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