Acid Rain Program; Continuous Emission Monitoring Rule Revisions

SUMMARY: Title IV of the Clean Air Act (CAA or the Act), as amended by

the Clean Air Act Amendments of 1990, authorizes the Environmental

Protection Agency (EPA or Agency) to establish the Acid Rain Program.

The Acid Rain Program and the provisions in this final rule benefit the

environment by ensuring that the sulfur dioxide (SO2),

nitrogen oxides (NOX) and carbon dioxide (CO2)

air pollution emissions to be measured and tracked pursuant to the

provisions of 40 CFR part 75 are accurately monitored and reported.

These provisions also benefit the regulated entities by providing

additional flexibility and improved cost effectiveness to the

monitoring and reporting options available to part 75 subject sources.

On January 11, 1993, the Agency promulgated final rules, including the

final continuous emission monitoring (CEM) rule, under title IV. On May

17, 1995 and November 20, 1996, the Agency revised the CEM rule to make

the implementation simpler. On May 21, 1998, the Agency proposed

additional revisions to the CEM rule, to make implementation easier and

more efficient for both EPA and the facilities affected by the rule, to

improve quality assurance requirements, and to create new alternative

monitoring options. EPA promulgated final rule revisions addressing

some of these additional proposed revisions, based on comments

received, when EPA promulgated a Finding of Significant Contribution

and Rulemaking for Certain States in the Ozone Transport Assessment

Group Region for Purposes of Reducing Regional Transport of Ozone

(NOX SIP call).

In this action, EPA is issuing final rule revisions addressing the

remaining May 21, 1998 proposed revisions to the CEM rule, with certain

changes to the proposal based on the public comments received. Some of

these revisions will be relevant for sources that become subject to

part 75 requirements in response to the NOX SIP call.

DATES: The effective date of this rule is June 25, 1999. The

incorporation by reference of certain publications listed in the

regulations is approved by the Director of the Federal Register as of

June 25, 1999.

ADDRESSES: Docket. Supporting information used in developing the

regulations is contained in Docket No. A-97-35. This docket is

available for public inspection and photocopying between 8:00 a.m. and

5:30 p.m. Monday through Friday, excluding government holidays and is

located at: EPA Air Docket (MC 6102) , Room M-1500, Waterside Mall, 401

M Street, SW, Washington, DC 20460. A reasonable fee may be charged for

photocopying.

FOR FURTHER INFORMATION CONTACT: Monika Chandra, Acid Rain Division

(6204J), U.S. Environmental Protection Agency, 401 M Street, SW,

Washington, DC 20460, (202) 564-9781.

SUPPLEMENTARY INFORMATION: The contents of the preamble are listed in

the following outline:

I. Regulated Entities

II. Background and Summary of Final Rule

III. Summary of Major Comments and Responses

A. Certification/Recertification Procedural Changes

B. Quality Assurance Requirements for Quantifying Stack Gas

Moisture Content

C. Percent Monitor Availability

D. Span and Range Requirements

E. Flow-to-Load Ratio Test Requirements

F. RATA and Bias Test Requirements

1. RATA Load Levels

2. Single Point Reference Method Sampling

G. Data Validation

1. Data Validation During Monitor Certification and

Recertification

2. Data Validation for RATAs and Linearity Checks

H. Appendix D--Sulfur Dioxide Emissions from the Combustion of

Gaseous Fuels

1. Summary of EPA Analysis of Appendix D Gaseous Fuel

SO2 and Heat Input Methodologies

2. Changes to the Definitions of ``Pipeline Natural Gas'' and

``Natural Gas''

3. Changes to the Methodology for Calculating SO2

Emissions Under Appendix D

4. Changes to the Applicability of Appendix D

5. Changes to the Method of Determining the Sulfur Content

Sampling Frequency for Gaseous Fuels

6. Changes to the Method of Determining the GCV Sampling

Frequency for Gaseous Fuels

I. Electronic Transfer of Quarterly Reports

J. Bias, Relative Accuracy and Availability Determinations

K. Appendix I--Proposed Optional Stack Flow Monitoring

Methodology

L. Subpart H--Clarifications to NOX Mass Monitoring

Requirements

IV. Administrative Requirements

A. Public Docket

B. Executive Order 12866

C. Unfunded Mandates Reform Act

D. Executive Order 12875

E. Executive Order 13084

F. Paperwork Reduction Act

G. Regulatory Flexibility

H. Submission to Congress and the General Accounting Office

I. Executive Order 13045

J. National Technology Transfer and Advancement Act

I. Regulated Entities

Entities regulated by this action are fossil fuel-fired boilers and

turbines that serve generators producing electricity, generate steam,

or cogenerate electricity and steam. While part 75 primarily regulates

the electric utility industry, the recent promulgation of 40 CFR part

96 and certain revisions to part 75 (see 63 FR 57356, October 27, 1998)

means that part 75 could potentially affect other industries. The

recent adoption of part 96, together with revisions to part 75, include

nitrogen oxides (NOX) mass provisions for the purpose of

serving as a model which could be adopted by a state, tribal, or

federal NOX mass reduction program covering the electric

utility and other industries. Regulated categories and entities

include:

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

Examples of regulated

Category entities

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

Industry.................................. Electric service providers,

boilers, turbines and other

process sources where

emissions exhaust through a

stack.

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

This table is not intended to be exhaustive, but rather provides a

guide for readers regarding entities likely to be regulated by this

action. This table lists the types of entities which EPA is now aware

could potentially be regulated by this action. Other types of entities

not listed in the table could also be regulated. To determine whether

your facility, company, business, organization, etc., is regulated by

this action, you should carefully examine the applicability provisions

in Secs. 72.6, 72.7, 72.8, and part 96 of title 40 of the Code of

Federal Regulations. If you have questions regarding the applicability

of this action to a particular entity, consult the person listed in the

preceding FOR FURTHER INFORMATION CONTACT section of this preamble.

II. Background and Summary of Final Rule

Title IV of the Act requires EPA to establish an Acid Rain Program

to reduce the adverse effects of acidic deposition. On January 11,

1993, the

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Agency promulgated final rules implementing the program, including the

CEM rule (58 FR 3590). Notices of direct final rulemaking and of

interim final rulemaking further amending the regulations were

published on May 17, 1995 (60 FR 26510 and 60 FR 26560). Subsequently,

on November 20, 1996, a final rule was published in response to public

comments received on the direct final and interim rules (61 FR 59142).

On May 21, 1998, the Agency published proposed revisions to the part 75

CEM regulations (62 FR 28032). As noted above, EPA recently promulgated

final revisions to part 75 addressing some of the May 21, 1998,

proposed revisions in conjunction with the promulgation of a Model

NOX Trading Rule in part 96 and the NOX SIP call

(see 63 FR 57356).

Today's action adopts final part 75 revisions to address the

remaining May 21, 1998, proposed revisions and to make minor technical

corrections to the part 75 provisions promulgated in conjunction with

part 96 and the NOX SIP Call. The final revisions involve

the following matters: (1) revised definitions of gas-fired, oil-fired,

and peaking unit to allow for changes in unit fuel usage and/or

operation; (2) a minor wording correction to the applicability

provisions in part 72; (3) new quality assurance/quality control (QA/

QC) requirements for quantifying stack gas moisture content; (4)

clarifying changes to the certification and recertification process;

(5) substitute data requirements for carbon dioxide (CO2),

heat input and moisture; (6) clarifying revisions to the petition

provisions for alternatives to part 75 requirements; (7) clarifying

changes to span and range requirements; (8) clarifying revisions to

general QA/QC requirements; (9) calibration error test requirements;

(10) linearity test requirements; (11) a new flow-to-load QA test for

flow monitors; (12) reductions in and/or clarifications to the relative

accuracy test audit (RATA) and bias test requirements; (13) clarifying

revisions to the procedures for CEM data validation; (14) clarifying

revisions to the sulfur dioxide (SO2) emissions data

protocol for gas-fired and oil-fired units (Appendix D); (15)

determination of CO2 emissions under Appendix G; (16)

recordkeeping and reporting changes to reflect the proposed revisions;

(17) a revised traceability protocol for calibration gases (Appendix

H); and (18) NOX mass emission recordkeeping and reporting

provisions, and minor revisions to NOX mass monitoring

requirements.

Many of these changes are minor technical revisions based on

comments received from facilities following the initial implementation

of part 75. Based on experience gained in the early years of the

program, facilities have developed a number of suggestions that will

simplify and streamline the monitoring process without sacrificing data

quality. The Agency has also amended quality assurance requirements

based on gaps identified by EPA during evaluation of the initial

implementation of part 75. Finally, several minor technical changes

have been made in order to maintain uniformity within the rule itself

and to clarify various provisions.

III. Summary of Major Comments and Responses

A. Certification/Recertification Procedural Changes

Background: EPA proposed to revise the recertification application

review period in Sec. 75.20(b)(5) from 60 days to 120 days, which is

the same review period as for the initial certification application.

The Agency believes that this will reduce confusion, simplify

certification/recertification application tracking, and will result in

the more efficient allocation of resources by local, state, and federal

agencies. Therefore, EPA has adopted this change in the final rule with

certain modifications in response to issues raised by commenters.

Discussion: Two states responded positively to the proposed change.

One state commented that the increased review time ``will allow more

effective use of staff resources and provide ample time for a thorough

review of the data submitted in the application'' (see Docket A-97-35,

Item IV-D-6). Another state commenter remarked that extending the

review period ``adds uniformity and consistency to the certification

and recertification process. This change is positive, and it allows the

state agencies the time to resolve minor deficiencies which may

otherwise serve as grounds to recommend disapproval. Based on

experience, the 120 day period is absolutely essential for the review

of certification/recertification applications'' (see Docket A-97-35,

Item IV-D-9).

Several commenters suggested that if EPA disapproved a

recertification application after the 120 day period, data recorded

during the entire 120 day period would become invalid and the use of

substitute data would be required (see Docket A-97-35, Items IV-D-17,

IV-D-20 and IV-D-24). However, as EPA stated in the preamble to the

proposal, ``less than 2 percent of all monitoring system applications

submitted between 1992 and September 1997 were disapproved'' (63 FR

28045, citing Docket A-97-35, Item II-A-4). As experience with the

program increases, the number of disapprovals is expected to decrease

even further. In addition, EPA's position is that the owners or

operators of affected facilities are responsible for initiating,

conducting, evaluating and certifying the results of the required

testing prior to submission to the appropriate regulatory Agencies. The

Agencies' role is to ``certify'' or verify the results. Thus, there is

no reason to expect that the additional time provided to meet the

administrative needs of the program will result in any significant

compliance risk to the regulated sources, except in instances where

insufficient care is taken to ensure proper conduct of the testing.

Two commenters stated that the owner or operator would be in

violation of the requirements of proposed Sec. 75.33(d) and

Sec. 75.10(a) if a recertification application were disapproved after

120 days (see Docket A-97-35, Items IV-D17 and IV-D-23) because the

percent monitor availability would be below 80%. These proposed

penalties have been withdrawn from the final rule in response to

comments received. Today's final rule does not treat a percent monitor

data availability of less than 80% as a violation. Instead, the final

rule provides that if percent monitor data availability is less than

80%, then the appropriate maximum value (e.g., maximum potential

concentration) or, in some cases, the appropriate minimum potential

value will be used to provide substitute data (see Section C of this

preamble for a further discussion of these provisions).

Several commenters suggested that since the review of the initial

certification applications for the Acid Rain Phase I and Phase II units

has been completed, the burden on the states and EPA has been removed .

Therefore, it should not take EPA 120 days to review recertification

applications (see Docket A-97-35, Items IV-D-14, IV-D-20, and IV-D-24).

This argument would be more compelling if the Acid Rain Program were

the only program that the various regulatory agencies are required to

implement. However, EPA and the States are currently responsible for

implementing several other programs that require comprehensive

administrative review of various types of applications and petitions

(e.g., Compliance Assurance Monitoring (CAM), the OTC NOX

Budget Program, the PSD program and Title V permitting). EPA also

anticipates that the NOX SIP call will further increase the

number of certification and recertification applications and

[[Page 28566]]

petitions that need to be reviewed by the regulatory agencies.

Many recertifications require the same tests as for initial

certification. Therefore, recertification applications often take as

much effort to review as certification applications. It is also

sometimes difficult to distinguish a recertification application

package from an initial certification application package, which can

complicate tracking the two types of applications if they have

different review periods. The recertification process usually requires

that a state or local program perform the initial review and forward

the results to the EPA regional office which will then make a

recommendation to EPA headquarters on whether to approve or disapprove

the application. This requires a significant amount of time and does

not allow much time to coordinate with the source to get additional

information, when needed. There is more likelihood of a disapproval

being issued under a short time frame. Finally, EPA notes that it does

not have control over the number of recertification applications that

are submitted. Individual utility choices, changes in rules, market

conditions, and technology all influence the number of

recertifications. Therefore, EPA has concluded that extending the

application review period from 60 to 120 days is both necessary and

appropriate.

B. Quality Assurance Requirements for Quantifying Stack Gas Moisture

Content

Background: Section 75.11(b) of the January 11, 1993 Acid Rain rule

requires the owner or operator to continuously (or on an hourly basis)

account for the moisture content of the stack gas when SO2

concentration is measured on a dry basis. The moisture content is

needed to correct the measured hourly stack gas volumetric flow rates

to a dry basis when calculating SO2 mass emission rates in

lb/hr. Section 75.13(a) of the rule, as amended on May 17, 1995,

contains provisions for CO2 monitoring paralleling the

provisions of Sec. 75.11(b); that is, when CO2 concentration

is measured on a dry basis, a correction for stack gas moisture content

is needed to accurately determine the CO2 mass emissions.

The stack gas moisture content is also needed when a dry-basis

O2 monitor is used to account for CO2 emissions

and, in some instances, when accounting for unit heat input or when

determining NOX emission rate in lb/mmBtu.

As presently codified, part 75 does not specify any quality

assurance requirements for moisture measurement devices. Approximately

5 to 10 percent of the continuous emission monitors in the Acid Rain

Program require moisture corrections to accurately measure

SO2, CO2, or NOX emissions or heat

input (see Docket A-97-35, Item II-I-6 ). The accuracy of the stack gas

moisture measurements directly affects the accuracy of the reported

SO2 mass emission rates, CO2 mass emission rates,

NOX emission rates and heat input values. An error of 1.0

percent H2O in measured moisture content causes a 1.0

percent error in the reported emission rate or heat input value.

Failure to quality assure the moisture data can therefore result in

significant under-reporting of SO2, CO2, and

NOX emissions and heat input.

In the May 21, 1998 proposed rule, EPA set forth quality assurance

procedures that would apply to moisture monitoring systems because the

Agency believes that when moisture corrections must be applied,

continuous, quality assured, direct measurement of the stack gas

moisture content or continuous measurement of surrogate parameters for

moisture, such as wet-and dry-basis oxygen concentrations, is the best

way to ensure the accuracy of the reported emission data. The proposed

rule specified that a moisture monitoring system could consist of

either: (1) a continuous moisture sensor; (2) an oxygen (O2)

analyzer (or analyzers) capable of measuring O2 on both a

wet basis and on a dry basis; or (3) a system consisting of a

temperature sensor and a certified data acquisition and handling system

(DAHS) component capable of determining moisture from a lookup table,

i.e., a psychometric chart (this third option would apply only to

saturated gas streams following wet scrubbers).

The proposed rule included requirements for the initial

certification of moisture monitoring systems. For continuous moisture

sensors, a 7-day calibration error test and a relative accuracy test

audit (RATA) would be required. For moisture monitoring systems

consisting of one or more wet-and dry-basis oxygen analyzers, the

proposed requirements included a 7-day calibration error test, a

linearity test and a cycle time test of each O2 analyzer,

and a RATA of the moisture measurement system. For the lookup table

option (saturated streams, only), the certification requirement would

consist of a DAHS verification. The proposed rule specified that owners

or operators would have to complete all moisture monitoring system

certification tests no later than January 1, 2000.

The proposed rule contained performance specifications for moisture

monitoring systems. These specifications would apply to continuous

moisture sensors and to wet-and dry-basis oxygen analyzers. For

moisture monitoring systems consisting of wet-and dry-basis

O2 analyzers, the proposed span values and performance

specifications for calibration error, linearity, and cycle time would

be the same as the current specifications for O2 monitors.

For moisture sensors, a calibration error specification of 3.0% of span

was proposed. The proposed relative accuracy (RA) specification for all

moisture monitoring systems would be 10.0 percent. An alternative RA

specification was also proposed, i.e., the RA test results would be

considered acceptable if the mean difference of the reference method

measurements and the moisture monitoring system measurements is within

1.0 percent H2O.

On-going QA requirements for moisture monitoring systems were also

proposed. Appendix B would be revised to require daily calibrations of

moisture monitoring systems, quarterly linearity checks of wet-and dry-

basis oxygen analyzer(s), and semiannual RATAs of moisture monitoring

systems. Any moisture monitoring system achieving a relative accuracy

of 7.5 percent or a mean difference between the CEMS and

reference method values within 0.7 percent H2O,

would qualify for an annual, rather than semiannual RATA frequency.

Missing data procedures for moisture were included in the proposed

rule in a new section, Sec. 75.37. Provided that the moisture data

availability is high (90.0 percent), the average of the

``hour before'' and ``hour after'' moisture values would be used for

each hour of the missing data period. When the percent data

availability drops below 90.0 percent, 0.0 percent moisture would be

substituted for each hour of the missing data period.

Finally, the proposed rule specified that records must be kept for

the moisture monitoring systems, including hourly average moisture

readings, percent data availability, and records of all calibration

error tests, linearity tests and relative accuracy test audits.

Today's final rule provides a number of options by which owners or

operators of affected sources may account for the stack gas moisture

content on an hourly basis. The rule also includes quality assurance

provisions for moisture monitoring systems. Today's rule differs from

the proposed rule as follows: (1) the alternate specification in terms

of the mean difference has been increased

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from 1.0 to 1.5% H2O, but the

principal relative accuracy specification for moisture monitoring

systems has been promulgated as proposed, at 10.0 percent; (2) the

daily calibration requirement for continuous moisture sensors has been

withdrawn; (3) the use of the lookup table option has been expanded to

include any demonstrably saturated gas stream, rather than limiting it

to gas streams following wet scrubbers; (4) a site-specific coefficient

or constant (``K'' factor), determined at the time of the RATA, may be

used to calibrate the moisture monitoring system with respect to EPA

Reference Method 4; and (5) in lieu of continuously monitoring the

stack gas moisture content, a conservative, fuel-specific default

moisture percentage may be reported for each unit operating hour (for

coal and wood, only).

Discussion: Two state agencies agreed with EPA that there is a need

for quality assurance of moisture monitoring systems (see Docket A-97-

35, Items IV-D-06 and IV-D-09). A third state agency disagreed with the

proposed QA/QC for the moisture monitors, contending that the proposed

amendments provide no added benefit in terms of data quality (see

Docket A-97-35, Item IV-D-11). That same state agency objected to

quality assuring a ``sub-channel'' parameter such as moisture, claiming

that it is inconsistent with the way EPA quality assures other combined

monitoring systems (such as a NOX-diluent system). The

commenter expressed confidence that existing daily, quarterly,

semiannual and annual QA/QC on the gas and flow rate monitors is

sufficient to ensure data quality, and that if the CEMS moisture value

is significantly in error, RATA limits would probably not be met. EPA

notes, however, that the commenter provided no data to demonstrate that

this is true. The Agency also does not agree with the commenter's

characterization of moisture as a ``sub-channel'' parameter. The

attempt to draw an analogy between moisture monitoring and the

NOX-diluent monitoring system is inappropriate. Under part

75, the moisture measurement system is a separate entity and should be

quality-assured as such. The moisture monitor is not a component of any

``combined'' monitoring system. The only true combined monitoring

systems under part 75 are the NOX-diluent and

SO2-diluent monitoring systems, for which the relative

accuracy is determined on a combined basis, in lb/mmBtu (i.e., the

individual relative accuracies of the pollutant and diluent component

monitors are not determined).

Several commenters indicated that they do not believe that a

moisture monitoring system can meet the proposed relative accuracy (RA)

specifications of 10.0% for a semiannual RATA frequency or 7.5% for an

annual RATA frequency. One commenter expressed the opinion that the RA

for a moisture monitoring system should be 15.0% (see Docket A-97-35,

Item IV-G-04). Another commenter suggested that the principal RA

specification should be 10% 15% for a semiannual RATA

frequency and RA 10% for an annual RATA frequency, and that

the alternate RA specification, in terms of the mean difference, should

be 2.0% H2O for a semiannual frequency and

1.5% for an annual RATA frequency (see Docket A-97-35,

Item IV-D-23). Another commenter noted that even slight drift in

measurements can result in significant errors in the moisture

measurements (see Docket A-97-35, Item IV-D-20). One commenter

requested that EPA consider the following alternatives to the proposed

QA/QC requirements for moisture monitors: (1) eliminate the moisture RA

requirement; (2) for wet and dry oxygen analyzers, allow relative

accuracy testing of the oxygen analyzer(s) rather than requiring a RATA

of the moisture system; (3) allow the use of a default value for

moisture, in lieu of monitoring moisture continuously; or (4) subtract

the absolute value of the average moisture values generated by the

moisture monitoring system from the average reference method value at

the time of a RATA and use the difference to correct all subsequent

moisture data until the next RATA (see Docket A-97-35, Item IV-D-02).

Only one set of data was submitted by the commenters for a moisture

monitoring system RATA. The data set indicated that the moisture

monitoring system, which consisted of wet and dry-basis oxygen

analyzers, could achieve an RA of 16.5% (see Docket A-97-35, Item, IV-

D-02). Note, however, that when the moisture monitoring system data and

the reference method data were compared, the moisture monitoring system

consistently indicated a moisture value that was approximately 3%

H2O higher than the reference method, with a confidence

coefficient of 0.507. The low confidence coefficient indicates that the

moisture monitoring system readings were consistently biased high with

respect to the reference method. Therefore, it appears that a suitable

coefficient or constant (``K'' factor) could be applied to the moisture

system readings, to make the moisture monitoring system readings agree

with the reference method. In this case, subtracting 3% moisture from

the average moisture monitoring system values for each run caused the

relative accuracy to drop from 16.5% to 2.4%, which is well below the

proposed 10.0% semiannual and 7.5% annual RA specifications. For the

alternate RA specification, after applying the 3% moisture correction,

the mean difference was essentially zero, which is also well below the

value of 1.0% moisture proposed for a semiannual RATA frequency and the

value of 0.7% moisture proposed for an annual RATA frequency. This

``K'' factor approach, which was suggested by one of the commenters,

has a precedent in the Acid Rain Program. Nearly all flow monitors must

be calibrated to match the EPA reference method (i.e., Method 2), by

using either a constant or a polynomial equation with multiple

coefficients. Section 6.5.7 of Appendix A of today's rule allows such

``K'' factors to be developed for moisture monitoring systems. The

``K'' value, which would be established at the time of the semiannual

or annual RATA, would be programmed into the DAHS and applied to the

subsequent moisture data. Sections 75.56 (a)(5)(ix) and 75.59

(a)(5)(vii) of today's rule require the owner or operator to keep

records on-site, indicating the current value of the coefficient or

``K'' factor and the date on which it began to be used. The rule

further requires a RATA of the moisture monitoring system whenever the

coefficient or ``K'' factor is changed.

Relative accuracy specifications of 10.0% (for semiannual RATA

frequency) and 7.5% (for annual RATA frequency) for moisture monitoring

systems have been promulgated in today's rule, as proposed. The

alternate RA specifications of 1.0% H2O (for

semiannual RATA frequency) and

0.7% H2O (for annual RATA frequency) have been

increased, respectively, to

1.5% H2O and 1.0% H2O.

In view of EPA's decision to allow the use of site-specific ``K''

factors for moisture monitoring systems, the Agency believes that

affected utilities will be able to meet these RA specifications.

The proposed rule set forth a missing data procedure for moisture

monitoring systems. Two commenters expressed concern regarding the

establishment of such a ``conservative'' missing data procedure (see

Docket A-97-35, Items IV-D-11 and IV-D-20). One of these commenters

further stated that there are insufficient data to know what

availability can reasonably be expected from moisture monitoring

systems,

[[Page 28568]]

especially in view of the proposed moisture QA/QC specifications. After

careful consideration, the Agency agrees with the commenter and, in

response, the final rule adopts the missing data procedures in

Sec. 75.37 that are less conservative than the procedures in the

proposed rule and that more closely resemble the standard missing data

procedures for SO2, NOX, and flow, as recommended

by the commenters. The moisture missing data algorithm is modeled after

the standard SO2 missing data algorithm in Sec. 75.33(b).

This is consistent with the provisions in Secs. 75.35 and 75.36 of

today's rule, which adopt this algorithm for CO2 and heat

input missing data. However, in finalizing the moisture missing data

provisions, it became evident that a single mathematical algorithm is

not adequate to cover all of the part 75 emission rate and heat input

equations that require moisture corrections. In most of the equations,

the lower moisture values are more conservative, and an ``inverted''

SO2 missing data algorithm is appropriate (for further

discussion of the ``inverted'' algorithm, see section C of this

preamble, below). However, there are certain emission rate equations

for which the opposite is true (i.e., the higher moisture values are

more conservative and the regular SO2 missing data algorithm

is appropriate). The specific equations for which the regular

SO2 algorithm applies are Equations F-3, F-4 and F-8 in

Method 19 in Appendix A of 40 CFR 60. Provided that all of the

moisture-corrected emission and heat input equations used by an

affected facility employ the same moisture missing data algorithm

(regular or inverted), it is a simple matter to substitute for missing

moisture data. However, when two or more equations require different

moisture algorithms, an alternative way of addressing missing moisture

data is needed. EPA believes that this situation will rarely be

encountered (at present, the Agency's records indicate that there are

only two such affected units in the Acid Rain Program). Therefore,

Sec. 75.37(d) of today's rule requires the owner or operator of such

units to petition the Administrator under Sec. 75.66(l), for an

alternative moisture missing data procedure.

Finally, several commenters requested that EPA allow the use of a

default moisture value in lieu of the required moisture monitoring (see

Docket A-97-35, Items IV-D-11, IV-D-02 and IV-D-23). The Agency has

performed a moisture data analysis for various fuels (see Docket A-97-

35, Item IV-A-2) and, based on the results, has provided fuel-specific

default values for moisture in today's rule (for coal and wood, only),

which may be reported for each unit operating hour, as an alternative

to operating and maintaining a continuous moisture monitoring system.

The default values are found in Secs. 75.11(b)(1) and 75.12(b) of

today's rule. Note that two sets of default values appear in the rule

to address the variability in format among the equations used for

determining pollutant emissions and heat input (as discussed in the

previous paragraph). The lower default values in Sec. 75.11(b)(1) apply

to Equations F-2, F-14b, F-16, F-17 and F-18 in Appendix F of part 75

and to Equations 19-5 and 19-9 in EPA Method 19 in Appendix A of 40 CFR

60. The higher default values in Sec. 75.12(b) apply when Equation 19-

3, 19-4 or 19-8 in EPA Method 19 in Appendix A of 40 CFR 60 is used to

determine the NOX emission rate. The default values were

determined as follows. The moisture percentage values (which included

both ultimate moisture and free moisture) for each fuel type were taken

from the appropriate tables in Docket Item IV-A-2, cited above. The

moisture values were then ranked from the lowest percentage value to

the highest percentage value, and the 10th percentile value was

selected for the ``low'' default value and the 90th percentile value

was selected for the ``high'' default value. Each default moisture

percentage was rounded to the nearest whole number.

C. Percent Monitor Availability

Background: EPA proposed that if the annual monitor data

availability dropped below 80% for SO2, NOX, flow

rate or CO2, this would violate the primary measurement

requirement of Sec. 75.10(a). In response to comments, today's final

rule does not treat a percent monitor data availability of less than

80% as a violation. Instead, the final rule provides that if percent

monitor data availability is less than 80%, then the appropriate

maximum value (i.e., maximum potential concentration (MPC) for

SO2 and CO2, maximum potential emission rate

(MER) for NOX and maximum potential flow rate for flow) will

have to be used as substitute data for any hour for which valid data is

not available. For O2, the minimum potential concentration

will be used to provide substitute data. For moisture, consistent with

the discussion in section B of this preamble, the minimum potential

moisture percentage will be used in most instances to provide

substitute data; however, for certain emission rate equations, the

maximum potential moisture percentage must be used.

Discussion: EPA received one comment that supported making a

percent monitor availability of less than 80% a violation (see Docket

A-97-35, Item IV-D-11) and another commenter favored the provision that

if percent monitor availability is below 80% due to ``unforseen events

beyond our control,'' this would be taken into consideration (see

Docket A-97-35, Item IV-G-9). EPA also received comments objecting to

making a percent monitor data availability of less than 80% a violation

and suggesting that EPA should modify the standard missing data

algorithms for SO2, NOX and flow rate to require

the use of a maximum substitute data value when monitor availability

drops below 80 percent (see Docket A-97-35, Items IV-D-17, IV-D-19, IV-

D-23, IV-D-24). In response to the comments, the final rule does not

make percent monitor availability of less than 80% a violation and

instead provides that if percent monitor data availability at a source

is less than 80%, then the owner or operator of the source will have to

substitute the appropriate maximum value (i.e., MPC for SO2

and CO2, MER for NOX emission rate and maximum

potential flow rate for flow) as suggested by the commenters. Note that

for O2 and, in most cases, for moisture, minimum potential

values will be substituted rather than maximum values, since the lower

values of these parameters are more conservative. However, if Equation

19-3, 19-4 or 19-8 in EPA Method 19 in Appendix A of 40 CFR 60 is used

to determine NOX emission rate, higher moisture values are

more conservative and the maximum potential moisture percentage will be

used to provide substitute data.

The missing data approach set forth in today's rule to address low

monitor data availability retains the basic design of the part 75

program and appropriately addresses the need for accountability from

sources that are inadequately maintaining their monitoring systems. The

Agency maintains that this provides a strong incentive to achieve at

least 80% monitor availability. Unlike the proposed approach of

considering sources to be in violation, the substitute data approach

adopted today creates this incentive while rendering unnecessary the

task of determining and evaluating the reason(s) for low monitor data

availability.

D. Span and Range Requirements

Background: The span of a CEMS provides an estimate of the highest

expected value for the parameter being

[[Page 28569]]

measured by the CEMS. For instance, the span value of an SO2

monitor is an approximation of the highest SO2 concentration

likely to be recorded by the CEMS during operation of the affected

unit. The range of a CEMS is the full-scale setting of the instrument.

Under part 75, the range of a monitor must be equal to or greater than

the span value. Section 2.1 of Appendix A further specifies that the

range must be chosen such that the majority of the readings during

normal operation fall between 25.0 and 75.0 percent of full-scale. The

span value is important because the reference gas concentrations and

signals used for daily calibration of the CEMS are expressed as

percentages of the span value. The allowable daily calibration error

for a CEMS is also expressed as a percentage of span.

Sections 2.1.1 through 2.1.4 of Appendix A of the January 11, 1993

rule specified procedures for determining the span values for

SO2, NOX, diluent gas (O2 or

CO2), and volumetric flow rate. For SO2, the

``maximum potential concentration'' (MPC) was first calculated based on

fuel sampling. The MPC values for NOX were specified in the

rule and were based on the type of fuel being combusted. The

SO2 and NOX span values were then determined by

multiplying the MPC by 1.25. For CO2 and O2, a

span value of 20.0 percent CO2 or O2 was required

for all diluent monitors. For flow rate, the ``maximum potential

velocity'' (MPV) was first determined. Then, the span value was

obtained by multiplying the MPV by 1.25 and rounding off the result.

In the January 11, 1993 rule, the SO2 or NOX

monitor range derived from the MPC was referred to as the ``high-

scale.'' The rule further specified that whenever the majority of the

readings during normal operation were expected to be less than 25.0

percent of the high full-scale range value (e.g., if a scrubber is used

to reduce SO2 emissions), a second, ``low-scale'' span and

range would be required. The low scale span value of the CEMS would be

defined as 1.25 times the ``maximum expected concentration'' (MEC).

In the first two years of Acid Rain Program implementation, it

became clear that the span and range provisions of part 75 lacked

sufficient flexibility and clarity. The May 17, 1995 rule revisions

attempted to address these deficiencies. Two alternative methods of

determining the MPC or MEC were added, i.e., from historical CEMS data

or from emission test results. For NOX, a comprehensive list

of MPC values was promulgated (Tables 2-1 and 2-2 in Appendix A),

taking into consideration the unit type in addition to the fuel type.

Flexibility was also added to the dual-range requirements for

NOX monitors. For flow rate, a more detailed procedure for

determining the span value was added.

The May 17, 1995 rule also revised the procedures for adjusting the

span and range of SO2, NOX, and flow monitors.

The original rule had specified that span and range adjustments were

required whenever the MPC, the MEC, or the MPV changed significantly

(although a ``significant'' change was undefined). When a significant

change in the MPC, MEC, or MPV occurred, a new range setting was to be

established and a new span value defined, equal to 80.0 percent of the

adjusted range value. The May 17, 1995 rule changed this procedure,

requiring the new span value to be determined first, followed by the

new range. The May 17, 1995 rule also added procedures for addressing

full-scale exceedances, specifying that the full-scale value is to be

reported for an exceedance of one hour and that a range adjustment is

required for an exceedance greater than one hour.

After promulgation of the May 17, 1995 rule, EPA continued to

receive questions and comments about the span and range sections of

part 75. Apparently, the span and range sections of the rule were still

not sufficiently clear, flexible, or detailed and were in need of

further revision. Therefore, on May 21, 1998, further revisions to the

span and range provisions were proposed.

The proposed rule provided an alternative procedure for determining

the MPC of SO2 or NOX, requiring the MPC to be

based upon a minimum of 720 quality assured monitor operating hours,

rather than 30 unit operating days. A specific requirement to calculate

the maximum potential NOX emission rate (MER) was also

proposed. The owner or operator could use the diluent cap value of 5.0

percent CO2 or 14.0 percent O2 for boilers (or

1.0 percent CO2 or 19.0 percent O2 for turbines)

in the NOX MER calculation.

The proposed rule provided a definition of the MPC for

CO2. The MPC would be 14.0 percent CO2 for

boilers and 6.0 percent CO2 for combustion turbines.

Alternatively, the MPC for CO2 could be based on a minimum

of 720 hours of representative quality assured historical CEM data. A

standardized procedure for calculating the maximum potential flow rate

(MPF) was proposed and a clear distinction between the ``calibration

span value'' of a flow monitor (expressed in the units of measure used

for the daily calibrations) and the ``flow rate span value'' (expressed

in the units used for electronic data reporting) was provided.

The proposed rule set forth changes to the procedures for

determining the maximum expected concentration (MEC) of SO2

and NOX, and to the criteria for determining whether dual

span and range requirements apply. A separate MEC determination would

be required for each type of fuel combusted, except for fuels that are

only used for unit startup or for flame stabilization. To determine

whether a second, low-scale span is required in addition to the high-

scale span based on the MPC, each of the maximum expected concentration

(MEC) values would be compared against the MPC. If any of the MEC

values was 2, NOX or flow

rate span value could be set anywhere between 1.00 and 1.25 times the

applicable maximum value (i.e., the MPC, MEC or MPF). For

CO2 and O2 monitors, the owner or operator would

be given maximum flexibility in selecting an appropriate span value.

For CO2 monitors installed on boilers, any representative

span value between 14.0 percent and 20.0 percent CO2 would

be acceptable. For combustion turbines, any representative

CO2 span value between 6.0 and 14.0 percent CO2

could be used. For O2 monitors, a span value between 15.0

percent and 25.0 percent O2 could be selected and an

alternative O2 span value of less than 15.0 percent could be

used, if supported by an acceptable technical justification.

The proposed rule expanded and clarified the guideline in section

2.1 of Appendix A for selecting an appropriate full-scale range. The

full-scale range would be selected so that the readings during typical

unit operation fall between 20.0 and 80.0 percent of full-scale, which

represents a slight increase in flexibility from the 25 to 75 percent

of full-scale guideline in the current rule. The proposal also cited

three specific cases in which the guideline in section 2.1 is

inapplicable: (1) during the combustion of very low sulfur fuels

(0.05% sulfur by weight); (2) for SO2 or

NOX readings on the high range for an affected unit with

SO2 or NOX emission controls and two span values;

and (3) when SO2 or NOX readings are less than

20.0 percent of the low measurement range for a dual-span unit with

SO2 or NOX emission controls, provided that the

low readings occur during periods of high control device efficiency.

[[Page 28570]]

The proposed rule specified that the following monitoring

configurations could be used to meet dual span and range requirements:

(1) a single analyzer with two ranges, or (2) two separate analyzers

connected to a common probe and sample interface. The high and low

ranges could be designated in the monitoring plan as two separate,

primary monitoring systems, or as separate components of a single,

primary monitoring system, or the ``normal'' range could be designated

as a primary monitoring system, and the other range as a non-redundant

backup monitoring system.

The proposed rule would allow the owner or operator to use a

``default high-range value'' in lieu of operating, maintaining, and

quality assuring a high-scale monitor range. The default high-range

value would be 200.0 percent of the MPC. This value would be reported

whenever the SO2 or NOX concentration exceeded

the full-scale of the low-range analyzer.

Finally, the proposed rule provided detailed guidelines and

procedures for adjusting the span and range of the CEMS. First, if the

maximum value upon which the high span value is based (i.e., the MPC or

MPF) was exceeded during a calendar quarter, but the span was not

exceeded, the span or range would not have to be adjusted. However, if

any quality assured hourly concentration or flow rate exceeded the MPC

or MPF by 5.0 percent during the quarter, a new MPC or MPF

would have to be defined. Second, if any quality assured reading on the

high measurement range exceeded the span value by 10.0

percent during the quarter but did not exceed the range, a new MPC or

MPF (as applicable) would have to be defined, and the span value (and

range, if necessary) would also have to be changed. Third, for full-

scale exceedances of a high monitor range, corrective action would be

required to adjust the span and range. A value of 200.0 percent of the

current full-scale range would be reported to EPA for each hour of each

full-scale exceedance.

Today's rule finalizes the proposed revisions to the span and range

sections of Appendix A. Most of the provisions have been finalized as

proposed, with only minor changes and clarifications. However, there

are three notable exceptions: (1) the proposed requirement for

mandatory quarterly evaluations of the MPC, MEC and MPF values and the

associated prescriptive criteria for adjusting the spans and ranges

have been withdrawn; (2) the proposed change in methodology for

determining dual span and range requirements (i.e., comparing the MEC

value(s) to the MPC) has been withdrawn; and (3) an additional

monitoring configuration option has been provided for units with dual

span requirements. For units with a dual-range SO2 or

NOX analyzer, the final rule allows the low and high ranges

to be represented as a single component of a primary SO2 or

NOX monitoring system.

Discussion: EPA received supportive comments from a number of

utilities, regarding several of the proposed span and range revisions

(see Docket A-97-35, Items IV-D-20, IV-D-23, IV-D-24, IV-D-25, and IV-

G-01). The commenters generally favored the increased flexibility in

determining SO2, NOX, CO2 and

O2 span values and supported the concept of a ``default high

range value.'' One commenter, however, opposed the use of purified

instrument air for O2 monitor calibrations (see Docket A-97-

35, Item IV-D-11) and, as discussed in greater detail below, two

commenters who supported the ``default high range'' concept took issue

with the proposed default value (see Docket A-97-35, Items IV-D-05 and

IV-D-24). One commenter asked EPA to give guidance as to what type of

technical justification would be required to use an alternative

O2 span value of less than 15 percent (see Docket A-97-35,

Item IV-D-23). The final rule provides an example, in section 2.3.1 of

Appendix A.

Several commenters stated that the proposed procedures for making

span and range adjustments were particularly complicated and burdensome

(see Docket A-97-35, Items IV-D-19, IV-D-20, IV-D-23, IV-D-24 and IV-G-

09). Two commenters stated that the requirement to perform quarterly

evaluations of the MPC, MEC and MPF values is unnecessary and excessive

(see Docket A-97-35, Items IV-D-11 and IV-G-02). One commenter

recommended using the guideline in section 2.1 of Appendix A to

determine whether span and range adjustments are needed (see Docket A-

97-35, Item IV-D-11). Another commenter recommended that EPA allow data

points that are clear ``outliers'' to be excluded from quarterly span

and range evaluations (see Docket A-97-35, Item IV-D-04). After

carefully considering these comments, EPA has decided to withdraw the

prescriptive proposed procedures for making span and range adjustments.

Instead, the final rule requires that span and range adjustments be

made only when the MPC, MEC or MPF changes ``significantly.'' This is

similar to the original guideline in the January 11, 1993 rule, except

that a ``significant'' change was undefined in that rule. In today's

rule, a significant change in the MPC, MEC or MPF means that the

guideline of section 2.1 of Appendix A ( for the majority of the

readings to be between 20 and 80% of the range, with certain allowable

exceptions) cannot be met, as determined either by the owner or

operator or through an audit by a regulatory agency. The Agency has

also reduced the frequency of mandatory evaluations of the MPC, MEC and

MPF values. In the final rule, only an annual evaluation of these

values is required. The results of the annual evaluations must be kept

on-site, in a format suitable for inspection.

Two commenters stated that the proposed requirement to treat the

two ranges of a dual-range monitor as separate monitoring systems or as

two separate components of the same system would cause additional

programming costs and would be technically difficult to implement (see

Docket A-97-35, Items IV-D-4 and IV-G-02). The commenters requested

that EPA continue to allow the low and high ranges to be represented in

the monitoring plan by a single component. After consideration, the

Agency has decided that the commenters' request is reasonable and has

included this option in the final rule. Note, however, that the use of

this option is restricted to dual-range analyzers that use electronic

gain to produce the two ranges. Today's rule requires the use of a

special dual-range component type code when this option is selected.

EPA will provide the necessary type code and reporting guidance in the

electronic data reporting (EDR) instructions for EDR version 2.1.

Two commenters stated that 200% of MPC is too high for the proposed

default high range value in sections 2.1.1.3(f) and 2.1.1.4(e) of

Appendix A, for the case where the owner or operator uses a default

value instead of operating a high-range monitor (see Docket A-97-35,

Items IV-D-05 and IV-D-24). A third commenter objected to the proposed

value of 200% of the range, which is to be reported during full-scale

exceedances (see Docket A-97-35, Item IV-G-05). Without a functional

high range monitor, it is not possible to determine the exact pollutant

concentration when a control device malfunctions or when a full-scale

exceedance occurs. In the preamble to the proposed rule, EPA cited one

instance in which the high SO2 range was exceeded and the

estimated SO2 concentration (based on fuel sampling) was

estimated to be about 150% of the range (see 63 FR 28058). For this

reason, the proposed values of 200% of the range (for full-scale

exceedances) and

[[Page 28571]]

200% of the MPC (for the default high range value) have been retained

in the final rule. EPA maintains that these values must be

conservative, based on a ``worst case'' analysis to ensure that

emissions will not be under-reported. The Agency believes that if spans

and ranges are properly set, full-scale exceedances will be relatively

rare. Also, EPA anticipates that the majority of the units for which

owners or operators will elect to use the default high range option

have reliable emission controls and the default value will rarely, if

ever, have to be used.

One commenter objected to the proposed changes to the method of

calculating MPC and MEC values, expressing concern that the revisions

might require his existing span and range values to be re-calculated

(see Docket A-97-35, Item IV-G-02). Another commenter (mistakenly)

interpreted the proposed definition of the MPC for CO2 in

section 2.3.1 of Appendix A to mean that his existing CO2

span values would have to be re-determined (see Docket A-97-35, Item

IV-D-04). A third commenter asked EPA to ``grandfather'' existing span

and range values (see Docket A-97-35, Item IV-D-20). It is not, and

never has been EPA's intent to require utilities to change their

existing spans and ranges, provided that they meet the guideline of

section 2.1 of Appendix A ( for the majority of the readings to be

between 20 and 80% of full-scale, with certain allowable exceptions).

The Agency does not believe that ``grandfathering'' of any existing

part 75 span and range values is necessary. The final rule simply adds

flexibility to the procedures for determining spans and ranges.

Affected units with previously-determined span and range values that

meet the guideline of section 2.1 of Appendix A do not have to change

their current span or range values. To further alleviate undue concern

about this, the Agency has withdrawn the proposed changes to the method

of determining whether a dual span is required. Rather than comparing

the MEC value(s) to the MPC value(s) (as proposed), today's rule

specifies that the MEC value should be compared to the high range

value. This is essentially the same as the requirement in the current

rule.

Finally, one commenter objected to the proposed requirement to

perform the RATA at the low range of the monitor on units that have

scrubbers. The commenter urged EPA to revert to the original rule and

allow the RATA to be performed at whatever range the CEMS is operating

on at the time of the RATA (see Docket A-97-35, Item IV-G-3). EPA does

not agree with the commenter. For units with SO2 scrubbers,

the vast majority of the data is collected on the low range. Therefore,

the SO2 RATA should be performed on that range. If the

scrubber malfunctions at the time of a scheduled SO2 RATA,

the RATA should either be rescheduled later in the quarter or should be

done during the 720 unit operating hour grace period allowed under

revised section 2.3.3 of Appendix B.

E. Flow-to-Load Ratio Test Requirements

Background: The quality assurance requirements for flow rate

monitoring systems in Appendices A and B of part 75 include daily

calibration error tests, daily interference checks, quarterly leak

checks (for differential pressure type monitors only), and semiannual

or annual RATAs. Of these required QA tests, only the RATA provides a

true evaluation of a flow monitor's measurement accuracy by direct

comparison against an independent reference method. The daily

calibration error test checks the system's internal electronic

components by means of reference signals. The calibration error test is

useful in that it can diagnose certain types of monitor problems, but

it does not evaluate the system's ability to measure an actual stack

gas flow rate. Because of this limitation, EPA believes that a more

substantive, periodic QA test is needed to ensure that the accuracy of

the reported flow rate data is maintained in the interval between

successive RATAs. The Agency is particularly concerned about the

potential for poor data quality from flow monitors that are not

properly maintained.

In view of this, EPA proposed to add a new flow monitor quality

assurance test, the ``flow-to-load ratio test,'' to part 75 in section

7.7 of Appendix A and section 2.2.5 of Appendix B. A similar test was

first suggested to the Agency by a flow monitor manufacturer (see

Docket A-97-35, Item II-D-69). The flow-to-load ratio test, which would

be performed quarterly, would be required beginning in the second

quarter of the year 2000. The basic premise of the flow-to-load ratio

test is that a meaningful correlation exists between the stack gas

volumetric flow rate and unit load. In general, for a single unit

discharging to a single stack, as the load increases, the flow rate

increases proportionally, and the flow rate at a given load should

remain relatively constant if the same type of fuel is burned. Common

stacks are somewhat less predictable, because the same combined unit

load can be produced in a number of ways by using different

combinations of boilers. Despite this, if the diluent gas concentration

is properly taken into account, the flow-to-load characteristics of

common stacks often become more normalized. The flow-to-load ratio, or

a normalized ratio, such as the gross heat rate (GHR) can thus serve as

a quantitative indicator of flow monitor accuracy from quarter to

quarter until the next RATA is performed.

The proposed rule provided a calculation methodology for the

quarterly flow-to-load or GHR evaluation. A ``reference'' flow-to-load

ratio or GHR would be established at the time of each normal-load flow

RATA, using data from the flow rate reference method. Then, in

subsequent quarters, hourly data from the flow monitor would be

compared to the reference ratio or GHR, and an absolute average

percentage difference between the hourly data and the reference ratio

would be calculated. If the percentage difference exceeded certain

limits, the utility would be required to investigate to try to

establish the cause of the test failure. If the investigation indicated

a problem with the flow monitor, the utility could perform corrective

actions, followed by an abbreviated flow-to-load diagnostic test, to

demonstrate that the corrective actions were effective. However, if the

investigation could not establish the cause of the flow-to-load test

failure, a normal load flow RATA would be required.

Today's final rule adopts the flow-to-load ratio test provisions.

The final rule is essentially the same as the proposal except for a few

minor changes in response to comments received.

Discussion: EPA received comments on the proposed quarterly flow-

to-load ratio test from seven utilities, two state agencies, one

utility regulatory response group and one flow monitor vendor. One

state agency was supportive of the test, because it can serve as a

quantitative indicator of flow monitor performance from quarter to

quarter (see Docket A-97-35, Item IV-D-9). The flow monitor vendor also

favored the test, because it will help to ensure that all flow

monitoring technologies perform in a reliable manner (see Docket A-97-

35, Item IV-D-12). Several utility commenters objected to the proposed

test, believing it would be burdensome, time-consuming, expensive to

implement (requiring significant DAHS software modifications), and

difficult to pass (see Docket A-97-35, Items IV-D-16, IV-G-5, IV-G-9,

IV-G-2). One commenter suggested that the test be used as a warning to

take corrective action rather than using it to directly validate or

invalidate flow rate data (see

[[Page 28572]]

Docket A-97-35, Item IV-D-11). Another commenter recommended that for

common stacks, additional hours be exempted from the data analysis,

specifically hours in which the combination of boilers and loads does

not match the combination used during the last normal load flow RATA

(see Docket A-97-35, Item IV-D-17). Two commenters recommended

increasing the threshold to qualify for a less stringent flow-to-load

specification from 50 MW to 60 or 70 MW (see Docket A-97-35, Items IV-

D-11, IV-D-2). Two commenters recommended reducing the frequency of

flow RATAs based on good performance in the flow-to-load test;

specifically, one commenter advocated performing flow RATAs every other

year and the other commenter recommended performing a flow RATA once

every five years (see Docket A-97-35, Items IV-D-22, IV-G-2). One

commenter stated that the proposed flow-to-load methodology does not

adequately address multiple stack configurations where one of the

stacks is a bypass stack, and also recommended that EPA make it clear

that the flow-to-load data analysis only applies to reported data and

not to redundant backup monitor data which are not reported (see Docket

A-97-35, Item IV-G-2). Finally, the utility regulatory response group

found the proposal to be an improvement over the pre-proposal draft

that was circulated in May, 1997, but took issue with the following:

(1) The method of calculating the test results, using the absolute

value of, rather than the arithmetic, percentage of differences between

the hourly flow-to-load ratios and the reference ratio; (2) failure of

the proposal to address units with bypass stacks or other complex stack

configurations; and (3) allowing only one week after the end of the

quarter to investigate and troubleshoot the flow monitor when a flow-

to-load test failure occurs, before a RATA requirement is triggered

(see Docket A-97-35, Item IV-D-20).

Today's rule includes flow-to-load test provisions in section 7.7

of Appendix A and section 2.2.5 of Appendix B. The final rule is

essentially the same as the proposal, except for the following changes,

which have been incorporated in response to the comments received.

First, a new section 7.8 has been added to Appendix A, which allows

owners or operators of units with complex stack configurations to

petition for an exemption from quarterly flow-to-load testing. Any such

petition would have to provide information and data which demonstrate

to the satisfaction of the Administrator that the flow rate through the

complex stack configuration cannot be reasonably correlated to unit

load. Second, for a unit with a multiple stack discharge configuration

consisting of a main stack and a bypass stack (e.g., for a unit with a

wet SO2 scrubber), the flow-to-load test is to be performed

on an individual stack basis and hours in which emissions are

discharged simultaneously through both stacks may be excluded from the

quarterly flow-to-load analysis. Third, the threshold to qualify for a

less stringent flow-to-load specification has been raised from 50 MW to

60 MW. Fourth, when a flow-to-load or GHR test is failed, two weeks,

rather than one, are allowed after the end of the quarter to

investigate the cause of the test failure before triggering a RATA

requirement.

EPA does not agree with the commenters who characterized the

proposed flow-to-load test as time-consuming, burdensome, and difficult

to implement (requiring extensive software revision). The Agency

believes that implementation of the flow-to-load test will not require

any special modification of existing part 75 DAHS systems or software.

All of the information needed to perform the quarterly flow-to-load or

GHR analysis is currently reported in the electronic quarterly report

required under Sec. 75.64. Rather, a PC-based computer program will be

needed, which can extract the essential information from the quarterly

report and analyze it. Once such a computer program is written,

analysis of the quarterly flow rate and load data should become a

routine operation which will be neither burdensome nor time-consuming.

The Agency also disagrees with those commenters who contended that

the flow-to-load test will be difficult to pass. On the contrary, the

flow-to-load test should be relatively easy to pass, provided that the

flow monitor is properly operated and well-maintained. Prior to issuing

the proposed rule, EPA analyzed quarterly flow rate and load data from

the third quarter of 1996 for 21 units and stacks, including 9 single

units, 11 common stacks, and 1 multiple-stack unit. The units chosen

for this analysis were selected as a representative sample of units

that would be affected by this QA test requirement and included various

operational circumstances (e.g., base loaded and peaking units, single

fuel units, and units that burn multiple fuels). The flow-to-load and

GHR test methodologies were applied to each unit or stack, excluding

none of the normal load data from the analysis. The results of the

flow-to-load and GHR data analyses were nearly the same. Only one

failure of the quarterly flow-to-load test was observed in each

analysis (i.e., the failure rate was f (the average percentage difference between the hourly

ratios and the reference ratio) was 6.1 percent for the analysis of the

flow-to-load ratios and 6.4 percent for the simulated GHR analysis

(with diluent gas corrections). However, as noted by one of the

commenters, the Agency acknowledges that these data analyses were

performed using the calculation method described in the May, 1997 pre-

proposal draft of the rule revisions, i.e., using the arithmetic

percentage difference between each hourly flow-to-load ratio and the

reference ratio, rather than the absolute percentage difference

prescribed in the proposed rule. To address the commenter's concern,

EPA has re-analyzed the data using the absolute percentage difference.

The results of the data analysis using the absolute percentage

difference were nearly the same as the results using the arithmetic

percentage difference. The failure rate was the same (f was 7.3 percent for the analysis of the flow-to-

load ratios and 8.0 percent for the simulated GHR analysis (with

diluent gas corrections), which is still well below the 15.0 percent

tolerance limit (see Docket A-97-35, Item IV-A-3). Thus, it appears to

make very little difference, in terms of ease of passing, whether the

absolute percentage difference or the arithmetic percentage difference

is used in the flow-to-load and GHR calculations. Therefore, the flow-

to-load and GHR calculation methodology has been finalized as proposed

using the absolute percentage difference.

Two commenters suggested that the flow RATA frequency should be

reduced based on good performance on the quarterly flow-to-load test

(see Docket A-97-35, Items IV-D-22 and IV-G-02). The Agency agrees with

the commenters that with the addition of the new QA tests it is

reasonable to lessen the frequency of the annual three load flow RATA.

Therefore, EPA is also adopting the following three provisions reducing

the flow RATA requirements: (1) Routine flow RATAs are changed from

three-load tests to two-load tests; (2) a single-load annual flow RATA

is allowed if the unit operates at one load level for 85

percent of the time since the last annual flow RATA; and (3) a three-

load flow RATA is required only once every five years and whenever the

instrument is re-linearized. EPA has adopted these reduced flow RATA

[[Page 28573]]

requirements principally because of the reasonable assurance of data

quality that will be provided in between RATAs by the new flow-to-load

test. Note, however, that the flow-to-load ratio test, which analyzes a

limited amount of flow rate data at a single load level, does not serve

as a replacement for annual RATA testing. Rather, the flow-to-load

ratio test helps to ensure that the flow monitor remains accurate in

between successive semiannual or annual RATAs.

F. RATA and Bias Test Requirements

1. RATA Load Levels

Background: The previous provisions of part 75 were neither

sufficiently standardized nor clear in defining the appropriate load

levels for RATAs. For example, the previous rule required gas monitor

RATAs to be conducted at normal load and required gas and flow rate

monitor bias adjustment factors to be determined at normal load, but no

definition of normal load was provided. In addition, section 6.5.2 of

Appendix A specified that the ``low'' load audit point for a 3-level

flow RATA can be located anywhere from the minimum safe, stable load to

50.0 percent of the maximum load, and no minimum separation is required

between the audit points at adjacent load levels. If adjacent audit

points are too close together, a multiple load flow evaluation loses

its significance.

EPA proposed revisions to Appendix A of part 75, which would more

clearly define the load levels at which RATAs are done in order to

achieve greater consistency in the way that RATAs are performed. The

proposed methodology, which would become effective as of April 1, 2000,

would require the utility to define the ``range of operation'' for each

affected unit or common stack (except for peaking units). The range of

operation would extend from the minimum safe, stable load to the

maximum achievable load. The ``low'' load level would then be defined

as 0-30% of the range of operation, the ``mid'' load level would be 30-

60% of the range and the ``high'' load level would be 60-100% of the

range. The proposed methodology would require a load frequency

distribution (histogram) to be developed, prior to each annual RATA, to

determine the percentage of time the unit or stack has operated at each

load level in the previous four ``QA operating quarters.'' A summary of

the data used for the load frequency determination would be maintained

on-site in a format suitable for inspection, and the results of the

determination would be included in the electronic quarterly report

under Sec. 75.64. The most frequently used load level would then be

designated as the ``normal'' load. The second most frequently used load

could, at the discretion of the owner or operator, be designated as a

second normal load level. Gas monitor RATAs would be required at the

normal load level. Routine quality assurance RATAs for flow monitors

would be done at the two most frequently used load levels. Today's rule

adopts the proposed changes with certain modifications in response to

comments.

Discussion: The Agency received comments on the proposed method of

determining RATA load levels from three individual utilities and from

two utility regulatory response groups. Only two comments were received

on the proposed definitions of ``range of operation,'' ``low,''

``mid,'' and ``high'' load levels. One commenter supported the effort

to establish load level definitions, but found the proposal to be too

inflexible and complicated and suggested that EPA should permit

overlapping load ranges (see Docket A-97-35, Item IV-D-20). The other

commenter requested that EPA modify the proposed definition of the

``minimum safe, stable load'' for common stacks. The commenter

expressed concern that for base-loaded units which share a common

stack, the proposed definition might require a unit to be shut down to

attain the low load level in a 3-load flow RATA (see Docket A-97-35,

Item IV-D-24). Four commenters opposed the proposed requirement to

develop a historical load frequency distribution to establish the

normal load level(s) for the unit or stack, stating that the load

frequency is too variable (being dependent on unit availability,

operation, and dispatch) and that the new requirement would add another

level of unnecessary data collection and manipulation (see Docket A-97-

35, Items IV-D-20, IV-D-24, IV-D-19, and IV-D-23). Another commenter

suggested that RATA load ranges should be based on the typical load

requirements for the quarter in which the RATA is done, particularly if

the historical data are no longer representative. The commenters

further recommended that EPA should: (1) eliminate the requirement to

use four operating quarters of data; (2) allow extenuating data to be

excluded; (3) allow recent changes to be considered when selecting load

ranges; and (4) allow utilities to consider forecasted usage of a unit

when selecting load ranges (see Docket A-97-35, Item IV-D-20). Finally,

one commenter objected to the proposed requirement to report the

results of the load frequency data analysis electronically, stating

that requiring electronic reporting of the results provides no

advantage over keeping the data analysis on-site and that such

reporting would require DAHS software changes (see Docket A-97-35, Item

IV-G-2).

Today's rule finalizes the proposed definitions of the ``range of

operation,'' and the ``low,'' ``mid,'' and ``high'' load levels in

section 6.5.2.1 of Appendix A and the associated requirement to report

the upper and lower boundaries of the range of operation, with one

minor revision. A provision has been added for frequently-operated

(e.g., base-loaded) units that share a common stack, which allows the

``minimum safe, stable load'' to be determined in a different manner.

For such units, the owner or operator may use the sum of the minimum

safe, stable loads for the individual units as the minimum safe stable

load for the common stack (rather than using the lowest of the minimum

safe, stable load values for the individual units). The Agency believes

that this adequately addresses the commenter's concern that one or more

units might have to be shut down in order to attain the ``low'' load

level during a 3-load flow RATA.

Section 6.5.2.1 of Appendix A of today's rule also finalizes the

proposed methodology for determining normal load and for selecting the

appropriate load levels for the annual 2-load flow RATAs, with

revisions based on comments received. In the final rule, a

determination of the normal load level(s) and the appropriate flow RATA

load levels is still required, but it has been made a one-time

requirement, rather than an annual requirement. The requirement becomes

effective on April 1, 2000, but owners or operators may comply with it

prior to that date. The owner or operator must review historical load

data for the unit or stack, for a minimum of four representative

operating quarters. From these data, the percentage of unit operating

time at each load level (``low,'' ``mid'' or ``high'') will be

determined. The historical load data may be analyzed by any suitable

means; construction of a histogram, per se, is not required. The load

level used the most frequently will be designated normal, and the

second most frequently used load level may, at the discretion of the

owner or operator, be designated as a second normal load. The two most

frequently used load levels are the load levels at which the annual 2-

load flow RATA will be performed. The results of the historical load

data analysis will be reported in the electronic quarterly report as

part of the electronic monitoring plan. EPA

[[Page 28574]]

believes that reporting one additional monitoring plan record will not

prove to be burdensome. A summary of the data used for the load

determinations and the calculated results must be kept on-site, in a

format suitable for inspection.

EPA continues to believe that a review of historical operating load

data is a reasonable way to standardize the determination of the normal

load level(s) and the appropriate flow RATA load levels for a unit or

stack. In order to maintain national consistency and to ensure that a

``level playing field'' is maintained among affected utilities, the

Agency believes that a standardized procedure is necessary. Although

several commenters took issue with the specifics of the proposed

methodology, none of them provided a sufficiently detailed alternative

procedure for serious consideration by the Agency. Requests to ``allow

exclusion of extenuating data'' and ``permit consideration of recent

changes when selecting load ranges'' do not provide a sufficient basis

for the development of appropriate regulatory language. Further, since

the standardized procedure is based on data for four operating

quarters, any unrepresentative data is likely to have minimal effect.

Therefore, EPA did not incorporate most of the commenters' suggestions.

However, to address the concern of several commenters about possible

variability in unit load and manner of unit operation, a provision has

been added to section 6.5.2.1 of Appendix A which requires the

historical load analysis to be repeated if the way in which a unit

operates changes significantly and the previously-determined normal

load level(s) and the two most frequently used load levels change. The

new provision requires a minimum of two representative operating

quarters of historical load data to document that a change in the

manner of unit operation has actually occurred.

2. Single-Point Reference Method Sampling

Background: Section 6.5.6 of Appendix A to part 75 gives the

traverse point location requirements for reference method sampling

during relative accuracy test audits (RATAs) of gas monitoring systems.

The reference method sampling points are to be located along a line, in

accordance with section 3.2 of Performance Specification No. 2 in

Appendix B to 40 CFR part 60. Performance Specification No. 2 requires

three reference method sampling points for each RATA test run. EPA

proposed changes to section 6.5.6 of Appendix A, pertaining to RATA

traverse point selection. Proposed section 6.5.6 would allow single-

point reference method sampling to be used in two specific instances:

(1) for all moisture determinations, a single reference method point,

located at least 1.0 meter from the stack wall, could be used; and (2)

for flue gas sampling, a single reference method measurement point,

located no less than 1.0 meter from the stack wall, could be used at

any test location if a stratification test is performed prior to each

RATA at the location and certain acceptance criteria are met.

In order to implement the second option (single-point gas

sampling), a 12-point stratification test, as described in proposed

section 6.5.6.1, would have to be passed one time at the sampling

location, meeting the acceptance criteria for single-point sampling

given in proposed section 6.5.6.3 of Appendix A. The location would

qualify for single-point gas sampling if the concentration at each

individual traverse point differed by no more than 5.0

percent from the arithmetic average concentration for all traverse

points. The results would also be acceptable if the concentration at

each individual traverse point differed by no more than

3.0 ppm or 0.3 percent CO2 (or O2) from the

arithmetic average concentration for all traverse points. Once a 12-

point stratification test was passed at the candidate sampling

location, either the 12-point test or an abbreviated 3-point or 6-point

stratification test, as described in proposed section 6.5.6.2, would

have to be passed prior to subsequent RATAs at the location.

Today's rule finalizes the provisions for single-point moisture and

gas reference method sampling, with certain modifications in response

to comments received. The criteria in today's rule to qualify for

single-point sampling are more stringent than the criteria in the

proposed rule.

Discussion: EPA received comments from two utilities and three

State air regulatory agencies on the proposal to allow single-point

reference method sampling. One of the utility commenters favored

allowing single-point sampling, viewing it as an excellent step to

improve the overall efficiency of RATA testing (see Docket A-97-35,

Item IV-D-21). The other utility commenter also favored the proposal,

believing that it would reduce the manpower requirements for gas RATA

testing (see Docket A-97-35, Item IV-D-22). One State agency commenter

opposed the unrestricted use of single-point moisture sampling, stating

that the moisture results could be biased if gas stratification is

present in the stack. Another State agency commenter viewed the

proposal to allow single-point reference method sampling as

unfavorable, expressing concern that single-point sampling may not

yield valid results, particularly if the sampling point is too near the

stack wall, where air in-leakage can occur (see Docket A-97-35, Item

IV-D-9). The third State agency commenter appeared to take issue with

the use of a 3-point abbreviated stratification test, stating that for

the large-diameter stacks in the Acid Rain Program, a three point test

is not adequate to demonstrate the absence of stratification.

In response to the comments received, the single-point reference

method provisions in section 6.5.6 of Appendix A of today's rule are

more restrictive than the provisions in the proposal. After careful

consideration, EPA has decided to allow single-point reference method

sampling, but to place additional restrictions on its use. The Agency

believes that some of the state agency commenters' concerns about the

proposed single-point sampling methodology are valid. Accordingly,

today's final rule addresses these concerns.

Today's rule allows the unrestricted use of single-point moisture

sampling only in applications where the moisture data are used to

determine the stack gas molecular weight. For all other moisture

measurement applications, i.e., for moisture monitoring system RATAs or

when moisture data are used to correct emission data from a dry basis

to a wet basis (or vice-versa), single-point moisture sampling is only

permitted if a 12-point pollutant or diluent gas stratification test is

performed and passed (at the 5.0 percent specification in section

6.5.6.3 of Appendix A) prior to the RATA. Similarly, for flue gas

sampling, today's rule allows the use of single-point reference method

sampling only if a 12-point gas stratification test is performed and

passed at the 5.0 percent specification prior to the RATA. Use of an

abbreviated (3- or 6-point) stratification test as a means of

qualifying for single-point sampling is not allowed.

Finally, when a test location qualifies for single-point reference

method sampling, today's rule specifies that the measurement point must

be located at least 1.0 meter from the stack wall and must be situated

along one of the measurement lines used in the 12-point stratification

test. EPA believes that these modifications to the proposed single-

point reference method sampling methodology are necessary to ensure

[[Page 28575]]

that representative samples will continue to be obtained.

G. Data Validation

1. Data Validation During Monitor Certification and Recertification

Background: The previous version of part 75 specified that for any

replacement, change, or modification to a monitoring system requiring

recertification of the CEMS, all data from the CEMS are invalid from

the hour of that replacement, change, or modification until the hour of

completion of all required recertification tests. The proposed rule

would have revised Sec. 75.20(b)(3) to conditionally allow emission

data generated by the CEMS during a recertification test period to be

used for part 75 reporting, provided that the required tests are

successfully completed in a timely manner and that certain data

validation rules are followed during the recertification test period.

Proposed sections 6.2, 6.3.1, and 6.5 of Appendix A would have allowed

these new data validation procedures to also be applied to the initial

certification of monitoring systems. The intended purpose of the

proposed revisions is to minimize the number of hours of substitute

data or maximum potential values that must be reported during a monitor

certification or recertification period.

In proposed Sec. 75.20(b)(3), specific rules were provided for data

validation during the recertification test period. The recertification

test period would begin with the first successful calibration error

test (known as a ``probationary calibration error test'') after making

the change to the CEMS and completing all necessary post-change

adjustments (e.g., reprogramming or linearization) of the CEMS. The

post-change activities could include preliminary tests such as trial

RATA runs or a challenge of the monitor with calibration gases. Data

from the CEMS would be considered invalid from the hour in which the

replacement, modification, or change to the system is commenced until

the hour of completion of the probationary calibration error test, at

which point the data status would become ``conditionally valid.''

The conditionally valid status of the CEMS data would continue

throughout the recertification test period, provided that the required

recertification tests were done ``hands-off'' (i.e., with no

adjustments, such as reprogramming or linearization of the CEMS, other

than the calibration adjustments allowed under proposed section 2.1.3

of Appendix B) and provided that the recertification tests and required

daily calibration error tests continued to be passed. If all of the

required recertification tests and calibration error tests were passed

hands-off, with no failures and within the required time period, then

all of the conditionally valid emission data recorded by the CEMS

during the recertification test period would be considered quality

assured and suitable for part 75 reporting. However, if any required

test was failed, the conditionally valid data would, in most cases, be

invalidated and a new recertification test period would have to be

initiated, following corrective actions.

Today's rule finalizes the CEMS validation procedures for

certifications and recertifications, with certain modifications in

response to comments received.

Discussion: EPA received strongly supportive comments on the

proposed revisions to Sec. 75.20(b)(3) from five utilities, one state

air regulatory agency and two utility regulatory response groups.

However, two utilities asked the Agency to modify the proposal to allow

trial gas injections and preliminary RATA runs to be done during the

recertification test period, rather than prior to it. One commenter

stated that preliminary gas injections and RATA runs, which are

considered to be a valuable maintenance tool, should be allowed

following the probationary calibration error test, and, provided that

the results of the trial runs are acceptable, the recertification

should be allowed to proceed (see Docket A-97-35, Item IV-G-3). Another

commenter requested that the proposal be revised to allow a single

challenge with each of the three gases prior to a linearity test and to

allow up to five preliminary trial runs prior to a RATA (see Docket A-

97-35, Item IV-G-5).

Today's rule finalizes the proposed data validation procedures in

Sec. 75.20(b)(3) for monitor certification and recertification, with

the following modifications in response to the comments. First, an

introductory statement of applicability has been added at the beginning

of Sec. 75.20(b)(3), clearly indicating that the provisions of the

section apply both to recertifications and to initial certifications.

The statement of applicability also allows the data validation

procedures to be applied, at the discretion of the owner or operator,

to the routine quality assurance linearity tests and RATAs required

under Appendix B of part 75 (see the section on ``Data Validation for

RATAs and Linearity Checks'' in this preamble, for a further discussion

of this option). Second, proposed paragraph (b)(3)(x) of Sec. 75.20 has

been merged with proposed paragraph (b)(3)(i), for greater clarity;

both paragraphs deal with missing data substitution prior to the

recertification test period. Third, the definition of a ``hands-off''

recertification test in Sec. 75.20(b)(3)(v) has been revised to make it

clear that once a recertification test has begun, only routine

calibration adjustments following daily calibration error tests are

permitted until the test is completed. Fourth, language has been added

to Sec. 75.20(b)(3) to address the case in which a multi-load flow RATA

is passed at one or more load levels and then failed at a subsequent

load level.

Regarding the fourth revision to Sec. 75.20(b)(3) described in the

previous paragraph, 2.3.2(e) of Appendix B of today's rule states that

in such cases, only the RATA at the failed load level needs to be

repeated (unless re-linearization of the monitor is necessary, in which

case a 3-load RATA is required). Because of this new Appendix B

provision, the following corresponding data validation provisions have

been added to Secs. 75.20(b)(3)(vii)(A) and 75.20(b)(3)(vii)(B): (1)

upon failure of the RATA at the particular load level, the length of

the new recertification test period is not 720 unit operating hours,

but is equal to the number of hours remaining in the original

recertification test period at the time of test failure; and (2) data

invalidation is prospective, beginning with the hour of failure of the

RATA at the particular load level; therefore, conditionally valid data

recorded prior to the test failure at the particular load level are not

invalidated. Finally, in response to the comments received, a new

paragraph, (b)(3)(vii)(E), has been added to Sec. 75.20 to address the

issue of trial RATA runs and pre-test gas injections. Section

75.20(b)(3)(vii)(E) allows pre-test trial gas injections and pre-RATA

runs to be done during the recertification period, for the purpose of

optimizing the performance of the monitoring system. A trial run or

injection will not affect the status of previously-recorded

conditionally valid data, provided that: (1) the results of the trial

run are within the Appendix A specifications for a passed linearity

test or RATA (i.e., for a trial gas injection, within 5% or

5 ppm of the reference gas or, for a trial RATA run, if the average

reference method and the average CEMS readings differ by no more than

10% of the reference method value, or 15 ppm,

or 0.02

lb/mmBtu, or 1.5% H2O, as applicable); (2) no

adjustments are made

[[Page 28576]]

to the calibration of the CEMS following the trial run, other than the

adjustments allowed under section 2.1.3 of Appendix B; and (3) the CEMS

is not repaired, re-linearized, or reprogrammed after the trial run. As

long as these conditions continue to be met, the CEMS can be further

optimized without data loss. However, if, for any trial run or

injection the conditions are not met, the trial run or injection is

treated as a failed or aborted linearity check or RATA and the

applicable provisions in Secs. 75.20(b)(3)(vii)(A) and

75.20(b)(3)(vii)(B) pertaining to aborted or failed recertification

tests must be followed.

2. Data Validation for RATAs and Linearity Checks

Background: EPA proposed rules for CEMS data validation prior to

and during the periodic linearity tests and RATAs required by part 75.

These new provisions were found in proposed sections 2.2.3 and 2.3.2 of

Appendix B. According to these provisions, a linearity test or RATA

could not be started if the CEMS were operating ``out-of-control'' with

respect to any of its other daily, semiannual, or annual quality

assurance tests. Prior to the test, both routine and non-routine

calibration adjustments, as defined in proposed section 2.1.3 of

Appendix B, would be permitted. During the linearity or RATA test

period, however, no adjustment of the monitor would be permitted except

for routine daily calibration adjustments following successful daily

calibration error tests. For 2-level and 3-level flow RATAs, no

linearization of the monitor would be permitted between load levels. If

a linearity check or RATA was failed or aborted due to a problem with

the monitor, the monitor would be declared out-of-control as of the

hour in which the test is failed or aborted. Data from the monitor

would remain invalid until the hour of completion of a subsequent

successful test of the same type.

The proposed rule also attempted to clarify the way in which

linearity and RATA test results are to be reported to EPA in the

electronic quarterly report required under Sec. 75.64. Proposed

sections 2.2.3 and 2.3.2 of Appendix B specified that only the results

of completed and partial tests which affect data validation would have

to be reported. That is, all completed passed tests, all completed

failed tests, and all tests aborted due to a problem with the CEMS

would have to be included in the quarterly report. Therefore, aborted

test attempts followed by corrective maintenance, re-linearization of

the monitor, or any other adjustments other than those allowed under

proposed section 2.1.3 of Appendix B would have to be reported.

However, tests which are aborted or invalidated due to problems with

the calibration gases or reference method or due to operational

problems with the affected unit(s) would not need to be reported,

because such runs do not affect the validation status of emission data

recorded by the CEMS. In addition, aborted RATA attempts which are part

of the process of optimizing a monitoring system's performance would

not have to be reported, provided that in the period from the end of

the aborted test to the commencement of the next RATA attempt: (1) no

corrective maintenance or re-linearization of the CEMS was performed,

and (2) no adjustments other than the calibration adjustments allowed

under proposed section 2.1.3 of Appendix B were made. However, such

aborted RATA runs would still have to be documented and kept on-site as

part of the official test log.

Today's rule finalizes the CEMS data validation requirements for

RATAs and linearity checks. The final rule has been modified from the

proposal, based on comments received.

Discussion: EPA received comments on the proposed data validation

procedures for RATAs and linearity checks from one state air regulatory

agency, two utilities and one utility regulatory response group. Two of

the commenters found the proposed rule language defining the allowable

pre-test adjustments to be inconsistent with the preamble language

found at 63 FR 28075. The commenters noted an apparent contradiction

between the preamble statement that there is ``no significant risk in

allowing pre-RATA adjustments provided that the monitor's accuracy

between successive RATAs can be reasonably established'' and the rule

language in section 6.5(a)(1) of Appendix A that ``no adjustments,

linearizations or reprogramming of the CEMS other than the calibration

adjustments described in section 2.1.3 of Appendix B to this part, are

permitted prior to and during the RATA test period.'' Both commenters

expressed concern that this proposed rule language appeared to exclude

important activities such as re-linearization of a flow monitor (see

Docket A-97-35, Items IV-D-20, IV-G-2). Another commenter also objected

to the proposed language in section 6.5(a)(1) of Appendix A, stating

that technicians need to be able to perform evaluations and adjustments

of flow and gas measurement systems prior to conducting a RATA (see

Docket A-97-35, Item IV-G-3). Another commenter took issue with the

provisions in proposed sections 2.2.3 and 2.3.2 of Appendix B which

allow ``non-routine'' adjustments to be made prior to linearity tests

and RATAs. The commenter especially objected to the idea of allowing

adjustments in a direction away from the reference gas tag value,

believing that this compromises the integrity of the audit and sets an

``unfortunate precedent'' (see Docket A-97-35, Item IV-D-11).

Today's rule finalizes the data validation provisions for linearity

checks and RATAs in sections 2.2.3 and 2.3.2 of Appendix B. Based on

the comments received, EPA has made substantive revisions to the

proposed rule in an attempt to clarify the allowable pre-test

adjustments and the rules for validating the CEMS data. Today's rule

specifies that when a linearity check or RATA is due, the owner or

operator has three options. First, the test may be done ``cold,'' with

no pre-test adjustments of any kind. Second, the test may be done after

making only the routine or non-routine calibration adjustments allowed

under section 2.1.3 of Appendix B. Under this second option, trial gas

injections and preliminary RATA runs are allowed, followed by

additional adjustments (if necessary) within the limits of section

2.1.3 of Appendix B, to optimize the monitor's performance. The trial

runs or injections need not be reported, provided that they meet the

acceptance criteria for trial RATA runs and gas injections in

Sec. 75.20(b)(3)(vii)(E) (see the section of this preamble entitled

``Data Validation During Monitor Certification and Recertification''

for further discussion of these acceptance criteria). If the acceptance

criteria are not met, the trial run is counted as a failed or aborted

test. Third, the CEMS may be repaired, re-linearized or reprogrammed

prior to the quality assurance test. In this case, the CEMS may either

be considered out-of-control from the hour of commencement of the

corrective maintenance, re-linearization or reprogramming until

completion of the required quality assurance test or the owner or

operator may follow the data validation procedures in Sec. 75.20(b)(3)

upon completion of the necessary corrective maintenance, re-

linearization, or reprogramming.

EPA believes that the revisions to sections 2.2.3 and 2.3.2 of

Appendix B address the commenters' concerns about pre-test adjustments.

For example, if, at the time of a scheduled flow RATA, the owner or

operator decides to re-linearize the primary flow monitor to optimize

its performance, this would be permissible under the third option

above. However, re-linearization of a flow monitor

[[Page 28577]]

triggers a requirement to perform a 3-load RATA. Therefore, if the

monitor is declared out-of-control from the hour of the re-

linearization until the hour of completion of the 3-load RATA (as would

be required by the proposed rule), this could result in significant

data loss, since a 3-load RATA can take days (or even weeks) to

complete, depending on electrical demand. For this reason, today's rule

allows the owner or operator to use the recertification data validation

procedures in Sec. 75.20(b)(3) to supplement the quality assurance

provisions in Appendix B. In this example, if the owner or operator

opts to use the data validation procedures in Sec. 75.20(b)(3), data

from the flow monitor would be considered conditionally valid upon

completion of a ``probationary calibration error test,'' following the

re-linearization of the monitor. The procedures in

Sec. 75.20(b)(3)(vii)(E) allow for trial runs and further optimization

of the monitor prior to the RATA. If the 3-level flow RATA is then

passed in accordance with the procedures of Sec. 75.20(b)(3) and within

the allotted time frame (indicating that the re-linearization was

successful), the conditionally valid data will become quality assured

and may be used for reporting.

For the following reasons, EPA does not agree with the commenter

who opposed allowing ``non-routine'' calibration adjustments prior to a

quality assurance test. The ``non-routine'' adjustments described in

section 2.1.3 of Appendix B allow adjustments only within the

performance specifications of the instrument. When a monitor is

initially certified, it must pass several quality assurance tests, one

of which is a 7-day calibration error test. The monitor must

demonstrate, for 7 consecutive operating days, that it is capable of

meeting a calibration error specification of 2.5 percent of

the instrument span (3.0 percent for flow monitors). Once a

monitor has been certified, the ``control limits'' for daily

calibration error tests of the monitor are twice the performance

specification value, i.e., 5.0 percent of span for gas

monitors and 6.0 percent for flow monitors. Thus, when the

``non-routine'' adjustments described under section 2.1.3 of Appendix B

are made prior to a linearity test or RATA, the monitor is actually

being held to a tighter specification than is used for daily operation.

The Agency therefore does not agree that keeping the instrument's

calibration within the performance specification ``band'' at the time

of linearity tests or RATAs compromises the integrity of the audits or

sets a bad precedent. On the contrary, it demonstrates that the monitor

continues to perform in a comparable manner to its performance at the

time of initial certification. When the monitor is held to the

calibration error specification required for initial certification, the

monitor is shown to be capable of passing a linearity test or RATA.

H. Appendix D--Sulfur Dioxide Emissions From the Combustion of Gaseous

Fuels

Background: EPA proposed several revisions to the procedures in

Appendix D of part 75 for determining sulfur dioxide emissions from

gas-fired and oil-fired units. Most of the proposed revisions would

provide affected utilities with additional flexibility and sampling

options. These changes were generally supported by the comments

received and have either been finalized as proposed or with minor

revisions and clarifications. However, for gaseous fuels, EPA received

a number of significant comments concerning the proposed changes to the

definition of the term ``pipeline natural gas'' under Sec. 72.2 and

received other comments which have prompted the Agency to re-evaluate

the applicability and use of Appendix D. In response to the significant

comments received, the Agency is adopting the following final revisions

to Appendix D and to Sec. 72.2:

(1) Revised definitions of ``pipeline natural gas,'' ``natural

gas'' and ``gas-fired'' have been promulgated in Sec. 72.2;

(2) The applicability of Appendix D has been expanded to include

gaseous fuels with any sulfur content (previously, Appendix D had been

limited to gaseous fuels with a sulfur content of 20 grains per 100

scf, or less); and

(3) The methodology for determining the frequency of fuel gross

calorific value (GCV) under section 2.3 of Appendix D has been

modified.

In order to put today's revisions in context, it is necessary to

review how the Agency addressed these issues in previous rulemakings.

Section 2.4 of Appendix D of the core rules of the Acid Rain Program

issued on January 11, 1993, allowed units combusting ``natural gas''

(as defined in Sec. 72.2) to calculate SO2 mass emissions

through either: (1) fuel sulfur sampling and measurement of the fuel

flow rate by a certified fuel flowmeter; or (2) the use of a default

SO2 emission rate of 0.0006 lb/mmBtu and heat input

determined using a certified fuel flowmeter and monthly analysis for

fuel GCV. In the preamble to the January 11, 1993 rule, the Agency

stated, ``the definition of ``natural gas'' does not, therefore,

include landfill gas, digester gas, biomass, or gasified coal'' (58 FR

3590 and 3596). The Agency further stated in the preamble that,

``essentially sulfur-free fuels such as natural gas, landfill methane,

or synthetic propane'' should qualify for the use of Appendix D

methodologies. The intent of the Agency in that rulemaking was to allow

the use of a default emission rate for SO2 mass emissions

calculations for natural gas and other fuels which have a similar low

sulfur content, but not for fuels which have higher sulfur content than

natural gas. Appendix D did not effectively address how to determine

SO2 mass emissions for gaseous fuels other than natural gas.

On May 17, 1995 the Agency revised the core Acid Rain rules to add

a new definition for ``pipeline natural gas,'' and revised the

definitions of ``natural gas'' and ``gas-fired.'' The most significant

change in the definition of ``natural gas'' was the addition of the

requirement that ``natural gas'' must contain ``one grain or less

hydrogen sulfide per 100 standard cubic feet and 20 grains or less

total sulfur per 100 standard cubic feet.'' The intent of this

additional language was to clarify which gaseous fuels qualified as

``natural gas.'' The criteria used (1 grain hydrogen sulfide

(H2S) and 20 grains total sulfur) were based on contracts

and tariff sheets for pipeline natural gas regulated by the Federal

Energy Regulatory Commission (FERC). Consistent with this approach, the

Agency defined ``pipeline natural gas'' as natural gas provided by a

supplier through a pipeline. In addition, the Agency modified the

definition of ``gas-fired'' to make it clear that the use of Appendix D

was limited to units combusting ``fuel oil,'' ``natural gas,'' and

``gaseous fuels containing no more sulfur than natural gas.'' The

default SO2 emission rate of 0.0006 lb/mmBtu could only be

used for the combustion of either natural gas or a fuel with a sulfur

content no greater than natural gas. To use the default SO2

emission rate, the owner or operator was required to demonstrate that

the fuel being combusted qualified as natural gas, based on contract or

tariff values which indicate that the gas meets the criteria for

natural gas H2S content and total sulfur content.

As noted in the preamble of the proposed rule, the May 12, 1995

revisions apparently did not eliminate confusion concerning the use of

the default SO2 emission rate. The SO2 default

emission rate of 0.0006 lb/mmBtu is equivalent to approximately 0.2

grains hydrogen sulfide per 100

[[Page 28578]]

standard cubic feet (scf) of gas, when hydrogen sulfide is the sole

source of total sulfur in the gas (as is the case for refined natural

gas), or 0.2 grains total sulfur per 100 scf of gas. The Agency did not

intend that fuels with average sulfur content much higher than 0.2

grains per 100 scf should be allowed to use the default value. In this

context, the current definition of ``natural gas'' under Sec. 72.2,

which includes the term ``20 grains of total sulfur,'' is somewhat

confusing. Further, use of the 0.0006 lb/mmBtu default emission rate

for ``natural gas'' with one grain of H2S per 100 scf would

result in an approximately five-fold underestimation of SO2

emissions. Therefore, in the proposed rule, the Agency modified the

definition of pipeline natural gas to include only natural gas with a

hydrogen sulfide content less than or equal to 0.3 grains hydrogen

sulfide per 100 scf, thereby clarifying that the default emission rate

of 0.0006 lb/mmBtu could only be used for natural gas with an

appropriately low hydrogen sulfide content.

The proposed rule required documentation of the hydrogen sulfide

content of the natural gas either through quality characteristics

specified by a purchase contract or pipeline transportation contract,

through certification of the gas vendor, based on routine vendor

sampling and analysis, or through at least one year's worth of

analytical data on the fuel hydrogen sulfide content from samples taken

at least monthly, demonstrating that all samples contain 0.3 grains or

less of hydrogen sulfide per 100 standard cubic feet. For a fuel to be

classified as ``pipeline natural gas'' the fuel would, of course, first

have to meet the current definition of ``natural gas'' in Sec. 72.2,

which states, ``Natural gas means a naturally occurring fluid mixture

of hydrocarbons (e.g., methane, ethane, or propane) containing 1 grain

or less hydrogen sulfide per 100 standard cubic feet, and 20 grains or

less total sulfur per 100 standard cubic feet), produced in geological

formations beneath the Earth's surface, and maintaining a gaseous state

at standard atmospheric temperature and pressure under ordinary

conditions.''

Discussion: Several comments were received on the proposed changes

to the definition of ``pipeline natural gas,'' and comments were also

received on the current definition of ``natural gas.'' In responding to

the comments, the Agency is revising both the definition of ``pipeline

natural gas'' and ``natural gas,'' as well as making various

corresponding changes to wording in part 75 to ensure consistency

within the rule.

Two commenters were opposed to the change to the definition of

pipeline natural gas (see Docket A-97-35, Items IV-D-23 and IV-D-24).

Both commenters suggested that the requirement to document that a

gaseous fuel has 0.3 gr/100 scf of H2S, as

opposed to the previous requirement to document an H2S

content 1.0 gr/100 scf, would either disqualify some sources

currently using the default emission rate of 0.0006 lb/mmBtu or force

those sources to use means other than the contract or tariff provisions

to demonstrate that the hydrogen sulfide content of the gas is less

than 0.3 gr./100 scf. Under the proposed Appendix D revisions, any

sources disqualified from the use of the default SO2

emission rate would either be required to begin daily gas sampling of

the fuel sulfur content or would have to install an SO2

CEMS.

Two other commenters suggested that the use of two sulfur content

criteria in the natural gas definition (the dual criteria of 1 grain

H2S and 20 grains total sulfur per 100 scf) was confusing

and could lead to misinterpretation of which fuels could be classified

as either ``pipeline natural gas'' or ``natural gas'' under Sec. 72.2

(see Docket A-97-35, Items IV-G-3 and IV-G-10). One of these commenters

suggested that the definition of natural gas should be changed to

incorporate only the requirement of 20 grains or less of total sulfur

per 100 scf. If this suggestion were followed, a source with 20 grains

total sulfur per 100 scf could use an SO2 emission rate of

0.0006 lb/mmBtu, thereby underestimating SO2 emissions 100-

fold. This would clearly be unacceptable and contrary to the Agency's

intent since the initial adoption of Appendix D.

One commenter suggested that the requirement to determine the fuel

GCV on the same frequency as sulfur sampling be removed from Appendix D

and that monthly GCV sampling be allowed in all cases (see Docket A-97-

35, Item IV-D-20). The commenter claimed that the variability of fuel

GCV is not necessarily the same as the variability of the sulfur

content of a fuel.

1. Summary of EPA Analysis of Appendix D Gaseous Fuel SO2

and Heat Input Methodologies

In responding to the comments received, the Agency first attempted

to quantify the SO2 emissions from the combustion of gaseous

fuels under the current Acid Rain rules. A data analysis was performed,

assuming that the vast majority of SO2 emissions from the

combustion of gaseous fuel are from affected units reporting gas as the

primary fuel. The data analysis (which was limited to 1997 emission

data) indicates the following: (1) there are 582 units that list gas as

the primary fuel (representing about 30% of the units in the program);

(2) these 582 units accounted for approximately 10% of the total heat

input reported for all Acid Rain-affected units; (3) the total amount

of SO2 emitted by these 582 units was 14,728 tons in 1997 or

0.1% of the total SO2 mass emissions in the program; and (4)

of the 14,728 tons of SO2 emitted by the 582 units, 12,844

tons were from only 17 units and the remaining 1,884 tons were from the

remaining 565 units (see Docket A-97-35, Item IV-A-4). Thus it appears

that gas-fired units account for a significant portion of the total

heat input and electrical generation under the Acid Rain Program, but

contribute only a fraction of one percent of the total SO2

emissions. Note, however, that even though emissions from the

individual gas-fired units are very small, the cumulative emissions

from all 582 units are roughly equivalent to the typical SO2

emissions from a coal-fired unit. For this reason, the method of

calculating the SO2 emissions from the gas-fired units must

be sufficiently accurate to prevent significant underestimation of

emissions. The methodology in the current rule allows the default

SO2 emission rate of 0.0006 lb/mmBtu to be used for all

types of natural gas. As previously noted, the default emission rate

corresponds to 0.2 grains of H2S per 100 scf, but the

definition of natural gas allows fuels with up to 1.0 grain of

H2S and 20 grains of total sulfur to be classified as

``natural gas.'' In view of this, it is possible that the reported

cumulative SO2 emissions reported in 1997 for the 582 gas-

fired units may be inaccurate by several orders of magnitude. This

level of uncertainty in reported emissions is unacceptable in an

allowance trading program such as the Acid Rain Program. Consequently,

a more representative method is needed to characterize the actual

sulfur content of the gaseous fuels combusted by Acid Rain-affected

units.

The Agency also performed an analysis of all available gaseous fuel

GCV sampling data from all Acid Rain sources reporting such data in

1997. Gaseous fuels were analyzed in two categories, pipeline natural

gas and ``other'' gas. Only 14 Acid Rain sources reported sampling and

analysis of ``other'' gases in 1997. The data analysis showed that for

275,669 pipeline natural gas analyses, the average fuel GCV was 1023

Btu/ft3 and the 95th

[[Page 28579]]

percentile value was 1051 Btu/ft3, a difference of only

2.6%. For the ``other'' gaseous fuels, the average GCV from 14,282

analyses was 819 Btu/ft3 and the 95th percentile value was

1118 Btu/ft3, a difference of approximately 26%. This

demonstrates the consistency of the GCV of pipeline natural gas and the

high variability of the few ``other'' gaseous fuels for which Appendix

D is currently being used (see Docket A-97-35, Item IV--A-1).

In finalizing today's rule, the Agency also considered the

potential impact of the revisions to Appendix D on the new Subpart H of

part 75 (which establishes the requirements for monitoring of

NOX mass emissions). Currently, the provisions of Subpart H

are being used by the Ozone Transport Commission (OTC) NOX

Budget Program and, in the future, Subpart H may be adopted as part of

an implementation plan as a means of complying with the NOX

SIP Call (see 63 FR 57356). Subpart H of part 75 allows heat input

determined by the procedures of Appendix D to be used in determining

NOX mass emissions from gas-fired units. In the process of

implementing part 75 and the OTC NOX Budget Program, the

Agency has encountered an increasing number of sources that combust

gaseous fuels which neither qualify as ``pipeline natural gas'' or

``natural gas.'' These fuels include refinery gas, landfill gas,

digester gas, coke oven gas, process gas, propane liquified gas,

liquified petroleum gas, blast furnace gas and coal-derived gas. Under

the previous version of part 75 units combusting these fuels would

either be required to install SO2 and stack flow monitoring

systems or would have to petition the Agency to use Appendix D. It is

likely that under the OTC NOX Budget Program and under the

SIP call, the number of sources combusting these ``other'' gaseous

fuels and required to monitor heat input using part 75 methods will

increase significantly. The Agency anticipates that the owners or

operators of the majority of these sources would petition to use the

procedures of Appendix D to determine heat input used for

NOX mass calculations, in lieu of installing CEMS. However,

the current Appendix D does not address how to determine hourly heat

input for gaseous fuels with variable GCV. The Agency also notes that

any error in hourly heat input determined under Appendix D would result

in a corresponding and equal error in the reported NOX mass

emissions. It is therefore particularly important to establish

consistent and easily implementable heat input monitoring criteria for

all types of gaseous fuels under Appendix D. Clear, flexible and

reasonable requirements for gaseous fuel GCV sampling and analysis are

needed.

Based on the comments received and the data analyses described

above, the Agency has concluded that:

The use of the default SO2 emission rate of

0.0006 lb/mmBtu is only appropriate for natural gas with a

documented contractual or tariff limit of 0.3 grains hydrogen

sulfide per hundred standard cubic feet or for fuels which are

demonstrated to have a similar low total sulfur content.

For natural gas with a contract or tariff hydrogen

sulfide limit up to 1.0 grain of hydrogen sulfide per 100 standard

cubic feet, or for fuels which are demonstrated to have a similar

low total sulfur content, a site-specific default SO2

emission rate should be allowed, which more closely represents the

potential SO2 emission rate for that fuel.

The applicability of Appendix D should be expanded to

include any gaseous fuel (rather than limiting it to fuels with a

total sulfur content 20 grains per 100 scf. For gaseous

fuels with highly variable sulfur content, hourly sampling using

advanced monitoring such as on-line gas chromatography should be

required. The frequency of determination of the GCV of a gaseous

fuel should be independent of the requirements for sulfur sampling

and should be based solely on the variability of the GCV.

2. Changes to the Definitions of ``Pipeline Natural Gas'' and ``Natural

Gas''

As previously stated, the Agency is revising the definitions of

``pipeline natural gas'' and ``natural gas'' in Sec. 72.2. Since the

definition of ``pipeline natural gas'' necessarily includes the

definition of ``natural gas'', and the definitions therefore involve

similar issues, EPA is addressing both definitions in today's final

rule. In particular, ``pipeline natural gas'' is defined in such a way

that only fuels with the appropriate sulfur content can meet the

definition and can use the default emission rate of 0.0006 lb/mmBtu.

Under the revised definition, pipeline natural gas must contain less

than 0.3 grains of hydrogen sulfide per 100 scf. Consistent with this

approach, the definition of ``natural gas'' is revised so that only the

requirement for the hydrogen sulfide content to be less than one grain

per 100 scf remains, and the requirement for the total sulfur content

to be 20 grains per 100 scf is deleted. Further, EPA is

adding to both definitions a requirement that hydrogen sulfide content

must account for at least 50% (by weight) of the total sulfur in the

fuel. This ensures that a fuel with a high total sulfur content, but a

relatively small hydrogen sulfide content, cannot qualify to use a

default SO2 emission rate. The Agency believes that in

general, any ``natural gas'' with 1.0 grain of

H2S/100 scf will also meet the requirement that hydrogen

sulfide must account for 50% of the total sulfur in the

fuel. However, the Agency reserves the right to request that the owner

or operator provide data to demonstrate compliance with this latter

requirement. Finally, EPA is adding a requirement to the ``natural

gas'' definition that the gas must have either a methane content of at

least 70% or the same GCV as methane (950 to 1100 Btu/scf). This

requirement ensures that the gas will have a stable GCV, consistent

with the Appendix D provisions which allow monthly GCV sampling for

either pipeline natural gas or natural gas. In today's rule, the

requirements for documenting that a fuel qualifies as ``pipeline

natural gas'' or ``natural gas'' are essentially the same as the

proposed rule. The three principal ways of providing the necessary

documentation are: (1) gas quality characteristics specified in a

purchase contract or pipeline transportation contract; (2)

certification by the gas vendor, based on routine sampling and analysis

for at least one year; and (3) at least one year of analytical data on

the fuel characteristics, derived from monthly (or more frequent)

samples. In addition, sections 2.3.5 and 2.3.6 of Appendix D of today's

rule allow the owner or operator to conduct a 720 hour demonstration of

the fuel's sulfur and GCV characteristics (see Items 5 and 6 in this

section, below).

EPA believes that the revised definitions of ``pipeline natural

gas'' and ``natural gas'' will: (1) apply to the low sulfur fuel

combusted by the vast majority of the sources in the Acid Rain Program;

(2) be documentable, in most cases, based on contract or tariff

provisions without other types of demonstrations; and (3) allow most

sources currently using 0.0006 lb/mmBtu as a default to continue using

that default value or to use an alternative, site-specific default

value that will not underestimate SO2 emissions.

3. Changes to the Methodology for Calculating SO2 Emissions

Under Appendix D

Today's rule adopts a two-tiered approach to the use of default

SO2 emission rates, depending on whether a fuel qualifies as

``pipeline natural gas'' or as ``natural gas.'' First, if the owner or

operator can demonstrate that the fuel combusted at a unit has

0.3 grains of hydrogen sulfide per 100 scf, the default

SO2 emission rate of 0.0006 lb/mmBtu may be used. Second,

the rule allows units combusting gaseous fuels

[[Page 28580]]

with >0.3 grains, but 1.0 grain of hydrogen sulfide per 100

scf to calculate a site-specific default SO2 emission rate,

as suggested by two of the commenters (see Docket A-97-35, Items IV-D-

23 and IV-D-24). The method of calculating the default value is based

on the actual conversion of hydrogen sulfide in natural gas to

SO2 and utilizes a realistic fuel GCV value of 1023 Btu/scf

(from the previously-discussed data analysis, above). The result is a

simple equation which converts hydrogen sulfide in natural gas to an

SO2 emission rate in lb/mmBtu.

4. Changes to the Applicability of Appendix D

In the process of considering comment on the definitions of

``pipeline natural gas'' and ``natural gas'' the Agency also re-

evaluated the appropriateness of limiting the applicability of Appendix

D to gaseous fuels with 20 grains of total sulfur per 100

scf. While EPA does not believe that a gaseous fuel with 20 or more

grains of total sulfur per 100 scf should be allowed to use a default

SO2 emission rate, neither does the Agency believe that

units combusting such fuel should be excluded from using Appendix D.

Currently, technologies such as on-line gas chromatography allow

accurate fuel sulfur analysis to be performed over intervals as short

as one hour. This ability to perform hourly sampling is comparable to a

CEMS in accuracy, precision and timeliness. Therefore, today's rule

removes the 20 grains of sulfur per 100 scf restriction on the use of

Appendix D for gaseous fuels.

5. Changes to the Method of Determining the Sulfur Content Sampling

Frequency for Gaseous Fuels

Section 2.3.6 of Appendix D of today's rule also includes a general

procedure for determining the appropriate frequency of sulfur content

sampling for any gaseous fuel which is transmitted by a pipeline. The

procedure consists of a 720 hour demonstration, similar to the one in

section 2.3.3.4 of Appendix D in the proposed rule. The results of the

720 hour demonstration may first be used to determine first if a fuel

qualifies as either ``pipeline natural gas'' or ``natural gas'' or as

``other'' gaseous fuel, and then to determine the appropriate total

sulfur sampling frequency for the fuel. If a fuel qualifies as pipeline

natural gas, the default SO2 emission rate of 0.0006 lb/

mmBtu could be used in lieu of fuel sampling. If the fuel qualifies as

``natural gas'' (but not pipeline natural gas), a site-specific default

SO2 emission rate may be used, based on the highest hourly

hydrogen sulfide concentration recorded during the 720 hour

demonstration. After a fuel qualifies as ``natural gas,'' the owner or

operator is required to sample the H2S content at least once

monthly for a year following the 720 hour demonstration. The default

emission rate for the demonstration may continue to be used, provided

that none of the samples taken during the year exceeds 1.0 grain/100

scf of H2S. All ``other'' gaseous fuels would require either

daily or hourly sampling of the total sulfur content, depending on the

fuel sulfur variability.

6. Changes to the Method of Determining the GCV Sampling Frequency for

Gaseous Fuels

Accurate determinations of heat input are important for the

calculation of SO2, NOX and CO2 mass

emissions under Appendices D, E, G and Subpart H of part 75. EPA has

found that fuels such as refinery gas, digester gas, landfill gas, coke

oven gas, process gas, propane liquified gas, liquified petroleum gas,

blast furnace gas, and coal derived gas can have highly variable GCV

(see Docket A-97-35, Item IV-A-4). For these fuels a standardized test

for determining the appropriate GCV sampling and analysis frequency is

essential. One commenter on the proposed rule noted that in many cases

the GCV of a fuel is relatively stable over a period of time, and

sampling each month for fuel heat content is adequate (see Docket A-97-

35, Item IV-D-20). The Agency agrees that this is true in many cases

(e.g., for natural gas), but not often for the fuels listed above. The

Agency also notes that the emissions data determined under Appendix D

must be as reliable, precise, timely and accessible as data from a

CEMS.

In view of this, the Agency is revising the criteria for

determining the frequency of GCV sampling for gaseous fuels. For any

fuel which meets the revised definition of either ``pipeline natural

gas'' or ``natural gas,'' this ensures that the fuel will have a stable

heat content and therefore monthly sampling is appropriate. For fuels

which do not qualify as either pipeline natural gas or natural gas and

for which ``as-delivered'' fuel sampling and analysis is not performed,

the same 720 hour demonstration described in item 5 in this section,

above, for fuel sulfur sampling will also be used to determine the

appropriate GCV sampling and analysis frequency. The heat content of

the fuel will be determined for each hour in the 720 hour period. For

units that switch fuels seasonally or when process changes occur (such

as refinery fuel gas combustion units) the 720 hour demonstration

period must also include data which characterizes the variability of

the fuel during the seasonal or process changes. The results of the 720

hour demonstration will be used to determine the average heat content

of the fuel and the standard deviation. As explained in section 2.3.5

of Appendix D in today's rule, depending on the results of the

demonstration, the owner or operator will perform either daily or

hourly sampling of the fuel GCV.

I. Electronic Transfer of Quarterly Reports

Background: For the reasons discussed in the preamble to the

proposed rule revisions (63 FR 57356, May 21, 1998), EPA proposed

changes to Sec. 75.64(f) concerning the method of submitting quarterly

reports. The proposal provided that all quarterly reports would have to

be submitted to EPA by direct computer-to-computer electronic transfer

via modem and EPA-provided software, unless otherwise approved by the

Administrator. This requirement was to begin with the quarterly report

for the first quarter of the year 2000.

Discussion: EPA received one comment (see Docket A-97-35, Item IV-

D-20) which opposed the proposed requirement based on difficulty in

receiving electronic transfer of quarterly reports due to technical

difficulties with EPA computers which may arise due to year 2000

conversion difficulties or other technical problems relative to

electronic transfer of quarterly reports at times when EPA computers

may not be accessible. Concern was expressed regarding the requirement

for utilities to provide proof that they attempted to transfer their

reports on time but were unsuccessful due to the inability to gain

access to the EPA computer system.

Based on the comment received, EPA has decided to change the

electronic reporting requirement in Sec. 75.64(f) so that beginning

with the quarterly report for the first quarter of the year 2001, all

quarterly reports must be submitted to EPA by direct computer-to-

computer electronic transfer via modem and EPA-provided software,

unless otherwise approved by the Administrator. This will ensure

adequate time for all parties to address the year 2000 concerns. EPA

notes that its system has already undergone testing and changes to

accommodate year 2000 concerns.

J. Bias, Relative Accuracy and Availability Determinations

Background: The preamble to the proposed rule described the

findings of studies performed to evaluate the

[[Page 28581]]

provisions for the bias test, relative accuracy, and monitor

availability trigger conditions as required by Secs. 75.7 and 75.8.

Issues concerning the bias relative accuracy, and monitor availability

provisions in the core Acid Rain rules had been raised in litigation

(Environmental Defense Fund v. Carol M. Browner, No. 93-120; et al.

D.C. Cir., 1993). The purpose of these studies was to address these

issues (see 63 FR 28197). The preamble of the proposed rule explained

how these findings led to the Agency's proposed determinations to

retain the current rule provisions concerning these matters. There were

no comments objecting to the substance of the proposed determinations.

Therefore, for the reasons set forth in the preamble to the proposed

rule, EPA is adopting the proposed rule revisions as final, with the

result that Secs. 75.7 and 75.8 are removed and reserved. Moreover,

since none of the issues raised concerning the bias, relative accuracy,

and monitor availability provisions in the core Acid Rain rules were

raised in any comments on the studies, EPA maintains that those

litigation issues have been resolved.

Discussion: Two comments were received. One (see Docket A-97-56,

Item IV-D-01) supported the proposed determinations. The second comment

(see Docket A-97-56, Item IV-D-02) expressed concern that the bias test

studies performed in response to Sec. 75.7 did not evaluate

overestimation in flow measurements. The commenter urged EPA to

complete its ongoing work as quickly as possible on a separate

rulemaking to resolve the commenter's flow overestimation concerns. The

Agency is pursuing the separate rulemaking recommended by the

commenter.

K. Appendix I--Proposed Optional Stack Flow Monitoring Methodology

Background: EPA proposed to add an F-factor/fuel flow method in

Appendix I to part 75 as an excepted method to measure volumetric flow

directly with a flow monitor. The Agency proposed this method based on

information provided by affected utilities, and based on the assumption

that the new excepted method would be used by a significant number of

units as a cost-effective option to a volumetric flow monitor. This

method would allow fuel flow measurement with a gas or oil flowmeter,

fuel sampling data, CO2 (or O2) CEMS data, and F-

factors to determine the flow rate of the stack gas rather than a

volumetric flow monitor. The F-factor/fuel flow method would be

available for use by oil-fired and gas-fired units, as defined under

Sec. 72.2, provided that they only burn natural gas and/or fuel oil.

For these units, EPA believes that the proposed method would provide

acceptably accurate measurements of volumetric flow. However, adoption

of the proposed method would require the Agency to develop regulations

imposing additional reporting and recordkeeping requirements for those

units that used this option. This would also place a burden on software

vendors to develop software to allow for electronic data reporting of

the required data elements.

Discussion: A few commenters stated generally that they supported

the Appendix I option, while two other commenters stated generally that

the method should be allowed for other types of units or simplified

(see Docket A-97-56, Items IV-D-9, 23, and 24, and IV-G-2 and -8).

However, utilities have submitted late comments that suggest that the

utilities (including those originally interested in an F-factor/fuel

flow method) are in fact unlikely to use the Appendix I option at this

time (see Docket A-97-56, Item IV-G-13). Based on a review of Acid Rain

program databases, only about 150 units affected by the Acid Rain

Program could potentially take advantage of this option. In contrast,

there are a significant number of units that implement the other

generally available excepted methods under Appendices D and E to Part

75 (currently, approximately 540 different units report using one or

both of these methods).

As discussed above there would be substantial effort involved for

EPA, utilities and software vendors to implement a new generally

available option such as proposed Appendix I. As discussed in the

preamble to the proposed rule, the annual savings on a per unit basis

for Appendix I units are at most $10-15,000 over the measurement of

volumetric flow directly with a flow monitor. The actual cost savings

would be less because other provisions of today's rule revise flow

monitor quality assurance requirements and significantly reduce the

costs of using a flow monitor. Given the relatively small amount of

savings on a per unit basis, the indication that no units would use the

option at this time, and the significant burden on all interested

parties in implementing a generally available option in Appendix I, the

Agency has determined not to adopt Appendix I.

However, if the owner or operator of a unit decides at some time in

the future to use this type of procedure for measuring flow, the

designated representative of the unit may petition the Agency under

Sec. 75.66 to use this type of procedure on a case-by-case basis. In

such a petition, the designated representative can reference the

information used to support the proposed Appendix I procedure (see 63

FR 28113-28115, May 21, 1998, for further details on the information

used to develop proposed Appendix I). The Agency will evaluate the

petition on the merits at that time.

L. Subpart H--Clarifications to NOX Mass Monitoring

Requirements

Background: By notice of proposed rulemaking (NPR, proposal, or

``proposed SIP call'') (62 FR 60318, November 7, 1997) and by

supplemental notice (SNPR or supplemental proposal) (63 FR 25902, May

11, 1998), EPA proposed to find that NOX emissions from

sources in 22 states and the District of Columbia, will significantly

contribute to nonattainment of the 1-hour and 8-hour ozone National

Ambient Air Quality Standards (NAAQS), or will interfere with

maintenance of the 8-hour NAAQS, in one or more downwind states

throughout the eastern United States.

In October, 1998 (63 FR 57356, October 27, 1998), EPA finalized the

proposed SIP call rulemaking. The final rule specified dates by which:

(1) the affected states must submit State Implementation Plan revisions

to reduce NOX emissions to eliminate the amounts of

NOX emissions that contribute significantly to

nonattainment, or that interfere with maintenance, downwind; and (2)

the affected sources must implement the measures chosen by the states

to achieve the required NOX emission reductions.

The provisions of the October 27, 1998 final rule allow each state

to determine the best way to achieve the necessary NOX

emission reductions. Consistent with the Ozone Transport Assessment

Group's recommendation to achieve NOX emissions decreases

primarily from large stationary sources in a trading program, EPA

promulgated a model rule for the implementation of such a trading

program as 40 CFR part 96 (``Part 96'') in the October 27, 1998

rulemaking.

If the states should choose to create a NOX mass trading

program and to adopt the provisions of the Part 96 model rule,

Sec. 96.70 requires the monitoring and reporting of NOX mass

emissions to be done in accordance with either: (1) Subpart H of 40 CFR

part 75, the Acid Rain CEM Rule (``Part 75''); or (2) for qualifying

low mass-emission units, Sec. 75.19 of Part 75. However, even if a

state should choose not to participate in such a trading program, the

October 27, 1998 rule still requires the monitoring provisions of

Subpart H to be used by

[[Page 28582]]

a core group of sources (large industrial boilers and turbines, and

large boilers and turbines used for the generation of electricity for

sale) if the NOX mass emission reduction program for that

state includes requirements to control such sources. To support these

NOX mass emission reduction programs and rulemakings, EPA

promulgated both Subpart H of Part 75 and the low mass emission unit

provisions in Sec. 75.19 of Part 75 as part of the October 27, 1998

rulemaking.

In the November 7, 1997 proposed SIP Call rule, EPA would have

required the affected units in a Federal or state NOX mass

emission reduction program to report NOX emissions on a

year-round basis and also to quality assure the NOX emission

data in accordance with the provisions of Part 75 on a year-round

basis. However, in response to comments on the proposed rule, EPA

modified Subpart H of Part 75 so that states could choose to allow

sources that were not subject to the requirements of Title IV of the

Clean Air Act (the Acid Rain Program) to monitor and report either on a

year round basis or on an ozone season only basis. Therefore, the

October 27, 1998 final rule provides for the monitoring and reporting

of NOX mass emissions either on an annual basis or during

the ozone season, when this is allowed by the governing state or

Federal rule.

If a state or Federal NOX mass emission reduction

program were to allow ``ozone season only'' monitoring and reporting,

there would be an issue related to data quality at the start of each

ozone season. To address this issue, in the October 27, 1998 final

rule, EPA included a provision in Sec. 75.74(c) of Subpart H, which

requires the continuous emission monitoring systems used to provide the

NOX mass emission data to be recertified prior to the start

of each ozone season.

Although Subpart H was proposed on May 21, 1998 as part of the Acid

Rain CEM Rule revisions, it was finalized several months ahead of

today's rulemaking, in order to support the SIP call. In the preamble

to the October 27, 1998 final rule (63 FR 57467), EPA explained its

intention to, where possible, make the provisions of Subpart H

consistent with any other changes that EPA promulgated as a result of

the May 21, 1998 proposed revisions to Part 75. EPA has re-examined the

provisions of Subpart H within the context of today's final rulemaking.

The Agency has found that a few minor clarifications of the regulatory

language in Subpart H and the addition of one new paragraph are needed

for consistency with today's final rule. The textual clarifications

affect Secs. 75.70(f)(1)(iv), 75.71(b) and 75.71(d)(2). The new

paragraph is found at Sec. 75.70(g)(6). In addition to these minor

corrections, EPA has found that certain provisions in Sec. 75.74(c),

pertaining to sources that monitor and report data only in the ozone

season, are substantially inconsistent with sections of today's final

rule (particularly the new CEM data validation provisions). The Agency

has also found an instance in which the text of Sec. 75.74(c) is

internally inconsistent and a second instance in which a statement in

the October 27, 1998 preamble does not agree with the regulatory

language in Sec. 75.74(c). In view of these considerations, today's

rulemaking revises Sec. 75.74(c), in order to make Subpart H more

consistent with the rest of Part 75 and to resolve the apparent

discrepancies and inconsistencies in the text of Sec. 75.74(c).

Discussion of Changes: As previously stated, Subpart H requires

owners or operators of sources that monitor and report only during the

ozone season to recertify their CEM systems prior to each ozone season.

EPA put this requirement in Subpart H because the Agency believes that

for sources which are not required to monitor and report on a year-

round basis, substantial quality assurance testing of the CEMS prior to

the ozone season is essential to validate the emission data at the

beginning of the ozone season. However, in the light of today's

rulemaking, the use of the word ``recertification'' in Sec. 75.74(c) of

Subpart H is regarded as inaccurate and inappropriate and does not

properly communicate the Agency's intent. In Sec. 75.20(b) of today's

final rule, the term ``recertification'' has been carefully defined, so

that it is limited to major changes to a CEMS which may affect its

ability to accurately measure emissions. Since in most instances

sources will be testing existing CEMS that have not undergone major

changes, EPA believes that this is more consistent with either

diagnostic testing or on-going quality assurance testing rather than

recertification. Therefore, in today's final rule, all of the

references in Sec. 75.74 to ``recertification testing'' of CEMS prior

to the ozone season have been replaced with terms such as ``diagnostic

testing'' or ``quality assurance testing,'' which properly convey the

Agency's intent and de-couple this testing from the formal

administrative process associated with recertification events. Since

the required pre-ozone season testing is considered to be quality

assurance (QA) or diagnostic testing rather than a recertification, the

Agency must specify which QA tests are to be performed. Section

75.74(c) therefore lists the specific quality assurance tests that are

required prior to the ozone season. For all CEM systems, a relative

accuracy test audit (RATA) is required and for all gas monitors, a

linearity check is also required. After a required linearity check or

RATA is passed, Sec. 75.74(c) requires that daily calibration error

tests and (if applicable) flow monitor interference checks begin to be

performed. These daily assessments must then continue to be performed

until the end of the ozone season.

Section 75.74(c)(5) of Subpart H, as promulgated on October 27,

1998, requires both the recording and reporting of hourly emission data

prior to the current ozone season in the time interval from the date

and hour that ``recertification'' testing of the CEM systems is

completed through the end of the ozone season. EPA believes that most

sources that choose this option would do the testing as close to the

ozone season as possible. However, there may be some instances in which

it would be difficult for a source to perform all of the testing in the

second quarter before the beginning of the ozone season. This means

that some sources for which the NOX emission data count for

compliance only during the ozone season would be required to submit

additional electronic quarterly reports outside the ozone season, if

they completed the pre-ozone season testing in the first or fourth

calendar quarter. In view of this, EPA has reconsidered the

implications of this extra reporting requirement and has concluded that

it will complicate program implementation. The Agency believes that

this complication is unnecessary. Therefore, in Sec. 75.74(c)(6) of

today's final rule, the Subpart H reporting provision for these sources

has been revised, so that only reporting of emission data in the ozone

season, from May 1 through September 30, is required. This means that

in the time period from the date and hour of completion of the required

pre-ozone season quality assurance testing of the CEM systems through

April 30 of the current year, the owner or operator is only required to

record and keep records of the hourly emission data on-site. The only

pre-ozone season data that must be reported are the results of daily

calibration error checks and flow monitor interference checks performed

in the time period from April 1 through April 30 and the results of any

linearity checks, RATAs, fuel flow meter tests and fuel sampling

performed outside of the ozone season for purposes of

[[Page 28583]]

compliance with Subpart H. This will provide the regulatory agencies

with added assurance that the CEMS data are quality-assured at the

start of the ozone season and will enable the agencies to have a

limited pre-ozone season electronic auditing capability. The

requirement to report the results of the daily assessments for the

month of April is not considered burdensome because April is in the

second calendar quarter, which is one of the two reporting quarters for

the affected sources. In fact, some affected sources may prefer to

report data for April, because it may be easier to generate an

electronic quarterly report for the entire second calendar quarter,

rather than just for the months of May and June. Therefore,

Sec. 75.74(c)(6) of today's final rule gives the owner or operator the

option to report unit operating data and emission data for the month of

April.

In reviewing the missing data provisions of Subpart H, EPA found a

discrepancy between the Agency's stated intent in the preamble to the

October 27, 1998 final rule and the regulatory language in

Sec. 75.74(c)(6)(i). The preamble states that ``[h]istorical lookback

periods for missing data only need to include data from the ozone

season'' (63 FR 57483, October 27, 1998). However, the rule language in

Sec. 75.74(c)(6)(i) does not state this explicitly, and could be

misinterpreted. The rule language states that all ``quality assured

data, in accordance with paragraph (c)(2) or (c)(3) of this section''

are to be used for missing data purposes. This could be interpreted as

meaning that the data recorded outside the ozone season, in the time

period between completion of the pre-ozone season quality assurance

testing of the CEM systems and May 1, are to be included in the missing

data lookback periods. This is not what EPA intends; rather, the

statement cited above from the October 27, 1998 preamble accurately

reflects the Agency's position. Therefore, Sec. 75.74(c)(7) of today's

rule clearly states that for purposes of missing data substitution,

only data recorded during the ozone season will be used for the

historical missing data lookback periods.

Finally, EPA has examined the quality assurance provisions of

Subpart H in view of the many substantial changes to the quality

assurance and data validation provisions of Part 75 in today's

rulemaking. The Agency has concluded that, in light of the many changes

that have been made to Part 75, the general references in Subpart H to

the quality assurance provisions in Sec. 75.21 and appendix B to Part

75 and references to the data validation procedures in Sec. 75.20 could

be clarified to make the requirements easier to understand,

particularly for sources that report data only during the ozone season.

There are several reasons for this.

First, sections 2.2.4 and 2.3.3 in appendix B of today's final rule

provide ``grace periods'' in which late or missed QA tests can be

completed. For linearity checks, the grace period is 168 unit operating

hours after the end of the quarter in which the test is due. For RATAs,

the grace period is 720 unit operating hours after the end of the

quarter in which the RATA is due. Because the grace periods in Part 75

are in terms of unit operating hours, they can sometimes extend for

more than one calendar quarter beyond the quarter in which the QA test

was due (particularly for infrequently-operated or seasonally-operated

units). Consequently, the Part 75 grace period provisions in appendix B

are considered to be inappropriate for sources that report emissions

data only during the ozone season. Without a complete record of unit

operation for each year, the regulatory agency will be unable to

determine whether the required QA tests have been completed within the

allotted grace period.

Second, Sec. 75.20(b)(3) of today's final rule provides

``conditional'' data validation procedures for CEMS recertifications.

These provisions allow a probationary period following a

recertification event, during which data from a CEMS are assigned a

``conditionally valid'' status. Provided that all recertification tests

are passed within the probationary period, with no test failures,

Sec. 75.20(b)(3) allows the conditionally valid data to be reported as

quality-assured. Today's rule also allows these data validation

procedures to be used for routine linearity checks and RATAs, in cases

where significant repair, adjustment or reprogramming of the CEMS is

done prior to the QA test. The maximum allowable length of the

probationary period is 168 unit operating hours for a linearity check

and 720 unit operating hours for a RATA. Once again, because these

probationary periods are in terms of unit operating hours, they can

extend outside the current calendar quarter, into the next quarter and

possibly beyond the next quarter. Therefore, for sources that report

only during the ozone season, some restrictions must be placed on the

use of the conditional data validation procedures in Sec. 75.20(b)(3).

In view of the above considerations, EPA has revised Subpart H to

make it clear which of the Part 75 QA and data validation provisions

are applicable to sources that report only in the ozone season and

which provisions are inapplicable. The Agency has replaced the general

references in Subpart H to the quality assurance provisions of

Sec. 75.21 and appendix B and the references to the provisions of

Sec. 75.20 with specific language that delineates the exact QA tests

required during each ozone season. Section 75.74(c)(3) of today's rule

also contains specific data validation provisions for sources that

report only during the ozone season. To the extent possible, these QA

and data validation provisions have been made the same as or similar to

the requirements for sources that report data on a year-round basis.

However, as necessary, special provisions have been added to

Sec. 75.74(c) to address the differences between year-round reporters

and sources that report only during the ozone season. EPA believes that

these revisions to Subpart H will help to achieve consistency in the

implementation of state and Federal NOX mass emission

reduction programs and will help to ensure the quality of the reported

data.

IV. Administrative Requirements

A. Public Docket

EPA has established Docket A-97-35 for the regulations. The docket

is an organized and complete file of all the information submitted to,

or otherwise considered by, EPA in the development of today's final

rule. The principal purposes of the docket are: (1) to allow interested

parties a means to identify and locate documents so that they can

effectively participate in the rulemaking process; and (2) to serve as

the record in case of judicial review. The docket is available for

public inspection at EPA's Air Docket, which is listed under the

ADDRESSES section of this notice.

B. Executive Order 12866

Under Executive Order 12866 (58 FR 51735, October 4, 1993), the

Administrator must determine whether the regulatory action is

``significant'' and therefore subject to Office of Management and

Budget (OMB) review and the requirements of the Executive Order. The

Order defines ``significant regulatory action'' as one that is likely

to result in a rule that may:

(1) Have an annual effect on the economy of $100 million or more

or adversely affect in a material way the economy, a sector of the

economy, productivity, competition, jobs, the environment, public

health or safety, or State, local or tribal governments or

communities;

(2) Create a serious inconsistency or otherwise interfere with

an action taken or planned by another agency;

[[Page 28584]]

(3) Materially alter the budgetary impact of entitlements,

grants, user fees, or loan programs or the rights and obligations of

recipients thereof; or

(4) Raise novel legal or policy issues arising out of legal

mandates, the President's priorities, or the principles set forth in

the Executive Order.

This rule is not expected to have an annual effect on the economy

of $100 million or more.

Pursuant to the terms of Executive Order 12866, it has been

determined that this rule is a ``significant regulatory action'' due to

its policy implications. Therefore, the rule was submitted to OMB for

review. Any written comments from OMB and any EPA response to those

comments are included in the public docket for this proposal. The

docket is available for public inspection at EPA's Air Docket Section,

which is listed in the ADDRESSES portion of this preamble.

C. Unfunded Mandates Reform Act

Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Pub.

L. 104-4, establishes requirements for Federal agencies to assess the

effects of their regulatory actions on state, local, and tribal

governments and the private sector. Under section 202 of the UMRA, EPA

generally must prepare a written statement, including a cost-benefit

analysis, for proposed and final rules with ``Federal mandates'' that

may result in expenditures to state, local, and tribal governments, in

the aggregate, or to the private sector, of $100 million or more in any

one year. Section 205 of the UMRA generally requires that, before

promulgating rules for which a written statement is needed, EPA must

identify and consider a reasonable number of regulatory alternatives

and adopt the least costly, most cost-effective, or least burdensome

alternative that achieves the objectives of the rule. The provisions of

section 205 do not apply when they are inconsistent with applicable

law. Moreover, section 205 allows EPA to adopt an alternative other

than the least costly, most cost-effective, or least burdensome

alternative if the Administrator publishes with the final rule an

explanation why that alternative was not adopted. Before EPA

establishes any regulatory requirements that may significantly or

uniquely affect small governments, including tribal governments, it

must have developed under section 203 of the UMRA a small government

agency plan. The plan must provide for notifying potentially affected

small governments, enabling officials of affected small governments to

have meaningful and timely input in the development of EPA regulatory

proposals with significant Federal intergovernmental mandates, and

informing, educating, and advising small governments on compliance with

the regulatory requirements.

This rule is not expected to result in expenditures of more than

$100 million in any one year and therefore is not subject to section

202 of the UMRA. Although the rule is not expected to significantly or

uniquely affect small governments, the Agency notified all potentially

affected small governments that own or operate units potentially

affected by the rule in order to assure that they had the opportunity

to have meaningful and timely input on the rule. EPA will continue to

use its outreach efforts related to part 75 implementation, including a

policy manual that is generally updated on a quarterly basis, to

inform, educate, and advise all potentially impacted small governments

about compliance with part 75.

EPA is not directly establishing any regulatory requirements that

may significantly or uniquely affect small governments, including

tribal governments. Thus, EPA is not obligated to develop under section

203 of the UMRA a small government agency plan.

D. Executive Order 12875

Under Executive Order 12875, EPA may not issue a regulation that is

not required by statute and that creates a mandate upon a State, local

or tribal government, unless the Federal government provides the funds

necessary to pay the direct compliance costs incurred by those

governments, or EPA consults with those governments. If EPA complies by

consulting, Executive Order 12875 requires EPA to provide to the Office

of Management and Budget a description of the extent of EPA's prior

consultation with representatives of affected State, local and tribal

governments, the nature of their concerns, copies of any written

communications from the governments, and a statement supporting the

need to issue the regulation. In addition, Executive Order 12875

requires EPA to develop an effective process permitting elected

officials and other representatives of State, local and tribal

governments ``to provide meaningful and timely input in the development

of regulatory proposals containing significant unfunded mandates.''

EPA has concluded that this rule will create a mandate on local and

tribal governments and that the Federal government will not provide the

funds necessary to pay the direct costs incurred by the local and

tribal governments in complying with the mandate. In developing this

rule, EPA consulted with local and tribal governments to enable them to

provide meaningful and timely input in the development of this rule.

Only local or tribal governments that own sources affected by Acid Rain

would be affected by this rulemaking. The governments that own an Acid

Rain affected source were contacted when the proposed rule was signed

and informed of their right to comment on the proposal. EPA received a

few comment letters from municipal utilities; these letters contained

support for many elements of the rule, as well as concerns with certain

provisions. The Agency has attempted to include changes to the proposed

rule revisions based on these and other comments wherever possible

consistent with the purpose and intent of the rule revisions, and to

the extent justified by the commenters. See section III of this

preamble and the response to comments document included in the docket

for this rulemaking for the Agency's responses to the specific comments

raised. EPA also notes generally that these sources already have to

comply with part 75. Today's rule adds more compliance flexibility and

may reduce the compliance costs for some of the sources owned by local

and tribal governments.

E. Executive Order 13084

Under Executive Order 13084, EPA may not issue a regulation that is

not required by statute, that significantly or uniquely affects the

communities of Indian tribal governments, and that imposes substantial

direct compliance costs on those communities, unless the Federal

government provides the funds necessary to pay the direct compliance

costs incurred by the tribal governments, or EPA consults with those

governments. If EPA complies by consulting, Executive Order 13084

requires EPA to provide the Office of Management and Budget, in a

separately identified section of the preamble to the rule, a

description of the extent of EPA's prior consultation with

representatives of affected tribal governments, a summary of the nature

of their concerns, and a statement supporting the need to issue the

regulation. In addition, Executive Order 13084 requires EPA to develop

an effective process permitting elected officials and other

representatives of Indian tribal governments ``to provide meaningful

and timely input in the development of regulatory policies on matters

that significantly or uniquely affect their communities.''

[[Page 28585]]

Today's rule does not significantly or uniquely affect the

communities of Indian tribal governments. Only tribal governments that

own sources affected by the Acid Rain Program are affected by this

rulemaking. As noted above in section IV.D. of this preamble, today's

rule adds compliance flexibility and may reduce compliance costs for

any tribal governments that own or operate affected sources.

Accordingly, the requirements of section 3(b) of Executive Order 13084

do not apply to this rule.

F. Paperwork Reduction Act

The information collection requirements in this rule have been

submitted for approval to the OMB under the Paperwork Reduction Act, 44

U.S.C. 3501, et seq. An Information Collection Request (ICR) document

has been prepared by EPA (ICR No. 1633.12), and a copy may be obtained

from Sandy Farmer, OPPE Regulatory Information Division; U.S.

Environmental Protection Agency (2137); 401 M Street, SW, Washington,

DC 20460, by calling (202) 260-2740, or via the Internet at

www.epa.gov/icr. The information requirements are not effective until

OMB approves them.

Currently, all affected facilities are required to keep records and

submit electronic quarterly reports under the provisions of part 75.

The revisions to the rule include several new options for compliance

with part 75 which have been requested by owners or operators of

affected facilities. To implement these options, EPA will have to

modify the existing recordkeeping and reporting requirements. In some

circumstances, these changes will result in significant reductions in

the reporting and

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