26560 Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations

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 §§ 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 follow-up 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 [§ 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

[§ 75.30(e)], (3) the procedure for

determining proper operation of units

with add-on controls for purposes of

substituting missing data (§ 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 §§ 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

[§ 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 [§ 75.30(e)] until

January 1, 1997. The EPA believes that

this will give utilities time to comment
Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations 26561

1As 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.

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.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.

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,

oil-fired, 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
26562 Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations

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

1. 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 EPA-Texas

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 NOX

emission 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 sitespecific 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 75. 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

NOX emission 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 NOX

CEMS.

The EPA has also made minor

changes to indicate that petitions are

submitted by the designated
Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations 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.

2. 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 qualityassured 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 quality-assured

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

§ 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 co-firing 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

§§ 75.31 or 75.33 for an SO2 CEMS.

3. 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 § 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

1. 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
26564 Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations

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 qualityassured. 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 qualityassuring 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.
Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations 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. WarrenHicks, 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

NOX CEMS (in lb/mmBtu), and the CO2

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 NOX and

diluent gas components of the NOX

CEMS, because NOX and O2 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 NOX or SO2-diluent monitoring

system, the cycle time is the longer of

the two cycle times for the NOX or 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

§ 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.
26566 Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations

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:

§ 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 § 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 § 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 § 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 § 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 § 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 § 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 § 75.16 and

in subpart E of this part.

5. Section 75.21 is amended by

adding a sentence to the end of

paragraph (a) and by adding paragraph

(f) to read as follows:

§ 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 nonredundant 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.

6. Section 75.30 is amended by

adding paragraphs (d) and (e) to read as

follows:

§ 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 § 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 § 75.11(e), the

owner or operator shall substitute for

missing data from a flow monitoring

system, CO2 diluent monitor or O2

diluent monitor using the missing data

substitution procedures in § 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 § 75.11(e), the

owner or operator shall substitute for
Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations 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 § 75.32, nor

in the calculations of substitute data

using the procedures of either § 75.31 or

§ 75.33. For the purpose of the missing

data and availability procedures for SO2

pollutant concentration monitors in

§§ 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 §§ 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 § 75.31 or

§ 75.33.

7. 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:

§ 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 non-redundant 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

§ 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.’’

* * * * *

8. Section 75.34 is revised to read as

follows:

§ 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

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

§§ 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 NOX addon emission controls during each hour,

as described in paragraph (d) of this

section. In addition, under § 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) In addition, the designated

representative may petition the

Administrator under § 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 qualityassured 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 § 75.32, for the affected

unit is below 90.0 percent and

parametric data establish that the addon 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 § 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 § 75.51(b) until January 1,

1996, or pursuant to § 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 § 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 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 § 75.34(a) (1) or (2), even

if the Administrator has approved a

parametric monitoring procedure.

(c) For an affected unit with NOX addon 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
26568 Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations

data for missing data periods. The

owner or operator shall use the

procedures in § 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.

(1) Where monitor data availability for

a NOX continuous 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 NOX continuous emission monitoring

system is less than 90.0 percent, the

owner or operator shall calculate

substitute data using the procedure in

§ 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 NOX

emission 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 NOX add-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 NOX

emission rate, as defined in § 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.

9. Section 75.53 is amended by

revising paragraph (d) introductory text

and by adding paragraph (d)(4) to read

as follows:

§ 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 § 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.

* * * * *

10. Section 75.55 is amended by

adding paragraphs (b) and (e) to read as

follows:

§ 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

§ 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 NOX

emission 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 NOX through 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

§ 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 § 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 NOX

emission controls petitioning to use or

using the optional parametric

monitoring procedures in appendix C of

this part, for each hour of missing NOX

emission rate data:

(i) Date and hour;

(ii) Inlet air flow rate (acfh, rounded

to the nearest thousand);

(iii) Excess O2 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 (°F); and

(vi) Other parameters specific to NOX

emission controls (e.g., average hourly

reagent feedrate);

(vii) Method of determination of NOX

emission rate using Codes 1–15 in Table

3 of § 75.54; and

(viii) Inlet and outlet NOX emission

rate values recorded by a NOX

continuous emission monitoring system

and the removal efficiency of the addon emission controls.

(3) For units with add-on SO2 or NOX

emission controls following the

provisions of § 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 addon emission controls are not operating

properly;

(iii) For units petitioning under

§ 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

§ 75.66 for substituting a representative

NOX emission rate during missing data

periods, any available inlet and outlet

NOX emission rate values recorded by a
Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations 26569

NOX continuous emission monitoring

system.

* * * * *

(e) Specific SO2 emission record

provisions during the combustion of

gaseous fuel. In accordance with the

provisions in § 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 §§ 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.

* * * * *

11. Section 75.56 is amended by

adding paragraph (a)(6) to read as

follows:

§ 75.56 Certification, quality assurance

and quality control record provisions.

(a) * * *

(6) For each SO2, NOX, CO2, or O2

pollutant concentration monitor, NOxdiluent 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.

* * * * *

12. Section 75.64 is amended by

revising paragraphs (a)(1) and (c) to read

as follows:

§ 75.64 Quarterly reports.

(a) * * *

(1) The information and hourly data

required in §§ 75.50 through 75.52 (or

§§ 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 § 75.50(f) or

§ 75.54(f);

(iv) For units with SO2 or NOX addon emission controls that do not elect to

use the approved site-specific

parametric monitoring procedures for

calculation of substitute data, the

information in § 75.55(b)(3); and

(v) The information recorded under

§ 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 § 75.34(a)(1), that the addon 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 NOX emissions,

pursuant to § 75.34.

* * * * *

13. Section 75.66 is amended by

revising paragraphs (e) and (f) to read as

follows:

§ 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 § 75.51(b) (or

§ 75.55(b), no later than January 1, 1996)

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 § 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 addon 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 NOX

emission rate does not underestimate

the SO2 concentration or NOX emission

rate during the missing data period.

* * * * *

14. 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

* * * * *

6. 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

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 lowscales of the pollutant concentration monitor.

Do not make manual adjustments to the

monitor settings until after taking

measurements at both zero and high
26570 Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations

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) highlevel, 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 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.

* * * * *

15. 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.

* * * * *

16. 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:

6. 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 NOX 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.

* * * * *

17. 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 lllllllllllllll

Component/system ID#: lllllllll

Analyzer type llllllllllllll

Serial Number llllllllllllll

High level gas concentration: lll ppm/%

(circle one)

Zero level gas concentration: lll ppm/%

(circle one)

Analyzer span setting: lll ppm/% (circle

one)

Upscale:

Stable starting monitor value: lll ppm/

% (circle one)

Stable ending monitor reading: lll

ppm/% (circle one)

Elapsed time: lll seconds

Downscale:

Stable starting monitor value: lll ppm/

% (circle one)
Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations 26571

Stable ending monitor value: lll ppm/

% (circle one)

Elapsed time: lll seconds

Component cycle time= lll seconds

System cycle time= lll seconds

* * * * *

18. 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

* * * * *

2. 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:

* * * * *

7. 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 § 75.11(e). These

procedures are optional prior to January 1,

1997 and are required on or after January 1,

1997.

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. 95–11497 Filed 5–10–95; 3:42 pm]

BILLING CODE 6560–50–P