Acid Rain Program: Continuous Emission Monitoring Rule Technical Revisions

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 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 [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.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, 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 [[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

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 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

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 non-

operation 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 [[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.

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 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 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 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 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 Secs. 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 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

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 [[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 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 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.

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:

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.

6. 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, CO2 diluent monitor or O2 diluent monitor using the

missing data substitution procedures in Sec. 75.36.

(2) Whenever a unit with an SO2 continuous emission monitoring

system combusts 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.

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:

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 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

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.''

* * * * *

8. 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 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 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 NOX add-on emission controls during each hour, as

described in paragraph (d) of this section. In addition, under

Sec. 75.64(c) the designated representative shall submit a certified

verification of the proper operation of the SO2 or NOX add-on

emission control for each missing data period at the end of each

quarter.

(2) 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 NOX emission rate data in accordance

with the requirements of paragraphs (b) and (c) of this section, and

appendix C of this part. The owner or operator shall record the data

required in appendix C of this part, pursuant to Sec. 75.51(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 NOX add-on emission controls,

the designated representative may petition the Administrator to approve

a parametric monitoring procedure, as described in appendix C of this

part, in order to calculate substitute NOX emission rate

[[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 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

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 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 Sec. 72.2 of this chapter, to report the

NOX emission rate, and either the maximum hourly SO2

concentration recorded by the inlet monitor during the previous 720

quality assured monitor operating hours, if available, or the maximum

potential concentration for SO2, as defined by section 2.1.1.1 of

appendix A of this part, to report SO2 concentration for each hour

of missing data until information demonstrating proper operation of the

SO2 or NOX emission controls is available.

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.

* * * * *

10. 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 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 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 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 ( deg.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 Sec. 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 add-on emission controls.

(3) For units with add-on SO2 or NOX emission 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 NOX emission rate during missing data periods, any

available inlet and outlet NOX emission rate values recorded by a

[[Page 26569]] NOX continuous 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.

* * * * *

11. 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, NOX, CO2, or O2 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.

* * * * *

12. 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 NOX add-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 NOX emissions, pursuant to Sec. 75.34.

* * * * *

13. 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,

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 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 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

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

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

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

* * * * *

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 Sec. 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