28032 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

ENVIRONMENTAL PROTECTION

AGENCY

40 CFR Parts 72 and 75

[FRL–6007–8]

RIN 2060–AG46

Acid Rain Program; Continuous

Emission Monitoring Rule Revisions

AGENCY: Environmental Protection

Agency (EPA).

ACTION: Proposed rule.

SUMMARY: Title IV of the Clean Air Act

(CAA or the Act), as amended by the

Clean Air Act Amendments of 1990,

authorizes the Environmental Protection

Agency (EPA or Agency) to establish the

Acid Rain Program. The Acid Rain

Program and the provisions in this

proposed rule benefit the environment

by preventing the serious, adverse

effects of acidic deposition on natural

resources, ecosystems, materials,

visibility, and public health. The

program does this by setting emissions

limitations to reduce the acidic

deposition precursor emissions of sulfur

dioxide and nitrogen oxides. On January

11, 1993, the Agency promulgated final

rules, including the final continuous

emission monitoring (CEM) rule, under

title IV. On May 17, 1995, the Agency

published direct final and interim rules

to make the implementation of the CEM

rule simpler. Subsequently, on

November 20, 1996, the Agency

published a final rule in response to

public comments received on the direct

final and interim rules.

These proposed revisions to the CEM

rule would make a number of further

minor changes to make the

implementation of the CEM rule

simpler, more streamlined, and more

efficient for both EPA and the facilities

affected by the rule. Furthermore, the

proposed revisions would provide

reduced monitoring burdens for affected

facility units with low mass emissions.

In addition, the proposed revisions

would establish quality assurance

requirements for moisture monitoring

systems and add a new flow monitor

quality assurance test to assure the

accuracy of data reported from these

types of monitoring systems. Finally,

the proposed revisions would create a

new monitoring option, the F-factor/fuel

flow method, for certain units.

DATES: Comments. All public comments

must be received on or before July 20,

1998.

Public Hearing. Anyone requesting a

public hearing must contact EPA no

later than May 31, 1998. If a hearing is

held, it will take place June 8, 1998,

beginning at 10:00 a.m.

ADDRESSES: Comments. Comments must

be mailed (in duplicate if possible) to:

EPA Air Docket (6102), Attention:

Docket No. A–97–35, Room M–1500,

Waterside Mall, 401 M Street, SW,

Washington, DC 20460.

Public Hearing. If a public hearing is

requested, it will be held at the

Environmental Protection Agency, 401

M Street, SW, Washington, DC 20460, in

the Education Center Auditorium. Refer

to the Acid Rain homepage at

www.epa.gov/acidrain for more

information or to determine if a public

hearing has been requested and will be

held.

Docket. Docket No. A–97–35,

containing supporting information used

to develop the proposal is available for

public inspection and copying from 8:00

a.m. to 5:30 p.m., Monday through

Friday, excluding legal holidays, at

EPA’s Air Docket Section at the above

address.

FOR FURTHER INFORMATION CONTACT:

Jennifer Macedonia, Acid Rain Division

(6204J), U.S. Environmental Protection

Agency, 401 M Street, SW, Washington,

DC 20460, telephone number (202) 564–

9123 or the Acid Rain Hotline at (202)

564–9620. Electronic copies of this

notice and technical support documents

can be accessed through the Acid Rain

Division website at http://www.epa.gov/

acidrain.

SUPPLEMENTARY INFORMATION: The

contents of the preamble are listed in

the following outline:

I. Regulated Entities

II. Background and Summary of the Proposed

Rule

III. Detailed Discussion of Proposed

Revisions

A. Use of Projections in the Definitions of

Gas-fired, Oil-fired, and Peaking Unit

B. Wording Correction of the Applicability

Provisions in Part 72

C. Low Mass Emissions Excepted

Methodology

1. Applicability Criteria

2. Method for Determining Emissions

3. Cutoff Limit for Applicability

4. Continuing Applicability Criteria

5. Reduced Monitoring and Quality

Assurance Requirements

6. Reduced Reporting Requirements

D. Quality Assurance Requirements for

Moisture Monitoring Systems

E. Certification/Recertification Procedural

Changes

1. Initial Certification versus

Recertification

2. Disapproval of an Incomplete

Application

3. Submittal Requirements for Certification

and Recertification Applications

4. Decertification Applicability

5. Recertification Test Notice

6. Monitoring Plans

7. Submittal Requirements for Petitions

and Other Correspondence

F. Substitute Data

1. Missing Data Procedures for CO2 and

Heat Input

2. Prohibition Against Low Monitor Data

Availability

G. General Authority to Grant Petitions

Under Part 75

H. NOX Mass Monitoring Provisions for

Adoption by NOX Mass Reduction

Programs

I. Span and Range Requirements

1. Maximum Potential Values

2. Maximum Expected SO2 and NOX

Concentrations

3. Span and Range Values

4. Dual Span and Range Requirements for

SO2 and NOX

5. Adjustment of Span and Range

J. Quality Assurance/Quality Control (QA/

QC) Program

1. QA/QC Plan

2. Flow Monitor Polynomial Coefficient

K. Calibration Gas Concentration for Daily

Calibration Error Tests

L. Linearity Test Requirements

1. Unit Operation During Linearity Tests

2. Linearity Test Frequency

3. Linearity Test Method

4. Exemptions

M. Flow-to-Load Test

N. RATA and Bias Test Requirements

1. RATA Frequency

2. RATA Load Levels

3. Flow Monitor Bias Adjustment Factors

4. Number of RATA Attempts

5. Concurrent SO2 and Flow RATAs

6. SO2 RATA Exemptions and Reduced

Requirements

7. QA Provisions for SO2 Monitors, for

Natural Gas Firing or Equivalent

8. General RATA Test Procedures

9. Reference Method Testing Issues

10. Alternative Relative Accuracy

Specifications and Specifications for

Low-Emitters

11. Bias Adjustment Factors for LowEmitters

12. Clarification of Diluent Monitor

Certification Requirements

13. Daily Calibration Requirements for

Redundant Backup Monitors

14. Daily Performance Specification and

Control Limits for Low-Span DP Flow

Monitors

O. CEM Data Validation

1. Recalibration and Adjustment of CEMS

2. Linearity Tests

3. RATAs

4. Recertification of Gas and Flow Monitors

5. Recertification and QA

6. Data from Non-Redundant Backup

Monitors

7. Missed QA Test Deadlines

P. Appendix D

1. Pipeline Natural Gas Definitions

2. Fuel Sampling

3. Sulfur, Density, and Gross Calorific

Value Used in Calculations

4. Missing Data Procedures for Sulfur

Content, Density, and Gross Calorific

Value

5. Installation of Fuel Flowmeters for

Recirculation

6. Fuel Flowmeter Testing
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28033

7. Use of Uncertified Commercial Gas

Flowmeter

Q. Appendix G

1. Use of ASTM D5373–93 for Determining

the Carbon Content of Coal

2. Changes to Fuel Sampling Frequency

3. Addition of Missing Data Procedures for

Fuel Analytical Data

R. Reporting Issues

1. Partial Unit Operating Hours and

Emission and Fuel Flow Rates

2. Use of Bias-Adjusted Flow Rates in Heat

Input Calculations

3. Removing the Restriction of Using the

Diluent Cap Only for Start-up

4. Complex Stacks—General Issues

5. Complex Stacks—Heat Input at Common

Stacks

6. Start-up Reporting—Units Shutdown

Over the Compliance Deadline

7. Start-up Reporting—New Units

8. Recordkeeping and Reporting Provisions

9. Electronic Transfer of Quarterly Reports

S. Revised Traceability Protocol for

Calibration Gases

T. Appendix I—New Optional Stack Flow

Monitoring Methodology

U. The Use of Predictive Emissions

Modeling Systems (PEMS)

IV. Administrative Requirements

A. Public Hearing

B. Public Docket

C. Executive Order 12866

D. Unfunded Mandate Reform Act

E. Paperwork Reduction Act

F. Regulatory Flexibility Act

G. National Technology Transfer and

Advancement Act

I. Regulated Entities

Entities potentially 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, today’s proposal could

potentially affect other industries. The

proposal includes 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:

Category Examples of regulated entities

Industry .... Electric service providers, boilers

and turbines from a wide

range of industries.

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 criteria in §§ 72.6, 72.7,

and 72.8 of title 40 of the Code of

Federal Regulations. If you have

questions regarding the applicability of

this action to a particular entity, consult

the person listed in the preceding FOR

FURTHER INFORMATION CONTACT section of

this preamble.

II. Background and Summary of the

Proposed 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

Agency promulgated final rules

implementing the program, including

the CEM rule (58 FR 3590–3766).

Technical corrections were published

on June 23, 1993 (58 FR 34126) and July

30, 1993 (58 FR 40746–40752). A notice

of direct final rulemaking and of interim

final rulemaking further amending the

regulations was 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–

59166) .

The issues addressed by this proposed

rule are: (1) revised definitions of gasfired, oil-fired, and peaking unit to

allow for changes in unit fuel usage

and/or operation; (2) a minor wording

correction of the applicability

provisions in Part 72; (3) new excepted

methodologies for units with low mass

emissions; (4) new QA/QC requirements

for moisture monitoring systems; (5)

clarifying changes to the certification

and recertification process; (6)

substitute data requirements for CO2

and heat input, as well as a prohibition

against low data availability; (7)

clarifying revisions to the petition

provisions for alternatives to part 75

requirements; (8) NOX mass monitoring

provisions provided as a model for

adoption by state, tribal, or federal NOX

mass reduction programs; (9) clarifying

changes to span and range requirements;

(10) clarifying revisions to general QA/

QC requirements; (11) calibration gas

concentrations for daily calibration error

tests; (12) linearity test requirements;

(13) a new flow-to-load QA test for flow

monitors; (14) reductions in and/or

clarifications to the relative accuracy

test audit (RATA) and bias test

requirements; (15) clarifying revisions to

the procedures for CEM data validation;

(16) clarifying revisions to the SO2

emissions data protocol for gas-fired and

oil-fired units (Appendix D); (17)

determining CO2 emissions (Appendix

G, sections 2.1 and 5); (18)

recordkeeping and reporting changes to

reflect the proposed revisions; (19) a

revised traceability protocol (Appendix

H); and (20) a new optional F-factor/fuel

flow method (Appendix I). In addition,

the preamble also includes a discussion

on potential provisions to allow for the

use of predictive emissions modeling

systems (PEMS) as an alternative to

CEMS for certain units.

Many of the changes proposed today

are minor technical revisions based on

comments received from utilities

following the initial implementation of

part 75. Based on experience gained in

the early years of the program, utilities

have developed a number of suggestions

that EPA believes would simplify and

streamline the monitoring process

without sacrificing data quality. In

addition, the Agency is proposing to

reduce the monitoring requirements for

units with low mass emissions to reduce

burdens on those types of units and to

add new monitoring options for some

units. The Agency has also proposed

new quality assurance requirements

based on gaps identified by EPA during

evaluation of the initial implementation

of part 75. Finally, several minor

technical changes are also proposed in

order to maintain uniformity within the

rule itself and to clarify various

provisions.

III. Detailed Discussion of Proposed

Revisions

A. Use of Projections in the Definitions

of Gas-Fired, Oil-Fired, and Peaking

Unit

Background

Section 72.2 of the January 11, 1993

rule provides definitions for the terms

‘‘gas-fired,’’ ‘‘oil-fired,’’ and ‘‘peaking

unit.’’ Each definition provides a limit

on the fuel usage or capacity factor

averaged over a three year period, as

well as an individual limit on each of

the three years, in order to qualify under

the definition. The May 17, 1995

revisions to part 75 amended those

definitions by adding provisions for

how a unit would initially qualify to

meet the definition. Each definition

provides for the case where a unit has

three years of historical data

demonstrating qualification, as well as

the case where a unit does not have data

for one or more of the three previous

years (e.g., a new unit or a unit that has

been in an extended shutdown). In

addition, the gas-fired definition

provides for the case where a unit’s fuel

usage is projected to change on or before

January 1, 1995 and the peaking unit

definition provides for the case where a

unit’s capacity factor is projected to

change on or before the certification

deadline (either 1995 or 1996) for NOX
28034 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

monitoring in § 75.4. In each case where

historical data does not exist or is not

representative based on projected

change, the amended definitions set

provisions for allowing projections of

unit operation to be used in place of

historical data in order to meet the

criteria of the respective definition.

However, none of the three definitions

provides for the case where a unit’s fuel

usage or capacity factor is expected to

change after initial classification.

Under the existing rule, the

importance of determining whether a

unit qualifies under the definitions of

gas-fired, oil-fired, and peaking unit,

centers on the differences in regulatory

requirements and options for different

classifications of units. For example,

under § 75.11(d)(2), a unit that qualifies

as gas-fired or oil-fired has an additional

option for monitoring SO2 emissions

using the excepted protocol of

Appendix D, in lieu of an SO2 CEMS

and flow monitor. Additionally, under

§ 75.14(c), a unit that qualifies as gasfired is exempt from opacity monitoring,

and, under section 2.3 of Appendix G to

part 75, a gas-fired unit has an

additional option for determining CO2

mass emissions in lieu of a CO2 CEMS

or using carbon sampling in conjunction

with a fuel flowmeter. Qualifying under

the definition of peaking unit also has

the advantage of allowing additional

regulatory options. For example, a

peaking unit has the option of

monitoring NOX emission rate using the

excepted protocol under Appendix E, in

lieu of a NOX CEMS. Further, under

section 2.3.1 of Appendix B to part 75,

a peaking unit is required to perform

annual quality assurance flow monitor

RATAs at a single load level instead of

at three load levels.

Utility representatives have contacted

EPA for guidance about how a change

in the manner of operation of the unit

after certification and initial

classification of the unit affects the

status of the unit with respect to the

definitions of gas-fired, oil-fired, and

peaking unit. For example, a utility

representative contacted the Agency

about a unit designed to burn gas and/

or oil that historically had burned

primarily oil and was classified as an

oil-fired unit. The utility had decided to

switch from oil to burn almost entirely

gas at the unit and asked whether it was

necessary to wait three years after the

switch to gas in order to gather three

years of historical data, to qualify for the

additional regulatory options available

only for gas-fired units. The utility

requested permission to use projections

of fuel usage certified by the designated

representative, to demonstrate that the

unit would meet the gas-fired definition

after the switch to gas, so that the unit

could be exempt from opacity

monitoring and qualify to use equation

G–4 to determine CO2 mass emissions.

The existing rule would require such a

unit to wait three years after the change

in operation in order to qualify as gasfired. Based on EPA’s experience of

implementing the provisions of Parts 72

and 75, the definitions of the terms gasfired, oil-fired, and peaking unit are not

sufficiently detailed or flexible to

address situations where a permanent

change in the manner of operation after

the initial classification (i.e, capacity

factor or fuel usage) affects the gas-fired,

oil-fired, or peaking unit status.

Discussion of Proposed Changes

Today’s proposal would amend the

definitions of the terms gas-fired, oilfired, and peaking unit, to add

provisions for an existing unit that does

not presently qualify under the

definition but that experiences a

permanent change in operation (i.e., fuel

usage for the gas-and oil-fired

definitions and capacity factor for the

peaking unit definition).

For the definition of gas-fired, the

proposed revisions would allow an

existing unit to qualify under the

definition if the designated

representative submits a minimum of

720 hours of unit operating data

demonstrating that the unit meets the

percentage criteria of a gas-fired unit

(i.e., no less than 90.0 percent of the

unit’s heat input from the combustion of

gaseous fuels with a total sulfur content

no greater than natural gas and the

remaining heat input from the

combustion of fuel oil), accompanied by

a certification statement from the

designated representative. The

designated representative statement

would certify that the changed pattern

of fuel usage, represented in the 720

hours of data, is considered permanent

and is projected to continue for the

foreseeable future.

The proposed definition of oil-fired

unit would simplify the provisions for

qualification, for purposes of part 75.

The proposed definition would simply

require that a unit burn only fuel oil and

gaseous fuels with a total sulfur content

no greater than natural gas and that the

unit does not meet the definition of gasfired, in order to qualify as oil-fired.

With this simplification, a unit could

qualify under any of the following

circumstances: (1) a new unit projected

to burn only fuel oil and gaseous fuels

with a sulfur content no greater than

natural gas but projected to burn too

much oil to qualify as gas-fired; (2) an

existing gas-fired unit, which burns only

fuel oil and natural gas, but which

exceeds the gas-fired annual limit of 15

percent of the annual heat input from

fuel oil; and (3) an existing coal-fired

unit that is converted to only burn fuel

oil and/or gas but which projects it will

burn too much oil to qualify as gas-fired.

The proposed definition of peaking

unit would allow an existing unit whose

capacity factor is projected to change, to

qualify as a peaking unit if the

designated representative submits a

demonstration satisfactory to the

Administrator that the unit will qualify

as a peaking unit, using the three

calendar years beginning with the first

full year following the change in the

unit’s capacity factor as the three year

period. This demonstration would need

to show that the unit’s capacity factor in

the year following the permanent

change in operation did not exceed 10.0

percent and that the projected average

annual capacity factor for the unit in the

three year period and the projected

capacity for each of the two individual

projected years will meet the definition

of a peaking unit.

Additionally, under today’s proposal,

the gas-fired definition would be revised

to clarify the requirements as they apply

for the purposes of part 75 versus the

requirements for the purposes of all

other Parts under the Acid Rain

Program. This proposed revision is

merely editorial and would not change

the intent of the existing regulation.

Rationale

The Agency proposes to allow

projections of fuel usage or capacity

factor in conjunction with some actual

data to be used for the purpose of

meeting the criteria of the gas- or oilfired or peaking unit definitions,

respectively. The Agency believes it is

unnecessary to require three years to

pass before a unit that the designated

representative certifies has permanently

changed its manner of operation is

allowed to utilize the additional

regulatory options allowed for units

meeting the definitions of gas-fired, oilfired, and peaking unit. The Agency

believes it is sufficient to require the

designated representative to submit

representative data that the unit would

qualify under the definition following

the permanent change in operation or

fuel usage (i.e., 720 hours for the gasfired definition and a full year for the

peaking unit definition) and to certify

that the change in fuel usage or capacity

factor is considered permanent and that

the unit is expected to continue to meet

the definition of gas-fired, oil-fired, or

peaking unit, as applicable, into the

foreseeable future.

Under the existing rule, the peaking

unit definition does provide for the
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28035

situation where a unit’s operation is

projected to change and the unit will

meet the peaking unit definition with

those projections. However, this

provision is limited to the case where a

unit’s operation has changed by the

certification deadline for NOX

monitoring. The existing rule does not

provide for the scenario where a change

to the unit’s operation after the

certification deadline would affect the

peaking unit status and where the

designated representative might want to

take advantage of regulatory options that

are available under this new status.

EPA believes that it is appropriate to

allow a unit to use the regulatory

options that are only allowed for

peaking units, if a unit’s operation

permanently changes such that it meets

the capacity factor definition with one

year of actual data and two years of

projections. If the projections are

incorrect, the unit will lose its peaking

unit status and will not be able to use

projections again to qualify.

Similarly, under the existing rule, the

gas-fired definition does provide for the

situation where an existing unit that

does not qualify under the gas-fired

definition experiences a change in

operations or fuel usage that would

result in the unit qualifying as gas-fired

in future years. However, this provision

is limited to the case where a unit’s

operation has changed by the

certification deadline for SO2 and

opacity monitoring, from 1995 through

1997. The existing rule does not provide

for the scenario where a change to the

unit’s fuel usage after the certification

deadline would affect the gas-fired

status and that the designated

representative might want to take

advantage of regulatory options that are

available under this new status.

However, EPA believes that it is

appropriate to allow a unit to use the

regulatory options that are only allowed

for gas-fired units, if a unit’s fuel usage

permanently changes such that it meets

the gas-fired definition with 720 hours

of actual data and projections of fuel

usage to make up the remainder of the

three year period. If the projections are

incorrect, the unit will lose its gas-fired

status and will not be able to use

projections again to qualify.

B. Wording Correction of the

Applicability Provisions in Part 72

Background

Section 72.6(b)(1) currently includes,

in the list of types of units that are

unaffected units under the Acid Rain

Program, ‘‘[a] simple combustion

turbine that commenced operation

before November 15, 1990.’’ 40 CFR

72.6(b)(1). Title IV actually provides,

through statutory definitions and

provisions setting emission limitations,

that a simple combustion turbine that

commenced commercial operation

before the enactment of title IV, i.e.,

November 15, 1990, is an unaffected

unit. A simple combustion turbine

commencing commercial operation on

or after November 15, 1990 is an

affected unit (unless it is exempt under

some other provision, e.g., the new units

exemption under § 72.7).

To begin, the definition of ‘‘existing

unit’’ in section 402(8) of the Act

excludes existing simple combustion

turbines (i.e., those that commenced

commercial operation prior to

November 15, 1990) and so excludes

them from being affected units subject

to an SO2 emission limitation under

section 405(a)(1). As stated in that

section 402(8):

‘‘existing unit’’ means a unit * * * that

commenced commercial operation before the

date of enactment of the Clean Air Act

Amendments of 1990 [i.e., November 15,

1990] * * * For purposes of this title,

existing units shall not include simple

combustion turbines * * * 42 U.S.C.

7651a(8).

In contrast, the statutory definition of

‘‘new unit’’ does not exclude any new

simple combustion turbines, and under

section 403(e), all new utility units are

affected units subject to an SO2

emission limitation. As stated in section

402(10):

‘‘new unit’’ means a unit that commences

commercial operation on or after the date of

enactment of the Clean Air Act Amendments

of 1990 [i.e., November 15, 1990]. 42 U.S.C.

7651a(10).

A unit that commences commercial

operation after November 15, 1990, and

so does not meet the definition of

‘‘existing unit’’, is therefore a new unit

and an affected unit subject to Acid

Rain Program requirements.

While § 72.6(b)(1) states that a simple

combustion turbine that ‘‘commenced

operation’’ before November 15, 1990 is

not an affected unit, EPA interprets this

provision, consistent with the Act, to

refer to commencement of commercial

operation. However, in order to remove

any ambiguity and any possibility of

erroneous application of the statutory

exemption for simple combustion

turbines, EPA believes that the

regulatory provision should be

corrected.

Discussion of Proposed Changes

Today’s proposal would revise the

existing § 72.6(b)(1) in order to make it

consistent with title IV of the Act. EPA

proposes to revise the language of the

provision to refer expressly to

‘‘commercial operation,’’ rather than

simply ‘‘operation,’’ of a simple

combustion turbine.

Rationale

EPA notes that the existing

§ 72.6(b)(1) was not intended to deviate

from the provisions in the Act

concerning simple combustion turbines.

In proposing the applicability

provisions that were finalized (with

changes) as § 72.6, EPA explained that:

simple combustion turbines would be subject

to Acid Rain Program requirements in Phase

II (as new units) if such units commenced

commercial operation on or after November

15, 1990, because the statutory exemption for

simple combustion turbines is only

applicable to existing units. 56 FR 63002,

63008 (1991).

In noting that new simple combustion

turbines are affected units, EPA

requested comment on whether a ‘‘de

minimis exclusion should be included

in the final rule’’ for ‘‘very small units’’

from the Acid Rain Program. Id. In

response to comments supporting an

exemption for simple combustion

turbines and other units, EPA

established in the final rule an

exemption for new units (including new

simple combustion turbines) serving

generators with total capacity of 25

MWe or less. 58 FR 3590, 3593–4

(1993); Response to Comment at P–22

and P–23 (1993). In the final rule

preamble, EPA did not indicate any

intention to make any other changes

concerning the applicability of the Acid

Rain Program to new simple combustion

turbines.

C. Low Mass Emissions Excepted

Methodology

Background

In the January 11, 1993 Acid Rain

permitting rule, EPA provided for a

conditional exemption from the

emissions reduction, permitting, and

emissions monitoring requirements of

the Acid Rain Program for new units

having a nameplate capacity of 25 MWe

or less that burn fuels with a sulfur

content no greater than 0.05 percent by

weight, because of the de minimis

nature of their emissions (see 58 FR

3593–94 and 3645–46). Moreover, in the

January 11, 1993 monitoring rule, EPA

allowed gas-fired and oil-fired peaking

units to use the provisions of Appendix

E, instead of CEMS, to determine the

NOX emission rate, stating that this was

a de minimis exception. EPA allowed

this exception from the requirements of

section 412 of the Clean Air Act because

the NOX emissions from these units

would be extremely low, both
28036 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

collectively and individually, and

because the cost of measuring a ton of

NOX with CEMS could be several

hundred dollars per ton of NOX

monitored (see 58 FR 3644–45). One

utility wrote to the Agency, suggesting

that the Agency consider further

regulatory relief for other units with

extremely low emissions that do not fall

under the categories of small new units

burning fuels with a sulfur content less

than or equal to 0.05 percent by weight

or gas-fired and oil-fired peaking units

(see Docket A–97–35, Item II–D–31).

The utility specifically suggested that

the Agency consider an exemption, the

ability to use Appendix E, or some other

simplified methods which are more cost

effective.

In the process of implementing part

75, other utilities also have suggested to

EPA that it provide regulatory relief to

low mass emitting units (see Docket A–

97–35, Items II–D–29, II–E–25). These

units might be low mass emitting

because they use a clean fuel, such as

natural gas, and/or because they operate

relatively infrequently. Some utilities

stated that they spend a great deal of

time reviewing the emissions data when

preparing quarterly reports for these

units. Others indicated that it would be

important to reduce monitoring and

quality assurance (QA) requirements in

order to save time and money currently

devoted to units with minimal

emissions (see Docket A–97–35, Item II–

E–25).

Discussion of Proposed Changes

Today’s proposal would incorporate

optional reduced monitoring, quality

assurance, and reporting requirements

into part 75 for units that burn only

natural gas or fuel oil, emit no more

than 25 tons of SO2 and no more than

25 tons of NOX annually, and have

calculated annual SO2 and NOX

emissions (reflecting their potential

emissions during actual operation) that

do not exceed such limits.

A unit would initially qualify for the

reduced requirements by demonstrating

to the Administrator’s satisfaction that

the unit meets the applicability criteria

in proposed § 75.19(a). Proposed

§ 75.19(a) would require facilities to

submit historical actual (or projections,

as described below) and calculated

emissions data from the previous three

calendar years demonstrating that a unit

falls below the 25-ton cutoffs for SO2

and NOX. The calculated emissions data

for the previous three calendar years

would be determined by applying the

emission factors and maximum rated

hourly heat input, under § 75.19(c), to

the hours of operation and fuel burned

during the previous three calendar

years. The data demonstrating that a

unit meets the applicability

requirements of § 75.19(a) would be

submitted in a certification application

for approval by the Administrator to use

the low mass emissions excepted

methodology. The Agency requests

comments on whether a unit that

exceeded the 25-ton emissions cutoff for

a part of the previous three years, but

that has made a permanent change in

the operation of the unit such that it

would expect to meet the applicability

criteria based on projections of future

operation, should be allowed to use the

excepted methodology.

For units that lack historical data for

one or more of the previous three

calendar years (including new units that

lack any historical data), proposed

§ 75.19(a) would require the facility to

provide (1) any historical emissions and

operating data, beginning with the unit’s

first calendar year of commercial

operation, that demonstrates that the

unit falls under the 25-ton cutoffs for

SO2 and NOX, both with actual

emissions and with calculated

emissions using the proposed

methodology, as described above; and

(2) a demonstration satisfactory to the

Administrator that the unit will

continue to emit below the tonnage

cutoffs (e.g., for a new unit, applying the

emission rates and hourly heat input,

under § 75.19(c), to a projection of

annual operation and fuel usage to

determine the projected mass

emissions).

For units with historical actual (or

projections, as described above)

emissions and calculated emissions

falling below the tonnage cutoffs,

facilities would be allowed to use the

optional methodology in proposed

§ 75.19(c) in lieu of either CEMS or,

where applicable, in lieu of the

excepted methods under Appendix D, E,

or G for the purpose of determining and

reporting heat input, NOX emission rate,

and NOX, SO2, and CO2 mass emissions.

Under the optional methodology in

proposed § 75.19(c), a facility would

calculate and report hourly SO2 and CO2

mass emissions based on the unit’s

maximum rated hourly heat input and

the appropriate emission factor, defined

in § 75.19(c), Tables 1a and 1c, for the

fuel burned that hour. Similarly, a

facility would calculate and report

hourly NOX mass emissions as the

product of the maximum rated hourly

heat input and the appropriate fuel and

boiler type NOX emission rate located in

proposed Table 1b. The facility would

no longer be required to keep

monitoring equipment installed on low

mass emissions units, nor would it be

required to meet the quality assurance

test requirements or QA/QC program

requirements of Appendix B to part 75.

Moreover, emissions reporting

requirements would be reduced by

requiring only that the facility report the

unit’s hourly mass emissions of SO2,

CO2, and NOX, the unit’s NOX emission

rate, and the fuel type burned for each

hour of operation, and report the

quarterly total and year-to-date

cumulative mass emissions, heat input,

and operating time, in addition to the

unit’s quarterly average and year-to-date

average NOX emission rate for each

quarter. Facilities would continue to be

required to monitor, record, and report

opacity data for oil-fired units, as

specified under §§ 75.14(a), 75.57(f),

and 75.64(a)(iii) respectively. Under

§ 75.14(c) and (d), however, gas-fired,

diesel-fired, and dual-fuel reciprocating

engine units would continue to be

exempt from opacity monitoring

requirements.

If an initially qualified unit were

subsequently to burn fuel other than

natural gas or fuel oil, the unit would be

disqualified from using the reduced

requirements starting the first date on

which the fuel (other than natural gas or

fuel oil) was burned.

In addition, if an initially qualified

unit were to subsequently exceed the

25-ton cutoff for either SO2 or NOX

while using the proposed methodology,

the facility would no longer be allowed

to use the reduced requirements in

proposed § 75.19(c) for determining the

affected unit’s heat input, NOX emission

rate, or SO2, CO2, and NOX mass

emissions. Proposed § 75.19(b) would

allow the facility two quarters from the

end of the quarter in which the

exceedance of the relevant 25-ton

cutoff(s) occurred to install, certify, and

report SO2, CO2, and NOX data from a

monitoring system that meets the

requirements of §§ 75.11, 75.12, and

75.13, respectively.

Rationale

In addressing concerns from utilities

about the cost of monitoring, quality

assurance testing, and reporting

emissions from low-emitting sources,

EPA considered how to establish

reduced requirements. Utilities have

indicated to EPA that it would be more

helpful for the Agency to reduce testing

requirements for monitoring equipment

than it would be to reduce only

reporting requirements (see Docket A–

97–35, Item II–E–25). The Agency

considered whether a reduction in

monitoring or reporting requirements

might have unintended adverse

consequences for the environment. In

order to minimize this possibility, but

still make the program more cost
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28037

effective for facilities, the Agency is

proposing to allow an exception from

full monitoring and reporting

requirements for low mass emitting

units. In proposing these reduced

requirements, the Agency is exercising

its discretion to allow de minimis

exceptions from statutory requirements

in administering the Clean Air Act (see,

e.g., Alabama Power Co. v. Costle, 636

F.2d 323, 360–61 (D.C. Cir. 1979); and

58 FR 3593–94 and 3645–46). The

Agency, in exercising its discretion,

believes that in light of the de minimis

aggregate amount of emissions from

low-emitting units as a group, little or

no environmental benefit would be

derived from continuing to require the

additional accuracy of monitoring data

from low-emitting units under the

existing regulations, if such units are

subjected instead to the proposed

optional requirements. EPA also notes

that any such benefit would be greatly

outweighed by the cost of providing the

more accurate data.

In drafting today’s proposal, the

Agency considered six relevant

questions: (1) What parameters should

the applicability criteria be based on?

(2) How should estimated emissions be

calculated? (3) What cutoff emission

level should be used to determine

applicability of the reduced

requirements? (4) What should the ongoing applicability requirements be? (5)

What should the reduced monitoring

and quality assurance requirements be

for these units? and (6) What should the

recordkeeping and reporting

requirements be for these units?

1. Applicability Criteria

The Agency believes that the initial

criteria for a unit to qualify for the

excepted monitoring should be

consistent with the on-going criteria for

using such monitoring so that only units

that can likely continue to use the

methodology will qualify in the first

place. With the reduced monitoring

requirements under this exception, a

unit will not need to install monitors.

Consequently, the Agency believes that

the on-going applicability criteria

should not depend on measurements

from emissions monitoring equipment

and that actual emissions data or actual

heat input data, which are measured by

the monitoring equipment, would not be

appropriate as the primary applicability

criteria for initial qualification for the

exception or as the criteria for on-going

qualification.

The Agency considered what criteria,

other than actual measurements, should

be used as a basis for determining

applicability to use the reduced

monitoring and reporting exception.

EPA considered various parameters to

use in the applicability criteria,

including: estimated emissions or heat

input, the fuel burned, the unit capacity

factor, and annual generation measured

in MW-hr. Because the Agency’s

objectives for the exception include

ensuring that the total emissions from

the group of units that would qualify

under the exception are de minimis and

allowing more cost effective monitoring

for units in such a group, the Agency

believes it would be preferable to base

the applicability on estimated

emissions. While it may be simpler to

base qualification for reduced

monitoring solely on the fuel burned,

the unit capacity factor, or the annual

generation than to estimate the

emissions, the Agency believes that it

would be more difficult under that

approach to ensure that total emissions

that qualify under the exception were de

minimis. The Agency further believes

that using any of the other parameters,

while attempting to ensure that the total

emissions from the group are de

minimis, might exclude some units that

actually have low emissions. For

example, a unit that burns mostly

natural gas with emergency oil would be

excluded from an exception limited to

units that burn only natural gas. The

Agency believes that an applicability

criteria based on emissions would relate

more directly to the objectives behind

the optional exception than would other

operating factors that might serve as a

proxy for emissions.

2. Method for Determining Emissions

The Agency considered several

methods for determining the estimated

emissions as the basis for applicability

of the reduced monitoring and reporting

excepted methodology. For each of the

methods considered, rather than using

actual measured sulfur and carbon

values, CO2, SO2, and flow CEM

readings, NOX CEM readings, or NOX

values from an Appendix E NOX-versusheat input correlation, a facility would

calculate the unit’s emissions based on

an emission rate factor and default heat

input. Since the units that would

qualify for the excepted methodology

would still be accountable for reporting

emissions to the Agency and

surrendering allowances based on those

emissions, where applicable, the

emissions estimations would not just be

used to determine if the unit qualifies

under the exception; the reported

estimations would also be used to

determine compliance. The Agency

considered its goals for emissions

accounting in order to establish the

emission rate factors and default heat

input. The Agency maintains that it

would be inappropriate to select values

that would potentially underestimate

emissions, thereby undermining the

Agency’s ability to determine

compliance and achieve emission

reductions under title IV or any other

regulatory program involving SO2, CO2,

or NOX. Some industry representatives

suggested that facilities would be

willing to use a conservative emission

estimate, such as a maximum potential

emission rate times the maximum heat

input, if it would allow them to save

time and money currently spent on

monitoring and quality assurance (see

Docket A–97–35, Items II–D–30, II–D–

43, II–D–45, II–E–13, and II–E–25).

The Agency explored basing the

estimated emissions on a unit’s

maximum potential emissions, i.e.,

converting the unit’s nameplate capacity

(which assumes maximum possible

operation) to a maximum annual heat

input for the unit and multiplying by

the unit’s maximum emission rate

(which assumes the highest emission

rate of all fuels capable of being burned

at the unit). This option would have

several advantages. It would ensure that

emissions are not underestimated,

would allow for reduced monitoring

requirements, and would ensure that a

unit that initially qualifies for the

exception would continue to qualify

without having to reevaluate the unit’s

emissions each year (unless some

modification was made to the unit to

increase its nameplate capacity or allow

a higher emitting fuel to be burned).

This approach, however, would likely

disqualify gas-fired units that sometimes

burn oil or peaking units that operate

infrequently, since maximum potential

emissions would be substantially higher

than their actual emissions and would

likely exceed the applicability criteria

limit. Using this method to estimate

emissions for purposes of an

applicability cutoff would greatly

diminish the usefulness of the reduced

requirements and would fail to fully

meet the intended purpose of today’s

proposal.

In place of using a heat input derived

from maximum possible operation (i.e.,

nameplate capacity), the Agency

considered estimating heat input by

multiplying the actual operating hours

times a maximum rated hourly heat

input for the unit. While this would

require re-evaluation of a unit’s

eligibility each year, this would allow

an infrequently operated peaking unit to

qualify if its emissions are low, which

EPA believes is worth the additional

burden of annual re-evaluation.

Therefore, the Agency is proposing to

use maximum rated hourly heat input as

the heat input in the emissions
28038 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

estimation. Maximum rated hourly heat

input would be defined, in § 72.2, as a

unit-specific maximum hourly heat

input (mmBtu) based on the

manufacturer’s rating of the unit or, if

that value has been exceeded in

practice, based on the highest observed

hourly heat input. In addition, there

would be provisions for a lower

maximum hourly heat input to be used

if the unit has undergone modifications

which permanently limit its capacity.

The Agency also considered what

emission rate(s) to apply, instead of

using the highest emission rate of all

fuels capable of being burned at the

unit, in order to avoid underestimation

and to allow a unit that primarily burns

gas but has the ability to burn oil to

qualify for the reduced requirements.

The Agency believes that it would be

appropriate to use emission rates based

on uncontrolled emissions for the actual

fuel burned in any given hour to

estimate emissions for purposes of the

initial and on-going applicability cutoffs

to qualify to use the low mass emissions

excepted methodology and for purposes

of emissions reporting, allowance

accounting, and compliance. This

approach would avoid disqualifying

gas-fired units simply because of their

occasional use of oil and would also

avoid underestimating emissions.

For determining SO2 mass emissions

using the low mass emissions

methodology, EPA proposes the use of

emission factors in lb/mmBtu based on

its AP–42 air pollution emission rate

factors, which are established from the

sulfur content and gross calorific value

of the fuel being burned (see Docket A–

97–35, Items II–A–11, II–I–1). Since the

SO2 emissions are directly proportional

to the amount of sulfur in the fuel and

in light of the limited variability in the

sulfur content of natural gas and oil, the

proposed SO2 mass emission factors

should be fairly representative of

uncontrolled, actual emissions. Because

of the relatively low sulfur content of

natural gas or oil, it is doubtful that any

of such units have SO2 controls. The

proposed factors fall within the typical

range of sulfur content and gross

calorific value for each fuel, although

somewhat on the conservative side for

sulfur content of diesel fuel and natural

gas other than pipeline natural gas.

For determining NOX mass emissions

and emission rate, EPA proposes using

the fuel- and unit-type-specific NOX

emission rate factors based on 90th

percentile emission rate data reported

under part 75 generally for uncontrolled

units (see Docket A–97–35, Item II–A–

9). While attempting to develop an

accounting approach for NOX emissions

from low mass emission units, EPA

encountered several issues. The first

issue involves the use of AP–42 factors.

During the finalization of the core part

75 monitoring rule, EPA considered

allowing peaking units with negligible

emissions both individually and

collectively to estimate NOX emissions

using AP–42 emission rate factors. EPA

rejected this approach in the January 11,

1993 final rule preamble at 58 FR 3644–

45 because the AP–42 emission rate

factors are derived from industry-wide

average estimates of emissions for

different fuel and boiler types and are

not based on actual historical operating

experience of the units to which the

estimates would be applied. Applying

AP–42 factors could result in

underestimation of NOX emissions

because actual NOX emissions can vary

significantly from unit to unit. The

formation of NOX from the combustion

of fossil fuels is dependent on the

amount of nitrogen in the fuel being

combusted and on the mix of nitrogen

and oxygen in combustion air. Further,

the NOX formation process depends on

unit-specific factors of combustion gas

temperature and stoichiometry of fuel

and air local to the flame. Consequently,

there can be significant variations in the

level of NOX emissions from unit to unit

due to variations in combustion

conditions. Therefore, EPA is not

proposing the use of AP–42 factors to

estimate NOX emissions from low mass

emissions units. Instead, now that three

years of actual historical operating data

collected under part 75 are available, it

was possible to develop the default NOX

emission rate factors being proposed

today. Although the default NOX

emission rate factors in today’s proposal

are generic factors, they should not

underestimate NOX emissions because

they are based on the 90th percentile of

actual annual average emission rates

reported generally from uncontrolled

units under part 75.

The Agency also considered using

site-specific NOX emission rate factors

based on historical emission data or

emissions testing data for the unit. For

example, a facility might use the

maximum value ever recorded by the

CEM for the unit, or it might use the

highest NOX emission rate value

calculated from the unit’s most recent

Appendix E NOX test, or it might use

site-specific values similar to those

discussed in the guidance manual for

implementing the NOX budget program

in the OTR (see Docket A–97–35, Item

II–I–7). The application of site-specific

NOX emission factors for low mass

emission units raises several issues.

First, for units with pollution controls

where the emission factor is based on

controlled emissions, the site-specific

emission factor could underestimate

actual emissions if the controls are not

operating properly. EPA considered

only allowing site-specific NOX

emission factors with units that do not

utilize NOX emission controls; however,

EPA realizes that many units employ at

least some form of NOX emission

controls (e.g., water or steam injection).

EPA also considered allowing a source

with controls to use a site-specific

emission factor only if it could

demonstrate that the pollution controls

are operating properly. However, this

would involve extensive, additional

recordkeeping and tracking to verify the

proper operation of pollution controls

and ensure that emissions are not

underestimated; this would run contrary

to the general approach under the

exception of reducing monitoring and

reporting requirements. A second issue

involves verifying that the site-specific

NOX emission factor is still

representative over time or after unit

modifications. This would require

future NOX emission rate testing.

Therefore, for purposes of creating a

methodology that is simple to

implement and in order to reduce future

testing requirements for facilities with

low mass emitting units, the Agency

proposes instead using NOX emission

rate factors based on fuel and unit type

and reflecting uncontrolled emissions.

EPA requests comments on this

approach, whether other approaches

should be used, and especially whether

there are any additional boiler types not

represented in today’s proposed rule for

which NOX emission rates should be

provided.

For determining CO2 mass emissions,

today’s rule proposes to use CO2

emission rate factors in tons/mmBtu.

The CO2 emission rate factors are

derived based on ideal gas theory and

standard Agency Fc factors for

estimating the volume of CO2 to be

emitted when a certain heat input of a

particular fuel is burned (see Docket A–

97–35, Item II–A–11). This resembles

the approach currently used in Equation

G–4 of Appendix G for gas-fired units.

Therefore, the Agency believes that an

appropriate method of estimating

emissions for the purposes of qualifying

for a reduced monitoring and reporting

exception and for purposes of emissions

accounting and compliance for units

under the exception is to calculate

emissions based on the actual number of

operating hours and the actual fuel

burned using maximum rated hourly

heat input and fuel-based and, for NOX

unit-type-based, emission factors. The

Agency requests comments on this

approach and on whether an alternate
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28039

1The terms ‘‘potential emissions’’ used in this

section of the preamble have a different meaning

than the terms ‘‘potential to emit’’ used elsewhere

by the Agency.

approach should be used. While the

Agency believes that the resulting

emissions estimates will in most, if not

all, cases be conservative and result in

an overestimation of emissions, it would

be possible, however unlikely, that the

estimate could underestimate the actual

emissions for some types of units.

Therefore, for existing units with

historical emissions data available, the

proposal would require that in addition

to meeting the applicability criteria

using the emissions estimates calculated

as described above, the unit would have

to meet the cutoffs for initial

qualification for the exception using the

actual annual emissions monitored

during the three years prior to applying

to use the exception.

3. Cutoff Limit for Applicability

EPA began developing applicability

criteria by first considering the level of

projected aggregate emissions

determined to be de minimis for

purposes of developing the new unit

exemption promulgated in the January

11, 1993 Acid Rain permitting rule (see

58 FR 3593–94 and 3645–46). Aggregate

emissions projected for units under the

exemption were approximately 138

cumulative tons of SO2 and 1934

cumulative tons of NOX emitted per

year. The Agency then conducted a

study of actual emissions data from

1996 quarterly reports under part 75 and

evaluated potential tonnage cutoffs for

SO2 and NOX. The Agency compared

the cumulative mass emissions from

groups of units emitting less than

various specified amounts to the total

emissions reported under the Acid Rain

program during the year (see Docket A–

97–35, Item II-A–10). For example, the

study shows what proportion of total

SO2 was emitted by units with both

actual and potential 1 emissions of 25

tons or less per year, 50 tons or less per

year, 60 tons or less per year, and 75

tons or less per year. From these

analyses, EPA also estimated how many

units might be eligible for reduced

requirements for determining emissions

and how much of an impact the new

emissions accounting option would

have on nationwide emissions

accounting.

EPA is proposing cutoff values of 25

tons per year of SO2 and 25 tons per

year of NOX. In order to qualify as a low

mass emissions unit, a unit would have

to demonstrate that both actual

historical emissions and potential

emissions (calculated with maximum

hourly heat input, emission factors and

either, for existing units, actual

historical number of operating hours or,

for new units, projections of future

annual operating hours) do not exceed

25 tons each for SO2 and NOX on an

annual basis. Based upon its analyses

(see Docket A–97–35, Item II-A–10),

EPA estimates that this tonnage cutoff

level would mean that the group of

units subject to the proposed reduced

requirements, even after Acid Rain

Program emission reductions are

considered, would have total annual

emissions of about 16 tons of SO2 and

90 tons of NOX (less than a thousandth

of a percent of total annual SO2

emissions and about 0.002 percent of

total annual NOX emissions for all

affected units). Both amounts, 16 tons of

SO2 and 90 tons of NOX, are less than

the total number of tons of those

pollutants determined to be de minimis

for purposes of the new unit exemption.

Today’s proposal to treat low mass

emission units as de minimis is

consistent with the de minimis

conclusions reached for new units.

While the reduced requirements are

somewhat less accurate than the

methodologies under the existing

regulations, the reduced requirements

are intended to yield emissions data that

are conservative and that, to the extent

they are inaccurate, are likely to

overstate emissions. Moreover, EPA

believes that the level of inaccuracy

(i.e., overstatement of emissions) would

similarly be extremely low (i.e., less

than a thousandth of a percent). Both

the total emissions subject to the

reduced requirements and the potential

amount of overstatement of emissions

are de minimis. Moreover, any

overstatement of regulated emissions

would have the effect of tightening

emission limits (e.g., by requiring

surrender of more allowances for SO2

than otherwise). Any overstatement of

other emissions would be too small to

affect adversely the air quality related

activities (e.g., air quality modeling) for

which the emissions data would be

used.

EPA would, however, be concerned

about extending today’s proposed

reductions in monitoring, quality

assurance, and reporting requirements

to units that exceed the 25-ton cutoffs

for actual or potential emissions.

Section 412 of the CAA requires all

affected units to monitor SO2,

volumetric flow, NOX, and opacity

using continuous emission monitoring

systems or an alternative monitoring

system approved by the Administrator

as having the same precision, reliability,

accessibility, and timeliness. In

addition, section 412 of the Act requires

that emissions data be quality-assured.

Section 821 of the Clean Air Act

Amendments of 1990 provides that,

through regulations issued by the

Administrator, all affected units must be

required to monitor CO2 emissions in

the same manner and to the same extent

as SO2 and NOX are monitored under

section 412. Part 75 of EPA’s rules

requires monitoring of SO2, NOX, and

CO2 and allows certain exceptions to the

statutory requirement for CEMS or

CEMS-equivalent alternative

monitoring: in Appendix D because,

inter alia, the information gathered

using the Appendix D methods is as

precise, reliable, accessible, and useful

as that from CEMS, and compares

acceptably with regard to timeliness;

and in Appendix E because the

emissions from all units eligible to use

Appendix E are negligible and such

units do not have emission limitations

for NOX under the Acid Rain Program

(see 58 FR 3641–45). The proposed

reduced monitoring and reporting

requirements for low mass emissions

units would not yield information

equivalent to that from CEMS. EPA

must balance the benefits of reduced

monitoring, quality assurance, and

reporting requirements for units against

the intent of the statute that monitoring

with CEMS or their equivalent be

required so as to obtain reliable, precise,

timely, and readily accessible

information on emissions. EPA solicits

comment on whether 25 tons is the

appropriate cutoff level for applicability

of the low mass emission excepted

methodology.

In particular, EPA is concerned that

extending the proposed reduction in

requirements to units with more than

this de minimis level of emissions could

have a negative impact on the

environment. Emissions data from the

Acid Rain Program are being used for a

variety of efforts, including emissions

modeling and establishing baseline

emissions information (prior to any

emission reductions) for new air

pollution control programs. Using less

accurate methods to monitor more than

a de minimis amount of emissions could

potentially undermine efforts to

establish baseline emissions and to

assess what emission reductions have

already taken place and how much

further emissions must be reduced in

order to meet air quality standards.

Furthermore, with regard to coal-fired

units, such units account for the largest

proportion of all emissions, tend to be

operated more frequently, and generally

have much higher emission rates in lb/

mmBtu for SO2, NOX and CO2, and the

majority of the units have emission

limitations and emission reduction
28040 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

requirements for SO2 and NOX. In

addition, the sulfur content in coal and

gaseous fuels other than natural gas is

much more variable than for natural gas

and oil, and the emission factors for coal

or gaseous fuels other than natural gas,

particularly an SO2 emission factor, are

therefore less reliable and much more

likely to understate, rather than

overstate, emissions. Based on these

considerations, the proposed rule would

restrict the use of the reduced

requirements to gas-fired units and oilfired units that burn natural gas and/or

fuel oil.

In order to qualify for the proposed

low mass emissions excepted

methodology, the proposed applicability

criteria would require a unit to meet

annual tonnage cutoffs of 25 tons each

for SO2 and NOX. EPA considered

whether the excepted methodology

should be available on a pollutant

specific level so that, for example, a unit

which falls below the tonnage cutoff for

SO2 but not for NOX could use the

proposed excepted methodology under

§ 75.19 to measure SO2 emissions but

use a NOX CEM or the excepted

methodology under Appendix E, where

applicable, to measure NOX emissions.

EPA believes this approach would not

be appropriate because some of the

same monitoring equipment and

reporting software is necessary for

measuring and reporting both of the

pollutants. One of the prime benefits of

the low mass emissions excepted

methodology would be the simplified

reporting which would require less time

and a less sophisticated Data

Acquisition and Handling System. In

particular, the need for a DAHS that

could calculate substitute data using the

missing data algorithms would be

removed because there are no missing

data algorithms for the low mass

emissions excepted methodology. If the

excepted methodology is only applied

to one of the pollutants, much of the

benefit would be negated because the

DAHS would still need to be capable of

calculating substitute data for the

measured pollutant and close to the full

quarterly report would still be required.

Another prime benefit of the proposed

low mass emissions excepted

methodology would be the removal of

monitoring and quality assurance

requirements. However, EPA believes

that almost all units that would qualify

for a 25-ton cutoff for only one pollutant

would meet the cutoff for SO2, not NOX,

and would already be using Appendices

D and E. A unit using a fuel flowmeter

to determine SO2 mass emissions under

Appendix D likely uses the same fuel

flowmeter to determine CO2 emissions

and heat input. Additionally, the same

fuel flowmeter is used to determine

NOX emissions under Appendix E. Even

if the unit were allowed to use the

proposed low mass emissions excepted

methodology for SO2 in lieu of

Appendix D, the unit would still have

to install, certify, operate, maintain,

quality assure, and report from a fuel

flowmeter to determine NOX emission

rate and heat input. Accurate heat input

is important since heat input is used to

calculate NOX mass emissions. In short,

the cost of operation, maintenance, and

quality assurance of the fuel flowmeter

would not be removed simply by

removing the requirement to monitor

SO2. Even if a unit that qualified under

the low mass emissions excepted

methodology for SO2 but not for NOX

was currently monitoring with

Appendix D, for SO2 and heat input,

and using a NOX CEM, for NOX

emission rate, using the excepted

methodology for SO2 but not for NOX

would have little benefit since the

installation, certification, and quality

assurance testing of the fuel flowmeter

would still be required to determine

heat input. Therefore, today’s proposed

low mass emissions excepted

methodology would be provided as an

option only if the unit has low mass

emissions of both SO2 and NOX. EPA

solicits comment on this approach and

on whether any benefit of allowing the

excepted methodology for one pollutant

only would outweigh the added

complexity in the excepted

methodology.

EPA also considered whether a

tonnage cutoff for CO2 emissions was

appropriate as part of the proposed

applicability criteria for low mass

emissions units. However, the proposed

excepted methodology under § 75.19

would require the use of a standard

emission factor (in lb of NOX/mmBtu)

for NOX to determine eligibility for the

exception. This would effectively

establish an upper limit on the annual

heat input for a given fuel and boiler

type at the level that would allow the

unit to meet the tonnage cutoff

applicability requirements. Because CO2

emissions are directly proportional to

heat input, there would be a built-in

annual CO2 emissions cutoff inherent in

the methodology.

4. Continuing Applicability Criteria

In drafting today’s proposal, EPA also

considered how to ensure that after

individual units initially qualified to

use the reduced monitoring exception,

they could continue to use the

exception only if they continued to have

de minimis emissions. Many of the units

that would qualify as low mass

emissions units under the proposal have

low emissions either because they use

pipeline natural gas and/or because they

operate infrequently. In both of these

situations, it is conceivable that a unit’s

emissions could become significant if

the unit’s fuel or hours of operation

were to change. Most gas-fired units are

capable of burning oil, but generally do

so only when pipeline natural gas is not

available. However, if the prices of gas

and oil were to change such that oil

became far more economical than gas,

some gas-fired units might switch to

burning high sulfur oil. Similarly,

increases in demand for electricity

could cause some peaking units to

operate more frequently, thereby

generating more emissions. Therefore,

EPA is proposing that in order to ensure

that emissions from units using the

reduced requirements would remain de

minimis, units would have to continue

to meet the applicability criteria in

order to qualify as low mass emissions

units. Because of the conservative heat

input and in some cases, conservative

emission factors, the Agency believes

that meeting the applicability criteria of

less than 25 tons of both SO2 and NOX

when calculating the emissions using

the low mass emissions excepted

methodology, will ensure that the actual

emissions of the low mass emission

units will be below those levels.

Therefore, once the methodology is

implemented, the on-going applicability

would only require that the limits be

met with the calculated mass emissions,

i.e., the facilities would be required to

continue to meet the 25-ton cutoffs on

an annual basis, as determined using the

emission calculation procedures in

proposed § 75.19.

It would, therefore, be necessary for

low mass emissions units to report NOX

mass emissions, in addition to the

required SO2 mass emissions and NOX

emission rate, in order to determine

continuing applicability. A continuing

applicability provision of this nature

would prevent a unit from continuing to

use the reduced requirements when its

emissions were no longer negligible. If

a unit initially met the applicability

criteria but failed to meet one or both of

the annual 25-ton cutoffs in a future

year, the unit would become

disqualified from using the exception.

Sufficient time would be necessary to

purchase, install, and certify CEMS or

the equipment necessary for monitoring

under Appendices D and/or E.

Therefore, a unit would not be

disqualified until two calendar quarters

after the quarter in which the 25-ton

cutoff is exceeded and would not be

required to certify and report from
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28041

monitoring systems until then. If that

unit changes, or is projected to change,

its fuel or amount of operation in the

future so that it would again meet the

25-ton SO2 and NOX cutoffs, the unit

could again qualify as a low mass

emissions unit. However, if the unit

initially qualified based on projected

operating hours and fuel usage and then

was disqualified the unit could not use

projected data to qualify again. The unit

would need to monitor using CEMS, an

approved alternative monitoring system,

or an optional protocol under

Appendices D and/or E, where

applicable, for at least an additional

three years in order to accumulate three

years of actual data.

5. Reduced Monitoring and Quality

Assurance Requirements

As discussed above, today’s proposed

rule would allow facilities to use a

maximum rated hourly heat input value

and an emission rate factor to determine

the mass emissions from a low-emitting

unit for each hour of actual operation.

This approach would involve no actual

emissions monitoring and no quality

assurance activities. Instead, the facility

would only need to keep track of

whether the unit combusted any fuel for

a particular hour and what type of fuel

was combusted. In this way, the

proposed revisions would significantly

reduce the burden on affected facilities,

while still ensuring that emissions are

not underreported.

6. Reduced Reporting Requirements

Some utilities have mentioned that

they find it troublesome to spend as

much time or more reviewing quarterly

report submissions for small,

infrequently operating gas-fired units as

they spend reviewing quarterly report

submissions for large coal-fired units

(see Docket A–97–35, Items II–D–75, II–

E–25). EPA agrees that facility

environmental personnel should be able

to spend a greater percentage of their

time focusing on units with higher

emissions than on low mass emissions

units, which, as discussed above,

account for such a small portion of total

emissions. Thus, today’s proposed rule

would simplify the reporting

requirements for low-emitting units so

that facilities could spend less of their

environmental department resources on

units with negligible emissions. For

units that rely on the procedures in

proposed § 75.19(c), the owner or

operator would have no requirements

related to records or reports of

certification testing and would be

exempt from all of the specific

recordkeeping requirements in

§§ 75.54(b) through (e) or 75.57(b)

through (e) relating to operating

parameter and emissions records.

Instead, the rule would require only that

an initial certification application,

containing data supporting the

applicability demonstration, and a

monitoring plan be submitted and that

limited hourly, quarterly, and year-todate cumulative data be reported on a

quarterly basis. The hourly record

would only be reported for hours of unit

operation, and an hour in which the

unit combusted fuel for any portion of

the hour would be considered a full

hour, for simplicity.

One utility has suggested that it

would be less burdensome if it could

simply report its quarterly cumulative

emissions, without reporting any

supporting hourly data; other utility

representatives have indicated that it

would be no more burdensome to report

an hourly default emission value if the

utility were already reporting hourly

operating information (see Docket A–

97–35, Item II–E–25). For purposes of

modeling air quality, the Agency

considers hourly operating information

far more valuable (e.g., for modeling

discrete periods of ozone exceedance)

than just a quarterly emission value

with no time or date mentioned.

Furthermore, because facilities already

keep track of the operation of their units

for business purposes, keeping track of

and reporting hourly operating

information should not be a substantial

burden. According to industry

representatives, however, allowing

facilities to record and report default

emission values instead of hourly

measured values would significantly

speed up their review of quarterly

reports prior to submission to the

Agency (see Docket A–97–35, Item II–E–

25). Thus, requiring facilities to report

hourly operational data and the default

emissions data for the fuel burned that

hour, but not hourly measured

emissions or heat input in additional

record types, would preserve the

Agency’s ability to model air quality

while imposing far less burden upon

facilities than the current part 75

requirements. Furthermore, because

hourly default values would be

employed, the need for missing data

procedures would be eliminated and the

Data Acquisition and Handling System

(DAHS) could be greatly simplified. In

fact, the reporting requirements for a

low mass emissions unit could most

likely be fulfilled with the use of a

commercially available spreadsheet

software package. EPA has incorporated

this approach into today’s proposed

rule.

D. Quality Assurance Requirements for

Moisture Monitoring Systems

Background

Section 75.11(b) of the original

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 § 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 (see

§§ 75.13(c), 75.16(e), and Equations F–

14b, F–16, F–17 and F–18 in Appendix

F) or when determining NOX emission

rate in lb/mmBtu (see section 3.2 in

Appendix F, and Equations 19–3

through 19–5, 19–8, and 19–9 in

Method 19 of Appendix A to part 60).

As presently codified, part 75 does

not specify any quality assurance

requirements for moisture measurement

devices. Implementation has shown this

to be an unfortunate omission in the

rule, since 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. The

Agency does not know the extent of

inaccuracy that currently exists in the

measurement of moisture by affected

units but believes it is important to

require certification and quality

assurance of moisture monitors—just as

is required for other CEMS used under

part 75—because the success of the SO2

trading system depends on accurate

monitoring.
28042 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

Discussion of Proposed Changes

Today’s proposal would incorporate

into part 75 quality assurance

requirements for moisture monitoring

systems. Section 75.11(b) would be

revised to require the owner or operator

to install, maintain, operate, and quality

assure a moisture monitoring system.

Proposed § 75.11(b) also specifies that a

moisture monitoring system may either

consist of: (1) a continuous moisture

sensor; (2) an oxygen 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 DAHS component

capable of determining moisture from a

lookup table, i.e., a psychrometric chart

(this third option would apply only to

saturated gas streams following wet

scrubbers). Corresponding changes

would be made to §§ 75.12, 75.13(c) and

75.16(e) to require that a quality assured

moisture monitoring system be used

whenever moisture corrections are

needed to accurately account for NOX

emissions, CO2 emissions, or heat input.

Requirements for the initial

certification of moisture monitoring

systems are proposed in three new

sections, §§ 75.20(c)(5), (c)(6), and (c)(7).

To make room for the new sections,

existing § 75.20(c)(3) would be deleted;

existing §§ 75.20(c)(4) and (c)(5) would

be redesignated as §§ 75.20(c)(3) and

(c)(4); and existing §§ 75.20(c)(6), (c)(7),

and (c)(8) would be redesignated,

respectively, as §§ 75.20(c)(8), (c)(9),

and (c)(10). The certification

requirements for continuous moisture

sensors are found in proposed

§ 75.20(c)(6) and include a 7-day

calibration error test and a relative

accuracy test audit (RATA). For

moisture monitoring systems consisting

of one or more wet- and dry-basis

oxygen analyzers, the proposed

certification requirements are found in

§ 75.20(c)(5) and include 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. Corresponding

revisions to § 75.22(a)(4) are proposed,

specifying that EPA Method 4 (either

the standard procedure or the midget

impinger procedure) would be used as

the reference method for the moisture

RATAs. For saturated gas streams, if a

lookup table is used to determine the

hourly stack gas moisture content, the

certification requirement in proposed

§ 75.20(c)(7) would consist of a DAHS

verification. At a minimum, the DAHS

verification would have to demonstrate,

at three temperatures covering the

normal range of stack temperatures, that

the software extracts the proper

moisture value from the lookup table

and applies it correctly to the emission

calculations. In today’s proposal, a new

§ 75.4(i) would also be added, requiring

owners or operators to complete all of

the applicable moisture monitoring

system certification tests specified in

proposed §§ 75.20(c)(5), (c)(6), and (c)(7)

no later than January 1, 2000.

Proposed performance specifications

for moisture monitoring systems are

found in sections 3.1, 3.2, 3.3, and 3.5

of Appendix A to part 75. These

specifications would apply to

continuous moisture sensors and to wetand dry-basis oxygen analyzers. The

proposed calibration error specification

in section 3.1 for continuous moisture

sensors is 3.0 percent of span. A new

section, 2.1.5, would be added to

Appendix A, defining the span of a

moisture sensor as equal to the full-scale

range of the instrument and requiring

that the range be consistent with section

2.1 of Appendix A. For moisture

monitoring systems consisting of wetand dry-basis O2 analyzers, the

proposed span values and performance

specifications for calibration error,

linearity, and cycle time in sections

2.1.3, 3.1, 3.2, and 3.5 of Appendix A

would be the same as the current

specifications for O2 monitors. The

proposed relative accuracy (RA)

specification for moisture monitoring

systems is found in a new section, 3.3.6,

in Appendix A and would be equal to

10.0 percent. An alternative RA

specification would also be provided in

section 3.3.6, i.e., the relative accuracy

would also be acceptable if the

difference between the mean difference

of the reference method measurements

and the moisture monitoring system

measurements is within ± 1.0 percent

H2O. A relative accuracy specification of

10.0 percent is being proposed in order

to maintain consistency with the

relative accuracy requirements for the

other program monitors (SO2, NOX, flow

rate, and CO2). The Agency notes that

moisture RATAs have not previously

been required by any other EPA

continuous monitoring regulation, and

therefore there is no relative accuracy

database upon which to draw. However,

moisture data are sometimes collected

using EPA Method 4 during each run of

a part 75 gas monitor RATA to convert

the gas reference method readings from

a dry basis to a wet basis. Therefore,

some part 75 sources that currently

account for moisture using wet- and

dry-basis oxygen analyzers or a moisture

sensor should be able to construct

moisture RATAs from previous test data

by comparing the Method 4 moisture

data from the gas monitor RATAs

against the readings recorded by the

moisture sensor or O2 analyzers at the

time of the gas RATAs. EPA encourages

those facilities that currently make

moisture corrections in their emission

equations to perform this type of data

analysis, if possible, and to provide

comment on the appropriateness of the

proposed moisture relative accuracy

specification.

On-going QA requirements for

moisture monitoring systems are also

proposed in sections 2.1.1, 2.1.4, 2.2.1,

2.3.1.1, and 2.3.1.2 of Appendix B to

part 75. Proposed section 2.1.1 of

Appendix B would require daily

calibrations of moisture monitoring

systems. Continuous moisture sensors

would be calibrated in accordance with

the manufacturers’ recommended

procedures. Proposed section 2.1.4

would give control limits for the daily

calibrations (i.e., ± 1.0 percent O2 for

oxygen analyzers and ± 6.0 percent of

span for continuous moisture sensors).

Proposed section 2.2.1 would require

quarterly linearity checks of wet- and

dry-basis oxygen analyzer(s). Proposed

section 2.3.1.1 would require

semiannual RATAs of moisture

monitoring systems, and proposed

section 2.3.1.2 would specify that if a

moisture monitoring system achieves a

relative accuracy of ≤ 7.5 percent or if

the mean difference between the CEMS

and reference method values is within

± 0.7 percent H2O, the system qualifies

for an annual, rather than semiannual

RATA frequency.

Missing data procedures for moisture

are included in today’s proposal in a

new section, § 75.37. The proposed

missing moisture data procedures are as

follows:

(1) Begin by using the following

‘‘initial’’ missing data procedures as of

the date and time of provisional

certification of the moisture monitoring

system or as of January 1, 2000

(whichever is earlier). Substitute 0.0

percent moisture for each hour of

missing data if no prior quality assured

data exist, and for the first 720 hours of

quality assured monitor operating data,

substitute, for each hour of each missing

data period, the average of the ‘‘hour

before’’ and ‘‘hour after’’ moisture

values.

(2) After 720 hours of quality assured

data have been obtained, provided that

the moisture data availability is ≥ 90.0

percent, substitute the average of the

‘‘hour before’’ and ‘‘hour after’’ values

for each hour of the missing data period.

(3) When the percent data availability

for moisture is below 90.0 percent,

substitute 0.0 percent moisture for each

hour of the missing data period.
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28043

These proposed missing data

procedures are considerably simpler

than the corresponding procedures for

SO2, NOX, CO2, and flow rate, in that

they do not include the concepts of

lookback periods, 90th, or 95th

percentile values. However, the

procedures are also somewhat less

representative than the missing data

procedures for SO2, NOX, CO2, and flow

rate, because the most conservative

possible value (0.0 percent moisture) is

substituted when the moisture monitor

data availability drops below 90.0

percent. The Agency solicits comment

on whether the simpler (but less

accurate) missing data procedures or the

more complex (but more representative)

procedures are more appropriate.

Finally, §§ 75.57(c) and 75.59(a)

(revised versions of §§ 75.54(c) and

75.56(a)) would be added in today’s

proposal to require that records be kept

of the following: (1) Component-system

identification code for the moisture

monitoring system; (2) hourly average

moisture readings (including, if

applicable, hourly averages from each

wet- and dry-basis O2 analyzer); (3)

percent data availability for the

moisture monitoring system; (4) daily

and 7-day calibrations of moisture

monitoring systems; (5) linearity tests of

each wet and dry oxygen analyzer used

to determine moisture; and (6) relative

accuracy tests of moisture monitoring

systems.

In summary, EPA is proposing quality

assurance (QA) procedures for moisture

monitoring systems because the Agency

believes that continuous, quality

assured, direct measurement of the stack

gas moisture content or continuous

measurement of surrogate parameters,

such as wet- and dry-basis oxygen

concentrations, is the best way to ensure

the accuracy of the reported emission

data when moisture corrections must be

applied. However, the Agency is willing

to consider and solicits comment on

simpler alternative methods of

accounting for the stack gas moisture

content, such as using a conservative

default moisture value. Any proposed

alternative methodology submitted to

the Agency for consideration would

have to provide a comparable level of

accuracy and would have to ensure that

emissions and heat input are not underreported.

E. Certification/Recertification

Procedural Changes

Background

Currently, § 75.20 lays out the process

for certifying monitoring systems.

Section 75.20(a) specifies the

requirements for initial certification,

including the contents of a certification

application, when the application must

be submitted and the process for

reviewing and acting on an application.

Sections 75.20(a)(3) and (4) of the

existing rule establish a certification

application review period of 120 days

(after receipt of a complete application)

for EPA to review an application and

issue an approval or disapproval. For a

continuous emission monitor (CEM),

initial certification includes the

following tests: relative accuracy, bias,

linearity (pollutant monitors only), 7-

day calibration error, cycle response

time (pollutant monitors only), missing

data, and formula verification. All of

these tests must be passed for a CEM to

be certified and produce valid quality

assured data. Once a CEMS is certified,

§ 75.20(b) specifies that if something

changes that significantly affects the

ability of the CEM to accurately measure

concentration or volumetric flow, the

affected monitoring system(s) must be

recertified. Recertification includes one

or more of the initial certification tests.

All required recertification tests must be

passed, and a recertification application

must be submitted in order for a CEM

to be recertified. Section 75.20(b)(5) of

the existing rule establishes a 60 day

review period for recertification

applications. Separate but similar

certification and recertification test

requirements apply for a monitoring

system other than a CEM, i.e., an

excepted monitoring system under

Appendix D or E, an alternative

monitoring system under subpart E, or

a system under proposed Appendix I.

Submittal requirements for

certification and recertification

applications are included in §§ 75.60

and 75.63 of the current part 75.

Generally, these provisions require

submittal of certification test results in

electronic formats, with some

information required to be submitted in

hardcopy format. Certification or

recertification test results also must be

submitted electronically in quarterly

reports under § 75.64. Finally, § 75.61

requires the designated representative to

provide advance notice to the applicable

state or local agency and EPA Regional

Office of certification and recertification

testing.

In many respects, monitoring plan

requirements are tied to the

certification/recertification process

because a modification to the

monitoring system that requires a

recertification application also usually

requires a monitoring plan update. In

addition, because it contains the

information about what type of

equipment is located where, the

monitoring plan is an essential tool in

the review of a certification or

recertification application. Section

75.53 specifies the content of

monitoring plans and when changes to

the plan are required. Section 75.62(a)

specifies the submission requirements

for monitoring plans.

Based on EPA’s initial experience

with part 75 implementation and the

numerous questions and problems

encountered in the review of

certification and recertification

applications and monitoring plans, the

Agency believes that the certification

and recertification provisions and the

related sections of the rule are possibly

neither sufficiently detailed nor clear.

Therefore, in today’s rulemaking, EPA is

proposing to revise those provisions and

sections in order to improve the

certification/recertification process. The

issues addressed in today’s proposed

rule include the following: (1) whether

a particular provision applies to initial

certification, recertification, or both; (2)

the scope of events that require

submittal of a recertification

application; (3) the review period

lengths for initial certification and

recertification applications; (4) the

criteria governing disapproval of an

incomplete certification or

recertification application; (5) the

format (electronic or hardcopy) in

which test notifications, certification

and recertification applications, and

monitoring plans are to be submitted;

(6) which EPA Regional Offices and

state and local agency offices must

receive test notifications, certification

and recertification applications, and

monitoring plans, and whether the

submittal and notice requirements can

be waived; and (7) when a monitoring

plan needs to be revised. The proposed

revisions on these topics and the

rationale for the changes are discussed

below.

The Agency notes that today’s

package of proposed revisions to part 75

includes other substantive revisions to

the certification and recertification

provisions in part 75. These are

discussed elsewhere in this preamble.

The provisions of most significance are

related to certain proposed QA/QC

revisions, back-up monitoring systems,

CEM data validation issues, and the new

Appendix I procedures. See sections

III.D, O, R and T of this preamble for

further discussion.

Discussion of Proposed Changes

The proposed revisions discussed in

this section affect § 75.20 generally, as

well as specific aspects of §§ 75.20(a)(4),

(b)(1), (b)(5), and (g)(6); 75.21(e)(1);

75.53(b); new § 75.53(e) and (f);

75.60(b); 75.61(a); 75.62(a); 75.63(a) and
28044 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

(b); 75.64(a), (b) and (d) and the addition

of § 75.59 as a revised version of § 75.56.

Proposed revisions to § 75.20 would

clarify which provisions apply to initial

certification, recertification, or both.

Proposed revisions to § 75.20(b)(1) and

(g)(6) would provide a narrow definition

of recertification events, thereby

significantly reducing the number of

monitoring system changes,

configuration changes or changes in the

manner of operation that would require

submission of a recertification

application. Proposed revisions to

§ 75.20(b)(5) would make the lengths of

the review periods the same for initial

certification and recertification

applications. Proposed revisions to

§ 75.20(a)(4) would clarify what

constitutes a complete certification or

recertification application and also

would more clearly define EPA’s

authority to disapprove an incomplete

application.

Proposed revisions to § 75.53(b)

would expand the universe of

monitoring system changes that require

monitoring plan revisions to include

any change that would make the

information in the current plan

inaccurate (currently, only changes that

require recertification require

monitoring plan changes). Sections

75.53(e) and (f), which are revised

versions of existing § 75.53(c) and (d),

would clarify which elements of a

monitoring plan must be submitted in

electronic format and which elements

must be submitted in hardcopy format.

Section 75.53(e) would revise existing

§ 75.53(c) so that after January 1, 2000

an owner or operator would have to

report the unit stack height in the

monitoring plan. Section 75.59 (a

revised version of § 75.56) would

specify the minimum required content

(as of January 1, 2000) for the hardcopy

portion of a certification or

recertification application. Section

75.60(b) would more clearly define the

general requirements for submittal of

reports and petitions. Section 75.61(a)

would allow for certification and

recertification test notices to be sent in

various alternative media and would

allow for EPA or a State or local agency

to waive test notices in some

circumstances. Section 75.62(a) would

be revised to clarify when monitoring

plans are to be submitted and to whom

elements of the monitoring plan must be

submitted. Similarly, § 75.63(a) would

be revised to detail which elements of

a certification or recertification

application are to be submitted

electronically, which elements are to be

submitted in hard copy, and to whom

the various elements would be

submitted. Section 75.63(b) would

clarify when and how failed tests are to

be reported in a certification or

recertification application. Finally,

§ 75.64(a) would specify that the

hardcopy monitoring plan is not to be

submitted with a quarterly report. The

rationale for these changes is discussed

below.

Rationale

1. Initial Certification Versus

Recertification

Several provisions in the current rule

refer either to certifications or to

certification applications; however, it is

not always clear whether these

provisions apply solely to initial

certifications or whether they also apply

to recertifications. Therefore, today’s

proposed revisions would make a

number of minor text edits throughout

§ 75.20 for clarification. There are,

however, some events that do not fit

neatly under the definition of initial

certification or recertification (e.g.,

construction of a new stack with a new

CEM at an existing unit when a scrubber

is installed). This element of

subjectivity in classifying an event as a

certification or recertification makes it

desirable for the certification and

recertification processes to be as similar

as possible. Having one general process

with one set of rules rather than having

two separate processes also makes

program implementation easier.

Currently, the main differences between

initial certifications and recertifications

are the types of tests required and the

lengths of the application review

periods. Today’s proposed rule

revisions would attempt to minimize

these differences to the extent possible

in order to bring greater uniformity and

consistency to the certification and

recertification process.

(a) Scope of Recertification Events.

The proposed revisions would narrow

the scope of the types of changes to a

monitoring system that would be

classified as ‘‘recertification events’’ and

would require submittal of a

recertification application. Sections

75.20(b)(1) and (g)(6) would define a

recertification event as any change that

requires the performance of an accuracy

test of a monitoring system, i.e., either

a relative accuracy test audit (RATA) of

a CEMS, an accuracy test of a fuel

flowmeter, or a retest to develop the

Appendix E NOX correlation curve. For

changes to a monitoring system or

process that do not require a system

accuracy test but require one or more of

the other (lesser) quality assurance tests

to be performed (e.g., linearity test or 7-

day calibration error test), those other

required tests would be classified as

diagnostic tests rather than as

recertification tests in § 75.20(b)(1) of

the proposal. For instance, a source

would be required to conduct a linearity

check after replacing a capillary tube in

a gas analyzer with a tube from a like

model and manufacturer (see Docket A–

97–35, Item II–I–9, Policy Manual,

Question 13.13). However, because this

change to the CEMS does not require a

RATA, it would not be considered a

recertification event. Therefore, no

recertification application would be

required, and the linearity test would be

considered a diagnostic test. Note that

even though diagnostic tests would not

be classified as recertifications, the

recertification data validation

procedures in proposed § 75.20(b)(3) of

today’s rule would apply to these tests.

EPA believes that the proposed

narrowing of the definition of a

recertification event will significantly

reduce the number of required

recertification applications and will

make the submittal requirements for

initial certifications and recertifications

more consistent.

(b) Recertification Review Period.

Consistent with the proposed narrowing

of the definition of a recertification

event, EPA also proposes to revise

§ 75.20(b)(5) by increasing the

recertification application review period

from 60 days to 120 days to make it the

same as the review period for initial

certifications. The advantage of making

the two review periods consistent is that

there would be no need to distinguish

which requirements are applicable to

which events. Some events combine

aspects of initial certification and of

recertification. For example, the

certification of a new CEMS on a new

stack at an existing unit when a

scrubber is installed can be thought of

as initial certification because it is an

entirely new system in a new location;

however, this event also involves

aspects of recertification because it is an

existing unit which has been reporting

emissions from certified systems.

Therefore, the Agency believes that

making the review periods the same

would reduce confusion and case-bycase determination of how long the

review period should be for a given

application. The Agency believes that it

would be more effective to establish

consistent procedural requirements for

both initial certification and

recertification events, rather than

attempting to classify each event as an

initial certification or recertification.

In making the review periods

consistent, EPA considered reducing the

length of the review period for initial

certifications. EPA considered both the
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28045

time it takes to complete a thorough

technical review of an application and

the time it takes to resolve issues raised

during that technical review. The

resolution of issues raised during a

review can take a significant amount of

time because it involves coordination

between the source submitting the

application, the applicable state and/or

local air agency, the applicable EPA

Regional Office, and the Acid Rain

Division at EPA headquarters.

Therefore, even though EPA would

anticipate receiving fewer recertification

applications under today’s proposed

revisions, EPA believes that a 120-day

review period is necessary for

recertifications (which, according to

today’s proposed definition of a

recertification event, would involve the

review of monitoring system accuracy

tests) in order to coordinate resolution

of issues raised during the technical

review of an application.

EPA recognizes that there are

concerns with increasing the

recertification review period to longer

than 60 days, as more hours of data

could be invalidated if an application

were disapproved. However, EPA

believes that the criteria for approval of

monitoring system certification tests are

clear and that when an application is

submitted, the owner/operator should

know whether or not the performance

specifications of part 75 have been met.

In EPA’s experience of four years of

implementation, disapprovals are rarely

issued; in fact, less than 2 percent of all

monitoring system applications

submitted between 1993 and September

1997 were disapproved (see Docket A–

97–35, Item II–A–4). In most cases

where applications have been

disapproved, the owner or operator

should have been aware of the

deficiencies before the application was

submitted. Additionally, EPA has found

that a longer review period has allowed

more time to resolve minor deficiencies

which could have served as grounds for

disapproval, but which, given sufficient

time, were often resolved without

issuing a notice of disapproval and

without invalidating any hourly

emissions data.

2. Disapproval of an Incomplete

Application

Section 75.20(a)(4) of the existing rule

requires EPA to issue a ‘‘notice of

approval or disapproval of the

certification application within 120

days of receipt of the complete

certification application.’’ This

provision implies that an application

must be complete in order to issue a

disapproval. In attempting to implement

this provision, EPA has encountered the

problem of incomplete applications.

The Agency has, in most of these

instances, issued a notice of

incompleteness to the source. However,

affected sources have not always

complied with the incomplete notices

and have sometimes failed to submit the

information requested to complete the

application in a timely manner.

Therefore, EPA proposes to clarify that

EPA may disapprove an incomplete

certification or recertification

application if the submittal deadline is

passed. Before a disapproval would be

issued for an incomplete application,

the designated representative would

receive a notice of insufficiency and be

given a reasonable period of time to

complete the application. If the

complete application was not received

by this extended deadline, EPA could

issue a notice of monitoring system

disapproval. The Agency believes that

this provision will result in faster

resolution of incomplete certification or

recertification applications, thereby

eliminating extended periods of

uncertainty about data validation status.

3. Submittal Requirements for

Certification and Recertification

Applications

The current rule requires the owner or

operator to submit certification and

recertification applications to the

Administrator (i.e., the Acid Rain

Division of EPA) and to the appropriate

EPA Regional Office and state or local

air agency. Hardcopy test results must

be submitted, as well as an updated

monitoring plan and electronic test

results. The electronic test results must

also be submitted to the Administrator

as part of the next quarterly report.

Sections 75.20(a)(4)(ii), 75.59, and

75.63 of today’s proposal would revise

and clarify the completeness, format,

and submittal requirements for

certification and recertification

applications. For a certification or

recertification application to be

considered complete, the appropriate

information specified in proposed

§ 75.63 would be sent to the

Administrator, to the EPA Regional

Office, and to the state and local air

agency. Under proposed § 75.63, the

Administrator would receive only a

hardcopy application form and would

not receive any hardcopy test results,

unless specifically requested. The

Administrator would, however, receive

certification and recertification test

results electronically in the quarterly

report. In most cases, the electronic test

results would be submitted in the

quarter in which the testing is

completed. However, there may be

occasional exceptions to this, for initial

certification testing and for

recertification testing, when a series of

tests spans two consecutive calendar

quarters.

The local and State agencies, as well

as the EPA Regional Office would

receive a hardcopy application form,

electronic test results, and hardcopy test

results. For recertification tests, today’s

proposal would allow the EPA Regional

Office or the state or local air agency to

waive the requirement for a hardcopy

recertification test report for their

respective offices. The EPA Regional

Office or the state or local agency could

also reinstate that requirement at a later

date. EPA Regional Offices and state and

local agencies have historically received

hardcopy certification and

recertification reports with varying

contents and formats. Section

75.59(a)(10) would specify the

minimum content for hardcopy

certification and recertification reports

for gas and stack flow CEMS. Section

75.63(a)(2)(iii) would limit the amount

of reporting for ‘‘non-recertification

events’’ that require diagnostic tests. For

a diagnostic test, the only reporting

requirement would be to submit the

applicable electronic test results in the

next quarterly report. For DAHS

verifications, no reporting would be

required; instead, records of the tests

would be maintained on-site in a

manner suitable for inspection.

This series of revisions is intended

both to clarify the elements of a

complete application, and to clarify how

and to whom the essential information

should be submitted. By not requiring

hardcopy test reports to be sent to the

Administrator and by allowing the EPA

Regional Office or state or local agencies

to waive hardcopy recertification test

reports, the Agency believes that

unnecessary hardcopy reporting to

offices that do not intend to review the

reports will be eliminated.

Finally, § 75.63(b) would clarify that

for failed certification or recertification

tests, only tests that affect data

validation would need to be reported.

For example, if the ordinary rules of

data validation, rather than the

retrospective validation procedures,

were applied and a test failure occurred

during the initial certification testing for

a new unit, only the passed test would

be reported if the test was subsequently

repeated and passed. However, if the

conditional data validation procedures

set forth in § 75.20(b)(3) of today’s

proposal had been utilized during that

same initial certification, the failed test

would have to be reported because it

would affect the data validation of

hourly emissions.
28046 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

4. Decertification Applicability

The proposed revisions to

§ 75.21(e)(1) would clarify that excepted

monitoring systems under Appendix D,

E, or I or an alternative monitoring

system under subpart E may be

decertified in accordance with

§ 75.21(e)(1). The proposed revisions

would also clarify that decertification

would apply to both an initial

certification and a recertification. EPA

believes that logic and consistency

dictate the need for these changes.

5. Recertification Test Notice

Section 75.61(a) would be revised to

reduce the burdens associated with

submitting notices of recertification

tests. The proposed revisions would

allow EPA or the state agency to waive

notification requirements for

recertification tests. Currently, a

designated representative must notify

EPA and the state agency prior to

commencing certification or

recertification testing so that EPA or a

state representative has an opportunity

to observe the testing. Allowing the

recertification notification requirement

to be waived and providing more media

options for notifications will help

conserve paper, reduce the reporting

burden, and provide more flexibility to

facilities when scheduling tests. In

addition, the Agency solicits comment

on whether § 75.61 should be revised to

state that the requirement for written

notification could be satisfied by mail,

facsimile, or e-mail, subject to approval

by the agency receiving the notification.

6. Monitoring Plans

In §§ 75.53(e) and (f), which are

revised versions of § 75.53(c) and (d),

and § 75.62, today’s proposal clarifies

completeness and formatting

requirements for monitoring plans. In

§ 75.53(e), the existing provisions would

be separated into two separate

paragraphs (e)(1) and (e)(2) to clarify

which parts of the monitoring plan must

be submitted in electronic format and

which elements must be submitted in

hardcopy format. In addition, a number

of minor changes would be made to

clarify the actual required content of the

plan. Similarly, in § 75.53(f), the same

type of revisions would be made to

clarify the electronic versus hardcopy

elements of monitoring plans for

specific situations (Appendix D, E, and

I units, units claiming an opacity

exemption, and units with add-on

emission controls). These proposed

revisions are generally consistent with

existing implementation of the

monitoring plan reporting requirements

and primarily would serve to clarify

possibly ambiguous elements of the

current rule. The revisions reflected in

§ 75.53(e) would add a requirement to

electronically report in the monitoring

plan the unit stack height above ground

level and the stack base elevation above

sea level. EPA understands that these

data are readily available to unit owners

and operators. EPA collects stack

heights for some units, e.g., for new or

modified sources subject to 40 CFR

§ 51.166. However, stack height data is

not currently collected for all of the

units affected under title IV of the Act.

Moreover, the stack height data that the

Agency has is inconsistent, i.e., some of

the data are for stack height above sea

level, some are for above ground level,

and some are undefined. Stack height

data is necessary to improve the

modeling of plume height and transport

of sulfates and nitrates as part of acidic

deposition and other atmospheric

modeling. EPA conducts atmospheric

modeling as part of the congressionallymandated program of air pollution

monitoring, analysis, modeling, and

inventory research under section 103 of

the Act. Such modeling is also used to

analyze the impact of the Act on the

public health, economy, and

environment, pursuant to section 312 of

the Act. (See also, e.g., Human Health

Benefits From Sulfate Reductions Under

Title IV of the 1990 Clean Air Act

Amendments at 3–6 through 3–11 (EPA,

1995)). EPA is also proposing to collect

the Energy Information Administration

(EIA) flue identification numbers

associated with each unit. While this

data is already reported to EIA, it is

difficult to correlate it with the unit and

stack level data reported to EPA. By

having sources specify for each unit and

stack the corresponding flue

identification number reported to EIA, it

will be easier to correlate the emissions

data reported to EPA to other data that

is reported to EIA and is used for

atmospheric modeling purposes, such as

stack exit temperature and velocity.

Section 75.62 would be revised to

clarify which parts of the monitoring

plan must be submitted to the EPA

Regional Office and state and local

agencies, and when such submittals are

required. The Administrator would

receive an electronic monitoring plan at

the following times: (1) no later than 45

days prior to the initial certification

application; (2) at the time of a

recertification application, if a change in

the hardcopy monitoring plan

information is associated with the

recertification event; and (3) in each

electronic quarterly report. The EPA

Regional Office and state and local

agency would receive the required

hardcopy monitoring plan 45 days prior

to an initial certification. Thereafter,

hardcopy monitoring plan information

(changed portions, only) would be

submitted as follows: (1) with a

recertification application, if a change in

the hardcopy monitoring plan

information is associated with the

recertification event; and (2) within 30

days of any other event with which a

hardcopy monitoring plan change is

associated. Finally, today’s proposed

rule would require a complete

monitoring plan to be kept on-site in a

form suitable for inspection (this could

include an electronic portion which

could be printed out for inspection).

These revisions are intended to clarify

the monitoring plan format and

submission requirements, but are

generally consistent with existing

practices.

Today’s proposal would also clarify

when revisions must be made to the

monitoring plan. Currently, only

changes that require recertification

require monitoring plan revisions. The

EPA recognizes, however, that many

changes affecting the information in a

monitoring plan would not require

recertification. Therefore, § 75.53(b)

would be revised to require that the

owner or operator update a monitoring

plan whenever information in the

monitoring plan changes (e.g., a change

to a serial number for a component of

a monitoring system), and § 75.62 would

require submission of the revised

monitoring plan in the next quarterly

report or, for hardcopy portions, within

30 days of the change. This revision

would assure that the monitoring plan

does not contain outdated, erroneous

information.

Section 75.64(a) would clarify that no

hardcopy monitoring plan is to be

submitted with a quarterly report.

7. Submittal Requirements for Petitions

and Other Correspondence

Section 75.60(b)(5) would clarify what

hardcopy information is sent to the

Administrator for petitions and other

communications. These revisions would

clarify the existing rule, but would not

represent a significant change in the

requirements for these types of

submittals.

F. Substitute Data

1. Missing Data Procedures for CO2 and

Heat Input

Background

In the May 17, 1995 rule, two new

sections, §§ 75.35 and 75.36, were

added to part 75. These two new

sections provided, respectively, missing

data procedures for CO2 and heat input,
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28047

which were not provided in the original

January 11, 1993 rule. Section 75.35

specifies that for CO2, the initial missing

data procedures of § 75.31 are to be

followed for the first 720 quality assured

monitor operating hours following

initial certification. Thereafter, provided

that the CO2 data availability (as of the

last hour of the previous quarter) is

maintained above 90.0 percent and

provided that the length of any CO2

missing data period does not exceed 72

consecutive hours, a simple average of

the ‘‘hour before’’ and ‘‘hour after’’ CO2

concentrations is used to fill in missing

data periods. However, if the monitor

availability as of the last hour in the

previous quarter is below 90.0 percent

or if a CO2 missing data period exceeds

72 consecutive hours in length

(regardless of the percent monitor

availability), then the fuel sampling

procedures of Appendix G must be used

to provide substitute CO2 data.

Section 75.36 has a parallel structure

to § 75.35. For units that determine unit

heat input by using a flow monitor and

a diluent (CO2 or O2) monitor, the initial

missing data procedures of § 75.31 are to

be followed for the first 720 quality

assured monitor operating hours (for the

diluent monitor) and for the first 2,160

quality assured monitor operating hours

(for the flow monitor), following initial

certification. Thereafter, the standard

missing data procedures of § 75.33 are to

be followed for the flow monitor. For

the diluent monitor, the on-going

missing data provisions of § 75.36 are

nearly identical to those for CO2 in

§ 75.35 (i.e., use an ‘‘hour before hour

after’’ missing data algorithm, provided

that the monitor availability is ≥ 90.0

percent and the missing data period

length is ≤ 72 hours). However, when

the diluent monitor availability is < 90.0

percent or when the diluent missing

data period exceeds 72 hours, § 75.36

specifies that the owner or operator

must use the procedures in section 5.5

of Appendix F to determine the hourly

heat input.

Utility representatives have asked

EPA to consider revising the missing

data procedures for CO2 and heat input

(see, e.g., Docket A–97–35, Items II–D–

20, II–D–30, II–E–13, and II–E–14). The

utilities object to several elements of the

current procedures. They suggest that

the Appendix G procedures are

burdensome and that the missing data

procedures are considerably different

from the standard missing data

procedures for SO2, NOX, and flow rate,

which are based solely on historical

data and monitor availability and

require no additional procedures such

as fuel sampling.

Discussion of Proposed Changes

EPA has reconsidered the provisions

of §§ 75.35 and 75.36 in light of the

concerns raised by the regulated

community, and is proposing revisions

to the diluent gas missing data

procedures for CO2 and for heat input

determinations. The Agency proposes

that the same missing data routines

prescribed in § 75.33(b) for SO2

pollutant concentration monitors also be

applied to the CO2 and O2 data streams

that are used to determine CO2

emissions and heat input. The diluent

gas substitute data values would

therefore be determined in a purely

mathematical way, based on historical

data and the percent monitor data

availability; no fuel sampling

procedures would be required.

Note that these proposed revisions

would require the percent monitor data

availability to be known on an hourly

basis. This would require the percent

availability for CO2 and O2 monitors to

be updated hourly within the data

acquisition system. EPA realizes that

this would involve software

modifications, and in cases where the

unit heat input is determined using a

flow monitor and an O2 diluent monitor

in accordance with Equation F–17 or F–

18, some new recordkeeping provisions

would also be required. The necessary

recordkeeping provisions have been

proposed in § 75.57(g). To allow time for

software revisions to be made, the

revised missing data procedures in

§§ 75.35 and 75.36 would not take effect

until January 1, 2000. The owner or

operator could, however, opt to use the

new procedures prior to January 1,

2000.

EPA believes that today’s proposed

revisions to the missing data procedures

for CO2 and heat input determinations

would be relatively easy to implement

because the missing data routines for

SO2 monitors are well-established and

are familiar to both the regulated

community and to software vendors.

The Agency believes that the proposed

revised missing data procedures would

ensure that data availability remains

high and would, over time, reduce the

cost of compliance with the

requirements of part 75.

2. Prohibition Against Low Monitor

Data Availability

Background

Under the current rule, when a unit

uses SO2, flow rate, and NOX

monitoring systems to account for its

emissions, for each clock hour in which

a CEMS fails to provide quality assured

data, a substitute data value must be

reported to EPA in accordance with the

standard missing data procedures of

§ 75.33. The method required for

determining the appropriate substitute

data values under § 75.33 depends on

several factors, such as the overall

monitor data availability and the length

of the missing data period. For monitor

data availabilities ≥ 90.0 percent, the

substitute data value (which is reported

for each clock hour of the missing data

period) will normally be the arithmetic

average of the readings from the hour

before and the hour after the missing

data period. At other times, it will be

the 90th (or 95th) percentile value from

a lookback period of 720 (for SO2) or

2,160 (for NOX and flow rate) quality

assured monitor operating hours. When

the data availability drops below 90.0

percent, the substitute data value for

SO2 will be the maximum concentration

recorded in the last 720 quality assured

monitor operating hours, and for flow

rate and NOX, the substitute data value

will be the maximum flow rate or NOX

emission rate recorded in the last 2,160

quality assured monitor operating hours

at the corresponding load range.

Based on four years of program

implementation, EPA believes that the

standard missing data procedures need

to be strengthened. As presently written,

the missing data algorithms lack a

safeguard which will ensure that high

monitor data availability continues to be

maintained in future years. In the

current version of § 75.33, no distinction

is made between data availabilities of

89.0 percent, 50.0 percent or 10.0

percent. For all three of these data

availability percentages, the substitute

data value is the same (i.e., the

maximum value in a lookback period of

720 or 2,160 quality-assured monitor

operating hours). This has potentially

serious consequences. For example, if

the substitute data value from the

lookback period is non-punitive or

perhaps is even favorable to the facility

(e.g., if a low-sulfur fuel was burned

during the lookback period), there

would be little incentive to repair a

malfunctioning CEMS in a timely

manner and emissions could possibly be

under-reported for a long period of time.

Currently, part 75 does not specifically

address this ‘‘gaming activity.’’

Discussion of Proposed Changes

In order to maintain the credibility of

the SO2 allowance accounting system

and to ensure that affected units

continue to comply with their part 76

NOX emission limits, monitor data

availability must not be allowed to

deteriorate indefinitely without clear

and significant consequence to the

facility. Therefore, in today’s

rulemaking, EPA is proposing to add a
28048 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

safeguard to part 75 to ensure that this

does not happen. A new paragraph

75.33(d) would be added, which would

make it a violation of the primary

measurement requirement of § 75.10(a)

to allow the annual monitor data

availability to drop below 80.0 percent

for SO2, NOX, flow rate, or CO2. Based

on an analysis conducted on data

availability information for the third

quarter of 1996, EPA believes that

affected facilities will easily be able to

comply with the 80.0 percent data

availability criterion (see analyses in

Docket A–97–35, Item II–B–16). The

results of that analysis indicated a mean

percent monitor data availability of 96.9

percent for SO2, 95.0 percent for NOX,

and 96.6 percent for flow rate. Although

there were 13 (out of 995 total) SO2

monitors, 21 (out of 997 total) flow

monitors, and 46 (out of 1365 total) NOX

monitoring systems with percent

monitor availabilities below 80.0

percent in the 4th quarter of 1996, the

Agency expects that many of these

systems would be exempt from the

prohibition based on a limited number

of operating hours in the previous year

(see Docket A–97–35, Item II–A–8).

The proposed prohibition would not

apply to units that have only a limited

number of operating hours (less than

3000 hours of operation in the previous

12 calendar quarters) because such units

can have a low data availability

percentage without necessarily having

extended monitor downtime incidents.

In addition, no violation would occur if

the low monitor availability is caused

by a sudden and reasonably

unforeseeable event beyond the control

of the owner or operator (such as

destruction of monitoring equipment by

fire or flood). The owner or operator

would, however, be required to notify

the Administrator, in writing, within 7

days of the occurrence of such

catastrophic events and also to provide

notification to the EPA Regional Office

and to the appropriate State agency. The

owner or operator would be further

required to submit a corrective action

plan, including an implementation

schedule. Thus, this proposed

prohibition should not result in

violations of part 75, except for

situations involving poor operation and

maintenance practices, which are

clearly not beyond the control of the

owner or operator.

Another option considered by the

Agency was to modify the standard

missing data algorithms for SO2, NOX,

and flow rate as follows. Under this

option, the algorithms for monitor data

availabilities of 90.0 percent to 100.0

percent would remain unchanged. The

algorithms currently used for all

monitor data availabilities below 90.0

percent would be retained, but these

would apply only to data availabilities

between 80.0 percent and 89.9 percent.

Finally, a new algorithm would be

added for monitor data availabilities

below 80.0 percent. When the data

availability drops below 80.0 percent,

the appropriate maximum substitute

data value would have to be used (i.e.,

the maximum potential concentration

for SO2 or CO2, the maximum NOX

emission rate, or the maximum potential

flow rate). EPA believes that requiring

maximum values to be reported when

the data availability drops below 80.0

percent would provide incentive to the

affected sources to keep their monitors

well-maintained. Because any changes

to the standard missing data algorithms

would require software modifications,

this option, if adopted, would not take

effect until January 1, 2000. The Agency

has not proposed this option because it

would require software changes for all

affected units even though very few

units have data availabilities that fall

below 80.0 percent. The Agency seeks

comment, however, on whether this

option should be used instead of the

proposed prohibition given that it is

more consistent with the structure of the

missing data requirements in part 75

and would be self-implementing

without any need to initiate

enforcement actions to achieve the

desired result of continued high data

availabilities that assure accurate

reporting of emissions.

The Agency also emphasizes that the

required data availability for the Acid

Rain Program would remain at 100.0

percent even if the proposed prohibition

is adopted, meaning that substitute data

would have to be supplied for any

periods in which data from a certified

monitoring system are not available.

This approach is in sharp contrast to

most other CEMS programs that do not

rely on substitute data. In those

programs, the Agency, as well as State

and local agencies, expect and often

require much higher data availabilities

than 80.0 percent. Based on the number

of units with data availability higher

than 95.0 percent under the Acid Rain

Program, CEMS data availability less

than 95.0 percent may well indicate a

failure to properly operate and maintain

a CEMS. Many agencies rely on that

95.0 percent availability level to target

systems for inspection and other

compliance-related follow-up actions. In

addition, agencies have adopted various

required minimum data availabilities for

CEMS that far exceed the 80.0 percent

level selected for the prohibition

proposed in today’s rulemaking.

It is also important to note that

monitor availability under part 75 and

monitor downtime under other

programs are not always the same.

Under part 75, a source may have actual

monitoring data that are suspect, based

on an evaluation of various quality

assurance activities. In this situation,

the owner or operator may, as a

conservative measure, report substitute

data rather than the actual data. In

contrast, this type of missing data

substitution does not occur under most

other programs. In most programs, the

suspect data would simply be

invalidated and no emission data would

be reported for those hours.

Therefore, because of the structure of

the missing data provisions in the Acid

Rain Program and the generally

applicable economic incentive to

achieve high data availabilities under

part 75, it would be improper to equate

the proposed prohibition in today’s

rulemaking with a required minimum

data availability requirement

established for other programs that do

not have the same features. The Agency

does not intend that this proposed

provision should serve as a precedent

for evaluating the appropriate

achievable data availability for other

programs. Consistent with current

practices, the Agency would continue to

expect CEMS to achieve high data

availability and that, generally, monitor

downtime in excess of 5.0 percent may

warrant appropriate investigation and

follow-up activities.

G. General Authority to Grant Petitions

Under Part 75

Background

Section 75.66(a) provides generally

that a designated representative of a unit

subject to part 75 may submit a petition

to the Administrator. Sections 75.66(b)

through (h) address petitions to the

Administrator on the specified topics of

alternative flow monitoring methods,

alternatives to standards incorporated

by reference, alternative monitoring

systems, parametric monitoring

procedures, missing data for units with

add-on emission controls, emission or

heat input apportionments, and the

partial recertification process. Each of

these subsections set forth the items

which must be included with a

particular type of petition. In addition,

§ 75.66(i) states that, for any other

petition to the Administrator under part

75, the designated representative for an

affected unit shall include sufficient

information for the evaluation of such

petition.
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28049

Discussion of Proposed Changes

Today’s proposal would revise

§ 75.66(a) to state clearly that the

designated representative of an affected

unit may petition the Administrator for

authorization to apply an alternative to

any requirement under part 75 or

incorporated by reference in part 75,

regardless of whether another section of

part 75 explicitly allows such a petition

concerning the particular requirement.

EPA views this change as a clarification

to the general authority already

provided by §§ 75.66(a) and (i). The

proposed rule would also be amended

to include new paragraphs (i) through

(l), which would set forth the specific

requirements for other petitions that are

explicitly allowed by other sections of

the rule but which are not currently

included in this section. In addition, the

proposed rule, at § 75.66(m), would also

indicate the appropriate documentation

to be submitted for petitions under

subsection (a), except those under

subsections (b) through (l), where the

required documentation is already

specified. The required documentation

in subsection (m) would be: (1)

Identification of the unit; (2)

information explaining why the

proposed alternative should be used

instead of the existing part 75 provision;

(3) descriptions and, if applicable,

diagrams of the equipment and

procedures to be used in the proposed

alternative; and (4) information

demonstrating that the proposed

alternative is consistent with the

purposes of the provision for which an

alternative is requested and is consistent

with the purposes of part 75 and of

section 412 of the Act.

Rationale

As presently codified, EPA is

concerned that the rule does not state

clearly what types of petitions may be

submitted under § 75.66. In particular,

existing subsection (i) could be

interpreted as referring only to petitions

that are mentioned in other sections of

part 75 and that are not specifically

listed in § 75.66(b) through (h). EPA has

not interpreted § 75.66(i) in this manner.

In administering the Act, EPA has

inherent discretion to grant de minimis

exceptions from statutory or regulatory

requirements, where EPA determines

that holding the regulated entity to the

applicable requirement would yield a

gain of trivial or no benefit, provided

Congress has not unambiguously

demonstrated its intent to foreclose such

exceptions. See, e.g., Public Citizen v.

Young, 831 F.2d 1108, 113 (D.C. Cir.

1987); Alabama Power Co. v. Costle, 636

F.2d 323, 360–61 (D.C. Cir. 1979). Since

the issuance of part 75 in 1993, EPA has

accepted, and, in some cases exercised

its discretion and granted, petitions

under § 75.66 that requested exceptions

and that were not specifically

referenced in § 75.66(b) through (h) or

elsewhere in part 75 (see Docket A–97–

35, Item II–B–17). Such petitions have

included, for example, a request to set

a CO2 span lower than that required by

part 75 in order to more accurately

quality assure the CO2 monitor. Another

petition requested an alternative to the

requirement to perform an annual

RATA on a unit that was scheduled to

shutdown, prior to the deadline for

performing the RATA, in order to install

a scrubber, construct a new stack, and

install and certify new CEMS. A petition

was also submitted for permission to

use a propane sampling frequency as

specified in the State operating permit

and to then calculate SO2 emissions by

using the highest sulfur content

recorded during the previous 365 days

and report these data in quarterly

reports. These petitions were submitted

for the purpose of requesting

alternatives to various requirements of

part 75, even though the ability to

petition the Agency on these issues was

not referenced explicitly in other

sections of part 75 or in § 75.66(b)

through (h). In most cases, the

circumstances leading to the request for

an alternative to a part 75 requirement

were not anticipated during the drafting

of part 75 regulations. In fact, today’s

proposal revises several part 75

requirements to allow for alternatives

that were originally requested and

approved through the petition process

set forth in § 75.66. The Agency

continues to believe that the general

provision allowing petitions for

alternatives to part 75 requirements is

necessary to enable EPA to address

circumstances that were not foreseen

during the development of such

requirements. This is important since

circumstances can sometimes vary

significantly from boiler to boiler. While

the response to comment document for

the January 11, 1993 rule (see Docket A–

91–69, Item V–C–1, Issue # M–8.8.2)

might be read to bar petitions for

exceptions from any provision of part

75, EPA maintains that such a reading

would be inconsistent with the

regulatory language of §§ 75.66(a) and (i)

that allow such petitions, and with the

established practice of the Agency in

administering part 75.

The existing § 75.66(i) states that for

petitions other than § 75.66(b) through

(h) petitions submitted under the

section, the designated representative

should include sufficient information

for the evaluation of the petition. No

other information is provided

concerning the contents of such

petitions. As §§ 75.66(b) through (h) all

provide a list of the type of information

that should be included in petitions

submitted under the respective sections,

the Agency believes that, in addition to

amending § 75.66(a) to clarify that

petitions may be submitted for

circumstances that may not be covered

by other sections authorizing petitions

to the Administrator, it is appropriate to

provide units with a list of the type of

information that should be included

with the petition. Similarly, EPA

believes that it is appropriate to add to

the section provisions setting forth the

information requirements for those

petitions that are explicitly allowed

under other sections of part 75 but that

are not listed in the existing § 75.66. All

these revisions would make the petition

process more uniform and minimize

confusion regarding what information

EPA would require in order to accept

and consider any petition for an

alternative to a part 75 requirement.

H. NOX Mass Monitoring Provisions for

Adoption by NOX Mass Reduction

Programs

Background

Part 75 contains requirements for

monitoring NOX emissions with a

continuous emission monitoring system

or other approved method. Owners and

operators are required to calculate

hourly, quarterly average, and annual

average NOX emission rates (in lb/

mmBtu). Part 75, however, currently

contains no requirements for reporting

NOX mass emissions (in tons). Other

NOX emission reduction programs being

developed pursuant to title I of the Act

(such as the NOX Budget Program in the

Ozone Transport Region) are expected

to require reporting of NOX mass

emissions from many of the units

affected under the Acid Rain Program.

To streamline reporting burdens under

multiple programs and to allow for the

administration of multi-state NOX mass

trading programs, the Agency believes it

appropriate to amend part 75 to include

provisions for monitoring, recording,

and reporting NOX mass emissions that

could apply to such trading programs.

These provisions would provide

standard procedures—resulting in

precise, reliable, accessible, and timely

emissions data—that could be adopted

under a state or federal NOX mass

emission reduction program. To the

extent that these standard provisions are

adopted, the burden on industry would

be reduced and the administration of

the programs would be facilitated, in
28050 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

that the Agency or implementing states

would not need to develop NOX mass

monitoring provisions anew and

industry would not need to become

familiar with multiple approaches to

NOX mass monitoring.

Discussion of Proposed Changes

The proposed NOX mass emissions

provisions would apply only where

EPA, states, or groups of states

incorporate them and mandate their use

through a separate regulatory action.

The proposed amendments would make

changes to §§ 75.1, 75.2, 75.4, 75.16,

75.17, Appendix D, section 2.1.2.2, and

Appendix F, section 5.5. They would

also add a new subpart H containing

new §§ 75.70, through 75.73 and a new

section 8 in Appendix F containing

sections 8.1, 8.1.1, 8.1.2, 8.1.3, 8.1.4,

8.2, 8.3, 8.3.1, and 8.3.2.

Section 75.1, the purpose and scope

section, would be amended to broaden

the scope by adding that part 75 will

also set forth provisions for monitoring

and reporting NOX mass emissions that

EPA, states, or groups of states may

require sources to use to demonstrate

compliance with a NOX mass emission

reduction program. Section 75.2 would

be amended to add that the provisions

of part 75 may also apply to sources

subject to a state or federal NOX mass

emission reduction program.

The compliance date section,

§ 75.4(a), would be altered to state that

the provisions relating to monitoring

and reporting of NOX mass emissions

become applicable on the deadlines

specified in the applicable state or

federal NOX mass emission reduction

program requiring the use of part 75 to

monitor and report NOX mass

emissions.

Section 75.16 would be amended to

state that title IV affected units using the

provisions of part 75 to monitor and

report NOX mass emissions under a

state or federal NOX mass emission

reduction program would have to meet

the heat input monitoring and

determination requirements in both

§ 75.16 and in subpart H, §§ 75.71 and

75.72. Section 75.17 would be amended

to state that title IV affected units using

the provisions of part 75 to monitor and

report NOX mass emissions under such

a program would have to meet the NOX

emission monitoring and determination

requirements in both § 75.17 and

subpart H, §§ 75.71 and 75.72.

The applicable procedures for the

monitoring and determination of NOX

mass emissions would be added in

proposed subpart H, §§ 75.70, 75.71,

and 75.72 and corresponding

recordkeeping and reporting

requirements would be set forth in

§ 75.73.

Section 75.70 would set forth the

general requirements including:

definitions, compliance dates,

incorporation by reference, initial

certification and recertification

procedures, quality assurance and

quality control requirements, substitute

data requirements, and requirements

regarding petitions. In general these

provisions for monitoring NOX mass

would mirror the provisions for

monitoring of SO2, NOX, and CO2 for

compliance with title IV. However,

because the program would be a state

program, rather than a federal program,

there would be some differences in the

administrative requirements. These

differences would be most pronounced

for units that were not subject to Acid

Rain emission limitations and were not

already subject to the provisions of part

75. The major differences in

administrative requirements would

involve the process for petitioning

under § 75.66 and the process for

certifying and recertifying monitors.

Under the existing Acid Rain Program,

the Administrator must approve all

petitions under § 75.66. Under this

proposal, petitions for units that were

only subject to the provisions of part 75

because they were subject to a state or

federal NOX mass emission reduction

program, would have to be approved by

both the permitting authority for the

applicable NOX mass program and the

Administrator. The permitting authority

would also be responsible for reviewing

and approving or disapproving

certification and recertification

applications for such units.

Section 75.71 sets forth the general

monitoring methodologies that would

be allowed for different types of units.

The proposal would require units to

determine hourly NOX mass emissions

(in lb) by monitoring NOX emission rate

(in lbs/mmBtu) and heat input (in

mmBtu/hr) on an hourly basis and by

multiplying those two values and the

hourly unit operating time (in hour or

fraction of an hour) together. Coal units

and other units that burn solid fuel and

that are covered by subpart H would be

required to measure NOX emission rate

using a NOX emission rate CEM

consisting of a NOX concentration CEM

and a diluent CEM (CO2 or O2 CEM) and

to measure heat input using a diluent

CEM and a continuous volumetric flow

monitor. All gas- and oil-fired units

covered by subpart H would be allowed

to use that approach or, alternatively,

could measure NOX emission rate using

a NOX emission rate CEM and heat

input by using a fuel flowmeter and

performing fuel sampling and analysis.

This alternative for determining heat

input from gas- and oil-fired units is set

forth in Appendix D of part 75. Gas and

oil units that qualify as either peaking

units or low mass emission units under

part 75 would also have additional

lower cost monitoring methodologies

available to them. Peaking units, for

example, would have the option to do

source testing to create heat input

versus NOX emission rate correlation

curves. Then, based on hourly

measurement of heat input from a fuel

flowmeter and fuel sampling and

analysis using the provisions in

Appendix D to part 75, the heat input

vs NOX emission rate correlation curves

would be used to estimate the hourly

NOX emission rate. This rate would be

used in conjunction with hourly

measured heat input to determine NOX

mass. A unit that qualifies as a low mass

emission unit would have the option to

use a fuel-type and boiler-type specific

default NOX emission rate and the unit’s

maximum rated hourly heat input to

determine NOX mass emissions. The

low mass emissions unit provisions are

in proposed § 75.19.

Section 75.72 sets forth the specific

requirements for monitoring emissions

at units that share common stacks and/

or common pipes, for units that emit to

multiple stacks and for units that

receive fuel from multiple pipes. These

provisions mirror similar provisions in

§ 75.16 for monitoring SO2 mass

emissions from similar units and groups

of units.

Appendix D, section 2.1.2.2 would

indicate that the heat input

apportionment procedures of that

section would not be applicable for

units whose compliance with this part

is required under a NOX mass emissions

reduction program. Instead, the unit

would have to meet the heat input

monitoring and determination

requirements in subpart H, §§ 75.71 and

75.72.

The applicable procedures for

calculating NOX mass emissions would

be added in proposed section 8 of

Appendix F. Section 8.1 of Appendix F

contains proposed equations for

determining hourly NOX mass

emissions, section 8.2 contains

proposed equations for determining

quarterly, cumulative annual and ozone

season NOX mass emissions, and section

8.3 contains specific provisions for

monitoring NOX emissions from a

common stack. Additionally, revisions

to section 5.5 of Appendix F would

indicate that the heat input calculation

procedures of section 5.5.3 would not be

applicable for units whose compliance

with this part is required under a NOX

mass emissions reduction program.
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28051

Rationale

(a) Authority to Propose NOX Mass

Provisions. The authority for the

proposed NOX mass provisions rests in

two separate portions of the Act. First,

section 412(a) states that the owner or

operator of an affected source under title

IV must monitor and quality assure data

for sulfur dioxide and nitrogen oxide for

each affected unit at the source. 42

U.S.C. 7651k(a). This section does not

limit the nitrogen oxide data

requirement to emission rate data in lb/

mmBtu or to data necessary for

compliance with emission limits

established under title IV. Indeed, oiland gas-fired units have been required

to report NOX emission rate data under

part 75 even though only existing coal

units are subject to NOX emission limits

under title IV. (See 58 FR 3590, 3644,

January 11, 1993). Thus, the Agency

believes that providing for reporting

NOX mass emissions under part 75 is an

appropriate exercise of the authority

under section 412, particularly since

NOX mass emissions reporting may be

required under a separate applicable

requirement.

Second, independently of the

authority granted by section 412, section

114(a) of the Act gives the

Administrator broad authority to collect

data for ‘‘the purpose of developing or

assisting in the development of any

implementation plan under section 110

or 111(d)’’, ‘‘of determining whether any

person is in violation of any such

standard or a requirement of such a

plan’’, or ‘‘carrying out any other

provision of [the] Act’’ (except certain

provisions of title II concerning mobile

sources). Section 114 is, of course, not

limited to sources that are affected units

under title IV. Moreover, section

301(a)(1) authorizes the Administrator

‘‘to prescribe such regulations as are

necessary to carry out his functions’’

under the Act, including the functions

specified in section 114. Thus, EPA

maintains that the Agency is authorized

to adopt provisions in part 75 that could

govern monitoring of NOX mass

emissions, especially where such

information is expected to support

States’ efforts to attain ambient air

quality standards.

From a policy perspective, now is the

appropriate and most efficient time to

adopt these changes. In July 1997, EPA

Administrator Carol Browner

announced a series of initiatives to

reform environmental data management

and collection (see Docket A–97–35,

Item II–I–21). The new initiatives are

intended to streamline reporting

requirements and increase coordination

across different programs that affect the

same sources. There are a number of

examples of ongoing efforts to

streamline the reporting of emissions for

utility units. One example is a proposal

to revise the NSPS NOX standards for

utility and industrial boilers subject to

reporting under 40 CFR part 60. That

proposal would allow facilities to

submit NSPS reports through part 75

reporting (see 62 FR 36948, July 9,

1997). Another example is the Ozone

Transport Commission’s NOX Budget

program. That program is expected to

require utility sources and certain

industrial sources in the northeast to

reduce emissions of NOX through a

trading program similar to the Acid Rain

SO2 trading program. On January 31,

1996, the OTC released the Model Rule

which outlines procedures for the

monitoring and reporting of NOX mass

emissions; these procedures are based

on the monitoring and reporting

requirements set forth in part 75 (see

Docket A–97–35, Items II–I–7 and II–I–

22). Today’s proposal would facilitate

the coordination of reporting under the

Acid Rain Program and NOX mass

programs like the OTC NOX Budget

Program.

In addition, the Agency believes it is

appropriate to include these

requirements in the current proposal

because the Acid Rain affected units

may be undertaking DAHS software

changes to respond to the other

proposed revisions to part 75 if they are

adopted. The Agency would enable

facilities to coordinate the necessary

software changes by proposing the

revised reporting requirements to allow

for NOX mass emission reporting at this

time along with the other part 75

revisions. Although EPA is proposing

this requirement now to facilitate

software changes, the requirement to

actually record and report NOX mass

emission data under part 75 generally

would not become effective for any unit

unless and until a program requiring

such recording and reporting is

implemented for that particular unit

(EPA notes that, as discussed elsewhere

in Section III.C.4. of this preamble, a

limited group of title IV affected units

(i.e., low mass emissions units) would

be required to record and report NOX

mass emissions for purposes of the Acid

Rain Program.) In addition, if a state

elected to require the use of these

requirements to support a state NOX

mass emission monitoring and reporting

requirement, these requirements would

not become federally enforceable until

those requirements were approved by

EPA as part of the SIP.

(b) Monitoring Methodology. The

proposed requirement would require

sources to determine NOX mass as a

function of hourly average NOX

emission rates, heat input rates, and

unit operating time. EPA is proposing

this approach because it accurately

accounts for NOX mass emissions

without requiring any changes to the

current missing data routines and

quality assurance requirements in part

75. An alternative to this approach, not

included in today’s proposal, would be

to measure total mass emissions using a

NOX pollutant concentration monitor, a

volumetric flow monitor and unit

operating time, analogous to the

approach taken currently for SO2

emissions. This methodology would

have two advantages: first, there would

be less missing data from a NOX

pollutant concentration monitor than

from a NOX CEMS which (under the

existing and proposed rule) contains

both a NOX pollutant concentration

monitor and a diluent monitor; and

second, it would avoid possible

overestimation from a bias adjustment

factor applied to the NOX system to

correct bias in the diluent monitor (see

Docket A–97–35, Item II–D–96).

However, this methodology would

also have a number of disadvantages. In

order to monitor NOX as total mass

emissions using a NOX pollutant

concentration monitor and a volumetric

flow monitor, several major changes

would need to be made to part 75. The

entire concept of a NOX CEMS—and the

quality assurance tests and missing data

procedures associated with the NOX

CEMS—might need to be revised, to

include either a NOX CEMS with only

a NOX pollutant concentration monitor

and a DAHS (in which case, a separate

flow monitoring system would also be

required in order to determine NOX

mass), or a NOX CEMS with a NOX

pollutant concentration monitor, a

volumetric flow monitor, and a DAHS.

Since the relative accuracy standard

currently in part 75 for NOX systems is

in lb/mmBtu, it would be necessary to

establish a new relative accuracy

standard for NOX concentration in ppm

if the NOX/flow method described above

were incorporated into the final rule.

Bias adjustment would also have to

occur on the newly defined NOX CEMS.

It would also be necessary to create a

missing data procedure either for NOX

concentration in ppm or for hourly NOX

mass emission rate in lb/hr. Hourly NOX

mass emission rate would be calculated

using the same formula as for SO2 mass

emission rate (Equation F–1 or F–2),

only using a constant of 1.194 x

10¥7(lb/scf)/ppm NOX. In addition, this

methodology would not easily support

the monitoring and reporting of NOX

emission rate data in lb/mmBtu.
28052 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

Therefore, in order to meet the emission

rate reporting requirements, affected

sources under title IV would still be

required to maintain a diluent CEMS

and the current NOX emission rate

missing data procedures. The Agency

has not proposed this approach because

it does not believe that the benefits of

slightly reduced amounts of missing

data for NOX mass and removal of the

bias adjustment factor for the diluent

monitor justify the complication of

having two separate procedures for

monitoring NOX emissions from a given

unit. Nevertheless, the Agency requests

comment on whether this approach to

measuring mass emissions should be

used in lieu of the proposed heat input

and emission rate approach for sources

required to report NOX mass.

(c) Common Stack and Pipe

Monitoring. The Agency notes that the

proposed procedures for monitoring

NOX emission rate at a common stack to

determine NOX mass emissions under

the proposed § 75.72 procedures are

different than the procedures currently

allowed for monitoring NOX emission

rate in § 75.17. The Agency is concerned

that the § 75.17 provisions would be too

imprecise for measuring NOX mass

emissions because the two values used

to determine NOX mass emissions (NOX

emission rate and heat input) are not

required to be measured at the same

location. In the existing rule, NOX

emission rate may be monitored at the

unit level in the duct leading to the

common stack and heat input can be

determined from measurements at the

common stack and then apportioned to

the individual units using unit load.

While this heat input apportionment

method has been allowed for Acid Rain

purposes, it is not accurate in all cases

because it does not account for different

heat rates from the units exhausting to

the common stack and does not account

for differences in operating time at the

units. It has been allowed by the Agency

for Acid Rain purposes because

apportioned heat input determined

under § 75.16 (e) had only a limited

effect on emissions trading (i.e., on the

SO2 allowance program). Although

apportioned heat input determined

under § 75.16(e) is used to determine

compliance with the reduced utilization

provisions of the Acid Rain Program,

the apportioned heat input estimate was

deemed accurate enough for that

purpose and for the relatively small

number of units and short period

involved. Determinations of reduced

utilization are required only for Phase I

units during 1995–1999 and for opt-in

units. However, for purposes of a NOX

mass trading program, the heat input

value would be used in the calculation

to determine NOX mass, and an

imprecise unit level heat input value

could cause the NOX mass emissions

from some units to be underestimated.

The NOX mass trading program could be

undermined by the lack of a consistent

emissions value for each NOX

allowance. Therefore, the proposed

provisions for monitoring heat input

and NOX emission rate from units in a

NOX mass trading program would be

similar to the provisions that are

currently used for monitoring SO2 mass

emissions at a common stack at § 75.16.

The provisions for monitoring SO2 mass

emissions require that the two values

needed to determine SO2 mass

emissions, stack flow rate and SO2

concentration, be monitored at the same

location. The Agency is proposing that,

for purposes of determining NOX mass

emissions, a facility could use the same

location options currently available for

SO2: the facility could either monitor

both NOX emission rate and heat input

at the common stack level or monitor

them both at the unit level. The Agency

is also proposing a third option: heat

input could be monitored at the unit

level and summed to the common stack

level, while NOX emission rate could be

monitored at the common stack level.

Even though this option would allow

NOX emission rate and heat input to be

measured at different locations, it does

not have the inherent inaccuracies

described above because it does not

require heat input apportionment.

Similarly, the optional procedures

currently allowed for the apportionment

of heat input measured at a common

pipe in Appendix D, section 2.1.2.2 are

not available for units with a common

pipe under subpart H. As discussed

above for common stacks, the Agency is

concerned that the heat input

apportionment under Appendix D,

section 2.1.2.2 provisions would be too

imprecise for the purpose of calculating

NOX mass emissions. In the existing

rule, heat input can be determined from

measurements at the common pipe and

then apportioned to the individual units

using unit load. For purposes of

calculating NOX mass emissions under

subpart H for a unit which is supplied

fuel from a common pipe, the

measurement of fuel flow rate would

have to be made at the pipe leading to

the individual unit in order to

determine unit level heat input.

The Agency solicits comment on the

proposed approach for monitoring NOX

mass emissions at a common stack or

pipe and whether it is appropriate to

mirror the common stack and pipe

provisions for SO2 mass emissions.

(d) Multiple duct/stack monitoring.

The current provisions for monitoring

NOX emission rate, in §§ 75.17(c)(1) and

(2), allow the owner or operator to

determine NOX emission rate for a unit

that exhausts through multiple ducts or

stacks using a Btu-weighted sum of the

NOX emission rates measured in each

duct or stack or by monitoring NOX

emission rate in only one duct or stack.

The new proposed § 75.72 would set

forth specific requirements for

monitoring NOX mass in multiple ducts

or stacks and would in some cases place

a number of limits on the options in

§ 75.17(c) and in some cases not allow

the options in § 75.17(c). The proposed

options for monitoring NOX mass are

similar to the existing provision in

§ 75.16(d) for monitoring SO2 mass

emissions at multiple ducts/stacks.

They are also similar to the provisions

being used in the OTC NOX Budget

Program to determine NOX mass in

similar situations.

The new proposed § 75.72 does not

contain an option for any units to use

a Btu-weighted sum of the NOX

emission rates measured in each duct or

stack. The reason that this option is not

appropriate is that in order to use this

option to determine a unit’s NOX

emission rate, the owner or operator of

the unit would have to monitor both

NOX emission rate and heat input in

each duct or stack. (As discussed above,

the heat input apportionment method

allowed under § 75.17 is not sufficiently

accurate for a NOX mass program.)

These two values allow the calculation

of NOX mass and, therefore, there is no

reason to determine a Btu-weighted sum

for purposes of this subpart.

The new proposed § 75.72 would not

allow coal units to monitor NOX

emission rate in only one duct or stack.

The proposal would also not allow gas

and oil units to monitor the NOX

emission rate in only one duct or stack,

unless heat input is determined using

the provisions of Appendix D to this

part and the owner or operator makes a

demonstration that the emission rate

would always be the same in both ducts

or stacks. Reasons that the emission rate

might vary include the use of add-on

emission controls in the ducts or stacks

or venting of emissions to one duct or

stack and not the other.

These limitations are required for

monitoring mass emissions (in lbs), but

are not necessary for monitoring

emission rate (in lbs/mmBtu) at coal

units or gas and oil units that use

continuous volumetric flow monitors,

because, for reasons discussed above,

monitoring mass requires the

monitoring of both emission rate and

heat input. Since the amount of stack
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28053

flow that is vented to each duct or stack

could vary significantly depending

upon the location and use of dampers

and induction fans in the ducts or

stacks, it is necessary to measure

volumetric flow in both ducts or stacks

in order to determine heat input for the

unit(s). In order to accurately use these

heat input values to determine NOX

mass, it is also necessary to measure

NOX emission rate in both ducts or

stacks. Therefore, proposed § 75.72

would require monitoring of heat input

and NOX emission rate in both ducts or

stacks for coal units and gas-and oilfired units that use continuous

volumetric flow monitors and exhaust

to multiple ducts or stacks.

Since gas-and oil-fired units that are

using the procedures in appendix D of

part 75 to determine heat input based on

fuel consumption do not have to

measure volumetric flow in the duct or

stack in order to determine heat input,

EPA believes it is appropriate to allow

these units to measure NOX emission

rate in only one duct or stack if they can

demonstrate to both the permitting

authority and the Administrator that the

NOX emission rate in either duct or

stack is representative of the NOX

emission rate in each duct or stack.

Therefore, proposed § 75.72 allows gasand oil-fired units that are using the

procedures in appendix D of part 75 to

measure NOX emission rate in only one

duct or stack if they can demonstrate to

both the permitting authority and the

Administrator that the NOX emission

rate in either duct or stack is

representative of the NOX emission rate

in each duct or stack.

(e) Reporting of NOX Mass Emissions.

The Agency also notes that the proposed

procedures differ in two key respects

from the way data is currently reported

under part 75. The first difference is that

the proposal would require reporting of

hourly NOX mass emissions, in lbs,

(instead of hourly mass emission rate, in

lb/hr, as is currently required for the

reporting of SO2 under part 75). The

OTC NOX Budget Program is expected

to require the reporting of hourly mass

emissions, in lb, rather than hourly

mass emission rates, in lb/hr, because of

experience under the Acid Rain

Program with reporting hourly SO2 and

CO2 mass emission rates. As discussed

in Section III.R.1 of this preamble, the

reporting of hourly SO2 and CO2 mass

emission rates has been a source of

some confusion in the implementation

of the Acid Rain Program. For the

reasons presented in Section III.R.1 of

this preamble, EPA is not proposing to

change the existing SO2 and CO2

reporting requirements. However, the

existing part 75 does not require any

NOX mass emission reporting, and in

order to avoid the problems experienced

under the Acid Rain Program and to be

consistent with the OTC NOX Budget

Program, EPA proposes here to base the

new NOX reporting on mass emissions

in pounds. Maintaining consistency

with the provisions expected to be

adopted for the OTC NOX Budget

Program is important to ensure that a

central body such as EPA would be able

to effectively administer the program if

states opted to participate in a multistate NOX trading program larger than

the Ozone Transport Region covered by

the OTC NOX Budget Program.

The second key difference is that, in

addition to reporting a quarterly and

cumulative annual total emissions

value, the proposed revisions would

also require reporting of a cumulative

ozone season total value. Generally, the

ozone season extends from May 1 to

September 30 of every year. The

cumulative ozone season emissions

would be reported with the second

quarter and third quarter reports

submitted to EPA. The reason that

reporting would be required on an

ozone season basis is that one of the

main reasons the data is being collected

is to support other programs designed to

control emissions during the ozone

season.

(f) Role of EPA and States/Localities

in Administering the Monitoring Portion

of a NOX Trading Program. The Agency

also notes that another important

potential difference between the use of

this part to support the Acid Rain

Program under Title IV of the CAA and

the use of this part to support other NOX

mass emission reduction programs is

the role that EPA and the state or local

permitting authority that may establish

such a program will play. Under the

Acid Rain Program, even though many

states have assumed the role of the

permitting authority under Phase II of

the program, EPA still retains authority

to issue approvals and disapprovals

related to all of the monitoring and

reporting issues, such as certification of

monitoring systems under § 75.20,

approval of petitions under § 75.66 and

approvals of alternate monitoring

petitions under § 75.48. EPA believes

that if a NOX mass emission reduction

program is approved as part of a SIP or

if EPA agrees to work with individual or

groups of states to help administer the

monitoring and reporting portion of a

NOX mass emission reduction program,

EPA would still have to be involved in

the approval process.

The level of this involvement might

vary depending upon the specific type

of approval or disapproval. It also

would vary depending upon whether or

not the unit had an Acid Rain emission

limitation. For instance, EPA would

play a significant role in the approval of

an alternate monitoring petition under

§ 75.48 or any other petitions under

§ 75.66. For a unit with an Acid Rain

emission limitation, any petition would

already have to be approved by EPA. In

order to streamline the process for these

sources, EPA believes that EPA should

continue to issue approvals and

disapprovals of petitions. However,

since sources would also be using the

monitored data to meet SIP

requirements, EPA would take this

action in consultation with the

applicable state. For units that are not

subject to an Acid Rain emission

limitation, EPA would still need to be

involved in petition determinations.

There are two primary reasons that this

involvement would be necessary. The

first would be as part of EPA’s typical

role in assuring that any alternative to

the approved SIP will still result in the

air quality benefit that would have been

derived if the permitting authority had

not deviated from the SIP. The second

would be as part of EPA’s role in

administering the emissions tracking

portion of a NOX mass emission

reduction program. If EPA was not

involved and a state approved, for a

unit, an alternative that allowed

variations to the reporting requirements,

EPA might not be able to administer the

emissions tracking portion of the

program for that unit. Similarly, for

approval and disapproval of

certification applications and

recertification applications, EPA

believes that there should be two

separate requirements; one for units

subject to an Acid Rain emission

limitation, and one for units not subject

to an Acid Rain emission limitation. For

units subject to an Acid Rain emission

limitation, EPA would still approve or

disapprove certification and

recertification applications. This would

streamline the process for units since

they would only have to deal with one

regulatory agency for both programs. For

units not subject to an Acid Rain

emission limitation, the permitting

authority would approve certification

and recertification applications. EPA

requests comment on this approach and

whether the respective roles of the

Administrator and the permitting

authority should be different for units

that are subject to both an Acid Rain

emission limitation and to a NOX mass

emission reduction program and for

units that are subject solely to a NOX

mass emission reduction program.
28054 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

I. Span and Range Requirements

Background

The span and range requirements for

part 75 continuous emission monitoring

systems are found under section 2.1 of

Appendix A to the January 11, 1993,

rule, as amended on May 17, 1995.

Sections 2.1.1, 2.1.2, 2.1.3 and 2.1.4 of

Appendix A give the specific span and

range requirements for SO2 monitors,

NOX monitors, diluent (O2 and CO2)

monitors, and flow rate monitors,

respectively.

The span of a CEMS provides an

estimate of the highest expected value

for the parameter being measured by the

CEMS. For instance, the span value of

an SO2 monitor should be an

approximation, based on the type of fuel

being combusted, 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 fullscale. Part 75 span values are used to

determine the appropriate reference gas

concentrations and reference signals for

daily calibration of the CEMS; the

reference concentrations and signal

values 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 to the January 11, 1993 rule

specified procedures for determining

the span values for four parameters:

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 results from the previous 12

months (using the highest sulfur content

and lowest heating value in Equation A–

1a or A–1b). The SO2 span value was

then obtained by multiplying the MPC

by 1.25 and rounding the result upward

to the next highest multiple of 100.0

ppm. The MPC values for NOX were

specified in the rule and were based on

the type of fuel being combusted (e.g.,

800.0 ppm for coal-firing and 400.0 ppm

for oil-firing). The NOX span value was

then determined by multiplying the

MPC by 1.25 (e.g., 1000.0 ppm for coalfiring and 500.0 ppm for oil-firing). 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 either using Equation A–3a

(or A–3b) or from historical test data

(i.e., from velocity traverses conducted

at or near maximum load). Then, the

span value was obtained by multiplying

the MPV by 1.25 and rounding the

result upward to the next highest

multiple of 100 feet per minute (fpm).

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 fullscale range value (e.g., if a scrubber

were used to reduce SO2 emissions), a

second, ‘‘low-scale’’ span and range

would be required. The low scale of the

CEMS would be defined as 1.25 times

the ‘‘maximum expected concentration’’

(MEC). The original rule was

prescriptive regarding the method of

determining the MEC. For SO2, the MEC

was to be calculated using Equation A–

2; for NOX, an MEC value of 320.0 ppm

was to be used for coal-firing and 160.0

ppm for oil-or gas-firing.

In the first two years of Acid Rain

Program implementation, it became

increasingly clear to both the regulated

community and to EPA that the span

and range provisions of part 75 lacked

sufficient flexibility and clarity. The

NOX provisions were particularly

problematic, being overly prescriptive

in some instances and sometimes

requiring two spans and ranges when a

single, appropriately-sized range would

suffice. Also, the units of the flow rate

span were expressed in terms of velocity

(i.e., feet per minute), and this was not

consistent with either the units of

measure used for daily monitor

calibrations or the units used for

electronic reporting of flow rate data.

The May 17, 1995 rule attempted to

address these deficiencies, as follows.

For SO2, an alternative means of

determining the MPC, in lieu of using

historical fuel sampling data, was

added; the MPC could be based upon 30

days of historical CEMS data. The use

of historical CEMS data was also

allowed as an option for MEC

determinations, instead of using

Equation A-2. For NOX, the method of

determining the MPC was made less

prescriptive. First, 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. The MPC value from

this list could be used in lieu of the fuelbased MPC prescribed in the original

rule. Second, two alternative methods of

determining the MPC or MEC were

added, i.e., from historical CEMS data or

from emission test results. Finally,

flexibility was added to the dual-range

requirements for NOX monitors so that,

in many instances, the span and range

requirements of part 75 could be met on

a site-specific basis, using a single span

and range.

The span provisions for CO2 and O2

were not significantly changed in the

May 17, 1995 rule. For flow rate,

however, a more detailed procedure for

determining the span value was added.

This addition was considered necessary

because during the first year of program

implementation it came to light that

there are actually two important span

values associated with flow rate: (a) the

‘‘calibration’’ span value used for daily

calibrations, and (b) the ‘‘flow rate’’

span value in units of standard cubic

feet per hour (scfh). These two span

values are both derived from the MPV,

but are almost invariably expressed in

different units of measure, and,

therefore, the two spans are generally

not equal numerically. For instance, the

calibration span value for the daily

calibration of a differential pressuretype flow monitor, expressed in units of

inches of water, is a small number

(generally less than 5.0 in. H2O); while

the flow rate span value, in scfh, is a

very large number, usually in the tens

or hundreds of millions.

The May 17, 1995 rule also revised

the procedures for adjusting the span

and range of SO2, NOX, and flow

monitors. Sections 2.1.1.4, 2.1.2.4, and

2.1.4 of Appendix A to the original rule

had specified that span and range

adjustments were required whenever

the MPC, the MEC, or the MPV changed

significantly. 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 revised sections 2.1.1.4, 2.1.2.4, and

2.1.4 of Appendix A to 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 fullscale 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.

Finally, the May 17, 1995 rule specified

that whenever the range of a gas monitor

is adjusted, a linearity test is required,

and a calibration error test must be done

when the range of a flow monitor is

adjusted.

Discussion of Proposed Changes

Since promulgation of the May 17,

1995 rule, EPA has continued to receive

questions and comments about the span

and range sections of part 75. Many of
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28055

the questions and comments have

centered on the adjustment of span and

range. The following questions are

typical: When must the span and range

be changed? What constitutes a

‘‘significant’’ change in the MPC, MEC,

or MPV? When a span and range

adjustment is required, what are the

deadlines for making the changes and

for completing the required linearity

test? How should full-scale exceedances

be reported? There also appears to be

some lingering confusion and

misunderstanding about how to

determine the flow rate span values and

how to calculate the maximum potential

flow rate (MPF) and the NOX maximum

emission rate (MER) (see Docket A–97–

35, Items II–B–8, II–D–67, and II–E–31).

In view of this, EPA believes that the

span and range sections of the rule are

still not sufficiently clear, flexible, or

detailed and are in need of further

revision. In June, 1996, a national part

75 CEM Implementation Workgroup

meeting was held in Washington D.C. to

discuss possible revisions to part 75.

One of the principal topics of discussion

was span and range (see Docket A–97–

35, Item II–E–32). Today’s rulemaking

proposes comprehensive revisions to

sections 2.1 through 2.1.4 of Appendix

A, based in part on the discussions of

the June, 1996 meeting. The principal

changes are described in paragraphs (1)

through (5), below.

1. Maximum Potential Values

The basic procedure for determining

the maximum potential of SO2

concentration would be unchanged by

today’s proposal. However, two new

provisions would be added to section

2.1.1.1 of Appendix A to prevent

overestimation of the MPC. The first of

these provisions would allow the

exclusion of clearly anomalous fuel

sampling results when determining the

MPC. The second provision would

apply to units for which the designated

representative certifies that the highest

sulfur fuel is never combusted alone,

but is always blended or co-fired with

other fuel(s) during normal operation.

For such units, the MPC would be

calculated using best estimates of the

highest sulfur content and lowest gross

calorific value expected for the blend or

fuel mixture and inserting these values

into Equation A–1a or A–1b. The best

estimates of the highest percent sulfur

and lowest GCV for a blend or fuel

mixture would be derived from

weighted-average values based upon the

historical composition of the blend or

mixture in the previous 12 (or more)

months.

The alternative procedure for

determining the MPC of SO2 based upon

quality assured historical CEMS data

would be retained, but it is proposed

that the MPC be based, at a minimum,

upon the previous 720 quality assured

monitor operating hours, rather than the

previous 30 unit operating days. This is

to ensure that a sufficient quantity of

valid data is used for the MPC

determination. Making the

determination based on 30 unit

operating days does not provide that

assurance, particularly for units that

may only operate for a few hours a day

(e.g., peaking units). Revised section

2.1.1.1 would also specify that for a unit

with add-on SO2 emission controls, the

historical CEMS data option may only

be selected if the certified SO2 monitor

used to determine the MPC is located at

the control device inlet.

For NOX, the general procedures for

determining the MPC would also remain

the same, i.e., either: (1) use the MPC

value prescribed in the original rule, (2)

use the unit-specific value listed in

Table 2–1 or 2–2, or (3) determine the

MPC by emission testing or from

historical CEM data. However, the

following changes to section 2.1.2.1 of

Appendix A are proposed. First, a

statement would be added that the MPC

would have to be based upon the

combustion of whichever fuel or blend

combusted at the unit produces the

highest level of NOX emissions. Second,

an advisory statement would be added,

noting that the initial MPC value

determined for a unit that is not

equipped with low-NOX burners (LNB)

would have to be re-evaluated if a lowNOX burner system is subsequently

installed and optimized. Third, if

historical CEMS data are used to

determine the MPC, the determination

would have to be based on the previous

720 (or more) quality assured monitor

operating hours (instead of the previous

30 unit operating days). Fourth, units

with add-on NOX emission controls

could only use the historical CEM data

option if the historical data represented

uncontrolled emissions (e.g., if the

certified CEMS used to collect the data

were located prior to the control device

inlet or, for a unit with seasonal NOX

controls, if the historical data were from

a period when the controls were not

operating). Fifth, if emission testing is

used for the MPC determination,

sufficient tests would have to be

performed at various loads and excess

oxygen levels to ensure that a credible

MPC value is obtained. For units with

add-on NOX emission controls, the

emission test data would have to be

collected upstream of all controls, or, for

a unit with seasonal controls, during a

period when the controls were not

operating. Finally, a specific

requirement to calculate the maximum

potential NOX emission rate (MER)

would be added to section 2.1.2.1 of

Appendix A. The May 17, 1995 rule had

provided a definition of the MER in

§ 72.2; however, a corresponding

requirement to calculate the MER was

not included in part 75 at that time. The

MER is occasionally needed to provide

substitute NOX emission rates during

missing data periods. The owner or

operator would be permitted to 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.

For CO2, today’s proposed rule would

add a new section 2.1.3.1 to Appendix

A, which provides a definition of the

MPC. The MPC for CO2 pollutant

concentration monitors would be 14.0

percent for boilers and 6.0 percent CO2

for combustion turbines. Alternatively,

the MPC could be based on a minimum

of 720 hours of representative quality

assured historical CEM data.

For flow rate, the procedure for

determining the MPV would be

essentially unchanged by today’s

proposed rule, i.e., the MPV would

either be determined from Equation A–

3a (or A–3b, as applicable) in Appendix

A, or it would be based on velocity

traverse data taken at or near maximum

load. However, a procedure for

calculating the maximum potential flow

rate (MPF) would be added to section

2.1.4.1 of Appendix A. The MPF is

occasionally used to provide substitute

flow rate data; therefore, a clear,

consistent method of determining the

MPF is needed.

2. Maximum Expected SO2 and NOX

Concentrations

Today’s proposal would significantly

change the procedures for determining

the maximum expected concentration

(MEC) of SO2. The purpose of the

revisions would be to ensure that the

proper span(s) and range(s) are selected

for SO2 measurement. Proposed section

2.1.1.2 of Appendix A would require the

MEC to be determined for units with

SO2 controls and also for uncontrolled

units that burn both high- and lowsulfur fuels (or blends) as primary or

backup fuels (e.g., high- and low-sulfur

coal or different grades of fuel oil).

The revised procedures for

determining the MEC for SO2 would be

as follows. For units with emission

controls, Equation A–2 in Appendix A

would be used to calculate the MEC. For

uncontrolled units that burn both highsulfur and low-sulfur fuels or blends as

primary or backup fuels, Equation A–1a

or A–1b in Appendix A (which in the
28056 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

current rule is reserved for MPC

calculations) would be used to

determine an MEC value for each fuel or

blend, with three important exceptions.

The MEC would not be calculated for:

(1) the highest-sulfur fuel or blend

(because it would be duplicative of the

MPC calculation); (2) fuels or blends

with a total sulfur content no greater

than the total sulfur content of natural

gas, i.e., ≤ 0.05 percent sulfur by weight,

because § 75.11(e)(3)(iv) of the current

rule specifies that natural gas

combustion does not trigger a dual span

and range requirement for the SO2

monitor (for gas firing, the MEC and

low-scale span values would be too low

to be practical for quality assurance

purposes, e.g., < 5 ppm for pipeline

natural gas); and (3) fuels or blends that

are combusted only during unit startup,

because such fuels are infrequently used

and are not representative of normal

unit operation.

Today’s proposal would continue to

allow the same flexibility in the SO2

MEC determination that was introduced

in the May 17, 1995 rule. That is, if a

certified SO2 CEMS is already installed,

the owner or operator could determine

the MEC based upon historical

continuous monitoring data, in lieu of

using mathematical equations. If this

option were chosen for a unit with SO2

controls, the MEC would be the

maximum SO2 concentration measured

at the control device outlet by the CEMS

over the previous 720 or more quality

assured monitor operating hours with

the unit and the control device both

operating normally. For units that burn

both high- and low-sulfur fuels or

blends as primary and backup fuels and

have no SO2 controls, the MEC for each

fuel would be the maximum SO2

concentration measured by the CEMS

over the previous 720 or more quality

assured monitor operating hours in

which that fuel or blend was the only

fuel being burned in the unit.

Today’s rule also proposes to change

the way in which the MEC is

determined for NOX. Revised section

2.1.2.2 of Appendix A would require a

determination of the MEC during

normal operation for units with add-on

NOX controls capable of reducing NOX

emissions to 20.0 percent or less of the

uncontrolled level (i.e., steam injection,

water injection, selective catalytic

reduction or selective non-catalytic

reduction). 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. The MEC

would be determined in one of three

ways: (1) using Equation A–2 in

Appendix A; or, if that equation is not

appropriate, (2) by emission testing or

(3) by using historical CEMS data from

the previous 720 (or more) quality

assured monitor operating hours.

Revised section 2.1.2.2 would give

specific guidelines and procedures by

which to obtain the MEC when the

emission testing or CEMS data options

are selected. All CEMS or emission test

data used for the MEC determination

would be taken under stable operating

conditions with all control devices and

methods operating properly.

3. Span and Range Values

For SO2, NOX, and flow rate,

respectively, revised sections 2.1.1.3,

2.1.2.3 and 2.1.4.2 of Appendix A

would allow the high-scale span value

to be between 100.0 and 125.0 percent

of the maximum potential value (i.e.,

the MPC or MPV), rounded off

appropriately. This is a change from the

current rule which requires the high

span to be set at 125.0 percent of MPC

or MPV, rounded off appropriately.

However, the change is not expected to

be disruptive, because properly sized

span values previously determined by

multiplying the MPC or MPV by 1.25

could continue to be used. The change

would allow the owner or operator to

set the span value in such a way that a

small exceedance of MPC or MPV

would not require a span change (see

paragraph 5, ‘‘Adjustment of Span and

Range,’’ below). The added flexibility in

span selection would also allow

different units with similar (but not

identical) MPCs for SO2 and/or NOX to

use the same span value and to use the

same calibration gas concentrations,

which could result in cost savings for

some facilities. In 1996, EPA received

and approved a petition from one utility

to equalize the SO2 span values at

several of its coal-fired units (see Docket

A–97–35, Items II–C–23, II–D–71).

For CO2 and O2 monitors, today’s

proposal would revise section 2.1.3 of

Appendix A to allow the owner or

operator maximum flexibility in

selecting an appropriate span value. The

CO2 or O2 span value would not be

determined in the same way as an SO2,

NOX, or flow rate span value. Rather, for

CO2 monitors installed on boilers, any

convenient span value between 14.0

percent and 20.0 percent CO2

representing the percent diluent in the

flue gas would be acceptable. For

combustion turbines, any 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. However,

if the O2 concentrations are expected to

be consistently below 15.0 percent, an

alternative span value of less than 15.0

percent could be used, provided that an

acceptable technical justification was

included in the monitoring plan. The

proposed rule would also allow purified

instrument air containing 20.9 percent

O2 to be used as the high level

calibration gas for oxygen monitors

having span values greater than or equal

to 21.0 percent O2.

There are two principal reasons why

EPA is proposing increased flexibility in

the selection of the CO2 and O2 span

values. The first is to encourage greater

accuracy in the diluent gas

measurements. The revisions would

allow the span value to be customized

so that the concentration of the upscale

calibration gas used for daily

calibrations can be as close as possible

to the actual average CO2 or O2

concentrations in the stack. In 1996,

EPA received and approved a petition

from one utility to use a CO2 span value

of 15.0 percent for its coal-fired units,

rather than the 20.0 percent span value

required by part 75 (see Docket A–97–

35, Items II–C–20, II–D–68). The second

reason for revising the CO2 and O2 span

requirements is to eliminate

unnecessary high-level span and range

requirements. The current rule requires

a high span value of 20.0 percent for all

CO2 and O2 monitors. However, there

are many units (e.g., combustion

turbines) for which the diluent gas

concentrations are so low that the

guideline in the current section 2.1 of

Appendix A (i.e., that the majority of

the readings be within 25.0 to 75.0

percent of full-scale) cannot be met

unless a second, low-scale span and

range are used. For most of these units,

there are technical and safety reasons

why the diluent concentrations must

remain low; therefore, it is unreasonable

to require a high range to be maintained

if a lower range will suffice and can

never be exceeded. During the Phase II

certification process, EPA approved CO2

span values of 10.0 percent for a number

of combustion turbines and waived the

high-scale range requirement (see

Docket A–97–35, Items II–C–19, II–C–

21, II–D–64).

Today’s proposal would not change

the basic way in which the full-scale

range setting of a monitor is determined.

The range would still have to be set

greater than or equal to the span value.

However, the guideline for selecting an

appropriate full-scale range in section

2.1 of Appendix A would be revised as

follows. With few exceptions, the fullscale range would be selected so that, to

the extent practicable, the readings

during typical unit operation fall

between 20.0 and 80.0 percent of fullscale; this represents a slight increase in

flexibility from the ‘‘25-to-75 percent of
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28057

full-scale’’ guideline in the current rule.

Today’s proposal would also emphasize

that section 2.1 is only a guideline and

would cite three specific cases in which

it is inapplicable. Specifically, the

guideline would not apply to: (1) quality

assured SO2 readings obtained during

the combustion of natural gas or fuel

with equivalent total sulfur content

(because the resulting SO2 emissions are

too low to be subject to the span and

range requirements); (2) quality assured

SO2 or NOX readings on the high range

for an affected unit with SO2 or NOX

emission controls and two span values

(because the high range is not the

normal operating range for the unit);

and (3) quality assured SO2 or NOX

readings 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 are

associated with periods of high control

device efficiency (because it is not

necessary to re-range a monitor based on

non-representative hours of exceptional

control performance).

For flow monitors, today’s rule

proposes to revise section 2.1.4.2 of

Appendix A to more clearly define the

‘‘calibration span value’’ (which is the

span expressed in the units of measure

used for the daily calibrations) and the

‘‘flow rate span value’’ (which is the

span expressed in the units used for

electronic data reporting, i.e., scfh). The

proposed rule defines these two span

values in considerable detail and

outlines how to use them. EPA believes

that this will result in greater

consistency in implementation of the

part 75 flow rate monitoring

requirements.

4. Dual Span and Range Requirements

for SO2 and NOX

In today’s rule, revisions are proposed

to the dual span and range requirements

for SO2 and NOX monitors in sections

2.1.1.4 and 2.1.2.4 of Appendix A. The

revised provisions are essentially the

same for both pollutants. 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 determined under revised

section 2.1.1.2 or 2.1.2.2 of Appendix A

would be compared against the

maximum potential concentration

(MPC) determined under proposed

sections 2.1.1.1 or 2.1.2.1. If this

comparison shows any of the MEC

values to be < 20.0 percent of the MPC,

a low-scale span would be required. If

several of the MEC values are found to

be < 20.0 percent of the MPC, then the

low-scale span would be based upon

whichever MEC value is closest to 20.0

percent of the MPC. The low-scale span

value would be determined in a manner

similar to the high-scale span, i.e., by

multiplying the MEC by a factor

between 1.00 and 1.25 and rounding off

the result appropriately.

When both a high-scale span and a

low-scale span are required for SO2 or

NOX, proposed sections 2.1.1.4 and

2.1.2.4 would allow the owner or

operator to use either of the following

monitor configurations to meet the dualrange requirement: (1) a single analyzer

with two ranges, or (2) two separate

analyzers connected to a common probe

and sample interface. The use of other

monitoring configurations would be

subject to the approval of the

Administrator. The monitor

configurations would be represented in

the monitoring plan as follows: (a) the

high and low ranges could be

designated as two separate, primary

monitoring systems; (b) the high and

low ranges could be designated as

separate components of a single,

primary monitoring system; or (c) one

range (the ‘‘normal’’ range) could be

designated as a primary monitoring

system, and the other range as a nonredundant backup monitoring system.

The high and low ranges would be

quality assured according to their

designation in the monitoring plan.

Primary monitoring systems would have

to meet the QA requirements for

primary systems in § 75.20(c), Appendix

A, and Appendix B, with the following

exception: relative accuracy test audits

(RATAs) would be required only on the

normal range. For units with emission

controls, the low range would be

considered normal; for other units, the

range in use at the time of the scheduled

RATA would be considered normal.

Non-redundant backup systems would

have to meet the applicable QA

requirements for ‘‘like-kind replacement

analyzers’’ in proposed § 75.20(d).

Today’s rule would add a new

alternative provision under sections

2.1.1.4 and 2.1.2.4 of Appendix A for

dual-span units with SO2 or NOX

emission controls. The new provision

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 (based on

uncontrolled emissions). This value

would be reported whenever the SO2 or

NOX concentration exceeded the fullscale of the low-range analyzer. The

default high-range value is being

proposed for controlled units that

seldom, if ever, experience full-scale

exceedances of the low monitor range

during normal operation (e.g., units that

have a permit condition requiring

cessation of unit operation when a fullscale exceedance occurs or units that

experience low-range exceedances only

during startup). EPA solicits comment

on the proposed approach of using a

default high-range value in lieu of a

high range monitor and on the value of

the default.

EPA specifically requests comment on

whether the proposed dual-span

monitoring configurations, monitoring

system designations, and quality

assurance requirements are adequate, or

whether there are additional

configurations (e.g., one range with two

spans, two separate analyzers with

separate probes, etc.) that should be

included in the rule.

Finally, when two spans and ranges

are required, proposed revised sections

2.1.1.4 and 2.1.2.4 of Appendix A

would specify that the low range would

have to be used to record emission data

when the SO2 or NOX concentrations are

expected to be consistently below 20.0

percent of the MPC (i.e., when a fuel or

blend with a MEC value < 20.0 percent

of the MPC is combusted). And if the

full-scale of the low range is exceeded,

the high range would be used to record

data (or, if applicable, the default high

range value would be reported).

5. Adjustment of Span and Range

In today’s rule, detailed guidelines

and procedures are proposed for

adjusting the span and range of the

CEMS in revised sections 2.1.1.5,

2.1.2.5, 2.1.3.2 and 2.1.4.3 of Appendix

A. The intent of these provisions is to

ensure that each owner or operator

assesses the adequacy of all CEMS span

values on at least a quarterly basis (and

whenever operational changes are

planned) and, based on that assessment,

makes any necessary adjustments to the

spans or ranges in a timely manner. EPA

believes that the proposed procedures

are sufficiently flexible so that frequent

span and range adjustments will not be

necessary. The procedures are primarily

directed at CEMS with improperly-sized

spans and ranges, to bring them into full

conformance with part 75 requirements

or for future changes in unit operation

(e.g., fuel switch or low-NOX burner

installation) that may significantly affect

the level of emissions or flow. All

required span or range adjustments

would have to be made no later than 45

days after the end of the quarter in

which the need to adjust the span or

range is identified, unless the span

change would require new calibration

gases to be ordered for daily calibration

error and linearity tests, in which case,

the owner or operator would have up to
28058 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

90 days after the end of the quarter to

make the span adjustment.

The revised procedures for span and

range adjustment would be as follows.

First, if the maximum value upon which

the high span value is based (i.e., the

MPC or, for flow rate, the MPF) is

exceeded during a calendar quarter, but

the span is not exceeded, the span or

range would not have to be adjusted.

However, for missing data purposes, if

any quality assured hourly

concentration or flow rate exceeds the

MPC or MPF by ≥ 5.0 percent during the

quarter, a new MPC or MPF would have

to be defined, equal to the highest value

recorded during the quarter, and a

monitoring plan update would be

required. Second, for the high

measurement range, if any quality

assured reading 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, equal to the highest

on-scale reading recorded during the

quarter, and the span value would also

have to be changed. If the new span

value exceeded the current full-scale

range setting, then a new range setting

would also be required. Similar span

adjustment requirements would apply

to the low scale if the two measurement

ranges are used separately for distinctly

different modes of operation (e.g.,

during the combustion of different

fuels), rather than being used in

combination to provide a continuum of

measurement range capability.

The proposed procedures for

responding to full-scale exceedances are

as follows. Whenever the full-scale of a

high monitor range is exceeded,

excluding hours of non-representative

operating conditions (e.g., a trial burn of

a new fuel), corrective action would be

required to adjust the span and range. In

addition, any time the range is

exceeded, 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. The Agency

believes that 200.0 percent of the range

is sufficiently conservative to ensure

that emissions would not be underreported. One utility that experienced a

full-scale exceedance of the high SO2

monitor range estimated from the results

of fuel sampling that the SO2

concentration was approximately 150.0

percent of full-scale during the incident

(see Docket A–97–35, Item II–D–24).

For units with two span values and

two measurement ranges for a particular

parameter (e.g., SO2), when the fullscale of the low range is exceeded,

provided that the high monitor range is

available to record emission data, no

corrective actions would be required.

However, if, at the time of the low-range

exceedance or during the continuation

of the low-range exceedance, the high

range is either out-of-service or out-ofcontrol for any reason (and therefore is

not available to record quality assured

data), the MPC would have to be

reported until the readings either

returned to the low scale or until the

high scale returned to service and was

able to provide quality assured data.

However, if the reason the high scale is

unavailable is because of a high scale

exceedance, 200.0 percent of the high

range value would be reported for each

hour of the exceedance.

Proposed sections 2.1.1.5(e),

2.1.2.5(e), and 2.1.4.3(e) of Appendix A

would require that the monitoring plan

be updated whenever changes are made

in the maximum potential values,

maximum expected values, span values,

or full-scale range settings. The updates

would be made in the quarter in which

the changes become effective. The

proposed sections 2.1.1.5(e) and

2.1.2.5(e) of Appendix A would further

require a linearity test to be done

whenever the span of a gas monitor is

adjusted, if the span change is

significant enough to require new

calibration gases for daily calibration

error tests and linearity checks. Finally,

proposed sections 2.1.4.3(c) and (d) of

Appendix A would require a calibration

error test to be done whenever a flow

monitor span or range is adjusted

(unless the adjustment requires a

significant change to the flow monitor

that would require recertification under

§ 75.20(b)).

J. Quality Assurance/Quality Control

(QA/QC) Program

1. QA/QC Plan

Background

Section 1 of Appendix B to part 75 as

originally promulgated on January 11,

1993 sets forth provisions for

developing and implementing a quality

control program. As part of the quality

control program, section 1 requires that

the source develop and maintain a

quality control plan that documents

how the equipment used to report

emissions data for part 75 is maintained

and quality assured. While the

provisions in sections 1.1, 1.2, and 1.4

of Appendix B to part 75 are applicable

only to continuous emissions

monitoring systems, the provisions in

sections 1.3 and 1.5 of the existing rule

are more generally applicable to all

monitoring systems under part 75. The

quality assurance requirements for

excepted monitoring systems under

Appendices D and E and for alternative

monitoring systems under subpart E are

provided in the respective Appendices

or subpart of part 75, as revised;

however, specific guidelines for the

quality control plans for these systems

are not given.

Based on the experience of state and

EPA inspectors at Acid Rain field

audits, there has been confusion and

inconsistency among industry sources

regarding the contents of the quality

control plan. In some cases, utility staff

have requested further guidance from

EPA on what the quality control plan

should contain. Based on this

experience, the Agency believes that the

quality control program provisions in

section 1 of Appendix B need to be

revised. Specifically, the rule needs to

be clarified in two areas: (1) the

applicability of the QA/QC program

(i.e., do the provisions apply to all

monitoring systems, only to CEMS, or

only to specific excepted or alternative

monitoring systems?); and (2) the

recordkeeping requirements for repair

and maintenance events. In addition,

several utilities have asked EPA to

consider deleting the requirement to

maintain an inventory of spare parts,

which they believe to be unnecessary

and burdensome.

Discussion of Proposed Changes

The proposed revisions discussed in

this section affect section 1 of Appendix

B to part 75. The terms ‘‘quality control

program and plan’’ would be changed to

‘‘quality assurance/quality control

program and plan.’’ The scope of section

1 would be expanded to include QA/QC

program provisions for excepted

monitoring systems under Appendices

D, E, and I and alternative monitoring

systems under subpart E. Section 1

would also be reordered to separate the

requirements applicable to all

monitoring systems (section 1.1) from

the requirements specific to CEMS

(section 1.2). The preventative

maintenance provisions, in section 1.3

of the existing rule, would be moved to

section 1.1.1 of the proposal, and would

be revised to delete the requirement to

maintain an inventory of spare parts. A

new section 1.1.3 would be added to

specify the requirements for

maintaining records of testing,

maintenance, and repair activities. QA/

QC program requirements specific to

excepted monitoring systems under

Appendices D, E, and I would be added

in section 1.3. These provisions would

require written procedures to be

maintained for fuel flowmeter testing,

primary element inspection, and fuel

sampling and analysis as well as

requiring a description of equipment

and records of testing to be maintained.

Section 1.3.6 would make the
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28059

recordkeeping requirements consistent

with the quality assurance requirements

of section 2.3.1 of Appendix E. Section

1.3.7 would specify which QA/QC

program requirements apply for

excepted monitoring systems under

Appendix I. Finally, section 1.4 would

define the QA/QC program

requirements for alternative monitoring

systems approved under subpart E,

based on the quality assurance

requirements of subpart E.

Rationale

The Agency believes that the manner

in which quality assurance/quality

control (QA/QC) and maintenancerelated activities are performed can have

a significant effect upon the accuracy of

the data reported by a monitoring

system. Therefore, today’s proposal

seeks to ensure that adequate records

are kept to document that each

monitoring system and its ancillary

components is being maintained and

operated in a proper manner. Section 1

in Appendix B to part 75 would,

therefore, be amended to provide

sources with General guidance

regarding QA/QC program

requirements. However, the Agency

recognizes that QA/QC programs may

vary from site to site and that many

sources have already developed and

implemented an effective QA/QC

program. It is the Agency’s intent to

allow each source the flexibility to

develop and implement a QA/QC

program that will result in the reporting

of accurate emissions data through

proper equipment calibration,

maintenance and troubleshooting

procedures.

(a) Inventory of Spare Parts. Section

1.3 of Appendix B to part 75 in the

January 11, 1993 rule requires that an

inventory of spare parts be maintained

as part of the QA/QC program. The

intent of this requirement is one of the

fundamental goals of a QA/QC program,

i.e., to maximize the availability of

quality-assured data from the

monitoring system. Since maintenance

and repairs are required in order to keep

the monitoring system operating

properly, the need for replacement parts

will arise over the term of use of the

monitoring equipment. In order to

minimize the amount of time when the

system is unable to provide data

because a new part is needed, the

existing rule requires that the source

maintain an inventory of spare parts.

The Agency has received comments on

this requirement from both affected

utilities and from state inspectors

arguing that it is unnecessary and

cumbersome (see Docket A–97–35, Item

II–D–49, II–E–28). Commenters have

suggested that different approaches have

been effectively employed to ensure that

spare parts are available in a timely

manner; however, not all of these

approaches require that an inventory of

spare parts be kept on-site. For example,

some spare parts may be available on a

very timely basis from a local supplier,

making it unnecessary to maintain spare

parts on-site. The Agency believes that

these different approaches may be

adequate substitutes for keeping an onsite inventory of spare parts. Therefore,

the requirement to maintain an

inventory of spare parts would be

removed in today’s proposal, although

the objective of an effective QA/QC

program, i.e., to maximize data

availability, would not change.

(b) Maintenance Records. The Agency

believes that maintaining records of

monitoring system maintenance and

repairs is an essential component of an

effective QA/QC program. Several

utilities have indicated that they agree

and have instituted QA/QC programs

which include maintaining such records

(see, e.g., Docket A–97–35, Item II–D–

88). However, some EPA and state

inspectors have found that not all

sources keep adequate records of

maintenance and repairs in their QA/QC

program. EPA believes that this failure

to keep adequate records compromises

the effectiveness of the QA/QC program.

Therefore, today’s proposal would

require each source to maintain proper

records of all testing, maintenance, or

repair activities performed on any

monitoring system or component.

Additionally, today’s proposal would

require that these records and any

additional supporting documentation be

made available for review during an

audit.

(c) Excepted Monitoring System

Requirements. The required quality

assurance activities for excepted

monitoring systems are set forth in the

respective Appendices D, E, or I.

Today’s proposed revisions in section

1.3 of Appendix B would specify that

information on the approved methods,

test procedures and test results must be

maintained on-site suitable for

inspection as part of the QA/QC

program. The proposed revisions would

consolidate all of the QA/QC

requirements in Appendix B rather than

having them spread out in Appendices

D, E, and I.

2. Flow Monitor Polynomial Coefficient

Background

Many of the stack gas volumetric flow

rate monitors currently in use by

affected sources use software

polynomial coefficients to convert

electrical signals from the monitors into

flow rate values that are electronically

reported to the Acid Rain Division. The

flow rate values generated from these

monitors are used by the source’s data

acquisition and handling system

(DAHS) to compute hourly mass

emission rates of SO2, CO2, and hourly

heat input rates. Currently, affected

sources are not specifically required to

report, record, or document the

numerical values of the polynomial

coefficients used by their flow monitors.

Discussion of Proposed Changes

Proposed § 75.59(a)(5)(vi) and

proposed revisions to section 1.1.3 of

Appendix B would require the current

values of the flow monitor coefficients

to be recorded and would require

records to be kept of any changes or

adjustments to the coefficient values.

The proposed revisions in § 75.20(b)

define flow monitor coefficient

adjustment as an event which requires

recertification.

Rationale

(a) Recordkeeping of Coefficients. The

agency has recently become aware (by a

comment received in response to a

request for review of the Acid Rain

Audit Manual) of a potentially serious

omission in the flow monitor

recordkeeping requirements of part 75

(see Docket A–97–35, Item II–D–92).

The commenter indicated that part 75

lacks a requirement to document the

values of the polynomial coefficients

which are programmed into the software

of most flow monitoring devices, and

that the Acid Rain CEM audit manual

does not recommend that Agency or

state auditors check the coefficient

values. The values of the polynomial

coefficients are important because they

are directly related to the accuracy of a

flow monitor. The coefficient values are

usually established at three different

load levels (low, mid, and high), in a

process called ‘‘linearization’’ or

‘‘characterization’’ of the monitor.

Linearization is done in an attempt to

ensure that the flow monitor reads

accurately across all load levels. The

Agency agrees with the commenter that

the flow monitor variables are a critical

component of the flow monitoring

system and that the adjustment of those

variables represents a significant change

to the flow monitoring system.

Therefore, today’s rulemaking proposes

to add § 75.59(a)(5)(vi) to require owners

and operators of affected sources to

record the numerical values of the flow

monitor polynomial coefficients used

during initial certification of the

monitor and during each subsequent

relative accuracy test audit (RATA). In
28060 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

addition, section 1 of Appendix B to

part 75 would be revised to require that

any changes to the flow monitor

polynomial coefficients be documented

and maintained as part of the QA/QC

program maintenance records. Section 1

of Appendix B would also be changed

to require the source to document

procedures related to the adjustment of

flow monitor variables in its QA/QC

plan. The values of the flow monitor

coefficients and the related adjustment

procedures would be required to be kept

on-site, in a format suitable for review

by an inspector during an audit.

(b) Recertification After Adjustment of

Coefficients. Since changing the flow

monitor polynomial constants

relinearizes the instrument, significantly

altering the monitored reading, today’s

proposed rule would amend § 75.20(b)

to require recertification subsequent to

any flow monitor polynomial coefficient

change. Since a three level RATA is the

only part 75 quality assurance test that

checks the linearity of a flow monitor,

the recertification would require a three

level RATA.

K. Calibration Gas Concentration for

Daily Calibration Error Tests

Background

All part 75 gas monitoring systems are

required by section 2.1.1 of Appendix B

of the current rule to pass daily

calibration error tests, in order to

validate emission data from the CEMS.

The procedures for conducting the daily

calibration error tests are found in

section 6.3.1 of Appendix A. Each daily

calibration error test consists of

injecting two protocol gases of known

concentration into the CEMS and

comparing the responses of the

instrument to the tag values of the

protocol gases. The two required gas

concentrations for the calibration error

tests are zero-level (i.e., 0.0 to 20.0

percent of the span value of the

instrument) and high-level (80.0 to

100.0 percent of span).

The span values of part 75 SO2 and

NOX monitors are determined by

multiplying the maximum potential

concentration (MPC) by 1.25 and

rounding the result upward to the

nearest 100.0 ppm. For CO2 and O2

monitors, a span value of 20.0 percent

O2 or CO2 is prescribed. These span

values have been deliberately oversized

to prevent full-scale exceedances from

occurring. Consequently, the SO2, NOX,

CO2, and O2 readings obtained during

normal unit operation are generally well

below the span values and typically

range from about 25.0 to 75.0 percent of

full-scale. Because of the oversized span

values, the concentrations of the highlevel calibration gases used for daily

calibration error tests are often much

higher than the actual pollutant and

diluent gas concentrations in the stack.

As a result, the representativeness of the

daily calibration error test can be

questioned, because the test does not

always check the accuracy of an

analyzer on the part of the scale where

most of the readings occur. For instance,

typical CO2 concentrations for many

part 75 units range from about 10.0 to

12.0 percent CO2 (i.e., 50.0 to 60.0

percent of the span value). However,

when CO2 analyzers are calibrated, the

high-level calibration gas concentrations

(i.e., 16.0 to 20.0 percent CO2 ) are

considerably higher than normal stack

emissions. In view of this, EPA believes

it would be appropriate to allow the

owner or operator to have greater

flexibility in selecting a representative

upscale gas for daily calibrations. One

State agency has successfully

implemented this type of flexibility in

its CEM program. The State’s CEM rule

specifies the acceptable range of values

for the upscale calibration gas, but adds

the following qualifying statement,

‘‘* * *unless an alternative

concentration can be demonstrated to

better represent the normal source

operating levels *–*–*’’ (see Docket A–

97–35, Item II–D–72).

Discussion of Proposed Changes

Today’s rule proposes to add

flexibility to the procedures for

conducting the calibration error tests of

part 75 gas monitors to encourage daily

calibrations to be done more

representatively. Section 6.3.1 of

Appendix A would be revised so that,

beginning on January 1, 2000, either the

mid-level gas (50.0 to 60.0 percent of

span) or the high-level gas (80.0 to 100.0

percent of span) could be used as the

upscale calibration gas for daily

calibration error tests. A corresponding

change would be made to the procedure

for calculating the calibration error in

section 7.2.1 of Appendix A. Prior to

January 1, 2000, the owner or operator

would have the option of using the midlevel calibration gas for daily

calibrations if it better represents the

typical stack gas concentrations than the

high-level gas.

L. Linearity Test Requirements

Background

Section 75.20(c) of the current part 75

rule requires a 3-point linearity test of

each SO2 and NOX pollutant

concentration monitor and each diluent

gas (O2 or CO2) monitor, as part of the

initial certification process. A linearity

test consists of a series of nine reference

calibration gas injections at three

different known concentration levels

(low, mid, and high) to establish the

accuracy of a gas analyzer across its

measurement range. The procedures for

conducting linearity tests are found in

section 6.2 of Appendix A to part 75.

Section 6.1 of Appendix A specifies that

linearity tests must be done while the

unit is operating.

After the initial certification of a gas

monitoring system, section 2.2 of

Appendix B to part 75 requires periodic

linearity tests to be performed. A

linearity check is required during each

unit operating quarter or, for bypass

stacks, during each quarter in which

flue gases are discharged through the

stack. For units with two span values for

a particular parameter (e.g., units with

add-on SO2 controls), linearity tests

must be conducted on both the ‘‘low’’

and ‘‘high’’ monitor ranges. Successive

linearity tests are, to the extent

practicable, to be conducted no less

than 2 months apart.

Utility representatives have asked

EPA to consider changing the

requirement for the unit to be operating

when linearity tests are done (see

Docket A–97–35, Items II–D–20, II–D–

65, II–E–13, II–E–14). This has been

requested because owners and operators

of peaking units and other units that

operate on an ‘‘on-call’’ basis have

experienced difficulty in complying

with the requirement for the unit to be

on-line during linearity tests. For

instance, a unit may only operate for a

few hours in a quarter and not be

needed again until the next quarter. In

such a situation, the utility might be

forced to re-start and operate the unit

(whether or not it is needed) to comply

with the linearity test requirement.

Some of the utility representatives have

also expressed the opinion that for

certain monitoring technologies (e.g.,

dry extractive), on-line and off-line

linearity tests are essentially equivalent.

Discussion of Proposed Changes

1. Unit Operation During Linearity Tests

Today’s rule proposes to revise the

linearity test requirements of part 75 to

make them easier with which to

comply. EPA agrees that the current

linearity test requirements of part 75

lack flexibility and that compliance

with the requirements is particularly

difficult for infrequently operated units.

However, the Agency does not agree

with the utility representatives that have

suggested allowing off-line linearity

tests as the best solution to the problem.

Nor is the Agency proposing to allow

technology-specific exemptions to the

on-line linearity test requirement.
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28061

Rather, today’s proposal would retain

the requirement for linearity tests to be

performed while the unit is combusting

fuel at conditions of typical stack

temperature and pressure. A clarifying

statement would be added to section 6.2

of Appendix A, indicating that the unit

does not have to be generating

electricity during the test. But EPA

would continue to require that a

linearity test be performed while the

unit is combusting fuel at conditions of

typical stack temperature and pressure

in order to test the monitoring system

under the same conditions as when the

monitor is measuring emissions, in

order to account for any temperature

and pressure effects. An on-line

linearity test challenges a CEMS while

it is in equilibrium with the stack

environment and has been sampling

stack gas continuously for a period of

time.

2. Linearity Test Frequency

The Agency proposes instead to add

flexibility to the linearity test

requirements by changing the basis

upon which the frequency of linearity

tests is determined and by providing a

linearity grace period. In today’s

proposal, section 2.2 of Appendix B

would be revised to require that a

linearity test be performed in each ‘‘QA

operating quarter’’ rather than in each

‘‘unit operating quarter’’ or ‘‘bypass

stack operating quarter.’’ For linearity

tests, a QA operating quarter would be

defined in the same way as for RATAs,

i.e., as a calendar quarter in which the

unit operates for at least 168 hours (or,

for common stacks, a quarter in which

effluent gases discharge through the

stack for at least 168 hours). EPA

believes that the QA operating quarter

methodology would, in most instances,

enable the owner or operator of a

peaking unit or other infrequently

operated unit to complete an on-line

linearity test within the calendar quarter

in which it is due. However, the

following additional changes would be

made to further ensure that the linearity

test requirements can be met: (1) the

requirement to perform successive

linearity tests at least 2 months apart

would be reduced to allow successive

tests to be done one month (30 days)

apart; and (2) a new section, 2.2.4,

would be added to Appendix B,

providing a 168 unit operating hour

grace period after the end of each QA

operating quarter in which to complete

the required test. Thus, to make it easier

for infrequently operated units to

complete the required linearity tests in

the quarters in which they are due, the

required waiting time between

successive linearity tests would be

reduced. And, if circumstances should

prevent a linearity test from being

completed in the QA operating quarter

in which it is due, the test could be

done during the grace period. If the

required linearity test were not

completed by the end of the grace

period, data from the monitor would be

considered invalid from the hour after

the grace period expires until the hour

of completion of a subsequent

successful linearity test.

For infrequently operated units,

certain calendar quarters would not

qualify as QA operating quarters.

Therefore, in accordance with today’s

proposed rule, no linearity tests would

be required in those quarters. However,

this exemption from linearity testing

would not be without limit. Proposed

section 2.2.2 of Appendix B would

allow no more than four consecutive

calendar quarters to elapse following the

quarter in which the last linearity test

was conducted, without a subsequent

linearity test having to be performed.

That is, a linearity test would either

have to be done by the end of the fourth

consecutive elapsed calendar quarter

since the last test or within a 168 unit

operating hour grace period after the

end of the fourth consecutive elapsed

quarter. Data from the monitor would

become invalid if the linearity test was

not completed by the end of the grace

period and would remain invalid until

a linearity test was successfully

completed.

Today’s proposal would also change

the requirement for units with two span

values for a particular parameter (e.g.,

units with add-on SO2 controls) to

perform quarterly linearity tests on both

the low and high monitor ranges.

Section 2.2.1 of Appendix B would be

revised to require a linearity test of a

monitor range only if that range is used

to report data during the QA operating

quarter. However, under proposed

section 2.2.3(e) of Appendix B, at least

one linearity test of each range would

still be required every four calendar

quarters to maintain data validation on

the range.

3. Linearity Test Method

Today’s proposal would add two new

requirements to section 6.2 of Appendix

A: (1) that all linearity tests must be

done ‘‘hands-off,’’ meaning that no

adjustments of the CEMS other than

certain calibration error adjustments

would be permitted prior to or during

the linearity test period; and (2) to the

extent practicable, each linearity test

would have to be completed within a

period of 24 unit operating hours. These

proposed provisions are intended to

ensure greater consistency in the way in

which linearity tests are conducted and

to ensure that the tests are completed in

a timely manner. The allowable

calibration adjustments prior to and

during a linearity test would be defined

in proposed section 2.1.3 of Appendix

B. For a further discussion, see Section

O of this preamble, ‘‘CEM Data

Validation,’’ below.

4. Exemptions

Finally, section 6.2 of Appendix A

would be revised to exempt SO2 and

NOX monitors with span values of 30

ppm or less from the linearity test

requirements of part 75. At these low

span values, the linearity test begins to

lose its significance. For example,

typical low, mid, and high calibration

gases for a span value of 30.0 ppm

would be 24.0 ppm, 18.0 ppm, and 9.0

ppm, respectively. The appropriate

linearity performance specification in

section 3.2 of Appendix A is ± 5.0 ppm

at each calibration gas level. Therefore,

in this illustration, the monitor reading

could be 14.0 ppm for both the ‘‘low’’

and ‘‘mid’’ gases or 20.0 ppm for both

the ‘‘mid’’ and ‘‘high’’ gases. Even

though a valid straight line comparing

the reference gas concentrations and the

monitor readings cannot be constructed

from such data, the monitor would still

appear to pass the linearity test.

M. Flow-to-Load Test

Background

The current quality assurance

requirements for flow rate monitoring

systems in Appendices A and B to part

75 include daily calibration error tests,

daily interference checks, quarterly leak

checks (for differential pressure type

monitors only), and semiannual or

annual relative accuracy test audits. 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 purports to

check flow monitor accuracy, but, as

explained below, the ability of the test

to accomplish this objective is

somewhat questionable.

There is a distinct difference between

the daily calibration error test of a flow

rate monitor and the calibration error

test of a gas monitor. To calibrate a gas

monitor, a protocol gas of known

concentration is sent through the

monitoring system and analyzed. This

generally serves as a reliable indicator of

the system’s ability to accurately

measure pollutant or diluent gas

concentrations, because the calibration

closely simulates the sampling and

analysis of stack gas by the monitoring
28062 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

system. A flow monitor calibration error

test, on the other hand, does not provide

the same level of assurance of data

quality. Generally, a flow monitor

calibration 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 is not a ‘‘true’’ calibration of the

monitor, since it does not evaluate the

system’s ability to measure an actual

stack gas flow rate. In order to perform

true daily flow monitor calibrations, two

reference stack gas flow rates would

have to be generated and measured.

Practical considerations preclude such

calibrations from being done, however,

because the unit load level would have

to be significantly varied during each

operating day, and suitable reference

method measurements (e.g., velocity

traverses using EPA Method 2) would

have to be made daily at each

calibration load level.

Because of the limited usefulness of

the flow monitor daily calibration error

test, 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. For instance, the sensors of

DP and thermal-type monitors are

subject to plugging and/or fouling,

which will cause the monitors to read

lower than true and can result in underreporting of emissions. One utility

observed a substantial increase in the

readings from its flow monitor after the

sensors were cleaned during a unit

outage. Apparently, the sensor problems

had not been detected by the daily

calibration error tests (see Docket A–97–

35, Item II–E–29). A second utility

experienced a gradual deterioration of

the monitor’s performance in the 9-

month period following the RATA. By

the sixth month (at load levels and CO2

concentrations virtually identical to the

conditions at the time of the RATA), the

flow monitor readings were consistently

15.0 to 20.0 percent lower than the

baseline average flow rate measured by

EPA Reference Method 2 during the

RATA. However, during the 9-month

period, the flow monitor had

consistently passed its daily calibration

error tests (see Docket A–97–35, Item II–

B–11). During a State inspection of a

third utility, the inspector observed a

consistent 20.0 to 30.0 percent

difference between the hourly flow rates

measured by the primary and redundant

backup flow monitors even though both

monitors had been passing their daily

calibration error tests. In this instance,

the primary flow monitor was being

used for data reporting and was reading

higher than the redundant backup

monitor; therefore, it is unlikely that

emissions were being under-reported.

Had the primary monitor malfunctioned

and the redundant backup been used,

however, emissions would have been

significantly under-reported (see Docket

A–97–35, Item II–B–10).

Discussion of Proposed Changes

In view of the apparent shortcomings

of the flow monitor daily calibration

error test, EPA proposes to add a new

flow monitor quality assurance test, the

‘‘flow-to-load test,’’ to part 75. The flowto-load test, which would be performed

quarterly, is described in proposed

sections 7.7 of Appendix A and 2.2.5 of

Appendix B. The proposed quarterly

flow-to-load test would be required

beginning in the first quarter of the year

2000.

The basic premise of the flow-to-load

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 (see Docket A–97–35,

Items II–B–9, II–D–69). 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 (see Docket A–97–35, Items

II–B–9, II–D–73, II–D–74, II–D–76, II–D–

83, II–D–84). The flow-to-load ratio, or

a normalized ratio, can thus serve as a

quantitative indicator of flow monitor

accuracy from quarter to quarter until

the next RATA is performed.

The quarterly flow-to-load ratio test

would be conducted as follows. The

owner or operator would be required to

determine Rref, a reference value of the

ratio of flow rate to unit load, each time

that a successful normal-load flow

RATA is performed. The value of Rref

would be reported in the electronic

quarterly report required under § 75.64,

along with the completion date of the

associated RATA. If two load levels

(e.g., mid and high) are designated as

normal, the owner or operator would

determine a separate Rref value for each

normal load level. The reference flowto-load ratio would be calculated as

follows:

R Q

L ref

ref

avg

= ( ) × − 10 5

In the equation above, Rref is the

reference value of the flow-to-load ratio

from the most recent normal-load flow

RATA; Qref is the average stack gas

volumetric flow rate (in scfh) measured

by the reference method during the

normal-load RATA; and Lavg is the

average unit load during the normalload flow RATA. For a common stack,

Lavg would be the sum of the operating

loads of all units that discharge through

the stack. For a unit that discharges its

emissions through multiple stacks or

ducts, Qref would be the sum of the total

volumetric flowrates that discharge

through all of the stacks (or ducts). The

reference flow-to-load ratio would be

rounded off to 2 decimal places.

As an alternative, the owner or

operator could calculate a reference

value of the gross heat rate (GHR) in lieu

of Rref. In order to exercise this option,

quality assured diluent gas (CO2 or O2)

data would have to be available for each

hour of the most recent normal-load

flow RATA. The reference value of the

GHR would be determined as follows:

( ) ( ) GHR Heat Input

L ref

avg

avg

= ×1000

In the equation above, (GHR)ref is the

reference value of the gross heat rate at

the time of the most recent normal-load

flow RATA; (Heat Input)avg is the

arithmetic average hourly heat input

during the normal-load flow RATA; and

Lavg is the average unit load during the

normal-load flow RATA. In calculating

(Heat Input)avg, the average volumetric

flow rate measured by the reference

method during the RATA would be

used in conjunction with the average

diluent gas concentration measured

during the RATA, substituting these

values into the applicable heat input

equation in Appendix F.

After establishing the reference flowto-load or GHR value, an evaluation of

the flow-to-load ratio or GHR would be

required for each primary and

redundant backup flow monitor on a

quarterly basis. The owner or operator

would be required to evaluate the flowto-load ratio in each ‘‘QA operating

quarter’’ (i.e., each quarter in which the

unit or stack operates for at least 168

hours). At the end of each QA operating

quarter, the owner or operator would

calculate the flow-to-load ratio for every

hour during the quarter in which: (1) the

unit (or combination of units, for a

common stack) operated within ±10.0

percent of Lavg, the average load during

the most recent normal-load flow
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28063

RATA; and (2) a quality assured hourly

average flow rate was obtained with a

certified flow rate monitor. The owner

or operator would have the option of

using either bias-adjusted flow rates or

unadjusted flow rates in the hourly

flow-to-load ratios, provided that all of

the ratios were calculated the same way.

EPA had originally considered

proposing that only unadjusted flow

rates should be used to calculate the

flow-to-load ratios. However, in

response to comments received from

CEMS Utility Workgroup members, the

Agency is proposing to allow either

unadjusted or bias-adjusted flow rates to

be used, on the condition that the

acceptance criteria for the flow-to-load

test would be more stringent if biasadjusted flow rates are used (see Docket

A–97–35, Item II–D–82).

For a common stack, the ‘‘load’’ in

each hourly flow-to-load ratio would be

the sum of the hourly operating loads of

all units that discharge through the

stack. For a unit that discharges its

emissions through multiple stacks (or

for a unit that monitors total flow rate

in multiple ducts or breechings), the

‘‘flow’’ in the flow-to-load ratio would

be the combined hourly volumetric flow

rate through all of the stacks (or ducts).

Each hourly flow-to-load ratio would be

rounded off to 2 decimal places.

Alternatively, the owner or operator

could calculate the hourly gross heat

rate (GHR) values in lieu of the hourly

flow-to-load ratios. However, an hourly

GHR could only be determined for those

hours within ±10.0 περψεντ οφ Λavg for

which quality assured flow rate and

diluent gas (CO2 or O2) concentration

data are available from a certified CEMS

or reference method. The owner or

operator could use either bias-adjusted

flow rates or unadjusted flow rates to

determine the hourly GHR values.

The calculated hourly flow-to-load

ratios (or gross heat rates) would be

analyzed at the end of the quarter. A

separate data analysis would be

performed for each primary and each

redundant backup flow rate monitor

used to record and report data during

the quarter. Each analysis would be

based on a minimum of 168 hours of

data. If two RATA load levels are

designated as normal, the analysis

would be performed at the higher load

unless fewer than 168 data points were

available at that load, in which case, the

analysis would be performed at the

lower load. If, for a particular flow

monitor, fewer than 168 hourly flow-toload ratios (or GHR values) were

available at any normal load level, a

flow-to-load (or GHR) evaluation would

not be required for that monitor for that

calendar quarter.

For each flow monitor, Eh, the

difference (absolute value) between each

hourly flow-to-load ratio and Rref, would

be expressed as a percentage of Rref (or,

if the GHR is used, the absolute

difference between each hourly GHR

value and (GHR)ref would be expressed

as a percentage of (GHR)ref). Then, Ef,

the arithmetic average of all of the Eh

values, would be calculated. Note that

Rref would always be based upon the

most recent normal-load RATA, even if

that RATA was performed in the

calendar quarter being evaluated.

The owner or operator would be

required to report the results of each

quarterly flow-to-load (or GHR)

evaluation in the electronic quarterly

report required under § 75.64. The

results of a quarterly flow-to-load (or

GHR) evaluation would be considered

acceptable, and no further action would

be required if the average absolute

percentage difference (Ef) did not

exceed the following limits:

(i) 15.0 percent, if Lavg for the most

recent normal load flow RATA is ≥ 50

megawatts (or ≥ 500 klb/hr of steam)

and if unadjusted flow rates were used

in the calculations;

(ii) 10.0 percent, if Lavg for the most

recent normal load flow RATA is ≥ 50

megawatts (or ≥ 500 klb/hr of steam)

and if bias-adjusted flow rates were

used in the calculations;

(iii) 20.0 percent, if Lavg for the most

recent normal load flow RATA is < 50

megawatts (or < 500 klb/hr of steam)

and if unadjusted flow rates were used

in the calculations;

(iv) 15.0 percent, if Lavg for the most

recent normal load flow RATA is < 50

megawatts (or < 500 klb/hr of steam)

and if bias-adjusted flow rates were

used in the calculations.

If Ef exceeded the applicable limit, the

owner or operator would have two

available options: (1) perform a RATA,

as described in proposed section 2.2.5.2

of Appendix B, unless a monitor

malfunction is diagnosed and corrected,

in which case an abbreviated flow-toload test could be performed, in lieu of

a RATA, in accordance with section

2.2.5.3 of Appendix B and discussed

below; or (2) re-examine the hourly data

used for the flow-to-load or GHR

analysis and recalculate Ef, after

excluding all non-representative hourly

flow rates. If the owner or operator were

to choose option (2), i.e., to recalculate

Ef, only the flow rates for the following

hours would be considered nonrepresentative and could be excluded

from the data analysis:

(1) Any hour in which the type of fuel

combusted was different from the fuel

burned during the most recent normalload RATA. The type of fuel would be

different if the fuel is in a different state

of matter (i.e., solid, liquid, or gas) or is

a different classification of coal (e.g.,

bituminous versus sub-bituminous) than

the fuel burned during the RATA;

(2) Any hour in which an SO2

scrubber was bypassed;

(3) Any hour in which ‘‘ramping’’

occurred, i.e., the hourly load differed

by more than + 15.0 percent from the

load during the preceding hour or the

subsequent hour;

(4) If a normal-load flow RATA was

performed and passed during the

quarter being analyzed, any hour prior

to completion of that RATA; and

(5) If a problem with the accuracy of

the flow monitor was discovered during

the quarter and corrected, any hour

prior to completion of the subsequent

diagnostic test described in proposed

section 2.2.5.3 of Appendix B,

confirming that the corrective actions

were successful.

After identifying and excluding any

non-representative hourly data in

accordance with (1) through (5) above,

the owner or operator could analyze the

remaining data a second time. At least

168 representative hourly ratios or GHR

values at normal load would have to

remain in order to perform the analysis;

otherwise, the flow-to-load (or GHR)

analysis would not be required for that

monitor for that calendar quarter.

If, after re-analyzing the data, Ef is

found to be within the applicable limit

in (i), (ii), (iii), or (iv), above, then no

further action would be required.

However, if Ef is still outside the

applicable limit, the monitor would be

declared out-of-control as of the first

hour of the quarter following the quarter

in which the flow-to-load test was

failed. The owner or operator would

then perform a RATA as described in

proposed section 2.2.5.2 of Appendix B,

unless, as the result of an investigation,

an instrument malfunction is discovered

and corrected as described in proposed

section 2.2.5.1 of Appendix B.

If a problem with the monitor is

identified, all corrective actions (e.g.,

non-routine maintenance, repairs, major

component replacements, relinearization of the monitor, etc.) would

have to be documented in the operation

and maintenance records for the

monitor. Data from the monitor would

remain invalid until a ‘‘probationary’’

calibration error test of the monitor was

passed following completion of all

corrective actions, at which point data

from the monitor would be assigned a

‘‘conditionally valid’’ status. The owner

or operator would then perform an

abbreviated flow-to-load test (found in

proposed section 2.2.5.3 of Appendix B)

to verify that the corrective actions were
28064 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

effective, unless the linearity of the flow

monitor was affected by the corrective

actions (e.g., by the changing of its

polynomial coefficients). If the flow

monitor linearity was affected, the

owner or operator would no longer have

the option of performing the abbreviated

flow-to-load test in section 2.2.5.3 of

Appendix B, but would instead be

required to perform a 3-load

recertification RATA in accordance with

the recertification test period and data

validation procedures of § 75.20(b)(3).

The abbreviated flow-to-load test in

proposed section 2.2.5.3 of Appendix B

is based on a recertification policy

developed jointly by EPA, several utility

representatives, and one flow monitor

vendor (see Docket A–97–35, Items II–

B–1, II–D–70, II–I–9, and II–I–16). Use

of the abbreviated flow-to-load test

would not be limited to situations in

which a quarterly flow-to-load test has

been failed. Rather, the test could be

performed after any documented repair,

component replacement, or other

corrective maintenance to a flow

monitor (except for changes affecting

the linearity of the flow monitor, such

as adjusting the flow monitor

coefficients) to demonstrate that the

repair, replacement, or other corrective

maintenance has not significantly

affected the monitor’s ability to

accurately measure the stack gas

volumetric flow rate. Data from the

monitoring system would be considered

invalid from the hour of commencement

of the repair, replacement, or other

corrective maintenance until the hour in

which a ‘‘probationary’’ calibration error

test is passed following completion of

the repair, replacement, or other

corrective maintenance and any

associated adjustments to the monitor.

The abbreviated flow-to-load test would

have to be completed within 168 unit

operating hours of the probationary

calibration error test (or, for peaking

units, within 30 unit operating days, if

that is less restrictive). Data from the

monitor would be considered

‘‘conditionally valid’’ (as defined in

§ 72.2) beginning with the hour of the

probationary calibration error test.

Following a flow-to-load test failure,

the abbreviated flow-to-load test could

be performed if the investigation into

the cause of the test failure revealed a

problem with the flow monitor and the

problem was subsequently corrected

without having to re-linearize the flow

monitor. The test procedures would be

as follows. The unit(s) would be

operated in such a way as to reproduce,

as closely as practicable, the exact

conditions at the time of the most recent

normal load flow RATA. To achieve

this, the load should be held constant to

within ± 5.0 percent of the average load

during the RATA, and the diluent gas

(CO2 or O2) concentration should be

maintained within ± 0.5 percent CO2 or

O2 of the average diluent concentration

during the RATA. For common stacks,

to the extent possible, the same

combination of units and load levels

that were used during the RATA should

be used. When the process parameters

have been set, a minimum of 6 and a

maximum of 12 consecutive hourly

average flow rates would be recorded

using the flow monitor(s) for which Ef

was outside the applicable limit. For

peaking units, a minimum of 3 and a

maximum of 12 consecutive hourly

average flow rates would be required.

The corresponding hourly load values

and, if applicable, the hourly diluent gas

concentrations would also be recorded.

The flow-to-load ratio or the GHR would

be calculated for each hour in the test

hour period using proposed Equation B–

1 or B–1a in Appendix B. Then, Eh

would be determined for each hourly

flow-to-load ratio or GHR using

proposed Equation B–2 in Appendix B.

Finally, Ef , the arithmetic average of the

Eh values, would be determined.

The results of the abbreviated flow-toload test would be considered

acceptable, and no further action would

be required if the value of Ef did not

exceed the applicable limit specified in

proposed section 2.2.5.1 of Appendix B.

All conditionally valid data recorded by

the flow monitor would then be

considered quality assured, beginning

with the hour of the probationary

calibration error test that preceded the

abbreviated flow-to-load test. However,

if Ef was found to be above the

applicable limit, all conditionally valid

data recorded by the flow monitor

would be considered invalid back to the

hour of the probationary calibration

error test that preceded the abbreviated

flow-to-load test, and a single-load

RATA would be required, in accordance

with proposed section 2.2.5.2 of

Appendix B.

When a single-load RATA is

performed because the owner or

operator is unable to reconcile a

quarterly flow-to-load test failure, either

by excluding non-representative hours

and recalculating Ef or by passing the

abbreviated flow-to-load test after

performing component replacement or

other corrective maintenance on the

flow monitor, then data from the

monitor would remain invalid until the

hour of successful completion of the

single-load RATA.

Rationale

EPA believes that the proposed

methodology for the quarterly flow-toload test is fundamentally sound. It has

been developed through a series of

teleconferences and face-to-face

meetings between EPA, members of the

regulated community, and State and

local agency personnel (see Docket A–

97–35, Items II–D–77, II–D–80, II–D–81,

II–D–82, II–D–85, II–E–23, II–E–24, II–

E–25, II–E–26, and II–E–28). In addition,

some provisions of the flow-to-load test

were revised following pre-proposal

comment. Specifically, the proposal

reflects, in section 2.2.5.1 (b) of

Appendix B to part 75, a commenter’s

request that if a quarterly flow-to-load

test is failed and the monitor

malfunction is discovered and corrected

(without the need to relinearize the

monitor), the correction could be

verified using the abbreviated flow-toload test in lieu of performing a single

load RATA (see Docket A–97–35, Item

II–D–42).

The proposed tolerance limits set

forth in paragraphs (i), (ii), (iii), and (iv)

of section 2.2.5 of Appendix B are

believed to be both reasonable and

achievable. When these tolerance limits

are met, it provides a strong indication

that the flow monitor is still accurate to

within 10.0 percent of the reference

method baseline established during the

last normal-load flow RATA and would,

therefore, appear to be in control with

respect to the relative accuracy

requirements of part 75. An extra

tolerance of 5.0 percent has been

incorporated into the limits to account

for imprecision in the flow-to-load

methodology. An extra 5.0 percent

tolerance has also been added for

smaller units (i.e., normal load less than

50 megawatts or 500 klb/hr of steam),

because the flow-to-load ratio or GHR

for such units is very sensitive to small

variations in load (see Docket A–97–35,

Item II–B–7).

To test the viability of the proposed

tolerance limits, 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 (see

Docket A–97–35, Items II–A–1, II–A–2,

II–A–3). 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.,

baseloaded and peaking units, single

fuel units, and units that burn multiple

fuels). The flow-to-load test was applied

to each unit or stack in the manner

described above, except that no hours

within ± 10.0 percent of Lavg were

excluded from the data analysis. The

data from these same units plus one

additional multiple-stack unit were
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28065

analyzed a second time, with each flowto-load ratio being multiplied by the

diluent gas concentration. This is

similar, but not identical, to calculating

the GHR. Once again, no hours within

± 10.0 percent of Lavg were excluded. In

both analyses, unadjusted flow rates

were used in the ratios. The results of

the two 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 < 5.0

percent). The average value of Ef was 6.1

percent for the analysis without the

diluent gas corrections and 6.4 percent

for the analysis with the diluent gas

corrections. A few units and stacks had

a much lower Ef value when the diluent

correction was applied, but in most

cases, the diluent correction had

relatively little effect. These results

suggest that the flow-to-load test can

provide EPA with the necessary

assurance that flow monitors continue

to generate accurate data from one

RATA to the next. The results also

indicate that the test should be

relatively easy to pass if flow monitors

are properly maintained and operated.

Because of the added quality

assurance that would be provided by

performing the flow-to-load or GHR test

each quarter, EPA has reconsidered the

scope of the other quality assurance

tests for flow monitors. In today’s

proposed rule, the Agency is proposing

to reduce the annual 3-load flow RATA

requirement to a 2-load RATA and to

reduce the frequency of 3-load RATAs

to once every five years (and whenever

a flow monitor is re-linearized). In

addition, single-load flow RATA testing

would be allowed in lieu of the annual

2-load test if the facility could

demonstrate that a unit has operated at

a single load level for at least 85.0

percent of the time in the four ‘‘QA

operating quarters’’ prior to the

scheduled RATA. (See Section N.2 of

this preamble, below, for further

discussion.) The Agency believes that,

taken together, these proposed changes

will reduce the cost and burden of

quality assurance testing for flow

monitors, while ensuring high data

quality. The proposed reduction in the

amount of required RATA testing is

considered feasible because of the

increased quality assurance provided by

the quarterly flow-to-load test. EPA

requests comment on the proposed

revisions to flow monitor quality

assurance requirements.

N. RATA and Bias Test Requirements

Background

Section 6.5 of Appendix A to the

January 11, 1993 rule, as amended on

May 17, 1995 and November 20, 1996,

requires relative accuracy test audits of

all primary and redundant backup SO2,

NOX, CO2, and flow monitoring systems

to be performed during the initial

certification of the CEMS. A RATA

consists of a series of 9 or more

simultaneous test runs, comparing

measurements made by the continuous

monitoring system against an EPA

reference test method. The procedures

for conducting RATAs are found in

section 6.5 of Appendix A to part 75.

Following the initial certification of a

CEMS, section 2.3 of Appendix B to part

75 requires that periodic RATAs of gas

and flow monitors be performed to

quality assure the data from the CEMS

on an on-going basis. The frequency at

which relative accuracy testing is

required depends upon the results of the

last RATA of a monitoring system. Part

75 currently requires RATAs to be

performed semiannually, unless a

monitoring system achieves a low

enough relative accuracy to qualify for

an annual test frequency. The Agency

has always interpreted ‘‘semiannually’’

to mean that the deadline for the next

RATA is the end of the second calendar

quarter following the quarter in which

a RATA is successfully completed, and

‘‘annually’’ to mean that the next RATA

is due by the end of the fourth calendar

quarter following the quarter in which

a RATA is successfully completed. For

monitors installed on peaking units and

bypass stacks, however, the RATA

deadlines are based on operating

quarters, not calendar quarters. That is,

the next RATA is due either at the end

of the second or fourth unit operating

quarter (for peaking units) or bypass

stack operating quarter following the

quarter in which a RATA is successfully

completed.

For SO2, NOX, and CO2 monitors, the

RATAs are to be conducted while the

unit is operating at normal load and

while combusting the fuel that is normal

for the unit. Flow monitor RATAs are to

be conducted at three different loads,

evenly spaced over the operating range

of the unit. When a flow monitor is on

a semiannual RATA frequency, a

normal-load RATA rather than a 3-load

RATA may be conducted to satisfy the

semiannual test requirement, but a 3-

load RATA is still required annually.

Note that for flow monitors installed on

peaking units and bypass stacks, 3-level

flow RATAs are not required; RATAs

are performed only at the normal load.

For SO2, NOX, and flow monitoring

systems, section 7.6 of Appendix A

requires that each time a RATA is

successfully completed, a bias test be

performed to determine if the system

has a low measurement bias. If a

monitoring system fails the bias test, a

‘‘bias adjustment factor’’ (BAF) must be

applied to all subsequent emission data

reported from that monitoring system.

For 3-load flow RATAs, the bias test is

done at the normal load. If a flow

monitor fails the normal-load bias test,

then a BAF must be calculated at each

of the three load levels, and the highest

of the three BAFs is applied to all flow

data reported from the monitor.

When a RATA is due, section 2.3.1 in

Appendix B of the rule allows the

owner or operator two attempts to

achieve an annual RATA frequency

and/or a favorable BAF. If a second

attempt is made, the RATA frequency

and BAF obtained in the second RATA

supersede the results of the first RATA.

Once the RATA frequency has been

established as semiannual or annual,

section 2.3.1 of Appendix B specifies

that (to the extent practicable) the next

RATA of the CEMS may not be done

until at least four months have elapsed.

Finally, § 75.21(a)(6) of the November

20, 1996 rule provides an exemption

from the RATA requirements of part 75

for SO2 monitors installed on units that

burn only natural gas or fuel with a

sulfur content no greater than natural

gas. For units that burn both gas and

higher-sulfur fuel, such as oil, as

primary or backup fuels, § 75.21(a)(5)

requires that the RATA of the SO2

monitor be done when the higher-sulfur

fuel is burned. Section 75.21(a)(7)

further states that calendar quarters in

which only fuel with a sulfur content no

greater than natural gas is burned are to

be excluded in determining the deadline

for the next SO2 monitor RATA.

Two utility groups, UARG and the

Class of ’85, have requested that EPA

consider revising the RATA

requirements of part 75 to make them

more flexible, easier with which to

comply, and less costly. Some of the

possible changes suggested by these

groups are as follows: (1) reduce the

frequency of required RATAs; (2)

determine RATA deadlines based on the

amount of unit operation since the last

RATA, rather than the number of

calendar quarters that have elapsed; (3)

remove the requirement to achieve a

more stringent relative accuracy

standard in order to obtain an annual

RATA frequency; (4) except for initial

certification, allow flow RATAs to be

done at a single load; (5) allow singlepoint sampling during gas RATAs; and

(6) allow a grace period in which to

complete a RATA whenever a deadline

is not met (see Docket A–97–35, items

II–D–20, II–D–30, II–D–65, II–E–13, II–

E–14).
28066 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

Discussion of Proposed Changes

EPA is proposing revisions to the

RATA requirements of part 75 based

upon experience gained through

implementation of the rule and in light

of the recommendations made by the

utility groups. Today’s rulemaking sets

forth the proposed changes, which are

intended to make the RATA

requirements less burdensome without

sacrificing data quality.

1. RATA Frequency

EPA does not propose to revise the

basic semiannual and annual RATA

requirements of part 75 or the incentive

system by which to obtain an annual

RATA frequency (i.e., to obtain the

reduced frequency, a better percentage

relative accuracy is required). Instead,

the Agency proposes to re-define the

terms ‘‘semiannual RATA frequency’’

and ‘‘annual RATA frequency,’’ and to

change the method by which RATA

deadlines are determined.

Today’s rule proposes to amend

section 2.3 of Appendix B so that the

deadline for the next RATA is

determined on the basis of ‘‘quality

assurance operating quarters,’’ rather

than calendar quarters. This change

would apply, with few exceptions, to all

primary and redundant backup

monitoring systems, including monitors

installed on peaking units and bypass

stacks. A ‘‘QA operating quarter’’ would

be defined as a calendar quarter in

which a unit operates for at least 168

hours or, for common-stacks and bypass

stacks, a quarter in which flue gases

discharge through the stack for at least

168 hours.

Any calendar quarter that does not

qualify as a QA operating quarter would

be excluded in determining the deadline

for the next RATA. EPA therefore

proposes to re-define the term

‘‘semiannual RATA frequency’’ to mean

that the next RATA is due at the end of

the second QA operating quarter

following the quarter in which a RATA

is successfully completed. Similarly,

‘‘annual RATA frequency’’ would mean

that the next RATA is due at the end of

the fourth QA operating quarter

following the quarter in which a RATA

is successfully completed.

The QA operating quarter

methodology has been proposed

principally for the benefit of cycling and

peaking units to make the part 75 RATA

requirements easier to meet. The

proposed methodology will not greatly

affect base-loaded units, since they

seldom operate for less than 168 hours

in a quarter. For base-loaded units, the

QA operating quarter method is, in most

instances, equivalent to the familiar

calendar quarter scheme for determining

RATA deadlines. Note, however, that on

occasion a base-loaded unit may obtain

an extended RATA deadline by the QA

operating quarter methodology, e.g.,

when the unit goes into an extended

outage (planned or forced) and

experiences one or more quarters in

which the unit operates for less than

168 hours.

Although the QA operating quarter

method allows RATA deadlines to be

extended by the exclusion of quarters in

which the unit(s) operate for less than

168 hours, such exclusion of calendar

quarters is not without limit. Section

2.3.1.1 of Appendix B proposes to allow

a maximum of eight consecutive

calendar quarters to elapse following the

quarter in which the last RATA was

performed. A RATA would either have

to be performed by the end of the eighth

consecutive elapsed calendar quarter

since the last RATA or within a 720 unit

operating hour ‘‘grace period’’ following

the end of the eighth consecutive

elapsed quarter. Failure to complete a

RATA within the grace period would

cause data from the monitoring system

to become invalid from the hour of

expiration of the grace period until the

hour of completion of a successful

RATA.

Although the proposed QA operating

quarter methodology would serve as the

basis for determining the RATA

deadline for most routine quality

assurance RATAs, there are five notable

instances in the current rule or in

today’s proposal where the RATA

deadline is either not determined solely

on that basis or is determined entirely

on another basis. The first instance is for

a unit that burns both natural gas (or

fuel with equivalent total sulfur content)

and other higher-sulfur fuels as primary

or backup fuels and that uses an SO2

monitor to account for SO2 mass

emissions. Section 75.21(a)(7) of the

current part 75 (redesignated as

§ 75.21(a)(9) in today’s proposal)

specifies that irrespective of the number

of hours of unit operation in the quarter,

any calendar quarter in which natural

gas (or fuel with a total sulfur content

no greater than the total sulfur content

of natural gas) is the only fuel

combusted in the unit (i.e., a ‘‘gas-only’’

quarter) is to be excluded in

determining the deadline for the next

RATA of the SO2 monitoring system.

Section 75.21(a)(5) of the current rule

further states that for such units, the

RATA of an SO2 monitoring system is

to be performed only when the highersulfur fuel is being combusted. Second,

as discussed in section III.N.6 of this

preamble, § 75.21(a)(7) of today’s

proposed rule would conditionally

exempt from SO2 RATA requirements

any unit certified by the designated

representative to burn fuel(s) with a

sulfur content greater than natural gas

only as emergency backup fuel or for

short-term testing, provided that the

annual usage of the higher-sulfur fuel(s)

is kept below 480 hours. However if,

during any quarter, the annual usage of

the higher-sulfur fuel exceeded 480

hours, an SO2 RATA would be required

either in that quarter or during a

subsequent grace period. Thus, for

RATAs of SO2 monitoring systems, it is

evident that the number of unit

operating hours in a calendar quarter is

not the only consideration that

determines the deadline for the next

RATA; the total sulfur content of the

fuel being combusted must also be

considered. Third, as discussed in

section III.O.6 of this preamble, for

certain non-redundant backup

monitoring systems, § 75.20(d) of

today’s proposal would require a

periodic RATA every eight calendar

quarters (rather than QA operating

quarters). Fourth, as discussed in

section III.N.2 of this preamble, under

section 2.3.1.3 of Appendix B in today’s

proposal, 3-level flow RATAs would

have to be performed once in every

period of five consecutive calendar

years (e.g., prior to permit renewal) and

whenever a flow monitor is relinearized. Fifth, as discussed in section

III.O.4 of this preamble, for

recertification RATAs, which are not

regularly scheduled tests, but are done

on an ‘‘as-required’’ basis, § 75.20(b)(3)

of today’s proposal specifies that the

deadline for completing such RATAs

would be 720 unit operating hours after

the start of the recertification test

period.

2. RATA Load Levels

Today’s proposed rule would more

clearly define the load levels at which

RATAs are done in order to provide

greater consistency in the way that

RATAs are performed. The current

provisions of part 75 are neither

sufficiently standardized nor clear in

defining the appropriate RATA load

levels, particularly for flow RATAs. For

example, section 6.5.2 of Appendix A

specifies 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. Also, there is no

minimum required load separation

between the audit points at adjacent

load levels. If adjacent audit points are

too close together, a 3-level flow

evaluation loses its significance. Finally,

while the current rule requires gas and

flow RATAs to be conducted at normal
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28067

load, no definition of normal load is

provided. It could be inferred from the

current section 6.5.2 of Appendix A that

the ‘‘mid’’ load level is considered

normal because it requires the 3-load

RATA to be done at a frequently used

low load, a frequently used high

operating load, and a normal load.

However, experience in implementing

the program has shown that for many

units, the high load level is considered

normal by the facility. For a few units,

low load is considered normal, and for

still others, the normal load can depend

upon the time of day or the season of

the year.

Proposed section 6.5.2.1 of Appendix

A would therefore require the owner or

operator first to define the ‘‘range of

operation’’ for each unit or common

stack equipped with hardware CEMS.

The range of operation would extend

from the minimum safe, stable load to

the ‘‘maximum sustainable load,’’ which

is the higher of: (a) the nameplate

capacity of the unit (less any physical or

regulatory deratings), or (b) the highest

sustainable load, based on at least four

quarters of representative historical

data. For a common stack, the lower

boundary of the range of operation

would be the lowest minimum safe,

stable load for any of the individual

units using the stack. The upper

boundary of the range would be

obtained by adding together the

maximum sustainable loads of all units

using the stack, or if that combined load

is unattainable in practice, by using the

highest sustainable combined load

based on at least four quarters of

representative historical data. Three

load levels would then be defined in

terms of the range of operation. The

‘‘low’’ level would be the lower 30.0

percent of the range; the ‘‘mid’’ level

would be the central portion (30.0

percent to 60.0 percent) of the range;

and the ‘‘high’’ level would be 60.0

percent to 100.0 percent of the range.

Proposed section 6.5.2 of Appendix A

would specify that for multi-level flow

RATAs, the audit points at adjacent load

levels (e.g., low and mid, or mid and

high) must be separated by no less than

25.0 percent of the range of operation.

The owner or operator would be

required to report the upper and lower

boundaries of the range of operation in

the electronic quarterly report required

under § 75.64.

Section 6.5.2.1 of Appendix A in

today’s proposal would further require

the owner or operator to determine, for

each unit or common stack on which

CEMs are installed (except for peaking

units), the two load levels (low, mid, or

high) that are the most frequently used.

The two-fold purpose of this

determination, which would be

required, at a minimum, annually (just

prior to the annual quality assurance

RATAs and in the same calendar quarter

as the RATAs), would be to identify the

normal load level(s) and to identify the

two load levels that are the most

appropriate for annual 2-level flow

monitor audits and for flow monitor

bias adjustment factor calculations. To

make the determination, the owner or

operator would construct an historical

load frequency distribution (e.g.,

histogram), depicting the relative

number of operating hours at each of the

three load levels, low, mid, and high.

The frequency distribution would be

based upon all available data from the

four most recent QA operating quarters,

as defined in proposed section 2.3.1.1 of

Appendix B. The load frequency

distribution would be used to determine

the percentage of the time (to the nearest

0.1 percent) that each load level (low,

mid, and high) has been used in recent

history and thereby to identify the two

most frequently used load levels. A

summary of the data used for these

determinations would be maintained

on-site in a format suitable for

inspection, and the results of the

determinations would be included in

the electronic quarterly report under

§ 75.64. The proposed revisions

discussed in this paragraph would

become effective as of January 1, 2000.

The owner or operator would be

required under proposed section 6.5.2.1

of Appendix A to designate the most

frequently used load level (low, mid, or

high) as the normal load level for each

unit or common stack (except for

peaking units). The owner or operator

would also have the option of

designating the second most frequently

used load level as an additional normal

load level. Today’s proposal would,

therefore, not limit normal load to a

single load level. This way of defining

normal load is particularly appropriate

for units that operate on a diurnal cycle

and units that operate at distinctly

different load levels during different

seasons of the year due to ambient

conditions, electrical demand, etc. EPA

believes that the added flexibility in the

definition of normal load (i.e., not

confining it to a single load level) will

allow the normal-load RATA

requirements of part 75 to be more

easily met. The owner or operator

would be required to identify the

selected normal load level(s) in the

electronic quarterly report required

under § 75.64. For peaking units, the

entire range of operation would, for

simplicity, be considered normal.

Revisions to section 2.3.1.3 of

Appendix B are proposed in today’s

rule, requiring the routine quality

assurance RATAs of flow monitors to be

done as follows. For flow monitors

installed on peaking units and bypass

stacks, no changes are proposed; the

requirement to perform only single-load

flow RATAs at normal load would be

retained. For all other flow monitors,

the routine semiannual and annual

RATAs would be done at 2 loads (i.e.,

the two most frequently used load

levels, as identified in section 6.5.2.1 of

Appendix A), with two exceptions: (1)

the 2-load flow RATA could be

performed alternately with a single-load

flow RATA at the most frequently used

(normal) load level, if the flow monitor

is on a semiannual RATA frequency;

and (2) a single-load flow RATA at the

most frequently used load level could be

performed in lieu of the 2-load RATA if,

for the four QA operating quarters prior

to the quarter in which the RATA is

conducted, the historical load frequency

distribution constructed under section

6.5.2.1 of Appendix A shows that the

unit has operated at the most frequently

used load level for ≥ 85.0 percent of the

time. For all units, the requirement to

perform periodic 3-load flow RATAs

would be retained, but the frequency

would be changed from annual to once

every five calendar years. A 3-load

RATA would also be required whenever

a flow monitor is re-linearized (i.e.,

when its polynomial coefficients are

changed). EPA is proposing to reduce

the required frequency of 3-load RATAs

and to allow limited use of single-load

flow RATA testing principally because

of the added assurance of data quality

that will be provided by the proposed

quarterly flow-to-load test.

3. Flow Monitor Bias Adjustment

Factors

Today’s rulemaking proposes to

change the method of determining the

bias adjustment factor for multiple-load

flow RATAs. For 2-load RATAs (which

would be done at the two most

frequently used load levels as identified

in proposed section 6.5.2.1 of Appendix

A), the bias test would be done at the

load level (or levels) designated as

normal. If the monitor were to fail the

bias test at any load level designated as

normal, a bias adjustment factor (BAF)

would be calculated at both load levels,

and the higher of the two BAFs would

then be applied to the subsequent flow

data. For 3-load RATAs, the bias test

would be required at each load level

designated as normal under proposed

section 6.5.2.1 of Appendix A. If the

bias test were failed at any load level

designated as normal, BAFs would be

calculated only at the two most

frequently used load levels (not all three
28068 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

levels), and the higher of the two BAFs

would be applied to subsequent flow

data. Thus, for all multiple-load flow

RATAs, the appropriate BAF would be

determined in the same way. For 3-load

RATAs, this methodology for

determining the BAF when the normalload bias test is failed differs from the

current rule, which requires the highest

BAF from any of the three levels to be

applied to subsequent data. Experience

gained in the first few years of program

implementation has shown that in many

instances, the highest BAF has been

from a load level that is seldom used

(generally the low load level), which

can result in an unrepresentatively high

BAF being applied to the normal-load

flow rate data.

4. Number of RATA Attempts

Section 2.3.1.4 of Appendix B to

today’s proposed rule would remove the

restriction limiting to two the number of

RATA attempts that may be done to

achieve an annual RATA frequency. In

addition, the requirement that

successive RATAs be conducted no less

than 4 months apart would be removed

from section 2.3.1 of Appendix B. The

proposed rule would conditionally

allow the owner or operator to perform

as many RATAs as are necessary to

achieve a better relative accuracy

percentage or a more favorable bias

adjustment factor, the condition being

that the data validation procedures for

RATAs in proposed section 2.3.2 of

Appendix B would have to be followed

(these procedures are discussed in detail

in Section II.O of this preamble, ‘‘CEM

Data Validation’’). The Agency believes

that this extra flexibility will provide an

incentive for owners or operators to

optimize CEMS performance and to

eliminate bias from their monitoring

systems and to reduce the frequency of

the required RATAs.

5. Concurrent SO2 and Flow RATAs

Today’s proposed rulemaking would

delete the requirement for concurrent

SO2 and flow RATA testing from § 6.5

of Appendix A. This requirement was

included in the January 11, 1993 rule in

order to generate a data base from which

EPA could determine the

appropriateness of setting a combined

flow rate-SO2 system relative accuracy

specification. Section 3.3.5 of Appendix

A was reserved for this future standard,

which, if promulgated, would have

become effective on January 1, 2000.

After three years of program

implementation, data collection, and

evaluation, however, the Agency

believes it is not appropriate or

necessary to propose a combined flow

rate-SO2 system relative accuracy

standard. Instead, EPA believes it would

be more appropriate to retain the

individual relative accuracy

specifications for the SO2 and flow

monitors. Because the historical relative

accuracy percentages of the individual

component monitors have proven to be

so low (i.e., average relative accuracy

less than 5.0 percent for the period from

the first quarter of 1995 through the

second quarter of 1996), the Agency

believes that it is not necessary to

promulgate the combined standard (see

Docket A–97–35, Item II–I–27). Data

analysis from an EPA study (see Docket

A–97–35, Item II–I–14) indicates that

quality assuring the individual

component monitors to 7.5 percent

relative accuracy (the RA value needed

to qualify for an annual RATA

frequency) effectively ensures that a

combined flow rate-SO2 standard of 10.0

to 15.0 percent relative accuracy will be

consistently achieved. That same study

also indicates that meeting a combined

flow rate-SO2 standard of 10.0 percent

does not necessarily ensure that the

individual component monitor relative

accuracies will be ≤ 10.0 percent. In

view of this and given that flow

monitors are also used to calculate heat

input and CO2 mass emissions, the

Agency believes it is appropriate to

maintain individual relative accuracy

standards for the flow monitor and SO2

monitor. EPA solicits comment on its

proposed treatment of this issue.

6. SO2 RATA Exemptions and Reduced

Requirements

Today’s proposed rulemaking would

clarify the RATA requirements for units

that burn principally natural gas and

other very low-sulfur fuels. In

§ 75.21(a)(6) of the November 20, 1996

rule, an exemption from SO2 RATA

requirements was provided for units

that have SO2 monitors and exclusively

burn natural gas (or fuels with a sulfur

content no greater than natural gas).

Today’s proposed rule would clarify

this exemption from SO2 RATAs by

interpreting the term ‘‘fuel with a total

sulfur content no greater than the total

sulfur content of natural gas’’ to mean

any type of fuel that has a total sulfur

content of less than or equal to 0.05

percent sulfur by weight. The rationale

for this is as follows. In order to meet

the definition of natural gas in § 72.2,

the total sulfur content of the gas cannot

exceed 20 grains/100 scf. When this

sulfur content is converted to a weight

percentage, it comes out slightly higher

than 0.05 percent sulfur by weight (see

Docket A–97–35, Item II–B–14).

Consequently, for a unit that has an SO2

monitor and for which the designated

representative certifies that the unit

burns only fuels (whether solid, liquid,

or gaseous) with a total sulfur content of

> 0.05 percent sulfur by weight, the SO2

monitor would be exempted from the

part 75 RATA requirements. The

Agency takes comment on this approach

and on whether 0.05 percent sulfur by

weight is an appropriate applicability

threshold for fuels other than natural

gas.

Finally, § 75.21(a)(7) of today’s rule

proposes reduced RATA requirements

for units with SO2 monitors for which

the designated representative certifies

that the units burn fuel(s) with a total

sulfur content greater than the total

sulfur content of natural gas (e.g.,

distillate oil) only as emergency backup

fuel(s) and/or for short-term testing. For

such units, RATA testing of the SO2

monitor would only be required if fuel

with a total sulfur content greater than

the total sulfur content of natural gas

(i.e., > 0.05 percent sulfur by weight) is

combusted for more than 480 hours in

a calendar year. If the higher-sulfur fuel

usage were to exceed 480 hours in a

particular year, then an SO2 RATA,

conducted while burning the highersulfur fuel, would be required either by

the end of the quarter in which the

exceedance occurred or within a 720

unit operating hour grace period

following that calendar quarter. In this

instance, if the grace period were used,

proposed section 2.3.3 in Appendix B

would specify that it would begin with

the first unit operating hour in which

the higher-sulfur fuel is combusted in

the unit, following the calendar quarter

in which the annual usage of the highersulfur fuel exceeded 480 hours. The

480-hour criterion for maintaining an

SO2 RATA exemption is consistent with

many state and local air permits which

contain a similar exemption from

particulate emission testing for gas-fired

units that burn oil for only 400 to 500

hours per year (see Docket A–97–35,

Item II–E–23). EPA believes that these

provisions would effectively eliminate

the need to start up a unit and/or to

burn an infrequently used,

uneconomical, and higher-emitting fuel

solely for the purpose of performing a

RATA of the SO2 monitor.

7. QA Provisions for SO2 Monitors, for

Natural Gas Firing or Equivalent

In § 75.11(e) of the November 20, 1996

revisions to part 75, three SO2

compliance options were promulgated

for units with SO2 CEMS during hours

in which only natural gas (or gaseous

fuel with a total sulfur content no

greater than the total sulfur content of

natural gas) is burned. One of the

compliance options was to allow the use

of an SO2 monitoring system, subject to
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certain restrictions and quality

assurance provisions. The restrictions

and QA provisions, which are found at

§§ 75.11(e)(3)(i) through (iv), are as

follows: (i) a calibration gas with a

concentration of 0.0 percent of span

must be used for daily calibration error

tests of the CEMS; (ii) the response of

the monitoring system to the 0.0 percent

calibration gas must be adjusted to read

exactly 0.0 ppm each time that a daily

calibration error test is passed; (iii) any

hourly average of less than 2.0 ppm

recorded by the SO2 monitor while fuel

is being combusted in the unit(s)

(including zero and negative averages)

must be reported as a default value of

2.0 ppm; and (iv) if a unit combusts

only natural gas (or gaseous fuel with a

total sulfur content no greater than the

total sulfur content of natural gas) and

never combusts any other type of fuel,

the SO2 monitor span must be set to a

value not exceeding 200.0 ppm.

Compliance with conditions (i) through

(iv) is required by January 1, 1999,

except that conditions (i) and (ii) are

always optional for units that combust

natural gas only during unit startup.

The provisions in §§ 75.11(e)(3)(i)

through (iv), as presently codified,

apply only to the combustion of gaseous

fuel with a total sulfur content no

greater than the total sulfur content of

natural gas. However, as noted above

(under ‘‘SO2 RATA Exemptions and

Reduced Requirements’’), today’s

proposed rulemaking would add an

interpretation of the term ‘‘fuel with a

total sulfur content no greater than the

total sulfur content of natural gas’’ to

§ 75.21(a)(6). The term would include

any fuel (whether solid, liquid, or

gaseous) with a total sulfur content of ≤

0.05 percent by weight. EPA believes

that it is appropriate to apply the quality

assurance and reporting provisions in

§§ 75.11(e)(3)(i) through (iv) to the

combustion of all fuels with a total

sulfur content ≤ 0.05 percent by weight.

Therefore, in today’s proposed rule, a

new section, § 75.21(a)(8) would be

added, extending the QA provisions of

§§ 75.11(e)(3)(i) through (iv) to the

combustion of all types of fuels with a

total sulfur content no greater than the

total sulfur content of natural gas. The

new requirements would become

effective on January 1, 2000.

Note that EPA has reconsidered one of

the four QA provisions for the use of an

SO2 monitor during natural gas (or fuel

with equivalent total sulfur content)

combustion in §§ 75.11(e)(3)(i) through

(iv). Specifically, the Agency believes

that § 75.11(e)(3)(ii), which requires a

daily adjustment of the monitor’s

calibration to read exactly 0.0 ppm, may

be too stringent because in practice it

can be very difficult to attain a reading

of exactly 0.0 ppm with a zero-level

calibration gas, particularly when

manual calibration adjustments are

made. Therefore, today’s rulemaking

proposes to revise § 75.11(e)(3)(ii) as

follows. Rather than requiring a daily

adjustment of the SO2 monitor’s

calibration, an adjustment would only

be required when the ‘‘as-found’’

response of the monitor to the zero gas

during a daily calibration error test

exceeded the performance specification

of the instrument (i.e., ±2.5 percent of

span). And instead of requiring the

calibration to be adjusted to exactly 0.0

ppm, the procedures for routine

calibration adjustments in proposed

section 2.1.3 of Appendix B would be

followed, to bring the ‘‘as-left’’ response

of the instrument (i.e., the response

during the additional calibration error

test required by proposed section 2.1.3

of Appendix B) ‘‘as close as practicable’’

to the true value of the zero gas (0.0

ppm).

The Agency solicits comment on the

proposed approach for QA provisions

for SO2 CEMS for gas-firing or

equivalent.

8. General RATA Test Procedures

Under today’s proposal, sections 6.5,

6.5.1, and 6.5.2 of Appendix A, which

describe the general requirements for

RATAs, would be extensively revised.

Some of the proposed changes are

simply structural, but others are

substantive. For instance, as previously

discussed above under ‘‘Concurrent SO2

and Flow RATAs,’’ the requirement to

perform concurrent SO2 and flow

RATAs would be deleted from the

regulation. Further, section 6.5 would

now recognize that more than one type

of fuel and more than one monitor range

may be considered normal for a

particular unit. Also, the requirement to

complete each RATA within 7

consecutive calendar days would be

modified to require that the RATA be

completed within 168 unit operating

hours (for single-load flow RATAs and,

to the extent practicable, for 2-load and

3-load flow RATAs). However, for the

multiple-load flow RATAs, up to 720

unit operating hours would be allowed,

if necessary, to complete the testing.

This is consistent with Agency guidance

published in March, 1995, Policy

Question 8.15 of the Acid Rain Policy

Manual, which discusses allowing up to

30 calendar days to complete all three

levels of a 3-load flow RATA (see

Docket A–97–35, Item II–I–9). Even

though the policy says the RATAs at the

individual load levels should be

completed within 7 days, thirty days are

acceptable to complete the 3-load RATA

in order to account for the possibility

that the unit might shut down in

between levels of the RATA or that

certain load levels may be difficult to

attain and to hold. Today’s proposal

would allow 720 unit operating hours

(irrespective of the number of calendar

days) to complete a multiple-load flow

RATA. EPA believes that this proposed

requirement provides greater flexibility

than currently allowed.

Sections 6.5.1 and 6.5.2 of Appendix

A would be re-titled ‘‘Gas Monitoring

Systems (Special Considerations)’’ and

‘‘Flow Monitor RATAs (Special

Considerations),’’ respectively.

Proposed section 6.5.1 contains a

recommendation that, for initial monitor

certifications, the RATA not be

commenced until all of the other

certification tests have been completed.

Section 6.5.2 would be amended, as

previously discussed under ‘‘Flow

RATA Load Levels.’’ The definition of

normal load would be revised and the

number of loads and the load levels at

which flow RATAs are to be performed

would be more clearly defined.

Today’s rule proposes changes to

section 6.5.6 of Appendix A, which

pertains to RATA traverse point

selection. Proposed section 6.5.6 would

allow the following alternative reference

method measurement point locations.

For all moisture determinations, a single

reference method point, located at least

1.0 meter from the stack wall, could be

used. For gas RATAs, the owner or

operator would have four options: (1) at

any location (including locations where

stratification is expected), a minimum of

six traverse points along a diameter,

located in accordance with Method 1 in

Appendix A to part 60, could be used;

(2) at locations where stratification is

not expected and section 3.2 of

Performance Specification No. 2 (‘‘PS

No. 2’’) in Appendix B to part 60 allows

the use of a short reference method

measurement line (with three points

located at 0.4, 1.0, and 2.0 meters from

the stack wall), the owner or operator

could use an alternative 3-point

measurement line, locating the three

points 4.4 percent, 14.6 percent and

29.6 percent of the way across the stack,

in accordance with Method 1 in

Appendix A to part 60; (3) at locations

where stratification is expected (i.e.,

after a wet scrubber or when dissimilar

gas streams are combined), the short

measurement line from section 3.2 of PS

No. 2 (or the alternative line described

in option (2) above) could be used in

lieu of the ‘‘long’’ measurement line

prescribed in section 3.2 of PS No. 2,

provided that a stratification test is

performed prior to each RATA at the

location and certain acceptance criteria
28070 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

are met; and (4) 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. EPA’s Office

of Air Quality Planning and Standards

(OAQPS) has endorsed the use of the

Method 1 traverse points as an

alternative to the points prescribed by

PS No. 2 (see Docket A–97–35, Item II–

C–22).

Regarding option (3) above, one utility

and one stack testing firm have

requested that EPA allow the short

measurement line to be used at

scrubbed unit stacks, citing logistical

difficulties and safety concerns

associated with using the long

measurement line prescribed by PS No.

2 for sampling locations following wet

scrubbers (see Docket A–97–35, Items

II–D–66, II–D–78). Both parties

appeared willing to perform

stratification testing to demonstrate that

the gas streams are not significantly

stratified. EPA responded to these

requests by issuing policy guidance

which discusses allowing the short

measurement line to be used for

scrubbed units, provided that

stratification test results show the

stratification at the sampling location to

be minimal (see Docket A–97–35, Item

II–I–9, Policy Manual, Question 8.25).

Regarding single-point RATA testing

(option (4), above), which utility groups

asked EPA to consider, today’s proposed

rule would allow it on the condition

that a stratification test at the sampling

location demonstrates stratification to

be essentially absent.

Sections 6.5.6.1 and 6.5.6.2 of

Appendix A in today’s proposed rule

provide two stratification test protocols

which may be used to demonstrate that

a sampling location qualifies for the

alternative RM measurement point

locations allowed under proposed

section 6.5.6 (i.e., options (3) and (4),

above). The first stratification test

protocol, in proposed section 6.5.6.1, is

based upon technical guidance issued

by OAQPS (see Docket A–97–35, Item

II–I–3) and would consist of measuring

the SO2, NOX, and diluent gas

concentrations at a minimum of 12

traverse points, located in accordance

with Method 1 in Appendix A to part

60. The gas concentration measurements

would be made using Reference

Methods 6C, 7E, and 3A in Appendix A

to part 60. The average NOX, SO2, and

CO2 (or O2) concentration at each of the

individual traverse points would be

determined, and the arithmetic average

NOX, SO2, and CO2 (or O2)

concentrations for all traverse points

calculated. This 12-point test would

have to be passed one time at the

sampling location under consideration.

Once the 12-point test has been passed

at the candidate sampling location, the

second (abbreviated) stratification test

protocol, in proposed section 6.5.6.2,

could be done prior to subsequent

RATAs at the location in lieu of the 12-

point test. The abbreviated test would

be done either at 3 points (located in

accordance with the long measurement

line in PS No. 2) or at 6 points along a

diameter (located according to EPA

Method 1 in Appendix A to part 60).

The acceptance criteria for the

stratification test results are given in

proposed section 6.5.6.3 of Appendix A.

For each pollutant or diluent gas, the

short 3-point reference method

measurement line specified in section

3.2 of PS No. 2 (or the alternative 3-

point line described in proposed section

6.5.6 of Appendix A) could be used for

that pollutant or diluent gas in lieu of

the long measurement line in section 3.2

of PS No. 2, if the concentration at each

individual traverse point differed by no

more than ±10.0 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 ±5.0 ppm or 0.5 percent

CO2 (or O2) from the arithmetic average

concentration for all traverse points.

Further, for each pollutant or diluent

gas, a single reference method

measurement point located at least 1.0

meter from the stack wall could be used

for that pollutant or diluent gas, 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. Finally, proposed

section 6.5.6.3 would require the owner

or operator to keep the results of all

stratification tests on-site, suitable for

inspection, as part of the supplementary

RATA records required under

§ 75.56(a)(7) and § 75.59(a)(7).

Today’s rule also proposes to clarify

the sampling strategy for RATAs in

section 6.5.7 of Appendix A. The

proposed revisions make it clear that for

gas monitor RATAs, the minimum time

per run is 21 minutes, and all of the

necessary data for each run (i.e.,

pollutant concentration measurements

and, if applicable, diluent concentration

data and moisture measurements)

would have to be collected, to the extent

practicable, within a 60-minute period.

The proposed revisions would also

require the pollutant and diluent

concentration measurements to be made

simultaneously during RATAs of SO2/

diluent and NOX/diluent monitoring

systems. For flow monitor RATAs, the

minimum time per run would be 5

minutes. A requirement to properly

account for flow pulsations (e.g., by

sight-weighted averaging) at each

velocity traverse point would be added,

as well as a clear statement that

successive flow RATA runs may be

done as rapidly as practicable, with no

required waiting period between runs.

Proposed section 6.5.7 of Appendix A

states that a minimum of one set of

auxiliary data (moisture and diluent gas

measurements) would have to be

collected for every three RATA runs or

for every clock hour of a flow RATA

(whichever is less restrictive). A related

change to § 75.22(a)(4) is also proposed,

which would allow the alternative

moisture measurement techniques

described in section 1.2 of Method 4 in

Appendix A to part 60 to be used for

stack gas molecular weight

determinations.

9. Reference Method Testing Issues

Discussion of Proposed Changes

Currently, § 75.22 specifies several

reference methods (Reference Methods

2, 2A, 2C, or 2D) as appropriate methods

for determining volumetric flow under

part 75. The Agency is currently

conducting a study of the accuracy of

Reference Method 2 to determine

whether changes to Method 2 or the

addition of other alternatives to the

Method are appropriate. Thus, the

Agency anticipates that, in the future,

revisions to Method 2 in part 60 may

create alternatives beyond the specific

reference methods specified in

§ 75.22(a)(2). Therefore, in § 75.22(a)(2),

EPA proposes to add: ‘‘or its allowable

alternatives, except for 2B and 2E’’ to

Method 2 to automatically incorporate

into part 75 anticipated future revisions

to the Method 2 requirements in

Appendix A to part 60.

Section 75.22 specifies a number of

instrumental reference methods from

Appendix A to part 60 (Reference

Methods 3A, 6C, 7E, and 20) as

appropriate test methods for conducting

CEMS performance tests under part 75.

These methods require the use of

calibration gases to calibrate the

reference analyzers. Currently, however,

part 60 does not require that EPA

protocol gas be used when performing

instrumental reference methods. The

Agency believes that protocol gas

should be used when performing

instrumental reference methods in order
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28071

to achieve accurate results. Therefore,

proposed § 75.22(c)(1) would state that,

for purposes of part 75, instrumental

reference methods must be performed

using calibration gases as defined in

section 5 of Appendix A to part 75.

10. Alternative Relative Accuracy

Specifications and Specifications for

Low-Emitters

One utility group has suggested to

EPA (see Docket A–97–35, Item II–E–13)

that there is inconsistency and apparent

inequity in the relative accuracy

specifications for units that qualify as

low emitters of NOX and SO2 (i.e.,

sources with average SO2 concentrations

of 250.0 ppm or less and/or average

NOX emission rates of 0.20 lb/mmBtu or

less). Specifically, they have questioned

the appropriateness of the alternative

relative accuracy specifications used to

determine the RATA frequency (i.e.,

semiannual or annual). Under section

3.3 of Appendix A and section 2.3.1 of

Appendix B to the current part 75 rule,

the RATA frequency for an SO2 monitor

installed on a low-emitting SO2 source

may be determined in either of two

ways: by the normal relative accuracy

specification (i.e. the RATA frequency is

semiannual if the relative accuracy is >

7.5 percent but ≤ 10.0 percent, and

annual if ≤ 7.5 percent relative accuracy

is achieved), or by the alternative

specification (i.e., the RATA frequency

is semiannual if the reference method

mean value and CEMS mean value

differ by > 8.0 ppm but ≤ 15.0 ppm, and

annual if the two mean values differ by

≤ 8.0 ppm). For low-emitting NOX

sources, the RATA frequency for the

NOX monitoring system is determined

in the identical manner to SO2 when the

normal specification is applied. For the

alternative specification, the NOX RATA

frequency is semiannual if the CEMS

and reference method mean values

differ by ≤ 0.01 lb/mmBtu but ≤ 0.02 lb/

mmBtu, and annual if the mean values

differ by > 0.01 lb/mmBtu. The 8.0 ppm

value for SO2 was originally determined

based on the performance of a single set

of monitors at a facility regulated under

subpart Da of the NSPS in part 60.

However, in the first few years of Acid

Rain Program implementation, many

part 75 utilities with wet scrubbers have

found it difficult to consistently meet

the 8.0 ppm criterion for obtaining an

annual RATA frequency.

The utility group maintains that since,

when the normal relative accuracy (RA)

specification is applied, the criterion for

obtaining an annual RATA frequency is

to achieve a relative accuracy 25.0

percent below the RA specification in

section 3.3 of Appendix A (i.e., 7.5

percent RA is 25.0 percent below the

specification of 10.0 percent), the

criterion for an annual RATA frequency

should be essentially the same when the

alternative specification is applied.

Under the current rule, the alternative

SO2 specification requires that the mean

CEMS and reference method values

differ by no more than 8.0 ppm in order

to obtain an annual RATA frequency.

This is 47.0 percent below the 15.0 ppm

alternative RA specification. Similarly

for NOX, the alternative NOX

specification for an annual RATA

frequency requires the difference

between the CEMS and reference

method mean values to be ≤ 0.01 lb/

mmBtu, or 50.0 percent below the 0.02

lb/mmBtu alternative RA specification.

EPA agrees that the alternate RA

specifications for low emitters of SO2

and NOX appear to be somewhat

inequitable, and today’s rulemaking

proposes changes to these

specifications. In proposed section 2.3.1

of Appendix B, the alternative relative

accuracy specification for low emitters

of SO2, (i.e., the difference between the

reference method and CEMS mean

values) that must be met by an SO2

monitor in order to obtain an annual

RATA frequency would be changed

from 8.0 ppm to 12.0 ppm. For low

emitters of NOX, the alternative low

emitter relative accuracy specification

that must be met by a NOX-diluent

monitoring system in order to obtain an

annual RATA frequency would be

changed from 0.01 lb/mmBtu to 0.015

lb/mmBtu.

In today’s rule, EPA is also proposing

an alternative relative accuracy

specification of 0.025 lb/mmBtu for

SO2-diluent monitoring systems to

obtain an annual RATA frequency and

an alternative relative accuracy

specification of ±0.7 percent CO2 or O2,

by which CO2 and O2 monitors could

obtain an annual RATA frequency.

During the investigation of the

alternative RA specifications for the SO2

and NOX-diluent monitoring systems,

the Agency noted that for SO2-diluent

systems, part 75 specifies only an

alternative RA criterion of 0.030 lb/

mmBtu for a semiannual RATA

frequency, but fails to specify a

corresponding alternative RA criterion

for obtaining an annual RATA

frequency. Similarly, for CO2 and O2

monitors, EPA noted that an alternative

relative accuracy specification of ±1.0

percent CO2 or O2 (in terms of the mean

difference between the reference

method and CEM values during the

RATA) is given for obtaining a

semiannual RATA frequency, but no

corresponding alternative criterion is

given for obtaining an annual frequency.

EPA notes that in order to make the

annual RATA frequency criteria for

NOX-diluent and SO2-diluent

monitoring systems more equitable, a

third decimal place is required.

However, §§ 75.54 and 75.55 currently

require NOX and SO2 emission rates in

lb/mmBtu to be reported only to 2

decimal places. Therefore, revisions are

being proposed, see §§ 75.57(d)(6) and

75.58(a)(1)(iv), to require that, beginning

on January 1, 2000, all NOX emission

rates in lb/mmBtu must be reported to

three decimal places. Prior to January 1,

2000, the owner or operator would have

the option of reporting NOX emission

rates to either two or three decimal

places. Note that no corresponding

change is being proposed for the

reporting of SO2 emission rates in lb/

mmBtu, since such emission rates will

only be reported to EPA by units that

have installed Phase I Qualifying

Technologies for a three-year period

(1997–1999), and are not required to be

reported thereafter. EPA solicits

comments on the appropriateness of

requiring all NOX lb/mmBtu emission

rates to be reported to three decimal

places. The Agency favors this

approach, particularly for quality

assurance purposes, due to increased

precision in the calculation of RATA

results. The Agency notes that this

proposed change would not affect the

way in which compliance with the NOX

emission limits under part 76 is

determined. Compliance with part 76

NOX limits, in lb/mmBtu, would still be

based on two decimal places.

All of the proposed revisions to the

part 75 relative accuracy specifications

in today’s rulemaking are summarized

in proposed Figure 2 of Appendix B.

11. Bias Adjustment Factors for Low

Emitters

As discussed in the preceding section,

sources that qualify as low emitters of

SO2 and/or NOX have two ways to

evaluate the relative accuracy of SO2

and NOX monitoring systems: (a) by the

normal relative accuracy specification

(i.e., 10.0 percent RA), and (b) by the

alternative RA specification (i.e., the

difference between the mean CEMS and

reference method values is within ±15.0

ppm for SO2 low emitters, or within

±0.02 lb/mmBtu for NOX low emitters).

The normal RA is determined by a

statistical analysis of the reference

method and CEMS data from the RATA.

Mathematically, the normal RA is the

sum of the absolute values of the mean

difference (dmean) and the confidence

coefficient (cc), expressed as a

percentage of the mean reference

method value (RM)avg. The mean

difference indicates how closely the

CEMS measurements agree with the
28072 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

reference method and is generally the

principal contributor to the percentage

relative accuracy in the RA equation.

The confidence coefficient (cc) is a

statistical term related to the standard

deviation and is an indicator of the

amount of scatter in the data.

Section 7.6 of Appendix A requires a

bias test of each SO2 and NOX

monitoring system whenever a RATA of

the CEMS is performed. If the mean

difference is greater than the absolute

value of the confidence coefficient, the

CEMS measurements are systematically

lower than the corresponding references

method measurements, i.e., the

monitoring system has a low bias. In

such cases, sources are given two

options. The first, preferred by EPA, is

to locate and eliminate the source of the

measurement bias in the instrument.

The second option is to apply a bias

adjustment factor (BAF). This

alternative was developed in response

to an industry request to provide an

alternative for sources that choose not to

expend the effort to locate and eliminate

the technical problem causing the

systematic measurement error. The BAF

is equal to 1.000 + |dmean| /(CEM)avg,

where (CEM)avg is the mean value of the

CEMS measurements from the RATA.

At least one utility has questioned

whether it is appropriate for low

emitters to calculate a BAF in the usual

way when a CEMS fails a RATA by the

normal RA specification, but passes by

the alternative specification, because in

such cases the BAF can become

inordinately high, particularly at very

low emission levels (see Docket A–97–

35, Items II–D–62 and II–E–23). Since

both the percent relative accuracy and

the BAF are based upon the same

statistical terms (dmean and cc), the

utility questions whether the standard

calculation procedure for the BAF is

adequate to determine a meaningful

BAF for low emitters. Just as the value

obtained from the standard relative

accuracy equation tends to become large

for low emitters, so, too, the BAF is seen

as becoming inordinately large for low

emitters which use the current BAF

equation.

As this comment suggests, it is not

uncommon for an SO2 or NOX CEMS

installed on a low-emitting unit to fail

a RATA by the normal specification of

10.0 percent RA and to pass the same

RATA by the alternative RA

specification. For instance, suppose that

the mean RM and CEMS values during

an SO2 RATA of a low emitter are 51.0

ppm and 40.0 ppm, respectively, and

that dmean is 11.0 ppm and the

confidence coefficient is 0.50. Suppose

further that the bias test is failed. Then,

the percent RA by the normal

specification (i.e., |dmean| + |cc | /

(RM)avg) would exceed 20.0 percent,

indicating a failed RATA, but the

alternative RA specification would

indicate a pass (i.e., (CEMS)avg is within

±15.0 ppm of (RM)avg). In this same

illustration, the BAF would be 1 + 11 /

40 = 1.275.

In fact, if it is assumed that the

difference between the CEMS and the

reference method measurements does

not decrease as emissions decline, then

the lower the SO2 or NOX emissions, the

more likely it is for the CEMS to fail the

normal relative accuracy specification

because the mean difference becomes a

larger percentage of the average

reference method value. It was precisely

in response to such concerns that the

alternative relative accuracy

specifications were originally included

in part 75.

Today’s rule proposes to provide an

option in the way the BAF is

determined for low emitters of SO2 and

NOX. Low emitters of SO2 and NOX

would be given the choice of using

either: (a) the normal BAF calculation

procedure described above and found in

Equation A–12, section 7.6.5 of

Appendix A, or (b) an alternative

default bias adjustment factor of 1.111.

The justification is as follows: for

units that meet the normal relative

accuracy standard of RA ≤ 10.0 percent,

the theoretically maximum possible

Bias Adjustment Factor is 1.111 (see

Docket A–97–35, Item II–B–2).

Therefore, low-emitting units meeting

the alternative relative accuracy

standards (|dmean| ≤ 15.0 ppm for SO2

low emitters and |dmean| ≤ 0.02 lb/mmBtu

for NOX low emitters) should not have

to apply a bias adjustment any higher

than the maximum BAF value

applicable to units meeting the normal

relative accuracy standard. EPA solicits

comment on allowing the alternative

BAF of 1.111 for low-emitting units.

12. Clarification of Diluent Monitor

Certification Requirements

Today’s proposed rule would clarify

the certification requirements for

diluent gas (CO2 and O2) monitors, in

response to comments received on the

pre-proposal draft of the rule (see

Docket A–97–35, Item II–D–52). Section

75.20(c)(1)(iii) of the current rule

requires a RATA of each NOX

continuous monitoring system to be

done for initial certification. Even

though the NOX system consists of two

component monitors (NOX

concentration and diluent gas), the

required RATA is done on a system

basis in units of lb/mmBtu. Separate

RATAs of the individual component

monitors are not required, except when

the diluent component monitor is also

used as a CO2 pollutant concentration

monitor or to account for unit heat

input, in which case § 75.20(c)(5)(iii) in

the current rule requires a RATA of the

diluent monitor. To be sure that this is

clear, today’s proposed rule would add

a statement to § 75.20(c)(1)(iii),

indicating that the RATA for the NOXdiluent system shall be done on a

system basis (i.e., individual component

RATAs are unnecessary for certification

of a NOX-diluent system). Therefore,

units that have installed NOX

monitoring systems, but that use

Appendix D for SO2 emission

accounting and Appendix G for CO2

accounting, would not be required to

submit separate RATA results for the

diluent monitor.

A second point of clarification would

be added in proposed § 75.20(c)(3),

which was previously designated as

§ 75.20(c)(4). The new section would

make it clear that when a diluent

monitor (O2 or CO2) is used both as a

CO2 pollutant concentration monitor

and for heat input determinations, only

one set of diluent monitor certification

test results would have to be submitted

under the component and system ID

codes of the CO2 monitoring system.

This is appropriate because there is no

such thing as a ‘‘heat input monitoring

system’’ or an ‘‘oxygen monitoring

system’’ under part 75.

13. Daily Calibration Requirements for

Redundant Backup Monitors

Section 75.20(d)(1) of the current rule

requires redundant backup (‘‘hotstandby’’) monitoring systems to be

operated during all periods of unit

operation and to meet all of the quality

assurance requirements of Appendix B,

including daily calibrations and

interference checks, quarterly linearity

checks and leak checks, and semiannual

or annual RATAs. One commenter on a

pre-proposal draft of today’s proposed

rule requested that EPA consider

changing the daily calibration

requirement for redundant backup

monitors (see Docket A–97–35, Item II–

D–35). The commenter recommended

that the daily calibrations be made

mandatory only for days on which the

redundant backup monitoring system is

actually used to report emission data to

EPA. Daily calibrations would be

optional on all other days. Fewer

calibrations of redundant backup

systems would considerably reduce

calibration gas consumption. The

commenter estimated that this change

could result in an annual savings of

more than $100,000 for his company.

EPA agrees that the request is

reasonable, provided that the redundant
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28073

backup systems are kept on hot-standby

and are calibrated prior to each use for

reporting. The Agency therefore

proposes to amend § 75.20(d)(1)

accordingly.

14. Daily Performance Specification and

Control Limits for Low-Span DP Flow

Monitors

Section 3.1 of Appendix A of the

current rule gives the calibration error

performance specification for flow

monitors. Section 2.1.4 of Appendix B

gives the calibration error limits for

daily operation of flow monitors. For

initial certification, a flow monitor is

required to meet a calibration error

specification of ≤ 3.0 percent of the span

value. For daily operation of the flow

monitor, the calibration error must not

exceed 6.0 percent of span. These

specifications are both reasonable and

achievable for the vast majority of flow

monitors. However, when a differential

pressure (DP) type flow monitor is used

to measure stack gas flow rate in a stack

that has low exit velocities, it can be

very difficult for the monitor to pass its

daily calibration error tests. This is

because the daily calibration span value

for a DP flow monitor is expressed in

units of inches of water. For stack exit

velocities less than 2000 feet per

minute, the calibration span value will

be a very small number (0.20 inches of

water or less). When performing a daily

calibration error test of a flow monitor

with a span value of 0.20 inches of

water, the test would be failed (i.e., the

calibration error would exceed 6.0

percent of span) if the response of the

monitor deviated from either the zero or

high reference signal by 0.02 inches of

water. For span values of 0.15 inches of

water or less, the calibration error test

would be failed if the monitor’s

response deviated from the reference

signals by 0.01 inches of water. One

utility with a DP type flow monitor with

a span value less than 0.15 inches of

water has indicated to EPA that it

cannot pass daily calibrations unless the

monitor responses exactly equal the

reference signal values (see Docket A–

97–35, Item II–E–30). Clearly, these

daily calibration specifications are too

stringent for low span DP-type flow

monitors. In view of this, EPA is

proposing alternative calibration error

specifications for DP type flow monitors

with low span values, with ‘‘low’’ span

value meaning a span value of 0.20

inches of water or less. The alternative

performance specification for initial

certification, given in proposed section

3.1 of Appendix A, would be ± 0.01

inches of water, rather than ± 3.0

percent of span. The alternative

specification for daily operation of the

monitor, given in proposed section 2.1.4

of Appendix B, would be ± 0.02 inches

of water, rather than ± 6.0 percent of

span. Since the results of a calibration

error test of a DP type flow monitor are

reported to 2 decimal places, the

performance specification of ± 0.01

inches of water, is the tightest

specification that could be imposed,

short of requiring the monitor to read

exactly the reference value with zero

tolerance (which is what the current

specification of ± 3.0 percent of span

essentially imposes on a DP flow

monitor with very low span). The

Agency solicits comment on this

proposed approach and on the value of

the alternate specification.

O. CEM Data Validation

Background

The current requirements of part 75

regarding CEM data validation are as

follows. Section 75.10 specifies that a

valid hourly average from a CEMS must

be based on a minimum of four evenly

spaced data points (i.e., one point in

each 15-minute quadrant of the clock

hour), except that two evenly spaced

data points separated by at least 15

minutes are sufficient to validate an

hourly average when daily calibration

error tests and/or other required quality

assurance activities are conducted

during the hour. Data from a CEMS are

considered to be quality assured,

provided that the monitoring system has

passed all of the initial certification tests

required under § 75.20(c) and provided

that the CEMS is not ‘‘out-of-control,’’ as

a result of having failed any of the daily,

quarterly, semiannual, and/or annual

quality assurance tests required in

sections 2.1 through 2.3 of Appendix B.

Out-of-control periods extend from the

hour of failure of a QA test until the

hour of completion of a subsequent

successful QA test of the same type. For

instance, if a linearity check of a gas

monitor is failed, the monitor is

considered out-of-control from the hour

of completion of the failed test until the

hour of completion of a subsequent

successful linearity test.

Finally, § 75.20(b)(3) specifies that

when a change is made to a CEMS such

that recertification of a monitor becomes

necessary, data from the CEMS are

invalid from the hour in which the

change is made to the system until the

hour of completion of all required

recertification tests.

In the first three years of

implementing part 75, EPA has received

numerous requests from the utilities for

guidance concerning CEM data

validation. This has prompted the

Agency to re-examine these provisions

of the rule. From this re-examination,

the Agency believes that the current

data validation provisions of part 75 are

neither sufficiently detailed nor flexible

to address the complex realities of daily

operation of utility boilers and

continuous emission monitoring

systems. Therefore, today’s proposed

rule would set forth more

comprehensive data validation criteria.

Discussion of Proposed Changes

Today’s proposed rule would set forth

proposed guidelines for the validation

of CEM data, attempting to take into

account the realities associated with the

operation and maintenance of electric

utility steam generating units and

continuous emission monitoring

systems. The proposed guidelines

would govern CEM data validation as it

pertains to six principal areas: (1)

calibration error tests and adjustment of

gas and flow monitors; (2) linearity tests

of gas monitors; (3) relative accuracy

test audits of gas and flow monitoring

systems; (4) recertifications of gas or

flow monitors; (5) data from nonredundant backup monitoring systems;

and (6) missed QA test deadlines. These

proposed guidelines for data validation

are discussed in detail below.

1. Recalibration and Adjustment of

CEMS

Today’s proposed rule would revise

section 2.1.3 of Appendix B, the

‘‘recalibration’’ section. The May 17,

1995 rule recommends (but does not

require) the calibration of a monitor to

be adjusted whenever the daily

calibration error exceeds the

performance specification in Appendix

A. For example, if the calibration error

of a gas monitor exceeds 2.5 percent of

span, but does not exceed the daily

control limit of 5.0 percent of span, the

monitor is considered to be out-ofadjustment but not out-of-control, and

EPA recommends that calibration of the

monitor be adjusted.

Today’s proposal would re-title

section 2.1.3 as ‘‘Additional Calibration

Error Tests and Calibration

Adjustments.’’ The recommendation to

adjust the monitor when the calibration

error exceeds the Appendix A

performance specification would be

retained, but definitions of ‘‘routine

calibration adjustments’’ and ‘‘nonroutine calibration adjustments’’ would

be added. Routine calibration

adjustments would be defined as

adjustments made to a CEMS following

a successful calibration error test. The

purpose of these adjustments would be

to bring the monitor readings as close as

practicable to the tag values of the

reference calibration gases or to the
28074 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

known values of the flow monitor

reference signals. Non-routine

calibration adjustments would be

adjustments in either direction (toward

or away from the reference value), but

within the performance specifications of

the monitor (i.e., within ± 2.5 percent of

span for an SO2 or NOX monitor, ± 0.5

percent CO2 or O2 for a diluent monitor,

or ± 3.0 percent of span for a flow

monitor). Non-routine calibration

adjustments would be permitted,

provided that an acceptable technical

justification is included in the QA/QC

program required under section 1 of

Appendix B. An additional calibration

error test would be required following

non-routine adjustments, to demonstrate

that the instrument is still operating

within its performance specifications.

In addition to the daily calibration

error requirements in section 2.1.1 of

Appendix B, today’s proposed rule

would require a calibration error test in

four specific instances: (1) whenever a

daily calibration error test is failed; (2)

when a CEMS is returned to service

following routine or corrective

maintenance that may affect the ability

of the CEMS to accurately measure and

record emissions data; (3) following

routine calibration adjustments in

which the monitor’s calibration is

physically adjusted, e.g., by means of a

potentiometer (however, an additional

calibration error test would not be

required if a mathematical algorithm in

the DAHS is used to make the routine

adjustments); and (4) following nonroutine calibration adjustments. Data

from the CEMS would be considered

invalid until the required additional

calibration error test had been

successfully completed.

EPA is proposing to allow non-routine

calibration adjustments within the

performance specifications of an

instrument for two principal reasons.

First, commenters have expressed

concern that restricting allowable

adjustments to routine calibration

adjustments would limit their ability to

make adjustments within the acceptable

plus or minus control limits of a

monitor, particularly prior to linearity

tests and RATAs. They have indicated

that this flexibility is necessary because

the tag values of reference gases are not

100.0 percent accurate and adjustments

of the analyzer may be needed to

account for these inaccuracies (see

Docket A–97-35, Item II–I–15). EPA

agrees that this is a legitimate concern.

Because there is a tolerance of ± 2.0

percent on the different reference gases

used for daily calibration error tests,

linearity tests, and RATAs, it may be

necessary to adjust toward or away from

the tag value in order to make sure that

the test specifications are met. The

Agency believes, however, that it is

appropriate to limit the calibration

adjustments to within the instrument’s

performance specifications (i.e., ± 2.5

percent of span (for SO2 and NOX), ± 3.0

percent of span (for flow rate), and ± 0.5

percent CO2 or O2) in order to provide

an on-going demonstration that the

CEMS can simultaneously comply with

the applicable daily, quarterly,

semiannual, or annual performance

specifications in Appendix A. One

utility has expressed concern about its

vendor’s practice of making large

calibration adjustments to the CO2

monitor prior to RATA testing (see

Docket A–97–35, Item II–D–63).

The second reason for proposing to

allow non-routine calibration

adjustments is the sensitivity of

dilution-extractive monitors to changes

in barometric pressure, temperature,

and molecular weight. EPA believes that

the best way to deal with this deficiency

in the dilution-extractive monitoring

technology is to develop a mathematical

algorithm (site-specific, if necessary)

that continuously applies a correction to

the measurement in order to

compensate for pressure, temperature,

and molecular weight, as necessary, and

to program the algorithm into the

DAHS. However, in commenting on a

pre-proposal draft of today’s proposed

rule, a number of utilities indicated that

they prefer to account for dilution probe

pressure effects by manually adjusting

the monitor’s calibration in anticipation

of barometric pressure changes (e.g.,

approaching weather fronts) (see Docket

A–97–35, Items II–D–41, II–D–55). After

much deliberation, the Agency is

proposing to allow such adjustments,

provided that: (1) the calibration of the

monitor is not adjusted outside of its

performance specifications; (2) an

additional calibration error test is done

to verify that the adjustments have been

properly made; and (3) the procedures

used for the adjustments are included in

the QA/QC program for the CEMS.

Despite this, EPA still prefers that

automatic pressure, temperature, and

molecular weight compensation be

used, where necessary, and would

strongly encourage all facilities with

dilution-extractive monitors to develop

and apply the necessary mathematical

algorithm(s).

2. Linearity Tests

Today’s proposal would provide rules

for data validation during linearity tests,

in proposed section 2.2.3 of Appendix

B. A routine quality assurance linearity

test could not be commenced if the

CEMS were operating ‘‘out-of-control’’

with respect to any of its other daily,

semiannual, or annual quality assurance

tests. Linearity tests would be done

‘‘hands-off,’’ as follows. 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 test

period, however, no adjustment of the

monitor would be permitted except for

routine daily calibration adjustments

following successful daily calibration

error tests (the Agency notes that it is

unlikely for calibration error tests to be

done during a linearity test period

except when two or more operating days

are required to complete the test, e.g.,

for a peaking unit).

Proposed section 2.2.3 of Appendix B

would specify that when a linearity

check is 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

hands-off linearity test. This proposed

requirement is not substantially

different from the out-of-control

provision in the current rule. It would

merely extend the definition of out-ofcontrol to include linearity tests that are

aborted prior to completion due to a

problem with the monitor. The

underlying assumption is that the

aborted linearity test would not have

been passed if all nine gas injections

had been completed. However, a

linearity test that is aborted for a reason

unrelated to a monitor malfunction (e.g.,

an unplanned or forced unit outage)

would not trigger an out-of-control

period.

Finally, a new section, 2.2.4, would

be added to Appendix B, providing a

linearity test grace period of 168 unit

operating hours. The purpose of the

grace period would be to give the owner

or operator a window of opportunity in

which to perform a linearity test, when

either: (1) the required linearity test

cannot be completed within the QA

operating quarter in which it is due, or

(2) four consecutive calendar quarters

have elapsed since the end of the

calendar quarter in which a linearity

test of a monitor (or range) was last

done. Data validation during a grace

period would be done according to the

applicable provisions of proposed

section 2.2.3 of Appendix B. Proposed

section 2.2.4 of Appendix B would

specify that if the required linearity test

has not been completed within the grace

period, data from the monitor would

become invalid, beginning with the first

hour following the expiration of the

grace period and would remain invalid

until the hour of completion of a
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28075

subsequent successful, hands-off

linearity test. Proposed section 2.2.4

would further specify that a linearity

test done during a grace period could

only be used to meet the linearity test

requirement of a previous QA operating

quarter, not the requirement of the

quarter in which the grace period is

used. Note that proposed sections 2.2.3

and 2.2.4 of Appendix B would also

extend the 168 unit operating hour grace

period to apply to the quarterly leak

checks of differential pressure-type flow

monitors.

3. RATAs

Today’s proposal would provide rules

for data validation during gas and flow

monitor RATA tests, in section 2.3.2 of

Appendix B. Proposed section 2.3.2

would specify that a routine quality

assurance RATA could not be

commenced if the monitoring system is

out-of-control with respect to any of its

daily quality assurance assessments,

including the additional calibration

error test requirements of proposed

section 2.1.3 of Appendix B. All RATAs

would be done ‘‘hands-off,’’ as follows.

Prior to the RATA , both routine and

non-routine calibration adjustments

would be permitted, in accordance with

proposed section 2.1.3 of Appendix B.

During the RATA test period, however,

only routine calibration adjustments (as

defined in proposed section 2.1.3 of

Appendix B) would be permitted. For 2-

level and 3-level flow RATAs, no

linearization of the monitor would be

permitted between load levels.

Note that EPA is proposing to allow

pre-RATA adjustments and linearization

of a CEMS, principally to encourage

facilities to optimize the performance of

their CEMS by achieving the best

possible relative accuracy results in a

cost-effective manner with little or no

data loss. The Agency believes that

there is no significant risk in allowing

pre-RATA adjustments, provided that

the monitor’s continued accuracy

between successive RATAs can be

reasonably established. For gas

monitors, EPA believes that the daily

calibration error tests and quarterly

linearity tests, which challenge the

analyzers with protocol gases of known

concentration, provide that assurance.

For flow monitors, however, the daily

calibration error tests, which check the

internal electronics of the flow monitor

but do not evaluate the actual flow

measurement capability of the

instrument, do not provide the

necessary assurance. Therefore, in

today’s rulemaking, EPA is proposing a

new flow monitor quality assurance

requirement, the ‘‘flow-to-load test,’’ to

provide a reasonable indicator of

continued flow monitor accuracy

between successive RATAs. The flowto-load test has been discussed in detail

under section III.M. of this preamble.

If a RATA is failed or aborted due to

a problem with the CEMS, proposed

section 2.3.2 of Appendix B would

specify that the monitoring system is

out-of-control as of the hour in which

the test is failed or aborted. Data from

the monitoring system would remain

invalid until the hour of completion of

a subsequent successful hands-off

RATA. This proposed requirement is

essentially the same as the out-ofcontrol provision in the current rule,

except that it would extend the

definition of out-of-control to include

RATAs that are aborted prior to

completion due to a problem with the

CEMS. Note, however, that a RATA

which is terminated for a reason

unrelated to monitor malfunction (e.g.,

process operating problems or unit

outage) would not trigger an out-ofcontrol period.

For multiple-load flow RATAs, each

load level would be treated as a separate

RATA. Therefore, if a flow RATA is

failed at a particular load level,

previously-passed RATAs at the other

loads would not have to be repeated

unless the flow monitor has to be relinearized. In that case, a subsequent 3-

load RATA would be required.

If a daily calibration error test is failed

during a RATA test period, proposed

section 2.3.2 of Appendix B would

require invalidation of the RATA, and

an out-of-control period would begin

with the hour of the failed calibration

error test. The RATA could not to be restarted until a subsequent calibration

error test had been passed, following

corrective actions.

Proposed section 2.3.2 of Appendix B

further specifies that when the RATA of

a CO2 pollutant concentration monitor

(or an O2 monitor used to measure CO2

emissions) is failed and that same CO2

(or O2) monitor also serves as the

diluent component in a NOX-diluent (or

SO2-diluent) monitoring system, then

both the CO2 (or O2) monitor and the

associated NOX-diluent (or SO2-diluent)

system would be considered to be outof-control until the hour of completion

of subsequent hands-off RATAs which

demonstrate that both systems are incontrol and have met the applicable

relative accuracy specifications in

sections 3.3.2 and 3.3.3 of Appendix A.

The beginning of the out-of-control

period for each monitoring system

would be the hour of completion of the

failed or aborted RATA of the CO2 (or

O2) monitor. The lengths of the out-ofcontrol periods would, therefore, be

determined from the same reference

point for both the CO2 (or O2)

monitoring system and the NOX-diluent

(or SO2-diluent) monitoring system.

Today’s proposal would clarify the

way in which RATA results are to be

reported to EPA in the electronic

quarterly report required under § 75.64.

Proposed section 2.3.2 of Appendix B

specifies that only the results of

completed and partial RATAs that affect

data validation would have to be

reported. That is, all completed passed

RATAs, all completed failed RATAs,

and all RATAs aborted due to a problem

with the CEMS would have to be

included in the quarterly report.

Therefore, aborted RATA attempts

followed by corrective maintenance, relinearization 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.

RATAs which are aborted or invalidated

due to problems with the 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 is performed, and (2) no

adjustments other than the calibration

adjustments allowed under proposed

section 2.1.3 of Appendix B are made.

However, such RATA runs would still

have to be documented and kept on-site

as part of the official test log.

Whenever a required RATA has not

been completed by its deadline, section

2.3.3 of Appendix B of today’s proposed

rulemaking would provide a grace

period of 720 unit operating hours in

which to complete the test. Data

validation during a grace period would

be done according to the applicable

provisions of proposed section 2.3.2 of

Appendix B. Proposed section 2.3.3

would specify that if the RATA is not

completed by the end of the grace

period, data from the CEMS would

become invalid upon expiration of the

grace period and remain invalid until

the hour of completion of a subsequent

successful hands-off RATA.

EPA has proposed a 720 unit

operating hour RATA grace period

because the Agency believes this will

allow the facility sufficient time to

schedule the RATA, to provide all

required test notifications, and to

complete the testing. The proposed

grace period would be based on unit
28076 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

operating hours rather than clock hours,

because this is believed to be more

equitable for peaking and cycling units.

Data validation during the grace period

would be prospective, i.e., data from the

monitoring system would be considered

valid during the grace period until the

time of the RATA. If the RATA is failed

or aborted due to a problem with the

CEMS, data would be invalidated from

the hour in which the test is failed or

aborted, forward. Data would not be

invalidated retrospectively back to the

beginning of the grace period. Several

utilities have expressed a preference for

a grace period with prospective data

invalidation, because it is simple to

implement and is consistent with other

part 75 provisions for which data

invalidation is prospective when a test

is failed (see Docket A–97–35, Item II–

E–23).

4. Recertification of Gas and Flow

Monitors

Today’s proposed rule would revise

§ 75.20(b)(3) concerning data validation

during recertification test periods. In the

January 11, 1993 rule, as amended on

May 17, 1995, § 75.20(b)(3) specifies

that for any replacement, change, or

modification to a monitoring system

requiring recertification of the CEMS, all

data from the CEMS are considered

invalid from the hour of that

replacement, change, or modification

until the hour of completion of all

required recertification tests. Today’s

rulemaking proposes 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 allow these new data

validation procedures to also be applied

to the initial certification of monitoring

systems. The proposed revisions are

based, in part, on policy guidance

issued by EPA to address the initial

certification of CEMS when a wet

scrubber is installed on an affected unit

(see Docket A–97–35, Item II–I–9, Policy

Manual, Question 16.10). The intent of

that policy guidance and of today’s

proposal 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 § 75.20(b)(3), specific

rules are provided for data validation

during the recertification test period.

The recertification test period would

begin with the first successful

calibration error test after making the

change to the CEMS and completing all

necessary post-change adjustments, reprogramming, linearization, etc. of the

CEMS. The post-change activities could

also include preliminary tests such as

trial RATA runs or a challenge of the

monitor with calibration gases. The first

successful calibration error test

following all of these activities would be

known as a probationary calibration

error test. 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.

Today’s proposal would place a

specific time limit on the length of the

recertification test period, depending

upon the type(s) of test(s) required. If a

linearity test or cycle time test is

required, the test would have to be

completed within 168 unit operating

hours of the hour in which the

probationary calibration error test was

passed, marking the beginning of the

recertification test period. If a RATA is

required, it would have to be completed

within 720 unit operating hours. If a 7-

day calibration error test were required,

it would have to be completed within 21

unit operating days. Routine daily

calibration error tests would continue to

be done as required by part 75

throughout the recertification test

period. If a particular recertification test

is not completed within the specified

number of hours, data validation would

be done as follows. For a late linearity

test, RATA, or cycle time test that is

passed on the first attempt, or for a late

7-day calibration error test (whether or

not it is passed on the first attempt),

data from the monitoring system would

be invalidated from the hour of

expiration of the recertification test

period until the hour of completion of

the late test. However, for a late linearity

test, RATA, or cycle time test that is

failed on the first attempt or aborted on

the first attempt due to a problem with

the monitor, all conditionally valid data

from the monitoring system would be

invalidated from the hour of the

probationary calibration error test that

initiated the original recertification test

period to the hour of completion of the

late recertification test. Data would

remain invalid until successful

completion of the failed/aborted test

and any additional recertification or

diagnostic tests that are required as a

result of changes made to the

monitoring system to correct the

problem(s) that caused failure of the late

recertification test.

A conditionally valid status would be

assigned to emission data generated by

a CEMS during a recertification test

period. The conditionally valid data

status would begin with the first hour of

the recertification test period (i.e., the

hour in which the probationary

calibration error test is passed,

following completion of all necessary

monitor adjustments, preliminary tests,

etc.). The conditionally valid status of

the CEMS data would continue

throughout the recertification test

period, provided that the required

recertification tests are done ‘‘handsoff’’ (i.e., with no adjustments,

reprogramming, etc. 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 continue to be

passed. If all of the required

recertification tests and calibration error

tests are 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. Note, however, that if a

required recertification test has not been

completed by the end of a calendar

quarter, the owner or operator would

indicate this by using a suitable

conditional data flag in the electronic

quarterly report for that quarter. The

owner or operator would be required to

resubmit the report for that quarter if the

required recertification test is

subsequently failed. In the resubmitted

report, the owner or operator would use

the appropriate missing data routine in

§ 75.31 or § 75.33 to replace each hour

of conditionally valid data that was

invalidated by the failed recertification

test with substitute data. In addition, if

conditionally valid data is submitted to

the Agency in any quarterly report, the

owner or operator would have to

indicate in the end of the year

compliance report required under

§ 72.90 whether the final status of the

conditionally valid data has been

determined. Note that in certain

instances where a recertification test

period spans two calendar quarters, it

may be possible to avoid use of the

conditional data flag and quarterly

report resubmittal. If a required

recertification test(s) is completed no

later than 30 days after the end of a

calendar quarter (i.e., prior to the

quarterly report submittal deadline), the

test data and results may be submitted
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with the quarterly report, even though

the test dates are from the next calendar

quarter. If the recertification test(s) is

passed, this would allow the

‘‘conditionally valid’’ data to be

reported as quality assured, in lieu of

using a conditional data flag. If the

test(s) is failed, conditionally valid data

could be replaced with substitute data,

as appropriate, and resubmittal of the

quarterly report would not be necessary.

If a recertification test is failed or

aborted due to a problem with the

CEMS or if a routine daily calibration

error test is failed during a

recertification test period, proposed

§ 75.20(b)(3) specifies that data

validation would be done as follows:

(1) If any required recertification test

is failed, the test would have to be

repeated. If any recertification test, other

than a 7-day calibration error test, is

failed or aborted due to a problem with

the CEMS, the original recertification

test period would end and any

necessary maintenance activities,

adjustments, linearizations, and

reprogramming of the CEMS would

need to be completed before a new

recertification test period could begin.

The new recertification test period

would begin with a probationary

calibration error test. The tests that

would be required in this new

recertification test period would include

any tests that were required for the

initial recertification event which were

not successfully completed and any

recertification or diagnostic tests

required as a result of changes that were

made to the monitoring system to

correct the problems that caused failure

of the recertification test;

(2) If a linearity test, RATA, or cycle

time test is failed or aborted due to a

problem with the CEMS, all

conditionally valid emission data

recorded by the CEMS would be

invalidated from the hour of

commencement of the original

recertification test period to the hour in

which the test is failed or aborted. Data

from the CEMS would remain invalid

until the hour in which a new

probationary calibration error test is

passed following all of the necessary

maintenance procedures, diagnostic

tests, etc., at which time the

conditionally valid status of emission

data from the CEMS would begin;

(3) If a 7-day calibration error test is

failed within the recertification test

period, the test would have to be restarted. Previously-recorded

conditionally valid emission data from

the CEMS would not be invalidated by

a failed 7-day calibration error test

unless the calibration error on the day

of the failed 7-day calibration error test

exceeded twice the performance

specification in section 3 of Appendix A

(causing the monitor to be considered

out-of-control); and

(4) If a calibration error test is failed

during a recertification test period, the

CEMS would be considered out-ofcontrol as of the hour in which the

calibration error test is failed. Emission

data from the CEMS would be

invalidated prospectively from the hour

of the failed calibration error test until

the hour of completion of a subsequent

successful calibration error test

following corrective action, at which

time the conditionally valid data status

would resume. Failure to perform a

required daily calibration error test

during a recertification test period

would also cause data from the CEMS

to be invalidated prospectively from the

hour in which the calibration error test

was due until the hour of completion of

a subsequent successful calibration error

test. Following a failed or missed

calibration error test, no recertification

tests could be performed until the

required subsequent calibration error

test had been passed.

5. Recertification and QA

In today’s proposed rule, a new

section, 2.4, entitled ‘‘Recertification,

Quality Assurance, and RATA

Deadlines’’ would be added to

Appendix B. The purpose of this section

would be to clarify the interrelationship between normal quality

assurance testing of CEMS and

recertification events and to further

clarify how RATA deadlines are

determined. Appendix B to part 75

currently requires periodic (daily,

quarterly, and semiannual or annual)

quality assurance tests of all CEMS. The

required daily QA tests include

calibration error tests of all monitors

and interference checks of flow

monitors. Quarterly QA tests include

linearity checks of gas monitors and

leak checks of differential pressure-type

flow monitors. The required semiannual

or annual QA tests for all types of CEMS

are RATAs.

Under the current rule, when a

significant change is made to a CEMS

which affects the ability of the

monitoring system to accurately read

and record emissions data, § 75.20(b)

specifies that the CEMS must be

recertified. To recertify a monitoring

system, one or more of the following

tests that were performed for initial

certification of the CEMS must be

repeated. That is, depending upon the

nature of the change made to a CEMS,

one or more of the following tests may

be required for recertification: (1)

calibration error test, (2) cycle time test,

(3) linearity check, (4) RATA, or (5)

DAHS verification. Notice that

recertification tests (1), (3), and (4) are

the same types of tests that are done for

routine daily, quarterly, and semiannual

or annual QA. There is, therefore, a

connection between routine QA tests

and recertification tests. Proposed

§ 75.20(b) would further clarify that any

change to a CEMS that does not require

a RATA would not be considered a

recertification event, and, therefore,

would not require a recertification

application. In such cases, the required

tests would be considered diagnostic

tests.

Routine QA tests are generally

planned and scheduled in advance,

while recertification tests are performed

on an as-required basis. Despite this, it

is sometimes possible to coordinate

component replacements or other

changes to a CEMS with the QA test

schedule for the CEMS. For instance,

suppose that in a particular quarter, a

CEMS component is replaced, and a

RATA is required to recertify the

monitoring system. Suppose, further,

that in the quarter of the component

replacement, the annual RATA is due,

but has not yet been conducted. In this

case, the recertification RATA could

serve a dual purpose, i.e., to recertify

the CEMS and to meet the annual RATA

requirement. For this reason, EPA

proposes to recommend in today’s rule

that, to the extent practicable,

component replacements, system

upgrades, and other events that require

recertification be coordinated with the

periodic (daily, quarterly, and

semiannual or annual) QA testing

required under Appendix B. Proposed

section 2.4 of Appendix B clarifies that

when a particular test is done for the

dual purpose of recertification and

routine QA, the data validation rules in

§ 75.20(b)(3) pertaining to recertification

would take precedence and would be

followed. In a similar manner, a

required diagnostic test (e.g., linearity

check) could also be used to satisfy a

quarterly linearity test requirement.

Proposed section 2.4 of Appendix B

emphasizes that, in general, whenever a

RATA is performed, whether for QA

purposes, recertification purposes, or

both, the projected deadline for the next

RATA (i.e., whether the next test is due

in 2 or 4 QA operating quarters) would

be established based upon the

percentage relative accuracy obtained.

For 2-load and 3-load flow RATAs, the

projected deadline for the next RATA

would be established according to the

highest relative accuracy at any of the

loads tested. There would, however, be

two important exceptions to this for

single-load flow RATAs. Irrespective of
28078 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

the relative accuracy percentage

obtained, the results of a single-load

flow RATA could only be used to

establish an annual RATA frequency if:

(1) the single-load flow RATA is

specifically required under section

2.3.1.3(b) of Appendix B for flow

monitors installed on peaking units and

bypass stacks, or (2) the single-load

RATA is allowed under proposed

section 2.3.1.3(c) of Appendix B for ≥

85.0 percent historical unit operation at

a single-load level. No other single-load

flow RATA could be used to establish

an annual frequency; however, a 2-load

flow RATA could be performed in place

of any required single-load RATA, in

order to achieve an annual frequency.

6. Data From Non-Redundant Backup

Monitors

Today’s rule proposes to revise the

quality assurance and data validation

requirements in § 75.20(d) for nonredundant backup monitoring systems.

Under the May 17, 1995 rule, a ‘‘nonredundant backup monitoring system’’

is defined as a ‘‘cold’’ backup

monitoring system which is brought

into service on an as-needed basis,

rather than being operated

continuously. Non-redundant backup

monitors must be initially certified at

each location at which they are to be

used, but unlike ‘‘redundant backup’’

monitors which are operated

continuously and kept on ‘‘hotstandby,’’ non-redundant backup

systems are not required to meet the

daily and quarterly quality assurance

requirements of Appendix B, except

when they are actually used for data

reporting. A linearity test of each nonredundant backup gas monitor is

required before it is placed in service,

and each non-redundant backup flow

monitor must pass a calibration error

test before being used to report data.

The use of non-redundant backup

monitors is restricted to 720 hours a

year at a particular unit or stack, unless

a 7-day calibration error test is passed.

A periodic recertification RATA of each

non-redundant backup monitor is

required at least once every two years,

at each location where it is to be used.

Section 75.20(d) of today’s proposal

would clarify and expand the definition

of a non-redundant backup monitoring

system. Under the proposal, two distinct

types of non-redundant backup systems

would be defined: (1) type-1 is a system

that has its own separate probe, sample

interface, and analyzer (e.g., a portable

gas monitoring system), and (2) type-2 is

a system consisting of one or more likekind replacement analyzers that use the

same sample probe and interface as the

primary monitoring system. This would

include non-redundant backup

analyzers that are used to meet the dual

span and range requirements for SO2 or

NOX under proposed sections 2.1.1.4

and 2.1.2.4 of Appendix A.

The ‘‘type-1’’ system is the familiar

non-redundant backup system described

in the current version of part 75.

However, the ‘‘type-2’’ system is a new

kind of non-redundant backup

monitoring system. EPA believes that

allowing limited use of type-2

monitoring systems will encourage

facilities that do not have redundant

backup monitors to perform better

maintenance on their primary analyzers.

The Agency is concerned that primary

analyzers with excessive, recurring

daily calibration drift (i.e., monitors that

fail calibration error tests more often

than expected) are sometimes kept in

service to avoid using substitute data,

when the analyzers should be in the

shop for maintenance. If the monitor

readings tend to drift low from day to

day, this can result in under-reporting of

emissions, because data validation for

daily calibrations under part 75 is

prospective. That is, data are

invalidated from the hour of a failed

calibration error test forward, while data

recorded from the hour of the previous

successful calibration to the hour of the

failed calibration are considered valid.

EPA believes that allowing limited use

of type-2 non-redundant backup

monitoring systems would provide a

simple way (i.e., like-kind analyzer

replacement) for primary analyzers to be

properly maintained and repaired with

minimal data loss.

Today’s proposal would retain the

requirement for type-1 non-redundant

backup monitoring systems to be

initially certified (except for a 7-day

calibration error test) at each location at

which they are to be used. However,

type-2 systems would require no initial

certification. Both types of systems

would have to pass a linearity test (for

gas monitors) or a calibration error test

(for flow monitors) each time that they

were used to report emission data. For

a type-2 ‘‘mix-and-match’’ NOX

monitoring system consisting of one

primary analyzer and one like-kind

replacement analyzer, only the like-kind

replacement analyzer would have to

pass a linearity test, provided that the

primary analyzer is operating and not

out-of-control with respect to any of its

quality assurance requirements. When a

non-redundant backup monitoring

system is brought into service, emission

data from the non-redundant backup

system could be deemed conditionally

valid during the linearity test period, as

follows. After making the like-kind

replacement and prior to conducting the

linearity test, a probationary calibration

error test could be done to begin the

period of conditionally valid data. If the

linearity test is then passed within 168

unit operating hours of the probationary

calibration error test, the conditionally

valid data would be validated. However,

if the linearity test is either failed,

aborted due to a problem with the

CEMS, or not completed as required,

then all of the conditionally valid data

would be invalidated beginning with

the hour of the probationary calibration

error test, and data from the nonredundant backup CEMS would remain

invalid until the hour of completion of

a successful linearity test.

Under today’s proposal, when a nonredundant backup system is used for

part 75 reporting, the bias adjustment

factor (BAF) from the most recent RATA

of the system would be applied to the

data generated by the system. If no

RATA results were available for a type2 system, the primary monitoring

system BAF would be applied to the

data generated by the type-2 system.

Today’s proposal would retain the

restrictions of the current rule, which

limit the annual usage of a nonredundant backup monitoring system to

720 hours at a particular location (unit

or stack). To use a non-redundant

backup system for more than 720 hours

per year at a particular location would

require a RATA of the system at that

location. For type-1 systems, a

recertification RATA would be required

at least once every eight calendar

quarters at each location at which the

system is to be used. All non-redundant

backup monitoring systems (type-1 and

type-2) would have to be assigned

unique system and component

identification numbers and would have

to be included in the monitoring plan

for the unit or stack.

7. Missed QA Test Deadlines

As discussed above under the

subsections on ‘‘Linearity Tests’’ and

‘‘Relative Accuracy Test Audits,’’

proposed sections 2.2.4 and 2.3.3 of

Appendix B to today’s rulemaking

would allow a grace period in which to

perform required linearity tests and

RATAs whenever a test cannot be

completed by the end of the quarter in

which it is due. EPA believes it is

appropriate to allow a grace period

because circumstances beyond the

control of the owner or operator (e.g.,

unplanned unit outages) sometimes

arise which prevent the deadline for a

quality assurance test from being met.

The proposed linearity grace period is

168 unit operating hours, and the

proposed RATA grace period is 720 unit

operating hours. A linearity grace period
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28079

could only be used to satisfy the

linearity requirement from a previous

quarter. For any RATA (or RATAs, if

more than one attempt is made)

conducted during a grace period, the

deadline for the next RATA would be

calculated from the quarter in which the

RATA was originally due, not from the

quarter in which the RATA is actually

completed.

Data validation during a grace period

would be done according to the

applicable provisions in proposed

section 2.2.3 of Appendix B (for

linearities) or section 2.3.2 of Appendix

B (for RATAs). Data from a CEMS would

become invalid upon expiration of a

grace period if the required linearity test

or RATA had not been completed. Data

from the CEMS would remain invalid

after the expiration of the grace period

until the required test is successfully

completed.

P. Appendix D

1. Pipeline Natural Gas Definitions

Background

Appendix D provides an optional

protocol by which oil-fired and gas-fired

units may account for their SO2 mass

emissions. Under the definitions of ‘‘oilfired’’ and ‘‘gas-fired’’ in § 72.2,

Appendix D may be used to measure

SO2 emissions from gaseous fuels only

if the gaseous fuel’s sulfur content is

less than or equal to that of natural gas.

In developing Appendix D, EPA

assumed that virtually all of the gaseous

fuel combusted by affected units in the

Acid Rain Program would be pipeline

natural gas. Section 2.3 of Appendix D

of the January 11, 1993 rule allowed for

accounting for SO2 emissions from

gaseous fuel using EPA’s ‘‘National

Allowance Database (NADB) emission

rate.’’ The NADB was used to establish

a baseline of historical SO2 emissions in

order to allocate allowances. For the

vast majority of units combusting

pipeline natural gas, NADB used the

historical heat input from gas and an

emission rate of 0.0006 pounds of SO2

per measured million British thermal

units (lb/mmBtu) (see Docket A–92–06;

Docket A–94–16, Item II–F–2). This

default factor is derived from EPA

Publication AP–42 and is based on a

sulfur content of 0.2 grains per 100

standard cubic feet of gaseous fuel (gr/

100 scf) (see Docket A–97–35, Item II–

I–1). Use of this default SO2 emission

rate factor for pipeline natural gas was

clarified by EPA in its Acid Rain Policy

Manual (see Docket A–97–35, Item II–I–

9, Policy Manual, Question 2.4).

Section 2.3.2 of Appendix D, as

revised by the May 17, 1995 direct final

rule, explicitly allows owners or

operators to use a default emission

factor of 0.0006 (lb/mmBtu) to estimate

SO2 emissions during hours in which

pipeline natural gas is combusted.

Alternatively, section 2.3.1 of Appendix

D, also as revised by the May 17, 1995

direct final rule, allows for determining

SO2 emissions from any gaseous fuel

with a sulfur content no greater than

natural gas by performing daily fuel

sampling, analyzing the sulfur content

of the gaseous fuel, and multiplying that

sulfur content in grains per 100

standard cubic feet (gr/100scf) times the

volume of gaseous fuel combusted.

Units combusting gaseous fuels with a

total sulfur content greater than natural

gas (i.e., > 20 gr/100scf) are not allowed

to use the procedures of Appendix D

and must instead use an SO2 CEMS and

a flow monitor to determine SO2 mass

emissions. This limitation is explicitly

stated in § 75.11(e)(4), as revised on

November 20, 1996.

The definition of ‘‘natural gas’’ in

§ 72.2, as revised by the May 17, 1995

direct final rule, indicates that the sulfur

content of natural gas is ‘‘1 grain or less

hydrogen sulfide per 100 standard cubic

feet, and 20 grains or less total sulfur

per 100 standard cubic feet.’’ This

definition was taken from Requirements

of the Federal Energy Regulatory

Commission (FERC) for regulation of the

transmission of natural gas. ‘‘Pipeline

natural gas’’ is also defined in § 72.2.

However, the definition is simply

‘‘natural gas that is provided by a

supplier through a pipeline,’’ and

provides no specifications for sulfur

content or hydrogen sulfide content.

Section 2.3.2.2 of Appendix D

requires documentation of the

contractual sulfur content of pipeline

natural gas from the supplier. This

documentation was intended to

demonstrate that the natural gas is

supplied through a pipeline, as well as

that it meets the sulfur content

definition for natural gas.

Questions over the applicability of

Appendix D and the apparent

inconsistencies between the definitions

‘‘natural gas’’ and ‘‘pipeline natural gas’’

in § 72.2 and the provisions of section

2.3 of Appendix D have caused

confusion during program

implementation since the May 17, 1995

direct final rule. Some utilities have

interpreted section 2.3.2.2 of Appendix

D to allow pipeline natural gas to have

a sulfur content as high as 20 gr/100 scf,

which is one hundred times higher than

the sulfur content upon which the

0.0006 lb/mmBtu emission factor is

based. During the process of applying

for certification of monitoring

equipment for six gas-fired units, one

utility indicated to the Agency that it

intended to use a default emission rate

of 0.0006 lb/mmBtu and heat input to

account for SO2 mass emissions from

propane liquefied petroleum gas (see

Docket A–97–35, Item II–D–6). Based

upon the information provided by the

utility in its monitoring plan for the

units, the sulfur content of propane was

several times higher than that of

pipeline natural gas, with a range of

sulfur content between 0.08 and 2.72 gr/

100 scf, compared to a typical sulfur

content of 0.2 gr/100 scf for pipeline

natural gas, upon which the default SO2

emission rate of 0.0006 lb/mmBtu is

based. Later information submitted by

the utility indicated that during the

previous three years, the sulfur content

of propane combusted at that plant had

an average value of 0.83 gr/100 scf and

a maximum value of 2.20 gr/100 scf (see

Docket A–97–35, Item II–D–60). EPA

rejected the utility’s monitoring

approach using the default emission rate

for pipeline natural gas because it

would have resulted in an

underestimation of SO2 emissions, as

well as not following the procedures of

Appendix D (see Docket A–97–35, Item

II–C–2).

Other utilities have tried to use the

default SO2 emission rate of 0.0006 lb/

mmBtu for higher sulfur gaseous fuels,

such as digester gas (see Docket A–94–

16, Item II–D–71). EPA issued policy

guidance to ensure that other utilities

were aware that the default SO2

emission rate of 0.0006 lb/mmBtu

should only be used for pipeline natural

gas with a low sulfur content of 0.2 gr/

100 scf (see Docket A–97–35, Item II–I–

9, Policy Manual, Question 2.15, as

originally published in March 1996).

However, several utilities were

concerned that this excluded some

pipeline natural gas (see Docket A–97–

35, Items II–B–3, II–E–16). As stated in

the technical support document for the

May 17, 1995 direct final rule, EPA had

intended that all pipeline natural gas

would qualify for use of the default SO2

emission rate of 0.0006 lb/mmBtu.

Therefore, the Agency revised its

guidance to clarify that a facility needed

only to document that it was using

pipeline natural gas, without

documenting a sulfur content of 0.2 gr/

100 scf (see Docket A–97–35, Item II–I–

9, Policy Manual, Question 2.15, as

revised in June 1996). During this

process, the Agency became concerned

that the definition of pipeline natural

gas in § 72.2 was not clear enough and

that the sulfur content documentation

required for pipeline natural gas in

section 2.3.2.2 of Appendix D was

confusing and possibly inappropriate.
28080 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

Discussion of Proposed Changes

For the definition of pipeline natural

gas in § 72.2, today’s proposal includes

a revised definition that would indicate

pipeline natural gas is low in the sulfurbearing compound hydrogen sulfide

(H2S). The proposed revised definition

would specifically include the

maximum hydrogen sulfide content for

pipeline natural gas permitted by fuel

purchase or transportation contracts.

The hydrogen sulfide content of

pipeline natural gas is proposed to be

up to 0.3 gr/100 scf.

In addition, section 2.3 of Appendix

D would be revised. As under the

current rule provisions, sources would

be allowed to use a default SO2

emission rate of 0.0006 lb SO2/mmBtu

in conjunction with unit heat input to

calculate the SO2 mass emission rate

during the combustion of pipeline

natural gas. In order to demonstrate that

the pipeline natural gas qualifies to use

the default SO2 emission rate of 0.0006

lb/mmBtu, it would be necessary for the

designated representative to provide

information in the monitoring plan on

the gas’s maximum hydrogen sulfide

content from the facility’s purchase

contract with the pipeline gas supplier

or from the pipeline natural gas

supplier’s transportation contract. In

such contracts, or in the tariff sheets

associated with them, the pipeline gas

supplier typically agrees to provide

natural gas with a maximum hydrogen

sulfide content of 0.25 gr/100 scf or 0.30

gr/100 scf. If a facility has previously

submitted contract information from its

pipeline gas supplier containing a limit

on the sulfur content, this information

typically also verifies the limit on the

hydrogen sulfide content. For pipeline

natural gas, it would not be necessary to

provide sampling information to verify

that the hydrogen sulfide content

actually meets the quality specification

limit on the hydrogen sulfide content

stated in the definition of pipeline

natural gas.

If a facility wanted to demonstrate

that another gaseous fuel had an SO2

emission rate no greater than pipeline

natural gas, and thus, could use the

default emission rate factor of 0.0006 lb/

mmBtu, the designated representative

would provide sulfur content and GCV

information in the monitoring plan for

the unit or could petition under

§ 75.66(i) after initial certification for

the unit. It would be necessary for the

designated representative to

demonstrate that the gaseous fuel has an

SO2 emission rate no greater than 0.0006

lb/mmBtu. The designated

representative would need to provide at

least 720 hours of data for the

demonstration. The data could come

from the fuel supplier, if the fuel came

from a gas supplier.

For all units using Appendix D,

proposed section 2.3.3 would require

the designated representative to provide

information to the Agency

demonstrating that the total sulfur

content of the gaseous fuel meets the

requirements of Appendix D and that

the unit meets the § 72.2 definition of

‘‘gas-fired’’ or ‘‘oil-fired.’’ Additionally,

the gas-fired definition would be revised

to indicate that the restriction of

burning gaseous fuels containing no

more sulfur than natural gas is actually

a restriction on the total sulfur in the

fuel. The gaseous fuel’s total sulfur

content would have to be shown to be

less than or equal to 20 grains total

sulfur per 100 standard cubic feet of

gaseous fuel.

Rationale

The Agency proposes to introduce

specific hydrogen sulfide content values

into the definition of pipeline natural

gas in order to provide a guideline that

will separate gaseous fuels with a higher

sulfur content from low sulfur pipeline

natural gas. The maximum hydrogen

sulfide content of 0.3 gr/100 scf is being

proposed for two reasons. First,

hydrogen sulfide contents of 0.25 or 0.3

gr/100 scf are typically required under

pipeline gas transmission contracts, and

should be relatively easy to document

(see Docket A–97–35, Item II–E–19). In

addition, 0.2 gr/100 scf is the sulfur

content equivalent to the default

emission rate factor of 0.0006 lb/mmBtu

from the Agency’s AP–42 emission

factors that may be used by units

combusting pipeline natural gas under

section 2.3.2 of Appendix D (see Docket

A–97–35, Item II–A–6). A maximum

hydrogen sulfide content of 0.3 gr/100

scf corresponds to this default emission

rate far more closely than a total sulfur

content of 20.0 gr/100 scf or a hydrogen

sulfide content of 1.0 gr/100 scf and,

yet, would allow for some variability in

the hydrogen sulfide content above a 0.2

gr/100 scf average. EPA believes that all

or virtually all pipeline natural gas that

is supplied through a pipeline for

commercial use can meet these

qualifications.

Pipeline natural gas is composed

predominantly of methane (CH4).

Hydrogen sulfide is the predominant

molecule containing sulfur in pipeline

natural gas. Therefore, restricting the

hydrogen sulfide content of pipeline

natural gas to 0.3 gr/100 scf serves as a

proxy for a limit on the total sulfur

content, while being relatively easy to

document. This revised definition of

pipeline natural gas would also serve to

restrict the default emission rate factor

from being inappropriately applied to

higher sulfur gaseous fuels, such as

liquefied petroleum gas (see Docket A–

97–35, Item II–D–6) or digester gas (see

Docket A–94–16, Item II–D–71).

Appendix D of today’s proposed rule

would be revised to clarify the

documentation requirements for sulfur

content and hydrogen sulfide content of

gaseous fuel, including pipeline natural

gas. The original wording of section

2.3.2.2 implied that pipeline natural gas

only need to have a total sulfur content

of 20 gr/100 scf, roughly 100 times the

sulfur content associated with the

default emission rate of 0.0006 lb/

mmBtu. Some utilities found this

confusing (see Docket A–97–35, Items

II–D–6, II–E–10). Therefore, EPA issued

guidance to clarify that the default

emission rate factor was only intended

to apply to lower sulfur pipeline natural

gas (see Docket A–97–35, Item II–I–9,

Policy Manual, Question 2.15).

However, some utilities using

pipeline natural gas were concerned

that because their fuel suppliers were

not willing to certify or agree to a sulfur

content of 0.3 gr/100 scf by contract,

they might be required to perform daily

gas sampling (see Docket A–97–35,

Items II–B–3, II–E–15, II–E–16). This

was not the Agency’s intent. The

Agency merely wishes to ensure that

facilities provide adequate

documentation to demonstrate that the

unit will not be underestimating SO2

emissions for a high sulfur gaseous fuel

by using an inappropriate default

emission rate factor that applies to

extremely low sulfur gas. Similar to

EPA’s Policy Manual Question 2.15

referred to above, a facility would need

only to provide the fuel quality

specification for total sulfur content and

hydrogen sulfide from the pipeline

supplier, or from the tariff sheet for the

pipeline, in order to qualify to use the

default emission rate.

If a facility intends to use the default

emission rate factor for a gaseous fuel

other than pipeline natural gas, sulfur

content and GCV data would have to be

provided and analyzed to demonstrate

that the fuel has an SO2 emission rate

no greater than 0.0006 lb/mmBtu. A

minimum of 720 hours of data would be

required for the demonstration. Each

hourly value of the total sulfur content

(in gr/100 scf) would be divided by the

GCV value (in Btu/100 scf) and then

multiplied by a conversion factor of 106

Btu/mmBtu. This would provide a ratio

of the number of grains of sulfur in the

fuel to the heat content of the fuel. For

pipeline natural gas with an assumed

SO2 emission rate of 0.0006 lb/mmBtu,

a sulfur content of 0.2 gr/100 scf and a
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28081

GCV value of 100,000 Btu per hundred

scf, the value of the ‘‘sulfur-to-heat

content’’ ratio is 2.0 gr/mmBtu.

Therefore, a candidate gaseous fuel

would qualify to use the default SO2

emission rate of 0.0006 lb/mmBtu for

part 75 reporting purposes if the 720

hours of historical data demonstrate that

the mean value of the sulfur-to-heat

content ratio is 2.0 gr/mmBtu or less.

To demonstrate that a unit qualifies to

use Appendix D when combusting a

gaseous fuel, the designated

representative for the facility would be

required to show that the gaseous fuel

has a total sulfur content of 20 grains/

100 scf or less. This demonstration

would apply to all gaseous fuels. For

gaseous fuels other than pipeline

natural gas, the sulfur content

information could come either from

contractual information on the sulfur

content based on routine vendor

sampling and analysis or from historic

fuel sampling data to show the gaseous

fuel’s sulfur content (see Docket A–97–

35, Item II–I–9, Policy Manual, Question

2.15). For gaseous fuels that are

produced in batches or lots with a

relatively uniform sulfur content, such

as liquefied petroleum gases, it would

be sufficient to provide historical

information on each batch over the past

year. This approach was accepted by the

Agency for six units combusting

liquefied petroleum gas (see Docket A–

97–35, Items II–C–14 and II–D–22).

In addition to documenting the total

sulfur content of the fuel, the owner or

operator would be required to submit

certain other fuel-specific information.

As previously noted, for units

combusting pipeline natural gas, a

designated representative would be

required to provide contractual

information to demonstrate that the

natural gas is supplied under

specification and has a hydrogen sulfide

content less than or equal to 0.3 gr/100

scf. And historical data would have to

be provided, as described above, to

obtain permission to use the default SO2

emission rate of 0.0006 lb/mmBtu for a

fuel other than pipeline natural gas. For

other gaseous fuels that are not

produced in batches with relatively

uniform sulfur content, such as gaseous

fuel generated through an industrial

process (e.g., digester gas from a paper

mill), since the sulfur content of the

gaseous fuel could be highly variable,

section 2.3.3.4 of today’s proposed

revisions to Appendix D would require

a minimum of 720 hours of historical

data documenting the sulfur content of

the fuel under representative operating

conditions. This information would

allow the Agency to determine how

variable the sulfur content is and if the

daily sampling procedure under section

2.3.1 of Appendix D is sufficient to

capture this variability without allowing

the underestimation of sulfur content. If

the sulfur variability were too great,

continuous sampling using a gas

chromatograph and hourly reporting of

sulfur content would be required under

today’s proposed rule.

2. Fuel Sampling

(a) Fuel Oil.

Background

Diesel fuel is distillate fuel oil of

grades No. 1 or 2. Diesel fuel is heavily

refined and has a much lower sulfur

content and greater consistency than

other grades of fuel oil. Section 2.2 of

Appendix D to the May 17, 1995 direct

final rule provides three options for

sampling of diesel fuel and two options

for sampling of other fuel oils. First, for

all fuel oils, including diesel fuel, daily

manual sampling is allowed. Second,

diesel fuel and other fuel oils may also

be sampled continuously using an

automated sampler according to ASTM

D4177–82 (Reapproved 1990), either

using continuous drip sampling or flow

proportional sampling. The samples

would then be mixed to form a daily

composite sample. Third, diesel fuel

may be sampled ‘‘as-delivered,’’ upon

receipt of a shipment. These sampling

approaches were selected to ensure that

sulfur content values would be as

accurate as possible, would not

underestimate SO2 mass emissions, and

would account for any variability in the

sulfur content of fuel.

Many utilities have expressed concern

about the cost of daily oil sampling (see

Docket A–97–35, Items II–D–18, II–D–

20, II–E–13, II–E–14). Some utilities

indicated that for a unit that burns oil

every day, the cost of daily oil sampling

is greater than the cost of SO2 CEMS and

flow monitors. Furthermore, industry

representatives provided information

indicating that within a given shipment

of fuel oil from a supplier, the

variability in sulfur content is low (see

Docket A–97–35, Items II–D–18 and II–

D–59). Many companies already have

state or Federal requirements for

sampling of fuel from each truck

delivery or in a storage tank on site at

the plant whenever fuel is added to the

storage tank (see Docket A–97–35, Item

II–D–93). The storage tank is a tank at

a plant that holds oil that is actually

combusted by the unit on that day. In

other words, no fuel will be blended

between the time when a fuel lot is

transferred to the storage tank and when

the fuel is combusted in the unit. In

other cases, such as EPA’s NSPS

regulations for industrial boilers under

40 CFR part 60, subpart Db, companies

keep copies of fuel receipts from the

supplier to indicate the sulfur content is

below the required sulfur content. Based

upon this information, EPA is proposing

to reduce the required sampling

frequency for fuel oil. This would be a

significant reduction in burden and cost

of using Appendix D, without causing

underestimation of SO2 emissions.

Discussion of Proposed Changes

Several utilities suggested that the

Agency propose to allow sampling of

each delivery of oil (see Docket A–97–

35, Items II–D–18, II–D–20, II–E–13, II–

E–22). Under this approach, either a

facility or its supplier would sample

each truck or barge containing oil before

the fuel is transferred into a tank at the

plant. If a delivery shipped in a group

of trucks were purchased under the

same order and were specified to have

the same gross calorific value, density,

and sulfur content, then only one

sample would be necessary for the

group of trucks. Samples taken by the

supplier would not need to be split and

kept on hand at the site. This approach

is currently allowed only for diesel fuel

under section 2.2.1.2 of Appendix D,

but would be extended to apply to all

fuel oils under today’s proposed rule.

This approach would be particularly

useful to a facility that receives large,

infrequent deliveries of fuel or to a

facility that already has other State or

Federal regulations requiring sampling

of each truck or barge delivered to the

plant.

A similar approach suggested by

another industry representative,

allowing facilities to use a sample of oil

taken from a tank belonging to the

supplier before the oil is delivered, is

also proposed in today’s rulemaking.

The supplier could take the sample and

the facility would be able to use that

value as long as it keeps records of the

fuel analysis results from the supplier.

This approach would be particularly

useful to a facility that receives a

delivery of oil from a single supplier’s

tank that is shipped in many different

trucks. This approach also would be

useful for a small facility that would

prefer to rely on samples taken by the

supplier rather than taking its own

samples and paying for their analysis.

Finally, the Agency proposes a third

sampling approach, allowing a facility

to sample oil manually from its storage

tank at the plant whenever oil is added

to the tank. This approach would yield

samples that are more representative of

the oil combusted because it would

include any fuel remaining in the tank

as well as all fuel added. Sampling from

the storage tank at the plant would be
28082 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

useful to a facility that burns oil

infrequently and adds oil to its storage

tank infrequently. It also would be

helpful where a facility already has

other State or Federal regulations

requiring sampling after adding fuel to

the storage tank.

Both the ‘‘before delivery’’ and ‘‘as

delivered’’ sampling approaches would

require a sample for each ‘‘lot’’ of oil;

consequently, a suitable definition of a

‘‘lot’’ is needed. For purposes of

determining when an oil sample should

be taken for the NSPS applicable to

utility boilers, section 5.2.2.2 of Method

19 in Appendix A to 40 CFR part 60

relies on a definition of fuel ‘‘lot’’

developed by the American Society for

Testing and Materials (ASTM). This

definition states that ‘‘the lot size of a

product oil is the weight of product oil

from one pretreatment facility and

intended as one shipment (ship load,

barge load, etc.).’’ In essence, a lot is a

single batch of oil that has uniform

properties and is purchased from a

single supplier and delivered to a buyer.

Among those uniform fuel properties

are gross calorific value, density, sulfur

content, and viscosity. In today’s

rulemaking, EPA proposes to adopt this

definition of a lot of oil for use in the

Acid Rain Program.

The Agency also considered whether

it is appropriate to keep the current

approach of daily manual oil sampling

as an option. Although it seems unlikely

that facilities would choose daily

sampling option if they have the three

options of sampling by lot, sampling

upon addition of fuel to a storage tank,

or continuous sampling, a utility group

has requested that EPA retain daily

manual sampling as an option. The

agency is, therefore, proposing to retain

daily manual oil sampling as an option

in Appendix D to allow facilities this

additional flexibility. An industry

representative suggested that EPA could

define the oil combusted during a 24-

hour period as a lot. For the reasons

discussed below and in the section

addressing sulfur content, density, and

gross calorific values used in

calculations, EPA is not incorporating

this suggestion in today’s proposed rule.

EPA also reconsidered whether it is

necessary to require daily composite

samples when samples are taken

continuously with an automatic

sampler. In today’s proposal, the

Agency is proposing that continuous

samples may be composited on a weekly

basis rather than daily. The Agency also

considered allowing an even longer

compositing period, such as a month,

but is not proposing this option for the

reasons discussed below. A weekly

composite sample of oil that is sampled

continuously would be an attractive

option for a facility that wants the most

representative and accurate sulfur

content data possible. This also would

be a useful option for those few facilities

that receive oil via a pipeline, rather

than in discrete lots.

Rationale

Facilities wish to be able to perform

less frequent fuel sampling in order to

save money. From the information EPA

has examined over the previous year,

the Agency believes that less frequent

oil sampling can be technically justified.

Based upon information provided by

utilities, the sulfur content of a lot of oil

varies from sample to sample, with a

standard deviation of 0.036 percent S to

0.063 percent S, or 5.62 to 6.85 percent

of the average sulfur content for all daily

samples between deliveries (see e.g.,

Docket A–97–35, Item II–D–18). Density

and gross calorific value of oil in a lot

should vary even less than sulfur

content, because sulfur is an impurity in

the composition of the fuel and not an

essential physical property of the oil, as

is density. Furthermore, the difference

between the sulfur content, density,

gross calorific value, and carbon content

of a fuel during the first daily sample

after a new delivery is received and the

average sulfur content, density, gross

calorific value, and carbon content for

all daily samples from between two

deliveries is extremely small (see Docket

A–97–35, Items II–B–18 and II–D–18 for

supporting information). Therefore, the

Agency expects that the variability of

fuel characteristics within a lot is low

enough that only a single representative

sample is necessary for the lot. Data

have indicated that there could be a

significant difference in sulfur content

between shipments, however (see

Docket A–97–35, Items II–B–12, II–B–18

and II–D–18). The Agency believes that

differences between lots, which could

potentially result in the underestimation

of SO2 emissions, can be dealt with by

selecting a conservative sulfur content,

density, or gross calorific value that

would not be exceeded in any sample,

rather than retaining more frequent

sampling requirements. Therefore,

today’s proposal incorporates this

approach.

Prior to drafting today’s proposed rule

revisions, EPA requested comments on

removing the option to perform daily

manual oil sampling for Appendix D

units. At least one utility group

expressed interest in retaining the

option to allow flexibility. The prime

benefit to a facility from continuing to

use daily manual sampling would

appear to be that the facility could

continue to use the same daily operating

procedures and that reprogramming of a

DAHS would not be necessary. Note

that when using the approach of daily

manual oil samples, a facility calculates

SO2 mass emissions using the highest

sulfur content in the previous 30 daily

oil samples. Therefore, this approach

requires more frequent analysis than

either the proposed weekly composite

sample for continuous samples or the

proposed sampling by lot, and provides

less accurate and more conservative

results. The Agency believes it would be

simpler and less confusing for both the

Agency and for the regulated

community to deal with a smaller

number of approaches to sampling and

calculating SO2 emissions. However, the

Agency is retaining this option since at

least some affected utilities want the

flexibility to continue to use this option.

EPA also considered the suggestion to

define a 24-hour period as a lot in order

to allow facilities to continue to perform

daily manual sampling. EPA is not

proposing this approach because of the

added complexity, compared to keeping

the current language in section 2.2.4 of

Appendix D concerning manual daily

sampling of oil. If a lot were defined as

an arbitrary 24-hour period, the other

requirements in the current rule (e.g.,

conservative sulfur, gross calorific

value, and density values used to

calculate SO2 mass emission rate and

heat input rate) would need to be

retained to ensure that SO2 emissions

were not underestimated. Furthermore,

using the terminology of a ‘‘lot’’ for both

a delivery and a period of time, while

requiring different treatment of sample

data from the two different types of

‘‘lots,’’ could potentially be confusing. It

seems preferable to keep the current

language for daily manual samples.

Because the Agency now believes it is

appropriate to sample each fuel lot

instead of sampling daily, the Agency

reconsidered whether daily composite

samples are necessary when a facility

performs automated continuous

sampling. Because continuous samplers

take fuel samples multiple times each

hour, they are highly representative of

the oil being burned. Flow proportional

samplers take samples automatically

when a certain volume or mass of fuel

has passed by, rather than during a

particular time period. Generally,

automatic samplers take multiple

samples each hour; however, only one

sample per hour is required under

section 2.2.3 of Appendix D of the

current rule. Even if the compositing

time period is extended, the composite

sample will be representative of the

sulfur content, density, and gross

calorific value of the oil between

samples. Therefore, the Agency believes
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28083

that the compositing period could be

extended from a day to as long a period

as a month. However, EPA believes that

it is unlikely that any container for

taking samples from an automatic

sampler would be large enough to

accommodate all automatic samples

taken during a month. In addition, at

least one industry representative

suggested that weekly composite

samples were appropriate (see Docket

A–97–35, Item II–D–30). Therefore, in

section 2.2.3 of today’s proposed rule,

EPA would extend the allowable length

of the compositing period for automatic

samples to one week. The Agency

believes this will make automatic

sampling less costly, while taking into

account the physical limitations of

sampling equipment.

(b) Gaseous Fuels.

Background

Section 2.3 of Appendix D, as revised

in the May 17, 1995 direct final rule,

provides only one approach for

sampling gaseous fuel: under section

2.3.1, gaseous fuel sampling must be

performed daily. Relatively few utilities

perform daily sampling upon gaseous

fuels, choosing instead to use a default

SO2 emission rate for pipeline natural

gas. In part, this is because the vast

majority of gaseous fuel used by power

plants is pipeline natural gas. Under

section 2.3.2 of Appendix D, facilities

may calculate SO2 mass emissions from

pipeline natural gas using a default

emission rate instead of performing fuel

sampling. Because of the difficulty and

potential danger of sampling gaseous

fuel, gas sampling is generally

conducted by the supplier, rather than

by the facility.

Those few utilities combusting

gaseous fuels other than pipeline

natural gas have expressed concern

about the difficulty and expense of daily

sampling, particularly in comparison to

the value of SO2 allowances for low SO2

emissions from relatively clean fuel

(see, e.g., Docket A–97–35, Items II–E–

11, II–E–20). For gaseous fuels that are

delivered in discrete batches or ‘‘lots,’’

one would expect the gaseous fuel to

behave like an ideal gas; sulfur should

be evenly distributed throughout the

batch. On this principle, the Ohio

Environmental Protection Agency

allowed a plant to take propane samples

from each discrete delivery, rather than

on a daily basis (see Docket A–97–35,

Items II–C–14 and II–D–22).

Discussion of Proposed Changes

Today’s proposal incorporates three

different sampling approaches for

gaseous fuels: sampling by lot, daily

sampling, and continuous sampling

with a gas chromatograph. For gaseous

fuel that is delivered in discrete lots,

such as liquefied petroleum gas, the

gaseous fuel could be sampled either

daily or for each lot delivered. Any

gaseous fuels other than pipeline

natural gas that are not delivered in

discrete lots, such as digester gas or sour

natural gas pumped directly from a

field, would, at a minimum, need to be

sampled daily. The samples could be

taken either by the supplier or by the

facility. However, if the average sulfur

content and sulfur variability of such a

fuel were too high (i.e., mean sulfur

content > 7 gr/100 scf and standard

deviation from the mean > 5 gr/100 scf,

based on 720 hours of representative

historical data), continuous sampling

with a gas chromatograph and hourly

reporting of sulfur content would be

required.

Rationale

The approach of sampling upon a lot

or discrete delivery of gaseous fuel is

being incorporated into today’s

proposed rule for the following reasons.

The Agency believes that discrete

deliveries are sufficiently different from

pipeline transmission of fuel that a

different sampling approach is

appropriate. According to the ideal gas

law, all gas within an enclosed volume

is mixed with a consistent composition;

therefore, a single sample should be

representative of all gas in the volume.

Although gaseous fuels delivered by lot,

such as liquefied petroleum gas, are

higher in sulfur content and have a

wider range of sulfur contents than

pipeline natural gas, they still have

relatively low sulfur contents compared

to liquid and solid fuels. Thus, less

frequent gas sampling appears

appropriate, based on the small

difference in the accuracy of calculated

SO2 mass emissions. For this same

reason, the Agency allowed as-delivered

sampling for diesel fuel in the May 17,

1995 direct final rule (see Docket A–94–

16, Item II–F–2). Finally, because of the

difficulty of sampling gaseous fuels,

EPA believes that it is less burdensome

and less dangerous if gas sampling is

conducted by the gas supplier. It is the

Agency’s understanding that the

sampling for a gas in a discrete delivery

or lot is typically conducted once for the

lot, rather than on a daily basis.

Through a petitioning process, EPA has

already allowed one utility to perform

sampling upon a lot or discrete delivery

of gaseous fuel (see Docket A–97–35,

Items II–C–14 and II–D–22).

EPA is proposing to require daily or

continuous sampling of gaseous fuels

other than pipeline natural gas or the

equivalent that are not shipped in

discrete lots, such as sour natural gas

pumped directly from a field, landfill

gas, or digester gas. Such gaseous fuels

cannot be guaranteed to be stable in

sulfur content. Therefore, proposed

section 2.3.3.4 in Appendix D would

require a minimum of 720 hours of

representative historical data to

characterize the sulfur variability of

such fuels. For the 720 hours of

demonstration data, the mean value and

standard deviation of the fuel sulfur

content would be calculated. If the

mean value does not exceed 7 gr/100 scf

(equivalent to about 10 ppm of SO2

emissions to the atmosphere), daily

sampling would suffice. If the mean

value is greater than 7 gr/100 scf,

however, the variability of the sulfur

content would be assessed in terms of

the standard deviation. If the standard

deviation exceeds 5 gr/100 scf, the

sulfur variability would be considered

too high and continuous sampling of the

fuel with a gas chromatograph would be

required. If continuous sampling were

required, the owner or operator would

have to implement a quality assurance

program for the gas chromatograph. A

copy of the QA plan would be kept onsite, suitable for inspection. For fuel

with a low average sulfur content or a

low sulfur variability, daily sampling

would be sufficient. However, for

gaseous fuel with a higher sulfur

content, if the sulfur variability were too

great, continuous sampling of the fuel

with a gas chromatograph and hourly

reporting of sulfur content would be

required.

3. Sulfur, Density and Gross Calorific

Value Used in Calculations

(a) Fuel Oil.

Background

The hourly SO2 mass emissions rate

due to combustion of oil is calculated

using the mass flow rate of oil

combusted and a sulfur content value

from a sample. If a unit’s oil flow rate

is measured with a volumetric fuel

flowmeter rather than a mass fuel

flowmeter, then it will be necessary to

determine the mass flow rate of oil from

the volume of fuel and a density value

from an oil sample. The heat input rate

is calculated using the flow rate of oil

multiplied by the gross calorific value

(GCV) of a sample.

The sulfur content, density, and GCV

used to calculate emissions and heat

input depend upon the oil sampling

method used. Some sampling methods

are more accurate than others. For

example, for flow proportional or

continuous drip sampling, the actual

sulfur content from a sample is used to

calculate SO2 mass emissions. However,
28084 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

when daily manual samples are taken

under section 2.2.4 of Appendix D, a

facility must use the highest fuel sulfur

content recorded at that unit from the

most recent 30 daily samples, which is

not necessarily the sulfur content of the

fuel being burned at any particular time.

For units where diesel fuel is sampled

upon delivery, section 2.2.1.2 instructs

a facility to calculate SO2 emissions

using the highest sulfur content of any

oil supply combusted in the previous 30

days that the unit combusted oil. In

daily manual sampling and as-delivered

sampling, conservative sulfur values are

used to avoid the possibility of

underestimating SO2 mass emissions

due to variations in sulfur content.

Gross calorific values are taken from the

most recent sample, rather than using

the highest value in the previous 30

days, because, for natural gas, GCV is

more consistent than sulfur content.

Today’s proposed rule includes

changes to the sampling frequency for

oil. Therefore, it is also necessary to

make corresponding changes to the

sulfur content, density, and GCVs to be

used in calculations. For example,

where oil samples would no longer be

taken daily, it would be inappropriate to

calculate SO2 mass emissions based

upon a certain number of daily samples.

In developing today’s proposal, EPA

considered what fuel analysis data

values for sulfur content, density, and

GCV would be appropriate and

consistent with the approaches for

taking manual samples. The appropriate

sulfur content, density, and GCV values

were considered for manual samples

taken from a storage tank at the facility

whenever fuel is added to the tank, for

samples taken from each lot before the

delivery is transferred from tank trucks

or barges, and for samples taken from

the fuel supplier’s storage tank.

Discussion of Proposed Changes

EPA has re-evaluated the sulfur

content, density, and GCVs to be used

to calculate SO2 mass emissions and

heat input based upon the new oil

sampling approaches. For daily manual

oil sampling, a facility would continue

to use the highest sulfur content from

previous 30 daily samples, and the

actual density and GCV. For continuous

oil sampling with an automatic sampler,

a facility would continue to use the

actual sulfur content, density, and GCV.

For the two new methods of manual

sampling, EPA considered whether

conservative or actual values should be

used to calculate emissions and heat

input. EPA also considered whether the

same type of calculational value should

be used for sulfur content, density, and

GCV. For example, if conservative sulfur

content and density values are used to

calculate the SO2 mass emission rate,

should a conservative or an actual

measured GCV be used to calculate the

heat input rate?

For manual samples taken from a

storage tank at a plant whenever fuel is

added to the tank, EPA considered the

following options: (1) using the highest

sulfur content and density from the

previous three samples, and the actual

GCV, (2) using the highest sulfur

content from the previous three

samples, and the actual density and

GCV, (3) using the actual sulfur content,

density, and GCV, (4) using the highest

sulfur content, density, and GCV from

the previous calendar year, and (5)

using the maximum sulfur content,

density, and GCV allowed by fuel

purchase contract with the fuel

supplier. The third, fourth, and fifth

options are incorporated into today’s

proposal in section 2.2.4.2. Under this

approach, a facility would take a sample

from the storage tank whenever fuel is

added to the tank. No blending of fuel

would be allowed from the time the oil

is sampled until the fuel is combusted

by the unit. The sample would be

analyzed for sulfur content, density, and

GCV. Based on the selected option (3, 4,

or 5), the appropriate values would then

be used to calculate the SO2 mass

emission rate and the heat input rate

from the date and hour in which the

transfer of oil is complete until the date

and hour when oil is again added to the

tank.

EPA considered several different

options for the case where a facility or

its supplier would sample each oil

delivery (or the supplier’s storage tank)

before the fuel is transferred into a tank

at the plant. EPA considered whether or

not these values needed to be

conservative and concluded that there

was a real possibility of underestimating

SO2 emissions by using the fuel analysis

values from a delivery. The options that

EPA considered to avoid the

underestimation were: (1) using the

highest sulfur content and density from

all samples taken from oil combusted

during the previous 30 days, and the

actual GCV, (2) using the maximum

sulfur content, density, and GCV in the

fuel purchase contract specifications, (3)

using the highest sulfur content,

density, and GCV from a sample taken

in the previous calendar year, and (4)

using the highest sulfur content,

density, and GCV ever recorded for the

unit. The second and third options are

incorporated into today’s proposed rule

in section 2.2.4.3 of Appendix D.

Under the selected options, a facility

or its supplier would need to sample a

delivery of fuel before it is transferred

into a storage tank. The facility would

then need to keep records of the fuel

analytical results for three years. The

facility would use the conservative

value it selected under option (2) or (3),

above, in order to calculate the SO2

mass emission rate and the heat input

rate. If an as-delivered sample were ever

analyzed and found to have a sulfur

content, density, or GCV that exceeded

the value being used in calculations

(i.e., the contract specification, or the

maximum value measured in the

previous calendar year), then the new

sampled value would be used to

calculate the SO2 mass emission rate or

the heat input rate, as follows. For a unit

using a default value of the maximum

value measured during the previous

calendar year, that new sample value

would become the new default value

and would be reported for the

remainder of the current year and the

next year, unless superseded by a higher

sampled value. For a unit using a

default value of a contract specification,

the new sample value would continue

to be used as the new default value

instead of the contract specification

value, unless superseded by a higher

sampled value or by a new contract.

Rationale

EPA considers continuous sampling

and the measurement of fuel from a

storage tank at a plant after each

addition of fuel to the tank to be highly

accurate methods that will be

representative of the fuel combusted in

a unit. However, if samples are taken

from the truck or barge used to ship the

fuel, or if samples are taken ‘‘asdelivered,’’ the sample values will not

necessarily accurately reflect the oil

being combusted by the unit at any

particular time (see Docket A–97–35,

Item II–E–22). For example, a storage

tank could contain oil with an average

sulfur content of 0.6 percent. Then a

new delivery with a sulfur content of

0.4 percent is received and transferred

to the tank. The ‘‘as-delivered’’ sample

value from the delivery truck would

underestimate the emissions at that

time, since the fuel actually combusted

will combine a mixture of the old fuel

supply in the storage tank and the new

fuel that is added. Thus, a more

conservative sulfur value should be

used to calculate SO2 emissions if

samples are taken from the delivery

containers or from a container used by

the oil supplier.

For density and GCV, today’s

proposal, at the suggestion of some

industry representatives, uses

conservative values determined by the

same method for both parameters (see

Docket A–97–35, Item II–E–24). This
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28085

has the advantage of being easy to

remember and to program. However, if

greater accuracy is desired, a facility

would always have the option of using

actual sulfur content, density, and GCVs

if it took samples from its storage tank

after each addition of fuel to the tank,

or if it took continuous, automatic

samples.

EPA considered which conservative

values would be appropriate for sulfur,

density, and GCV. EPA at first

considered using the maximum value

from all oil supplies combusted in the

previous 30 days. This is similar to the

current wording of section 2.2.1.2 of

Appendix D for calculation of SO2

emissions from diesel fuel as-delivered

sampling. However, in the process of

implementing this provision of part 75,

EPA found this wording was somewhat

confusing and issued policy guidance to

clarify section 2.2.1.2 of Appendix D

(see Docket A–97–35, Item II–I–9, Policy

Manual, Question 2.9). This policy

essentially directs facilities to keep track

of the amount of fuel used as well as its

sulfur content. Because of the more

complicated nature of this accounting,

some industry representatives suggested

that it would be simpler to use a

conservative default value that would

not require tracking fuel usage (see

Docket A–97–35, Item II–E–24). Of the

default values considered, EPA felt that

the most appropriate default values

would be the maximum values

established by agreement with the fuel

supplier through a contract or the

maximum measured value from all

samples in the previous calendar year.

Contractual limits should be higher than

or equal to the actual sulfur content,

density, or GCV. Because not all units

would necessarily have a fuel contract

limiting oil sulfur content, density, or

GCV, EPA is also proposing to provide

the option of using the maximum oil

sulfur content, density, or GCV in the

previous calendar year.

The Agency also considered whether

the current provisions of 2.2.4 of

Appendix D should be retained for

calculation of SO2 emissions using the

highest sulfur from the previous 30

daily samples when performing daily

manual sampling. As discussed above in

Section III.P.2(a) of this preamble on oil

sampling frequency, the Agency is

proposing to retain the option as

requested by at least one utility

representative.

(b) Gaseous Fuels.

Background

The vast majority of Acid Rain units

which burn gaseous fuels combust

pipeline natural gas. Section 2.3.2 of

Appendix D contains a provision for

calculation of SO2 mass emissions from

pipeline natural gas using a default SO2

emission rate in lb/mmBtu and the heat

input rate of pipeline natural gas.

However, if a facility or its supplier is

sampling gaseous fuel for sulfur content,

either because it is not pipeline natural

gas or because the facility chooses to use

a sampled value, then Appendix D

requires the facility to calculate the SO2

mass emission rate using the sulfur

content of the sample and the volume of

gas combusted, and to calculate the heat

input using the GCV of the sample and

the volume of gas combusted (see

Equations D–5 and F–20). Because of

the nature of gaseous fuels, they are

always measured with a volumetric fuel

flowmeter. The formulas for calculating

the SO2 mass emission rate and the heat

input rate use volume directly and do

not require information on gas density.

The current provisions of Appendix D

allow a facility to calculate the SO2

mass emission rate and the heat input

rate using the actual value from a daily

sample of gaseous fuel.

When the provisions of section 2.3 of

Appendix D were added to part 75 in

the May 17, 1995 direct final rule, EPA

presumed that virtually every utility

combusting gaseous fuel was

combusting pipeline natural gas.

However, the Agency found that

utilities were combusting other types of

gaseous fuels. One utility submitted a

monitoring plan and a certification

application for fuel flowmeter

monitoring systems that indicated the

utility was also using propane liquefied

petroleum gas (LPG) (see Docket A–97–

35, Item II–D–6). The utility indicated

that it wished to use the default

emission rate factor reserved for

pipeline natural gas in its monitoring

plan and later petitioned the Agency

specifically for permission to use the

default emission rate factor of 0.0006 lb/

mmBtu. In conversations with utility

staff, EPA found that the utility wanted

to avoid the expense of additional daily

samples and the trouble of entering

daily sulfur values manually into its

data acquisition and handling system

(see Docket A–97–35, Items II–E–11, II–

E–20). The Agency eventually approved

a revised petition for the utility that

allowed the utility to take propane

samples from each discrete delivery,

rather than on a daily basis, where the

utility calculates sulfur dioxide

emissions from propane by using the

highest sulfur content recorded during

the previous 365 days and reports these

data in its quarterly electronic data

report (see Docket A–97–35, Items II–C–

14 and II–D–22).

The Agency found that there were

also some utilities burning gaseous fuels

that were by-products of an industrial

process (see Docket A–94–16, Item II–

D–71). EPA had concerns that such

‘‘digester gas’’ might have a more

variable sulfur content than pipeline

natural gas, since the gaseous fuel

would begin with a higher sulfur

content than pipeline natural gas and

would not necessarily go through a

process that would reduce and stabilize

the sulfur content.

Discussion of Proposed Changes

In today’s proposed rule, the

provisions for sampling gaseous fuels

are found in section 2.3.1 of Appendix

D. For gaseous fuels that are delivered

in discrete lots, a facility would use

conservative values for sulfur content

and GCV to calculate the SO2 mass

emission rate and the heat input rate.

For the sulfur content value, the highest

sampled sulfur content from the

previous calendar year or the maximum

value allowed by contract would be

used to calculate the SO2 mass emission

rate. For GCV, the highest of all sampled

values in the previous calendar year or

the maximum value allowed by contract

would be used to calculate the heat

input rate. If, for any gas sample, the

assumed sulfur content or GCV were

exceeded, the sampled value would

become the new assumed value. For

units using the contract value, the

sampled value would continue to be

used unless a new (higher) contract

specification were put in place or unless

an even higher sampled value is

obtained. For units using the maximum

value from the previous year, the

sampled value would continue to be

used for the remainder of the current

year and for the next calendar year

unless it was superseded by an even

higher sampled value.

For any gaseous fuel where daily fuel

sampling is required, a facility would

use the highest sulfur in the previous 30

daily samples. For gaseous fuels other

than pipeline natural gas, where daily

sampling of sulfur content is required,

the highest GCV from the previous 30

daily samples would be used. For

pipeline natural gas, where monthly

sampling of GCV only is required, the

actual measured GCV, the highest of all

sampled values in the previous calendar

year, or the maximum value allowed by

contract would be used.

For a gaseous fuel that is not

produced in batches and that has a

relatively high sulfur content and a high

sulfur variability, continuous sampling

with a gas chromatograph would be

required. Sulfur content would be

reported as actual measured hourly

average values. The GCV would also be

determined on an hourly basis, or,
28086 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

alternatively, the highest value in the

previous 30 unit operating days could

be reported.

Rationale

For gaseous fuel supplied in discrete

deliveries, EPA is proposing to take the

same approach as for fuel oil that is

being delivered to a plant by barge or

truck. EPA has already approved this

approach with one utility that combusts

liquefied petroleum gas (see Docket A–

97–35, Items II–C–14 and II–D–22).

Because a discrete delivery of gaseous

fuel would be maintained in an

enclosed chamber with a relatively

constant temperature and pressure, one

would expect the gaseous fuel to behave

like an ideal gas. Thus, sulfur and other

constituents of the fuel should be evenly

distributed throughout the delivery of

fuel. Using conservative values to

calculate the SO2 mass emission rate

and the heat input rate should account

for any variability between deliveries.

Furthermore, this reduces the number of

changes that would be made to a data

acquisition and handling system to add

fuel supply data.

For gaseous fuel other than pipeline

natural gas, where daily fuel sampling is

required, EPA considered leaving

unchanged the current provisions of

section 2.3.1 of Appendix D that would

allow a utility to use the actual value

from a day’s sample to calculate the SO2

mass emission rate and the heat input

rate. However, the Agency believes that

it is appropriate to change the sulfur

content value to be a somewhat

conservative historical value. This is

because the Agency has concerns that

there may be some gaseous fuels other

than natural gas, such as digester gas,

that may have significant variability in

their sulfur content over the course of a

day or a longer period of time. This

might result in the underestimation of

the SO2 mass emission rate.

In the case of fuel oil, some industry

representatives suggested it was

simplest to determine the appropriate

conservative values for sulfur content,

density, and GCV by the same method

(see Docket A–97–35, Item II–E–24).

With one exception (for fuels with

relatively high sulfur content and high

sulfur variability), today’s proposal

follows this suggestion for gaseous fuels.

The proposal uses the highest sulfur

content and the highest GCV from the

previous 30 daily samples. This is

currently the procedure used to

determine the sulfur value used in

calculations from daily manual oil

samples. Since this algorithm for daily

manual oil sample calculations is

already being used by many software

programmers, it is a good conservative

value to use for daily samples in this

case. The Agency notes that currently,

the heat input is calculated using the

actual sampled GCV and that this

change would require software

reprogramming for units where gaseous

fuel is sampled daily. However, for

pipeline natural gas that is sampled

monthly for GCV, facilities could

continue to use the actual GCV

measured in a monthly sample. The

other two options are more conservative

and would require software changes.

The Agency requests comment on the

proposal to use the more conservative

GCV value to determine the heat input

rate for gas combustion when gaseous

fuel is sampled daily (which differs

from the current procedure in section

2.3.1.3 of Appendix D and section 5.5.2

of Appendix F).

For gaseous fuel that has a relatively

high sulfur content and high sulfur

variability, daily sampling is not

considered adequate to ensure that SO2

emissions will not be underestimated.

Therefore, for such fuels, continuous

sampling with a gas chromatograph and

hourly reporting of sulfur content would

be required. For GCV, which is expected

to be less variable than sulfur content,

either the actual hourly measured value

or the highest GCV value obtained in the

last 30 unit operating days could be

reported.

4. Missing Data Procedures for Sulfur,

Density, and Gross Calorific Value

Background

(a) Fuel Oil. The May 17, 1995 direct

final rule included missing data

procedures for missing analytical

information on sulfur content, density,

and GCV in section 2.4 of Appendix D.

These procedures are based on a daily

sampling frequency. For example,

missing sulfur content, density, or GCV

data are to be calculated using the

highest measured sulfur content, oil

density, or GCV during the previous

thirty days when the unit burned oil.

This was intended to mean that the

substitute data values are to be based on

the previous thirty daily oil samples for

which data are available.

In order to ensure that a DAHS is

capable of implementing the missing

data procedures required by the rule,

§ 75.20(c)(7) and § 75.20(g)(1)(ii) require

testing of each DAHS. EPA issued

policy guidance discussing how

facilities should report the results of

these tests for units measured with fuel

flowmeters. This policy guidance

provided a form checklist that facilities

could use to show the results of their

own tests of the missing data

substitution procedures (see Docket A–

97–35, Item II–I–9, Policy Manual,

Question 15.9). Some utilities objected

to testing the DAHS missing data

procedures on the grounds that they

should never miss sample data. In part,

this would be because the facility is

required, under section 2.2.5 of

Appendix D, to split its sample and

keep a portion. One utility offered to

substitute the maximum potential sulfur

content, which would require less

complicated DAHS programming than

using the maximum sulfur content of

the previous 30 daily samples.

(b) Gaseous Fuels. Section 2.4.1 of

Appendix D, as revised by the May 17,

1995 direct final rule, provides missing

data substitution procedures for missing

sulfur data from daily samples of

gaseous fuel. The DAHS is required to

substitute the highest measured sulfur

content recorded during the previous 30

days when the unit combusted gaseous

fuel. As for oil, this was intended to be

the highest sulfur value from the

previous 30 daily samples with

available sulfur values. Section 2.4.2 of

Appendix D requires the substitution of

the highest measured GCV recorded

during the previous three months that

the unit burned gaseous fuel when data

are missing from a monthly gaseous fuel

sample. As for fuel oil, the missing data

procedures for gaseous fuels are linked

to the frequency of fuel sampling.

A utility indicated to EPA that

because it receives gas sampling

information from its supplier, it should

never have missing data for GCV. The

utility suggested that it should not have

to go to the expense of programming its

DAHS for missing data procedures that

should never need to be used. This

argument was similar to that used by

another utility when referring to missing

data procedures for manual samples of

fuel oil taken upon each delivery.

Discussion of Proposed Changes

EPA proposes to revise the missing

data substitution procedures for both

fuel oil and gaseous fuel, in order to

simplify them. For any instance in

which the sulfur content, GCV, or

density value is missing, the maximum

potential value would be reported until

the results of a subsequent valid sulfur

content analysis, GCV determination, or

density measurement are obtained. The

proposed appropriate maximum

potential values are specified in the

table below. The default values for

sulfur content, GCV, and density of

residual oil and diesel fuel were taken

from handbook values (see Docket A–

97–35, Item II–A–7). The default

maximum sulfur content values for

gaseous fuel are consistent with the

maximum sulfur content allowed under
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28087

the definition of natural gas and the de

facto maximum sulfur content of

pipeline natural gas, based on the

proposed definition. Thus, any gas with

a sulfur content that did not allow it to

qualify as pipeline natural gas (i.e.,

greater than 0.30 gr/100 scf) but still

allowed it to be measured following

Appendix D procedures (i.e., total sulfur

content not exceeding 20.0 gr/100 scf)

would have a default maximum

potential sulfur content of 20.0 gr/100

scf. The default values for GCV of

gaseous fuels were taken from handbook

values (see Docket A–97–35, Item II–I–

1). For pipeline natural gas, it is

assumed that the gas is primarily

methane (GCV of 1050 Btu/scf) with a

small amount of other hydrocarbons

with a higher GCV (see Docket A–97–35,

Item II–E–19). For other gaseous fuels, it

is assumed that they are primarily

butane (GCV of 2100 Btu/scf), the

hydrocarbon gas with the highest GCV

of gases commercially used for fuel.

MAXIMUM POTENTIAL DEFAULT VALUES FOR SULFUR CONTENT, DENSITY, AND GCV DATA

Parameter Fuel Maximum potential

default value

Sulfur content ..................................................................... residual oil .......................................................................... 3.5 percent by weight.

diesel fuel ........................................................................... 1.0 percent by weight.

pipeline natural gas ........................................................... 0.30 gr/100 scf.

gaseous fuels with sulfur content greater than pipeline

natural gas.

20.0 gr/100 scf.

GCV/heat content ............................................................... residual oil .......................................................................... 19,500 Btu/lb.

diesel fuel ........................................................................... 20,000 Btu/lb.

pipeline natural gas ........................................................... 1100 Btu/scf.

gaseous fuels with sulfur content greater than pipeline

natural gas.

2100 Btu/scf.

Oil Density .......................................................................... residual oil .......................................................................... 8.5 lb/gal,

diesel fuel ........................................................................... 7.4 lb/gal.

Rationale

(a) Fuel Oil. It seems possible that a

facility might occasionally miss a

sample taken with an automatic

sampler, and thus, would have missing

data. Therefore, today’s proposal

includes a provision for substitution of

missing sulfur content, density, and

GCV data from continuous, automatic

sampling.

Based upon comments from some

utilities, it seems relatively unlikely that

both a facility and its supplier would

miss performing a sample during a

delivery. Both a facility and its fuel

supplier will want to verify that the fuel

delivered is actually supplying the heat

content that it is supposed to, either

under a contract or a fuel specification;

thus, both a facility and its fuel supplier

will have an incentive to ensure

sampling takes place for a delivery.

Furthermore, if samples taken by a

facility are split, then there should

generally be the ability to provide

analytical data for that fuel, even if test

results were somehow lost. Because the

event of missing fuel samples is

unlikely for as-delivered samples, EPA

believes that it would be appropriate to

establish a simple, conservative value

that could easily be substituted in a data

acquisition and handling system. This

would be easier to program than using

historical values that require tracking

fuel usage over an extended period of

time.

EPA is specifically proposing the

most conservative (maximum potential)

values for missing data purposes. This

would ensure that substituted missing

data values would be less advantageous

to a facility than taking samples and

using sulfur content, density, and GCV

data from samples. In addition, several

utilities suggested to EPA that this was

a reasonable approach (see Docket A–

97–35, Item II–E–24).

(b) Gaseous Fuels. As mentioned

previously, gas sampling is generally

performed by fuel suppliers because of

the difficulty and potential danger of

opening up a pressurized pipe

containing a highly flammable gas. It

seems extremely unlikely that a fuel

supplier would not have information

available on the sulfur content or GCV

of gaseous fuel, since industrial

customers will purchase fuel or agree to

a contract based upon these

characteristics. The exception to this

might be gaseous fuel manufactured

through an industrial process that is not

produced specifically for sale as a fuel,

such as digester gas. In today’s proposed

rule, EPA is using the same reasoning as

above for missing manual fuel oil

sample data and is using the same basic

substitution approach for missing sulfur

content and GCV data for gaseous fuel.

EPA considered keeping the existing

missing data substitution procedures

from sections 2.4.1 and 2.4.2 of

Appendix D for missing data from

gaseous fuel. This would have the

advantage of requiring no

reprogramming of software for facilities

already following the existing

procedures. EPA also considered using

the maximum sulfur content or GCV

from the previous calendar year, the

same procedure proposed in today’s

rule for calculation of SO2 mass

emission rate or heat input, for discrete

deliveries of gas or for manual samples

of oil taken from a delivery truck or

barge. However, using the proposed

maximum value would require little

reprogramming and would greatly

simplify the missing data procedures. In

policy guidance, the Agency has

indicated it would accept a simplified

DAHS for units using the procedures of

Appendices D and E. In particular, these

policies endorse manual entry of fuel

analytical data, simplified missing data

procedures for fuel flowmeters, and a

DAHS that uses commercial spreadsheet

software instead of a specialized custom

software for purposes of part 75 (see

Docket A–97–35, Item II–I–9, Policy

Manual, Questions 14.72 and 14.73). In

keeping with the policy of allowing

Appendices D and E units to use

commercial spreadsheet software, EPA

has proposed what it believes to be the

simplest possible missing data

substitution procedure for missing

sulfur content and GCV data. In

addition, using the proposed maximum

potential sulfur content or GCV would

ensure that substituted missing data

values are more conservative than the

values normally used to calculate the

SO2 mass emission rate and the heat

input rate.
28088 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

5. Installation of Fuel Flowmeters for

Recirculation

Background

The current provisions of section

2.1.1 of Appendix D require the use of

an additional ‘‘return’’ fuel flowmeter

when some fuel is recirculated, i.e.,

initially sent toward a unit and then

diverted away from the unit without

being burned. This additional fuel

flowmeter is required, regardless of the

amount of fuel being diverted.

At least one utility has requested to

use only the fuel flowmeter measuring

fuel leaving the oil tank without a

second fuel flowmeter to measure any

fuel diverted away by the recirculation

fuel line. The utility argued that using

a single fuel flowmeter would result

only in the overestimation of SO2

emissions, since the utility would

measure a larger amount of fuel usage.

This would allow the facility to avoid

the expense of installation, certification,

and quality assurance testing on a fuel

flowmeter on the recirculation fuel line.

Since the proportion of fuel being

recirculated was minimal, the utility

was willing to use a more conservative

SO2 emissions calculation in exchange

for devoting fewer resources for the

testing and maintenance of the

recirculation line fuel flowmeter.

Discussion of Proposed Changes

In today’s proposal, EPA proposes to

allow facilities to use only a fuel

flowmeter on the main fuel line from

the oil tank if the amount of oil

recirculated is demonstrated to be less

than 5.0 percent of total fuel usage for

each hour during the year.

Rationale

EPA believes that it is reasonable not

to require installation, certification and

quality assurance of secondary fuel

flowmeters in cases where the amount

of fuel to be combusted is a small

proportion of the total fuel used, and

where knowing the exact volume of the

recirculated fuel makes little difference

in the calculation of emissions and heat

input. EPA has allowed one utility to

use an estimate of the maximum oil

usage at start-up, rather than requiring

the utility to install a return line oil

flowmeter to measure the startup fuel

flow rate.

At first, EPA considered making the

installation of a fuel flowmeter on a

recirculation fuel line optional.

Presumably, if the cost in lost SO2

allowances were greater than the cost of

installing and maintaining a fuel

flowmeter, then a facility would choose

to use a fuel flowmeter on the

recirculation fuel line. However, many

fuel flowmeters used under Appendix D

for determining the SO2 mass emission

rate and the heat input rate are also used

to estimate the NOX emission rate in lb/

mmBtu under Appendix E to part 75.

The Appendix E procedures estimate

hourly NOX emission rates using a

correlation between measured NOX

emission rates and heat input rates. The

correlation is established during a

testing period. Therefore, subsequent to

the test period, if the hourly heat input

values should become less accurate, it

could result in the estimated NOX

emission rates becoming less accurate.

Such loss in accuracy could occur if the

heat input rates during the initial testing

period were based upon subtraction of

measured volumes or masses of

recirculated fuel from the total fuel flow

rates, and then the facility later began

estimating, rather than measuring, the

recirculated fuel volumes or masses.

The potential inaccuracy would

increase if the proportion of recirculated

oil to the total flow rate of oil varies over

time. The NOX emission rate can

sometimes increase with increases in

the heat input rate and can sometimes

decrease with increases in the heat

input rate, depending on the particular

type of boiler; in addition, when certain

types of control equipment are installed,

the NOX emission rate may not have any

relationship with the heat input. Thus,

an overestimation of the heat input rate

would sometimes result in the

overestimation and sometimes result in

the underestimation of the NOX

emission rate under Appendix E. For

these reasons, EPA believes that there

needs to be some limits on the cases

where a facility can choose not to use

a return fuel flowmeter.

In today’s proposed rule, EPA is

proposing that a facility may choose to

use only a fuel flowmeter on the main

fuel line from the oil tank and not

install a return meter in those cases

where the previously measured

proportion of oil from the recirculation

line is less than or equal to 5.0 percent

of the unit’s total oil usage during each

hour of the year. EPA believes that an

error of 5.0 percent in the heat input

rate should be small enough that it will

not significantly affect accounting for

the NOX emission rate under Appendix

E. An analysis of emissions data from a

gas-fired Appendix E unit with a higher

than average NOX emission rate for gas

(0.157 lb/mmBtu) showed that a 5.0

percent increase in heat input would

change the quarterly average NOX

emission rate by only 3.17 percent

(0.152 vs. 0.157 lb/mmBtu) (see Docket

A–97–35, Item II–B–19). At the same

time, EPA believes that an average

proportion of 5.0 percent of total fuel

usage should provide relief for the most

extreme situations where it might cost

more to perform quality assurance

testing on a return fuel flowmeter than

the value of the allowances saved by

monitoring with the return flowmeter.

The Agency also considered whether

it would be more appropriate to

determine the proportion of recirculated

fuel on an hourly average basis or on an

annual average basis to determine if the

returned fuel was less than 5.0 percent

of total fuel usage. The Agency

concluded that the proportion of fuel

could be determined only if a return

fuel flowmeter were already installed on

the recirculation fuel line. Thus, there

would appear to be little advantage to

basing the proportion of fuel on an

annual basis. Hourly average fuel flow

rate would also be more directly related

to the heat input rate used to calculate

hourly NOX emission rate under

Appendix E. EPA notes this is not fully

consistent with the objective of revising

this provision, i.e., to exempt facilities

from installation and operation of

additional fuel flowmeters. Therefore,

the Agency believes it is better to base

the reduced fuel flow rate monitoring

requirement either on actual historical

fuel flowmeter data or on some other

method, as yet unknown, that would

yield a reasonable estimate of the

average proportion of fuel recirculated

to the total amount of fuel used. At this

time, the Agency is unaware of what

other methods could provide a

reasonable estimate of the average

proportion of fuel recirculated to the

total amount of fuel used, either on an

hourly or an annual basis. Accordingly,

the Agency would allow facilities to

suggest methods through the petitioning

process of § 75.66.

6. Fuel Flowmeter Testing

(a) Fuel Flowmeter Accuracy Tests.

Background

Sections 2.1.5 and 2.1.6 of Appendix

D, as revised by the May 17, 1995 direct

final rule, refer to calibration and

recalibration of fuel flowmeters. Section

2.1.5.2 gives procedures for a test of the

flowmeter accuracy by comparing a

candidate flowmeter against another

flowmeter that has already been

calibrated according to specified

procedures. If a flowmeter does not

meet the specified accuracy, then it

would need to be recalibrated by

adjusting it, then retested to ensure it is

reading accurately.

Some utilities have found confusing

the terminology of ‘‘calibration’’ for a

test that compares measurements from

two different flowmeters. Generally, the
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28089

term ‘‘calibration’’ is used to refer to

adjustments made to a flowmeter to

ensure it is reading accurately.

However, the type of test described in

section 2.1.5.2 is more like a relative

accuracy test audit than a calibration, in

that it checks the flowmeter accuracy by

comparing the fuel flowmeter readings

against readings from an outside

standard.

Discussion of Proposed Changes

To alleviate the confusion

surrounding flowmeter testing, today’s

proposal introduces the term

‘‘flowmeter accuracy test.’’ This

terminology is used in sections 2.1.5

and 2.1.6 of Appendix D.

Rationale

EPA believes that the term ‘‘flowmeter

accuracy test’’ more clearly reflects the

nature of the test that is performed.

Introducing this new term also will

clarify that the word ‘‘calibration’’ refers

to flowmeter adjustments, rather than to

a comparative test between a candidate

flowmeter and a reference meter.

(b) Methods for Fuel Flowmeter

Accuracy Testing.

Background

Section 2.1.5.1 of Appendix D, as

revised by the May 17, 1995 direct final

rule, includes a list of standards and

procedures that may be used to

determine if a flowmeter is sufficiently

accurate for use under the Acid Rain

Program. However, because of the large

number of different brands and kinds of

fuel flowmeters, there are also many

manufacturers’ procedures that are not

explicitly permitted under part 75.

Consequently, many Acid Rain

certification applications for units with

fuel flowmeters have contained

petitions under §§ 75.23 and 75.66 for

approval of other fuel flowmeter testing

procedures. Among those methods was

AGA Report No. 7 for turbine

flowmeters. This method was

incorporated by reference into part 75 in

the November 20, 1996 final rule. In

addition, another standard method that

EPA approved through petitions is

American Petroleum Institute (API)

Section 2, ‘‘Conventional Pipe Provers,’’

from Chapter 4 of the Manual of

Petroleum Measurement Standards,

October 1988 edition (see reproduction

of this document in Docket A–97–35,

Item II–D–10 (Attachment B)).

In the process of implementing part

75, many utilities have commented on

the problems of testing and calibrating

fuel flowmeters. Unlike CEMS or stack

flow monitors, it is not always possible

to perform an accuracy test with the fuel

flowmeter remaining in the pipe where

it is installed. Utilities have stated that

certain fuel flowmeters are extremely

difficult to remove, send out for testing,

recalibrate, and then reinstall (see

Docket A–97–35, Item II–E–22). In

addition, removing a fuel flowmeter

from in-line may require stopping flow

of the fuel and possibly shutting down

the unit, with negative economic

consequences (see Docket A–97–35,

Item II–E–8). In addition, if a facility

needs to operate a unit while the

flowmeter is being tested at a laboratory,

then no flow data will be available for

the fuel measured by the flowmeter

unless the facility has a backup fuel

flowmeter. Utilities have petitioned for

alternative quality assurance procedures

for fuel flowmeters in order to avoid the

inconvenience and expense of removing

the fuel flowmeter and testing it (see

Docket A–97–35, Item II–D–9). Because

of this, the Agency has been evaluating

various ways of testing a fuel flowmeter

in-line (that is, still installed in the pipe

in its regular position).

Some utilities have suggested that an

alternative way to check fuel flowmeter

accuracy would be to compare over time

the ratio of the fuel flowrate to unit

output (‘‘load’’), measured either in

electrical generation in MWe or in steam

flow in 1000 lb/hr (see Docket A–97–35,

Item II–E–21). A fuel flow-to-load

comparison could be used to determine

if fuel flowmeter readings are still

similar to the readings obtained the last

time the fuel flowmeter was tested

against an outside method. A significant

change in the amount of fuel used at a

load level would call into question the

validity of fuel flow readings from a

flowmeter. A fuel flow-to-load

comparison could provide this check

without removal of the fuel flowmeter

from its installed location, which would

be of considerable benefit to facilities.

Discussion of Proposed Changes

EPA is proposing to incorporate by

reference the standard: American

Petroleum Institute (API) Section 2,

‘‘Conventional Pipe Provers,’’ from

Chapter 4 of the Manual of Petroleum

Measurement Standards. The Agency

also specifically requests comment on

any other voluntary consensus

standards from standard setting

organizations, such as API, AGA,

ASME, or ISO, that would be

appropriate for incorporation by

reference into part 75. Any suggested

methods should also be submitted to the

Agency as part of the comments to assist

in the Agency’s evaluation.

Section 2.1.7 of Appendix D to

today’s proposed rule includes

provisions for an optional,

supplemental quality assurance test for

fuel flowmeters using a ratio of the fuel

flow rate and the unit load. The fuel

flow rate-to-load ratio comparison test

would provide an additional way to

meet the requirement to periodically

test fuel flowmeter accuracy. This test

would serve as a supplement to more

rigorous fuel flowmeter tests. These

more rigorous tests include the

standards incorporated by reference

under section 2.1.5.1 of Appendix D

that require the fuel flowmeter to be

taken out of line and shipped to a

laboratory, and the ‘‘master meter’’

comparison procedures under section

2.1.5.2 of Appendix D. For orifice-,

nozzle-, and venturi-type flowmeters,

the more rigorous tests would include

an inspection of the primary element

and an accuracy test on the transmitters

or transducers. If a facility performed

and passed regular quarterly fuel flowto-load ratio testing, then it would need

to perform the more rigorous checks on

monitor performance only once every 20

calendar quarters (five years).

The fuel flow-to-load ratio test would

require a facility to establish a baseline

period from a period of time when the

fuel flowmeter is known to be operating

properly. After establishing this baseline

of accurate fuel flow data (or heat input

rate data), a facility would calculate the

fuel flow-to-load ratio (or ‘‘gross heat

rate’’ (GHR)) during the baseline period.

In each ‘‘flowmeter operating quarter’’

that the fuel flowmeter operates after the

baseline period is completed, the

facility would calculate the fuel flow-toload ratio (or GHR) for each hour the

fuel flowmeter is used to report data.

The facility would compare the hourly

fuel flow-to-load ratio (or GHR) to the

fuel flow-to-load ratio (or GHR) during

the baseline period in order to calculate

the absolute value of the percentage

difference for each hour. Next, the

facility would calculate the average

percentage difference for the quarter. If

the percentage difference exceeded the

specified limits for the test, the fuel

flowmeter would fail the test. The key

elements of the fuel flow rate-to-load

evaluation are discussed in the

following paragraphs.

(1) Use of Gross Heat Rate-to-Load

Ratio. Today’s proposed rule would

allow a facility the option of calculating

either the ratio of the fuel flow rate to

the gross generation in MWe or the

steam flow rate in thousands of pounds

of steam per hour (‘‘fuel flow-to-load

ratio’’) or the ratio of the heat input rate

to the gross generation in MWe or the

steam flow rate in thousands of pounds

of steam per hour (‘‘GHR’’). In order to

allow a meaningful comparison, a

facility would use one of these two

ratios consistently, both in calculating
28090 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

an initial baseline ratio and in

calculating hourly ratios during a

particular quarter. Equations D–1c and

D–1e describe the calculation of the fuel

flow-to-load ratio for the baseline period

and for hourly values during a calendar

quarter, respectively. For the GHR, the

respective equations are Equations D–1d

and D-1f. These equations are found in

proposed sections 2.1.7.1 and 2.1.7.2 of

Appendix D.

(2) Baseline Period for Fuel Flow-toLoad Ratio. The provisions for

calculating the baseline fuel flow-toload ratio or gross heat rate are found in

section 2.1.7.1 of today’s proposed rule.

EPA is proposing that the owner or

operator of a facility would establish a

baseline of fuel flow rate (or heat input

rate) data following a flowmeter

accuracy test under either section

2.1.5.1 or 2.1.5.2 of Appendix D, or

following both a transmitter or

transducer accuracy test under section

2.1.6.1 of Appendix D and an inspection

of a primary element for an orifice-,

nozzle-, or venturi-type fuel flowmeter

under section 2.1.6.6. Throughout

section 2.1.7 of today’s proposed rule,

these are referred to as ‘‘the most recent

quality assurance procedure(s).’’ The

baseline period of fuel flow rate (or heat

input rate) data for a fuel flowmeter to

be tested under section 2.1.7 would use

the first 168 hours of quality assured

data measured by that flowmeter

following the most recent quality

assurance procedure(s) for which: (1)

only the fuel measured by that fuel

flowmeter is combusted (i.e., no cofiring of fuels occurs); (2) the load is

relatively stable and not ‘‘ramping’’

rapidly up or down; and (3) the load is

sufficiently above the minimum safe,

stable operating load (unless low-load

operation is normal for the unit).

Today’s proposal includes a limit to

the length of time over which the

baseline period could extend. The

baseline period of 168 hours could not

extend for longer than the end of the

second calendar quarter following the

calendar quarter in which the most

recent quality assurance procedure(s)

was performed. For orifice-, nozzle-, and

venturi-type fuel flowmeters, two

quality assurance procedures would be

required: both a transmitter or

transducer accuracy test under section

2.1.6.1 of Appendix D and an inspection

of a primary element, such as an orifice

plate. For practical purposes, this means

that the transmitter or transducer

accuracy test and the primary element

inspection would have to be completed

either in the same calendar quarter or in

consecutive calendar quarters. If there

were not 168 hours of quality-assured

fuel flowmeter data from hours when a

single fuel is combusted, then the fuel

flowmeter would not be allowed to be

tested using the fuel flow-to-load ratio

as a supplement to other quality

assurance tests.

The 168 hours of quality-assured fuel

flowmeter data next would be averaged

and divided by the average load, in

megawatts or 1000 lb steam/hr, during

the same 168 hours to determine the

baseline fuel flow-to-load ratio (see

Equation D–1c). Alternatively, the

facility could instead calculate the gross

heat rate by averaging hourly heat input

rate during the 168 hours of the baseline

period and by dividing the average heat

input rate by the average load during the

same 168 hours (see Equation D–1d).

In cases where the fuel flowmeter is

located on a common pipe header, one

fuel flow rate measurement could be

associated with the load from several

units that receive fuel from the common

pipe header. In order to analyze the fuel

flow-to-load ratio for a flowmeter on a

common pipe header, the load from all

units receiving fuel from the common

pipe header would have to be combined

for each hour, averaged over the

baseline period of 168 hours, and

compared to the average fuel flow rate

during the baseline period. If a single

unit receives fuel from multiple pipes,

each pipe with its own fuel flowmeter,

then the flow rates from all fuel

flowmeters would have to be added

together to obtain the average fuel

flowrate for the unit to be divided by the

unit load.

(3) Data Preparation and Analysis. In

each flowmeter operating quarter

following the final quarter of the

baseline period, all hourly fuel

flowmeter data would be compared to

the load. A flowmeter operating quarter

would be a calendar quarter in which

the unit combusts the fuel measured by

the fuel flowmeter for at least 168 hours.

For each hour in which the fuel is

combusted, the owner or operator

would calculate the fuel flow-to-load

ratio (or GHR) (see Equation D–1e for

the fuel flow-to-load ratio and Equation

D–1f for the GHR). Hourly fuel flow

rates on common pipe headers would be

compared to the sum of the loads from

all units receiving fuel from the

common pipe header. For units with

multiple pipes and multiple fuel

flowmeters, the total hourly fuel flow

rate for the fuel would be compared to

the unit load.

Next, the facility would compare the

hourly fuel flow-to-load ratios (or GHRs)

to the baseline fuel flow-to-load ratio (or

GHR). The absolute value of the

percentage difference would be

calculated for each hour using Equation

D–1g. Then the facility would calculate

the average value of the percentage

difference for the quarter, using each

hourly percentage difference in

Equation D–1h.

The quarterly average of the hourly

percentage difference values next would

be compared to the limitation. For either

the fuel flow-to-load ratio or the GHR,

Ef, the quarterly average of the hourly

percentage difference values would

need to be no greater than 10.0 percent,

unless the average of the hourly loads

used for the analysis was ≤ 50 MWe (or

≤ 500 klb/hr of steam), in which case the

limit on Ef would be 15.0 percent. If a

fuel flowmeter were to fail to meet this

limit when using all data in the

flowmeter operating quarter, then the

facility would have the option of

excluding certain hours. Otherwise, a

failure to meet the 10.0 percent (or 15.0

percent, if applicable) limit would be

considered a failure of the fuel flow-toload ratio test.

(4) Optional Data Exclusions. As

mentioned above, if a fuel flowmeter’s

data would not meet the 10.0 percent (or

15.0 percent, if applicable) limit on the

quarterly average of the percentage

difference values, then a facility could

opt to exclude certain hours of

unrepresentative fuel flow rate (or heat

input rate) data and then reanalyze the

smaller set of data. The types of data

that EPA proposes as non-representative

would be the same as the hours

excluded during the baseline period,

including: (1) hours when the unit

combusts multiple fuels measured by

multiple fuel flowmeters, such as cofiring of gas and residual oil or co-firing

of residual oil and diesel fuel; (2) hours

when the unit load is rapidly rising or

falling, sometimes referred to as

‘‘ramping,’’ to such a degree that the

load in a given hour differs by more

than ± 15.0 percent from the load during

either the previous hour or the hour

afterwards; or (3) hours in which the

unit load is in the lower 10.0 percent of

the unit’s operating range, unless

operation at those low levels is

considered normal for the unit. The

facility would proceed to analyze the

remaining quarterly fuel flow rate or

heat input rate values, provided that

there are at least 168 hours remaining

for the quarter after excluding nonrepresentative hours. If less than 168

representative hours remained after

excluding the allowable hours, then a

flow-to-load or GHR test would not be

required for that flowmeter for that

flowmeter operating quarter. If the fuel

flowmeter data still failed to meet the

10.0 percent (or 15.0 percent, if

applicable) limit on the quarterly

average of the percentage difference

values after excluding the allowable
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28091

hours, the flowmeter would fail the fuel

flow-to-load ratio test.

(5) Consequences of Failing Fuel

Flow-to-Load Ratio or GHR Tests. There

would be two primary consequences of

failing a fuel flow-to-load ratio or a GHR

test. First, the data from the fuel

flowmeter would no longer be

considered quality-assured. Thus, the

facility would need to invalidate data

from the fuel flowmeter following the

test. Proposed section 2.1.7.4 of

Appendix D specifies that the missing

data procedures of section 2.4.2 of

Appendix D would be used to substitute

for the invalid data (unless a different

fuel flowmeter is available that has been

tested for accuracy and has been

demonstrated to meet the accuracy

specification), beginning with the first

hour the fuel measured by the fuel

flowmeter is used during the quarter

following the flowmeter operating

quarter in which the meter fails the fuel

flow-to-load ratio test. Second, in order

to establish that the fuel flowmeter is

again operating properly and providing

quality-assured data, the facility would

perform a fuel flowmeter accuracy test

according to sections 2.1.5.1 or 2.1.5.2

of Appendix D or, for orifice-, nozzle-,

and venturi-type flowmeters, a

transmitter or transducer accuracy test

according to section 2.1.6.1 of Appendix

D. In addition to the transmitter or

transducer test, orifice-, nozzle-, and

venturi-type fuel flowmeters would

need to be further tested following a

failed flow-to-load or GHR test in order

to ensure that the problem causing the

failure of the fuel flow-to-load ratio was

a problem with the transmitters or

transducers.

Once the orifice-, nozzle-, or venturitype flowmeter has been recalibrated

and passes a transmitter or transducer

accuracy test according to section

2.1.6.1 of Appendix D, the facility

would perform a shortened version of

the fuel flow-to-load ratio test. The

shortened version of the test would use

six to twelve hours of data following the

passed transmitter or transducer

accuracy test. If the fuel flowmeter

passed the abbreviated fuel flow-to-load

ratio test, then its data would be

considered valid, beginning with the

time and date of the passed transmitter

or transducer accuracy test. However, if

the fuel flowmeter were to fail the

abbreviated fuel flow-to-load ratio test,

then it would be necessary for the

facility to inspect the primary element

for corrosion or damage. Furthermore,

data would be considered invalid until

the orifice-, nozzle-, or venturi-type fuel

flowmeter passes an inspection of the

primary element. Although data from

the flowmeter would be considered

quality-assured after successful

completion of all required accuracy

testing, visual inspections and

diagnostic tests, the baseline would

have to be re-established no later than

the end of the second flowmeter

operating quarter following the quarter

in which the quality assurance tests are

completed.

Rationale:

EPA is proposing to incorporate by

reference the standard: American

Petroleum Institute (API) Section 2,

‘‘Conventional Pipe Provers,’’ from

Chapter 4 of the Manual of Petroleum

Measurement Standards, October 1988

edition. The Agency has already

approved this method of fuel flowmeter

testing in response to a petition (see

Docket A–97–35, Item II-C–6). This is

also a standard agreed to by API that is

traceable to NIST standards. The

Agency has a general policy of

approving standards from technically

knowledgeable groups such as the

Organization for International Standards

(ISO), the American Society for Testing

and Materials (ASTM), the American

Society of Mechanical Engineers

(ASME), the American Gas Association

(AGA), the Gas Processors Association

(GPA), and API. EPA would also be

willing to incorporate additional

standards by reference if commenters

supply a copy for consideration.

The Agency recognizes that it is

difficult and sometimes costly to take a

fuel flowmeter out from its installation

location to be tested (see Docket A–97–

35, Item II-E–22). Today’s proposed rule

would provide the flexibility of an

additional approach for testing fuel

flowmeters where they are installed.

Today’s proposal for a fuel flow rate-toload comparison test would allow

facilities to assure the quality of their

fuel flow rate data without taking a fuel

flowmeter out of line. Several industry

representatives suggested that a fuel

flow rate-to-load comparison was a

useful approach to quality assuring data

(see Docket A–97–35, Items II–E–22, II–

E–23). Some industry representatives

felt that a fuel flow rate-to-load ratio

was straightforward and even more

representative than a stack flow rate-toload ratio (see Docket A–97–35, Item IIE–23).

In general, utilities have indicated

that the idea of a fuel flow-to-load ratio

is an appropriate quality assurance test

for fuel flowmeters (see Docket A–97–

35, Items II–D–30, II–D–41, II–E–33).

Use of the fuel flow-to-load ratio was

first suggested to the Agency as an

alternative to annual orifice inspections

(see Docket A–97–35, Item II–E–22).

One utility mentioned that the fuel

flow-to-load ratio test would be most

useful if it allowed them to stretch the

time between transmitter or transducer

accuracy tests on orifice-, nozzle-, and

venturi-type fuel flowmeters, as well as

primary element inspections and fuel

flowmeter accuracy tests performed inline against a ‘‘master meter’’ or

performed in a laboratory (see Docket

A–97–35, Item II–D–49).

Utilities have also indicated that they

would prefer the provisions of the fuel

flow-to-load ratio test to be as similar as

possible to the stack flow-to-load ratio

test in today’s proposed rule (see Docket

A–97–35, Item II-E–33). This would be

easier for facilities to comply with

because they would need to learn fewer

new procedures, they could use the

same equations and algorithms in

computer software or hand calculations,

and they could report information in a

similar format. To the extent possible,

the Agency has incorporated this

suggestion in today’s proposed rule.

However, because monitoring with fuel

flowmeters is not identical to

monitoring with stack volumetric flow

monitors, there are some differences in

the procedures and in the data to be

recorded and reported.

Today’s proposed rule would allow

the quarterly fuel flow-to-load ratio test

as an optional supplement to flowmeter

accuracy tests under section 2.1.5.1 or

2.1.5.2 of Appendix D, transmitter or

transducer accuracy tests under section

2.1.6.1 of Appendix D for orifice-,

nozzle-, and venturi-type fuel

flowmeters, and visual inspections of

the primary element required under

section 2.1.6.6 of Appendix D for

orifice-, nozzle-and venturi-type fuel

flowmeters. These more rigorous fuel

flowmeter quality assurance procedures

would still be required at least once

every 20 calendar quarters (five years),

even if the procedures of section 2.1.7

of Appendix D were followed. The

Agency has proposed a quarterly fuel

flow-to-load ratio test for several

reasons: (1) this is consistent with the

provisions of the proposed volumetric

stack flow-to-load ratio test in today’s

proposed rule; (2) the test involves

examining data more closely when

preparing quarterly reports; and (3) a

quarterly test allows facilities to find

problems in fuel flowmeter data before

an entire year has passed. The Agency

also considered requiring the fuel flowto-load ratio to be used more frequently

than quarterly, perhaps daily; however,

this would require facilities to spend far

more time and effort in evaluating data

at different times during the quarter

than they may do currently, particularly

for small, infrequently operated units. In

addition, many utilities claim that fuel
28092 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

flowmeters tend to be stable, and

therefore little change would be

expected over short time periods such

as a day (see Docket A–97–35, Item II–

E–33).

EPA is proposing that the optional

fuel flow-to-load ratio test could serve

as a supplement to other quality

assurance procedures for fuel

flowmeters for up to 20 calendar

quarters (five years). EPA is proposing a

time period of 20 calendar quarters for

the following reasons. First, it is similar

to the current provision in section

2.1.5.2 of Appendix D, which allows a

reference fuel flowmeter to be accuracy

tested as seldom as once in five calendar

years if comparison with an in-line

‘‘master’’ flowmeter shows less than a

1.0 percent difference in their flow

rates. Second, a five-year test cycle

offers certain administrative advantages.

For instance, fuel flowmeters used to

provide heat input data for the heat

input-versus-load correlation of

Appendix E could be accuracy-tested

before each Appendix E test (i.e., once

every five years). In addition, a five-year

period would ensure that fuel

flowmeters are tested by the time the

unit’s operating permit is renewed. The

20 calendar quarter (five-year) period is

consistent with the provisions for

reduced three-level flow RATAs for

stack flow monitors. The 20 calendar

quarter (five-year) period between tests

is also consistent with the proposed

time between quality assurance tests for

fuel flowmeters that are used very

infrequently. Repeating the periodic

quality assurance procedures for fuel

flowmeters at least every five years

would catch slow, long-term changes in

heat rates mentioned by a facility and

would allow a facility to update its

baseline data periodically (see Docket

A–97–35, Item II–D–49). Finally,

allowing the option of a 20 calendar

quarter (five-year) period between more

rigorous quality assurance procedures

would be safer and less costly than

annual testing, while, in coordination

with quarterly fuel flow-to-load ratio

testing, still providing assurance of the

quality of the data.

(1) Use of Gross Heat Rate or Flow-toLoad Ratio. Today’s proposed rule

would allow a facility the option of

calculating either the ratio of the fuel

flow rate to the gross generation in MWe

or the steam flow rate in thousands of

pounds of steam per hour (‘‘fuel flowto-load ratio’’) or the ratio of the heat

input rate to the gross generation in

MWe or the steam flow rate in

thousands of pounds of steam per hour

(‘‘gross heat rate’’ or ‘‘GHR’’). One utility

suggested that, because the load is

created based upon a number of factors

in addition to the fuel flow rate, such as

the gas heat rate (i.e., gross calorific

value), a ratio of the heat input to the

unit load would be a better test than the

ratio of the fuel flow rate to the unit load

(see Docket A–97–35, Item II–D–50). In

addition, some utilities pointed out that

the Agency allows facilities to use either

a stack flow-to-load ratio or a heat

input-to-load ratio (gross heat rate) as a

diagnostic test on stack volumetric flow

monitors, through Policy Manual

Question 13.15 (see Docket A–97–35,

Item II–I–9). The Agency agrees that the

heat input-to-load ratio (GHR) is also a

technically appropriate check on the

performance of fuel flowmeters.

Therefore, today’s proposal includes

options for both the fuel flow-to-load

ratio and the GHR.

(2) Baseline Period for Fuel Flow-toLoad Ratio or GHR. When using this

type of comparison test, it is important

to establish a baseline of reliable data to

which hourly data can later be

compared. For the stack volumetric

flow-to-load ratio, the baseline of

reliable data consists of data from the

reference method for flow, Method 2 of

Appendix A to 40 CFR part 60.

However, there is no universally

applicable test for flowmeters that is

performed in-line with a reference

method while the unit is operating,

parallel to the flow RATA. EPA asked

several utilities what could be a source

of baseline data to which the fuel

flowmeter could later be compared. One

utility suggested using fuel flowmeter

readings during a time when the unit is

operating at a steady load, such as when

the unit undergoes Appendix E testing

for a NOX-versus-heat input correlation

or when a NOX CEMS undergoes a

normal level RATA (see Docket A–97–

35, Item II–D–41). A second utility

recommended that the baseline be

established just after performing a

transmitter calibration, i.e., after

performing a quality assurance test on

the fuel flowmeter (see Docket A–97–35,

Item II–D–49). The Agency believes that

using fuel flowmeter data taken

immediately following a flowmeter

quality assurance test would be most

likely to be accurate and representative

of proper operation of the fuel

flowmeter. Flowmeter quality assurance

tests might include any of the methods

incorporated by reference in section

2.1.5.1 of Appendix D; meter testing

against a certifiable ‘‘master’’ meter

under section 2.1.5.2 of Appendix D; or

transmitter or transducer accuracy

testing under section 2.1.6.1 of

Appendix D, and inspection of a

primary element for an orifice-, nozzle-

, or venturi-type fuel flowmeter under

section 2.1.6.6 of Appendix D. This

approach is proposed in today’s rule.

The utilities supporting the idea of

using fuel flowmeter data taken

immediately after a flowmeter quality

assurance test have suggested that it

would be important to have a fairly

large number of hours in the baseline,

on the order of 100 or more, to ensure

that the baseline period is representative

of typical operation (see Docket A–97–

35, Item II–E–33). In today’s rule, EPA

is proposing to use the first 168 hours

of quality assured data measured by that

flowmeter for which: (1) only the fuel

measured by that fuel flowmeter is

combusted; (2) the unit load is not

significantly ‘‘ramping’’ up or down;

and (3) the unit load is safely above the

minimum safe, stable load. The Agency

believes that a baseline period

containing 168 hours of data is

sufficiently long to be representative of

different unit operating conditions that

may occur later. This specific time

period is consistent with the minimum

number of hours that a unit combusts a

fuel before the quarter counts toward

the deadline for the next quality

assurance test, and with the minimum

number of hours that a unit combusts a

fuel before a quarter needs to be

evaluated using the fuel flow-to-load

ratio. Certain hours would be excluded

from the baseline (i.e., periods of cofiring, unstable, or low load), because

the fuel flow-to-load ratio or GHR would

tend to be less reliable during those

periods.

Today’s proposal would also limit the

baseline period so that it may extend no

more than two quarters beyond the

quarter in which the flowmeter passes

its accuracy tests. The Agency has

concerns that if the baseline data were

to extend longer than this, the

performance of the fuel flowmeter might

degrade. In order for the baseline data

to reflect fuel flow rate data that are

most likely to be accurate, the Agency

is proposing that the fuel flow rate or

heat input rate data used in the baseline

period must either be obtained in the

calendar quarter in which the quality

assurance procedure is performed, or

within two calendar quarters after the

QA test. The Agency considered

limiting the time period to the same

calendar quarter as the quality

assurance procedure or to one

flowmeter operating quarter beyond the

QA test. However, because a quality

assurance procedure may be conducted

at any time during a quarter, it could be

difficult for a facility to collect 168

hours of fuel flowmeter data after a

quality assurance procedure in the same

calendar quarter or even (for

infrequently operated units that ramp
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28093

up and down often) in the next calendar

quarter.

For orifice-, nozzle-, and venturi-type

fuel flowmeters, two quality assurance

procedures would be required prior to

collecting the baseline data: (1) a

transmitter or transducer accuracy test,

and (2) an inspection of a primary

element. The Agency considered

whether these two quality assurance

procedures should be separated and

whether the baseline period could

simply be based upon a time period

after the most recent quality assurance

procedure. The Agency believes that the

baseline period data would be more

reliable if they were taken shortly after

completing both quality assurance

procedures for orifice-, nozzle-, and

venturi-type fuel flowmeters. Using the

same time period for both tests

simplifies administration of the fuel

flow-to-load ratio test. EPA also notes

that a unit does not need to be operating

in order to perform the tests; thus, it

should not be burdensome for a facility

to plan to coordinate the two quality

assurance procedures.

(3) Data Preparation and Analysis.

The proposed procedures for data

preparation and analysis for the fuel

flow-to-load ratio are similar to those for

the volumetric stack flow-to-load ratio.

Equations of the same form as those for

the stack volumetric flow-to-load ratio

are used to calculate the hourly fuel

flow-to-load ratio, the hourly absolute

value of the percentage difference

between the baseline fuel flow-to-load

ratio and the hourly fuel flow-to-load

ratio, and the quarterly average

percentage difference. Common pipe

headers would be treated in the same

way as common stacks. If there were

multiple units associated with a single

fuel flowmeter or flow monitor, the total

load from all units would be summed

before the flow rate data are divided by

the load data to calculate the flow-toload ratio. Fuel flowmeters on multiple

pipes would be treated in the same way

as multiple stacks associated with a

single unit. If there are multiple fuel

flowmeters or flow monitors associated

with a single unit, the flow rates from

all fuel flowmeters for the same fuel or

all flow monitors would be added

together before the flow rate data are

divided by the load data to calculate the

flow-to-load ratio.

Certain aspects of the volumetric

stack flow-to-load ratio test are not the

same for the fuel flow-to-load ratio test.

For example, the volumetric stack flowto-load ratio test requires the facility to

screen out those hours when the unit

operates further than 10.0 percent away

from the average load during the most

recent normal-load flow RATA. As was

discussed previously, there is no

equivalent of an in-line flow RATA for

fuel flowmeters. EPA does not believe

that there is a need to screen out hours

for the fuel flow-to-load test when the

unit operates at a load somewhat less

than or greater than normal. Some

facilities have indicated that the fuel

flow-to-load ratio or GHR based on fuel

flow readings is less variable over

different loads than the volumetric stack

flow-to-load ratio (see Docket A–97–35,

Items II–E–33 and II–D–98). However,

preliminary evidence has also indicated

that the fuel flow-to-load ratio or GHR

can be significantly different at very low

operating loads than at other load levels

(see Docket A–97–35, Item II–A–5). For

this reason, EPA is proposing to allow

hours in which the unit load is within

the lower 10.0 percent of the range of

operation to be excluded from both the

baseline data and the quarterly flow-toload or GHR analysis, unless such low

loads are considered normal for the

unit.

Another feature of the volumetric

stack flow-to-load ratio test that differs

from the fuel flow-to-load ratio test is

the treatment of bias-adjusted data. Fuel

flow rate data are never adjusted for

bias. There is no bias test for fuel

flowmeters. Bias-adjustment of data is

an issue for the volumetric stack flowto-load ratio test because bias-adjusted

data has already been adjusted to make

it more consistent with the value of the

reference method data. Thus, biasadjusted volumetric stack flow data

must meet a stricter quarterly average

percentage difference of 10.0 percent

from the reference flow-to-load ratio,

whereas the allowable difference is 15.0

percent when unadjusted volumetric

stack flow data are used. (See discussion

of stack flow-to-load test in Section

III.M. of this preamble.) EPA notes that

since the same fuel flow meter is used

to produce both the baseline data and

the quarterly data, the fuel flow-to-load

ratio is more closely analogous to the

use of bias-adjusted volumetric flow

data. Therefore, the limit on the

quarterly average percentage difference

from baseline for fuel flow rate data

should be at least as stringent as that for

bias-adjusted volumetric flow data (10.0

percent). Information provided by

facilities on the gross heat rate derived

from fuel flow rate data have shown less

variability than the corresponding stack

heat rate (see Docket A–97–35, Item II–

D–98). Based upon this information,

EPA is proposing a limit of 10.0 percent

on Ef, the quarterly average percentage

difference from the baseline for the

quarterly flow rate-to-load or GHR

evaluation. EPA considered whether it

would be appropriate to set a different

limit for smaller units, as was done for

the stack flow-to-load test. Analysis of

some preliminary fuel flow-to-load data

has shown that for lower loads (e.g., <

50 MWe), the flow-to-load ratio is quite

sensitive to small changes in load (see

Docket A–97–35, Item II–A–5). This

indicates that it would be appropriate to

set a higher limit for smaller units.

Therefore, today’s rule proposes a limit

of 15.0 percent on the value of Ef when

the quarterly average load used for the

data analysis is 50 megawatts or less (or

≤ 500 klb steam per hour). The Agency

solicits comment on the 15.0 percent

limit for loads less than or equal to 50

megawatts.

(4) Optional Data Exclusions. As for

volumetric stack flow monitors, if a fuel

flowmeter’s data would not meet the

limit on the percentage deviation from

the baseline, then a facility could opt to

exclude certain hours of

unrepresentative fuel flow rate (or heat

input rate) data and then reanalyze the

smaller set of data. The hours of data

that EPA proposes to view as nonrepresentative for fuel flowmeters are:

(1) hours when the unit combusts

multiple fuels; (2) hours when the unit

load in a given hour would differ by

more than ± 15.0 percent from the load

during either the previous hour or the

subsequent hour; or (3) hours when the

load is very close to the minimum safe,

stable load (unless operation in that

range is normal).

The baseline period for fuel

flowmeters and the data used for the

quarterly flow-to-load or GHR analyses

would include only those hours when a

single fuel is combusted—the fuel

measured by the fuel flowmeter. If the

quarterly fuel flow rate data included

hours when multiple fuels are co-fired,

the fuel flow-to-load ratio or GHR for

the fuel flowmeter being tested would

be biased low. This could result in a

failure of the flow-to-load test or GHR

evaluation. Today’s proposed rule

would also allow a facility to exclude

from the baseline data and the quarterly

analyses those hours that are not

representative because the unit’s load is

changing rapidly. Specifically, hours

could be excluded when the unit load

in a given hour would differ by more

than ± 15.0 percent from the load during

either the previous hour or the hour

afterwards. There will be a lag in the

time between when electricity is

generated and registered as load and the

time that the fuel flowmeter measures

the fuel that is combusted to generate

the load. Therefore, during an hour

when the load changes rapidly, the fuel

flow rate will not necessarily be

changing by the same amount or in the
28094 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

same direction. At least one utility has

suggested that the Agency consider such

an exclusion for the proposed fuel flowto-load ratio test (see Docket A–97–35,

Item II–D–41).

In general, the fuel flow is directly

proportional to load, with a linear

graphical relationship. However, this is

not always the case at extremely low

loads (see Docket A–97–35, Items II–E–

33, II–D–98). Therefore, today’s

proposed rule would allow certain lowload hours to be excluded from the

flow-to-load baseline and quarterly data

analyses. Specifically, loads in the

lower 10.0 percent of the ‘‘range of

operation’’ of the unit, (as that term is

defined in proposed section 6.5.2.1 of

Appendix A in today’s proposal) could

be excluded, unless such loads are

considered normal for the unit.

Today’s proposed rule, in section

2.1.7 of Appendix D, would also exempt

a fuel flowmeter from the fuel flow-toload ratio test in a quarter when a more

rigorous quality assurance test is

performed. This is unlike the volumetric

stack flow-to-load ratio, which is

required each QA operating quarter,

including quarters when the flow

monitor is tested with a RATA

(provided, of course, that sufficient data

for the analysis are obtained after the

RATA).

(5) Consequences of Failing the Fuel

Flow-to-Load Ratio Test. The

consequences of failing the fuel flow-toload ratio test would be similar to the

consequences of failing quality

assurance tests in general for fuel

flowmeters. Data from the fuel

flowmeter would no longer be

considered quality assured. Because the

fuel flow-to-load ratio test is only

performed at the end of a quarter, the

facility would invalidate data from the

fuel flowmeter beginning with the first

hour in the quarter after the quarter in

which the meter fails the fuel flow-toload ratio test. In order to establish that

the fuel flowmeter is operating properly

and providing quality assured data

again, the facility would perform a

flowmeter accuracy test or (for orifice-,

nozzle-, and venturi-type flowmeters) a

transmitter or transducer accuracy test.

The Agency believes it is appropriate to

perform an accuracy test if the fuel flowto-load ratio test is failed, because in

such cases the facility has had the

benefit of postponing the accuracy test

based upon the assumption that the fuel

flowmeter has continued to measure

accurately and consistently with its

operation during the baseline period.

Note that for orifice-, nozzle-, and

venturi-type fuel flowmeters, a

transmitter/transducer test alone would

not suffice to demonstrate that the

flowmeter is back in control. The owner

or operator would still need to ensure

that the cause of the failed fuel flow-toload ratio test was a problem with the

transmitters or transducers rather than a

problem with the primary element.

Sudden changes in flowmeter

performance are likely to be caused by

a problem with transmitters (see Docket

A–97–35, Item II–D–33). However, it

cannot be assumed that the transmitters

are solely responsible for degradation in

monitor performance. In order to verify

that the primary element is not

contributing additional error to the fuel

flow measurements because of

corrosion, a facility would conduct an

abbreviated (6 to 12 hour) version of the

fuel flow-to-load ratio test, similar to the

diagnostic test for volumetric stack flow

monitors in Policy Manual Question

13.15 (see Docket A–97–35, Item II–I–9).

The Agency believes that this

abbreviated fuel flow-to-load ratio test

would provide additional assurance that

the fuel flowmeter is indeed operating

properly. In addition, it would be more

timely than waiting for another calendar

quarter to pass to repeat the fuel flowto-load ratio. The abbreviated test would

also be less burdensome than removing

the primary element from the fuel pipe.

EPA believes the abbreviated fuel flowto-load ratio test strikes a reasonable

balance by providing some additional

quality assurance in a timely manner. If

the orifice-, nozzle-, or venturi-type fuel

flowmeter failed the abbreviated fuel

flow-to-load ratio test, then it would

appear that the primary element may

also have a problem. Therefore, upon

failure of an abbreviated fuel flow-toload ratio test, the facility would be

required to inspect the primary element

and to repair or replace it, as necessary.

The rules for data validation upon

failure of the fuel flow-to-load ratio are

not parallel with the procedures for data

validation following failure of the

volumetric stack flow-to-load ratio test

in that there is no conditional validation

of data. A number of utilities have

emphasized that they wish to spend less

time and effort preparing and evaluating

quarterly reports for units using

Appendix D, which are generally

smaller and less frequently operated

than coal-fired units or oil-fired units

that choose to use CEMS (see Docket A–

97–35, Item II–E–33). The concept of

conditional data validation for fuel

flowmeters is not consistent with this

objective, because it would introduce

additional complexity into the process,

would require significantly more time

and resources to quality-assure the data,

and might require additional DAHS

programming. Therefore, the Agency is

not proposing the use of conditional

data validation for fuel flowmeters.

(c) Fuel Flowmeter Quality Assurance

Testing Frequency

Background

Section 2.1.6.1 of Appendix D, as

revised by the May 17, 1995 direct final

rule, requires regular quality assurance

‘‘recalibrations’’ (accuracy tests) of fuel

flowmeters at least annually (once every

four calendar quarters). For fuel

flowmeters that were not used on a

regular basis, such as fuel flowmeters

used to measure the usage of emergency

fuel or backup fuel, or flowmeters

installed on peaking units, owners or

operators are allowed to do flowmeter

accuracy tests once every four quarters

when the unit actually combusts the

fuel measured by the flowmeter, rather

than once every four calendar quarters.

Flowmeters can be retested either by

using one of the methods incorporated

by reference in section 2.1.5.1 of

Appendix D to part 75 or by an in-line

comparison of the fuel flowmeter

against a ‘‘master’’ fuel flowmeter using

the procedure in section 2.1.5.2 of

Appendix D.

Some utilities have expressed concern

about the annual fuel flowmeter testing

requirement (see Docket A–97–35, Items

II–D–20, II–E–13, II–E–14). In many

cases, it is neither practical nor costeffective to modify the fuel pipes (e.g.,

to install a parallel length of pipe) to

allow installation of a master fuel

flowmeter for comparison testing. Thus,

most utilities must remove a fuel

flowmeter from the pipe and return it to

a laboratory or to the manufacturer to be

retested. In some cases, especially for oil

flowmeters, this can be difficult.

Some utilities have raised the issue of

whether there should be a minimum

time period that a fuel flowmeter is used

before a quality assurance test is

required. For instance, a utility might

test its unit’s burners once each quarter

for a few hours to ensure that the unit

can be operated when needed and may

not operate for the rest of the quarter.

Under the current rule, the fuel

flowmeter would have to be quality

assurance tested after four such

operating quarters, even though the

flowmeter was only used for a few hours

in those calendar quarters.

Discussion of Proposed Changes

Today’s proposed rule includes a

provision that only those calendar

quarters in which the fuel measured by

the fuel flowmeter is combusted for at

least 168 hours would count toward

determining the next quality assurance

test deadline. The 168-hour time period
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28095

is roughly equivalent to one week of

operation while combusting the fuel

measured by a particular fuel flowmeter.

A calendar quarter in which the fuel

measured by a fuel flowmeter is

combusted for 168 hours or more would

be called a ‘‘flowmeter operating

quarter.’’ For example, if a unit

combusted oil for 200 hours in the first

calendar quarter of the year, 10 hours in

the second calendar quarter, 250 hours

in the third calendar quarter, and 100

hours in the fourth calendar quarter,

then only the first and third calendar

quarters would be considered flowmeter

operating quarters for the oil flowmeter.

Only the first and third calendar

quarters would count toward

determining the deadline for the next

required oil flowmeter accuracy test.

In today’s proposed rule, each fuel

flowmeter would need to be accuracy

tested at least once every four flowmeter

operating quarters. However, the

deadline for testing infrequently-used

meters could not be extended

indefinitely. No more than 20 calendar

quarters (five years) would be allowed

to elapse between successive flowmeter

accuracy tests, regardless of the number

of ‘‘flowmeter operating quarters’’ that

have elapsed since the last test. The

interval between successive quality

assurance tests could also be extended

for up to 20 calendar quarters if the

quarterly fuel flow rate-to-load

procedures in proposed section 2.1.7 of

Appendix D were implemented.

Rationale

In evaluating the frequency of fuel

flowmeter accuracy testing, EPA

considered simply extending the less

strict requirement for fuel flowmeter

quality assurance testing for peaking

units, backup fuel, and emergency fuel

to apply to all units and all fuel

flowmeters. Thus, quality assurance

testing would be required once every

four quarters in which the unit

combusted the fuel measured by the

flowmeter.

One industry representative

recommended that the Agency require

fuel flowmeter calibrations once every

four unit operating quarters, where a

unit operates at least 168 hours in the

quarter (see Docket A–97–35, Item II–E–

13). This approach would treat all fuel

flowmeters the same, whether they were

used for primary, emergency, or backup

fuel.

Another utility suggested that the

Agency consider creating some sort of

diagnostic test comparing the flow rate

of the fuel flowmeter to the unit load

(generation) to determine whether the

fuel flowmeter readings are degrading

over time, rather than specifying a

particular frequency for accuracy testing

(see Docket A–97–35, Item II–E–22).

Although this suggestion was originally

referring to problems with corrosion of

an orifice plate, such a test could also

be used for other types of fuel

flowmeters as a check on the quality of

fuel flowmeter data.

The Agency also considered

extending the typical time between

accuracy tests to the equivalent of two

years. This time was suggested by a

member of the AGA subcommittee

responsible for the drafting of AGA

Report No. 7 for turbine-type flowmeters

(see Docket A–97–35, Item II–E–17). The

Agency also considered extending the

typical time between accuracy testing to

12 calendar quarters—the equivalent of

three years. Three years is the period of

time that records must be retained in a

file at the source under § 75.54 (or

proposed § 75.57).

The Agency also considered allowing

fuel flowmeters to continue for up to

five calendar years between accuracy

tests. This is similar to the current

provision in section 2.1.5.2 of Appendix

D, which allows a reference fuel

flowmeter to be accuracy tested as

seldom as once in five calendar years,

if the in-line comparison with a master

fuel flowmeter shows a 1.0 percent or

less difference in their flow rates. A

five-year test cycle offers certain

administrative advantages. For instance,

fuel flowmeters used to provide heat

input data for the heat input-versus-load

correlation of Appendix E could be

accuracy-tested before each Appendix E

test (i.e., once every five years). In

addition, the five calendar-year period

would ensure that fuel flowmeters are

tested by the time the unit’s operating

permit is renewed. Facilities might find

this time cycle easier to determine than

a time period based upon a number of

calendar quarters. However, test data

would need to be retained for five years,

rather than for three years, the

recordkeeping period for most records

under part 75. However, the Agency is

not proposing this option because five

years is far too long a period of time to

allow a unit to continue with no checks

at all upon the quality of its data. Such

an approach would allow the use of data

from a fuel flowmeter that potentially

had been reading inaccurately for the

previous five years.

Another option that EPA evaluated

was to establish different fuel flowmeter

quality-assurance testing frequencies

depending on the fuel measured by the

fuel flowmeter. Under this approach, oil

flowmeters would need to be tested

every four calendar quarters in which

oil was combusted. Gas flowmeters

would only need to be tested once every

five years. The two fuels would be

treated differently because units emit

less NOX and far less SO2 when

combusting gas than when combusting

oil. In addition, gaseous fuels,

particularly pipeline natural gas, should

be less corrosive; therefore, a gas

flowmeter should be less likely to

degrade than an oil flowmeter.

EPA believes that today’s proposed

approach to reducing the fuel flowmeter

quality assurance testing frequency

takes into account many of the concerns

raised by utilities. All unit types and

fuel types would have the same

frequency of testing. This would avoid

confusion that could follow from an

approach that set different requirements

for fuels or units that are used less

frequently. A group of utilities had

indicated that they prefer a more

consistent approach (see Docket A–97–

35, Item II–E–13). Under today’s

proposal, infrequently-used fuel

flowmeters (e.g., meters for backup fuel

or emergency fuel) would only need to

be calibrated once every five years.

When a facility renews its operating

permit, the permitting agency could

verify that all fuel flowmeters have been

tested at least once in the previous five

years.

The minimum period of 168 hours of

fuel flowmeter usage which defines a

‘‘flowmeter operating quarter’’ is

consistent with the definition of a ‘‘QA

operating quarter’’ in Appendix B in

today’s proposed rule for the quality

assurance of CEMS. The Agency

believes that using a consistent

minimum number of hours in a calendar

quarter for both CEMS and fuel

flowmeters will make implementation

easier for facilities and air regulatory

agencies. In addition, 168 hours should

be a sufficiently long period of time to

ensure that short-term usage of backup

fuel or emergency fuel or short-term

tests of a unit do not trigger unnecessary

quality assurance testing.

Today’s proposed rule would also

provide more flexibility in the methods

that could be used for fuel flowmeter

quality assurance testing. As discussed

above in Section III.P.2 of this preamble,

a new testing procedure has been

proposed that would allow a facility to

test flow rate-to-load ratio of the fuel

flowmeter while leaving it installed.

Thus, the Agency believes that the

overall burden of fuel flowmeter testing

has been significantly reduced. In

addition to the reduced frequency of

testing discussed above, the Agency

believes the less burdensome testing

procedures should address concerns of

the regulated community.

The Agency requests comment on

whether facilities would prefer to base
28096 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

the frequency of fuel flowmeter quality

assurance testing on the type of fuel

used or the amount of time the fuel

flowmeter is used. Under the first

approach, gas flowmeters would receive

greater regulatory relief. Under the

second approach, which is being

proposed in today’s rule, infrequentlyused flowmeters (typically oil

flowmeters) would receive greater

regulatory relief.

(d) Orifice, Nozzle, and Venturi Visual

Inspections

Background

Section 2.1.6 of Appendix D, as

revised in the May 17, 1995 direct final

rule, created special provisions for the

ongoing quality assurance testing of

orifice fuel flowmeters. Orifice-,

nozzle-, and venturi-type fuel

flowmeters are designed and installed

within a set of physical specifications,

such as the orifice diameter (see Docket

A–97–35, Item II–D–13). Maintaining

these physical specifications determines

the flowmeter’s ability to read

accurately. Thus, it is not necessary to

take an orifice-, nozzle-, or venturi-type

flowmeter out of line and send it to a

laboratory to determine its accuracy.

After installation of an orifice-,

nozzle-, or venturi-type flowmeter is

complete, the two major factors that

contribute to error in flow readings are:

drift in the transmitters (or transducers)

which determines the total pressure,

differential pressure and temperature,

and corrosion of the primary element

(e.g., the orifice plate) itself. Quality

assurance testing of the transmitters is

discussed in the next section of the

preamble. In order to identify cases

where error might result from corrosion

of the orifice plate, the May 17, 1995

direct final rule added a requirement for

an annual visual inspection of the

orifice plate. If an orifice plate fails the

inspection, then the facility must

perform a test on the transmitters during

the next calendar quarter. A procedure

for visual inspections is given in

Appendix B of part 2 of American Gas

Association (AGA) Report No. 3, which

is one of the accepted standards for

installation and use of orifice

flowmeters.

Some facilities have expressed

concern with the frequency of visual

inspections (see Docket A–97–35, Items

II–D–20, II–E–13, II–E–14). This process

must be done either with a tool, such as

a boroscope, or else the primary element

must be removed from the pipe and

lifted out to be inspected. In the case of

large, heavy orifices, it is necessary to

use a crane to remove the orifice. Fuel

must not be flowing through the pipe

while the orifice plate is being removed

(see Docket A–97–35, Item II–E–8).

The current provisions of Appendix D

to part 75 do not explicitly state the

consequences of failing a quality

assurance test. Section 2.1.5.1 of

Appendix D states that if a fuel

flowmeter exceeds the flowmeter

accuracy of ± 2.0 percent of the upper

range value, then the flowmeter may not

be used under part 75. Section 2.1.5.2

states that if a fuel flowmeter’s accuracy

exceeds ± 2.0 percent of the upper range

value, then the flowmeter must be

recalibrated to meet that accuracy, or it

must be replaced with another

flowmeter that meets the specification.

Neither section explicitly states the

impact upon the validity of data if a test

is failed. However, if fuel flowmeter

systems are to be treated parallel with

continuous emission monitoring

systems under § 75.21(e)(2), the

consequences of failing a quality

assurance test for a fuel flowmeter or an

inspection of the primary element

should result in the monitor being

considered out-of-control and the data

being considered invalid.

In section 2.1.6.1 of Appendix D, the

specific consequence of failing a visual

inspection of the primary element is

that the transmitters must be tested in

the following calendar quarter, rather

than waiting until the regular annual

calibration is required. However, no

mention is made of any mandatory

corrective action(s) to eliminate the

corrosion problem.

Discussion of Proposed Changes

Section 2.1.6.6 of Appendix D in

today’s rulemaking proposes to require

visual inspections of primary elements

(i.e., orifice, nozzle or venturi) at the

frequency recommended by the

manufacturer or once every three years,

whichever is more frequent. The Agency

solicits comment on the proposed

frequency of visual inspections.

The proposed rule would also

explicitly require repair or replacement

of the primary element and invalidation

of data when a visual inspection is

failed. Once the primary element is

replaced or repaired, the new or

repaired primary element would have to

demonstrate that it meets the overall

flow rate accuracy of ± 2.0 percent of the

upper range value. This could be

demonstrated by showing that the new

or repaired primary element meets the

design and installation requirements of

AGA Report No. 3 or ASME MFC–3M,

the same methods required for initial

certification. Alternatively, the flow rate

accuracy could be demonstrated by

testing the fuel flowmeter against a

reference fuel flowmeter using the

provisions of section 2.1.5.2 of

Appendix D. Finally, whenever a

primary element is repaired, the fuel

flowmeter transmitters would also have

to be tested before the fuel flowmeter is

used to provide quality assured data.

Rationale

During the process of reviewing

certification applications for units using

orifice flowmeters, the Agency learned

of one plant where orifice corrosion was

a serious problem. This utility had an

orifice flowmeter which had been

installed in the 1960’s. This utility did

not have documentation of the standard

used to install the orifice as a

demonstration of the meter’s accuracy.

In order to qualify for certification, the

utility inspected the orifice. The utility

personnel discovered that the orifice

had been completely eaten away and

was incapable of reading the flow rate

(see Docket A–97–35, Item II–E–22). The

utility replaced the orifice before it was

able to have its fuel flowmeter certified.

In addition, it was required to invalidate

the flow rate data from the orifice meter

and substitute for the missing data.

Based upon this experience, the Agency

believes that corrosion of an orifice can

be a problem, and that in severe cases

of corrosion, replacement of the orifice

is necessary.

Despite this, many utilities have

expressed concern over the difficulty of

removing an orifice from place for

visual inspection (see Docket A–97–35,

Items II–D–20, II–E–13, II–E–14),

because removal requires halting the

flow of gas through the pipeline in order

to remove the orifice, which can be

expensive (see Docket A–97–35, Item II–

E–8).

Utilities have provided the Agency

with several suggestions for reducing

the frequency of primary element

inspections. One industry group

recommended that the Agency reduce

the inspection frequency to once every

five years, to be coordinated with

renewal of the plant’s operating permit

under title V of the Act (see Docket A–

97–35, Items II–D–20, II–E–13, and II–

E–14). One utility representative

mentioned that most orifice

manufacturers recommend an

inspection once every three years; thus,

he recommended that the Agency

require visual inspections the earlier of

once every three years or the time

period specified by the manufacturer

(see Docket A–97–35, Item II–D–41).

Another utility suggested that the

Agency consider creating some sort of

diagnostic test comparing the flow rate

of the fuel flowmeter to unit load

(generation) to determine whether the

fuel flowmeter readings are degrading
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28097

over time, rather than specifying a

particular time period (see Docket A–

97–35, Item II–E–22).

EPA agrees that it would be helpful to

facilities to reduce the frequency of

visual inspections from their current

annual frequency. Having considered all

of the options suggested by the utilities,

the Agency is proposing that the

primary element of all nozzle, venturi

and orifice fuel flowmeters be visually

inspected at the frequency

recommended by the manufacturer or

once every three years, whichever is the

more frequent. The Agency believes that

up to three years between visual

inspections is a technically sound

period of time that will assure the

quality of fuel flow rate data, while

providing regulatory relief from the

current annual requirement.

The Agency also has reconsidered the

consequences of failure of a visual

inspection. The May 17, 1995 direct

final rule added a requirement to test a

flowmeter’s transmitters in the calendar

quarter following a failed inspection,

but the rule does not explicitly require

that the primary element be repaired or

replaced, nor does it explicitly require

data from the fuel flowmeter to be

invalidated.

Today’s proposed rule would require

the primary element to be removed

following a failed visual inspection and

would require the problem to be

corrected. The Agency believes that it is

appropriate to provide two options for

correcting the problem: either replace

the element with a new one or repair it.

This would provide flexibility to

facilities, while still assuring that the

fuel flowmeter will be repaired to give

quality assured data.

Today’s proposed rule would also

change the timing of the requirement for

fuel flowmeter transmitter or transducer

testing if a primary element fails its

visual inspection. The Agency believes

that it would be appropriate also to test

the fuel flowmeter transmitters before

the fuel flowmeter is placed into service

again. This would be a more thorough

quality assurance check of the entire

fuel flowmeter than simply addressing

the problem with the primary element.

Thus, when the fuel flowmeter is placed

into service again, its accuracy would be

tested as fully as possible. In addition,

EPA proposes to remove the

requirement for a test on the flowmeter

transmitters in the calendar quarter

following a failed visual inspection.

This requirement might be appropriate

if it seemed that transmitter drift was

likely to be a problem or if the Agency

had no other means of assuring the

quality of the data from the flowmeter

after a problem with the primary

element was known to have occurred.

However, the Agency believes that

problems with the primary element are

separate from problems with drift in the

transmitters. Because today’s proposal

would require a check on the fuel

flowmeter transmitters after repair or

replacement of the primary element,

requiring an additional test of the

transmitters in the following calendar

quarter appears to be unnecessary.

The proposed rule gives procedures

for data validation when a primary

element fails a visual inspection. The

element would have to be replaced or

repaired, and the transmitters would

have to be tested before data would

again be valid from the fuel flowmeter.

During the period in which the

flowmeter data are considered invalid,

the appropriate missing data

substitution procedures would be used.

The Agency has clarified that these data

validation procedures would also apply

to failures of other fuel flowmeter

quality assurance tests. EPA believes

that this will make facilities’ obligations

clearer. In addition, the Agency believes

that fuel flowmeter systems should be

treated as consistently as possible with

CEMS. Consistent treatment simplifies

the part 75 requirements and is more

equitable for sources using different

monitoring approaches.

(e) Orifice, Venturi, and Nozzle

Flowmeter Transmitter Testing

Background

As discussed previously, once an

orifice-, nozzle-, or venturi-type

flowmeter has been installed, one of the

major causes of error in the measured

flow rates is drift in the transmitters or

transducers that determines the total

pressure, differential pressure, and

temperature. The flow measurement

error for these types of flowmeters is a

combination of the errors in these

individual transmitters or transducers

and a constant error value associated

with the physical dimensions of the

primary element. The May 17, 1995

direct final rule added a requirement

that flowmeter transmitters be tested at

least annually. The transmitters are also

required to be retested in the next

calendar quarter if the overall flow rate

error is greater than 1.0 percent of the

upper range value of the flowmeter. For

practical purposes, this requires a

facility to know the error from the

physical dimensions of the primary

element in order to determine if the

flowmeter meets the overall accuracy

requirement.

Some utilities asked the Agency how

to determine the overall flowmeter

accuracy from individual transmitter

values (see Docket A–97–35, Item II–E–

31). EPA addressed this issue in Policy

Guidance (see Docket A–97–35, Item II–

I–9, Policy Manual, Question 10.17).

This guidance included a formula for

calculating total flowmeter accuracy

from error in transmitter readings for

differential pressure, static pressure and

temperature, and error from all other

sources (i.e. physical dimensions of the

primary element). Some utilities

indicated that they do not always have

information available on the constant

error from other portions of the primary

element (see Docket A–97–35, Item II–

E–13). The policy guidance also

indicated that a facility could report test

results electronically using the highest

amount of error from any of the three

transmitters. Provided that the highest

error from an individual transmitter is

1.0 percent of the upper range value of

the transmitter or less, the overall

flowmeter accuracy will be less than 2.0

percent of the upper range value (see

Docket A–97–35, Item II–I–10).

EPA has also observed that

transmitter test data reported for

orifice-, nozzle-, and venturi-type

flowmeters have not been consistent.

Some facilities test each transmitter

once at three different levels, including

a low, middle, and high value (see

Docket A–97–35, Item II–D–16). Others

test each transmitter at five different

levels, including zero, full scale, and

three intermediate levels (see Docket A–

97–35, Item II–D–17). The Agency had

previously issued some guidance on

reporting test results, both for orifice

flowmeters and other flowmeters (see

Docket A–97–35, Items II–I–4, p. 3–58,

and II–I–9, Policy Manual, Questions

10.17 and 12.27). However, this

guidance appears to have been

insufficient, as utilities have continued

to request guidance in how to perform

and report test results (see Docket A–

97–35, Item II–D–21). Questions have

included the number of levels at which

transmitters should be tested, whether

all of these levels must be non-zero, the

number of times the transmitter should

be tested at a particular level, if results

may be reported in hardcopy or should

be reported electronically, and how data

should be reported electronically.

Discussion of Proposed Changes

Today’s proposed rule would make

the requirement to assess the total

accuracy of orifice-, nozzle-, and

venturi-type fuel flowmeters from the

transmitter/transducer test results an

option. As an alternative, proposed

section 2.1.6.5 in Appendix D would

allow each of the three transmitters

(static pressure, differential pressure,

and temperature) individually to meet
28098 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

an accuracy specification of 1.0 percent

of the upper range value of the

transmitter.

Today’s rulemaking also proposes a

procedure in section 2.1.6.1 of

Appendix D for testing the accuracy of

orifice-, nozzle-, and venturi-type fuel

flowmeters. Each transmitter would be

calibrated against NIST-traceable

reference values at least once at the zero

level and at a minimum of two other

levels across the range of values that the

transmitter reads during normal unit

operation. Note that in many instances

this would be a portion of the full-scale

range of the transmitter, rather than the

entire range. In addition, revised section

2.1.6.2 of today’s proposed rule includes

the new Equation D–1a to clarify how to

calculate the error from an individual

transmitter.

Finally, today’s proposal would

clearly specify the consequences of

failure of an accuracy test on

transmitters in section 2.1.6.5 of

Appendix D. Just as CEM data are

considered invalid from the time that a

quality assurance test is failed until the

test is subsequently passed, data from a

fuel flowmeter would be considered

invalid from the date and time of a

failed transmitter accuracy test until the

date and time of a passed transmitter

accuracy test.

Rationale

The Agency considered two main

options for determining the accuracy of

a transmitter or transducer of an

orifice-, nozzle-, or venturi-type fuel

flowmeter. In the first approach (which

is consistent with current policy

guidance), these types of fuel

flowmeters would be required to meet

an accuracy of 2.0 percent of the upper

range value of the total flow rate of the

fuel flowmeter. The accuracy would be

determined using the square root of the

sum of the squares of all sources of error

in the fuel flowmeter, according to the

following equation:

dq

q

K dP

P

d P

P

dT

T

v

v

f

f

f

f

= +

−



 



 + 



 



 +





 





















2

2 2 2 1 2

2 2 2

∆

∆

/

Where: dqv/qv = Error in the volumetric

flow rate due to transmitter drift at

a given level; K = Original error resulting from

installation of orifice (including all

other variables);

dPf = Average difference between static

pressure transmitter reading(s) and

reference static pressure reading(s)

at a given level;

Pf = Average reference static pressure

reading at a given level; d∆P = Average difference between

differential pressure transmitter

reading(s) and reference differential

pressure reading(s) at a given level;

∆P = Average reference differential

pressure reading at a given level; dTf = Average difference between

temperature transmitter reading(s)

and reference temperature

reading(s) at a given level; and

Tf = Average reference temperature

reading at a given level.

If the error calculations for error from

the primary element of the fuel

flowmeter were not available, then the

facility could use a default value of 1.0

percent of the upper range value error

from all parts of the fuel flowmeter

except for the differential pressure,

static pressure, and temperature

transmitters. (In other words, the factor

‘‘K’’ in the equation above would be

equal to 1.0 percent of the upper range

value.) However, this would almost

certainly trigger the requirement for

recalibration or retesting of the accuracy

of the transmitters in the next calendar

quarter because the fuel flowmeter

accuracy would exceed 1.0 percent of

the upper range value. Based upon

statements from the American Gas

Association, it is the Agency’s

understanding that for an orifice-,

nozzle-, or venturi-type fuel flowmeter

meeting AGA Report No. 3 or ASME

MFC–3M, the maximum error from

portions of the meter other than the

transmitters should be 1.0 percent of the

upper range value (see Docket A–94–16,

Item II–F–2, and this Docket, A–97–35,

Item II–E–18).

In the second approach to

determining error for orifice-, nozzle-,

and venturi-type fuel flowmeters, each

transmitter or transducer would be

tested separately for accuracy, and each

transmitter or transducer would be

required to meet an accuracy

specification of 1.0 percent of the full

scale range of the transmitter. Under

this approach, it would no longer be

necessary to determine the total error in

the flowrate from the fuel flowmeter.

Because this proposal would eliminate

the calculation of the total error in

flowrate, there would no longer need to

be a requirement to retest the accuracy

of the transmitters in the next calendar

quarter when the total fuel flowmeter

accuracy exceeds 1.0 percent of the

upper range value. In today’s rule, EPA proposes to allow

both of the approaches described above

for calculating the total flowmeter

accuracy. The second approach (i.e.,

calculating individual transmitter

accuracy) is simpler than calculating the

total error in the flow rate, although it

is less directly related to the accuracy of

SO2 mass emission rate and heat input

measurements than the fuel flowrate.

An individual transmitter accuracy

specification of 1.0 percent of the full

scale of each transmitter would be

slightly stricter than a total fuel

flowmeter accuracy specification of 2.0

percent of the upper range value of the

fuel flowmeter, because one transmitter

could potentially have an error greater

than 1.0 percent of its full scale range

while the entire error in the fuel

flowrate would still be less than 2.0 of

the upper range value of the fuel

flowmeter. Thus, the option of

calculating the total error in the fuel

flowrate has been retained in today’s

proposal. At least one industry

representative suggested allowing both

approaches of calculating accuracy

when testing transmitters of an

orifice-, nozzle-, or venturi-type fuel

flowmeter (see Docket A–97–35, Item II–

E–24).

The Agency considered two main

methodologies for transmitter testing on

orifice-, nozzle-, and venturi-type

flowmeters. The first method would be

to require a five-point test that checks

the linearity of the transmitter. The

transmitter would be tested against an

NIST traceable method (e.g., testing a

pressure transmitter against an NIST

traceable deadweight transmitter) at the

following percentages of the full scale

range of the transmitter: 0.0 percent,

20.0 to 30.0 percent, 40.0 to 60.0

percent, 70.0 to 80.0 percent, and 100.0

percent. This is the general approach

that was taken by many utilities that

provided transmitter calibration results

to EPA (see Docket A–97–35, Items II–

D–26 through 28).

The second method would be to

require a comparison to an NIST

traceable transmitter at the zero level

and at least two other levels across the

range of readings on the transmitter or

transducer. This would be different

from the first method in that the

transmitter would only need to be tested

across the range where the transmitter is
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28099

actually used. For example, if a fuel

flowmeter transmitter’s readings never

rise higher than 60.0 percent of the full

scale range of the transmitter, then the

transmitter could be tested at 0.0

percent, 30.0 percent, and 60.0 percent

of full scale. These procedures are

reflected in the proposed revised section

2.1.6.1 of Appendix D.

The Agency is proposing the second

method in today’s rule, i.e., that each

individual transmitter must be tested at

three or more points across its normal

range of readings. EPA realizes that it is

standard industry procedure to test a

fuel flowmeter at five levels across its

entire range (see Docket A–97–35, Item

II–E–24). However, the Agency is aware

of at least one case where a fuel

flowmeter failed to meet an accuracy

specification of 2.0 percent of the upper

range value when it was tested at 100.0

percent of the upper range value.

However, the fuel flowmeter was never

used to measure a rate greater than

roughly 55.0 percent of the upper range

value (see Docket A–97–35, Item II–D–

15). If this flowmeter had only been

required to test across the range where

the fuel flowmeter actually measured

fuel flow rates, it would have met the

accuracy specification. Section 2.1.5

requires fuel flowmeters that are tested

against a master fuel flowmeter to be

tested across the range of measured fuel

flowrate only. Requiring testing of each

transmitter at three or more points

across the range of all readings would

still ensure that the transmitter reads

accurately across all readings, while

reducing the possibility that the

transmitter might fail an accuracy test

because of a high error reading at the

high end of the transmitter’s range

where the transmitter is never used. At

least one utility has mentioned that this

would be helpful (see Docket A–97–35,

Item II–E–24). The Agency solicits

comment on the proposed approach.

Today’s proposed rule also includes

Equation D–1a for calculating error from

an individual flowmeter transmitter.

The Agency feels that this would clarify

the calculation. It also would prevent

the possible confusion that would occur

if a facility attempted to use the existing

Equation D–1, which is designed for a

fuel flowmeter that is compared to

another fuel flowmeter.

Finally, under today’s proposal, when

a transducer or transmitter test is failed,

a fuel flowmeter would be considered

out-of-control, and its data would be

considered invalid until the date and

time the transmitter is retested and

meets an accuracy of 1.0 percent of its

full scale.

(f) Reporting of Fuel Flowmeter Testing

Data

Background

As mentioned above in Section III.P.5

of the preamble, utilities have had

questions about how to report the

results of their fuel flowmeter testing

data. In certification applications and

quality assurance testing results,

utilities have reported test data in a

variety of ways. In some cases, the

Agency was unable to determine the

flowmeter accuracy from the testing

information provided because data were

not labeled as reference flow rate data,

flowmeter data, or accuracy data. For

example, for turbine flowmeters, data on

the reproducibility of the ‘‘K-factor’’ was

often presented. However, these are not

flow rate data, nor is it clear what the

accuracy of the flow rate is (see Docket

A–97–35, Item II–D–9). Sometimes data

were presented in tables. Other data

were presented in graphs (see Docket A–

97–35, Item II–D–9). In many cases,

Agency or state environmental agency

staff needed to request additional

information from utilities to determine

if they had met the accuracy

requirement for fuel flowmeters (see

Docket A–97–35, Items II–C–3, II–C–5).

To clarify the requirements for

certification applications for fuel

flowmeters, the Agency issued policy

guidance about the type of information

to provide (see Docket A–97–35, Item

II–I–9, Policy Manual, Question 12.27).

This guidance included a sample table

with an example of how to submit

information for a fuel flowmeter that is

tested against a master meter or flow

prover reference value.

Discussion of Proposed Changes

EPA proposes to add a sample table

to Appendix D (Table D–1) for

summarizing the results of accuracy

tests of fuel flowmeters that are

calibrated by comparison against other

fuel flowmeters or a prover. In addition,

EPA proposes to add a separate table for

summarizing the results of calibrations

of the transmitters or transducers of an

orifice-, nozzle-, or venturi-type fuel

flowmeter.

Rationale

In today’s proposed rule, EPA would

provide clarification in the form of a

table for summarizing the quality

assurance test results of fuel flowmeters

that are compared against other fuel

flowmeters or a prover. A second table

is provided for summarizing the results

of calibrations of transmitters or

transducers of an orifice-, nozzle-, or

venturi-type fuel flowmeter. This

second table accounts for differences in

the testing procedure for transmitters or

transducers. In both cases, EPA has tried

to make clear what critical information

would have to be reported in order to

demonstrate that the fuel flowmeter (or

the transmitter of an orifice-, nozzle-, or

venturi-type fuel flowmeter) meets the

accuracy specification. In addition, EPA

will design revised electronic record

types with this type of information so

that test results may be more easily

reported electronically. The Agency is

aware that this has been difficult or

confusing for some utilities (see Docket

A–97–35, Items II–D–23, and II–I–9,

Policy Manual, Question 12.27). The

Agency also considered adding a sample

graph for reporting accuracy data.

However, EPA feels that it would be

easier to compare the data in tabular

format and to enter it into the electronic

data format than to enter values from a

graph. Most of the graphs provided to

EPA have been relatively easy to read,

and there appears to be less of a need

for an example to be included in

Appendix D (see Docket A–97–35, Item

II–D–9).

7. Use of Uncertified Commercial Gas

Flowmeter

Background

Currently, a facility using Appendix D

may either install its own gas flowmeter

or use a commercial gas flowmeter

owned by a pipeline natural gas

supplier, provided that the meter meets

the reporting and accuracy requirements

of Appendix D, including initial

certification and continuing quality

assurance requirements. Some utilities

have suggested to EPA that they would

like to be able to use data from the

commercial billing of pipeline natural

gas without having to demonstrate that

the gas flowmeter meets initial

certification and continuing quality

assurance requirements (see Docket A–

97–35, Items II–D–45, II–D–49). Those

utilities assert that because the amount

of gas measured is already subject to

market forces, the monitoring should be

sufficiently accurate for the Acid Rain

Program. Utilities have mentioned that

gas companies often are already

conducting meter calibrations as quality

assurance, but utility customers

generally do not have access to this

information (see Docket A–97–35, Items

II–D–49, II–E–33). Facilities would find

it advantageous to rely upon their

commercial billing charges for

accounting for pipeline natural gas

usage because they would need to

devote less time, effort, and money to

the maintenance of gas fuel flowmeters.

This is particularly desirable to facilities

since the SO2 emissions from pipeline
28100 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

natural gas are extremely low compared

to the SO2 emissions from other fuels.

Discussion of Proposed Rule Changes

Proposed section 2.1.4.2 of Appendix

D would allow facilities to record and

report the gas flow rate, the heat input

rate, and emission values based on gas

flowmeter readings from a flowmeter

used for commercial billing of pipeline

natural gas without meeting the

certification requirements of section

2.1.5 of Appendix D or the quality

assurance requirements of section 2.1.6

of Appendix D under specified

conditions. Relief from the certification

and quality assurance requirements for

gas flowmeters used for commercial

billing would be limited to flowmeters

where the gas flowmeter is used for

commercial billing under a contract

with another company having no

common owner with the unit(s) served

by the flowmeter, which would exclude

any gas flowmeters used for transfers of

gas between different divisions,

subsidiaries, or affiliates of the same

company.

If the commercial billing gas

flowmeter would be used without

undergoing certification or quality

assurance under part 75 requirements,

then the designated representative

would need to report hourly records of

the gas flow rate, the heat input rate,

and emissions due to combustion of

pipeline natural gas, as well as heat

input rate for each unit if the

commercial billing gas flowmeter is on

a common pipe header. This would be

similar to the reporting currently done

for a certified gas flowmeter, but no

quality assurance records would be

required. The quarterly report would

contain record types 303 for fuel flow

rate and heat input rate, record type 314

for the SO2 mass emission rate, either

record type 320 or 323 for the NOX

emission rate in lb/mmBtu, and either

record type 330 or 331 for CO2 mass

emissions. It also would be necessary

for the designated representative to

identify the commercial billing gas

flowmeter in Table B (electronic record

type 510) of the monitoring plan for the

unit.

So long as the records from the

commercial billing gas flowmeter are

the values used for commercial billing,

the designated representative would

report those values from the commercial

billing gas flowmeter without

adjustment. If the records from the

commercial billing gas flowmeter are

not consistent with the values used for

commercial billing because of some

problem that needs to be reconciled

between the gas vendor and the facility

customer, then the designated

representative would consider the

readings from the commercial billing

gas flowmeter to be invalid for that

billing period and would report hourly

records using the missing data

procedures for fuel flowmeter data

found in section 2.4 of Appendix D for

all hours of gas combustion during that

billing period. A facility would not be

able to use the commercial billing value

in the quarterly report if the commercial

billing value was different from the

value on the commercial billing gas

flowmeter.

Rationale

Utilities have suggested that the

purchase of pipeline natural gas from a

vendor is subject to market forces that

ensure accurate monitoring (see Docket

A–97–35, Item II–D–49). Utilities have

stated that gas vendors already have

procedures for certification and meter

calibration and that the gas vendors

have an even greater incentive than

utilities to maintain a high monitor

‘‘uptime’’ (i.e., availability) for gas fuel

flowmeters. Typically, utilities will

work together with their gas vendors if

they believe there is any sort of

discrepancy in their monthly billing for

pipeline natural gas (see Docket A–97–

35, Items II–D–33, II–E–33).

The Agency believes that this

argument is reasonable. However, EPA

also understands that some utilities

require their gas vendor to correct their

billing values based upon the evidence

of the utility’s own gas flowmeters. In

addition, it is likely that utilities will be

combusting more pipeline natural gas in

the future as they respond to current

and potential future environmental

requirements for reducing NOX and

CO2. Therefore, the Agency believes that

there must be conditions placed upon

reporting emissions and heat input for

the Acid Rain Program from gas

flowmeters used for commercial billing

if the gas flowmeters will not be

required to meet the certification and

quality assurance requirements of part

75.

The Agency is proposing to limit the

waiver from certification and quality

assurance requirements to commercial

billing gas flowmeters that are used in

billing transactions between companies

with entirely different ownership (e.g., a

pipeline natural gas vendor and a

separate electric utility company with

no owners in common). Some utilities

requested the relief from quality

assurance requirements based upon the

reasoning that a gas vendor would do its

own quality assurance and

maintenance, and perhaps with better

accuracy than a utility would be able to

maintain, but the utility would not

necessarily have access to the test

results and would not have control over

what quality assurance might occur (see

Docket A–97–35, Items II–D–49, II–E–

33). This reasoning is sound if the

utility and the gas vendor have no

common owners, but it would not

necessarily be sound if a gas supplier

were part of the same company as the

electric utility. Also, utilities suggested

that a gas vendor may have an incentive

to overstate the amount of gas in order

to bill more, rather than having an

incentive to underestimate or underreport (see Docket A–97–35, Item II–D–

49). Once again, this argument is

reasonable if the gas vendor is a separate

entity, but may not be reasonable if the

gas supplier has common owners with

the electric utility. Therefore, today’s

proposed rule includes a limitation on

the waiver from certification and quality

assurance requirements for commercial

billing gas flowmeters to those gas

flowmeters used for commercial billing

between companies with separate

ownership.

EPA solicits comment on the

proposed approach of allowing the use

of uncertified fuel flowmeters for

purposes of determining emissions and

heat input in the limited circumstances

described above.

EPA has proposed in today’s rule that

a facility may only report data from a

commercial billing gas flowmeter if the

data are used in a commercial

transaction. A group of utilities

suggested that the Agency allow

facilities to report quarterly SO2

emissions based on gas supplier data,

including any reconciliation that has

taken place (see Docket A–97–35, Item

II–D–45). Such a reconciliation between

a gas vendor and its customer may occur

if the customer believes there is a

discrepancy in their monthly billing for

pipeline natural gas (see Docket A–97–

35, Items II–D–33, II–E–33). If a facility

and its gas vendor determined that gas

supply information from a fuel

flowmeter were not sufficiently accurate

to purchase gas, then the Agency

presumes the gas supply information is

also not sufficiently accurate for

emissions accounting.

The Agency also considered whether

a facility should be able to use the

reconciled gas volumes agreed upon for

billing if that value were not from the

commercial billing gas flowmeter. In

general in the Acid Rain Program, handtyped corrections to emissions data are

not permitted (see Docket A–97–35,

Item II–I–14), with the primary

exception of cases where sound

engineering judgement indicates there is

an obvious error that cannot exist, such

as a negative concentration reading.
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28101

Allowing a facility to enter a

commercial billing value by hand would

contradict this basic reporting policy of

the Acid Rain Program.

Today’s proposed rule also specifies

the type and frequency of information

that would be required to be reported by

a facility concerning pipeline natural

gas. Some utilities have requested the

ability to report only a quarterly

cumulative SO2 mass emission number

for emissions from gas (see Docket A–

97–35, Item II–D–45). However, the

Agency believes that there are several

reasons for maintaining hourly heat

input rate and emissions data during

combustion of pipeline natural gas.

First, hourly data is the most useful

interval of data for air quality modeling

in order to see if progress is being made

in reducing emissions. Hourly data from

combustion of pipeline natural gas will

become even more important as more

units switch to combusting pipeline

natural gas in order to reduce their

emissions. In addition, hourly data are

easier to check for anomalous values

than quarterly data. Further, hourly heat

input rate data is necessary in order to

determine the NOX emission rate when

using the NOX-versus-heat input rate

correlation of Appendix E to part 75.

Also, since hourly data are already

being recorded, reported, and processed

by automated computer data acquisition

and handling systems, a change to this

requirement would require costly

reprogramming for industry and for

EPA. For all of these reasons, EPA is

proposing that facilities continue to

report hourly gas flow rates, heat input

rates, and emissions from commercial

billing gas flowmeters that are not

required to meet the certification and

quality assurance requirements of part

75.

Q. Appendix G

1. Use of ASTM D5373–93 for

Determining the Carbon Content of Coal

Background

Appendix G to part 75 provides

procedures for determining CO2

emissions from fuel sampling and

analysis instead of from a CO2 CEMS

and a flow monitor. Section 2.1 of

Appendix G includes a mass-balance

equation for determining CO2 (see

Equation G–1), the frequency for

sampling fuel, and the specific methods

for analyzing fuel for carbon content.

Section 2.3 of Appendix G provides a

method for determining CO2 mass

emissions from a gas-fired unit from its

heat input using Equation G–4. Some

facilities use Appendix G procedures to

determine CO2 mass emissions every

day for their units. Other facilities might

use the procedures of section 2.1 of

Appendix G only to provide CO2 mass

emissions during extended periods

when CO2 data are missing from their

CO2 CEMS, under the provisions of

§ 75.36.

A utility and its fuel analysis

laboratory contacted EPA concerning

use of an additional ASTM method for

analysis of carbon content. The industry

staff felt that the new infrared analysis

method, ASTM D5373–93, was the most

up-to-date method and that this method

should be at least as accurate as the

methods specified in Appendix G to

part 75 (see Docket A–97–35, Item II–D–

25). Based upon the precision and bias

information in the method, EPA

approved its use under § 75.66 (see

Docket A–97–35, Item II–C–16).

Discussion of Proposed Changes

Today’s proposed rule would allow

the use of ASTM D5373–93, ‘‘Standard

Methods for Instrumental Determination

of Carbon, Hydrogen, and Nitrogen in

Laboratory Samples of Coal and Coke,’’

for Section 2.1 of Appendix G to part 75.

This method is for determining the

carbon content of coal. ASTM D5373–93

would also be incorporated by reference

in § 75.6. Facilities would also continue

to have the option to use ASTM D3178–

89 to analyze coal for carbon content.

Rationale

EPA has previously approved the use

of ASTM D5373–93 for analyzing the

carbon content of coal (see Docket A–

97–35, Item II–C–16). The Agency

believes this method is of sufficient

accuracy for use in the Acid Rain

Program. In addition, EPA historically

has accepted analytical methods from

standard-setting organizations such as

the American Society for Testing and

Materials (ASTM). The Agency solicits

comment on the use of ASTM D5373–

93 for analyzing the carbon content of

coal.

2. Changes to Fuel Sampling Frequency

Background

Section 2.1 of Appendix G (as revised

by the May 17, 1995 direct file rule)

specifies that fuel sampling should be

done weekly for gas or oil for each

shipment for diesel fuel and at least

once per month for gaseous fuel. The

sampling frequencies for diesel fuel and

for gaseous fuel are consistent with the

frequency for sampling under Appendix

D to part 75.

Most gas-fired and oil-fired units that

perform fuel sampling for sulfur content

under Appendix D also perform fuel

sampling for carbon content. Today’s

proposed rule would reduce the

frequency with which facilities need to

sample oil or gas under Appendix D.

Discussion of Proposed Changes

The fuel sampling frequency specified

in section 2.1 of Appendix G would be

made consistent with the proposed

requirements for Appendix D oil and

gas sampling. Thus, all oil samples

could be taken upon delivery, either

from the delivery vessel itself or from

the storage tank after a delivery is

transferred. Gas samples would be taken

monthly (for pipeline natural gas), for

each shipment (for gases delivered in

lots), or daily (for fuels that are analyzed

daily for sulfur). Coal samples would

continue to be taken weekly.

Rationale

Appendix D of today’s proposed rule

would reduce the required sampling

frequency of oil and gaseous fuels

delivered in lots. Based upon

information provided by one utility, the

variability of carbon content in oil is

less than the variability of sulfur content

(see Docket A–97–35, Item II–D–18).

Some utilities have stated that they

would prefer the procedures for sulfur

and GCV to be similar (see Docket A–

97–35, Item II–D–24). Based upon this

statement, the Agency believes that

facilities would also prefer to have

consistent fuel sampling procedures for

Appendices D and G. Therefore, the

Agency believes it is appropriate to

make the fuel sampling frequency for

carbon analysis under Appendix G

consistent with the fuel sampling

frequency for sulfur content under

Appendix D. Similarly, section 5.5 of

Appendix F would be revised to make

the gas sampling frequency consistent

with Appendix D. The Agency solicits

comment on the proposed changes to

the fuel sampling frequency.

3. Addition of Missing Data Procedures

for Fuel Analytical Data

Background

Appendix D provides procedures for

substituting missing fuel analytical

information, either for sulfur or GCV.

However, Appendix G to part 75 does

not specify what should be done if

carbon content data are missing.

Some software programmers asked

EPA what missing data procedures

should be used for carbon content data

(see Docket A–97–35, Item II–E–5). The

Agency responded to this question at a

public conference and in policy

guidance (see Docket A–97–35, Items II–

E–5, and II–I–9, Policy Manual,

Question 6.3). In its policy guidance,

EPA stated that facilities should ‘‘[f]ill

in the most recent carbon content . . .

available for that fuel type (gas, oil or
28102 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

coal) of the same grade (for oil) or rank

(for coal). If at all possible, use a carbon

content value from the same fuel

supply.’’

Discussion of Proposed Changes

Today’s proposed rule would allow

facilities to substitute for missing carbon

content prior to January 1, 2000, using

either the most recent carbon content for

that fuel type, grade and rank, or

procedures parallel to those of

Appendix D. Beginning January 1, 2000,

facilities would substitute for missing

carbon content data using procedures

consistent with Appendix D. For

gaseous fuels and for oil sampled

manually, these procedures would

provide for a conservative maximum

carbon content value. Specifically, the

permissible conservative carbon content

values would be either the maximum

carbon content measured in the

previous calendar year or, if this

information were not available, a default

value based upon handbook fuel

characteristics. For weekly coal samples

or composite oil samples, CO2 mass

emissions would be calculated using the

highest carbon content from the

previous four carbon samples available.

Rationale

Software programmers have already

indicated that it is useful to have a

procedure for filling in missing carbon

content data for purposes of

programming (see Docket A–97–35, Item

II–E–5). Some utilities have stated that

they would prefer the missing data

procedures to be similar for both sulfur

and GCV, even if both values are

conservative (see Docket A–97–35, Item

II–E–24). Therefore, the Agency believes

that facilities would also prefer to have

Appendix G missing data procedures for

carbon content that are parallel with

those for sulfur content and GCV in

Appendix D. Thus, today’s proposal

would allow for missing data for manual

oil samples or for gaseous fuel using the

maximum carbon content measured in

the previous calendar year or, if this

information were not available, a default

value based upon handbook fuel

characteristics.

In determining the conservative

default carbon content values that

would be used for missing data

substitution in the event that no

previous carbon content samples are

available, the Agency consulted several

handbook reference tables on fuel

characteristics. Specifically, the Agency

reviewed handbook values for the

carbon content of coal (of various

ranks), oil (of various grades), and gas

(of different types). (see Docket A–97–

35, Items II–I–18, II–I–19, II–I–20). In

the case of coal, there was a fairly wide

range of carbon content values for

different ranks of coal. Therefore,

today’s rule would propose separate

default carbon content values for

Anthracite, Bituminous, and

Subbituminous/Lignite. In contrast, the

carbon content values for different

grades of residual oil were fairly

consistent. For this reason, today’s rule

proposes a single default carbon content

value for all grades of oil. Finally, for

gaseous fuels, the handbooks which

were reviewed presented a fairly narrow

range of values for natural gas but a

much wider range of values for other

types of gaseous fuels. Therefore,

today’s rule proposes a value for natural

gas and a separate, conservative value

for all other types of gaseous fuels.

The Agency solicits comment on the

proposed revisions to the missing data

procedures under Appendix D.

R. Reporting Issues

1. Partial Unit Operating Hours and

Emission and Fuel Flow Rates

Background

For affected units that use CEMS to

account for emissions under part 75,

hourly emission rates of SO2 (in lb/hr),

NOX (in lb/mmBtu), and CO2 (in tons/

hr), and hourly heat input rates (in

mmBtu/hr) are calculated using the

applicable equations in Appendix F. For

affected units that use fuel flow meters

and fuel analysis (or default emission

rates) rather than CEMS, the applicable

equations in Appendices D, F and G (for

certain gas-fired units) are used to

determine the hourly SO2 and CO2 mass

emission rates and heat input rates. For

oil and gas-fired peaking units that use

Appendix E to account for NOX

emissions, the hourly NOX emission

rates in lb/mmBtu are derived from a

graph of NOX emission rate versus heat

input rate, the hourly heat input rates

being derived from the applicable

equation in Appendix F. Under

§ 75.54(b)(2), unit operating time is

reported by rounding the actual

operating time up to the nearest 15

minutes.

The equations in Appendices D

through G assume that each unit

operating hour consists of a full 60

minutes of unit operation (or, for

common stacks, that emissions are

discharged through the stack for 60

minutes in each hour); the equations do

not attempt to account for partial unit

operating hours. This is a shortcoming

in the current rule, because partial unit

operating hours sometimes occur during

periods of unit startup, shutdown, and

malfunction. Therefore, to ensure

accurate accounting of SO2 and CO2

mass emissions and unit heat input, part

75 should address the issue of partial

unit operating hours. Note, that because

NOX emission rates are measured with

respect to heat input (lb/mmBtu), rather

than with respect to time (lb/hr), this

discussion is not relevant for NOX

emission rate. Many vendors and

utilities have asked EPA for guidance on

how to calculate mass emission rates

during partial unit operating hours (see,

e.g., Docket A–97–35, Item II–D–4).

The crux of the partial unit operating

hour issue is when to adjust the

emission data for unit operating time,

before the reporting of hourly values or

at the quarterly summation. For many

units, there are very few hours of partial

operation, and adjusting the data for

operating time merely involves

multiplying by 1, a seemingly

inconsequential issue. For other units,

such as peaking and cycling units,

which start up and shut down often, the

issue of how the data is reported is

relevant because there can be a

significant amount of partial unit

operating hours. Definitive and

standardized reporting requirements

allow facilities and/or vendors to

program their software such that their

calculated result equals the result

calculated by EPA.

For SO2 and CO2, the question is

whether to report hourly emissions on

a mass basis (i.e., lb or tons) or on a

mass emission rate basis (i.e., lb/hr or

tons/hr). For heat input, the question is

whether to report the total hourly heat

input (in mmBtu) or the hourly heat

input rate (in mmBtu/hr). For example,

suppose that a unit emits for a full 60

minutes in a particular clock hour at an

SO2 concentration of 602.5 parts per

million (ppm), a CO2 concentration of

10.0 percent, a volumetric flow rate of

4,000,000 standard cubic feet per hour

(scfh), and a heat input rate of 300

mmBtu/hr. Suppose further that the

same unit operates for only 15 minutes

in the next hour and all of the

parameters (i.e., SO2 and CO2

concentration, flow rate, and heat input

rate) remain unchanged. If unit

operating time is disregarded, the SO2

mass emission rate (calculated from

Equation F–1 in Appendix F) would be

the same (400 lb/hr) for both the partial

operating hour and the full unit

operating hour. Similarly, the CO2 mass

emission rate would be the same (22.8

tons/hr) and the heat input rate would

be the same (300 mmBtu/hr) for both the

full and partial operating hours. The

mass emission rates and heat input rate

for the partial unit operating hour are

the same as the full-hour values because

they are based solely upon data

recorded during unit operation, i.e., in
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28103

the first 15 minutes of the hour. The

hourly average rates for the partial hour

do not include ‘‘zero’’ values for the

three 15-minute periods of unit nonoperation during the clock hour (e.g., an

SO2 emission rate of (400 lb/hr + 0 + 0

+ 0)/4 = 100 lb/hr would not be

appropriate). If the emission and heat

input rates are adjusted by multiplying

them by the operating time, then, for the

full operating hour (i.e., operating time

= 1.0), the SO2 and CO2 mass emissions

and heat input would be, respectively,

400 lb SO2, 22.8 tons CO2, and 300

mmBtu. For the partial hour (operating

time = 0.25), the corresponding values

would all be divided by four, i.e., 100

lb SO2, 5.7 tons CO2, and 75 mmBtu,

respectively.

Software vendors and utilities have

requested clarification as to whether

hourly SO2 mass emission values

should be reported as totals, in lb, or as

rates, in lb/hr. As early as November of

1993, EPA stated that hourly SO2 mass

emission values should be reported as

rates in lb/hr. Then, when determining

quarterly cumulative SO2 mass

emissions, each hourly emission rate

would be converted to a mass basis by

multiplying it by the unit operating time

(expressed as a fraction of an hour) for

the same hour. Similarly, hourly heat

input values would be expressed as

rates, in mmBtu/hr, and hourly CO2

mass emissions would be expressed as

rates, in tons/hr. Parallel issues were

also addressed by the Agency’s policy,

for units that determine SO2 and CO2

mass emissions and heat input from fuel

flow rates and fuel analyses under

Appendix D to part 75 (see Docket A–

97–35, Item II–I–9, Policy Manual,

Questions 14.14, 14.36 and 14.37).

Some utilities have requested that the

Agency change its policy and allow

reporting of hourly total SO2 and CO2

mass emissions and heat input instead

of mass emission rates and heat input

rates (see Docket A–97–35, Item II–E–

14). The utilities argued that this would

simplify determination of the total yearto-date SO2 mass emissions, in order to

estimate the number of allowances

needed to cover a unit’s emissions or to

prepare a report on mass emissions for

a state environmental agency, because

the reported values would already be

multiplied by the hourly operating time.

Thus, by performing the multiplication

by operating time before reporting the

hourly value rather than waiting until

calculating the quarterly value, it might

save a calculation step if a facility

wanted to use the data for another

purpose. For these reasons, reporting of

totals is a preferred approach for some

facilities. However, other utilities that

have incorporated the correct rate

approach into their software have

indicated that they would prefer not to

have to revise their software to report in

totals.

Partial unit operating hours must also

be considered in the recording and

reporting of hourly unit load. The

standard missing data procedures in

§ 75.33 require historical flow rate data

to be placed in load ‘‘bins’’ (ranges)

based upon the maximum operating

electrical generation (or steam flow rate)

of the unit. However, the recorded

hourly volumetric flow rate value in

scfh applies only to the fraction of the

hour in which the unit operates.

Therefore, the reported load for the hour

should be based upon the average

electrical generation during the period

when the unit operates. Thus, the

electrical generation should be recorded

as a rate for the period when the unit

operates, rather than an integrated total

for the entire hour. The units for

reporting hourly load should, therefore,

be MWe or 1000 lb/hr of steam, and not

MW-hr or 1000 lb of steam.

Discussion of Proposed Changes

In today’s rulemaking, EPA is

proposing to amend part 75 to clarify

that heat input, fuel flow, SO2 mass

emissions, and CO2 mass emissions are

all to be reported on an hourly basis as

rates. Today’s proposal also would

clarify that the hourly emission rates are

to be based only upon data collected

during periods of unit operation (i.e., for

partial unit operating hours, emission

rates or heat input rates of zero that are

recorded during periods of nonoperation are not to be included in the

hourly average emission rates). These

clarifications are found in proposed

§ 75.57, and Appendices D, E and F to

part 75. Today’s proposed rule would

also clarify that the proper units of

reporting for load are MWe and lb/hr of

steam.

Today’s proposal would also provide

new options for reporting unit operating

time. While the current requirement to

report operating time rounded to the

nearest 15 minutes would be retained as

an option, the proposal would allow

more flexibility by specifying that, for

reporting purposes, unit operating time

be rounded up to the nearest fraction of

an hour (in equal increments that can

range from one hundredth to one

quarter of an hour, at the option of the

owner or operator).

Consistent with the requirement to

report hourly SO2 and CO2 mass

emissions and hourly heat input as

rates, today’s rulemaking proposes to

revise the quarterly summation formulas

for SO2 and CO2 and to add summation

formulas for heat input in Appendix F

to part 75. The proposed formulas show

that hourly mass emission rates or heat

input rates would be multiplied by unit

operating time before summing to get

total mass emissions. Today’s proposal

also includes new formulas in

Appendix D for summing hourly SO2

mass emission rates and hourly heat

input values from fuel flowmeter

systems in order to determine quarterly

and annual total SO2 mass emissions

and total heat input. The Appendix D

and F equations revised or added to

address summations include Equations

D–6, D–7, D–8, D–9, F–3, F–12, F–24,

and F–25.

In addition, EPA is proposing

optional recordkeeping provisions for

determining total heat input, total SO2

mass emissions or total CO2 mass

emissions for the hour. In addition to

reporting the required emission and

heat input rates, owners or operators

could choose to report the total hourly

heat input and mass emissions under

this option.

Rationale

As stated above, some utilities have

expressed a preference for reporting

hourly total values for SO2 and CO2

mass emissions and heat input, rather

than rates (see Docket A–97–35, Item II–

E–14). They have stated that this is

easier to understand and that reporting

hourly total values, instead of or in

addition to rates, would make it easier

to determine the cumulative total mass

emissions at any time during the year.

One representative requested that

EPA consider allowing either method of

calculation (i.e., hourly rates or totals),

so long as the annual mass emissions

and heat inputs are correctly

determined and reported. EPA notes

that, although this approach may appear

advantageous because it would not

require some facilities to reprogram

their DAHS software, it would require

other facilities to reprogram their

software and it would make it difficult

for EPA to verify emissions calculations

from reported hourly data. Because EPA

considers it essential to the Acid Rain

Program to be able to recalculate annual

compliance values based upon hourly

emission information reported by

facilities, the Agency is not revising the

rule to take the representative’s

suggestion. EPA considered using the

total mass emissions (or total heat input)

approach instead of the mass emission

rate (or heat input rate) approach

currently stated in Agency policy (see

Docket A–97–35, Item II–I–9, Policy

Manual, Questions 14.14 and 14.36). In

fact, as discussed in section III.H. of this

preamble, the Agency is proposing,

under subpart H of part 75, model
28104 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

reporting requirements for NOX mass

emissions that would (if adopted by an

applicable state or federal authority)

require hourly NOX mass emissions to

be reported as a total value (in lb) rather

than an hourly mass emission rate (in

lb/hr). However, using hourly mass

emission totals for values currently

reported to the Agency would have the

distinct disadvantage of requiring both

EPA and the utilities who correctly

implemented the mass emission rate

approach to reprogram software to

perform the new calculations, whereas

retaining the use of SO2 and CO2

emission and heat input hourly rates

offers several advantages.

First, using hourly mass emission

rates and heat input rates instead of

totals is consistent with the units of

measure in which flow rate is recorded.

Volumetric flow monitors measure flow

rate during a given time in standard

cubic feet per hour scfh, rather than

total flow in standard cubic feet (scf).

When SO2 concentration is multiplied

by volumetric flow rate, one calculates

a mass emission rate rather than a total

mass of SO2. Similarly, multiplying a

volumetric flow rate by a diluent gas

concentration yields a heat input rate in

mmBtu/hr, rather than a total heat input

in mmBtu.

Second, the current missing data

procedures for volumetric flow rate,

which are based upon the assumption

that flow is a rate that is comparable

from one hour to another, rather than a

total volumetric flow that will vary

depending upon the unit operating time,

would no longer be appropriate if

volumetric flow rate were changed to a

total volumetric flow. Third, for

Appendix E gas-fired or oil-fired

peaking units, it is critical that heat

input rate, and not total heat input, be

used to determine the NOX emission

rate. The Appendix E correlation curve

formulas are based upon heat input rate

rather than total heat input. Appendix E

allows a facility to create a correlation

of the NOX emission rate measured in

the stack during stack testing and heat

input combusted during that same

period of time, rather than installing

CEMS on gas-fired or oil-fired peaking

units. If a facility were mistakenly to use

the total heat input from an hour rather

than the heat input rate, it would

correlate to the wrong portion of the

NOX to heat input rate correlation curve

and would incorrectly estimate NOX

emission rate. For example, if heat input

totals were used to determine NOX

emission rate from the Appendix E

curve, the unit would have a different

NOX emission rate if it combusted

25,000 mmBtu in half an hour than if it

combusted 25,000 mmBtu during a full

hour. This would apply both under the

current provisions of Appendix E and

today’s revised provisions to Appendix

E.

In view of the above considerations,

today’s proposed rule would affirm that

facilities are to report SO2 and CO2

emissions and heat input as rates on an

hourly basis. However, facilities would

also be allowed, at their discretion, to

report SO2 and CO2 emissions and heat

input as hourly totals, in addition to

reporting them as rates. This approach

would not require reprogramming of

computerized reporting software for

those utilities that are following EPA’s

current policy, and would provide

consistent reporting that allows EPA to

recalculate emissions and heat input

values. Those utilities that find

recording and reporting of hourly total

SO2 and CO2 mass emissions and heat

input to be desirable would be able to

do so. EPA will provide the necessary

electronic record types to support this

optional reporting.

Although today’s proposed rule

would affirm that emissions and heat

input are to be reported as rates, rather

than totals, EPA has become concerned

that for partial unit operating hours,

some utilities are incorrectly calculating

hourly average flow rates by including

flow rates of zero in the hourly average

to represent periods of non-operation,

rather than basing the average flow rate

solely on the minutes of operation of the

affected unit during the clock hour. In

one example, it appears that the

software is designed to calculate the

average flow rate by including data from

all minutes during those fifteen-minute

quadrants of an hour when the unit

operates, thus including some minutes

when the unit is not operating, rather

than creating an average flow rate just

from merely those minutes when the

unit is operating and emitting (see

Docket A–97–35, Item II–C–17). EPA

suspects that still other utilities may be

calculating an average hourly flow rate

that includes flow rates of zero for

whole quadrants of an hour when a unit

does not operate. This can result in the

flow rate values for partial operating

hours being under-reported to EPA and

a lowering of the average flow rates in

the load ranges used to provide

substitute flow rate data, both of which

can cause underestimation of SO2 mass

emissions.

The Agency is also concerned that

this same kind of improper data

averaging may be occurring when

hourly gas concentrations are

determined during partial operating

hours. EPA would, therefore, require in

today’s proposal that facilities base all

of their reported hourly average

concentrations, flow rates, emission

rates, and heat input rates solely upon

data that are recorded during unit

operation (that is, when the unit is

combusting fuel and emitting).

Some utilities have indicated that the

approach of averaging in readings of

zero from periods of non-operation has

been incorporated to compensate for

having to report operating time rounded

up to the nearest fifteen minutes (Note,

this is not an acceptable approach). A

utility representative indicated that

reporting operating time to less

precision can cause overestimation of

emissions because the operating time is

multiplied by the mass emission rate.

Thus, a mass emission rate of 400 lb/hr

measured over a period of 20 minutes,

during an hour when the unit shut

down, would be multiplied by an

operating time of .5 hr (i.e., 20 minutes

rounded up to the nearest fifteen

minutes) and would result in 200 lb of

SO2 being reported rather than the 132

lb of SO2 that was actually emitted. The

utility suggested that a solution would

be to allow operating time to be reported

to more precision than is currently

allowed. Therefore, today’s proposal

would allow flexibility for reporting

unit operating time to greater precision.

While the current requirement to report

operating time rounded up to the

nearest 15 minutes would be retained as

an option, the proposal would allow

more flexibility by specifying that unit

operating time be rounded up to the

nearest fraction of an hour (in equal

increments that can range from one

hundredth to one quarter of an hour, at

the option of the owner or operator).

Thus, a facility could decide whether it

had enough partial operating hours (e.g.,

unit start-ups and shutdowns) to merit

changing their software to report

operating time to more precision.

2. Use of Bias-Adjusted Flow Rates in

Heat Input Calculations.

In late 1995, the first year of the Phase

I SO2 allowance program, EPA

conducted an audit of the Phase Iaffected units. Data from the second

quarter of 1995 were retrieved from the

Emission Tracking System (ETS) in

order to determine whether the SO2

emission rates and heat input values

were being properly reported. The

results of the audit showed that a

number of sources were not reporting

heat input correctly. The problem in

most instances was that the unadjusted

flow rate was being used in the heat

input equation, rather than the biasadjusted value. EPA believes that this is

attributable to the fact that part 75 does

not explicitly state that the bias-adjusted

flow rate is to be used in heat input
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28105

calculations. The Agency has attempted

to clarify this through policy guidance

(see Docket A–97–35, Item II–I–9, Policy

Manual, Question 14.81). To correct the

situation, the necessary language would

be added to section 7.6.5 of Appendix

A in today’s proposed rule.

3. Removing the Restriction on Using

the Diluent Cap Only for Start-Up

Background:

Based on the May 17, 1995 direct final

rule, sections 3.3.4, 4.1, 4.4.1, 5.1, 5.2.1,

5.2.2, 5.2.3, and 5.2.4 of Appendix F

currently provide for the substitution of

a constant CO2 or O2 value for a

measured value from a CO2 or O2

monitor during unit start-up. This

provision was originally created in

response to concerns from some utilities

that their NOX emission rate in lb/

mmBtu was being overestimated during

unit start-up (see Docket A–90–51, Item

IV–D–220, Letter from English, Mark G.,

Deputy General Counsel, Kansas City

Power & Light Company on EPA’s

Proposed Part 75 regulations; see also

Docket A–94–16, Item II–F–2). During

unit start-up or other periods when the

unit is at a low load level, CO2

concentrations are lower than during

normal operation and O2 concentrations

are higher than during normal

operation. The NOX emission rate

equation, however, is not designed to be

used in these situations because it

assumes complete combustion and

normal operating conditions. As a

result, the NOX emission rate equation

overestimates the NOX emission rate

when the CO2 concentration is very low

or the O2 concentration is very high,

such as during start-up. The equations

for calculating emission rates in lb/

mmBtu use measured CO2 concentration

or the difference between ambient air’s

O2 concentration and the measured O2

concentration in the denominator. For

example, NOX emission rate is

calculated using a NOX pollutant

concentration monitor and a CO2

diluent monitor using the following

equation:

E C F

CO NO NO c X X = × − 1194 10 7 100

2

. %

When a small CO2 concentration is

entered into this equation, the

calculated NOX emission rate will be

very high and will overestimate the

actual emissions.

The idea of capping CO2 or O2

concentration was implemented in part

75 for determination of NOX emission

rate, CO2 mass emissions, and heat

input during unit start-up. The cap

concentration was set at a minimum

CO2 concentration of 5.0 percent CO2

and a maximum O2 concentration of

14.0 percent O2, based upon some

information provided by utilities for

boilers (see Docket A–94–16, Item II–D–

34).

Some utilities asked EPA to consider

extending this cap on diluent gas

concentrations to other situations when

a unit is operating at a low level (see,

e.g., Docket A–97–35, Items II–D–20 and

30, and Docket A–97–35, Items II–E–13

and II–E–14). In addition to unit startup, this might include periods of unit

shutdown or unit ‘‘banking,’’ where a

unit is combusting a very small amount

of fuel to keep the boiler warm, but little

or no electricity is generated. During

these other situations where a unit

operates at a low level, the CO2

concentration will be very low and the

O2 concentration will be very high,

resulting in high calculated NOX

emission rate values like those during

unit start-up. One software vendor

specifically mentioned that it would be

easiest to implement the diluent cap if

it could be used any time the CO2

concentration would fall below or the

O2 concentration would rise above the

cap value (see Docket A–97–35, Item II–

E–7). This could be implemented

mathematically in the software, rather

than having to examine the unit

operation or the number of hours since

the unit started operating in order to

trigger use of the diluent cap.

During the process of implementing

the May 17, 1995 direct final rule, EPA

issued guidance that explained that

facilities may use the diluent cap values

for calculating NOX emission rate

during unit start-up whenever the CO2

concentration is below 5.0 percent or

the O2 concentration is above 14.0

percent, and also may use the actual

measured CO2 or O2 concentration

values at all times for calculating CO2

mass emissions or heat input (see

Docket A–97–35, Item II–I–9, Policy

Manual, Question 14.39). In Question

14.39, EPA recommended that even if

the diluent cap is used to calculate NOX

emission rate, the actual diluent

measurement should be used for the

purpose of calculating CO2 mass

emissions or heat input, because the

purpose of the diluent cap was ‘‘to

avoid using an extreme diluent

concentration in the denominator of the

equation to calculate emission rate in

lb/mmBtu.’’ The formulas for

calculating hourly CO2 mass emission

rate or hourly heat input rate do not use

the CO2 or O2 concentrations in the

denominator of the equation. Thus, use

of the diluent cap would tend to

overestimate both CO2 mass emission

rate and hourly heat input.

Discussion of Proposed Changes

Today’s proposed rule would allow

facilities to use diluent cap values of

14.0 percent O2 or 5.0 percent CO2 for

boilers and 19.0 percent O2 or 1.0

percent CO2 for turbines. For the

purpose of calculating NOX emission

rates in lb/mmBtu, the diluent cap

would be allowed to be used for any

hour in which the average measured

CO2 concentration is below the cap

value or the average measured O2

concentration is above the cap value.

Diluent cap values would still be

allowed to be used to calculate CO2

mass emissions or heat input, as well as

NOX (or SO2) emission rate in lb/

mmBtu.

Rationale

EPA acknowledges that there are

periods of low unit operation or low

load in addition to unit start-up where

the calculated NOX emission rate would

be overestimated if it were based upon

measured diluent concentrations.

Therefore, the Agency believes that

extending use of the diluent cap is

appropriate. The Agency believes that

allowing use of the diluent cap anytime

when the actual measured value is

above the cap (for O2) or below the cap

(for CO2) is easier to program and to

implement than limiting the use of the

diluent cap based upon unit load,

another option that EPA considered.

The Agency believes that it is unlikely

that a unit would ever be able to operate

at a high load and still have an O2 or

CO2 concentration beyond the diluent

cap value. Therefore, it is not necessary

to limit the use of the diluent cap value

based on unit load.

The Agency is also proposing new

diluent cap values for turbines.

Turbines tend to operate with much

higher levels of excess O2 than boilers.

For example, Method 20 of Appendix A,

40 CFR part 60, the procedure for testing

SO2, NOX and diluent gas from

stationary gas turbines subject to the

NSPS, requires testers to correct data to

a typical concentration of 15.0 percent

O2. Emissions data reported to EPA

confirms that for turbines, hourly

concentrations of O2 are typically

between 14.0 and 16.0 percent and

hourly concentrations of CO2 are

typically between 3.0 and 4.0 percent.

Thus, a turbine’s diluent gas

concentration is likely to consistently

exceed the diluent cap value of 14.0

percent O2 and to be consistently below

the cap value of 5.0 percent CO2

promulgated in the May 17, 1995 direct

final rule. If these values were allowed

to be used by turbines at all times rather

than just during unit start-up, a turbine
28106 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

could conceivably report its NOX

emission rate using only the diluent cap

value and never report the actual

monitored diluent concentrations,

thereby consistently underestimating

the NOX emission rate. Therefore,

today’s proposal provides diluent cap

values of 19.0 percent O2 or 1.0 percent

CO2 that are clearly beyond the typical

O2 or CO2 concentrations measured at

turbines, while still providing some

relief at extreme diluent concentrations.

It is EPA’s observation that turbines

with NOX CEMS have not reported

emissions using the diluent cap thus far.

Thus, no turbines should need to

reprogram software in order to report

the use of the new diluent cap value for

turbines with a new method of

determination code.

EPA considered removing the option

for facilities to use the diluent cap for

heat input rate and CO2 concentration,

as well as for NOX (and SO2) emission

rate in lb/mmBtu, but is not proposing

to do so in today’s proposal. As

explained previously, the diluent cap

was created in order to calculate more

representative NOX emission rate data

during certain unusual circumstances.

However, when a diluent cap value is

used to calculate the hourly CO2 mass

emission rate or the heat input rate, the

final calculation would often be less

representative of actual emissions or

heat input during those hours. The

Agency also found that allowing some

facilities to use the diluent cap only for

NOX emission rate and others to use the

diluent cap also for hourly CO2 mass

emission rate and heat input rate makes

it difficult to check emissions and heat

input rate data to verify that

calculations are performed correctly.

This is because a data acquisition and

handling system could use either the

actual reported diluent gas

concentration or the diluent cap value

to calculate NOX emission rate, CO2

mass emission rate, or heat input rate,

but there is currently no provision in

the electronic data reporting format for

a facility to indicate which value was

used to calculate the heat input.

However, some utilities have indicated

that making a change to discontinue

using the diluent cap for calculations of

heat input rate and CO2 mass emission

rate would require a significant change

in their software calculations (see

Docket A–97–35, Item II–E–25).

Therefore, today’s proposed rule would

allow facilities the options of (1) not

using the diluent cap at all, (2) using the

diluent cap only for calculating NOX (or

SO2) emission rate in lb/mmBtu, or (3)

using the diluent cap for calculating

NOX (or SO2) emission rate in lb/

mmBtu, heat input rate, and CO2

emissions. In addition, EPA is

proposing to add a minor additional

reporting requirement to indicate

whether the diluent cap is used in

calculating CO2 and heat input in the

electronic data reporting format. This

would allow EPA to verify facilities’

calculations, while requiring less

reprogramming than changing the

calculations for heat input and CO2

emissions.

The Agency solicits comment on the

proposed revisions relating to the

diluent cap.

4. Complex Stacks—General Issues

Background

Many power plants regulated under

part 75 have relatively simple stack and

monitoring configurations. Many

utilities have one stack for each affected

unit and have CEMS installed on the

stack. Other plants have more than one

unit discharging to the atmosphere

through a common stack, with CEMS

installed on the common stack. Still

others have individual units that

exhaust into multiple stacks and have

CEMS installed on each stack. The

monitoring requirements for these

various configurations are addressed in

§§ 75.13, 75.16, 75.17, and 75.18. EPA

has issued guidance to assist utilities in

preparing quarterly reports for these

unit and stack configurations (see

Docket A–97–35, Items II–I–4 and II–I–

9, Policy Manual, Section 17).

For the configurations described

above, the process of accounting for

emissions and heat input from the units

and stacks will follow simple

mathematical rules. For example, for

single unit-single stack configurations,

the emissions and heat input for the

unit are directly determined from the

stack CEMS (or from an excepted

methodology, where applicable). For

units discharging through a common

stack with CEMS on the common stack,

the combined emissions and heat input

are determined from the CEMS, and the

heat input to each individual unit is

determined by apportionment of the

combined heat input, using a ratio of the

unit load to the combined load of all

units utilizing the common stack. For a

single unit exhausting through multiple

stacks, the sum of the SO2 and CO2 mass

emissions and heat input for the

different stacks equals the total SO2 and

CO2 mass emissions and heat input for

the unit.

However, in implementing part 75,

EPA has become aware of a number of

affected units that have stack exhaust

configurations which are more complex

than the configurations described above.

For example, one utility has a

configuration in which two units can

emit through two different stacks at the

same time, combining their emissions in

both stacks (see Docket A–97–35, Items,

II–C–1, II–D–12). In this case, the stack

configuration is both a common stack

and a multiple stack configuration. EPA

has had significant problems in

determining the emissions and heat

input from these units, and in one case,

EPA rejected the quarterly reports for

the units (see Docket A–97–35, Item II–

C–8). The utility worked closely with

EPA to resolve the reporting issues

resulting from this unusual situation

(see Docket A–97–35, Item II–D–21).

Other utilities with similar situations

have contacted the Agency to ensure

there would not be problems with their

reporting (see, e.g. Docket A–97–35,

Item II–D–5).

There have been other cases in which

a unit that is accountable for holding

SO2 allowances shares a common stack

with a unit that does not hold SO2

allowances (e.g., where an affected unit

and a non-affected unit share a common

stack or, prior to 1/1/2000, where a

Phase I unit and a Phase II unit share

a common stack). These are termed

‘‘subtractive stack’’ situations in the

following discussion. Utilities with

subtractive stack situations have

generally used the provisions of

§ 75.16(a)(2)(ii)(C) or § 75.16(b)(2)(ii)(B).

These provisions allow a facility to

monitor separately the common stack

and the unit with no allowance

requirement and to subtract the

emissions from the non-affected or

Phase II unit from the common stack

emissions. In some cases, it has not been

clear in the electronic quarterly reports

whether a utility is reporting combined

emissions from all of the units using the

common stack or whether the emissions

from the non-affected unit(s) have

already been subtracted out of the

reported emissions (see Docket A–97–

35, Item II–C–18). This confusion in

interpreting the quarterly emissions

reports has made compliance

determination difficult.

The Agency found that there is a

potential problem with the

underestimation of emissions using this

subtractive approach. In some cases, the

error in the monitors’ measurements

might be such that a larger emissions

value is subtracted from a smaller value,

resulting in the reporting of false

negative emissions (see Docket A–97–

35, Item A–94–16–IV–D–18, Comments

from Monitor Labs). In other cases, there

may be an incentive for making

inaccurate measurements with the

monitoring systems installed on a unit

with no allowance requirement. For
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28107

example, if the SO2 pollutant

concentration monitor on a unit with no

allowance requirement did not operate

properly and had a significant amount

of missing data, the facility would

calculate SO2 emissions from the unit

using a conservative, high concentration

value. Therefore, emissions reported for

the units with allowance requirements

would, as a result of the subtraction, be

less than the actual emissions. Thus, a

facility might have a disincentive for

good monitor performance and

accuracy, because it could lower the

emissions reported for the units with

allowance requirements. Though

allowed under the current wording of

Appendix A to part 75 and subpart D of

part 75, this is contrary to the intent of

the missing data substitution

procedures, which is to encourage good

monitor performance while preventing

any systematic underestimation of

emissions. (See Docket A–97–35, Items

II–B–13, II–E–4, and II–I–12.)

Discussion of Proposed Changes

Today’s proposed rulemaking would

add a general regulatory requirement to

§§ 75.16 and 75.17 for facilities with

complex stack configurations (i.e.,

subtractive stack situations or

configurations involving combinations

of common stacks and multiple stacks)

to receive approval from EPA’s

Administrator for a method of

calculating and reporting emissions

from the units and stacks in the

configuration. The facility would be

required to reach agreement with the

Agency on issues such as: identification

of the stack in its quarterly report,

representation of the configuration in its

monitoring plan, groups of units for

which cumulative emissions must be

reported, testing procedures, use of the

bias test, and use of the missing data

substitution procedures. This would

apply both to sources that already have

certified monitoring equipment and are

submitting quarterly reports and to units

that do not yet have certified monitoring

systems (e.g. new units).

Rationale

The Agency evaluated two basic

approaches to resolving issues in these

complex stack monitoring

configurations. First, EPA considered

resolving the issues through policy

guidance and through instructions for

submitting quarterly reports. Second,

the Agency considered putting detailed

instructions in part 75 for reporting

from and testing of monitoring systems

installed in these complex stack

configurations. These rule provisions

would have explicitly addressed

missing data substitution to ensure that

when emissions are reported, they are

not underestimated from units with an

allowance requirement or a NOX

emission limitation. For example, EPA

could have required, for the subtracted

unit(s), that the facility only use those

provisions of the standard missing data

procedures that are not intended to be

conservative estimates, such as the

average SO2 concentration during the

hour before and the hour after a missing

data period. Another approach for

missing data substitution could have

been to count zero emissions for the

unit with no allowance requirement

during any missing data periods. Or

perhaps creation of a site-specific

missing data procedure could have been

required (see Docket A–97–35, Items II–

E–4 and II–I–12). To prevent a potential

underestimation of emissions and a

disincentive for more accurate

monitoring due to application of a bias

adjustment on a monitor on a unit with

no allowance requirement where its

emissions are subtracted from a

common stack, EPA could have required

that the bias calculation be based upon

both the monitors on the common stack

and the monitors on units with no

allowance requirement, resulting in a

single bias adjustment factor for the

subtractive stack situation.

However, EPA’s experience thus far in

implementing the program indicates

that each complex monitoring

configuration tends to be unique. Thus,

the Agency has rejected the two

approaches discussed above and has

decided instead to make General

regulatory revisions that allow for caseby-case resolution of issues in

individual plant situations, rather than

making extensive, detailed revisions to

part 75 to address each unique situation.

The Agency prefers to make

regulatory revisions rather than

addressing issues solely through policy

and guidance. In some cases, the

Agency has given advice to utilities on

how to report emissions, and the utility

involved has not followed the Agency

guidance (see Docket A–97–35, Items II–

C–7, II–C–24, and II–D–8). In another

case, the current provisions of part 75

for missing data substitution and for the

bias test appeared to be in conflict with

guidance that the Agency wanted to

issue in order to ensure that emissions

are not underestimated in a subtractive

stack situation (see Docket A–97–35,

Item II–B–13). Therefore, today’s

proposed rule would require owners or

operators of facilities with complex

stack configurations to apply for

approval of their monitoring plans and

reporting methodologies from EPA’s

Administrator on a case-by-case basis.

The Agency believes that the General

regulatory provisions requiring approval

of a complex monitoring situation by

EPA’s Administrator will give both

facilities and the Agency flexibility to

deal with site-specific cases, while also

giving the Agency regulatory authority

to resolve any case-specific problems.

It is possible that any final rule

resulting from today’s proposal may not

be promulgated until 1999. Thus, EPA

is proposing to require the

Administrator’s approval of the

monitoring plans and reporting

methodologies only for those situations

that will exist on and after January 1,

2000. Any subtractive stack situations

that exist only during the duration of

Phase I would not fall under this

requirement. However, complex stack

situations that exist where affected and

non-affected units share a common

stack would need to meet today’s

proposed requirement. Similarly, in

situations where coal-fired units sharing

a common stack have different NOX

emission limitations under part 76, or

situations where some units sharing a

common stack have a NOX emission

limitation under part 76 and others have

no NOX emission limitations under part

76, any complex monitoring

configuration would need to be

approved by EPA’s Administrator.

5. Complex Stacks—Heat Input at

Common Stacks

Background

For a unit that utilizes a flow monitor

to determine SO2 mass emissions,

section 5 of Appendix F to part 75

requires heat input to be calculated

using the installed flow monitor and a

diluent gas (O2 or CO2) monitor. The

January 11, 1993 final rule indicated

that units with common stacks, multiple

stacks, or bypass stacks should follow

the same General procedures for

monitoring heat input as are used for

monitoring SO2 under § 75.16. As

written, those procedures allowed

facilities to monitor their heat input

either by placing individual monitors on

each unit that serves a common stack or

by placing monitors only on the

common stack and measuring a

combined heat input from all of the

units sharing the common stack. The

May 17, 1995 rule required the

combined heat input measured by

monitors on the common stack to be

apportioned to the individual units, in

two specific provisions. First, unit level

heat input was required under

§ 75.16(e)(2) for cases in which a

knowledge of the heat input for each

unit is critical to compliance

determination (i.e., for situations where

any units using the common stack have
28108 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

a NOX emission limit). Second,

§ 75.16(e)(3) required unit level heat

input to be determined for all other

common stacks, but only until the year

2000. The November 20, 1996 rule

outlined the acceptable methodology for

apportioning heat input, i.e., by using

the ratio of the unit load in MWe or lb

of steam per hour to the combined load

of all units utilizing the common stack

(provided that all of the units utilizing

the common stack are combusting fuel

with the same F-factor).

Discussion of Proposed Changes

Today’s proposed rule would revise

the existing requirements found in

§ 75.54(b) and two specific provisions of

§ 75.16(e) for accounting of heat input

for units serving a common stack, a bypass stack, or multiple stacks. First, EPA

would require determination and

reporting of the unit level heat input to

be continued after the year 2000 for all

affected units, rather than restricting it

to certain situations after 2000. Second,

EPA would clarify that the proper units

of measure for load to be used in an

apportionment of common stack heat

input to determine unit level heat input

are totals of MWe-hr and 1000 lb of

steam, rather than rates of MWe and

1000 lb/hr of steam.

Rationale

EPA considered leaving the current

provisions of § 75.16(e) and § 75.54(b)

from the May 17, 1995 and November

20, 1996 rules unchanged. However,

this would have the serious drawback of

requiring the facilities to reprogram

their computer software for certain units

and not for others. Corresponding

monitoring plan changes would also be

required. Additionally, EPA would have

to reprogram its emission tracking

software to accommodate two different

heat input reporting methodologies for

common stacks. In view of these

considerations, EPA is proposing to

continue to receive individual heat

input data from all affected units. This

information is useful for developing

inventories of total NOX mass emissions

in tons in support of other Agency

rulemakings. Without such information,

the inventories would be based on

assumptions about how units operate,

rather than being based on unit level

heat input as reported from the facility.

The Agency believes that a relatively

small number of sources would be

affected by this proposed change. This

is because (1) most coal-fired units

would still need to report unit level heat

input under the current provisions of

§ 75.16(e)(2), even after the year 2000;

and (2) gas-fired and oil-fired units

using fuel flowmeters to determine heat

input and to implement the procedures

of Appendix D or Appendix E would

still be required to monitor heat input

for each unit under section 2.1 of

Appendix D. Because of the usefulness

of having heat input data for individual

units, because of the burden of

reprogramming software to remove the

heat input apportionment by the year

2000, and because of the small number

of sources that would benefit from

retaining the current provisions of

§ 75.16(e)(3), EPA believes it is

reasonable to require all units that

measure combined heat input at a

common stack to continue to apportion

heat input to the individual units. The

Agency solicits comment on the number

of sources that would be affected by this

revision.

6. Start-Up Reporting—Units Shutdown

Over the Compliance Deadline

Background

As currently written, part 75 requires

that units which are shutdown over an

applicable compliance date specified in

§ 75.4 must submit a notice of the

planned and (if different) actual

shutdown date. In addition, § 75.4(d)

provides an extended certification

deadline for such units of ‘‘the earlier of

45 unit operating days or 180 calendar

days after the date that the unit

recommences commercial operation of

the affected unit.’’ If an owner or

operator subsequently recommences

commercial operation of the unit, a

notice related to the planned and (if

different) actual date of

recommencement of commercial

operation is required. In addition to

these notices, § 75.64 requires that after

the applicable compliance date passes,

the owner or operator must submit

quarterly reports for such units. If the

unit remains shut down and does not

operate during the quarter, the quarterly

report must show zero emissions. Utility

commenters (see, e.g., Docket A–97–35,

Items II–D–20, II–D–30) have

recommended that this quarterly report

requirement for shutdown units be

deleted because it is unnecessary and

burdensome.

Discussion of Proposed Changes

Section 75.64(a) would be modified so

that quarterly reporting is not required

until the first quarter in which a

previously shutdown unit recommences

commercial operation. In this case, the

first quarterly report would contain data

beginning with the hour in which the

unit recommences commercial

operation.

Rationale

Units that are shutdown over their

applicable certification deadlines are

required to submit notice, pursuant to

§ 75.61(a)(3), of the planned date of

recommencement of commercial

operation and also must submit a

follow-up notice if the actual date of

recommencement of commercial

operation is different from the planned

date. As a result of these notice

provisions, EPA will know whenever

the status of a shutdown unit changes.

Because shutdown units have no

emissions, the Agency believes that

quarterly reporting in addition to the

notice provisions is unnecessary to

fulfill the emission reporting objectives

of the Act.

The Agency notes, however, that the

proposed revision differs from that

suggested by certain utilities (see Docket

A–97–35, Item II–D–30). The utilities

proposed tying the reporting

requirement to the certification deadline

in § 75.4(d). However, under § 75.4(d),

facilities are required to report

emissions data using special provisions

in that section prior to the extended

certification deadline in § 75.4(d). Thus,

the proposed revisions would tie the

obligation for quarterly reporting to the

quarter in which commercial operation

is recommenced.

7. Start-Up Reporting—New Units

Background

As currently written, § 75.64(a)

requires the first quarterly report for

new units to be submitted for the

quarter corresponding to the compliance

date in § 75.4. However, the current

provision is unclear about which hourly

emissions data need to be included in

the first quarterly report if the

compliance deadline does not

correspond to the first hour in the

quarter.

Discussion of Proposed Changes

Section 75.64(a) would be modified to

clarify that a new unit must start

reporting data beginning with the earlier

of the date and time of provisional

certification or the compliance deadline

in § 75.4(b).

Rationale

These proposed revisions are

generally consistent with existing

implementation of the new unit

reporting requirements, and primarily

would serve to clarify ambiguous

elements of the current rule.
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28109

8. Recordkeeping and Reporting

Provisions

Background

Subpart F and subpart G of the

existing part 75 regulation set forth the

recordkeeping and reporting

requirements that accompany the

monitoring provisions of part 75.

Specifically, in subpart F, § 75.53

contains the monitoring plan

requirements, § 75.54 contains the

general recordkeeping provisions,

§ 75.55 lists the general recordkeeping

provisions for specific situations, and

§ 75.56 consists of the certification,

quality assurance and quality control

record provisions. In subpart G, § 75.62

lists the monitoring plan reporting

provisions, § 75.62 contains the

reporting requirements for initial

certification and recertification

applications, and § 75.64 discusses the

provisions for quarterly reports.

Quarterly reports are electronic data

files containing emissions and operating

data from affected units, as well as

monitoring plan information and the

results of certification and quality

assurance tests. Under § 75.64, these

electronic data reports are required to be

submitted to the Agency each calendar

quarter. This electronic information is

used by the Agency for many different

purposes, including implementation of

the SO2 allowance trading program,

determination of compliance with

emission limits, development of reports

on utility emissions, and modeling of air

quality to assess the effectiveness of the

Act.

In order to effectively use the

electronic quarterly report information,

EPA created a standardized reporting

format, the electronic data reporting

(EDR) format. The electronic file formats

and record structures of the EDR

provide the vehicle by which required

information is submitted to the Agency

every calendar quarter. The EDR

primarily defines the order, length, and

placement of information within the

electronic report or file. The individual

tables of the EDR define the record type,

type code, start column, data element

description, units, range, length, and

FORTRAN format for each data element

in the electronic report. The information

in the EDR fields mirrors the required

information set forth in subparts F and

G of part 75. Considering both the

volume of information contained in

each quarterly report (e.g, operating and

emissions data for each of the hours in

the quarter) and the number of reports

submitted to the Agency (i.e., currently,

1765 reports are received each quarter

for the 2055 affected units; some reports

contain information for more than one

unit if several units are interrelated, as

in a common stack configuration), a

standard format is critical in order for

the Agency to review, verify, and use

the information reported. A standard

format allows the Agency to develop

software to receive and verify the files

and to correlate and separate out

specific information for compliance

determinations. A standard format also

allows software vendors to create

standard software which can be utilized

by many affected units. This is more

cost effective than developing sitespecific software and thus reduces the

software cost to industry.

Today’s rulemaking proposes a

number of revisions to subparts F and

G of part 75 (the reporting and

recordkeeping sections of the rule). The

majority of these changes are necessary

to implement the proposed substantive

revisions to the sections of the rule and

appendices discussed elsewhere in this

notice. In addition, EPA is

proposingrevisions to these subparts in

order to streamline implementation of

the program and to coordinate reporting

under the Acid Rain Program with other

programs.

To support the changes to the

recordkeeping provisions, new §§ 75.57,

75.58, and 75.59 would be added. These

sections would replace existing

§§ 75.54, 75.55, and 75.56. The addition

of new sections is necessary because the

proposed revisions would not be

mandatory until January 1, 2000, and to

have the proposed revisions listed

throughout existing effective sections

could lead to confusion. However, an

owner or operator would be free to

follow the provisions of §§ 75.57, 75.58,

and 75.59 before January 1, 2000, if he

chooses to do so. In addition, the owner

or operator would be required to satisfy,

prior to January 1, 2000, the elements in

these sections that support a regulatory

option proposed in other sections of

part 75 if the owner or operator elects

to implement that option prior to

January 1, 2000.

Because, as discussed above, the Acid

Rain Program relies on a standardized

electronic data reporting format, EPA

has also developed draft revisions to the

EDR formats and instructions (draft EDR

version 2.1). The following discussion

refers to both the rule sections and EDR

record types (RTs) that would be

affected by the proposed revisions.

Discussion of Proposed Changes

There are a number of proposed rule

changes to the recordkeeping and

reporting requirements of part 75 and

corresponding draft EDR revisions that

would be necessary to implement the

substantive revisions proposed by EPA

and discussed elsewhere in this

preamble. These include the following

requirements:

(1) Changes to support new CO2

missing data requirements (see § 75.57

and RT 202, 210, and 211);

(2) Changes to support new reporting,

QA and missing data requirements for

moisture monitoring (see §§ 75.53,

75.57, and 75.59, and RT 211, 212, 220,

and 618);

(3) Changes to support optional

Appendix I (flow methodology for gas

and oil units) (see §§ 75.57 and 75.58,

and RT 220, 302, 303, 608, and 609);

(4) Changes to support more

flexibility for units that have multiple

range analyzers (see §§ 75.53 and 75.59,

and RT 230, 530, 600, 601, and 602);

(5) Changes to support the use of the

diluent cap during all hours (see § 75.57

and RT 300 and 330);

(6) Changes to support test

exemptions and extensions for units

that operate infrequently (see §§ 75.59

and 75.64, and RT 301, 697, and 698);

(7) Changes to support increased

flexibility in fuel sampling (see § 75.58

and RT 302, 303, 313, and 314);

(8) Changes to allow reporting of

hourly total values in addition to hourly

rates (see § 75.57 and RT 300, 310, and

330);

(9) Changes to support the proposed

re-definition of unit operating loads (see

§§ 75.53 and 75.59, and RT 535 and

611);

(10) Changes to support reporting of

conditional data during recertification

events (see § 75.59, and RT 556);

(11) Changes to support a new

quarterly flow-to-load QA check for

flow monitors (see § 75.59, and RT 605

and 606);

(12) Changes to allow QA test grace

periods (see § 75.59, and RT 699);

(13) Changes to support simplified

reporting for low mass emissions units

(see §§ 75.53, 75.58, and 75.63, and RT

360, 508, and 531);

(14) Changes to support fuel flow-toload QA checks for fuel flow meters (see

§ 75.59, and RT 628 and 629); and

(15) Changes to support expanded

reporting of RATA supporting

information (see § 75.59, and RT 614,

615, 616, 617, and 618).

In addition, since the EDR version 1.3

was released, EPA has developed

additional record types to aid in the

implementation of the program, by

allowing the designated representative

to certify the validity of quarterly

reports using an electronic certification

statement. The proposed revisions

would adopt the necessary rule

language to implement these

miscellaneous record types (see § 75.64,

and RT 900, 901, 910, and 920).
28110 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

The proposed revisions would also set

forth optional requirements for

reporting of NOX mass emissions that

states or EPA could adopt as part of a

NOX mass trading program, such as the

OTC NOX Budget Program. In this

situation both a rule change and an EDR

change would be needed (see §§ 75.57

and 75.64 and RT 301, 307, and 328).

The proposed rule revisions also

include a number of changes that EPA

believes will facilitate implementation

of the program. These include:

(1) Reporting of test numbers, reasons

for tests and indicators of aborted tests

(see § 75.59, and RT 560, 600, 601, 602,

603, 610, and 611);

(2) Changing the deadlines for

reporting the RATA supporting

information that was originally required

on January 1, 1998 (see § 75.59, and RT

614, 615, 616, 617, and 618);

(3) Reporting of an optional record

type that will allow facilities to provide

contact person information that many

facilities currently provide in quarterly

report cover letters (see § 75.59, and RT

999);

(4) Based on comments received, the

rule would be revised so that reporting

the reasons for missing data as part of

the quarterly report would become

optional, but would still need to be

maintained on-site (see §§ 75.56 and

75.59, and RT 550);

(5) Reporting of facility location,

identification, and EDR version

numbers to support the transition from

EDR 1.3 to EDR 2.1 (see § 75.64, and RT

100 and 102);

(6) Reporting of information

documenting the calculation of heat

input (see § 75.57, and RT 300);

(7) Reporting of reference method

backup QA data (see § 75.59(a)(11), and

RTs 260, 261, and 262);

(8) Expanded reporting of unit

definition information (see §§ 75.53, and

RTs 504, 585, 586, and 587);

(9) Reporting of Appendix E segment

ID information (see § 75.58, and RT 323,

324, and 560);

(10) Reporting of qualification data for

peaking units or gas-fired units (see

§ 75.53, and RT 507);

(11) Reporting of the qualifying test

for off-line calibrations (see § 75.59, and

RT 623);

(12) Reporting of Appendix E

emission rate test data (see §§ 75.59, and

RT 650–653);

(13) Reporting of span effective date

information and flow rate span values

(see § 75.53, and RT 530); and

(14) Removal of the recordkeeping

provisions of §§ 75.50, 75.51, and 75.52

that are no longer effective.

Rationale

The majority of the proposed changes

to subparts F and G are needed to

support proposed substantive changes

elsewhere in part 75. EPA is also

proposing certain minor revisions to the

order and wording of provisions in

these subparts so that the records

required by the rule match up

consistently with the record type

descriptions in the EDR. Certain utility

groups previously had objected that

EPA had not made the EDR format

available for formal public notice and

comment. The Agency maintains that it

is not required to provide notice and

comment for the EDR. The data

included in (or proposed to be included

in) the EDR are also listed in the rule (or

the proposed rule revisions) as

requirements under the recordkeeping

and/or reporting provisions of §§ 75.53

through 75.64, which have already

undergone (or are undergoing) public

notice and comment. Since the EDR

simply shows how to present

electronically the data whose

submission is (or will be) required by

the rule, it is the rule, not the EDR, that

imposes the data requirements. Notice

and comment on the contents of the

EDR would therefore be unnecessary

and duplicative. Moreover, the

requirement to present the rule’s data

requirements in a specified format is

authorized by § 75.64(d), which requires

a quarterly report to be submitted in the

format specified by the Administrator.

Like the data requirements, this format

requirement in part 75 was adopted

after public notice and comment.

In today’s rulemaking, EPA has

developed draft EDR revisions

simultaneously with the proposed rule

revisions and is therefore including the

draft EDR revisions in the docket for

comment at the same time as the

proposed rule revisions (see Docket A–

97–35, Item II-A–12). EPA is also

posting the draft EDR v2.1 revisions and

draft EDR v2.1 reporting instructions on

the Acid Rain Homepage

(www.epa.gov/acidrain). However, the

Agency maintains that notice and

comment are not necessary for revisions

to the EDR so long as the data included

in the EDR is the same as the data

required by rule provisions that have

undergone or are undergoing notice and

comment. Thus, future EDR revisions

may be made without prior notice and

comment on the EDR in order to

implement rule revisions for which

notice and opportunity for comment are

provided. However, the Agency will

continue its informal procedures for

involving the affected stakeholders in

any such EDR revisions.

There are a number of other proposed

changes to §§ 75.54–75.64 that have

been included to implement existing

provisions in other sections of part 75.

First, information on test numbers and

reasons for tests would be required so

that quality-assurance test data can be

more easily correlated and interpreted.

Second, the reporting of various runspecific and point-specific RATA

support information would be required

(e.g., point velocity head readings, gas

reference method quality-assurance

data, moisture reference method data,

etc.). The Agency believes that most

testing companies currently either

collect these data electronically or enter

the data into computer programs

manually to determine RATA results.

By requiring the reporting of these data

elements in a standard electronic

format, the Agency believes that both

facilities and regulatory personnel

would be able to more easily interpret

data that are currently provided by test

contractors in many different hardcopy

formats.

The Agency is proposing not to

require the electronic reporting of RATA

support information prior to the year

2000. Sections 75.56 (a)(5)(iii)(F) and

(a)(7) and § 75.64(a)(1) of part 75

currently require RATA supporting

information to be reported in the

electronic quarterly report. EPA

believes, however, that it would be more

cost effective to require the more

detailed RATA support records to be

electronically reported beginning in the

year 2000, rather than having a twostage implementation. The Agency has

notified all designated representatives

that this RATA supporting information

will not be required to be reported

electronically, in RT612 and 613 of the

quarterly report, prior to January 1,

2000.

The Agency notes that certain data

elements (e.g., yaw angle, pitch angle,

axial velocity, wall effect point

identifier, etc.) have been included in

anticipation of future revisions to EPA

Reference Method 2. EPA is presently

evaluating a number of alternative flow

rate measurement methodologies, such

as the use of a 3-dimensional probe.

Depending on the outcome of the

Agency’s evaluation, one or more of

these alternative flow measurement

techniques may be allowed beginning in

the year 2000. Therefore, EPA believes

it is appropriate to include data

elements to support these anticipated

Method 2 revisions in draft EDR version

2.1.

Finally, by changing the requirements

for reporting the results of the most

recent RATA from requiring it to be

reported in the quarter in which it was
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28111

performed, to requiring it to be reported

in the quarter in which it was performed

and each subsequent quarter in which a

BAF that was calculated using the

results of that RATA are used, EPA

would make the individual quarterly

reports more self contained and make it

easier for people who are using the

reported data to understand how the

BAFs reported in those reports were

applied. EPA considered adding a field

to the hourly emissions data record for

each pollutant to indicate the BAF

applied in that hour. However, the

Agency received requests from utilities

on an early draft of the EDR revisions

that the hourly emissions data record

types not be revised to add a field for

BAF. The Agency believes that reporting

the results of the most recent RATA,

including the BAF, in each quarterly

report would accommodate the utilities’

requests not to add the BAF to each

hourly record type and would achieve

the objective of making the quarterly

reports easier to interpret because the

BAF being applied will be found in each

quarterly report. In addition, since

electronic RATA results involve a

relatively small amount of information

that can be copied into subsequent

reports and does not have to be

recreated, it should not be a significant

burden to reporting facilities.

The proposed revisions would also

remove the requirement to report the

reasons for missing data and make it

optional. However, even if the

information is not reported, the reasons

for missing data would have to be

maintained on site in a manner suitable

for inspection. Based on the high data

availability achieved during initial

implementation of the program, the

Agency believes that this type of

information is not needed in the review

of most quarterly reports. For those

situations in which the Agency may

wish to review this information, the

records would still be on-site for audit

purposes or for submittal to the Agency.

The EPA is also proposing to

incorporate additions which would

allow the reporting of electronic

signatures and certification statements

so that no hardcopy reporting of any

kind (e.g., cover letters) would be

necessary to meet the quarterly report

requirements.

Finally, the removal of recordkeeping

§§ 75.50, 75.51, and 75.52 (and the

corresponding explanatory text

included in Appendix J to the existing

rule) is necessary because those sections

were scheduled for replacement during

the May 17, 1995 rule revisions. At that

time, §§ 75.54, 75.55, and 75.56 were

added as replacements for §§ 75.50,

75.51, and 75.52, effective January 1,

1996. Because the effective date is now

past, the old sections and Appendix J

will be removed and reserved in order

to prevent any confusion.

9. Electronic Transfer of Quarterly

Reports

Background

Sections 75.64(a) and (d) of the

original January 11, 1993 Acid Rain rule

requires emissions, monitoring, and

quality assurance data to be

electronically reported to the

Administrator on a quarterly basis in a

format to be specified by the

Administrator. Version 1.3 of the

Electronic Data Reporting (EDR) format

(see Docket A–97–35, Item II–I–5)

further specifies the record structures to

be used to report the required data

elements. Page 3–3 of the May 1995

Acid Rain Program CEMS Submission

Instructions (see Docket A–97–35, Item

II–I–4) further specifies the mode of

transmission of the electronic data file

to the Agency. Three modes of transfer

are listed as options: (a) by mail on

diskette, (b) by mail on magnetic tape,

or (c) through direct electronic transfer.

Since the beginning of the program,

the Agency has received quarterly

reports by mail on diskette and through

direct electronic transfer. To date, the

magnetic tape option has never been

utilized. Based on the first four years of

implementation of part 75, the Agency

believes that the use of the direct

electronic transfer mode of transmission

has many advantages to the Agency and

to the affected sources. In fact, more

than seventy percent of the reports for

sources currently affected by part 75

were submitted directly to the EPA

mainframe with EPA-provided software

in second quarter 1997, and the number

of sources using this option has steadily

increased over time (see Docket A–97–

35, Item II–I–8).

Discussion of Proposed Changes

Today’s proposal would require

quarterly reports to be submitted via

direct electronic transfer unless

otherwise approved by the

Administrator. This would remove the

option of sending files through the mail

on interceding media except for

hardship cases where a modem is not

available or where technical difficulties

prevent the successful transmission of

files via modem.

An additional revision to section 4 of

Appendix A to part 75 would require

data acquisition and handling systems

(DAHS) to be capable of transmitting a

record of measurements and other

required information by direct

computer-to-computer electronic

transfer via modem and EPA-provided

software.

Rationale

For each quarterly report submitted,

the Agency performs an assessment

which results in a feedback report for

the submitting designated

representative. This feedback report

provides information to the facility that

may be used in making trading

decisions, that may indicate that a

change is needed to the facility

software, and/or that may indicate that

the file needs to be corrected and

resubmitted. A major advantage of

submission through direct electronic

transfer with a modem and EPAprovided software is that the designated

representative submitting the file

receives the EPA assessment of the

submitted data much more quickly than

for a file that is transmitted through the

mail on diskette. Currently, for a file

that is submitted to the Agency by

electronic transfer via modem and EPAprovided software, the EPA assessment

is received by the designated

representative, via modem and EPAprovided software, immediately

(typically within ten minutes) after the

transmission of the quarterly report file.

However, for files submitted on diskette

that must travel through the mail system

and be processed by Agency personnel,

a letter containing the EPA assessment

is currently sent to the designated

representative through the mail and

arrives 45 days or later from when the

submission was originally received by

the Agency. Therefore, with direct

electronic transfer, potential errors get

corrected and resolved more quickly

and trading decisions can be made with

assurance that submitted data meets the

minimum quality standards acceptable

to the Agency. Additionally, the source

may electronically submit the quarterly

report, via modem and EPA software,

prior to the deadline, immediately

receive the EPA assessment, fix any

errors, and resubmit the file by the

deadline. Many utilities have indicated

that this is an important advantage over

submission of the quarterly report by

diskette.

Another benefit of direct electronic

transfer is the reduced risk of error in

transmission to the Agency or handling

at the Agency. Throughout the

implementation of the program, many

files submitted on diskette through the

mail have been lost, returned to the

sender, damaged in transit, or contained

viruses (see Docket A–97–35, Item II–I–

8). When a file is submitted using direct

electronic transfer of a quarterly report,

the designated representative submitting

the file(s) receives an immediate
28112 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

confirmation that the file was received

by the Agency.

Further, immediate feedback from the

agency on quarterly report submissions

may also contribute to cost savings for

facilities if a file submitted via direct

electronic transfer is rejected and

required to be amended and

resubmitted. Utilities have indicated

that submitting the report to EPA,

receiving feedback, and making the

necessary corrections to the file in a

single work session significantly

reduces the cost of reworks, particularly

for facilities that retain their master file

at the individual plant locations.

An additional advantage to direct

electronic transfer is the reduced cost to

the Agency resulting from the

minimized EPA labor hours required to

process a diskette. For instance, a

diskette transmitted through the mail

must be catalogued, scanned for

readability and viruses, uploaded to the

EPA mainframe Emissions Tracking

System, and renamed. On the other

hand, transmission of a file by direct

computer-to-computer electronic

transfer using EPA software eliminates

all of those manual steps because they

are performed automatically by the EPA

software used for transmission of the

report.

A possible concern about a

requirement to submit the quarterly

report via modem is the possibility that

source may not be equipped with a

modem and electronic transfer

capability. Although the Agency

believes that most sources currently

have a modem or will have a modem by

the year 2000, the Agency understands

that a very small percentage might not.

Therefore, the Agency would accept

petitions from sources unable to

transmit files via modem in order to

allow transmission via diskette for

hardship cases.

Additionally, a utility group

representative raised a concern about

the possibility of a computer at either

the facility source or at the EPA being

inoperative at the time of the deadline

for transmission, preventing a source

from successfully transferring the

quarterly report to the Agency. In order

to minimize the risk of this type of

problem, there is a wide window,

currently thirty days, during which EPA

will accept quarterly report

transmissions each quarter.

Additionally, EPA has instituted

preventative measures to minimize the

possibility that the EPA computer

would be inoperative for an extended

length of time, preventing quarterly

report transmission. Nevertheless, the

Agency accepts that it is conceivable

that a technical difficulty could prevent

the successful electronic submission of

a quarterly report and, therefore, would

also approve diskette submission on an

as-needed basis for sources unable to

transfer a file via modem and EPAprovided software due to technical

difficulties. Furthermore, EPA solicits

comment on whether it should allow a

grace period for late submissions due to

a technical difficulty with the EPA

computer.

Finally, section 4 of Appendix A to

part 75 would be amended to require

the DAHS to be capable of transmitting

the required information by direct

electronic transfer via modem and EPAprovided software, for consistency with

the proposed § 75.64(f). In addition,

section 4 of Appendix A to part 75

would retain the requirement for the

DAHS to be capable of transmitting a

record of measurements and other

required information via an IBMcompatible personal computer diskette

so that an on-site inspector could collect

electronic data on a diskette for review.

S. Revised Traceability Protocol for

Calibration Gases

Background

Currently, Appendix H to part 75

requires affected units to follow a 1987

version of EPA Protocol procedures for

developing calibration gases. This

protocol document has been superseded

by a later version, the ‘‘EPA Traceability

Protocol for Assay and Certification of

Gaseous Calibration Standards,’’

September 1997, EPA 600/R–97/121.

The 1997 document is actually five

protocols. Two of these protocols

(formerly known as Protocols 1 and 2)

have been combined to allow both

CEMS and ambient air analyzers to be

calibrated from gases produced either

without dilution (Procedure G1) or with

dilution (Procedure G2). The remaining

three protocols (Procedures P1, P2, and

P3) describe procedures that are

mandatory for ambient air quality

analyzers (not continuous emission

monitoring systems).

The 1997 Protocol document,

described above, is required by other

parts of the CFR, such as the NSPS

provisions in part 60. Because the old

and new protocols specify different

certification periods (i.e., useful shelf

lives) for most calibration gases, some

affected units that must comply with

both part 60 and part 75 have been

forced to replace calibration gas

cylinders more frequently because of the

shorter certification period in the 1987

Protocol procedures required by part 75.

Under the 1987 Protocol document,

affected units with low SO2 emission

rates occasionally had difficulty finding

calibration gases that were within the

concentration ranges required by

Appendix A to part 75. The 1997

Protocol document allows calibration

gases to be developed over a wider

range of concentrations than was

previously allowed.

Under the current part 75 rule,

‘‘Protocol 1 gases must be vendorcertified to be within 2.0 percent of the

concentration specified on the cylinder

label (tag value).’’ However, no method

is specified to determine the uncertainty

value. The overall uncertainty in the

concentration estimated for a calibration

gas comes from many different sources,

including uncertainty in the reference

standards, uncertainty in the analyzer

multi-point calibration, uncertainty in

the zero/span correction factors, and

measurement imprecision.

Discussion of Proposed Changes and

Rationale

Today’s rule proposes to remove

Appendix H and revise parts 72 and 75

to be consistent with the 1997 Protocol

document. The following sections of

part 75 would be revised: §§ 72.2 and

72.3; sections 5.1.1 through 5.1.6, 6.2,

and 6.3.1 of Appendix A; and all of

Appendix H.

The final rule would incorporate by

reference the 1997 Protocol document.

This is the preferred option for the

following reasons: (a) calibration gas

certification periods would be identical

under parts 60 and 75, thereby allowing

affected units to reduce expenditures on

calibration gas without sacrificing

accuracy or performance; (b) lower

emitting affected units would more

easily be able to comply with the

required range of calibration gas

concentrations; (c) improved assaying

procedures and accuracy determinations

would be allowed; and (d) a wider

selection of calibration gases would be

allowed.

While today’s proposal would retain

the requirement for EPA protocol gases

to be within 2.0 percent of the tag value,

section 5.1.3 in Appendix A would be

revised to specify the use of the

uncertainty calculation procedure in

section 2.1.8 of the 1997 Protocol

document for estimating the analytical

uncertainty associated with the assay of

the calibration gas. This uncertainty

estimate includes the uncertainty of the

reference standard and any gas

manufacturer’s intermediate standard

(GMIS) and interference correction

equation that may be used in developing

the calibration gas.

EPA proposes to change the term

‘‘Protocol 1 gas’’ to ‘‘EPA protocol gas’’

because the 1997 Protocol document

combines the Protocol 1 and Protocol 2
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28113

procedures; therefore, the term

‘‘Protocol 1 gas’’ would no longer be

used.

Today’s proposal would also continue

to allow a ‘‘research gas mixture’’ to be

used as a calibration gas. However, an

RGM would need to meet the same 2.0

percent uncertainty requirement that a

protocol gas would meet.

The proposed rule would explicitly

allow GMISs to be used as calibration

gas for two reasons. First, an EPA

protocol gas may be made from a GMIS.

Therefore, GMISs are at least as accurate

as EPA protocol gases. Second, GMISs

are more readily available and less

expensive than standard reference

material or National Institute of

Standards and Technology (NIST)

traceable reference material, both of

which are allowable as calibration gas

under part 75.

Today’s proposal clarifies that NIST/

EPA-approved certified reference

materials (CRMs) would be acceptable

as calibration gas by adding those CRMs

to the definition of ‘‘calibration gas’’ in

§ 72.2.

The 1997 Protocol document accepts

primary reference standards from the

Netherlands Measurement Institute as

being equivalent to standard reference

materials from the NIST. As a result,

today’s proposal adds ‘‘standard

reference material-equivalent

compressed gas primary reference

material’’ to the ‘‘calibration gas’’

definition in § 72.2 and to section 5.1.2

of Appendix A.

Finally, the definition of ‘‘zero air

material’’ would be revised to

accommodate other acceptable

procedures.

Major differences between the 1987

Protocol procedures and the 1997

Protocol procedures are explained on

pages 1–1 through 1–3 of the 1993

Protocol document and on pages 1–1

through 1–2 of the 1997 Protocol

document (see Docket A–97–35, Items

II–I–23 and 24).

T. Appendix I—New Optional Stack

Flow Monitoring Methodology

Background

Section 412 of the Act requires that

units subject to title IV install SO2

concentration monitors and volumetric

flow monitors for the purpose of

determining SO2 emissions. The

purpose of the volumetric flow

requirement is to enable a unit to

convert SO2 concentrations into mass

emission rates of pounds per hour (lbs/

hr). Volumetric flow is also used to

determine heat input rate in mmBtu/hr

and CO2 mass emission rate in ton/hr.

In December 1991, 56 FR 63002

(December 3, 1991), EPA proposed an

exception to the requirement to install

SO2 concentration monitors and

volumetric flow monitors at oil- and

gas-fired units in Appendix D to part 75.

The exception relies on fuel flowmeters

and fuel sampling and analysis to

determine SO2 emissions from oil- and

gas-fired units. In comments on the

December 1991 proposed rule, some

industry commenters also advocated

allowing oil- and gas-fired units to use

a diluent monitor, an F-factor, and a fuel

flowmeter as an alternative to a

volumetric flow monitor. An F-factor is

a fuel-specific constant that relates the

heat content of a fuel and the volume of

gases given off upon combustion. It is

used to convert pollutant concentrations

into units of pounds of pollutant per

million British thermal units of heat

input (lb/mmBtu). EPA already allows

the use of F-factors in emissions

monitoring under part 75 and under 40

CFR part 60, subparts Da and Db.

Method 19 of Appendix A to part 60

uses F-factors as the reference methods

for calculating SO2 and NOX emissions

in terms of lb/mmBtu for subpart Da and

Db units. F-factors also are used in the

performance tests for certain pollutants

required under § 60.8 to determine if a

source is in compliance with a

particular emission standard in lb/

mmBtu. Part 75 also uses F-factors in

conjunction with diluent gas and

volumetric flow data to determine heat

input under section 5 of Appendix F to

part 75. Table 19–1 of Method 19 in

Appendix A to part 60 and Table 1 in

section 3.3.5 of Appendix F to part 75

list the appropriate F-factors for

different types of fuel, including oil and

natural gas.

Although the commenters supported

the two exceptions included in

Appendix D, some commenters did not

believe the exceptions would be

economical at all oil- and gas-fired

units. According to one commenter, fuel

sampling protocols have an inherently

high bias because they assume a 100

percent conversion of fuel sulfur into

SO2, which results in higher emissions

reporting from fuel sampling protocols

than from CEMS. The commenter

claimed that the high bias appears to be

in the range of 5 to 10 percent.

According to the commenter, the higher

emissions reporting ‘‘penalty’’ that is

inherent in fuel sampling protocols

would justify installing SO2 CEMS at

some oil- and gas-fired units,

particularly large, base-loaded oil-fired

units. In addition, the commenter

claimed that, for oil- and gas-fired units

which install SO2 CEMS, use of the ‘‘Ffactor/fuel flow method’’—which

includes use of an F-factor, a fuel

flowmeter, fuel sampling data, and a

diluent (CO2 or O2) concentration

monitor—would provide much more

accurate and precise information than

volumetric flow monitors (see Docket

A–90–51, Item IV–D–184).

In a four-day experiment performed in

1991 by one commenter, measurements

from the F-factor/fuel flow method were

compared to those generated by a

combined SO2 CEMS and a volumetric

flow monitor. However, EPA did not

believe that four consecutive days of

data were sufficient to support a

conclusive equivalency determination.

Instead, in the January 11, 1993 final

rule (58 FR 3590, 3643), EPA reserved

Appendix I to part 75 for the F-factor/

fuel flow method and stated that, to be

approved, the method would have to

meet the criteria for alternative methods

as required by section 412 of the Act

and the provisions of § 75.40 in a 30-day

(720 hour) trial.

Section 412 of the Act requires that an

alternative monitoring system provide

information with ‘‘the same precision,

reliability, accessibility, and timeliness

as that provided by CEMS . . .’’ 42

U.S.C. 7651k. To be approved, the

alternative monitoring system must

meet the criteria for alternative methods

in a 720 hour trial as required by the

provisions of subpart E of part 75. The

rule designates a certified CEMS or a

reference method according to

Appendix A to part 60 as the reference

for evaluating the alternative monitoring

system’s performance.

In order to meet the precision and

reliability criteria, an alternative

monitoring system must achieve

performance specifications and quality

assurance requirements equivalent to

those for CEMS. In addition, to

demonstrate precision, an alternative

monitoring system must pass three

statistical tests evaluating the flow

CEMS and alternative method in terms

of their respective systematic error,

random error, and correlation.

Additionally, to meet the reliability

criterion, the alternative monitoring

system is required to match a certified

CEMS in terms of annual availability.

Finally, to meet the accessibility and

timeliness criteria, an alternative

monitoring system must match the

CEMS’ ability to record requisite

emissions data on an hourly basis and

report results within 24 hours.

In 1995, Long Island Lighting

Company (LILCO) sponsored an

‘‘alternative flow monitor demonstration

project’’ to demonstrate the equivalency

of fuel flow measurements and F-factor

calculations to stack instrument flue gas

measurements for the determination of

volumetric flow. The project was
28114 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

performed by Entropy at LILCO’s Port

Jefferson Unit 4, a 180 MW oil-fired unit

that burns residual oil with a maximum

sulfur content of one percent. The

components of the alternative method

consisted of a fuel flowmeter and a CO2

CEMS. The alternative F-factor/fuel flow

method was compared to a flue gas

volumetric flow CEMS.

Testing of the F-factor/fuel flow

method took place in April–May 1995,

and 739 hours of data were collected

over a wide range of operating loads (40

MW—190 MW). Fuel oil samples were

taken daily and analyzed for density

and carbon content. The alternative

method successfully passed statistical

tests but showed statistically significant

bias (see Docket A–97–35, Item II–D–

14). Due to the bias uncovered during

the test, EPA concluded that the

alternative flow monitor demonstration

project did not meet the requirements of

subpart E of part 75 for an alternative

monitoring system. However, EPA is

proposing that a default multiplier,

derived from the demonstration data, be

incorporated into the equations used

under Appendix I to compensate for the

detected systematic bias and thereby

help to ensure that emissions are not

underestimated when using the Ffactor/fuel flow method. With these

provisions, EPA proposes to include the

F-factor/fuel flow method as an

excepted method for determining flow

in Appendix I to part 75. The proposed

default multiplier, 1.12, is based on the

data and results of the LILCO

demonstration and is supported by EPA

and the Class of ‘85 Regulatory

Response Group. The default multiplier

would be incorporated into the

equations used under Appendix I

whenever a relative accuracy test audit

is performed on a component-bycomponent basis as was proposed in the

LILCO demonstration.

Discussion of Proposed Changes

EPA proposes to include the F-factor/

fuel flow method in Appendix I as an

excepted method for use in place of a

volumetric flow monitor for oil- and

gas-fired units that burn only natural gas

and/or fuel oil. The F-factor/fuel flow

method uses fuel flow measurement,

fuel sampling data, CO2 (or O2) CEMS

data and F-factors to determine the flow

rate of the stack gas. EPA proposes

limiting use of the F-factor/fuel flow

method to oil- and gas-fired units that

burn only natural gas and/or fuel oil

because of the greater fuel consistency

of oil and natural gas and because the

fuel flow rates of oil and natural gas can

be monitored accurately with a fuel

flowmeter, unlike the feed rate of coal.

Appendix I flow monitoring would be

done using any of the following

combinations of components: a CO2

monitor and a volumetric oil flowmeter,

a CO2 monitor and a mass oil flowmeter,

a CO2 monitor and a volumetric gas

flowmeter, an O2 monitor and a

volumetric oil flowmeter, an O2 monitor

and a mass oil flowmeter, or an O2

monitor and a volumetric gas flowmeter.

Today’s proposal would amend

§ 75.20, ‘‘Certification and

Recertification Procedures,’’ to add

certification and recertification

procedures for units using Appendix I

flow monitoring systems. Initial

certification of the components of the Ffactor/fuel flow method would be

performed either component by

component or on a system basis. If each

component is tested separately, then the

fuel flowmeter would be tested in

accordance with section 2.1.5 of

Appendix D, and the CO2 or O2 monitor

would have to pass a 7-day calibration

test, a linearity check, a cycle time test

and a relative accuracy test audit

(RATA) using Method 3A from

Appendix A to part 60. A bias test

would also have to be conducted. If the

excepted Appendix I flow monitoring

system is tested as an entire system,

then the following tests would be

performed: a 7-day calibration error test,

a linearity check, and a cycle time test

on the CO2 or O2 monitor, and a relative

accuracy test audit on the entire

excepted flow monitoring system using

Method 2 from Appendix A to part 60,

and a bias test. The owner or operator

would also test the data acquisition and

handling system. Upon successful

completion of all certification tests, the

Appendix I system would be considered

provisionally certified.

Today’s proposal would amend

§ 75.21, ‘‘Quality Assurance and Quality

Control Requirements,’’ to include

Appendix I flow monitoring systems. A

unit utilizing the optional F-factor/fuel

flow method would have to meet

ongoing quality assurance testing

requirements. First, the daily and

quarterly assessment requirements for a

CO2 or O2 monitor in sections 2.1 and

2.2 of Appendix B would have to be

followed. Second, one of the following

would have to be met, depending on

whether the owner or operator chooses

to test the method on a component-bycomponent basis or on a system level:

(1) the fuel flow meter quality assurance

requirements and a separate RATA on

the CO2 (or O2) monitor; or (2) a system

level flow RATA. If the components are

tested separately, the applicable

procedures in section 2.1.6 of Appendix

D would have to be followed for the fuel

flowmeter quality assurance (i.e., a flow

meter accuracy test, a transmitter

accuracy test and primary element

inspection, and/or the supplemental

quarterly fuel flow-to-load quality

assurance testing) and the applicable

RATA procedures in sections 6.5

through 6.5.2.2 of Appendix A for the

CO2 (or O2) monitor would be followed.

In addition, the bias test would have to

be performed on the CO2 (or O2) monitor

and, if the bias test is failed, a bias

adjustment factor (BAF) would have to

be calculated and applied to hourly

data.

If the entire system is tested, the

applicable procedures in sections 6.5

through 6.5.2.2 of Appendix A would

have to be used to meet the performance

specifications for flow relative accuracy

in section 3.3.4 of Appendix A. The bias

test would have to be performed on the

volumetric flow data and, if the bias test

is failed, a BAF would have to be

calculated using the procedures in

section 7.6 of Appendix A.

Several other sections of the rule

would be modified or added in order to

incorporate the new excepted method

described in Appendix I, including

§§ 75.30, 75.57, 75.58, and 75.59.

Section 75.30, ‘‘General Provisions’’ (for

missing data substitution procedures),

would be modified by adding quality

assured data from a certified excepted

flow monitoring system under

Appendix I to the list of monitoring

systems that measure flow rate data, for

which the missing data substitution

procedures of subpart D are required. If

fuel sampling data, fuel flow rate data,

and diluent gas data are missing, then

the data acquisition and handling

system would have to substitute for

missing volumetric flow data. In

addition, § 75.57, would include

additional information that Appendix I

flow monitoring systems must record.

This includes fuel flow rate data and

data from component monitors. Section

75.58(g) would be added to address

specific volumetric flow rate record

provisions for units using the optional

protocol in Appendix I. Section 75.59,

‘‘Certification, Quality Assurance and

Quality Control Record Provisions,’’

would also include certification and

quality assurance information that

facilities must record for Appendix I

flow monitoring system tests.

Finally, the new proposed Appendix

I would describe the applicability,

procedures, calculations, missing data,

and recordkeeping and reporting

requirements for units using Appendix

I to determine flow.

The Appendix I formulas are more

complex if an O2 monitor is used. EPA

proposes to allow the use of an O2

monitor for Appendix I; however, the
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28115

initial programming of the formulas and

monitoring plan development may take

longer for Appendix I flow monitoring

systems that use an O2 monitor.

Volumetric stack flow rate during oil

combustion would be calculated from

(1) a bias adjustment factor from the

applicable bias test results; (2) the fuel

flow rate (in gal/hr); (3) the fuel density

(in lb/gal); (4) the percent carbon by

weight; (5) the CO2 (or O2) concentration

percent by volume; and (6) the

appropriate conversion factor. The

carbon content of the fuel would have

to be determined according to the

procedures in section 2.1 of Appendix

G and the density of the oil would have

to be determined according to the

procedures in section 2.2 of Appendix

D.

Rationale: EPA is proposing an Ffactor/fuel flow method in Appendix I

to part 75 as an excepted method to

measure volumetric flow directly with a

flow monitor because 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 § 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, while affording cost

savings that some industry

representatives estimate could be

substantial. The Agency solicits

comment on the proposed Appendix I

and associated changes to part 75.

Appendix I may offer cost savings to

some oil and gas fired units.

Representatives from oil- and gas-fired

units have estimated that the costs of

operating, maintaining and testing

volumetric flow monitors range from

approximately $15,000 to $25,000 per

year. In contrast, using the F-factor/fuel

flow method is estimated to result in

costs of only approximately $5,000 to

$7,000 per year due to elimination of

the operating, maintenance, testing and

fuel costs associated with the

volumetric flow monitor.

U. The Use of Predictive Emissions

Modeling Systems (PEMS)

A number of parties have submitted

preliminary field test data designed to

demonstrate that EPA should set forth

specific requirements for alternative

monitoring methodologies that predict

NOX emission rates at gas-fired units.

These ‘‘predictive emissions modeling

systems’’ (PEMS) use mathematical

models to predict NOX emission rates

based on sensor readings of key

operating parameters. The agency is

evaluating the submitted data and will

consider taking further action under a

future rulemaking if additional study

demonstrates the equivalency of PEMS

to CEMS for well defined classes of

units.

IV. Administrative Requirements

A. Public Hearing

If requested as specified in the DATES

section of this preamble, a public

hearing will be held to discuss the

proposed regulations. Persons wishing

to make oral presentations at the public

hearing should contact EPA at the

address given in the ADDRESSES section

of this preamble. If necessary, oral

presentations will be limited to 15

minutes each. Any member of the

public may file a written statement with

EPA before, during, or within 30 days of

the hearing. Written statements should

be addressed to the Air Docket address

given in the ADDRESSES section of this

preamble.

A verbatim transcript of the public

hearing, if held, and all written

statements will be available for public

inspection and copying during normal

working hours at EPA’s Air Docket in

Washington, DC (see the ADDRESSES

section of this preamble).

B. Public Docket

The Docket for this regulatory action

is A–97–35. The docket is an organized

and complete file of all the information

submitted to or otherwise considered by

EPA in the development of this

proposed rulemaking. 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 preamble.

C. Executive Order 12866

Under Executive Order 12866 (58 FR

51735, October 4, 1993), the

Administrator must determine whether

the regulatory action is ‘‘significant’’

and therefore subject to Office of

Management and Budget (OMB) review

and the requirements of the Executive

Order. The Order defines ‘‘significant

regulatory action’’ as one that is likely

to result in a rule that may:

(1) Have an annual effect on the economy

of $100 million or more or adversely affect

in a material way the economy, a sector of

the economy, productivity, competition, jobs,

the environment, public health or safety, or

State, local or tribal governments or

communities;

(2) Create a serious inconsistency or

otherwise interfere with an action taken or

planned by another agency;

(3) Materially alter the budgetary impact of

entitlements, grants, user fees, or loan

programs or the rights and obligations of

recipients thereof; or

(4) Raise novel legal or policy issues

arising out of legal mandates, the President’s

priorities, or the principles set forth in the

Executive Order.

This proposed rule is not expected to

have an annual effect on the economy

of $100 million or more. However,

pursuant to the terms of Executive

Order 12866, it has been determined

that this proposed rule is a significant

action because it raises novel policy

issues. As such, the proposed rule has

been submitted for OMB review. Any

written comments from OMB and any

EPA response to OMB comments are in

the public docket for this proposal.

D. Unfunded Mandates Reform Act

Title II of the Unfunded Mandates

Reform Act of 1995 (UMRA), P.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. Before

promulgating an EPA rule for which a

written statement is needed, section 205

of the UMRA generally requires EPA to

identify and consider a reasonable

number of regulatory alternatives and

adopt the least costly, most costeffective, 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
28116 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

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 proposed rule is not expected to

result in expenditures of more than

$100 million in any one year and, as

such, is not subject to section 202 of the

UMRA. Although the proposed rule is

not expected to significantly or uniquely

affect small governments, the Agency

has notified all potentially affected

small governments that own or operate

units potentially affected by the

proposal in order to assure that they

have the opportunity to have

meaningful and timely input on the

proposed 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.

E. Paperwork Reduction Act

The information collection

requirements in this proposal 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.

1835.01), 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.gov/icr.

Currently, all affected utilities are

required to keep records and submit

electronic quarterly reports under the

provisions of part 75. The proposed rule

includes several new options for

compliance with part 75 which have

been requested by affected utilities. To

implement these options, EPA would

have to modify the existing

recordkeeping and reporting

requirements. In some circumstances,

these changes would result in

significant reductions in the reporting

and recordkeeping burdens or costs for

some units (such as low mass emissions

units). However, these changes would

require modifications to the software

used to generate electronic reports. In

addition, there would be some increased

burden or costs for certain units to

fulfill the new quality assurance

procedures proposed in these proposed

revisions. Finally, several other

technical revisions to the existing

reporting and recordkeeping

requirements have been proposed to

clarify existing provisions or to facilitate

reporting for other regulatory programs

in the context of Acid Rain Program

reporting. Although these one-time

software changes would tend to increase

the short-term burdens allocated to the

Acid Rain Program, such changes

should reduce a source’s overall longterm burden by streamlining the

source’s reporting obligations under

both the Acid Rain Program and the Act.

The average annual projected hour

burden is 2,608,836, which is based on

an estimated 835 likely respondents (on

a per utility basis). The projected cost

burden resulting from the collection of

information is $47,555,000, which

includes a total projected capital and

start-up cost of $1,436,000 (for

monitoring equipment/software), and a

total projected operation and

maintenance cost (which includes

purchase of testing contractor services

and total projected fuel sampling and

analysis cost of $716,000) of

$46,119,000. Burden means the total

time, effort, or financial resources

expended by persons to generate,

maintain, retain, disclose, or provide

information to or for a Federal agency.

This includes the time needed to review

instructions; develop, acquire, install,

and utilize technology and systems for

purposes of collecting, validating, and

verifying information, processing and

maintaining information, and disclosing

and providing information; adjust the

existing ways to comply with any

previously applicable instructions and

requirements; train personnel to be able

to respond to a collection of

information; search data sources;

complete and review the collection of

information; and transmit or otherwise

disclose the information.

An agency may not conduct or

sponsor and a person is not required to

respond to a collection of information,

unless it displays a currently valid OMB

control number. The OMB control

numbers for EPA’s regulations are listed

in 40 CFR part 9 and 48 CFR chapter 15.

Comments are requested on the

Agency’s need for this information, the

accuracy of the provided burden

estimates, and any suggested methods

for minimizing respondent burden,

including through the use of automated

collection techniques. Send comments

on the ICR to the Director, OPPE

Regulatory Information Division; U.S.

Environmental Protection Agency

(2137); 401 M Street, SW, Washington,

DC 20460; and to the Office of

Information and Regulatory Affairs,

Office of Management and Budget, 725

17th Street, NW, Washington, DC 20503,

marked ‘‘Attention: Desk Officer for

EPA.’’ Include the ICR number in any

correspondence. Since OMB is required

to make a decision concerning the ICR

between 30 and 60 days after May 21,

1998, a comment to OMB is best assured

of having its full effect if OMB receives

it by June 22, 1998. The final rule will

respond to any OMB or public

comments on the information collection

requirements contained in this proposal.

F. Regulatory Flexibility Act

The Regulatory Flexibility Act (RFA),

5 U.S.C. 601, et seq., generally requires

an agency to conduct a regulatory

flexibility analysis of any rule subject to

notice and comment rulemaking

requirements unless the agency certifies

that the rule will not have a significant

economic impact on a substantial

number of small entities. Small entities

include small businesses, small not-forprofit enterprises, and governmental

jurisdictions. This proposed rule would

not have a significant impact on a

substantial number of small entities.

Today’s proposed revisions to part 75

result in a net cost reduction to utilities

affected by the Acid Rain Program,

including small entities. Most

importantly, the proposed changes to

Appendix D and the addition of an

optional calculation procedure instead

of actual monitoring for oil- and gasfired units with low mass emissions

would significantly reduce the cost of

complying with part 75 for oil-and gasfired units, many of which are owned or

operated by small entities. Therefore, I

certify this action will not have a

significant economic impact on a

substantial number of small entities.

G. National Technology Transfer and

Advancement Act

Section 12(d) of the National

Technology Transfer and Advancement

Act of 1995 (‘‘ANTTAA’’), Pub L. No.

104–113 15 USC 272 note, directs EPA

to use voluntary consensus standards in

its regulatory activities unless to do so

would be inconsistent with applicable

law or otherwise impractical. Voluntary

consensus standards are technical

standards (e.g., materials specifications,

test methods, sampling procedures,

business practices, etc.) that are

developed or adopted by voluntary

consensus standards bodies. The

NTTAA requires EPA to provide

Congress, through OMB, explanations

when the Agency decides not to use

available and applicable voluntary

consensus standards.

This regulatory action proposes to

incorporate by reference voluntary

consensus standards pursuant to § 12(d)

of the NTTAA. The EPA has adopted

the general policy of using voluntary
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28117

consensus standards from technically

knowledgeable groups such as the

Organization for International Standards

(ISO), the American Society for Testing

and Materials (ASTM), the American

Society of Mechanical Engineers

(ASME), the American Gas Association

(AGA), the Gas Processors Association

(GPA), and the American Petroleum

Institute (API).

EPA invites public comment on the

voluntary consensus standards which

are proposed to be incorporated by

reference for use in part 75. EPA has not

identified any additional voluntary

consensus standards which might be

applicable to this rulemaking. This does

not indicate that other applicable

standards do not exist or that any other

standards should not be allowed.

Therefore, EPA also invites public

comment on any other voluntary

consensus standards which may be

appropriate for the proposed regulatory

action. Further, if additional applicable

voluntary consensus standards are

identified in the future, the designated

representative may petition under

§ 75.66(c) to use an alternative to any

standard incorporated by reference and

prescribed in this part.

EPA proposes to incorporate by

reference the following voluntary

consensus standards for use under part

75:

a. ASTM D5373–93 ‘‘Standard

Methods for Instrumental Determination

of Carbon, Hydrogen and Nitrogen in

laboratory samples of Coal and Coke.’’

This standard is proposed to be

incorporated by reference for use under

section 2.1 of Appendix G to part 75 and

is discussed further in section III.Q.1 of

this preamble.

b. API Section 2 ‘‘Conventional Pipe

Provers’’ from Chapter 4 of the Manual

of Petroleum Measurement Standards,

October 1988 edition. This standard is

proposed to be incorporated by

reference for use under paragraph

(g)(1)(i) of § 75.20 and under section

2.1.5.1 of Appendix D to part 75. The

proposal to incorporate this standard by

reference is discussed further in section

III.P.6.(b) of this preamble.

List of Subjects in 40 CFR Parts 72 and

75

Air pollution control, Carbon dioxide,

Continuous emission monitors, Electric

utilities, Environmental protection,

Nitrogen oxides, Reporting and

recordkeeping requirements, Sulfur

dioxide.

Dated: April 27, 1998.

Carol M. Browner,

Administrator, U.S. Environmental Protection

Agency.

For the reasons set out in the

preamble, title 40 chapter 1 of the Code

of Federal Regulations is proposed to be

amended as follows:

PART 72—PERMITS REGULATION

1. The authority for part 72 continues

to read as follows:

Authority: 42 U.S.C. 7601 and 7651, et seq.

2. Section 72.2 is amended by revising

the definitions of ‘‘calibration gas,’’

‘‘excepted monitoring system,’’ ‘‘gasfired,’’ ‘‘pipeline natural gas,’’ ‘‘span,’’

‘‘stationary gas turbine,’’ and ‘‘zero air

material’’; by revising paragraph (2) of

‘‘oil-fired’’ and paragraph (2) of the

‘‘peaking unit’’; by adding paragraph (3)

to the definition of ‘‘peaking unit’’; by

adding new definitions for

‘‘conditionally valid data,’’ ‘‘EPA

protocol gas,’’ ‘‘gas manufacturer’s

intermediate standard,’’ ‘‘low mass

emissions unit,’’ ‘‘maximum rated

hourly heat input,’’ ‘‘ozone season,’’

‘‘probationary calibration error test,’’

‘‘research gas mixture (RGM)’’, and

‘‘standard reference material-equivalent

compressed gas primary reference

material’’; and by removing the

definition of ‘‘protocol 1 gas,’’ to read as

follows:

§ 72.2 Definitions.

* * * * *

Calibration gas means:

(1) A standard reference material;

(2) A standard reference materialequivalent compressed gas primary

reference material;

(3) A NIST traceable reference

material;

(4) NIST/EPA-approved certified

reference materials;

(5) A gas manufacturer’s intermediate

standard;

(6) An EPA protocol gas;

(7) Zero air material; or

(8) A research gas mixture.

* * * * *

Conditionally valid data means data

from a continuous monitoring system

that are not quality assured, but which

may become quality assured if certain

conditions are met. Examples of data

that may qualify as conditionally valid

are: data recorded by an uncertified

monitoring system prior to its initial

certification; or data recorded by a

certified monitoring system following a

significant change to the system that

may affect its ability to accurately

measure and record emissions. A

monitoring system must pass a

probationary calibration error test, in

accordance with section 2.1.1 of

appendix B of part 75 of this chapter, to

initiate the conditionally valid data

status. In order for conditionally valid

emission data to become quality

assured, one or more quality assurance

tests or diagnostic tests must be passed

within a specified time period.

* * * * *

EPA protocol gas means a calibration

gas mixture prepared and analyzed

according to section 2 of the ‘‘EPA

Traceability Protocol for Assay and

Certification of Gaseous Calibration

Standards,’’ September 1997, EPA–600/

R–97/121 or such revised procedure as

approved by the Administrator.

* * * * *

Excepted monitoring system means a

monitoring system that follows the

procedures and requirements of § 75.19

of this chapter or of appendix D or E to

part 75 for approved exceptions to the

use of continuous emission monitoring

systems.

* * * * *

Gas-fired means:

(1) For all purposes under the Acid

Rain Program, except for part 75 of this

chapter, the combustion of:

(i) Natural gas or other gaseous fuel

(including coal-derived gaseous fuel),

for at least 90.0 percent of the unit’s

average annual heat input during the

previous three calendar years and for at

least 85.0 percent of the annual heat

input in each of those calendar years;

and

(ii) Any fuel, except coal or solid or

liquid coal-derived fuel for the

remaining heat input, if any.

(2) For purposes of part 75 of this

chapter, the combustion of:

(i) Natural gas or other gaseous fuel

with a total sulfur content no greater

than the total sulfur content of natural

gas (including coal-derived gaseous

fuel) for at least 90.0 percent of the

unit’s average annual heat input during

the previous calendar years and for at

least 85.0 percent of the annual heat

input in each of those calendar years;

and

(ii) Fuel oil, for the remaining heat

input, if any.

(3) For purposes of part 75 of this

chapter, a unit may initially qualify as

gas-fired if the designated representative

demonstrates to the satisfaction of the

Administrator that the requirements of

paragraph (2) of this definition are met,

or will in the future be met, through one

of the following submissions:

(i) For a unit for which a monitoring

plan has not been submitted under

§ 75.62 of this chapter,

(A) The designated representative

submits fuel usage data for the unit for
28118 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

the three calendar years immediately

preceding the date of initial submission

of the monitoring plan for the unit

under § 75.62; or

(B) For a unit that does not have fuel

usage data for one or more of the three

calendar years immediately preceding

the date of initial submission of the

monitoring plan for the unit under

§ 75.62, if the designated representative

submits: the unit’s designated fuel

usage; all available fuel usage data

(including the percentage of the unit’s

heat input derived from the combustion

of gaseous fuels), beginning with the

date on which the unit commenced

commercial operation; and the unit’s

projected fuel usage.

(ii) For a unit for which a monitoring

plan has already been submitted under

§ 75.62, that has not qualified as gasfired under paragraph (3)(i) of this

definition, and whose fuel usage

changes, the designated representative

submits either:

(A) Three calendar years of data

following the change in the unit’s fuel

usage, showing that no less than 90.0

percent of the unit’s average annual heat

input during the previous three calendar

years, and no less than 85.0 percent of

the unit’s annual heat input during any

one of the previous three calendar years

is from the combustion of gaseous fuels

with a total sulfur content no greater

than the total sulfur content of natural

gas and the remaining heat input is from

the combustion of fuel oil; or

(B) A minimum of 720 hours of unit

operating data following the change in

the unit’s fuel usage, showing that no

less than 90.0 percent of the unit’s heat

input is from the combustion of gaseous

fuels with a total sulfur content no

greater than the total sulfur content of

natural gas and the remaining heat input

is from the combustion of fuel oil, and

a statement that this changed pattern of

fuel usage is considered permanent and

is projected to continue for the

foreseeable future.

(iii) If a unit qualifies as gas-fired

under paragraph (2)(i) or (ii) of this

definition, the unit is classified as gasfired as of the date of the submission

under such paragraph.

(4) For purposes of part 75 of this

chapter, a unit that initially qualifies as

gas-fired must meet the criteria in

paragraph (2) of this definition each

year in order to continue to qualify as

gas-fired. If such a unit fails to meet

such criteria for a given year, the unit

no longer qualifies as gas-fired starting

January 1 of the year after the first year

for which the criteria are not met. If a

unit failing to meet the criteria in

paragraph (2) of this definition initially

qualified as a gas-fired unit under

paragraph (3)(ii) of this definition, the

unit may qualify as a gas-fired unit for

a subsequent year only under paragraph

(3)(i) of this definition.

* * * * *

Gas manufacturer’s intermediate

standard (GMIS) means a compressed

gas calibration standard that has been

assayed and certified by direct

comparison to a standard reference

material (SRM), an SRM-equivalent

PRM, a NIST/EPA-approved certified

reference material (CRM), or a NIST

traceable reference material (NTRM), in

accordance with section 2.1.2.1 of the

‘‘EPA Traceability Protocol for Assay

and Certification of Gaseous Calibration

Standards,’’ September 1997, EPA–600/

R–97/121.

* * * * *

Low mass emissions unit means a gasfired or oil-fired unit that burns only

natural gas and/or fuel oil and that

qualifies under §§ 75.19(a) and (b) of

this chapter.

* * * * *

Maximum rated hourly heat input

means a unit-specific maximum hourly

heat input (mmBtu) which is the higher

of the manufacturer’s maximum rated

hourly heat input or the highest

observed hourly heat input.

Oil-fired means:

* * * * *

(2) For purposes of part 75 of this

chapter, a unit may qualify as oil-fired

if the unit burns only fuel oil and

gaseous fuels with a total sulfur content

no greater than the total sulfur content

of natural gas and if the unit does not

meet the definition of gas-fired.

* * * * *

Ozone season means the period of

time from May 1st to September 30th,

inclusive.

* * * * *

Peaking unit means:

* * * * *

(2) For purposes of part 75 of this

chapter, a unit may initially qualify as

a peaking unit if the designated

representative demonstrates to the

satisfaction of the Administrator that the

requirements of paragraph (1) of this

definition are met, or will in the future

be met, through one of the following

submissions:

(i) For a unit for which a monitoring

plan has not been submitted under

§ 75.62,

(A) The designated representative

submits capacity factor data for the unit

for the three calendar years immediately

preceding the date of initial submission

of the monitoring plan for the unit

under § 75.62; or

(B) For a unit that does not have

capacity factor data for one or more of

the three calendar years immediately

preceding the date of initial submission

of the monitoring plan for the unit

under § 75.62, the designated

representative submits: all available

capacity factor data, beginning with the

date on which the unit commenced

commercial operation; and projected

capacity factor.

(ii) For a unit for which a monitoring

plan has already been submitted under

§ 75.62, that has not qualified as a

peaking unit under paragraph (2)(i) of

this definition, and where capacity

factor changes, the designated

representative submits either:

(A) Three calendar years of data

following the change in the unit’s

capacity factor showing an average

capacity factor of no more than 10.0

percent during the three previous

calendar years and a capacity factor of

no more than 20.0 percent in each of

those calendar years; or

(B) One calendar year of data

following the change in the unit’s

capacity factor showing a capacity factor

of no more than 10.0 percent and a

statement that this changed pattern of

operation resulting in a capacity factor

less than 10.0 percent is considered

permanent and is projected to continue

for the foreseeable future.

(3) For purposes of part 75 of this

chapter, a unit that initially qualifies as

a peaking unit must meet the criteria in

paragraph (1) of this definition each

year in order to continue to qualify as

a peaking unit. If such a unit fails to

meet such criteria for a given year, the

unit no longer qualifies as a peaking

unit starting January 1 of the year after

the year for which the criteria are not

met. If a unit failing to meet the criteria

in paragraph (1) of this definition

initially qualified as a gas-fired unit

under paragraph (2)(ii) of this

definition, the unit may qualify as a

peaking unit for a subsequent year only

under paragraph (2)(i) of this definition.

* * * * *

Pipeline natural gas means natural gas

that is provided by a supplier through

a pipeline and that contains 0.3 grains

or less of hydrogen sulfide per 100

standard cubic feet. The hydrogen

sulfide content of the natural gas must

be documented 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
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28119

0.3 grains or less of hydrogen sulfide per

100 standard cubic feet.

* * * * *

Probationary calibration error test

means an on-line calibration error test

performed in accordance with section

2.1.1 of appendix B of part 75 of this

chapter that is used to initiate a

conditionally valid data period.

* * * * *

Research gas mixture (RGM) means a

calibration gas mixture developed by

agreement of a requestor and NIST that

NIST analyzes and certifies as ‘‘NIST

traceable.’’ RGMs may have

concentrations different from those of

standard reference materials.

* * * * *

Span means the highest pollutant or

diluent concentration or flow rate that a

monitor component is required to be

capable of measuring under part 75 of

this chapter.

* * * * *

Standard reference materialequivalent compressed gas primary

reference material (SRM-equivalent

PRM) means those gas mixtures listed in

a declaration of equivalence in

accordance with section 2.1.2 of the

‘‘EPA Traceability Protocol for Assay

and Certification of Gaseous Calibration

Standards,’’ September 1997, EPA–600/

R–97/121.

* * * * *

Stationary gas turbine means a

turbine that is not self-propelled and

that combusts natural gas, other gaseous

fuel with a total sulfur content no

greater than the total sulfur content of

natural gas, or fuel oil in order to heat

inlet combustion air and thereby turn a

turbine, in addition to or instead of

producing steam or heating water.

* * * * *

Zero air material means either:

(1) A calibration gas certified by the

gas vendor not to contain concentrations

of SO2, NOX, or total hydrocarbons

above 0.1 parts per million (ppm), a

concentration of CO above 1 ppm, a

concentration of CO2 above 400 ppm; or

(2) Ambient air conditioned and

purified by a CEMS for which the CEMS

manufacturer or vendor certifies that the

particular CEMS model produces

conditioned gas that does not contain

concentrations of SO2, NOX, or total

hydrocarbons above 0.1 ppm, a

concentration of CO above 1 ppm, or a

concentration of CO2 above 400 ppm; or

(3) For dilution-type CEMS,

conditioned and purified ambient air

provided by a conditioning system

concurrently supplying dilution air to

the CEMS; or

(4) A multicomponent mixture

certified by the supplier of the mixture

that the concentration of the component

being zeroed is less than or equal to the

applicable concentration specified in

paragraph (1) of this definition, and that

the mixture’s other components do not

interfere with the specific CEM readings

or cause the CEM being zeroed to read

concentrations of the gas being zeroed.

3. Section 72.3 is amended by adding

in alphabetical order, new acronyms for

kacfm, kscfh, and NIST to read as

follows:

§ 72.3 Measurements, abbreviations, and

acronyms.

* * * * *

kacfm—thousands of cubic feet per

minute at actual conditions.

kscfh—thousands of cubic feet per

hour at standard conditions.

NIST—National Institute of Standards

and Technology.

* * * * *

§ 72.6 [Amended]

4. Section 72.6 is amended by

removing from paragraph (b)(1) the

word ‘‘operation’’ and adding, in its

place, the words ‘‘commercial

operation.’’

5. Section 72.90 is amended by

revising paragraph (c)(3) to read as

follows:

§ 72.90 Annual compliance certification

report.

* * * * *

(c) * * *

(3) Whether all the emissions from the

unit, or a group of units (including the

unit) using a common stack, were

monitored or accounted for through the

missing data procedures and reported in

the quarterly monitoring reports,

including whether conditional data

were reported in the quarterly report. If

conditional data were reported, the

owner or operator shall indicate

whether the status of all conditional

data has been resolved and all necessary

quarterly report resubmissions have

been made.

* * * * *

PART 75—CONTINUOUS EMISSION

MONITORING

6. The authority citation for part 75

continues to read as follows:

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

7. Section 75.1 is amended by revising

paragraph (a) to read as follows:

§ 75.1 Purpose and scope.

(a) Purpose. The purpose of this part

is to establish requirements for the

monitoring, recordkeeping, and

reporting of sulfur dioxide, nitrogen

oxides, and carbon dioxide emissions,

volumetric flow, and opacity data from

affected units under the Acid Rain

Program pursuant to Sections 412 and

821 of the Clean Air Act, 42 U.S.C.

7401-7671q as amended by Public Law

101–549 (November 15, 1990) (the Act).

In addition, this part sets forth

provisions for the monitoring,

recordkeeping, and reporting of NOX

mass emissions with which EPA,

individual States, or groups of States

may require sources to comply in order

to demonstrate compliance with a NOX

mass emission reduction program, if

these provisions are adopted as

requirements under such a program.

* * * * *

8. Section 75.2 is amended by revising

paragraph (a) and adding a new

paragraph (c) to read as follows:

§ 75.2 Applicability.

(a) Except as provided in paragraphs

(b) and (c) of this section, the provisions

of this part apply to each affected unit

subject to Acid Rain emission

limitations or reduction requirements

for SO2 or NOX.

* * * * *

(c) The provisions of this part may

apply to sources subject to a State or

federal NOX mass emission reduction

program, if these provisions are adopted

as requirements under such a program.

9. Section 75.4 is amended by revising

paragraphs (a) introductory text and

(d)(1) and adding a new paragraph (i) to

read as follows:

§ 75.4 Compliance dates.

(a) The provisions of this part apply

to each existing Phase I and Phase II

unit on February 10, 1993. For

substitution or compensating units that

are so designated under the Acid Rain

permit which governs that unit and

contains the approved substitution or

reduced utilization plan, pursuant to

§ 72.41 or § 72.43 of this chapter, the

provisions of this part become

applicable upon the issuance date of the

Acid Rain permit. For combustion

sources seeking to enter the Opt-in

Program in accordance with part 74 of

this chapter, the provisions of this part

become applicable upon the submission

of an Opt-in permit application in

accordance with § 74.14 of this chapter.

The provisions of this part for the

monitoring, recording, and reporting of

NOX mass emissions become applicable

on the deadlines specified in the

applicable State or federal NOX mass

emission reduction program, if these

provisions are adopted as requirements

under such a program. In accordance

with § 75.20, the owner or operator of

each existing affected unit shall ensure

that all monitoring systems required by
28120 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

this part for monitoring SO2, NOX, CO2,

opacity, and volumetric flow are

installed and that all certification tests

are completed no later than the

following dates (except as provided in

paragraphs (d) through (h) of this

section):

* * * * *

(d) * * *

(1) The maximum potential

concentration of SO2, the maximum

potential NOX emission rate, the

maximum potential flow rate, as defined

in section 2.1 of appendix A to this part,

or the maximum potential CO2

concentration, as defined in section

2.1.3.1 of appendix A to this part.

* * * * *

(i) In accordance with § 75.20, the

owner or operator of each affected unit

at which SO2 concentration is measured

on a dry basis or at which moisture

corrections are required to account for

CO2 emissions, NOX emission rate in lb/

mmBtu, or heat input, shall ensure that

the continuous moisture monitoring

system required by this part is installed

and that all applicable initial

certification tests required under

§ 75.20(c)(5), (c)(6), or (c)(7) for the

continuous moisture monitoring system

are completed no later than the

following dates:

(1) January 1, 2000, for a unit that is

existing and has commenced

commercial operation by October 3,

1999; or

(2) For a new affected unit which has

not commenced commercial operation

by October 4, 1999, not later than 90

days after the date the unit commences

commercial operation; or

(3) For an existing unit that is

shutdown and is not yet operating by

January 1, 2000, not later than the

earlier of 45 unit operating days or 180

calendar days after the date that the unit

recommences commercial operation.

10. Section 75.5 is amended by

revising paragraph (f)(2) to read as

follows:

§ 75.5 Prohibitions.

* * * * *

(f) * * *

(2) The owner or operator is

monitoring emissions from the unit with

another certified monitoring system or

an excepted methodology approved by

the Administrator for use at that unit

that provides emission data for the same

pollutant or parameter as the retired or

discontinued monitoring system; or

* * * * *

11. Section 75.6 is amended by

redesignating paragraph (a)(40) as

paragraph (a)(41) and by adding new

paragraphs (a)(40) and (f) to read as

follows:

§ 75.6 Incorporation by reference.

* * * * *

(a) * * *

(40) ASTM D5373–93, ‘‘Standard

Methods for Instrumental Determination

of Carbon, Hydrogen, and Nitrogen in

Laboratory Samples of Coal and Coke,’’

for appendix G to this part.

* * * * *

(f) The following materials are

available for purchase from the

following address: American Petroleum

Institute, Publications Department, 1220

L Street NW, Washington, DC 20005–

4070: American Petroleum Institute

(API) Section 2, ‘‘Conventional Pipe

Provers,’’ from Chapter 4 of the Manual

of Petroleum Measurement Standards,

October 1988 (Reaffirmed 1993), for

§ 75.20 and appendix D to this part.

12. Section 75.10 is amended by

revising paragraphs (d)(3) and (f) to read

as follows:

§ 75.10 General operating requirements.

* * * * *

(d) * * *

(3) Failure of an SO2, CO2, or O2

pollutant concentration monitor, flow

monitor, or NOX continuous emission

monitoring system to acquire the

minimum number of data points for

calculation of an hourly average in

paragraph (d)(1) of this section, shall

result in the failure to obtain a valid

hour of data and the loss of such

component data for the entire hour. An

hourly average NOX or SO2 emission

rate in lb/mmBtu is valid only if the

minimum number of data points is

acquired by both the pollutant

concentration monitor (NOX or SO2) and

the diluent monitor (O2 or CO2). For a

moisture monitoring system consisting

of one or more oxygen analyzers capable

of measuring O2 on a wet-basis and a

dry-basis, an hourly average percent

moisture value is valid only if the

minimum number of data points is

acquired for both the wet-and dry-basis

measurements. Except for SO2 emission

rate data in lb/mmBtu, if a valid hour of

data is not obtained, the owner or

operator shall estimate and record

emission, moisture, or flow data for the

missing hour by means of the automated

data acquisition and handling system, in

accordance with the applicable

procedure for missing data substitution

in subpart D of this part.

* * * * *

(f) Minimum measurement capability

requirement. The owner or operator

shall ensure that each continuous

emission monitoring system and

component thereof is capable of

accurately measuring, recording, and

reporting data, and shall not incur a full

scale exceedance, except as provided in

sections 2.1.1.5, 2.1.2.5, and 2.1.4.3 of

appendix A to this part.

* * * * *

13. Section 75.11 is amended by

revising paragraphs (a), (b), (d)(1), (d)(2),

(e)(2), (e)(3) introductory text, (e)(3)(ii),

(e)(3)(iv), and (e)(4) and by adding

paragraph (d)(3), to read as follows:

§ 75.11 Specific provisions for monitoring

SO2 emissions (SO2 and flow monitors).

(a) Coal-fired units. The owner or

operator shall meet the general

operating requirements in § 75.10 for an

SO2 continuous emission monitoring

system and a flow monitoring system for

each affected coal-fired unit while the

unit is combusting coal and/or any other

fuel, except as provided in paragraph (e)

of this section, in § 75.16, and in subpart

E of this part. During hours in which

only natural gas or gaseous fuel with a

total sulfur content no greater than the

total sulfur content of natural gas (i.e.,

≤ 20 grains per 100 standard cubic feet

(gr/100 scf)) is combusted in the unit,

the owner or operator shall comply with

the applicable provisions of paragraph

(e)(1), (e)(2), or (e)(3) of this section.

(b) Moisture correction. Where SO2

concentration is measured on a dry

basis, the owner or operator shall

install, operate, maintain, and quality

assure a continuous moisture

monitoring system for measuring and

recording the moisture content of the

flue gases, in order to correct the

measured hourly volumetric flow rates

for moisture when calculating SO2 mass

emissions (in lb/hr) using the

procedures in appendix F to this part.

The following continuous moisture

monitoring systems are acceptable: a

continuous moisture sensor; an oxygen

analyzer (or analyzers) capable of

measuring O2 both on a wet basis and

on a dry basis; or a stack temperature

sensor and a moisture look-up table, i.e.,

a psychrometric chart (for saturated gas

streams following wet scrubbers, only).

The moisture monitoring system shall

include as a component the automated

data acquisition and handling system

(DAHS) for recording and reporting both

the raw data (e.g., hourly average wet

and dry-basis O2 values) and the hourly

average values of the stack gas moisture

content derived from those data. When

a moisture look-up table is used, the

moisture monitoring system shall be

represented as a single component, the

certified DAHS, in the monitoring plan

for the unit or common stack.

* * * * *

(d) * * *

(1) By meeting the general operating

requirements in § 75.10 for an SO2

continuous emission monitoring system
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28121

and flow monitoring system. If this

option is selected, the owner or operator

shall comply with the applicable

provisions in paragraph (e)(1), (e)(2), or

(e)(3) of this section during hours in

which the unit combusts only natural

gas (or gaseous fuel with a total sulfur

content no greater than the total sulfur

content of natural gas);

(2) By providing other information

satisfactory to the Administrator using

the applicable procedures specified in

appendix D to this part for estimating

hourly SO2 mass emissions. Appendix D

shall not, however, be used when the

unit combusts gaseous fuel with a total

sulfur content greater than the total

sulfur content of natural gas (i.e., > 20

gr/100 scf); when such fuel is burned,

the owner or operator shall comply with

the provisions of paragraph (e)(4) of this

section; or

(3) By using the low mass emissions

excepted methodology in § 75.19(c) for

estimating hourly SO2 mass emissions if

the affected unit qualifies as a low mass

emissions unit under § 75.19(a) and (b).

(e) * * *

(2) When gaseous fuel with a total

sulfur content no greater than the total

sulfur content of natural gas (i.e., ≤ 20

gr/100 scf) is combusted in the unit, the

owner or operator may, in lieu of

operating and recording data from the

SO2 monitoring system, determine SO2

emissions by certifying an excepted

monitoring system in accordance with

§ 75.20 and with appendix D to this

part, by following the fuel sampling and

analysis procedures in section 2.3.1 of

appendix D to this part, by meeting the

recordkeeping requirements of § 75.55

or § 75.58, as applicable, and by meeting

all quality control and quality assurance

requirements for fuel flowmeters in

appendix D to this part. If this

compliance option is selected, the

hourly unit heat input reported under

§ 75.54(b)(5) or § 75.57(b)(5), as

applicable, shall be determined using a

certified flow monitoring system and a

certified diluent monitor, in accordance

with the procedures in section 5.2 of

appendix F of this part. The flow

monitor and diluent monitor shall meet

all of the applicable quality control and

quality assurance requirements of

appendix B of this part.

(3) When gaseous fuel with a total

sulfur content no greater than the total

sulfur content of natural gas (i.e., ≤ 20

gr/100 scf) is burned in the unit, the

owner or operator may determine SO2

mass emissions by using a certified SO2

continuous monitoring system, in

conjunction with a certified flow rate

monitoring system. However, on and

after January 1, 2000, the SO2

monitoring system shall be subject to

the following provisions; prior to

January 1, 2000, the owner or operator

may comply with these provisions:

* * * * *

(ii) The calibration response of the

SO2 monitoring system shall be

adjusted, either automatically or

manually, in accordance with the

procedures for routine calibration

adjustments in section 2.1.3 of appendix

B to this part, whenever the zero-level

calibration response during a required

daily calibration error test exceeds the

applicable performance specification of

the instrument in section 3.1 of

appendix A to this part (i.e., ± 2.5

percent of the span value or ± 5 ppm,

whichever is less restrictive). This

calibration adjustment is optional if

gaseous fuel is burned in the affected

unit only during unit startup.

* * * * *

(iv) In accordance with the

requirements of section 2.1.1.2 of

appendix A to this part, for units that

sometimes burn natural gas (or gaseous

fuel with a total sulfur content no

greater than the total sulfur content of

natural gas) and at other times burn

higher-sulfur fuel(s) such as coal or oil,

a second low-scale SO2 measurement

range is not required when natural gas

(or gaseous fuel with a total sulfur

content no greater than the total sulfur

content of natural gas) is combusted. For

units that burn only natural gas (or

gaseous fuel with a total sulfur content

no greater than the total sulfur content

of natural gas) and burn no other type(s)

of fuel(s), the owner or operator shall set

the span of the SO2 monitoring system

to a value no greater than 200 ppm.

(4) During any hours in which a unit

combusts only gaseous fuel(s) with a

total sulfur content no greater than the

total sulfur content of natural gas (i.e.,

≤ 20 gr/100 scf), the owner or operator

shall meet the general operating

requirements in § 75.10 for an SO2

continuous emission monitoring system

and a flow monitoring system.

* * * * *

14. Section 75.12 is amended by

revising the title; by redesignating

existing paragraphs (b), (c), and (d) as

paragraphs (c), (d), and (f), respectively;

by adding new paragraphs (b) and (e);

and by revising the newly designated

paragraph (c), to read as follows:

§ 75.12 Specific provisions for monitoring

NOX emission rate (NOX and diluent gas

monitors).

* * * * *

(b) Moisture correction. If a correction

for the stack gas moisture content is

needed to properly calculate the NOX

emission rate in lb/mmBtu, i.e., if the

NOX pollutant concentration monitor

measures on a different moisture basis

from the diluent monitor, the owner or

operator shall install, operate, maintain,

and quality assure a continuous

moisture monitoring system, as defined

in § 75.11(b).

(c) Determination of NOX emission

rate. The owner or operator shall

calculate hourly, quarterly, and annual

NOX emission rates (in lb/mmBtu) by

combining the NOX concentration (in

ppm), diluent concentration (in percent

O2 or CO2), and percent moisture (if

applicable) measurements according to

the procedures in appendix F to this

part.

* * * * *

(e) Low mass emissions units.

Notwithstanding the requirements of

§§ 75.12(a) and (c), the owner or

operator of an affected unit that

qualifies as a low mass emissions unit

under § 75.19(a) and (b) shall comply

with one of the following:

(1) Meet the general operating

requirements in § 75.10 for a NOX

continuous emission monitoring system;

(2) Meet the requirements specified in

paragraph (d)(2) of this section for using

the excepted monitoring procedures in

appendix E to this part, if applicable; or

(3) Use the low mass emissions

excepted methodology in § 75.19(c) for

estimating hourly NOX emission rate

and hourly NOX mass emissions.

* * * * *

15. Section 75.13 is amended by

revising paragraphs (a) and (c) and by

adding paragraph (d) to read as follows:

§ 75.13 Specific provisions for monitoring

CO2 emissions.

(a) CO2 continuous emission

monitoring system. If the owner or

operator chooses to use the continuous

emission monitoring method, then the

owner or operator shall meet the general

operating requirements in § 75.10 for a

CO2 continuous emission monitoring

system and flow monitoring system for

each affected unit. The owner or

operator shall comply with the

applicable provisions specified in

§§ 75.11(a) through (e) or § 75.16, except

that the phrase ‘‘SO2 continuous

emission monitoring system’’ is

replaced with ‘‘CO2 continuous

emission monitoring system,’’ the

phrase ‘‘SO2 concentration’’ is replaced

with ‘‘CO2 concentration,’’ the term

‘‘maximum potential concentration of

SO2’’ is replaced with ‘‘maximum

potential concentration of CO2,’’ and the

phrase ‘‘SO2 mass emissions’’ is

replaced with ‘‘CO2 mass emissions.’’

* * * * *

(c) Determination of CO2 mass

emissions using an O2 monitor
28122 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

according to appendix F. If the owner or

operator chooses to use the appendix F

method, then the owner or operator may

determine hourly CO2 concentration

and mass emissions with a flow

monitoring system; a continuous O2

concentration monitor; fuel F and Fc

factors; and, where O2 concentration is

measured on a dry basis, a continuous

moisture monitoring system, as defined

in § 75.11(b), using the methods and

procedures specified in appendix F to

this part. For units using a common

stack, multiple stack, or bypass stack,

the owner or operator may use the

provisions of § 75.16, except that the

phrase ‘‘SO2 continuous emission

monitoring system’’ is replaced with

‘‘CO2 continuous emission monitoring

system,’’ the term ‘‘maximum potential

concentration of SO2’’ is replaced with

‘‘maximum potential concentration of

CO2,’’ and the phrase ‘‘SO2 mass

emissions’’ is replaced with ‘‘CO2 mass

emissions.’’

(d) Determination of CO2 mass

emissions from low mass emissions

units. The owner or operator of a unit

that qualifies as a low mass emissions

unit under §§ 75.19(a) and (b) shall

comply with one of the following:

(1) Meet the general operating

requirements in § 75.10 for a CO2

continuous emission monitoring system

and flow monitoring system;

(2) Meet the requirements specified in

paragraph (b) or (c) of this section for

use of the methods in appendix G or F

to this part, respectively; or

(3) Use the low mass emissions

excepted methodology in § 75.19(c) for

estimating hourly CO2 mass emissions.

16. Section 75.16 is amended by:

a. Revising paragraphs (b)(2)(ii)(B),

(b)(2)(ii)(D), (d)(2), and (e)(1);

b. Removing paragraphs (e)(2) and

(e)(3);

c. Redesignating existing paragraphs

(e)(4) and (e)(5) as paragraphs (e)(2) and

(e)(3), respectively;

d. Revising the last sentence and

adding a new sentence to the end of the

newly designated paragraph (e)(3); and

e. Adding a new paragraph (e)(4), to

read as follows:

§ 75.16 Special provisions for monitoring

emissions from common, bypass, and

multiple stacks for SO2 emissions and heat

input determinations.

* * * * *

(b) * * *

(2) * * *

(ii) * * *

(B) Install, certify, operate, and

maintain an SO2 continuous emission

monitoring system and flow monitoring

system in the duct from each

nonaffected unit; determine SO2 mass

emissions from the affected units as the

difference between SO2 mass emissions

measured in the common stack and SO2

mass emissions measured in the ducts

of the nonaffected units, not to be

reported as an hourly average value less

than zero; combine emissions for the

Phase I and Phase II affected units for

recordkeeping and compliance

purposes; calculate and report SO2 mass

emissions from the Phase I and Phase II

affected units, pursuant to an approach

approved by the Administrator, such

that these emissions are not

underestimated; or

* * * * *

(D) Petition through the designated

representative and provide information

satisfactory to the Administrator on

methods for apportioning SO2 mass

emissions measured in the common

stack to each of the units using the

common stack and on reporting the SO2

mass emissions. The Administrator may

approve such demonstrated substitute

methods for apportioning and reporting

SO2 mass emissions measured in a

common stack whenever the

demonstration ensures that there is a

complete and accurate accounting of all

emissions regulated under this part and,

in particular, that the emissions from

any affected unit are not

underestimated.

* * * * *

(d) * * *

(2) Install, certify, operate, and

maintain an SO2 continuous emission

monitoring system and flow monitoring

system in each stack. Determine SO2

mass emissions from each affected unit

as the sum of the SO2 mass emissions

recorded for each stack.

Notwithstanding the prior sentence, if

another unit also exhausts flue gases to

one or more of the stacks, the owner or

operator shall also comply with the

applicable common stack requirements

of this section to determine and record

SO2 mass emissions from the units

using that stack and shall calculate and

report SO2 mass emissions from the

affected units and stacks, pursuant to an

approach approved by the

Administrator, such that these

emissions are not underestimated.

(e) * * *

(1) The owner or operator of an

affected unit using a common stack,

bypass stack, or multiple stack with a

diluent monitor and a flow monitor on

each stack may choose to install

monitors to determine the heat input for

the affected unit, wherever flow and

diluent monitor measurements are used

to determine the heat input, using the

procedures specified in paragraphs (a)

through (d) of this section, except that

the terms ‘‘SO2 mass emissions’’ and

‘‘emissions’’ are replaced with the term

‘‘heat input’’ and the phrase ‘‘SO2

continuous emission monitoring system

and flow monitoring system’’ is

replaced with the phrase ‘‘a diluent

monitor and a flow monitor.’’ The

applicable equation in appendix F to

this part shall be used to calculate the

heat input from the hourly flow rate,

diluent monitor measurements, and (if

the equation in appendix F requires a

correction for the stack gas moisture

content) hourly moisture measurements.

Notwithstanding the options for

combining heat input in paragraphs

(a)(1)(ii), (a)(2)(ii), (b)(1)(ii), and (b)(2)(ii)

of this section, the owner or operator of

an affected unit with a diluent monitor

and a flow monitor installed on a

common stack to determine the

combined heat input at the common

stack shall also determine and report

heat input to each individual unit.

* * * * *

(3) * * * The heat input may be

apportioned either by using the ratio of

load (in MWe-hr) for each individual

unit to the total load for all units

utilizing the common stack or by using

the ratio of steam flow (in 1000 lb) for

each individual unit to the total steam

flow for all units utilizing the common

stack. The heat input should be

apportioned according to the procedures

in appendix F to this part.

(4) Notwithstanding paragraph (e)(1)

of this section, any affected unit that is

using the procedures in this part to meet

the monitoring and reporting

requirements of a State or federal NOX

mass emission reduction program must

also meet the requirements for

monitoring heat input in §§ 75.71 and

75.72.

17. Section 75.17 is amended by

adding introductory text before

paragraph (a) and by revising paragraph

(a)(2)(i)(C) to read as follows:

§ 75.17 Specific provisions for monitoring

emissions from common, by-pass, and

multiple stacks for NOX emission rate.

Notwithstanding the provisions of

paragraphs (a), (b), and (c) of this

section, the owner or operator of an

affected unit that is using the

procedures in this part to meet the

monitoring and reporting requirements

of a State or federal NOX mass emission

reduction program must also meet the

provisions for monitoring NOX emission

rate in §§ 75.71 and 75.72.

(a) * * *

(2) * * *

(i) * * *

(C) Each unit’s compliance with the

applicable NOX emission limit will be

determined by a method satisfactory to
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28123

the Administrator for apportioning to

each of the units the combined NOX

emission rate (in lb/mmBtu) measured

in the common stack and for reporting

the NOX emission rate, as provided in

a petition submitted by the designated

representative. The Administrator may

approve such demonstrated substitute

methods for apportioning and reporting

NOX emission rate measured in a

common stack whenever the

demonstration ensures that there is a

complete and accurate estimation of all

emissions regulated under this part and,

in particular, that the emissions from

any unit with a NOX emission limitation

are not underestimated.

* * * * *

18. Section 75.19 is added to subpart

B to read as follows:

§ 75.19 Optional SO2, NOX, and CO2

emissions calculation for low mass

emissions units.

(a) Applicability. (1) Consistent with

the requirements of paragraphs (a)(2)

and (b) of this section, the low mass

emissions excepted methodology in

paragraph (c) of this section may be

used in lieu of continuous emission

monitoring systems or, if applicable, in

lieu of excepted methods under

appendix D or E to this part, for the

purpose of determining hourly heat

input, hourly NOX emission rate, and

hourly NOX, SO2, and CO2 mass

emissions from a low mass emissions

unit. A low mass emissions unit is a gasfired or oil-fired unit that burns only

natural gas and/or fuel oil and that:

(i) Emits no more than 25 tons of SO2

annually and no more than 25 tons of

NOX annually; and

(ii) Has calculated emissions of no

more than 25 tons of SO2 annually and

no more than 25 tons of NOX annually

based on the maximum rated hourly

heat input, the actual operating time for

each fuel burned, and the low mass

emissions excepted methodology,

calculations, and values in paragraph (c)

of this section.

(2) A unit may initially qualify as a

low mass emissions unit only under the

following circumstances:

(i) The designated representative

provides historical actual and calculated

emissions data from the previous three

calendar years immediately prior to the

submission of an application to use the

low mass emissions excepted

methodology, and the data demonstrates

to the satisfaction of the Administrator

that the unit meets the criteria in

paragraphs (a)(1)(i) and (ii) of this

section; or

(ii) If a unit does not have the

historical data required in paragraph

(a)(2)(i) of this section for any one or

more of the previous three calendar

years, the designated representative

submits:

(A) Any historical annual emissions

and operating data, as required in

paragraphs (a)(1)(i) and (a)(1)(ii) of this

section, beginning with the unit’s first

calendar year of commercial operation,

and the data demonstrates to the

satisfaction of the Administrator that the

unit meets the criteria in paragraphs

(a)(1)(i) and (a)(1)(ii) of this section; and

(B) A demonstration satisfactory to

the Administrator that the unit will

continue to qualify as a low mass

emissions unit under the requirements

of this paragraph (a). The demonstration

shall include any historical emissions

and operating data for less than a

calendar year for the unit and projected

emissions information for the unit, as

determined using projected operating

hours and fuel usage, and the low mass

emissions excepted methodology,

calculations, and values in paragraph (c)

of this section.

(b) Disqualification. If a unit that

initially qualifies as a low mass

emissions units under this section

changes the fuel that is burned in the

unit such that a fuel other than natural

gas or fuel oil is combusted in the unit,

the unit is disqualified from using the

low mass emissions excepted

methodology as of the first hour that the

new fuel is combusted in the unit. In

addition, if a unit that initially qualifies

as a low mass emissions unit under this

section emits more than 25 tons of SO2

or 25 tons of NOX in any calendar year

or has calculated emissions greater than

25 tons of SO2 or 25 tons of NOX in any

calendar year, as determined using the

low mass emission equations in

paragraph (c) of this section, the owner

or operator of the unit shall have two

quarters from the end of the quarter in

which the exceedance occurs to install,

certify, and report SO2, NOX, and CO2

from monitoring systems that meet the

requirements of §§ 75.11, 75.12, and

75.13, respectively. The unit shall be

disqualified as a low mass emissions

unit as of the end of the second quarter

following the quarter in which either of

the 25 ton limits was exceeded. A unit

that has been disqualified from using

the low mass emissions excepted

methodology may subsequently qualify

again as a low mass emissions unit

under paragraph (a)(2) of this section,

provided that if such unit qualified

under paragraph (a)(2)(ii) of this section,

the unit may subsequently qualify again

if the unit meets the requirements of

paragraph (a)(2)(i) of this section.

(c) Low mass emissions excepted

methodology, calculations, and

values.—(1) Operating time. (i) Report

an hourly record if the unit operated for

any portion of the hour or if records are

missing, as to whether or not the unit

operated for any portion of that hour.

(ii) Quarterly operating time (hr) is

equal to the sum of all of the reported

operating hours in the quarter, such that

any hour in which the unit combusted

fuel for any portion of the hour is

considered a full hour.

(iii) Year-to-date cumulative operating

time (hr) is equal to the sum of all of the

reported operating hours in the year to

date, such that any hour in which the

unit combusted fuel for any portion of

the hour is considered a full hour.

(2) Heat input. (i) Hourly heat input

(mmBtu) is equal to the maximum rated

hourly heat input, as defined in § 72.2

of this chapter. However, the owner or

operator of an affected unit may petition

the Administrator under § 75.66 for a

lower value for maximum rated hourly

heat input than that defined in § 72.2 of

this chapter. The Administrator may

approve such lower value if the owner

or operator demonstrates that either the

maximum hourly heat input specified

by the manufacturer or the highest

observed hourly heat input, or both, are

not representative of the unit’s current

capabilities because modifications have

been made to the unit, limiting its

capacity permanently.

(ii) Calculate the quarterly total heat

input (mmBtu) using Equation 7a as

follows:

HIqtr = Tqtr × HIhr

(Eq. 7a)

where:

Tqtr = Actual number of operating hours

in the quarter, in hr.

HIhr = Hourly heat input under

paragraph (c)(2)(i) of this section, in

mmBtu.

(iii) Calculate the year-to-date

cumulative heat input (mmBtu) as the

sum of all of the hourly heat input

values in the year to date.

(3) SO2. (i) Calculate the hourly total

SO2 mass emissions (lbs) using Equation

7b and the appropriate fuel-based SO2

emission factor from Table 1a for the

fuel being burned in that hour. If more

than one fuel is burned in the hour, use

the highest emission factor for all of the

fuels burned in the hour. If records are

missing as to which fuel was burned in

the hour, use the highest emission factor

for all of the fuels capable of being

burned in that unit.

TABLE 1a.—SO2 EMISSION FACTORS

(LB/MMBTU) FOR VARIOUS FUEL TYPES

Fuel type SO2 Emission factors

Pipeline Natural Gas 0.0006 lb/mmBtu.
28124 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

TABLE 1a.—SO2 EMISSION FACTORS

(LB/MMBTU) FOR VARIOUS FUEL

TYPES—Continued

Fuel type SO2 Emission factors

Natural Gas ............... 0.06 lb/mmBtu.

Residual Oil ............... 2.1 lb/mmBtu.

Diesel Fuel ................ 0.5 lb/mmBtu.

WSO2 = EFSO2 x HIhr

(Eq. 7b)

Where:

WSO2 = SO2 mass emissions, in lbs.

EFSO2 = Fuel-based SO2 emission factor

from Table 1a of this section, in lb/

mmBtu.

HIhr = Hourly heat input under

paragraph (c)(2)(i) of this section, in

mmBtu.

(ii) Calculate the quarterly total SO2

mass emissions (tons) by summing all of

the hourly SO2 mass emissions under

paragraph (c)(3)(i) of this section in the

quarter and dividing by 2000 lb/ton.

(iii) Calculate the year-to-date

cumulative SO2 mass emissions (tons)

by summing all of the SO2 mass

emissions under paragraph (c)(3)(i) of

this section in the year to date.

(4) NOX. (i) Determine the hourly NOX

emission rate (lb/mmBtu) by using the

appropriate fuel and boiler type default

NOX emission rate in Table 1b for the

fuel being burned in that hour. If more

than one fuel is burned in the hour, use

the highest emission rate for all of the

fuels burned in the hour. If records are

missing as to which fuel was burned in

the hour, use the highest emission factor

for all of the fuels capable of being

burned in that unit.

TABLE 1b.—NOX EMISSION RATES (LB/MMBTU) FOR VARIOUS BOILER/FUEL TYPES

Boiler type Fuel type NOX Emission rate

Tangentially fired ............................................................................................................. Oil ............................................................... 0.366

Tangentially fired ............................................................................................................. Gas ............................................................. 0.290

Dry Bottom Wall fired ...................................................................................................... Oil ............................................................... 0.490

Dry Bottom Wall fired ...................................................................................................... Gas ............................................................. 0.400

Combustion Turbine ........................................................................................................ Oil ............................................................... 0.258

Combustion Turbine ........................................................................................................ Gas ............................................................. 0.172

Combined Cycle .............................................................................................................. Oil ............................................................... 0.273

Combined Cycle .............................................................................................................. Gas ............................................................. 0.273

(ii) Calculate the hourly total NOX

mass emissions (lbs) as the product of

the NOX emission rate (lb/mmBtu) and

hourly heat input (mmBtu), using

Equation 7c as follows:

WNOX = EFNOX × HIhr

(Eq. 7c)

where:

WNOX = NOX mass emissions, in lbs.

EFNOX = Boiler-type and fuel-type NOX

emission factor from Table 1b of

this section, in lb/mmBtu.

HIhr = Hourly heat input under

paragraph (c)(2)(i) of this section, in

mmBtu.

(iii) Calculate the quarterly average

NOX emission rate (lb/mmBtu) by

summing all of the hourly NOX

emission rates for the quarter and

dividing the total by the number of

reported operating hours under

paragraph (c)(1)(i) of this section in the

quarter.

(iv) Calculate the quarterly total NOX

mass emissions (tons) by summing all of

the hourly NOX mass emissions under

paragraph (c)(4)(ii) of this section in the

quarter and dividing the total by 2000

lb/ton.

(v) Calculate the year-to-date

cumulative average NOX emission rate

(lb/mmBtu) by summing all of the

hourly NOX emission rates for all of the

hours in the year to date and dividing

the total by the number of reported

operating hours under paragraph

(c)(1)(i) of this section in the year to

date.

(vi) Calculate the year-to-date

cumulative NOX mass emissions total

(tons) by summing all of the hourly NOX

mass emissions under paragraph

(c)(4)(ii) of this section in the year to

date.

(5) CO2. (i) Calculate the hourly total

CO2 mass emissions (tons) using

Equation 7d and the appropriate fuelbased CO2 emission factor from Table 1c

for the fuel being burned in that hour.

If more than one fuel is burned in the

hour, use the highest emission factor for

all of the fuels burned in the hour. If

records are missing as to which fuel was

burned in the hour, use the highest

emission factor for all of the fuels

capable of being burned in that unit.

TABLE 1c.—CO2 EMISSION FACTORS

(TON/MMBTU) FOR GAS AND OIL

Fuel type CO2 emission factors

Natural Gas ............... 0.059 ton/mmBtu.

Oil .............................. 0.081 ton/mmBtu.

WCO2=EFCO2 × HIhr

(Eq. 7d)

Where:

WCO2 = CO2 mass emissions, in tons.

EFCO2 = Fuel-based CO2 emission factor

from Table 1c, in ton/mmBtu.

HIhr = Hourly heat input under

paragraph (c)(2)(i) of this section, in

mmBtu.

(ii) Calculate the quarterly total CO2

mass emissions (tons) by summing all of

the hourly CO2 mass emissions under

paragraph (c)(5)(i) of this section in the

quarter.

(iii) Calculate the year-to-date

cumulative CO2 mass emissions (tons)

by summing all of the hourly CO2 mass

emissions under paragraph (c)(5)(i) of

this section in the year to date.

(d) The quality control and quality

assurance requirements in § 75.21 are

not required for a low mass emissions

unit for which the optional low mass

emissions excepted methodology in

paragraph (c) of this section is being

used in lieu of a continuous emission

monitoring system or an excepted

monitoring system under appendix D or

E to this part.

Subpart C—[Amended]

19. Section 75.20 is amended by:

a. Revising the title of the section;

b. Revising the titles of paragraphs

(a)(3), (a)(4), (c), (d), (g), (g)(1), (g)(2),

(g)(4), and (g)(5);

c. Revising paragraphs (a)

introductory text, (a)(1), (a)(3), (a)(4)

introductory text, (a)(4)(i), (a)(4)(ii),

(a)(4)(iii), (a)(5)(i), (b), (c) introductory

text, (c)(1)(iii), (d)(1), (d)(2), (g)

introductory text, (g)(1) introductory

text, (g)(1)(i), (g)(2), (g)(4), and (g)(5);

d. Removing existing paragraph (c)(3);

e. Revising and redesignating existing

paragraphs (c)(4), (c)(5), (c)(6), (c)(7),

and (c)(8) as paragraphs (c)(3), (c)(4),

(c)(8), (c)(9), and (c)(10), respectively;

and revising newly designated

paragraphs (c)(4) introductory text,

(c)(8) introductory text, (c)(8)(i),
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28125

(c)(9)(ii), and (c)(10) introductory text;

and

f. Adding new paragraphs (c)(5),

(c)(6), (c)(7), (g)(6), (g)(7), (h), and (i), to

read as follows:

§ 75.20 Initial certification and

recertification procedures.

(a) Initial certification approval

process. The owner or operator shall

ensure that each continuous emission or

opacity monitoring system required by

this part, which includes the automated

data acquisition and handling system,

and, where applicable, the CO2

continuous emission monitoring system,

meets the initial certification

requirements of this section and shall

ensure that all applicable initial

certification tests under paragraph (c) of

this section are completed by the

deadlines specified in § 75.4 and prior

to use in the Acid Rain Program. In

addition, whenever the owner or

operator installs a continuous emission

or opacity monitoring system in order to

meet the requirements of §§ 75.13

through 75.18, where no continuous

emission or opacity monitoring system

was previously installed, initial

certification is required.

(1) Notification of initial certification

test dates. The owner or operator or

designated representative shall submit a

written notice of the dates of initial

certification testing at the unit as

specified in § 75.61(a)(1).

* * * * *

(3) Provisional approval of

certification (or recertification)

applications. Upon the successful

completion of the required certification

(or recertification) procedures of this

section for each continuous emission or

opacity monitoring system or

component thereof, each continuous

emission or opacity monitoring system

or component thereof shall be deemed

provisionally certified (or recertified) for

use under the Acid Rain Program for a

period not to exceed 120 days following

receipt by the Administrator of the

complete certification (or recertification)

application under paragraph (a)(4) of

this section, provided that no

continuous emission or opacity monitor

systems for a combustion source seeking

to enter the Opt-in Program in

accordance with part 74 of this chapter

shall be deemed provisionally certified

(or recertified) for use under the Acid

Rain Program. Data measured and

recorded by a provisionally certified (or

recertified) continuous emission or

opacity monitoring system or

component thereof, in accordance with

the requirements of appendix B to this

part, will be considered valid qualityassured data (retroactive to the date and

time of provisional certification or

recertification)), provided that the

Administrator does not invalidate the

provisional certification (or

recertification) by issuing a notice of

disapproval within 120 days of receipt

by the Administrator of the complete

certification (or recertification)

application. Note that if the data

validation procedures of paragraph

(b)(3) of this section are applied to the

initial certification (or recertification) of

a continuous emissions monitoring

system, it is possible for data recorded

by the CEMS during the certification (or

recertification) test period to be quality

assured retrospectively, upon

completion of all of the certification (or

recertification) tests. Therefore, in

certain instances, the date and time of

provisional certification (or

recertification) of the CEMS may be

earlier than the date and time of

completion of the required certification

(or recertification) tests.

(4) Certification (or recertification)

application formal approval process.

The Administrator will issue a notice of

approval or disapproval of the

certification (or recertification)

application to the owner or operator

within 120 days of receipt of the

complete certification (or recertification)

application. In the event the

Administrator does not issue such a

written notice within 120 days of

receipt, each continuous emission or

opacity monitoring system which meets

the performance requirements of this

part and is included in the certification

(or recertification) application will be

deemed certified (or recertified) for use

under the Acid Rain Program.

(i) Approval notice. If the certification

(or recertification) application is

complete and shows that each

continuous emission or opacity

monitoring system meets the

performance requirements of this part,

then the Administrator will issue a

written notice of approval of the

certification (or recertification)

application within 120 days of receipt.

(ii) Incomplete application notice. A

certification (or recertification)

application will be considered complete

when all of the applicable information

required to be submitted in § 75.63 has

been received by the Administrator, the

EPA Regional Office, and the

appropriate State and/or local air

pollution control agency. If the

certification (or recertification)

application is not complete, then the

Administrator will issue a written

notice of incompleteness that provides a

reasonable timeframe for the designated

representative to submit the additional

information required to complete the

certification (or recertification)

application. If the designated

representative has not complied with

the notice of incompleteness by a

specified due date, then the

Administrator may issue a notice of

disapproval specified under paragraph

(a)(4)(iii) of this section. The 120-day

review period shall not begin prior to

receipt of a complete application.

(iii) Disapproval notice. If the

certification (or recertification)

application shows that any continuous

emission or opacity monitoring system

or component thereof does not meet the

performance requirements of this part,

or if the certification (or recertification)

application is incomplete and the

requirement for disapproval under

paragraph (a)(4)(ii) of this section has

been met, the Administrator shall issue

a written notice of disapproval of the

certification (or recertification)

application within 120 days of receipt.

By issuing the notice of disapproval, the

provisional certification (or

recertification) is invalidated by the

Administrator, and the data measured

and recorded by each uncertified

continuous emission or opacity

monitoring system or component

thereof shall not be considered valid

quality-assured data beginning with the

following time: from the hour of the

probationary calibration error test that

began the initial certification (or

recertification) test period, if the data

validation procedures of paragraph

(b)(3) of this section were used to

retrospectively validate data; or from the

date and time of completion of the

invalid certification tests until the date

and time that the owner or operator

completes subsequently approved initial

certification tests, if the data validation

procedures of paragraph (b)(3) of this

section were not used. The owner or

operator shall follow the procedures for

loss of initial certification in paragraph

(a)(5) of this section for each continuous

emission or opacity monitoring system

or component thereof which is

disapproved for initial certification. For

each disapproved recertification, the

owner or operator shall follow the

procedures of paragraph (b)(5) of this

section.

* * * * *

(5) * * *

(i) Until such time, date, and hour as

the continuous emission monitoring

system or component thereof can be

adjusted, repaired, or replaced and

certification tests successfully

completed, the owner or operator shall

substitute the following values, as

applicable, for each hour of unit

operation during the period of invalid
28126 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

data specified in paragraph (a)(4)(iii) of

this section or in § 75.21: the maximum

potential concentration of SO2 as

defined in section 2.1.1.1 of appendix A

to this part to report SO2 concentration;

the maximum potential NOX emission

rate, as defined in § 72.2 of this chapter

to report NOX emissions; the maximum

potential flow rate, as defined in section

2.1.4.1 of appendix A to this part to

report volumetric flow; or the maximum

potential concentration of CO2, as

defined in section 2.1.3.1 of appendix A

to this part to report CO2 concentration

data; and

* * * * *

(b) Recertification approval process.

Whenever the owner or operator makes

a replacement, modification, or change

in a certified continuous emission

monitoring system or continuous

opacity monitoring system that is

determined by the Administrator to

significantly affect the ability of the

system to accurately measure or record

the SO2 or CO2 concentration, stack gas

volumetric flow rate, NOX emission rate,

or opacity, or to meet the requirements

of § 75.21 or appendix B to this part, the

owner or operator shall recertify the

continuous emission monitoring system

or continuous opacity monitoring

system, according to the procedures in

this paragraph. Furthermore, whenever

the owner or operator makes a

replacement, modification, or change to

the flue gas handling system or the unit

operation that is determined by the

Administrator to significantly change

the flow or concentration profile, the

owner or operator shall recertify the

monitoring system according to the

procedures in this paragraph. Examples

of changes which require recertification

include: replacement of the analyzer;

change in location or orientation of the

sampling probe or site; changing of flow

rate monitor polynomial coefficients;

and complete replacement of an existing

continuous emission monitoring system

or continuous opacity monitoring

system. The owner or operator shall

recertify a continuous opacity

monitoring system whenever the

monitor path length changes or as

required by an applicable State or local

regulation or permit. Any change to a

stack flow rate or gas monitoring system

for which the Administrator determines

that a RATA is not necessary shall not

be considered a recertification event. In

such cases, any other tests that the

Administrator determines to be

necessary (linearity checks, calibration

error tests, DAHS verifications, etc.)

shall be performed as diagnostic tests,

rather than recertification tests. The data

validation procedures in paragraph

(b)(3) of this section shall be applied to

linearity checks, 7-day calibration error

tests, and cycle time tests when these

are required as diagnostic tests. When

the data validation procedures of

paragraph (b)(3) of this section are

applied in this manner, replace the

word ‘‘recertification’’ with the word

‘‘diagnostic.’’

(1) Tests required. For recertification

testing after changing the flow rate

monitor polynomial coefficients, the

owner or operator shall complete a 3-

level RATA. For all other recertification

testing, the owner or operator shall

complete all initial certification tests in

paragraph (c) of this section that are

applicable to the monitoring system,

except as otherwise approved by the

Administrator.

(2) Notification of recertification test

dates. The owner, operator, or

designated representative shall submit

notice of testing dates for recertification

under this paragraph as specified in

§ 75.61(a)(1)(ii), unless all of the tests in

paragraph (c) of this section are required

for recertification, in which case the

owner or operator shall provide notice

in accordance with the notice

provisions for initial certification testing

in § 75.61(a)(1)(i).

(3) Recertification test period

requirements and data validation. (i) In

the period extending from the hour of

the replacement, modification or change

made to a monitoring system that

triggers the need to perform

recertification test(s) of the CEMS to the

hour of successful completion of a

probationary calibration error test

(according to paragraph (b)(3)(ii) of this

section) following the replacement,

modification, or change to the CEMS,

the owner or operator shall either

substitute for missing data, according to

the standard missing data procedures in

§§ 75.33 through 75.37, or report

emission data using a reference method

or another monitoring system that has

been certified or approved for use under

this part.

(ii) Once the modification or change

to the CEMS has been completed and all

of the associated repairs, component

replacements, adjustments,

linearization, and reprogramming of the

CEMS have been completed, a

probationary calibration error test is

required to establish the beginning point

of the recertification test period. In this

instance, the first successful calibration

error test of the monitoring system

following completion of all necessary

repairs, component replacements,

adjustments, reprogramming, and any

preliminary tests (e.g., trial RATA runs

or a challenge of the monitor with

calibration gases other than those used

to perform the daily calibration error

test) shall be the probationary

calibration error test. The probationary

calibration error test must be passed

before any of the required recertification

tests are commenced.

(iii) Beginning with the hour of

commencement of a recertification test

period, emission data recorded by the

CEMS are considered to be

conditionally valid, contingent upon the

results of the subsequent recertification

tests.

(iv) Each required recertification test

shall be completed no later than the

following number of unit operating

hours after the probationary calibration

error test that initiates the test period:

(A) For a linearity test and/or cycle

time test, 168 consecutive unit operating

hours;

(B) For a RATA (whether normal-load

or multiple-load), 720 consecutive unit

operating hours; and

(C) For a 7-day calibration error test,

21 consecutive unit operating days.

(v) All recertification tests shall be

performed hands-off, as follows. No

adjustments to the calibration of the

CEMS, other than the adjustments

described in section 2.1.3 of appendix B

to this part, are permitted prior to or

during the recertification test period.

Routine daily calibration error tests

shall be performed throughout the

recertification test period, in accordance

with section 2.1.1 of appendix B to this

part. The additional calibration error

test requirements in section 2.1.3 of

appendix B to this part shall also apply

during the recertification test period.

(vi) If all of the required

recertification tests and required daily

calibration error tests are successfully

completed in succession with no

failures, and if each recertification test

is completed within the time period

specified in paragraph (b)(3)(iv)(A), (B),

or (C) of this section, then all of the

conditionally valid emission data

recorded by the CEMS shall be

considered quality assured, from the

hour of commencement of the

recertification test period until the hour

of completion of the required test(s).

(vii) If a required recertification test is

failed or aborted due to a problem with

the CEMS, or if a calibration error test

is failed during a recertification test

period, data validation shall be done as

follows:

(A) If any required recertification test

is failed, it shall be repeated. If any

recertification test other than a 7-day

calibration error test is failed or aborted

due to a problem with the CEMS, the

original recertification test period is

ended, and a new recertification test

period must be commenced with a
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28127

probationary calibration error test. The

tests that are required in this new

recertification test period will include

any tests that were required for the

initial recertification event which were

not successfully completed and any

recertification or diagnostic tests that

are required as a result of changes made

to the monitoring system to correct the

problems that caused the failure of the

recertification test. The new

recertification test sequence shall not be

commenced until all necessary

maintenance activities, adjustments,

linearizations, and reprogramming of

the CEMS have been completed;

(B) If a linearity test, RATA, or cycle

time test is failed or aborted due to a

problem with the CEMS, all

conditionally valid emission data

recorded by the CEMS are invalidated,

from the hour of commencement of the

recertification test period to the hour in

which the test is failed or aborted. Data

from the CEMS remain invalid until the

hour in which a new recertification test

period is commenced, following

corrective action, and a probationary

calibration error test is passed, at which

time the conditionally valid status of

emission data from the CEMS begins;

(C) If a 7-day calibration error test is

failed within the recertification test

period, previously-recorded

conditionally valid emission data from

the CEMS are not invalidated, provided

that the calibration error on the day of

the failed 7-day calibration error test

does not exceed twice the performance

specification in section 3 of appendix A

to this part; and

(D) If a calibration error test is failed

(i.e., the results of the test exceed twice

the performance specification in section

3 of appendix A to this part) during a

recertification test period, the CEMS is

out-of-control as of the hour in which

the calibration error test is failed.

Emission data from the CEMS shall be

invalidated prospectively from the hour

of the failed calibration error test until

the hour of completion of a subsequent

successful calibration error test

following corrective action, at which

time the conditionally valid status of

data from the monitoring system

resumes. Failure to perform a required

daily calibration error test during a

recertification test period shall also

cause data from the CEMS to be

invalidated prospectively, from the hour

in which the calibration error test was

due until the hour of completion of a

subsequent successful calibration error

test. Previously-passed recertification

tests in the sequence and previouslyrecorded conditionally valid data shall

not be affected by a late calibration error

test. Whenever a calibration error test is

failed or missed during a recertification

test period, no further recertification

tests shall be performed until the

required subsequent calibration error

has been passed, re-establishing the

conditionally valid status of data from

the monitoring system.

(viii) If any required recertification

test is not completed within its allotted

time period, data validation shall be

done as follows. For a late linearity test,

RATA, or cycle time test that is passed

on the first attempt, data from the

monitoring system shall be invalidated

from the hour of expiration of the

recertification test period until the hour

of completion of the late test. For a late

7-day calibration error test, whether or

not it is passed on the first attempt, data

from the monitoring system shall also be

invalidated from the hour of expiration

of the recertification test period until

the hour of completion of the late test.

For a late linearity test, RATA, or cycle

time test that is failed on the first

attempt or aborted on the first attempt

due to a problem with the monitor, all

conditionally valid data from the

monitoring system shall be considered

invalid back to the hour of the first

probationary calibration error test which

initiated the recertification test period.

Data from the monitoring system shall

remain invalid until the hour of

successful completion of the late

recertification test and any additional

recertification or diagnostic tests that

are required as a result of changes made

to the monitoring system to correct

problems that caused failure of the late

recertification test.

(ix) If any required recertification test

of a monitoring system has not been

completed by the end of a calendar

quarter and if data contained in the

quarterly report is conditionally valid

pending the results of test(s) to be

completed in a subsequent quarter, the

owner or operator shall indicate this by

means of a suitable conditional data flag

in the electronic quarterly report for that

quarter. The owner or operator shall

resubmit the report for that quarter if the

required recertification test is

subsequently failed. In the resubmitted

report, the owner or operator shall use

the appropriate missing data routine in

§ 75.31 or § 75.33 to replace with

substitute data each hour of

conditionally valid data that was

invalidated by the failed recertification

test. In addition, if the owner or

operator submits any conditionally

valid data (as defined in § 72.2 of this

chapter) in any of the four quarterly

reports for a given year, the owner or

operator shall indicate the status of the

conditionally valid data (i.e., resolved or

unresolved) in the annual compliance

certification report required under

§ 72.90 of this chapter for that year.

Alternatively, if any required

recertification test is not completed by

the end of a particular calendar quarter

but is completed no later than 30 days

after the end of that quarter (i.e., prior

to the deadline for submitting the

quarterly report under § 75.64), the test

data and results may be submitted with

the earlier quarterly report even though

the test date(s) are from the next

calendar quarter. In such instances, if

the recertification test(s) are passed in

accordance with the provisions of

paragraph (b)(3) of this section,

conditionally valid data may be

reported as quality-assured, in lieu of

reporting a conditional data flag. If the

recertification test(s) is failed and if

conditionally valid data are replaced, as

appropriate, with substitute data, then

neither the reporting of a conditional

data flag nor resubmission is required.

(x) If the replacement, modification,

or change requiring recertification of the

CEMS is such that the data collected by

the prior certified monitoring system are

no longer representative, such as after a

change to the flue gas handling system

or unit operation that requires changing

the span value to be consistent with

section 2.1 of appendix A to this part,

the owner or operator shall substitute

for missing data as follows, in the

period extending from the hour of

commencement of the replacement,

modification, or change requiring

recertification of the CEMS to the hour

of commencement of the recertification

test period:

(A) For a change that results in a

significantly higher concentration or

flow rate, substitute maximum potential

values according to the procedures in

paragraph (a)(5) of this section; or

(B) For a change that results in a

significantly lower concentration or

flow rate, substitute data using the

standard missing data procedures.

(C) The owner or operator shall then

use the initial missing data procedures

in § 75.31, beginning with the first hour

of quality assured data obtained with

the recertified monitoring system,

unless otherwise provided by § 75.34 for

units with add-on emission controls.

(4) Recertification application. The

designated representative shall apply for

recertification of each continuous

emission or opacity monitoring system

used under the Acid Rain Program. The

owner or operator shall submit the

recertification application in accordance

with § 75.60, and each complete

recertification application shall include

the information specified in § 75.63.

(5) Approval or disapproval of request

for recertification. The procedures for
28128 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

provisional certification in paragraph

(a)(3) of this section shall apply to

recertification applications. The

Administrator will issue a written

notice of approval or disapproval

according to the procedures in

paragraph (a)(4) of this section. In the

event that a recertification application is

disapproved, data from the monitoring

system are invalidated and the

applicable missing data procedures in

§ 75.31 or § 75.33 shall be used from the

date and hour of receipt of such notice

back to the hour of the probationary

calibration error test that began the

recertification test period. Data from the

monitoring system remain invalid until

a subsequent probationary calibration

error test is passed, beginning a new

recertification test period. The owner or

operator shall repeat all recertification

tests or other requirements, as indicated

in the Administrator’s notice of

disapproval, no later than 30 unit

operating days after the date of issuance

of the notice of disapproval. The

designated representative shall submit a

notification of the recertification retest

dates, as specified in § 75.61(a)(1)(ii),

and shall submit a new recertification

application according to the procedures

in paragraph (b)(4) of this section.

(c) Initial certification and

recertification procedures. Prior to the

deadline in § 75.4, the owner or operator

shall conduct initial certification tests

and in accordance with § 75.63, the

designated representative shall submit

an application to demonstrate that the

continuous emission or opacity

monitoring system and components

thereof meet the specifications in

appendix A to this part. The owner or

operator shall compare reference

method values with output from the

automated data acquisition and

handling system that is part of the

continuous emission monitoring system

being tested. Except as specified in

paragraphs (b)(1), (d), and (e) of this

section, the owner or operator shall

perform the following tests for initial

certification or recertification of

continuous emission or opacity

monitoring systems or components

according to the requirements of

appendix A to this part:

(1) * * *

(iii) A relative accuracy test audit. For

the NOX-diluent system, the RATA shall

be done on a system basis, in units of

lb/mmBtu.

* * * * *

(3) The initial certification test data

from an O2-or a CO2-diluent gas monitor

certified for use in a NOX continuous

emission monitoring system may be

submitted to meet the requirements of

paragraph (c)(4) of this section. Also, for

a diluent monitor that is used both as a

CO2 monitoring system and to

determine heat input, only one set of

diluent monitor certification data need

be submitted (under the component and

system identification numbers of the

CO2 monitoring system).

(4) For each CO2 pollutant

concentration monitor, each O2 monitor

which is part of a CO2 continuous

emission monitoring system, each

diluent monitor used to monitor heat

input and each SO2-diluent continuous

emission monitoring system:

* * * * *

(5) For each continuous moisture

monitoring system consisting of wet-and

dry-basis O2 analyzers:

(i) A 7-day calibration error test of

each O2 analyzer;

(ii) A cycle time test of each O2

analyzer;

(iii) A linearity test of each O2

analyzer; and

(iv) A RATA, directly comparing the

percent moisture measured by the

monitor to a reference method.

(6) For each continuous moisture

sensor:

(i) A 7-day calibration error test; and

(ii) A RATA, directly comparing the

percent moisture measured by the

monitor sensor to a reference method.

(7) For a continuous moisture

monitoring system consisting of a

temperature sensor and a data

acquisition and handling system

(DAHS) software component

programmed with a moisture lookup

table:

(i) A demonstration that the correct

moisture value for each hour is being

taken from the moisture lookup tables

and applied to the emission

calculations. At a minimum, the

demonstration shall be made at three

different temperatures covering the

normal range of stack temperatures.

(ii) [Reserved]

(8) The owner or operator shall ensure

that initial certification or recertification

of a continuous opacity monitor for use

under the Acid Rain Program is

conducted according to one of the

following procedures:

(i) Performance of the tests for initial

certification or recertification, according

to the requirements of Performance

Specification 1 in appendix B to part 60

of this chapter; or

* * * * *

(9) * * *

(ii) Proper computation and

application of the missing data

substitution procedures in subpart D of

this part and the bias adjustment factors

in section 7 of appendix A to this part.

(10) The owner or operator shall

provide, or cause to be provided,

adequate facilities for initial

certification or recertification testing

that include:

* * * * *

(d) Initial certification and

recertification and quality assurance

procedures for optional backup

continuous emission monitoring

systems.

(1) Redundant backups. The owner or

operator of an optional redundant

backup continuous emission monitoring

system shall comply with all the

requirements for initial certification and

recertification according to the

procedures specified in paragraphs (a),

(b), and (c) of this section. The owner

or operator shall operate the redundant

backup continuous emission monitoring

system during all periods of unit

operation, except for periods of

calibration, quality assurance,

maintenance, or repair. The owner or

operator shall perform upon the

redundant backup continuous emission

monitoring system all quality assurance

and quality control procedures specified

in appendix B to this part, except that

the daily assessments in section 2.1 of

appendix B to this part are optional for

days on which the redundant backup

monitoring system is not used to report

emission data under this part. For any

day on which a redundant backup

monitoring system is used to report

emission data, the system must meet all

of the applicable daily assessment

criteria in appendix B to this part.

(2) Non-redundant backups. The

owner or operator of an optional nonredundant backup continuous emission

monitoring system shall comply with all

of the following requirements for initial

certification, quality assurance,

recertification, and data reporting:

(i) For a non-redundant backup gas

monitoring system that has its own

separate probe, sample interface, and

analyzer or for a non-redundant backup

flow monitor, all of the tests in

paragraph (c) of this section are required

for initial certification of the system,

except for the 7-day calibration error

test.

(ii) For a non-redundant backup gas

monitoring system consisting of one or

more like-kind replacement analyzers

that use the same probe and sample

interface as a primary monitoring

system, no initial certification of the

non-redundant backup monitoring

system is required. Note that a nonredundant backup analyzer, connected

to the same probe and interface as a

primary analyzer in order to satisfy the

dual span requirements of section
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28129

2.1.1.4 or 2.1.2.4 of appendix A to this

part, shall be considered a like-kind,

non-redundant backup analyzer.

(iii) Each non-redundant backup

monitoring system shall comply with

the daily and quarterly quality

assurance and quality control

requirements in appendix B to this part

for each day and quarter that the nonredundant backup monitoring system is

used to report data, except that the

requirements for when a linearity test

must be performed are superseded by

the requirements of this section. The

owner or operator shall ensure that each

non-redundant backup continuous

emission monitoring system passes a

linearity check (for pollutant

concentration and diluent gas monitors)

or a calibration error test (for flow

monitors) prior to each use for recording

and reporting emissions. For a nonredundant backup NOX-diluent or SO2-

diluent monitoring system consisting of

a primary pollutant analyzer and a likekind replacement diluent analyzer (or

vice-versa), provided that the primary

analyzer is operating and is not out-ofcontrol with respect to any of its quality

assurance requirements, only the likekind replacement analyzer must pass a

linearity check before the system is used

for data reporting. When a nonredundant backup monitoring system is

brought into service prior to conducting

the linearity test, a probationary

calibration error test (as described in

paragraph (b)(3)(ii) of this section),

which will begin a period of

conditionally valid data, may be

performed in order to allow the use of

data retrospectively, as follows.

Conditionally valid data from the CEMS

are validated back to the hour of

completion of the probationary

calibration error test if the following

conditions are met: if no adjustments

are made to the monitor other than

those specified in section 2.1.3 of

appendix B to this part between the

probationary calibration error test and

the successful completion of the

linearity test, and if the linearity test is

passed within 168 unit operating hours

of the probationary calibration error test.

However, if the linearity test is either

failed, aborted due to a problem with

the CEMS, or not completed as required,

then all of the conditionally valid data

are invalidated back to the hour of the

probationary calibration error test, and

data from the CEMS remain invalid

until the hour of completion of a

successful linearity test.

(iv) When data are reported from a

non-redundant backup monitoring

system, the appropriate bias adjustment

factor (BAF) shall be determined as

follows:

(A) Apply the BAF from the most

recent RATA of the non-redundant

backup system (even if that RATA was

done more than 12 months previously);

or

(B) If no RATA results are available

for the non-redundant backup system

(e.g., for a non-redundant backup gas

monitoring system that uses the same

probe and sample interface as the

primary monitoring system), apply the

primary monitoring system BAF.

(v) A non-redundant backup system

may not be used for reporting data from

a particular affected unit or common

stack for more than 720 hours in any

one calendar year, unless the

monitoring system passes a RATA at

that same unit or stack.

(vi) For each non-redundant backup

gas monitoring system that has its own

separate probe, sample interface, and

analyzer and for each non-redundant

backup flow monitor, no more than

eight successive calendar quarters shall

elapse following the quarter in which

the last RATA of the monitoring system

was done at a particular unit or stack,

without performing a subsequent RATA.

Otherwise, the monitoring system may

not be used to report data from that unit

or stack until the hour of completion of

a successful RATA at that location.

* * * * *

(g) Initial certification and

recertification procedures for excepted

monitoring systems under appendices D

and E. The owner or operator of a gasfired unit, oil-fired unit, or diesel-fired

unit using the optional protocol under

appendix D or E to this part shall ensure

that an excepted monitoring system

under appendix D or E to this part meets

the applicable general operating

requirements of § 75.10, the applicable

requirements of appendices D and E to

this part, and the initial certification or

recertification requirements of this

paragraph.

(1) Initial certification and

recertification testing. The owner or

operator shall use the following

procedures for initial certification and

recertification of an excepted

monitoring system under appendix D or

E to this part.

(i) When the optional SO2 mass

emissions estimation procedure in

appendix D to this part or the optional

NOX emissions estimation protocol in

appendix E to this part is used, the

owner or operator shall provide data

from a flowmeter accuracy test (or shall

provide a statement of calibration if the

flowmeter meets the accuracy standard

by design) for each fuel flowmeter,

according to the appropriate calibration

procedures using one of the following

standard methods: ASME MFC–3M–

1989 with September 1990 Errata,

‘‘Measurement of Fluid Flow in Pipes

Using Orifice, Nozzle, and Venturi’’;

ASME MFC–4M–1986 (Reaffirmed

1990) ‘‘Measurement of Gas Flow by

Turbine Meters’’; ASME MFC–5M–

1985, ‘‘Measurement of Liquid Flow in

Closed Conduits Using Transit-Time

Ultrasonic Flowmeters’’; ASME MFC–

6M–1987 with June 1987 Errata,

‘‘Measurement of Fluid Flow in Pipes

Using Vortex Flow Meters’’; ASME

MFC–7M–1987 (Reaffirmed 1992),

‘‘Measurement of Gas Flow by Means of

Critical Flow Venturi Nozzles’’; ASME

MFC–9M–1988 with December 1989

Errata, ‘‘Measurement of Liquid Flow in

Closed Conduits by Weighing Method’’;

ISO 8316: 1987(E) ‘‘Measurement of

Liquid Flow in Closed Conduits—

Method by Collection of the Liquid in

a Volumetric Tank’’; Section 8,

Calibration from American Gas

Association Transmission Measurement

Committee Report No. 7: Measurement

of Gas by Turbine Meters (1985 Edition);

American Gas Association Report No. 3:

Orifice Metering of Natural Gas and

Other Related Hydrocarbon Fluids Part

1: General Equations and Uncertainty

Guidelines (October 1990 Edition), Part

2: Specification and Installation

Requirements (February 1991 Edition),

and Part 3: Natural Gas Applications

(August 1992 Edition), excluding the

modified calculation procedures of Part

3; or American Petroleum Institute (API)

Section 2, ‘‘Conventional Pipe Provers,’’

from Chapter 4 of the Manual of

Petroleum Measurement Standards,

October 1988 (Reaffirmed 1993), as

required by appendices D and E to this

part (all methods incorporated by

reference under § 75.6).

* * * * *

(2) Initial certification and

recertification testing notification. The

designated representative shall provide

initial certification testing notification

and periodic retesting notification for an

excepted monitoring system under

appendix E to this part as specified in

§ 75.61. The designated representative

shall submit recertification testing

notification, as specified in § 75.61, for

quality assurance related NOX emission

rate testing under section 2.3 of

appendix E to this part for an excepted

monitoring system under appendix E to

this part. Initial certification testing

notification or periodic retesting

notification is not required for testing of

a fuel flowmeter or for testing of an

excepted monitoring system under

appendix D to this part.

* * * * *
28130 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

(4) Initial certification or

recertification application. The

designated representative shall submit

an initial certification or recertification

application in accordance with §§ 75.60

and 75.63.

(5) Provisional approval of initial

certification and recertification

applications. Upon the successful

completion of the required initial

certification or recertification

procedures for each excepted

monitoring system under appendix D or

E to this part, each excepted monitoring

system under appendix D or E to this

part shall be deemed provisionally

certified for use under the Acid Rain

Program during the period for the

Administrator’s review. The provisions

for the initial certification or

recertification application formal

approval process in paragraph (a)(4) of

this section shall apply, except that

‘‘continuous emission or opacity

monitoring system’’ shall be replaced

with ‘‘excepted monitoring system’’ and

except that ‘‘shall follow the procedures

for loss of initial certification in

paragraph (a)(5)’’ or ‘‘shall follow the

procedures of paragraph (b)(5)’’ shall be

replaced with ‘‘shall follow the

procedures for loss of certification in

paragraph (g)(7)’’. Data measured and

recorded by a provisionally certified

excepted monitoring system under

appendix D or E to this part will be

considered quality assured data from

the date and time of completion of the

last initial certification or recertification

test, provided that the Administrator

does not revoke the provisional

certification by issuing a notice of

disapproval in accordance with the

provisions in paragraph (a)(4) or (b)(5)

of this section.

(6) Recertification requirements.

Recertification of an excepted

monitoring system under appendix D or

E to this part is required for any

modification to the system or change in

operation that could significantly affect

the ability of the system to accurately

account for emissions and for which the

Administrator determines that an

accuracy test of the fuel flowmeter or a

retest under appendix E to this part to

re-establish the NOX correlation curve is

required. Examples of such changes or

modifications include fuel flowmeter

replacement, changes in unit

configuration, or exceedance of

operating parameters.

(7) Procedures for loss of certification

or recertification for excepted

monitoring systems under appendices D

and E to this part. In the event that a

certification or recertification

application is disapproved for an

excepted monitoring system, data from

the monitoring system are invalidated,

and the applicable missing data

procedures in section 2.4 of appendix D

or section 2.5 of appendix E to this part

shall be used from the date and hour of

receipt of such notice back to the hour

of the provisional certification. Data

from the excepted monitoring system

remain invalid until all required tests

are repeated and the excepted

monitoring system is again

provisionally certified. The owner or

operator shall repeat all certification or

recertification tests or other

requirements, as indicated in the

Administrator’s notice of disapproval,

no later than 30 unit operating days

after the date of issuance of the notice

of disapproval. The designated

representative shall submit a

notification of the certification or

recertification retest dates if required

under paragraph (g)(2) of this section

and shall submit a new certification or

recertification application according to

the procedures in paragraph (g)(4) of

this section.

(h) Initial certification and

recertification procedures for low mass

emission units using the excepted

methodologies under § 75.19. The owner

or operator of a gas-fired, oil-fired, or

diesel-fired unit using the optional low

mass emissions excepted methodologies

under § 75.19 shall meet the applicable

general operating requirements of

§ 75.10, the applicable requirements of

§ 75.19, and the applicable certification

requirements of this paragraph (h).

(1) Monitoring plan. The designated

representative shall submit a monitoring

plan in accordance with §§ 75.53 and

75.62.

(2) Certification application. The

designated representative shall submit a

certification application in accordance

with § 75.63(a)(1)(iii).

(3) Approval of certification

applications. Upon submission of the

required certification application for

approval to use the low mass emissions

excepted methodology under § 75.19,

the excepted methodology shall be

deemed provisionally certified for use

under the Acid Rain Program during the

period for the Administrator’s review.

The provisions for the certification

application formal approval process in

the introductory text of paragraph (a)(4)

and in paragraphs (a)(4)(i), (ii), and (iv)

of this section shall apply, except that

‘‘continuous emission or opacity

monitoring system’’ shall be replaced

with ‘‘excepted methodology.’’

(4) Disapproval of certification

applications. If the Administrator

determines that the certification

application does not demonstrate that

the unit meets the requirements of

§§ 75.19(a) and (b), the Administrator

shall issue a written notice of

disapproval of the certification

application within 120 days of receipt.

By issuing the notice of disapproval, the

provisional certification is invalidated

by the Administrator, and the data

recorded under the excepted

methodology shall not be considered

valid. The owner or operator shall

follow the procedures for loss of

certification:

(i) The owner or operator shall

substitute the following values, as

applicable, for each hour of unit

operation during the period of invalid

data specified in paragraph (a)(4)(iii) of

this section or in §§ 75.21(e)

(introductory paragraph) and

75.21(e)(1): the maximum potential

concentration of SO2, as defined in

section 2.1 of appendix A to this part to

report SO2 concentration; the maximum

potential NOX emission rate, as defined

in § 72.2 of this chapter to report NOX

emissions; the maximum potential flow

rate, as defined in section 2.1 of

appendix A to this part to report

volumetric flow; or the maximum CO2

concentration used to determine the

maximum potential concentration of

SO2 in section 2.1.1.1 of appendix A to

this part to report CO2 concentration

data until such time, date, and hour as

a continuous emission monitoring

system or excepted monitoring system,

where applicable, is installed and

provisionally certified;

(ii) The designated representative

shall submit a notification of

certification test dates, as specified in

§ 75.61(a)(1)(ii), and a new certification

application according to the procedures

in paragraph (a)(2) of this section; and

(iii) The owner or operator shall

install and provisionally certify

continuous emission monitoring

systems or excepted monitoring

systems, where applicable, no later than

180 unit operating days after the date of

issuance of the notice of disapproval.

(i) Initial certification and

recertification procedures for excepted

flow monitoring systems under

appendix I. The owner or operator of a

gas-fired unit, oil-fired unit, or dieselfired unit using the optional protocol

under appendix I to this part shall

ensure that an excepted flow monitoring

system under appendix I to this part

meets the applicable general operating

requirements of § 75.10, the applicable

requirements of appendix I to this part,

and the initial certification and

recertification requirements of this

paragraph.

(1) Initial certification and

recertification testing. The owner or

operator shall, where applicable, use the
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28131

following procedures for certification

and recertification of an excepted flow

monitoring system under appendix I to

this part.

(i) For an excepted flow monitoring

system under appendix I to this part

where each component is tested

separately, perform the following tests

on each O2 or CO2 component monitor:

(A) 7-day calibration error test;

(B) Linearity check;

(C) Cycle time test;

(D) Relative accuracy test audit using

Test Method 3A from appendix A to

part 60 of this chapter; and

(E) Bias test.

(ii) For an excepted flow monitoring

system under appendix I to this part

where each component is tested

separately, meet the certification

procedures under paragraph (g)(1)(i) of

this section and the recertification

procedures under paragraph (g)(6) of

this section on each fuel flowmeter

component using the standards

specified, or meet the testing procedure

under section 2.1.5.2 of appendix D to

this part.

(iii) For an excepted flow monitoring

system under appendix I to this part

that is tested as an entire system,

perform the following tests:

(A) 7-day calibration error test on the

O2 or CO2 monitor,

(B) Linearity check on the O2 or CO2

monitor,

(C) Cycle time test on the O2 or CO2

monitor,

(D) Relative accuracy test audit on the

entire excepted flow monitoring system

under appendix I to this part, using Test

Method 2 (or its allowable alternatives)

from appendix A to part 60 of this

chapter, and

(E) Bias test on the entire excepted

flow monitoring system under appendix

I to this part.

(iv) For the automated data

acquisition and handling system used as

part of an excepted flow monitoring

system under appendix I to this part, the

owner or operator shall perform tests

designed to verify:

(A) The proper computation of hourly

averages for volumetric flow rates, heat

input, and pollutant mass emissions;

and

(B) The proper computation and

application of the missing data

substitution procedures for volumetric

flow in subpart D of this part.

(2) Initial certification and

recertification testing notification. The

designated representative shall provide

initial certification and recertification

testing notification for an excepted flow

monitoring system under appendix I to

this part, as specified in § 75.61, for any

relative accuracy test audit.

(3) Monitoring plan. The designated

representative shall submit a monitoring

plan in accordance with §§ 75.53 and

75.62. For a unit that previously had a

flow monitoring system or an excepted

monitoring system under appendix D to

this part and later submits a revised

monitoring plan for an excepted flow

monitoring system under appendix I to

this part, the designated representative

shall submit the revised monitoring

plan no later than 45 days prior to the

first day of certification testing.

(4) Certification or recertification

application. The designated

representative shall submit an initial

certification or recertification

application in accordance with §§ 75.60

and 75.63.

(5) Approval of initial certification

and recertification applications. Upon

successful completion of the required

initial certification or recertification

procedures for each excepted

monitoring system under appendix I to

this part, each excepted monitoring

system under appendix I to this part

shall be deemed provisionally certified

for use under the Acid Rain Program

during the period for the

Administrator’s review. The provisions

for the initial certification (or

recertification) application formal

approval process in paragraph (a)(4) of

this section shall apply, except that

‘‘continuous emission or opacity

monitoring system’’ shall be replaced

with ‘‘excepted monitoring system’’ and

except that ‘‘shall follow the procedures

for loss of initial certification in

paragraph (a)(5)’’ or ‘‘shall follow the

procedures of paragraph (b)(5)’’ shall be

replaced with ‘‘shall follow the

procedures for loss of certification in

paragraph (i)(7)’’. Data measured and

recorded by a provisionally certified

excepted monitoring system under

appendix I to this part will be

considered quality assured data from

the date and time of completion of the

final certification test, provided that the

Administrator does not revoke the

provisional certification by issuing a

notice of disapproval within 120 days of

receipt of the complete initial

certification or recertification

application in accordance with the

provisions in paragraph (a)(4) of this

section.

(6) Recertification requirements. A

recertification of an excepted flow

monitoring system under appendix I to

this part is required for any

modification to the equipment used in

the appendix I excepted flow

monitoring system that would require

recertification under paragraph (b) or (g)

of this section.

(7) Procedures for loss of certification

for excepted monitoring systems under

appendix I to this part. In the event that

a certification or recertification

application is disapproved for an

excepted monitoring system under

appendix I to this part, data from the

monitoring system are invalidated, and

the applicable missing data procedures

in section 4 of appendix I to this part

shall be used from the date and hour of

receipt of such notice back to the hour

of the provisional certification. Data

from the excepted monitoring system

remain invalid until all required tests

are repeated and the excepted

monitoring system is again

provisionally certified. The owner or

operator shall repeat all certification or

recertification tests or other

requirements, as indicated in the

Administrator’s notice of disapproval,

no later than 30 unit operating days

after the date of issuance of the notice

of disapproval. The designated

representative shall submit a

notification of the certification or

recertification retest dates, if required

under paragraph (i)(2) of this section,

and shall submit a new certification or

recertification application according to

the procedures in paragraph (i)(4) of this

section.

20. Section 75.21 is amended by:

a. Revising paragraphs (a)(2), (a)(4),

(a)(5), (a)(6) and (e);

b. Redesignating existing paragraphs

(a)(7) and (a)(8) as paragraphs (a)(9) and

(a)(10), respectively; revising newly

designated paragraph (a)(9); and

c. Adding new paragraphs (a)(7),

(a)(8), and (f), to read as follows:

§ 75.21 Quality assurance and quality

control requirements.

(a) * * *

(2) The owner or operator shall ensure

that each non-redundant backup

continuous emission monitoring system

meets the quality assurance

requirements of § 75.20(d) for each day

and quarter that the system is used to

report data.

* * * * *

(4) When a unit combusts only natural

gas or gaseous fuel with a total sulfur

content no greater than the total sulfur

content of natural gas and SO2

emissions are determined in accordance

with § 75.11(e)(3), the owner or operator

of a unit with an SO2 continuous

emission monitoring system is not

required to perform the daily or

quarterly assessments of the SO2

monitoring system under appendix B to

this part on any day or in any calendar

quarter in which only natural gas (or

gaseous fuel with a total sulfur content

no greater than the total sulfur content
28132 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

of natural gas) is combusted in the unit.

Notwithstanding, the results of any

daily calibration error test and linearity

test of the SO2 monitoring system

performed while the unit is combusting

only natural gas (or gaseous fuel with a

total sulfur content no greater than the

total sulfur content of natural gas) shall

be considered valid. If any such test is

failed, the SO2 monitoring system shall

be considered to be out-of-control. The

length of the out-of-control period shall

be determined in accordance with the

applicable procedures in section 2.1.4 or

2.2.3 of appendix B to this part.

(5) For a unit with an SO2 continuous

monitoring system, in which natural gas

(or gaseous fuel with a total sulfur

content no greater than the total sulfur

content of natural gas) is sometimes

burned as a primary and/or backup fuel

and in which higher-sulfur fuel(s) such

as oil or coal are, at other times, burned

as primary or backup fuel(s), the owner

shall perform the relative accuracy test

audits of the SO2 monitoring system (as

required by section 6.5 of appendix A to

this part and section 2.3.1 of appendix

B to this part) only when the highersulfur fuel is combusted in the unit and

shall not perform SO2 relative accuracy

test audits when gaseous fuel is the only

fuel being combusted.

(6) If the designated representative

certifies that a unit with an SO2

monitoring system burns only fuel(s)

with a total sulfur content no greater

than the total sulfur content of natural

gas, the SO2 monitoring system is

exempted from the relative accuracy test

audit requirements in appendices A and

B to this part. For the purposes of this

part, a fuel having a total sulfur content

no greater than 0.05 percent sulfur by

weight shall be deemed to qualify as a

‘‘fuel with a total sulfur content no

greater than the total sulfur content of

natural gas.’’

(7) If the designated representative

certifies that a particular unit with an

SO2 monitoring system combusts fuel(s)

with a total sulfur content greater than

the total sulfur content of natural gas

(i.e., >0.05 percent sulfur by weight)

only as emergency backup fuel(s) or for

short-term testing, the SO2 monitoring

system shall be conditionally exempted

from the RATA requirements of

appendices A and B to this part,

provided that the unit combusts the

higher-sulfur fuel(s) for no more than

480 hours per calendar year. If, in a

particular calendar year, the highersulfur fuel usage exceeds 480 hours, a

RATA of the SO2 monitor shall be

performed (while combusting the

higher-sulfur fuel) either by the end of

the calendar quarter in which the

exceedance occurs or by the end of a

720 unit operating hour grace period

following the quarter in which the

exceedance occurs (see SO2 RATA

provisions in section 2.3.3 of appendix

B to this part for further discussion of

the grace period).

(8) On and after January 1, 2000, the

quality assurance provisions of

§§ 75.11(e)(3)(i) through 75.11(e)(3)(iv)

shall apply (except that the term

‘‘gaseous fuel’’ shall be replaced with

‘‘fuel’’) to all units with SO2 monitoring

systems during hours in which only fuel

having a total sulfur content no greater

than the total sulfur content of natural

gas (i.e., ≤0.05 percent sulfur by weight)

is combusted in the unit, except for

units that use such fuel only for unit

startup.

(9) Provided that a unit with an SO2

monitoring system is not exempted

under paragraph (a)(6) or (a)(7) of this

section from the SO2 RATA

requirements of this part, any calendar

quarter during which a unit combusts

only fuel(s) with a total sulfur content

no greater than the total sulfur content

of natural gas (i.e. ≤0.05 percent sulfur

by weight) shall be excluded in

determining the quarter in which the

next relative accuracy test audit must be

performed for the SO2 monitoring

system. However, no more than eight

successive calendar quarters shall

elapse after a relative accuracy test audit

of an SO2 monitoring system, without a

subsequent relative accuracy test audit

having been performed. The owner or

operator shall ensure that a relative

accuracy test audit is performed either

by the end of the eighth successive

elapsed calendar quarter since the last

RATA or in the next calendar quarter in

which a fuel with a total sulfur content

greater than the total sulfur content of

natural gas is burned in the unit.

* * * * *

(e) Consequences of audits. The

owner or operator shall invalidate data

from a continuous emission monitoring

system or continuous opacity

monitoring system upon failure of an

audit under paragraph (a)(4)(iv) of

§ 75.20, an audit under appendix B to

this part, or any other audit, beginning

with the unit operating hour of

completion of a failed audit as

determined by the Administrator. The

owner or operator shall not use

invalidated data for reporting either

emissions or heat input, nor for

calculating monitor data availability.

(1) Audit decertification. Whenever

both an audit of a continuous emission

or opacity monitoring system (or

component thereof, including the data

acquisition and handling system), or an

audit of any excepted monitoring

system under appendix D, E, or I to this

part, or of any alternative monitoring

system under subpart E of this part, and

a review of the initial certification

application or of a recertification

application, reveal that any system or

component should not have been

certified or recertified because it did not

meet a particular performance

specification or other requirement of

this part, both at the time of the initial

certification or recertification

application submission and at the time

of the audit, the Administrator will

issue a notice of disapproval of the

certification status of such system or

component. For the purposes of this

paragraph, an audit shall be either a

field audit of the facility or an audit of

any information submitted to EPA or the

State agency regarding the facility. By

issuing the notice of disapproval, the

certification status is revoked,

prospectively, by the Administrator.

The data measured and recorded by

each system shall not be considered

valid quality-assured data from the date

of issuance of the notification of the

revoked certification status until the

date and time that the owner or operator

completes subsequently approved initial

certification or recertification tests. The

owner or operator shall follow the

procedures in § 75.20(a)(5) for initial

certification or § 75.20(b)(5) for

recertification to replace, prospectively,

all of the invalid, non-quality-assured

data for each disapproved system.

(2) Out-of-control period. Whenever a

continuous emission monitoring system

or continuous opacity monitoring

system fails a quality assurance audit,

an audit under § 75.20(a)(4)(iv), or

another audit, the system is out-ofcontrol. The owner or operator shall

follow the procedures for out-of-control

periods in § 75.24.

(f) Excepted flow monitoring systems

under appendix I. The owner or

operator of an affected unit shall

operate, calibrate, and maintain each

excepted flow monitoring system under

appendix I to this part used under the

Acid Rain Program according to the

quality assurance and quality control

procedures in appendices B and I to this

part.

21. Section 75.22 is amended by

revising paragraphs (a)(2), (a)(4), and

(c)(1) introductory text to read as

follows:

§ 75.22 Reference test methods.

(a) * * *

(2) Method 2 or its allowable

alternatives, except for 2B and 2E, are

the reference methods for determination

of volumetric flow.

* * * * *
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28133

(4) Method 4 (either the standard

procedure described in section 2 of the

method or the moisture approximation

procedure described in section 3 of the

method) shall be used to correct

pollutant concentrations from a dry

basis to a wet basis (or from a wet basis

to a dry basis) and shall be used when

relative accuracy test audits of

continuous moisture monitoring

systems are conducted. For the purpose

of determining the stack gas molecular

weight, however, the alternative

techniques for approximating the stack

gas moisture content described in

section 1.2 of Method 4 may be used in

lieu of the procedures in sections 2 and

3 of the method.

* * * * *

(c) * * *

(1) Instrumental EPA Reference

Methods 3A, 6C, 7E, and 20 shall be

conducted using calibration gases as

defined in section 5 of appendix A to

this part. Otherwise, performance tests

shall be conducted and data reduced in

accordance with the test methods and

procedures of this part unless the

Administrator:

* * * * *

22. Section 75.24 is amended by

revising paragraph (d) to read as

follows:

§ 75.24 Out-of-control periods.

* * * * *

(d) When the bias test indicates that

an SO2 monitor, volumetric flow

monitor, or NOX continuous emission

monitoring system is biased low (i.e.,

the arithmetic mean of the differences

between the reference method value and

the monitor or monitoring system

measurements in a relative accuracy test

audit exceed the bias statistic in section

7 of appendix A to this part), the owner

or operator shall adjust the monitor or

continuous emission monitoring system

to eliminate the cause of bias such that

it passes the bias test or calculate and

use the bias adjustment factor as

specified in section 2.3.4 of appendix B

to this part and in accordance with

§ 75.7.

* * * * *

23. Section 75.30 is amended by

revising paragraphs (a)(2) and (d) to read

as follows:

§ 75.30 General provisions.

(a) * * *

(2) A valid quality assured hour of

flow data (in scfh) has not been

measured and recorded for an affected

unit from a certified flow monitor, or

from a certified excepted flow

monitoring system under appendix I to

this part, or by an approved alternative

monitoring system under subpart E of

this part; or

* * * * *

(d) The owner or operator shall

comply with the applicable provisions

of this paragraph during hours in which

a unit with an SO2 continuous emission

monitoring system combusts only

natural gas or gaseous fuel with a total

sulfur content no greater than the total

sulfur content of natural gas.

(1) Whenever a unit with an SO2

continuous emission monitoring system

combusts only pipeline natural gas and

the owner or operator is using the

procedures in section 7 of appendix F

to this part to determine SO2 mass

emissions pursuant to § 75.11(e)(1), the

owner or operator shall, for purposes of

reporting heat input data under

§ 75.54(b)(5) or § 75.57(b)(5), as

applicable, and for the calculation of

SO2 mass emissions using Equation F–

23 in section 7 of appendix F to this

part, substitute for missing data from a

flow monitoring system, CO2-diluent

monitor or O2-diluent monitor using the

missing data substitution procedures in

§ 75.36.

(2) Whenever a unit with an SO2

continuous emission monitoring system

combusts gaseous fuel with a total

sulfur content no greater than the total

sulfur content of natural gas (i.e., ≥20 gr/

100 scf) and the owner or operator uses

the gas sampling and analysis and fuel

flow procedures in appendix D to this

part to determine SO2 mass emissions

pursuant to § 75.11(e)(2), the owner or

operator shall substitute for missing

total sulfur content, gross calorific

value, and fuel flowmeter data using the

missing data procedures in appendix D

to this part and shall also, for purposes

of reporting heat input data under

§ 75.54(b)(5) or § 75.57(b)(5), substitute

for missing data from a flow monitoring

system, CO2-diluent monitor, or O2-

diluent monitor using the missing data

substitution procedures in § 75.36.

(3) The owner or operator of a unit

with an SO2 monitoring system shall not

include hours, when the unit combusts

only natural gas (or a gaseous fuel with

total sulfur content no greater than the

total sulfur content of natural gas), in

the SO2 data availability calculations in

§ 75.32 or in the calculations of

substitute SO2 data using the procedures

of either § 75.31 or § 75.33, when SO2

emissions are determined in accordance

with § 75.11(e)(1) or (e)(2). For the

purpose of the missing data and

availability procedures for SO2 pollutant

concentration monitors in §§ 75.31 and

75.33 only, all hours during which the

unit combusts only natural gas, or

gaseous fuel with a total sulfur content

no greater than the total sulfur content

of natural gas, shall be excluded from

the definition of ‘‘monitor operating

hour,’’ ‘‘quality assured monitor

operating hour,’’ ‘‘unit operating hour,’’

and ‘‘unit operating day,’’ when SO2

emissions are determined in accordance

with § 75.11(e)(1) or (e)(2).

(4) During all hours in which a unit

with an SO2 continuous emission

monitoring system combusts only

natural gas (or gaseous fuel with a total

sulfur content no greater than the total

sulfur content of natural gas) and the

owner or operator uses the SO2

monitoring system to determine SO2

mass emissions pursuant to

§ 75.11(e)(3), the owner or operator shall

determine the percent monitor data

availability for SO2 in accordance with

§ 75.32 and shall use the standard SO2

missing data procedures of § 75.33.

24. Section 75.32 is amended by

revising the last sentence in paragraph

(a)(3) to read as follows:

§ 75.32 Determination of monitor data

availability for standard missing data

procedures.

(a) * * *

(3) * * * The owner or operator of a

unit with an SO2 monitoring system

shall, when SO2 emissions are

determined in accordance with

§ 75.11(e)(1) or (e)(2), exclude hours in

which a unit combusts only natural gas

(or gaseous fuel with a total sulfur

content no greater than the total sulfur

content of natural gas) from calculations

of percent monitor data availability for

SO2 pollutant concentration monitors,

as provided in § 75.30(d).

* * * * *

25. Section 75.33 is amended by

adding a new paragraph (d) to read as

follows:

§ 75.33 Standard missing data procedures.

* * * * *

(d) On and after January 1, 2000,

failure to maintain a monitor data

availability, as calculated pursuant to

§ 75.32, of at least 80.0 percent for SO2,

NOX, flow rate, or CO2 shall be

considered a violation of the primary

measurement requirement of § 75.10(a).

This paragraph (d) shall not apply: if,

for a particular unit or stack for which

the monitor data availability drops

below 80.0 percent, less than 3,000 unit

operating hours have been accumulated

in the previous 12 calendar quarters; or

if a data availability percentage of less

than 80.0 percent results from a sudden

and reasonably unforeseeable event

beyond the control of the owner or

operator, such as catastrophic monitor

failure or destruction of monitoring

equipment by fire, flood, etc. If such
28134 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

circumstances have caused (or are

projected to cause) the monitor data

availability to drop below 80.0 percent,

the owner or operator shall notify the

Administrator, in writing, within 7 days

of the event(s). Notification, in writing,

shall also be provided to the EPA

Regional Office and to the appropriate

State agency. The written notifications

shall fully explain the circumstances

that have caused (or may cause) the low

monitor data availability and shall

contain an action plan and a projected

time schedule for correction of the

problem. Failures that are caused in part

by poor maintenance or careless

operation shall not, for the purposes of

this paragraph, be considered

reasonably unforeseeable events beyond

the control of the owner or operator.

26. Section 75.34 is amended by

revising paragraph (a)(3) to read as

follows:

§ 75.34 Units with add-on emission

controls.

(a) * * *

(3) The designated representative may

petition the Administrator under § 75.66

for approval of site-specific parametric

monitoring procedure(s) for calculating

substitute data for missing SO2 pollutant

concentration and NOX emission rate

data in accordance with the

requirements of paragraphs (b) and (c) of

this section and appendix C to this part.

The owner or operator shall record the

data required in appendix C to this part,

pursuant to § 75.55(b) or § 75.58(b), as

applicable.

* * * * *

27. Section 75.35 is amended by

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

follows:

§ 75.35 Missing data procedures for CO2

data.

(a) On and after January 1, 2000, the

owner or operator of a unit with a CO2

continuous emission monitoring system

(or an O2-diluent monitor that is used to

determine CO2 concentration in

accordance with appendix F to this part)

shall substitute for missing CO2

concentration data using the procedures

of this section. Prior to January 1, 2000,

the owner or operator may substitute for

missing CO2 or O2 concentration data

using the procedures of this section.

* * * * *

(c) Upon completion of the first 720

quality assured monitor operating hours

following initial certification of the CO2

continuous emission monitoring system,

the owner or operator shall provide

substitute data for CO2 concentration or

CO2 mass emissions required under this

subpart, including CO2 data calculated

from O2 measurements using the

procedures in appendix F to this part,

in accordance with the procedures in

§ 75.33(b), except that the terms ‘‘SO2

concentration’’ and ‘‘SO2 pollutant

concentration monitor’’ shall be

replaced, respectively, with ‘‘CO2

concentration’’ and ‘‘CO2 pollutant

concentration monitor.’’

28. Section 75.36 is amended by

revising paragraphs (a), (b), and (c) to

read as follows:

§ 75.36 Missing data procedures for heat

input.

(a) When hourly heat input is

determined using a flow monitoring

system and a diluent gas (O2 or CO2)

monitor, substitute data must be

provided to calculate the heat input

whenever quality assured data are

unavailable from the flow monitor, the

diluent gas monitor, or both. When flow

rate data are unavailable, substitute flow

rate data for the heat input calculation

shall be provided according to § 75.31 or

§ 75.33, as applicable. On and after

January 1, 2000, when diluent gas data

are unavailable, the owner or operator

shall provide substitute O2 or CO2 data

for the heat input calculations in

accordance with this section. Prior to

January 1, 2000, the owner or operator

may substitute for missing CO2 or O2

concentration data using the procedures

in this section.

(b) During the first 720 quality

assured monitor operating hours

following initial certification (i.e.,

following the date and time of

completion of successful certification

tests of the CO2 or O2 monitor), the

owner or operator shall provide

substitute CO2 or O2 data, as applicable,

for the calculation of heat input (under

section 5.2 of appendix F to this part)

according to § 75.31(b).

(c) Upon completion of the first 720

quality assured monitor operating hours

following initial certification of the CO2

(or O2) monitor, the owner or operator

shall provide substitute data for CO2 or

O2 concentration to calculate heat input

according to the procedures in

§ 75.33(b), except that the term ‘‘SO2

concentration’’ shall be replaced with

‘‘CO2 concentration’’ or ‘‘O2

concentration’’ (as applicable) and the

term ‘‘SO2 pollutant concentration

monitor’’ shall be replaced with ‘‘CO2-

diluent monitor’’ or ‘‘O2-diluent

monitor’’ (as applicable).

* * * * *

29. Section 75.37 is added to subpart

D to read as follows:

§ 75.37 Missing data procedures for

moisture.

The owner or operator shall substitute

for missing moisture data (beginning no

later than January 1, 2000 or the date

and hour on which the unit or stack is

required to begin reporting under

§ 75.64, whichever date is earlier) as

follows:

(a) Where no prior quality assured

percent moisture data exist, substitute

0.0 percent moisture for each unit

operating hour;

(b) For the first 720 quality assured

monitor operating hours, substitute for

each hour of the missing data period the

average of the percent moisture values

obtained during the hour before and the

hour after the missing data period;

(c) Once 720 quality assured monitor

operating hours have been obtained,

begin calculating the percent data

availability of the moisture monitoring

system, in accordance with § 75.32;

(d) When the percent data availability,

as of the last hour in the missing data

period, is ≥90.0 percent, substitute for

each hour of the missing data period the

average of the percent moisture values

obtained during the hour before and the

hour after the missing data period;

(e) If the percent data availability of

the moisture monitor is < 90.0 percent

as of the last hour in the missing data

period, substitute 0.0 percent moisture

for each hour of the missing data period.

Subpart E—[Amended]

30. Section 75.48 is amended by

revising paragraphs (a)(3)(ii) and (a)

(3)(iii) to read as follows:

§ 75.48 Petition for an alternative

monitoring system.

(a) * * *

(3) * * *

(ii) Hourly test data for the alternative

monitoring system at each required

operating level and fuel type. The fuel

type, operating level and gross unit load

shall be recorded.

(iii) Hourly test data for the

continuous emissions monitoring

system at each required operating level

and fuel type. The fuel type, operating

level and gross unit load shall be

recorded.

* * * * *

31. Section 75.50 is removed and

reserved.

§ 75.50 [Removed and Reserved]

32. Section 75.51 is removed and

reserved.

§ 75.51 [Removed and Reserved]

33. Section 75.52 is removed and

reserved.

§ 75.52 [Removed and Reserved]

34. Section 75.53 is amended by

revising paragraphs (a) and (b) and

adding paragraphs (e) through (f) to read

as follows:
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28135

§ 75.53 Monitoring plan.

(a) General Provisions.

(1) Compliance dates. Beginning on

January 1, 2000, the owner or operator

shall comply with the provisions in

paragraphs (a), (b), (e) and (f) of this

section only. Before January 1, 2000, the

owner or operator shall comply with

either paragraphs (a) through (d) or

paragraphs (a), (b), (c), and (f) of this

section, except that the owner or

operator shall comply with provisions

in paragraphs (e) and (f) of this section

only before January 1, 2000, when those

provisions support a regulatory option

provided in another section of this part

75 and the regulatory option is

exercised before January 1, 2000.

(2) The owner or operator of an

affected unit shall prepare and maintain

a monitoring plan. Except as provided

in paragraphs (d) (or (f), as applicable)

of this section, a monitoring plan shall

contain sufficient information on the

continuous emission or opacity

monitoring systems, excepted

methodology under § 75.19, or excepted

monitoring systems under appendix D

or E to this part and the use of data

derived from these systems to

demonstrate that all unit SO2 emissions,

NOX emissions, CO2 emissions, and

opacity are monitored and reported.

(b) Whenever the owner or operator

makes a replacement, modification, or

change in the certified continuous

emission monitoring system, continuous

opacity monitoring system, excepted

methodology under § 75.19, excepted

monitoring system under appendix D, E,

or I to this part, or alternative

monitoring system under subpart E of

this part, including a change in the

automated data acquisition and

handling system or in the flue gas

handling system, that affects

information reported in the monitoring

plan (e.g., a change to a serial number

for a component of a monitoring

system), then the owner or operator

shall update the monitoring plan.

* * * * *

(e) Contents of the monitoring plan.

Each monitoring plan shall contain the

information in paragraph (e)(1) of this

section in electronic format and the

information in paragraph (e)(2) of this

section in hardcopy format.

(1) Electronic. (i) ORISPL numbers

developed by the Department of Energy

and used in the National Allowance

Database, for all affected units involved

in the monitoring plan, with the

following information for each unit:

(A) Short name;

(B) Classification of unit as one of the

following: Phase I (including

substitution or compensating units),

Phase II, new, or nonaffected;

(C) Type of boiler (or boilers for a

group of units using a common stack);

(D) Type of fuel(s) fired by boiler, fuel

type start and end date, primary/

secondary fuel indicator, and, if more

than one fuel, the fuel classification of

the boiler;

(E) Type(s) of emission controls for

SO2, NOX, and particulates installed or

to be installed, including specifications

of whether such controls are precombustion, post-combustion, or

integral to the combustion process;

control equipment code, installation

date, and optimization date; control

equipment retirement date (if

applicable); and, an indicator for

whether the controls are an original

installation;

(F) Maximum hourly heat input

capacity;

(G) Date of first commercial operation;

(H) Unit retirement date (if

applicable);

(I) Maximum hourly gross load (in

MW, rounded to the nearest MW, or

steam load in 1000 lb/hr, rounded to the

nearest 100 lb/hr);

(J) Identification of all units using a

common stack;

(K) Activation date for the stack/pipe;

(L) Retirement date of the stack/pipe

(if applicable); and

(M) Indicator of whether the stack is

a bypass stack.

(ii) For each unit and parameter

required to be monitored, identification

of monitoring methodology information,

consisting of monitoring methodology,

type of fuel associated with the

methodology, missing data approach for

the methodology, methodology start

date, and methodology end date (if

applicable).

(iii) The following information:

(A) Program(s) for which the EDR is

submitted;

(B) Unit classification;

(C) Reporting frequency;

(D) Program participation date;

(E) State regulation code (if

applicable); and

(F) State or local regulatory agency

code.

(iv) Identification and description of

each monitoring component (including

each monitor and its identifiable

components, such as analyzer and/or

probe) in the continuous emission

monitoring systems (i.e., SO2 pollutant

concentration monitor, flow monitor,

moisture monitor; NOX pollutant

concentration monitor and diluent gas

monitor), the continuous opacity

monitoring system, or excepted

monitoring system (i.e., fuel flowmeter,

data acquisition and handling system),

including:

(A) Manufacturer, model number and

serial number;

(B) Component/system identification

code assigned by the utility to each

identifiable monitoring component

(such as the analyzer and/or probe).

Each code shall use a three-digit format,

unique to each monitoring component

and unique to each monitoring system;

(C) Designation of the component type

or method of operation, such as in situ

pollutant concentration monitor or

thermal flow monitor;

(D) Designation of the system as a

primary, redundant backup, nonredundant backup, like kind nonredundant backup, data backup, or

reference method backup system, as

provided in § 75.10(e);

(E) First and last dates the system

reported data; and

(F) Status of the monitoring

component.

(v) Identification and description of

all major hardware and software

components of the automated data

acquisition and handling system,

including:

(A) For hardware components, the

manufacturer and model number; and

(B) For software components,

identification of the provider and

model/version number.

(vi) Explicit formulas for each

measured emission parameter, using

component/system identification codes

for the primary system used to measure

the parameter to link continuous

emission monitoring system or excepted

monitoring system observations with

reported concentrations, mass

emissions, or emission rates, according

to the conversions listed in appendix D,

E, or F to this part. Formulas for backup

monitoring systems are required only if

different formulas for the same

parameter are used for the primary and

backup monitoring systems (e.g., if the

primary system measures pollutant

concentration on a different moisture

basis from the backup system). The

formulas must contain all constants and

factors required to derive mass

emissions or emission rates from

component/system code observations

and an indication of whether the

formula is being added, corrected,

deleted, or is unchanged. Each

emissions formula is identified with a

unique three digit code. The owner or

operator of a low mass emissions unit

for which the owner or operator is using

the optional low mass emissions

excepted methodology in § 75.19(c) is

not required to report such formulas.

(vii) Inside cross-sectional area (ft2) at

flue exit (for all units) and at flow

monitoring location (for units with flow

monitors, only).
28136 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

(viii) Stack height (ft) above ground

level and stack base elevation above sea

level.

(ix) Flue identification number, as

reported to the Energy Information

Administration (EIA).

(x) For each parameter monitored:

scale, maximum potential concentration

(and method of calculation), maximum

expected concentration (if applicable)

(and method of calculation), maximum

potential flow rate (and method of

calculation), maximum potential NOX

emission rate, span value, full-scale

range, daily calibration units of

measure, span effective date/hour, span

inactivation date/hour, indication of

whether dual spans are required, default

high range value, flow rate span, and

flow rate span value and full scale value

(in scfh) for each unit or stack using

SO2, NOX, CO2, O2, or flow component

monitors.

(xi) If the monitoring system or

excepted methodology provides for the

use of a constant, assumed, or default

value for a parameter under specific

circumstances, then include the

following information for each such

value for each parameter:

(A) Identification of the parameter;

(B) Default, maximum, minimum, or

constant value, and units of measure for

the value;

(C) Purpose of the value;

(D) Indicator of use during controlled/

uncontrolled hours;

(E) Type of fuel;

(F) Source of the value;

(G) Value effective date and hour;

(H) Date and hour value is no longer

effective (if applicable); and

(I) For units using the excepted

methodology under § 75.19, the

applicable SO2 emission factor.

(2) Hardcopy. (i) Information,

including (as applicable) identification

of the test strategy; protocol for the

relative accuracy test audit; other

relevant test information; calibration gas

levels (percent of span) for the

calibration error test and linearity

check; calculations for determining

maximum potential concentration,

maximum expected concentration (if

applicable), maximum potential flow

rate, maximum potential NOX emission

rate, and span; and apportionment

strategies under §§ 75.13 through 75.17.

(ii) Description of site locations for

each monitoring component in the

continuous emission or opacity

monitoring systems, including

schematic diagrams and engineering

drawings specified in paragraphs

(e)(2)(iv) and (e)(2)(v) of this section and

any other documentation that

demonstrates each monitor location

meets the appropriate siting criteria.

(iii) A data flow diagram denoting the

complete information handling path

from output signals of continuous

emission monitoring system

components to final reports.

(iv) For units monitored by a

continuous emission or opacity

monitoring system, a schematic diagram

identifying entire gas handling system

from boiler to stack for all affected units,

using identification numbers for units,

monitor components, and stacks

corresponding to the identification

numbers provided in paragraphs

(e)(1)(i), (e)(1)(ii), (e)(1)(vi), and

(e)(1)(vii) of this section. The schematic

diagram must depict stack height and

the height of any monitor locations.

Comprehensive and/or separate

schematic diagrams shall be used to

describe groups of units using a

common stack.

(v) For units monitored by a

continuous emission or opacity

monitoring system, stack and duct

engineering diagrams showing the

dimensions and location of fans, turning

vanes, air preheaters, monitor

components, probes, reference method

sampling ports, and other equipment

that affects the monitoring system

location, performance, or quality control

checks.

(f) Contents of monitoring plan for

specific situations. The following

additional information shall be included

in the monitoring plan for the specific

situations described:

(1) For each gas-fired unit or oil-fired

unit for which the owner or operator

uses the optional protocol in appendix

D to this part for estimating heat input

and/or SO2 mass emissions or in

appendix I to this part for estimating

stack flow rate, or for each gas-fired or

oil-fired peaking unit for which the

owner/operator uses the optional

protocol in appendix E to this part for

estimating NOX emission rate (using a

fuel flowmeter), the designated

representative shall include the

following additional information in the

monitoring plan:

(i) Electronic. (A) Parameter

monitored;

(B) Type of fuel measured, maximum

fuel flow rate, units of measure, and

basis of maximum fuel flow rate (i.e.,

upper range value or unit maximum) for

each fuel flowmeter;

(C) Test method used to check the

accuracy of each fuel flowmeter;

(D) Submission status of the data; and

(E) Monitoring system identification

code.

(ii) Hardcopy. (A) A schematic

diagram identifying the relationship

between the unit, all fuel supply lines,

the fuel flowmeter(s), and the stack(s).

The schematic diagram must depict the

installation location of each fuel

flowmeter and the fuel sampling

location(s). Comprehensive and/or

separate schematic diagrams shall be

used to describe groups of units using

a common pipe.

(B) For units using the optional

protocol for gaseous fuel in appendix D

to this part, historical fuel sampling

information on the sulfur content of the

gaseous fuel according to section 2.3.3

of appendix D to this part.

(2) For each gas-fired peaking unit

and oil-fired peaking unit for which the

owner or operator uses the optional

procedures in appendix E to this part for

estimating NOX emission rate, the

designated representative shall include

in the monitoring plan:

(i) Electronic. Unit operating and

capacity factor information

demonstrating that the unit qualifies as

a peaking unit or gas-fired unit, as

defined in § 72.2 of this chapter.

(ii) Hardcopy. (A) A protocol

containing methods used to perform the

baseline or periodic NOX emission test;

and

(B) Unit operating parameters related

to NOX formation by the unit.

(3) For each gas-fired unit and dieselfired unit or unit with a wet flue gas

pollution control system for which the

designated representative claims an

opacity monitoring exemption under

§ 75.14, the designated representative

shall include in the hardcopy

monitoring plan the information

specified under § 75.14(b), (c), or (d),

demonstrating that the unit qualifies for

the exemption.

(4) For each monitoring system

recertification, maintenance, or other

event, the designated representative

shall include the following additional

information in electronic format in the

monitoring plan:

(i) Component/system identification

code;

(ii) Event code or code for required

test;

(iii) Event begin date and hour;

(iv) Conditional data period begin

date and hour (if applicable);

(v) Date and hour that last test is

successfully completed; and

(vi) Indicator of whether conditionally

valid data were reported at the end of

the quarter.

35. Section 75.54 is amended by

adding new paragraphs (g) and (h) to

read as follows:

§ 75.54 General recordkeeping provisions.

* * * * *

(g) Missing data records. The owner or

operator shall record the causes of any

missing data periods and the actions
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28137

taken by the owner or operator to cure

such causes.

(h) Compliance dates. On January 1,

2000, the provisions of this section are

no longer applicable. Before January 1,

2000, the owner or operator shall

comply with either this section or

§ 75.57. Beginning on January 1, 2000,

the owner or operator shall comply with

§ 75.57 only.

36. Section 75.55 is amended by

adding a new paragraph (g) to read as

follows:

§ 75.55 General recordkeeping provisions

for specific situations.

* * * * *

(g) Compliance dates. On January 1,

2000, the provisions of this section are

no longer applicable. Before January 1,

2000, the owner or operator shall

comply with either this section or

§ 75.58. Beginning on January 1, 2000,

the owner or operator shall comply with

§ 75.58 only.

37. Section 75.56 is amended by

adding new paragraphs (a)(5)(vii) and

(e) to read as follows:

§ 75.56 Certification, quality assurance,

and quality control record provisions.

(a) * * *

(5) * * *

(vii) For flow monitors, the flow

polynomial equation used to linearize

the flow monitor and the numerical

values of the polynomial coefficients of

that equation.

* * * * *

(e) Compliance dates. On January 1,

2000, the provisions of this section are

no longer applicable. Before January 1,

2000, the owner or operator shall

comply with either this section or

§ 75.59. Beginning on January 1, 2000,

the owner or operator shall comply with

§ 75.59 only.

38. Section 75.57 is added to Subpart

F to read as follows:

§ 75.57 General recordkeeping provisions.

(a) Recordkeeping requirements for

affected sources. The owner or operator

of any affected source subject to the

requirements of this part shall maintain

for each affected unit a file of all

measurements, data, reports, and other

information required by this part at the

source in a form suitable for inspection

for at least three (3) years from the date

of each record. Unless otherwise

provided, throughout this subpart the

phrase ‘‘for each affected unit’’ also

applies to each group of affected or

nonaffected units utilizing a common

stack and common monitoring systems,

pursuant to §§ 75.13 through 75.18, or

utilizing a common pipe header and

common fuel flowmeter, pursuant to

section 2.1.2 of appendix D to this part.

The file shall contain the following

information:

(1) The data and information required

in paragraphs (b) through (f) of this

section, beginning with the earlier of the

date of provisional certification or the

deadline in § 75.4(a), (b), or (c);

(2) The supporting data and

information used to calculate values

required in paragraphs (b) through (f) of

this section, excluding the subhourly

data points used to compute hourly

averages under § 75.10(d), beginning

with the earlier of the date of

provisional certification or the deadline

in § 75.4(a), (b), or (c);

(3) The data and information required

in § 75.55 or § 75.58 for specific

situations, as applicable, beginning with

the earlier of the date of provisional

certification or the deadline in § 75.4(a),

(b), or (c);

(4) The certification test data and

information required in § 75.56 or

§ 75.59 for tests required under § 75.20,

beginning with the date of the first

certification test performed; the quality

assurance and quality control data and

information required in § 75.56 or

§ 75.59 for tests; and the quality

assurance/quality control plan required

under § 75.21 and appendix B to this

part, beginning with the date of

provisional certification;

(5) The current monitoring plan as

specified in § 75.53, beginning with the

initial submission required by § 75.62;

and

(6) The quality control plan as

described in section 1 of appendix B to

this part, beginning with the date of

provisional certification.

(b) Operating parameter record

provisions. The owner or operator shall

record for each hour the following

information on unit operating time, heat

input rate, and load, separately for each

affected unit and also for each group of

units utilizing a common stack and a

common monitoring system or utilizing

a common pipe header and common

fuel flowmeter.

(1) Date and hour;

(2) Unit operating time (rounded up to

the nearest fraction of an hour (in equal

increments that can range from one

hundredth to one quarter of an hour, at

the option of the owner or operator));

(3) Hourly gross unit load (rounded to

nearest MWge) (or steam load in 1000

lb/hr at stated temperature and pressure,

rounded to the nearest 1000 lb/hr, if

elected in the monitoring plan);

(4) Operating load range

corresponding to hourly gross load of 1

to 10, except for units using a common

stack or common pipe header, which

may use up to 20 load ranges for stack

or fuel flow, as specified in the

monitoring plan;

(5) Hourly heat input rate (mmBtu/hr,

rounded to the nearest tenth);

(6) Identification code for formula

used for heat input, as provided in

§ 75.53; and

(7) For CEMS units only:

(i) F-factor for heat input calculation;

and

(ii) Indication of whether the diluent

cap was used for heat input calculations

for the hour.

(c) SO2 emission record provisions.

The owner or operator shall record for

each hour the information required by

this paragraph for each affected unit or

group of units using a common stack

and common monitoring systems,

except as provided under § 75.11(e) or

for a gas-fired or oil-fired unit for which

the owner or operator is using the

optional protocol in appendix D to this

part or for a low mass emissions unit for

which the owner or operator is using the

optional low mass emissions

methodology in § 75.19(c) for estimating

SO2 mass emissions:

(1) For SO2 concentration during unit

operation, as measured and reported

from each certified primary monitor,

certified back-up monitor, or other

approved method of emissions

determination:

(i) Component-system identification

code, as provided in § 75.53;

(ii) Date and hour;

(iii) Hourly average SO2 concentration

(ppm, rounded to the nearest tenth);

(iv) Hourly average SO2 concentration

(ppm, rounded to the nearest tenth),

adjusted for bias if bias adjustment

factor is required, as provided in

§ 75.24(d);

(v) Percent monitor data availability

(recorded to the nearest tenth of a

percent), calculated pursuant to § 75.32;

and

(vi) Method of determination for

hourly average SO2 concentration using

Codes 1–55 in Table 4a of this section.

(2) For flow rate during unit

operation, as measured and reported

from each certified primary monitor,

certified back-up monitor, or other

approved method of emissions

determination:

(i) Component system identification

code, as provided in § 75.53 (including

the separate identification code for the

moisture monitoring system, if

applicable);

(ii) Date and hour;

(iii) Hourly average volumetric flow

rate (in scfh, rounded to the nearest

thousand);

(iv) Hourly average volumetric flow

rate (in scfh, rounded to the nearest

thousand), adjusted for bias if bias
28138 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

adjustment factor required, as provided

in § 75.24(d);

(v) Hourly average moisture content of

flue gas (percent, rounded to the nearest

tenth), where SO2 concentration is

measured on a dry basis. If the

continuous moisture monitoring system

consists of wet- and dry-basis oxygen

analyzers, record both the wet- and drybasis oxygen hourly averages (in percent

O2, rounded to the nearest tenth);

(vi) Percent monitor data availability

(recorded to the nearest tenth of a

percent), for the flow monitor, and, if

applicable, separately for the moisture

monitoring system, calculated pursuant

to § 75.32; and

(vii) Method of determination for

hourly average flow rate using Codes 1–

55 in Table 4a of this section.

(3) For SO2 mass emission rate during

unit operation, as measured and

reported from the certified primary

monitoring system(s), certified

redundant or non-redundant back-up

monitoring system(s), or other approved

method(s) of emissions determination:

(i) Date and hour;

(ii) Hourly SO2 mass emission rate

(lb/hr, rounded to the nearest tenth);

(iii) Hourly SO2 mass emission rate

(lb/hr, rounded to the nearest tenth),

adjusted for bias if bias adjustment

factor required, as provided in

§ 75.24(d); and

(iv) Identification code for emissions

formula used to derive hourly SO2 mass

emission rate from SO2 concentration

and flow data in paragraphs (c)(1) and

(c)(2) of this section, as provided in

§ 75.53.

TABLE 4A.—CODES FOR METHOD OF EMISSIONS AND FLOW DETERMINATION

Code Hourly emissions/flow measurement or estimation method

1 ............. Certified primary emission/flow monitoring system.

2 ............. Certified backup emission/flow monitoring system.

3 ............. Approved alternative monitoring system.

4 ............. Reference method: SO2: Method 6C. Flow: Method 2. NOX: Method 7E. CO2 or O2: Method 3A.

5 ............. For units with add-on SO2 and/or NOX emission controls: SO2 concentration or NOX emission rate estimate from Agency

preapproved parametric monitoring method.

6 ............. Average of the hourly SO2 concentrations, CO2 concentrations, flow rate, or NOX emission rate for the hour before and the hour following a missing data period.

7 ............. Hourly average SO2 concentration, CO2 concentration, flow rate, or NOX emission rate using initial missing data procedures.

8 ............. 90th percentile hourly SO2 concentration, flow rate, or emission rate.

9 ............. 95th percentile hourly SO2 concentration, flow rate, or NOX emission rate.

10 ........... Maximum hourly SO2 concentration, flow rate, or NOX emission rate.

11 ........... Hourly average flow rate or NOX emission rate in corresponding load range.

12 ........... Maximum potential concentration of SO2, maximum potential concentration of CO2, maximum potential flow rate, or maximum potential NOX emission rate, as determined using section 2.1 of appendix A to this part.

13 ........... Fuel analysis data from appendix G to this part for CO2 mass emissions. (This code is optional through 12/31/99, and shall not be

used after 1/1/00.)

14 ........... Diluent cap value (if the cap is replacing a CO2 measurement, it shall be 5.0 percent for boilers and 1.0 percent for turbines; if it is

replacing an O2 measurement, it shall be 14.0 percent for boilers and 19.0 percent for turbines.

15 ........... Fuel analysis data from appendix G to this part for CO2 mass emissions. (This code is optional through 12/31/99, and shall not be

used after 1/1/00.)

16 ........... SO2 concentration value of 2 ppm during hours when only natural gas (or fuel with equivalent sulfur content) is combusted.

19 ........... 200.0 percent of the MPC; default high range value.

20 ........... 200.0 percent of the full-scale range setting (full-scale exceedance of high range).

40 ........... Stack volumetric flow calculated using the procedures of appendix I.

54 ........... Other quality assured methodologies approved through petition. These hours are included in missing data lookback and are included

as unavailable hours for percent monitor availability calculations.

55 ........... Other substitute data approved through petition. These hours are not included in missing data lookback and are included as unavailable hours for percent monitor availability calculations.

(d) NOX emission record provisions.

The owner or operator shall record the

information required by this paragraph

for each affected unit for each hour, or

partial hour during which the unit

operates, except for a gas-fired peaking

unit or oil-fired peaking unit for which

the owner or operator is using the

optional protocol in appendix E to this

part or a low mass emissions unit for

which the owner or operator is using the

optional low mass emissions excepted

methodology in § 75.19(c) for estimating

NOX emission rate. For each NOX

emission rate as measured and reported

from the certified primary monitor,

certified back-up monitor, or other

approved method of emissions

determination:

(1) Component system identification

code, as provided in § 75.53 (including

identification code for the moisture

monitoring system, if applicable);

(2) Date and hour;

(3) Hourly average concentration

(ppm, rounded to the nearest tenth);

(4) Hourly average diluent gas

concentration (percent O2 or percent

CO2, rounded to the nearest tenth) and,

if applicable, the hourly average

moisture content of the stack gas

(percent H2O, rounded to the nearest

tenth). If the continuous moisture

monitoring system consists of wet- and

dry-basis oxygen analyzers, also record

both the hourly wet- and dry-basis

oxygen readings (in percent O2, rounded

to the nearest tenth);

(5) Hourly average NOX emission rate

(lb/mmBtu, rounded either to the

nearest hundredth or thousandth prior

to January 1, 2000 and rounded to the

nearest thousandth on and after January

1, 2000);

(6) Hourly average NOX emission rate

(lb/mmBtu, rounded either to the

nearest hundredth or thousandth prior

to January 1, 2000 and rounded to the

nearest thousandth on and after January

1, 2000), adjusted for bias if bias

adjustment factor is required, as

provided in § 75.24(d). The requirement

to report hourly NOX emission rates to

the nearest thousandth shall not affect

NOX compliance determinations under

part 76 of this chapter; compliance with

each applicable emission limit under

part 76 shall be determined to the

nearest hundredth pound per million

Btu;

(7) Percent monitoring system data

availability (recorded to the nearest

tenth of a percent), for the NOX
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28139

monitoring system, and, if applicable,

separately for the moisture monitoring

system, calculated pursuant to § 75.32;

(8) Method of determination for

hourly average NOX emission rate using

Codes 1–55 in Table 4a of this section;

(9) Identification code for emissions

formulas used to derive hourly average

NOX emission rate and total NOX mass,

as provided in § 75.53, and F-factor used

to convert NOX concentrations into

emission rates;

(e) CO2 emission record provisions.

Except for a low mass emissions unit for

which the owner or operator is using the

optional low mass emissions excepted

methodology in § 75.19(c) for estimating

CO2 mass emissions, the owner or

operator shall record or calculate CO2

emissions for each affected unit using

one of the following methods specified

in this section:

(1) If the owner or operator chooses to

use a CO2 continuous emission

monitoring system (including an O2

monitor and flow monitor, as specified

in appendix F to this part), then the

owner or operator shall record for each

hour or partial hour during which the

unit operates the following information

for CO2 mass emissions, as measured

and reported from the certified primary

monitor, certified back-up monitor, or

other approved method of emissions

determination:

(i) Component/system identification

code, as provided in § 75.53;

(ii) Date and hour;

(iii) Hourly average CO2 concentration

(in percent, rounded to the nearest

tenth);

(iv) Hourly average volumetric flow

rate (scfh, rounded to the nearest

thousand scfh);

(v) Hourly average moisture content of

flue gas (percent, rounded to the nearest

tenth), where CO2 concentration is

measured on a dry basis. If the

continuous moisture monitoring system

consists of wet- and dry-basis oxygen

analyzers, also record both the hourly

wet- and dry-basis oxygen readings (in

percent O2, rounded to the nearest

tenth);

(vi) Hourly average CO2 mass

emission rate (tons/hr, rounded to the

nearest tenth);

(vii) Percent monitor data availability

for both the CO2 monitoring system and,

if applicable, the moisture monitoring

system (recorded to the nearest tenth of

a percent), calculated pursuant to

§ 75.32;

(viii) Method of determination for

hourly average CO2 mass emission rate

using Codes 1–55 in Table 4a of this

section;

(ix) Identification code for emissions

formula used to derive hourly average

CO2 mass emission rate, as provided in

§ 75.53; and

(x) Indication of whether the diluent

cap was used for CO2 calculation for the

hour.

(2) As an alternative to paragraph

(e)(1) of this section, the owner or

operator may use the procedures in

§ 75.13 and in appendix G to this part,

and shall record daily the following

information for CO2 mass emissions:

(i) Date;

(ii) Daily combustion-formed CO2

mass emissions (tons/day, rounded to

the nearest tenth);

(iii) For coal-fired units, flag

indicating whether optional procedure

to adjust combustion-formed CO2 mass

emissions for carbon retained in flyash

has been used and, if so, the adjustment;

(iv) For a unit with a wet flue gas

desulfurization system or other controls

generating CO2, daily sorbent-related

CO2 mass emissions (tons/day, rounded

to the nearest tenth); and

(v) For a unit with a wet flue gas

desulfurization system or other controls

generating CO2, total daily CO2 mass

emissions (tons/day, rounded to the

nearest tenth) as sum of combustionformed emissions and sorbent-related

emissions.

(f) Opacity records. The owner or

operator shall record opacity data as

specified by the State or local air

pollution control agency. If the State or

local air pollution control agency does

not specify recordkeeping requirements

for opacity, then record the information

required by paragraphs (f) (1) through

(5) of this section for each affected unit,

except as provided in § 75.14 (b), (c),

and (d). The owner or operator shall

also keep records of all incidents of

opacity monitor downtime during unit

operation, including reason(s) for the

monitor outage(s) and any corrective

action(s) taken for opacity, as measured

and reported by the continuous opacity

monitoring system:

(1) Component/system identification

code;

(2) Date, hour, and minute;

(3) Average opacity of emissions for

each six minute averaging period (in

percent opacity);

(4) If the average opacity of emissions

exceeds the applicable standard, then a

code indicating such an exceedance has

occurred; and

(5) Percent monitor data availability

(recorded to the nearest tenth of a

percent), calculated according to the

requirements of the procedure

recommended for State Implementation

Plans in appendix M to part 51 of this

chapter.

(g) O2-diluent record provisions. The

owner or operator of a unit using a flow

monitor and an O2-diluent monitor to

determine heat input, in accordance

with Equation F–17 or F–18 of appendix

F to this part, shall keep the following

records for the O2-diluent monitor:

(1) Component-system identification

code, as provided in § 75.53;

(2) Date and hour;

(3) Hourly average O2 concentration

(in percent, rounded to the nearest

tenth);

(4) Percent monitor data availability

(recorded to the nearest tenth of a

percent), calculated pursuant to § 75.32;

(5) Method of determination code for

O2 concentration data using Codes 1–55,

substituting the words ‘‘O2

concentrations’’ and ‘‘O2 concentration’’

for the words ‘‘CO2 concentrations’’ and

CO2 concentration’’ in the descriptions

of Codes 6 and 7 in Table 4a of this

section, respectively.

(h) Missing data records. The owner

or operator shall record the causes of

any missing data periods and the

actions taken by the owner or operator

to cure such causes.

(i) Compliance dates. Beginning on

January 1, 2000, the owner or operator

shall comply with the provisions in

paragraphs (a), (b), (e) and (f) of this

section only. Before January 1, 2000, the

owner or operator shall comply with

either paragraphs (a) through (d) or

paragraphs (a), (b), (c), and (f) of this

section, except that the owner or

operator shall comply with provisions

in paragraphs (e) and (f) of this section

only before January 1, 2000, when those

provisions support a regulatory option

provided in another section of this part

75 and the regulatory option is

exercised before January 1, 2000.

39. Section 75.58 is added to read as

follows:

§ 75.58 General recordkeeping provisions

for specific situations.

(a) Specific SO2 emission record

provisions for units with qualifying

Phase I technology. In addition to the

SO2 emissions information required in

§ 75.54(c), from January 1, 1997 through

December 31, 1999, the owner or

operator shall record the applicable

information in this paragraph for each

affected unit on which SO2 emission

controls have been installed and

operated for the purpose of meeting

qualifying Phase I technology

requirements pursuant to § 72.42 of this

chapter and § 75.15.

(1) For units with post-combustion

emission controls:

(i) Component/system identification

codes for each inlet and outlet SO2-

diluent continuous emission monitoring

system;

(ii) Date and hour;
28140 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

(iii) Hourly average inlet SO2

emission rate during unit operation (lb/

mmBtu, rounded to nearest hundredth);

(iv) Hourly average outlet SO2

emission rate during unit operation (lb/

mmBtu, rounded to nearest hundredth);

(v) Percent data availability for both

inlet and outlet SO2-diluent continuous

emission monitoring systems (recorded

to the nearest tenth of a percent),

calculated pursuant to Equation 8 of

§ 75.32 (for the first 8,760 unit operating

hours following initial certification) and

Equation 9 of § 75.32, thereafter; and

(vi) Identification code for emissions

formula used to derive hourly average

inlet and outlet SO2 mass emissions

rates for each affected unit or group of

units using a common stack.

(2) For units with combustion and/or

pre-combustion emission controls:

(i) Component/system identification

codes for each outlet SO2-diluent

continuous emission monitoring system;

(ii) Date and hour;

(iii) Hourly average outlet SO2

emission rate during unit operation (lb/

mmBtu, rounded to nearest hundredth);

(iv) For units with combustion

controls, average daily inlet SO2

emission rate (lb/mmBtu, rounded to

nearest hundredth), determined by coal

sampling and analysis procedures in

§ 75.15; and

(v) For units with pre-combustion

controls (i.e., fuel pretreatment), fuel

analysis demonstrating the weight,

sulfur content, and gross calorific value

of the product and raw fuel lots.

(b) Specific parametric data record

provisions for calculating substitute

emissions data for units with add-on

emission controls. In accordance with

§ 75.34, the owner or operator of an

affected unit with add-on emission

controls shall either record the

applicable information in paragraph

(b)(3) of this section for each hour of

missing SO2 concentration data or NOX

emission rate (in addition to other

information), or shall record the

information in paragraph (b)(1) of this

section for SO2 or paragraph (b)(2) of

this section for NOX through an

automated data acquisition and

handling system, as appropriate to the

type of add-on emission controls:

(1) For units with add-on SO2

emission controls petitioning to use or

using the optional parametric

monitoring procedures in appendix C to

this part, for each hour of missing SO2

concentration or volumetric flow data:

(i) The information required in

§ 75.54(b) or § 75.57(b) for SO2

concentration and volumetric flow, if

either one of these monitors is still

operating;

(ii) Date and hour;

(iii) Number of operating scrubber

modules;

(iv) Total feedrate of slurry to each

operating scrubber module (gal/min);

(v) Pressure differential across each

operating scrubber module (inches of

water column);

(vi) For a unit with a wet flue gas

desulfurization system, an in-line

measure of absorber pH for each

operating scrubber module;

(vii) For a unit with a dry flue gas

desulfurization system, the inlet and

outlet temperatures across each

operating scrubber module;

(viii) For a unit with a wet flue gas

desulfurization system, the percent

solids in slurry for each scrubber

module.

(ix) For a unit with a dry flue gas

desulfurization system, the slurry feed

rate (gal/min) to the atomizer nozzle;

(x) For a unit with SO2 add-on

emission controls other than wet or dry

limestone, corresponding parameters

approved by the Administrator;

(xi) Method of determination of SO2

concentration and volumetric flow

using Codes 1–55 in Table 4 of § 75.54

or Table 4a of § 75.57; and

(xii) Inlet and outlet SO2

concentration values, recorded by an

SO2 continuous emission monitoring

system, and the removal efficiency of

the add-on emission controls.

(2) For units with add-on emission

controls petitioning to use or using the

optional parametric monitoring

procedures in appendix C to this part,

for each hour of missing NOX emission

rate data:

(i) Date and hour;

(ii) Inlet air flow rate (scfh, rounded

to the nearest thousand);

(iii) Excess O2 concentration of flue

gas at stack outlet (percent, rounded to

nearest tenth of a percent);

(iv) Carbon monoxide concentration

of flue gas at stack outlet (ppm, rounded

to the nearest tenth);

(v) Temperature of flue gas at furnace

exit or economizer outlet duct (°F);

(vi) Other parameters specific to NOX

emission controls (e.g., average hourly

reagent feedrate);

(vii) Method of determination of NOX

emission rate using Codes 1–55 in Table

4 of § 75.54 or Table 4a of § 75.57; and

(viii) Inlet and outlet NOX emission

rate values recorded by a NOX

continuous emission monitoring system

and the removal efficiency of the addon emission controls.

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

emission controls following the

provisions of § 75.34(a)(1) or (a)(2), the

owner or operator shall, for each hour

of missing SO2 or NOX emission data,

record:

(i) Parametric data which demonstrate

the proper operation of the add-on

emission controls, as described in the

quality assurance/quality control

program for the unit. The parametric

data shall be maintained on site and

shall be submitted, upon request, to the

Administrator, EPA Regional office,

State, or local agency;

(ii) A flag indicating either that the

add-on emission controls are operating

properly, as evidenced by all parameters

being within the ranges specified in the

quality assurance/quality control

program, or that the add-on emission

controls are not operating properly;

(iii) For units petitioning under

§ 75.66 for substituting a representative

SO2 concentration during missing data

periods, any available inlet and outlet

SO2 concentration values recorded by

an SO2 continuous emission monitoring

system; and

(iv) For units petitioning under

§ 75.66 for substituting a representative

NOX emission rate during missing data

periods, any available inlet and outlet

NOX emission rate values recorded by a

continuous emission monitoring system.

(c) Specific SO2 emission record

provisions for gas-fired or oil-fired units

using optional protocol in appendix D

to this part. In lieu of recording the

information in § 75.54(c) or § 75.57(c),

the owner or operator shall record the

applicable information in this paragraph

for each affected gas-fired or oil-fired

unit for which the owner or operator is

using the optional protocol in appendix

D to this part for estimating SO2 mass

emissions.

(1) For each hour when the unit is

combusting oil:

(i) Date and hour;

(ii) Hourly average flow rate of oil,

while the unit combusts oil, with the

units in which oil flow is recorded (gal/

hr, lb/hr, m3/hr, or bbl/hr, rounded to

the nearest tenth) (flag value if derived

from missing data procedures);

(iii) Sulfur content of oil sample used

to determine SO2 mass emission rate

(rounded to nearest hundredth for diesel

fuel or to the nearest tenth of a percent

for other fuel oil) (flag value if derived

from missing data procedures);

(iv) Method of oil sampling (flow

proportional, continuous drip, as

delivered, manual from storage tank, or

daily manual);

(v) Mass rate of oil combusted each

hour (lb/hr, rounded to the nearest

tenth) (flag value if derived from

missing data procedures);

(vi) SO2 mass emission rate from oil

(lb/hr, rounded to the nearest tenth);

(vii) For units using volumetric oil

flowmeters, density of oil with the units

in which oil density is recorded (flag
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28141

value if derived from missing data

procedures);

(viii) Gross calorific value (heat

content) of oil used to determine heat

input (Btu/mass unit) (flag value if

derived from missing data procedures);

(ix) Hourly heat input rate from oil,

according to procedures in appendix F

to this part (mmBtu/hr, to the nearest

tenth);

(x) Fuel usage time for combustion of

oil during the hour (rounded up to the

nearest fraction of an hour (in equal

increments that can range from one

hundredth to one quarter of an hour, at

the option of the owner or operator))

(flag to indicate multiple/single fuel

types combusted); and

(xi) Monitoring system identification

code.

(2) For gas-fired units or oil-fired

units using the optional protocol in

appendix D to this part for daily manual

oil sampling, when the unit is

combusting oil, the highest sulfur

content recorded from the most recent

30 daily oil samples (rounded to nearest

tenth of a percent).

(3) For gas-fired units or oil-fired

units, using the optional protocol in

appendix D to this part for using an

assumed sulfur content or density, or for

as-delivered fuel sampled from each

delivery:

(i) Record the measured sulfur

content, GCV and, if applicable, density

from each fuel sample; and

(ii) Record and report the assumed

sulfur content, GCV and, if applicable,

density used to calculate SO2 mass

emission rate or heat input rate.

(4) For each hour when the unit is

combusting gaseous fuel:

(i) Date and hour;

(ii) Hourly heat input rate from

gaseous fuel, according to procedures in

appendix F to this part (mmBtu/hr,

rounded to the nearest tenth);

(iii) Sulfur content or SO2 emission

rate, in one of the following formats, in

accordance with the appropriate

procedure from appendix D to this part:

(A) Sulfur content of gas sample

(rounded to the nearest 0.1 grains/100

scf) (flag value if derived from missing

data procedures); or

(B) SO2 emission rate from NADB or

default SO2 emission rate of 0.0006 lb/

mmBtu for pipeline natural gas;

(iv) Hourly flow rate of gaseous fuel,

while the unit combusts gas (100 scfh)

(flag value if derived from missing data

procedures);

(v) Gross calorific value (heat content)

of gaseous fuel used to determine heat

input rate (Btu/100 scf) (flag value if

derived from missing data procedures);

(vi) Heat input rate from gaseous fuel,

while the unit combusts gas (mmBtu/hr,

rounded to the nearest tenth);

(vii) SO2 mass emission rate due to

the combustion of gaseous fuels (lb/hr);

(viii) Fuel usage time for combustion

of gaseous fuel during the hour

(rounded up to the nearest fraction of an

hour (in equal increments that can range

from one hundredth to one quarter of an

hour, at the option of the owner or

operator)) (flag to indicate multiple/

single fuel types combusted); and

(ix) Monitoring system identification

code.

(5) For each oil sample or sample of

diesel fuel:

(i) Date of sampling;

(ii) Sulfur content (percent, rounded

to the nearest hundredth for diesel fuel

and to the nearest tenth for other fuel

oil) (flag value if derived from missing

data procedures);

(iii) Gross calorific value or heat

content (Btu/lb) (flag value if derived

from missing data procedures); and

(iv) Density or specific gravity, if

required to convert volume to mass (flag

value if derived from missing data

procedures).

(6) For each sample of gaseous fuel for

sulfur content:

(i) Date of sampling;

(ii) Sulfur content (grains/100 scf,

rounded to the nearest tenth) (flag value

if derived from missing data

procedures);

(7) For each sample of gaseous fuel for

gross calorific value:

(i) Date of sampling; and

(ii) Gross calorific value or heat

content (Btu/100 scf) (flag value if

derived from missing data procedures).

(8) For each oil sample or sample of

gaseous fuel:

(i) Type of oil or gas; and

(ii) Type of sulfur sampling and value

used in calculations.

(d) Specific NOX emission record

provisions for gas-fired peaking units or

oil-fired peaking units using optional

protocol in appendix E to this part. In

lieu of recording the information in

paragraph § 75.54(d) or § 75.57(d), the

owner or operator shall record the

applicable information in this paragraph

for each affected gas-fired peaking unit

or oil-fired peaking unit for which the

owner or operator is using the optional

protocol in appendix E to this part for

estimating NOX emission rate. The

owner or operator shall meet the

requirements of this section, except that

the requirements under paragraphs

(d)(1)(vii), (d)(2)(vii), and (d)(3)(vi) of

this section shall become applicable on

the date on which the owner or operator

is required to monitor, record, and

report NOX mass emissions under an

applicable State or federal NOX mass

emission reduction program, if the

provisions of subpart H of this part are

adopted as requirements under such a

program.

(1) For each hour when the unit is

combusting oil:

(i) Date and hour;

(ii) Hourly average fuel flow rate of oil

while the unit combusts oil with the

units in which oil flow is recorded (gal/

hour, lb/hr, or bbl/hour) (flag value if

derived from missing data procedures);

(iii) Gross calorific value (heat

content) of oil used to determine heat

input (Btu/lb) (flag value if derived from

missing data procedures);

(iv) Hourly average NOX emission rate

from combustion of oil (lb/mmBtu);

(v) Heat input rate of oil (mmBtu/hr,

rounded to the nearest tenth;

(vi) Fuel usage time for combustion of

oil during the hour (rounded up to the

nearest fraction of an hour (in equal

increments that can range from one

hundredth to one quarter of an hour, at

the option of the owner or operator));

and

(vii) NOX mass emissions, calculated

in accordance with section 8.1 of

appendix F to this part.

(2) For each hour when the unit is

combusting gaseous fuel:

(i) Date and hour;

(ii) Hourly average fuel flow rate of

gaseous fuel, while the unit combusts

gas (100 scfh) (flag value if derived from

missing data procedures);

(iii) Gross calorific value (heat

content) of gaseous fuel used to

determine heat input (Btu/100 scf) (flag

value if derived from missing data

procedures);

(iv) Hourly average NOX emission rate

from combustion of gaseous fuel (lb/

mmBtu, rounded to nearest hundredth);

(v) Heat input rate from gaseous fuel,

while the unit combusts gas (mmBtu/hr,

rounded to the nearest tenth);

(vi) Fuel usage time for combustion of

gaseous fuel during the hour (rounded

up to the nearest fraction of an hour (in

equal increments that can range from

one hundredth to one quarter of an

hour, at the option of the owner or

operator)); and

(vii) NOX mass emissions, calculated

in accordance with section 8.1 of

appendix F to this part.

(3) For each hour when the unit

combusts any fuel:

(i) Date and hour;

(ii) Hourly average heat input rate

from all fuels (mmBtu/hr, rounded to

the nearest tenth);

(iii) Hourly average NOX emission rate

for the unit for all fuels;

(iv) For stationary gas turbines and

diesel or dual-fuel reciprocating

engines, hourly averages of operating

parameters under section 2.3 of

appendix E to this part (flag if value is
28142 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

outside of manufacturer’s recommended

range);

(v) For boilers, hourly average boiler

O2 reading (percent, rounded to the

nearest tenth) (flag if value exceeds by

more than 2 percentage points the O2

level recorded at the same heat input

during the previous NOX emission rate

test);

(vi) NOX mass emissions, calculated

in accordance with section 8.1 of

appendix F to this part;

(vii) Segment ID of the correlation

curve; and

(viii) Monitoring system identification

code.

(4) For each fuel sample:

(i) Date of sampling;

(ii) Gross calorific value (heat content)

(Btu/lb for oil, Btu/100 scf for gaseous

fuel); and

(iii) Density or specific gravity, if

required to convert volume to mass.

(e) Specific SO2 emission record

provisions during the combustion of

gaseous fuel. (1) If SO2 emissions are

determined in accordance with the

provisions in § 75.11(e)(2) during hours

in which only natural gas (or gaseous

fuel with a total sulfur content no

greater than the total sulfur content of

natural gas) is combusted in a unit with

an SO2 continuous emission monitoring

system, the owner or operator shall

record the information in paragraph

(c)(3) of this section in lieu of the

information in §§ 75.54(c)(1) and (c)(3)

or §§ 75.57(c)(1) and (c)(3), for those

hours.

(2) The provisions of this paragraph

apply to a unit which, in accordance

with the provisions of § 75.11(e)(3), uses

an SO2 continuous emission monitoring

system to determine SO2 emissions

during hours in which only natural gas

or gaseous fuel with a total sulfur

content no greater than the total sulfur

content of natural gas is combusted in

the unit. If the unit sometimes burns

only natural gas (or gaseous fuel with

total sulfur content no greater than the

total sulfur content of natural gas) as a

primary and/or backup fuel and at other

times combusts higher-sulfur fuels, such

as coal or oil, as primary and/or backup

fuel(s), then the owner or operator shall

keep records on-site, suitable for

inspection, of the type(s) of fuel(s)

burned during each period of missing

SO2 data and the number of hours that

each types of fuel was combusted in the

unit during each missing data period.

This recordkeeping requirement does

not apply to an affected unit that burns

natural gas (or gaseous fuel with a total

sulfur content no greater than the total

sulfur content of natural gas)

exclusively, nor does it apply to a unit

that burns such gaseous fuel(s) only

during unit startup.

(f) Specific SO2, NOX, and CO2 record

provisions for gas-fired or oil-fired units

using the optional low mass emissions

excepted methodology in § 75.19. In lieu

of recording the information in

§§ 75.54(b) through (e) or § 75.57(b)

through (e), the owner or operator shall

record, for each hour when the unit is

operating for any portion of the hour,

the following information for each

affected low mass emissions unit for

which the owner or operator is using the

optional low mass emissions excepted

methodology in § 75.19(c):

(1) Date and hour;

(2) Fuel type (pipeline natural gas,

natural gas, residual oil, or diesel fuel)

(note: if more than one type of fuel is

combusted in the hour, indicate the fuel

type which results in the highest

emission factors for SO2, CO2, and

NOX);

(3) Average hourly NOX emission rate

(lb/mmBtu, rounded to the nearest

thousandth);

(4) Hourly NOX mass emissions (lbs,

rounded to the nearest tenth);

(5) Hourly SO2 mass emissions (lbs,

rounded to the nearest tenth); and

(6) Hourly CO2 mass emissions (tons,

rounded to the nearest tenth).

(g) Specific provisions for gas-fired

units or oil-fired units using optional

protocol in appendix I to this part. In

addition to recording the information in

§ 75.54(c) or § 75.57(c), as applicable,

the owner or operator shall record the

applicable information in this paragraph

for each affected unit for which the

owner or operator is using the optional

protocol in appendix I to this part. This

includes:

(1) For each hour when the unit is

combusting oil:

(i) Date and hour;

(ii) Hourly average flow rate of oil

with the units in which oil flow is

recorded (gal/hr, lb/hr, m3/hr, or bbl/hr,

rounded to the nearest tenth) (flag value

if derived from missing data

procedures);

(iii) Method of oil sampling (flow

proportional, continuous drip, as

delivered, or manual);

(iv) Mass of oil combusted each hour

(lb/hr, rounded to the nearest tenth);

(v) For units using volumetric oil

flowmeters, density of oil (flag value if

derived from missing data procedures);

(vi) Gross calorific value (heat

content) of oil used to determine heat

input (Btu/mass unit) (flag value if

derived from missing data procedures);

(vii) Hourly heat input rate from oil,

according to procedures in appendix F

to this part (mmBtu/hr, to the nearest

tenth); and

(viii) Fuel usage time for combustion

of oil during the hour (rounded up to

the nearest 15 minutes).

(2) For each hour when the unit is

combusting gaseous fuel:

(i) Date and hour;

(ii) Hourly heat input rate from

gaseous fuel according to procedures in

appendix F to this part (mmBtu/hr,

rounded to the nearest tenth);

(iii) Hourly flow rate of gaseous fuel

(100 scfh) (flag value if derived from

missing data procedures);

(iv) Gross calorific value (heat

content) of gaseous fuel used to

determine heat input (Btu/100 scf) (flag

value if derived from missing data

procedures);

(v) Heat input rate from gaseous fuel

(mmBtu/hr, rounded to the nearest

tenth);

(vi) Fuel usage time for combustion of

gaseous fuel during the hour (rounded

up to the nearest 15 minutes); and

(vii) F-factor (Fc=Carbon-based Ffactor of 1040 scf CO2/mmBtu for

natural gas, or Fd=Dry basis, O2-based Ffactor of 8,710 dscf/mmBtu for natural

gas).

(3) For each oil sample or sample of

diesel fuel:

(i) Date of sampling;

(ii) Gross calorific value or heat

content (Btu/lb) (flag value if derived

from missing data procedures);

(iii) Density or specific gravity, if

required to convert volume to mass (flag

value if derived from missing data

procedures); and

(iv) Percent carbon by weight.

(4) For each monthly sample of

gaseous fuel:

(i) Date of sampling; and

(ii) Gross calorific value or heat

content (Btu/100 scf) (flag value if

derived from missing data procedures).

(5) Hourly average diluent gas

concentration (percent O2 or percent

CO2, rounded to the nearest tenth).

(h) Compliance dates. Beginning on

January 1, 2000, the owner or operator

shall comply with this section only.

Before January 1, 2000, the owner or

operator shall comply with either this

section or § 75.55; except that if a

regulatory option provided in another

section of this part 75 is exercised prior

to January 1, 2000, then the owner or

operator shall comply with any

provisions of this section that support

the regulatory option beginning with the

date on which the option is exercised.

40. Section 75.59 is added to read as

follows:

§ 75.59 Certification, quality assurance,

and quality control record provisions.

(a) Continuous emission or opacity

monitoring systems. The owner or
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28143

operator shall record the applicable

information in this section for each

certified monitor or certified monitoring

system (including certified backup

monitors) measuring and recording

emissions or flow from an affected unit.

(1) For each SO2 or NOX pollutant

concentration monitor, flow monitor,

CO2 monitor (including O2 monitors

used to determine CO2 emissions),

moisture sensor, or diluent gas monitor

(including wet-and dry-basis O2

monitors used to determine percent

moisture), the owner or operator shall

record the following for all daily and 7-

day calibration error tests, including any

follow-up tests after corrective

(i) Component/system identification

code;

(ii) Instrument span and span scale;

(iii) Date and hour;

(iv) Reference value (i.e., calibration

gas concentration or reference signal

value, in ppm or other appropriate

units);

(v) Observed value (monitor response

during calibration, in ppm or other

appropriate units);

(vi) Percent calibration error (rounded

to the nearest tenth of a percent) (flag if

using alternative performance

specification for low emitters or

differential pressure flow monitors);

(vii) Calibration gas level;

(viii) Test number and reason for test;

(ix) For 7-day calibration tests for

certification or recertification, a

certification from the cylinder gas

vendor or CEMS vendor that calibration

gas, as defined in § 72.2 of this chapter

and appendix A to this part, was used

to conduct calibration error testing;

(x) Description of any adjustments,

corrective actions, or maintenance

following test; and

(xi) For the qualifying test for off-line

calibration, the owner or operator shall

indicate whether the unit is off-line or

on-line.

(2) For each flow monitor, the owner

or operator shall record the following

for all daily interference checks,

including any follow-up tests after

corrective action:

(i) Code indicating whether monitor

passes or fails the interference check;

and

(ii) Description of any adjustments,

corrective actions, or maintenance

following test.

(3) For each SO2 or NOX pollutant

concentration monitor, CO2 monitor

(including O2 monitors used to

determine CO2 emissions), or diluent

gas monitor (including wet-and drybasis O2 monitors used to determine

percent moisture), the owner or operator

shall record the following for the initial

and all subsequent linearity check(s),

including any follow-up tests after

corrective action:

(i) Component/system identification

code;

(ii) Instrument span and span scale;

(iii) Date and hour;

(iv) Reference value (i.e., reference gas

concentration, in ppm or other

appropriate units);

(v) Observed value (average monitor

response at each reference gas

concentration, in ppm or other

appropriate units);

(vi) Percent error at each of three

reference gas concentrations (rounded to

nearest tenth of a percent) (flag if using

alternative performance specification);

(vii) Calibration gas level;

(viii) Mean of reference values and

mean of measured values;

(ix) Test number and reason for test

(flag if aborted test); and

(x) Description of any adjustments,

corrective action, or maintenance

following test.

(4) For each flow monitor (where

applicable) the owner or operator shall

record items in paragraphs (a)(4)(i)

through (v) of this section, for all

quarterly leak checks, including any

follow-up tests after corrective action,

and items in paragraphs (a)(4)(vi) and

(vii) of this section, for all flow-to-load

ratio and gross heat rate tests:

(i) Component/system identification

code;

(ii) Date and hour;

(iii) Reason for test;

(iv) Code indicating whether monitor

passes or fails the quarterly leak check;

(v) Description of any adjustments,

corrective actions, or maintenance

following test;

(vi) Test data from the flow-to-load

ratio or gross heat rate evaluation,

including:

(A) Component/system identification

code;

(B) Calendar year and quarter;

(C) Indication of whether the test is a

flow-to-load ratio or gross heat rate

evaluation;

(D) Indication of whether bias

adjusted flow rates were used;

(E) Average absolute percent

difference between reference ratio (or

BHR) and hourly ratios (or GHE values);

(F) Test result;

(G) Number of hours used in final

quarterly average;

(H) Number of hours exempted for use

of a different fuel type;

(I) Number of hours exempted for load

ramping up or down;

(J) Number of hours exempted for

scrubber bypass;

(K) Number of hours exempted for

hours preceding a normal-load flow

RATA; and

(L) Number of hours exempted for

hours preceding a successful diagnostic

test, following a documented monitor

repair or major component replacement;

and

(vii) Reference data for the flow-toload ratio or gross heat rate evaluation,

including:

(A) Reference flow RATA end date

and time;

(B) Test number;

(C) Reference RATA load and load

level;

(D) Average reference method flow

rate during reference flow RATA;

(E) Reference flow/load ratio;

(F) Average reference method diluent

gas concentration during flow RATA

and diluent gas units of measure;

(G) Fuel specific Fd- or Fc-factor

during flow RATA and F-factor units of

measure; and

(H) Reference gross heat rate value.

(5) For each SO2 pollutant

concentration monitor, flow monitor,

CO2 pollutant concentration monitor

(including any O2 concentration

monitor used to determine CO2 mass

emissions or heat input), NOX

continuous emission monitoring system,

SO2-diluent continuous emission

monitoring system, moisture monitoring

system, and approved alternative

monitoring system, the owner or

operator shall record the following

information for the initial and all

subsequent relative accuracy test audits:

(i) Reference method(s) used;

(ii) Individual test run data from the

relative accuracy test audit for the SO2

concentration monitor, flow monitor,

CO2 pollutant concentration monitor,

NOX continuous emission monitoring

system, SO2-diluent continuous

emission monitoring system, moisture

monitoring system, or approved

alternative monitoring systems,

including:

(A) Date, hour, and minute of

beginning of test run;

(B) Date, hour, and minute of end of

test run;

(C) System identification code;

(D) Test number and reason for test;

(E) Operating load level (low, mid,

high, or normal, as appropriate) and

number of load levels comprising test;

(F) Run number;

(G) Run data for monitor, in the

appropriate units of measure;

(H) Run data for reference method, in

the appropriate units of measure;

(I) Flag value (0, 1, or 9, as

appropriate) indicating whether run has

been used in calculating relative

accuracy and bias values or whether the

test was aborted prior to completion;

(J) Average gross unit load; and
28144 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

(K) Flag to indicate whether an

alternative performance specification

has been used.

(iii) Calculations and tabulated

results, as follows:

(A) Arithmetic mean of the

monitoring system measurement values,

of the reference method values, and of

their differences, as specified in

Equation A–7 in appendix A to this

part.

(B) Standard deviation, as specified in

Equation A–8 in appendix A to this

part.

(C) Confidence coefficient, as

specified in Equation A–9 in appendix

A to this part.

(D) Relative accuracy test results, as

specified in Equation A–10 in appendix

A to this part. (For multi-level flow

monitor tests the relative accuracy test

results shall be recorded at each load

level tested. Each load level shall be

expressed as a total gross unit load,

rounded to the nearest MWe, or as

steam load, rounded to the nearest

thousand lb/hr.)

(E) Bias test results as specified in

section 7.6.4 in appendix A to this part.

(F) Bias adjustment factor from

Equations A–11 and A–12 in appendix

A to this part for any monitoring system

that failed the bias test (except as

provided in section 7.6.5 of appendix A

to this part) and 1.000 for any

monitoring system that passed the bias

test. (For multi-load RATAs of flow

monitors only, when the bias test is

passed at the load level(s) designated as

normal in section 6.5.2.1 of appendix A

to this part, the system BAF shall be

recorded as 1.000. When the bias test is

failed at any load level designated as

normal in section 6.5.2.1 of appendix A

to this part, bias adjustment factors shall

be recorded at the two most frequently

used load levels, as defined in section

6.5.2.1 of appendix A to this part.)

(iv) Description of any adjustment,

corrective action, or maintenance

following test.

(v) F-factor value(s) used to convert

NOX pollutant concentration and

diluent gas (O2 or CO2) concentration

measurements into NOX emission rates

(in lb/mmBtu), heat input or CO2

emissions.

(vi) For flow monitors, the flow

polynomial equation used to linearize

the flow monitor and the numerical

values of the polynomial coefficients of

that equation.

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

pollutant concentration monitor, NOXdiluent continuous emission monitoring

system, or SO2-diluent continuous

emission monitoring system, the owner

or operator shall record the following

information for the cycle time test:

(i) Component/system identification

code;

(ii) Date;

(iii) Start and end times;

(iv) Upscale and downscale cycle

times for each component;

(v) Stable start monitor value;

(vi) Stable end monitor value;

(vii) Reference value of calibration

gas(es);

(viii) Calibration gas level; and

(ix) Cycle time result for the entire

system.

(x) Reason for test.

(7) The owner or operator shall also

record, for each relative accuracy test

audit, supporting information sufficient

to substantiate compliance with all

applicable sections and appendices in

this part. This RATA supporting

information shall include, but shall not

be limited to, the following data

elements:

(i) For each RATA using Reference

Method 2 (or its allowable alternatives)

in appendix A to part 60 of this chapter

to determine volumetric flow rate:

(A) Information indicating whether or

not the location meets requirements of

Method 1 in appendix A to part 60 of

this chapter; and

(B) Information indicating whether or

not the equipment passed the required

leak checks.

(ii) For each run of each RATA using

Reference Method 2 (or its allowable

alternatives) in appendix A to part 60 of

this chapter to determine volumetric

flow rate, record the following data

elements (as applicable to the

measurement method used):

(A) Operating load level (low, mid,

high, or normal, as appropriate);

(B) Number of reference method

traverse points;

(C) Average absolute stack gas

temperature (° F);

(D) Barometric pressure at test port

(inches of mercury);

(E) Stack static pressure (inches of

H2O);

(F) Absolute stack gas pressure

(inches of mercury);

(G) Percent CO2 and O2 in the stack

gas, dry basis;

(H) CO2 and O2 reference method

used;

(I) Moisture content of stack gas

(percent H2O);

(J) Molecular weight of stack gas, dry

basis (lb/lb-mole);

(K) Molecular weight of stack gas, wet

basis (lb/lb-mole);

(L) Stack diameter (or equivalent

diameter) at the test port (ft);

(M) Average square root of velocity

head of stack gas (inches of H2O) for the

run;

(N) Stack or duct cross-sectional area

at test port (ft 2);

(O) Average axial velocity (ft/sec); and

(P) Total volumetric flow rate (scfh,

wet basis).

(iii) For each traverse point of each

run of each RATA using Reference

Method 2 (or its allowable alternatives)

in appendix A to part 60 of this chapter

to determine volumetric flow rate,

record the following data elements (as

applicable to the measurement method

used):

(A) Reference method probe type;

(B) Pressure measurement device

type;

(C) Traverse point ID;

(D) Probe or pitot tube calibration

coefficient;

(E) Date of latest probe or pitot tube

calibration;

(F) ∆P at traverse point (inches of

H2O);

(G) Ts, stack temperature at the

traverse point (° F);

(H) Calculated impact (total) velocity

at the traverse point (ft/sec);

(I) Composite (wall effects) traverse

point identifier;

(J) Number of points included in

composite traverse point;

(K) Yaw angle of flow at traverse point

(degrees);

(L) Pitch angle of flow at traverse

point (degrees); and

(M) Calculated axial velocity at

traverse point (ft/sec).

(iv) For each RATA using Method 6C,

7E, or 3A in appendix A to part 60 of

this chapter to determine SO2, NOX,

CO2, or O2 concentration:

(A) Pollutant or diluent gas being

measured;

(B) Span of reference method

analyzer;

(C) Type of reference method system

(e.g., extractive or dilution type);

(D) Reference method dilution factor

(dilution type systems, only);

(E) Reference gas concentrations (zero,

mid, and high gas levels) used for the 3-

point pre-test analyzer calibration error

test (or for dilution type reference

method systems, for the 3-point pre-test

system calibration error test) and for any

subsequent recalibrations;

(F) Analyzer responses to the zero-,

mid-, and high-level calibration gases

during the 3-point pre-test analyzer (or

system) calibration error test and during

any subsequent recalibration(s);

(G) Analyzer calibration error at each

gas level (zero, mid, and high) for the 3-

point pre-test analyzer (or system)

calibration error test and for any

subsequent recalibration(s) (percent of

span value);

(H) Reference gas concentration (zero,

mid, or high gas levels) used for each

pre-run or post-run system bias check or

(for dilution type reference method
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28145

systems) for each pre-run or post-run

system calibration error check;

(I) Analyzer response to the

calibration gas for each pre-run or postrun system bias (or system calibration

error) check;

(J) The arithmetic average of the

analyzer responses to the zero-level gas,

for each pair of pre- and post-run system

bias (or system calibration error) checks;

(K) The arithmetic average of the

analyzer responses to the upscale

calibration gas, for each pair of pre-and

post-run system bias (or system

calibration error) checks;

(L) The results of each pre-run and

each post-run system bias (or system

calibration error) check using the zerolevel gas (percentage of span value);

(M) The results of each pre-run and

each post-run system bias (or system

calibration error) check using the

upscale calibration gas (percentage of

span value);

(N) Calibration drift and zero drift of

analyzer during each RATA run

(percentage of span value);

(O) Moisture basis of the reference

method analysis;

(P) Moisture content of stack gas, in

percent, during each test run (if needed

to convert to moisture basis of CEMS

being tested);

(Q) Unadjusted (raw) average

pollutant or diluent gas concentration

for each run;

(R) Average pollutant or diluent gas

concentration for each run, corrected for

calibration bias (or calibration error)

and, if applicable, corrected for

moisture;

(S) The F-factor used to convert

reference method data to units of lb/

mmBtu (if applicable);

(T) The code for the formula used to

convert reference method data to units

of lb/mmBtu (if applicable);

(U) Date(s) of the latest analyzer

interference test(s);

(V) Results of the latest analyzer

interference test(s);

(W) Date of the latest NO2 to NO

conversion test (Method 7E only);

(X) Results of the latest NO2 to NO

conversion test (Method 7E only); and

(Y) For each calibration gas cylinder

during each RATA, record the cylinder

gas vendor, cylinder number, expiration

date, pollutant(s) in the cylinder, and

certified gas concentration(s).

(v) For each test run of each moisture

determination using Method 4 in

appendix A to part 60 of this chapter (or

its allowable alternatives), whether the

determination is made to support a gas

RATA, to support a flow RATA, or to

quality assure the data from a

continuous moisture monitoring system,

record the following data elements (as

applicable to the moisture measurement

method used):

(A) Parameter (SO2, NOX, flow, CO2,

or H2O), to indicate whether the

moisture determination is used to

support a gas or flow rate RATA or

whether the determination is used to

quality assure a moisture monitoring

system;

(B) Test number;

(C) Run number;

(D) The beginning date, hour, and

minute of the run;

(E) The ending date, hour, and minute

or the run;

(F) Unit operating level (low, mid,

high, or normal, as appropriate);

(G) Moisture measurement method;

(H) Volume of H2O collected in the

impingers (ml);

(I) Mass of H2O collected in the silica

gel (g);

(J) Dry gas meter calibration factor;

(K) Average dry gas meter temperature

(°F);

(L) Barometric pressure (inches of

mercury);

(M) Differential pressure across the

orifice meter (inches of H2O);

(N) Initial and final dry gas meter

readings (ft3);

(O) Total sample gas volume,

corrected to standard conditions (dscf);

and

(P) Percentage of moisture in the stack

gas (percent H2O).

(vi) The upper and lower boundaries

of the range of operation (as defined in

section 6.5.2.1 of appendix A to this

part) for the unit or common stack on

which the continuous emission

monitor(s) are installed, expressed in

megawatts or thousands of lb/hr of

steam;

(vii) The load level(s) designated as

normal in section 6.5.2.1 of appendix A

to this part for the unit or common stack

on which the continuous emission

monitor(s) are installed, expressed in

megawatts or thousands of lb/hr of

steam;

(viii) Except for peaking units, the two

load levels (i.e., low, mid, or high)

identified in section 6.5.2.1 of appendix

A to this part as the most frequently

used;

(ix) Except for peaking units, the

relative frequency (percentage) of

historical usage of each load level (low,

mid, and high) in the previous four QA

operating quarters, as determined in

section 6.5.2.1 of appendix A to this

part, to the nearest 0.1 percent. The

beginning and ending calendar quarters

in the historical look-back period shall

also be recorded. A summary of the data

used to determine the most frequently

and second most frequently used load

levels and the percentage of time that

each load level has been used

historically shall be kept on-site in a

format suitable for inspection;

(x) Indication of whether the unit/

stack qualifies for single load flow

RATA testing (operation for ≥ 85.0

percent of operating hours is at a single

load level); and

(xi) Date of the load analysis

described in paragraphs (a)(7)(vi)

through (a)(7)(x) of this section.

(8) For each certified continuous

emission monitoring system, continuous

opacity monitoring system, or

alternative monitoring system, the date

and description of each event which

requires recertification of the system

and the date and type of each test

performed to recertify the system in

accordance with § 75.20(b).

(9) Hardcopy quality assurance

relative accuracy test reports,

certification reports, or recertification

reports for pollutant concentration or

stack flow CEMS shall include, as a

minimum, the following elements (as

applicable to the type(s) of test(s)

performed):

(i) Summarized test results near the

front of the report;

(ii) DAHS printouts of the CEMS data

generated during the calibration error,

linearity, cycle time, and relative

accuracy tests;

(iii) For pollutant concentration

monitor relative accuracy tests at

normal operating load:

(A) The raw reference method data

from each run (usually in the form of a

computerized printout, showing a series

of one-minute readings and the run

average);

(B) The raw data and results for all

required pre-test and post-test quality

assurance checks (i.e., calibration gas

injections) of the reference method

analyzers;

(C) The raw data and results for any

moisture measurements made during

the relative accuracy testing;

(D) Tabulated, final, corrected

reference method run data (i.e., the

actual values used in the relative

accuracy calculations), along with the

equations used to convert the raw data

to the final values and example

calculations to demonstrate how the test

data were reduced;

(iv) For flow monitor relative

accuracy tests:

(A) The raw Reference Method 2 data,

including auxiliary moisture data (often

in the form of handwritten data sheets);

(B) The tabulated, final volumetric

flow rate values used in the relative

accuracy calculations (determined from

the Method 2 data and other necessary

measurements, e.g., moisture, stack

temperature and pressure, etc.), along
28146 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

with the equations used to convert the

raw data to the final values and example

calculations to demonstrate how the test

data were reduced;

(v) Calibration gas certificates for the

gases used in the linearity, calibration

error, and cycle time tests and for the

calibration gases used to quality assure

the gas monitor reference method data

during the relative accuracy test audit;

(vi) Laboratory calibrations of the

source sampling equipment;

(vii) A copy of the test protocol used

for the CEMS certifications or

recertifications, including narrative that

explains any testing abnormalities,

problematic sampling, and analytical

conditions that required a change to the

test protocol, and/or solutions to

technical problems encountered during

the testing program;

(viii) Diagrams illustrating test

locations and sample point locations (to

verify that locations are consistent with

presented information in the monitoring

plan). Include a discussion of any

special traversing or measurement

scheme. The discussion shall also

confirm that sample points satisfied

applicable acceptance criteria; and

(ix) Names of key personnel involved

in the test program, including test team

members, plant contacts, agency

representatives or test observers on site,

etc.

(10) Whenever reference methods are

used as backup monitoring systems

pursuant to § 75.20(d)(3), the owner or

operator shall record the following

information:

(i) For each test run using Reference

Method 2 (or its allowable alternatives)

in appendix A to part 60 of this chapter

to determine volumetric flow rate,

record the following data elements (as

applicable to the measurement method

used):

(A) Unit or stack identification

number;

(B) Reference method system and

component identification numbers;

(C) Run date and hour;

(D) The data elements in paragraph

(a)(7)(ii) of this section, except for

paragraphs (a)(7)(ii) (A), (F), (H), and

(L);

(E) Data element in paragraph

(a)(7)(iii)(A) of this section.

(ii) For each reference method test run

using Method 6C, 7E, or 3A in appendix

A to part 60 of this chapter to determine

SO2, NOX, CO2, or O2 concentration:

(A) Unit or stack identification

number;

(B) The reference method system and

component identification numbers;

(C) Run number;

(D) Run start date and hour;

(E) Run end date and hour;

(F) Data elements in paragraph

(a)(7)(iv) (B) through (I) and (L) through

(O) of this section; and

(G) Stack gas density adjustment

factor (if applicable).

(iii) For each hour of each reference

method test run using Method 6C, 7E,

or 3A in appendix A to part 60 of this

chapter to determine SO2, NOX, CO2, or

O2 concentration:

(A) Unit or stack identification

number;

(B) The reference method system and

component identification numbers;

(C) Run number;

(D) Run date and hour;

(E) Pollutant or diluent gas being

measured;

(F) Unadjusted (raw) average

pollutant or diluent gas concentration

for the hour; and

(G) Average pollutant or diluent gas

concentration for the hour, adjusted as

appropriate for moisture, calibration

bias (or calibration error) and stack gas

density.

(11) For each other quality-assurance

test or other quality assurance activity,

the owner or operator shall record the

following:

(i) Component/system identification

code;

(ii) Parameter;

(iii) Test or activity completion date

and hour;

(iv) Test or activity description;

(v) Test result;

(vi) Reason for test;

(vii) Test code.

(12) For each quality assurance test

extension or exemption request, the

owner or operator shall record the

following:

(i) For a RATA deadline extension or

exemption request:

(A) Monitoring system identification

code;

(B) Date of last RATA;

(C) RATA expiration date without

extension;

(D) RATA expiration date with

extension;

(E) Type of RATA extension of

exemption claimed or lost;

(F) Year to date hours of fuel usage

with a sulfur content >0.05 percent by

weight; and

(G) Year to date hours of nonredundant back-up CEMS use at the

unit/stack.

(ii) For a linearity test quarterly

exemption:

(A) Component/system identification

code; and

(B) Basis for exemption.

(iii) For a quality assurance test

extension claim based on a grace period:

(A) Component/system identification

code;

(B) Type of test;

(C) Beginning of grace period;

(D) Date and hour of completion of

required quality assurance test or

maximum allowable grace period if no

quality assurance test was completed

during the grace period; and

(E) Number of unit/stack operating

hours from the beginning of the grace

period to the completion of the quality

assurance test or the maximum

allowable grace period.

(13) An indication of which data have

been excluded from the quarterly span

and range evaluations of the SO2 and

NOX monitors and the reasons for

excluding the data, as required in

sections 2.1.1.5 and 2.1.2.5 of appendix

A to this part. For purposes of reporting

under § 75.64(a)(1), this information

shall be reported with the quarterly

report as descriptive text consistent

with § 75.64(g).

(b) Excepted monitoring systems for

gas-fired and oil-fired units. The owner

or operator shall record the applicable

information in this section for each

excepted monitoring system following

the requirements of appendix D to this

part or appendix E to this part for

determining and recording emissions

from an affected unit.

(1) For each oil-fired unit or gas-fired

unit using the optional procedures of

appendix D to this part for determining

SO2 mass emissions and/or heat input

or the optional procedures of appendix

E to this part for determining NOX

emission rate, for certification and

quality assurance testing of fuel

flowmeters tested against a reference

fuel flow rate (i.e., flow rate another fuel

flowmeter under section 2.1.5.2 of

appendix D to this part or flow rate from

a procedure according to a standard

incorporated by reference under section

2.1.5.1 of appendix D to this part):

(i) Date and hour of test completion;

(ii) Upper range value of the fuel

flowmeter;

(iii) Flowmeter measurements during

accuracy test (and mean of values),

including units of measure;

(iv) Reference flow rates during

accuracy test (and mean of values),

including units of measure;

(v) Average flowmeter accuracy as a

percent of upper range value for low,

mid, and high fuel flowrates;

(vi) Indicator of whether test method

was a lab comparison to reference meter

or an in-line comparison against a

master meter;

(vii) Test result (aborted, pass, or fail);

(viii) Component and system

identification numbers of the fuel

flowmeter being tested;
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28147

(ix) Date and hour fuel flowmeter was

reinstalled ( only for tests not performed

inline); and

(x) Description of fuel flowmeter

calibration specification or procedure

(in the certification application, or

periodically if a different method is

used for annual quality assurance

testing).

(2) For each transmitter or transducer

accuracy test for an orifice-, nozzle-, or

venturi-type flowmeter used under

section 2.1.6 of appendix D to this part:

(i) Date of test;

(ii) Full-scale value of the transmitter

or transducer;

(iii) Transmitter input (precalibration) prior to accuracy test,

including units of measure;

(iv) Expected transmitter output

during accuracy test (reference value

from NIST-traceable equipment),

including units of measure;

(v) Actual transmitter output during

accuracy test, including units of

measure;

(vi) Transmitter or transducer

accuracy as a percent of the full-scale

value;

(vii) Transmitter output level as a

percent of the full-scale value);

(viii) Transmitter or transducer

accuracy, as a percent of full-scale

value, and overall accuracy (if

applicable), as a percent of upper range

value;

(ix) Test and run number;

(x) Time of run (only for tests against

another flowmeter inline);

(xi) Component and system

identification numbers of the fuel

flowmeter being tested;

(xii) Transmitter or transducer type

(differential pressure, static pressure, or

temperature); and

(xiii) Test result.

(3) For each visual inspection of the

primary element or transmitter or

transducer accuracy test for an orifice-,

nozzle-, or venturi-type flowmeter

under sections 2.1.6.1 through 2.1.6.6 of

appendix D to this part:

(i) Date of inspection/test;

(ii) Hour of completion of inspection/

test;

(iii) Component and system

identification numbers of the fuel

flowmeter being inspected/tested; and

(iv) Results of inspection/test (pass or

fail).

(4) For fuel flowmeters that are tested

using the flow-to-load ratio procedures

of section 2.1.7 of appendix D to this

part:

(i) Test data for the fuel flowmeter

flow-to-load ratio or gross heat rate

check, including:

(A) Component/system identification

code;

(B) Calendar year and quarter;

(C) Indication of whether the test is

for flow-to-load ratio or gross heat rate;

(D) Test result;

(E) Number of hours excluded due to

co-firing;

(F) Number of hours excluded due to

ramping;

(G) Number of hours excluded for

lower 10.0 percent range of operation;

and

(H) Quarterly average absolute percent

difference between baseline ratio (or

baseline GHR) and hourly quarterly

ratios (or GHR value).

(ii) Reference data for the fuel

flowmeter flow-to-load ratio or gross

heat rate evaluation, including:

(A) Completion date and hour of most

recent primary element inspection;

(B) Completion date and hour of most

recent flowmeter or transmitter accuracy

test;

(C) Beginning and hour of baseline

period;

(D) Completion date and hour of

baseline period;

(E) Average fuel flow rate;

(F) Average load;

(G) Baseline fuel flow-to-load ratio

and fuel flow-to-load units of measure;

(H) Baseline GHR and GHR units;

(I) Number of hours excluded due to

ramping; and

(J) Number of hours excluded in lower

10.0 percent of range of operation.

(5) For gas-fired peaking units or oilfired peaking units using the optional

procedures of appendix E to this part,

for each initial performance, periodic, or

quality assurance/quality control-related

test:

(i) For each run of emission data;

(A) Run start date and time;

(B) Run end date and time;

(C) Fuel flow rate (lb/hr, gal/hr, scf/

hr, bbl/hr, or m3/hr);

(D) Gross calorific value (heat content)

of fuel (Btu/lb or Btu/scf);

(E) Density of fuel, and units of

measure for fuel density (if needed to

convert mass to volume);

(F) Total heat input during the run

(mmBtu);

(G) Hourly heat input rate for run

(mmBtu/hr);

(H) Response time of the O2 and NOX

reference method analyzers;

(I) NOX concentration (ppm);

(J) O2 concentration (percent O2);

(K) NOX emission rate (lb/mmBtu);

(L) Fuel or fuel combination (by heat

input fraction) combusted;

(M) Run number;

(N) Operating level;

(O) Elapsed time;

(P) Test number;

(Q) Monitoring system identification

code for appendix E system, and oil or

fuel flow system;

(R) Heat input from oil and/or gas

during the run;

(S) Volumetric flow of oil and/or gas

during the run, and units of measure for

volumetric flow; and

(T) Mass fuel flow during the run.

(ii) For each unit load and heat input:

(A) Average NOX emission rate (lb/

mmBtu);

(B) F-factor used in calculations;

(C) Average heat input rate (mmBtu/

hr);

(D) Unit operating parametric data

related to NOX formation for that unit

type (e.g., excess O2 level, water/fuel

ratio);

(E) Fuel or fuel combination (by heat

input fraction) combusted;

(F) Completion date and time of last

run in level; and

(G) Arithmetic mean of reference

method values at this level.

(c) For units with add-on SO2 and

NOX emission controls following the

provisions of § 75.34(a)(1) or (a)(2), the

owner or operator shall keep the

following records on-site in the quality

assurance/quality control plan required

by section 1 in appendix B to this part:

(1) A list of operating parameters for

the add-on emission controls, including

parameters in § 75.55(b), appropriate to

the particular installation of add-on

emission controls; and

(2) The range of each operating

parameter in the list that indicates the

add-on emission controls are properly

operating.

(d) Excepted flow monitoring systems

under appendix I. The owner or

operator shall record the applicable

information in this section for each

certified excepted flow monitoring

system under appendix I to this part

measuring and recording flow from an

affected unit.

(1) Certification test records. Record

the results of the following tests:

(i) For each CO2 or O2 component

monitor:

(A) 7-day calibration error tests, as

specified in paragraph (a)(1) of this

section;

(B) Cycle time test, as specified in

paragraph (a)(6) of this section; and

(C) Linearity checks, as specified in

paragraph (a)(3) of this section.

(ii) For each appendix I flow

monitoring system tested in a

component by component assessment:

(A) Flowmeter accuracy test data (or

a statement of calibration, if the

flowmeter meets the accuracy standard

by design), as specified in paragraph

(b)(1) of this section;

(B) Relative accuracy test and bias

data for the CO2 (or O2) monitor, as

specified in paragraphs (a)(5) and (a)(7)

of this section; and
28148 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

(C) Fuel sampling and analysis data,

as specified in section 2.3 of appendix

I to this part.

(iii) For each appendix I flow

monitoring system tested in a system

relative accuracy assessment:

(A) Relative accuracy test and bias

data for the appendix I flow monitoring

system, as specified for a flow

monitoring system in paragraphs (a)(5)

and (a)(7) of this section; and

(B) Fuel sampling and analysis data,

as specified in section 2.3 of appendix

I to this part.

(2) Quality assurance/quality control

test records. Record the results of the

following tests:

(i) For CO2 or O2 monitors:

(A) Daily calibration error tests, as

specified in paragraph (a)(1) of this

section; and

(B) Quarterly linearity checks, as

specified in paragraph (a)(3) of this

section.

(ii) For each appendix I flow

monitoring system tested in a

component-by-component assessment:

(A) Flowmeter accuracy test data, as

specified in paragraph (b)(1) or (b)(2) of

this section and paragraph (b)(3) or

(b)(4) of this section;

(B) Relative accuracy test and bias

data for the CO2 (or O2) monitor, as

specified in paragraphs (a)(5) and (a)(7)

of this section; and

(C) Fuel sampling and analysis data,

as specified in section 2.3 of appendix

I to this part.

(iii) For each appendix I flow

monitoring system tested in a system

relative accuracy assessment:

(A) Relative accuracy test and bias

data for the appendix I flow monitoring

system, as specified for a flow

monitoring system in paragraphs (a)(5)

and (a)(7) of this section; and

(B) Fuel sampling and analysis data,

as specified in section 2.3 of appendix

I to this part.

(e) Compliance dates. Beginning on

January 1, 2000, the owner or operator

shall comply with this section only.

Before January 1, 2000, the owner or

operator shall comply with either this

section or § 75.56; except that if a

regulatory option provided in another

section of this part 75 is exercised prior

to January 1, 2000, then the owner or

operator shall comply with any

provisions of this section that support

the regulatory option beginning with the

date on which the option is exercised.

41. Section 75.60 is amended by

revising paragraphs (a), (b)(1), and (b)(2)

and by adding new paragraphs (b)(3),

(b)(4), (b)(5) and (b)(6) to read as

follows:

§ 75.60 General provisions.

(a) The designated representative for

any affected unit subject to the

requirements of this part shall comply

with all reporting requirements in this

section and with the requirements of

§ 72.21 of this chapter for all

submissions.

(b) * * *

(1) Initial certifications. The

designated representative shall submit

initial certification applications

according to § 75.63.

(2) Recertifications. The designated

representative shall submit

recertification applications according to

§ 75.63.

(3) Monitoring plans. The designated

representative shall submit monitoring

plans according to § 75.62.

(4) Electronic quarterly reports. The

designated representative shall submit

electronic quarterly reports according to

§ 75.64.

(5) Other petitions and

communications. The designated

representative shall submit petitions,

correspondence, application forms,

designated representative signature, and

petition-related test results in hardcopy

to the Administrator. Additional

petition requirements are specified in

§§ 75.66 and 75.67.

(6) Quality assurance RATA reports. If

requested by the applicable EPA

Regional Office, appropriate State, and/

or appropriate local air pollution control

agency, the designated representative

shall submit the quality assurance

RATA report within 45 days after

completing a quality assurance RATA

according to section 2.3.1 of appendix B

to this part, or within 15 days of

receiving the request, whichever is later.

The designated representative shall

report the hardcopy information

required by § 75.59(a)(10) to the

applicable EPA Regional Office,

appropriate State, and/or appropriate

local air pollution control agency that

requested the RATA report.

* * * * *

42. Section 75.61 is amended by

revising paragraphs (a) introductory

text, (a)(1) introductory text, and (b) and

by adding a new paragraph (a)(1)(iv) to

read as follows:

§ 75.61 Notifications.

(a) Submission. The designated

representative for an affected unit (or

owner or operator, as specified) shall

submit notice to the Administrator, to

the appropriate EPA Regional Office,

and to the applicable State and local air

pollution control agencies for the

following purposes, as required by this

part.

(1) Initial certification and

recertification test notifications. The

owner or operator or designated

representative for an affected unit shall

submit written notification of initial

certification tests, recertification tests,

and revised test dates as specified in

§ 75.20 for continuous emission

monitoring systems, for alternative

monitoring systems under subpart E of

this part, or for excepted monitoring

systems under appendix E or I to this

part, except as provided in paragraphs

(a)(1)(iv) and (a)(4) of this section and

except for testing only of the data

acquisition and handling system.

* * * * *

(iv) Waiver from notification

requirements. The Administrator, the

appropriate EPA Regional Office, or the

applicable State or local air pollution

control agency may issue a waiver from

the requirement of paragraph (a)(1) of

this section to provide it for a unit or a

group of units for one or more

recertification tests. The Administrator,

the appropriate EPA Regional Office, or

the applicable State or local air

pollution control agency may also

discontinue the waiver and enforce the

requirement of paragraph (a)(1) of this

section to provide it notice of

recertification testing for future tests for

a unit or a group of units.

* * * * *

(b) The owner or operator or

designated representative shall submit

notification of certification tests and

recertification tests for continuous

opacity monitoring systems as specified

in § 75.20(c)(8) to the State or local air

pollution control agency.

* * * * *

43. Section 75.62 is amended by

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

follows:

§ 75.62 Monitoring plan.

(a) Submission.—(1) Electronic. Using

the format specified in paragraph (c) of

this section, the designated

representative for an affected unit shall

submit a complete, electronic, up-todate monitoring plan file (except for

hardcopy portions identified in

paragraph (a)(2) of this section) to the

Administrator: No later than 45 days

prior to the initial certification test; at

the time of recertification application

submission; and in each electronic

quarterly report.

(2) Hardcopy. The designated

representative shall submit all of the

hardcopy information required under

§ 75.53 to the appropriate EPA Regional

Office and the appropriate State and/or

local air pollution control agency prior

to initial certification. Thereafter, the
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28149

designated representative shall submit

hardcopy information only if that

portion of the monitoring plan is

revised. The designated representative

shall submit the required hardcopy

information: no later than 45 days prior

to the initial certification test; with any

recertification application, if a hardcopy

monitoring plan change is associated

with the recertification event; and

within 30 days of any other event with

which a hardcopy monitoring plan

change is associated, pursuant to

§ 75.53(b).

* * * * *

(c) Format. Each monitoring plan

shall be submitted in a format specified

by the Administrator.

44. Section 75.63 is revised to read as

follows:

§ 75.63 Initial certification or recertification

application.

(a) Submission. The designated

representative for an affected unit or a

combustion source shall submit

applications and reports as follows:

(1) Initial certifications. (i) Within 45

days after completing all initial

certification tests, submit to the

Administrator the electronic

information required by paragraph (b)(1)

of this section and a hardcopy

certification application form (EPA form

7610–14). Except for subpart E

applications or unless specifically

requested by the Administrator, do not

submit a hardcopy of the test data and

results to the Administrator.

(ii) Within 45 days after completing

all initial certification tests, submit the

hardcopy information required by

paragraph (b)(2) of this section to the

applicable EPA Regional Office and the

appropriate State and/or local air

pollution control agency.

(iii) For units for which the owner or

operator is applying for certification

approval of the optional excepted

methodology under § 75.19 for low mass

emissions units, submit:

(A) To the Administrator, the

electronic information required by

paragraph (b)(1)(i) of this section, the

hardcopy information required by

paragraph (b)(3) of this section, and a

hardcopy certification application form

(EPA form 7610–14) signed by the

designated representative.

(B) To the applicable EPA Regional

Office and appropriate State and/or

local air pollution control agency, the

hardcopy information required by

paragraphs (b)(2)(i), (iii), and (iv) of this

section and by paragraph (b)(3) of this

section.

(2) Recertifications. (i) Within 45 days

after completing all recertification tests,

submit to the Administrator the

electronic information required by (b)(1)

of this section and a hardcopy

certification application form (EPA form

7610–14). Except for subpart E

applications or unless specifically

requested by the Administrator, do not

submit a hardcopy of the test data and

results to the Administrator.

(ii) Within 45 days after completing

all recertification tests, submit the

hardcopy information required by

paragraph (b)(2) of this section to the

applicable EPA Regional Office and the

appropriate State and/or local air

pollution control agency. The applicable

EPA Regional Office or appropriate

State or local air pollution control

agency may waive the requirement for

submission to it of a hardcopy

recertification. The applicable EPA

Regional Office or the appropriate State

or local air pollution control agency

may also discontinue the waiver and

enforce the requirement of this

paragraph (a)(2)(ii) to provide a

hardcopy report of the recertification

test data and results.

(iii) Notwithstanding the

requirements of paragraphs (a)(2)(i) and

(a)(2)(ii) of this section, for an event for

which the Administrator determines

that only diagnostic tests (see § 75.20(b))

are required rather than a RATA, an

accuracy test of the fuel flowmeter, or a

retest of the appendix E NOX correlation

curve, no hardcopy submittal of any

kind is required; however, the results of

all diagnostic test(s) shall be submitted

in the electronic quarterly report

required under § 75.64. For DAHS

(missing data and formula) verifications,

neither a hardcopy nor an electronic

submittal of any kind is required; these

test results shall be kept on-site, suitable

for inspection.

(b) Contents. Each application for

initial certification or recertification

shall contain the following information,

as applicable:

(1) Electronic. (i) A complete, up-todate version of the electronic portion of

the monitoring plan, according to

§ 75.53(c) and (d), or § 75.53(e) and (f),

as applicable, in the format specified in

§ 75.62(c).

(ii) The results of the test(s) required

by § 75.20, including the type of test

conducted, testing date, information

required by § 75.56 or § 75.59, as

applicable, and the results of any failed

tests that affect data validation.

(2) Hardcopy. (i) Any changed

portions of the hardcopy monitoring

plan information required under

§ 75.53(c) and (d), or § 75.53(e) and (f),

as applicable.

(ii) The results of the test(s) required

by § 75.20, including the type of test

conducted, testing date, information

required by § 75.59(a)(10), and the

results of any failed tests that affect data

validation.

(iii) Certification or recertification

application form (EPA form 7610–14).

(iv) Designated representative

signature.

(3) If the owner or operator is

applying to use the optional low mass

emissions excepted methodology in

§ 75.19(c) in lieu of a certified

monitoring system,

(i) A statement that the unit burns

only natural gas or fuel oil and a list of

the fuels that are burned or a statement

that the unit is projected to burn only

natural gas or fuel oil and a list of the

fuels that are projected to be burned;

(ii) A statement that the unit meets

the applicability requirements in

§ 75.19(a) and (b); and

(iii) Any unit historical actual and

projected emissions data and calculated

emissions data demonstrating that the

affected unit qualifies as a low mass

emissions unit under § 75.19(a) and (b).

(c) Format. The electronic portion of

each certification or recertification

application shall be submitted in a

format to be specified by the

Administrator. The hardcopy test results

shall be submitted in a format suitable

for review and shall include the

information in § 75.59(a)(10).

45. Section 75.64 is amended by

revising paragraphs (a) introductory

text, (d), and (e); by redesignating

existing paragraphs (a)(1), (a)(2), (a)(3),

(a)(4), (a)(5), and (a)(6) as paragraphs

(a)(2), (a)(3), (a)(4), (a)(5),(a)(6) and

(a)(8), respectively; by revising newly

designated paragraphs (a)(2), and (a)(4);

by adding new paragraphs (a)(1), (a)(7),

(a)(9), (f), and (g); and by removing the

third sentence in paragraph (c), to read

as follows:

§ 75.64 Quarterly reports.

(a) Electronic submission. The

designated representative for an affected

unit shall electronically report the data

and information in paragraphs (a), (b),

and (c) of this section to the

Administrator quarterly, beginning with

the data from the later of: the last

(partial) calendar quarter of 1993 (where

the calendar quarter data begins at

November 15, 1993), the calendar

quarter corresponding to the date of

provisional certification, or the calendar

quarter corresponding to the relevant

deadline for initial certification in

§ 75.4(a), (b), or (c), whichever quarter is

earlier (where the report contains hourly

data beginning with the hour of

provisional certification or the hour

corresponding to the relevant

certification deadline, whichever is

earlier). For an affected unit subject to
28150 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

§ 75.4(d) that is shutdown on the

relevant compliance date in § 75.4(a),

the owner or operator shall submit

quarterly reports for the unit beginning

with the data from the quarter in which

the owner or operator recommences

commercial operation of the unit (where

the report contains hourly data

beginning with the first hour of

recommenced commercial operation of

the unit). For any provisionally-certified

monitoring system, § 75.20(a)(3) shall

apply for initial certifications, and

§ 75.20(b)(5) shall apply for

recertifications. Each electronic report

must be submitted to the Administrator

within 30 days following the end of

each calendar quarter. Each electronic

report shall include the date of report

generation, for the information provided

in paragraphs (a)(2) through (a)(9) of this

section, and shall also include for each

affected unit (or group of units using a

common stack):

(1) Facility information:

(i) Identification, including:

(A) Facility/ORISPL number;

(B) Calendar quarter and year data

contained in the report; and

(C) EDR version used for the report.

(ii) Location, including:

(A) Plant name and facility ID;

(B) EPA AIRS facility system ID;

(C) State facility ID;

(D) Source category/type;

(E) Primary SIC code;

(F) State postal abbreviation;

(G) County code; and

(H) Latitude and longitude.

(2) The information and hourly data

required in §§ 75.53 through 75.59,

excluding:

(i) Descriptions of adjustments,

corrective action, and maintenance;

(ii) Information which is incompatible

with electronic reporting (e.g., field data

sheets, lab analyses, quality control

plan);

(iii) Opacity data listed in § 75.54(f) or

§ 75.57(f), and in § 75.59(a)(9);

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

use the approved site-specific

parametric monitoring procedures for

calculation of substitute data, the

information in § 75.55(b)(3) or

§ 75.58(b)(3);

(v) The information recorded under

§ 75.56(a)(7) for the period prior to

January 1, 2000;

(vi) Information required by § 75.54(g)

or § 75.57(h) concerning the causes of

any missing data periods and the

actions taken to cure such causes; and

(vii) Hardcopy monitoring plan

information required by § 75.53 and

hardcopy test data and results required

by § 75.56 or § 75.59;

(viii) Records of flow polynomial

equations and numerical values

required by § 75.56(a)(5)(vii) or

§ 75.59(a)(5)(vi);

(ix) Daily fuel sampling information

required by § 75.58(c)(3)(i) for units

using assumed values under appendix

D;

(x) Information required by

§§ 75.59(b)(1)(ii), (iii), (iv), and (x), and

(b)(2) concerning fuel flowmeter

accuracy tests and transmitter/

transducer accuracy tests;

(xi) Stratification test results required

as part of the RATA supplementary

records under §§ 75.56(a)(7) or

75.59(a)(7);

(xii) Data and results of RATAs that

are aborted or invalidated due to

problems with the reference method or

operational problems with the unit and

data and results of linearity checks that

are aborted or invalidated due to

operational problems with the unit; and

(xiii) The summary of data used to

determine the percentage of historical

usage of each load level as required

under § 75.59(a)(8)(iv).

(xiv) Supplementary RATA

information required under

§§ 75.59(a)(7)(iv)(A), (U), (V), (W), (X),

and (Y).

* * * * *

(4) Average NOX emission rate (lb/

mmBtu, rounded to the nearest

hundredth prior to January 1, 2000 and

to the nearest thousandth on and after

January 1, 2000) during the quarter and

cumulative NOX emission rate for the

calendar year.

* * * * *

(7) Unit/stack/pipe operating hours

for quarter and cumulative unit/stack/

pipe operating hours for calendar year.

* * * * *

(9) For low mass emissions units for

which the owner or operator is using the

optional low mass emissions

methodology in § 75.19(c) to calculate

NOX mass emissions, the designated

representative must also report tons

(rounded to the nearest tenth) of NOX

emitted during the quarter and

cumulative NOX mass emissions for the

calendar year.

* * * * *

(d) Electronic format. Each quarterly

report shall be submitted in a format to

be specified by the Administrator,

including both electronic submission of

data and electronic or hardcopy

submission of compliance certifications.

(e) Phase I qualifying technology

reports. In addition to reporting the

information in paragraphs (a), (b), and

(c) of this section, the designated

representative for an affected unit on

which SO2 emission controls have been

installed and operated for the purpose

of meeting qualifying Phase I technology

requirements pursuant to § 72.42 of this

chapter shall also submit reports

documenting the measured percent SO2

emissions removal to the Administrator

on a quarterly basis, beginning the first

quarter of 1997 and continuing through

the fourth quarter of 1999. Each report

shall include all measurements and

calculations necessary to substantiate

that the qualifying technology achieves

the required percent reduction in SO2

emissions.

(f) Method of submission. Beginning

with the quarterly report for the first

quarter of the year 2000, all quarterly

reports shall be submitted to EPA by

direct computer-to-computer electronic

transfer via modem and EPA-provided

software, unless otherwise approved by

the Administrator.

(g) Any cover letter text

accompanying a quarterly report shall

either be submitted in hardcopy to the

Agency or be provided in electronic

format compatible with the other data

required to be reported under this

section.

46. Section 75.65 is revised to read as

follows:

§ 75.65 Opacity reports.

The owner or operator or designated

representative shall report excess

emissions of opacity recorded under

§ 75.54(f) or § 75.57(f), as applicable, to

the applicable State or local air

pollution control agency.

47. Section 75.66 is amended by

revising paragraphs (a) and the first

sentence of (e) introductory text; by

redesignating paragraph (i) as paragraph

(m) and revising it; and by adding

paragraphs (i) through (l), to read as

follows:

§ 75.66 Petitions to the Administrator.

(a) General. The designated

representative for an affected unit

subject to the requirements of this part

may submit a petition to the

Administrator requesting that the

Administrator exercise his or her

discretion to approve an alternative to

any requirement prescribed in this part

or incorporated by reference in this part.

Any such petition shall be submitted in

accordance with the requirements of

this section. The designated

representative shall comply with the

signatory requirements of § 72.21 of this

chapter for each submission.

* * * * *

(e) Parametric monitoring procedure

petitions. The designated representative

for an affected unit may submit a

petition to the Administrator, where

each petition shall contain the

information specified in § 75.55(b) or
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28151

§ 75.58(b), as applicable, for the use of

a parametric monitoring method. * * *

* * * * *

(i) Emergency fuel petition. The

designated representative for an affected

unit may submit a petition to the

Administrator to use the emergency fuel

provisions in Section 2.1.4 of Appendix

E of this part. The designated

representative shall include the

following information in the petition:

(1) Identification of the affected

unit(s);

(2) A procedure for determining the

NOX emission rate for the unit when the

emergency fuel is combusted; and

(3) A demonstration that the permit

restricts use of the fuel to emergencies

only.

(j) Petition for alternative method of

accounting for emissions prior to

completion of certification tests. The

designated representative for an affected

unit may submit a petition to the

Administrator to use an alternative to

the procedures in § 75.4 (d)(3), (e)(3),

(f)(3) and/or (g)(3) to account for

emissions during the period between

the compliance date for a unit and the

completion of certification testing for

that unit. The designated representative

shall include:

(1) Identification of the affected

unit(s);

(2) A detailed explanation of the

alternative method to account for

emissions of the following parameters,

as applicable: SO2 mass emissions (in

lbs), NOX emission rate (in lbs/mmbtu),

CO2 mass emissions (in lbs) and, if the

unit is subject to the requirements of

subpart H of this part, NOX mass

emissions (in lbs); and

(3) A demonstration that the proposed

alternative does not underestimate

emissions.

(k) Petition for an alternative to the

stabilization criteria for the cycle time

test in section 6.4 of Appendix A of this

part. The designated representative for

an affected unit may submit a petition

to the Administrator to use an

alternative stabilization criteria for the

cycle time test in section 6.4 of

Appendix A of this part, if the installed

monitoring system does not record data

in 1-minute or 3-minute intervals. The

designated representative shall provide

a description of the alternative criteria.

(l) Petition for an alternative to the

maximum rated hourly heat input used

to determine emissions under the low

mass emissions excepted methodology

in § 75.19. The designated

representative for an affected unit may

submit a petition to the Administrator to

use an alternative to the maximum rated

hourly heat input to determine

emissions under the low mass emissions

excepted methodology set forth in

§ 75.19. The designated representative

shall provide the following information:

(1) Identification of the affected

unit(s);

(2) Information demonstrating that the

maximum rated hourly heat input, as

defined in § 72.2 of this chapter, is not

representative of the unit’s current

capabilities because modifications have

been made to the unit, limiting its

capacity permanently; and

(3) Information documenting that the

proposed alternative maximum heat

input is representative of the unit’s

highest potential heat input.

(m) Any other petitions to the

Administrator under this part. Except

for petitions addressed in paragraphs (b)

through (l) of this section, any petition

submitted under this paragraph shall

include sufficient information for the

evaluation of the petition, including, at

a minimum, the following information:

(1) Identification of the affected

unit(s);

(2) A detailed explanation of why the

proposed alternative is being suggested

in lieu of the requirement;

(3) A description and diagram of any

equipment and procedures used in the

proposed alternative, if applicable;

(4) A demonstration that the proposed

alternative is consistent with the

purposes of the requirement for which

the alternative is proposed and is

consistent with the purposes of this part

and of section 412 of the Act and that

any adverse effect of approving such

alternative will be de minimis; and

(5) Any other relevant information

that the Administrator may require.

48. Subpart H is added to read as

follows:

Subpart H—NOX Mass Emissions

Provisions

Sec.

75.70 NOX mass emissions provisions.

75.71 Specific provisions for monitoring

NOX emission rate and heat input for the

purpose of calculating NOX mass

emissions.

75.72 Determination of NOX mass

emissions.

75.73 Recordkeeping and reporting.

Subpart H—NOX Mass Emissions

Provisions

§ 75.70 NOX mass emissions provisions.

(a) The owner or operator of a unit

shall comply with the requirements of

this subpart only if such compliance is

required by an applicable state or

federal NOX mass emission reduction

program that incorporates by reference,

or otherwise adopts the requirements of,

this subpart. For purposes of this

subpart, the term ‘‘affected unit’’ shall

mean any unit that is subject to a state

or federal NOX mass emission reduction

program requiring compliance with this

subpart, the term ‘‘nonaffected unit’’

shall mean any unit that is not subject

to such a program, the term ‘‘permitting

authority’’ shall mean the permitting

authority under an applicable state or

federal NOX mass emission reduction

program that adopts the requirements of

this subpart, and the term ‘‘designated

representative’’ shall mean the

responsible party under the applicable

state or federal NOX mass emission

reduction program that adopts the

requirements of this subpart. In

addition, as set forth in this subpart, the

provisions of subparts A, C, D, E, F, and

G and appendices A through G

applicable to NOX emission rate and

heat input shall apply to the owner or

operator of a unit required to meet the

requirements of this subpart by a state

or federal NOX mass emission reduction

program, except that the term ‘‘affected

unit’’ shall mean any unit that is subject

to a state or federal NOX mass emission

reduction program requiring compliance

with this subpart, the term ‘‘permitting

authority’’ shall mean the permitting

authority under an applicable state or

federal NOX mass emission reduction

program that adopts the requirements of

this subpart, and the term ‘‘designated

representative’’ shall mean the

responsible party under the applicable

state or federal NOX mass emission

reduction program that adopts the

requirements of this subpart.

(b) Compliance dates. The owner or

operator of an affected unit shall meet

the compliance deadlines established by

an applicable state or federal NOX mass

emission reduction program that adopts

the requirements of this subpart.

(c) Prohibitions. (1) No owner or

operator of an affected unit or a nonaffected unit under § 75.72(b)(2)(ii) shall

use any alternative monitoring system,

alternative reference method, or any

other alternative for the required

continuous emission monitoring system

without having obtained prior written

approval in accordance with paragraph

(g) of this section.

(2) No owner or operator of an

affected unit or a non-affected unit

under § 75.72(b)(2)(ii) shall operate the

unit so as to discharge, or allow to be

discharged emissions of NOX to the

atmosphere without accounting for all

such emissions in accordance with the

applicable provisions of this part.

(3) No owner or operator of an

affected unit or a non-affected unit

under § 75.72(b)(2)(ii) shall disrupt the

continuous emission monitoring system,

any portion thereof, or any other
28152 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

approved emission monitoring method,

and thereby avoid monitoring and

recording NOX mass emissions

discharged into the atmosphere, except

for periods of recertification or periods

when calibration, quality assurance

testing, or maintenance is performed in

accordance with the applicable

provisions of this part.

(4) No owner or operator of an

affected unit or a non-affected unit

under § 75.72(b)(2)(ii) shall retire or

permanently discontinue use of the

continuous emission monitoring system,

any component thereof, or any other

approved emission monitoring system

under this part, except under any one of

the following circumstances:

(i) During the period that the unit is

covered by a retired unit exemption

under § 96.5 that is in effect;

(ii) The owner or operator is

monitoring NOX mass emissions from

the affected unit with another certified

monitoring system approved, in

accordance with the provisions of

paragraph (d) of this section; or

(iii) The designated representative

submits notification of the date of

certification testing of a replacement

monitoring system in accordance with

§ 75.73(d)(5).

(d) Initial certification and

recertification procedures. (1) The

owner or operator of an affected unit

that is subject to an Acid Rain emissions

limitation shall comply with the initial

certification and recertification

procedures of this part except that:

(i) The owner or operator shall meet

any additional requirements set forth in

an applicable state or federal NOX mass

emission reduction program that adopts

the requirements of this subpart.

(ii) For any additional NOX emission

rate CEMS required under the common

stack provisions in § 75.72, the owner or

operator shall meet the requirements of

paragraph (d)(2) of this section.

(2) The owner or operator of an

affected unit that is not subject to an

Acid Rain emissions limitation shall

comply with the initial certification and

recertification procedures established by

an applicable state or federal NOX mass

emission reduction program that adopts

the requirements of this subpart. The

owner or operator of an affected unit

that is subject to an Acid Rain emissions

limitation shall, for any additional NOX

emission rate CEMS required under the

common stack provisions in § 75.72,

comply with the initial certification and

recertification procedures established by

an applicable state or federal NOX mass

emission reduction program that adopts

the requirements of this subpart.

(e) Quality assurance and quality

control requirements. The owner or

operator shall meet the quality

assurance and quality control

requirements in § 75.21.

(f) Missing data procedures. Except as

provided in § 75.34, the owner or

operator shall provide substitute data

for each affected unit and each nonaffected unit under § 75.72(b)(2)(ii)

using a continuous emissions

monitoring system in accordance with

the missing data procedures in subpart

D of this part whenever the unit

combusts fuel and:

(1) A valid quality assured hour of

NOX emission rate data (in lb/mmBtu)

has not been measured and recorded for

an affected unit or non-affected unit

under § 75.72(b)(2)(ii) by a certified NOX

continuous emission monitoring system

or by an approved monitoring system

under subpart E of this part;

(2) A valid quality assured hour of

flow data (in scfh) has not been

measured and recorded for an affected

unit or non-affected unit under

§ 75.72(b)(2)(ii) from a certified flow

monitor or by an approved alternative

monitoring system under subpart E of

this part; or

(3) A valid quality assured hour of

heat input data (in mmBtu) has not been

measured and recorded for an affected

unit from a certified flow monitor and

a certified diluent (CO2 or O2) monitor

or by an approved alternative

monitoring system under subpart E of

this part or by an accepted monitoring

system under appendix D to this part.

(g) Petitions. (1) The owner or

operator of an affected unit that is

subject to an Acid Rain emissions

limitation may submit a petition to the

Administrator requesting an alternative

to any requirement of this subpart. Such

a petition shall meet the requirements of

§ 75.66 and any additional requirements

established by an applicable state or

federal NOX mass emission reduction

program that adopts the requirements of

this subpart. Use of an alternative to any

requirement of this subpart is in

accordance with this subpart and with

such state or federal NOX mass emission

reduction program only to the extent

that the petition is approved by the

Administrator, in consultation with the

permitting authority.

(2) Notwithstanding paragraph (g)(1)

of this section, petitions requesting an

alternative to a requirement concerning

any additional CEMS required solely to

meet the common stack provisions of

§ 75.72, shall be submitted to the

permitting authority and the

Administrator and shall be governed by

paragraph (g)(3)(ii) of this section. Such

a petition shall meet the requirements of

§ 75.66 and any additional requirements

established by an applicable state or

federal NOX mass emission reduction

program that adopts the requirements of

this subpart.

(3)(i) The owner or operator of an

affected unit that is not subject to an

Acid Rain emissions limitation may

submit a petition to the permitting

authority and the Administrator

requesting an alternative to any

requirement of this subpart. Such a

petition shall meet the requirements of

§ 75.66 and any additional requirements

established by an applicable state or

federal NOX mass emission reduction

program that adopts the requirements of

this subpart.

(ii) Use of an alternative to any

requirement of this subpart is in

accordance with this subpart only to the

extent that it is approved by both the

permitting authority and the

Administrator.

§ 75.71 Specific provisions for monitoring

NOX emission rate and heat input for the

purpose of calculating NOX mass

emissions.

(a) Coal-fired units. The owner or

operator of an affected unit shall meet

the general operating requirements in

§ 75.10 for a NOX continuous emission

monitoring system (including a NOX

pollutant concentration monitor and an

O2- or CO2-diluent gas monitor) to

measure NOX emission rate and for a

continuous flow monitoring system and

an O2- or CO2-diluent gas monitor to

measure heat input, except as provided

by the Administrator in accordance with

subpart E of this part.

(b) Moisture correction. If a correction

for the stack gas moisture content is

needed to properly calculate the NOX

emission rate in lb/mmBtu (i.e., if the

NOX pollutant concentration monitor

measures on a different moisture basis

from the diluent monitor), the owner or

operator of an affected unit shall install,

operate, maintain, and quality assure a

continuous moisture monitoring system,

as defined in § 75.11(b).

(c) Gas-fired nonpeaking units or oilfired non-peaking units. The owner or

operator of an affected unit that

qualifies as a gas-fired or oil-fired unit

but not as a peaking unit, as defined in

§ 72.2 of this chapter, based on

information submitted by the designated

representative in the monitoring plan

shall either:

(1) Meet the requirements of

paragraph (a) of this section and, if

applicable, paragraph (b) of this section;

or

(2) Meet the general operating

requirements in § 75.10 for a NOX

continuous emission monitoring system,

except as provided, where applicable, in

paragraph (e)(2) of this section or by the
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28153

Administrator in accordance with

subpart E of this part, and use the

procedures specified in appendix D to

this part for determining hourly heat

input. However, the heat input

apportionment provisions in section

2.1.2 of appendix D to this part shall not

be used to meet the NOX mass reporting

provisions of this subpart.

(d) Peaking units that combust

natural gas or fuel oil. The owner or

operator of an affected unit that

combusts only natural gas or fuel oil

and that qualifies as a peaking unit, as

defined in § 72.2 of this chapter, based

on information submitted by the

designated representative in the

monitoring plan shall either:

(1) Meet the requirements of

paragraph (c) of this section; or

(2) Use the procedures in appendix D

to this part for determining hourly heat

input and the procedure specified in

appendix E to this part for estimating

hourly NOX emission rate. However, the

heat input apportionment provisions in

section 2.1.2 of appendix D to this part

shall not be used to meet the NOX mass

reporting provisions of this subpart. In

addition, if after certification of an

excepted monitoring system under

appendix E to this part, a unit’s

operations exceed a capacity factor of

20.0 percent in any calender year or

exceed a capacity factor of 10.0 percent

averaged over three years, the owner or

operator shall meet the requirements of

paragraph (c) of this section or, if

applicable, paragraph (e) of this section

by no later than December 31 of the

following calender year.

(e) Low mass emissions units.

Notwithstanding the requirements of

paragraphs (c) and (d) of this section,

the owner or operator of an affected unit

that qualifies as a low mass emissions

unit under § 75.19(a) shall comply with

one of the following:

(1) Meet the applicable requirements

specified in paragraph (c) or (d) of this

section for monitoring NOX emission

rate and heat input; or

(2) Use the low mass emissions

excepted methodology in § 75.19(c) for

estimating hourly emission rate, hourly

heat input, and hourly NOX mass

emissions.

(f) Other units. The owner or operator

of an affected unit that combusts wood,

refuse, or other materials shall comply

with the monitoring provisions

specified in paragraph (a) of this section

and, where applicable, paragraph (b) of

this section.

§ 75.72 Determination of NOX mass

emissions.

The owner or operator of an affected

unit shall calculate hourly NOX mass

emissions (in lbs) by multiplying the

hourly NOX emission rate (in lbs/

mmBtu) by the hourly heat input (in

mmBtu/hr) and the hourly operating

time (in hr). The owner or operator shall

also calculate quarterly and cumulative

year-to-date NOX mass emissions and

cumulative NOX mass emissions for the

ozone season (in tons) by summing the

hourly NOX mass emissions according

to the procedures in section 8 of

appendix F to this part.

(a) Unit utilizing common stack with

other affected unit(s). When an affected

unit utilizes a common stack with one

or more affected units, but no

nonaffected units, the owner or operator

shall either:

(1) Record the combined NOX mass

emissions for the units exhausting to the

common stack, install, certify, operate,

and maintain a NOX continuous

emissions monitoring system in the

common stack and:

(i) Install, certify, operate, and

maintain a continuous flow monitoring

system at the common stack; or

(ii) If all of the units using the

common stack are eligible to use the

procedures in appendix D to this part,

use the procedures in appendix D to this

part to determine heat input for each

affected unit and use the combined heat

input of all of the units exhausting to

the common stack for calculating NOX

mass emissions; however, the heat input

apportionment provisions in section

2.1.2 of appendix D to this part shall not

be used to meet the NOX mass reporting

provisions of this subpart; or

(2) Install, certify, operate, and

maintain a NOX continuous emissions

monitoring system in the duct to the

common stack from each affected unit

and:

(i) Install, certify, operate, and

maintain a flow monitor in the duct to

the common stack from each affected

unit; or

(ii)(A) For any unit using the common

stack and eligible to use the procedures

in appendix D to this part, use the

procedures in appendix D to determine

heat input for that affected unit.

However, the heat input apportionment

provisions in section 2.1.2 of appendix

D to this part shall not be used to meet

the mass reporting provisions of this

subpart; and

(B) Install, certify, operate, and

maintain a flow monitor in the duct to

the common stack for each remaining

affected unit.

(b) Unit utilizing common stack with

nonaffected unit(s). When one or more

affected units utilizes a common stack

with one or more nonaffected units, the

owner or operator shall either:

(1) Install, certify, operate, and

maintain a NOX continuous emission

monitoring system in the duct to the

common stack from each affected unit;

and

(i) Install, certify, operate, and

maintain a continuous flow monitoring

system in the duct to the common stack

from each affected unit; or

(ii)(A) For any unit using the common

stack and eligible to use the procedures

in appendix D to this part, use the

procedures in appendix D to determine

heat input for that affected unit;

however, the heat input apportionment

provisions in section 2.1.2 of appendix

D to this part shall not be used to meet

the mass reporting provisions of this

subpart; and

(B) Install, certify, operate, and

maintain a flow monitor in the duct to

the common stack for each remaining

affected unit that exhausts to the

common stack; or

(2) Install, certify, operate, and

maintain a NOX continuous emission

monitoring system in the common stack;

and

(i) Designate the nonaffected units as

affected units in accordance with the

applicable state or federal NOX mass

emissions reduction program and meet

the requirements of paragraph (a)(1) of

this section; or

(ii)(A) Install, certify, operate, and

maintain a continuous flow monitoring

system in the common stack and a NOX

continuous emission monitoring system

in the duct to the common stack from

each nonaffected unit and either install,

certify, operate, and maintain a

continuous flow monitoring system in

the duct from each nonaffected unit or,

for any nonaffected unit exhausting to

the common stack and otherwise

eligible to use the procedures in

appendix D to this part, determine heat

input using the procedures in appendix

D for that nonaffected unit (however,

the heat input apportionment provisions

in section 2.1.2 of appendix D to this

part shall not be used to meet the NOX

mass reporting provisions of this

subpart), and for any remaining

nonaffected unit that exhausts to the

common stack, install, certify, operate,

and maintain a flow monitor in the duct

to the common stack; and

(B) Submit a petition to the permitting

authority and the Administrator to

allow a method of calculating and

reporting the NOX mass emissions from

the affected units as the difference

between NOX mass emissions measured

in the common stack and NOX mass

emissions measured in the ducts of the

nonaffected units, not to be reported as

an hourly value less than zero. The

permitting authority and the
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Administrator may approve such a

method whenever the designated

representative demonstrates, to the

satisfaction of the permitting authority

and the Administrator, that the method

ensures that the NOX mass emissions

from the affected units are not

underestimated; or

(iii) Install a continuous flow

monitoring system in the common stack

and record the combined emissions

from all units as the combined NOX

mass emissions for the affected units for

recordkeeping and compliance

purposes; or

(iv) Submit a petition to the

permitting authority and the

Administrator to allow use of a method

for apportioning NOX mass emissions

measured in the common stack to each

of the units using the common stack and

for reporting the NOX mass emissions.

The permitting authority and the

Administrator may approve such a

method whenever the designated

representative demonstrates, to the

satisfaction of the permitting authority

and the Administrator, that the method

ensures that the NOX mass emissions

from the affected units are not

underestimated.

(c) Unit with bypass stack. Whenever

any portion of the flue gases from an

affected unit can be routed to avoid the

installed NOX continuous emissions

monitoring system, the owner and

operator shall either:

(1) Install, certify, operate, and

maintain a NOX continuous emissions

monitoring system and a continuous

flow monitoring system on the bypass

flue, duct, or stack gas stream and

calculate NOX mass emissions for the

unit as the sum of the emissions

recorded by all required monitoring

systems; or

(2) Monitor NOX mass emissions on

the bypass flue, duct, or stack gas stream

using the reference methods in

§ 75.22(b) for NOX concentration, flow,

and diluent and calculate NOX mass

emissions for the unit as the sum of the

emissions recorded by the installed

monitoring systems on the main stack

and the emissions measured by the

reference method monitoring systems.

(d) Unit with multiple stacks.

Notwithstanding § 75.17(c), when the

flue gases from an affected unit utilize

two or more ducts feeding into two or

more stacks (which may include flue

gases from other affected or nonaffected

unit(s)), or when the flue gases from an

affected unit utilize two or more ducts

feeding into a single stack and the

owner or operator chooses to monitor in

the ducts rather than in the stack, the

owner or operator shall either:

(1) Install, certify, operate, and

maintain a NOX continuous emission

monitoring system and a continuous

flow monitoring system in each duct

feeding into the stack or stacks and

determine NOX mass emissions from

each affected unit using the stack or

stacks as the sum of the NOX mass

emissions recorded for each duct; or

(2) Install, certify, operate, and

maintain a NOX continuous emissions

monitoring system and a continuous

flow monitoring system in each stack,

and determine NOX mass emissions

from the affected unit using the sum of

the NOX mass emissions recorded for

each stack, except that where another

unit also exhausts flue gases to one or

more of the stacks, the owner or

operator shall also comply with the

applicable requirements of paragraphs

(a) and (b) of this section to determine

and record NOX mass emissions from

the units using that stack; or

(3) If the unit is eligible to use the

procedures in appendix D to this part,

install, certify, operate, and maintain a

NOX continuous emissions monitoring

system in one of the ducts feeding into

the stack or stacks and use the

procedures in appendix D to this part to

determine heat input for the unit,

provided that:

(i) There are no add-on NOX controls

at the unit;

(ii) The unit is not capable of emitting

solely through an unmonitored stack

(i.e., has no dampers); and

(iii) The owner or operator of the unit

demonstrates to the satisfaction of the

permitting authority and the

Administrator that the NOX emission

rate in the monitored duct or stack is

representative of the NOX emission rate

in each duct or stack.

§ 75.73 Recordkeeping and reporting.

(a) General recordkeeping provisions.

The owner or operator of any affected

unit shall maintain for each affected

unit and each non-affected unit under

§ 75.72(b)(2)(ii) a file of all

measurements, data, reports, and other

information required by this part at the

source in a form suitable for inspection

for at least three (3) years from the date

of each record. Except for the

certification data required in

§ 75.57(a)(4) and the initial submission

of the monitoring plan required in

§ 75.57(a)(5), the data shall be collected

beginning with the earlier of the date of

provisional certification or the deadline

in § 75.70. The certification data

required in § 75.57(a)(4) shall be

collected beginning with the date of the

first certification test performed.

The file shall contain the following

information:

(1) The information required in

§§ 75.57(a)(2), (a)(4), (a)(5), (a)(6), (b),

(c)(2), (d), (g), and (h);

(2) The information required in

§§ 75.58 (b), (d), and (g);

(3) For each hour when the unit is

operating, NOX mass emissions,

calculated in accordance with section

8.1 of appendix F to this part;

(4) During the second and third

calendar quarters, cumulative ozone

season heat input and cumulative ozone

season operating hours;

(5) Heat input and NOX

methodologies for the hour;

(6) Specific heat input record

provisions for gas-fired or oil-fired units

using the procedures in appendix D to

this part. In lieu of the information

required in § 75.57(c)(2), the owner or

operator shall record the following

information in this paragraph for each

affected gas-fired or oil-fired unit and

each non-affected gas-or oil-fired unit

under § 75.72(b)(2)(ii) for which the

owner or operator is using the

procedures in appendix D to this part

for estimating heat input:

(i) For each hour when the unit is

combusting oil:

(A) Date and hour;

(B) Hourly average flow rate of oil,

while the unit combusts oil (in gal/hr,

lb/hr, m3/hr, or bbl/hr, rounded to the

nearest tenth) (flag value if derived from

missing data procedures);

(C) Method of oil sampling (flow

proportional, continuous drip, as

delivered, manual from storage tank, or

daily manual);

(D) Mass rate of oil combusted each

hour (in lb/hr, rounded to the nearest

tenth) (flag value if derived from

missing data procedures);

(E) For units using volumetric oil

flowmeters, density of oil (flag value if

derived from missing data procedures);

(F) Gross calorific value (heat content)

of oil used to determine heat input (in

Btu/mass unit) (flag value if derived

from missing data procedures);

(G) Hourly heat input rate from oil,

according to procedures in appendix F

to this part (in mmBtu/hr, to the nearest

tenth);

(H) Fuel usage time for combustion of

oil during the hour (rounded up to the

nearest fraction of an hour (in equal

increments that can range from one

hundredth to one quarter of an hour, at

the option of the owner or operator))

(flag to indicate multiple/single fuel

types combusted); and

(I) Monitoring system identification

code;

(ii) For gas-fired units or oil-fired

units, using the procedures in appendix

D to this part with an assumed density

or for as-delivered fuel sampled from

each delivery:
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28155

(A) Measured GCV and, if applicable,

density from each fuel sample; and

(B) Assumed GCV and, if applicable,

density used to calculate heat input rate;

(iii) For each hour when the unit is

combusting gaseous fuel:

(A) Date and hour;

(B) Hourly heat input rate from

gaseous fuel, according to procedures in

appendix F to this part (in mmBtu/hr,

rounded to the nearest tenth);

(C) Hourly flow rate of gaseous fuel,

while the unit combusts gas (in 100

scfh) (flag value if derived from missing

data procedures);

(D) Gross calorific value (heat content)

of gaseous fuel used to determine heat

input rate (in Btu/100 scf) (flag value if

derived from missing data procedures);

(E) Heat input rate from gaseous fuel,

while the unit combusts gas (in mmBtu/

hr, rounded to the nearest tenth);

(F) Fuel usage time for combustion of

gaseous fuel during the hour (rounded

up to the nearest fraction of an hour (in

equal increments that can range from

one hundredth to one quarter of an

hour, at the option of the owner or

operator)) (flag to indicate multiple/

single fuel types combusted); and

(G) Monitoring system identification

code;

(iv) For each oil sample or sample of

diesel fuel:

(A) Date of sampling;

(B) Gross calorific value or heat

content (in Btu/lb) (flag value if derived

from missing data procedures); and

(C) Density or specific gravity, if

required to convert volume to mass (flag

value if derived from missing data

procedures);

(v) For each sample of gaseous fuel:

(A) Date of sampling; and

(B) Gross calorific value or heat

content (in Btu/100 scf) (flag value if

derived from missing data procedures);

(vi) For each oil sample or sample of

gaseous fuel:

(A) Type of oil or gas; and

(B) Percent carbon or F-factor of fuel;

(7) Specific NOX, record provisions for

gas-fired or oil-fired units using the

optional low mass emissions excepted

methodology in § 75.19. In lieu of

recording the information in § 75.57(b),

(c)(2), (d), and (g), the owner or operator

shall record, for each hour when the

unit is operating for any portion of the

hour, the following information for each

affected low mass emissions unit for

which the owner or operator is using the

low mass emissions excepted

methodology in § 75.19(c):

(i) Date and hour;

(ii) If one type of fuel is combusted in

the hour, fuel type (pipeline natural gas,

natural gas, residual oil, or diesel fuel)

or, if more than one type of fuel is

combusted in the hour, the fuel type

which results in the highest emission

factors for NOX;

(iii) Average hourly NOX emission

rate (in lb/mmBtu, rounded to the

nearest thousandth); and

(iv) Hourly NOX mass emissions (in

lbs, rounded to the nearest tenth).

(b) Certification, quality assurance

and quality control record provisions.

The owner or operator of any affected

unit shall record the applicable

information in § 75.59 for each affected

unit or group of units monitored at a

common stack and each non-affected

unit under § 75.72(b)(2)(ii).

(c) Monitoring plan record provisions.

(1) General provisions. The owner or

operator of an affected unit shall

prepare and maintain a monitoring plan

for each affected unit or group of units

monitored at a common stack and each

non-affected unit under § 75.72(b)(2)(ii).

Except as provided in paragraph (d) or

(f) of this section, a monitoring plan

shall contain sufficient information on

the continuous emission monitoring

systems, excepted methodology under

§ 75.19, or excepted monitoring systems

under appendix D or E to this part and

the use of data derived from these

systems to demonstrate that all the

unit’s NOX emissions are monitored and

reported.

(2) Whenever the owner or operator

makes a replacement, modification, or

change in the certified continuous

emission monitoring system, excepted

methodology under § 75.19, excepted

monitoring system under appendix D or

E to this part, or alternative monitoring

system under subpart E of this part,

including a change in the automated

data acquisition and handling system or

in the flue gas handling system, that

affects information reported in the

monitoring plan (e.g., a change to a

serial number for a component of a

monitoring system), then the owner or

operator shall update the monitoring

plan.

(3) Contents of the monitoring plan

for units not subject to an Acid Rain

emissions limitation. Each monitoring

plan shall contain the information in

§ 75.53(e)(1) in electronic format and the

information in § 75.53(e)(2) in hardcopy

format. In addition, to the extent

applicable, each monitoring plan shall

contain the information in

§ 75.53(f)(1)(i), (f)(2)(i), and (f)(4) in

electronic format and the information in

§ 75.53(f)(1)(ii) and (f)(2)(ii) in hardcopy

format.

(d) General reporting provisions. (1)

The designated representative for an

affected unit shall comply with all

reporting requirements in this section

and with any additional requirements

set forth in an applicable state or

Federal NOX mass emission reduction

program that adopts the requirements of

this subpart.

(2) The designated representative for

an affected unit shall submit the

following for each affected unit or group

of units monitored at a common stack

and each non-affected unit under

§ 75.72(b)(2)(ii);

(i) Initial certification applications in

accordance with § 75.70(d);

(ii) Monitoring plans in accordance

with paragraph (e) of this section; and

(iii) Quarterly reports in accordance

with paragraph (f) of this section.

(3) Other petitions and

communications. The designated

representative for an affected unit shall

submit petitions, correspondence,

application forms, and petition-related

test results in accordance with the

provisions in § 75.70(g).

(4) Quality assurance RATA reports. If

requested by the permitting authority,

the designated representative of an

affected unit shall submit the quality

assurance RATA report for each affected

unit or group of units monitored at a

common stack and each non-affected

unit under § 75.72(b)(2)(ii) by the later

of 45 days after completing a quality

assurance RATA according to section

2.3 of appendix B to this part or 15 days

of receiving the request. The designated

representative shall report the hardcopy

information required by § 75.59(a)(10) to

the permitting authority.

(5) Notifications. The designated

representative for an affected unit shall

submit written notice to the permitting

authority according to the provisions in

§ 75.61 for each affected unit or group

of units monitored at a common stack

and each non-affected unit under

§ 75.72(b)(2)(ii).

(e) Monitoring plans. (1) Submission.

(i) Electronic. The designated

representative for an affected unit shall

submit a complete, electronic, up-todate monitoring plan file (except for

hardcopy portions identified in

paragraph (e)(1)(ii) of this section) for

each affected unit or group of units

monitored at a common stack and each

non-affected unit under § 75.72(b)(2)(ii)

as follows:

(A) To the permitting authority, no

later than 45 days prior to the initial

certification test and at the time of

recertification application submission;

and

(B) To the Administrator, no later

than 45 days prior to the initial

certification test, at the time of

recertification application submission,

and in each electronic quarterly report.

(ii) Hardcopy. The designated

representative of an affected unit shall
28156 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

submit all of the hardcopy information

required under § 75.53, for each affected

unit or group of units monitored at a

common stack and each non-affected

unit under § 75.72(b)(2)(ii), to the

permitting authority prior to initial

certification. Thereafter, the designated

representative shall submit hardcopy

information only if that portion of the

monitoring plan is revised. The

designated representative shall submit

the required hardcopy information: no

later than 45 days prior to the initial

certification test; with any

recertification application, if a hardcopy

monitoring plan change is associated

with the recertification event; and

within 30 days of any other event with

which a hardcopy monitoring plan

change is associated, pursuant to

§ 75.53(b).

(2) [Reserved]

(f) Quarterly reports. (1) Electronic

submission. The designated

representative for an affected unit shall

electronically report the data and

information in this paragraph (f)(1) and

in paragraphs (f)(2) and (3) of this

section to the Administrator quarterly.

Each electronic report shall include the

date of report generation, for the

information provided in paragraphs

(f)(1)(ii) through (f)(1)(vi) of this section,

and shall also include for each affected

unit or group of units monitored at a

common stack:

(i) Facility information:

(A) Identification, including:

(1) Facility/ORISPL number;

(2) Calendar quarter and year data

contained in the report; and

(3) EDR version used for the report;

(B) Location, including:

(1) Plant name and facility ID;

(2) EPA AIRS facility system ID;

(3) State facility ID;

(4) Source category/type;

(5) Primary SIC code;

(6) State postal abbreviation;

(7) County code; and

(8) Latitude and longitude;

(ii) The information and hourly data

required in paragraph (a) of this section,

except for:

(A) Descriptions of adjustments,

corrective action, and maintenance;

(B) Information which is incompatible

with electronic reporting (e.g., field data

sheets, lab analyses, quality control

plan);

(C) For units with NOX add-on

emission controls that do not elect to

use the approved site-specific

parametric monitoring procedures for

calculation of substitute data, the

information in § 75.58(b)(3);

(D) Information required by § 75.57(h)

concerning the causes of any missing

data periods and the actions taken to

cure such causes;

(E) Hardcopy monitoring plan

information required by § 75.53 and

hardcopy test data and results required

by § 75.59;

(F) Records of flow polynomial

equations and numerical values

required by § 75.59(a)(5)(vi);

(G) Daily fuel sampling information

required by § 75.58(c)(3)(i) for units

using assumed values under appendix

D;

(H) Information required by

§ 75.59(b)(2) concerning transmitter/

transducer accuracy tests;

(I) Stratification test results required

as part of the RATA supplementary

records under § 75.56(a)(7) or

§ 75.59(a)(7);

(J) Data and results of RATAs that are

aborted or invalidated due to problems

with the reference method or

operational problems with the unit and

data and results of linearity checks that

are aborted or invalidated due to

operational problems with the unit; and

(K) The summary of data used to

determine the percentage of historical

usage of each load level as required

under § 75.59(a)(8)(iv);

(iii) Average NOX emission rate (lb/

mmBtu, rounded to the nearest

thousandth) during the quarter and

cumulative NOX emission rate for the

calendar year;

(iv) Tons of NOX emitted during

quarter, cumulative tons of NOX emitted

during the year, and, during the second

and third calender quarters, cumulative

tons of NOX emitted during the ozone

season;

(v) During the second and third

calender quarters, cummulative heat

input for the ozone season; and

(vi) Unit/stack/pipe operating hours

for quarter, cumulative unit/stack/pipe

operating hours for calendar year, and,

during the second and third calender

quarters, cumulative operating hours

during the ozone season.

(2) The designated representative

shall affirm that the component/system

identification codes and formulas in the

quarterly electronic reports submitted to

the Administrator pursuant to paragraph

(e) of this section represent current

operating conditions.

(3) Compliance certification. The

designated representative shall submit

and sign a compliance certification in

support of each quarterly emissions

monitoring report based on reasonable

inquiry of those persons with primary

responsibility for ensuring that all of the

unit’s emissions are correctly and fully

monitored. The certification shall state

that:

(i) The monitoring data submitted

were recorded in accordance with the

applicable requirements of this part,

including the quality assurance

procedures and specifications; and

(ii) With regard to a unit with add-on

emission controls and for all hours

where data are substituted in

accordance with § 75.34(a)(1), the addon emission controls were operating

within the range of parameters listed in

the monitoring plan and the substitute

values do not systematically

underestimate NOX emissions.

(4) The designated representative

shall comply with all of the quarterly

reporting requirements in §§ 75.64(d),

(f), and (g).

Appendix A to Part 75—Specifications and

Test Procedures

Appendix A—[Amended]

49.–53. Appendix A to part 75 is

amended by revising section 2.1 to read

as follows:

* * * * *

2. Equipment Specifications

2.1 Instrument Span and Range

In implementing sections 2.1.1 through

2.1.5 of this appendix, set the measurement

range for each parameter (SO2, NOX, CO2, O2,

or flow rate) high enough to prevent fullscale exceedances from occurring, yet low

enough to ensure good measurement

accuracy and to maintain a high signal-tonoise ratio. To meet these objectives, it is

recommended that the range be selected such

that the readings obtained during typical unit

operation are kept, to the extent practicable,

between 20.0 and 80.0 percent of full-scale

range of the instrument. Note that this

guideline does not apply to: (1) SO2 readings

obtained during the combustion of natural

gas or fuel with a total sulfur content no

greater than the total sulfur content of natural

gas; (2) SO2 or NOX readings recorded on the

high measurement range, for units with SO2

or NOX emission controls and two span

values; or (3) SO2 or NOX readings less than

20.0 percent of full-scale on the low

measurement range for a dual span unit with

SO2 or NOX emission controls, provided that

the readings occur during periods of high

control device efficiency.

2.1.1 SO2 Pollutant Concentration Monitors

Determine, as indicated below, the span

value(s) and range(s) for an SO2 pollutant

concentration monitor so that all potential

and expected concentrations can be

accurately measured and recorded. Note that

if a unit exclusively combusts fuel(s) with a

total sulfur content no greater than the total

sulfur content of natural gas (i.e., ≤ 0.05

percent sulfur by weight), the SO2 monitor

span requirements in § 75.11(e)(3)(iv) apply

in lieu of the requirements of this section.

2.1.1.1 Maximum Potential Concentration

Make an initial determination of the

maximum potential concentration (MPC) of

SO2 by using Equation A–1a or A–1b. Base

the MPC calculation on the maximum

percent sulfur and the minimum gross

calorific value (GCV) for the highest-sulfur
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28157

fuel to be burned. The maximum sulfur

content and minimum GCV shall be

determined from all available fuel sampling

and analysis data for that fuel from the

previous 12 months (minimum), excluding

clearly anomalous fuel sampling results. If

the designated representative certifies that

the highest-sulfur fuel is never burned alone

in the unit during normal operation but is

always blended or co-fired with other fuel(s),

the MPC may be calculated using a best

estimate of the highest sulfur content and

lowest gross calorific value expected for the

blend or fuel mixture and inserting these

values into Equation A–1a or A–1b. Derive

the best estimate of the highest percent sulfur

and lowest GCV for a blend or fuel mixture

from weighted-average values based upon the

historical composition of the blend or

mixture in the previous 12 (or more) months.

If insufficient representative fuel sampling

data are available to determine the maximum

sulfur content and minimum GCV, use values

from contract(s) for the fuel(s) that will be

combusted by the unit in the MPC

calculation.

Alternatively, if a certified SO2 CEMS is

already installed, the owner or operator may

make the initial MPC determination based

upon quality assured historical data recorded

by the CEMS. If this option is chosen, the

MPC shall be the maximum SO2

concentration observed during the previous

720 (or more) quality assured monitor

operating hours when combusting the

highest-sulfur fuel (or highest-sulfur blend if

fuels are always blended or co-fired) that is

to be combusted in the unit or units

monitored by the SO2 monitor. For units with

SO2 emission controls, the certified SO2

monitor used to determine the MPC must be

located at or before the control device inlet.

Report the MPC and the method of

determination in the monitoring plan

required under § 75.53.

When performing fuel sampling to

determine the MPC, use ASTM Methods:

ASTM D3177–89, ‘‘Standard Test Methods

for Total Sulfur in the Analysis Sample of

Coal and Coke’’; ASTM D4239–85, ‘‘Standard

Test Methods for Sulfur in the Analysis

Sample of Coal and Coke Using High

Temperature Tube Furnace Combustion

Methods’’; ASTM D4294–90, ‘‘Standard Test

Method for Sulfur in Petroleum Products by

Energy-Dispersive X-Ray Fluorescence

Spectroscopy’’; ASTM D1552–90, ‘‘Standard

Test Method for Sulfur in Petroleum

Products (High Temperature Method)’’;

ASTM D129–91, ‘‘Standard Test Method for

Sulfur in Petroleum Products (General Bomb

Method)’’; ASTM D2622–92, ‘‘Standard Test

Method for Sulfur in Petroleum Products by

X-Ray Spectrometry’’ for sulfur content of

solid or liquid fuels; ASTM D3176–89,

‘‘Standard Practice for Ultimate Analysis of

Coal and Coke’’; ASTM D240–87

(Reapproved 1991), ‘‘Standard Test Method

for Heat of Combustion of Liquid

Hydrocarbon Fuels by Bomb Calorimeter’’; or

ASTM D2015–91, ‘‘Standard Test Method for

Gross Calorific Value of Coal and Coke by the

Adiabatic Bomb Calorimeter’’ for GCV

(incorporated by reference under § 75.6).

MPC or MEC S

GCV

O w ( ) . % . %

. = × 







 −





 1132 10 20 9

20 9

6 2

(Eq. A–1a) or

MPC or MEC S

GCV

CO w ( ) . % %

= × 













 66 93 10

100

6 2

(Eq. A–1b)

Where:

MPC=Maximum potential concentration

(ppm, wet basis). To convert to dry basis,

divide the MPC by 0.9).

MEC=Maximum expected concentration

(ppm, wet basis). To convert to dry basis,

divide the MEC by 0.9).

%S=Maximum sulfur content of the fuel to

be fired, wet basis, weight percent, as

determined by ASTM D3177–89, ASTM

D4239–85, ASTM D4294–90, ASTM

D1552–90, ASTM D129–91, or ASTM

D2622–92 for solid or liquid fuels

(incorporated by reference under § 75.6).

%O2w=Minimum oxygen concentration,

percent wet basis, under typical

operating conditions.

%CO2w=Maximum carbon dioxide

concentration, percent wet basis, under

typical operating conditions.

11.32×106=Oxygen-based conversion factor

in (Btu/lb)(ppm)/%.

66.93×106=Carbon dioxide-based conversion

factor in (Btu/lb)(ppm)/%.

Note: All percentage values to be inserted

in the equations of this section are to be

expressed as a percentage, not a fractional

value (e.g., 3, not .03).

2.1.1.2 Maximum Expected Concentration

Make an initial determination of the

maximum expected concentration (MEC) of

SO2 whenever: (a) SO2 emission controls are

used; or (b) both high-sulfur and low-sulfur

fuels (e.g., high-sulfur coal and low-sulfur

coal or different grades of fuel oil) or highsulfur and low-sulfur fuel blends are

combusted as primary or backup fuels in a

unit without SO2 emission controls. For units

with SO2 emission controls, use Equation A–

2 to make the initial MEC determination.

When high-sulfur and low-sulfur fuels or

blends are burned as primary or backup fuels

in a unit without SO2 controls, use Equation

A–1a or A–1b to calculate the initial MEC

value for each fuel or blend, except for: (1)

the highest-sulfur fuel or blend (for which

the MPC was previously calculated in section

2.1.1.1 of this appendix); (2) fuels or blends

with a total sulfur content no greater than the

total sulfur content of natural gas, i.e., ≤ 0.05

percent sulfur by weight; or (3) fuels or

blends that are used only for unit startup.

For each MEC determination, substitute

into Equation A–1a or A–1b the highest

sulfur content and minimum GCV value for

that fuel or blend, based upon all available

fuel sampling and analysis results from the

previous 12 months (or more), or, if fuel

sampling data are unavailable, based upon

fuel contract(s).

Alternatively, if a certified SO2 CEMS is

already installed, the owner or operator may

make the initial MEC determination(s) based

upon historical monitoring data. If this

option is chosen for a unit with SO2 emission

controls, the MEC shall be the maximum SO2

concentration measured downstream of the

control device outlet by the CEMS over the

previous 720 (or more) quality assured

monitor operating hours with the unit and

the control device both operating normally.

For units that burn high- and low-sulfur fuels

or blends as primary and backup fuels and

have no SO2 emission controls, the MEC for

each fuel shall be the maximum SO2

concentration measured by the CEMS over

the previous 720 (or more) quality assured

monitor operating hours in which that fuel or

blend was the only fuel being burned in the

unit.

MEC MPC RE =  −







100

100

(Eq. A–2)

where:

MEC=Maximum expected concentration

(ppm).

MPC=Maximum potential concentration

(ppm), as determined by Eq. A–1a or A–

1b.

RE=Expected average design removal

efficiency of control equipment

(percent).

2.1.1.3 Span Value(s) and Range(s)

Determine the high span value and the

high full-scale range of the SO2 monitor as

follows. (Note: For purposes of this part, the

high span and range refer, respectively, either

to the span and range of a single span unit

or to the high span and range of a dual span

unit.) The high span value shall be obtained

by multiplying the MPC by a factor no less

than 1.00 and no greater than 1.25. Round the
28158 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

span value upward to the next highest

multiple of 100 ppm. If the SO2 span

concentration is ≤ 500 ppm, the span value

may be rounded upward to the next highest

multiple of 10 ppm, instead of the nearest

100 ppm. The high span value shall be used

to determine concentrations of the calibration

gases required for daily calibration error

checks and linearity tests. Select the fullscale range of the instrument to be consistent

with section 2.1 of this appendix and to be

greater than or equal to the span value.

Report the full-scale range setting and

calculations of the MPC and span in the

monitoring plan for the unit. Note that for

certain applications, a second (low) SO2 span

value may be required (see section 2.1.1.4 of

this appendix). If an existing state, local, or

federal requirement for span of an SO2

pollutant concentration monitor requires a

span lower than that required by this section

or by section 2.1.1.4 of this appendix, the

state, local, or federal span value may be

used if a satisfactory explanation is included

in the monitoring plan, unless span and/or

range adjustments become necessary in

accordance with section 2.1.1.5 of this

appendix. Span values higher than those

required by either this section or section

2.1.1.4 of this appendix must be approved by

the Administrator.

2.1.1.4 Dual Span and Range Requirements

For most units, the high span value based

on the MPC, as determined under section

2.1.1.3 of this appendix will suffice to

measure and record SO2 concentrations

(unless span and/or range adjustments

become necessary in accordance with section

2.1.1.5 of this appendix). In some instances,

however, a second (low) span value based on

the MEC may be required to ensure accurate

measurement of all possible or expected SO2

concentrations. To determine whether two

SO2 span values are required, proceed as

follows:

(a) For units with SO2 emission controls,

compare the MEC from section 2.1.1.2 of this

appendix to the MPC value from section

2.1.1.1 of this appendix. If the MEC is ≥20.0

percent of the MPC, then the high span value

and range determined under section 2.1.1.3

of this appendix are sufficient. If the MEC is

< 20.0 percent of the MPC, however, a second

(low) span value is required.

(b) For units that combust high- and lowsulfur primary and backup fuels (or blends)

and have no SO2 controls, compare the MPC

value from section 2.1.1.1 of this appendix

(for the highest-sulfur fuel or blend) to the

MEC value for each of the other fuels or

blends, as determined under section 2.1.1.2

of this appendix. If all of the MEC values are

≥20.0 percent of the MPC, the high span and

range determined under section 2.1.1.3 of

this appendix are sufficient, regardless of

which fuel or blend is burned in the unit. If

any MEC value is <20.0 percent of the MPC,

however, a second (low) span value must be

used when that fuel or blend is combusted.

(c) When two SO2 spans are required, the

owner or operator may either use a single

SO2 analyzer with a dual range (i.e., low- and

high-scales) or two separate SO2 analyzers

connected to a common sample probe and

sample interface. For units with SO2

emission controls, the owner or operator may

use a low range analyzer and a default high

range value, as described in paragraph (f) of

this section, in lieu of maintaining and

quality assuring a high-scale range. Other

monitor configurations are subject to the

approval of the Administrator.

(d) The owner or operator shall designate

the monitoring systems and components as

follows: (1) designate the low and high

monitor ranges as separate components of a

single, primary monitoring system; or (2)

designate the low and high monitor ranges as

separate, primary monitoring systems; or (3)

designate the normal monitor range as a

primary monitoring system and the other

monitor range as a non-redundant backup

monitoring system; or (4) for units with SO2

controls, if the default high range value is

used, designate the low range analyzer as the

primary monitoring system.

(e) Each monitoring system designated as

primary shall meet the initial certification

and quality assurance requirements for

primary monitoring systems in § 75.20(c) and

appendices A and B to this part, with one

exception: relative accuracy test audits

(RATAs) are required only on the normal

range (for units with SO2 emission controls,

the low range is considered normal). Each

monitoring system designated as a nonredundant backup shall meet the applicable

quality assurance requirements in § 75.20(d).

(f) For dual span units with SO2 emission

controls, the owner or operator may, as an

alternative to maintaining and quality

assuring a high monitor range, use a default

high range value. If this option is chosen, the

owner or operator shall report a default SO2

concentration of 200.0 percent of the MPC for

each unit operating hour in which the fullscale of the low range SO2 analyzer is

exceeded.

(g) The high span value and range shall be

determined in accordance with section

2.1.1.3 of this appendix. The low span value

shall be obtained by multiplying the MEC by

a factor no less than 1.00 and no greater than

1.25, and rounding the result upward to the

next highest multiple of 10 ppm (or 100 ppm,

as appropriate). For units that burn high- and

low-sulfur primary and backup fuels or

blends and have no SO2 emission controls,

select, as the basis for calculating the

appropriate low span value and range, the

fuel-specific MEC value closest to 20.0

percent of the MPC (from paragraph (b) of

this section). The low range must be greater

than or equal to the low span value, and the

required calibration gases must be selected

based on the low span value. For units with

two SO2 spans, use the low range whenever

the SO2 concentrations are expected to be

consistently below 20.0 percent of the MPC,

i.e., when the MEC of the fuel or blend being

combusted is less than 20.0 percent of the

MPC. When the full-scale of the low range is

exceeded, the high range shall be used to

measure and record the SO2 concentrations;

or, if applicable, the default high range value

in paragraph (f) of this section shall be

reported for each hour of the full-scale

exceedance.

2.1.1.5 Adjustment of Span and Range

For each affected unit or common stack,

the owner or operator shall make a quarterly

evaluation of the MPC, MEC, span, and range

values for each SO2 monitor and shall make

any necessary span and range adjustments,

with corresponding monitoring plan updates,

as described in paragraphs (a) through (e),

below. Span and range adjustments may be

required as a result of changes in the fuel

supply, changes in the manner of operation

of the unit, installation or removal of

emission controls, etc. In implementing the

provisions in paragraphs (a) through (e),

below, note that SO2 data recorded during

short-term, non-representative process

operating conditions (e.g., a trial burn of a

different type of fuel) shall be excluded from

the analysis; however, if the high range is

exceeded, 200.0 percent of the high range

must still be reported as the hourly SO2

concentration for each hour of the full-scale

exceedance, as required by paragraph (c)(1)

of this section. The owner or operator shall

document all such unrepresentative

operating conditions in the quarterly report

required under § 75.64 and shall indicate

which data (dates and hours) have been

excluded from the quarterly span and range

evaluation.

Make each required span or range

adjustment no later than 45 days after the

end of the quarter in which the need to adjust

the span or range is identified, except that up

to 90 days after the end of that quarter may

be taken to implement a span adjustment if

the calibration gases currently being used for

daily calibration error tests and linearity

checks are unsuitable for use with the new

span value.

(a) No span or range adjustment is required

if, during a calendar quarter, the hourly SO2

concentration exceeds the MPC but does not

exceed the high span value. However, for

missing data purposes, if any of the hourly

SO2 concentrations exceed the current MPC

by ≥5.0 percent, a new MPC equal to the

highest quality assured hourly SO2

concentration recorded during the quarter

must be defined in the monitoring plan.

Update the monitoring plan to reflect the

new MPC value.

(b) A span adjustment is required if any of

the on-scale, quality assured hourly SO2

concentrations exceed the high span value by

≤ 10.0 percent during a quarter, but do not

exceed the high range. Define a new MPC

value (as applicable) equal to the highest

quality assured on-scale SO2 concentration

recorded during the quarter, and set the new

span value according to section 2.1.1.3 of this

appendix, using the new MPC value. If the

new span value exceeds the current full-scale

range, adjust the range setting also. Update

the monitoring plan to reflect the new MPC,

the new span value, and (if applicable) the

new full-scale range. Where separate ranges

are used to measure emissions from the

combustion of different types of fuel, the low

span and MEC shall be increased in the

manner described in this paragraph if any onscale hourly value exceeds the low span

value by 10.0 percent or more.

(c) Whenever a full-scale range is exceeded

during a quarter and the exceedance is not

caused by a monitor out-of-control period,

proceed as follows:

(1) For exceedances of the high range,

report 200.0 percent of the current full-scale

range as the hourly SO2 concentration for
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28159

each hour of the full-scale exceedance and

make adjustments to the MPC, span, and

range to prevent future full-scale

exceedances.

(2) For units with two SO2 spans and

ranges, if the low range is exceeded, no

further action is required, provided that the

high range is available and is not out-ofcontrol or out-of-service for any reason.

However, if the high range is not able to

provide quality assured data at the time of

the low range exceedance or at any time

during the continuation of the exceedance,

report the MPC as the SO2 concentration

until the readings return to the low range or

until the high range is able to provide quality

assured data (unless the reason that the highscale range is not able to provide quality

assured data is because the high-scale range

has been exceeded; if the high-scale range is

exceeded follow the procedures in paragraph

(c)(1) of this section).

(d) If the fuel supply, the composition of

the fuel blend(s), the emission controls, or

the manner of operation change such that the

maximum expected or potential

concentration changes significantly, adjust

the span and range setting to assure the

continued accuracy of the monitoring system.

The owner or operator should evaluate

whether any planned changes in operation of

the unit may affect the concentration of

emissions being emitted from the unit or

stack and should plan any necessary span

and range changes needed to account for

these changes, so that they are made in as

timely a manner as practicable to coordinate

with the operational changes. Determine the

adjusted span(s) using the procedures in

sections 2.1.1.3 and 2.1.1.4 of this appendix

(as applicable). Select the full-scale range(s)

of the instrument to be greater than or equal

to the new span value(s) and to be consistent

with the guidelines of section 2.1 of this

appendix.

(e) Whenever changes are made to the

MPC, MEC, full-scale range, or span value of

the SO2 monitor, as described in paragraphs

(a) through (d) of this section, record and

report (as applicable) the new full-scale range

setting, the new MPC or MEC and

calculations of the adjusted span value in an

updated monitoring plan. The monitoring

plan update shall be made in the quarter in

which the changes become effective. In

addition, record and report the adjusted span

as part of the records for the daily calibration

error test and linearity check specified by

appendix B to this part. Whenever the span

value is adjusted, use calibration gas

concentrations that meet the requirements of

section 5.1 of this appendix, based on the

adjusted span value. When a span adjustment

is so significant that the calibration gases

currently being used for daily calibration

error tests and linearity checks are unsuitable

for use with the new span value, then a

diagnostic linearity test using the new

calibration gases must be performed and

passed. Data from the monitor are considered

invalid from the hour in which the span is

adjusted until the required linearity check is

passed in accordance with section 6.2 of this

appendix.

2.1.2 NOX Pollutant Concentration

Monitors

Determine, as indicated below, the span

and range value(s) for the NOX pollutant

concentration monitor so that all expected

NOX concentrations can be determined and

recorded accurately.

2.1.2.1 Maximum Potential Concentration

The maximum potential concentration

(MPC) of NOX for each affected unit shall be

based upon whichever fuel or blend

combusted in the unit produces the highest

level of NOX emissions. Make an initial

determination of the MPC using the

appropriate option below. Note that an initial

MPC value determined for a unit that is not

equipped with low-NOX burners must be reevaluated if a low-NOX burner system is

subsequently installed.

Option 1: Use 800 ppm for coal-fired and

400 ppm for oil-or gas-fired units as the

maximum potential concentration of NOX (if

an MPC of 1600 ppm for coal-fired units or

480 ppm for oil-or gas-fired units was

previously selected under this part, that

value may still be used, provided that the

guidelines of section 2.1 of this appendix are

met);

Option 2: Use the specific values based on

boiler type and fuel combusted, listed in

Table 2–1 or Table 2–2;

Option 3: Use NOX emission test results; or

Option 4: Use historical CEM data over the

previous 720 (or more) unit operating hours

when combusting the fuel or blend with the

highest NOX emission rate.

For the purpose of providing substitute

data during NOX missing data periods in

accordance with §§ 75.31 and 75.33 and as

required elsewhere under this part, the

owner or operator shall also calculate the

maximum potential NOX emission rate

(MER), in lb/mmBtu, by substituting the MPC

for NOX in conjunction with the minimum

CO2 or maximum O2 concentration (under all

unit operating conditions except for unit

startup, shutdown, and upsets) and the

appropriate F-factor into the applicable

equation in appendix F to this part. 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 combustion turbines may

be used in the NOX MER calculation.

Report the method of determining the

initial MPC and the calculation of the

maximum potential NOX emission rate in the

monitoring plan for the unit.

For units with add-on NOX controls, NOX

emission testing may only be used to

determine the MPC if testing can be

performed on uncontrolled emissions (e.g.,

measured at or before the control device

inlet). If NOX emission testing is performed,

use the following guidelines. Use Method 7E

from appendix A to part 60 of this chapter

to measure total NOX concentration. (Note:

Method 20 from appendix A to Part 60 may

be used for gas turbines, instead of Method

7E.) Operate the unit, or group of units

sharing a common stack, at the minimum

safe and stable load, the normal load, and the

maximum load. If the normal load and

maximum load are identical, an intermediate

level need not be tested. Operate at the

highest excess O2 level expected under

normal operating conditions. Make at least

three runs of 20 minutes (minimum) duration

with three traverse points per run at each

operating condition. Select the highest point

NOX concentration (e.g., the highest oneminute average) from all test runs as the MPC

for NOX.

If historical CEM data are used to

determine the MPC, the data must represent

a minimum of 720 quality assured monitor

operating hours, obtained under various

operating conditions, including the

minimum safe and stable load, normal load

(including periods of high excess air at

normal load), and maximum load. For units

with add-on NOX controls, historical CEM

data may only be used to determine the MPC

if there are 720 quality assured monitor

operating hours of CEM data measuring

uncontrolled emissions (e.g., the CEM data

are collected at or before the control device

inlet). The highest hourly NOX concentration

in ppm shall be the MPC.

2.1.2.2 Maximum Expected Concentration

Make an initial determination of the

maximum expected concentration (MEC) of

NOX during normal operation for affected

units with add-on NOX controls of any kind

(i.e., steam injection, water injection, SCR, or

SNCR). Determine a separate MEC value for

each type of fuel (or blend) combusted in the

unit, except for fuels that are only used for

unit startup and/or flame stabilization.

Calculate the MEC of NOX using Equation A–

2, if applicable, inserting the maximum

potential concentration, as determined using

the procedures in section 2.1.2.1 of this

appendix. Where Equation A–2 is not

applicable, set the MEC either by: (1)

measuring the NOX concentration using the

testing procedures in this section; or (2) using

historical CEM data over the previous 720 (or

more) quality assured monitor operating

hours. Include in the monitoring plan for the

unit each MEC value and the method by

which the MEC was determined.

If NOX emission testing is used to

determine the MEC value(s), the MEC for

each type of fuel (or blend) shall be based

upon testing at minimum load, normal load,

and maximum load. At least three tests of 20

minutes (minimum) duration, using at least

3 traverse points, shall be performed at each

load, using Method 7E from appendix A to

part 60 of this chapter (Note: Method 20 from

appendix A to part 60 may be used for gas

turbines instead of Method 7E). The test must

be performed at a time when all NOX control

devices and methods used to reduce NOX

emissions are operating properly. The testing

shall be conducted downstream of all NOX

controls. The highest point NOX

concentration (e.g., the highest one-minute

average) recorded during any of the test runs

shall be the MEC.

If historical CEM data are used to

determine the MEC value(s), the MEC for

each type of fuel shall be based upon 720 (or

more) hours of quality assured data

representing the entire load range under

stable operating conditions. The data base for

the MEC shall not include any CEM data

recorded during unit startup, shutdown, or

malfunction or during any NOX control

device malfunctions or outages. All NOX

control devices and methods used to reduce
28160 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

NOX emissions must be operating properly

during each hour. The CEM data shall be

collected downstream of all NOX controls.

For each type of fuel, the highest of the 720

(or more) quality assured hourly average NOX

concentrations recorded by the CEMS shall

be the MEC.

2.1.2.3 Span Value(s) and Range(s)

Determine the high span value of the NOX

monitor as follows. The high span value shall

be obtained by multiplying the MPC by a

factor no less than 1.00 and no greater than

1.25. Round the span value upward to the

next highest multiple of 100 ppm. If the NOX

span concentration is ≤ 500 ppm, the span

value may be rounded upward to the next

highest multiple of 10 ppm, rather than 100

ppm. The high span value shall be used to

determine the concentrations of the

calibration gases required for daily

calibration error checks and linearity tests.

Note that for certain applications, a second

(low) NOX span value may be required (see

section 2.1.2.4 of this appendix).

If an existing state, local, or federal

requirement for span of an NOX pollutant

concentration monitor requires a span lower

than that required by this section or by

section 2.1.2.4 of this appendix, the state,

local, or federal span value may be used,

where a satisfactory explanation is included

in the monitoring plan, unless span and/or

range adjustments become necessary in

accordance with section 2.1.2.5 of this

appendix. Span values higher than required

by this section or by section 2.1.2.4 of this

appendix must be approved by the

Administrator.

Select the full-scale range of the instrument

to be consistent with section 2.1 of this

appendix and to be greater than or equal to

the high span value. Include the full-scale

range setting and calculations of the MPC

and span in the monitoring plan for the unit.

2.1.2.4 Dual Span and Range Requirements

For most units, the high span value based

on the MPC, as determined under section

2.1.2.3 of this appendix will suffice to

measure and record NOX concentrations

(unless span and/or range adjustments must

be made in accordance with section 2.1.2.5

of this appendix). In some instances,

however, a second (low) span value based on

the MEC may be required to ensure accurate

measurement of all expected and potential

NOX concentrations. To determine whether

two NOX spans are required, proceed as

follows:

(a) Compare the MEC value(s) determined

in section 2.1.2.2 of this appendix to the MPC

value determined in section 2.1.2.1 of this

appendix. If the MEC values for all fuels (or

blends) are ≥ 20.0 percent of the MPC, the

high span and range values determined

under section 2.1.2.3 of this appendix are

sufficient, irrespective of which fuel or blend

is combusted in the unit. If any of the MEC

values is < 20.0 percent of the MPC, two

spans (low and high) are required, one based

upon the MPC and the other based on the

MEC.

(b) When two NOX spans are required, the

owner or operator may either use a single

NOX analyzer with a dual range (low-and

high-scales) or two separate NOX analyzers

connected to a common sample probe and

sample interface. For units with add-on NOX

emission controls (i.e., steam injection, water

injection, SCR, or SNCR), the owner or

operator may use a low range analyzer and

a ‘‘default high range value,’’ as described in

paragraph 2.1.2.4(e) of this section, in lieu of

maintaining and quality assuring a high-scale

range. Other monitor configurations are

subject to the approval of the Administrator.

(c) The owner or operator shall designate

the monitoring systems and components as

follows: (1) designate the low and high

ranges as separate components of a single,

primary monitoring system; or (2) designate

the low and high ranges as separate, primary

monitoring systems; or (3) designate the

normal range as a primary monitoring system

and the other range as a non-redundant

backup monitoring system; or (4) for units

with add-on NOX controls, if the default high

range value is used, designate the low range

analyzer as the primary monitoring system.

(d) Each monitoring system designated as

primary shall meet the initial certification

and quality assurance requirements for

primary monitoring systems in § 75.20(c) and

appendices A and B to this part, with one

exception: relative accuracy test audits

(RATAs) are required only on the normal

range (for dual span units with add-on NOX

emission controls, the low range is

considered normal). Each monitoring system

designated as non-redundant backup shall

meet the applicable quality assurance

requirements in § 75.20(d).

(e) For dual span units with add-on NOX

emission controls (i.e., steam injection, water

injection, SCR, or SNCR), the owner or

operator may, as an alternative to

maintaining and quality assuring a high

monitor range, use a default high range value.

If this option is chosen, the owner or operator

shall report a default value of 200.0 percent

of the MPC for each unit operating hour in

which the full-scale of the low range NOX

analyzer is exceeded.

(f) The high span and range shall be

determined in accordance with section

2.1.2.3 of this appendix. The low span value

shall be 100.0 to 125.0 percent of the MEC,

rounded up to the next highest multiple of

10 ppm (or 100 ppm, if appropriate). If more

than one MEC value (as determined in

section 2.1.2.2 of this appendix) is <20.0

percent of the MPC, the low span value shall

be based upon whichever MEC value is

closest to 20.0 percent of the MPC. The low

range must be greater than or equal to the low

span value, and the required calibration gases

for the low range must be selected based on

the low span value. For units with two NOX

spans, use the low range whenever NOX

concentrations are expected to be

consistently <20.0 percent of the MPC, i.e.,

when the MEC of the fuel being combusted

is <20.0 percent of the MPC. When the fullscale of the low range is exceeded, the high

range shall be used to measure and record the

NOX concentrations; or, if applicable, the

default high range value in paragraph (e) of

this section shall be reported for each hour

of the full-scale exceedance.

2.1.2.5 Adjustment of Span and Range

For each affected unit or common stack,

the owner or operator shall make a quarterly

evaluation of the MPC, MEC, span, and range

values for each NOX monitor and shall make

any necessary span and range adjustments,

with corresponding monitoring plan updates,

as described in paragraphs (a) through (e),

below. Span and range adjustments may be

required as a result of changes in the fuel

supply, changes in the manner of operation

of the unit, installation or removal of

emission controls, etc. In implementing the

provisions in paragraphs (a) through (e),

below, note that NOX data recorded during

short-term, non-representative operating

conditions (e.g., a trial burn of a different

type of fuel) shall be excluded from the

analysis; however, if the high range is

exceeded, 200.0 percent of the high range

must still be reported as the hourly NOX

concentration for each hour of the full-scale

exceedance, in accordance with paragraph

(c)(1) of this section. The owner or operator

shall document all such unrepresentative

operating conditions in the quarterly report

required under § 75.64 and shall indicate

which data have been excluded from the

quarterly span and range evaluation.

Make each required span or range

adjustment no later than 45 days after the

end of the quarter in which the need to adjust

the span or range is identified, except that up

to 90 days after the end of that quarter may

be taken to implement a span adjustment if

the calibration gases currently being used for

daily calibration error tests and linearity

checks are unsuitable for use with the new

span value.

(a) No span or range adjustment is required

if, during a calendar quarter, the hourly NOX

concentration exceeds the MPC but does not

exceed the high span value. However, for

missing data purposes, if any of the hourly

NOX concentrations exceed the current MPC

by ≥ 5.0 percent, a new MPC equal to the

highest quality assured hourly NOX

concentration recorded during the quarter

must be defined in the monitoring plan.

Update the monitoring plan to reflect the

new MPC value.

(b) A span adjustment is required

whenever any of the on-scale, quality

assured, hourly NOX concentrations exceed

the high span value by ≥ 10.0 percent during

a quarter but do not exceed the high range.

Define a new MPC value (as applicable) equal

to the highest quality assured on-scale NOX

concentration recorded during the quarter,

and set the new span value according to

section 2.1.2.3 or 2.1.2.4 of this appendix (as

applicable), using the new MPC value. If the

new span value exceeds the current full-scale

range, adjust the range setting also. Update

the monitoring plan to reflect the new MPC,

the new span value, and (if applicable) the

new full-scale range. Where separate ranges

are used to measure emissions from different

fuels or in different seasons (i.e. where

seasonal controls are used), the low span and

MEC shall be increased in the manner

described in this paragraph if any on-scale

hourly value exceeds the low span value by

10.0 percent or more.

(c) Whenever a full-scale range is exceeded

during a quarter and the exceedance is not

caused by a monitor out-of-control period,

proceed as follows:

(1) For exceedances of the high range,

report 200.0 percent of the current full-scale
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28161

range as the hourly NOX concentration for

each hour of the full-scale exceedance and

make adjustments to the MPC, span, and

range to prevent future full-scale

exceedances.

(2) For units with two NOX spans and

ranges, if the low range is exceeded, no

further action is required, provided that the

high range is available and is not out-ofcontrol or out-of-service for any reason.

However, if the high range is not able to

provide quality assured data at the time of

the low range exceedance or at any time

during the continuation of the exceedance,

report the MPC as the NOX concentration

until the readings return to the low range or

until the high range is able to provide quality

assured data (unless the reason that the highscale range is not able to provide quality

assured data is because the high-scale range

has been exceeded; if the high-scale range is

exceeded follow the procedures in paragraph

(c)(1) of this section).

(d) If the fuel supply, emission controls, or

other process parameters change such that

the maximum expected concentration or the

maximum potential concentration changes

significantly, adjust the NOX pollutant

concentration span(s) and (if necessary)

monitor range(s) to assure the continued

accuracy of the monitoring system. The

owner or operator should evaluate whether

any planned changes in operation of the unit

or stack may affect the concentration of

emissions being emitted from the unit and

should plan any necessary span and ranges

changes needed to account for these changes,

so that they are made in as timely a manner

as practicable to coordinate with the

operational changes. Determine the adjusted

span(s) using the procedures in section

2.1.2.3 or 2.1.2.4 of this appendix (as

applicable). Select the full-scale range(s) of

the instrument to be greater than or equal to

the adjusted span value(s) and to be

consistent with the guidelines of section 2.1

of this appendix.

(e) Whenever changes are made to the

MPC, MEC, full-scale range, or span value of

the NOX monitor as described in paragraphs

(a) through (d) of this section, record and

report (as applicable) the new full-scale range

setting, the new MPC or MEC, maximum

potential NOX emission rate, and the

adjusted span value in an updated

monitoring plan for the unit. The monitoring

plan update shall be made in the quarter in

which the changes become effective. In

addition, record and report the adjusted span

as part of the records for the daily calibration

error test and linearity check required by

appendix B to this part. Whenever the span

value is adjusted, use calibration gas

concentrations that meet the requirements of

section 5.1 of this appendix, based on the

adjusted span value. When a span adjustment

is significant enough that the calibration

gases currently being used for daily

calibration error tests and linearity checks are

unsuitable for use with the new span value,

a linearity test using the new calibration

gases must be performed and passed. Data

from the monitor are considered invalid from

the hour in which the span is adjusted until

the required linearity check is passed in

accordance with section 6.2 of this appendix.

2.1.3 CO2 and O2 Monitors

For an O2 monitor (including O2 monitors

used to measure CO2 emissions or percentage

moisture), select a span value between 15.0

and 25.0 percent O2. For a CO2 monitor

installed on a boiler, select a span value

between 14.0 and 20.0 percent CO2. For a

CO2 monitor installed on a combustion

turbine, an alternative span value between

6.0 and 14.0 percent CO2 may be used. An

alternative O2 span value below 15.0 percent

O2 may be used if an appropriate technical

justification is included in the monitoring

plan. Select the full-scale range of the

instrument to be consistent with section 2.1

of this appendix and to be greater than or

equal to the span value. Select the calibration

gas concentrations for the daily calibration

error tests and linearity checks in accordance

with section 5.1 of this appendix, as

percentages of the span value. For O2

monitors with span values ≥21.0 percent O2,

purified instrument air containing 20.9

percent O2 may be used as the high-level

calibration material.

2.1.3.1 Maximum Potential Concentration

of CO2

For CO2 pollutant concentration monitors,

the maximum potential concentration shall

be 14.0 percent CO2 for boilers and 6.0

percent CO2 for combustion turbines.

Alternatively, the owner or operator may

determine the MPC based on a minimum of

720 hours of quality assured historical CEM

data representing the full operating load

range of the unit(s).

2.1.3.2 Adjustment of Span and Range

Adjust the span value and range of a CO2

or O2 monitor according to the general

guidelines in section 2.1.1.5 of this appendix

(insofar as those provisions are applicable),

replacing the term ‘‘SO2’’ with ‘‘CO2 or O2.’’

Set the new span and range in accordance

with section 2.1.3 of this appendix and

provide a rationale for the new span value in

the monitoring plan.

2.1.4 Flow Monitors

Select the full-scale range of the flow

monitor so that it is consistent with section

2.1 of this appendix and can accurately

measure all potential volumetric flow rates at

the flow monitor installation site.

2.1.4.1 Maximum Potential Velocity and

Flow Rate

Make an initial determination of the

maximum potential velocity (MPV) using

Equation A–3a or A–3b, or determine the

MPV (wet basis) from velocity traverse

testing using Reference Method 2 (or its

allowable alternatives) in appendix A to part

60 of this chapter. If using test values, use the

highest average velocity (determined from

the Method 2 traverses) measured at or near

the maximum unit operating load. Express

the MPV in units of wet standard feet per

minute (fpm). For the purpose of providing

substitute data during periods of missing

flow rate data in accordance with §§ 75.31

and 75.33 and as required elsewhere in this

part, calculate the maximum potential stack

gas flow rate (MPF) in units of standard cubic

feet per hour (scfh), as the product of the

MPV (in units of wet, standard fpm) times 60,

times the cross-sectional area of the stack or

duct (in ft2) at the flow monitor location.

2.1.4.2 Span Values and Range

Determine the span and range of the flow

monitor as follows. Convert the MPV, as

determined in section 2.1.4.1 of this

appendix, to the same units of flow rate that

are used for daily calibration error tests (e.g.,

scfh, kscfh, kacfm, or differential pressure

(inches of water)). Next, determine the

‘‘calibration span value’’ by multiplying the

MPV (converted to equivalent daily

calibration error units) by a factor no less

than 1.00 and no greater than 1.25, and

rounding up the result to at least 2 significant

figures. For calibration span values in inches

of water, retain at least 2 decimal places.

Select appropriate reference signals for the

daily calibration error tests as percentages of

the calibration span value. Finally, calculate

the ‘‘flow rate span value’’ (in scfh) as the

product of the MPF, as determined in section

2.1.4.1 of this appendix, times the same

factor (between 1.00 and 1.25) that was used

to calculate the calibration span value.

Round off the flow rate span value to the

nearest 1000 scfh. Select the full-scale range

of the flow monitor so that it is greater than

or equal to the span value and is consistent

with section 2.1 of this appendix. Include in

the monitoring plan for the unit: calculations

of the MPV, MPF, calibration span value,

flow rate span value, and full-scale range

(expressed both in units of scfh and, if

different, in the units of calibration).

MPV

F H

A O H O

d f

d

= 





 −











 −





 



 20 9

20 9

100

100 2 2

.

. % %

(Eq. A–3a)

or

MPV

F H

A CO H O

c f

d

= 











 



 −





 



 100 100

100 % % 2 2
28162 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

(Eq. A–3b)

Where:

MPV=maximum potential velocity (fpm,

standard wet basis),

Fd=dry-basis F factor (dscf/mmBtu) from

Table 1, Appendix F of this part,

Fc=carbon-based F factor (scfCO2/mmBtu)

from Table 1, Appendix F this part,

HF=maximum heat input (mmBtu/minute)

for all units, combined, exhausting to the

stack or duct where the flow monitor is

located,

A=inside cross sectional area (ft2) of the flue

at the flow monitor location,

%O2d=maximum oxygen concentration,

percent dry basis, under normal

operating conditions,

%CO2d=minimum carbon dioxide

concentration, percent dry basis, under

normal operating conditions,

%H2O=maximum percent flue gas moisture

content under normal operating

conditions.

2.1.4.3 Adjustment of Span and Range

For each affected unit or common stack,

the owner or operator shall make a quarterly

evaluation of the MPV, MPF, span, and range

values for each flow rate monitor and shall

make any necessary span and range

adjustments with corresponding monitoring

plan updates, as described in paragraphs (a)

through (e), below. Span and range

adjustments may be required as a result of

changes in the fuel supply, changes in the

stack or ductwork configuration, changes in

the manner of operation of the unit,

installation or removal of emission controls,

etc. In implementing the provisions in

paragraphs (a) through (e), below, note that

flow rate data recorded during short-term,

non-representative operating conditions (e.g.,

a trial burn of a different type of fuel) shall

be excluded from the analysis; however, if

the high range is exceeded, 200.0 percent of

the full-scale range must still be reported as

the hourly flow rate for each hour of the fullscale exceedance, in accordance with

paragraph (c) of this section. The owner or

operator shall document all such

unrepresentative operating conditions in the

quarterly report required under § 75.64 and

shall indicate which data have been excluded

from the quarterly span and range evaluation.

Make each required span or range adjustment

no later than 45 days after the end of the

quarter in which the need to adjust the span

or range is identified.

(a) No span or range adjustment is required

if, during a calendar quarter, the hourly flow

rate exceeds the MPF but does not exceed the

flow rate span value. However, for missing

data purposes, if any of the hourly flow rates

exceed the current MPF by ≥5.0 percent, a

new MPF equal to the highest quality assured

hourly flow rate recorded during the quarter

must be defined in the monitoring plan.

Update the monitoring plan to reflect the

new MPF value.

(b) A span adjustment is required

whenever any of the on-scale, quality

assured, hourly flow rates exceed the flow

rate span value by ≥10.0 percent during a

quarter. Define a new MPF equal to the

highest on-scale flow rate recorded during

the quarter, and set the new flow rate span

value according to section 2.1.4.2 of this

appendix. Then, calculate the new

calibration span value by converting the new

flow rate span value from units of scfh to

units of daily calibration. If the new flow rate

span value exceeds the current full-scale

range, adjust the range setting also. Update

the monitoring plan to reflect the new span

and (if applicable) range values.

(c) Whenever the full-scale range is

exceeded during a quarter, provided that the

exceedance is not caused by a monitor outof-control period, report 200.0 percent of the

current full-scale range as the hourly flow

rate for each hour of the full-scale

exceedance. If the range is exceeded, make

adjustments to the MPF, flow rate span, and

range to prevent future full-scale

exceedances. Calculate the new calibration

span value by converting the new flow rate

span value from units of scfh to units of daily

calibration. A calibration error test must be

performed and passed to validate data on the

new range.

(d) If the fuel supply, stack or ductwork

configuration, operating parameters, or other

conditions change such that the maximum

potential flow rate changes significantly,

adjust the span and range to assure the

continued accuracy of the flow monitor. The

owner or operator should evaluate whether

any planned changes in operation of the unit

may affect the flow of the unit or stack and

should plan any necessary span and range

changes needed to account for these changes,

so that they are made in as timely a manner

as practicable to coordinate with the

operational changes. Calculate the adjusted

calibration span and flow rate span values

using the procedures in section 2.1.4.2 of this

appendix.

(e) Whenever changes are made to the

MPV, MPF, full-scale range, or span value of

the flow monitor, as described in paragraphs

(a) through (d) of this section, record and

report (as applicable) the new full-scale range

setting, calculations of the flow rate span

value, calibration span value, MPV, and MPF

in an updated monitoring plan for the unit.

The monitoring plan update shall be made in

the quarter in which the changes become

effective. Record and report the adjusted

calibration span and reference values as parts

of the records for the calibration error test

required by appendix B to this part.

Whenever the calibration span value is

adjusted, use reference values for the

calibration error test that meet the

requirements of section 2.2.2.1 of this

appendix, based on the most recent adjusted

calibration span value. Perform a calibration

error test according to section 2.1.1 of

appendix B to this part whenever making a

change to the flow monitor span or range,

unless the range change also triggers a

recertification under § 75.20(b).

2.1.5 Moisture Sensors

The span value of a continuous moisture

sensor shall be equal to the full-scale range

of the instrument. The range shall be selected

in accordance with the requirements of

section 2.1 of this appendix.

* * * * *

54. Section 3 of appendix A to part 75

is amended by revising section 3.1 and

the last sentence in the first paragraph

of section 3.2; by adding a new section

3.3.6; and by revising section 3.5, to

read as follows:

3. Performance Specifications

3.1 Calibration Error

The initial calibration error of SO2 and

NOX pollutant concentration monitors shall

not deviate from the reference value of either

the zero or upscale calibration gas by more

than 2.5 percent of the span of the

instrument, as calculated using Equation A–

5 of this appendix. Alternatively, where the

span value is less than 200 ppm, calibration

error test results are also acceptable if the

absolute value of the difference between the

monitor response value and the reference

value, |R–A| in Equation A–5 of this

appendix, is ≥5 ppm. The calibration error of

CO2 or O2 monitors (including O2 monitors

used to measure CO2 emissions or percent

moisture) shall not deviate from the reference

value of the zero or upscale calibration gas

by >0.5 percent O2 or CO2, as calculated

using the term |R–A| in the numerator of

Equation A–5 of this appendix. The

calibration error of flow monitors shall not

exceed 3.0 percent of the calibration span

value of the instrument, as calculated using

Equation A–6 of this appendix. For

differential pressure-type flow monitors, the

calibration error test results are also

acceptable if |R—A|, the absolute value of the

difference between the monitor response and

the reference value in Equation A–6, does not

exceed 0.01 inches of water. The calibration

error of a continuous moisture sensor shall

not exceed 3.0 percent of the span value, as

calculated using Equation A–5 of this

appendix.

3.2 Linearity Check

* * * For CO2 or O2 monitors (including

O2 monitors used to measure CO2 emissions

or percent moisture):

* * * * *

3.3 * * *

3.3.6 Relative Accuracy for Moisture

Monitoring Systems

The relative accuracy of a moisture

monitoring system shall not exceed 10.0

percent. The relative accuracy test results are

also acceptable if the mean difference of the

reference method measurements (in percent

H2O) and the corresponding moisture

monitoring system measurements (in percent

H2O) are within ±1.0 percent H2O.

* * * * *

3.5 Cycle Time

The cycle time for pollutant concentration

monitors, oxygen monitors used to determine

percent moisture, and any other continuous

emission monitoring system(s) required to

perform a cycle time test shall not exceed 15

minutes.

55. Section 4 of appendix A to part 75

is amended by revising the introductory

paragraph and paragraph (6) to read as

follows:
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28163

4. Data Acquisition and Handling Systems

Automated data acquisition and handling

systems shall: (1) Read and record the full

range of pollutant concentrations and

volumetric flow from zero through span; and

(2) provide a continuous, permanent record

of all measurements and required

information as an ASCII flat file capable of

transmission both by direct computer-tocomputer electronic transfer via modem and

EPA-provided software and by an IBMcompatible personal computer diskette.

* * * * *

(6) Provide a continuous, permanent record

of all measurements and required

information as an ASCII flat file capable of

transmission both by direct computer-tocomputer electronic transfer via modem and

EPA-provided software and by an IBMcompatible personal computer diskette.

56. Section 5 of appendix A to part 75

is amended by revising sections 5.1,

5.2.1, 5.2.2, 5.2.3, and 5.2.4 to read as

follows:

5. Calibration Gas

5.1 Reference Gases

For the purposes of part 75, calibration

gases include the following:

5.1.1 Standard Reference Materials (SRM)

These calibration gases may be obtained

from the National Institute of Standards and

Technology (NIST) at the following address:

Quince Orchard and Cloppers Road,

Gaithersburg, MD 20899–0001.

5.1.2 SRM-Equivalent Compressed Gas

Primary Reference Material (PRM)

Contact the Gas Metrology Team,

Analytical Chemistry Division, Chemical

Science and Technology Laboratory of NIST,

at the above address, for a list of vendors and

cylinder gases.

5.1.3 NIST Traceable Reference Materials

Contact the Gas Metrology Team,

Analytical Chemistry Division, Chemical

Science and Technology Laboratory of NIST,

at the above address, for a list of vendors and

cylinder gases.

5.1.4 EPA Protocol Gases

EPA Protocol gases must be vendorcertified to be within 2.0 percent of the

concentration specified on the cylinder label

(tag value), using the uncertainty calculation

procedure in section 2.1.8 of the ‘‘EPA

Traceability Protocol for Assay and

Certification of Gaseous Calibration

Standards,’’ September 1997, EPA–600/R–97/

121.

A copy of EPA–600/R–97/121 is available

from the National Technical Information

Service, 5285 Port Royal Road, Springfield,

VA 703–487–4650 and from the Office of

Research and Development, (MD–77B), U.S.

Environmental Protection Agency, Research

Triangle Park, NC 27711, Attn: Berne

Bennett, 919–541–2366.

5.1.5 Research Gas Mixtures

Research gas mixtures must be vendorcertified to be within 2.0 percent of the

concentration specified on the cylinder label

(tag value), using the uncertainty calculation

procedure in section 2.1.8 of the ‘‘EPA

Traceability Protocol for Assay and

Certification of Gaseous Calibration

Standards,’’ September 1997, EPA–600/R–97/

121. Inquiries about the RGM program

should be directed to: National Institute of

Standards and Technology, Analytical

Chemistry Division, Chemical Science and

Technology Laboratory, B–324 Chemistry,

Gaithersburg, MD 20899.

5.1.6 Zero Air Material

Zero air material is defined in § 72.2 of this

chapter.

5.1.7 NIST/EPA-Approved Certified

Reference Materials

Existing certified reference materials

(CRMs) that are still within their certification

period may be used as calibration gas.

5.1.8 Gas Manufacturer’s Intermediate

Standards

Gas manufacturer’s intermediate standards

is defined in § 72.2 of this chapter.

* * * * *

5.2.1 Zero-level Concentration

0.0 to 20.0 percent of span, including span

for high-scale or both low-and high-scale for

SO2, NOX, CO2, and O2 monitors, as

appropriate.

5.2.2 Low-level Concentration

20.0 to 30.0 percent of span, including

span for high-scale or both low-and highscale for SO2, NOX, CO2, and O2 monitors, as

appropriate.

5.2.3 Mid-level Concentration

50.0 to 60.0 percent of span, including

span for high-scale or both low-and highscale for SO2, NOX, CO2, and O2 monitors, as

appropriate.

5.2.4 High-level Concentration

80.0 to 100.0 percent of span, including

span for high-scale or both low-and highscale for SO2, NOX, CO2, and O2 monitors, as

appropriate.

57. Section 6 of appendix A to part 75

is amended by revising sections 6.2,

6.3.1, 6.5, 6.5.1, 6.5.2, 6.5.6, 6.5.7, and

6.5.9 to read as follows:

6. Certification Tests and Procedures

* * * * *

6.2 Linearity Check

For the purposes of initial certification,

recertification, and quality assurance, check

the linearity of each SO2, NOX, CO2, and O2

monitor while the unit, or group of units for

a common stack, is combusting fuel at

conditions of typical stack temperature and

pressure; it is not necessary for the unit to

be generating electricity during this test.

Notwithstanding these requirements, if the

SO2 or NOX span value for a particular

monitor range is ≤30 ppm, that range is

exempted from the linearity test

requirements of this part.

Challenge each monitor with calibration

gas, as defined in section 5.1 of this

appendix, at the low-, mid-, and high-range

concentrations specified in section 5.2 of this

appendix. For units using emission controls

and other units using both a high and a low

span, perform a linearity check on both the

low-and high-scales for initial certification.

For on-going quality assurance of the CEMS,

perform linearity tests on the range(s) and at

the frequency specified in section 2.2.1 of

appendix B to this part.

Introduce the calibration gas at the gas

injection port, as specified in section 2.2.1 of

this appendix. Operate each monitor at its

normal operating temperature and

conditions. For extractive and dilution type

monitors, pass the calibration gas through all

filters, scrubbers, conditioners, and other

monitor components used during normal

sampling and through as much of the

sampling probe as is practical. For in-situ

type monitors, perform calibration checking

all active electronic and optical components,

including the transmitter, receiver, and

analyzer. Challenge the monitor three times

with each reference gas (see example data

sheet in Figure 1). Do not use the same gas

twice in succession. The linearity check must

be done hands-off, as follows. No

adjustments other than the calibration

adjustments described in section 2.1.3 of

appendix B to this part are permitted prior

to or during the linearity test period. To the

extent practicable, the duration of each

linearity test, from the hour of the first

injection to the hour of the last injection,

shall not exceed 24 unit operating hours.

Record the monitor response from the data

acquisition and handling system. For each

concentration, use the average of the

responses to determine the error in linearity

using Equation A–4 in this appendix.

Linearity checks are acceptable for monitor

or monitoring system certification,

recertification, or quality assurance if none of

the test results exceed the applicable

performance specifications in section 3.2 of

this appendix.

The status of emission data from a CEMS

prior to and during a linearity test period

shall be determined as follows:

(a) For the initial certification of a CEMS,

data from the monitoring system are

considered invalid until all certification tests,

including the linearity test, have been

successfully completed, unless the data

validation procedures in § 75.20(b)(3) are

used. When the procedures in § 75.20(b)(3)

are followed, substitute the words ‘‘initial

certification’’ for ‘‘recertification,’’ and

complete all of the initial certification tests

by the applicable deadline in § 75.4, rather

than within the time periods specified in

§ 75.20(b)(3)(iv) for the individual tests.

(b) For the routine quality assurance

linearity checks required by section 2.2.1 of

appendix B to this part, use the data

validation procedures in section 2.2.3 of

appendix B to this part.

(c) When a linearity test is required as a

diagnostic test or for recertification, use the

data validation procedures in § 75.20(b)(3).

(d) For linearity tests of non-redundant

backup monitoring systems, use the data

validation procedures in § 75.20(d)(2)(iii).

(e) For linearity tests performed during a

grace period and after the expiration of a

grace period, use the data validation

procedures in sections 2.2.3 and 2.2.4,

respectively, of appendix B to this part.
28164 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

6.3 * * *

6.3.1 Pollutant Concentration Monitor and

CO2 or O2 Monitor 7-day Calibration Error

Test

For the purposes of initial certification and

recertification, measure the calibration error

of each pollutant concentration monitor and

CO2 or O2 monitor while the unit is

combusting fuel at conditions of typical

temperature and pressure (but not necessarily

generating electricity) once each day for 7

consecutive operating days according to the

following procedures. (In the event that

extended unit outages occur after the

commencement of the test, the 7 consecutive

unit operating days need not be 7

consecutive calendar days.) Units using dual

span monitors must perform the calibration

error test on both high-and low-scales of the

pollutant concentration monitor. The daily

calibration error test procedures in this

section shall also be used to perform the

daily assessments and additional calibration

error tests required under sections 2.1.1 and

2.1.3 of appendix B to this part.

Do not make manual or automatic

adjustments to the monitor settings until after

taking measurements at both zero and high

concentration levels for that day during the

7-day test. If automatic adjustments are made

following both injections, conduct the

calibration error test such that the magnitude

of the adjustments can be determined and

recorded. Record and report test results for

each day using the unadjusted concentration

measured in the calibration error test prior to

making any manual or automatic adjustments

(i.e., resetting the calibration).

The calibration error tests should be

approximately 24 hours apart, (unless the 7-

day test is performed over non-consecutive

days). Perform calibration error tests at both

the zero-level concentration and either the

mid-level or high-level concentration, as

specified in section 5.2 of this appendix. In

addition, repeat the procedure for SO2 and

NOX pollutant concentration monitors using

the low-scale for units equipped with

emission controls or other units with dual

span monitors. Use only calibration gas, as

specified in section 5.1 of this appendix.

Introduce the calibration gas at the gas

injection port, as specified in section 2.2.1 of

this appendix. Operate each monitor in its

normal sampling mode. For extractive and

dilution type monitors, pass the calibration

gas through all filters, scrubbers,

conditioners, and other monitor components

used during normal sampling and through as

much of the sampling probe as is practical.

For in-situ type monitors, perform

calibration, checking all active electronic and

optical components, including the

transmitter, receiver, and analyzer. Challenge

the pollutant concentration monitors and

CO2 or O2 monitors once with each

calibration gas. Record the monitor response

from the data acquisition and handling

system. Using Equation A–5 of this appendix,

determine the calibration error at each

concentration once each day (at

approximately 24-hour intervals) for 7

consecutive days according to the procedures

given in this section.

Calibration error tests are acceptable for

monitor or monitoring system certification if

none of these daily calibration error test

results exceed the applicable performance

specifications in section 3.1 of this appendix.

The status of emission data from a CEMS

during a 7-day calibration error test period

shall be determined as follows:

(a) For the initial certification of a CEMS,

data from the monitoring system are

considered invalid until all certification tests,

including the 7-day calibration error test,

have been successfully completed, unless the

data validation procedures in § 75.20(b)(3)

are used. When the procedures in

§ 75.20(b)(3) are followed, substitute the

words ‘‘initial certification’’ for

‘‘recertification,’’ and complete all of the

initial certification tests by the applicable

deadline in § 75.4, rather than within the

time periods specified in § 75.20(b)(3)(iv) for

the individual tests.

(b) When a 7-day calibration error test is

required as a diagnostic test or for

recertification, use the data validation

procedures in § 75.20(b)(3).

* * * * *

6.5 Relative Accuracy and Bias Tests

For the purposes of initial certification,

recertification, and quality assurance,

perform the required relative accuracy test

audits as follows for each CO2 and SO2

pollutant concentration monitor, each flow

monitor, each NOX continuous emission

monitoring system, each O2 monitor used to

calculate heat input or CO2 concentration,

each moisture monitoring system, and each

SO2-diluent continuous emission monitoring

system (lb/mmBtu) used by units with a

qualifying Phase I technology for the period

during which the units are required to

monitor SO2 emission removal efficiency,

from January 1, 1997 through December 31,

1999:

(a) All relative accuracy test audits shall be

done ‘‘hands-off’’, as follows:

(1) 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.

(2) For 2-level and 3-level flow monitor

audits, no re-linearization of the monitor (i.e.,

changing of the polynomial coefficients) is

permitted between load levels.

(b) Except as provided in § 75.21(a)(5),

perform each RATA while the unit (or units,

if more than one unit exhausts into the flue)

is combusting the fuel that is normal for that

unit (for some units, more than one type of

fuel may be considered normal; e.g., a unit

that combusts gas or oil on a seasonal basis).

When relative accuracy test audits are

performed on continuous emission

monitoring systems or component(s) on

bypass stacks/ducts, use the fuel normally

combusted by the unit (or units, if more than

one unit exhausts into the flue) when

emissions exhaust through the bypass stack/

ducts.

(c) Perform each RATA at the load level(s)

specified in section 6.5.1 or 6.5.2 of this

appendix or in section 2.3.1.3 of appendix B

to this part, as applicable.

(d) For monitoring systems with dual

ranges, perform the relative accuracy test on

the range normally used for measuring

emissions. For units with add-on SO2 or NOX

controls or for units that need a dual range

to record high concentration ‘‘spikes’’ during

startup conditions, the low range is

considered normal. However, for some dual

span units (e.g., for units that switch fuels

and have both a high and low span value),

either of the two measurement ranges may be

considered normal; in such cases, perform

the RATA on the range that is in use at the

time of the scheduled test.

(e) Record monitor or monitoring system

output from the data acquisition and

handling system.

(f) For initial certification and

recertification RATAs and for the quality

assurance RATAs required by § 75.20(d) or

by section 2.3.1 of appendix B to this part,

complete each single-load relative accuracy

test audit within a period of 168 consecutive

unit operating hours. For 2-level and 3-level

flow monitor RATAs, complete all of the

RATAs at all levels, to the extent practicable,

within a period of 168 consecutive unit

operating hours; however, if this is not

possible, up to 720 consecutive unit

operating hours may be taken to complete a

multiple-load flow RATA.

(g) The status of emission data from the

CEMS prior to and during the RATA test

period shall be determined as follows:

(1) For the initial certification of a CEMS,

data from the monitoring system are

considered invalid until all certification tests,

including the RATA, have been successfully

completed, unless the data validation

procedures in § 75.20(b)(3) are used. When

the procedures in § 75.20(b)(3) are followed,

substitute the words ‘‘initial certification’’ for

‘‘recertification,’’ and complete all of the

initial certification tests by the applicable

deadline in § 75.4, rather than within the

time periods specified in § 75.20(b)(3)(iv) for

the individual tests.

(2) For the routine quality assurance

RATAs required by section 2.3.1 of appendix

B to this part, use the data validation

procedures in section 2.3.2 of appendix B to

this part.

(3) For recertification RATAs, use the data

validation procedures in § 75.20(b)(3).

(4) For quality assurance RATAs of nonredundant backup monitoring systems, use

the data validation procedures in

§§ 75.20(d)(2)(v) and (vi).

(5) For RATAs performed during and after

the expiration of a grace period, use the data

validation procedures in sections 2.3.2 and

2.3.3, respectively, of appendix B to this part.

(h) For each SO2 or CO2 pollutant

concentration monitor, each flow monitor,

and each NOX continuous emission

monitoring system, calculate the relative

accuracy, in accordance with section 7.4 of

this appendix. In addition (except for CO2

monitors), test for bias and determine the

appropriate bias adjustment factor, in

accordance with sections 7.6.4 and 7.6.5 of

this appendix, using the data from the

relative accuracy test audits.

6.5.1 Gas Monitoring System RATAs

(Special Considerations)

(a) For the purposes of initial certification,

recertification, and quality assurance,

perform the required relative accuracy test

audits for each SO2 or CO2 pollutant
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concentration monitor, each O2 monitor, each

NOX continuous emission monitoring

system, and each SO2-diluent continuous

emission monitoring system (lb/mmBtu) used

by units with a qualifying Phase I technology

for the period during which the units are

required to monitor SO2 emission removal

efficiency, from January 1, 1997 through

December 31, 1999, at the normal load level

for the unit (or combined units, if common

stack), as defined in section 6.5.2.1 of this

appendix. If two load levels have been

designated as normal, the RATAs may be

done at either load level.

(b) For the initial certification of a gas

monitoring system and for recertifications in

which, in addition to a RATA, one or more

other tests are required (i.e., a linearity test,

cycle time test, or 7-day calibration error

test), EPA recommends that the RATA not be

commenced until the other required tests of

the CEMS have been passed.

6.5.2 Flow Monitor RATAs (Special

Considerations)

(a) Except for flow monitors on bypass

stacks/ducts and peaking units, perform

relative accuracy test audits for the initial

certification of each flow monitor at three

different exhaust gas velocities (low, mid,

and high), corresponding to three different

load levels within the range of operation, as

defined in section 6.5.2.1 of this appendix.

For a common stack/duct, the three different

exhaust gas velocities may be obtained from

frequently used unit/load combinations for

the units exhausting to the common stack.

Select the three exhaust gas velocities such

that the audit points at adjacent load levels

(i.e., low and mid or mid and high), in

megawatts (or in thousands of lb/hr of steam

production), are separated by no less than

25.0 percent of the range of operation, as

defined in section 6.5.2.1 of this appendix.

(b) For flow monitors on bypass stacks/

ducts and peaking units, the flow monitor

relative accuracy test audits for initial

certification and recertification shall be

single-load tests, performed at the normal

load, as defined in section 6.5.2.1 of this

appendix.

(c) The semiannual and annual quality

assurance flow monitor RATAs required

under appendix B to this part shall be done

at the load level(s) specified in section 2.3.1.3

of appendix B.

(d) Flow monitor recertification RATAs

shall be done at three load level(s), unless

otherwise specified in paragraph (b) of this

section or unless otherwise approved by the

Administrator.

6.5.2.1 Range of Operation and RATA Load

Levels (Definitions)

The owner or operator shall determine the

upper and lower boundaries of the ‘‘range of

operation’’ for each unit (or combination of

units, for common-stack configurations) that

uses CEMS to account for its emissions. The

lower boundary of the range of operation of

a unit shall be the minimum safe, stable load

(or, for common-stacks, the lowest of the

minimum safe, stable loads for any of the

units discharging through the stack). The

upper boundary of the range of operation of

a unit shall be the maximum sustainable

load. The ‘‘maximum sustainable load’’ is the

higher of: (1) the nameplate or rated capacity

of the unit, less any physical or regulatory

limitations or other deratings, or (2) the

highest sustainable unit load, based on at

least four quarters of representative historical

operating data. For common-stacks, the

maximum sustainable load is the sum of all

of the maximum sustainable loads of the

individual units discharging through the

stack, unless this load is unattainable in

practice, in which case use the highest

sustainable combined load for the units that

discharge through the stack, based on at least

four quarters of representative historical

operating data. The load values for the unit(s)

shall be expressed either in units of

megawatts or thousands of lb/hr of steam

load.

The operating levels for relative accuracy

test audits shall, except for peaking units, be

defined as follows: (1) the low operating level

shall be the first 30.0 percent of the range of

operation; (2) the mid operating level shall be

the middle portion (30.0 to 60.0 percent) of

the range of operation; and (3) the high

operating level shall be the upper end (60.0

to 100.0 percent) of the range of operation.

For example, if the upper and lower

boundaries of the range of operation are 100

and 1100 megawatts, respectively, then the

low, mid, and high operating levels would be

100 to 400 megawatts, 400 to 700 megawatts,

and 700 to 1100 megawatts, respectively.

The provisions of this paragraph become

effective January 1, 2000. This determination

shall be made just prior to conducting the

quality assurance RATAs required under

section 2.3 of appendix B of this part (in the

same calendar quarter in which the RATAs

are conducted) but not required more

frequently than once a year, if the RATA(s)

are conducted semiannually. The owner or

operator shall determine, for each unit or

common stack (except for peaking units) the

load level (low, mid or high) that is the most

frequently used. In addition, the owner or

operator shall determine which load level is

the second most frequently-used. To make

the determinations, the owner or operator

shall construct a historical load frequency

distribution (e.g., histogram), depicting the

relative number of operating hours at each of

the three load levels, low, mid and high. The

frequency distribution shall be based upon

all available data from the four most recent

QA operating quarters, as defined in section

2.3.1.1 of appendix B of this part. The owner

or operator shall use the frequency

distribution to determine, to the nearest 0.1

percent, the percentage of the time that each

load level (low, mid, high) has been used in

the previous four QA operating quarters. A

summary of the data used for these

determinations shall be kept on-site in a

format suitable for inspection and the results

of the determinations shall be included in the

electronic quarterly report under § 75.64.

Except for peaking units, the owner or

operator shall designate the most frequently

used load level as the normal load level for

each unit (or combination of units, for

common stacks). The owner or operator may

also, if appropriate, designate the second

most frequently used load level as an

additional normal load level for the unit or

stack. For peaking units, the entire operating

load range shall be considered normal.

Beginning on January 1, 2000, the owner or

operator shall report the upper and lower

boundaries of the range of operation for each

unit (or combination of units, for common

stacks), in units of megawatts or thousands

of lb/hr of steam production, in the electronic

quarterly report required under § 75.64.

Except for peaking units, the owner or

operator shall also indicate in the electronic

quarterly report: (1) the two load levels (low,

mid, or high) that are the most frequently

used, as determined under this section; (2)

the relative (percent) historical usage of each

load level, as determined under this section;

and (3) the load level (or levels) designated

as normal under this section.

6.5.2.2 Multi-Load Flow RATA Results

For each multi-load flow RATA, calculate

the flow monitor relative accuracy at each

operating level. If a flow monitor relative

accuracy test is failed or aborted due to a

problem with the monitor on any level of a

2-level (or 3-level) relative accuracy test

audit, the RATA must be repeated at that

load level. However, the entire 2-level (or 3-

level) relative accuracy test audit does not

have to be repeated unless the flow monitor

polynomial coefficients are changed, in

which case a 3-level RATA is required.

* * * * *

6.5.6 Reference Method Traverse Point

Selection

Select traverse points that ensure

acquisition of representative samples of

pollutant and diluent concentrations,

moisture content, temperature, and flue gas

flow rate over the flue cross section. To

achieve this, the reference method traverse

points shall meet the requirements of section

3.2 of Performance Specification 2 (‘‘PS No.

2’’) in appendix B to part 60 of this chapter

(for SO2, NOX, and moisture monitoring

system RATAs), Performance Specification 3

in appendix B to part 60 of this chapter (for

O2 and CO2 monitor RATAs), Method 1 (or

1A) (for volumetric flow rate monitor

RATAs), Method 3 (for molecular weight),

and Method 4 (for moisture determination) in

appendix A to part 60 of this chapter.

The following alternative reference method

traverse point locations are permitted for

moisture and gas monitor RATAs:

(a) For all moisture determinations, a

single reference method point, located at

least 1.0 meter from the stack wall, may be

used.

(b) For gas monitoring system RATAs, the

owner or operator may use any of the

following options:

(1) At any location (including locations

where stratification is expected), use a

minimum of six traverse points along a

diameter, in the direction of any expected

stratification. The points shall be located in

accordance with Method 1 in appendix A to

part 60 of this chapter.

(2) At locations where section 3.2 of PS No.

2 allows the use of a short reference method

measurement line (with three points located

at 0.4, 1.0, and 2.0 meters from the stack

wall), the owner or operator may use an

alternative 3-point measurement line,

locating the three points at 4.4, 14.6, and 29.6

percent of the way across the stack, in
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accordance with Method 1 in appendix A to

part 60 of this chapter.

(3) At locations where stratification is

likely to occur (i.e., following a wet scrubber

or when dissimilar gas streams are

combined), the short measurement line from

section 3.2 of PS No. 2 (or the alternative line

described in paragraph (c) of this section)

may be used in lieu of the prescribed ‘‘long’’

measurement line in section 3.2 of PS No. 2,

provided that the 12-point stratification test

described in section 6.5.6.1 of this appendix

is performed and passed one time at the

location (according to the acceptance criteria

of section 6.5.6.3(a) of this appendix) and

provided that either the 12-point

stratification test or the alternative

(abbreviated) stratification test in section

6.5.6.2 of this appendix is performed and

passed prior to each subsequent RATA at the

location (according to the acceptance criteria

of section 6.5.6.3(a) of this appendix).

(4) A single reference method measurement

point, located no less than 1.0 meter from the

stack wall, may be used at any sampling

location if the 12-point stratification test

described in section 6.5.6.1 of this appendix

is performed and passed one time at the

location (according to the acceptance criteria

of section 6.5.6.3(b) of this appendix) and

provided that either the 12-point

stratification test or the alternative

(abbreviated) stratification test in section

6.5.6.2 of this appendix is performed and

passed prior to each subsequent RATA at the

location (according to the acceptance criteria

of section 6.5.6.3(b) of this appendix).

6.5.6.1 Stratification Test

(a) With the unit(s) operating under steadystate conditions at normal load, as defined in

section 6.5.2.1 of this appendix, use a

traversing gas sampling probe to measure the

pollutant (SO2 or NOX) and diluent (CO2 or

O2) concentrations at a minimum of twelve

(12) points, located according to Method 1 in

appendix A to part 60 of this chapter.

(b) Use Methods 6C, 7E, and 3A in

appendix A to part 60 of this chapter to make

the measurements. Data from the reference

method analyzers must be quality assured by

performing analyzer calibration error and

system bias checks before the series of

measurements and by conducting system bias

and calibration drift checks after the

measurements, in accordance with the

procedures of Methods 6C, 7E, and 3A.

(c) Measure for a minimum of 2 minutes

at each traverse point. To the extent

practicable, complete the traverse within a 2-

hour period.

(d) If the load has remained constant (± 3.0

percent) during the traverse and if the

reference method analyzers have passed all

of the required quality assurance checks,

proceed with the data analysis.

(e) Calculate the average NOX, SO2, and

CO2 (or O2) concentrations at each of the

individual traverse points. Then, calculate

the arithmetic average NOX, SO2, and CO2 (or

O2) concentrations for all traverse points.

6.5.6.2 Alternative (Abbreviated)

Stratification Test

(a) With the unit(s) operating under steadystate conditions at normal load, as defined in

section 6.5.2.1 of this appendix, use a

traversing gas sampling probe to measure the

pollutant (SO2 or NOX) and diluent (CO2 or

O2) concentrations at three points. The

points shall be located according to the

specifications for the long measurement line

in section 3.2 of PS No. 2 (i.e., locate the

points 16.7 percent, 50.0 percent, and 83.3

percent of the way across the stack).

Alternatively, the concentration

measurements may be made at six traverse

points along a diameter. The six points shall

be located in accordance with Method 1 in

appendix A to part 60 of this chapter.

(b) Use Methods 6C, 7E, and 3A in

appendix A to part 60 of this chapter to make

the measurements. Data from the reference

method analyzers must be quality assured by

performing analyzer calibration error and

system bias checks before the series of

measurements and by conducting system bias

and calibration drift checks after the

measurements, in accordance with the

procedures of Methods 6C, 7E, and 3A.

(c) Measure for a minimum of 2 minutes

at each traverse point. To the extent

practicable, complete the traverse within a 1-

hour period.

(d) If the load has remained constant (± 3.0

percent) during the traverse and if the

reference method analyzers have passed all

of the required quality assurance checks,

proceed with the data analysis.

(e) Calculate the average NOX, SO2, and

CO2 (or O2) concentrations at each of the

individual traverse points. Then, calculate

the arithmetic average NOX, SO2, and CO2 (or

O2) concentrations for all traverse points.

6.5.6.3 Stratification Test Results and

Acceptance Criteria

(a) For each pollutant or diluent gas, the

short reference method measurement line

described in section 3.2 of PS No. 2 may be

used in lieu of the long measurement line

prescribed in section 3.2 of PS No. 2, if the

results of a stratification test, conducted in

accordance with section 6.5.6.1 or 6.5.6.2 of

this appendix (as appropriate; see section

6.5.6(b)(3) of this appendix), show that the

concentration at each individual traverse

point differs by no more than ±10.0 percent

from the arithmetic average concentration for

all traverse points. The results are also

acceptable if the concentration at each

individual traverse point differs by no more

than ±5 ppm or ±0.5 percent CO2 (or O2) from

the arithmetic average concentration for all

traverse points.

(b) For each pollutant or diluent gas, a

single reference method measurement point,

located at least 1.0 meter from the stack wall

may be used for that pollutant or diluent gas

if the results of a stratification test,

conducted in accordance with section 6.5.6.1

or 6.5.6.2 of this appendix (as appropriate;

see section 6.5.6(b)(4) of this appendix),

show that the concentration at each

individual traverse point differs by no more

than ±5.0 percent from the arithmetic average

concentration for all traverse points. The

results are also acceptable if the

concentration at each individual traverse

point differs by no more than ±3 ppm or ±0.3

percent CO2 (or O2) from the arithmetic

average concentration for all traverse points.

(c) The owner or operator shall keep the

results of all stratification tests on-site,

suitable for inspection, as part of the

supplementary RATA records required under

§ 75.56(a)(7) or § 75.59(a)(7), as applicable.

6.5.7 Sampling Strategy

Conduct the reference method tests so they

will yield results representative of the

pollutant concentration, emission rate,

moisture, temperature, and flue gas flow rate

from the unit and can be correlated with the

pollutant concentration monitor, CO2 or O2

monitor, flow monitor, and SO2 or NOX

continuous emission monitoring system

measurements. The minimum acceptable

time for a gas monitoring system RATA run

or for a moisture monitoring system RATA

run is 21 minutes. For each run of a gas

monitoring system RATA, all necessary

pollutant concentration measurements,

diluent concentration measurements, and

moisture measurements (if applicable) must,

to the extent practicable, be made within a

60-minute period. For NOX-diluent or SO2-

diluent monitoring system RATAs, the

pollutant and diluent concentration

measurements must be made simultaneously.

For flow monitor RATAs, the minimum time

per run shall be 5 minutes. Flow rate

reference method measurements may be

made either sequentially from port to port or

simultaneously at two or more sample ports.

The velocity measurement probe may be

moved from traverse point to traverse point

either manually or automatically. If, during a

flow RATA, significant pulsations in the

reference method readings are observed, be

sure to allow enough measurement time at

each traverse point to obtain an accurate

average reading (e.g., a ‘‘sight-weighted’’

average from a manometer). A minimum of

one set of auxiliary measurements for stack

gas molecular weight determination (i.e.,

diluent gas data and moisture data) is

required for every clock hour of a flow RATA

or for every three test runs (whichever is less

restrictive). Successive flow RATA runs may

be performed without waiting in-between

runs. If an O2-diluent monitor is used as a

CO2 continuous emission monitoring system,

perform a CO2 system RATA (i.e., measure

CO2, rather than O2, with the reference

method). To properly correlate individual

SO2 or NOX continuous emission monitoring

system data (in lb/mmBtu) and volumetric

flow rate data with the reference method

data, annotate the beginning and end of each

reference method test run (including the

exact time of day) on the individual chart

recorder(s) or other permanent recording

device(s).

* * * * *

6.5.9 Number of Reference Method Tests

Perform a minimum of nine sets of paired

monitor (or monitoring system) and reference

method test data for every required (i.e.,

certification, recertification, semiannual, or

annual) relative accuracy test audit. For 2-

level and 3-level relative accuracy test audits

of flow monitors, perform a minimum of nine

sets at each of the operating levels.

Note: The tester may choose to perform

more than nine sets of reference method

tests. If this option is chosen, the tester may

reject a maximum of three sets of the test

results, as long as the total number of test
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results used to determine the relative

accuracy or bias is greater than or equal to

nine. Report all data, including the rejected

CEM data and corresponding reference

method test results.

* * * * *

58. Section 7 of appendix A to part 75

is amended by revising the introductory

text of section 7.2.1 and the term ‘‘R’’

following equation A–5 and by revising

section 7.6.4; and by adding 4

paragraphs at the end of section 7.6.5

and a new section 7.7 to read as follows:

7. Calculations

* * * * *

7.2 * * *

7.2.1 Pollutant Concentration and Diluent

Monitors

For each reference value, calculate the

percentage calibration error based upon

instrument span for daily calibration error

tests using the following equation:

* * * * *

(Eq. A–5)

Where:

R=Reference value of zero or upscale (highlevel or mid-level, as applicable)

calibration gas introduced into the

monitoring system.

* * * * *

7.6.4 Bias Test

For gas monitoring systems, if the mean

difference, d, is greater than the absolute

value of the confidence coefficient, |cc|, the

monitor or monitoring system has failed to

meet the bias test requirement. For flow

monitor bias tests, if the mean difference, d,

is greater than |cc| at any load level

designated as normal under section 6.5.2.1 of

this appendix, the monitor has failed to meet

the bias test requirement.

7.6.5 * * *

For single-load RATAs of SO2-and NOXdiluent monitoring systems and for singleload flow RATAs required or allowed under

section 6.5.2 of this appendix and sections

2.3.1.3(b) and 2.3.1.3(c) of appendix B to this

part, the appropriate BAF is determined

directly from the RATA results at normal

load, using Equation A–12. Notwithstanding,

when a NOX or SO2 CEMS installed on a lowemitting affected unit (i.e., average SO2

concentration during the RATA <250 ppm or

average NOX emission rate <0.200 lb/mmBtu)

meets the normal 10.0 percent relative

accuracy specification (as calculated using

Equation A–10) or the alternate relative

accuracy specification in section 3.3 of this

appendix for low-emitters, but fails the bias

test, the BAF may be determined using

Equation A–12, or a default BAF of 1.111

may be used.

For a 2-level flow RATA, if the RATA is

passed but the bias test is failed at a load

level designated as normal under section

6.5.2.1 of this appendix, use Equation A–12

to calculate the bias adjustment factor at both

of the operating levels. For a 3-level flow

monitor relative accuracy test audit, if the

RATA is passed but the bias test is failed at

a load level designated as normal under

section 6.5.2.1 of this appendix, calculate

bias adjustment factors only for the two mostfrequently used load levels, as determined in

section 6.5.2.1 of this appendix. For both 2-

level and 3-level flow RATAs, whenever the

bias test is failed at a load level designated

as normal under section 6.5.2.1 of this

appendix, apply the larger of the two

calculated bias adjustment factors to

subsequent flow monitor data using Equation

A–11.

Each time a RATA is successfully

completed and the appropriate bias

adjustment factor has been determined, apply

the BAF prospectively to all monitoring

system data, beginning with the first clock

hour following the hour in which the RATA

was completed. For a 2-load flow RATA, the

‘‘hour in which the RATA was completed’’

refers to the hour in which the testing at both

loads was completed; for a 3-load RATA, it

refers to the hour in which the testing at all

three loads was completed.

Use the bias-adjusted values in computing

substitution values in the missing data

procedure, as specified in subpart D of this

part, and in reporting the concentration of

SO2, the flow rate, and the average NOX

emission rate, the unit heat input, and the

calculated mass emissions of SO2 and CO2

during the quarter and calendar year, as

specified in subpart G of this part.

7.7 Reference Flow-to-Load Ratio or Gross

Heat Rate

The owner or operator shall determine Rref,

the reference value of the ratio of flow rate

to unit load, each time that a successful flow

RATA is performed at a load level designated

as normal in section 6.5.2.1 of this appendix.

The owner or operator shall report the

current value of Rref in the electronic

quarterly report required under § 75.64 and

shall also report the completion date of the

associated RATA. If two load levels have

been designated as normal under section

6.5.2.1 of this appendix, the owner or

operator shall determine a separate Rref value

for each of the normal load levels. The

requirements of this section shall become

effective as of January 1, 2000. The reference

flow-to-load ratio shall be calculated as

follows:

R Q

L ref

ref

avg

= × − 10 5

(Eq. A–13)

Where:

Rref=Reference value of the flow-to-load ratio,

from the most recent normal-load flow

RATA, scfh/megawatts or scfh/1000 lb/

hr of steam.

Qref=Average stack gas volumetric flow rate

measured by the reference method

during the normal-load RATA, scfh.

Lavg=Average unit load during the normalload flow RATA, megawatts or 1000 lb/

hr of steam.

In Equation A–13, for a common stack, Lavg

shall be the sum of the operating loads of all

units that discharge through the stack. For a

unit that discharges its emissions through

multiple stacks, Qref will be the sum of the

total volumetric flow rates that discharge

through all of the stacks. Round off the value

of Rref to 2 decimal places.

In addition to determining Rref or as an

alternative to determining Rref, a reference

value of the gross heat rate (GHR) may be

determined. In order to use this option,

quality assured diluent gas (CO2 or O2) must

be available for each hour of the most recent

normal-load flow RATA. The reference value

of the GHR shall be determined as follows:

( ) ( ) GHR Heat Input

L ref

avg

avg

= ×1000

(Eq. A–13a)

Where:

(GHR)ref=Reference value of the gross heat

rate at the time of the most recent

normal-load flow RATA, Btu/kwh or

Btu/lb steam load.

(Heat Input)avg=Average hourly heat input

during the normal-load flow RATA, as

determined using the applicable

equation in appendix F to this part,

mmBtu/hr.

Lavg=Average unit load during the normalload flow RATA, megawatts or 1000 lb/

hr of steam.

In the calculation of (Heat Input)avg, use

Qref, the average volumetric flow rate

measured by the reference method during the

RATA, and use the average diluent gas

concentration measured during the flow

RATA.

* * * * *

59. Section 1 of appendix B to part 75

is revised as follows:

Appendix B to Part 75—Quality

Assurance and Quality Control

Procedures

1. Quality Assurance/Quality Control

Program

Develop and implement a quality

assurance/quality control (QA/QC) program

for the continuous emission monitoring

systems, excepted monitoring systems

approved under appendix D, E, or I to this

part, and alternative monitoring systems

under subpart E of this part, and their

components. At a minimum, include in each

QA/QC program a written plan that describes

in detail (or that refers to separate documents

containing) complete, step-by-step

procedures and operations for each of the

following activities. Upon request from

regulatory authorities, the source shall make

all procedures, maintenance records, and

ancillary supporting documentation from the

manufacturer (e.g., software coefficients and

troubleshooting diagrams) available for

review during an audit.

1.1 Requirements for All Monitoring

Systems

1.1.1 Preventive Maintenance

Keep a written record of procedures

needed to maintain the monitoring system in

proper operating condition and a schedule

for those procedures. This shall, at a

minimum, include procedures specified by

the manufacturers of the equipment and, if

applicable, additional or alternate procedures

developed for the equipment.
28168 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

1.1.2 Recordkeeping and Reporting

Keep a written record describing

procedures that will be used to implement

the recordkeeping and reporting

requirements in subparts E, F, and G and

appendices D, E, and I of this part, as

applicable.

1.1.3 Maintenance Records

Keep a record of all testing, maintenance,

or repair activities performed on any

monitoring system or component in a

location and format suitable for inspection. A

maintenance log may be used for this

purpose. The following records should be

maintained: date, time, and description of

any testing, adjustment, repair, replacement,

or preventive maintenance action performed

on any monitoring system and records of any

corrective actions associated with a monitor’s

outage period. Additionally, any adjustment

that recharacterizes a system’s ability to

record and report emissions data must be

recorded (e.g., changing flow monitor

polynomial coefficients, temperature and

pressure coefficients, and dilution ratio

settings), and a written explanation of the

procedures used to make the adjustment(s)

shall be kept.

1.2 Specific Requirements for Continuous

Emissions Monitoring Systems

1.2.1 Calibration Error Test and Linearity

Check Procedures

Keep a written record of the procedures

used for daily calibration error tests and

linearity checks (e.g., how gases are to be

injected, adjustments of flow rates and

pressure, introduction of reference values,

length of time for injection of calibration

gases, steps for obtaining calibration error or

error in linearity, determination of

interferences, and when calibration

adjustments should be made). Identify any

calibration error test and linearity check

procedures specific to the continuous

emission monitoring system that vary from

the procedures in appendix A to this part.

1.2.2 Calibration and Linearity Adjustments

Explain how each component of the

continuous emission monitoring system will

be adjusted to provide correct responses to

calibration gases, reference values, and/or

indications of interference both initially and

after repairs or corrective action. Identify

equations, conversion factors, assumed

moisture content, and other factors affecting

calibration of each continuous emission

monitoring system.

1.2.3 Relative Accuracy Test Audit

Procedures

Keep a written record of procedures and

details peculiar to the installed continuous

emission monitoring systems that are to be

used for relative accuracy test audits, such as

sampling and analysis methods.

1.2.4 Parametric Monitoring for Units with

Add-on Emission Controls

The owner or operator shall keep a written

(or electronic) record including a list of

operating parameters for the add-on SO2 or

NOX emission controls, including parameters

in § 75.55(b) or § 75.58(b), as applicable, and

the range of each operating parameter that

indicates the add-on emission controls are

operating properly. The owner or operator

shall keep a written (or electronic) record of

the parametric monitoring data during each

SO2 or NOX missing data period.

1.3 Specific Requirements for Excepted

Systems Approved under Appendices D, E,

and I

1.3.1 Fuel Flowmeter Accuracy Test

Procedures

Keep a written record of the specific fuel

flowmeter accuracy test procedures. These

may include: standard methods or

specifications listed in § 75.20(g) and section

2.1.5.1 of appendix D to this part and

incorporated by reference under § 75.6; the

procedures of sections 2.1.5.2 or 2.1.7 of

appendix D to this part; or other methods

approved by the Administrator through the

petition process of § 75.66(c).

1.3.2 Transducer or Transmitter Accuracy

Test Procedures

Keep a written record of the procedures for

testing the accuracy of transducers or

transmitters of an orifice-, nozzle-, or venturitype fuel flowmeter under section 2.1.6 of

appendix D to this part. These procedures

should include a description of equipment

used, steps in testing, and frequency of

testing.

1.3.3 Fuel Flowmeter, Transducer, or

Transmitter Calibration and Maintenance

Records

Keep a record of adjustments,

maintenance, or repairs performed on the

fuel flowmeter monitoring system. Keep

records of the data and results for fuel

flowmeter accuracy tests and transducer

accuracy tests, consistent with appendix D to

this part.

1.3.4 Primary Element Inspection

Procedures

Keep a written record of the standard

operating procedures for inspection of the

primary element (i.e., orifice, venturi, or

nozzle) of an orifice-, venturi-, or nozzle-type

fuel flowmeter. Examples of the types of

information to be included are: what to

examine on the primary element; how to

identify if there is corrosion sufficient to

affect the accuracy of the primary element;

and what inspection tools (e.g., boroscope), if

any, are used.

1.3.5 Fuel Sampling Method and Sample

Retention

Keep a written record of the standard

procedures used to perform fuel sampling,

either by utility personnel or by fuel supply

company personnel. These procedures

should specify the portion of the ASTM

method used, as incorporated by reference

under § 75.6, or other methods approved by

the Administrator through the petition

process of § 75.66(c). These procedures

should describe safeguards for ensuring the

availability of an oil sample (e.g., procedure

and location for splitting samples, procedure

for maintain sample splits on site, and

procedure for transmitting samples to an

analytical laboratory). These procedures

should identify the ASTM analytical

methods used to analyze sulfur content, gross

calorific value, and density, as incorporated

by reference under § 75.6, or other methods

approved by the Administrator through the

petition process of § 75.66(c).

1.3.6 Appendix E Monitoring System

Quality Assurance Information

Identify the unit manufacturer’s

recommended range of quality assuranceand quality control-related operating

parameters. Keep records of these operating

parameters for each hour of unit operation

(i.e., fuel combustion). Keep a written record

of the procedures used to perform NOX

emission rate testing. Keep a copy of all data

and results from the initial and from the most

recent NOX emission rate testing, including

the values of quality assurance parameters

specified in section 2.3 of appendix E to this

part.

1.3.7 Appendix I Additional Requirements

1.3.7.1 For all appendix I systems, the

fuel sampling and analysis requirements in

section 1.3.5 of this appendix shall be met;

and, for the diluent monitor, the Calibration

Error Test and Linearity Check Procedures

requirements in sections 1.2.1 and 1.2.2 of

this appendix shall be met.

1.3.7.2 For appendix I systems that are

certified according to the system certification

procedures, the Relative Accuracy Test Audit

Procedures requirement in section 1.2.3 of

this appendix shall be met for the annual or

semiannual Method 2 flow RATA.

1.3.7.3 For appendix I systems that are

certified according to the component-bycomponent certification procedures, the fuel

flowmeter requirements applicable to the

type of fuel flowmeter used in sections 1.3.1

through 1.3.5 of this appendix shall be met.

The Relative Accuracy Test Audit Procedures

requirement in section 1.2.3 of this appendix

shall be met for the diluent monitor that is

part of the appendix I system.

1.4 Requirements for Alternative Systems

Approved under Subpart E

1.4.1 Daily Quality Assurance Tests

Explain how the daily assessment

procedures specific to the alternative

monitoring system are to be performed.

1.4.2 Daily Quality Assurance Test

Adjustments

Explain how each component of the

alternative monitoring system will be

adjusted in response to the results of the

daily assessments.

1.4.3 Relative Accuracy Test Audit

Procedures

Keep a written record of procedures and

details peculiar to the installed alternative

monitoring system that are to be used for

relative accuracy test audits, such as

sampling and analysis methods.

60. Section 2 of appendix B to part 75

is amended by:

a. Revising sections 2.1.1, 2.1.3, 2.1.4,

2.2, 2.3; revising paragraph (1) of section

2.1.5.1;

b. Redesignating existing section 2.4

as section 2.5; and

c. Adding a new section 2.4, to read

as follows:
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28169

2. Frequency of Testing

* * * * *

2.1 * * *

2.1.1 Calibration Error Test

Except as provided in section 2.1.1.2 of

this appendix, perform the daily calibration

error test of each gas monitoring system

(including moisture monitoring systems

consisting of wet- and dry-basis O2 analyzers)

according to the procedures in section 6.3.1

of appendix A to this part, and perform the

daily calibration error test of each flow

monitoring system according to the

procedure in section 6.3.2 of appendix A to

this part. For continuous moisture sensors,

follow the manufacturer’s recommended

procedures for the daily calibration error

check. Include the calibration procedures as

part of the quality assurance program

required under section 1 of this appendix.

* * * * *

2.1.3 Additional Calibration Error Tests and

Calibration Adjustments

In addition to the daily calibration error

tests required under section 2.1.1 of this

appendix, a calibration error test of a CEMS

shall be performed in accordance with

section 2.1.1 of this appendix, as follows: (1)

whenever a daily calibration error test is

failed; (2) whenever a monitoring system is

returned to service following repair or

corrective maintenance that could affect the

monitor’s ability to accurately measure and

record emissions data; and (3) after making

certain calibration adjustments, as described

in this section. In all cases, data from the

CEMS are considered invalid until the

required additional calibration error test has

been successfully completed.

Routine calibration adjustments of a

monitor are permitted after any successful

calibration error test. These routine

adjustments shall be made so as to bring the

monitor readings as close as practicable to

the known tag values of the calibration gases

or to the actual value of the flow monitor

reference signals. An additional calibration

error test is required following routine

calibration adjustments where the monitor’s

calibration has been physically adjusted (e.g.,

by turning a potentiometer) to verify that the

adjustments have been made properly. An

additional calibration error test is not

required, however, if the routine calibration

adjustments are made by means of a

mathematical algorithm programmed into the

data acquisition and handling system. The

EPA recommends that routine calibration

adjustments be made, at a minimum,

whenever the daily calibration error exceeds

the limits of the applicable performance

specification in appendix A to this part for

the pollutant concentration monitor, CO2 or

O2 monitor, or flow monitor.

Additional (non-routine) calibration

adjustments of a monitor are permitted,

provided that an appropriate technical

justification is included in the quality control

program required under section 1 of this

appendix. The allowable non-routine

adjustments are as follows. The owner or

operator may physically adjust the

calibration of a monitor (e.g., by means of a

potentiometer), provided that the postadjustment zero and upscale responses of the

monitor are within the performance

specifications of the instrument given in

section 3.1 of appendix A to this part. An

additional calibration error test is required

following such adjustments to verify that the

monitor is operating within the performance

specifications.

2.1.4 Data Validation

(a) An out-of-control period occurs when

the calibration error of an SO2 or NOX

pollutant concentration monitor exceeds 5.0

percent of the span value (or exceeds 10

ppm, for span values <200 ppm), when the

calibration error of a CO2 or O2 monitor

(including O2 monitors used to measure CO2

emissions or percent moisture) exceeds 1.0

percent O2 or CO2, or when the calibration

error of a flow monitor or a moisture sensor

exceeds 6.0 percent of the span value, which

is twice the applicable specification of

appendix A to this part. Notwithstanding, a

differential pressure-type flow monitor for

which the calibration error exceeds 6.0

percent of the span value shall not be

considered out-of-control if |R¥A|, the

absolute value of the difference between the

monitor response and the reference value in

Equation A–6, is ≤0.02 inches of water. The

out-of-control period begins with the hour of

completion of the failed calibration error test

and ends with the hour following the hour

of completion of a successful calibration

error test. Note, however, that if the failed

calibration, corrective action, and successful

calibration error test occur within the same

hour, emission data for that hour recorded by

the monitor after the successful calibration

error test may be used for reporting purposes,

provided that 2 or more valid readings are

obtained as required by § 75.10. A NOXdiluent continuous emission monitoring

system is considered out-of-control if the

calibration error of either component monitor

exceeds twice the applicable performance

specification in appendix A to this part.

Emission data shall not be reported from an

out-of-control monitor.

(b) An out-of-control period also occurs

whenever interference of a flow monitor is

identified. The out-of-control period begins

with the hour of completion of the failed

interference check and ends with the hour of

completion of an interference check that is

passed.

2.1.5 * * *

2.1.5.1 * * *

(1) Data from a monitoring system are

invalid, beginning with the first hour

following the expiration of a 26-hour data

validation period or beginning with the first

hour following the expiration of an 8-hour

start-up grace period (as provided under

section 2.1.5.2 of this appendix), if the

required subsequent daily assessment has not

been conducted.

* * * * *

2.2 Quarterly Assessments

For each primary and redundant backup

continuous emission monitoring system,

perform the following quarterly assessments.

This requirement is effective as of the

calendar quarter following the calendar

quarter in which the monitor or continuous

emission monitoring system is provisionally

certified.

2.2.1 Linearity Check

Perform a linearity check, in accordance

with the procedures in section 6.2 of

appendix A to this part, for each primary and

redundant backup SO2 and NOX pollutant

concentration monitor and each primary and

redundant backup CO2 or O2 monitor

(including O2 monitors used to measure CO2

emissions or to continuously monitor

moisture) at least once during each QA

operating quarter. A QA operating quarter is

a calendar quarter in which the unit operates

(i.e., combusts fuel) for at least 168 hours or,

for common stacks and bypass stacks, a

calendar quarter in which flue gases are

discharged through the stack for at least 168

hours. For units using both a low and high

span value, a linearity check is required only

on the range(s) used to record and report

emission data during the QA operating

quarter. Conduct the linearity checks no less

than 30 days apart, to the extent practicable.

The data validation procedures in section

2.2.3 of this appendix shall be followed.

2.2.2 Leak Check

For differential pressure flow monitors,

perform a leak check of all sample lines (a

manual check is acceptable) at least once

during each QA operating quarter. For this

test, the unit does not have to be in

operation. Conduct the leak checks no less

than 30 days apart, to the extent practicable.

If a leak check is failed, follow the applicable

data validation procedures in section 2.2.3(f)

of this appendix.

2.2.3 Data Validation

(a) A routine quality assurance linearity

test shall not be commenced if the

monitoring system is operating out-of-control

with respect to any of the daily, quarterly, or

semiannual quality assurance assessments

required by sections 2.1, 2.2, and 2.3 of this

appendix or with respect to the additional

calibration error test requirements in section

2.1.3 of this appendix.

(b) Linearity checks shall be done handsoff, as follows. No adjustments of the monitor

are permitted prior to or during the linearity

test period, other than the routine and nonroutine calibration adjustments described in

section 2.1.3 of this appendix. The nonroutine adjustments are permitted only prior

to the test, not during the test period.

(c) If a daily calibration error test is failed

during a linearity test period, prior to

completing the test, the linearity test is

invalidated and must be repeated. Data from

the monitor are invalidated prospectively

from the hour of the failed calibration error

test until the hour of completion of a

subsequent successful calibration error test.

The linearity test shall not be re-commenced

until the monitor has successfully completed

a calibration error test.

(d) An out-of-control period occurs when

a linearity test is failed (i.e., when the error

in linearity at any of the three concentrations

in the quarterly linearity check (or any of the

six concentrations, when both ranges of a

single analyzer with a dual range are tested)

exceeds the applicable specification in
28170 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

section 3.2 of appendix A to this part) or

when a linearity test is aborted due to a

problem with the CEMS. For a NOX-diluent

or SO2-diluent continuous emission

monitoring system, the system is considered

out-of-control if either of the component

monitors exceeds the applicable specification

in section 3.2 of appendix A to this part or

if the linearity test of either component is

aborted due to a problem with the monitor.

The out-of-control period begins with the

hour of the failed or aborted linearity check

and ends with the hour of completion of a

satisfactory linearity check following

corrective action and/or monitor repair. Note

that a monitor shall not be considered outof-control when a linearity test is aborted for

a reason unrelated to the monitor’s

performance (e.g., a forced unit outage).

(e) No more than four successive calendar

quarters shall elapse after the quarter in

which a linearity check of a CEMS (or range

of a CEMS) was last performed without a

subsequent linearity test having been

conducted. If a linearity test has not been

completed by the end of the fourth calendar

quarter since the last linearity test, then the

linearity test must be completed within a 168

unit operating hour ‘‘grace period’’ (as

provided in section 2.2.4 of this appendix)

following the end of the fourth successive

elapsed calendar quarter, or data from the

CEMS (or range) will become invalid.

(f) An out-of-control period also occurs

when a flow monitor sample line leak is

detected. The out-of-control period begins

with the hour of the failed leak check and

ends with the hour of a satisfactory leak

check following corrective action.

(g) For each monitoring system, report the

results of all completed and partial linearity

tests that affect data validation (i.e., all

completed, passed linearity checks; all

completed, failed linearity checks; and all

linearity checks aborted due to a problem

with the monitor) in the quarterly report

required under § 75.64. Note that linearity

attempts which are aborted or invalidated

due to problems with the reference

calibration gases or due to operational

problems with the affected unit(s) need not

be reported. Such partial tests do not affect

the validation status of emission data

recorded by the monitor. However, a record

of all linearity tests and attempts (whether

reported or not) must be kept on-site as part

of the official test log for each monitoring

system.

2.2.4 Linearity and Leak Check Grace

Period

When a required linearity test or flow

monitor leak check has not been completed

by the end of the QA operating quarter in

which it is due or if, due to infrequent

operation of a unit or infrequent use of a

required high range of a CEMS, four

successive calendar quarters have elapsed

after the quarter in which a linearity check

of a CEMS (or range) was last performed

without a subsequent linearity test having

been done, the owner or operator has a grace

period of 168 consecutive unit operating

hours in which to perform a linearity test or

leak check of that CEMS (or range). The grace

period begins with the first unit operating

hour following the calendar quarter in which

the linearity test was due. Data validation

during a linearity or leak check grace period

shall be done in accordance with the

applicable provisions in section 2.2.3 of this

appendix.

If, at the end of the 168 unit operating hour

grace period, the required linearity test or

leak check has not been completed, data from

the monitoring system (or range) shall be

invalid, beginning with the hour following

the expiration of the grace period. Data from

the monitoring system (or range) remain

invalid until the hour of completion of a

subsequent successful hands-off linearity test

or leak check of the CEMS (or range). Note

that when a linearity test or a leak check is

conducted within a grace period for the

purpose of satisfying the linearity test or leak

check requirement from a previous QA

operating quarter, the results of that linearity

test or leak check may only be used to meet

the linearity check or leak check requirement

of the previous quarter, not the quarter in

which the grace period is used.

2.2.5 Flow-to-Load Ratio or Gross Heat Rate

Evaluation

For each installed flow rate monitoring

system on each unit or common stack, the

owner or operator shall evaluate the flow-toload ratio quarterly, i.e., for each QA

operating quarter, as defined in sections 2.2.1

and 2.3.1.1 of this appendix. At the end of

each QA operating quarter, the owner or

operator shall use Equation B–1 in this

appendix to calculate the flow-to-load ratio

for every hour during the quarter in which:

(1) the unit (or combination of units, for a

common stack) operated within ±10.0

percent of Lavg, the average load during the

most recent normal-load flow RATA; and (2)

a quality assured hourly average flow rate

was obtained with a certified flow rate

monitor.

R Q

L h

h

h

= ×1000

(Eq. B–1)

Where:

Rh = Hourly value of the flow-to-load ratio,

scfh/megawatts or scfh/1000 lb/hr of

steam load.

Qh = Hourly stack gas volumetric flow rate,

as measured by the flow rate monitor,

scfh.

Lh = Hourly unit load, megawatts or 1000 lb/

hr of steam; must be within ±10.0

percent of Lavg during the most recent

normal-load flow RATA.

In Equation B–1, the owner or operator

may use either bias-adjusted flow rates or

unadjusted flow rates, provided that all of the

ratios are calculated the same way. For a

common stack, Lh shall be the sum of the

hourly operating loads of all units that

discharge through the stack. For a unit that

discharges its emissions through multiple

stacks or monitors its emissions in multiple

breechings, Qh will be the combined hourly

volumetric flow rate for all of the stacks or

ducts. Round off each value of Rh to 2

decimal places.

Alternatively, the owner or operator may

calculate the hourly gross heat rates (GHR) in

lieu of the hourly flow-to-load ratios. The

hourly GHR shall be determined only for

those hours in which quality assured flow

rate data and diluent gas (CO2 or O2)

concentration data are both available from a

certified CEMS or reference method. If this

option is selected, calculate each hourly GHR

value as follows:

( ) ( ) GHR Heat Input

L h

h

h

= ×1000

(Eq. B–1a)

Where:

(GHR)h = Hourly value of the gross heat rate,

Btu/kwh or Btu/lb steam load.

(Heat Input)h = Hourly heat input, as

determined from the quality assured

flow rate and diluent data, using the

applicable equation in appendix F to this

part, mmBtu/hr.

Lh = Hourly unit load, megawatts or 1000 lb/

hr of steam; must be within ± 10.0

percent of Lavg during the most recent

normal-load flow RATA.

In Equation B–1a, the owner or operator

may either use bias-adjusted flow rates or

unadjusted flow rates in the calculation of

(Heat Input)h, provided that all of the heat

input values are determined in the same

manner.

The owner or operator shall evaluate the

calculated hourly flow-to-load ratios (or gross

heat rates) as follows. A separate data

analysis shall be performed for each primary

and each redundant backup flow rate

monitor used to record and report data

during the quarter. Each analysis shall be

based on a minimum of 168 hours of data.

When two RATA load levels are designated

as normal, the analysis shall be performed at

the higher load level, unless there are fewer

than 168 data points available at that load

level, in which case the analysis shall be

performed at the lower load level. If, for a

particular flow monitor, fewer than 168

hourly flow-to-load ratios (or GHR values) are

available at any of the load levels designated

as normal, a flow-to-load (or GHR) evaluation

is not required for that monitor for that

calendar quarter.

For each flow monitor, use Equation B–2

in this appendix to calculate Eh, the absolute

percentage difference between each hourly Rh

value and Rref, the reference value of the

flow-to-load ratio, as determined in

accordance with section 7.7 of appendix A to

this part. Note that Rref shall always be based

upon the most recent normal-load RATA,

even if that RATA was performed in the

calendar quarter being evaluated.

E

R R

R h

ref h

ref

= − ×100

(Eq. B–2)

Where:

Eh = Absolute percentage difference between

the hourly average flow-to-load ratio and

the reference value of the flow-to-load

ratio at normal load.

Rh = The hourly average flow-to-load ratio,

for each flow rate recorded at a load level

within ± 10.0 percent of Lavg.
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28171

Rref = The reference value of the flow-to-load

ratio from the most recent normal-load

flow RATA, determined in accordance

with section 7.7 of appendix A to this

part.

Equation B–2 shall be used in a consistent

manner. That is, use Rref and Rh if the flowto-load ratio is being evaluated, and use

(GHR)ref and (GHR)h if the gross heat rate is

being evaluated. Finally, calculate Ef, the

arithmetic average of all of the hourly Eh

values. The owner or operator shall report

the results of each quarterly flow-to-load (or

gross heat rate) evaluation, as determined

from Equation B–2, in the electronic

quarterly report required under § 75.64.

The results of a quarterly flow-to-load (or

gross heat rate) evaluation are acceptable,

and no further action is required, if the

calculated value of Ef is less than or equal to:

(i) 15.0 percent, if Lavg for the most recent

normal-load flow RATA is ≥50 megawatts (or

≥500 klb/hr of steam) and if unadjusted flow

rates were used in the calculations; (ii) 10.0

percent, if Lavg for the most recent normalload flow RATA is ≥50 megawatts (or ≥500

klb/hr of steam) and if bias-adjusted flow

rates were used in the calculations; (iii) 20.0

percent, if Lavg for the most recent normalload flow RATA is <50 megawatts (or <500

klb/hr of steam) and if unadjusted flow rates

were used in the calculations; or (iv) 15.0

percent, if Lavg for the most recent normalload flow RATA is <50 megawatts (or <500

klb/hr of steam) and if bias-adjusted flow

rates were used in the calculations.

If Ef is above these limits, the owner or

operator shall: (a) implement Option 1 in

section 2.2.5.1 of this appendix; (b) perform

a RATA in accordance with Option 2 in

section 2.2.5.2 of this appendix; or (c) reexamine the hourly data used for the flowto-load or GHR analysis and recalculate Ef,

after excluding all non-representative hourly

flow rates.

If the owner or operator chooses to

recalculate Ef, the flow rates for the following

hours are considered non-representative and

may be excluded from the data analysis:

(1) Any hour in which the type of fuel

combusted was different from the fuel

burned during the most recent normal-load

RATA. For purposes of this determination,

the type of fuel is different if the fuel is in

a different state of matter (i.e., solid, liquid,

or gas) than is the fuel burned during the

RATA or if the fuel is a different

classification of coal (e.g., bituminous versus

sub-bituminous);

(2) Any hour in which an SO2 scrubber was

bypassed;

(3) Any hour in which ‘‘ramping’’

occurred, i.e., the hourly load differed by

more than ±15.0 percent from the load during

the preceding hour or the subsequent hour;

(4) If a normal-load flow RATA was

performed and passed during the quarter

being analyzed, any hour prior to completion

of that RATA; and

(5) If a problem with the accuracy of the

flow monitor was discovered during the

quarter and was corrected (as evidenced by

passing the abbreviated flow-to-load test in

section 2.2.5.3 of this appendix), any hour

prior to completion of the abbreviated flowto-load test.

After identifying and excluding all nonrepresentative hourly data in accordance

with (1) through (5) above, the owner or

operator may analyze the remaining data a

second time. At least 168 representative

hourly ratios or GHR values must be

available to perform the analysis; otherwise,

the flow-to-load (or GHR) analysis is not

required for that monitor for that calendar

quarter.

If, after re-analyzing the data, Ef meets the

applicable limit in (i),(ii), (iii), or (iv), above,

no further action is required. If, however, Ef

is still above the applicable limit, the monitor

shall be declared out-of-control, beginning

with the first hour of the quarter following

the quarter in which Ef exceeded the

applicable limit. The owner or operator shall

then either implement Option 1 in section

2.2.5.1 of this appendix or Option 2 in

section 2.2.5.2 of this appendix.

2.2.5.1 Option 1

Within one week of the end of the calendar

quarter for which the flow-to-load (or GHR)

evaluation indicates noncompliance,

investigate and troubleshoot each flow

monitor for which Ef has been found to be

above the applicable limit. Evaluate the

results of each investigation as follows:

(a) If the investigation fails to uncover a

problem with the flow monitor, a RATA shall

be performed in accordance with Option 2 in

section 2.2.5.2 of this appendix.

(b) If a problem with the flow monitor is

identified through the investigation

(including the need to re-linearize the

monitor by changing the polynomial

coefficients), corrective actions shall be

taken. All corrective actions (e.g., nonroutine maintenance, repairs, major

component replacements, re-linearization of

the monitor, etc.) shall be documented in the

operation and maintenance records for the

monitor. Data from the monitor shall remain

invalid until a probationary calibration error

test of the monitor is passed following

completion of all corrective actions, at which

point data from the monitor are conditionally

valid. The owner or operator shall then

either: (1) complete the abbreviated flow-toload test in section 2.2.5.3 of this appendix;

or (2) perform a 3-level recertification RATA

according to the recertification test period

and data validation procedures of

§ 75.20(b)(3), if the corrective action has

affected the linearity of the flow monitor

(e.g., by requiring changes to the flow

monitor polynomial coefficients).

2.2.5.2 Option 2

Perform a single-load RATA (at a load

designated as normal under section 6.5.2.1 of

appendix A to this part) of each flow monitor

for which Ef is outside of the applicable limit.

Data from the monitor remain invalid until

the required RATA has been successfully

completed.

2.2.5.3 Abbreviated Flow-to-Load Test

The following abbreviated flow-to-load test

may be performed after any documented

repair, component replacement, or other

corrective maintenance to a flow monitor

(except for changes affecting the linearity of

the flow monitor, such as adjusting the flow

monitor coefficients) to demonstrate that the

repair, replacement, or other maintenance

has not significantly affected the monitor’s

ability to accurately measure the stack gas

volumetric flow rate. Data from the

monitoring system are considered invalid

from the hour of commencement of the

repair, replacement, or maintenance until the

hour in which a probationary calibration

error test is passed following completion of

the repair, replacement, or maintenance and

any associated adjustments to the monitor.

The abbreviated flow-to-load test shall be

completed within 168 unit operating hours of

the probationary calibration error test (or, for

peaking units, within 30 unit operating days,

if that is less restrictive). Data from the

monitor are considered to be conditionally

valid (as defined in § 72.2 of this chapter),

beginning with the hour of the probationary

calibration error test.

Operate the unit(s) in such a way as to

reproduce, as closely as practicable, the exact

conditions at the time of the most recent

normal-load flow RATA. To achieve this, it

is recommended that the load be held

constant to within ±5.0 percent of the average

load during the RATA and that the diluent

gas (CO2 or O2) concentration be maintained

within ±0.5 percent CO2 or O2 of the average

diluent concentration during the RATA. For

common stacks, to the extent practicable, use

the same combination of units and load

levels that were used during the RATA.

When the process parameters have been set,

record a minimum of 6 and a maximum of

12 consecutive hourly average flow rates,

using the flow monitor(s) for which Ef was

outside the applicable limit. For peaking

units, a minimum of 3 and a maximum of 12

consecutive hourly average flow rates are

required. Also record the corresponding

hourly load values and, if applicable, the

hourly diluent gas concentrations. Calculate

the flow-to-load ratio (or GHR) for each hour

in the test hour period, using Equation B–1

or B–1a. Determine Eh for each hourly flowto-load ratio (or GHR), using Equation B–2 of

this appendix and then calculate Ef, the

arithmetic average of the Eh values.

The results of the abbreviated flow-to-load

test shall be considered acceptable, and no

further action is required if the value of Ef

does not exceed the applicable limit

specified in section 2.2.5.1 of this appendix.

All conditionally valid data recorded by the

flow monitor shall be considered quality

assured, beginning with the hour of the

probationary calibration error test that

preceded the abbreviated flow-to-load test.

However, if Ef is outside the applicable limit,

all conditionally valid data recorded by the

flow monitor shall be considered invalid

back to the hour of the probationary

calibration error test that preceded the

abbreviated flow-to-load test, and a singleload RATA is required in accordance with

section 2.2.5.2 of this appendix. If the flow

monitor must be re-linearized, however, a 3-

load RATA is required, in accordance with

the recertification test period and data

validation procedures of § 75.20(b)(3).

2.3 Semiannual and Annual Assessments

For each primary and redundant backup

continuous emission monitoring system,

perform relative accuracy assessments either
28172 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

semiannually or annually, as specified in

subsection 2.3.1.1 or 2.3.1.2, below, for the

type of test and the performance achieved.

This requirement is effective as of the

calendar quarter following the calendar

quarter in which the continuous emission

monitoring system is provisionally certified.

A summary chart showing the frequency

with which a relative accuracy test audit

must be performed, depending on the

accuracy achieved, is located at the end of

this appendix in Figure 2.

2.3.1 Relative Accuracy Test Audit (RATA)

2.3.1.1 Standard RATA Frequencies

Except as otherwise specified in

§ 75.21(a)(6) or (a)(7) or in section 2.3.1.2 of

this appendix, perform relative accuracy test

audits semiannually, i.e., once every two

successive QA operating quarters for each

primary and redundant backup SO2 pollutant

concentration monitor, flow monitor, CO2

pollutant concentration monitor (including

O2 monitors used to determine CO2

emissions), moisture monitoring system,

NOX-diluent continuous emission monitoring

system, or SO2-diluent continuous emission

monitoring system used by units with a

Phase I qualifying technology for the period

during which the units are required to

monitor SO2 emission removal efficiency,

from January 1, 1997 through December 31,

1999. A QA operating quarter is a calendar

quarter in which the unit operates for at least

168 hours or, for a common stack or bypass

stack, a calendar quarter in which flue gases

are discharged through the stack for at least

168 hours. A calendar quarter that does not

qualify as a QA operating quarter shall be

excluded in determining the deadline for the

next RATA. No more than eight successive

calendar quarters shall elapse after the

quarter in which a RATA was last performed

without a subsequent RATA having been

conducted. If a RATA has not been

completed by the end of the eighth calendar

quarter since the quarter of the last RATA,

then the RATA must be completed within a

720 unit operating hour grace period (as

provided in section 2.3.3 of this appendix)

following the end of the eighth successive

elapsed calendar quarter, or data from the

CEMS will become invalid.

The relative accuracy test audit frequency

of a CEMS may be reduced, as specified in

subsection 2.3.1.2, below, for primary or

redundant backup monitoring systems which

qualify for less frequent testing. Perform all

required RATAs in accordance with the

applicable procedures and provisions in

sections 6.5 through 6.5.2.2 of appendix A to

this part and subsections 2.3.1.3 and 2.3.1.4

of this appendix.

2.3.1.2 Reduced RATA Frequencies

Relative accuracy test audits of primary

and redundant backup SO2 pollutant

concentration monitors, CO2 pollutant

concentration monitors (including O2

monitors used to determine CO2 emissions),

moisture monitors, flow monitors, or NOXdiluent or SO2-diluent monitoring systems

may be performed annually (i.e., once every

four successive QA operating quarters, rather

than once every two successive QA operating

quarters) if any of the following conditions

are met for the specific monitoring system

involved: (1) the relative accuracy during the

audit of an SO2 or CO2 pollutant

concentration monitor (including an O2

pollutant monitor used to measure CO2 using

the procedures in appendix F to this part) or

of a NOX-diluent or SO2-diluent continuous

emissions monitoring system is ≤7.5 percent;

(2) prior to January 1, 2000, the relative

accuracy during the audit of a flow monitor

is ≤10.0 percent at each operating level

tested; (3) on and after January 1, 2000, the

relative accuracy during the audit of a flow

monitor is ≤7.5 percent at each operating

level tested; (4) on low flow (≤10.0 fps)

stacks/ducts, when flow monitor achieves a

relative accuracy ≤7.5 percent (10.0 percent

if prior to January 1, 2000) during the audit

or when the monitor mean, calculated using

Equation A–7 in appendix A to this part, is

within ±1.5 fps of the reference method

mean; (5) on low SO2 emitting units (average

SO2 concentrations 250 ppm, or average SO2

emission rate 0.500 lb/mmBtu for SO2-

diluent continuous emission monitoring

systems), when the CEMS achieves a relative

accuracy ≤7.5 percent during the audit or

when the monitor mean value from the

RATA is within ± 12 ppm (or 0.025 lb/

mmBtu for SO2-diluent continuous emission

monitoring systems) of the reference method

mean value; (6) on low NOX emitting units

(average NOX emission rate ≤0.200 lb/

mmBtu), when the NOX continuous emission

monitoring system achieves a relative

accuracy ≤7.5 percent or when the

monitoring system mean value from the

RATA, calculated using Equation A–7 in

appendix A to this part, is within ± 0.015 lb/

mmBtu of the reference method mean value;

(7) for a CO2 or O2 monitor, when the mean

difference between the reference method

values from the RATA and the corresponding

monitor values is within ±0.7 percent CO2 or

O2; and (8) when the relative accuracy of a

continuous moisture monitoring system is

≤7.5 percent or when the mean difference

between the reference method values from

the RATA and the corresponding monitoring

system values is within ±0.7 percent H2O.

2.3.1.3 RATA Load Levels

(a) For SO2 pollutant concentration

monitors, CO2 pollutant concentration

monitors (including O2 monitors used to

determine CO2 emissions), moisture

monitoring systems, and SO2-diluent and

NOX-diluent monitoring systems, the

required RATA tests shall be done at the load

level designated as normal under section

6.5.2.1 of appendix A to this part. If two load

levels are designated as normal, the required

RATA(s) may be done at either load level.

(b) For flow monitors installed on peaking

units and bypass stacks, all required relative

accuracy test audits shall be single-load

audits at the normal load, as defined in

section 6.5.2.1 of appendix A to this part.

(c) For all other flow monitors, the RATAs

shall be performed as follows. When a flow

monitor qualifies for an annual RATA

frequency under section 2.3.1.2 of this

appendix, the annual RATA shall be done at

the two most frequently used load levels, as

determined under section 6.5.2.1 of appendix

A to this part. The annual 2-load flow RATA

may be performed alternately with a singleload flow RATA at the most frequently used

(normal) load level if the flow monitor is on

a semiannual RATA frequency. In addition,

a single-load flow RATA, at the most

frequently used load level, may be performed

in lieu of the 2-load RATA if, for the four QA

operating quarters prior to the quarter in

which the RATA is performed, the historical

load frequency distribution determined

under section 6.5.2.1 of appendix A to this

part shows that the unit has operated at the

most frequently used load level for ≤85.0

percent of the time. Finally, a 3-load RATA,

at the low-, mid-, and high-load levels,

determined under section 6.5.2.1 of appendix

A to this part, shall be performed at least

once in every period of five consecutive

calendar years, and a 3-load RATA is

required whenever a flow monitor is relinearized, i.e., when one or more of its

polynomial coefficients are changed. For all

multi-level flow audits, the audit points at

adjacent load levels (e.g., mid and high) shall

be separated by no less than 25.0 percent of

the ‘‘range of operation,’’ as defined in

section 6.5.2.1 of appendix A to this part.

2.3.1.4 Number of RATA Attempts

The owner or operator may perform as

many RATA attempts as are necessary to

achieve the desired relative accuracy test

audit frequencies and/or bias adjustment

factors. However, the data validation

procedures in section 2.3.2 of this appendix

must be followed.

2.3.2 Data Validation

(a) A routine quality assurance RATA shall

not commence if the monitoring system is

operating out-of-control with respect to any

of the daily and quarterly quality assurance

assessments required by sections 2.1 and 2.2

of this appendix or with respect to the

additional calibration error test requirements

in section 2.1.3 of this appendix.

(b) All RATAs must be done hands-off, as

follows. No adjustment of the monitor’s

calibration is permitted prior to or during the

RATA test period, other than the adjustments

described in section 2.1.3 of this appendix.

The non-routine calibration adjustments

described in section 2.1.3 of this appendix

are permitted only prior to the RATA, not

during the test period. For 2-level and 3-level

flow monitor audits, no linearization of the

monitor is permitted in-between load levels.

(c) For single-load RATAs, if a daily

calibration error test is failed during a RATA

test period, prior to completing the test, the

RATA is invalidated and must be repeated.

Data from the monitor are invalidated

prospectively from the hour of the failed

calibration error test until the hour of

completion of a subsequent successful

RATA. The subsequent RATA shall not be recommenced until the monitor has

successfully passed a calibration error test in

accordance with section 2.1.3 of this

appendix. For multiple-load flow RATAs,

each load level is treated as a separate RATA

(i.e., when a calibration error test is failed

prior to completing the RATA at a particular

load level, only the RATA at that load level

is invalidated; the results of any previouslypassed RATA(s) at the other load level(s) are

unaffected).

(d) If a RATA is failed (that is, if the

relative accuracy exceeds the applicable
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28173

specification in section 3.3 of appendix A to

this part) or if the RATA is aborted prior to

completion due to a problem with the CEMS,

then all emission data from the CEMS are

invalidated prospectively from the hour in

which the RATA is failed or aborted. Data

from the CEMS remain invalid until the hour

of completion of a subsequent RATA that

meets the applicable specification in section

3.3 of appendix A to this part. Note that a

monitoring system shall not be considered

out-of-control when a RATA is aborted for a

reason other than monitoring system

malfunction (see paragraph (g) of this

section).

(e) For a 2-level or 3-level flow RATA, if,

at any load level, a RATA is failed or aborted

due to a problem with the CEMS, the RATA

at that load level must be repeated. Data from

the flow monitor are invalidated from the

hour in which the test is failed or aborted

and remain invalid until the successful

completion of a RATA at the failed load

level. RATA(s) that were previously passed at

the other load level(s) do not have to be

repeated unless the flow monitor must be relinearized following the failed or aborted test.

If the monitor is re-linearized, a subsequent

3-load RATA is required.

(f) For a CO2 pollutant concentration

monitor (or an O2 monitor used to measure

CO2 emissions) which also serves as the

diluent component in a NOX-diluent (or SO2-

diluent) monitoring system, if the CO2 (or O2)

RATA is failed, then both the CO2 (or O2)

monitor and the associated NOX-diluent (or

SO2-diluent) system are considered out-ofcontrol until the hour of completion of

subsequent hands-off RATAs which

demonstrate that both systems have met the

applicable relative accuracy specifications in

sections 3.3.2 and 3.3.3 of appendix A to this

part. The out-of-control period for each

monitoring system begins with the hour of

completion of the failed CO2 (or O2) monitor

RATA.

(g) For each monitoring system, report the

results of all completed and partial RATAs

that affect data validation (i.e., all completed,

passed RATAs; all completed, failed RATA;

and all RATAs aborted due to a problem with

the CEMS) in the quarterly report required

under § 75.64. Note that RATA attempts that

are aborted or invalidated due to problems

with the reference method or due to

operational problems with the affected

unit(s) need not be reported. Such runs do

not affect the validation status of emission

data recorded by the CEMS. In addition,

aborted RATA attempts that are part of the

process of optimizing a monitoring system’s

performance do not have to be reported,

provided that, in the period extending from

the hour in which the test is aborted to the

hour of commencement of the next RATA

attempt: (1) no corrective maintenance or

reprogramming of the monitoring system is

done; and (2) only the calibration

adjustments allowed under section 2.1.3 of

this appendix are made. However, a record

of all RATAs and RATA attempts (whether

reported or not) must be kept on-site as part

of the official test log for each monitoring

system.

(h) Each time that a hands-off RATA of an

SO2 pollutant concentration monitor, a NOXdiluent monitoring system, or a flow monitor

is successfully completed, perform a bias test

in accordance with section 7.6.4 of appendix

A to this part. Apply the appropriate bias

adjustment factor to the reported SO2, NOX,

or flow rate data, in accordance with section

7.6.5 of appendix A to this part.

(i) Failure of the bias test does not result

in the monitoring system being out-ofcontrol.

2.3.3 RATA Grace Period

The owner or operator has a grace period

of 720 consecutive unit operating hours in

which to complete the required RATA for a

particular CEMS, whenever: (a) a required

RATA has not been performed by the end of

the QA operating quarter in which it is due;

(b) five consecutive calendar years have

elapsed without a required 3-load flow RATA

having been conducted; (c) an SO2 RATA has

not been completed by the end of the

calendar quarter in which the annual usage

of fuel(s) with a total sulfur content greater

than the total sulfur content of natural gas

exceeds 480 hours, for a unit which is

conditionally exempted under § 75.21(a)(7)

from the SO2 RATA requirements of this part;

or (d) eight successive calendar quarters have

elapsed, following the quarter in which a

RATA was last performed, without a

subsequent RATA having been done, due to:

(1) infrequent operation of the unit(s); (2)

frequent combustion of fuel(s) with a total

sulfur content no greater than the total sulfur

content of natural gas (i.e., ≤0.05 percent

sulfur by weight) (SO2 monitors, only); or (3)

a combination of factors (1) and (2).

Except for SO2 monitoring system RATAs,

the grace period shall begin with the first

unit operating hour following the calendar

quarter in which the required RATA was

due. For SO2 monitor RATAs, the grace

period shall begin with the first unit

operating hour in which fuel with a total

sulfur content greater than the total sulfur

content of natural gas (i.e., >0.05 percent

sulfur by weight) is burned in the unit(s),

following the quarter in which the required

RATA is due. Data validation during a RATA

grace period shall be done in accordance

with the applicable provisions in section

2.3.2 of this appendix.

If, at the end of the 720 unit operating hour

grace period, the RATA has not been

completed, data from the monitoring system

shall be invalid, beginning with the first unit

operating hour following the expiration of

the grace period. Data from the CEMS remain

invalid until the hour of completion of a

subsequent hands-off RATA. Note that when

a RATA (or RATAs, if more than one attempt

is made) is done during a grace period in

order to satisfy a RATA requirement from a

previous quarter (i.e., for reasons (a), (b), or

(d) in this section), the deadline for the next

RATA shall be determined from the quarter

in which the RATA was due, not from the

quarter in which the grace period is used.

2.3.4 Bias Adjustment Factor

Except as otherwise specified in section

7.6.5 of appendix A to this part, if an SO2

pollutant concentration monitor, flow

monitor, or NOX continuous emission

monitoring system fails the bias test specified

in section 7.6 of appendix A to this part, use

the bias adjustment factor given in Equations

A–11 and A–12 of appendix A to this part

to adjust the monitored data.

2.4 Recertification, Quality Assurance, and

RATA Deadlines

When a significant change is made to a

monitoring system such that recertification of

the monitoring system is required in

accordance with § 75.20(b), a recertification

test (or tests) must be performed to ensure

that the CEMS continues to generate valid

data. In many instances, a required

recertification test is the same type of test as

one of the routine, periodic quality assurance

tests required by this appendix (e.g., a

linearity test or a RATA). When this occurs,

the recertification test may be used to satisfy

the quality assurance test requirement of this

appendix. For example, if, for a particular

change made to a CEMS, one of the required

recertification tests is a linearity check and

the linearity test is successful, then, unless

another recertification event occurs in that

same QA operating quarter, it would not be

necessary to perform a subsequent linearity

test of the CEMS in that quarter. For this

reason, EPA recommends that owners or

operators coordinate component

replacements, system upgrades, and other

events that may require recertification, to the

extent practicable, with the periodic quality

assurance testing required by this appendix.

When a quality assurance test is done for the

dual purpose of recertification and routine

quality assurance, the applicable data

validation procedures in § 75.20(b)(3) shall

be followed in lieu of the procedures in this

appendix.

Except as provided in section 2.3.3 of this

appendix, whenever a successful RATA of a

gas monitor or a successful 2-load or 3-load

RATA of a flow monitor is performed

(irrespective of whether the RATA is done to

satisfy a recertification requirement or to

meet the quality assurance requirements of

this appendix, or both), the deadline for the

next RATA shall be established based upon

the date and time of completion of the RATA

and the relative accuracy percentage

obtained. For 2-load and 3-load flow RATAs,

use the highest percentage relative accuracy

at any of the loads to determine the deadline

for the next RATA. The results of a singleload flow RATA may be used to establish a

RATA deadline when: (1) the single-load

flow RATA is specifically required under

section 2.3.1.3(b) of this appendix (for flow

monitors installed on peaking units and

bypass stacks); or (2) the single-load RATA

is allowed for a unit that has operated at the

most frequently used load level for ≥85.0

percent of the time, under section 2.3.1.3(c)

of this appendix. No other single-load flow

RATA may be used to establish an annual

RATA frequency; however, a 2-load flow

RATA may be performed in place of any

required single-load RATA, in order to

establish an annual RATA frequency.

2.5 Other Audits

* * * * *

61. Figures 1 and 2 at the end of

appendix B are revised to read as

follows:
28174 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

FIGURE 1.—QUALITY ASSURANCE TEST REQUIREMENTS

Test

QA test frequency requirements

Daily* Quarterly* Semiannual*

Calibration Error (2 pt.) ................................................................................................................ ✔

Interference (flow) ........................................................................................................................ ✔

Flow-to-Load Ratio ....................................................................................................................... ........................ ✔

Leak Check (DP flow monitors) ................................................................................................... ........................ ✔

Linearity (3 pt.) ............................................................................................................................. ........................ ✔

RATA (SO2, NOX, CO2, percent H2O) 1 ....................................................................................... ........................ ✔

RATA (flow ) 1, 2 ............................................................................................................................ ........................ ........................ ✔

*For monitors on bypass stack/duct, ‘‘daily’’ means bypass operating days, only. ‘‘Quarterly’’ means once every QA operating quarter. ‘‘Semiannual’’ means once every two QA operating quarters. 1 Conduct RATA annually (i.e., once every four QA operating quarters), if monitor meets accuracy requirements to qualify for less frequent testing.2For flow monitors installed on peaking units and bypass stacks, conduct all RATAs at a single, normal load. For other flow monitors, conduct

RATAs at the two most frequently used loads. Alternating single-load and 2-load RATAs may be done if a monitor is on a semiannual frequency.

A single-load RATA may be done in lieu of a 2-load RATA if, in the past four QA operating quarters, the unit has operated at one load level for ≥

85.0 percent of the time. A 3-load RATA is required at least once in every period of five consecutive calendar years and whenever a flow monitor

is re-linearized.

FIGURE 2.—RELATIVE ACCURACY TEST FREQUENCY INCENTIVE SYSTEM

RATA Semiannual1

(percent) Annual1

SO2 ..................................... 7.5% < RA ≤ 10.0% or ± 15.0 ppm 2 ............................... RA ≤ 7.5.% or ± 12.0 ppm 2

SO2/diluent ......................... 7.5% < RA ≤ 10.0% or ± 0.030 lb/mmBtu 2 ..................... RA ≤ 7.5% or ± 0.025 lb/mmBtu 2

NOX/diluent ......................... 7.5% < RA ≤ 10.0% or ± 0.020 lb/mmBtu 2 ..................... RA ≤ 7.5% or ±0.015 lb/mmBtu 2

Flow (Phase I) .................... 10.0% < RA ≤ 15.0% or ± 1.5 fps 2 ................................. RA ≤ 10.0%

Flow (Phase II) ................... 7.5% < RA ≤ 10.0% or ± 1.5 fps 2 ................................... RA ≤ 7.5%

CO2/O2 ................................ 7.5% < RA ≤ 10.0% or ± 1.0% CO2/O2

2 ......................... RA ≤ 7.5% or ± 0.7% CO2/O22

Moisture .............................. 7.5% < RA ≤ 10.0% or ± 1.0% H2O2 ............................... RA ≤ 7.5% or ± 0.7% H2O2

1The deadline for the next RATA is the end of the second (if semiannual) or fourth (if annual) successive QA operating quarter following the

quarter in which the CEMS was last tested. Exclude calendar quarters in which the unit operates for < 168 hours (or, for common stacks and bypass stacks, exclude quarters in which gases discharge through the stack for < 168 hours) in determining the RATA deadline. For SO2 monitors,

QA operating quarters in which only fuel with a total sulfur content no greater than the total sulfur content of natural gas (i.e., ≤ 0.05 percent sulfur by weight) is combusted may also be excluded. However, the exclusion of calendar quarters is limited as follows: the deadline for the next

RATA shall be no more than 8 calendar quarters after the quarter in which a RATA was last performed. 2The difference between monitor and reference method mean values applies to moisture monitors, CO2, and O2 monitors, low emitters, or low

flow, only.

62. Section 2 of appendix C to part 75

is amended by revising sections 2.1 and

2.2.1 and by revising Table C–1 to read

as follows:

Appendix C to Part 75—Missing Data

Estimation Procedures

* * * * *

2. Load-Based Procedure for Missing Flow

Rate and NOX Emission Rate Data

2.1 Applicability

This procedure is applicable for data from

all affected units for use in accordance with

the provisions of this part to provide

substitute data for volumetric flow rate (scfh)

and NOX emission rate (in lb/mmBtu).

2.2 * * *

2.2.1 For a single unit, establish 10

operating load ranges defined in terms of

percent of the maximum hourly average gross

load of the unit, in gross megawatts (MWge),

as shown in Table C–1. (Do not use

integrated hourly gross load in MW-hr.) For

units sharing a common stack monitored

with a single flow monitor, the load ranges

for flow (but not for NOX) may be broken

down into 20 operating load ranges in

increments of 5.0 percent of the combined

maximum hourly average gross load of all

units utilizing the common stack. If this

option is selected, the twentieth (uppermost)

operating load range shall include all values

greater than 95.0 percent of the maximum

hourly average gross load. For a cogenerating

unit or other unit at which some portion of

the heat input is not used to produce

electricity or for a unit for which hourly

average gross load in MWge is not recorded

separately, use the hourly gross steam load of

the unit, in pounds of steam per hour at the

measured temperature (°F) and pressure

(psia) instead of MWge. Indicate a change in

the number of load ranges or the units of

loads to be used in the precertification

section of the monitoring plan.

TABLE C–1.—DEFINITION OF OPERATING LOAD RANGES FOR LOAD-BASED

SUBSTITUTION DATA PROCEDURES

Operating load range

Hourly

gross

load*

1 ................................................ 0–10

2 ................................................ >10–20

3 ................................................ >20–30

4 ................................................ >30–40

5 ................................................ >40–50

6 ................................................ >50–60

TABLE C–1.—DEFINITION OF OPERATING LOAD RANGES FOR LOAD-BASED

SUBSTITUTION DATA PROCEDURES—

Continued

Operating load range

Hourly

gross

load*

7 ................................................ >60–70

8 ................................................ >70–80

9 ................................................ >80–90

10 ................................................ >90

*Percent of maximum hourly gross load or

maximum hourly gross steam load (percent).

* * * * *

63. Section 1 of appendix D to part 75

is amended by revising section 1.1 to

read as follows:

Appendix D to Part 75—Optional SO2

Emissions Data Protocol for Gas-Fired

and Oil-Fired Units

1. Applicability

1.1 This protocol may be used in lieu of

continuous SO2 pollutant concentration and

flow monitors for the purpose of determining

hourly SO2 emissions and heat input from:
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28175

(1) gas-fired units, as defined in § 72.2 of this

chapter; or (2) oil-fired units, as defined in

§ 72.2 of this chapter. This optional SO2

emissions data protocol contains procedures

for conducting oil sampling and analysis in

section 2.2 of this appendix; the procedures

for oil sampling may be used for any gas-fired

unit or oil-fired unit. In addition, this

optional SO2 emissions data protocol

contains three procedures for determining

SO2 emissions due to the combustion of

gaseous fuels having a total sulfur content no

greater than 20 grains per 100 standard cubic

foot.

* * * * *

64. Section 2 of appendix D to part 75

is amended by:

a. Revising section 2.1 Flowmeter

Measurements;

b. Revising sections 2.2, 2.2.1, 2.2.3,

2.2.4, 2.2.6, and 2.2.8; and removing and

reserving section 2.2.2;

c. Revising sections 2.3, 2.3.1, 2.3.1.3,

2.3.2; redesignating section 2.3.1.4 as

2.3.1.4.1 and revising it; and adding

sections 2.3.1.4.1, 2.3.1.4.2, 2.3.1.4.3,

and 2.3.3; and

d. Revising section 2.4.1; removing

section 2.4.2; redesignating sections

2.4.3, 2.4.3.1, 2.4.3.2, and 2.4.3.3 as

2.4.2, 2.4.2.1, 2.4.2.2, and 2.4.2.3,

respectively; revising newly designated

sections 2.4.2, 2.4.2.1, and 2.4.2.3; and

redesignating section 2.4.4 as 2.4.3.

2. Procedure

2.1 Flowmeter Measurements

For each hour when the unit is combusting

fuel, measure and record the flow rate of fuel

combusted by the unit, except as provided

for gas in section 2.1.4.1 of this appendix.

Measure the flow rate of fuel with an in-line

fuel flowmeter, and automatically record the

data with a data acquisition and handling

system, except as provided in section 2.1.4 of

this appendix.

2.1.1 Measure the flow rate of each fuel

entering and being combusted by the unit. If

a portion of the flow greater than 5.0 percent

of the annual average flow rate from the main

pipe is diverted from the unit without being

burned and that diversion occurs

downstream of the fuel flowmeter, an

additional in-line fuel flowmeter is required

to account for the unburned fuel. In this case,

record the flow rate of each fuel combusted

by the unit as the difference between the flow

measured in the pipe leading to the unit and

the flow in the pipe diverting fuel away from

the unit. The hourly average proportion of

flow rate from the pipe diverting fuel away

from the unit to total fuel usage by the unit

may be determined by using fuel usage data

from fuel flowmeters in a previous year or by

using a method approved by the

Administrator under the provisions of

§ 75.66(i).

2.1.2 Install and use fuel flowmeters

meeting the requirements of this appendix in

a pipe going to each unit, or install and use

a fuel flowmeter in a common pipe header

(i.e., a pipe carrying fuel for multiple units).

However, the use of a fuel flowmeter in a

common pipe header and the provisions of

sections 2.1.2.1 and 2.1.2.2 of this appendix

are not applicable to any unit that is using

the provisions of subpart H of this part to

monitor, record, and report NOX mass

emissions under a state or federal NOX mass

emission reduction program. For all other

units, if the fuel flowmeter is installed in a

common pipe header, do one of the

following:

2.1.2.1 Measure the fuel flow rate in the

common pipe, and combine SO2 mass

emissions for the affected units for

recordkeeping and compliance purposes; or

2.1.2.2 Provide information satisfactory to

the Administrator on methods for

apportioning SO2 mass emissions and heat

input to each of the affected units

demonstrating that the method ensures

complete and accurate accounting of the

actual emissions from each of the affected

units included in the apportionment and all

emissions regulated under this part. The

information shall be provided to the

Administrator through a petition submitted

by the designated representative under

§ 75.66. Satisfactory information includes

apportionment, using fuel flow

measurements, the ratio of hourly integrated

gross load (in MWe-hr) in each unit to the

total load for all units receiving fuel from the

common pipe header, or the ratio of hourly

steam flow (in 1000 lb) at each unit to the

total steam flow for all units receiving fuel

from the common pipe header, and

documentation that shows the provisions of

sections 2.1.5 and 2.1.6 of this appendix have

been met for the fuel flowmeter used in the

apportionment.

2.1.3 For a gas-fired unit or an oil-fired

unit that continuously or frequently

combusts a supplemental fuel for flame

stabilization or safety purposes, measure the

flow rate of the supplemental fuel with a fuel

flowmeter meeting the requirements of this

appendix.

2.1.4 Situations in Which Certified

Flowmeter Is Not Required

2.1.4.1 Start-up or Ignition Fuel

For an oil-fired unit that uses gas solely for

start-up or burner ignition or a gas-fired unit

that uses oil solely for start-up or burner

ignition, a flowmeter for the start-up fuel is

not required. Estimate the volume of oil

combusted for each start-up or ignition either

by using a fuel flowmeter or by using the

dimensions of the storage container and

measuring the depth of the fuel in the storage

container before and after each start-up or

ignition. A fuel flowmeter used solely for

start-up or ignition fuel is not subject to the

calibration requirements of sections 2.1.5 and

2.1.6 of this appendix. Gas combusted solely

for start-up or burner ignition does not need

to be measured separately.

2.1.4.2 Gas Flowmeter Used for Commercial

Billing

A gas flowmeter used for commercial

billing of pipeline natural gas may be used

to measure, record, and report hourly fuel

flow rate. A gas flowmeter used for

commercial billing of pipeline natural gas is

not required to meet the certification

requirements of section 2.1.5 of this

appendix or the quality assurance

requirements of section 2.1.6 of this

appendix under the following circumstances:

(1) the gas flowmeter is used for commercial

billing under a contract, provided that the

company providing the gas under the

contract and each unit combusting the gas do

not have any common owners and are not

owned by subsidiaries or affiliates of the

same company; (2) the designated

representative reports hourly records of gas

flow rate, heat input rate, and emissions due

to combustion of pipeline natural gas; (3) the

designated representative also reports hourly

records of heat input rate for each unit, if the

gas flowmeter is on a common pipe header,

consistent with section 2.1.2 of this

appendix; (4) the designated representative

reports hourly records directly from the gas

flowmeter used for commercial billing if

these records are the values used, without

adjustment, for commercial billing, or reports

hourly records using the missing data

procedures of section 2.4 of this appendix if

these records are not the values used,

without adjustment, for commercial billing;

and (5) the designated representative

identifies the gas flowmeter in the unit’s

monitoring plan.

2.1.5 For the purposes of initial

certification, each fuel flowmeter used to

meet the requirements of this protocol shall

meet a flowmeter accuracy of ± 2.0 percent

of the upper range value (i.e, maximum

calibrated fuel flow rate) across the range of

fuel flow rate to be measured at the unit.

Flowmeter accuracy may be determined

under section 2.1.5.1 of this appendix for

initial certification either by design or by

measurement under laboratory conditions by

the manufacturer, by an independent

laboratory, or by the owner or operator, or

may be determined under section 2.1.5.2 of

this appendix by measurement against a

NIST traceable reference method.

2.1.5.1 Use the procedures in the

following standards to verify flowmeter

accuracy or design, as appropriate to the type

of flowmeter: ASME MFC–3M–1989 with

September 1990 Errata (‘‘Measurement of

Fluid Flow in Pipes Using Orifice, Nozzle,

and Venturi’’); ASME MFC–4M–1986

(Reaffirmed 1990), ‘‘Measurement of Gas

Flow by Turbine Meters’’; American Gas

Association Report No. 3, ‘‘Orifice Metering

of Natural Gas and Other Related

Hydrocarbon Fluids Part 1: General

Equations and Uncertainty Guidelines’’

(October 1990 Edition), Part 2: ‘‘Specification

and Installation Requirements’’ (February

1991 Edition), and Part 3: ‘‘Natural Gas

Applications’’ (August 1992 edition)

(excluding the modified flow-calculation

method in Part 3); Section 8, Calibration from

American Gas Association Transmission

Measurement Committee Report No. 7:

Measurement of Gas by Turbine Meters (1985

Edition); ASME MFC–5M–1985

(‘‘Measurement of Liquid Flow in Closed

Conduits Using Transit-Time Ultrasonic

Flowmeters’’); ASME MFC–6M–1987 with

June 1987 Errata (‘‘Measurement of Fluid

Flow in Pipes Using Vortex Flow Meters’’);

ASME MFC–7M–1987 (Reaffirmed 1992),

‘‘Measurement of Gas Flow by Means of

Critical Flow Venturi Nozzles’’; ISO 8316:

1987(E) ‘‘Measurement of Liquid Flow in

Closed Conduits—Method by Collection of
28176 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

the Liquid in a Volumetric Tank’’; American

Petroleum Institute (API) Section 2,

‘‘Conventional Pipe Provers,’’ from Chapter 4

of the Manual of Petroleum Measurement

Standards, October 1988 (Reaffirmed 1993);

or MFC–9M–1988 with December 1989 Errata

(‘‘Measurement of Liquid Flow in Closed

Conduits by Weighing Method’’) for all other

flowmeter types (incorporated by reference

under § 75.6). The Administrator may also

approve other procedures that use equipment

traceable to National Institute of Standards

and Technology standards. Document such

procedures, the equipment used, and the

accuracy of the procedures in the monitoring

plan for the unit, and submit a petition

signed by the designated representative

under § 75.66(c). If the flowmeter accuracy

exceeds ±2.0 percent of the upper range

value, the flowmeter does not qualify for use

under this part.

2.1.5.2 Alternatively, determine the

flowmeter accuracy of a fuel flowmeter used

for the purposes of this part by comparing it

to the measured flow from a reference

flowmeter which has been either designed

according to the specifications of American

Gas Association Report No. 3 or ASME MFC–

3M–1989, as cited in section 2.1.5.1 of this

appendix, or tested for accuracy during the

previous 365 days, using a standard listed in

section 2.1.5.1 of this appendix or other

procedure approved by the Administrator

under § 75.66 (all standards incorporated by

reference under § 75.6). Any secondary

elements, such as pressure and temperature

transmitters, must be calibrated immediately

prior to the comparison. Perform the

comparison over a period of no more than

seven consecutive unit operating days.

Compare the average of three fuel flow rate

readings over 20 minutes or longer for each

meter at each of three different flow rate

levels. The three flow rate levels shall

correspond to: (1) normal full unit operating

load, (2) normal minimum unit operating

load, and (3) a load point approximately

equally spaced between the full and

minimum unit operating loads. Calculate the

flowmeter accuracy at each of the three flow

levels using the following equation:

ACC R A

URV = − ×100

(Eq. D–1)

Where:

ACC = Flowmeter accuracy as a percentage

of the upper range value, including all

error from all parts of both flowmeters.

R = Average of the three flow measurements

of the reference flowmeter.

A = Average of the three measurements of the

flowmeter being tested.

URV = Upper range value of fuel flowmeter

being tested (i.e. maximum measurable

flow).

Notwithstanding the requirement for

calibration of the reference flowmeter within

365 days prior to an accuracy test, when an

in-place reference meter or prover is used,

the reference meter calibration requirement

may be waived if, during the previous inplace accuracy test with that reference meter,

the reference flowmeter and the flowmeter

being tested agreed to within ± 1.0 percent

of each other at all levels tested. This

exception to calibration and flowmeter

accuracy testing requirements for the

reference flowmeter shall apply for periods of

no longer than five consecutive years (i.e., 20

consecutive calendar quarters).

2.1.5.3 If the flowmeter accuracy exceeds

the specification in section 2.1.5 of this

appendix, the flowmeter does not qualify for

use for this appendix. Either recalibrate the

flowmeter until the flowmeter accuracy is

within the performance specification, or

replace the flowmeter with another one that

is demonstrated to meet the performance

specification. Substitute for fuel flow rate

using the missing data procedures in section

2.4.2 of this appendix until quality assured

fuel flow data become available.

2.1.5.4 For purposes of initial

certification, when a flowmeter is tested

against a reference fuel flow rate (i.e., fuel

flow rate from another fuel flowmeter under

section 2.1.5.2 of this appendix or flow rate

from a procedure according to a standard

incorporated by reference under section

2.1.5.1 of this appendix), report the results of

flowmeter accuracy tests using Table D–1

below.

TABLE D–1.—TABLE OF FLOWMETER ACCURACY RESULTS

Measurement level

(percent of URV)

Run

No.

Time of

run

(HHMM)

Candidate

flowmeter

reading

Reference

flow

reading

Percent

accuracy

(percent of

URV)

Test number:lTest completion date 1:lTest completion time 1: l

Reinstallation date 2 (for testing under 2.1.5.1 only):l Reinstallation time 2:l

Unit or pipe ID: Component/System ID :

Flowmeter serial number: Upper range value:

Units of measure for flowmeter and reference flow readings:

Low (Minimum) level ................................................................................... 1

l percent 3 of URV .................................................................................... 2

3

Average

Mid-level ...................................................................................................... 1

l percent 3 of URV .................................................................................... 2

3

Average

High (Maximum) level ................................................................................. 1

l percent 3 of URV .................................................................................... 2

3

Average

1 Report the date, hour, and minute that all test runs were completed.

2For laboratory tests not performed inline, report the date, hour, and minute that the fuel flowmeter was reinstalled following the test.

3 It is required to test at least at three different levels, from minimum to maximum.

2.1.6 Quality Assurance

Test the accuracy of each fuel flowmeter

prior to use under this part and at least once

every four fuel flowmeter QA operating

quarters thereafter. A ‘‘fuel flowmeter QA

operating quarter’’ is a unit operating quarter

in which the unit combusts the fuel

measured by the fuel flowmeter for more

than 168 hours. Notwithstanding these

requirements, no more than 20 successive

calendar quarters shall elapse after the

quarter in which a fuel flowmeter was last

tested for accuracy without a subsequent

flowmeter accuracy test having been

conducted. Test the flowmeter accuracy more

frequently if required by manufacturer

specifications.

Except for orifice-, nozzle-, and venturitype flowmeters, perform the required

flowmeter accuracy testing using the

procedures in either section 2.1.5.1 or section

2.1.5.2 of this appendix. Each fuel flowmeter
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28177

must meet the accuracy specification in

section 2.1.5 of this appendix.

For orifice-, nozzle-, and venturi-type

flowmeters (that are designed according to

the specifications of American Gas

Association Report No. 3 or ASME MFC–3M–

1989, as cited in section 2.1.5.1 of this

appendix (both standards incorporated by

reference under § 75.6) or that have satisfied

the initial certification test requirement by

meeting an accuracy of 2.0 percent of the

upper range value or less by comparison with

another fuel flowmeter, following the

procedures of section 2.1.5.2 of this

appendix), perform a transmitter accuracy

test once every four flowmeter QA operating

quarters and a primary element visual

inspection once every 12 calendar quarters,

according to the procedures in sections

2.1.6.1 through 2.1.6.6 of this appendix for

periodic quality assurance.

Notwithstanding the requirements of this

section, if the procedures of section 2.1.7 of

this appendix are performed during each fuel

flowmeter QA operating quarter, subsequent

to a required flowmeter accuracy test or

transmitter accuracy test and primary

element inspection, where applicable, those

procedures may be used to meet the

requirement for periodic quality assurance

testing for a period of up to 20 calendar

quarters from the previous accuracy test or

transmitter accuracy test and primary

element inspection, where applicable.

2.1.6.1 Transmitter or Transducer Accuracy

Test for Orifice-, Nozzle-, and Venturi-Type

Flowmeters

Calibrate the differential pressure

transmitter or transducer, static pressure

transmitter or transducer, and temperature

transmitter or transducer, as applicable,

using equipment that has a current certificate

of traceability to NIST standards. Check the

calibration of each transmitter or transducer

by comparing its readings to that of the NIST

traceable equipment at least once at each of

the following levels: the zero-level and at

least two other levels across the range of

readings on the transmitter or transducer

corresponding to normal unit operation.

Determine either the accuracy of each

individual transmitter or transducer of the

orifice-, nozzle-, or venturi-type flowmeter

according to section 2.1.6.2 of this appendix,

or determine the accuracy of the entire

orifice-, nozzle-, or venturi-type flowmeter

according to section 2.1.6.3 of this appendix.

2.1.6.2 Transmitter or Transducer Accuracy

Calculation

Calculate the flowmeter accuracy at each

level across the range of readings on the

transmitter or transducer corresponding to

normal unit operation by using the following

equation:

ACC R T

FS = − ×100

(Eq. D–1a)

Where:

ACC=Accuracy of the transmitter or

transducer as a percentage of full-scale.

R=Reading of the NIST-traceable reference

value (in milliamperes, inches of water,

psi, or degrees).

T=Reading of the transmitter or transducer

being tested (in milliamperes, inches of

water, psi, or degrees, consistent with

the units of measure of the NISTtraceable reference value).

FS = Full-scale range of the transmitter or

transducer being tested.

2.1.6.3 Total Flowmeter Accuracy

Calculation

Use the transmitter or transducer accuracy

calculated from Equation D–1a to determine

if each individual transmitter or transducer

meets an accuracy of ± 1.0 percent of its fullscale range at each level. If one or more of

the transmitters or transducers does not meet

this accuracy at each level, then either: (1)

follow the data validation procedures in

section 2.1.6.5 of this appendix, or (2)

determine the total flowmeter accuracy at

each level, i.e. error in the volumetric flow

rate, including all transmitters or transducers

and the primary element, using the following

equation:

dq

q

K dP

P

d P

P

dT

T

v

v

f

f

f

f

= +

−



 



 + 



 



 +





 





















2

2 2

1 2

2 2 2

∆

∆

(Eq. D–1b)

Where:

dqv/qv=Error in the volumetric flow rate due

to transmitter drift at a given level.

K=Original error resulting from installation

of orifice (including all other variables).

For an orifice-, nozzle-, or venturi-type

flowmeter that was originally installed to

the specifications of AGA Report No. 3

or ASME MFC–3M, as cited in section

2.1.5.1 of this appendix, an assumed

value of 1.0 percent of the upper range

value may be used for ‘‘K’’ if original

error data or dimensional information

from installation of the meter or other

information on total installation error are

not available.

dPf=Average difference between static

pressure transmitter reading(s) and

reference static pressure reading(s) at a

given level.

Pf=Average reference static pressure reading

at a given level.

d∆P=Average difference between differential

pressure transmitter reading(s) and

reference differential pressure reading(s)

at a given level.

∆P = Average reference differential pressure

reading at a given level.

dTf=Average difference between temperature

transmitter reading(s) and reference

temperature reading(s) at a given level.

Tf=Average reference temperature reading at

a given level.

Note: For gases, overall flow rate is directly

related to pressure and is inversely related to

temperature. Therefore, when performing

this test on a gas fuel flowmeter, it is

recommended that readings be entered into

the equation at the following levels:

TABLE D–2—RECOMMENDED LEVELS FOR USING TRANSMITTER TEST RESULTS TO CALCULATE OVERALL GAS

FLOWMETER ACCURACY

Level of total flow calculation Level of static pressure reading Level of differential pressure reading Level of temperature reading

Low ................................................... Low .................................................. Low .................................................. High.

Mid .................................................... Mid ................................................... Mid ................................................... Mid.

High .................................................. High ................................................. High ................................................. Low.

If the overall flowmeter accuracy at each

flow rate level is less than or equal to ± 2.0

percent of the upper range value of the fuel

flowmeter, then the fuel flow rate data

remain valid, and the data invalidation

procedures of section 2.1.6.5 of this appendix

are not required. If the overall flowmeter

accuracy at any flow rate level is greater than

± 2.0 percent of the upper range value of the
28178 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

fuel flowmeter, then data from the fuel

flowmeter are considered invalid, beginning

with the date and hour of a failed accuracy

test and continuing until the date and hour

of a successful accuracy test for all

transmitters or transducers; during the period

when data from the fuel flowmeter are

considered invalid, provide data from

another fuel flowmeter that meets the

requirements of § 75.20(d) and section 2.1.5

of this appendix, or substitute for fuel flow

rate using the missing data procedures in

section 2.4.2 of this appendix.

2.1.6.4 Recordkeeping and Reporting of

Transmitter or Transducer Accuracy Results

Record the accuracy of the orifice, nozzle,

or venturi meter or its individual transmitters

or transducers and keep this information in

a file at the site or other location suitable for

inspection. When testing individual orifice,

nozzle, or venturi meter transmitters or

transducers for accuracy, include the

information displayed in Table D–3 below.

At a minimum, record results for each

transmitter or transducer at the zero-level

and at least two other levels across the range

of the transmitter or transducer readings that

correspond to normal unit operation.

TABLE D–3.—TABLE OF FLOWMETER TRANSMITTER OR TRANSDUCER ACCURACY RESULTS

Measurement level

(percent of full-scale)

Run number

(if multiple

runs) 2

Run time

(HHMM)

Transmitter/

Transducer

input

(pre-calibration)

Expected

transmitter/

transducer

output

(reference)

Actual

transmitter/

transducer

output 3

Percent

accuracy

(percent of

full-scale)

Test number: l Test completion date: l Unit or pipe ID: l

Flowmeter serial number: Component/System ID:

Full-scale value: Units of measure 3:

Transducer/Transmitter Type (check one): l Differential Pressure l Static Pressure l Temperature

Low (Minimum) level.

l percent1 of full-scale.

Mid-level.

l percent1 of full-scale.

(If tested at more than 3 levels).

2nd Mid-level.

l percent1 of full-scale.

(If tested at more than 3 levels).

High (Maximum) level.

l percent1 of full-scale.

1At a minimum, it is required to test at zero-level and at least two other levels across the range of the transmitter or transducer readings corresponding to normal unit operation. 2 It is required to test at least once at each level.

3 Use the same units of measure for all readings (e.g., use degrees (°), inches of water (in H2O), pounds per square inch (psi), or milliamperes

(ma) for both transmitter or transducer readings and reference readings).

In addition, when testing the whole orifice,

nozzle, or venturi meter for accuracy, record

the information displayed in Table D–1

above. At a minimum, record the overall

flowmeter accuracy results for the entire fuel

flowmeter at the zero-level and at least two

other levels across the range of normal unit

operation.

Report the final result of the accuracy test

(pass or fail) for the combination of all

transmitters or transducers of the orifice,

nozzle or venturi meter in the emissions

report of the quarter in which the accuracy

is determined, using the electronic format

specified by the Administrator under § 75.64.

2.1.6.5 Failure of Transducer or Transmitter

Except as provided in section 2.1.6.3 of

this appendix, if the accuracy during a

calibration or test of an individual

transmitter or transducer is greater than ±1.0

percent of the full-scale range for that

transmitter or transducer at any level or if the

individual transmitter or transducer fails to

operate properly, recalibrate the transmitter

or transducer or replace the transmitter or

transducer with another one until the

transmitter or transducer accuracy is less

than or equal to ±1.0 percent of the full-scale

range for that transmitter or transducer,

consistent with sections 2.1.6.1 and 2.1.6.2 of

this appendix. Data from the fuel flowmeter

are considered invalid, beginning with the

date and hour of a failed accuracy test (or a

failure to operate properly) for any

transmitter or transducer and continuing

until the date and hour of an accuracy test

for all transmitters or transducers in which

all transmitters or transducers meet an

accuracy of ±1.0 percent of the full-scale

range for that transducer or transmitter.

During this period, provide data from another

fuel flowmeter that meets the requirements of

§ 75.20(d) and section 2.1.5 of this appendix,

or substitute for fuel flow rate using the

missing data procedures in section 2.4.2 of

this appendix. Record and report test data

and results, consistent with section 2.1.6.4 of

this appendix and § 75.56 or § 75.59, as

applicable.

2.1.6.6 Primary Element Inspection

Conduct a visual inspection of the orifice,

nozzle, or venturi at least once every twelve

calendar quarters. Notwithstanding this

requirement, the procedures of section 2.1.7

of this appendix may be used to reduce the

inspection frequency of the orifice, nozzle, or

venturi to at least once every twenty calendar

quarters. The inspection may be performed

using a boroscope. If the visual inspection

indicates that the orifice, nozzle, or venturi

has become damaged or corroded, then: (1)

replace the primary element with another

primary element meeting the requirements of

American Gas Association Report No. 3 or

ASME MFC–3M–1989, as cited in section

2.1.5.1 of this appendix (both standards

incorporated by reference under § 75.6); (2)

replace the primary element with another

primary element, and demonstrate that the

overall flowmeter accuracy meets the

accuracy specification in section 2.1.5 of this

appendix under the procedures of section

2.1.5.2 of this appendix; or (3) restore the

damaged or corroded primary element to ‘‘as

new’’ condition; determine the overall

accuracy of the flowmeter, using either the

specifications of American Gas Association

Report No. 3 or ASME MFC–3M–1989, as

cited in section 2.1.5.1 of this appendix (both

standards incorporated by reference under

§ 75.6); and retest the transmitters or

transducers prior to providing quality

assured data from the flowmeter. If the

primary element size is changed, calibrate

the transmitter or transducers consistent with

the new primary element size. Data from the

fuel flowmeter are considered invalid,

beginning with the date and hour of a failed

visual inspection and continuing until the

date and hour when: (1) the damaged or

corroded primary element is replaced with

another primary element meeting the

requirements of American Gas Association

Report No. 3 or ASME MFC–3M–1989, as

cited in section 2.1.5.1 of this appendix (both

standards incorporated by reference under

§ 75.6); (2) the damaged or corroded primary

element is replaced, and the overall accuracy

of the flowmeter is demonstrated to meet the

accuracy specification in section 2.1.5 of this
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28179

appendix under the procedures of section

2.1.5.2 of this appendix; or (3) the restored

primary element is installed to meet the

requirements of American Gas Association

Report No. 3 or ASME MFC–3M–1989, as

cited in section 2.1.5.1 of this appendix (both

standards incorporated by reference under

§ 75.6) and its transmitters or transducers are

retested to meet the accuracy specification in

section 2.1.6.4 of this appendix. During this

period, provide data from another fuel

flowmeter that meets the requirements of

§ 75.20(d) and section 2.1.5 of this appendix,

or substitute for fuel flow rate using the

missing data procedures in section 2.4.2 of

this appendix.

2.1.7 Fuel Flow-to-Load Quality Assurance

Testing for Certified Fuel Flowmeters

The procedures of this section may be used

as an optional supplement to the quality

assurance procedures in section 2.1.5.1,

2.1.5.2, 2.1.6.1, or 2.1.6.6 of this appendix

when conducting periodic quality assurance

testing of a certified fuel flowmeter. Note,

however, that these procedures may not be

used unless the 168 hour baseline data

requirement of 2.1.7.2 has been met. If,

following a flowmeter accuracy test or

flowmeter transmitter test and primary

element inspection, where applicable, the

procedures of this section are performed

during each subsequent flowmeter QA

operating quarter, as defined in section 2.1.6

of this appendix (excluding the quarter(s) in

which the baseline data are collected), then

these procedures may be used to meet the

requirement for periodic quality assurance

for a period of up to 20 calendar quarters

from the previous periodic quality assurance

procedure(s) performed according to sections

2.1.5.1, 2.1.5.2, or 2.1.6.1 through 2.1.6.6 of

this appendix. The procedures of this section

are not required for any quarter in which a

flowmeter accuracy test or a transmitter

accuracy test and a primary element

inspection, where applicable, are conducted.

Notwithstanding the requirements of

§ 75.54(a) or § 75.57(a), as applicable, when

using the procedures of this section, keep

records of the test data and results from the

previous flowmeter accuracy test under

section 2.1.5.1 or 2.1.5.2 of this appendix,

records of the test data and results from the

previous transmitter or transducer accuracy

test under section 2.1.6.1 of this appendix for

orifice-, nozzle-, and venturi-type fuel

flowmeters, and records of the previous

visual inspection of the primary element

required under section 2.1.6.6 of this

appendix for orifice-, nozzle-, and venturitype fuel flowmeters until the next flowmeter

accuracy test, transmitter accuracy test, or

visual inspection is performed, even if the

previous flowmeter accuracy test, transmitter

accuracy test, or visual inspection was

performed more than three years previously.

2.1.7.1 Baseline Flow Rate-to-Load Ratio or

Heat Input-to-Load Ratio

Determine Rbase, the baseline value of the

ratio of fuel flow rate to unit load, following

each successful periodic quality assurance

procedure performed according to section

2.1.5.1, 2.1.5.2, or 2.1.6.1 and 2.1.6.6 of this

appendix. Establish a baseline period of data

consisting, at a minimum, of 168 hours of

quality assured fuel flowmeter data taken

immediately after the most recent quality

assurance procedure(s), during which only

the fuel measured by the fuel flowmeter is

combusted (i.e. only gas, only residual oil, or

only diesel fuel is combusted by the unit).

During the baseline data collection period,

the owner or operator may exclude the

following data as non-representative: (1) any

hour in which the unit is ‘‘ramping’’ up or

down, i.e., the load during the hour differs

by more than 15.0 percent from the load in

the previous or subsequent hour; and (2) any

hour in which the unit load is in the lower

10.0 percent of the range of operation, as

defined in section 6.5.2.1 of appendix A to

this part, unless operation in this lower

portion of the range is considered normal for

the unit. The baseline data must be obtained

no later than the end of the second calendar

quarter following the calendar quarter of the

most recent quality assurance procedure for

that fuel flowmeter. For orifice-, nozzle-, and

venturi-type fuel flowmeters, if the fuel flowto-load ratio is to be used as a supplement

both to the transmitter accuracy test under

section 2.1.6.1 of this appendix and to

primary element inspections under section

2.1.6.6 of this appendix, then the baseline

data must be obtained after both procedures

are completed and no later than the end of

the second calendar quarter following the

calendar quarter of both the most recent

transmitter or transducer test and the most

recent primary element inspection for that

fuel flowmeter. From these 168 (or more)

hours of baseline data, calculate the baseline

fuel flow rate-to-load ratio as follows:

R Q

L base

base

avg

=

(Eq. D–1c)

Where:

Rbase=Value of the fuel flow rate-to-load ratio

during the baseline period; 100 scfh/

MWe or 100 scfh/klb per hour steam

load for gas-firing; (lb/hr)/MWe or (lb/

hr)/klb per hour steam load for oil-firing.

Qbase=Average fuel flow rate measured by the

fuel flowmeter during the baseline

period, 100 scfh for gas-firing and lb/hr

for oil-firing.

Lavg=Average unit load during the baseline

period, megawatts or 1000 lb/hr of

steam.

In Equation D–1c, for a common pipe

header, Lavg is the sum of the operating loads

of all units that receive fuel through the

common pipe header. For a unit that receives

its fuel through multiple pipes, Qbase is the

sum of the fuel flow rates for a particular fuel

(i.e., gas, diesel fuel, or residual oil) from

each of the pipes. Round off the value of Rbase

to the nearest tenth.

Alternatively, a baseline value of the gross

heat rate (GHR) may be determined in lieu of

Rbase. The baseline value of the GHR, GHRbase,

shall be determined as follows:

( ) ( ) GHR Heat Input

L base

avg

avg

= ×1000

(Eq. D–1d)

Where:

(GHR)base=Baseline value of the gross heat

rate during the baseline period, Btu/kwh

or Btu/lb steam load.

(Heat Input)avg=Average (mean) hourly heat

input rate recorded by the fuel flowmeter

during the baseline period, as

determined using the applicable

equation in appendix F to this part,

mmBtu/hr.

Lavg=Average (mean) unit load during the

baseline period, megawatts or 1000 lb/hr

of steam.

Report the current value of Rbase (or

GHRbase) and the completion date of the

associated quality assurance procedure in

each electronic quarterly report required

under § 75.64.

2.1.7.2 Data Preparation and Analysis

Evaluate the fuel flow rate-to-load ratio (or

GHR) for each flowmeter QA operating

quarter, as defined in section 2.1.6 of this

appendix. At the end of each flowmeter QA

operating quarter, use Equation D–1e in this

appendix to calculate Rh, the hourly fuel

flow-to-load ratio, for every quality assured

hourly average fuel flow rate obtained with

a certified fuel flowmeter.

R Q

L h

h

h

=

(Eq. D–1e)

Where:

Rh=Hourly value of the fuel flow rate-to-load

ratio; 100 scfh/MWe, (lb/hr)/MWe, 100

scfh/1000 lb/hr of steam load, or (lb/hr)/

1000 lb/hr of steam load.

Qh = Hourly fuel flow rate, as measured by

the fuel flowmeter, 100 scfh for gas-firing

or lb/hr for oil-firing.

Lh = Hourly unit load, megawatts or 1000 lb/

hr of steam.

For a common pipe header, Lh shall be the

sum of the hourly operating loads of all units

that receive fuel through the common pipe

header. For a unit that receives its fuel

through multiple pipes, Qh will be the sum

of the fuel flow rates for a particular fuel (i.e.,

gas, diesel fuel, or residual oil) from each of

the pipes. Round off each value of Rh to the

nearest tenth.

Alternatively, calculate the hourly gross

heat rates (GHR) in lieu of the hourly flowto-load ratios. If this option is selected,

calculate each hourly GHR value as follows:

( ) ( ) GHR Heat Input

L h

h

h

= ×1000

(Eq. D–1f)

Where:

(GHR)h = Hourly value of the gross heat rate,

Btu/kwh or Btu/lb steam load.

(Heat Input)h = Hourly heat input rate, as

determined using the applicable

equation in appendix F to this part,

mmBtu/hr.

Lh = Hourly unit load, megawatts or 1000 lb/

hr of steam.

Evaluate the calculated flow rate-to-load

ratios (or gross heat rates) as follows. Perform

a separate data analysis for each fuel

flowmeter following the procedures of this
28180 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

section. Base each analysis on a minimum of

168 hours of data. If, for a particular fuel

flowmeter, fewer than 168 hourly flow-toload ratios (or GHR values) are available, a

flow-to-load (or GHR) evaluation is not

required for that flowmeter for that calendar

quarter.

For each hourly flow-to-load ratio or GHR

value, calculate the percentage difference

(percent Dh) from the baseline fuel flow-toload ratio using Equation D–1g.

%D

R R

R h

base h

base

= − ×100

(Eq. D–1g)

Where:

%Dh = Absolute value of the percentage

difference between the hourly fuel flow

rate-to-load ratio and the baseline value

of the fuel flow rate-to-load ratio (or

hourly and baseline GHR).

Rh = The hourly fuel flow rate-to-load ratio

(or GHR).

Rbase = The value of the fuel flow rate-to-load

ratio (or GHR) from the baseline period,

determined in accordance with section

2.1.7.1 of this appendix.

Consistently use Rbase and Rh in Equation

D–1g if the fuel flow-to-load ratio is being

evaluated, and consistently use (GHR)base and

(GHR)h in Equation D–1g if the gross heat rate

is being evaluated.

Next, determine the arithmetic average of

all of the hourly percent difference (percent

Dh) values using Equation D–1h, as follows:

SO2c = ∑ SO2

q=1

the current quarter

q

(Eq. D–1h)

Where:

Ef = Quarterly average percentage difference

between hourly flow rate-to-load ratios

and the baseline value of the fuel flow

rate-to-load ratio (or hourly and baseline

GHR).

%Dh = Percentage difference between the

hourly fuel flow rate-to-load ratio and

the baseline value of the fuel flow rateto-load ratio (or hourly and baseline

GHR).

q = Number of hours used in fuel flow-toload (or GHR) evaluation.

When the quarterly average load value

used in the data analysis is greater than 50

MWe (or 500 klb steam per hour), the results

of a quarterly fuel flow rate-to-load (or GHR)

evaluation are acceptable and no further

action is required, if the quarterly average

percentage difference (Ef) is no greater than

10.0 percent. When the arithmetic average of

the hourly load values used in the data

analysis is ≤ 50 MWe (or 500 klb steam per

hour), the results of the analysis are

acceptable if the value of Ef is no greater than

15.0 percent.

2.1.7.3 Optional Data Exclusions

If Ef is outside the limits in section 2.1.7.2

of this appendix, the owner or operator may

re-examine the hourly fuel flow rate-to-load

ratios (or GHRs) that were used for the data

analysis and identify and exclude fuel flowto-load ratios or GHR values for any nonrepresentative fuel flow-to-load ratios or GHR

values. Specifically, the Rh or (GHR)h values

for the following hours shall be considered

non-representative: (1) any hour in which the

unit combusted another fuel in addition to

the fuel measured by the fuel flowmeter

being tested; (2) any hour for which the load

differed by more than ± 15.0 percent from the

load during either the preceding hour or the

subsequent hour; and (3) any hour for which

the unit load was in the lower 10.0 percent

of the range of operation, as defined in

section 6.5.2.1 of appendix A to this part,

unless operation in this lower portion of the

range is considered normal for the unit.

After identifying and excluding all nonrepresentative hourly fuel flow-to-load ratios

or GHR values, analyze the quarterly fuel

flow rate-to-load data a second time.

2.1.7.4 Consequences of Failed Fuel Flowto-Ratio Test

If Ef is outside the applicable limit in

section 2.1.7.2 of this appendix (after

analysis using any optional data exclusions

under section 2.1.7.3 of this appendix),

perform transmitter accuracy tests according

to section 2.1.6.1 of this appendix for

orifice-, nozzle-, and venturi-type

flowmeters, or perform a fuel flowmeter

accuracy test, in accordance with section

2.1.5.1 or 2.1.5.2 of this appendix, for each

fuel flowmeter for which Ef is outside of the

applicable limit. In addition, for an orifice-

, nozzle-, or venturi-type fuel flowmeter,

repeat the fuel flow-to-load ratio comparison

of section 2.1.7.2 of this appendix using six

to twelve hours of data following a passed

transmitter accuracy test in order to verify

that no significant corrosion has affected the

primary element. If, for the abbreviated 6–to–

12 hour test, the orifice-, nozzle-, or venturitype fuel flowmeter is not able to meet the

limit in section 2.1.7.2 of this appendix, then

perform a visual inspection of the primary

element according to section 2.1.6.6 of this

appendix, and repair or replace the primary

element, as necessary.

Substitute for fuel flow rate, for any hour

when that fuel is combusted, using the

missing data procedures in section 2.4.2 of

this appendix, beginning with the first hour

of the calendar quarter following the quarter

for which Ef was found to be outside the

applicable limit and continuing until quality

assured fuel flow data become available.

Following a failed flow rate-to-load or GHR

evaluation, data from the flowmeter shall not

be considered quality assured until the hour

in which all required flowmeter accuracy

tests, transmitter accuracy tests, visual

inspections and diagnostic tests have been

passed. Additionally, a new value of Rbase or

(GHR)base shall be established no later than

two flowmeter QA operating quarters after

the quarter in which the required quality

assurance tests are completed (for orifice-,

nozzle-, or venturi-type fuel flowmeters, a

new value of Rbase or (GHR)base shall only be

established if both a transmitter accuracy test

and a primary element inspection have been

performed).

2.1.7.5 Test Results

Report the results of each quarterly flow

rate-to-load (or GHR) evaluation, as

determined from Equation D–1h, in the

electronic quarterly report required under

§ 75.64. Table D–4 is provided as a reference

on the type of information to be recorded

under § 75.59 and reported under § 75.64.

TABLE D–4.—BASELINE INFORMATION AND TEST RESULTS FOR FUEL FLOW-TO-LOAD TEST

Time period

Baseline period Quarter

Plant name:lll State:llll ORIS code:llll

Unit/pipe ID #:llll Fuel flowmeter component and system ID #s:ll–ll

Calendar quarter (1st, 2nd, 3rd, 4th) and year:llll

Range of operation:llll tollll MWe or klb steam/hr (indicate units)

Completion date and time of most recent primary element inspection

(orifice-, nozzle-, and venturi-type flowmeters only).

Number of hours excluded from quarterly average due to co-firing different fuels:llllhrs.

ll/ll/ll ll:ll

Completion date and time of most recent flowmeter or transmitter accuracy test.Number of hours excluded from quarterly average due to ramping

load:llllhrs.

ll/ll/ll ll:ll

Beginning date and time of baseline period ............................................. Number of hours in the lower 10.0 percent of the range of operation

excluded from quarterly average:llllhrs.
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28181

TABLE D–4.—BASELINE INFORMATION AND TEST RESULTS FOR FUEL FLOW-TO-LOAD TEST—Continued

Time period

Baseline period Quarter

ll/ll/ll ll:ll

End date and time of baseline period: Number of hours included in quarterly average:llllhrs.

ll/ll/ll ll:ll

Average fuel flow rate:llll

(100 scfh for gas and lb/hr for oil) ............................................................

Quarterly percentage difference between hourly ratios and baseline

ratio:llll percent.

Average load:llll

(MWe or 1000 lb steam/hr) ......................................................................

Test result: pass, fail

Plant name:llll State:llll ORIS code:llll

Unit/pipe ID#:llll Fuel flowmeter component and system ID #:ll–ll

Calendar quater (1st, 2nd, 3rd, 4th) and year:llll

Range of operation:llll MWe or klb steam/hr (indicate units)

Time period

Baseline fuel flow-to-load ratio:llll

Units of fuel flow-to-load:llll

Baseline GHR:llll

Units of fuel flow-to-load:llll

Number of hours excluded from baseline ratio or GHR due to ramping

load:llll hrs.

Number of hours in the lower 10.0 percent of the range of operation

excluded from baseline ratio or GHR:llll hrs.

2.2 Oil Sampling and Analysis

Perform sampling and analysis of oil to

determine the percentage of sulfur by weight

in the oil combusted by the unit. Calculate

SO2 mass emissions and heat input rate using

the sulfur content, density, and gross

calorific value (heat content), as described in

the sections below and in Table D–5.

TABLE D–5.—OIL SAMPLING METHODS AND SULFUR, DENSITY AND GROSS CALORIFIC VALUE USED IN CALCULATIONS

Parameter Sampling technique/frequency Value used in calculations

Oil Sulfur Content.. ............... Daily manual sampling .................................................... Highest sulfur content from previous 30 daily samples.

Flow proportional/weekly composite.. ............................. Actual measured value.

In storage tank (after addition of fuel to tank) ................ Actual measured value OR highest of all sampled values in previous calendar year OR maximum value allowed by contract.1

As delivered (in delivery truck or barge).1 ...................... Highest of all sampled values in previous calendar year

OR maximum value allowed by contract.1

Oil Density ............................ Daily manual sampling .................................................... Actual measured value.

Flow proportional/weekly composite.. ............................. Actual measured value.

In storage tank (after addition of fuel to tank) ................ Actual measured value OR highest of all sampled values in previous calendar year OR maximum value allowed by contract.1

As delivered (in delivery truck or barge).1 ...................... Highest of all sampled values in previous calendar year

OR maximum value allowed by contract.1

Oil GCV ................................ Daily manual sampling .................................................... Actual measured value.

Flow proportional/weekly composite ............................... Actual measured value.

In storage tank (after addition of fuel to tank) ................ Actual measured value OR highest of all sampled values in previous calendar year OR maximum value allowed by contract.1

As delivered (in delivery truck or barge).1 ...................... Highest of all sampled values in previous calendar year

OR maximum value allowed by contract.1

1Assumed values may only be used if sulfur content, gross calorific value, or density of each sample is no greater than the assumed value

used to calculate emissions or heat input.

2.2.1 When combusting oil, sample the

oil: (1) from the storage tank for the unit after

each addition of oil to the storage tank, in

accordance with section 2.2.4.2 of this

appendix; (2) from the fuel lot in the

shipment tank or container upon receipt of

each oil delivery or from the fuel lot in the

oil supplier’s storage container, in

accordance with section 2.2.4.3 of this

appendix; (3) following the flow proportional

sampling methodology in section 2.2.3 of this

appendix; or (4) following the daily manual

sampling methodology in section 2.2.4.1 of

this appendix. For purposes of this appendix,

a fuel lot of oil is the mass or volume of

product oil from one source (supplier or

pretreatment facility), intended as one

shipment or delivery (ship load, barge load,

group of trucks, discrete purchase of diesel

fuel through pipeline, etc.), which meets the

fuel purchase specifications for sulfur

content and GCV. A storage tank is a

container at a plant holding oil that is

actually combusted by the unit, such that
28182 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

blending of any other fuel with the fuel in

the storage tank occurs from the time that the

fuel lot is transferred to the storage tank to

the time when the fuel is combusted in the

unit.

2.2.2 [Reserved]

2.2.3 Flow Proportional Sampling

Conduct flow proportional oil sampling or

continuous drip oil sampling in accordance

with ASTM D4177–82 (Reapproved 1990),

‘‘Standard Practice for Automatic Sampling

of Petroleum and Petroleum Products’’

(incorporated by reference under § 75.6),

every day the unit is combusting oil. Extract

oil at least once every hour and blend into

a composite sample. The sample compositing

period may not exceed 7 calendar days (168

hr). Use the actual sulfur content (and where

density data are required, the actual density)

from the composite sample to calculate the

hourly SO2 mass emission rates for each

operating day represented by the composite

sample. Calculate the hourly heat input rates

for each operating day represented by the

composite sample, using the actual gross

calorific value from the composite sample.

2.2.4 Manual Sampling

2.2.4.1 Daily Samples

Representative oil samples may be taken

from the storage tank or fuel flow line

manually every day that the unit combusts

oil according to ASTM D4057–88, ‘‘Standard

Practice for Manual Sampling of Petroleum

and Petroleum Products’’ (incorporated by

reference under § 75.6), provided that the

highest fuel sulfur content recorded at that

unit from the most recent 30 daily samples

is used for the purpose of calculating SO2

emissions under section 3 of this appendix.

Use the gross calorific value measured from

that day’s samples to calculate heat input. If

oil supplies with different sulfur contents are

combusted on the same day, sample the

highest sulfur fuel combusted that day.

2.2.4.2 Sampling from a Unit’s Storage Tank

Take a manual sample after each addition

of oil to the storage tank. No additional fuel

shall be blended with the sampled fuel prior

to combustion. Sample according to the

single tank composite sampling procedure or

all-levels sampling procedure in ASTM

D4057–88, ‘‘Standard Practice for Manual

Sampling of Petroleum and Petroleum

Products’’ (incorporated by reference under

§ 75.6). Use the sulfur content (and where

required, the density) of either the most

recent sample or one of the conservative

assumed values described in section 2.2.4.3

of this appendix, to calculate SO2 mass

emission rate. Calculate heat input rate using

the gross calorific value from either: (1) the

most recent oil sample taken or (2) one of the

conservative assumed values described in

section 2.2.4.3 of this appendix.

2.2.4.3 Sampling from Each Delivery

Alternatively, an oil sample may be taken

from the shipment tank or container upon

receipt of each lot of fuel oil or from the

supplier’s storage container which holds the

lot of fuel oil. For the purpose of this section,

a lot is defined as a shipment or delivery

(e.g., ship load, barge load, group of trucks,

discrete purchase of diesel fuel through a

pipeline, etc.) which meets the fuel purchase

specifications for sulfur content and GCV. Oil

sampling may be performed either by the

owner or operator of an affected unit, an

outside laboratory, or a fuel supplier,

provided that samples are representative and

that sampling is performed according to

either the single tank composite sampling

procedure or the all-levels sampling

procedure in ASTM D4057–88, ‘‘Standard

Practice for Manual Sampling of Petroleum

and Petroleum Products’’ (incorporated by

reference under § 75.6). Except as otherwise

provided in this section 2.2.4.3, calculate SO2

mass emission rate using the sulfur content

(and where required, the density) from one

of the two values below, and calculate heat

input using the gross calorific value from one

of the two following values: (1) the highest

value sampled during the previous calendar

year or (2) the maximum value indicated in

the contract with the fuel supplier unit.

Continue to use this assumed value unless

and until the actual sampled sulfur content,

density, or gross calorific value of a delivery

exceeds the assumed value.

If the actual sampled sulfur content, gross

calorific value, or density of an oil sample is

greater than the assumed value for that

parameter, then use the actual sampled value

for sulfur content, gross calorific value, or

density of fuel to calculate SO2 mass

emission rate or heat input rate as the new

assumed sulfur content, gross calorific value,

or density. Continue to use this new assumed

value to calculate SO2 mass emission rate or

heat input rate unless and until: (1) it is

superseded by a higher value from an oil

sample; (2) a new contract with a higher

maximum sulfur content, gross calorific

value, or density is adopted, in which case

the new contract value becomes the assumed

value; or (3) both the calendar year in which

the sampled value exceeded the assumed

value and the subsequent calendar year have

elapsed.

* * * * *

2.2.6 Where the flowmeter records

volumetric flow rate rather than mass flow

rate, analyze oil samples to determine the

density or specific gravity of the oil.

* * * * *

2.2.8 Results from the oil sample analysis

must be available no later than thirty

calendar days after the sample is composited

or taken. However, during an audit, the

Administrator may require that the results of

the analysis be available as soon as

practicable, and no later than 5 business days

after receipt of a request from the

Administrator.

2.3 SO2 Emissions from Combustion of

Gaseous Fuels

Account for the hourly SO2 mass emissions

due to combustion of gaseous fuels for each

day when gaseous fuels are combusted by the

unit using the procedures in either section

2.3.1 or 2.3.2. The procedures in section 2.3.1

may be used for accounting for SO2 mass

emissions from any gaseous fuel with a total

sulfur content ≤20.0 gr/100 scf. The

procedures in section 2.3.2 may be used for

pipeline natural gas or for any gaseous fuel

for which the designated representative

demonstrates to the satisfaction of the

Administrator, in a petition to the

Administrator under § 75.66(i), that the fuel

has an SO2 emission rate no greater than

0.0006 lb/mmBtu. Values used for

calculations of SO2 mass emission rates are

summarized in Table D–6, below.

TABLE D–6.—GAS SAMPLING METHODS AND SULFUR AND HEAT CONTENT (GCV) VALUES USED IN CALCULATIONS

Parameter Sampling technique/frequency Value used in calculations

Gas Sulfur Content .............. Gaseous fuel in lots—as-delivered sampling 1 ............... Highest of all sampled values in previous calendar year

OR maximum value allowed by contract 1

Any gaseous fuel—daily sampling 2 ................................ Highest sulfur in previous 30 daily samples.

Any gaseous fuel—continuous sampling (at least hourly) with a gas chromatograph.Actual measured hourly average sulfur content.

Gas GCV/heat content ......... Gaseous fuel in lots—as-delivered sampling 1 ............... Highest of all sampled values in previous calendar year

OR maximum value allowed by contract.1

Gaseous fuels other than pipeline natural gas that are

sampled for sulfur content—daily sampling.

Highest GCV in previous 30 daily samples.

Gaseous fuels other than pipeline natural gas that are

sampled for sulfur content—continuous sampling (at

least hourly).

Actual measured hourly average GCV or highest GCV

in previous 30 unit operating days.

Pipeline natural gas—monthly sampling for GCV only. Actual measured GCV OR highest of all sampled values in previous calendar year OR maximum value allowed by contract.3

1Assumed sulfur and GCV values may only continue to be used if sulfur content and gross calorific value of each as-delivered sample is no

greater than the assumed value used to calculate emissions or heat input.
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28183

2 Continuous sampling (at least hourly) may be required if the sulfur content exhibits too much variability (see section 2.3.3.4, below).

3Assumed GCV values of the highest sampled value in the previous calendar year or the maximum value allowed by contract may only continue to be used if gross calorific value of each monthly sample is no greater than the assumed value used to calculate heat input.

2.3.1 For gaseous fuels received in

shipments or lots, sample each shipment or

lot of fuel. A fuel lot for gaseous fuel is the

volume of product gas from one source

(supplier or pretreatment facility), intended

as one shipment or delivery, which meets the

fuel purchase specifications for sulfur

content and GCV. For gaseous fuels, other

than pipeline natural gas, that are not

delivered in discrete lots or shipments,

sample the gaseous fuel at least daily.

Continuous sampling (at least hourly) with a

gas chromatograph may be required if the

sulfur content exhibits too much variability

(see section 2.3.3.4, below). For gaseous fuel

meeting the definition of pipeline natural gas

in § 72.2 of this chapter, either use the

procedures of section 2.3.2 of this appendix

or sample the gaseous fuel at least daily.

Sampling may be performed by either the

owner or operator or by the fuel supplier.

* * * * *

2.3.1.3 Determine the heat content or

gross calorific value for a sample using the

procedures of section 5.5 of appendix F to

this part to determine the heat input rate for

each hour the unit combusted gaseous fuel.

Calculate heat input using the appropriate

GCV from sections 2.3.1.4.1 through 2.3.1.4.3

of this appendix.

2.3.1.4 Calculate the hourly SO2 mass

emission rate, in lb/hr, using Equation D–4

of this appendix. Multiply the hourly

metered volumetric flow rate of gas

combusted (in 100 scfh) by the appropriate

sulfur content from sections 2.3.1.4.1 through

2.3.1.4.2 of this appendix.

2.3.1.4.1 For gaseous fuels received in

shipments or lots, use one of the following

values: (1) the highest sulfur content and

GCV from all shipments in the previous

calendar year or (2) the maximum sulfur

content and maximum GCV values

established by agreement with the fuel

supplier through a contract. Continue to use

this assumed value until and unless the

actual sampled sulfur content or gross

calorific value of a delivery exceeds the

previously reported assumed value.

If the actual sampled sulfur content or

gross calorific value of a gas sample is greater

than the assumed value for that parameter,

then use the actual sampled value for sulfur

content or gross calorific value of gas to

calculate SO2 mass emission rate or heat

input rate as the new assumed sulfur content

or gross calorific value. Continue to use this

sampled value to calculate SO2 mass

emission rate or heat input rate until: (1) it

is superseded by a new, higher value from a

gas sample; (2) a new contract with a higher

maximum sulfur content or gross calorific

value is adopted, in which case the new

contract value becomes the new assumed

value; or (3) both the calendar year in which

the sampled value exceeded the assumed

value and the subsequent calendar year have

elapsed.

2.3.1.4.2 For gaseous fuels other than

pipeline natural gas that are not received in

shipments or lots that are transmitted by

pipeline and sampled daily, use the highest

sulfur content and GCV from the previous 30

daily gas samples. When continuous gas

sampling (at least hourly) is required, use the

actual measured hourly average sulfur

content for each hour that the gaseous fuel

is combusted.

2.3.1.4.3 For pipeline natural gas, use the

highest sulfur content in the previous 30

daily gas samples, and the GCV from: (1) one

or more samples taken during the most recent

month when the unit burned gas for at least

48 hours; (2) the highest GCV from all

samples in the previous calendar year; or (3)

the maximum GCV values established by

agreement with the fuel supplier through a

contract. Continue to use this assumed value

unless and until the actual sampled sulfur

content or gross calorific value of a delivery

exceeds the previously reported assumed

value.

If the actual sampled sulfur content or

gross calorific value of a gas sample is greater

than the assumed value for that parameter,

use the actual sampled value for sulfur

content or gross calorific value of gas to

calculate SO2 mass emission rate or heat

input rate as the new assumed sulfur content

or gross calorific value. Continue to use this

sampled value to calculate SO2 mass

emission rate or heat input rate until: (1) it

is superseded by a new, higher value from a

gas sample; (2) a new contract with a higher

maximum sulfur content or gross calorific

value is adopted, in which case the new

contract value becomes the new assumed

value; or (3) both the calendar year in which

the sampled value exceeded the assumed

value and the subsequent calendar year have

elapsed.

2.3.2 If the fuel is pipeline natural gas, as

defined in § 72.2 of this chapter, calculate

SO2 emissions under this section using a

default SO2 emission rate of 0.0006 lb/

mmBtu.

2.3.2.1 Use the default SO2 emission rate

of 0.0006 lb/mmBtu and the hourly heat

input rate from pipeline natural gas in

mmBtu/hr, as determined using the

procedures in section 5.5 of appendix F to

this part. Calculate SO2 mass emission rate

using Equation D–5 of this appendix.

Determine the heat content or gross calorific

value for at least one sample each month that

the gaseous fuel is combusted using the

procedures in section 5.5 of appendix F to

this part.

2.3.2.2 The procedures in this section

2.3.2 may also be used for a gaseous fuel

other than pipeline natural gas if the

Administrator approves a petition under

§ 75.66(i) in which the designated

representative demonstrates that the gaseous

fuel combusted at the unit has an SO2

emission rate no greater than 0.0006 lb/

mmBtu. To demonstrate this, the petition

shall include at least 720 hours of fuel

sampling data, indicating the total sulfur

content and GCV of the fuel for each hour.

Each hourly value of the total sulfur content

in the gas or blend (in gr/100 scf) shall be

converted to a ‘‘fuel sulfur-to-heating value

ratio,’’ by dividing the total sulfur content by

the gross calorific value of the fuel (in Btu/

100 scf) and then multiplying by a

conversion factor of 106 Btu/mmBtu. The

mean value of the fuel sulfur-to-heating value

ratios shall then be calculated. If the mean

value of the ratios does not exceed 2.0 grains

of sulfur per mmBtu, then the default SO2

emission rate of 0.0006 lb/mmBtu may be

used to account for SO2 mass emissions

under this part, whenever the gaseous fuel is

combusted.

2.3.3 For all types of gaseous fuels, the

owner or operator shall provide, in the

monitoring plan for the unit, historical fuel

sampling information on the sulfur content of

the gaseous fuel sufficient to demonstrate

that use of this appendix is applicable

because the gas has a total sulfur content of

20.0 grain/100 scf or less. Provide this

information with the initial monitoring plan

for the unit and following any significant

changes in gas contract or source of supply.

However, for units combusting pipeline

natural gas that have gas flowmeters certified

prior to the effective date of this rule, this

information may be retained on site in a form

suitable for inspection, rather than submitted

as an update to the monitoring plan. In

addition, provide the following specific

information in the monitoring plan required

under § 75.53, depending on the type of

gaseous fuel:

2.3.3.1 For pipeline natural gas, provide

information demonstrating that the definition

of pipeline natural gas in § 72.2 of this

chapter has been met. This demonstration

must be made using one of the following

sources of information: (1) the gas quality

characteristics specified by a purchase

contract or by a pipeline transportation

contract; (2) a certification of the gas vendor,

based on routine vendor sampling and

analysis; or (3) at least one year’s worth of

analytical data on the fuel hydrogen sulfide

content from samples taken monthly or more

frequently.

2.3.3.2 For gaseous fuel other than

pipeline natural gas for which a petition has

been submitted and approved under section

2.3.2.2 of this appendix, provide the

information required to be included in the

petition pursuant to section 2.3.2.2.

2.3.3.3 For liquefied petroleum gas and

other gaseous fuels provided in batches or

lots having uniform sulfur content, provide

either contractual information from the fuel

supplier or provide historical information on

each lot of liquefied petroleum gas from at

least one year.

2.3.3.4 For any other gaseous fuel or

blend, including gas produced by a variable

process (e.g., digester gas or landfill gas),

provide data on the fuel sulfur content, as

follows. Provide a minimum of 720 hours of

data, indicating the total sulfur content of the

gas or blend (in gr/100 scf). The data shall

be obtained with a gas chromatograph, and,

for gaseous fuel produced by a variable

process, the data shall be representative of all

process operating conditions. The data shall

be reduced to hourly averages and shall be
28184 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

used to determine whether daily sampling of

the sulfur content of the gas or blend is

sufficient or whether sampling, at least

hourly, with a gas chromatograph is required.

Specifically, daily gas sampling shall be

sufficient, provided that either: (1) the mean

value of the total sulfur content of the gas or

blend is ≤7 grains per 100 scf; or (2) the

standard deviation of the hourly average

values from the mean does not exceed 5

grains per 100 scf. If the gas or blend does

not meet requirement (1) or (2), then

sampling, at least hourly, of the fuel with a

gas chromatograph (GCH) and hourly

reporting of the hourly average sulfur content

of the fuel is required. If sampling, at least

hourly, from a gas chromatograph is required,

the owner or operator shall develop and

implement a program to quality assure the

data from the GCH, in accordance with the

manufacturer’s recommended procedures.

The quality assurance procedures shall be

kept on-site, in a form suitable for inspection.

2.4 * * *

2.4.1 Missing Data for Oil and Gas Samples

When oil sulfur content, density, or gross

calorific value data are missing or invalid for

an oil or gas sample taken according to the

procedures in section 2.2.3, 2.2.4.1, 2.2.4.2,

2.2.4.3, 2.3.1, 2.3.1.1, 2.3.1.2, or 2.3.1.3 of

this appendix, then substitute the maximum

potential sulfur content, density, or gross

calorific value of that fuel from Table D–7 of

this appendix.

TABLE D–7.—MISSING DATA SUBSTITUTION PROCEDURES FOR SULFUR, DENSITY, AND GROSS CALORIFIC VALUE

Data

Parameter Missing data substitution maximum potential value

Oil Sulfur Content ................. 3.5 percent for residual oil, or. 1.0 percent for diesel fuel.

Oil Density ............................ 8.5 lb/gal for residual oil, or 7.4 lb/gal for diesel fuel.

Oil GCV ................................ 19,500 Btu/lb for residual oil, or 20,000 Btu/lb for diesel fuel.

Gas Sulfur Content ............... 0.30 gr/100 scf for pipeline natural gas, or 20.0 gr/100 scf for other gaseous fuel.

Gas GCV/Heat Content ........ 1100 Btu/scf for pipeline natural gas, or 2100 Btu/scf for other gaseous fuel.

2.4.2 Whenever data are missing from any

fuel flowmeter that is part of an excepted

monitoring system under appendix D or E to

this part, where the fuel flowmeter data are

required to determine the amount of fuel

combusted by the unit, use the procedures in

sections 2.4.2.2 and 2.4.2.3 of this appendix

to account for the flow rate of fuel combusted

at the unit for each hour during the missing

data period. In addition, a fuel flowmeter

used for measuring fuel combusted by a

peaking unit may use the simplified fuel flow

missing data procedure in section 2.4.2.1 of

this appendix.

2.4.2.1 Simplified Fuel Flow Missing

Data for Peaking Units.

If no fuel flow rate data are available for

a fuel flowmeter system installed on a

peaking unit (as defined in § 72.2 of this

chapter), then substitute for each hour of

missing data using the maximum potential

fuel flow rate. The maximum potential fuel

flow rate is the lesser of the following: (1) the

maximum fuel flow rate the unit is capable

of combusting or (2) the maximum flow rate

that the flowmeter can measure (i.e, upper

range value of flowmeter leading to a unit).

2.4.2.2 * * *

2.4.2.3 For hours where two or more fuels

are combusted, substitute the maximum

hourly fuel flow rate measured and recorded

by the flowmeter (or flowmeters, where fuel

is recirculated) for the fuel for which data are

missing at the corresponding load range

recorded for each missing hour during the

previous 720 hours when the unit combusted

that fuel with any other fuel. For hours where

no previous recorded fuel flow rate data are

available for that fuel during the missing data

period, calculate and substitute the

maximum potential flow rate of that fuel for

the unit as defined in section 2.4.2.2 of this

appendix.

2.4.3 * * *

65. Section 3 of appendix D to part 75

is amended by:

a. Revising sections 3, 3.1, 3.2, 3.2.1,

3.2.3, 3.2.4, and 3.3;

b. Redesignating section 3.4 as section

3.5 and revising the introductory text;

and

c. Adding a new section 3.4, to read

as follows:

3. Calculations

Use the calculation procedures in section

3.1 of this appendix to calculate SO2 mass

emission rate. Where an oil flowmeter

records volumetric flow rate, use the

calculation procedures in section 3.2 of this

appendix to calculate the mass flow rate of

oil. Calculate hourly SO2 mass emission rate

from gaseous fuel using the procedures in

section 3.3 of this appendix. Calculate hourly

heat input rate for oil and for gaseous fuel

using the equations in section 5.5 of

appendix F to this part. Calculate total SO2

mass emissions and heat input as provided

under section 3.4 of this appendix.

3.1 SO2 Mass Emission Rate Calculation for

Oil

3.1.1 Use the following equation to

calculate SO2 mass emissions per hour (lb/

hr):

M M S

SO oil

oil

2 2 0

100 0

= × × . %

.

(Eq. D–2)

where:

MSO2 = Hourly mass emission rate of SO2

emitted from combustion of oil, lb/hr.

Moil = Mass rate of oil consumed per hr, lb/

hr.

%Soil = Percentage of sulfur by weight

measured in the sample.

2.0 = Ratio of lb SO2/lb S.

3.1.2 Record the SO2 mass emission rate

from oil for each hour that oil is combusted.

3.2 Mass Flow Rate Calculation for Oil

Using Volumetric Flow Rate

3.2.1 Where the oil flowmeter records

volumetric flow rate rather than mass flow

rate, calculate and record the oil mass flow

rate for each hourly period using hourly oil

flow rate measurements and the density or

specific gravity of the oil sample.

* * * * *

3.2.3 Where density of the oil is

determined by the applicable ASTM

procedures from section 2.2.5 of this

appendix, use the following equation to

calculate the rate of the mass of oil consumed

(in lb/hr):

Moil=Voil×Doil

(Eq. D–3)

Where:

Moil = Mass rate of oil consumed per hr, lb/

hr.

Voil = Volume rate of oil consumed per hr,

measured in scf, gal, barrels, or m3.

Doil = Density of oil, measured in lb/scf, lb/

gal, lb/barrel, or lb/m3.

3.2.4 Calculate the hourly heat input rate

to the unit from oil (mmBtu/hr) by

multiplying the heat content of the daily oil

sample by the hourly oil mass rate.

3.3 SO2 Mass Emissions Rate Calculation

for Gaseous Fuels

3.3.1 Use the following equation to

calculate the SO2 emission rate using the gas

sampling and analysis procedures in section

2.3.1 of this appendix:

M Q S ( ) SO g g g

.

2

2 0

7000 = 





 × ×

(Eq. D–4)

Where:

M(SO2)g = Hourly mass rate of SO2 emitted

due to combustion of gaseous fuel, lb/hr.

Qg = Hourly metered flow rate of gaseous fuel

combusted, 100 scf/hr.

Sg = Sulfur content of gaseous fuel, in grain/

100 scf.

2.0 = Ratio of lb SO2/lb S.

7000 = Conversion of grains/100 scf to lb/100

scf.

3.3.2 Use the following equation to

calculate the SO2 emission rate using the
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28185

0.0006 lb/mmBtu emission rate in section

2.3.2 of this appendix:

M(SO2)g = ER × HIg

(Eq. D–5)

Where:

M(SO2)g = Hourly mass rate of SO2 emissions

from combustion of pipeline natural gas,

lb/hr.

ER = SO2 emission rate of 0.0006 lb/mmBtu

for pipeline natural gas.

Hig = Hourly heat input rate of pipeline

natural gas, calculated using procedures

in appendix F to this part, in mmBtu/hr.

3.3.3 Record the SO2 mass emission rate

for each hour when the unit combusts

gaseous fuel.

3.4 Conversion of Rates to Totals and

Summation of Quarterly and Cumulative

Values

3.4.1 SO2 Mass Emissions Conversions

and Summations.

For a unit or for a common pipe, calculate

total quarterly SO2 mass emissions (using

Equation D–6) and total cumulative SO2 mass

emissions (using Equation D–7). First convert

hourly SO2 mass emission rates for each fuel

to total hourly SO2 mass emissions, by

multiplying the hourly rates by the fuel usage

time. Second, sum the total hourly SO2 mass

emissions from all fuels for the quarter.

Third, convert the quarterly SO2 mass

emission total to tons. Finally, for cumulative

emissions, sum the quarterly SO2 mass

emission totals, in tons, for each quarter in

the year to date.

SO t q 2 i

1

2000 = ∑ ∑ ∑ SO2i fuel system

first system

last system

hour=1

n

first fuel

last fuel

(Eq. D–6)

Where:

SO2q = Total SO2 mass emissions for the

quarter, tons.

SO2i fuel system = SO2 mass emission rate for

a given fuel for a particular fuel flow

system, lb/hr.

ti = Fuel usage time for the fuel and system,

hour or fraction of an hour.

SO2c = ∑ SO2

q=1

the current quarter

q

(Eq. D–7)

Where:

SO2c = Total SO2 mass emissions for the year

to date, tons.

SO2q = Total SO2 mass emissions for the

quarter, tons.

3.4.2 Heat Input Conversions and

Summations

Calculate total quarterly (using Equation

D–8) and total cumulative (using Equation D–

9) heat input for a unit or common pipe with

fuel flow systems.

HI HI t q i = ∑ ∑ ∑ i fuel system

first system

last system

hour=1

n

first fuel

last fuel

(Eq. D–8)

Where:

HIq = Total heat input for the quarter,

mmBtu.

HIi fuel system = Heat input rate during fuel

usage for a given fuel for a particular fuel

flow system, using Equation F–19 or F–

20, mmBtu/hr.

ti = Fuel usage time for the fuel and system,

hour or fraction of an hour.

HI HI c q = ∑

q=1

the current quarter

(Eq. D–9)

Where:

HIc=Total heat input for the year to date,

mmBtu.

HIq=Total heat input for the quarter, mmBtu.

3.5 Records and Reports

Calculate and record quarterly and

cumulative SO2 mass emissions and heat

input for each calendar quarter using the

procedures and equations of section 3.4 of

this appendix.

* * * * *

APPENDIX E TO PART 75—OPTIONAL

NOX EMISSIONS ESTIMATION

PROTOCOL FOR GAS-FIRED

PEAKING UNITS AND OIL-FIRED

PEAKING UNITS

* * * * *

66. Section 2 of appendix E to part 75

is amended by revising sections 2.5.4

and 2.5.5 to read as follows:

2. Procedure

* * * * *

2.5 Missing Data Procedures

* * * * *

2.5.4 Substitute missing data from a fuel

flowmeter using the procedures in section

2.4.2 of appendix D to this part.

2.5.5 Substitute missing data for gross

calorific value of fuel using the procedures in

sections 2.4.1 of appendix D to this part.

67. Section 3 of Appendix E to part

75 is amended by revising sections 3.1,

3.3.1, and 3.3.4 to read as follows:

3. Calculations

3.1 Heat Input

Calculate the total heat input by summing

the product of heat input rate and fuel usage

time of each fuel, as in the following

equation:

HT=HIfuel 1t1+HIfuel 2t2+HIfuel

3t3+...+HIlastfueltlast

(Eq. E–1)

Where:
28186 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

HT=Total heat input of fuel flow or a

combination of fuel flows to a unit,

mmBtu.

HIfuel 1,2,3,...last=Heat input rate from each fuel,

in mmBtu/hr as determined using

Equation F–19 or F–20 in section 5.5 of

appendix F to this part, mmBtu/hr.

t1,2,3....last=Fuel usage time for each fuel

(rounded up to the nearest fraction of an

hour (in equal increments that can range

from one hundredth to one quarter of an

hour, at the option of the owner or

operator)).

* * * * *

3.3 * * *

3.3.1 Conversion from Concentration to

Emission Rate.

Convert the NOX concentrations (ppm) and

O2 concentrations to NOX emission rates (to

the nearest 0.01 lb/mmBtu for tests

performed prior to January 1, 2000 or to the

nearest 0.001 lb/mmBtu for tests performed

on and after January 1, 2000), according to

the appropriate one of the following

equations: F–5 in appendix F to this part for

dry basis concentration measurements or 19–

3 in Method 19 of appendix A to part 60 of

this chapter for wet basis concentration

measurements.

* * * * *

3.3.4 Average NOX Emission Rate During

Co-firing of Fuels.

E

E HI t

H h

f f f

T

=

∑ ( ) ×

f =1

all fuels

(Eq. E–2)

Where:

Eh=NOX emission rate for the unit for the

hour, lb/mmBtu.

Ef=NOX emission rate for the unit for a given

fuel at heat input rate HIf, lb/mmBtu.

HIf=Heat input rate for the hour for a given

fuel, during the fuel usage time, as

determined using Equation F–19 or F–20

in section 5.5 of appendix F to this part,

mmBtu/hr

HT=Total heat input for all fuels for the hour

from Equation E–1.

tf=Fuel usage time for each fuel (rounded up

to the nearest fraction of an hour (in

equal increments that can range from one

hundredth to one quarter of an hour, at

the option of the owner or operator)).

Note: For hours where a fuel is combusted

for only part of the hour, use the fuel flow

rate or mass flow rate during the fuel usage

time, instead of the total fuel flow or mass

flow during the hour, when calculating heat

input rate using Equation F–19 or F–20.

68. Section 2 of appendix F to part 75

is revised to read as follows:

Appendix F to Part 75—Conversion

Procedures

* * * * *

2. Procedures for SO2 Emissions

Use the following procedures to compute

hourly SO2 mass emission rate (in lb/hr) and

quarterly and annual SO2 total mass

emissions (in tons). Use the procedures in

Method 19 in appendix A to part 60 of this

chapter to compute hourly SO2 emission

rates (in lb/mmBtu) for qualifying Phase I

technologies. When computing hourly SO2

emission rate in lb/mmBtu, a minimum

concentration of 5.0 percent CO2 and a

maximum concentration of 14.0 percent O2

may be substituted for measured diluent gas

concentration values at boilers during hours

when the hourly average concentration of

CO2 is less than 5.0 percent CO2 or the hourly

average concentration of O2 is greater than

14.0 percent O2.

2.1 When measurements of SO2

concentration and flow rate are on a wet

basis, use the following equation to compute

hourly SO2 mass emission rate (in lb/hr):

Eh = KChQh

(Eq. F–1)

Where:

Eh = Hourly SO2 mass emission rate during

unit operation, lb/hr.

K = 1.660 × 10¥7 for SO2, (lb/scf)/ppm.

Ch = Hourly average SO2 concentration

during unit operation, stack moisture

basis, ppm.

Qh = Hourly average volumetric flow rate

during unit operation, stack moisture

basis, scfh.

2.2 When measurements by the SO2

pollutant concentration monitor are on a dry

basis and the flow rate monitor

measurements are on a wet basis, use the

following equation to compute hourly SO2

mass emission rate (in lb/hr):

E K C Q

H O

h hp hs = ( ) 100 −

100

% 2

(Eq. F–2)

Where:

Eh = Hourly SO2 mass emission rate during

unit operation, lb/hr.

K = 1.660 × 10¥7 for SO2, (lb/scf)/ppm.

Chp = Hourly average SO2 concentration

during unit operation, ppm (dry).

Qhs= Hourly average volumetric flow rate

during unit operation, scfh as measured

(wet).

%H2O = Hourly average stack moisture

content during unit operation, percent by

volume.

2.3 Use the following equations to

calculate total SO2 mass emissions for each

calendar quarter (Equation F–3) and for each

calendar year (Equation F–4), in tons:

E

E t

q

h h

h i

n

= =

∑

2000

(Eq. F–3)

Where:

Eq = Quarterly total SO2 mass emissions,

tons.

Eh = Hourly SO2 mass emission rate, lb/hr.

th = Unit operating time, hour or fraction of

an hour (in equal increments that can

range from one hundredth to one quarter

of an hour, at the option of the owner or

operator).

n = Number of hourly SO2 emissions values

during calendar quarter.

2000 = Conversion of 2000 lb per ton.

E E a q

q

=

=

∑

1

4

(Eq. F–4)

Where:

Ea = Annual total SO2 mass emissions, tons.

Eq = Quarterly total SO2 mass emissions,

tons.

q = Quarters for which Eq are available

during calendar year.

2.4 Round all SO2 mass emission rates

and totals to the nearest tenth.

69. Section 3 of appendix F to part 75

is amended by revising sections 3.3.2,

3.3.3, 3.3.4, 3.4, and 3.5 to read as

follows:

3. Procedures for NOX Emission Rate

* * * * *

3.3 * * *

3.3.2 E = Pollutant emissions during unit

operation, lb/mmBtu.

3.3.3 Ch = Hourly average pollutant

concentration during unit operation, ppm.

3.3.4 %O2, %CO2 = Oxygen or carbon

dioxide volume during unit operation

(expressed as percent O2 or CO2). A

minimum concentration of 5.0 percent

CO2 and a maximum concentration of

14.0 percent O2 may be substituted for

measured diluent gas concentration

values at boilers during hours when the

hourly average concentration of CO2 is

<5.0 percent CO2 or the hourly average

concentration of O2 is >14.0 percent O2.

A minimum concentration of 1.0 percent

CO2 and a maximum concentration of

19.0 percent O2 may be substituted for

measured diluent gas concentration

values at stationary gas turbines during

hours when the hourly average

concentration of CO2 is <1.0 percent CO2

or the hourly average concentration of O2

is >19.0 percent O2.

* * * * *

3.4 Use the following equations to

calculate the average NOX emission rate for

each calendar quarter (Equation F–9) and the

average emission rate for the calendar year

(Equation F–10), in lb/mmBtu:

E E

n q

i

i

n

=

=

∑

1

(Eq. F–9)

Where:

Eq = Quarterly average NOX emission rate, lb/

mmBtu.

Ei = Hourly average NOX emission rate

during unit operation, lb/mmBtu.

n = Number of hourly rates during calendar

quarter.

E E

m a i

i

m

=

=

∑

1

(Eq. F–10)

Where:

Ea = Average NOX emission rate for the

calendar year, lb/mmBtu.
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28187

Ei = Hourly average NOX emission rate

during unit operation, lb/mmBtu.

m = Number of hourly rates for which Ei is

available in the calendar year.

3.5 Round all NOX emission rates to the

nearest 0.01 lb/mmBtu prior to January 1,

2000 and to the nearest 0.001 lb/mmBtu on

and after January 1, 2000.

70. Section 4 of appendix F to part 75

is amended by revising sections 4.1, 4.2,

4.3, and 4.4.1 to read as follows:

4. Procedures for CO2 Mass Emissions

* * * * *

4.1 When CO2 concentration is measured

on a wet basis, use the following equation to

calculate hourly CO2 mass emissions rates (in

tons/hr):

Eh = KChQh

(Eq. F–11)

Where:

Eh = Hourly CO2 mass emission rate during

unit operation, tons/hr.

K = 5.7 X 10¥7 for CO2, (tons/scf) /%CO2.

Ch = Hourly average CO2 concentration

during unit operation, wet basis, percent

CO2. For boilers, a minimum

concentration of 5.0 percent CO2 may be

substituted for the measured

concentration when the hourly average

concentration of CO2 is < 5.0 percent

CO2, provided that this minimum

concentration of 5.0 percent CO2 is also

used in the calculation of heat input for

that hour. For stationary gas turbines, a

minimum concentration of 1.0 percent

CO2 may be substituted for measured

diluent gas concentration values during

hours when the hourly average

concentration of CO2 is < 1.0 percent

CO2, provided that this minimum

concentration of 1.0 percent CO2 is also

used in the calculation of heat input for

that hour.

Qh = Hourly average volumetric flow rate

during unit operation, wet basis, scfh.

4.2 When CO2 concentration is measured

on a dry basis, use Equation F–2 to calculate

the hourly CO2 mass emission rate (in tons/

hr) with a K-value of 5.7 × 10¥7 (tons/scf)

percent CO2, where Eh = hourly CO2 mass

emission rate, tons/hr and Chp = hourly

average CO2 concentration in flue, dry basis,

percent CO2.

4.3 Use the following equations to

calculate total CO2 mass emissions for each

calendar quarter (Equation F–12) and for

each calendar year (Equation F–13):

E E t CO q h h

h

HR

2

1

=

=

∑

(Eq. F–12)

Where:

E(CO2)q = Quarterly total CO2 mass emissions,

tons.

Eh = Hourly CO2 mass emission rate, tons/hr.

th = Unit operating time, in hours or fraction

of an hour (in equal increments that can

range from one hundredth to one quarter

of an hour, at the option of the owner or

operator).

HR = Number of hourly CO2 mass emission

rates available during calendar quarter.

* * * * *

4.4 * * *

4.4.1 Use appropriate F and Fc factors

from section 3.3.5 of this appendix in the

following equation to determine hourly

average CO2 concentration of flue gases (in

percent by volume):

CO F

F

O

d

c d

2

2 100 20 9

20 9 = . −.

(Eq. F–14a)

Where:

CO2d = Hourly average CO2 concentration

during unit operation, percent by

volume, dry basis.

F, Fc = F-factor or carbon-based Fc-factor from

section 3.3.5 of this appendix.

20.9 = Percentage of O2 in ambient air.

O2d = Hourly average O2 concentration

during unit operation, percent by

volume, dry basis. For boilers, a

maximum concentration of 14.0 percent

O2 may be substituted for the measured

concentration when the hourly average

concentration of O2 is > 14.0 percent O2,

provided that this maximum

concentration of 14.0 percent O2 is also

used in the calculation of heat input for

that hour. For stationary gas turbines, a

maximum concentration of 19.0 percent

O2 may be substituted for measured

diluent gas concentration values during

hours when the hourly average

concentration of O2 is > 19.0 percent O2,

provided that this maximum

concentration of 19.0 percent O2 is also

used in the calculation of heat input for

that hour.

CO F

F

H O w O c 2 w 2

2

100

20 9

20 9 100

100 =  −





 − 



 



 . . %

or

(Eq. F–14b)

Where:

CO2w = Hourly average CO2 concentration

during unit operation, percent by

volume, wet basis.

O2w = Hourly average O2 concentration

during unit operation, percent by

volume, wet basis. For boilers, a

maximum concentration of 14.0 percent

O2 may be substituted for the measured

concentration when the hourly average

concentration of O2 is > 14.0 percent O2,

provided that this maximum

concentration of 14.0 percent O2 is also

used in the calculation of heat input for

that hour. For stationary gas turbines, a

maximum concentration of 19.0 percent

O2 may be substituted for measured

diluent gas concentration values during

hours when the hourly average

concentration of O2 is > 19.0 percent O2,

provided that this maximum

concentration of 19.0 percent O2 is also

used in the calculation of heat input for

that hour.

F, Fc = F-factor or carbon-based Fc-factor from

section 3.3.5 of this appendix.

20.9 = Percentage of O2 in ambient air.

%H2O = Moisture content of gas in the stack,

percent.

* * * * *

71. Section 5 of appendix F to part 75

is amended by revising sections 5, 5.1,

5.2, 5.5, 5.5.1, and 5.5.2 and by adding

new sections 5.3, 5.6, and 5.7 to read as

follows:

5. Procedures for Heat Input

Use the following procedures to compute

heat input rate to an affected unit (in mmBtu/

hr or mmBtu/day):

5.1 Calculate and record heat input rate

to an affected unit on an hourly basis, except

as provided below. The owner or operator

may choose to use the provisions specified in

§ 75.16(e) or in section 2.1.2 of appendix D

to this part in conjunction with the

procedures provided below to apportion heat

input among each unit using the common

stack or common pipe header.
28188 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

5.2 For an affected unit that has a flow

monitor (or approved alternate monitoring

system under subpart E of this part for

measuring volumetric flow rate) and a

diluent gas (O2 or CO2) monitor, use the

recorded data from these monitors and one

of the following equations to calculate hourly

heat input rate (in mmBtu/hr).

5.2.1 When measurements of CO2

concentration are on a wet basis, use the

following equation:

HI Q F

CO w

c

w = 1

100

% 2

(Eq. F–15)

Where:

HI = Hourly heat input rate during unit

operation, mmBtu/hr.

Qw = Hourly average volumetric flow rate

during unit operation, wet basis, scfh.

Fc = Carbon-based F-factor, listed in section

3.3.5 of this appendix for each fuel, scf/

mmBtu.

%CO2w = Hourly concentration of CO2 during

unit operation, percent CO2 wet basis.

For boilers, a minimum concentration of

5.0 percent CO2 may be substituted for

the measured concentration when the

hourly average concentration of CO2 is <

5.0 percent CO2, provided that this

minimum concentration of 5.0 percent

CO2 is also used in the calculation of

CO2 mass emissions for that hour. For

stationary gas turbines, a minimum

concentration of 1.0 percent CO2 may be

substituted for measured diluent gas

concentration values during hours when

the hourly average concentration of CO2

is < 1.0 percent CO2, provided that this

minimum concentration of 1.0 percent

CO2 is also used in the calculation of

CO2 mass emissions for that hour.

5.2.2 When measurements of CO2

concentration are on a dry basis, use the

following equation:

HI Q

H O

F

CO d

h

c

= ( ) −























100

100 100

% 2 % 2

(Eq. F–16)

Where:

HI = Hourly heat input rate during unit

operation, mmBtu/hr.

Qh = Hourly average volumetric flow rate

during unit operation, wet basis, scfh.

Fc = Carbon-based F-Factor, listed above in

section 3.3.5 of this appendix for each

fuel, scf/mmBtu.

%CO2d = Hourly concentration of CO2 during

unit operation, percent CO2 dry basis.

For boilers, a minimum concentration of

5.0 percent CO2 may be substituted for

the measured concentration when the

hourly average concentration of CO2 is <

5.0 percent CO2, provided that this

minimum concentration of 5.0 percent

CO2 is also used in the calculation of

CO2 mass emissions for that hour. For

stationary gas turbines, a minimum

concentration of 1.0 percent CO2 may be

substituted for measured diluent gas

concentration values during hours when

the hourly average concentration of CO2

is < 1.0 percent CO2, provided that this

minimum concentration of 1.0 percent

CO2 is also used in the calculation of

CO2 mass emissions for that hour.

%H2O = Moisture content of gas in the stack,

percent.

5.2.3 When measurements of O2

concentration are on a wet basis, use the

following equation:

HI Q F

H O O w = w

1 [ ] ( ) 20 9 100 100 ( ) − −

20 9

2 2 . / % %

.

(Eq. F–17)

Where:

HI = Hourly heat input rate during unit

operation, mmBtu/hr.

Qw = Hourly average volumetric flow rate

during unit operation, wet basis, scfh.

F = Dry basis F-Factor, listed above in section

3.3.5 of this appendix for each fuel, dscf/

mmBtu.

%O2w = Hourly concentration of O2 during

unit operation, percent O2 wet basis. For

boilers, a maximum concentration of

14.0 percent O2 may be substituted for

the measured concentration when the

hourly average concentration of O2 is >

14.0 percent O2, provided that this

maximum concentration of 14.0 percent

O2 is also used in the calculation of CO2

mass emissions for that hour. For

stationary gas turbines, a maximum

concentration of 19.0 percent O2 may be

substituted for measured diluent gas

concentration values during hours when

the hourly average concentration of O2 is

> 19.0 percent O2, provided that this

maximum concentration of 19.0 percent

O2 is also used in the calculation of CO2

mass emissions for that hour.

%H2O = Hourly average stack moisture

content, percent by volume.

5.2.4 When measurements of O2

concentration are on a dry basis, use the

following equation:

HI Q

H O

F

O

w

d = ( ) −















( ) −















100

100

20 9

20 9

% 2 2 . %

.
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28189

(Eq. F–18)

Where:

HI = Hourly heat input rate during unit

operation, mmBtu/hr.

Qw = Hourly average volumetric flow during

unit operation, wet basis, scfh.

F = Dry basis F-factor, listed above in section

3.3.5 of this appendix for each fuel, dscf/

mmBtu.

%H2O = Moisture content of the stack gas,

percent.

%O2d = Hourly concentration of O2 during

unit operation, percent O2 dry basis. For

boilers, a maximum concentration of

14.0 percent O2 may be substituted for

the measured concentration when the

hourly average concentration of O2 is >

14.0 percent O2, provided that this

maximum concentration of 14.0 percent

O2 is also used in the calculation of CO2

mass emissions for that hour.. For

stationary gas turbines, a maximum

concentration of 19.0 percent O2 may be

substituted for measured diluent gas

concentration values during hours when

the hourly average concentration of O2 is

> 19.0 percent O2, provided that this

maximum concentration of 19.0 percent

O2 is also used in the calculation of CO2

mass emissions for that hour.

5.3 Heat Input Summation (for Heat Input

Determined Using a Flow Monitor and

Diluent Monitor)

5.3.1 Calculate total quarterly heat input

for a unit or common stack using a flow

monitor and diluent monitor to calculate heat

input, using the following equation:

HI HI t q i i

hour

n

=

=

∑

1

(Eq. F–18a)

Where:

HIq = Total heat input for the quarter,

mmBtu.

HIi = Hourly heat input rate during unit

operation, using Equation F–15, F–16, F–

17, or F–18, mmBtu/hr.

ti = Hourly operating time for the unit or

common stack, hour or fraction of an

hour (in equal increments that can range

from one hundredth to one quarter of an

hour, at the option of the owner or

operator).

5.3.2 Calculate total cumulative heat

input for a unit or common stack using a flow

monitor and diluent monitor to calculate heat

input, using the following equation:

HI HI c q = ∑

q=1

the current quarter

(Eq. F–18b)

Where:

HIc = Total heat input for the year to date,

mmBtu.

HIq = Total heat input for the quarter,

mmBtu.

5.4 [Reserved]

5.5 For a gas-fired or oil-fired unit that

does not have a flow monitor and is using the

procedures specified in appendix D to this

part to monitor SO2 emissions or for any unit

using a common stack for which the owner

or operator chooses to determine heat input

by fuel sampling and analysis, use the

following procedures to calculate hourly heat

input rate in mmBtu/hr. The procedures of

section 5.5.3 of this appendix shall not be

used to determine heat input from a coal unit

that is required to comply with the

provisions of this part for monitoring,

recording, and reporting NOX mass emissions

under a state or federal NOX mass emission

reduction program.

5.5.1 When the unit is combusting oil,

use the following equation to calculate

hourly heat input rate:

HI M GCV o o o = 106

(Eq. F–19)

Where:

HIo = Hourly heat input rate from oil,

mmBtu/hr.

Mo = Mass rate of oil consumed per hour, as

determined using procedures in

appendix D to this part, in lb/hr, tons/

hr, or kg/hr.

GCVo = Gross calorific value of oil, as

measured by ASTM D240–87

(Reapproved 1991), ASTM D2015–91, or

ASTM D2382–88 for each oil sample

under section 2.2 of appendix D to this

part, Btu/unit mass (incorporated by

reference under § 75.6).

106 = Conversion of Btu to mmBtu. When

performing oil sampling and analysis

solely for the purpose of the missing data

procedures in § 75.36, oil samples for

measuring GCV may be taken weekly,

and the procedures specified in

appendix D to this part for determining

the mass rate of oil consumed per hour

are optional.

5.5.2 When the unit is combusting gaseous

fuels, use the following equation to calculate

heat input rate from gaseous fuels for each

hour:

HI

Q GCV

g

g g = ( ) ×

106

(Eq. F–20)

Where:

HIg=Hourly heat input rate from gaseous fuel,

mmBtu/hour.

Qg=Metered flow rate of gaseous fuel

combusted during unit operation,

hundred cubic feet.

GCVg=Gross calorific value of gaseous fuel,

as determined by sampling (for each

delivery for gaseous fuel in lots, for each

daily gas sample for gaseous fuel

delivered by pipeline, for each hourly

average for gas measured hourly with a

GCH, or for each monthly sample of

pipeline natural gas, or as verified by the

contractual supplier at least once every

month pipeline natural gas is combusted,

as specified in section 2.3 of appendix D

to this part) using ASTM D1826–88,

ASTM D3588–91, ASTM D4891–89, GPA

Standard 2172–86 ‘‘Calculation of Gross

Heating Value, Relative Density and

Compressibility Factor for Natural Gas

Mixtures from Compositional Analysis,’’

or GPA Standard 2261-90 ‘‘Analysis for

Natural Gas and Similar Gaseous

Mixtures by Gas Chromatography,’’ Btu/

100 scf (incorporated by reference under

§ 75.6).

106=Conversion of Btu to mmBtu.

* * * * *

5.6 Heat Input Rate Apportionment for

Units Sharing a Common Stack or Pipe

5.6.1 Where applicable, the owner or

operator of an affected unit that determines

heat input rate at the unit level by

apportioning the heat input monitored at a

common stack or common pipe using

megawatts should apportion the heat input

rate using the following equation:

HI HI t

t

MW t

MW t

i CS

CS

i

i i

i i

i

n = 



 





























 =  ∑

1

(Eq. F–21a)

Where:

HIi=Heat input rate for a unit, mmBtu/hr.

HICS=Heat input rate at the common stack or

pipe; mmBtu/hr.

MWi=Gross electrical output, MWe.

ti=Operating time at a particular unit, hour or

fraction of an hour (in equal increments

that can range from one hundredth to

one quarter of an hour, at the option of

the owner or operator).

tCS=Operating time at common stack, hour or

fraction of an hour (in equal increments

that can range from one hundredth to

one quarter of an hour, at the option of

the owner or operator).

n=Total number of units using the common

stack.

i=Designation of a particular unit.

5.6.2 Where applicable, the owner or

operator of an affected unit that determines

the heat input rate at the unit level by

apportioning the heat input rate monitored at

a common stack or common pipe using steam

load should apportion the heat input rate

using the following equation:
28190 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

HI HI t

t

SF t

SF t

i CS

CS

i

i i

i i

i

n = 



 





























 =  ∑

1

(Eq. F–21b)

Where:

HIi=Heat input rate for a unit, mmBtu/hr.

HICS=Heat input rate at the common stack or

pipe, mmBtu/hr.

SF=Gross steam load, lb/hr.

ti=Operating time at a particular unit, hour or

fraction of an hour (in equal increments

that can range from one hundredth to

one quarter of an hour, at the option of

the owner or operator).

tCS=Operating time at common stack, hour or

fraction of an hour (in equal increments

that can range from one hundredth to

one quarter of an hour, at the option of

the owner or operator).

n=Total number of units using the common

stack.

i=Designation of a particular unit.

5.7 Heat Input Rate Summation for Units

with Multiple Stacks or Pipes

The owner or operator of an affected unit

that determines the heat input rate at the unit

level by summing the heat input rates

monitored at multiple stacks or multiple

pipes should sum the heat input rates using

the following equation:

HI

HI t

t Unit

s s

s

n

Unit

= =

∑

1

(Eq. F–21c)

Where:

HIUnit=Heat input rate for a unit, mmBtu/hr.

HIs=Heat input rate for each stack or duct

leading from the unit, mmBtu/hr.

tUnit=Operating time for the unit, hour or

fraction of the hour (in equal increments

that can range from one hundredth to

one quarter of an hour, at the option of

the owner or operator).

ts=Operating time during which the unit is

exhausting through the stack or duct,

hour or fraction of the hour (in equal

increments that can range from one

hundredth to one quarter of an hour, at

the option of the owner or operator).

72. Section 8 of appendix F to part 75

is added to read as follows:

8. Procedures for NOX Mass Emissions

The owner or operator of a unit that is

required to monitor, record, and report NOX

mass emissions under a state or federal NOX

mass emission reduction program must use

the procedures in section 8.1 to account for

hourly NOX mass emissions, and the

procedures in section 8.2 to account for

quarterly, seasonal, and annual NOX mass

emissions if the provisions of subpart H of

this part are adopted as requirements under

such a program.

8.1 Use the following procedures to

calculate hourly NOX mass emissions in lbs

for the hour.

8.1.1 If both NOX emission rate and heat

input are monitored at the same unit or stack

level (e.g, the NOX emission rate value and

heat input value both represent all of the

units exhausting to the common stack), use

the following equation:

M E HI t NO h h h Xh =

(Eq. F–23)

Where:

MNOx(h)=NOX mass emissions in lbs for the

hour.

Eh=Hourly average NOX emission rate for

hour h, lb/mmBtu.

Hih=Hourly average heat input rate for hour

h, mmBtu/hr.

th=Monitoring location operating time for

hour h, in hours or fraction of an hour

(in equal increments that can range from

one hundredth to one quarter of an hour,

at the option of the owner or operator).

If the combined NOX emission rate and

heat input are monitored for all of the

units in a common stack, the monitoring

location operating time is equal to the

total time when any of those units was

exhausting through the common stack.

8.1.2 If NOX emission rate is measured at

a common stack and heat input is measured

at the unit level, sum the hourly heat inputs

at the unit level according to the following

formula:

HI

HI t

t CS

u u

u

p

CS

= =

∑

1

(Eq. F–24)

Where:

HICS=Hourly average heat input rate for hour

h for the units at the common stack,

mmBtu/hr.

tCS=Common stack operating time for hour h,

in hours or fraction of an hour (in equal

increments that can range from one

hundredth to one quarter of an hour, at

the option of the owner or operator)(e.g.,

total time when any of the units which

exhaust through the common stack are

operating).

HIu=Hourly average heat input rate for hour

h for the unit, mmBtu/hr.

tu=Unit operating time for hour h, in hours

or fraction of an hour (in equal

increments that can range from one

hundredth to one quarter of an hour, at

the option of the owner or operator). Use

the hourly heat input rate at the common

stack level and the hourly average NOX

emission rate at the common stack level

and the procedures in section 8.1.1 of

this appendix to determine the hourly

NOX mass emissions at the common

stack.

8.1.3 If a unit has multiple ducts and

NOX emission rate is only measured at one

duct, use the NOX emission rate measured at

the duct, the heat input measured for the

unit, and the procedures in section 8.1.1 of

this appendix to determine NOX mass

emissions.

8.1.4 If a unit has multiple ducts and

NOX emission rate is measured in each duct,

heat input shall also be measured in each

duct and the procedures in section 8.1.1 of

this appendix shall be used to determine

NOX mass emissions.

8.2 Use the following procedures to

calculate quarterly, cumulative ozone season,

and cumulative yearly NOX mass emissions,

in tons:

M

M

NO

NO

h

p

X

X h

( )

( )

time period = =

∑

1

2000

(Eq. F–25)

Where:

M(NOX)time period=NOX mass emissions in tons

for the given time period (quarter,

cumulative ozone season, cumulative

year-to-date).

M(NOX)h=NOX mass emissions in lbs for the

hour.

p=The number of hours in the given time

period (quarter, cumulative ozone

season, cumulative year-to-date).

8.3 Specific provisions for monitoring

NOX mass emissions from common stacks.

The owner or operator of a unit utilizing a

common stack may account for NOX mass

emissions using either of the following

methodologies, if the provisions of subpart H

are adopted as requirements of a state or

federal NOX mass reduction program:

8.3.1 The owner or operator may

determine both NOX emission rate and heat

input at the common stack and use the

procedures in section 8.1.1 of this appendix

to determine hourly NOX mass emissions.

8.3.2 The owner or operator may

determine the NOX emission rate at the

common stack and the heat input at each of

the units and use the procedures in section

8.1.2 of this appendix to determine the

hourly NOX mass emissions.

APPENDIX G TO PART 75—

DETERMINATION OF CO2 EMISSIONS

* * * * *

73. Section 2 of appendix G to part 75

is amended by revising the term ‘‘Wc’’

that follows Equation G–1 to read as

follows:
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28191

2. Procedures for Estimating CO2 Emissions

From Combustion

2.1 * * *

(Eq. G–1)

Where:

* * * * *

WC=Carbon burned, lb/day, determined

using fuel sampling and analysis and

fuel feed rates. Collect at least one fuel

sample during each week that the unit

combusts coal, one sample per each

shipment for oil and diesel fuel, and one

fuel sample for each delivery for gaseous

fuel in lots, for each daily gas sample for

gaseous fuel delivered by pipeline, or for

each monthly sample of pipeline natural

gas. Collect coal samples from a location

in the fuel handling system that provides

a sample representative of the fuel

bunkered or consumed during the week.

Determine the carbon content of each

fuel sampling using one of the following

methods: ASTM D3178–89 or ASTM

D5373–93 for coal; ASTM D5291–92

‘‘Standard Test Methods for Instrumental

Determination of Carbon, Hydrogen, and

Nitrogen in Petroleum Products and

Lubricants,’’ ultimate analysis of oil, or

computations based upon ASTM D3238–

90 and either ASTM D2502–87 or ASTM

D2503–82 (Reapproved 1987) for oil; and

computations based on ASTM D1945–91

or ASTM D1946–90 for gas. Use daily

fuel feed rates from company records for

all fuels and the carbon content of the

most recent fuel sample under this

section to determine tons of carbon per

day from combustion of each fuel. (All

ASTM methods are incorporated by

reference under § 75.6). Where more than

one fuel is combusted during a calendar

day, calculate total tons of carbon for the

day from all fuels.

* * * * *

74. Appendix G to part 75 is amended

by adding a new section 5 and Table

G–1 to read as follows:

5. Missing Data Substitution Procedures for

Fuel Analytical Data

Use the following procedures to substitute

for missing fuel analytical data used to

calculate CO2 mass emissions under this

appendix.

5.1 Missing Carbon Content Data Prior to

1/1/2000

Prior to January 1, 2000, follow either the

procedures of this section or the procedures

of section 5.2 of this appendix to substitute

for missing carbon content data. On and after

January 1, 2000, use the procedures of

section 5.2 of this appendix to substitute for

missing carbon content data, not the

procedures of this section.

5.1.1 Most Recent Previous Data

Substitute the most recent, previous carbon

content value available for that fuel type (gas,

oil, or coal) of the same grade (for oil) or rank

(for coal). To the extent practicable, use a

carbon content value from the same fuel

supply. Where no previous carbon content

data are available for a particular fuel type or

rank of coal, substitute the default carbon

content from Table G–1 below.

5.1.2 [Reserved]

5.2 Missing Carbon Content Data on and

After 1/1/2000

Prior to January 1, 2000, follow either the

procedures of this section or the procedures

of section 5.1 of this appendix to substitute

for missing carbon content data. On and after

January 1, 2000, use the procedures of this

section to substitute for missing carbon

content data.

5.2.1 Missing Weekly Samples

If carbon content data are missing for

weekly coal samples or composite oil

samples from continuous sampling,

substitute the highest carbon content from

the previous four carbon samples available.

If no previous carbon content data are

available, use the default carbon content from

Table G–1, below.

5.2.2 Manual Sample From Storage Tank

If carbon content data are missing for

manual oil or diesel fuel samples taken from

the storage tank after transfer of a new

delivery of fuel, substitute the highest carbon

content from all samples in the previous

calendar year. If no previous carbon content

data are available from the previous calendar

year, use the default carbon content from

Table G–1, below.

5.2.3 As-Delivered Sample

If carbon content data are missing for asdelivered samples of oil, diesel fuel, or

gaseous fuel delivered in lots, substitute the

highest carbon content from all deliveries of

that fuel in the previous calendar year. If no

previous carbon content data are available for

that fuel from the previous calendar year, use

the default carbon content from Table G–1,

below.

5.2.4 Sample of Gaseous Fuel Supplied by

Pipeline

If carbon content data are missing for a

gaseous fuel that is supplied by a pipeline

and sampled on either a monthly or a daily

basis for sulfur and gross calorific value,

substitute the highest carbon content

available for that fuel from the previous

calendar year. If no previous carbon content

data are available for that fuel from the

previous calendar year, use the default

carbon content from Table G–1, below.

TABLE G–1.—MISSING DATA SUBSTITUTION PROCEDURES FOR MISSING CARBON CONTENT DATA

Parameter Sampling technique/frequency Missing data substitution procedure

Oil and coal carbon content All oil and coal samples, prior to January 1, 2000 ......... Most recent, previous carbon content value available

for that grade of oil.

Weekly coal sample or Flow proportional/weekly composite oil sample (beginning no later than January 1,

2000).

Highest carbon in previous 4 weekly samples.

In storage tank (after addition of fuel to tank) (beginning no later than January 1, 2000).Maximum carbon content from all samples in previous

calendar year.

As delivered (in delivery truck or barge) (beginning no

later than January 1, 2000).

Maximum carbon content from all deliveries in previous

calendar year.

Gas carbon content .............. All gaseous fuel samples, prior to January 1, 2000 ....... Most recent, previous carbon content value available

for that type of gaseous fuel.

Gaseous fuel in lots—as-delivered sampling (beginning

no later than January 1, 2000).

Maximum carbon content of all samples in previous

calendar year.

Gaseous fuel delivered by pipeline that is sampled for

sulfur content—daily sampling (beginning no later

than January 1, 2000).

Maximum carbon content of all samples in previous

calendar year.

Pipeline natural gas that is not sampled for sulfur content—monthly sampling for GCV and carbon only

(beginning no later than January 1, 2000).

Maximum carbon content of all samples in previous

calendar year.

Default coal carbon content All .................................................................................... Anthracite: 90.0 percent.

Bituminous: 85.0 percent.

Subbituminous/Lignite: 75.0 percent.

Default oil carbon content .... All .................................................................................... 90.0 percent.
28192 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

TABLE G–1.—MISSING DATA SUBSTITUTION PROCEDURES FOR MISSING CARBON CONTENT DATA—Continued

Parameter Sampling technique/frequency Missing data substitution procedure

Default gas carbon content .. All .................................................................................... Natural gas: 75.0 percent.

Other gaseous fuels: 90.0 percent.

5.3 Gross Calorific Value Data

For a gas-fired unit using the procedures of

section 2.3 of this appendix to determine CO2

emissions, substitute for missing gross

calorific value data used to calculate heat

input by following the missing data

procedures for gross calorific value in section

2.4 of appendix D to this part.

Appendix H To Part 75—Revised

Traceability Protocol No. 1

75. Appendix H to part 75 is removed

and reserved.

76. Appendix I to part 75 is added as

follows:

Appendix I To Part 75—Optional FFactor/Fuel Flow Method

1. Applicability

1.1 This procedure may be used in lieu of

continuous flow monitors for the purpose of

determining volumetric flow from gas-fired

units, as defined in § 72.2 of this chapter, or

oil-fired units, as defined in § 72.2 of this

chapter, provided that the units burn only

pipeline natural gas, natural gas, and/or fuel

oil. These procedures use fuel flow

measurement, fuel sampling data, CO2 (or O2)

CEMS data, and F-factors to determine the

flow rate of the stack gas. These procedures

may only be used during those hours when

only one type of fuel is combusted.

1.2 Apply to the Administrator, in a

certification application, for approval to use

this method in lieu of a continuous flow

monitor, no later than the deadlines for the

certification of continuous emission

monitoring systems specified in §§ 75.20 and

75.63.

2. Procedure

2.1 Initial Certification and Recertification

Testing

Either of the following procedures may be

used to perform initial certification and

recertification testing of the appendix I

excepted flow monitoring system:

2.1.1 Component-by-Component

Certification Testing

Test both the fuel flowmeter component

and the CO2 (or O2) monitor component

separately, following the procedures of this

part. Determine BAFSystem and BAFCO2 or

BAFO2, using the procedures in section 3.7 of

this appendix.

2.1.1.1 Certification of the Fuel Flowmeter

Test the fuel flowmeter according to the

procedures and performance specifications in

section 2.1.5 of appendix D to this part.

2.1.1.2 Certification of the CO2 (or O2)

Monitor

Test the CO2 or O2 monitor according to

the procedures and performance

specifications in appendix A to this part.

Notwithstanding the requirements of

appendix A to this part, calculate the BAF of

the CO2 or O2 monitor according to section

3.7 of this appendix.

2.1.2 System Certification Testing

Test the entire appendix I flow monitoring

system to meet the relative accuracy

requirements for flow, as found in section

3.3.4 of appendix A to this part, using the

applicable procedures in sections 6.5 through

6.5.2.2 of appendix A to this part. Use the

fuel sampling data for density and carbon

content to calculate the hourly volumetric

flow rate according to section 2.3 of this

appendix. Perform the bias test and, if

necessary, calculate a bias adjustment factor

for the appendix I flow monitoring system

using the procedures in section 7.6 of

appendix A to this part. Also perform the 7-

day calibration error test, cycle time test, and

linearity check on the CO2-or O2-diluent

monitor.

2.2 On-Going Quality Assurance Testing

2.2.1 Daily Assessments

The CO2 or O2 monitor shall meet the daily

assessment requirements in section 2.1 of

appendix B to this part.

2.2.2 Quarterly Assessments

The CO2 or O2 monitor shall meet the

quarterly assessment requirements in section

2.2 of appendix B to this part.

2.2.3 Semiannual or Annual Assessments

2.2.3.1 Component-by-Component

Assessments

Test both the fuel flowmeter and the CO2

(or O2) monitor separately. Determine

BAFSystem and BAFCO2 or BAFO2 using the

procedures in section 3.7 of this appendix.

2.2.3.1.1 Assessment of the Fuel Flowmeter

The fuel flowmeter shall meet the periodic

quality assurance requirements in section

2.1.6 of appendix D to this part. The fuel

flowmeter shall meet the flowmeter accuracy

specification in section 2.1.5 of appendix D

to this part.

2.2.3.1.2 Relative Accuracy Assessment of

the CO2 (or O2) Monitor

Test the CO2 or O2 monitor for relative

accuracy according to the applicable

procedures in sections 6.5 through 6.5.2.2 of

appendix A to this part. Determine the

relative accuracy test frequency (i.e.,

semiannual or annual) using section 2.3.1

and figure 2 in appendix B to this part.

Perform the bias test and calculate any bias

adjustment factor, as specified in section

3.7.1 of this appendix for the CO2 monitor or

as specified in section 3.7.2 of this appendix

for the O2 monitor.

2.2.3.2 System Relative Accuracy

Assessment

Test the entire appendix I flow monitoring

system to meet the relative accuracy

requirements for flow, as found in section

3.3.4 of appendix A to this part, using the

procedures in section 6.5.2 of appendix A to

this part. Use Reference Method 2 (or its

allowable alternatives) in appendix A to part

60 of this chapter to obtain the reference

method flow rate value for each run. Use the

appropriate equation selected from Eq. I–1

through Eq. I–9 to calculate the Appendix I

flow rate value for each RATA run. Base the

fuel sampling on section 2.3 of this appendix.

Determine the schedule for future relative

accuracy tests using the provisions of section

2.3.1 and figure 2 of appendix B to this part

for a flow monitoring system. Perform the

bias test and, if necessary, calculate a bias

adjustment factor for the appendix I flow

monitoring system using the procedures in

section 7.6 of appendix A to this part.

2.3 Fuel Sampling and Analysis

2.3.1 Carbon Content of Oil

Determine carbon content of the oil by

using the following procedures. Collect at

least one sample per each shipment for oil

and diesel fuel. Determine the carbon content

of the fuel sampling using one of the

following methods: ASTM D5291–92

‘‘Standard Test Methods for Instrumental

Determination of Carbon, Hydrogen, and

Nitrogen in Petroleum Products and

Lubricants,’’ ultimate analysis of oil, or

computations based upon ASTM D3238–90

and either ASTM D2502–87 or ASTM

D2503–82 (Reapproved 1987) for oil.

2.3.2 Density of Oil

Determine the density of oil using the

procedures in section 2.2 of appendix D to

this part.

2.3.3 Gross Calorific Value of Natural Gas

Determine gross calorific value of natural

gas by using the procedures in section 5.5.2

of appendix F to this part.

3. Calculations

3.1 Hourly Volumetric Flow during

Combustion of Oil Only for Systems that Use

a CO2 Monitor and a Volumetric Oil

Flowmeter

Q V C

CO s = 32 08 × × ×

2

. %

%

ρ

(Eq. I–1)
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28193

Where:

Qs=Volumetric stack flow rate, adjusted for

bias, in scfh.

BAFsystem=Bias adjustment factor for the

system, as determined by Equation I–

10A or I–10B (for component-bycomponent testing) in section 3.7 of this

appendix or by Equation I–11 (for system

testing) in section 3.8 of this appendix.

V=Volumetric oil flow rate, gal/hr.

ρ=Oil density, lb/gal.

%C=Percent carbon by weight.

%CO2=CO2 concentration, percent by

volume.

32.08=Conversion factor, 385 scf CO2/12 lb C,

volume of CO2 emitted for each pound

carbon in oil.

3.2 Hourly Volumetric Flow during

Combustion of Oil Only for Systems that Use

an O2 Monitor and a Volumetric Oil

Flowmeter

3.2.1 If relative accuracy is determined on

a system basis, use the following equation to

determine the volumetric stack flow rate:

Q

BAF V C

O H O s

d

= × × × × ×

( ) − × − ( )

207 6379 20 9 100

20 9 100 2 2

. % ( . )( )

. % %

system ρ

(Eq. I–2)

Where:

Qs=Volumetric stack flow rate, adjusted for bias, in scfh.

BAFsystem=Bias adjustment factor for the system, as determined by Equation I–11 (for system testing) in section 3.8 of this appendix.

V=Volumetric oil flow rate, gal/hr.

ρ=Oil density, lb/gal.

%C=Percent carbon by weight.

%O2d=Dry basis O2 concentration, percent by volume.

%H2O=Percent moisture in the flue gas.

207.6379=Conversion factor, 385 scf CO2/12 lb C×9190 dscf O2/1420 scf CO2, volume of O2 emitted for each pound carbon in oil.

3.2.2 If relative accuracy is determined on a component by component basis, use the following equation to determine the volumetric

stack flow rate:

Q V C

BAF O H O s

O d

= × × × × ×

[ ] − × ( ) × − ( )

207 6379 112 20 9 100

20 9 100 2 2 2

. . % ( . )( )

. % %

ρ

(Eq. I–3)

Where:

Qs Volumetric stack flow rate, adjusted for

bias, in scfh.

BAFO2=Bias adjustment factor for the O2

monitor, as determined by section 3.7.2

of this appendix.

V=Volumetric oil flow rate, gal/hr.

ρ=Oil density, lb/gal.

%C=Percent carbon by weight.

%O2d=Dry basis O2 concentration, percent by

volume.

%H2O=Percent moisture in the flue gas.

1.12=Default multiplier used to compensate

for systematic error in the demonstration

data.

207.6379=Conversion factor, 385 scf CO2/12

lb C×9190 dscf O2/1420 scf CO2, volume

of O2 emitted for each pound carbon in

oil.

3.3 Hourly Volumetric Flow during

Combustion of Oil Only for Systems that Use

a CO2 Monitor and a Mass Oil Flowmeter

Q

BAF M C

CO s = 32 08 × × ×

2

. %

%

system

(Eq. I–4)

Where:

Qs=Volumetric stack flow rate, adjusted for

bias, in scfh.

BAFsystem=Bias adjustment factor for the

system, as determined by Equation I–

10A or I–10B (for component by

component testing) in section 3.7 of this

appendix or by Equation I–11 (for system

testing) in section 3.8 of this appendix.

M=Oil mass flow rate, lb/hr.

%C=Percent carbon by weight.

%CO2=CO2 concentration, percent by

volume.

32.08=Conversion factor, 385 scf CO2/12 lb C,

volume of CO2 emitted for each pound

carbon in oil.

3.4 Hourly Volumetric Flow during

Combustion of Oil Only for Systems that Use

an O2 Monitor and a Mass Oil Flowmeter

3.4.1 If relative accuracy is determined on

a system basis, use the following equation to

determine the volumetric stack flow rate:

Q

BAF M C

O H O s

d

= × × × ×

( ) − × − ( )

207 6379 20 9 100

20 9 100 2 2

. % ( . )( )

. % %

system

(Eq. I–5)

Where:

Qs=Volumetric stack flow rate, adjusted for

bias, in scfh.

BAFsystem=Bias adjustment factor for the

system, as determined by Equation I–11

(for system testing) in section 3.8 of this

appendix.

M=Oil mass flow rate, lb/hr.

%C=Percent carbon by weight.

%O2d=Dry basis O2 concentration, percent by

volume.

%H2O=Percent moisture in the flue gas.

207.6379=Conversion factor, 385 scf CO2/12

lb C×9190 dscf O2/1420 scf CO2, volume

of O2 emitted for each pound carbon in

oil.

3.4.2 If relative accuracy is determined on

a component by component basis, use the

following equation to determine the

volumetric stack flow rate:

Q M C

BAF O H O s

O d

= × × × ×

[ ] − × ( ) × − ( )

207 6379 112 20 9 100

20 9 100 2 2 2

. . % ( . )( )

. % %
28194 Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules

(Eq. I–6)

Where:

Qs=Volumetric stack flow rate, adjusted for

bias, in scfh.

BAFO2=Bias adjustment factor for the O2

monitor, as determined by section 3.7.2

of this appendix.

M=Oil mass flow rate, lb/hr.

%C=Percent carbon by weight.

%O2d=Dry basis O2 concentration, percent by

volume.

%H2O=Percent moisture in the flue gas.

1.12=Default multiplier used to compensate

for systematic error in the demonstration

data.

207.6379=Conversion factor, 385 scf CO2/12

lb C×9190 dscf O2/1420 scf CO2, volume

of O2 emitted for each pound carbon in

oil.

3.5 Hourly Volumetric Flow during

Combustion of Natural Gas Only for Systems

that Use a CO2 Monitor and a Volumetric Gas

Flowmeter

Q

BAF V GCV F

CO s

c = 0 01× × × ×

2

.

%

system

(Eq. I–7)

Where:

Qs=Volumetric stack flow rate, adjusted for

bias, in scfh.

BAFsystem=Bias adjustment factor for the

system, as determined by Equation I–

10A or I-10B (for component by

component testing) in section 3.7 of this

appendix or by Equation I–11 (for system

testing) in section 3.8 of this appendix.

V=Volumetric gas flow rate, 100 scfh.

GCV=Gross calorific value of the gaseous

fuel, Btu/scf.

Fc=Carbon-based F-factor of 1040 scf CO2/

mmBtu for natural gas, from section 3 of

appendix F to this part.

%CO2=CO2 concentration, percent by

volume.

0.01=Conversion factor, 10¥6 mmBtu/

Btu×102 scf/100 scf×102 (conversion of

fraction to percentage).

3.6 Hourly Volumetric Flow during

Combustion of Natural Gas Only for Systems

that Use an O2 Monitor and a Volumetric Gas

Flowmeter

3.6.1 Determining Flow for Systems that

Are Tested on a System Basis

Q

BAF V GCV F

O H O s

d

d

= × × × × ×

( ) − × − ( )

0 01 20 9 100

20 9 100 2 2

. ( . )( )

. % %

system

(Eq. I–8)

Where:

Q2=Volumetric stack flow rate, adjusted for

bias, in scfh.

BAFsystem=Bias adjustment factor for the

system, as determined by Equation I–11

(for system testing) in section 3.8 of this

appendix.

V=Volumetric gas flow rate, 100 scfh.

GCV=Gross calorific value of the natural gas,

Btu/scf.

Fd=Dry basis, O2-based F-factor for natural

gas, 8,710 dscf/mmBtu.

%O2d=Dry basis O2 concentration, percent by

volume.

%H2O=Percent moisture in the flue gas.

0.01=Conversion factor, 10¥6 mmBtu/Btu x

102 scf/100 scf×102 (conversion of

fraction to percentage).

3.6.2 Determining Flow for Systems that are

Tested on a Component-by-Component Basis

Q V GCV F

BAF O H O s d

O d

= × × × × ×

[ ] − × ( ) × − ( )

0 01 112 20 9 100

20 9 100 2 2 2

. . ( . )( )

. % %

(Eq. I–9)

Where:

Qs=Volumetric stack flow rate, adjusted for

bias, in scfh.

BAFO2=Bias adjustment factor for the O2

monitor, as determined by section 3.7.2

of this appendix.

V=Volumetric gas flow rate, 100 scfh.

GCV=Gross calorific value of the natural gas,

Btu/scf.

Fd=Dry basis, O2-based F-factor for natural

gas, 8,710 dscf/mmBtu.

%O22d=Dry basis O2 concentration, percent

by volume.

%Hd2O=Percent moisture in the flue gas.

1.12=Default multiplier used to compensate

for systematic error in the demonstration

data.

0.01=Conversion factor, 10–6 mmBtu/Btu x

102 scf/100 scf x 102 (conversion of

fraction to percentage).

3.7 Bias Adjustment Factor for a System

Tested Component-by-Component

3.7.1 Calculation of the System Bias

Adjustment Factor, BAFsystem, for CO2

Monitor

Calculate the mean difference of the

relative accuracy test data for the CO2

monitor, d ̄, using Equation A–7 in section

7.3.1 of appendix A to this part. Calculate the

confidence coefficient (cc) using Equation A–

9 in section 7.3.3 of appendix A to this part.

If d ̄ < -cc, where d ̄ is defined by Equation A–

7, calculate the bias adjustment factor for a

system tested component by component, as

follows:

BAF

d

CEM

system =

+ 



 





112

1

.

(Eq. I–10A)

If d ≥ -cc, then

BAFsystem=1.12

(Eq. I–10B)

Where:

BAFsystem=Overall bias adjustment factor for

the appendix I flow monitoring system.

1.12=Default multiplier used to compensate

for systematic error in the demonstration

data.

d

 ̄=Mean difference between the reference

method and continuous emission

monitoring system (RMi-CEMi) as

defined in Equation A–7 in section 7.3.1

of appendix A to this part.

C ̄ E ̄M ̄ =Mean of the data values provided by

the CO2 monitor during the relative

accuracy test audit.

3.7.2 Calculation of the Component Bias

Adjustment Factor, BAFO2, for O2 Monitor

Perform the bias test for the O2 monitor

using the procedures in section 7.6 of

appendix A to this part and, if necessary,

calculate a bias adjustment factor.

3.8 Bias Adjustment Factor for a System

Tested on a System Level

Calculate the bias adjustment factor for a

system tested on a system level, as follows:

BAFSystem=GAFflow rate

(Eq. I–11)

Where:

BAFsystem=Overall bias adjustment factor for

the appendix I flow monitoring system.

BAFflow rate=Bias adjustment factor from

relative accuracy testing using Reference

Method 2 for volumetric flow rate.

4. Missing Data

4.1 The owner or operator shall provide

substitute volumetric flow data using the

flow missing data procedures in subpart D of

this part.

4.2 [Reserved]

5. Recordkeeping and Reporting

Follow the applicable monitoring plan

provisions of § 75.53, the applicable general

recordkeeping provisions of § 75.57, the

specific recordkeeping provisions of

§ 75.58(g), the certification recordkeeping

provisions of § 75.59(d)(1), and the quality

assurance test recordkeeping provisions of

§ 75.59(d)(2). Maintain a quality assurance/

quality control plan, as specified in appendix
Federal Register / Vol. 63, No. 98 /Thursday, May 21, 1998 / Proposed Rules 28195

B to this part. Follow the reporting

provisions of §§ 75.60 through 75.67.

77. Appendix J to part 75 is removed

and reserved.

[FR Doc. 98–11749 Filed 5–20–98; 8:45 am]

BILLING CODE 6560–50–P

ENVIRONMENTAL PROTECTION

AGENCY

40 CFR Part 75

[FRL–6007–7]

RIN 2060–AH64

Acid Rain Program: Determinations

under EPA Study of Bias Test and

Relative Accuracy and Availability

Analysis

AGENCY: Environmental Protection

Agency (EPA).

ACTION: Notice of proposed

determinations and proposed

rulemakings.

SUMMARY: Title IV of the Clean Air Act

Amendments of 1990 (the Act)

authorizes EPA to establish a program to

reduce the adverse effects of acidic

deposition. The Act requires electric

utilities affected by the Acid Rain

Program to install continuous emission

monitoring systems (CEMS) to measure

emissions of sulfur dioxide (SO2),

nitrogen oxides (NOX), and carbon

dioxide (CO2). On January 11, 1993,

Continuous Emission Monitoring

regulations were published. They

established procedures and

requirements for installing, certifying,

operating, and quality assuring CEMS at

Acid Rain affected utility units. In

response to comments and litigation

from representatives of the electric

utility industry and environmental

advocacy groups, provisions were

incorporated in the CEMS regulations

requiring EPA to conduct studies, reach

determinations, and, if necessary,

initiate rulemakings on the

appropriateness of retaining or revising

three elements in the CEMS regulations:

the bias test, relative accuracy test, and

the availability trigger conditions of the

Missing Data Substitution Procedure.

This Notice of Proposed Rulemaking

presents EPA’s proposed determinations

and consequent proposed rule revisions.

DATES: Comments. Comments on the

proposed determinations and rule

revisions must be received on or before

July 6, 1998.

Public Hearing. Anyone requiring a

public hearing must contact EPA no

later than June 1, 1998. If a hearing is

held, it will take place June 5, 1998,

beginning at 10:00 a.m.

ADDRESSES: Comments. All written

comment must be identified with the

appropriate docket number (Docket No.

A–97–56) and must be submitted in

duplicate to EPA Air Docket Section

(6102), Waterside Mall, Room M1500,

1st Floor, 401 M Street, SW,

Washington, D.C. 20460.

Public Hearing. If a public hearing is

requested, it will be held at the

Environmental Protection Agency, 401

M Street, SW, Washington, D.C. 20460,

in the Education Center Auditorium.

Refer to the Acid Rain homepage at

www.epa.gov/acidrain for more

information or to determine if a public

hearing has been requested and will be

held.

Docket. Docket No. A–97–56,

containing supporting information used

to develop the proposed determinations

and rule revisions is available for public

inspection and copying from 8:00 a.m.

to 5:30 p.m., Monday through Friday,

excluding legal holidays, at EPA’s Air

Docket Section at the above address.

FOR FURTHER INFORMATION CONTACT:

Elliot Lieberman at (202) 564 9136, Acid

Rain Division (6204J), U.S.

Environmental Protection Agency, 401

M St., S.W., Washington, D.C. 20460; or

the Acid Rain Hotline at (202) 564 9620.

Electronic copies of this notice and

technical support documents can be

accessed through the Acid Rain Division

website at http://www.epa.gov/acidrain.

SUPPLEMENTARY INFORMATION:

I. EPA Studies Under 40 CFR 75.7

A. Background

B. Collaborative Field Study

C. Certification Test Study

D. Proposed Findings and Conclusions

II. EPA Analyses in Response to 40 CFR 75.8

A. Background

B. Relative Accuracy

C. Availability Trigger Conditions for

Missing Data Substitution Procedure

III. Proposed Rule Revisions

IV. Administrative Requirements

A. Executive Order 12866

B. Unfunded Mandates Act

C. Paperwork Reduction Act

D. Regulatory Flexibility

I. EPA Studies Under 40 CFR 75.7

A. Background

To ensure a consistent level of

precision and accuracy in the emission

measurements obtained across the Acid

Rain Program, Part 75 of the Acid Rain

regulations requires a series of

performance tests to be conducted on

each CEMS both at initial certification

and periodically thereafter. Among the

required performance tests is the

relative accuracy test audit (RATA) in

which a minimum of nine simultaneous

measurements are taken from a unit’s

installed CEMS and an EPA approved

reference method. The paired RATA

data are then subjected to two statistical

tests: The relative accuracy test, which

establishes the degree of accuracy of the

CEMS relative to the reference method;

and the bias test, which uses a t-statistic

to determine if the CEMS measurements

are consistently lower than the reference

method measurements. See 40 CFR Part

75, Appendix A and B.

As stated in the preamble of the

January 1993 regulations, EPA found

that ‘‘both statistical theory and field

test results show that the bias test is a

sound and effective statistical procedure

for detecting consistent measurement

error in the long-term operation of a

CEMS’’ (58 FR 3590, 3627 (1993)).

However, at the time of promulgation of

the Acid Rain regulations, although

utilities had extensive experience with

the relative accuracy test, they had

virtually no previous experience with

the bias test. This unfamiliarity led to

several concerns with the bias test.

Thus, the January 1993 regulations

committed EPA to conduct field studies

to determine ‘‘whether there are

statistically significant variances’’ in the

EPA-approved reference methods that

utilities use to test the performance of

the CEMS installed under the Acid Rain

Program and ‘‘whether the bias test

should be adjusted to compensate for

statistical variances in the reference

method’’ (58 FR 3628).

In particular, EPA was required to:

1. Investigate whether there are

statistically significant variances in the

EPA reference methods (Issue #1);

2. Distinguish between the variability

in reference monitor readings

attributable to measurement error and

the variability due to the choice of

reference monitor among those certified

by the Agency (Issue #2);

3. Investigate possible differences in

bias test failure rates by emission levels

(Issue #3); and

4. Assess whether any adjustments are

necessary to properly determine

measurement bias (Issue #4).

The regulations called for the

completion of a study addressing these

issues by October 31, 1993. In response,

EPA conducted two studies. The first

was a collaborative field study,

involving four independent reference

method test teams, at Big Rivers Electric

Corporation’s Green Generating Station,

Unit 2, in Sebree, Kentucky. This

location was specifically selected for

testing because its relatively low range

of SO2 emission concentrations (from 56

ppm to 231 ppm) would allow EPA to

examine bias test failure rates at SO2

emission levels different from those

prevailing in previous field studies and

consider an industry concern that