31978 Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules

ENVIRONMENTAL PROTECTION

AGENCY

40 CFR Parts 72, 75, 78, and 97

[FRL–6984–8]

RIN 2060–AJ43

Revisions to the Federal NOX Budget

Trading Program, the Emissions

Monitoring Provisions, the Permits

Regulation Provisions, and the Appeal

Procedures

AGENCY: Environmental Protection

Agency (EPA).

ACTION: Proposed rule.

SUMMARY: EPA is proposing rule

revisions that would modify the existing

requirements for sources affected by the

Federal NOX Budget Trading Program,

the Acid Rain Program, and the October

27, 1998 NOX SIP Call. The proposed

revisions would streamline and add

flexibility to the monitoring and

reporting requirements in response to

the significant changes that have

occurred in power generation in recent

years due to deregulation and recent

environmental actions initiated by EPA

to reduce nitrogen oxides emissions.

This proposed action would also make

certain technical corrections, remove

outdated provisions, and correct

printing, typographical, and

grammatical errors to correct or clarify

cross references, and, in a few instances,

to ensure that the specific rule language

is consistent with the Agency’s intent.

DATES: Comments. All public comments

must be received on or before July 30,

2001.

Public Hearing. Anyone requesting a

public hearing must contact EPA no

later than June 25, 2001. If a hearing is

held, it will take place June 27, 2001,

beginning at 10 a.m.

ADDRESSES: Comments. Comments must

be mailed (in duplicate if possible) to:

EPA Air Docket (6102), Attention:

Docket No. A–2000–33, 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 Clean Air Markets

homepage at www.epa.gov/airmarkets

for more information or to determine if

a public hearing has been requested and

will be held.

Docket. Docket No. A–2000–33,

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:

Gabrielle Stevens, Clean Air Markets

Division (6204N), U.S. Environmental

Protection Agency, Ariel Rios Building,

1200 Pennsylvania Avenue, NW.,

Washington, DC 20460, telephone

number (202) 564–2681 or the Acid

Rain Hotline at (202) 564–9620.

Electronic copies of this document and

technical support documents can be

accessed through the EPA Web site at:

http://www.epa.gov/airmarkets.

SUPPLEMENTARY INFORMATION: In

accordance with titles I and IV of the

Clean Air Act (CAA or the Act), EPA is

proposing rule revisions to support

previous actions the Agency has taken

to mitigate interstate transport of

nitrogen oxides as well as to reduce the

acidic deposition precursor emissions of

sulfur dioxide and nitrogen oxides

(NOX). Title I of the CAA, as amended

by the Clean Air Act Amendments of

1990, authorizes EPA, under section 126

of the Act, to require reductions of NOX

emissions from sources that emit in

violation of the CAA prohibition against

significantly contributing to ozone

nonattainment or maintenance problems

in a downwind State that petitions EPA

for relief. On January 18, 2000, EPA

published a section 126 finding that a

number of large electric generating units

and large industrial boilers and turbines

named in petitions filed by several

northeastern States emit NOX in

violation of the CAA. In that same

notice, the EPA finalized the Federal

NOX Budget Trading Program as the

control remedy for sources affected by

the rule. EPA originally promulgated 40

CFR parts 72, 75, and 78 on January 11,

1993, to implement the Acid Rain

Program as authorized by title IV of the

Act. EPA has subsequently promulgated

several final rules revising the January

11, 1993 rules. The most recent

revisions were promulgated on May 26,

1999. Finally, note that although today’s

proposal will not revise the Finding of

Significant Contribution and

Rulemaking for Certain States in the

Ozone Transport Assessment Group for

Purposes of Reducing the Transport of

Ozone ( NOX SIP call), promulgated on

October 27, 1998, under section 110 of

the Act, the proposed changes to the

monitoring and reporting provisions of

40 CFR part 75 (and related changes to

certain definitions in 40 CFR part 72)

will affect sources that are subject to the

NOX SIP call, since many of these

sources will be required to implement

part 75 emissions monitoring.

The provisions of 40 CFR parts 72, 75,

78, and 97 will be revised to modify the

existing requirements for sources

affected by the Acid Rain Program, the

Federal NOX Budget Trading Program,

and the October 27, 1998, NOX SIP call.

Today’s proposal is limited to the

specific provisions in parts 72, 75, 78,

and 97 identified and discussed here.

EPA is not considering reopening or

requesting public comment on any other

provisions of parts 72, 75, 78, or 97 or

of the section 126 or NOX SIP call

rulemaking.

A redline/strikeout version of 40 CFR

parts 72 and 75 as amended by this

proposed rule is available in the Docket

and on the EPA Web site referenced

above. 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. Rule Definitions

1. How does EPA propose to revise the

definitions of pipeline natural gas and

natural gas in § 72.2?

2. How does EPA propose to change the

definitions of unit and stack operating

hours?

3. What other definitions would be revised

or added to the rule?

B. Certification Timeline Issues

1. What is the deadline for an application

for initial certification?

2. For an appendix E peaking unit, when

is initial certification required while

combusting the backup fuel?

3. What happens if a unit loses peaking,

gas-fired, or LME status?

C. Missing Data

1. How will the proposed rule affect the

missing data procedures in §§ 75.31

through 75.37 for units that produce

electrical or thermal output?

2. How will subpart H missing data

provisions be affected for units that

produce electrical or thermal output?

3. What are the missing data requirements

for units that do not produce electrical

or thermal output?

4. How will today’s proposed rule revise

the procedures in appendix C for

establishing load ranges (or ‘‘bins’’) for

missing data purposes?

5. How will the maximum potential

moisture provision be revised?

6. How will the proposed rule affect the

method of determination codes?

D. Low Mass Emissions (LME) Units

1. What are the certification requirements

for low mass emissions (LME) units?

2. How does the LME methodology apply

to subpart H units?

3. When must the annual demonstration

for LME units be completed?

4. How should EPA Reference Method 20

be altered when determining a fuel-and

unit-specific NOX emission rate for an

LME unit?

5. What temperature and humidity

corrections are required for turbines

Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules 31979

when unit-and fuel-specific NOX

emission rates are determined for LME

units?

6. How is identical unit status

demonstrated for a group of LME units?

7. How is the fuel-and unit-specific NOX

emission rate determined for LME

turbines equipped with water injection,

steam injection, or water/fuel emulsion,

and no other type(s) of add-on NOX

controls?

8. What effect would today’s proposed rule

have on LME units sharing a common

fuel supply?

9. When would single load testing be

allowed to determine unit-and fuelspecific NOX emission rates for LME

units?

10. How are unit-specific, fuel-specific

NOX emission rates for LME units

determined from the individual test run

data at each load level?

11. Which mathematical equations are

affected by the proposed changes to

§ 75.19?

E. Conditionally Valid Data—Mandatory

Use

F. Quality Assurance/Quality Control (QA/

QC)

1. What changes are proposed for CEMS

span and range evaluations?

2. Will EPA allow use of two separate CEM

systems with separate probes and sample

interfaces to meet dual-range

requirements?

3. What changes would the proposed rule

make with regard to determining NOX

MPC, MEC, span, and range?

4. What revisions would be made to the 7-

day calibration error test for peaking

units?

5. What changes would be made to QA/QC

for units with very low NOX

concentrations?

6. When would EPA require the

application of a calibration correction

factor to linearity or RATA test data?

7. What changes would be made to the

flow-to-load ratio test?

8. When would three-load flow RATAs be

allowed for routine quality assurance?

9. What changes would be made to the data

analysis time period for single-load flow

RATA claims?

10. For units that do not produce electrical

output or steam load, at what operating

levels should gas and flow monitor

RATAs be performed?

G. Streamlining Changes

H. Monitoring Plan Information Submittal

1. What changes are proposed in the

timeline for monitoring plan updates?

2. Is EPA changing the process for

electronic submittal of monitoring plan

updates and certification/recertification

test results?

I. Appendix D—Miscellaneous Issues

J. Reporting and Recordkeeping

1. Will certification and recertification test

notice requirements change?

2. Will EPA continue to accept hardcopy

certification statements?

3. Will EPA allow the electronic storage of

quality assurance/quality control plan

information?

K. NOX Monitoring in Multiple Stacks/

Common Stacks

L. Appendix E Issues

1. How will the proposed rule affect

Appendix E test notifications and

submittal of hardcopy recertification test

results?

2. Will the frequency of retesting of

Appendix E units be changed?

3. How will the timeline for unscheduled

Appendix E retests be revised?

4. How will Appendix E missing data

procedures be changed?

5. How will the Appendix E testing

requirements for emergency fuel be

changed?

M. Reference Methods

1. Which Code of Federal Regulations

versions of reference methods are to be

used?

2. Are there other changes to reference

methods?

N. Appendix G Revisions

O. Technical Changes and Corrections

P. What other changes is EPA proposing to

the Federal NOX Budget Trading

Program today?

IV. Administrative Requirements

A. Public Hearing

B. Public Docket

C. Executive Order 12866

D. Unfunded Mandates Reform Act

E. Paperwork Reduction Act

F. Regulatory Flexibility

G. National Technology Transfer and

Advancement Act

H. Executive Order 13175

I. Executive Order 12898

J. Executive Order 13045

K. Executive Order 13132

I. Regulated Entities

Entities regulated by this action are

fossil fuel-fired boilers, turbines, and

combined cycle units that serve

generators which produce electricity,

generate steam, or cogenerate electricity

and steam. While part 75 primarily

regulates the electric utility industry,

certain State and Federal NOX mass

emission trading programs may rely on

subpart H of part 75, and those

programs may include boilers, turbines,

and combined cycle units from other

industries. Regulated categories and

entities include:

Category Examples of regulated

entities

Industry ................... (1) Electric service providers

(2) Process sources

with large boilers

and turbines where

emissions exhaust

through a stack

This table is not intended to be

exhaustive, but rather to provide a guide

for readers regarding entities likely to be

regulated by this action. This table lists

the types of entities which EPA is now

aware could potentially be regulated by

this action. Other types of entities not

listed in the table could also be

regulated. To determine whether your

facility, company, business,

organization, etc., is regulated by this

action, you should carefully examine

the applicability provisions in §§ 72.6,

72.7, and 72.8 of title 40 of the Code of

Federal Regulations and in 40 CFR parts

96 and 97. 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

Today’s proposed action modifies

existing monitoring and reporting

requirements in 40 CFR parts 72 and 75

that support emission control programs

that use the monitoring and reporting

provisions of part 75 such as the Acid

Rain Program and State NOX reduction

programs developed in response to the

October 27, 1998, NOX SIP call. The

emphasis of these revisions is threefold: (1) To streamline the rule by

eliminating outdated sections; (2) to

make technical corrections and

clarifications to the rule; and (3) to add

flexibility to the monitoring and

reporting requirements. The most

substantive proposed changes are as

follows: the definitions of ‘‘pipeline

natural gas’’ and ‘‘natural gas’’ in § 72.2

would be revised to remove all

references to the H2S content of the fuel

and would instead be based on total

sulfur content (corresponding changes

would be made to appendix D to part

75); the compliance and certification

timelines for certifying monitoring

systems would be made the same for

new units, newly affected units,

deferred units, and new stacks; the low

mass emissions (LME) units provisions

in § 75.19 would be clarified; for units

with certain types of NOX emission

controls, qualification as a LME unit

would be made easier; the CEMS

missing data procedures would be

revised to allow fuel-specific missing

data substitution as well as the use of a

controlled and uncontrolled database

for units with add-on emission controls;

the missing data procedures in subpart

H of part 75 would be expanded and

clarified for sources that report emission

data only in the ozone season; the NOX

span and range provisions in appendix

A would be revised to make them more

realistic and easier to implement for

combustion turbines; and the alternate

calibration error limit for daily

operation would be tightened from 10

ppm to 5 ppm for units with span

values of 50 ppm or less. Many of the

above changes to part 75 would affect

the monitoring and reporting sections of

31980 Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules

the part 97 rule. Therefore, today’s

proposed rule would also revise certain

sections of part 97 to make the

monitoring and reporting sections of the

part 75 and part 97 rules consistent. In

addition, certain miscellaneous changes

would be made to clarify or correct

minor errors in other sections of part 97

or to make the administrative appeal

procedures in part 78 applicable to

decisions of the Administrator under

part 97.

III. Detailed Discussion of Proposed

Revisions

A. Rule Definitions

EPA policy guidance and the

instructions EPA has developed for

monitoring and electronic reporting

under part 75 rely on many terms that

are used in part 75 but that are not

defined in § 72.2 (the definitions section

for all Acid Rain Program regulations).

Also, some of the existing definitions in

§ 72.2 are incorrect or incomplete. To

address these concerns, the proposed

revisions would add or modify several

definitions.

1. How Does EPA Propose To Revise the

Definitions of Pipeline Natural Gas and

Natural Gas in § 72.2?

Background. Following the May 26,

1999, rulemaking, a utility group sued

EPA over the definitions of ‘‘pipeline

natural gas’’ and ‘‘natural gas’’

contained in § 72.2. The issue is that

gaseous fuel must meet a two-fold

requirement to qualify as one of these

fuels. In the current rule, there is an H2S

content limit (0.3 gr/100 scf for pipeline

natural gas and 1.0 gr/100 scf for natural

gas) and a requirement that H2S

constitute more than 50 percent of the

total fuel sulfur content. Appendix D to

the rule does not explain how to comply

with the second of these two

requirements (the H2S as a percentage of

total sulfur requirement). Further,

industry members are concerned that

this requirement cannot be

implemented in a fair and consistent

manner. For example, a very clean fuel

with 0.1 gr/100 scf of H2S and 0.3 gr/

100 scf of total sulfur would not qualify

as pipeline natural gas, because H2S is

less than 50 percent of the total sulfur

content, but a fuel with three times

more H2S and twice as much total sulfur

(0.3 gr/100 scf of H2S and over 0.6 gr/

100 scf of total sulfur) would qualify as

pipeline natural gas under the current

rule. In response to the industry’s

concerns, EPA recently issued guidance

on how to demonstrate compliance with

the H2S content limit. As explained in

the guidance, EPA also granted a

petition allowing owners or operators to

meet total sulfur limits in lieu of the

H2S percent of-total-sulfur requirement.

Discussion of Proposed Changes. The

proposed rule would revise the

definitions of ‘‘pipeline natural gas’’ and

‘‘natural gas’’ in § 72.2. All references to

H2S content would be removed and

these fuels would be defined in terms of

total sulfur content. For the purposes of

determining SO2 emissions, it makes no

difference whether the fuel’s sulfur is in

the form of H2S or any other form. The

proposed total sulfur content values are

0.5 gr/100 scf or less for pipeline natural

gas and 20.0 gr/100 scf or less for

natural gas. EPA chose the value of 0.5

gr/100 scf for pipeline natural gas so

that typical supplies of pipeline natural

gas that have an average sulfur content

of 0.2 to 0.3 gr/100 scf will consistently

yield samples below this cutoff of 0.5

gr/100 scf. In addition, SO2 emission

rates calculated using this value will not

be much higher than the rate of 0.0006

lb SO2 /mmBtu for pipeline natural gas

that EPA used to compute allocations

for sources combusting pipeline natural

gas. The value of 20.0 gr/scf is the

maximum total sulfur content allowed

under most contracts for transmitting

pipeline natural gas and allowed under

most tariffs established with the Federal

Energy Regulatory Commission.

In addition, appendix D, sections

2.3.1.4 and 2.3.2.4 would be revised to

require initial and periodic sampling to

document the total sulfur content of the

fuel. The revised rule would require

periodic sampling on a semiannual

basis, as well as whenever it is

reasonable to believe that the

composition of the fuel supply has

changed. For fuels that qualify as

pipeline natural gas, the 0.0006 lb/

mmBtu default SO2 emission rate would

be used, and for fuels that qualify as

natural gas, an SO2 emission rate would

be calculated based on Equation D–1h

in appendix D. Note that Equation D–1h

would be revised to be based upon the

total sulfur content of the fuel, rather

than the H2S content.

2. How Does EPA Propose To Change

the Definitions of Unit and Stack

Operating Hours?

Background. The current rule allows

quality-assurance (QA) test exemptions

and deadline extensions for continuous

emission monitors, based on the amount

of unit operation. Grace periods are also

allowed to complete missed QA tests.

To qualify for QA test extensions and

exemptions, an owner or operator must

determine whether there are at least 168

unit or stack operating hours in the

quarter (so that the quarter meets the

definition of a ‘‘QA operating quarter’’).

The length of grace periods is also

determined on a unit or stack operating

hour basis. The rule defines ‘‘unit

operating hour’’ and ‘‘stack operating

hour’’ in such a way that partial

operating hours are counted as full

hours. This is counterintuitive to the

way that source operators normally

count operating hours. They normally

count cumulative operating time so that

30 minutes of operation equals 0.5

operating hours, not 1.0 hours.

Discussion of Proposed Changes.

Definitions of ‘‘cumulative stack

operating hours’’ and ‘‘cumulative unit

operating hours’’ would be added to

§ 72.2. The definitions of ‘‘QA operating

quarter’’ and’’ fuel flowmeter QA

operating quarter’’ would be revised to

put them in terms of cumulative unit or

stack operating hours. Finally, all

references to the length of grace periods

would be changed to be in terms of

cumulative unit operating hours or

cumulative stack operating hours.

3. What Other Definitions Would Be

Revised or Added to the Rule?

Background. There are several

definitions in § 72.2 that are either

unclear or inconsistent with the way in

which part 75 has been implemented. In

addition, some terms that are used in

the Acid Rain Program Policy Manual

and the EDR v2.1 Instructions are not

defined in the rule.

Discussion of Proposed Changes.

Under the proposal, EPA would add

definitions of ‘‘common pipe,’’

‘‘common pipe operating time,’’

‘‘diluent cap value,’’ ‘‘fuel flowmeter

system,’’ ‘‘fuel usage time,’’’’multiple

stack configuration,’’ ‘‘stack operating

time,’’ and ‘‘unit operating time.’’ These

terms are all used in part 75 and the

accompanying guidance materials, but

are not defined in § 72.2. EPA believes

these terms should be defined because

they are terms of art as used in various

sections of part 75.

Finally, the definitions of

‘‘continuous emission monitoring

system or CEMS,’’ ‘‘emergency fuel,’’

‘‘heat input,’’ ‘‘hour before and after,’’

‘‘maximum potential NOX emission

rate,’’ ‘‘maximum rated hourly heat

input,’’ ‘‘missing data period,’’ ‘‘monitor

accuracy,’’ ‘‘stack operating hour,’’ and

‘‘unit operating hour’’ would be revised.

See the technical support document

(Docket A–2000–33, Item II–A–2) for an

explanation of these technical changes.

B. Certification Timeline Issues

1. What Is the Deadline for an

Application for Initial Certification?

Background. The current rule

specifies different monitor certification

timelines in § 75.4, for new units, new

Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules 31981

stacks, and deferred units. New units

must certify their monitors within 90

calendar days after the unit commences

commercial operation. Similarly, for

newly affected units, owners or

operators have 90 calendar days from

the date on which they become Acid

Rain affected units to certify monitors.

Also, when a new stack or flue gas

desulfurization system (FGD) is

constructed, the owner or operator has

90 calendar days from the date on

which emissions first exit to the

atmosphere through the new stack or

FGD to install and certify continuous

monitoring systems. However, for

deferred units (affected units that were

in cold-storage on their compliance

deadline), owners or operators have

either 45 operating days or 180 calendar

days (whichever occurs first) to certify

monitors after recommencing operation.

The 90 calendar day timeline has

proven to be problematic, particularly

for new units that experience

mechanical problems when they first

begin operating. The deferred unit

timeline has greater flexibility.

Discussion of Proposed Changes. EPA

proposes to make all of the timelines the

same for deferred units, new units, new

stacks, and newly affected units. In all

cases, the certification deadline would

be the earlier of 90 unit operating days

or 180 calendar days after the unit

commences commercial operation or

recommences operation. Paragraphs (b),

(c), (d), and (e) of § 75.4 would be

revised to incorporate this change.

Corresponding changes would be made

to 40 CFR 97.70, the monitoring and

reporting sections of the January 18,

2000, final section 126 rule, in order to

make the certification timelines in parts

75 and 97 consistent.

2. For an Appendix E Peaking Unit,

When Is Initial Certification Required

While Combusting the Backup Fuel?

Background. The current rule

specifies in § 75.4(f) that for an

appendix E unit for which certification

testing prior to the applicable deadline

has been done only while combusting

the primary fuel, certification tests using

backup fuel must be completed within

30 unit operating days after the backup

fuel is first combusted following the

certification deadline.

Discussion of Proposed Changes. The

proposal would revise § 75.4(f) to state

that certification is required within the

earlier of 90 unit operating days or 180

calendar days after the backup fuel is

first burned following the initial

certification deadline. This revised

timeline is consistent with the changes

to the timelines in § 75.4, paragraphs

(b), (c), (d), and (e) in today’s proposed

rule.

3. What Happens if a Unit Loses

Peaking, Gas-Fired, or LME Status?

Background. Under the current rule,

when an appendix E unit loses its status

as a peaking unit, a NOX CEMS must be

installed by December 31 of the

following calendar year. Similarly, loss

of gas-fired unit status requires (in some

cases) installation of a COMS by

December 31 of the following year. Loss

of low mass emissions (LME) unit status

under § 75.19 requires monitoring

systems to be installed within two

quarters after the quarter in which LME

status is lost. The LME requirement

appears to be inconsistent with the

others in that it contains a shorter

timeline to install and certify

monitoring systems. In addition, when

peaking unit or LME status is lost, the

rule does not provide specific

instructions regarding what emission

values to report if the deadline for

certifying monitors is not met.

Discussion of Proposed Changes. For

units that lose their LME status, EPA

proposes to change the deadline in

§ 75.19(b)(2) for monitor certification to

December 31 of the year after the year

in which the unit exceeded the LME

applicability threshold(s), thus making

the monitor certification timeline the

same as the timelines in §§ 75.12(d)(2)

and 75.14(c) for, respectively, loss of

peaking unit status and loss of gas-fired

status. In the period from the time of

loss of LME status until the certification

deadline, units would continue to

monitor and report in accordance with

the provisions for LME units.

Today’s proposed rule also includes

provisions in §§ 75.19(b)(2), 75.12(d)(2),

75.71(d), and appendix E, section 1.1

that would specify the emission

reporting requirements when LME

status or peaking unit status is lost and

the monitor certification deadline is not

met. For loss of peaking unit status, the

maximum potential NOX emission rate

would be reported after the CEM

certification deadline. For loss of LME

status, SO2 and CO2 emissions would be

reported after the deadline using the

applicable LME default emission rate

and the maximum potential hourly heat

input, and NOX emissions would be

reported using the fuel specific

maximum potential NOX emission rate.

C. Missing Data

1. How Will the Proposed Rule Affect

the Missing Data Procedures in §§ 75.31

Through 75.37 for Units That Produce

Electrical or Thermal Output?

Background. The part 75 CEMS

missing data procedures in §§ 75.31

through 75.37 require the use of

substitute data values for each unit

operating hour in which quality-assured

data are not obtained, either from a

certified CEMS, a reference method, or

an approved alternative monitoring

system. The method of determining the

appropriate substitute data values

depends principally on two things: (1)

The length of the missing data period;

and (2) the percent monitor data

availability at the end of the missing

data period. In some cases, the

substitute data value is simply the

arithmetic average of the CEMS hourly

averages recorded before and after the

missing data period. In other cases, the

substitute data value is either the 90th

percentile value, the 95th percentile

value, or the maximum value in a

historical lookback period consisting of

a certain number of quality-assured

monitor operating hours (the previous

720 hours of quality-assured data for

SO2, CO2, and moisture, and the

previous 2,160 hours of quality-assured

data in a particular load range (‘‘load

bin’’) for NOX and flow rate). Finally, if,

at the time of the missing data period,

the percent monitor data availability is

below 80 percent, the appropriate

maximum potential value must be

reported for each hour of the missing

data period.

The part 75 missing data procedures

do not take into consideration the type

of fuel combusted. Rather, a single

database of quality-assured monitor

operating hours is maintained for each

monitored parameter (SO2, NOX, flow

rate, etc.) in order to provide substitute

data values when a historical lookback

is required. For a unit that combusts

different types of fuel having

significantly different emission levels

for a particular parameter (e.g., for a unit

which can burn either coal or natural

gas, the SO2 emissions are much higher

when coal is burned), the substitute data

values obtained in a historical lookback

may not be representative of the actual

emissions during the missing data

period.

For units with add-on SO2 or NOX

emission controls, § 75.34 in the current

rule allows three missing data options.

The owner or operator may either: (1)

Use the standard missing data

procedures, if the controls are

documented to be operating properly, or

otherwise use maximum potential

31982 Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules

values; or (2) petition the Administrator

to use the maximum controlled

emission rate recorded in the previous

720 quality-assured monitor operating

hours, if the percent monitor data

availability is below 90 percent and if

the controls are documented to be

operating properly during the missing

data period; or (3) petition the

Administrator to use site-specific

parametric monitoring procedures for

missing data substitution. These missing

data options have proven to be difficult

to implement and lack flexibility. The

representativeness of the substitute data

values derived from these procedures,

particularly for Options (1) and (3), is

also uncertain.

Option (1) requires parametric data to

be recorded during missing data periods

to document proper operation of the

add-on emission controls, in order to

justify using the standard missing data

procedures. The parameters selected

and the acceptable ranges for the

parameters must be documented in the

QA plan for the unit. The designated

representative must submit a

certification statement in the electronic

quarterly report, affirming that the

emission controls operated within the

acceptable parametric ranges during

each missing data period and that use of

the standard missing data procedures is

appropriate. This approach to missing

data substitution is problematic because

currently there are no clear guidelines,

either in the rule or in EPA policy

guidance, for selecting the appropriate

parameters or the acceptable parametric

ranges. Therefore, it is difficult to

establish whether the emission controls

are actually working properly during a

missing data period, even if parametric

data have been recorded and are

available for auditing purposes. Further,

when the standard missing data

procedures are used, the substitute data

values derived from historical lookbacks

may not be representative of the actual

emissions during the missing data

period, because the historical databases

used for the lookbacks include all

quality-assured CEMS data, for both

controlled and uncontrolled operation.

Option (2), above, is difficult to

implement administratively, because it

requires a petition every time the owner

or operator wants to use a missing data

value based solely on data recorded

during hours when the emission

controls were working, instead of using

the standard missing data routines. Use

of this missing data option could

therefore require a petition to be

submitted to and answered by EPA

every quarter.

To date, no units in the Acid Rain

Program have petitioned to use Option

(3), above.

Discussion of Proposed Changes.

Today’s proposed rule would revise the

part 75 missing data procedures to allow

missing data substitution to be done on

a fuel-specific basis. Also, for units with

add-on SO2 or NOX emission controls,

EPA proposes to revise § 75.34 to

include a new missing data option,

based on the operating status of the

emission controls. Note that the use of

these new rule provisions would be

optional. Therefore, sources using the

missing data provisions in the current

rule could continue to do so.

Today’s proposed rule would add

fuel-specific missing data provisions to

§ 75.33, in five new paragraphs, (b)(5),

(b)(6), (c)(7), (c)(8), and (c)(9). These

provisions would allow the owner or

operator to create and maintain separate

databases for each type of fuel

combusted in the unit, for missing data

purposes. Substitute data values would

be derived from the appropriate

database, depending on the type of fuel

being burned during the missing data

period. To use these new provisions, the

owner or operator would be required to

determine fuel-specific maximum

potential values for concentration,

emission rate, or flow rate (as

applicable).

The owner or operator would be

allowed to switch to the new fuelspecific missing data procedures at any

time. Until the requisite number of

hours of quality-assured fuel-specific

data were recorded for the lookback

periods (either 720 or 2,160 hours), the

owner or operator would use all

available data in the databases for the

lookbacks.

For units with add-on controls, the

proposed rule would retain the missing

data option in § 75.34(a)(3), allowing the

owner or operator to petition to use a

site-specific parametric missing data

substitution procedure. The owner or

operator could also continue using the

missing data option in § 75.34(a)(1),

which allows the standard missing data

procedures to be used for hours in

which proper operation of the emission

controls is documented by means of

parametric data, and requires maximum

potential values to be reported for all

other missing data hours. Note,

however, that the proposed rule would

expand and clarify the way in which

parametric data are used to document

proper operation of the add-on emission

controls, as explained below in the

discussion of the changes to

§ 75.34(a)(2).

Today’s proposed rule would

significantly revise § 75.34(a)(2), to

allow the owner or operator of a unit

with add-on SO2 or NOX emission

controls (including units equipped with

dry low- NOX technology) to create and

maintain two separate databases,

controlled and uncontrolled, for missing

data purposes. Any hour in which the

add-on controls are documented to be

operating (on) would be included in the

controlled database. Any hour in which

the controls are not operating (off)

would be included in the uncontrolled

database. For units with more than one

type of add-on controls (e.g., steam

injection plus SCR), hours in which any

of the add-on controls operate would be

included in the controlled database.

Alternatively, the uncontrolled database

could consist of either: (a) qualityassured data recorded by a certified

monitor at the control device inlet; or

(b) for a unit with a main stack and a

bypass stack, quality-assured data

recorded by a certified monitoring

system installed on the bypass stack.

If the proposed missing data option in

§ 75.34(a)(2) were selected, then,

whenever a historical lookback was

required, the substitute data value for

each hour of the missing data period

would be taken from the appropriate

database (controlled or uncontrolled),

depending on whether the emission

controls are documented (by means of

parametric data) to be operating

properly during the hour. For the SO2

missing data algorithms in § 75.33,

paragraphs (b)(1)(i) and (b)(2)(i), which

require the hour before and hour after

average value to be reported rather than

performing a historical lookback,

proposed § 75.34(a)(2) would restrict the

use of the hour before and hour after

value to missing data hours in which

the emission controls are documented to

be operating properly; otherwise, the

maximum uncontrolled value recorded

in the previous 720 hours would be

reported. The owner or operator would

be required, under § 75.58(b)(3), to keep

records of the operational status (on or

off) of the emission controls for all unit

operating hours, and to keep records of

the parametric data recorded during

periods of missing SO2 or NOX data. The

designated representative would also be

required to submit a certification

statement in the quarterly report,

verifying that the add-on controls were

operating properly during each missing

data hour in which substitute values

from the controlled database were

reported, or, for SO2, each missing data

hour in which the average of the hour

before and hour after values was

reported.

The owner or operator of a unit with

add-on emission controls would be

allowed to switch to the missing data

Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules 31983

procedures in § 75.34(a)(2) at any time.

If, at the time of the change, the

standard missing data procedures of

§ 75.33 are already in use, and if hourly

calculation of percent monitor data

availability (PMA) is being performed

according to § 75.32, it would not be

necessary to repeat the initial missing

data procedures of § 75.31. Rather,

calculation of the PMA could continue

uninterrupted and the two emission

databases (controlled and uncontrolled)

could be created prospectively.

Alternatively, the databases could be

created from historical CEM data, if

records are available to document the

operating status (on or off) of the addon controls during each quality-assured

monitor operating hour. Until the

requisite number of hours of qualityassured data for the lookback periods

are recorded (i.e., either 720 or 2,160

hours), the owner or operator would use

all available data in each database for

the lookbacks.

Section 75.34(d) of the proposed rule

would expand and clarify the way in

which parametric data are used to

document proper operation of add-on

emission controls during periods of

missing SO2 or NOX data. According to

§ 75.58(b)(3)(ii) of the current rule,

‘‘proper operation’’ of the controls

means that parametric data were

recorded during the missing data

period, indicating that, ‘‘all parameters

* * * [were] * * * within the ranges

specified in the quality assurance/

quality control program.’’ EPA believes

that in view of today’s proposed

substantive changes to § 75.34, this

regulatory language is inadequate,

because it gives no guidelines

concerning which parameters to

monitor or how to determine the

acceptable parametric ranges.

EPA therefore proposes to revise

§ 75.34(d), as follows. The owner or

operator of a unit with add-on controls

would, for missing data purposes, still

be required (as in the current rule) to

document in the QA/QC program for the

unit the parameter(s) monitored and the

acceptable parametric ranges and

combinations of parameters which

indicate proper operation of the

emission controls. However, for units

that use a control method involving

injection of water, steam, or chemical

reagents into the combustion chamber

or flue gas stream (e.g., limestone

injection, limestone scrubbing, water

injection, steam injection, SCR, or

SNCR) today’s proposed rule would

require at least one key parameter to be

monitored during missing data periods,

to document proper emission control

operation. A key parameter would be

one that has a direct relationship to

control device removal efficiency, such

as the water-to-fuel ratio, the ammonia

injection rate, or the slurry flow rate.

Further, proposed § 75.34(d) would

require the owner or operator to

establish a demonstrable correlation

between the parametric data and control

device removal efficiency, as part of the

QA/QC program for the unit. The

correlation would be based on

parametric data recorded during unit

operation, when the add-on controls are

in-service and the SO2 or NOX monitor

at the control device outlet is providing

quality-assured data. The correlation

would be derived from a minimum of

720 hours of data, obtained at various

load levels, representing the range of

operation of the unit. The correlation

would serve as the basis for determining

whether substitute data values should

be taken from the controlled database or

from the uncontrolled database during

periods of missing SO2 or NOX data.

Finally, the owner or operator would be

required to provide to EPA or to the

State, upon request, either the

parametric data recorded during missing

data periods or the related QA/QC

program information (or both).

EPA believes that the new proposed

missing data option in § 75.34(a)(2),

which conditionally allows the use of

substitute data values taken from a

controlled database, would be

sufficiently protective of the

environment, for two reasons. First, if

the add-on controls were not working

properly when flagged as being on,

emissions would be higher than normal.

These high emission values would be

recorded by the CEMS and would

become part of the controlled database.

This would result in conservatively high

substitute data values being obtained

from the historical lookbacks and

applied to controlled missing data

hours. Second, the proposed revisions

to § 75.34(d), requiring the owner or

operator to monitor key parameters for

certain types of controls and to develop

an actual correlation between the

parametric data and the removal

efficiency of the control device, would

provide reasonable assurance that the

emission controls are operating properly

during missing data periods.

2. How Will Subpart H Missing Data

Provisions Be Affected for Units That

Produce Electrical or Thermal Output?

Background. The missing data

procedures for subpart H units are

specified in §§ 75.70(f) and 75.74(c)(7).

Section 75.70(f) requires the missing

data procedures in subpart D of part 75

(§§ 75.31 through 75.37) to be used for

sources that report emission data on a

year-round basis. Section 75.74(c)(7)

also requires subpart H sources that

report data on an ozone season-only

basis to use the missing data procedures

of subpart D, except that: (1) Only data

from within the ozone season are to be

used in the historical lookbacks; and (2)

when a fuel combusted in the current

ozone season has a higher NOX emission

rate than the fuel(s) burned in the

previous ozone season, or when a unit’s

add-on controls are not working

properly (as indicated by recorded

parametric data), the maximum

potential NOX emission rate (MER) must

be reported.

Discussion of Proposed Changes.

Because owners and operators of

subpart H units are required to use the

initial and standard missing data

procedures in §§ 75.31 through 75.37,

all of today’s proposed changes to those

sections would apply to subpart H units.

Therefore, the owner or operator of a

subpart H unit could elect to use either

the new fuel-specific missing data

procedures in § 75.33 or, for units with

add-on emission controls, the new

missing data procedure in proposed

§ 75.34(a)(2).

Today’s proposed rule would also

revise § 75.74(c)(7), the section which

provides the missing data procedures

for subpart H sources that report

emission data only during the ozone

season, rather than on a year-round

basis. EPA proposes to make three

substantive revisions to that section.

First, § 75.74(c)(7)(ii) would be

revised to require reporting of the MER

only when sufficient, prior qualityassured NOX emission data are not

available for combustion of a new fuel

that has a higher NOX emission rate

than any fuel burned in the previous

ozone seasons. Once sufficient qualityassured emission data are obtained for

the new fuel, it would no longer be

necessary or appropriate to report the

MER, as NOX emission data for the new

fuel would be in the missing data banks,

and the standard, historical lookbacks

could be used to provide representative

substitute data values.

Second, EPA proposes to remove from

§ 75.74(c)(7)(ii) the requirement to

report the MER when the NOX emission

controls are not working properly, as

indicated by parametric data recorded

under § 75.74(c)(8). The requirement to

report the MER when the emission

controls are not working properly is

associated with the missing data option

in § 75.34(a)(1) and is found in that

section. Therefore, it is unnecessary to

restate the requirement in subpart H.

Since proposed § 75.74(c)(7)(ii) requires

subpart H units that report data on an

ozone season-only basis to use the

missing data procedures in §§ 75.31

31984 Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules

through 75.37, owners and operators of

such units must follow the missing data

provisions in § 75.34 if the units have

add-on NOX emission controls. This

includes the provision in § 75.34(a)(1), if

that missing data option is selected,

requiring the MER to be reported when

proper operation of the NOX emission

controls cannot be documented.

Third, today’s proposed rule would

add a new paragraph (iii), with

subparagraphs (A) through (M), to

§ 75.74(c)(7), explaining how to apply

the initial and standard part 75 missing

data procedures in §§ 75.31 through

75.37 on an ozone season-only basis.

EPA is adding these provisions to

subpart H because the part 75 missing

data routines are designed for sources

that report emission data on a yearround basis. For example, for all of the

part 75 standard missing data routines

that use 720 or 2,160 hour historical

lookbacks to determine the appropriate

substitute data values, the databases for

the lookbacks consist of quality-assured

CEMS data that have been recorded

throughout the year. Also, the percent

monitor data availability (PMA)

calculations described in § 75.32 are

always based on a particular number of

unit operating hours, either the number

of unit operating hours since initial

certification, or the number of unit

operating hours in the past three years,

or the previous 8,760 unit operating

hours. The number of unit operating

hours used in the PMA calculations

includes operating hours from all four

calendar quarters of the year.

Section 75.74, paragraph (c)(7)(i)

clearly states that for subpart H sources

that report data on an ozone season-only

basis, only data from within the ozone

season are to be included in the missing

data routines. Thus, as written, the

missing data procedures in subpart D of

part 75, which use data from all twelve

months of the year, are incompatible

with the requirements of § 75.74(c)(7)(i).

Despite this, EPA believes that there is

a relatively simple way to resolve this

inconsistency in the rule, as discussed

in the following paragraphs.

Section 75.74, paragraph (c)(7)(iii) in

today’s proposed rule would modify the

initial and standard part 75 missing data

procedures in §§ 75.31 through 75.37 to

adapt them to sources that report

emission data only during the ozone

season. This adaptation is possible

because there is a commonality between

year-round reporting and ozone seasononly reporting—in both cases there is a

discrete time period used for

compliance determination. For yearround reporters, that time period is the

calendar year, and for ozone seasononly reporters, the compliance time

period is the ozone season. This

commonality allows the missing data

instructions for ozone season-only

reporters to be written in a parallel

manner to the missing data procedures

for year-round reporters.

Paragraphs (A) through (M) in

proposed § 75.74(c)(7)(iii) provide the

necessary parallel rule language to adapt

the missing data provisions in §§ 75.31

through 75.37 to ozone season-only

reporters. The following is a summary of

the essential elements of these proposed

rule provisions:

• Use of the initial missing data

procedures in § 75.31 would commence

with the first operating hour in the first

ozone season for which emission

reporting is required.

• For initial missing data purposes

and for the historical data lookbacks

required under § 75.33, phrases such as

‘‘720 quality-assured monitor operating

hours’’ would be replaced with phrases

such as ‘‘720 quality-assured monitor

operating hours within the ozone

season.’’

• For PMA calculations, phrases such

as ‘‘total unit operating hours’’ would be

replaced with ‘‘total unit operating

hours within the ozone season.’’ Also,

‘‘8,760 unit operating hours’’ (the

number of hours in a calendar year)

would be replaced with ‘‘3,672 unit

operating hours’’ (the number of hours

in an ozone season).

• For both PMA calculations and

historical lookbacks, the phrase ‘‘three

years (26,280 clock hours)’’ would be

replaced with ‘‘three ozone seasons.’’

3. What Are the Missing Data

Requirements for Units That Do not

Produce Electrical or Thermal Output?

Background. Today’s proposed rule

would add missing data procedures to

part 75 for units that do not generate

electricity or produce steam load. The

new missing data provisions would be

added to §§ 75.31 and 75.33, to

appendix C of part 75, and to section 2.4

of appendix D. The rationale for these

new provisions and a discussion of the

provisions are presented in the

following paragraphs.

As stated in Section II of this

preamble, one of the main objectives of

today’s proposed rule is to modify the

existing monitoring and reporting

sections of parts 72 and 75 which

support emission control programs that

use the monitoring and reporting

provisions of part 75, such as State NOX

reduction programs developed in

response to the October 27, 1998 SIP

call. Under the NOX SIP call, States

have the flexibility to include stationary

sources other than electric generating

units in their NOX reduction plans. For

example, the State of New York has

proposed regulation 204 to control

emissions of nitrogen oxides from

stationary sources. The sources affected

by this regulation include EGU and nonEGU sources, such as industrial boilers

and cement kilns. To comply with

sections 204–8 of this regulation, all of

the affected units must monitor and

report NOX mass emissions according to

subpart H of 40 CFR part 75, beginning

on May 1, 2002. Other States, including

New Jersey, Pennsylvania, Maryland,

Delaware, and Massachusetts have

proposed, or may be proposing, similar

rules which require some non-electric

generating units to monitor according to

subpart H of part 75. To date, EPA has

identified three non-EGU source

categories that would likely be subject

to part 75 monitoring and reporting

under the various State rules: industrial

boilers, refinery process heaters, and

cement kilns.

At the request of the New York State

Department of Environmental

Conservation, EPA examined the part 75

monitoring provisions to assess whether

these provisions are adequate for

determining NOX mass emissions from

non-electric generating units. As a result

of this assessment, EPA concluded that

for industrial boilers, which produce

thermal output (i.e., steam load) and

which are very similar to electric utility

boilers, no significant changes to the

monitoring and reporting provisions of

part 75 would be required. However, for

cement kilns and refinery process

heaters, which do not produce

electricity or steam load, EPA has

identified three key areas where

modifications to the existing part 75

monitoring provisions would be

necessary to allow full and complete

monitoring of NOX mass emissions.

These areas are:

• Determination of the maximum

potential concentration (MPC) for NOX;

• The missing data routines for NOX

concentration, NOX emission rate, stack

flow rate, and fuel flow rate; and

• RATA load level requirements.

Discussion of Proposed Changes. To

address the first issue (NOX MPC

determination), EPA is proposing to add

default MPC values for process heaters

and cement kilns to part 75. The

selected MPC values and the rationale

for them are found in section III.F.3 of

this preamble. The third issue (RATA

load level requirements) is discussed in

detail in section III.F.10 of this

preamble. To address the second issue

(missing data routines), EPA is

proposing to add non-load-based

missing data procedures to part 75, as

previously noted.

Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules 31985

The missing data procedures in part

75 for NOX, stack flow rate, and fuel

flow rate are load-based. That is, all of

the quality-assured hourly data recorded

by part 75 NOX monitors, flow monitors,

and fuel flowmeters are segregated into

load ranges (or ‘‘bins’’). The purpose of

using the load bin approach is to ensure

that representative substitute data

values are provided during periods of

monitor downtime (i.e., for each missing

data hour, the appropriate substitute

data value is taken from the

corresponding load bin). However, for

units that do not produce electrical or

thermal output, the current part 75

missing data procedures for NOX, stack

flow rate, and fuel flow rate are

inadequate.

The missing data procedures for nonload-based units in today’s proposed

rule are the result of discussions

between EPA and representatives of the

cement industry. The Agency had

received a letter on August 20, 1999,

from the American Portland Cement

Alliance (APCA) (see Docket A–2000–

33, Item II–D–1), containing a proposed

methodology for performing missing

data substitution for NOX and flow rate

at cement kilns. EPA responded to this

draft proposal in a letter to APCA dated

April 24, 2000 (see Docket A–2000–33,

Item II–C–2). In that response letter, the

Agency expressed agreement with some,

but not all, of the provisions of APCA’s

proposal. The missing data approach

outlined in today’s proposed rule for

non-load-based units reflects EPA’s

stated position in the April 24, 2000,

letter to APCA.

The proposed non-load-based missing

data routines are modeled after, and are

much the same as, the existing routines

for load-based units. However, there are

two important differences:

• The owner or operator of a nonload-based unit would have the choice

of either not using bins at all or using

‘‘operational bins’’ to segregate the

quality-assured NOX, stack flow rate, or

fuel flow rate data; and

• For a non-load-based unit, the

arithmetic average of the previous 2,160

quality-assured hours of NOX

concentration or NOX emission rate (as

applicable) would be used in the

standard NOX missing data routines,

instead of the arithmetic average of the

values from the hour before and hour

after the missing data period.

The reason for allowing the use of

operational bins is to give affected

facilities the flexibility to customize

their missing data routines, based on

plant operational parameters and

conditions that affect NOX emissions,

stack flow rate, or fuel flow rate. The

procedures and requirements for

defining operational bins are found in

proposed new sections 3 and 4 of

appendix C to part 75. The owner or

operator would be required to provide a

complete description of each

operational bin in the hardcopy portion

of the monitoring plan required under

§§ 75.53(e)(2) (for NOX and stack flow

rate) or 75.53(f)(1)(ii) (for fuel flow rate).

The description of each operational bin

would include the unique combination

of parameters and operating conditions

associated with the bin and an

explanation of the relationship between

these parameters and conditions and the

magnitude of the NOX emissions, stack

flow rates, or fuel flow rates. When

using operational bins, it would be

necessary to monitor the parameter(s)

and operating conditions used to define

the operational bin. For any hour in

which essential operating or parametric

data are unavailable and the operational

bin could not be determined, the

proposed non-load-based provisions in

§§ 75.31 and 75.33 and section 2.4 of

appendix D would require maximum

potential values to be reported.

In response to a recommendation by

the cement industry, EPA proposes to

use the average of the previous 2,160

quality-assured hours of NOX data in the

standard missing data routines for nonload-based units instead of using the

average of the hour before and hour after

values. APCA advocated this approach

in the previously mentioned missing

data proposal that was sent to EPA on

August 20, 1999. EPA agrees with

APCA’s position that hour-to-hour

variability of NOX emissions from a

cement kiln is high, and using the hour

before and hour after average could

cause significant underestimation or

overestimation of emissions.

4. How Will Today’s Proposed Rule

Revise the Procedures in Appendix C

for Establishing Load Ranges (or ‘‘bins’’)

for Missing Data Purposes?

Background and Discussion of

Proposed Changes. Today’s proposed

rule will revise section 2.2.1 of

appendix C to clarify the method of

determining the maximum hourly

average gross load (MHGL) for

cogeneration units or other units for

which some portion of the heat input is

not used to produce electricity. The

MHGL for such units would be

determined by converting the maximum

rated hourly heat input of the unit to an

equivalent electrical output in

megawatts. The maximum rated hourly

unit heat input would include the

maximum potential heat input from

auxiliary combustion sources, such as

duct burners or auxiliary boilers. The

efficiency of the unit would be used in

conjunction with the maximum unit

heat input to calculate the MHGL. If the

actual efficiency of a particular

combustion source is unknown, a

default efficiency of 50 percent would

be used for a combustion turbine, and

33 percent for any other type of

combustion source. Having established

the maximum hourly gross load, the

missing data load ranges would then be

determined as percentages of the MHGL.

5. How Will the Maximum Potential

Moisture Provision Be Revised?

Background. For units for which you

continuously account for the stack gas

moisture content with a moisture

monitoring system, substitute data must

be reported whenever an hourly

moisture reading is missing. When a

moisture monitoring system is

uncertified, and when the percent

monitor data availability for moisture

drops below 80 percent, the maximum

potential moisture percentage or the

minimum potential moisture percentage

must be reported (depending upon

which emission and heat input rate

equations are used). For the minimum

potential moisture percentage, the rule

specifies that the value may be

determined from quality-assured CEM

data or a default value of 3 percent H2O

may be used. However, to determine the

maximum potential moisture

percentage, the rule requires qualityassured CEM data to be used—no

default value is specified.

Discussion of Proposed Changes. The

proposal would add a second option to

section 2.1.6 of appendix A, allowing

the use of a default maximum potential

moisture value of 16 percent H2O. This

revision would treat maximum and

minimum potential moisture values on

a consistent basis for substitute data

purposes.

6. How Will the Proposed Rule Affect

the Method of Determination Codes?

Background. Two method of

determination codes, MODC values

‘‘13’’ and ‘‘15’’ from Table 4a under

§ 75.57, became inactive as of January 1,

2000. Also, today’s proposed rule would

add provisions that require new MODCs

that do not appear in the current version

of Table 4a.

Discussion of Proposed Changes. EPA

proposes to add three new MODC codes,

‘‘21,’’ ‘‘22,’’ and ‘‘23’’ to Table 4a in

§ 75.57 for use in the electronic data

reporting (EDR) format, and to designate

the inactive codes ‘‘13’’ and ‘‘15’’ as

‘‘Reserved.’’ MODC 21 would be used

when replacing a negative hourly

concentration, emission rate, or percent

moisture value with zero. MODC 22

would be used when an hourly average

31986 Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules

SO2 or NOX concentration is reported

from a certified monitor at the inlet to

an emission control device. MODC 23

would be used when the maximum

potential SO2 concentration, CO2

concentration, NOX concentration, NOX

emission rate, or flow rate, or when the

minimum potential moisture percentage

is reported for an hour in which flue

gases are discharged through an

unmonitored bypass stack. These

changes will make the specific

electronic data reporting format

elements consistent with the rule.

D. Low Mass Emissions (LME) Units

1. What Are the Certification

Requirements for Low Mass Emissions

(LME) Units?

Background. In response to concerns

raised by both regulated entities and

other regulatory agencies, EPA

examined the administrative procedures

pertaining to LME units in part 75. It

was determined that some provisions

should be clarified to simplify program

implementation and insure that the

LME requirements are consistent with

other sections of part 75.

Discussion of Proposed Changes. The

proposed revisions require the

electronic portion of the LME

certification application to be sent to

EPA Headquarters (the Clean Air

Markets Division) and the hardcopy

portion to the appropriate Region and

State. The proposal would also require

LME applications to be submitted no

less than 45 days prior to the date on

which use of the methodology will

commence.

In addition, EPA proposes to remove

the references to January 1, 1997, in

§§ 75.19(a)(2)(ii), 75.19(b)(4), and

75.20(h)(3), as this date has no

regulatory or statutory significance.

Instead, the use of these provisions

would depend upon whether a unit is

a new or newly affected unit and to

what extent the LME applicability

demonstration relies on the use of

projected data, instead of actual,

historical data. The proposal would also

clarify the period of provisional

certification for LME units in

§ 75.20(h)(3), the date on which a

qualifying unit begins using the

methodology in § 75.19(a)(1)(ii), and the

certification application submittal

process in § 75.63(a)(1).

2. How Does the LME Methodology

Apply to Subpart H Units?

Background. In its current form

§ 75.19 contains only a limited

explanation of the requirements for

units subject to subpart H of part 75

(and not covered under the Acid Rain

Program) that are using the LME

methodology to account for emissions.

Note that some of these requirements for

subpart H units are the same as those for

Acid Rain Program units.

Discussion of Proposed Changes.

Paragraphs (a), (b), and (c) of § 75.19

would be revised to distinguish the

applicability, on-going qualification,

and reporting requirements for Acid

Rain Program units and non-Acid Rain

Program, subpart H units. The revisions

would make a clear distinction between

sources that report emission data on a

year-round basis and those that report

data only during the ozone season.

These changes would help owners and

operators of non-Acid Rain Program

units understand how to comply with

the LME requirements. Language was

added to clarify that non-Acid Rain

Program units using the LME

methodology and the provisions of

subpart H of part 75 (to comply with the

monitoring and reporting requirements

of a NOX mass trading program) must

submit NOX mass emission data, but are

not required to submit SO2 mass

emissions data. In addition, language

was added to clearly state the initial and

ongoing qualification criteria for nonAcid Rain Program units. Specifically,

non-Acid Rain Program units for which

you choose to report data year round

under the LME methodology must emit

no more than 50 tons of NOX annually,

while units for which you choose to

report only ozone season NOX mass

emission data must emit no more than

25 tons of NOX each ozone season.

3. When Must the Annual

Demonstration for LME Units be

Completed?

Background. The current rule does

not specifically state the deadline for

performing the annual demonstration of

LME qualification. EPA believes that a

consistent standard should be used for

all units every year.

Discussion of Proposed Changes. For

a unit to continue to qualify as a LME

unit, certain mass emission thresholds

must be met on an on-going basis. These

thresholds are: 25 tons SO2 and 50 tons

NOX annually for an Acid Rain Program

unit; 50 tons NOX annually for a nonAcid Rain Program, subpart H unit

reporting on a year-round basis; and 25

tons per ozone season for a non-Acid

Rain Program, subpart H unit reporting

on an ozone season basis only. The

owner or operator must demonstrate

annually that the unit does not exceed

the applicable mass emissions

threshold(s). The proposed rule would

add language to § 75.19(b)(1) to

expressly state that the annual

demonstration will be considered

complete only when the official data

reconciliation process is complete. More

specifically, only the final emissions

data record for the year or ozone season

(i.e., the final accounting of emissions,

after data have been fully reconciled

and any necessary quarterly report

resubmittals have been made) will be

used to determine whether a unit has

met the applicable mass emissions

threshold and satisfied the LME

qualification requirements.

4. How Should EPA Reference Method

20 Be Altered When Determining a

Fuel-and Unit-Specific NOX Emission

Rate for an LME Unit?

Background. The Method 20 test

procedures require the measured NOX

concentrations to be corrected to 15

percent O2. For units simply

determining the NOX emission rate, this

correction is unnecessary because the

measured fuel- and unit-specific NOX

emission rate will be the same whether

or not the concentration is corrected to

15 percent O2.

Discussion of Proposed Changes.

Today’s proposal would remove the

requirement from § 75.19(c)(1)(iv)(A)

that a unit must correct NOX

concentration values to 15 percent O2

when performing Method 20 testing.

5. What Temperature and Humidity

Corrections are Required for Turbines

When Unit- and Fuel-Specific NOX

Emission Rates are Determined for LME

Units?

Background. Beginning in the 1999

ozone season, the Ozone Transport

Commission (OTC) NOX Budget

Program required monitoring and

reporting of NOX mass emissions for use

in a regional NOX trading program. Each

State participating in the program

required monitoring and reporting to be

performed according to the ‘‘Guidance

for Implementation of Emissions

Monitoring Requirements for the NOX

Budget Program’’ and the ‘‘ NOX Budget

Program Monitoring Certification and

Reporting Instructions.’’ These

documents required reporting of

emissions data in the Electronic Data

Reporting (EDR) version 2.0 format.

Under this program, a large number of

small peaking turbines were required to

begin monitoring and reporting data in

the EDR v2.0 format. This group of units

contains simple combustion peaking

turbines of 15 to approximately 75 MWh

capacity. These units have historically

been exempt from the Acid Rain

Program monitoring and reporting

under either § 72.6(b)(1), an exemption

for simple turbines built prior to

November 15, 1990, or § 72.7, the new

unit exemption. The monitoring and

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reporting options allowed for these type

of units in the OTC NOX Budget

Program guidance documents are

similar to the monitoring and reporting

provisions under § 75.19 with some key

differences, including the use of a

multiplier of 1.15 to all fuel- and unitspecific NOX emission rates determined

using the testing procedures of

appendix E. In the preamble to the May

1999 final revisions to part 75, EPA

states that the reason for the 1.15

multiplier is that the NOX emission rate

may vary at a given load for any

particular unit. In particular, EPA was

concerned with possible

underestimation of emissions using the

results of appendix E testing to

determine fuel- and unit-specific NOX

emission rates.

EPA anticipates that the majority of

the simple peaking turbine units

described above will be required to

begin monitoring and reporting data

according to the LME provisions under

§ 75.19 in the future as part of a larger

NOX trading program. Several utilities

asked that the LME requirements under

§ 75.19 be modified to allow removal of

the 1.15 multiplier to fuel and unitspecific NOX emission rates. They

argued that the requirement to use a

1.15 multiplier would result in a high

overestimation of NOX emission rates

under some circumstances. EPA

investigated the causes of variability in

NOX emission rates in turbines by

reviewing literature, reviewing test

results, analyzing CEMS data for

turbines, and by discussing turbine

operation with turbine and utility

experts (see Docket A–2000–33, Item II–

B–1). The result of the investigation was

confirmation that temperature, pressure,

and, in particular, humidity affect the

NOX emission rate in combustion

turbines. The investigation revealed that

several empirically-derived

mathematical algorithms have been

developed to correct a measured NOX

concentration to a theoretical NOX

concentration at a different temperature,

pressure, and humidity, including the

equation in subpart GG, Standards of

Performance for Stationary Gas Turbines

(§ 60.335).

Discussion of Proposed Changes. The

proposal would add a new requirement

for certain turbines to correct measured

NOX concentrations using an equation

similar to the equation in subpart GG of

the New Source Performance Standards

(40 CFR part 60), for correcting to the

International Organization for

Standardization (ISO) standard ambient

conditions. This correction, in

§ 75.19(c)(1)(iv)(A)(4), would apply only

to uncontrolled diffusion flame style

turbines and would compensate for

temperature and humidity effects on

NOX formation by correcting the

measured NOX concentrations at the test

conditions to the average annual

temperature, atmospheric pressure, and

humidity at the location of the turbine.

If a unit (including an Acid Rain

Program unit) is subject to an ozone

season-based NOX mass emission

reduction program, average ozone

season values of temperature,

atmospheric pressure, and humidity

would be used instead of average annual

values. The proposed rule suggests (but

does not require) using National

Oceanic and Atmospheric

Administration temperature and

humidity data from the weather station

at the nearest airport. This provision

would prevent underestimation or

overestimation of NOX emissions for

uncontrolled diffusion flame turbines.

Today’s proposal also removes the

requirement to multiply the measured

NOX emission rates for such turbines by

1.15, as the new correction equation

would make use of the multiplier

unnecessary.

6. How Is Identical Unit Status

Demonstrated for a Group of LME

Units?

Background. The rule currently

requires, in § 75.19(c)(1)(iv)(B)(1), that

to be considered identical a group of

LME units must be of the same

manufacturer, model, and size, have the

same history of modifications (e.g., the

same controls installed), and have

similar outlet temperatures under

similar operating conditions. Section

75.19(c)(1)(iv)(B)(3) further requires that

if there are more than two identical

units in the group, the NOX emission

rate of each unit tested must be within

10 percent of the average emission rate

for all units tested, at each load level.

Discussion of Proposed Changes. The

proposal would delete from

§ 75.19(c)(1)(iv)(B)(3) the requirement

that the emission rate for each unit must

be within 10 percent of the group

average rate in order for a particular unit

to be considered an identical unit.

These proposed identical unit

provisions in part 75 are based in large

part on comparable provisions used

under the Ozone Transport Commission

(OTC) NOX Budget Program. Because

the OTC requirements for identical units

have been effective and have minimized

the compliance burdens on LME units,

EPA believes that it is appropriate to

eliminate the ten percent requirement

from the part 75 LME provisions. The

criteria in § 75.19(c)(1)(iv)(B)(1) for

identifying identical units would be

retained, however.

7. How Is the Fuel- and Unit-Specific

NOX Emission Rate Determined for LME

Turbines Equipped With Water

Injection, Steam Injection, or Water/

Fuel Emulsion, and no Other Type(s) of

add-on NOX Controls?

Background. The current LME

provisions in § 75.19 include a

provision which restricts the use of fueland unit-specific NOX emission rates to

be no less than 0.15 lb/mmBtu for units

with any type of NOX emission controls.

Use of the 0.15 value ensures that large,

highly controlled units would not use

the LME provisions for estimating

emissions. EPA believes that the LME

provisions are inappropriate for units

with such controls as SCR or SNCR and

that NOX emission monitoring is the

only effective way to determine that a

unit achieves its target control level.

Industry representatives have asked

EPA to consider allowing the use of

controlled fuel and unit specific NOX

emission rates below the 0.15 lb/mmBtu

minimum for turbines with water

injection, steam injection, or water/fuel

emulsion. The representatives stated

that if the water-to-fuel ratio were

monitored each hour, the use of a fueland unit-specific default for times when

the water-to-fuel ratio were within

acceptable limits would not

underestimate emissions.

EPA investigated the claims of the

industry representatives. EPA reviewed

data from CEMS installed at turbines

with water and steam injection and

water/fuel emulsion. Based on results of

the investigation, EPA believes that if

the water-to-fuel ratio is monitored,

then effective and constant control of

NOX is achieved with little chance of

underestimation of NOX emissions (see

Docket A–2000–33, Item II–B–1).

Discussion of Proposed Changes. The

proposal would revise

§ 75.19(c)(1)(iv)(H)(1) to allow the use of

measured NOX emission rates for units

with water or steam injection or water/

fuel emulsion (and no other type(s) of

add-on NOX controls) even if the

emission rates are below 0.15 lb/

mmBtu. This removes the current rule

requirement that all tested emission

rates below 0.15 lb/mmBtu be adjusted

upward to a default value of 0.15 lb/

mmBtu. The proposed action requires

units with steam or water injection to

monitor the water-to-fuel or steam-tofuel ratio in order to give assurance that

the emission controls are operating

properly, making it unnecessary to use

the default value.

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8. What Effect Would Today’s Proposed

Rule Have on LME Units Sharing a

Common Fuel Supply?

Background. The current LME

provisions require that where a group of

units shares a common fuel supply, use

the long term fuel flow (LTFF)

methodology for heat input, and use a

fuel-and unit-specific default NOX

emission rate, the group of units must

perform the required testing and use the

highest tested NOX emission rate for all

units. EPA has reviewed the

requirement for taking the highest NOX

emission rate for all units, found it to be

unnecessary, and is proposing to

remove the requirement.

Discussion of Proposed Changes.

Today’s proposal would delete and

reserve §§ 75.19(c)(1)(iv)(C)(2) and

75.19(c)(1)(iv)(C)(5). These sections

describe unnecessary restrictions for

groups of units sharing a common fuel

supply and using the long term fuel

flow heat input approach. It is highly

unlikely that an incorrectly apportioned

heat input for units with different

efficiencies could lead to improper

estimation of emissions. Therefore, EPA

proposes to remove these restrictions

from the rule. In addition, a source

would use the highest rate at each

individual unit to calculate emissions

from that unit, rather than using the

highest NOX emission rate from the

entire group of units.

9. When Would Single Load Testing Be

Allowed to Determine Unit- and FuelSpecific NOX Emission Rates for LME

Units?

Background. The current LME

provisions require four load testing for

all units which opt to determine a

default fuel- and unit-specific NOX

emission rate. Several industry

representatives asked that this

requirement be waived for units which

operate at a single load only. EPA

considered two options as alternatives

to the four load testing requirement.

Option 1. Require the first appendix E

test to be performed at all four loads,

then allow future testing to be

performed at the load at which the

highest NOX emission rate was found.

Option 2. Allow single load testing for

units which submit a demonstration

that a unit operates at a single load.

EPA considers option 2 to be

preferable. It allows single load testing

to be performed as of the first test and

can save time and effort, consistent with

the intent of the LME provisions to be

cost effective and simple to use. EPA

solicits comment on these methods or

other methods suitable for allowing

single load testing to be used for

determining fuel- and unit-specific NOX

emission rates.

Discussion of Proposed Changes. EPA

proposes to add a new provision to the

rule, § 75.19(c)(1)(iv)(I), which would

conditionally allow single load testing

for a unit which the owner or operator

can demonstrate has operated at a single

load level for at least 85 percent of the

time in the three years prior to the

emission test. In addition, the new

section would conditionally allow

turbines, that operate to a set point

temperature and not a given load, to

perform single load testing. If a set point

turbine is tested at base load, but the

unit is capable of operating at a higher

(peak) load and is not tested at peak

load, the fuel- and unit-specific NOX

emission rate obtained from the base

load testing would be adjusted upward

using a conservative multiplier of 1.15

to ensure that emissions are not

underestimated when the unit operates

at peak load.

10. How Are Unit-Specific, FuelSpecific NOX Emission Rates for LME

Units Determined From the Individual

Test Run Data at Each Load Level?

Background. The current LME

provisions require the use of the highest

emission rate from the appendix E test.

This language is not clear in describing

whether the value used was the highest

reading of any run during the test or the

average of the required three runs

during the test. In this rulemaking EPA

is clarifying its intent that the three run

average from a test is the value used as

the fuel- and unit-specific default

emission rate.

Discussion of Proposed Changes.

Today’s proposal would revise

§ 75.19(c)(1)(iv)(C) to clarify the way in

which the fuel- and unit-specific NOX

emission rates are calculated for LME

units when four load emission tests are

performed. The proposal would add

new language to that section, explaining

how to determine the appropriate NOX

emission rates when single load testing

is performed.

For four load testing of an individual

LME unit, the appropriate NOX

emission rate would be the highest

three-run average obtained at any load

level tested. For single load testing, the

NOX emission rate would simply be the

three-run average at the load level

tested. For four load testing of a group

of identical LME units, the appropriate

NOX emission rate would be the highest

three-run average obtained for any unit

in the group, at any load level tested.

For single load testing of a group of

identical LME units, the NOX emission

rate would be the highest three-run

average obtained for any tested unit.

11. Which Mathematical Equations Are

Affected by the Proposed Changes to

§ 75.19?

Background. Today’s proposal would

correct several equations pertaining to

LME units. These revisions are

necessary to correct one equation and to

clarify the nomenclature of several other

equations.

Discussion of Proposed Changes. The

proposed revisions will correct Equation

LM–1 and clarify the nomenclature for

Equations LM–3, LM–5, LM–6, LM–7,

LM–7a, LM–8, and LM–8a.

E. Conditionally Valid Data—

Mandatory Use

Background. In the May 26, 1999,

revisions to part 75, new CEM data

validation provisions were promulgated.

One such provision in § 75.20(b)(3)

addresses the use of conditional data

validation. For recertification testing

and diagnostic tests, § 75.20(b)(3)

requires that sources use conditional

data validation. For initial certifications

and routine quality assurance, the rule

allows, but does not require, conditional

data validation.

Discussion of Proposed Changes. To

address the inconsistency in the rule,

§ 75.20(b)(3) would be revised to make

the use of conditional data validation

optional in all cases. Appendix A,

sections 2.1.1.5(c) and 2.1.2.5(c) and

appendix B, sections 2.2.5, would also

be revised to reference the amended

§ 75.20(b)(3).

F. Quality Assurance/Quality Control

(QA/QC)

1. What Changes Are Proposed for

CEMS Span and Range Evaluations?

Background. Part 75 requires periodic

evaluations (at least annually) of the

spans and ranges of all required

continuous monitors to ensure that the

proper span and range values are being

used. To perform the annual span/range

evaluation, a review of the emission

data from the past year is required. The

results are acceptable if the data meet

the guidelines in section 2.1 of

appendix A. The basic requirement of

that section is for the majority of the

data to be between 20 and 80 percent of

the full-scale range, with certain

allowable exceptions.

With the increased emphasis in recent

years on reducing NOX emissions, many

new combustion turbines are being

built. The span/range evaluation

guideline in section 2.1 of appendix A

does not fully address the issues raised

by this type of unit. These units

typically have NOX controls capable of

reducing emissions to very low levels

(e.g., 20 ppm or less for oil-firing and

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less than 10 ppm for gas-firing) and are

often required by part 75 to have two

measurement ranges (low and high).

Some of these units operate their

emission controls only on a seasonal

basis, rather than year-round. One span

and range issue for these units is that

when natural gas is combusted, the

majority of the NOX emissions may not

meet the 20 to 80 percent guideline of

section 2.1 if, for example, the low-scale

measurement range is set at 25 ppm

based on oil-firing, in accordance with

section 2.1.2.3 of appendix A. Further,

if gas is the primary fuel in this example

and the NOX emissions are typically 5

ppm or less during gas combustion, one

might erroneously conclude during the

annual span/range evaluation that the

low range needs to be adjusted or that

a third monitoring range (e.g., 0–10

ppm) is necessary to measure the gasfired emissions, in order to meet the

section 2.1 guideline. A second issue is

that under appendix A, section 2.1, for

dual-span units with add-on emission

controls, SO2 or NOX data recorded on

the high monitor range are exempted

from meeting the 20 to 80 percent

guideline. However, this exemption is

not appropriate for units with

seasonally operated emission controls.

Discussion of Proposed Changes. To

address the first issue described above,

the proposed rule would clearly state

that for dual-span units low-range

readings below 20 percent of full-scale

are exempted from the 20 to 80 percent

guideline, provided that the maximum

expected concentration (MEC) and the

low-scale span and range values have

been determined according to the

applicable provisions of appendix A. In

the example cited in the Background

section above, if the low measurement

range of 25 ppm (based on oil-burning)

was properly set according to section

2.1.2.3 of appendix A, then re-ranging

the low measurement scale would not

be appropriate, even if the majority of

the data do not fall between 20 and 80

percent of the range when natural gas is

combusted. This is because the unit is

capable of burning oil, and a low-scale

range of 25 ppm, if set according to

section 2.1.2.3 of appendix A, is a good

choice for that fuel. Nor would it be

necessary to establish a third monitoring

range. Part 75 was never intended to

require more than two monitoring

ranges.

To address the second issue described

above, the proposed rule would require

units that operate their emission

controls seasonally to meet the 20 to 80

percent guideline on the high

measurement range. The Agency

believes it is appropriate for units using

their emission controls seasonally (such

as a unit that uses SCR during the

summer only) to meet the 20 to 80

percent guideline on the high range

because emissions data will be recorded

on that range for extended periods of

time during the year. This is unlike the

case in which controls are used yearround, where the source is likely to

operate without the controls only on

occasion and relatively few readings are

recorded on the high scale.

2. Will EPA Allow Use of Two Separate

CEM Systems With Separate Probes and

Sample Interfaces To Meet Dual-Range

Requirements?

Background. For units required to

have two spans and ranges for NOX or

SO2, the current rule disallows the use

of two separate CEM systems with

separate probes and sample interfaces.

This option was excluded because dualspan units often use add-on controls

and have very low emissions. In many

cases, the add-on controls are used yearround, so the emissions remain low

virtually all the time. The low emission

levels can make it difficult to perform

and pass a RATA on the high range.

Despite this, EPA has received two

petitions requesting permission to use

separate systems with separate probes

and interfaces to meet a dual-range

requirement (see Docket A–2000–33;

Items II–C–1 and II–D–13). To date, one

of these petitions has been approved, for

a unit that operates its NOX controls

seasonally.

Discussion of Proposed Changes.

Today’s proposal would revise

appendix A, section 2.1 to conditionally

allow the use of separate CEMS with

separate probes and interfaces to satisfy

dual-range requirements. The condition

is that RATAs of both ranges must be

performed and passed. The revised rule

would also state that the two CEMS

should be designated as separate

monitoring systems in the monitoring

plan.

3. What Changes Would the Proposed

Rule Make With Regard to Determining

NOX MPC, MEC, Span, and Range?

Background. EPA receives many

questions about the way in which the

MPC, MEC, span, and range are

determined for NOX, especially for new

combustion turbines. Some of the

questioners have requested additional

options for MPC and MEC

determinations and claim that the rule

does not address dry, low-NOX control

technology, which is being used on

many new turbines. Others have

questioned the appropriateness of the 50

ppm default value for the MPC of new

turbines in Table 2–2 of appendix A.

Discussion of Proposed Changes. The

proposed rule would clarify the

definition of MPC for NOX, making a

distinction between uncontrolled units

and units with low NOX burner

technology. The proposal would also

revise appendix A, section 2.1 to add a

new option for NOX MPC

determination: use of a reliable estimate

of the unit’s uncontrolled emissions

obtained from the manufacturer. A new

option for MEC would also be added:

use of the federally-enforceable permit

limit. The new MEC option could only

be used for units that have add-on

emission controls or that use dry, lowNOX technology.

The 50 ppm default MPC value for

new turbines in Table 2–2 would be

removed and replaced with two new

values: (a) 150 ppm for units that are

permitted to fire only natural gas; and

(b) 200 ppm for units permitted to fire

both gas and oil. These values are much

more representative of actual NOX

emissions from turbines during unit

startup and periods when the emission

controls are not operational. EPA

requests comment on whether the new

values are representative (see Docket A–

2000–33, Item II–B–2).

Finally, default MPC values would be

added to the rule for two categories of

non-load-based units: cement kilns and

process heaters. As discussed in more

detail under section III.C of this

preamble, certain States are likely to

require these two source categories to

report NOX mass emissions under the

NOX SIP call. For cement kilns, an MPC

value of 2,000 ppm is proposed; for

process heaters, an MPC value of 200

ppm is proposed for gas-fired units, and

500 ppm for oil-fired heaters. The

default MPC value for cement kilns was

determined using NOX emissions data

sent to EPA during pre-proposal

discussions between the Agency,

representatives of cement kilns located

in New York, and the Portland Cement

Association. NOX emissions data for

seven cement kilns were submitted for

review. The data represented more than

one year of hourly NOX concentration

values for each of the kilns. EPA

selected 2,000 ppm as an appropriate

MPC for cement kilns based on the

maximum values reported for these

units (see Docket A–2000–33, Item II–I–

3). For process heaters, the Agency

evaluated NOX emissions data

submitted in quarterly EDR reports for

six process heater units regulated under

the OTC NOX Budget Program. EPA

selected the 200 and 500 ppm MPC

values based on the maximum NOX

concentration values reported for these

units (see Docket A–2000–33, Item II–I–

3). EPA is proposing the default NOX

31990 Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules

MPC values for cement kilns and

process heaters principally because an

MPC value would be required in the

initial monitoring plan submittal if

these units were to become regulated

under the NOX SIP call. None of the

default NOX MPC values in appendix A,

section 2.1.2.1 of the current rule are

considered to be appropriate for either

cement kilns or process heaters, and

emission test results or historical CEMS

data might not be available at the time

of initial monitoring plan submittals

from these sources. Therefore, EPA has

proposed default NOX MPC values that

can be used for the initial MPC

determinations for cement kilns and

process heaters.

4. What Revisions Would Be Made to

the 7-day Calibration Error Test for

Peaking Units?

Background. For gas monitors, the 7-

day calibration error test is required

only for initial certification,

recertification, and occasionally as a

diagnostic test. It is not a routine,

required periodic QA test. The current

rule specifies that the 7-day calibration

error test data must be recorded while

the unit is operating. For peaking units,

the requirement for the unit to be

operating during the test can be

problematic. Because of the infrequent

and unpredictable nature of peaking

unit operation, the 7-day test may take

weeks or even months to complete.

Discussion of Proposed Changes.

Today’s proposal would revise the 7-day

calibration error test requirement for gas

monitors installed on peaking units in

appendix A, section 6.3.1, to require

data to be recorded for only three of the

seven test days with the unit operating.

The unit would not be required to

operate for the other four days of the

test.

5. What Changes Would Be Made to

QA/QC for Units With Very low NOX

Concentrations?

Background. The current rule requires

owners and operators of units with very

low SO2 and NOX concentrations to

perform RATAs and daily calibrations

on their CEMS. They are required to

perform linearity checks unless the span

value is 30 ppm or less (see appendix

A, section 6.2). Appendix B to part 75

provides an alternate daily calibration

specification for low emitters of SO2 and

NOX.

With respect to the daily calibrations

of SO2 and NOX monitors, the allowable

calibration error is currently 5 percent

of the span value. However, appendix B

to part 75 provides an alternate daily

calibration specification for low emitters

of SO2 and NOX. The alternative

specification for units with low

concentrations (for span values less than

200 ppm) is 10 ppm or less (based on

the absolute value of the difference

between the tag value of the calibration

gas and the instrument response). For

most low-emitting sources, the alternate

10 ppm specification is reasonable and

provides relief from the 5 percent of

span requirement, which is often too

stringent at low span values. However,

for very low span values, the 10 ppm

alternate specification is not stringent

enough and needs to be tightened. This

is especially important because many of

the new Acid Rain-affected gas turbines

that are being built have very low NOX

emissions. To illustrate, suppose that for

a very low span value of 10 ppm, the

upscale calibration gas for daily

calibrations is 9 ppm. When the 10 ppm

alternate calibration error specification

is applied, the monitor could actually be

inoperative, read 0 ppm, and the

calibration would still be passed.

Discussion of Proposed Changes.

Today’s proposal would modify the

alternate calibration error specification

in section 2.1.4(a) of appendix B, for

daily operation of SO2 and NOX

monitors. The 10 ppm alternate

specification would be retained for span

values greater than 50 ppm but less than

200 ppm. For span values less than or

equal to 50 ppm, the alternate

specification would be lowered to 5

ppm. EPA believes that a daily

calibration error limit of 5 ppm is both

reasonable and achievable, in view of

the measurement capability of today’s

gas analyzers. The Agency notes that 5

ppm is also the alternate low-emitter

performance specification in section

3.1(b) of appendix A, for initial

certification of SO2 and NOX monitors.

6. When Would EPA Require the

Application of a Calibration Correction

Factor to Linearity or RATA Test Data?

Background. After a routine daily

calibration error test, many Data

Acquisition and Handling Systems

(DAHSs) apply a mathematical

correction to the subsequent emission

data in order to account for the

calibration error. When a linearity check

or RATA is initiated after a daily

calibration, the current rule does not

specify whether the mathematical

correction factor should be applied to

the monitor readings recorded during

the linearity test or RATA.

Discussion of Proposed Changes. EPA

proposes to add language to sections

2.2.3(c) and 2.3.2(c) of appendix B,

requiring that if a mathematical

correction factor (calibration

adjustment) is applied by the DAHS

following a daily calibration error test,

the correction factor would be applied

to all subsequent data recorded by the

monitor until the next calibration error

test is performed, including any

linearity test or RATA data recorded in

that time interval.

7. What Changes Would Be Made to the

Flow-to-Load Ratio Test?

Background. In the May 26, 1999,

revisions to part 75, a new quarterly QA

test for flow monitors was promulgated:

the flow-to-load ratio test. Since

promulgation, EPA has received many

questions about the methodology,

relating both to the procedural aspects

of how the data analysis is done and to

the consequences when the test is

failed. As a result, EPA believes it is

necessary to clarify the test procedures

and to re-evaluate the issue of data

validation when the test is failed.

Discussion of Proposed Changes. The

proposed rule would allow you to take

the data exclusions listed in section

2.2.5(c) of appendix B before analyzing

the quarterly flow-to-load data. The

current rule appears to require an initial

data analysis with no exclusions and to

allow owners and operators to claim the

data exclusions only when the first

analysis results in a failed test. Proposed

section 2.2.5(c) also clarifies the issue of

co-firing as it pertains to data

exclusions. For units that co-fire

different fuels as part of their normal

operation, you could claim flow-to-load

test data exclusions for hours in which

fuels were not co-fired if the reference

flow RATA at normal load was done

while co-firing. Conversely, if the

reference flow RATA was done while

firing a single fuel, flow-to-load test data

exclusions could be claimed for hours

in which fuels were co-fired. The

proposed rule would also add a

statement to section 6.5(a) of appendix

A requiring that units which co-fire

fuels as the predominant mode of

operation perform RATAs while cofiring.

The proposal would change the

method of data validation following a

flow-to-load ratio test failure. Section

2.2.5(c)(8) of appendix B would allow

the flow rate data to be declared

conditionally valid, rather than invalid,

when a flow-to-load test is failed,

pending the results of a follow-up

investigation and/or a RATA. This

would allow data validation in case a

false positive is obtained with the flowto-load test. If the investigation fails to

reveal a problem and a confirming

RATA is passed hands-off, no data loss

would be incurred. The timeline for

investigating a flow-to-load test failure

would also be changed from ‘‘within 2

Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules 31991

weeks’’ to ‘‘within 14 unit operating

days.’’

The proposal would clarify the

instructions for multiple stack

configurations and allow you to do the

data analysis in one of two ways: (1)

Using combined flow and average unit

load; or (2) using the flow in each stack

and the corresponding unit load.

Finally, section 7.8 in appendix A of

part 75 would be revised to exempt nonload-based units (i.e., units that do not

produce electrical output or steam load)

from the flow-to-load ratio test.

8. When Would Three-Load Flow

RATAs Be Allowed for Routine Quality

Assurance?

Background. The current rule

specifies that an annual two-load flow

RATA is required for routine quality

assurance of a flow monitor. The rule

appears to require two-load testing and

to disallow three-load tests for routine

QA.

Discussion of Proposed Changes.

Today’s proposal would clarify in

section 2.3.1.3(c) of appendix B that you

may perform a three-load RATA in lieu

of any required two-load flow RATA.

9. What Changes Would Be Made to the

Data Analysis Time Period for SingleLoad Flow RATA Claims?

Background. In the May 26, 1999

revisions to part 75, a new provision

was promulgated, allowing annual flow

RATAs to be done at a single load level.

To qualify for the single-load option the

source must have operated at one load

level (low, mid, or high) for at least 85%

of the time since the last annual flow

RATA. A historical load analysis must

be done to confirm this, extending from

the date and hour of completion of the

last annual flow RATA to a date no less

than seven days prior to the date of the

current annual flow RATA. Some

utilities have asked if EPA would

consider changing this timeline. Two

suggestions have been offered: (1) Make

the end date of the analysis 21 days

ahead of the scheduled RATA date; and

(2) include in the analysis all data from

the quarter of the last RATA and

exclude all data from the quarter of the

current RATA.

Discussion of Proposed Changes. EPA

believes that the suggested revisions are

appropriate and would increase the

amount of time available to conduct test

planning. The proposal would modify

the timeline for the data analysis in

section 2.3.1.3(c) of appendix B, to

allow data to be analyzed from either:

(a) The date/hour of the last annual flow

RATA to a date no more than 21 days

prior to the current flow RATA; or (b)

the beginning of the quarter in which

the last annual flow RATA was done,

through the end of the calendar quarter

preceding the quarter of this year’s

annual flow RATA.

10. For Units That Do Not Produce

Electrical Output or Steam Load, at

What Operating Levels Should Gas and

Flow Monitor RATAs Be Performed?

Background. For units that do not

produce electrical or thermal output

(e.g., cement kilns and process heaters),

today’s proposed rule would provide a

method by which to establish the proper

‘‘operating levels’’ (as opposed to ‘‘load

levels’’) at which to perform relative

accuracy test audits (RATAs). The

proposed methodology is found in

section 6.5.2.1 of appendix A. The

rationale for, and a discussion of, these

proposed rule provisions is presented in

the following paragraphs.

Units subject to the monitoring and

reporting requirements of part 75 must

account for their emissions on a

continuous basis. Most units use

continuous emission monitoring

systems (CEMS) for this purpose. Part

75 requires periodic RATAs of all CEMS

to demonstrate that the data recorded by

the monitoring systems accurately

represent the SO2, NOX, and CO2

emissions from the affected unit. RATAs

of gas and flow monitors are required

for initial certification and either

semiannually or (if the relative accuracy

obtained on the previous RATA was ≤

7.5 percent) annually thereafter.

Section 6.5.1 of appendix A to part 75

requires that RATAs of gas monitors be

done at the ‘‘normal’’ load level. Section

6.5.2 of appendix A and section 2.3.1.3

of appendix B specify the load levels for

flow RATAs. In general, flow monitor

RATAs are performed at multiple load

levels (either two or three), with a few

exceptions (e.g., for flow monitors

installed on peaking units, only singleload RATAs are required). For multipleload flow RATAs, at least one of the

tested load levels must be the ‘‘normal’’

load level.

The method of establishing the

normal load level is found in section

6.5.2.1 of appendix A. First, the owner

or operator must determine the ‘‘range

of operation’’ for the unit or stack. The

range of operation extends from the

minimum safe, stable load to the

maximum sustainable load. Next, the

range of operation is divided into three

load levels. The first 30 percent of the

range of operation is considered to be

the ‘‘low’’ load level, the next 30

percent of the range is the ‘‘mid’’ load

level, and the remaining 40 percent of

the range is the ‘‘high’’ load level. The

‘‘normal’’ load level is determined by

performing an analysis of at least four

quarters of representative historical load

data. From these data a distribution

graph, such as a histogram, is

constructed showing the percentage of

the time that each load level has been

used historically. The most frequentlyused load level (low, mid, or high) is

automatically designated as the normal

load level. The owner or operator may

opt to designate the next most

frequently used load level as a second

normal load. Thus, the appropriate load

levels for the required RATAs of the gas

and flow monitors are established.

Discussion of Proposed Changes. As

previously discussed in section III.C of

this preamble, EPA anticipates that

under the NOX SIP call, sources such as

cement kilns or refinery process heaters,

which do not produce electrical or

thermal output, will become subject to

the monitoring and reporting

requirements of part 75. Consequently,

these sources will be required to

perform periodic RATAs of their gas

and flow monitors. Because these

sources do not produce electrical or

steam load, the concept of performing

‘‘normal load’’ RATAs cannot be

applied to them. Therefore, an

alternative RATA approach is needed

for these non-load-based units. Today’s

proposed rule would revise section

6.5.2.1 of appendix A to provide the

necessary alternative methodology.

The proposed RATA approach for

units that do not produce electrical or

steam load would be based on an

‘‘operating level’’ concept, rather than a

‘‘load level’’ concept. The method of

determining the normal operating level

for a non-load-based unit would be

much the same as the previouslydescribed method for determining the

normal load level for a load-based unit.

The owner or operator would determine

the range of operation, divide it into

three operating levels, and perform a

data analysis to establish the ‘‘normal’’

(i.e., most frequently-used) operating

level. The only significant difference

between the load-based and non-loadbased methodologies is that instead of

defining the range of operation in units

of electrical or steam load (i.e., in

megawatts or klb/hr of steam), the range

of operation of the non-load-based unit

would be defined in units of stack gas

velocity, in ft/sec. The range of

operation would extend from the

minimum expected velocity to the

maximum potential velocity. These

minimum and maximum gas velocities

could either be determined from

reference method test data or by using

Equation A–3a or A–3b (as applicable)

in section 2.1.4.1 of appendix A to part

75.

31992 Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules

EPA is aware that for new or newlyaffected units, four quarters of historical

load data (for load-based units) or flow

rate data (for non-load-based units) may

not be initially available to establish the

two most frequently-used operating

loads (or levels) and the normal

operating load (or level). Also, for a nonload-based unit which is not required to

install a flow monitor, the necessary

flow rate data for the determinations

will neither be available initially nor at

some point in the future. Therefore, a

revision to section 6.5.2.1 (c) of

appendix A is proposed, which would

allow the initial determinations to be

made as follows: (1) For load-based

units or for non-load-based units with

installed flow monitors, the

determinations could be based on less

than four quarters of data, or, if no

representative historical data are

available, projections of how the unit

will be operated could be used. Note,

however, that as soon as four

representative quarters of load or flow

rate data are obtained, the determination

of the two most frequently-used

operating loads (or levels) and the

normal operating load(s) (or level(s))

would have to be repeated; or (2) for

non-load-based units without installed

flow monitors, sound engineering

judgment (based on a combination of

knowledge of the unit, operating

experience, and actual stack gas velocity

measurements using EPA Method 2)

would be used to make the operating

level determinations.

Once the boundaries of the range of

operation are established and the

normal operating level(s) has been

identified, the owner or operator of a

non-load-based unit would perform the

required gas and flow RATAs in

essentially the same manner as for a

load-based unit. The only difference is

that in many sections of part 75 the term

‘‘operating level’’ would replace the

term ‘‘load’’ or ‘‘load level.’’ Today’s

proposed rule would modify the text in

several sections of part 75 (e.g., by

adding a parenthetical expression such

as ‘‘(or normal operating level)’’ after the

term ‘‘normal load’’), to indicate that the

provisions apply to both load-based and

non-load-based units. The affected rule

sections are: § 75.20(c)(2), sections 6.5.1,

6.5.2, 6.5.6.1(a), and 6.5.6.2(a) of

appendix A, and sections 2.3.1.3,

2.3.2(d), 2.3.2(f), 2.4(b), and Figure 1 of

appendix B.

G. Streamlining Changes

Background. There are a number of

rule sections in part 75 that have

expired, either on December 31, 1999, or

on March 31, 2000. For some, but not

all, of these expired rule provisions, part

75 contains new (replacement)

provisions, having effective dates of

January 1, 2000, or April 1, 2000,

respectively. The expired provisions are

a potential source of confusion to both

the regulated community and to

regulators in assessing compliance with

part 75. For instance, the rule contains

two sets of recordkeeping and reporting

provisions, one of which expired on

March 31, 2000, and the other which

became effective on April 1, 2000.

Removing the expired sections would

greatly facilitate part 75 implementation

and compliance.

EPA notes that the removal of expired

provisions will not change the fact that

those provisions were in effect up to

their respective expiration dates. EPA

intends to take appropriate enforcement

action against violations of those

provisions that occurred before the time

of expiration.

Discussion of Proposed Changes.

Today’s proposed changes would

streamline part 75 by eliminating

outdated language in the rule and by

removing a number of references

throughout part 75 to sections of the

rule that are no longer effective. This

streamlining would occur in several

places in the rule.

The May 26, 1999 revisions to part 75

became effective on June 25, 1999.

However, the regulatory language in

certain sections of the rule specified that

compliance with those sections would

not be required until a later date, April

1, 2000. The reason for the later

effective date of certain provisions was

to allow adequate time for development

of the necessary reporting software

associated with the rule changes. For

instance, on May 26, 1999, revised

recordkeeping and reporting sections

were added to the rule as new §§ 75.57,

75.58, and 75.59, to replace the previous

recordkeeping and reporting §§ 75.54,

75.55, and 75.56, as of April 1, 2000.

However, due to the April 1, 2000

effective date of the new sections, the

old sections could not be deleted from

part 75, because this would have left a

regulatory gap extending from June 25,

1999 (the effective date of the May 26,

1999 revisions) until April 1, 2000,

during which there would have been no

part 75 recordkeeping and reporting

requirements in effect. So, the old

sections were left in the rule and

language was added to them to indicate

that they were in effect only until April

1, 2000, and could no longer be used on

and after that date.

Other rule sections with April 1, 2000

expiration dates and effective dates

include the monitoring plan provisions

(§ 75.53, paragraphs (e) and (f) replaced

§ 75.53, paragraphs (c) and (d) on April

1, 2000) and the CO2 missing data

provisions (§ 75.35, paragraphs (b) and

(d) replaced § 75.35(c) on April 1, 2000).

Today’s proposal would remove from

part 75 all of the rule sections that

expired on April 1, 2000, and all textual

references to those sections.

Rule sections that only applied to

Phase I units and are now inapplicable

and textual references to those sections

would also be removed by today’s

proposal. For example, the 15 percent

relative accuracy specification for flow

monitors expired at the end of Phase I

(on December 31, 1999) and was

replaced on January 1, 2000, by the

current 10 percent standard. Today’s

proposed rule would revise appendix A,

section 3.3.4; appendix B, sections

2.3.1.2(b) and (c), and Figure 2 of

appendix B, to reflect this.

EPA has prepared a technical support

document (see Docket A–2000–33, Item

II–A–2) that identifies in tabular form

each of the streamlining revisions in the

proposed revisions to part 75.

H. Monitoring Plan Information

Submittal

1. What Changes Are Proposed in the

Timeline for Monitoring Plan Updates?

Background. In several places part 75

requires the monitoring plan to be

updated following a particular change

or event (such as a span adjustment).

For example, § 75.62(a)(2) requires

submittal of updated hardcopy portions

of the monitoring plan within 30 days

of the event associated with a change.

However, for events that require

updating of the electronic monitoring

plan, in many cases no similar deadline

for submitting the changes is specified

in part 75.

Discussion of Proposed Changes.

Today’s proposed rule would add

parallel requirements to §§ 75.62(a)(1)

and 75.73(e) for electronic monitoring

plan updates. It would require the

updated electronic monitoring plan to

be submitted within 30 days of the

event associated with a change, unless

otherwise specified in part 75.

2. Is EPA Changing the Process for

Electronic Submittal of Monitoring Plan

Updates and Certification/

Recertification Test Results?

Background. The current rule requires

that you submit the complete, up-todate electronic monitoring plan to EPA

at least 45 days prior to initial

certification, with each certification or

recertification application, and in each

quarterly report. The rule also requires

an electronic version of the test results

of all monitor certifications and

recertifications to be submitted to EPA.

Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules 31993

To best handle the data, EPA has

decided to develop a consistent process

for transmitting and receiving the

information.

Discussion of Proposed Changes.

Today’s proposal would add language to

§§ 75.62(a)(1), 75.63(c), and 75.73(e)(1),

requiring monitoring plan updates and

certification or recertification data to be

submitted electronically by a method

specified by EPA. The Agency’s goal is

to develop a process by which the

required electronic monitoring plan

information and test data could be

submitted at any time and the database

would be automatically updated. Until

the final goal is achieved, EPA may use

short-term, interim methods, such as

email, to receive the information. The

language in today’s proposed rule,

‘‘* * * by a method specified by the

Administrator,’’ is sufficiently general to

allow the use of such interim methods

until the goal is reached.

I. Appendix D—Miscellaneous Issues

Background. In addition to the

revisions of the definitions of pipeline

natural gas and natural gas described

above in section C of this preamble, EPA

believes that there are a number of other

changes and clarifications that would

improve implementation of the

excepted method allowed under

appendix D to part 75.

Discussion of Proposed Changes. The

proposed rule would modify section

2.1.2 of appendix D, as follows. EPA

proposes to relax the restriction in

section 2.1.2 which prohibits units

using the provisions of subpart H of part

75 to monitor and report NOX mass

emissions (i.e., units subject to a State

or federal NOX emission reduction

program) from apportioning the

measured hourly heat input at a

common pipe to the individual units

served by the pipe. For subpart H units,

revised section 2.1.2 would

conditionally allow apportionment of

the common pipe heat input, provided

that: (1) All of the units served by the

common pipe are affected units; and (2)

all of the units served by the pipe have

similar efficiencies (i.e., they are all

boilers or all combustion turbines).

Section 2.1.2 would be further revised

by removing the text from subsection

2.1.2.2 which describes a petition

process for obtaining permission to

apportion SO2 emissions to the

individual units served by a common

pipe. This petition process is considered

to be superfluous, because section 2.1.2

assumes that a certified appendix D fuel

flowmeter has been installed on the

common pipe. For SO2 emissions

accounting purposes, it is sufficient to

report the combined SO2 emissions for

the units served by the common pipe,

based on fuel flow rate measurements

made at the pipe. Thus, revised section

2.1.2 would simply state that if you

install a fuel flowmeter on a common

pipe, you should report combined SO2

emissions from the units served by the

pipe and you should apportion the

common pipe heat input to the

individual units using the appropriate

equation from appendix F to part 75

(e.g., Equation F–21a or F–21b).

The proposed rule would revise

section 2.1.4.1 of appendix D to exempt

oil-fired units that use a different grade

of oil only for unit startup from using

a certified fuel flowmeter. This

exemption parallels the existing

exemption for oil-fired units that use gas

fuel only for unit startup.

The proposed rule would also revise

section 2.1.4.3 of appendix D to clarify

the reporting requirements when

emergency fuel is burned. The owner or

operator would have the option during

emergency fuel combustion to either: (1)

Use and report maximum potential

values for heat input rate, fuel sulfur

content, GCV, and density; or (2) to use

measured values if a certified fuel

flowmeter is installed for the emergency

fuel and/or if fuel sampling and analysis

of the fuel is performed.

For temperature transmitter

calibrations, EPA would revise section

2.1.6.1(a) of appendix D to allow fixed

reference points (such as the freezing

point or boiling point of water) to be

used for the zero and upscale

calibrations.

For a subpart H unit for which you

report data only during the ozone

season and for which you use an orifice,

nozzle, or venturi-type appendix D fuel

flowmeter to determine heat input rate,

the proposal would clarify that the

owner or operator still would have to

use all calendar quarters in the year to

determine the deadline for the next

visual inspection of the primary element

(see § 75.74(c)(4)). This clarification is

appropriate because the 12 calendar

quarter time interval for conducting

these visual inspections is not

dependent on the reporting schedule.

For the optional fuel flow-to-load

ratio test in section 2.1.7, minor errors

in the instructions for common pipe and

multiple pipe configurations would be

corrected. Also, for the optional fuel

flow-to-load ratio test, the proposal

would allow data exclusions to be taken

before analyzing the data. The current

rule appears to require an initial data

analysis with no exclusions, and allows

the data exclusions to be claimed only

when the first analysis results in a failed

test. This was not the original intent

when EPA adopted this provision.

For units using the fuel flow-to-load

ratio test to extend the fuel flowmeter

accuracy test deadline, the proposal

would clarify the various reasons for

which owners or operators could claim

a one-quarter extension of the fuel

flowmeter accuracy test deadline.

Today’s proposal would clarify in

Tables D–4, D–5, and elsewhere in the

text that owners and operators could not

continue to use an assumed sulfur

content or GCV value, such as a contract

specification or the maximum value

from the previous year, if a sampled

value exceeded the assumed value. In

these circumstances the sampled value

would become the new assumed value.

Guidelines would be added to section

2.3.2.1.2, explaining how to apply the

results of periodic sulfur and GCV

samples. Owners and operators would

have to begin using the new values as

of the date when the sample results

were received (not retroactively to the

date the sample was taken).

A clarification would be added that

the demonstrations of sulfur content

and GCV variability described in

sections 2.3.5 and 2.3.6 are options, not

requirements, for units that combust

other gaseous fuels (fuels that do not

qualify as either pipeline natural gas or

natural gas) and choose not to perform

daily GCV sampling and hourly fuel

sulfur content sampling, respectively.

Also, these sections would be revised to

make clear that, as stated in sections

2.3.1.4 and 2.3.2.4, the 720-hour

demonstration methodology may be

used to demonstrate that a particular

fuel meets the appropriate GCV and/or

sulfur content requirements to qualify as

pipeline natural gas or natural gas.

The missing data requirements for the

sulfur content of gaseous fuels in Table

D–6 would be changed. All of the

missing data values would be based on

the total sulfur content of the gas. For

pipeline natural gas, a missing data

value of 0.002 lb/mmBtu is proposed.

For natural gas, the missing data value

would be an emission rate (in lb/

mmBtu) calculated from Equation D–1h,

using the lesser of: (a) The maximum

total sulfur content specified in the fuel

contract; or (b) 1.5 times the highest

total sulfur value from the previous

year’s samples. For gaseous fuels

sampled daily, the substitute data value

would be 1.5 times the highest total

sulfur content obtained in the previous

30 daily samples. For gaseous fuels

sampled hourly, the missing data value

would be the highest total sulfur content

from the previous 720 hourly samples.

The reason for selecting the 0.002 lb/

mmBtu value for pipeline natural gas

(which exceeds the lb/mmBtu

equivalent of the 0.5 gr/100 scf total

31994 Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules

sulfur limit in the definition of pipeline

natural gas) and for using the 1.5

multipliers is to ensure that the missing

data values will be higher than the

values normally used in the calculations

from Table D–5.

Equations D–10 and D–11 would be

removed from section 3.4.3(b). These

equations are not needed because they

are redundant with equations F–21a and

F–21b in appendix F. A new equation,

D–15a, which gives the unit heat input

rate when multiple fuels are burned

during the hour, would be added to

section 3.5.4.

Sections 2.3.1.4(b) and 2.3.2.4(b) of

appendix D would be revised to require

initial and periodic sampling of pipeline

natural gas and natural gas for

documenting the total sulfur content of

fuel. The proposed sampling frequency

is semiannual and whenever ‘‘it is

reasonable to believe that the fuel

composition has changed significantly.’’

EPA solicits comment on the

acceptability of this rather subjective

‘‘reasonability’’ criterion for

determining when an additional sample

is required. For compliance purposes,

more precise language such as, ‘‘Take an

additional sample whenever there is any

change to the contract or fuel supply to

the unit, such that the latest sample is

no longer representative of the fuel

currently being combusted,’’ may be

more appropriate.

For fuels that qualify as pipeline

natural gas, the 0.0006 lb/mmBtu

default SO2 emission rate would

continue to be used. For natural gas,

revised Equation D–1h would be used to

calculate the SO2 emission rate, based

on the total sulfur content sampling

results.

Two new sections, 2.3.1.4(c) and

2.3.2.4(c), would be added to appendix

D, to state that if the results of periodic

sampling show exceedances of the

applicable total sulfur limits, the fuel

would have to be reclassified.

Finally, as previously noted under

section III.C.3 of this preamble, fuel

flow rate missing data provisions for

non-load-based units (such as cement

kilns and process heaters) would be

added to section 2.4 of appendix D.

Guidelines for creating and using

optional ‘‘operational bins’’ for

determining appropriate fuel flow rate

missing data values for non-load-based

units would be added to appendix C of

part 75, as new section 4.

J. Reporting and Recordkeeping

1. Will Certification and Recertification

Test Notice Requirements Change?

Background. For initial certifications,

the current rule requires at least 45 days

notice before the first date of scheduled

testing. For recertifications, 45 days of

advance notice is required when all

recertification tests are required (full

recertification), but only 7 days notice is

required when all of the tests are not

required (partial recertification). This

raises two questions: (1) Whether the

notification requirements should be the

same for both certifications and

recertifications; and (2) how much

advance notice is actually needed.

Discussion of Proposed Changes. The

proposed rule changes would revise

§§ 75.20 and 75.61 to make a single

notification requirement of 21 days for

initial certifications and for all

recertifications, regardless of whether

all of the tests are required. Based on the

experience to date in implementing part

75, EPA believes the existing seven day

notice provides too little time for State

and local agency personnel and EPA

personnel to schedule site visits to

observe the recertification testing.

Conversely, the Agency believes that 45

days notice is too far in advance,

especially for recertifications. Test

observation is a critical component of

agency oversight of the Acid Rain

Program monitoring requirements, and

the 21 day test notification requirement

would ensure that the agencies can

successfully fulfill this responsibility.

2. Will EPA Continue to Accept

Hardcopy Certification Statements?

Background. The current rule allows

either electronic or hardcopy signatures

and certification statements for

quarterly report submittals. This creates

unnecessary extra work for the EPA

analysts who must document the receipt

of all compliance certifications.

Discussion of Proposed Changes.

Today’s proposal would revise

§ 75.64(d) to eliminate the option to

submit hardcopy compliance

certifications and would, instead,

require electronic submittal. Because of

the electronic reporting requirements for

all other quarterly report elements, all

designated representatives will have the

technical capability to submit electronic

certifications. This rule change should

therefore reduce the reporting burdens

on both the regulated entities and EPA

staff.

3. Will EPA Allow the Electronic

Storage of Quality Assurance/Quality

Control Plan Information?

Background. Section 1 of appendix B

requires you to develop a quality

assurance/quality control (QA/QC)

program for all approved monitoring

systems at a facility. The QA/QC

program must include a written plan

that provides detailed procedures and

operations for certain activities, such as

preventive maintenance and quality

assurance test procedures. You must

make this information and any ancillary

supporting information from the

monitor manufacturer (for example,

maintenance manuals) available to

auditors upon request. EPA has received

a request from one utility to allow the

QA/QC plan information to be stored

electronically rather than in hardcopy.

Discussion of Proposed Changes.

Today’s proposal would revise

appendix B, section 1, to allow QA/QC

plan information to be stored

electronically, provided that the

information can be made available in

hardcopy to inspectors or auditors upon

request. Part 75 already allows

electronic storage of hardcopy

monitoring plan information, if the

information can be furnished in

hardcopy upon request during an audit

(see § 75.53(e)). The proposed rule

revision would use an approach for QA/

QC plans that is consistent with this

existing monitoring plan provision.

K. NOX Monitoring in Multiple Stacks/

Common Stacks

Background. For an exhaust

configuration consisting of a main stack

and a bypass stack, if the use of the

bypass stack is limited by regulation or

permit to emergency malfunctions of the

flue gas desulfurization system, § 75.16

of the current rule allows the maximum

potential SO2 concentration to be

reported during the malfunction in lieu

of installing monitors on the bypass

stack. For NOX, however, the rule has

no corresponding provision. Rather, it

appears that monitoring of the bypass

stack or monitoring of the duct(s)

leading to the bypass stack are the only

available options. Also, the current

multiple stack and bypass stack

provisions for NOX (see §§ 75.17(c) and

75.72, paragraphs (c) and (d)) are not

particularly clear or consistent.

Discussion of Proposed Changes. EPA

would clarify and expand the

instructions for SO2 and NOX

monitoring in multiple and bypass

stacks in §§ 75.16(c) and 75.17(c), and in

§ 75.72, paragraphs (c) and (d) in this

proposal. EPA would also add a new

provision to §§ 75.17(c) and 75.72(c), for

configurations consisting of a main

stack and a bypass stack, that allows the

maximum potential NOX emission rate

to be reported when the bypass stack is

used. Instructions would also be

provided for reporting other parameters

(i.e., SO2, CO2, flow rate, moisture, heat

input rate) during hours when the

bypass stack is used.

Today’s proposed rule would revise

the language in § 75.16(c)(3) which

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restricts the reporting of the maximum

potential SO2 concentration (MPC) to

emergency situations in which the flue

gas desulfurization (FGD) system is

bypassed. Today’s rule would allow the

MPC to be reported in lieu of

monitoring at the bypass stack, provided

that the use of the bypass stack is

limited to unit startups, emergency

situations, and routine maintenance of

the FGD system and the main stack.

Instructions would also be provided for

reporting other parameters (i.e., NOX ,

CO2, flow rate, moisture, heat input rate)

during hours when the bypass stack is

used.

L. Appendix E Issues

1. How Will the Proposed Rule Affect

Appendix E Test Notifications and

Submittal of Hardcopy Recertification

Test Results?

Background. For routine appendix E

retests and recertification testing, the

rule is currently unclear regarding the

test notification requirements and

submittal of the hardcopy test results.

Discussion of Proposed Changes. The

proposal would add a requirement to

§ 75.61(a)(5) to provide notice of routine

appendix E retesting at least 21 days

prior to the start of the testing. It would

also add a requirement to

§ 75.61(a)(1)(ii) to provide notice of

appendix E recertification testing.

Finally, the proposed rule would add a

requirement to §§ 75.60(b) and 75.73(d)

to submit the results of routine

appendix E retest results in hardcopy to

the appropriate Region and State, upon

request. This is exactly analogous to the

requirement in §§ 75.60(b)(6) and

75.73(d)(4) to provide hardcopy RATA

results.

2. Will the Frequency of Retesting of

Appendix E Units Be Changed?

Background. Section 2.2 of appendix

E requires periodic retesting for quality

assurance purposes. The timeline for

retesting is every 3,000 operating hours

or the five year anniversary of the

operating permit, whichever is sooner.

These requirements are difficult to

implement and to track. The permit

anniversary date is not a good reference

point. Also, the rule does not indicate

whether the 3,000 operating hours are

fuel-specific.

Discussion of Proposed Changes.

Today’s proposal would revise

appendix E, section 2.2, to require

retesting for all fuels, once every 20

calendar quarters. The quarter of the last

test would serve as the reference point,

similar to the methodology used for

setting RATA and fuel flowmeter

accuracy test deadlines. Fuel-specific

missing data procedures would be used

when a retest is not completed by the

deadline. For each fuel, the new

correlation curve obtained in a retest

would be used for reporting, beginning

with the first operating hour in which

the fuel is combusted after completion

of the retest. This is analogous to the

part 75 requirement to apply CEMS bias

adjustment factors beginning with the

first operating hour after completion of

a RATA.

3. How Will the Timeline for

Unscheduled Appendix E Retests Be

Revised?

Background. Section 2.3 of appendix

E requires retesting within 10 unit

operating days or 180 calendar days

(whichever occurs first) whenever the

monitored operating parameters are

exceeded for more than 16 consecutive

hours or the data availability, since the

last test, is less than 90 percent. For

many units, 10 operating days is not a

sufficient amount of time to schedule a

retest and perform the testing.

Discussion of Proposed Changes. EPA

proposes to revise appendix E, section

2.3, to change the 10 unit operating day

requirement to 30 unit operating days.

This change would provide sufficient

time to schedule and perform the tests

and to meet the applicable test

notification requirements.

4. How Will Appendix E Missing Data

Procedures Be Changed?

Background. For missing data

purposes, appendix E prescribes that the

highest NOX emission rate from the

most recent set of baseline correlation

tests be reported for each hour of the

missing data period. There are three

situations for which this missing data

scheme may be inappropriate: (1) When

the measured hourly heat input rate is

higher than the highest heat input rate

from the baseline correlation tests; (2)

for a unit with add-on NOX controls, if

the controls are not in operation or it is

not possible to document that the

controls are operating properly; and (3)

when emergency fuel is combusted.

Discussion of Proposed Changes. To

address the concerns about situations in

which the current missing data

procedures may be inappropriate, the

proposed rule would add to section 2.5

of appendix E a requirement to calculate

a fuel-specific maximum potential NOX

emission rate (MER) for each type of

fuel combusted by the unit and would

add three new sections, 2.5.2.1, 2.5.2.2,

and 2.5.2.3, to require reporting of the

fuel-specific NOX MER for cases (2), and

(3), described above. For fuel mixtures,

EPA would require substitution of the

highest MER value for the fuels in the

mixture.

For case (1) described above, two

reporting options would be allowed.

Whenever the heat input rate for a given

unit operating hour exceeds the highest

heat input rate from the baseline

correlation tests, the owner or operator

could either: (a) Report the hourly NOX

emission rate as the higher of the linear

extrapolation of the correlation curve or

the fuel-specific MER; or (b) report 1.25

times the highest NOX emission rate on

the correlation curve, not to exceed the

fuel-specific MER. Note that for units

with NOX emission controls, the use of

an extrapolated NOX emission rate

under (a), above, and the use of 1.25

times the highest value on the

correlation curve under (b), above,

would be disallowed, and the MER

would have to be reported for any hour

in which the emission controls could

not be documented to be in proper

operation.

5. How Will the Appendix E Testing

Requirements for Emergency Fuel Be

Changed?

Background. The current rule allows

the designated representative for an

appendix E unit to petition the

Administrator for an exemption from

appendix E testing for emergency fuel.

Many Phase II Acid Rain units

submitted such petitions with their

initial certification applications, and the

petitions were approved.

Discussion of Proposed Changes.

Today’s proposed rule would revise

section 2.1.4 of appendix E to remove

the requirement to petition the

Administrator to obtain an exemption

from appendix E testing for emergency

fuel. EPA believes that the petition

process is unnecessary, provided that

the unit has a federally enforceable

permit which restricts the combustion

of a particular fuel to emergency

situations. Therefore, the proposed rule

would exempt emergency fuel from

appendix E testing if the unit has the

necessary permit and if documentation

is provided in the monitoring plan for

the unit.

M. Reference Methods

1. Which Code of Federal Regulations

Versions of Reference Methods Are To

Be Used?

Background. In the May 26, 1999

revisions to part 75, EPA specified that

only particular versions of Reference

Methods 6C, 7E, and 3A (the methods

used for gas RATAs) be used. Those

versions are the 1995, 1996, and 1997

Code of Federal Regulations versions of

the methods. This provision was added

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to the rule because EPA at that time had

proposed substantive revisions to these

methods for the New Source

Performance Standards (NSPS) Program

that were not appropriate for the Acid

Rain Program. However, the revisions to

the reference methods were never

finalized, therefore the reference to

particular versions is no longer needed.

Removing the caveat will eliminate

confusion because these reference

methods have been basically the same

in all versions of the Code of Federal

Regulations, from 1988 through 1999.

Discussion of Proposed Changes.

Today’s proposal would revise

§ 75.22(a) and appendix A, section 6.5.6,

to remove from the rule all references to

the 1995, 1996, and 1997 Code of

Federal Regulations versions of

Reference Methods 6C, 7E, and 3A.

2. Are There Other Changes to Reference

Methods?

Background. Three issues have arisen

regarding the part 60 reference test

methods used to certify and quality

assure part 75 CEMS. First, when

measurement of the stack gas moisture

content is required to determine the

stack gas molecular weight, § 75.22(a)(4)

allows the source to use any of the

alternative moisture techniques listed in

section 1.2 of Method 4. This includes,

among other things, ‘‘previous

experience.’’ Second, when an

automated version of Method 2 is used

for flow RATA testing, often all four

available sample ports are occupied

simultaneously with velocity probes

which are bolted in place. This can

make it difficult to obtain a moisture

sample once every three runs or once

every clock hour, as required in section

6.5.7 of appendix A. Third, questions

have arisen regarding the manner in

which NOX compliance tests and

RATAs are performed for combustion

turbines.

Discussion of Proposed Changes.

Today’s proposed rule would revise

§ 75.22(a)(4), to clarify that for purposes

of determining the stack gas molecular

weight during a part 75 flow RATA, the

only acceptable alternative moisture

methodology listed in section 1.2 of

Method 4 is the wet bulb-dry bulb

measurement technique. The other

methodologies listed (‘‘drying tubes,’’

‘‘condensation techniques,’’

‘‘stoichiometric calculations,’’ and

‘‘previous experience’’) are not defined

precisely enough to approve their use.

In contrast, the wet bulb-dry bulb

technique is well-established and is

generally familiar to emission testers.

Today’s proposal would also revise

section 6.5.7 of appendix A to allow, for

purposes of determining stack gas

molecular weight during part 75 flow

RATAs, moisture measurements to be

made before and after a series of RATA

runs at a particular load level (low, mid,

or high), in lieu of measuring moisture

every three runs or once every clock

hour, as required by the current rule.

The results of the before and after

moisture measurements would be

averaged arithmetically, and the average

value would be applied to all RATA

runs in the series. Note, however, that

this moisture measurement option could

only be used if the before and after runs

were performed no more than three

hours apart. Section 6.5.7 would be

further revised by clarifying that

sufficient measurement time must be

allowed at each traverse point of a flow

RATA to ensure that stable temperature

readings are obtained, particularly for

the first point at which data are taken

after a probe is moved from one port to

the next.

Finally, today’s proposed rule would

revise § 75.22 and section 6.5.10 of

appendix A, to allow the use of EPA

Method 20, as an alternative to Method

7E, for relative accuracy test audits

(RATAs) of NOX monitoring systems

installed on combustion turbines.

Further, the proposed rule would revise

section 6.5.6(b) of appendix A, to allow

the reference method measurement

points specified in section 6.1.2 of

Method 20 to be used for a Method 7E

RATA of a NOX monitoring system

installed on a combustion turbine. EPA

believes these added flexibilities will

simplify certification and quality

assurance testing for combustion

turbines. The rationale for these two

new provisions follows.

Many utilities are constructing new

gas turbines. Almost invariably, NOX

monitoring systems will be installed on

these units. EPA Method 20 is the NOX

compliance test method for new gas

turbines, under subpart GG of 40 CFR

part 60, the New Source Performance

Standards (NSPS) for stationary sources.

Method 7E is the method currently

prescribed by part 75 as the reference

method for NOX RATAs. Today’s

proposed rule would allow Method 20

data to be used for a dual purpose, that

is, as compliance test data for NSPS and

as reference method test data for the

RATA of the part 75 NOX monitoring

system. This would make a second

reference method test using Method 7E

unnecessary.

EPA believes that for a Method 7E

RATA of a NOX monitoring system

installed on a combustion turbine,

allowing the Method 20 sample points

to be used as the reference method

measurement points is potentially

beneficial, particularly if the stack or

duct being tested is rectangular. The

provisions in section 3.2 of Performance

Specification No. 2 (PS No. 2) in

appendix B of 40 CFR part 60 specify

the required reference method

measurement points for gas monitor

RATAs. However, section 3.2 of PS No.

2 only addresses the point layout for

circular stacks. There are no clear

guidelines for rectangular stacks or

ducts. On the other hand, section 6.1.2

of Method 20 does have a procedure for

selecting reference method

measurement points which applies to

both circular and rectangular stacks or

ducts.

N. Appendix G Revisions

Background and Discussion of

Proposed Changes. Today’s proposed

rule would revise section 2.3 of

appendix G to expand the applicability

of Equation G–4 to oil-fired units.

Currently, section 2.3 restricts the use of

Equation G–4 to gas-fired units (as

defined in § 72.2). There is no technical

reason to prohibit the use of this

equation by oil-fired units. Many gasfired units that currently use Equation

G–4 occasionally combust fuel oil.

During the oil-burning hours, Equation

G–4 is still used to report CO2

emissions, except that an FC factor of

1,420 scf/mmBtu (for oil) instead of the

usual FC factor of 1,040 scf/mmBtu for

natural gas is used. Allowing the use of

Equation G–4 for oil-fired units would

enable the owner or operator to report

hourly CO2 emissions in tons per hour,

instead of using Equation G–1, which

requires CO2 reporting on a tons per day

basis. This option would not only

simplify emission reporting for oil-fired

units but would enable EPA to perform

meaningful electronic audits of the

reported CO2 emissions, as the hourly

heat input (i.e., the term ‘‘H’’ in

Equation G–4) is the only variable in

Equation G–4 and is required to be

reported each hour in the EDR.

However, the cumbersome term WC (i.e.,

lbs of carbon burned per day) in

Equation G–1 is not reported anywhere

in the EDR.

O. Technical Changes and Corrections

Background. An important objective

of this proposed rulemaking is to make

technical changes and corrections to

part 75. These changes and corrections

are necessary to eliminate printing,

typographical, and grammatical errors,

to correct or clarify cross references,

and, in a few instances, to ensure that

the specific rule language is consistent

with the Agency’s intent. None of these

technical corrections and changes adds

new requirements or substantively

Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules 31997

affects the obligations of the entities that

must comply with part 75 requirements.

The technical changes and corrections

fall into several categories. In the first

category are efforts to rewrite rule

provisions to increase clarity and to

accord with other provisions of part 75.

In the second category are corrections

and clarifications of equations,

including the definitions of certain

variables. The final category of technical

changes consists of corrections of

printing, typographical, and

grammatical errors. Included in this

category are repetitive words and

phrases, misspelled words, and

misplaced punctuation.

Discussion of Proposed Changes. The

technical support document (Docket A–

2000–33, Item II–A–2) provides a

specific description for each of these

technical changes and corrections.

P. What Other Changes is EPA

Proposing to the Federal NOX Budget

Trading Program Today?

Background and Discussion of

Proposed Changes. We are proposing a

number of minor changes to the Federal

NOX Budget Trading Program in part 97

to correct errors or clarify provisions.

For example, one proposed change is to

correct the definition of ‘‘percent

monitor data availability’’ in § 97.2. This

definition is used to allow units to

qualify for early reduction credits in

§ 97.43(a)(1) or to qualify to use data as

a baseline for allowance allocations for

opt-in units under § 97.84(b). EPA

intended to make this definition

consistent with the term’s use in the

part 75 monitoring rule, except that

‘‘percent monitor data availability’’

would apply only for an ozone season

instead of for a year’s worth of data on

a rolling basis. Some companies have

pointed out that the current definition is

inconsistent because hours when the

unit does not operate are still used in

the calculation. This means that a unit

might not be able to meet the required

90 percent monitor data availability

simply because the unit does not

operate for many hours during the

ozone season. EPA is proposing to

revise the definition so that it refers to

the percentage of unit operating hours

with valid, quality-assured data during

an ozone season, rather than the

percentage of all 3,672 hours during an

ozone season.

As a further example of changes to

part 97, the definition of ‘‘ NOX

allowance’’ in § 97.2 provides that the

term includes NOX allowances from an

approved State NOX Budget Trading

Program, except for purposes of certain

listed sections relating to allocations.

Section 97.40, defining the trading

program budget, is added to that list of

sections. In addition, EPA is correcting

the reference in § 97.42(e)(2) to

allowances ‘‘deducted under paragraph

(c)(1) of this section’’ to refer instead to

‘‘paragraph (e)(1) of this section.’’ Other

proposed changes to part 97 are

addressed in a technical support

document (Technical Support

Document, Docket A–2000–33, Item II–

A–2). EPA believes these minor changes

may reduce confusion and improve

consistency within part 97.

Finally, EPA is proposing a number of

other minor changes to part 78 to make

existing administrative appeal

procedures applicable to decisions of

the Administrator under part 97. The

changes to part 78 are addressed in a

technical support document (Technical

Support Document, Docket A–2000–33,

Item II–A–2).

IV. Administrative Requirements

A. Public Hearing

If requested as specified in the DATES

section of this document, 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 document. 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

document.

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 document).

B. Public Docket

The Docket for this regulatory action

is A–2000–33. 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 document.

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), Public

Law 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

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205 do not apply when they are

inconsistent with applicable law.

Moreover, section 205 allows EPA to

adopt an alternative other than the least

costly, most cost-effective, or least

burdensome alternative if the

Administrator publishes with the final

rule an explanation why that alternative

was not adopted. Before EPA establishes

any regulatory requirements that may

significantly or uniquely affect small

governments, including tribal

governments, it must have developed

under section 203 of the UMRA a small

government agency plan. The plan must

provide for notifying potentially

affected small governments, enabling

officials of affected small governments

to have meaningful and timely input in

the development of EPA regulatory

proposals with significant federal

intergovernmental mandates, and

informing, educating, and advising

small governments on compliance with

the regulatory requirements.

This 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. EPA will continue to use its

outreach efforts related to part 75

implementation, including a policy

manual that is updated regularly, to

inform, educate, and advise all

potentially impacted small governments

about compliance with part 75.

E. Paperwork Reduction Act

The information collection

requirements in 40 CFR parts 72, 75, 78

and 97 affect two EPA programs, the

Acid Rain Program and the Federal NOX

Budget Trading Program. There are two

program ICRs currently in place that

account for the basic recordkeeping and

reporting burdens associated with 40

CFR parts 72, 75, 78 and 97. First, the

Acid Rain Program ICR1633.12, (OMB

No. 2060–0258) addresses the costs for

units affected by the Acid Rain Program.

The NOX SIP Call ICR1857.02, (OMB

No. 2060–0445) addresses the costs,

including NOX mass monitoring costs,

by both Acid Rain Program (ARP) units

and non-ARP units in the NOX Budget

Trading Program.

Most of the changes associated with

this rulemaking are aimed at fine tuning

the regulations in response to issues

raised during the ongoing

implementation of part 75. Thus, they

do not significantly affect the burden

estimates included in the two existing

ICRs. Table 1, below, categorizes the

proposed changes to parts 72 and 75,

and proposed associated changes to part

97, as recordkeeping and reporting

burden/cost neutral or as burden/cost

reducing; none of the changes is

expected to significantly increase

burdens or costs. (The remaining

changes to parts 72, 78, and 97 do not

affect recordkeeping and reporting

requirements.)

Further, the Agency expects the

changes to have minimal impact on

existing program ICRs because many of

the changes merely serve to make

additional flexibilities feasible. For

example, many of the proposed rule

revisions to the LME section will clarify

how the rule applies to non-ARP SIP

Call units that use part 75 for NOX mass

monitoring. The existing rule language

is unclear for these non-ARP units. The

changes make use of the LME provisions

feasible for non-ARP units so that the

scope of applicability to non-ARP units

is not expected to be significantly

different than that for ARP units.

The SIP Call ICR assumed none of the

non-ARP units would take advantage of

the reduced burdens and costs

associated with the LME provisions

because those estimates only related to

burden incurred through the year 2002.

In future years, as LMEs avail

themselves of the proposed provisions,

it is estimated that there will be burden

reductions. These reductions will be

reflected in the next revisions to the SIP

Call ICR.

Table 1—Summary of Impacts of Major Rule

Revisions

A. Rule Revisions Assumed To Be Cost/

Burden Neutral

Pipeline natural gas definition revision,

and other definition clarifications

Standardization of deadlines for various

activities/reports/notices

Data validation clarifications

Span/range clarifications

Bypass monitoring flexibility changes

Clarifications for Subpart H missing data

General LME clarifications

Missing data options relating to fuel type,

degree of control, and non-load based

units

Alternative bypass stack monitoring

options

Other miscellaneous changes

B. Rule Revisions Assumed To Decrease

Costs/Burdens

Expanded clarification of LME for Subpart

H monitoring

Although not indicated in Table 1,

there are two primary ways in which the

proposed parts 72, 75 and 97 revisions

could result in some increased burden

or cost. First, the regulated industry and

State and local agencies involved with

part 75 monitoring will have to review

the revised regulation to understand the

changes. The existing ARP and SIP Call

ICRs have accounted for this increase in

a line item for ongoing rule review.

Nevertheless, it is important to note that

new units just initiating part 75

monitoring in response to the NOX SIP

Call will experience less burden as a

consequence of the numerous

clarifications, the specific changes to

address NOX mass monitoring issues,

and the removal of outdated sections.

Taken as a whole, EPA does not believe

that the regulatory review burdens will

be affected significantly.

The second type of burden or cost

increase would be associated with any

required data acquisition and handling

system (DAHS) software changes that

may be necessary to the extent the rule

revisions affect recording and reporting

data in the required electronic data

formats. Generally, EPA has attempted

to minimize any DAHS impacts

associated with these revisions. There

are some optional elements of the

proposed revisions that would require

DAHS software changes, but only if the

owner or operator decides to take

advantage of the option for its

circumstances. EPA believes many

sources will only avail themselves of

these types of changes as part of other

routine monitoring system component

upgrades. Consequently, the expected

impact in this area is also expected to

be minimal. An agency may not conduct

or sponsor, and a person is not required

to respond to a collection of information

unless it displays a valid OMB control

number. The OMB control numbers for

EPA’s regulations are listed in 40 CFR

part 9 and 48 CFR chapter 15.

The Agency requests comment on its

assessment of information burden

imposed by these requirements. An ICR

amendment was not prepared because

the changes were anticipated to be

minimal in the context of the two

existing ICRs. Send comments on the

ICRs to the Director, Collection

Strategies Division; U.S. Environmental

Protection Agency (2822); 1200

Pennsylvania Ave., NW, Washington,

DC 20460; and to the Office of

Information and Regulatory Affairs,

Office of Management and Budget, 725

17th St., NW, Washington, DC 20503,

marked ‘‘Attention: Desk Officer for

EPA.’’ Include the ICR in any

correspondence. Additional information

in support of the Agency’s estimate is

contained in the docket for this

proposed rulemaking.

F. Regulatory Flexibility

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 under the Administrative

Procedure Act or any other statute

unless the agency certifies that the rule

will not have a significant economic

impact on a substantial number of small

Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules 31999

entities. Small entities include small

businesses, small not-for-profit

enterprises, and governmental

jurisdictions.

The EPA has determined that it is not

necessary to prepare a regulatory

flexibility analysis in connection with

this proposed action. For the Acid Rain

Program, these proposed revisions

would not result in increased impacts to

small entities.

For these reasons, I certify that today’s

proposed rule would 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 (‘‘NTTAA’’), Public Law

104–113, 15 U.S.C. 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.

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.

H. Executive Order 13175

Executive Order 13175, entitled

‘‘Consultation and Coordination with

Indian Tribal Governments’’ (65 FR

67249, November 6, 2000), requires EPA

to develop an accountable process to

ensure ‘‘meaningful and timely input by

tribal officials in the development of

regulatory policies that have tribal

implications.’’ ‘‘Policies that have tribal

implications’’ is defined in the

Executive Order to include regulations

that have ‘‘substantial direct effects on

one or more Indian tribes, on the

relationship between the Federal

government and the Indian tribes, or on

the distribution of power and

responsibilities between the Federal

government and Indian tribes.’’

This proposed rule does not have

tribal implications. It will not have

substantial direct effects on tribal

governments, on the relationship

between the Federal government and

Indian tribes, or on the distribution of

power and responsibilities between the

Federal government and Indian tribes,

as specified in Executive Order 13175.

Thus, Executive Order 13175 does not

apply to this rule.

In the spirit of Executive Order 13175,

and consistent with EPA policy to

promote communications between EPA

and tribal governments, EPA

specifically solicits additional comment

on this proposed rule from tribal

officials.

I. Executive Order 12898

Executive Order 12898 requires that

each federal agency make achieving

environmental justice part of its mission

by identifying and addressing, as

appropriate, disproportionately high

and adverse human health or

environmental effects of its programs,

policies, and activities on minorities

and low-income populations. The

technical revisions in this proposed rule

to various monitoring and other

requirements would have no impact on

emission levels or the location of

emission reductions. Thus, the

proposed rule revisions would not have

a disproportionately high and adverse

impact on minorities or low-income

populations.

J. Executive Order 13045

Executive Order 13045, entitled

‘‘Protection of Children from

Environmental Health Risks and Safety

Risks’’ (62 FR 19885, April 23, 1997),

applies to any rule that the Agency

determines (1) is ‘‘economically

significant’’ as defined under Executive

Order 12866 and (2) concerns an

environmental health or safety risk that

EPA has reason to believe may have a

disproportionate effect on children.

Today’s proposed rule is not subject

to Executive Order 13045 because it is

not expected to have an annual effect on

the economy of $100 million or more.

Further, EPA does not have reason to

believe that the environmental health

risks or safety risks addressed by this

action present a disproportionate risk to

children.

K. Executive Order 13132

Executive Order 13132, entitled

‘‘Federalism’’ (64 FR 43255, August 10,

1999), requires EPA to develop an

accountable process to ensure

‘‘meaningful and timely input by State

and local officials in the development of

regulatory policies that have federalism

implications.’’ ‘‘Policies that have

federalism implications’’ are defined in

the Executive Order to include

regulations that have ‘‘substantial direct

effects on the States, on the relationship

between the national government and

the States, or on the distribution of

power and responsibilities among the

various levels of government.’’

Under section 6 of Executive Order

13132, EPA may not issue a regulation

that has federalism implications, that

imposes substantial direct compliance

costs, and that is not required by statute,

unless the Federal government provides

the funds necessary to pay the direct

compliance costs incurred by State and

local governments, or EPA consults with

State and local officials early in the

process of developing the proposed

regulation. EPA also may not issue a

regulation that has federalism

implications and that preempts State

law, unless the Agency consults with

State and local officials early in the

process of developing the proposed

regulation.

The rule revisions in this proposed

action will not have substantial direct

effects on the States, on the relationship

between the national government and

the States, or on the distribution of

power and responsibilities among the

various levels of government, as

specified in Executive Order 13132.

This proposed action does not create a

mandate upon State, local, or tribal

governments, except to the extent such

governments own or operate an affected

source. Even in those cases, the

proposed rule revisions do not have

federalism implications and do not

impose significant compliance costs

beyond the costs already incurred under

part 75.

In the spirit of Executive Order 13132,

and consistent with EPA policy to

promote communications between EPA

and State and local governments, EPA

specifically solicits comment on this

proposed rule from State and local

officials.

List of Subjects

40 CFR Part 72

Environmental protection, Acid rain,

Administrative practice and procedure,

Air pollution control, Continuous

emission monitoring, Electric utilities,

Nitrogen oxides, Reporting and

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recordkeeping requirements, Sulfur

oxides.

40 CFR Part 75

Environmental protection, Acid rain,

Administrative practice and procedure,

Air pollution control, Carbon dioxide,

Continuous emission monitoring,

Electric utilities, Nitrogen oxides,

Reporting and recordkeeping

requirements, Sulfur oxides.

40 CFR Part 78

Environmental protection, Acid rain,

Administrative practice and procedure,

Air pollution control, Continuous

emission monitoring, Electric utilities,

Nitrogen oxides, Reporting and

recordkeeping requirements, Sulfur

oxides.

40 CFR Part 97

Environmental protection,

Administrative practice and procedure,

Air pollution control, Continuous

emission monitoring, Electric utilities,

NOX Budget Program, Reporting and

recordkeeping requirements.

Dated: May 16, 2001.

Christine Todd Whitman,

Administrator.

For the reasons set out in the

preamble, title 40 chapter I of the Code

of Federal Regulations is proposed to be

amended as follows:

PART 72—PERMITS REGULATION

1. The authority citation 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:

a. Revising the definitions of

‘‘Cogeneration unit’’, ‘‘Continuous

emission monitoring system or CEMS’’,

‘‘Hour before and after’’, ‘‘Maximum

potential NOX emission rate’’, ‘‘Missing

data period’’, ‘‘Monitor accuracy’’,

‘‘Pipeline natural gas’’, ‘‘Stack operating

hour’’, and ‘‘Unit operating hour’’;

b. In the definition of ‘‘Automated

data acquisition and handling system’’

by adding the words ‘‘moisture

monitors,’’ before the word ‘‘opacity’’;

c. In the definition of ‘‘By-pass stack’’

by removing the hyphen from the word

‘‘bypass’’;

d. In paragraph (1) of the definition of

‘‘Calibration error’’ by adding the word

‘‘a’’ before the words ‘‘gaseous

monitor’’;

e. In the definition of ‘‘Compliance

plan’’ by adding a closing parenthesis

after the second instance of the words

‘‘part 76 of this chapter’’;

f. In the definition of ‘‘Continuous

opacity monitoring system or COMS’’ by

revising the words ‘‘systems are

component parts’’ in the second

sentence to read ‘‘components are’’, and

in paragraph (2) by revising the word

‘‘A’’ to read ‘‘An automated’’;

g. Revising paragraph (2) of the

definition of ‘‘Emergency fuel’’;

h. In the definition of ‘‘Fuel flowmeter

QA operating quarter’’ by adding the

word ‘‘cumulative’’ after the words ‘‘at

least 168’’ and removing the words ‘‘or

more’’ at the end of the definition;

i. Remove the definition of ‘‘Heat

input’’ and add in its place a new

definition ‘‘Heat input rate’’;

j. Remove the definition of

‘‘Maximum rated hourly heat input’’

and add in its place the definition for

‘‘Maximum rated hourly heat input

rate’’;

k. In the definition of ‘‘Natural gas’’

by revising the second sentence and by

removing the word ‘‘meet’’, and

replacing the ‘‘%’’ symbol with the

word ‘‘percent’’ in the third sentence;

l. In the definition of ‘‘QA operating

quarter’’ by adding the word

‘‘cumulative’’ after each occurrence of

the words ‘‘at least 168’’;

m. In the definition of ‘‘Relative

accuracy’’ by adding the words ‘‘or

moisture’’ after the words ‘‘between the

pollutant’’ and by adding the words ‘‘or

moisture monitor’’ after the words ‘‘flow

monitor’’;

n. Adding in alphabetical order new

definitions for ‘‘Common pipe’’,

‘‘Common pipe operating time’’,

‘‘Cumulative stack operating hours’’,

‘‘Cumulative unit operating hours’’,

‘‘Diluent cap value’’, ‘‘Fuel flowmeter

system’’, ‘‘Fuel usage time’’, ‘‘Multiple

stack configuration’’, ‘‘Stack operating

time’’, and ‘‘Unit operating time’’.

The revisions and additions read as

follows:

§ 72.2 Definitions.

* * * * *

Cogeneration unit means a unit that

produces electric energy and useful

thermal energy for industrial,

commercial, or heating or cooling

purposes, through the sequential use of

the original fuel energy.

* * * * *

Common pipe means an oil or gas

supply line through which the same

type of fuel is distributed to two or more

affected units.

Common pipe operating time means

the portion of a clock hour during

which fuel flows through a common

pipe. The common pipe operating time,

in hours, is expressed as a decimal

fraction, with valid values ranging from

0.00 to 1.00.

* * * * *

Continuous emission monitoring

system or CEMS means the equipment

required by part 75 of this chapter used

to sample, analyze, measure, and

provide, by means of readings recorded

at least once every 15 minutes (using an

automated data acquisition and

handling system (DAHS)), a permanent

record of SO2, NOX, or CO2 emissions or

stack gas volumetric flow rate. The

following are the principal types of

continuous emission monitoring

systems required under part 75 of this

chapter. Sections 75.10 through 75.18

and § 75.71(a) of this chapter indicate

which type(s) of CEMS is required for

specific applications:

(1) A sulfur dioxide monitoring

system, consisting of an SO2 pollutant

concentration monitor and an

automated DAHS. An SO2 monitoring

system provides a permanent,

continuous record of SO2 emissions in

units of parts per million (ppm);

(2) A flow monitoring system,

consisting of a stack flow rate monitor

and an automated DAHS. A flow

monitoring system provides a

permanent, continuous record of stack

gas volumetric flow rate, in units of

standard cubic feet per hour (scfh);

(3) A nitrogen oxides ( NOX) emission

rate (or NOX-diluent) monitoring

system, consisting of a NOX pollutant

concentration monitor, a diluent gas

(CO2 or O2) monitor, and an automated

DAHS. A NOX-diluent monitoring

system provides a permanent,

continuous record of: NOX

concentration in units of parts per

million (ppm), diluent gas concentration

in units of percent O2 or CO2 (percent

O2 or CO2), and NOX emission rate in

units of pounds per million British

thermal units (lb/mmBtu);

(4) A nitrogen oxides concentration

monitoring system, consisting of a NOX

pollutant concentration monitor and an

automated DAHS. A NOX concentration

monitoring system provides a

permanent, continuous record of NOX

emissions in units of parts per million

(ppm). This type of CEMS is used only

in conjunction with a flow monitoring

system to determine NOX mass

emissions (in lb/hr) under subpart H of

part 75 of this chapter;

(5) A carbon dioxide monitoring

system, consisting of a CO2 pollutant

concentration monitor (or an oxygen

monitor plus suitable mathematical

equations from which the CO2

concentration is derived) and the

automated DAHS. A carbon dioxide

monitoring system provides a

permanent, continuous record of CO2

emissions in units of percent CO2

(percent CO2); and

(6) A moisture monitoring system, as

defined in § 75.11(b)(2) of this chapter.

A moisture monitoring system provides

Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules 32001

a permanent, continuous record of the

stack gas moisture content, in units of

percent H2O (percent H2O).

* * * * *

Cumulative stack operating hours

means the sum of the stack operating

times (as defined in this section) for a

series of consecutive stack operating

hours (as defined in this section),

rounded to the nearest hour.

Cumulative unit operating hours

means the sum of the unit operating

times (as defined in this section) for a

series of consecutive unit operating

hours (as defined in this section),

rounded to the nearest hour.

* * * * *

Diluent cap value means a default

CO2 or O2 concentration which may be

used to calculate the hourly NOX

emission rate, CO2 mass emission rate,

or heat input rate, when the measured

hourly average CO2 or O2 concentration

is below the default value. The diluent

cap values for boilers are 5 percent CO2

and 14 percent O2. For combustion

turbines, the diluent cap values are 1

percent CO2 and 19 percent O2.

* * * * *

Emergency fuel means:

* * * * *

(2) For purposes of the requirement

for stack testing for an excepted

monitoring system under appendix E of

part 75 of this chapter, the fuel

identified in a federally-enforceable

permit for a plant and identified by the

designated representative in the unit’s

monitoring plan as the fuel which is

combusted only during emergencies

where the primary fuel is not available.

* * * * *

Fuel flowmeter system means an

excepted monitoring system (as defined

in this section) which provides a

continuous record of the flow rate of

fuel oil or gaseous fuel, in accordance

with appendix D to part 75 of this

chapter. A fuel flowmeter system

consists of one or more fuel flowmeter

components, all necessary auxiliary

components (e.g., transmitters,

transducers, etc.), and a data acquisition

and handling system (DAHS).

* * * * *

Fuel usage time means the portion of

a clock hour during which a unit

combusts a particular type of fuel. The

fuel usage time, in hours, is expressed

as a decimal fraction, with valid values

ranging from 0.00 to 1.00.

* * * * *

Heat input rate means the product

(expressed in mmBtu/hr) of the gross

calorific value of the fuel (expressed in

mmBtu/mass of fuel) and the fuel feed

rate into the combustion device

(expressed in mass of fuel/hr) and does

not include the heat derived from

preheated combustion air, recirculated

flue gases, or exhaust from other

sources.

Hour before and hour after means, for

purposes of the missing data

substitution procedures of part 75 of

this chapter, the quality-assured hourly

SO2 or CO2 concentration, hourly flow

rate, hourly NOX concentration, hourly

moisture, hourly O2 concentration, or

hourly NOX emission rate (as

applicable) recorded by a certified

monitor during the unit or stack

operating hour immediately before and

the unit or stack operating hour

immediately after a missing data period.

* * * * *

Maximum potential NOX emission

rate, or MER means the emission rate of

nitrogen oxides (in lb/mmBtu)

calculated in accordance with section 3

of appendix F to part 75 of this chapter,

using the maximum potential nitrogen

oxides concentration as defined in

section 2.1.2.1 of appendix A to part 75

of this chapter, and either the maximum

oxygen concentration (in percent O2) or

the minimum carbon dioxide

concentration (in percent CO2) under all

operating conditions of the unit except

for unit start-up, shutdown, and upsets.

The diluent cap value, as defined in this

section, may be used in lieu of the

maximum O2 or minimum CO2

concentration to calculate the MER.

Maximum rated hourly heat input

rate means a unit-specific maximum

hourly heat input rate (mmBtu/hr)

which is the higher of the

manufacturer’s maximum rated hourly

heat input rate or the highest observed

hourly heat input rate.

Missing data period means the total

number of consecutive hours during

which any certified CEMS or approved

alternative monitoring system is not

providing quality-assured data,

regardless of the reason.

Monitor accuracy means the closeness

of the measurement made by a CEMS to

the reference value of the emissions or

volumetric flow being measured,

expressed as the difference between the

measurement and the reference value.

* * * * *

Multiple stack configuration refers to

an exhaust configuration in which the

flue gases from a particular unit

discharge to the atmosphere through

two or more stacks. The term also refers

to a unit for which emissions are

monitored in two or more ducts leading

to the exhaust stack, in lieu of

monitoring at the stack.

* * * * *

Natural gas * * * Natural gas

contains 20.0 grains or less of total

sulfur per 100 standard cubic feet.

***

* * * * *

Pipeline natural gas means a naturally

occurring fluid mixture of hydrocarbons

(e.g., methane, ethane, or propane)

produced in geological formations

beneath the Earth’s surface that

maintains a gaseous state at standard

atmospheric temperature and pressure

under ordinary conditions, and which is

provided by a supplier through a

pipeline. Pipeline natural gas contains

0.5 grains or less of total sulfur per 100

standard cubic feet. Additionally,

pipeline natural gas must either be

composed of at least 70 percent methane

by volume or have a gross calorific

value between 950 and 1100 Btu per

standard cubic foot.

* * * * *

Stack operating hour means a clock

hour during which flue gases flow

through a particular stack or duct (either

for the entire hour or for part of the

hour) while the associated unit(s) are

combusting fuel.

Stack operating time means the

portion of a clock hour during which

flue gases flow through a particular

stack or duct while the associated

unit(s) are combusting fuel. The stack

operating time, in hours, is expressed as

a decimal fraction, with valid values

ranging from 0.00 to 1.00.

* * * * *

Unit operating hour means a clock

hour during which a unit combusts any

fuel, either for part of the hour or for the

entire hour.

* * * * *

Unit operating time means the portion

of a clock hour during which a unit

combusts any fuel. The unit operating

time, in hours, is expressed as a decimal

fraction, with valid values ranging from

0.00 to 1.00.

* * * * *

PART 75—CONTINUOUS EMISSION

MONITORING

3. The authority citation for part 75

continues to read as follows:

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

§ 75.1 [Amended].

4. Section 75.1 is amended by adding

the words ‘‘(the Act)’’ at the end of the

first sentence of paragraph (a).

5. Section 75.4 is amended by:

a. In paragraph (b) introductory text

by adding the word ‘‘moisture,’’ after

the word ‘‘opacity,’’;

b. In paragraphs (b)(2) and (c)(2) by

revising the words ‘‘Not later than 90’’

32002 Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules

to read ‘‘The earlier of 90 unit operating

days or 180 calendar’’;

c. Remove ‘‘or’’ at the end of

paragraphs (b)(1) and (c)(1) and remove

the period at the end of paragraphs

(b)(2) and (c)(2) and add ‘‘; or’’ in its

place;

d. Adding paragraphs (b)(3) and (c)(3);

e. In the first sentence of paragraph

(d) by revising the words ‘‘the earlier of

45’’ to read ‘‘90’’, adding the words

‘‘(whichever occurs first)’’ following the

words ‘‘180 calendar days’’, and

removing the words ‘‘of the affected

unit’’ after the words ‘‘recommences

commercial operation’’;

f. In the first sentence of paragraph (e)

introductory text by revising the words

‘‘90 calendar days’’ to read ‘‘90 unit

operating days or 180 calendar days

(whichever occurs first)’’;

g. Revising paragraphs (f) introductory

text and (f)(1);

h. Removing and reserving paragraphs

(g) and (h); and

i. In paragraph (i) by removing the

word ‘‘or’’ in paragraph (i)(1) and by

revising paragraphs (i)(2) and (i)(3).

The revisions and additions read as

follows:

§ 75.4 Compliance dates.

* * * * *

(b) * * *

(3) The owner or operator shall

determine and report SO2 concentration,

NOX emission rate, CO2 concentration,

and flow data for all unit operating

hours after the applicable compliance

date in this paragraph until all required

certification tests are successfully

completed using either:

(i) The maximum potential

concentration of SO2, the maximum

potential NOX emission rate, as defined

in section 2.1.2.1 of appendix A to this

part, the maximum potential flow rate,

as defined in section 2.1.4.1 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;

(ii) Reference methods under

§ 75.22(b); or

(iii) Another procedure approved by

the Administrator pursuant to a petition

under § 75.66.

(c) * * *

(3) The owner or operator shall

determine and report SO2 concentration,

NOX emission rate, CO2 concentration,

and flow data for all unit operating

hours after the applicable compliance

date in this paragraph until all required

certification tests are successfully

completed using either:

(i) The maximum potential

concentration of SO2, the maximum

potential NOX emission rate, as defined

in section 2.1.2.1 of appendix A to this

part, the maximum potential flow rate,

as defined in section 2.1.4.1 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;

(ii) Reference methods under

§ 75.22(b); or

(iii) Another procedure approved by

the Administrator pursuant to a petition

under § 75.66.

* * * * *

(f) In accordance with § 75.20, the

owner or operator of an affected gasfired or oil-fired peaking unit, if

planning to use appendix E of this part,

shall ensure that the required

certification tests for excepted

monitoring systems under appendix E

are completed for backup fuel, as

defined in § 72.2 of this chapter, no later

than 90 unit operating days or 180

calendar days (whichever occurs first)

after the date that the unit first combusts

the backup fuel following the

certification testing with the primary

fuel. Until all required certification tests

are successfully completed, the owner

or operator shall report NOX emission

rate data for all unit operating hours that

the backup fuel is combusted using

either:

(1) The fuel-specific maximum

potential NOX emission rate;

* * * * *

(i) * * *

(2) For a new affected unit which has

not commenced commercial operation

by January 2, 2000, 90 unit operating

days or 180 calendar days (whichever

occurs first) after the date the unit

commences commercial operation; or

(3) For an existing unit that is

shutdown and is not yet operating by

April 1, 2000, 90 unit operating days or

180 calendar days (whichever occurs

first) after the date that the unit

recommences commercial operation.

§ 75.6 [Amended].

6. In § 75.6 amend paragraphs (a)(19),

(a)(26), and (a)(35) by removing the

words ‘‘§ 75.15 and’’.

7. Section 75.10 is amended by:

a. In paragraph (a)(1) by revising the

word ‘‘The’’ in the first sentence to read

‘‘To determine SO2 emissions, the’’, and

by revising the words ‘‘the automated’’

to read ‘‘an automated’’;

b. In paragraph (a)(2) by revising the

word ‘‘The’’ in the first sentence to read

‘‘To determine NOX emissions, the’’; by

revising the words ‘‘the automated’’ to

read ‘‘an automated’’; and by revising

the first occurrence of the word ‘‘ NOX’’

in the first sentence to read ‘‘ NOXdiluent’’;

c. In paragraph (a)(3)(i) by revising the

words ‘‘the automated’’ to read ‘‘an

automated’’;

d. In paragraph (a)(3)(iii) by revising

the words ‘‘using an O2 concentration

monitor in order’’ to read ‘‘that uses an

O2 concentration monitor’’ and by

revising the words ‘‘using the

procedures in appendix F of this part

with the automated’’ to read ‘‘(according

to the procedures in appendix F of this

part) with an automated’’;

e. Removing ‘‘and’’ at the end of

paragraph (a)(3) and removing the

period at the end of paragraph (a)(4) and

adding ‘‘; and’’ in its place;

f. Adding new paragraph (a)(5);

g. In paragraph (c) by adding the word

‘‘Rate’’ after the words ‘‘Heat Input’’ in

the heading and by adding the words

‘‘rate, in units of mmBtu/hr,’’ after the

words ‘‘record the heat input’’;

h. In paragraph (d)(1) by removing the

words ‘‘and component thereof’’ from

the first sentence, removing the words

‘‘SO2 emission rate in lb/mmBtu (if

applicable),’’ from the second sentence,

and by adding the word ‘‘or’’ after the

words ‘‘of this part,’’ in the fourth

sentence;

i. In paragraph (d)(3) by revising the

words ‘‘flow monitor, or NOX’’ to read

‘‘ NOX concentration monitor, flow

monitor, moisture monitor, or NOXdiluent’’, by revising the words ‘‘An

hourly average NOX or SO2’’ in the

second sentence to read ‘‘For a NOXdiluent monitoring system, hourly

average NOX’’, by adding the word

‘‘NOX’’ before the word ‘‘pollutant’’ and

by removing the words ‘‘(NOX or SO2)’’

in the second sentence; and by revising

in the fourth sentence the words

‘‘Except for SO2 emission rate data in lb/

mmBtu, if’’ to read ‘‘If’’;

j. In paragraph (f) by removing the

words ‘‘and component thereof’’; and

k. Revising the capitalization in the

title of paragraph (g) from ‘‘Minimum

Recording and Recordkeeping

Requirements’’ to ‘‘Minimum recording

and recordkeeping requirements’’.

The revisions and additions read as

follows:

§ 75.10 General operating requirements.

(a) * * *

(5) A single, certified flow monitoring

system may be used to meet the

requirements of paragraphs (a)(1) and

(a)(3) of this section. A single certified

diluent monitor may be used to meet the

requirements of paragraphs (a)(2) and

(a)(3) of this section. A single automated

data acquisition and handling system

may be used to meet the requirements

of paragraphs (a)(1) through (a)(4) of this

section.

* * * * *

§ 75.11 [Amended].

8. Section 75.11 is amended by:

Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules 32003

a. Revising the word ‘‘psychometric’’

in paragraph (b)(2) to read

‘‘psychrometric’’;

b. In the second sentence of paragraph

(e)(1) by adding the words ‘‘(according

to the applicable equation in section 5.2

of appendix F to this part)’’ after the

word ‘‘monitor’’, and removing the

words ‘‘and equation D–5 in appendix

D to this part’’;

c. In paragraph (e)(2) by revising in

the first sentence the words ‘‘§ 75.55 or

§ 75.58, as applicable,’’ to read

‘‘§ 75.58,’’, and by, in the second

sentence, adding the word ‘‘rate’’ after

‘‘heat input’’ and revising the words

‘‘§ 75.54(b)(5) or § 75.57(b)(5), as

applicable,’’ to read ‘‘§ 75.57(b)(5)’’;

d. In paragraph (e)(3) by removing the

third sentence, removing the period at

the end of the second sentence and

adding a semicolon, removing the words

‘‘then on and after April 1, 2000,’’ in the

second sentence, and by revising the

words ‘‘be subject to’’ to read ‘‘meet’’ in

the second sentence; and

e. In the first sentence of paragraph

(e)(3)(iii) by adding the words ‘‘biasadjusted’’ before the words ‘‘hourly

average’’.

9. Section 75.12 is amended by:

a. Revising the section heading;

b. In paragraph (a) by adding the word

‘‘(CEMS)’’ after the words ‘‘continuous

emission monitoring system’’ in the first

sentence and by revising the words ‘‘

NOX continuous emission monitoring

system’’ to read ‘‘ NOX-diluent CEMS’’

in the second sentence;

c. In paragraph (d)(2) by revising the

word ‘‘ NOX’’ to read ‘‘ NOX-diluent’’ in

the second sentence and by adding a

new third sentence; and

d. In paragraph (e) by revising the

reference to ‘‘(c)’’ to read ‘‘(d)’’.

The revisions and additions read as

follows:

§ 75.12 Specific provisions for monitoring

NOX emission rate ( NOX-diluent monitoring

systems).

* * * * *

(d) * * *

(2) * * * If the required CEMS has not

been installed and certified by that date,

the owner or operator shall report the

maximum potential NOX emission rate

(MER) (as defined in § 72.2 of this

chapter) for each unit operating hour,

starting with the first unit operating

hour after the deadline and continuing

until the CEMS has been provisionally

certified. For each unit operating hour

in which the MER is reported, the MER

shall be specific to the type of fuel being

combusted in the unit.

* * * * *

10. Section 75.13 is amended by:

a. Revising the heading and first

sentence of paragraph (b); and

b. Revising the first sentence of

paragraph (c).

The revisions and additions read as

follows:

§ 75.13 Specific provisions for monitoring

CO2 emissions.

* * * * *

(b) Determination of CO2 emissions

using appendix G to this part. If the

owner or operator chooses to use the

appendix G method, then the owner or

operator shall follow the procedures in

appendix G to this part for estimating

daily CO2 mass emissions based on the

measured carbon content of the fuel and

the amount of fuel combusted. * * *

(c) Determination of CO2 mass

emissions using an O2 monitor

according to appendix F to this part.

The owner or operator shall 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 (or where Equation F–14b in

appendix F to this part is used to

determine CO2 concentration), either a

continuous moisture monitoring system,

as specified in § 75.11(b)(2), or a fuelspecific default moisture percentage (if

applicable), as defined in § 75.11(b)(1);

and by using the methods and

procedures specified in appendix F to

this part. * * *

* * * * *

§ 75.15 [ Reserved].

11. Section 75.15 is removed and

reserved.

12. Section 75.16 is amended by:

a. Removing and reserving all of

paragraph (a);

b. Revising paragraph (b) heading and

introductory text and paragraph (c);

c. Amending paragraphs (e) heading

and introductory text, (e)(1), (e)(2),

(e)(3), and (e)(4) by adding the word

‘‘rate’’ after each occurrence of the

words ‘‘heat input’’ except for the last

occurrence in paragraph (e)(1);

d. In paragraph (e)(1) by revising the

reference to ‘‘(a)’’ to read ‘‘(b)’’ in the

first sentence, and by removing

‘‘(a)(1)(ii), (a)(2)(ii),’’ and the comma

after ‘‘(b)(1)(ii)’’ in the third sentence;

e. In paragraph (e)(2) by revising the

words ‘‘appendix F of this part’’ to read

‘‘appendix F to this part’’; and

f. In paragraph (e)(3) by adding the

words ‘‘, in conjunction with the

appropriate unit and stack operating

times’’ after the words ‘‘utilizing the

common stack’’.

The revisions and additions read as

follows:

§ 75.16 Special provisions for monitoring

emissions from common, bypass, and

multiple stacks for SO2 emissions and heat

input determinations.

* * * * *

(b) Common stack procedures. The

following procedures shall be used

when more than one unit uses a

common stack:

* * * * *

(c) Unit with bypass stack. Whenever

any portion of the flue gases from an

affected unit can be routed through a

bypass stack so as to avoid the installed

SO2 continuous emission monitoring

system and flow monitoring system, the

owner or operator shall either: (1) Install, certify, operate, and

maintain separate SO2 continuous

emission monitoring systems and flow

monitoring systems on the main stack

and the bypass stack and calculate SO2

mass emissions for the unit as the sum

of the SO2 mass emissions measured at

the two stacks; or

(2) Monitor SO2 mass emissions at the

main stack using SO2 and flow rate

monitoring systems and measure SO2

mass emissions at the bypass stack

using the reference methods in

§ 75.22(b) for SO2 and flow rate and

calculate SO2 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; or (3) Install, certify, operate, and

maintain SO2 and flow rate monitoring

systems only on the main stack. If this

option is chosen, report the following

values for each hour during which

emissions pass through the bypass

stack: the maximum potential

concentration of SO2 as determined

under section 2.1.1.1 of appendix A to

this part (or, if available, the SO2

concentration measured by a certified

monitor located at the control device

inlet), and the maximum potential flow

rate, as defined in section 2.1.4.1 of

appendix A to this part. If the bypass

stack is also unmonitored for NOX, CO2,

or moisture, report the following values

for each hour in which the bypass stack

is used: the maximum potential CO2

concentration, as defined in section

2.1.3.1 of appendix A to this part, the

maximum potential NOX emission rate,

as defined in section 2.1.2.1(b) of

appendix A to this part, the minimum

potential moisture percentage, as

defined in section 2.1.5 of appendix A

to this part, and, if O2 concentration is

used to determine the hourly heat input

rate, report the minimum potential O2

concentration (as defined in section

2.1.3.2 of appendix A to this part). The

maximum potential SO2 concentration

and the maximum potential NOX

32004 Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules

emission rate shall be specific to the

type of fuel combusted in the unit

during the bypass (see § 75.33(b)(5)).

This option may only be used if use of

the bypass stack is limited to unit

startup, emergency situations (e.g.,

malfunction of a flue gas desulfurization

system), and periods of routine

maintenance of the flue gas

desulfurization system or maintenance

on the main stack. If this option is

chosen, it is not necessary to designate

the exhaust configuration as a multiple

stack configuration in the monitoring

plan required under § 75.53, with

respect to SO2, flow rate, or any other

parameter that is monitored only at the

main stack.

* * * * *

13. Section 75.17 is amended by:

a. Removing the hyphen from the

word ‘‘by-pass’’ in the section heading;

b. In the introductory text by revising

the words ‘‘and (c)’’ to read ‘‘(c), and

(d)’’;

c. In paragraph (b)(1) by revising the

word ‘‘NOX’’ to read ‘‘NOX-diluent’’;

d. Revising the paragraph heading and

first sentence of paragraph (c)

introductory text;

e. Revising paragraphs (c)(1) and

(c)(2); and

f. Adding new paragraph (d).

The revisions and additions read as

follows:

§ 75.17 Specific provisions for monitoring

emissions from common, bypass, and

multiple stacks for NOX emission rate.

* * * * *

(c) Unit with multiple stacks or ducts.

When the flue gases from an affected

unit discharge to the atmosphere

through two or more stacks or when 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 the

stack, the owner or operator shall

monitor the NOX emission rate in a way

that is representative of each affected

unit. * * *

(1) Install, certify, operate, and

maintain a NOX-diluent continuous

emission monitoring system and a flow

monitoring system in each stack or duct

and determine the NOX emission rate

for the unit as the Btu-weighted average

of the NOX emission rates measured in

the stacks or ducts using the heat input

estimation procedures in appendix F to

this part. Alternatively, for units that are

eligible to use the procedures of

appendix D to this part, the owner or

operator may monitor heat input and

NOX emission rate at the unit level, in

lieu of installing flow monitors on each

stack or duct. If this alternative unitlevel monitoring is performed, report,

for each unit operating hour, the highest

emission rate measured by any of the

NOX-diluent monitoring systems

installed on the individual stacks or

ducts as the hourly NOX emission rate

for the unit, and report the hourly unit

heat input as determined under

appendix D to this part. Also, when this

alternative unit-level monitoring is

performed, the applicable NOX missing

data procedures in §§ 75.31 or 75.33

shall be used for each unit operating

hour in which a quality-assured NOX

emission rate is not obtained for one or

more of the individual stacks or ducts;

or

(2) Provided that the products of

combustion are well-mixed, install,

certify, operate, and maintain a NOX

continuous emission monitoring system

in one stack or duct from the affected

unit and record the monitored value as

the NOX emission rate for the unit. The

owner or operator shall account for NOX

emissions from the unit during all times

when the unit combusts fuel. Therefore,

this option shall not be used if the

monitored stack or duct can be bypassed

(e.g., by using dampers). Follow the

procedure in § 75.17 for units with

bypass stacks. Further, this option shall

not be used unless the monitored NOX

emission rate truly represents the NOX

emissions discharged to the atmosphere

(e.g., the option is disallowed if there

are any additional NOX emission

controls downstream of the monitored

location).

(d) Unit with a main stack and bypass

stack configuration. For an affected unit

with a discharge configuration

consisting of a main stack and a bypass

stack, the owner or operator shall either:

(1) Follow the procedures in

paragraph (c)(1) of this section; or

(2) Install, certify, operate, and

maintain a NOX-diluent CEMS only on

the main stack. If this option is chosen,

it is not necessary to designate the

exhaust configuration as a multiple

stack configuration in the monitoring

plan required under § 75.53, with

respect to NOX or any other parameter

that is monitored only at the main stack.

For each unit operating hour in which

the bypass stack is used, report the

maximum potential NOX emission rate

(as defined in § 72.2 of this chapter).

The maximum potential NOX emission

rate shall be specific to the type of fuel

combusted in the unit during the bypass

(see § 75.33(c)(8)). In addition, if SO2,

CO2, flow rate, or (if applicable)

moisture monitoring systems are

installed only on the main stack and not

on the bypass stack, report the following

values for each hour in which the

bypass stack is used: The maximum

potential values of SO2 concentration,

CO2 concentration, and stack gas flow

rate, as defined in section 2 of appendix

A to this part, the minimum potential

moisture percentage, as defined in

section 2.1.5 of appendix A to this part,

and, if O2 concentration is used to

determine the hourly heat input rate,

report the minimum potential O2

concentration (as defined in section

2.1.3.2 of appendix A to this part). If

SO2 emissions and the unit heat input

are determined using a fuel flowmeter

in accordance with appendix D to this

part and if CO2 emissions are estimated

using the procedures in appendix G to

this part, report SO2 emissions and CO2

emissions in accordance with

appendices D and G to this part, and

report the actual measured heat input

rate for each hour in which the bypass

stack is used.

14. Section 75.19 is amended by:

a. Revising paragraphs (a)(1)(i),

(a)(1)(ii), (a)(2)(i), (a)(2)(ii), (b)(1), (b)(2),

(b)(3), (c)(1)(iv)(A), (c)(1)(iv)(C), and

(c)(3)(ii)(H);

b. In paragraph (b)(4) introductory

text by revising the words ‘‘unit

commencing operation after January 1,

1997’’ to read ‘‘new or newly-affected

unit’’;

c. In paragraph (b)(4)(ii) by revising

the words ‘‘ NOX, and CO2’’ to read

‘‘CO2, and/or NOX’’;

d. In paragraph (b)(4)(iii) by revising

the words ‘‘and NOX’’ in the first

sentence to read ‘‘and/or NOX’’ and by

revising the words ‘‘tables 1, 2 and 3’’

to read ‘‘tables LM–1, LM–2, and LM–

3’’ in the second sentence;

e. Removing and reserving paragraph

(c)(1)(iv)(B)(3);

f. In paragraph (c)(1)(iv)(B)(4) by

revising the reference to

‘‘(c)(1)(iv)(B)(3)’’ to read

‘‘(c)(1)(iv)(B)(1)’’;

g. In the first sentence of paragraph

(c)(1)(iv)(D) by revising the words ‘‘,

each unit in a group of units sharing a

common fuel supply, or’’ to read ‘‘or

group of’’;

h. In paragraph (c)(1)(iv)(E) by

removing the words ‘‘, each low mass

emission unit in a group of units

combusting a common fuel,’’;

i. Revising the first and last sentences

of (c)(1)(iv)(G);

j. In the first sentence of (c)(1)(iv)(H)

by adding the words ‘‘(including units

that use dry low-NOX technology),’’

after the first occurrence of the words

‘‘NOX emission controls’’;

k. In the last sentence of

(c)(1)(iv)(H)(1) by adding the words ‘‘,

and the appropriate default NOX

emission rate from Table LM–2 shall be

reported instead’’ after the words ‘‘for

that hour’’;

l. Adding new paragraph (c)(1)(iv)(I);

Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules 32005

m. In paragraph (c)(2)(iii) by revising

the word ‘‘output’’ to read ‘‘load’’ and

adding the words ‘‘per hour’’ after the

words ‘‘pounds of steam’’;

n. In paragraph (c)(2)(iv) by adding

the words ‘‘add-on’’ after the words

‘‘unit with’’ and adding the words

‘‘(including dry low-NOX technology)’’

after the words ‘‘of any kind’’;

o. In paragraph (c)(3)(i) by adding

‘‘HIhr,’’ after the words ‘‘of this section,’’

in the first sentence, by revising Eq.

LM–1 and the accompanying variable

definitions, and by adding a new

paragraph (c)(3)(i)(D);

p. Removing the word ‘‘use’’ in the

second sentence of paragraph

(c)(3)(ii)(D)(1);

q. Adding a sentence following the

first sentence of paragraphs (c)(3)(ii)(E),

(c)(3)(ii)(G), and (c)(4)(ii)(C);

r. In the definition of Mqtr in Equation

LM–2 in paragraph (c)(3)(ii)(E) by

removing the word ‘‘entire’’;

s. In the definition of Qg in Equation

LM–3 in paragraph (c)(3)(ii)(E) by

revising the word ‘‘Value’’ to read

‘‘Volume’’ and adding parentheses

around the words ‘‘standard cubic feet

(scf)’’;

t. In paragraph (c)(3)(ii)(F) by adding

the words ‘‘, using Equation LM–4’’ after

the reference to ‘‘LM–3’’;

u. Revising the definition of variables

following Equations LM–7 and LM–8 in

paragraph (c)(3)(ii)(I), the definition of

variables following Equations LM–7a

and LM–8a in paragraph (c)(3)(ii)(J), and

the definitions of the first two variables

following Equation LM–10 in paragraph

(c)(4)(ii)(A);

v. In the definition of variable

‘‘EFSO2’’ for Equation LM–9 in

paragraph (c)(4)(i) by revising the

reference ‘‘table 1’’ to read ‘‘table LM–

1’’;

w. In paragraph (e)(5) by revising the

words ‘‘which have NOX emission

controls of any kind’’ to read ‘‘which

have add-on NOX emission controls of

any kind (including dry low-NOX

technology)’’; and

x. In Table LM–5 that follows

paragraph (e) by adding the word

‘‘Other’’ before ‘‘Natural Gas’’ in the first

column of the second entry of the table.

The revisions and additions read as

follows:

§ 75.19 Optional SO2, NOX, and CO2

emissions calculation for low mass

emissions units.

(a) * * *

(1) * * *

(i) A low mass emissions unit is an

affected unit that burns only natural gas

or fuel oil (i.e., diesel fuel or residual

oil) and for which:

(A) An initial demonstration is

provided, in accordance with paragraph

(a)(2) of this section, which shows that

the unit emits no more than:

(1) 25 tons of SO2 annually and 50

tons of NOX annually, for Acid Rain

Program affected units (including units

which are also subject to the provisions

of subpart H of this part),

(2) 50 tons of NOX annually, for units

which are subject to the provisions of

subpart H of this part and which report

emissions data on a year-round basis, in

accordance with § 75.74(b), or

(3) 25 tons of NOX per ozone season,

for units which are subject to the

provisions of subpart H of this part and

which report emissions data only during

the ozone season, in accordance with

§ 75.74(b); and

(B) An annual demonstration is

provided thereafter, using one of the

allowable methodologies in paragraph

(c) of this section, showing that the low

mass emission unit continues to emit no

more than the applicable number of tons

of SO2 and/or NOX specified in

paragraph (a)(1)(i)(A) of this section.

(ii) Any qualifying unit must start

using the low mass emissions excepted

methodology as follows:

(A) For a unit that reports emission

data on a year-round basis, begin using

the methodology in the first unit

operating hour in the calendar year in

which the unit (as indicated in the

certification application) will first

qualify as a low mass emissions unit; or

(B) For a unit that is subject to subpart

H of this part and that reports only

during the ozone season according to

§ 75.74(c), begin using the methodology

in the first unit operating hour in the

ozone season in which the unit (as

indicated in the certification

application) will first qualify as a low

mass emissions unit.

(2) * * *

(i) If the designated representative

submits a certification application to

use the low mass emissions excepted

methodology and the Administrator (or

permitting authority) certifies the use of

such methodology. The certification

application shall be submitted no later

than 45 days prior to the date on which

use of the low mass emissions excepted

methodology will commence. The

certification application must contain,

as applicable, the information in

paragraph (a)(2)(i)(A), (a)(2)(i)(B), or

(a)(2)(i)(C) of this section.

(A) Acid Rain Program affected units.

For affected units under the Acid Rain

Program (including units which are also

subject to the provisions of subpart H of

this part), the certification application

shall contain:

(1) Actual SO2 and NOX mass

emissions data for each of the three

calendar years prior to the calendar year

in which the unit will first qualify as a

low mass emissions unit, demonstrating

to the satisfaction of the Administrator

that the unit emits no more than 25 tons

of SO2 and no more than 50 tons of NOX

annually; and

(2) Calculated SO2 and NOX mass

emissions, for each of the three calendar

years prior to the calendar year in which

the unit will first qualify as a low mass

emissions unit, demonstrating to the

satisfaction of the Administrator that the

unit emits no more than 25 tons of SO2

and no more than 50 tons of NOX

annually. The calculated emissions for

each year shall be determined using

either the maximum rated heat input

methodology described in paragraph

(c)(3)(i) of this section or the long term

fuel flow heat input methodology

described in paragraph (c)(3)(ii) of this

section, in conjunction with the

appropriate emission rate from

paragraph (c)(1)(i) of this section for SO2

and paragraph (c)(1)(ii) or (c)(1)(iv) of

this section for NOX.

(B) Non-Acid Rain subpart H units

reporting on a year-round basis. For

units that are not affected under the

Acid Rain Program, but are subject to

the provisions of subpart H of this part,

and which report emissions data on a

year-round basis, the certification

application shall contain:

(1) Actual NOX mass emissions data

for each of the three calendar years prior

to the calendar year in which the unit

will first qualify as a low mass

emissions unit, demonstrating to the

satisfaction of the Administrator (or the

permitting authority if subpart H is used

under a State approved SIP) that the

unit emits no more than 50 tons of NOX

annually; and

(2) Calculated NOX mass emissions,

for each of the three calendar years prior

to the calendar year in which the unit

will first qualify as a low mass

emissions unit, demonstrating to the

satisfaction of the Administrator that the

unit emits no more than 50 tons of NOX

annually. The calculated emissions for

each year shall be determined using

either the maximum rated heat input

methodology described in paragraph

(c)(3)(i) of this section or the long term

fuel flow heat input methodology

described in paragraph (c)(3)(ii) of this

section, in conjunction with the

appropriate NOX emission rate from

paragraph (c)(1)(ii) or (c)(1)(iv) of this

section.

(C) Non-Acid Rain subpart H units,

reporting ozone season data only. For

units that are not affected under the

Acid Rain Program, but are subject to

the provisions of subpart H of this part,

and which report emissions data only

32006 Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules

during the ozone season, the

certification application shall contain:

(1) Actual NOX mass emissions data

for each of the three ozone seasons prior

to the ozone season in which the unit

will first qualify as a low mass

emissions unit, demonstrating to the

satisfaction of the Administrator (or the

permitting authority if subpart H is used

under a State approved SIP) that the

unit emits no more than 25 tons of NOX

per ozone season; and

(2) Calculated NOX mass emissions,

for each of the three ozone seasons prior

to the ozone season in which the unit

will first qualify as a low mass

emissions unit, demonstrating to the

satisfaction of the Administrator that the

unit emits no more than 25 tons of NOX

per ozone season. The calculated

emissions for each ozone season shall be

determined using either the maximum

rated heat input methodology described

in paragraph (c)(3)(i) of this section or

the long term fuel flow heat input

methodology described in paragraph

(c)(3)(ii) of this section, in conjunction

with the appropriate NOX emission rate

from paragraph (c)(1)(ii) or (c)(1)(iv) of

this section.

(ii) When the three full years (or, if

applicable, three full ozone seasons) of

actual, historical SO2 and/or NOX mass

emissions data required under

paragraph (a)(2)(i) of this section are not

available, the designated representative

may submit an application to use the

low mass emissions excepted

methodology based upon a combination

of historical SO2 and NOX mass

emissions data and projected SO2 and/

or NOX mass emissions, totaling three

years (or ozone seasons). Historical data

must be used for any years (or ozone

seasons) in which historical data exists

and projected data should be used for

any remaining future years (or ozone

seasons). For example, if an Acid Rain

Program unit commenced operation two

years ago, the designated representative

may submit actual, historical data for

the previous two years and one year of

projected emissions for the current

calendar year or, for a new (or newlyaffected) unit for which no actual

historical data are available, the

designated representative may submit

three years of projected emissions,

beginning with the current calendar

year. Any actual or projected annual (or

ozone season) emissions must

demonstrate to the satisfaction of the

Administrator that the unit will emit

less than the applicable number of tons

of SO2 and/or NOX specified in

paragraph (a)(1)(i)(A) of this section.

Projected emissions shall be calculated

using either the default emission rates

in tables LM–1, LM–2, and LM–3 of this

section, or, for NOX emission rate, a

fuel-and-unit-specific NOX emission

rate determined in accordance with the

testing procedures in paragraph

(c)(1)(iv) of this section, in conjunction

with projections of unit operating hours

or fuel type and fuel usage, according to

one of the allowable calculation

methodologies in paragraph (c) of this

section.

(b) * * *

(1) Once a low mass emission unit has

qualified for and has started using the

low mass emissions excepted

methodology, an annual demonstration

is required, showing that the unit

continues to emit no more than the

applicable number of tons of SO2 and/

or NOX specified in paragraph

(a)(1)(i)(A) of this section. The

calculation methodology used for the

annual demonstration shall be the same

methodology, from paragraph (c) of this

section, by which the unit initially

qualified to use the low mass emissions

excepted methodology. The annual

demonstration will be based upon the

emissions data which the Administrator

used to determine whether the unit held

sufficient allowances for the calendar

year or ozone season.

(2) If any low mass emission unit fails

to provide the required annual

demonstration under paragraph (b)(1) of

this section, such that the calculated

cumulative emissions for the unit

exceed the applicable number of tons of

SO2 and/or NOX specified in paragraph

(a)(1)(i)(A) of this section at the end of

any calendar year or ozone season, then:

(i) The low mass emission unit shall

be disqualified from using the low mass

emissions excepted methodology as of

December 31 of the following calendar

year (for sources that report emission

data on a year-round basis) or as of

December 31 of the calendar year in

which the unit exceeds the number of

tons of NOX specified in paragraph

(a)(1)(i)(A)(3) of this section (for sources

that report emission data only during

the ozone season); and

(ii) The owner or operator of the low

mass emission unit shall install, certify,

and report SO2 (Acid Rain Program

units only), NOX, and CO2 (Acid Rain

Program units only) emissions from

monitoring systems that meet the

requirements of §§ 75.11, 75.12, and

75.13 by December 31 of the year after

the unit exceeded the number of tons of

SO2 and/or NOX specified in paragraph

(a)(1)(i)(A)(1) or paragraph (a)(1)(i)(A)(2)

of this section (for sources that report

emission data on a year-round basis) or

by May 1 of the year after the unit

exceeds the number of tons of NOX

specified in paragraph (a)(1)(i)(A)(3) of

this section (for sources that report

emission data only during the ozone

season). If the required monitoring

systems have not been installed and

certified by the applicable deadline, the

owner or operator shall report the

following values for each unit operating

hour, beginning with the first operating

hour after the deadline and continuing

until the monitoring systems have been

provisionally certified: the maximum

hourly heat input for the unit, as

defined in § 72.2 of this chapter; the SO2

emissions, in lb/hr, calculated using the

applicable default SO2 emission rate in

Table LM–1 in this section and the

maximum hourly unit heat input; the

CO2 emissions, in tons/hr, calculated

using the applicable default CO2

emission rate in Table LM–3 in this

section and the maximum hourly unit

heat input; and the fuel-specific

maximum potential NOX emission rate,

as defined in § 72.2 of this chapter.

(3) If a low mass emission unit that

initially qualifies to use the low mass

emissions excepted methodology under

this section changes fuels, such that a

fuel other than those allowed for use in

the low mass emissions methodology

(i.e., natural gas, diesel fuel, or residual

oil) is combusted in the unit, the unit

shall be disqualified from using the low

mass emissions excepted methodology

as of the first hour that the new fuel is

combusted in the unit. The owner or

operator shall install, certify, and report

SO2 (Acid Rain Program units only),

NOX, and CO2 (Acid Rain Program units

only) from monitoring systems that meet

the requirements of §§ 75.11, 75.12, and

75.13 prior to a change to such fuel. If

the required monitoring systems are not

installed and certified prior to the fuel

switch, the owner or operator shall

report (as applicable) the maximum

potential concentration of SO2, CO2 and

NOX, the maximum potential NOX

emission rate, the maximum potential

flowrate, the maximum potential hourly

heat input and the maximum (or

minimum, if appropriate) potential

moisture percentage, from the date and

hour of the fuel switch until the

monitoring systems are certified or until

probationary calibration error tests of

the monitors are passed and the

conditional data validation procedures

in § 75.20(b)(3) begin to be used. All

maximum and minimum potential

values shall be specific to the new fuel

and shall be determined in a manner

consistent with section 2 of appendix A

to this part and § 72.2 of this chapter.

The owner or operator must notify the

Administrator (or the permitting

authority) in the case where a unit

switches fuels without previously

having installed and certified a SO2,

Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules 32007

NOX and CO2 monitoring system

meeting the requirements of §§ 75.11,

75.12, and 75.13.

* * * * *

(c) * * *

(1) * * *

(iv) * * *

(A) Except as otherwise provided in

this paragraph or in paragraphs

(c)(1)(iv)(F) and (G) of this section,

determine a fuel-and-unit-specific NOX

emission rate by conducting a four load

NOX emission rate test procedure as

specified in section 2.1 of appendix E to

this part, for each type of fuel

combusted in the unit. For a group of

units sharing a common fuel supply, the

appendix E testing must be performed

on each individual unit in the group,

unless some or all of the units in the

group belong to an identical group of

units, as defined in paragraph

(c)(1)(iv)(B) of this section, in which

case, representative testing may be

conducted on units in the identical

group of units, as described in

paragraph (c)(1)(iv)(B) of this section.

For a unit or group of identical units

that qualify under § 75.19(c)(1)(iv)(I),

single load testing is allowed in lieu of

the four load testing. For the purposes

of this section, make the following

modifications to the appendix E test

procedures:

(1) Do not measure the heat input as

required under section 2.1.3 of

appendix E to this part.

(2) Do not plot the test results as

specified under section 2.1.6 of

appendix E to this part.

(3) When using method 20 for

turbines do not correct the NOX

concentration to 15 percent O2.

(4) If the test is performed on an

uncontrolled diffusion flame turbine

(i.e., any turbine not using dry low NOX

lean premixed combustion technology

or any turbine without steam or water

injection) a correction to the observed

average NOX concentration from each

run of the Method 20 test must be

applied using the following equation:

NOx NOx P

P

e

T

T corr obs r

o

H H r

a

o r = 



 



 



 



 ( ) − ( ) −

0 5

19

. . 1 53

Eq. LM 1a

Where:

NOXcorr = Corrected NOX concentration

(ppm). NOXobs = Average measured NOX

concentration for each run of the

Method 20 test (ppm). Pr = Average annual atmospheric

pressure (or average ozone season

atmospheric pressure for a subpart

H unit that reports data only during

the ozone season) at the nearest

weather station (e.g., a standardized

NOAA weather station located at

the airport) for the year (or ozone

season) prior to the year of the test

(in Hg). Po = Observed atmospheric pressure

during the test run (in Hg). Hr = Average annual atmospheric

humidity ratio (or average ozone

season humidity ratio for a subpart

H unit that reports data only during

the ozone season) at the nearest

weather station, for the year (or

ozone season) prior to the year of

the test (lb moisture/lb air).

Ho = Observed humidity ratio during the

test run (lb moisture/lb air).

Tr = Average annual atmospheric

temperature (or average ozone

season atmospheric temperature for

a subpart H unit that reports data

only during the ozone season) at the

nearest weather station, for the year

(or ozone season) prior to the year

of the test (°R).

Ta = Observed atmospheric temperature

during the test run (°R).

(B) * * *

* * * * *

(C) Based on the results of the part 75

appendix E testing, determine the fueland-unit-specific NOX emission rate as

follows:

(1) If a four-load test is performed for

an individual low mass emission unit

with no NOX emissions controls of any

kind or for a turbine with water

injection, steam injection, or water/fuel

emulsion and no other type of add-on

NOX controls, the highest three run

average NOX emission rate obtained at

any load in the part 75 appendix E test

for a particular type of fuel shall be the

fuel-and-unit-specific NOX emission

rate, for that type of fuel. (2) [Reserved]

(3) If representative four-load testing

is performed according to paragraph

(c)(1)(iv)(B)(2) of this section for a group

of identical low mass emission units

with no NOX controls of any kind on

any of the units, or for a group of

identical turbines with water injection,

steam injection, or water/fuel emulsion

on all units and no other type of addon NOX controls, the fuel-and-unitspecific NOX emission rate for all units

in the group, for a particular type of

fuel, shall be the highest three run

average NOX emission rate obtained at

any load from any unit tested in the

group, for that type of fuel. (4) If a four-load test is performed for

an individual low mass emission unit

which has add-on NOX emission

controls (except for a turbine that uses

water injection, steam injection, or

water/fuel emulsion and has no other

type of add-on NOX controls), the fueland-unit-specific NOX emission rate for

each type of fuel combusted in the unit

shall be the higher of: (i) The highest emission rate from any

load of the appendix E test for that type

of fuel; or

(ii) 0.15 lb/mmBtu.

(5) [Reserved]

(6) If representative four-load testing

is performed according to paragraph

(c)(1)(iv)(B)(2) of this section for a group

of identical low mass emission units

having identical add-on NOX controls

(except for a group of identical turbines

with water injection, steam injection, or

water fuel emulsion and no other type

of add-on NOX controls), the fuel-andunit-specific NOX emission rate for each

unit in the group of units, for a

particular type of fuel, shall be the

higher of:

(i) The highest NOX emission rate

from all appendix E tests of all tested

units in the group, for that type of fuel;

or

(ii) 0.15 lb/mmBtu.

(7) If a single-load test is performed

according to § 75.19(c)(1)(iv)(I) for an

individual low mass emission unit with

no NOX emissions controls of any kind

or for a turbine with water injection,

steam injection, or water/fuel emulsion

and no other type of add-on NOX

controls, the fuel-and-unit-specific NOX

emission rate for a particular type of

fuel combusted in the unit shall be

either:

(i) The three run average NOX

emission rate obtained in the appendix

E test for that type of fuel; or

(ii) For an uncontrolled turbine which

is tested only at base load and which is

capable of operating at a higher load or

higher internal operating temperature,

the three run average NOX emission rate

obtained in the appendix E tests for that

type of fuel, multiplied by 1.15.

(8) If representative single-load testing

is performed according to

§ 75.19(c)(1)(iv)(I) for a group of

identical low mass emission units with

no NOX controls of any kind on any of

the units, or an identical group of

turbines with water injection, steam

32008 Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules

injection, or water/fuel emulsion and no

other type of add-on NOX controls, the

fuel-and-unit-specific NOX emission

rate for all units in the group, for a

particular type of fuel shall be:

(i) The highest three run average NOX

emission rate obtained for that type of

fuel in any of the appendix E tests; or

(ii) For a group of uncontrolled

turbines which are tested only at base

load and which are capable of operating

at a higher peak load or higher internal

operating temperature, the highest three

run average NOX emission rate obtained

in any of the appendix E tests for that

type of fuel, multiplied by 1.15.

* * * * *

(G) Low mass emission units for

which at least 3 years of quality-assured

NOX emission rate data from a NOXdiluent CEMS and corresponding fuel

usage data are available may determine

fuel-and-unit-specific NOX emission

rates from the actual data using the

following procedure. * * * Use the

95th percentile value for each data set

as the fuel-and-unit-specific NOX

emission rate, except that for a unit with

add-on NOX emission controls

(excluding turbines with water

injection, steam injection, or water/fuel

emulsion and no other type of add-on

NOX controls), if the 95th percentile

value is less than 0.15 lb/mmBtu, a

value of 0.15 lb/mmBtu shall be used as

the fuel-and-unit-specific NOX emission

rate.

* * * * *

(I) Notwithstanding the requirements

in paragraph (c)(1)(iv)(A) of this section,

for a unit (or group of identical units)

with no NOX controls of any kind or for

a turbine (or group of identical turbines)

with water injection, steam injection,

water/fuel emulsion, and no other type

of add-on NOX controls, single-load

appendix E testing at the normal

operating load may be performed

instead of a four load test, if the unit has

operated (or if all units in the group of

identical units have operated) at a single

load level for at least 85.0 percent of all

operating hours in the previous three

years (12 calendar quarters) prior to the

calendar quarter of the appendix E test.

To determine whether a unit qualifies

for single-load testing, proceed as

follows. Determine the range of

operation of the unit, according to

section 6.5.2.1 of appendix A to this

part. Divide the range of operation into

four equal load bands. For example, if

the range of operation extends from 20

MW to 100 MW, the four equal load

bands would be: band #1: 20 MW to 40

MW; band #2: 41 MW to 60 MW; band

#3: 61 MW to 80 MW; and band #4: 81

to 100 MW. Then, perform a historical

load analysis for all unit operating hours

in the 12 calendar quarters preceding

the quarter of the test. Determine the

percentage of the data that fall in each

load band. For a unit which is not part

of a group of identical units, if 85.0

percent or more of the data fall within

one load band, this is the normal load

level for the unit and single-load testing

may be performed at any point within

that load band. For a group of identical

units, if each unit in the group meets the

85.0 percent criterion, then

representative single-load testing within

the normal load band(s) may be

performed. For combustion turbines that

are operated to produce approximately

constant output (in MW) but which use

internal operating and exhaust

temperatures and not the actual output

in MW to control operation of the

turbine, the internal operating

temperature setpoint may be used as a

surrogate for load in demonstrating that

the unit qualifies for single-load testing.

To qualify for single load testing, the

owner or operator must document that

the unit has operated within ±10

percent of the setpoint temperature for

85.0 percent of the unit operating hours

in the previous 12 calendar quarters. If

the setpoint temperature rather than

unit load is used to justify single-load

testing, the designated representative

must certify in the monitoring plan for

the unit that this is the manner of

operation and must document the

setpoint temperature. If the unit

normally operates at a base load

setpoint temperature but is capable of

operating in a higher output peak load

when demand requires, then the test

must either be performed at peak load

or a multiplier of 1.15 shall be used to

adjust a base load test result to

approximate a peak load test result.

* * * * *

(3) * * *

(i) * * *

(B) * * *

HI HI Eq qtr hr

n

= − ∑ ( ) . LM 1

1

Where:

n = Number of unit operating hours in

the quarter.

HIhr = Hourly heat input under

paragraph (c)(3)(i)(A) of this section

(mmBtu).

* * * * *

(D) For a unit subject to the provisions

of subpart H of this part, which is not

required to report emission data on a

year-round basis and elects to report

only during the ozone season, the

quarterly heat input for the second

calendar quarter of the year shall

include only the heat input for the

months of May and June, and the

cumulative ozone season heat input

shall be the sum of the quarterly heat

input values for the second and third

calendar quarters of the year.

(ii) * * *

(E) * * * For a unit subject to the

provisions of subpart H of this part,

which is not required to report emission

data on a year-round basis and elects to

report only during the ozone season, the

quarterly heat input for the second

calendar quarter of the year shall

include only the heat input for the

months of May and June. * * *

* * * * *

(G) * * * For a unit subject to the

provisions of subpart H of this part,

which is not required to report emission

data on a year-round basis and elects to

report only during the ozone season, the

cumulative ozone season heat input

shall be the sum of the quarterly heat

input values for the second and third

calendar quarters of the year.

(H) For each low mass emission unit

or each low mass emission unit in an

identical group of units, the owner or

operator shall determine the cumulative

quarterly unit load in megawatts or

thousands of pounds of steam per hour.

The quarterly cumulative unit load shall

be the sum of the hourly unit load

values recorded under paragraph (c)(2)

of this section and shall be determined

using Equation LM–5 or LM–6. For a

unit subject to the provisions of subpart

H of this part, which is not required to

report emission data on a year-round

basis and elects to report only during

the ozone season, the quarterly

cumulative load for the second calendar

quarter of the year shall include only

the unit loads for the months of May

and June.

Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules 32009

MW MW Eq

ST ST Eq

qtr

all

qtr

all

= −

= −

∑

∑

-hours

-hours

 LM 5 (for MW output)

 LM 6 (for steam output)

.

.

Where:

MWqtr = Sum of all unit operating loads

recorded during the quarter by the

unit (MW).

STfuel-qtr = Sum of all hourly steam loads

recorded during the quarter by the

unit (klb of steam/hr).

MW = Unit operating load for a

particular unit operating hour

(MW).

ST = Unit steam load for a particular

unit operating hour (klb of steam/

hr).

(I) * * *

(Eq LM–8 for steam output) * * *

Where:

HIhr = Hourly heat input to the unit

(mmBtu).

MWhr = Hourly operating load for the

unit (MW).

SThr = Hourly steam load for the unit

(klb of steam/hr).

(J) * * *

(Eq LM–8a for steam output) * * *

Where:

HIhr = Hourly heat input to the

individual unit (mmBtu).

MWhr = Hourly operating load for the

individual unit (MW).

SThr = Hourly steam load for the

individual unit (klb of steam/hr).

∑MWqtr all-units = Sum of the quarterly

operating loads (from Eq. LM–5) for

all units in the group (MW).

∑STqtr all-units = Sum of the quarterly

steam loads (from Eq. LM–6) for all

units in the group (klb of steam/hr).

(4) * * *

(ii) * * *

(A) * * *

(Eq LM–10) * * *

WNOX = Hourly NOX mass emissions

(lbs).

EFNOX = Either the NOX emission factor

from Table LM–2 of this section or

the fuel- and unit-specific NOX

emission rate determined under

paragraph (c)(1)(iv) of this section

(lb/mmBtu). * * *

* * * * *

(C) * * * For a unit subject to the

provisions of subpart H of this part,

which is not required to report emission

data on a year-round basis and elects to

report only during the ozone season, the

ozone season NOX mass emissions for

the unit shall be the sum of the

quarterly NOX mass emissions, as

determined under paragraph (c)(4)(ii)(B)

of this section, for the second and third

calendar quarters of the year.

* * * * *

15. Section 75.20 is amended by:

a. Revising paragraphs (b)(2), (b)(3)(i),

(c)(2)(ii), (c)(2)(iii), (c)(4) introductory

text, (c)(4)(i) through (iii), (g)(2), (h)(3),

(h)(4) introductory text, (h)(4)(i) and

(h)(4)(ii);

b. In the first sentence of paragraph (a)

by removing the words ‘‘, which

includes the automated data acquisition

and handling system, and, where

applicable, the CO2 continuous

emission monitoring system,’’;

c. In the first sentence of paragraph

(a)(3) by revising the words ‘‘section for

each continuous emission or opacity

monitoring system or component

thereof,’’ to read ‘‘section, each’’,

removing the words ‘‘or component

thereof’’ after each of the two additional

occurrences of the words ‘‘opacity

monitoring system’’ in paragraph (a)(3),

and adding the word ‘‘conditional’’

before the words ‘‘data validation’’ in

the last sentence;

d. In paragraph (a)(4)(iii) by removing

each occurrence of the words ‘‘or

component thereof’’, by adding the

word ‘‘conditional’’ immediately before

each occurrence of ‘‘data validation’’,

and by removing the words ‘‘, until the

date and time that the owner or operator

completes subsequently approved initial

certification or recertification tests’’ that

appear at the end of the second

sentence;

e. In paragraph (a)(4)(iv) by removing

the words ‘‘or component thereof,’’;

f. In the first sentence of paragraph

(a)(5)(i) by removing the words ‘‘or

component thereof’’ and by adding the

words ‘‘(or, if the conditional data

validation procedures in paragraphs

(b)(3)(ii) through (b)(3)(ix) of this section

are used, until a probationary

calibration error test is passed following

corrective actions in accordance with

paragraph (b)(3)(ii) of this section)’’ after

the words ‘‘successfully completed’’;

g. In paragraphs (b)(3)(iv)(A),

(b)(3)(iv)(B), and (b)(3)(vii)(A) by

revising each occurrence of the word

‘‘consecutive’’ to read ‘‘cumulative’’;

h. Revising the third and fourth

sentences of paragraph (b)(5);

i. Removing the second paragraph

labeled (c)(1)(v) and paragraph

(h)(4)(iii);

j. Adding new paragraphs (c)(2)(iv)

and (h)(5);

k. In paragraph (d)(2)(iii) by removing

the words ‘‘or SO2-diluent’’ in the third

sentence and by adding the word

‘‘cumulative’’ after ‘‘168’’ in the fifth

sentence;

l. In paragraph (d)(2)(v) by adding the

words ‘‘(or 720 hours in any ozone

season, for sources that report emission

data only during the ozone season, in

accordance with § 75.74(c))’’ after the

words ‘‘one calendar year’’ in the first

sentence and by adding the words ‘‘(or

ozone season, as applicable)’’ after the

words ‘‘per calendar year’’ in the second

sentence;

m. In the third sentence of (d)(2)(vii)

by adding the words ‘‘, beginning with

the letters ‘‘LK’’ (e.g., ‘‘LK1,’’ ‘‘LK2,’’

etc.)’’ after the words ‘‘replacement

analyzer’’ and by adding the word

‘‘shall’’ before the word ‘‘specify’’;

n. Adding a sentence to the end of

paragraph (g)(1)(i);

o. In paragraph (g)(5) by adding the

words ‘‘(or recertified)’’ after the word

‘‘certified’’ in the first sentence, adding

the words ‘‘or for disapproval of a

recertification request’’ and ‘‘or denial

of a recertification request’’ after,

respectively, the first and second

occurrence of the words ‘‘loss of

certification’’ in the second sentence,

removing the word ‘‘either’’ from the

second sentence, adding the words ‘‘(or

recertified)’’ after the word ‘‘certified’’

in the final sentence; and

p. In the last sentence of paragraph

(h)(1) by adding the word ‘‘acceptable’’

before the word ‘‘water-to-fuel’’.

The revisions and additions read as

follows:

§ 75.20 Initial certification and

recertification procedures.

* * * * *

(b) * * *

(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).

(3) * * *

(i) The owner or operator shall either

use substitute data, according to the

32010 Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules

standard missing data procedures in

§§ 75.33 through 75.37, or shall report

emission data using a reference method

or another monitoring system that has

been certified or approved for use under

this part, 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 testing until

the hour of successful completion of all

of the required recertification tests.

Alternatively, if conditional data

validation is used, as provided in

paragraphs (b)(3)(ii) through (b)(3)(ix) of

this section, the owner or operator shall

either use substitute data or shall report

data from a certified CEMS or reference

method, beginning with the hour of the

replacement, modification, or change

made to the monitoring system until the

hour in which a probationary

calibration error test (according to

paragraph (b)(3)(ii) of this section) is

passed. Notwithstanding this

requirement, if the replacement,

modification, or change requiring

recertification of the CEMS is such that

the historical data stream is no longer

representative (e.g., where the SO2

concentration and stack flow rate

change significantly after installation of

a wet scrubber), the owner or operator

shall substitute for missing data as

follows, in lieu of using the standard

missing data procedures in §§ 75.33

through 75.37: 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 for a change that results in

a significantly lower concentration or

flow rate, substitute data using the

standard missing data procedures. 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. The first

hour of quality-assured data for the

recertified monitoring system shall

either be the hour after all recertification

tests have been completed or, if

conditional data validation is used, the

first quality-assured hour shall be

determined in accordance with

paragraphs (b)(3)(ii) through (b)(3)(ix) of

this section.

* * * * *

(5) Approval or disapproval of request

for recertification. * * * 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 the

disapproval notice back to the hour of

the adjustment or change to the CEMS

that triggered the need for recertification

testing or, if the conditional data

validation procedures in paragraphs

(b)(3)(ii) through (b)(3)(ix) of this section

were used, back to the hour of the

probationary calibration error test that

began the recertification test period.

Data from the monitoring system remain

invalid until all required recertification

tests have been passed or until a

subsequent probationary calibration

error test is passed, beginning a new

recertification test period. * * *

(c) * * *

(2) * * *

(ii) Relative accuracy test audits, as

follows:

(A) For a flow monitor installed on a

peaking unit or bypass stack, a singleload RATA at the normal load level, as

defined in section 6.5.2.1(d) of appendix

A to this part; or

(B) For all other flow monitors, a

RATA at each of the three load levels (or

operational levels) corresponding to the

three flue gas velocities described in

section 6.5.2(a) of appendix A to this

part;

(iii) A bias test for the single-load flow

RATA described in paragraph

(c)(2)(ii)(A) of this section; and

(iv) A bias test (or bias tests) for the

3-level flow RATA described in

paragraph (c)(2)(ii)(B) of this section, at

the following load or operational

level(s):

(A) At each load level designated as

normal under section 6.5.2.1(d) of

appendix A to this part, for units that

produce electrical or thermal output; or

(B) At the operational level identified

as normal in section 6.5.2.1(d) of

appendix A to this part, for units that do

not produce electrical or thermal

output.

* * * * *

(4) For each CO2 pollutant

concentration monitor, each CO2

monitoring system that uses an O2

monitor to determine CO2

concentration, and each diluent gas

monitor used only to monitor heat input

rate:

(i) A 7-day calibration error test;

(ii) A linearity check;

(iii) A relative accuracy test audit,

where, for an O2 monitor used to

determine CO2 concentration, the CO2

reference method shall be used for the

RATA; and

* * * * *

(g) * * *

(1) * * *

(i) * * * For orifice, nozzle, and

venturi-type flowmeters, the results of

primary element visual inspections and/

or calibrations of the transmitters or

transducers shall also be provided.

* * * * *

(2) Initial certification, recertification,

and QA testing notification. The

designated representative shall provide

initial certification testing notification,

recertification testing notification, and

routine periodic retesting notification

for an excepted monitoring system

under appendix E to this part as

specified in § 75.61. Initial certification

testing notification, recertification

testing notification, or periodic quality

assurance testing notification is not

required for an excepted monitoring

system under appendix D to this part.

* * * * *

(h) * * *

* * * * *

(3) Approval of certification

applications. 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 ‘‘low mass emissions

excepted methodology.’’ Provisional

certification status for the low mass

emissions methodology begins when a

complete certification application is

received, and the methodology is

considered to be certified either upon

receipt of a written approval notice from

the Administrator or, if such notice is

not provided, at the end of the

Administrator’s 120 day review period.

However, in contrast to CEM systems or

appendix D and E monitoring systems,

a provisionally certified or certified low

mass emissions excepted methodology

may not be used to report data under the

Acid Rain Program or in a NOX mass

emissions reduction program under

subpart H of this part prior to the

applicable commencement date

specified in § 75.19(a)(1)(ii).

(4) Disapproval of low mass emissions

unit certification applications. If the

Administrator determines that the

certification application for a low mass

emissions unit 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 any emission

data reported using the excepted

methodology during the Administrator’s

120-day review period shall be

considered invalid. The owner or

operator shall use the following

Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules 32011

procedures when a certification

application is disapproved:

(i) The owner or operator shall

substitute the following values, as

applicable, for each hour of unit

operation in which data were reported

using the low mass emissions

methodology until such time, date, and

hour as continuous emission monitoring

systems or excepted monitoring

systems, where applicable, are installed

and provisionally certified: the

maximum potential concentration of

SO2, as defined in section 2.1.1.1 of

appendix A to this part; the maximum

potential fuel flowrate, as defined in

section 2.4.2 of appendix D to this part;

the maximum potential values of fuel

sulfur content, GCV, and density (if

applicable) in Table D–6 of appendix D

to this part; the maximum potential

NOX emission rate, as defined in § 72.2

of this chapter; the maximum potential

flow rate, as defined in section 2.1.4.1

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. For a unit subject to a

State or federal NOX mass reduction

program where the owner or operator

intends to monitor NOX mass emissions

with a NOX pollutant concentration

monitor and a flow monitoring system,

substitute for NOX concentration using

the maximum potential concentration of

NOX, as defined in section 2.1.2.1 of

appendix A to this part, and substitute

for volumetric flow using the maximum

potential flow rate, as defined in section

2.1.4.1 of appendix A to this part; and

(ii) The designated representative

shall submit a notification of

certification test dates for the required

monitoring systems, as specified in

§ 75.61(a)(1)(ii), and shall submit a

certification application according to

the procedures in paragraph (a)(2) of

this section.

(5) Recertification. Recertification of

an approved low mass emissions

excepted methodology is not required.

Once the Administrator has approved

the methodology for use, the owner or

operator is subject to the on-going

qualification and disqualification

procedures in § 75.19(b)(1), on an

annual basis.

§ 75.21 [Amended].

16. Section 75.21 is amended by:

a. In paragraph (a)(7) by adding the

words ‘‘only for infrequent, non-routine

operation (e.g.,’’ after the words ‘‘higher

sulfur fuel(s)’’ in the first sentence, by

adding a closing parenthesis after the

words ‘‘short-term testing’’ in the first

sentence, and by revising in the last

sentence the words ‘‘720 unit (or stack)

operating hour grace period’’ to read

‘‘grace period of 720 cumulative unit or

stack operating hours’’;

b. In paragraph (a)(8) by removing the

words ‘‘On and after April 1, 2000’’ and

by capitalizing the initial occurrence of

the word ‘‘the’’;

c. In paragraph (a)(9) by revising in

the first sentence the words ‘‘exempted

under paragraphs (a)(6) or (a)(7) of this

section from the SO2 RATA

requirements of this part’’ to read

‘‘exempted from the SO2 RATA

requirements of this part under

paragraphs (a)(6) or (a)(7) of this

section’’, and by revising in the last

sentence the words ‘‘720 unit (or stack)

operating hour grace period’’ to read

‘‘grace period of 720 cumulative unit or

stack operating hours’’; and

d. In paragraph (e)(2) by removing the

word ‘‘another’’.

17. Section 75.22 is amended by:

a. Removing the last sentence of

paragraph (a) introductory text;

b. In the last sentence of paragraph

(a)(4) by revising the word ‘‘techniques’’

to read ‘‘wet bulb-dry bulb technique’’;

and

c. Adding a sentence to the end of

paragraph (a)(5).

The revisions and additions read as

follows:

§ 75.22 Reference test methods.

(a) * * *

(5) * * * Alternatively, Method 20

may be used as the reference method for

relative accuracy test audits of NOX

CEMS installed on combustion turbines.

* * * * *

18. Section 75.24 is amended by:

a. Revising paragraph (a)(1); and

b. In paragraph (c)(2) by removing the

words ‘‘or certified portable monitor

or’’.

The revisions read as follows:

§ 75.24 Out-of-control periods and

adjustment for system bias.

(a) * * *

(1) For daily calibration error tests, an

out-of-control period occurs when the

calibration error of a pollutant

concentration monitor exceeds the

applicable specification in section 2.1.4

of appendix B to this part.

* * * * *

19. Section 75.30 is amended by:

a. In paragraph (a)(6) by removing the

period at the end of the paragraph and

replacing it with ‘‘; or’’;

b. Adding new paragraphs (a)(7) and

(a)(8);

c. In the first sentence of paragraph (b)

by adding the words ‘‘percent

moisture,’’ after the words ‘‘flow rate,’’;

and

d. In paragraphs (d)(1) and (d)(2) by

removing the words ‘‘§ 75.54(b)(5) or’’

and the words ‘‘as applicable,’’.

The revisions and additions read as

follows:

§ 75.30 General provisions.

(a) * * *

(7) A valid, quality-assured hour of

moisture data (in percent H2O) has not

been measured or recorded for an

affected unit, either by a certified

moisture monitoring system or an

approved alternative monitoring method

under subpart E of this part. This

requirement does not apply when a

default percent moisture value, as

provided in §§ 75.11(b) or 75.12(b), is

used to account for the hourly moisture

content of the stack gas; or

(8) A valid, quality-assured hour of

heat input rate data (in mmBtu/hr) has

not been measured and recorded for a

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.

* * * * *

20. Section 75.31 is amended by:

a. Revising the first sentence of

paragraph (a);

b. Revising paragraphs (c)

introductory text and (c)(1);

c. Adding a new sentence to the

beginning of paragraph (c)(2);

d. In paragraph (c)(3) by adding the

words ‘‘(or for non-load-based units

using operational bins, when no prior

quality-assured data exist in the

corresponding operational bin)’’ after

the words ‘‘higher load range’’; and

e. Adding a new paragraph (d).

The revisions and additions read as

follows:

§ 75.31 Initial missing data procedures.

(a) During the first 720 qualityassured monitor operating hours

following initial certification of the

required SO2, CO2, O2 or moisture

monitoring system(s) at a particular unit

or stack location (i.e., the date and time

at which quality assured data begins to

be recorded by CEMS(s) installed at that

location), and during the first 2,160

quality-assured monitor operating hours

following initial certification of the

required NOX-diluent, NOX

concentration, or flow monitoring

system(s) at the unit or stack location,

the owner or operator shall provide

substitute data required under this

subpart according to the procedures in

paragraphs (b) and (c) of this section.

***

* * * * *

(c) Volumetric flow and NOX emission

rate or NOX concentration data (load

ranges or operational bins used). The

procedures in this paragraph apply to

affected units for which load-based

32012 Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules

ranges or non-load-based operational

bins, as defined, respectively, in

sections 2 and 3 of appendix C to this

part are used to provide substitute NOX

and flow rate data. For each hour of

missing volumetric flow rate data, NOX

emission rate data, or NOX

concentration data used to determine

NOX mass emissions:

(1) Whenever prior quality-assured

data exist in the load range (or

operational bin) corresponding to the

operating load (or operating conditions)

at the time of the missing data period,

the owner or operator shall substitute,

by means of the automated data

acquisition and handling system, for

each hour of missing data, the

arithmetic average of all of the prior

quality-assured hourly flow rates, NOX

emission rates, or NOX concentrations

in the corresponding load range (or

operational bin) as determined using the

procedure in appendix C to this part.

When non-load-based operational bins

are used, if essential operating or

parametric data are unavailable for any

hour in the missing data period, such

that the operational bin cannot be

determined, the owner or operator shall,

for that hour, substitute (as applicable)

the maximum potential flow rate as

specified in section 2.1.4.1 of appendix

A to this part or the maximum potential

NOX emission rate or the maximum

potential NOX concentration as

specified in section 2.1.2.1 of appendix

A to this part.

(2) This paragraph (c)(2) does not

apply to non-load-based units using

operational bins. * * *

* * * * *

(d) Non-load-based volumetric flow

and NOX emission rate or NOX

concentration data (operational bins not

used). The procedures in this paragraph

apply only to affected units that do not

produce electrical output (in megawatts)

or thermal output (in klb/hr of steam)

and for which operational bins are not

used. For each hour of missing

volumetric flow rate data, NOX emission

rate data, or NOX concentration data

used to determine NOX mass emissions:

(1) Whenever prior quality-assured

data exist at the time of the missing data

period, the owner or operator shall

substitute, by means of the automated

data acquisition and handling system,

for each hour of missing data, the

arithmetic average of all of the prior

quality-assured hourly average flow

rates or NOX emission rates or NOX

concentrations.

(2) Whenever no prior quality-assured

flow rate, NOX emission rate, or NOX

concentration data exist, the owner or

operator shall, as applicable, substitute

for each hour of missing data, the

maximum potential flow rate as

specified in section 2.1.4.1 of appendix

A to this part or the maximum potential

NOX emission rate or the maximum

potential NOX concentration as

specified in section 2.1.2.1 of appendix

A to this part.

21. Section 75.32 is amended by:

a. Revising paragraph (a) introductory

text;

b. In paragraph (a)(1) by adding the

words ‘‘or stack’’ after the word ‘‘unit’’

and revising the word ‘‘equation’’ to

read ‘‘Equation’’; and

c. Revising paragraph (a)(2) and the

first three sentences of paragraph (a)(3).

The revisions and additions read as

follows:

§ 75.32 Determination of monitor data

availability for standard missing data

procedures.

(a) Following initial certification of

the required SO2, CO2, O2 or moisture

monitoring system(s) at a particular unit

or stack location (i.e., the date and time

at which quality assured data begins to

be recorded by CEMS(s) at that

location), the owner or operator shall,

upon completion of the first 720 qualityassured monitor operating hours,

calculate and record, by means of the

automated data acquisition and

handling system, the percent monitor

data availability for the SO2 pollutant

concentration monitor, the CO2

pollutant concentration monitor, the O2

or CO2 diluent monitor used to calculate

heat input, and the moisture monitoring

system (as applicable). Similarly,

following initial certification of the

required NOX-diluent, NOX

concentration, or flow monitoring

system(s) at a unit or stack location, the

owner or operator shall, upon

completion of the first 2,160 qualityassured monitor operating hours,

calculate and record, by means of the

automated data acquisition and

handling system, the percent monitor

data availability for the flow monitor,

the NOX-diluent monitoring system, and

the NOX concentration monitoring

system (as applicable). Notwithstanding

these requirements, if three years

(26,280 clock hours ) have elapsed since

the date and hour of initial certification

and fewer than 720 (or 2,160, as

applicable) quality-assured monitor

operating hours have been recorded, the

owner or operator shall begin

calculating and recording the percent

monitor data availability. The percent

monitor data availability shall be

calculated for each monitored parameter

at each unit or stack location, as follows:

* * * * *

(2) Upon completion of 8,760 unit or

stack operating hours following initial

certification and thereafter, the owner or

operator shall, for the purpose of

applying the standard missing data

procedures of § 75.33, use Equation 9 to

calculate, hourly, percent monitor data

availability. Notwithstanding this

requirement, if three years (26,280 clock

hours) have elapsed since initial

certification and fewer than 8,760 unit

or stack operating hours have been

accumulated, the owner or operator

shall begin using a modified version of

Equation 9, as described in paragraph

(a)(3) of this section.

Percent

monitor data

 operating hours

quality-assured data

were recorded during previous

 unit operating hours

8,760 (Eq. 9)

availability

Total unit

for which 

= ×

8 760 100 ,

(3) When calculating percent monitor

data availability using Equation 8 or 9,

the owner or operator shall include all

unit operating hours, and all monitor

operating hours for which qualityassured data were recorded by a

certified primary monitor; a certified

redundant or non-redundant backup

monitor or a reference method for that

unit; or by an approved alternative

monitoring system under subpart E of

this part. No hours from more than three

years (26,280 clock hours) earlier shall

be used in Equation 9. For a unit that

has accumulated fewer than 8,760 unit

or stack operating hours in the previous

three years (26,280 clock hours), use the

words ‘‘in the previous three years’’

instead of ‘‘during previous 8,760 unit

or stack operating hours’’ in Equation 9,

and use ‘‘total unit or stack operating

Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules 32013

hours in the previous three years’’

instead of ‘‘8,760.’’ * * *

* * * * *

22. Section 75.33 is amended by:

a. Revising paragraphs (a) and (c)

introductory text;

b. Adding paragraphs (b)(5), (b)(6),

(b)(7), (c)(7), (c)(8), (c)(9), (c)(10), (d),

and (e);

c. In paragraphs (c)(1) introductory

text and (c)(2) introductory text by

removing the words ‘‘or continuous

emission monitoring system’’;

d. In paragraphs (c)(1)(i), (c)(1)(ii)(A),

(c)(2)(i), (c)(2)(ii)(A), and (c)(3) by

adding the words ‘‘or operational bin’’

after each occurrence of the words ‘‘unit

load range’’;

e. In paragraph (c)(3) by removing the

words ‘‘section 2 of’’;

f. In paragraph (c)(4) by adding a

sentence to the end of the paragraph;

g. In paragraph (c)(5) by adding a new

first sentence and by adding the words

‘‘recording during the previous 2,160

quality-assured monitor operating

hours’’ before the words ‘‘at the next’’;

h. In paragraph (c)(6) by revising the

words ‘‘or a higher load range’’ to read

‘‘(or a higher load range) or for the

corresponding operational bin’’; and

i. Redesignating Tables 1 and 2 from

paragraph to follow paragraph (c)(9) and

revising them.

The revisions and additions read as

follows:

§ 75.33 Standard missing data procedures

for SO2, NOX and flow rate.

(a) Following initial certification of

the required SO2, NOX, and flow rate

monitoring system(s) at a particular unit

or stack location (i.e., the date and time

at which quality assured data begins to

be recorded by CEMS(s) at that location)

and upon completion of the first 720

quality-assured monitor operating hours

(for SO2 ) or the first 2,160 quality

assured monitor operating hours (for

flow, NOX emission rate, or NOX

concentration), the owner or operator

shall provide substitute data required

under this subpart according to the

procedures in paragraphs (b) and (c) of

this section and depicted in Table 1

(SO2) and Table 2 of this section ( NOX,

flow). Notwithstanding these

requirements, if three years (26,280

clock hours) have elapsed since the date

and hour of initial certification, and

fewer than 720 (or 2,160, as applicable)

quality assured monitor operating hours

have been recorded, the owner or

operator shall begin using the missing

data procedures of this section. The

owner or operator of a unit shall

substitute for missing data using

quality-assured monitor operating hours

of data from no earlier than three years

(26,280 clock hours) prior to the date

and time of the missing data period.

(b) * * *

(5) The owner or operator may, for

units that combust more than one type

of fuel, elect to implement the missing

data routines in paragraphs (b)(1)

through (b)(4) of this section on a fuelspecific basis. If this option is selected,

the owner or operator shall document

this in the monitoring plan required

under § 75.53. To implement this

option, the owner or operator shall

create and maintain a separate SO2

concentration database for each type of

fuel (or blend), in order to obtain the

appropriate substitute data values when

that fuel (or blend) is combusted. Also,

for the purposes of providing substitute

data under paragraph (b)(4) of this

section, a separate, fuel-specific

maximum potential SO2 concentration

(MPC) value shall be determined for

each type of fuel (or blend) combusted

in the unit, in a manner consistent with

section 2.1.1.1 of appendix A to this

part. For fuel that qualifies as pipeline

natural gas or natural gas (as defined in

§ 72.2 of this chapter), the owner or

operator shall, for the purposes of

determining the MPC, either determine

the maximum total sulfur content and

minimum gross calorific value (GCV) of

the gas by fuel sampling and analysis or

shall use a default total sulfur content

of 0.05 percent by weight (dry basis) and

a default GCV value of 950 Btu/scf. The

exact methodology used to determine

each fuel-specific MPC value shall be

documented in the monitoring plan for

the unit or stack.

(6) If the owner or operator elects to

switch from non-fuel-specific missing

data routines to fuel-specific routines

(as described in paragraph (b)(5) of this

section) and if, at the time of the change,

the initial missing data procedures of

§ 75.31 have previously been completed

on a non-fuel-specific basis and the

calculation of percent monitor data

availability and use of the standard

missing data procedures has begun in

accordance with §§ 75.32 and 75.33, the

owner or operator need not repeat the

initial missing data procedures on a

fuel-specific basis. Rather, the

calculation of percent monitor data

availability may continue

uninterrupted, and the fuel-specific SO2

concentration databases may be created

prospectively, beginning at the time of

the change. Alternatively, the databases

may be created from historical CEM

data, if records are available

documenting the type of fuel combusted

during each quality-assured monitor

operating hour. If, at the time of the

missing data period, there is at least

one, but fewer than 720 quality-assured

monitor operating hours of fuel-specific

SO2 concentration data in a particular

database, use whatever data are in the

database, for the purposes of the

lookback periods described in § 75.33,

paragraphs (b)(1)(ii)(A), (b)(2)(ii)(A), and

(b)(3). If there are no quality-assured

monitor operating hours of fuel-specific

SO2 concentration data in a particular

database, report the fuel-specific MPC

value determined under paragraph (b)(5)

of this section for each hour of the

missing data period.

(7) Table 1 of this section summarizes

the provisions of paragraphs (b)(1)

through (b)(6) of this section.

(c) Volumetric flow rate, NOX

emission rate and NOX concentration

data. Use the procedures in this

paragraph to provide substitute NOX

and flow rate data for all affected units

for which load-based ranges have been

defined in accordance with section 2 of

appendix C to this part. For units that

do not produce electrical or thermal

output (i.e., non-load-based units), use

the procedures in this paragraph only to

provide substitute data for volumetric

flow rate, and only if operational bins

have been defined for the unit, as

described in section 3 of appendix C to

this part. Otherwise, use the applicable

missing data procedures in paragraph

(d) or (e) of this section for non-loadbased units. For each hour of missing

volumetric flow rate data, NOX emission

rate data, or NOX concentration data

used to determine NOX mass emissions:

* * * * *

(4) * * * In addition, when non-loadbased operational bins are used, the

owner or operator shall substitute (as

applicable) the maximum potential flow

rate for any hour in the missing data

period in which essential operating or

parametric data are unavailable and the

operational bin cannot be determined.

(5) This paragraph does not apply to

non-load-based affected units using

operational bins. * * *

* * * * *

(7) If there are fewer than 2,160

quality-assured monitor operating hours

in a load range or operational bin, use

whatever data are in the load range or

bin for purposes of the lookback periods

described in paragraphs (c)(1)(i),

(c)(1)(ii)(A), (c)(2)(i), (c)(2)(ii)(A), (c)(3),

and (c)(5) of this section.

(8) This paragraph (c) (8) does not

apply to affected units using non-loadbased operational bins. The owner or

operator may, for units that combust

more than one type of fuel, elect to

implement the missing data routines in

paragraphs (c)(1) through (c)(7) of this

section on a fuel-specific basis. If this

option is selected, the owner or operator

32014 Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules

shall document this in the monitoring

plan required under § 75.53. To

implement this option, the owner or

operator shall (as applicable) create and

maintain a separate flow rate, NOX

emission rate, or NOX concentration

database for each type of fuel, in order

to obtain the appropriate substitute data

values when that fuel is combusted.

Also, for the purposes of providing

substitute data under paragraph (c)(4) of

this section, a separate, fuel-specific

maximum potential concentration

(MPC), maximum potential NOX

emission rate (MER), or maximum

potential flow rate (MPF) value (as

applicable) shall be determined for each

type of fuel combusted in the unit, in a

manner consistent with section 2.1.2.1

or 2.1.4.1 of appendix A to this part.

The exact methodology used to

determine each fuel-specific MPC, MPF,

or MER value shall be documented in

the monitoring plan for the unit or

stack.

(9) This paragraph (c)(9) does not

apply to affected units using non-loadbased operational bins. If the owner or

operator elects to switch from non-fuelspecific missing data routines to fuelspecific routines (as described in

paragraph (b)(8) of this section) and if,

at the time of the change, the initial

missing data procedures of § 75.31 have

previously been completed on a nonfuel-specific basis and the calculation of

percent monitor data availability and

use of the standard missing data

procedures has begun in accordance

with §§ 75.32 and 75.33, the owner or

operator need not repeat the initial

missing data procedures on a fuelspecific basis. Rather, the calculation of

percent monitor data availability may

continue uninterrupted, and the fuelspecific NOX or flow rate databases may

be created prospectively, beginning at

the time of the change. Alternatively,

the databases may be created from

historical CEM data, if records are

available documenting the type of fuel

combusted during each quality-assured

monitor operating hour. If, at the time

of the missing data period, there is at

least one, but fewer than 2,160 qualityassured monitor operating hours of fuelspecific NOX or flow rate data in a

particular load range, use whatever data

are in the load range, for the purposes

of the lookback periods described in

paragraphs (c)(1)(i), (c)(1)(ii)(A), (c)(2)(i),

(c)(2)(ii)(A), and (c)(3) of this section. If

there are no quality-assured monitor

operating hours of fuel-specific NOX or

flow rate data in a particular load range

(or a higher range), report the

appropriate fuel-specific maximum

potential value determined under

paragraph (c)(2)(ii)(B)(8) of this section.

Tables 1 and 2 follow:

TABLE 1.—MISSING DATA PROCEDURE FOR SO2 CEMS, CO2 CEMS, MOISTURE CEMS AND DILUENT (CO2 OR O2)

MONITORS FOR HEAT INPUT DETERMINATION

Trigger conditions Calculation routines

Monitor data availability

(percent)

Duration (N) of CEMS

outage

(hours) 2

Method Lookback period

95 or more ........................................................ N ≤ 24 ........................ Average ........................................................... y HB/HA

N > 24 ........................ For SO2, CO2, and H2O**, the greater of .......

Average ........................................................... HB/HA.

90th percentile 1 .............................................. *720 hours.

For O2 and H2Ox, the lesser of .......................

Average ........................................................... HB/HA.

10th percentile ................................................ *720 hours.

90 or more, but below 95 ................................. N ≤ 8 .......................... Average ........................................................... y HB/HA

N > 8 .......................... For SO2, CO2, and H2O**, the greater of:.

Average ........................................................... HB/HA.

95th percentile 1 .............................................. *720 hours.

For O2 and H2O x, the lesser of:.

Average ........................................................... HB/HA.

5th percentile .................................................. *720 hours.

80 or more, but below 90 ................................. N > 0 .......................... For SO2, CO2, and H2O **, Maximum value 1 *720 hours.

For O2 and H2O x: Minimum value 1 ................ *720 hours.

Below 80 ........................................................... N > 0 .......................... Maximum potential concentration 3 or % (for

SO2, CO2, and H2O **) or Minimum potential concentration or % (for O2 and H2O x).

None.

HB/HA = hour before and hour after the CEMS outage.

*Quality-assured, monitor operating hours, during unit operation. May be either fuel-specific or non-fuel-specific. For units that report data only

for the ozone season, include only quality assured monitor operating hours within the ozone season in the lookback period. Use data from no

earlier than 3 years (or ozone seasons) prior to the missing data period. 1For units with add-on SO2 emission controls, the owner or operator may maintain separate databases of controlled and uncontrolled emissions and provide substitute data from the appropriate database according to whether the add-on controls are documented to be operating properly during the missing data period. 2 During unit operating hours.

3For units with add-on SO2 controls, you may (if available) report the SO2 concentration from a certified inlet monitor, in lieu of reporting the

MPC. X Use this algorithm for moisture except when Equation 19–3, 19–4 or 19–8 in Method 19 in appendix A to part 60 of this chapter is used for

NOX emission rate.

**Use this algorithm for moisture only when Equation 19–3, 19–4 or 19–8 in Method 19 in appendix A to part 60 of this chapter is used for

NOX emission rate. yFor units with add-on SO2 controls, if the missing data procedures of § 75.34(a)(2) are used, report the maximum SO2 concentration in the

previous 720 quality-assured monitor operating hours in the uncontrolled database in lieu of HB/HA average value, for each missing data hour in

which the add-on controls are not documented to be operating properly.

Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules 32015

TABLE 2.—MISSING DATA PROCEDURE FOR NOX-DILUENT CEMS, NOX CONCENTRATION CEMS AND FLOW RATE CEMS

Trigger conditions Calculation routines

Monitor data availability

(percent)

Duration (N) of

CEMS outage

(hours) 2

Method

Lookback period

(in hours)

Load ranges

95 or more .............................................. N ≤ 24 .................... Average .................................................. 2160 Yes.

N > 24 .................... The greater of:

Average .................................................. HB/HA No.

90th percentile ....................................... *2160 Yes.

90 or more, but below 95 ....................... N ≤ 8 ...................... Average .................................................. *2160 Yes.

N > 8 ...................... The greater of:

Average .................................................. HB/HA No.

95th percentile ....................................... *2160 Yes.

80 or more, but below 90 ....................... N > 0 ...................... Maximum value 1 .................................... *2160 Yes.

Below 80 ................................................. N > 0 ...................... Maximum NOX emission rate; or maximum potential NOX concentration 3;

or maximum potential flow rate.

None No.

HB/HA = hour before and hour after the CEMS outage.

*Quality-assured, monitor operating hours, in the corresponding load range (‘‘load bin’’) for each hour of the missing data period. May be either

fuel-specific or non-fuel-specific. If there are < 2,160 hours of data in the load bin, use all data in the bin for the lookback. For units that report

data only for the ozone season, include only quality assured monitor operating hours within the ozone season in the lookback period. Use data

from no earlier than three years (or ozone seasons) prior to the missing data period. 1For units with add-on NOX emission controls, the owner or operator may maintain separate databases of controlled and uncontrolled emissions and provide substitute data from the appropriate database according to whether the add-on controls are documented to be operating properly during the missing data period. 2 During unit operating hours.

3For units with add-on NOX controls, you may report the NOX concentration from a certified inlet monitor (if available) in lieu of reporting the

MPC.

(10) The load-based provisions of

paragraphs (c)(1) through (c)(9) of this

section are summarized in Table 2 of

this section. The non-load-based

provisions for volumetric flow rate,

found in paragraphs (c)(1) through

(c)(4), (c)(6), and (c)(7) of this section,

are presented in Table 4 of this section.

(d) Non-load-based NOX emission rate

and NOX concentration data. Use the

procedures in this paragraph to provide

substitute NOX data for affected units

that do not produce electrical output (in

megawatts) or thermal output (in klb/hr

of steam). For each hour of missing NOX

emission rate data, or NOX

concentration data used to determine

NOX mass emissions:

(1) Whenever the monitor data

availability is equal to or greater than

95.0 percent, the owner or operator shall

calculate substitute data by means of the

automated data acquisition and

handling system for each hour of each

missing data period according to the

following procedures:

(i) For a missing data period less than

or equal to 24 hours, substitute, as

applicable, for each missing hour, the

arithmetic average of the NOX emission

rates or NOX concentrations recorded by

a monitoring system in a 2,160 hour

lookback period. The lookback period

may be comprised of either:

(A) The previous 2,160 quality

assured monitor operating hours, or

(B) The previous 2,160 qualityassured monitor operating hours at the

corresponding operational bin, if

operational bins, as defined in section 3

of appendix C to this part, are used.

(ii) For a missing data period greater

than 24 hours, substitute, as applicable,

for each missing hour, the greater of:

(A) The 90th percentile NOX emission

rate or the 90th percentile NOX

concentration recorded by a monitoring

system during the previous 2,160

quality assured monitor operating hours

(or during the previous 2,160 qualityassured monitor operating hours at the

corresponding operational bin, if

operational bins are used), or

(B) The arithmetic average of the

hourly NOX emission rates or NOX

concentrations recorded by a monitoring

system during the previous 2,160

quality-assured monitor operating hours

(or during the previous 2,160 qualityassured monitor operating hours at the

corresponding operational bin, if

operational bins are used).

(2) Whenever the monitor data

availability is at least 90.0 percent but

less than 95.0 percent, the owner or

operator shall calculate substitute data

by means of the automated data

acquisition and handling system for

each hour of each missing data period

according to the following procedures:

(i) For a missing data period of less

than or equal to eight hours, substitute,

as applicable, the arithmetic average of

the hourly NOX emission rates or NOX

concentrations recorded by a monitoring

system during the previous 2,160

quality-assured monitor operating hours

(or during the previous 2,160 qualityassured monitor operating hours at the

corresponding operational bin, if

operational bins are used).

(ii) For a missing data period greater

than eight hours, substitute, as

applicable, for each missing hour, the

greater of:

(A) The 95th percentile hourly flow

rate or the 95th percentile NOX emission

rate or the 95th percentile NOX

concentration recorded by a monitoring

system during the previous 2,160

quality-assured monitor operating hours

(or during the previous 2,160 qualityassured monitor operating hours at the

corresponding operational bin, if

operational bins are used), or

(B) The arithmetic average of the

hourly NOX emission rates or NOX

concentrations recorded by a monitoring

system during the previous 2,160

quality-assured monitor operating hours

(or during the previous 2,160 qualityassured monitor operating hours at the

corresponding operational bin, if

operational bins are used).

(3) Whenever the monitor data

availability is at least 80.0 percent but

less than 90.0 percent, the owner or

operator shall, by means of the

automated data acquisition and

handling system, substitute, as

applicable, for each hour of each

missing data period, the maximum

hourly NOX emission rate or the

maximum hourly NOX concentration

32016 Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules

recorded during the previous 2,160

quality-assured monitor operating hours

(or during the previous 2,160 qualityassured monitor operating hours at the

corresponding operational bin, if

operational bins are used).

(4) Whenever the monitor data

availability is less than 80.0 percent, the

owner or operator shall substitute, as

applicable, for each hour of each

missing data period, the maximum NOX

emission rate, as defined in section

2.1.2.1 of appendix A to this part, or the

maximum potential NOX concentration,

as defined in section 2.1.2.1 of appendix

A to this part. In addition, when

operational bins are used, the owner or

operator shall substitute (as applicable)

the maximum potential NOX emission

rate or the maximum potential NOX

concentration for any hour in the

missing data period in which essential

operating or parametric data are

unavailable and the operational bin

cannot be determined.

(5) If operational bins are used and no

prior quality-assured NOX concentration

data or NOX emission rate data exist for

the corresponding operational bin, the

owner or operator shall substitute, as

applicable, either the maximum

potential NOX emission rate or the

maximum potential NOX concentration,

as defined in section 2.1.2.1 of appendix

A to this part.

(6) If operational bins are used and

there is at least one, but fewer than

2,160 quality-assured monitor operating

hours of NOX emission rate or NOX

concentration data in a particular

operational bin, use whatever data are

in the bin, for the purposes of the

lookback periods described in

paragraphs (d)(1)(i)(B), (d)(1)(ii)(A),

(d)(1)(ii)(B), (d)(2)(i), (d)(2)(ii)(A),

(d)(2)(ii)(B), and (d)(3) of this section.

(7) Table 3 of this section summarizes

the provisions of paragraphs (d)(1)

through (d)(6) of this section.

(e) Non-load-based volumetric flow

rate data. (1) If operational bins, as

defined in section 3 of appendix C to

this part, are used for a non-load-based

unit, use the missing data procedures in

paragraph (c) of this section to provide

substitute volumetric flow rate data for

the unit.

(2) If operational bins are not used for

a non-load-based unit, modify the

procedures in paragraph (c) of this

section as follows:

(i) In paragraphs (c)(1) through (c)(3),

the words ‘‘previous 2,160 qualityassured monitor operating hours’’ shall

apply rather than ‘‘previous 2,160

quality-assured monitor operating hours

at the corresponding unit load range or

operational bin, as determined using the

procedure in appendix C to this part;’’

(ii) The last sentence in paragraph

(c)(4) does not apply;

(iii) Paragraphs (c)(5), (c)(7), (c)(8),

and (c)(9) are not applicable; and

(iv) In paragraph (c)(6), the words,

‘‘for either the corresponding load range

(or a higher load range) or for the

corresponding operational bin’’ do not

apply.

(3) Table 4 of this section summarizes

the provisions of paragraphs (e)(1) and

(e)(2) of this section. Tables 3 and 4

follow:

TABLE 3.—NON-LOAD-BASED MISSING DATA PROCEDURE FOR NOX-DILUENT CEMS AND NOX CONCENTRATION CEMS

Trigger conditions Calculation routines

Monitor data availability

(percent)

Duration (N) of CEMS

outage

(hours) 1

Method Lookback period (in hours)

95 or more ............................................................. N≤24 .............................. Average ................................................................ *2160

The greater of:

N>24 ............................. Average ................................................................ *2160

90th percentile ...................................................... *2160

90 or more, but below 95 ...................................... N≤8 ................................ Average ................................................................ *2160

N>8 ............................... The greater of:

Average ................................................................ *2160

95th percentile ...................................................... *2160

80 or more, but below 90 ...................................... N>0 ............................... Maximum value .................................................... *2160

Below 80, or operational bin indeterminable ........ N>0 ............................... Maximum NOX emission rate or maximum potential NOX concentration.

None

* If operational bins are used, the lookback period is 2,160 quality-assured, monitor operating hours in the corresponding operational bin. If

there are < 2,160 hours of data in the operational bin, use all data in the bin for the lookback. If operational bins are not used, the lookback period is the previous 2,160 quality-assured monitor operating hours. For units for which data are reported only for the ozone season, include only

quality-assured monitor operating hours within the ozone season in the lookback period. Use data from no earlier than three years (or ozone

seasons) prior to the missing data period. 1 During unit operating hours.

TABLE 4.—NON-LOAD-BASED MISSING DATA PROCEDURE FOR FLOW RATE CEMS

Trigger conditions Calculation routines

Monitor data availability

(percent)

Duration (N) of CEMS

outage

(hours) 1

Method Lookback period

(in hours)

95 or more ........................................................ N≤24 ........................... Average ........................................................... *2160

N>24 ........................... The greater of:

Average ........................................................... HB/HA

90th percentile ................................................ *2160

Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules 32017

TABLE 4.—NON-LOAD-BASED MISSING DATA PROCEDURE FOR FLOW RATE CEMS—Continued

Trigger conditions Calculation routines

Monitor data availability

(percent)

Duration (N) of CEMS

outage

(hours) 1

Method Lookback period

(in hours)

90 or more, but below 95 ................................. N≤8 ............................. Average ........................................................... *2160

N>8 ............................. The greater of:

Average ........................................................... HB/HA.

95th percentile ................................................ *2160

80 or more, but below 90 ................................. N>0 ............................. Maximum value ............................................... *2160

Below 80, or operational bin indeterminable ... N>0 ............................. Maximum potential flow rate ........................... None

*If operational bins are used, the lookback period is the previous 2,160 quality-assured, monitor operating hours in the corresponding operational bin. If there are < 2,160 hours of data in the operational bin, use all data in the bin for the lookback. If operational bins are not used, the

lookback period is the previous 2,160 quality-assured, monitor operating hours. For units that report data only for the ozone season, include only

quality assured monitor operating hours within the ozone season in the lookback period. Use data from no earlier than three years (or ozone

seasons) prior to the missing data period. 1 During unit operating hours.

23. Section 75.34 is amended by:

a. Revising paragraphs (a)

introductory text, (a)(1), (a)(2), and (d); b. Redesignating paragraph (a)(3) as

(a)(4) and adding new paragraph (a)(3); c. In the second sentence of newly

redesignated paragraph (a)(4) by

removing the words ‘‘§ 75.55(b) or’’ and

‘‘, as applicable’’; and

d. In paragraph (c) by revising the

word ‘‘ NOX2’’ to read ‘‘ NOX’’. The revisions and additions read as

follows:

§ 75.34 Units with add-on emission

controls.

(a) The owner or operator of an

affected unit equipped with add-on SO2

and/or NOX emission controls

(including turbines that use dry lowNOX (DLN) technology) shall use one of

the following options for each hour in

which quality-assured data from the

outlet SO2 and/or NOX monitoring

system(s) are not obtained, and shall

document which option is selected in

the monitoring plan required under

§ 75.53:

*(1) The owner or operator may use

the missing data substitution procedures

specified in §§ 75.31 through 75.33 to

provide substitute data for any missing

data hour(s) in which the add-on

emission controls are documented to be

operating properly, as described in the

quality assurance/quality control

program for the unit, required by section

1 in appendix B of this part. To provide

the necessary documentation, the owner

or operator shall, for each missing data

period, record parametric data to verify

the proper operation of the SO2 or NOX

add-on emission controls during each

hour, as described in paragraph (d) of

this section. For any missing data

hour(s) in which such parametric data

are either not provided or, if provided,

do not demonstrate that proper

operation of the SO2 or NOX add-on

emission controls has been maintained,

the owner or operator shall substitute

(as applicable) the maximum potential

NOX concentration (MPC) as defined in

section 2.1.2.1 of appendix A to this

part, the maximum potential NOX

emission rate, as defined in § 72.2 of

this chapter, or the maximum potential

concentration for SO2, as defined by

section 2.1.1.1. Alternatively, for SO2 or

NOX, the owner or operator may

substitute, if available, the hourly SO2

or NOX concentration recorded by a

certified inlet monitor, in lieu of the

MPC. For each hour in which data from

an inlet monitor are reported, the owner

or operator shall use a method of

determination code (MODC) of ‘‘22’’

(see Table 4a in § 75.57). In addition,

under § 75.64(c), the designated

representative shall submit as part of

each electronic quarterly report, a

certification statement, verifying the

proper operation of the SO2 or NOX addon emission control for each missing

data period in which the missing data

procedures of §§ 75.31 through 75.33

were applied; or

(2) The owner or operator may use the

missing data procedures in §§ 75.31

through 75.33 for all missing data hours

if:

(i) For purposes of the data lookback

periods described in § 75.33, two

separate historical databases are created

and maintained. The first (controlled)

database shall consist of quality-assured

monitor operating hours of SO2

concentration, NOX concentration, or

NOX emission rate (as applicable)

recorded downstream of the add-on

emission controls, when the add-on

controls are in operation (i.e., on). For

a unit with more than one type of addon controls (e.g., a unit with steam

injection and SCR), the emission data

for any hour(s) in which any of the addon controls are operating shall be

included in the controlled database. The

second (uncontrolled) database shall

consist of quality-assured monitor

operating hours of SO2 concentration,

NOX concentration, or NOX emission

rate (as applicable) recorded when none

of the add-on emission controls are in

operation (i.e., off). Alternatively, the

uncontrolled database may consist of

quality-assured monitor operating hours

of data recorded by a certified

monitoring system located at the control

device inlet or by a certified monitoring

system installed on a bypass stack (for

exhaust configurations in which the flue

gases are occasionally routed through an

auxiliary stack, bypassing the add-on

emission controls);

(ii) For each hour of each missing data

period, when the appropriate

mathematical algorithm from Table 1 or

Table 2 in § 75.33 requires a lookback

for the 90th percentile value, or the 95th

percentile value, or the maximum value

from the previous 720 (or 2,160) qualityassured monitor operating hours, the

value is obtained from the appropriate

database (i.e., from the controlled

database if the add-on controls are

documented to be operating properly

during the hour or from the

uncontrolled database if the add-on

controls are either not in operation or

not documented to be operating

properly during the hour). To provide

the necessary documentation, the owner

or operator shall, for each missing data

period, record parametric data, as

described in paragraph (d) of this

section;

(iii) For SO2, when substitution of the

average of the hour-before and hourafter values is required under

§§ 75.33(b)(1)(i) or (b)(2)(i), the

maximum SO2 concentration recorded

in the previous 720 quality-assured

monitoring hours in the uncontrolled

database is substituted in lieu of the

hour-before and hour-after value, for

each hour of the missing data period in

32018 Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules

which the add-on controls are either not

in operation or are not documented to

be operating properly;

(iv) When the percent monitor data

availability (calculated according to

§ 75.32) is <80 percent, the maximum

potential SO2 or NOX concentration or

the maximum potential NOX emission

rate (as applicable) is substituted for

each hour of the missing data period, in

accordance with § 75.33(b)(4) and (c)(4);

and

(v) The designated representative, in

accordance with § 75.64(c), submits as

part of each electronic quarterly report

a certification statement verifying the

proper operation of the SO2 or NOX addon emission controls during each

missing data hour in which substitute

data values from the first (controlled)

database are reported, and (if

applicable) for SO2, during each missing

data hour in which the average of the

hour before and hour after values is

reported.

(3) If the owner or operator elects to

switch from the missing data option in

paragraph (a)(1) of this section to the

option in paragraph (a)(2) of this

section, and if, at the time of the change,

the initial missing data procedures in

§ 75.31 have been previously completed

and use of the standard missing data

procedures of § 75.33 has begun, the

owner or operator need not repeat the

initial missing data procedures. Rather,

calculation of the percent monitor data

availability may continue uninterrupted

and the two databases (controlled and

uncontrolled) may be created

prospectively, beginning at the time of

the change. Alternatively, the databases

may be created from historical CEM

data, if records are available

documenting the operational status (i.e.,

on or off) of the emission controls

during each quality-assured monitor

operating hour. If, at the time of the

missing data period, there are no

quality-assured monitor operating hours

of SO2 or NOX data in the appropriate

database for the lookback periods

described in § 75.33(b)(1)(ii)(A),

(b)(2)(ii)(A), (b)(3), (c)(1)(i), (c)(1)(i)(A),

(c)(2)(i), (c)(2)(ii)(A), and (c)(3), report

the appropriate maximum potential SO2

or NOX concentration or the maximum

potential NOX emission rate (as

applicable) for each hour of the missing

data period. If there is at least one, but

fewer than the requisite number of

quality-assured monitor operating hours

of SO2 or NOX data in the appropriate

database for the lookback periods (i.e.,

either 720 or 2,160 hours, as applicable)

the owner or operator shall use all

available data in the database for the

lookbacks.

* * * * *

(d) In order to implement the option

in paragraphs (a)(1) and (a)(2) of this

section, the owner or operator shall

keep records of information as described

in § 75.58(b)(3)(i) to verify the proper

operation of all add-on SO2 or NOX

emission controls (including dry lowNOX technology), during all periods of

SO2 or NOX emission missing data. The

owner or operator shall document in the

quality assurance/quality control (QA/

QC) program required by section 1 of

appendix B to this part, the parameters

monitored and (as applicable) the ranges

and combinations of parameters that

indicate proper operation of the

controls. If any of the following control

methods are used: wet or dry limestone

scrubbing, limestone injection, steam or

water injection, selective catalytic or

non-catalytic reduction (i.e., SCR or

SNCR), or any other control method

involving injection of water, steam, or

chemical reagents into the combustion

chamber or flue gas stream, at least one

key parameter directly related to the

control device removal efficiency shall

be monitored. Examples of such key

parameters include the water-to-fuel

ratio, the ammonia injection rate, and

the slurry flow rate. Irrespective of

which specific parameter(s) are

monitored, a demonstrable correlation

between the parametric data and control

device removal efficiency shall be

established, as part of the QA/QC

program. The correlation shall be based

on parametric data recorded during unit

operation, with the add-on controls inservice and the SO2 or NOX monitor (as

applicable) at the control device outlet

providing quality-assured data. EPA

recommends that the correlation be

based on a minimum of 720 hours of

such data, obtained at various load

levels, covering the range of operation of

the unit. The correlation shall serve as

the basis for determining whether to use

substitute data values from the

controlled database or from the

uncontrolled database, during periods of

missing SO2 or NOX data. The owner or

operator shall provide the information

recorded under § 75.58(b)(3) and the

related QA/QC program information to

the Administrator, to the EPA Regional

Office, or to an auditor from EPA or

from the appropriate State or local

agency, upon request.

24. Section 75.35 is revised to read as

follows:

§ 75.35 Missing data procedures for CO2.

(a) The owner or operator of a unit

with a CO2 continuous emission

monitoring system for determining CO2

mass emissions in accordance with

§ 75.10 (or an O2 monitor that is used to

determine CO2 concentration in

accordance with appendix F to this part)

shall substitute for missing CO2

pollutant concentration data using the

procedures of paragraphs (b) and (d) of

this section.

(b) During the first 720 quality

assured monitor operating hours

following initial certification at a

particular unit or stack location (i.e., the

date and time at which quality assured

data begins to be recorded by a CEMS

at that location), or (when implementing

these procedures for a previously

certified CO2 monitoring system) during

the 720 quality assured monitor

operating hours preceding

implementation of the standard missing

data procedures in paragraph (d) of this

section, the owner or operator shall

provide substitute CO2 pollutant

concentration data according to the

procedures in § 75.31(b).

(c) [Reserved]

(d) Upon completion of 720 quality

assured monitor operating hours using

the initial missing data procedures of

§ 75.31(b), the owner or operator shall

provide substitute data for CO2

concentration data or substitute CO2

data for heat input determination, as

applicable, in accordance with the

procedures in § 75.33(b) except that the

term ‘‘CO2 concentration’’ shall apply

rather than ‘‘SO2 concentration,’’ the

term ‘‘CO2 pollutant concentration

monitor’’ or ‘‘CO2 diluent monitor’’

shall apply rather than ‘‘SO2 pollutant

concentration monitor,’’ and the term

‘‘maximum potential CO2 concentration,

as defined in section 2.1.3.1 of appendix

A to this part’’ shall apply, rather than

‘‘maximum potential SO2

concentration.’’

25. Section 75.36 is amended by:

a. Revising the section heading;

b. In paragraph (a) by adding the word

‘‘rate’’ after the words ‘‘hourly heat

input’’ in the first sentence, by adding

the word ‘‘rate’’ after the words ‘‘heat

input’’ in the second and third

sentences, removing the words ‘‘On and

after April 1, 2000,’’ in the third

sentence and capitalizing ‘‘When’’ to

begin that sentence, and by removing

the last sentence;

c. Revising paragraph (b);

d. Removing and reserving paragraph

(c); and

e. In paragraph (d) by adding the word

‘‘rate’’ after each occurrence of the word

‘‘input’’.

The revisions and additions read as

follows:

Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules 32019

§ 75.36 Missing data procedures for heat

input rate determinations.

* * * * *

(b) During the first 720 quality

assured monitor operating hours

following initial certification at a

particular unit or stack location (i.e., the

date and time at which quality assured

data begins to be recorded by a CEMS

at that location), or (when implementing

these procedures for a previously

certified CO2 or O2 monitor) during the

720 quality assured monitor operating

hours preceding implementation of the

standard missing data procedures in

paragraph (d) of this section, 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).

* * * * *

26. Section 75.37 is amended by:

a. In paragraph (a) by revising the

words ‘‘On and after April 1, 2000, the’’

to read ‘‘The’’ in the first sentence and

by removing the second sentence;

b. Revising paragraphs (c) and

(d)(2)(i); and

c. In paragraph (d) introductory text

by removing the words ‘‘of the moisture

monitoring system’’.

The revisions and additions read as

follows:

§ 75.37 Missing data procedures for

moisture.

* * * * *

(c) During the first 720 quality assured

monitor operating hours following

initial certification at a particular unit or

stack location (i.e., the date and time at

which quality assured data begins to be

recorded by a moisture monitoring

system at that location), the owner or

operator shall provide substitute data

for moisture according to § 75.31(b).

(d) * * *

(2) * * *

(i) Provided that none of the following

equations is used to determine SO2

emissions, CO2 emissions or heat input:

Equation F–2, F–14b, F–16, F–17, or F–

18 in appendix F to this part, or

Equation 19–5 or 19–9 in Method 19 in

appendix A to part 60 of this chapter,

use the missing data procedures in

§ 75.33(b), except that the term

‘‘moisture percentage’’ shall apply

rather than ‘‘SO2 concentration,’’ the

term ‘‘moisture monitoring system’’

shall apply rather than ‘‘SO2 pollutant

concentration monitor,’’ and the term

‘‘maximum potential moisture

percentage, as defined in section 2.1.6 of

appendix A to this part’’ shall apply,

rather than ‘‘maximum potential SO2

concentration;’’ or

* * * * *

27. Section 75.41 is amended by

adding the words ‘‘(Eq. 22)’’

immediately before ‘‘where,’’ in

paragraph (b)(2)(v)(B) and by revising

Equation 27 in paragraph (c)(2)(ii) to

read as follows:

§ 75.41 Precision criteria.

* * * * *

(c) * * *

(2) * * *

(ii) * * *

r

ee e e n

ee ee

pv p v

p p

n

v v

n

= − ( )( )

− ( ) 

  − ( ) 

 









( ) ∑ ∑ ∑

∑ ∑ ∑ ∑

( )

/

/ / /

2 2 2 2 1 2 Eq. 27

28. Section 75.53 is amended by:

a. Removing and reserving paragraphs

(c) and (d);

b. Revising paragraphs (a)(1),

(e)(1)(viii), (f)(1)(i)(F), and (f)(2)(i)(H);

c. In paragraph (b) by adding the

words ‘‘, by the applicable deadline

specified in § 75.62 or elsewhere in this

part’’ prior to the period at the end of

the paragraph;

d. In paragraph (e)(1)(i)(D) by adding

the words ‘‘emergency/startup’’ after the

words ‘‘primary/secondary’’;

e. In paragraph (e)(1)(i)(E) by adding

the words ‘‘primary/secondary controls

indicator;’’ after the words ‘‘(if

applicable);’’;

f. In paragraph (e)(1)(ix) by revising

the words ‘‘Part 75 monitoring’’ to read

‘‘Monitoring’’, adding the words ‘‘ARP/

Subpart H facility ORISPL number,’’

after the words ‘‘boiler identification

number,’’, and adding the words ‘‘(or

equivalent)’’ after the words ‘‘reporting

indicator’’;

g. In paragraph (f)(2)(i)(F) by adding

the word ‘‘rate’’ after the word ‘‘input’’

and the word ‘‘emission’’ after the word

‘‘ NOX’’;

h. Adding a sentence to the end of

paragraph (f)(5)(i); and

i. Adding paragraphs (f)(5)(i)(A)

through (H).

The revisions and additions read as

follows:

§ 75.53 Monitoring plan.

(a) * * *

(1) The owner or operator shall meet

the requirements of paragraphs (a), (b),

(e), and (f) of this section.

* * * * *

(e) * * *

(1) * * *

(viii) Stack exit height (ft) above

ground level and ground level elevation

above sea level.

* * * * *

(f) * * *

(1) * * *

(i) * * *

(F) The method used to demonstrate

that the unit qualifies for monthly GCV

sampling or daily fuel sampling for

sulfur content, if applicable.

* * * * *

(2) * * *

(i) * * *

(H) To document the unit qualifies as

a peaking unit, current calendar year or

ozone season, capacity factor data as

specified in the definition of peaking

unit in § 72.2 of this chapter, and an

indication of whether the data are

actual, projected, or operating data.

* * * * *

(5) * * *

(i) * * * The following items should

be included:

(A) Current calendar year of

application;

(B) Type of qualification;

(C) Years one, two, and three;

(D) Annual or ozone season measured

or projected NOX mass emissions for

years one, two, and three;

(E) Annual or ozone season NOX mass

calculated from emission factors for

years one, two, and three;

(F) Annual measured or projected SO2

mass emissions for years one, two, and

three;

(G) Annual SO2 mass calculated from

emission factors for years one, two, and

three; and

(H) Annual or ozone season operating

hours for years one, two, and three.

* * * * *

§ 75.54 [Reserved]

29. Section 75.54 is removed and

reserved.

§ 75.55 [Reserved]

30. Section 75.55 is removed and

reserved.

§ 75.56 [Reserved]

31. Section 75.56 is removed and

reserved.

32020 Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules

32. Section 75.57 is amended by:

a. Revising the introductory

paragraph;

b. In paragraph (a)(3) by removing the

words ‘‘§ 75.55 or’’ and ‘‘as applicable,’’;

c. In paragraph (a)(4) by removing

both occurrences of the words ‘‘§ 75.56

or’’;

d. Revising Table 4a at the end of

paragraph (c)(4);

e. Revising paragraph (d)(6); and

f. Revising the first sentence of

paragraph (d)(7).

The revisions read as follows:

§ 75.57 General recordkeeping provisions.

The owner or operator shall meet all

of the applicable recordkeeping

requirements of this section.

* * * * *

(c) * * *

(4) * * *

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 or its allowable alternatives under appendix A to part 60 of this chapter.

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, O2 concentrations, NOX concentrations, flow rates,

moisture percentages or NOX emission rates for the hour before and the hour following a missing data period.

7 .................................... Average of the hourly SO2 concentration, CO2 concentration, O2 concentration, NOX concentration, moisture percentage, flow rate, or NOX emission rate for the hour before and the hour following a missing data period, using initial

missing data procedures.

8 .................................... 90th percentile hourly SO2 concentration, CO2 concentration, NOX concentration, flow rate, moisture percentage, or

NOX emission rate or 10th percentile hourly O2 concentration or moisture percentage in the applicable lookback period (moisture missing data algorithm depends on which equations are used for emissions and heat input).

9 .................................... 95th percentile hourly SO2 concentration, CO2 concentration, NOX concentration, flow rate, moisture percentage, or

NOX emission rate or 5th percentile hourly O2 concentration or moisture percentage in the applicable lookback period (moisture missing data algorithm depends on which equations are used for emissions and heat input).

10 .................................. Maximum hourly SO2 concentration, CO2 concentration, NOX concentration, flow rate, moisture percentage, or NOX

emission rate or minimum hourly O2 concentration or moisture percentage in the applicable lookback period (moisture missing data algorithm depends on which equations are used for emissions and heat input).

11 .................................. Average of hourly flow rates, NOX concentrations or NOX emission rates in corresponding load range (or, if applicable, a higher load range), for the applicable lookback period, using the initial missing data procedures.

12 .................................. Maximum potential concentration of SO2, maximum potential concentration of CO2, maximum potential concentration

of NOX maximum potential flow rate, maximum potential NOX emission rate, maximum potential moisture percentage, minimum potential O2 concentration or minimum potential moisture percentage, as determined using section

2.1 of appendix A to this part (moisture missing data algorithm depends on which equations are used for emissions

and heat input).

13 .................................. [Reserved].

14 .................................. Diluent cap value (if the cap is replacing a CO2 measurement, use 5.0 percent for boilers and 1.0 percent for turbines;

if it is replacing an O2 measurement, use 14.0 percent for boilers and 19.0 percent for turbines).

15 .................................. [Reserved].

16 .................................. SO2 concentration value of 2.0 ppm during hours when only ‘‘very low sulfur fuel’’, as defined in § 72.2 of this chapter,

is combusted.

17 .................................. Like-kind replacement non-redundant backup analyzer.

19 .................................. 200 percent of the MPC; default high range value.

20 .................................. 200 percent of the full-scale range setting (full-scale exceedance of high range).

21 .................................. Negative hourly SO2 concentration, NOX concentration, percent moisture, or NOX emission rate replaced with zero.

22 .................................. Hourly average SO2 or NOX concentration, measured by a certified monitor at the control device inlet (units with addon emission controls only).

23 .................................. Maximum potential SO2 concentration, NOX concentration or NOX emission rate or flow rate, for an hour in which flue

gases are discharged through an unmonitored bypass stack.

25 .................................. Maximum potential NOX emission rate (MER). (Use only when a NOX concentration full-scale exceedance occurs and

the diluent monitor is unavailable.)

54 .................................. Other quality assured methodologies approved through petition. These hours are included in missing data lookback

and are treated 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 treated as unavailable hours for percent monitor availability calculations.

(d) * * *

(6) Hourly average NOX emission rate

(for NOX-diluent monitoring systems

only, in units of lb/mmBtu, rounded to

the nearest thousandth);

(7) Hourly average NOX emission rate

(for NOX-diluent monitoring systems

only, in units of lb/mmBtu, rounded to

the nearest thousandth), adjusted for

bias if bias adjustment factor is required,

as provided in § 75.24(d). * * *

* * * * *

33. Section 75.58 is amended by:

a. Revising the introductory

paragraph;

b. In paragraphs (b)(1)(i) and (c) by

removing the words ‘‘§ 75.54(c) or’’;

c. In paragraph (b)(1)(xi) and

(b)(2)(vii) by removing the words

‘‘Codes 1–15 in Table 4 of § 75.54 or’’;

Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules 32021

d. Revising paragraph (b)(3);

e. Adding a period to the end of

paragraph (c)(7)(ii);

f. In paragraph (d) by removing the

words ‘‘paragraph 75.54(d) or’’;

g. In paragraph (e)(1) by removing the

words ‘‘§§ 75.54(c)(1) and (c)(3) or’’; and

h. In paragraph (f) by removing the

words ‘‘§§ 75.54(b) through (e) or’’.

The revisions read as follows:

§ 75.58 General recordkeeping provisions

for specific situations.

The owner or operator shall meet all

of the applicable recordkeeping

requirements of this section.

* * * * *

(b) * * *

(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 record:

(i) Parametric data which

demonstrate, for each hour of missing

SO2 or NOX emission data, 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, for each hour of

missing SO2 or NOX emission data,

either that the add-on emission controls

are operating properly, as described in

the quality assurance/quality control

program, or that the add-on emission

controls are not operating properly; and

(iii) For the purposes of creating the

controlled and uncontrolled databases

described under § 75.34(a)(2), a flag

indicating whether the add-on emission

controls are operating (on) or not

operating (off) during each unit

operating hour.

* * * * *

34. Section 75.59 is amended by:

a. Revising the introductory

paragraph;

b. Revising paragraphs (a)(1)(vii),

(a)(7)(ii)(P) and (a)(7)(iii)(F);

c. In the second sentence of paragraph

(a)(7) by adding the words ‘‘of this

section’’ after the words ‘‘through

(a)(7)(vi)’’;

d. In paragraph (a)(10)(i)(E) by

revising the reference to ‘‘(a)(7)(iii)(A)’’

to read ‘‘(a)(7)(iii)’’;

e. In paragraph (b)(2)(v) by adding the

word ‘‘level’’ after the word ‘‘high’’;

f. In paragraphs (b)(4)(ii)(K) and

(b)(5)(i)(N) by removing the word ‘‘and’’

after the semicolon;

g. In paragraph (b)(4)(ii)(L) by

removing the period and adding in its

place ‘‘; and’’;

h. In paragraph (b)(5)(i)(O) by

removing the period and adding in its

place a semicolon;

i. Adding paragraphs (b)(4)(ii)(M),

(b)(5)(i)(P), and (b)(5)(i)(Q);

j. In paragraph (c)(1) by removing the

words ‘‘§ 75.55(b) or’’;

k. In paragraph (d)(1) by revising the

word ‘‘under’’ to read ‘‘using the

procedures of’’;

l. Adding the word ‘‘and’’ at the end

of paragraph (d)(1)(xi);

m. Removing paragraphs (d)(1)(xiii)

through (d)(1)(xvi);

n. Redesignating existing paragraph

(d)(2) as (d)(3) and adding a new

paragraph (d)(2); and

o. In newly designated paragraph

(d)(3)(x) by removing the words ‘‘and

(3)’’.

The revisions and additions read as

follows:

§ 75.59 Certification, quality assurance,

and quality control record provisions.

The owner or operator shall meet all

of the applicable recordkeeping

requirements of this section.

(a) * * *

(1) * * *

(vii) Reference signal or calibration

gas level;

* * * * *

(7) * * *

(ii) * * *

(P) Average stack flow rate, adjusted,

if applicable, for wall effects (scfh, wet

basis);

* * * * *

(iii) * * *

(F) Average velocity differential

pressure at traverse point (inches of

H2O) or the average of the square roots

of the velocity differential pressures at

the traverse point ((inches of H2O)1/2);

* * * * *

(b) * * *

(4) * * *

(ii) * * *

(M) Number of hours excluded due to

co-firing.

* * * * *

(5) * * *

(i) * * *

(P) Flag to indicate highest NOX

emission rate for unit-specific, fuelspecific NOX emission rate testing; and

(Q) Adjusted NOX default rate (for low

mass emission unit default testing).

* * * * *

(d) * * *

(2) For each single-load or four-load

appendix E test, record the following:

(i) The three-run average NOX

emission rate for each load level;

(ii) An indicator that the average NOX

emission rate is the highest NOX average

emission rate recorded at any load level

of the test (if appropriate);

(iii) The default NOX emission rate

(highest three run average NOX emission

rate at any load level, multiplied by

1.15, if appropriate;

(iv) An indicator that the add-on NOX

emission controls were operating or not

operating during each run of the test;

and

(v) Parameter data indicating the use

and efficacy of control equipment

during the test.

* * * * *

35. Section 75.60 is amended by

adding paragraph (b)(7) to read as

follows:

§ 75.60 General provisions.

* * * * *

(b) * * *

(7) Routine appendix E retest reports.

If requested by the applicable EPA

Regional Office, appropriate State, and/

or appropriate local air pollution control

agency, the designated representative

shall submit a hardcopy report within

45 days after completing a required

periodic retest according to section 2.2

of appendix E 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(b)(5) to the

applicable EPA Regional Office,

appropriate State, and/or appropriate

local air pollution control agency that

requested the hardcopy report.

* * * * *

36. Section 75.61 is amended by:

a. In paragraph (a)(1) by removing the

words ‘‘and except for testing only of

the data acquisition and handling

system’’ from the end of that paragraph,

by adding a period to the end of the first

sentence, and by adding two new

sentences to the end of the paragraph;

b. In paragraph (a)(1)(i) by revising the

number ‘‘45’’ to read ‘‘21’’;

c. Revising paragraphs (a)(1)(ii) and

(a)(1)(iii);

d. In paragraph (a)(1)(iv) by revising

both references to ‘‘(a)(1)’’ to read

‘‘(a)(1)(ii)’’, by adding the words ‘‘or

other retests’’ to the end of the first

sentence, and by adding the words ‘‘(or

other retests)’’ after the words

‘‘recertification tests’’ in the second

sentence;

e. In the first sentence of paragraph

(a)(2) introductory text by adding the

words ‘‘, or will become affected,’’ after

the words ‘‘commercial operation’’;

f. In paragraph (a)(4) by removing

‘‘(a)’’ after the second and third

occurrences of ‘‘§ 75.4’’;

g. Revising the first sentence of

paragraph (a)(5) introductory text;

h. In paragraph (a)(5)(ii) by adding the

words ‘‘, appendix E retest, or low mass

32022 Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules

emissions unit retest’’ after the words

‘‘relative accuracy test’’; and

i. Revising paragraph (a)(6).

The revisions and additions read as

follows:

§ 75.61 Notifications.

(a) * * *

(1) * * * The owner or operator shall

also provide written notification of

testing performed under

§ 75.19(c)(1)(iv)(A) to establish fuel and

unit-specific NOX emission rates for low

mass emissions units. Such notifications

are not required, however, for initial

certifications and recertifications of

excepted monitoring systems under

appendix D to this part.

* * * * *

(ii) Notification of certification

retesting, recertification testing, and

retesting of low mass emissions units.

For retesting required following a loss of

certification under § 75.20(a)(5), for

recertification testing required under

§ 75.20(b), or for retesting required

under § 75.19(c)(1)(iv)(D), notice of the

date of any required RATA testing, any

required retesting under section 2.3 in

appendix E to this part, or any required

retesting to determine new fuel and

unit-specific NOX emission rates for low

mass emissions units shall be submitted

either in writing or by telephone at least

21 days prior to the first scheduled day

of testing. Testing may be performed on

a date other than that already provided

in a notice under this paragraph

(a)(1)(ii) as long as notice of the new

date is provided by telephone or other

means at least 7 days prior to the

original scheduled test date or the

revised test date, whichever is earlier.

(iii) Repeat of testing without notice.

Notwithstanding the above notice

requirements, the owner or operator

may elect to repeat a certification or

recertification test or low mass

emissions unit retest immediately,

without advance notification, whenever

the owner or operator has determined

during the certification or recertification

testing or low mass emissions unit

retesting that a test was failed or must

be aborted, or that a second test is

necessary in order to attain a reduced

relative accuracy test frequency.

* * * * *

(5) Periodic relative accuracy test

audits, appendix E retests, and low

mass emissions unit retests. The owner

or operator or designated representative

of an affected unit shall submit written

notice of the date of periodic relative

accuracy testing performed under

section 2.3.1 of appendix B to this part,

of periodic retesting performed under

section 2.2 of appendix E to this part,

and of periodic retesting of low mass

emissions units performed under

§ 75.19(c)(1)(iv)(D), no later than 21

days prior to the first scheduled day of

testing. * * *

* * * * *

(6) Notice of combustion of emergency

fuel under appendix D or E. The

designated representative of an oil-fired

unit or gas-fired unit using appendix D

or E of this part shall, for each calendar

quarter in which emergency fuel is

combusted, provide notice of the

combustion of the emergency fuel in the

cover letter (or electronic equivalent)

which transmits the next quarterly

report submitted under § 75.64. The

notice shall specify the exact dates and

hours during which the emergency fuel

was combusted.

* * * * *

37. Section 75.62 is amended by:

a. Revising paragraph (a)(1); and

b. In the third sentence of paragraph

(a)(2) by adding the words ‘‘certification

and’’ after the words ‘‘with any’’ and the

words ‘‘certification or’’ after the words

‘‘associated with the’’.

The revisions and additions read as

follows:

§ 75.62 Monitoring plan submittals.

(a) * * *

(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-to-date

monitoring plan file (except for

hardcopy portions identified in

paragraph (a)(2) of this section) to the

Administrator, by a method specified by

the Administrator, as follows: no later

than 45 days prior to the initial

certification tests; at the time of each

certification or recertification

application submission; in each

electronic quarterly report; and

whenever an update of the electronic

monitoring plan information is required,

either under § 75.53(b) or elsewhere in

this part (for such required updates,

submit the updated electronic

monitoring plan within 30 days of the

event with which the monitoring plan

change is associated, unless otherwise

specified in this part).

* * * * *

38. Section 75.63 is amended by:

a. Revising paragraphs (a)(1)(i) and

(ii), and removing paragraph (a)(1)(iii);

b. In paragraph (a)(2)(i) by adding the

words ‘‘under § 75.20(b)’’ after the

words ‘‘recertification tests’’ and the

words ‘‘of this section’’ after the words

‘‘paragraph (b)(1)’’;

c. Revising the first and second

sentences of paragraph (a)(2)(ii);

d. In paragraph (a)(2)(iii) by adding

the words ‘‘rather than certification

testing’’ after the words ‘‘are required’’;

e. Revising paragraph (b)(1)(i);

f. In paragraph (b)(1)(ii) by removing

the words ‘‘§ 75.56 or’’ and ‘‘as

applicable,’’; and

g. Revising the first sentence of

paragraphs (b)(2)(i) and (c).

The revisions and additions read as

follows:

§ 75.63 Initial certification or recertification

application.

(a) * * *

(1) * * *

(i) For CEM systems or excepted

monitoring systems under appendix D

or E to this part, within 45 days after

completing all initial certification tests,

submit:

(A) To the Administrator, the

electronic information required by

paragraph (b)(1) of this section and a

hardcopy certification application form

(EPA form 7610–14). The results of the

certification tests shall also be included

in the appropriate electronic quarterly

report submittal under § 75.64. Except

for subpart E applications for alternative

monitoring systems or unless

specifically requested by the

Administrator, do not submit a

hardcopy of the test data and results to

the Administrator.

(B) To the applicable EPA Regional

Office and the appropriate State and/or

local air pollution control agency, the

hardcopy information required by

paragraph (b)(2) of this section.

(ii) 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, no later than 45

days prior to commencing use of the

methodology:

(A) To the Administrator, the

electronic information required by

paragraph (b)(1)(i) of this section, and a

hardcopy certification application form

(EPA form 7610–14); and

(B) To the applicable EPA Regional

Office and appropriate State and/or

local air pollution control agency, the

hardcopy information required by

§ 75.19(a)(2), the hardcopy results of any

appendix E (of this part) tests or any

CEMS data analysis used to derive a fuel

and unit specific default NOX emission

rate, and the hardcopy information in

paragraphs (b)(2)(i), (iii), and (iv) of this

section.

(2) * * *

(ii) Within 45 days after completing

all recertification tests under § 75.20(b),

submit the hardcopy information

required by paragraph (b)(2) of this

section to the applicable EPA Regional

Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules 32023

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 to provide hardcopy

recertification test data and results.

***

* * * * *

(b) * * *

(1) * * *

(i) A complete, up-to-date version of

the electronic portion of the monitoring

plan, according to § 75.53(e) and (f), in

the format specified in § 75.62(c).

* * * * *

(2) * * *

(i) Any changed portions of the

hardcopy monitoring plan information

required under § 75.53(e) and (f). * * *

* * * * *

(c) Format. The electronic portion of

each certification or recertification

application shall be submitted in a

format to be specified by the

Administrator and by a method

specified by the Administrator. * * *

39. Section 75.64 is amended by:

a. Revising the first and third

sentences of paragraph (a) introductory

text and revising paragraph (a)(2)

introductory text;

b. In paragraph (a)(2)(iii) by removing

the words ‘‘§ 75.54(f) or’’;

c. In paragraph (a)(2)(iv) by removing

the words ‘‘§ 75.55(b)(3) or’’;

d. In paragraph (a)(2)(vi) by removing

the words ‘‘§ 75.54(g) or’’;

e. In paragraph (a)(2)(vii) by removing

the words ‘‘§ 75.56 or’’;

f. In paragraph (a)(2)(viii) by removing

the words ‘‘§ 75.56(a)(5)(vii),

§ 75.56(a)(5)(ix),’’;

g. In paragraph (a)(2)(xi) by removing

the words ‘‘§ 75.56(a)(7) or’’;

h. In paragraph (a)(4) by removing the

words ‘‘hundredth prior to April 1, 2000

and to the nearest’’ and the words ‘‘on

and after April 1, 2000’’;

i. Removing and reserving paragraphs

(a)(2)(v), (a)(8), and (e);

j. In paragraph (d) by removing the

words ‘‘or hardcopy’’; and

k. In paragraph (f) by removing the

words ‘‘modem and’’.

The revisions 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 earlier of 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). * * * For an

affected unit subject to § 75.4(d) that is

shutdown on the relevant compliance

date in § 75.4(a) or has been placed in

long-term cold storage, the owner or

operator shall submit quarterly reports

for the unit beginning with the data

from the quarter in which the unit

recommences commercial operation

(where the initial quarterly report

contains hourly data beginning with the

first hour of recommenced commercial

operation of the unit). * * *

* * * * *

(2) The information and hourly data

required in § 75.53 and §§ 75.57 through

75.59, excluding the following:

* * * * *

§ 75.65 [Amended].

40. Section 75.65 is amended by

removing the words ‘‘§ 75.54(f) or’’ and

‘‘, as applicable,’’.

§ 75.66 [Amended]

41. Section 75.66 is amended by:

a. In paragraph (e) by removing the

words ‘‘§ 75.55(b) or’’ and ‘‘, as

applicable,’’; and

b. Removing and reserving paragraph

(i).

42. Section 75.70 is amended by:

a. Adding a hyphen to the term ‘‘nonaffected’’ in paragraph (a)(1);

b. In paragraph (d)(1) by adding the

words ‘‘in § 75.20’’ after the words

‘‘recertification procedures’’;

c. Revising paragraphs (e), (f)

introductory text, and (f)(1) introductory

text;

d. In paragraphs (f)(1)(i), (ii), and (iii)

by adding a comma after the word

‘‘valid’’ and revising the words ‘‘quality

assured’’ to read ‘‘quality-assured’’;

e. In paragraphs (f)(1)(ii) and (iii) by

removing the word ‘‘or’’ from the end of

each paragraph;

f. In paragraph (f)(1)(iii) by adding the

word ‘‘rate’’ before the word ‘‘data’’,

revising the word ‘‘mmBtu’’ to read

‘‘mmBtu/hr’’, and revising the word

‘‘accepted’’ to read ‘‘excepted’’;

g. In paragraph (f)(1)(iv) by revising

the words ‘‘volumetric flow monitor,

and without a diluent monitor’’ to read

‘‘flow monitor’’, by adding a comma

after the reference to ‘‘§ 75.32’’, and by

removing the period and adding ‘‘; or’’

to the end of the paragraph;

h. Adding new paragraph (f)(1)(v);

i. In paragraph (g)(1) by adding the

word ‘‘rate’’ after the words ‘‘and heat

input’’;

j. In paragraph (g)(2) by revising the

words ‘‘of the unit under section 2.1’’ to

read ‘‘, as defined in section 2.1.4.1’’;

and

k. Revising paragraph (g)(6).

The revisions and additions read as

follows:

§ 75.70 NOX mass emissions provisions.

* * * * *

(e) Quality assurance and quality

control requirements. For units that use

continuous emission monitoring

systems to account for NOX mass

emissions, the owner or operator shall

meet the applicable quality assurance

and quality control requirements in

§ 75.21, appendix B to this part, and

§ 75.74(c) for the NOX-diluent

continuous emission monitoring

systems, flow monitoring systems, NOX

concentration monitoring systems,

moisture monitoring systems, and

diluent monitors required under § 75.71.

Units using the low mass emissions

excepted methodology under § 75.19

shall meet the applicable quality

assurance requirements of that section,

except as otherwise provided in

§ 75.74(c). Units using excepted

monitoring methods under appendices

D and E to this part shall meet the

applicable quality assurance

requirements of those appendices.

(f) Missing data procedures. Except as

provided in § 75.74(c)(7), the owner or

operator shall provide substitute data

from monitoring systems required under

§ 75.71 for each affected unit as follows:

(1) For an owner or operator using a

continuous emissions monitoring

system, substitute for missing data in

accordance with the applicable missing

data procedures in §§ 75.31 through

75.37 whenever the unit combusts fuel

and:

* * * * *

(v) A valid, quality-assured hour of

moisture data (in percent H2O) has not

been measured or recorded for an

affected unit, either by a certified

moisture monitoring system or an

approved alternative monitoring method

under subpart E of this part. This

requirement does not apply when a

default percent moisture value, as

provided in §§ 75.11(b) or 75.12(b), is

used to account for the hourly moisture

content of the stack gas.

* * * * *

(g) * * *

(6) For any unit using continuous

emissions monitors, the conditional

data validation procedures in

§ 75.20(b)(3)(ii) through (b)(3)(ix).

* * * * *

43. Section 75.71 is amended by:

a. In paragraph (a)(1) by adding the

word ‘‘rate’’ after the words ‘‘heat

input’’ and by removing the hyphen

after each occurrence of the words ‘‘O2’’

and ‘‘CO2’’;

b. In the second sentence of paragraph

(a)(2) by adding the word ‘‘rate’’ after

32024 Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules

the words ‘‘measure heat input’’, by

removing the word ‘‘use’’ after the

words ‘‘if applicable,’’, and by adding

the words ‘‘may be used’’ after the

words ‘‘appendix D to this part’’;

c. In paragraph (b)(1) by revising

‘‘i.e.’’ to read ‘‘e.g.’’ and by adding the

words ‘‘or to calculate the heat input

rate’’ before the words ‘‘, the owner’’;

d. In paragraph (b)(3) by adding the

word ‘‘rate’’ after the word ‘‘input’’ and

by adding a comma after the word

‘‘maintain’’;

e. In the first and second sentences of

paragraph (c)(2) by adding the word

‘‘rate’’ after the words ‘‘heat input’’; and

f. In paragraph (d)(2) by removing the

words ‘‘or, if applicable, paragraph (e) of

this section’’, by revising the reference

in ‘‘paragraph (c)’’ to read ‘‘paragraph

(c)(1) or (c)(2)’’, and by adding two new

sentences to the end of the paragraph.

The revisions and additions read as

follows:

§ 75.71 Specific provisions for monitoring

NOX and heat input for the purpose of

calculating NOX mass emissions.

* * * * *

(d) * * *

(2) * * * If the required CEMS are not

installed and certified by that date, the

owner or operator shall report hourly

NOX mass emissions as the product of

the maximum potential NOX emission

rate (MER) and the maximum hourly

heat input of the unit (as defined in

§ 72.2 of this chapter), starting with the

first unit operating hour after the

deadline and continuing until the CEMS

are provisionally certified. For each unit

operating hour in which the MER is

used for NOX mass reporting, the MER

shall be specific to the type of fuel being

combusted in the unit.

* * * * *

44. Section 75.72 is amended by:

a. Revising the first sentence of the

introductory paragraph to the section;

b. Revising paragraphs (a)(1)

introductory text and (a)(1)(i);

c. Redesignating paragraph (a)(1)(ii) as

paragraph (a)(1)(iii) and adding a new

paragraph (a)(1)(ii);

d. In the newly redesignated

paragraph (a)(1)(iii)(A) by adding the

word ‘‘rate’’ after the words ‘‘heat

input’’ and by adding the words ‘‘and a

diluent monitor’’ after the word

‘‘system’’ in newly redesignated

paragraph (a)(1)(iii)(B);

e. In paragraph (a)(2) introductory text

by adding the words ‘‘, for purposes of

heat input determination,’’ after the

words ‘‘from each unit and’’;

f. In paragraph (a)(2)(ii)(A) by adding

the word ‘‘rate’’ after the words ‘‘heat

input’’;

g. In paragraph (b)(1) introductory text

by removing the semicolon and adding

the words ‘‘, for purposes of heat input

determination,’’ at the end of the

paragraph;

h. In paragraph (b)(2)(ii)(B) by adding

the word ‘‘rate’’ after the words ‘‘heat

input’’ in the first sentence;

i. In paragraph (b)(2)(iii) by adding the

words ‘‘, in accordance with paragraph

(a) of this section’’ after the word

‘‘purposes’’;

j. Revising paragraph (c);

k. Revising paragraph (d);

l. In paragraph (e) introductory text by

revising the first sentence, adding a new

second sentence, and revising the words

‘‘appendix F of ‘‘ to read ‘‘appendix F

to’’ in the third sentence;

m. In paragraph (e)(1) introductory

text by revising the second sentence and

adding a new third sentence;

n. In paragraph (e)(1)(i) by adding the

word ‘‘rate’’ after ‘‘heat input’’ and by

revising the reference to ‘‘§ 75.16(e)(5)’’

to read ‘‘§ 75.16(e)(3)’’;

o. In paragraph (e)(2) by adding the

word ‘‘rate’’ after the words ‘‘heat

input’’ in the first sentence; and

p. In paragraph (g) by removing the

words ‘‘the owner or operator should’’

and by revising the reference to

‘‘§ 75.16(e)(5)’’ to read ‘‘§ 75.16(e)(3)’’.

The revisions and additions read as

follows:

§ 75.72 Determination of NOX mass

emissions.

Except as provided in paragraphs (e)

and (f) of this section, 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 rate (in mmBtu/hr)

and the unit or stack operating time (as

defined in § 72.2). * * *

(a) * * *

(1) Install, certify, operate, and

maintain a NOX-diluent continuous

emissions monitoring system and a flow

monitoring system and diluent monitor

in the common stack, record the

combined NOX mass emissions for the

units exhausting to the common stack,

and, for the purposes of determining the

hourly unit heat input rates, either:

(i) Apportion the common stack heat

input rate to the individual units

according to the procedures in

§ 75.16(e)(3);

(ii) Install, certify, operate, and

maintain a flow monitoring system and

diluent monitor in the duct to the

common stack from each unit; or

* * * * *

(c) Unit with a main stack and a

bypass stack. Whenever any portion of

the flue gases from an affected unit can

be routed through a bypass stack to

avoid the installed NOX-diluent

continuous emissions monitoring

system or NOX concentration

monitoring system, the owner and

operator shall either:

(1) Install, certify, operate, and

maintain separate NOX-diluent

continuous emissions monitoring

systems and flow monitoring systems on

the main stack and the bypass stack and

calculate NOX mass emissions for the

unit as the sum of the NOX mass

emissions measured at the two stacks;

(2) Monitor NOX mass emissions at

the main stack using a NOX-diluent

CEMS and a flow monitoring system

and measure NOX mass emissions at the

bypass stack using the reference

methods in § 75.22(b) for NOX

concentration, flow rate, and diluent gas

concentration, or NOX concentration

and flow rate, 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;

or

(3) Install, certify, operate, and

maintain a NOX-diluent CEMS and a

flow monitoring system only on the

main stack. If this option is chosen, it

is not necessary to designate the exhaust

configuration as a multiple stack

configuration in the monitoring plan

required under § 75.53, since only the

main stack is monitored. For each unit

operating hour in which the bypass

stack is used, report NOX mass

emissions as follows. If the unit heat

input is determined using a flow

monitor and a diluent monitor, report

NOX mass emissions using the

maximum potential NOX emission rate,

the maximum potential flow rate, and

either the maximum potential CO2

concentration or the minimum potential

O2 concentration (as applicable). The

maximum potential NOX emission rate

shall be specific to the type of fuel

combusted in the unit during the bypass

(see § 75.33(c)(8)). If the unit heat input

is determined using a fuel flowmeter, in

accordance with appendix D to this

part, report NOX mass emissions as the

product of the fuel-specific maximum

potential NOX emission rate and the

actual measured hourly heat input rate.

(d) Unit with multiple stack or duct

configuration. When the flue gases from

an affected unit discharge to the

atmosphere through more than one

stack, 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-diluent continuous

Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules 32025

emission monitoring system and a flow

monitoring system in each of the

multiple stacks and determine NOX

mass emissions from the affected unit as

the sum of the NOX mass emissions

recorded for each stack. If another unit

also exhausts flue gases into one of the

monitored stacks, the owner or operator

shall comply with the applicable

requirements of paragraphs (a) and (b) of

this section, in order to properly

determine the NOX mass emissions from

the units using that stack;

(2) Install, certify, operate, and

maintain a NOX-diluent continuous

emissions monitoring system and a flow

monitoring system in each of the ducts

that feed into the stack, and determine

NOX mass emissions from the affected

unit using the sum of the NOX mass

emissions measured at each duct; or

(3) If the unit is eligible to use the

procedures in appendix D to this part

and if the conditions and restrictions of

§ 75.17(c)(2) are fully met, install,

certify, operate, and maintain a NOXdiluent continuous emissions

monitoring system in one of the ducts

feeding into the stack or in one of the

multiple stacks, (as applicable) in

accordance with § 75.17(c)(2), and use

the procedures in appendix D to this

part to determine heat input rate for the

unit.

(e) Units using a NOX concentration

monitoring system and a flow

monitoring system to determine NOX

mass. The owner or operator may use a

NOX concentration monitoring system

and a flow monitoring system to

determine NOX mass emissions for the

cases described in paragraphs (a)

through (c) of this section and in

paragraph (d)(1) or paragraph (d)(2) of

this section (in place of a NOX-diluent

continuous emissions monitoring

system and a flow monitoring system).

However, this option may not be used

for the case described in paragraph

(d)(3) of this section. * * *

(1) * * * In addition, the owner or

operator must provide heat input rate

values for each unit utilizing a common

stack. The owner or operator may either:

* * * * *

45. Section 75.73 is amended by:

a. In the second sentence of paragraph

(a) by adding the word ‘‘compliance’’

before the word ‘‘deadline’’, and by

revising the reference to ‘‘§ 75.70’’ to

read ‘‘§ 75.70(b)’’;

b. Revising paragraph (a)(6)

introductory text;

c. Adding new paragraphs (a)(8),

(a)(9), (d)(6), (f)(1)(vii), and (f)(1)(viii);

d. Revising all of paragraph (c)(3)

except for the heading and the first

sentence;

e. Revising paragraph (e)(1); and

f. In paragraph (e)(2) by adding the

words ‘‘certification or’’ before the

words ‘‘recertification application’’ in

the third sentence, and by adding a new

sentence to the end of the paragraph.

The revisions and additions read as

follows:

§ 75.73 Recordkeeping and reporting.

(a) * * *

(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 information in

§ 75.58(c) for each affected gas-fired or

oil-fired unit and each non-affected gasor 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.

* * * * *

(8) Total NOX mass emissions for the

hour.

(9) Formulas from monitoring plan for

total NOX mass.

* * * * *

(c) * * *

(3) * * * In addition, to the extent

applicable, each monitoring plan shall

contain the information in § 75.53,

paragraphs (f)(1)(i), (f)(2)(i), and (f)(4) in

electronic format and the information in

§ 75.53, paragraphs (f)(1)(ii) and (f)(2)(ii)

in hardcopy format. For units using the

low mass emissions excepted

methodology under § 75.19, the

monitoring plan shall include the

additional information in § 75.53,

paragraphs (f)(5)(i) and (f)(5)(ii). The

monitoring plan also shall identify, in

electronic format, the reporting

schedule for the affected unit (ozone

season or quarterly), the beginning and

end dates for the reporting schedule,

seasonal controls indicator, ozone

season fuel switching flag, and whether

year-round reporting for the unit is

required by a State or local agency.

(d) * * *

(6) Routine appendix E retest reports.

If requested by the applicable EPA

Regional Office, appropriate State, and/

or appropriate local air pollution control

agency, the designated representative

shall submit a hardcopy report within

45 days after completing a required

periodic retest according to section 2.2

of appendix E 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(b)(5) to the

applicable EPA Regional Office,

appropriate State, and/or appropriate

local air pollution control agency that

requested the hardcopy report.

(e) * * *

(1) Electronic submission. The

designated representative for an affected

unit shall submit to the Administrator,

by a method specified by the

Administrator, a complete, electronic,

up-to-date monitoring plan file (except

for hardcopy portions identified in

paragraph (e)(2) 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)

to the permitting authority, no later than

45 days prior to the initial certification

test; at the time of a certification or

recertification application submission;

and whenever an update of the

electronic monitoring plan is required,

either under § 75.53 or elsewhere in this

part. Submit the updated electronic

monitoring plan within 30 days of the

event with which the monitoring plan is

associated, unless otherwise specified in

this part.

(2) * * * Electronic submittal of all

monitoring plan information, including

hardcopy portions, is permissible

provided that a paper copy of the

hardcopy portions can be furnished

upon request.

(f) * * *

(1) * * *

(vii) Reporting period heat input.

(viii) New reporting frequency and

begin date of the new reporting

frequency.

* * * * *

46. Section 75.74 is amended by:

a. Revising paragraph (c)(2)(i)(D)(1);

b. Adding a new second sentence to

paragraph (c)(2)(ii);

c. In the third sentence of paragraph

(c)(2)(ii)(C) by revising the words ‘‘in

every period of five consecutive

calendar’’ to read ‘‘every five’’;

d. Revising paragraph (c)(2)(ii)(H)(1);

e. Revising the second sentence of

paragraph (c)(3)(iii);

f. In the second sentence of paragraph

(c)(3)(iv) by adding the words ‘‘the

cumulative’’ after the word ‘‘only’’ and

by revising the words ‘‘included when

determining’’ to read ‘‘used to

determine’’;

g. In paragraph (c)(3)(v) by adding a

new second sentence;

h. In paragraph (c)(3)(vi)(B) by

removing the quotation marks around

the words ‘‘probationary calibration

error test’’ in the first sentence, by

revising the reference to ‘‘§ 75.20(b)(3)’’

to read ‘‘§ 75.20(b)(3)(ii)’’ in the first

sentence, and by adding the words

‘‘(subject to the restrictions in paragraph

(c)(3)(xii) of this section)’’ after the

words ‘‘§ 75.20(b)(3)’’ in the third

sentence;

32026 Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules

i. In paragraph (c)(3)(viii) by adding

the word ‘‘cumulative’’ after the number

‘‘168’’;

j. In paragraph (c)(3)(x) by adding the

words ‘‘, if applicable,’’ after the words

‘‘§ 75.20(b)(3) and’’;

k. In paragraph (c)(3)(xi) by adding a

comma after each occurrence of the

word ‘‘diagnostic’’, by revising the

words ‘‘§ 75.31 or § 75.33’’ in the third

sentence to read ‘‘§ 75.31, § 75.33, or

§ 75.37’’, and by adding the words

‘‘conditional data validation’’ before the

word ‘‘provisions’’ in the fifth sentence;

l. In paragraphs (c)(3)(xii)(A) and (B)

by revising each occurrence of the

words ‘‘§ 75.31 or § 75.33’’ to read

‘‘§ 75.31, § 75.33, or § 75.37’’, by adding

a comma after the occurrence of the

word ‘‘diagnostic’’ in each paragraph,

and by adding the words ‘‘conditional

data validation’’ before the word

‘‘provisions’’ in the second sentence of

paragraph (c)(3)(xii)(B).

m. In paragraph (c)(4) by adding the

word ‘‘rate’’ after the words ‘‘heat

input’’ in the first sentence and by

adding a new third sentence;

n. In paragraph (c)(5) by adding the

word ‘‘rate’’ after the words ‘‘heat

input’’;

o. Revising paragraphs (c)(6)(v),

(c)(7)(ii), and (c)(8)(ii);

p. Adding a new paragraph (c)(7)(iii);

q. In the second sentence of paragraph

(c)(10)(ii) by revising the word

‘‘monitoring’’ to read ‘‘monitored’’; and

r. In the second sentence of paragraph

(c)(11) by revising the word ‘‘calender’’

to read ‘‘calendar’’.

The revisions and additions read as

follows:

§ 75.74 Annual and ozone season

monitoring and reporting requirements.

* * * * *

(c) * * *

(2) * * *

(i) * * *

(D) * * *

(1) If the monitor passed a linearity

check on or after January 1 of the

previous year and the unit or stack on

which the monitor is located operated

for fewer than 336 cumulative unit or

stack operating hours (as defined in

§ 72.2 of this chapter) in the previous

ozone season, the owner or operator

may have a grace period of up to 168

cumulative unit or stack operating hours

to perform a linearity check, subject to

the restrictions in this paragraph and in

paragraph (c)(3)(xii) of this section, and

the owner or operator may continue to

submit quality assured data from that

monitor as long as all other required

quality assurance tests are passed. If the

unit or stack operates for more than the

allowable grace period of 168

cumulative operating hours in the

current ozone season without a linearity

check of the monitor having been

performed, the owner or operator of the

unit shall either report data from a

certified backup monitoring system or

reference method or shall report

substitute data using the missing data

procedures under paragraph (c)(7) of

this section, starting with the first unit

or stack operating hour after the grace

period expires and continuing until the

successful completion of a linearity

check. Note that the grace period shall

not extend beyond the end of the third

calendar quarter.

* * * * *

(ii) * * * Notwithstanding this

requirement, a pre-ozone season RATA

need not be performed between October

1 and April 30, if a RATA was passed

during the previous ozone season and if

the conditions in paragraph (a)(3)(vii) of

this section are met, thereby ensuring

that the data from the CEMS are qualityassured at the beginning of the current

ozone season.

* * * * *

(H) * * *

(1) If the monitoring system passed a

RATA on or after January 1 of the

previous year and the unit or stack on

which the monitor is located operated

for fewer than 336 cumulative unit or

stack operating hours (as defined in

§ 72.2 of this chapter) in the previous

ozone season, the owner or operator

may have a grace period of up to 720

cumulative unit or stack operating hours

to perform a RATA, subject to the

restrictions in this paragraph and in

paragraph (c)(3)(xii) of this section, and

the owner or operator may continue to

report quality assured data from that

monitor as long as all other required

quality assurance tests are passed. If the

unit or stack operates for more than the

allowable grace period of 720

cumulative unit or stack operating hours

in the current ozone season, without a

RATA of the monitoring system having

been performed, the owner or operator

of the unit or stack shall either report

data from a certified backup monitoring

system or reference method or shall

report substitute data using the missing

data procedures under paragraph (c)(7)

of this section, starting with the first

unit operating hour after the grace

period expires and continuing until the

successful completion of the RATA.

Note that the grace period shall not

extend beyond the end of the third

calendar quarter.

* * * * *

(3) * * *

(iii) * * * If the flow-to-load ratio test

for the second calendar quarter is failed,

the owner or operator shall follow the

procedures in section 2.2.5(c)(8) of

appendix B to this part. * * *

* * * * *

(v) * * * Automatic deadline

extensions may be claimed for the two

calendar quarters outside the ozone

season (the first and fourth calendar

quarters), since a fuel flow-to-load ratio

test is not required in those quarters.

***

* * * * *

(4) * * * The owner or operator shall

include all calendar quarters in the year

when determining the deadline for

visual inspection of the primary fuel

flowmeter element, as specified in

section 2.1.6(c) of appendix D to this

part.

* * * * *

(6) * * *

(v) The results of RATAs (and any

other quality assurance test(s) required

under paragraph (c)(2) or (c)(3) of this

section) which affect data validation for

the current ozone season, but which

were performed outside the ozone

season (i.e., between October 1 of the

previous calendar year and April 30 of

the current calendar year), shall be

reported in the quarterly report for the

second quarter of the current calendar

year (or in the report for the third

calendar quarter of the current calendar

year, if the unit or stack does not

operate in the second quarter).

(7) * * *

(ii) The standard missing data

procedures of §§ 75.31 through 75.37

shall be used, with one exception. When

a fuel which has a significantly higher

NOX emission rate than any of the

fuel(s) combusted in prior ozone

seasons is combusted in the unit, and no

quality-assured NOX data have been

recorded in the current or any previous

ozone season while combusting the new

fuel, the owner or operator shall

substitute the maximum potential NOX

emission rate, as defined in § 72.2 of

this chapter, from a NOX-diluent

continuous emission monitoring system,

or the maximum potential concentration

of NOX, as defined in section 2.1.2.1 of

appendix A to this part, from a NOX

concentration monitoring system. The

maximum potential value used shall be

specific to the new fuel. The owner or

operator shall substitute the maximum

potential value for each hour of missing

NOX data until the first hour that

quality-assured NOX data are obtained

while combusting the new fuel, and

then shall resume use of the standard

missing data routines, either on a fuelspecific or non-fuel-specific basis; and

(iii) In order to apply the missing data

routines described in §§ 75.31 through

Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules 32027

75.37 on an ozone season-only basis, the

procedures in those sections shall be

modified as follows:

(A) The use of the initial missing data

procedures in § 75.31 shall commence

with the first unit operating hour in the

first ozone season for which emissions

data are required to be reported under

§ 75.64.

(B) In § 75.31(a), the phrases, ‘‘during

the first 720 quality-assured monitor

operating hours within the ozone

season’’ and ‘‘during the first 2,160

quality-assured monitor operating hours

within the ozone season.’’ apply

respectively instead of the phrases

‘‘during the first 720 quality-assured

monitor operating hours’’ and ‘‘during

the first 2,160 quality-assured monitor

operating hours.’’

(C) The sentence, ‘‘The owner or

operator of a unit shall use these

procedures for no longer than three

ozone seasons following initial

certification’’ applies instead of the last

sentence of § 75.31(a).

(D) In § 75.32(a), the phrases ‘‘the first

720 quality-assured monitor operating

hours within the ozone season,’’ ‘‘the

first 2,160 quality-assured monitor

operating hours within the ozone

season,’’ and ‘‘three ozone seasons’’

apply, respectively, instead of the

phrases ‘‘the first 720 quality-assured

monitor operating hours,’’ ‘‘the first

2,160 quality-assured monitor operating

hours,’’ and ‘‘three years (26,280 clock

hours).’’

(E) In § 75.32(a)(1), the phrase

‘‘Following initial certification, prior to

completion of 3,672 unit operating

hours within the subsequent ozone

season(s)’’ applies instead of the phrase

‘‘Prior to completion of 8,760 unit

operating hours following initial

certification.’’

(F) In Equation 8, the phrase ‘‘Total

unit operating hours within the ozone

season’’ applies instead of the phrase

‘‘Total unit operating hours.’’

(G) In § 75.32(a)(2), phrase, ‘‘3,672

unit operating hours within the ozone

season,’’ applies instead of the phrase,

‘‘8,760 unit operating hours’’, and the

phrase, ‘‘three ozone seasons’’ applies

instead of the phrase, ‘‘three years

(26,280 clock hours).’’

(H) In the numerator of Equation 9,

the phrase, ‘‘Total unit operating hours

within the ozone season’’ applies

instead of the phrase ‘‘Total unit

operating hours’’, and the phrase,

‘‘3,672 unit operating hours within the

ozone season’’ applies instead of the

phrase, ‘‘8,760 unit operating hours’’. In

the denominator of Equation 9, the

number ‘‘3,672’’ applies instead of

‘‘8,760.’’

(I) Use the following instead of the

first three sentences in § 75.32(a)(3):

‘‘When calculating percent monitor data

availability using Equation 8 or 9, the

owner or operator shall include all unit

operating hours within the ozone

season, and all monitor operating hours

within the ozone season for which

quality-assured data were recorded by a

certified primary monitor; a certified

redundant or non-redundant backup

monitor or a reference method for that

unit; or by an approved alternative

monitoring system under subpart E of

this part. No hours from more than three

ozone seasons earlier shall be used in

Equation 9.’’ For a unit that has

accumulated fewer than 3,672 unit

operating hours in the previous three

ozone seasons, use the following in the

numerator of Equation 9, ‘‘Total unit

operating hours for which qualityassured data were recorded in the

previous three ozone seasons’’, and in

the denominator of Equation 9 use

‘‘Total unit operating hours in the

previous three ozone seasons.’’

(J) In § 75.33(a), the phrases ‘‘the first

720 quality-assured monitor operating

hours within the ozone season,’’ ‘‘the

first 2,160 quality-assured monitor

operating hours within the ozone

season,’’ and ‘‘three ozone seasons’’

apply, respectively, instead of the

phrases ‘‘the first 720 quality-assured

monitor operating hours,’’ ‘‘the first

2,160 quality-assured monitor operating

hours,’’ and ‘‘three years (26,280 clock

hours).’’

(K) Instead of the last sentence of

§ 75.33(a), use ‘‘For the purposes of

missing data substitution, the owner or

operator of a unit shall not use qualityassured monitor operating hours of data

that were recorded more than three

ozone seasons prior to the ozone season

in which the missing data period

occurs.’’

(L) In §§ 75.33(b), 75.33(c), 75.35,

75.36, and 75.37, the phrases, ‘‘720

quality-assured monitor operating hours

within the ozone season’’ and ‘‘2,160

quality-assured monitor operating hours

within the ozone season’’ apply,

respectively, instead of the phrases ‘‘720

quality-assured monitor operating

hours’’ and ‘‘2,160 quality-assured

monitor operating hours.’’

(M) In § 75.34(a)(2), the phrases, ‘‘720

(or 2,160) quality-assured monitor

operating hours within the ozone

season,’’ ‘‘previous 720 quality-assured

monitor operating hours recorded

within the ozone season in the

uncontrolled database,’’ and ‘‘the

requisite number of quality-assured

monitor operating hours of SO2 or NOX

data recorded within the ozone season

in the appropriate database for the

lookback periods,’’ apply respectively

instead of ‘‘720 (or 2,160) qualityassured monitor operating hours,’’

‘‘previous 720 quality-assured monitor

operating hours in the uncontrolled

database,’’ and ‘‘the requisite number of

quality-assured monitor operating hours

of SO2 or NOX data in the appropriate

database for the lookback periods.’’

(8) * * *

(ii) For units with add-on emission

controls, using the missing data option

in § 75.34(a)(1), the range of operating

parameters for add-on emission

controls, as described in § 75.34(a) and

information for verifying proper

operation of the add-on emission

controls during missing data periods, as

described in § 75.34(d). For units using

the missing data option in § 75.34(a)(2),

information documenting the operating

status of the add-on emission controls

during unit operation, as described in

§ 75.34(d).

* * * * *

Appendix A Section 1 [Amended].

47. Section 1 of Appendix A to Part

75 is amended by:

a. In section heading 1.1 by revising

the words ‘‘Pollutant Concentration and

CO2 or O2’’ to read ‘‘Gas’’;

b. In the second sentence of section

1.1 by revising the words ‘‘SO2 pollutant

concentration monitor or NOX’’ to read

‘‘SO2, CO2, O2, or NOX concentration

monitoring system or NOX-diluent’’;

c. In section heading 1.1.1 by

removing the words ‘‘Pollutant

Concentration and CO2 or O2’’;

d. In section heading 1.1.2 by

removing the words ‘‘Pollutant

Concentration and CO2 or O2 Gas’’;

e. In the fourth sentence of section 1.2

by revising the words ‘‘section 6.5.2’’ to

read ‘‘section 6.5.2.1’’; and

f. Removing the first sentence of

section 1.2.2.

48. Section 2 of Appendix A to Part

75 is amended by:

a. Revising the second and third

sentences of section 2.1;

b. In the first sentence of section 2.1.1

by revising the words ‘‘this section 2’’

to read ‘‘sections 2.1.1.1 through 2.1.1.5

of this appendix’’;

c. Moving Equations A–1a and A–1b

and the variable equations and Note

following them from paragraph (c) of

section 2.1.1.1 to the end of paragraph

(a) of section 2.1.1.1;

d. Revising the definition of the

variable ‘‘%S’’ in Equation A–1b of

paragraph (a) of section 2.1.1.1;

e. Adding a definition for the variable

‘‘GCV’’ after the definition of the

variable ‘‘%CO2W’’ in Equation A–1b in

paragraph (a) of section 2.1.1.1;

f. Adding two sentences to the end of

paragraph (b) of section 2.1.1.1;

32028 Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules

g. Adding three sentences to the end

of paragraph (a) of section 2.1.1.2;

h. In the definition of MPC in

Equation A–2 in paragraph (c) of section

2.1.1.2 by adding the words ‘‘in section

2.1.1.1 of this appendix’’ after the words

‘‘as determined by Eq. A–1a or A–1b’’;

i. Revising the fifth and tenth

sentences of section 2.1.1.3;

j. In paragraph (c) of section 2.1.1.4 by

adding a sentence after the first

sentence;

k. Removing the first sentence of

paragraph (d) of section 2.1.1.4 and

adding three sentences in its place;

l. In the first sentence of section

2.1.1.5 by revising the words

‘‘paragraphs (a) and (b)’’ to read

‘‘paragraphs (a), (b), and (c)’’;

m. In paragraph (c) of section 2.1.1.5

by revising the final sentence;

n. In section 2.1.2 by revising the

words ‘‘section 2.1.2.1’’ to read

‘‘sections 2.1.2.1 through 2.1.2.5 of this

appendix’’;

o. In paragraph (a) of section 2.1.2.1

by adding two new sentences at the end

of Option 1, by removing the word ‘‘or’’

from Option 3, by revising the period at

the end of Option 4 to read ‘‘; or’’, and

by adding a new Option 5;

p. Adding two new sentences to the

end of paragraph (c) of section 2.1.2.1;

q. Revising the first sentence of

paragraph (d) of section 2.1.2.1;

r. Revising the second sentence of

paragraph (e) and Table 2–2 in section

2.1.2.1;

s. Revising paragraph (a) of section

2.1.2.2;

t. In the third sentence of paragraph

(b) of section 2.1.2.2 by adding the

words ‘‘(if applicable)’’ after the words

‘‘ NOX emissions’’;

u. Revising the second and third

sentences of paragraph (c) of section

2.1.2.2;

v. Revising the fourth sentence of

paragraph (a) of section 2.1.2.3;

w. In the first sentence of paragraph

(b) of section 2.1.2.3 by revising the

words ‘‘requires a span’’ to read

‘‘requires or allows the use of a span

value’’;

x. Revising the second sentence of

paragraph (b) of section 2.1.2.4 and

adding a new sentence after the first

sentence;

y. Removing the first sentence of

paragraph (c) of section 2.1.2.4 and

adding three sentences in its place;

z. In the third sentence of section

2.1.2.5 by revising the words

‘‘paragraphs (a) and (b)’’ to read

‘‘paragraphs (a), (b), and (c)’’;

aa. In paragraph (c) of section 2.1.2.5

by adding the word ‘‘diagnostic’’ before

the words ‘‘linearity test’’ in the fifth

sentence and by revising the final

sentence;

bb. Amending section 2.1.3 by adding

a sentence to the end of the section;

cc. In section 2.1.3.3 by adding two

new sentences to the beginning of the

section;

dd. In the fifth sentence of section

2.1.4.2 by adding the words ‘‘, as

specified in section 2.2.2.1 of this

appendix’’ after the words ‘‘of the

calibration span value’’;

ee. In section 2.1.6 by adding a

sentence to the end of that section; and

ff. Revising section 2.2.

The revisions and additions read as

follows:

Appendix A to Part 75—Specifications and

Test Procedures

* * * * *

2. Equipment Specifications

2.1 Instrument Span and Range

* * * To meet these objectives, select the

range such that the majority of the readings

obtained during typical unit operation are

kept, to the extent practicable, between 20.0

and 80.0 percent of the full-scale range of the

instrument. These guidelines do not apply to:

(1) SO2 readings obtained during the

combustion of very low sulfur fuel (as

defined in § 72.2 of this chapter); (2) SO2 or

NOX readings recorded on the high

measurement range, for units with SO2 or

NOX emission controls and two span values,

unless the emission controls are operated

seasonally (for example, only during the

ozone season); or (3) SO2 or NOX readings

less than 20.0 percent of full-scale on the low

measurement range for a dual span unit,

provided that the maximum expected

concentration (MEC), low-scale span value,

and low-scale range settings have been

determined according to sections 2.1.1.2,

2.1.1.4(a), (b), and (g) of this appendix (for

SO2), or according to sections 2.1.2.2,

2.1.2.4(a) and (f) of this appendix (for NOX).

2.1.1 SO2 Pollutant Concentration Monitors

***

2.1.1.1 Maximum Potential Concentration

(a) * * *

Where, * * *

%S = Maximum sulfur content of fuel to be

fired, wet basis, weight percent, as

determined according to the applicable

method in paragraph (c) of section

2.1.1.1.

* * * * *

GCV = Minimum gross calorific value of the

fuel or blend to be combusted, based on

historical fuel sampling and analysis

data or, if applicable, based on the fuel

contract specifications (Btu/lb). If based

on fuel sampling and analysis, the GCV

shall be determined according to the

applicable method in paragraph (c) of

section 2.1.1.1.

* * * * *

(b) * * * Note that the initial MPC value

is subject to periodic review under section

2.1.1.5 of this appendix. If an MPC value is

found to be either inappropriately high or

low, the MPC shall be adjusted in accordance

with section 2.1.1.5, and corresponding span

and range adjustments shall be made, if

necessary.

* * * * *

2.1.1.2 Maximum Expected Concentration

(a) * * * Each initial MEC value shall be

documented in the monitoring plan required

under § 75.53. Note that each initial MEC

value is subject to periodic review under

section 2.1.1.5 of this appendix. If an MEC

value is found to be either inappropriately

high or low, the MEC shall be adjusted in

accordance with section 2.1.1.5, and

corresponding span and range adjustments

shall be made, if necessary.

* * * * *

2.1.1.3 Span Value(s) and Range(s)

* * * If the SO2 span concentration is ≤

500 ppm, the span value may either be

rounded upward to the next highest multiple

of 10 ppm, or to the next highest multiple of

100 ppm. * * * If an existing State, local, or

federal requirement for span of an SO2

pollutant concentration monitor requires or

allows the use of a span value 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. * * *

2.1.1.4 Dual Span and Range Requirements

* * * * *

(c) * * * Alternatively, if RATAs are

performed and passed on both measurement

ranges, the owner or operator may use two

separate SO2 analyzers connected to separate

probes and sample interfaces. * * *

(d) The owner or operator shall designate

the monitoring systems and components in

the monitoring plan under § 75.53 as follows:

when a single probe and sample interface are

used, either designate the low and high

monitor ranges as separate SO2 components

of a single, primary SO2 monitoring system;

designate the low and high monitor ranges as

the SO2 components of two separate, primary

SO2 monitoring systems; designate the

normal monitor range as a primary

monitoring system and the other monitor

range as a non-redundant backup monitoring

system; or, when a single, dual-range SO2

analyzer is used, designate the low and high

ranges as a single SO2 component of a

primary SO2 monitoring system (if this

option is selected, use a special dual-range

component type code, as specified by the

Administrator, to satisfy the requirements of

§ 75.53(e)(1)(iv)(D)). When two SO2 analyzers

are connected to separate probes and sample

interfaces, designate the analyzers as the SO2

components of two separate, primary SO2

monitoring systems. For units with SO2

controls, if the default high range value is

used, designate the low range analyzer as the

SO2 component of a primary SO2 monitoring

system. * * *

* * * * *

2.1.1.5 Adjustment of Span and Range

* * * * *

Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules 32029

(c) * * * Use the data validation

procedures in § 75.20(b)(3), beginning with

the hour in which the span is changed.

* * * * *

2.1.2.1 Maximum Potential Concentration

(a) * * *

Option 1: * * * For cement kilns, use 2000

ppm as the MPC. For process heaters, use 200

ppm if the unit burns only gaseous fuel and

500 ppm if the unit burns oil;

* * * * *

Option 5: If a reliable estimate of the

uncontrolled NOX emissions from the unit is

available from the manufacturer, the

estimated value may be used.

* * * * *

(c) * * * Note that whichever MPC option

in section 2.1.2.1(a) of this appendix is

selected, the initial MPC value is subject to

periodic review under section 2.1.2.5 of this

appendix. If an MPC value is found to be

either inappropriately high or low, the MPC

shall be adjusted in accordance with section

2.1.2.5, and corresponding span and range

adjustments shall be made, if necessary.

(d) For units with add-on NOX controls

(whether or not the unit is equipped with

low-NOX burner technology), or for units

equipped with dry low-NOX (DLN)

technology, NOX emission testing may only

be used to determine the MPC if testing can

be performed either upstream of the add-on

controls or during a time or season when the

add-on controls or DLN are not in operation.

***

(e) * * * For a unit with add-on NOX

controls (whether or not the unit is equipped

with low-NOX burner technology), or for a

unit equipped with dry low-NOX (DLN)

technology, historical CEM data may only be

used to determine the MPC if the 720 quality

assured monitor operating hours of CEM data

are collected upstream of the add-on controls

or if the 720 hours of data include periods

when the add-on controls or DLN are not in

operation. * * *

TABLE 2–2.—MAXIMUM POTENTIAL

CONCENTRATION FOR NOX—GASAND OIL-FIRED UNITS

Unit type

Maximum

potential

concentration for NOX

(ppm)

Tangentially-fired dry bottom .... 380

Wall-fired dry bottom ................ 600

Roof-fired (vertically-fired) dry

bottom, arch-fired .................. 550

Existing combustion turbine ..... 200

New combustion turbine, permitted to fire either oil or natural gas ................................. 200

New combustion turbine, permitted to fire only natural gas 150

Others ....................................... (1)

1As approved by the Administrator.

2.1.2.2 Maximum Expected Concentration

(a) 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

(e.g., steam injection, water injection, SCR, or

SNCR) and for turbines that use dry lowNOX technology. Also determine the MEC for

uncontrolled units and units that use only

low NOX burners (LNB) for NOX control, if

more than one type of fuel is combusted in

the unit. 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 and

except for the fuel or blend that was used to

determine the MPC under section 2.1.2.1 of

this appendix. 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; (2) using

historical CEM data over the previous 720 (or

more) quality assured monitor operating

hours; or (3) if the unit has add-on NOX

controls or uses dry low NOX technology,

and has a federally-enforceable permit limit

for NOX concentration, the permit limit may

be used as the MEC. Include in the

monitoring plan for the unit each MEC value

and the method by which the MEC was

determined. Note that each initial MEC value

is subject to periodic review under section

2.1.2.5 of this appendix. If an MEC value is

found to be either inappropriately high or

low, the MEC shall be adjusted in accordance

with section 2.1.2.5, and corresponding span

and range adjustments shall be made, if

necessary.

* * * * *

(c) * * * The data base for the MEC shall

not include any CEM data recorded during

unit startup, shutdown, or malfunction or

(for units with add-on NOX controls or

turbines using dry low NOX technology)

during any NOX control device malfunctions

or outages. All NOX control devices and

methods used to reduce NOX emissions (if

applicable) must be operating properly

during each hour. * * *

2.1.2.3 Span Value(s) and Range(s)

(a) * * * If the NOX span concentration is

≤500 ppm, the span value may either be

rounded upward to the next highest multiple

of 10 ppm, or to the next highest multiple of

100 ppm. * * *

* * * * *

2.1.2.4 Dual Span and Range Requirements

* * * * *

(b) * * * Two separate NOX analyzers

connected to separate probes and sample

interfaces may be used if RATAs are passed

on both ranges. For units with add-on NOX

emission controls (e.g., steam injection, water

injection, SCR, or SNCR) or units equipped

with dry low-NOX technology, the owner or

operator may use a low range analyzer and

a ‘‘default high range value,’’ as described in

section 2.1.2.4(e) of this appendix, in lieu of

maintaining and quality assuring a high-scale

range. * * *

(c) The owner or operator shall designate

the monitoring systems and components in

the monitoring plan under § 75.53 as follows:

When a single probe and sample interface are

used, either designate the low and high

ranges as separate NOX components of a

single, primary NOX monitoring system;

designate the low and high ranges as the NOX

components of two separate, primary NOX

monitoring systems; designate the normal

range as a primary monitoring system and the

other range as a non-redundant backup

monitoring system; or, when a single, dualrange NOX analyzer is used, designate the

low and high ranges as a single NOX

component of a primary NOX monitoring

system (if this option is selected, use a

special dual-range component type code, as

specified by the Administrator, to satisfy the

requirements of § 75.53(e)(1)(iv)(D)). When

two NOX analyzers are connected to separate

probes and sample interfaces, designate the

analyzers as the NOX components of two

separate, primary NOX monitoring systems.

For units with add-on NOX controls or units

equipped with dry low-NOX technology, if

the default high range value is used,

designate the low range analyzer as the NOX

component of the primary NOX monitoring

system. * * *

* * * * *

2.1.2.5 Adjustment of Span and Range

* * * * *

(c) * * * Use the data validation

procedures in § 75.20(b)(3), beginning with

the hour in which the span is changed.

2.1.3 CO2 and O2 Monitors

* * * If a dual-range or autoranging

diluent analyzer is installed, the analyzer

may be represented in the monitoring plan as

a single component, using a special

component type code specified by the

Administrator to satisfy the requirements of

§ 75.53(e)(1)(iv)(D).

* * * * *

2.1.3.3 Adjustment of Span and Range

The MPC and MEC values for diluent

monitors are subject to the same periodic

review as SO2 and NOX monitors (see

sections 2.1.1.5 and 2.1.2.5 of this appendix).

If an MPC or MEC value is found to be either

inappropriately high or low, the MPC shall

be adjusted and corresponding span and

range adjustments shall be made, if

necessary. * * *

* * * * *

2.1.6 Maximum Potential Moisture

Percentage

* * * Alternatively, a default maximum

potential moisture value of 15 percent H2O

may be used.

2.2 Design for Quality Control Testing

2.2.1 Pollutant Concentration and CO2 or O2

Monitors

(a) Design and equip each pollutant

concentration and CO2 or O2 monitor with a

calibration gas injection port that allows a

check of the entire measurement system

when calibration gases are introduced. For

extractive and dilution type monitors, all

monitoring components exposed to the

sample gas, (e.g., sample lines, filters,

scrubbers, conditioners, and as much of the

probe as practicable) are included in the

measurement system. For in situ type

32030 Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules

monitors, the calibration must check against

the injected gas for the performance of all

active electronic and optical components

(e.g. transmitter, receiver, analyzer).

(b) Design and equip each pollutant

concentration or CO2 or O2 monitor to allow

daily determinations of calibration error

(positive or negative) at the zero- and midor high-level concentrations specified in

section 5.2 of this appendix.

2.2.2 Flow Monitors

Design all flow monitors to meet the

applicable performance specifications.

2.2.2.1 Calibration Error Test

Design and equip each flow monitor to

allow for a daily calibration error test

consisting of at least two reference values: (1)

Zero to 20 percent of span or an equivalent

reference value (e.g., pressure pulse or

electronic signal) and (2) 50 to 70 percent of

span. Flow monitor response, both before

and after any adjustment, must be capable of

being recorded by the data acquisition and

handling system. Design each flow monitor

to allow a daily calibration error test of (1)

the entire flow monitoring system, from and

including the probe tip (or equivalent)

through and including the data acquisition

and handling system, or (2) the flow

monitoring system from and including the

transducer through and including the data

acquisition and handling system.

2.2.2.2 Interference Check

(a) Design and equip each flow monitor

with a means to ensure that the moisture

expected to occur at the monitoring location

does not interfere with the proper

functioning of the flow monitoring system.

Design and equip each flow monitor with a

means to detect, on at least a daily basis,

pluggage of each sample line and sensing

port, and malfunction of each resistance

temperature detector (RTD), transceiver or

equivalent.

(b) Design and equip each differential

pressure flow monitor to provide (1) an

automatic, periodic back purging

(simultaneously on both sides of the probe)

or equivalent method of sufficient force and

frequency to keep the probe and lines

sufficiently free of obstructions on at least a

daily basis to prevent velocity sensing

interference, and (2) a means for detecting

leaks in the system on at least a quarterly

basis (manual check is acceptable).

(c) Design and equip each thermal flow

monitor with a means to ensure on at least

a daily basis that the probe remains

sufficiently clean to prevent velocity sensing

interference.

(d) Design and equip each ultrasonic flow

monitor with a means to ensure on at least

a daily basis that the transceivers remain

sufficiently clean (e.g., backpurging system)

to prevent velocity sensing interference.

Appendix A to Part 75 [Amended]

49. Section 3 of Appendix A to Part

75 is amended by:

a. In section heading 3.3.1 by adding

the word ‘‘Monitors’’ after the word

‘‘SO2’’;

b. Revising section 3.3.1;

c. Revising paragraph (a) of section

3.3.2;

d. In the first sentence of paragraph

(b) of section 3.3.2 by revising the words

‘‘not exceed’’ to read ‘‘be within’’;

e. In section heading 3.3.3 by

removing the words ‘‘Pollutant

Concentration’’;

f. In paragraph 3.3.3 by adding ‘‘±’’

before the words ‘‘1.0 percent’’;

g. In section heading 3.3.4 by adding

the word ‘‘Monitors’’ after the word

‘‘Flow’’;

h. Revising section 3.3.4;

i. In the second sentence of section

3.3.6 by revising the words ‘‘appendix

are’’ to read ‘‘appendix is’’; and

j. Revising the second sentence of

paragraph (b) of section 3.3.7.

The revisions and additions read as

follows:

3. Performance Specifications

* * * * *

3.3 Relative Accuracy

3.3.1 Relative Accuracy for SO2 Monitors

(a) The relative accuracy for SO2 pollutant

concentration monitors shall not exceed 10.0

percent except as provided below in this

section.

(b) For affected units where the average of

the reference method measurements of SO2

concentration during the relative accuracy

test audit is less than or equal to 250.0 ppm,

the mean value of the monitor measurements

shall be within ±15.0 ppm of the reference

method mean value wherever the relative

accuracy specification of 10.0 percent is not

achieved.

3.3.2 Relative Accuracy for NOX-Diluent

Continuous Monitoring Systems

(a) The relative accuracy for NOX-diluent

continuous emission monitoring systems

shall not exceed 10.0 percent at any load

level at which a RATA is performed (the low,

mid, or high load level, as defined in section

6.5.2.1 of this appendix).

* * * * *

3.3.4 Relative Accuracy for Flow Monitors

(a) The relative accuracy of flow monitors

shall not exceed 10.0 percent at any load

level at which a RATA is performed (the low,

mid, or high load level, as defined in section

6.5.2.1 of this appendix).

(b) For affected units where the average of

the flow reference method measurements of

gas velocity at a particular load level of the

relative accuracy test audit is less than or

equal to 10.0 fps, the mean value of the flow

monitor velocity measurements shall be

within ±2.0 fps of the reference method mean

value in fps at that load level, wherever the

10.0 percent relative accuracy specification is

not achieved.

* * * * *

3.3.7 Relative Accuracy for NOX

Concentration Monitoring Systems

* * * * *

(b) * * * Alternatively, for affected units

where the average of the reference method

measurements of NOX concentration during

the relative accuracy test audit is less than or

equal to 250.0 ppm, the mean value of the

continuous emission monitoring system

measurements shall be within ±15.0 ppm of

the reference method mean value.

* * * * *

50. Section 4 of Appendix A to Part

75 is amended by:

a. Revising the second sentence of the

first paragraph of section 4;

b. Removing the last sentence of the

first paragraph of section 4; and

c. In subparagraph (3) of section 4 by

adding the words ‘‘the appropriate’’

before the word ‘‘units’’, by removing

the words ‘‘of the standard’’, and by

adding the word ‘‘e.g.,’’ before the

words ‘‘lb/hr’’.

The revisions and additions read as

follows:

4. Data Acquisition and Handling Systems

* * * These systems also shall have the

capability of interpreting and converting the

individual output signals from an SO2

pollutant concentration monitor, a flow

monitor, a CO2 monitor, a NOX pollutant

concentration monitor, and a NOX-diluent

continuous emission monitoring system to

produce a continuous readout of pollutant

mass emission rates in the appropriate units

(e.g., lb/hr, lb/mmBtu, tons/hr). * * *

* * * * *

Appendix A to Part 75 [Amended]

51. Section 6 of Appendix A to Part

75 is amended by:

a. In the first sentence of paragraph (a)

of section 6.2 by adding the word

‘‘conditional’’ before the words ‘‘data

validation procedures’’;

b. In section 6.3.1 by removing the

word ‘‘extended’’ before the words ‘‘unit

outages’’ in the second sentence, and by

adding a new sentence after the second

sentence;

c. In the first sentence of paragraph (a)

of section 6.3.1 by adding the word

‘‘conditional’’ before the words ‘‘data

validation procedures’’;

d. In the fourth sentence of section

6.3.2 by removing the word ‘‘extended’’

before the words ‘‘unit outages’’, and by

adding a new sentence after the fourth

sentence;

e. In the first sentence of paragraph (a)

of section 6.3.2 by adding the word

‘‘conditional’’ before the words ‘‘data

validation procedures’’;

f. In the first sentence of paragraph (a)

of section 6.4 by adding the word

‘‘conditional’’ before the words ‘‘data

validation procedures’’;

g. In the first sentence of section 6.5

by adding the word ‘‘and’’ after the

words ‘‘heat input,’’ and by removing

the words ‘‘and each SO2-diluent

continuous emission monitoring

system’’;

Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules 32031

h. Revising paragraphs (a) and (c) of

section 6.5;

i. In the first sentence of paragraph

(f)(1) of section 6.5 by adding the word

‘‘conditional’’ before the words ‘‘data

validation procedures’’;

j. In the second sentence of paragraph

(g) of section 6.5 by removing the words

‘‘SO2-diluent’’;

k. Revising paragraph (a) of section

6.5.1 and paragraph (a) of section 6.5.2;

l. In paragraph (b) of section 6.5.2 by

revising the words ‘‘section 6.5.2.1’’ to

read ‘‘section 6.5.2.1(d)’’;

m. In paragraph (c) of section 6.5.2 by

adding the words ‘‘(or three operating

levels)’’ after the word ‘‘level(s)’’;

n. In paragraph (d) of section 6.5.2 by

adding the words ‘‘(or operating levels)’’

after the word ‘‘level(s)’’;

o. In section heading 6.5.2.1 by

adding the words ‘‘(or Operating)’’ after

the words ‘‘Normal Load’’;

p. Revising paragraph (a) of section

6.5.2.1;

q. In the first sentence of paragraph

(b) of section 6.5.2.1 by revising the

words ‘‘30.0 to 60.0 percent’’ to read ‘‘>

30.0 percent, but ≤ 60.0 percent’’ and

revising the words ‘‘60.0 to 100.0

percent’’ to read ‘‘> 60.0 percent’’;

r. Revising paragraphs (c) and (d) of

section 6.5.2.1;

s. Revising the first sentence of

paragraph (e) of section 6.5.2.1;

t. Removing and reserving section

6.5.3;

u. Amending section 6.5.6 by

removing the third sentence;

v. In paragraph (b)(2) of section 6.5.6

by revising the number ‘‘1.0’’ To read

‘‘1.2’’;

w. Adding paragraph (b)(5) to section

6.5.6;

x. In the first sentence of paragraph (a)

of sections 6.5.6.1 and 6.5.6.2 by

revising the words ‘‘normal load’’ to

read ‘‘the normal load level (or normal

operating level)’’;

y. In paragraph (c) of section 6.5.6.3

by removing the words ‘‘§ 75.56(a)(7)

or’’ and the words ‘‘, as applicable’’;

z. In paragraph (a) of section 6.5.7 by

removing the words ‘‘or SO2-diluent’’ in

the fourth sentence, by adding one

sentence before, and two sentences

after, the ninth sentence, and by

removing the words ‘‘§ 75.56(a)(5)(ix)

and’’ from the next to last sentence; and

aa. In section 6.5.10 by adding a

comma after the number ‘‘7D’’, and by

adding a new third sentence.

The revisions and additions read as

follows:

6. Certification Tests and Procedures

* * * * *

6.3 7-Day Calibration Error Test

6.3.1 Gas Monitor 7-Day Calibration Error

Test

* * * Notwithstanding this requirement,

for a peaking unit (as defined in § 72.2 of this

chapter), only 3 of the 7 days in the test need

be unit operating days. * * *

* * * * *

6.3.2 Flow Monitor 7-Day Calibration Error

Test

* * * Notwithstanding these

requirements, for a peaking unit (as defined

in § 72.2 of this chapter), only 3 of the 7 days

in the test need be unit operating days. * * *

* * * * *

6.5 Relative Accuracy and Bias Tests

(General Procedures)

* * * * *

(a) 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 a normal

primary or backup fuel 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). For units that

co-fire fuels as the predominant mode of

operation, perform the RATAs while cofiring. When relative accuracy test audits are

performed on continuous emission

monitoring systems installed 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) 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 that operate continuously rather

than seasonally, 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 use fuel

switching or for which the emission controls

are operated seasonally), provided that both

monitor ranges are connected to a common

probe and sample interface, 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. If the low and high

measurement ranges are connected to

separate sample probes and interfaces, RATA

testing on both ranges is required.

* * * * *

6.5.1 Gas Monitoring System RATAs

(Special Considerations)

(a) Perform the required relative accuracy

test audits for each SO2 or CO2 pollutant

concentration monitor, each CO2 or O2

diluent monitor used to determine heat

input, each NOX-diluent continuous

emission monitoring system, and each NOX

concentration monitoring system used to

determine NOX mass emissions, as defined in

§ 75.71(a)(2) at the normal load level or

normal operating 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 or operating levels have been

designated as normal, the RATAs may be

done at either load level.

* * * * *

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 or operating 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 or operating level

combinations for the units exhausting to the

common stack. Select the three exhaust gas

velocities such that the audit points at

adjacent load or operating levels (i.e., low

and mid or mid and high), in megawatts (or

in thousands of lb/hr of steam production or

in ft/sec, as applicable), 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.

* * * * *

6.5.2.1 Range of Operation and Normal

Load (or Operating) Load Level(s)

(a) The owner or operator shall determine

the upper and lower boundaries of the ‘‘range

of operation’’ as follows for each unit (or

combination of units, for common stack

configurations) that uses CEMS to account for

its emissions and for each unit that uses the

optional fuel flow-to-load quality assurance

test in section 2.1.7 of appendix D to this

part:

(1) For affected units that produce

electrical output (in megawatts) or thermal

output (in klb/hr of steam production), the

lower boundary of the range of operation of

a unit shall be the minimum safe, stable load.

For common stacks, the minimum safe, stable

load shall be the lowest of the minimum safe,

stable loads for any of the units discharging

through the stack. Alternatively, for a group

of frequently-operated units that serve a

common stack, the sum of the minimum safe,

stable loads for the individual units may be

used as the lower boundary of the range of

operation. 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 either: the nameplate

or rated capacity of the unit, less any

physical or regulatory limitations or other

deratings; or 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; or

32032 Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules

(2) For affected units that do not produce

electrical or thermal output, the lower

boundary of the range of operation shall be

the minimum expected flue gas velocity (in

ft/sec) during normal, stable operation of the

unit. The upper boundary of the range of

operation shall be the maximum potential

flue gas velocity (in ft/sec) as defined in

section 2.1.4.1 of this appendix. The

minimum expected and maximum potential

velocities may be derived from the results of

reference method testing or by using

Equation A–3a or A–3b (as applicable) in

section 2.1.4.1 of this appendix. If Equation

A-3a or A–3b is used to determine the

minimum expected velocity, replace the

word ‘‘maximum’’ to read ‘‘minimum’’ in the

definitions of ‘‘MPV,’’ ‘‘Hf,’’ ‘‘% O2d,’’ and

‘‘% H2O,’’ and replace the word ‘‘minimum’’

to read ‘‘maximum’’ in the definition of

‘‘CO2d.’’

* * * * *

(c) Analysis of historical load or operating

level data. (1) For units that produce

electrical or thermal output, the owner or

operator shall identify, for each affected unit

or common stack (except for peaking units),

the ‘‘normal’’ load level or levels (low, mid

or high), based on the operating history of the

unit(s). To identify the normal load level(s),

the owner or operator shall, at a minimum,

determine the relative number of operating

hours at each of the three load levels, low,

mid and high over the past four

representative operating quarters. The owner

or operator shall determine, to the nearest 0.1

percent, the percentage of the time that each

load level (low, mid, high) has been used

during that time period. A summary of the

data used for this determination and the

calculated results shall be kept on-site in a

format suitable for inspection. For new units

or newly-affected units, the data analysis in

this paragraph may be based on fewer than

four quarters of data if fewer than four

representative quarters of historical load data

are available. Or, if no historical load data are

available, the owner or operator may

designate the normal load based on the

expected or projected manner of operating

the unit. However, in either case, once four

quarters of representative data become

available, the historical load analysis shall be

repeated.

(2) If the affected unit does not produce

electrical or steam load, follow the

procedures in paragraph (c)(1) of this section,

except that:

(i) The words ‘‘load level’’ shall read

‘‘operating level;’’ and

(ii) If the unit does not have an installed

flow monitor, the historical data analysis

described in paragraph (c)(1) of this section

is not required.

(d) Determination of normal load. (1)

Based on the analysis of the historical load

data described in paragraph (c) of this

section, the owner or operator shall, for units

that produce electrical or thermal output,

designate the most frequently used load level

as the normal load level for the unit (or

combination of units, for common stacks).

The owner or operator may also designate the

second most frequently used load level as an

additional normal load level for the unit or

stack. For peaking units, normal load

designations are unnecessary; the entire

operating load range shall be considered

normal. If the manner of operation of the unit

changes significantly, such that the

designated normal load(s) or the two most

frequently used load levels change, the

owner or operator shall repeat the historical

load analysis and shall redesignate the

normal load(s) and the two most frequently

used load levels, as appropriate. A minimum

of two representative quarters of historical

load data are required to document that a

change in the manner of unit operation has

occurred. Update the electronic monitoring

plan whenever the normal load level(s) and

the two most frequently-used load levels are

redesignated.

(2) For units that do not produce electrical

or thermal output, follow the procedures in

paragraph (d)(1) of this section, except that:

(i) The words ‘‘load’’ and ‘‘load level’’ shall

read ‘‘operating level;’’ and

(ii) If the unit does not have an installed

flow monitor, the two most frequently-used

operating levels and the normal operating

level(s) shall be determined using sound

engineering judgment, in lieu of performing

a historical data analysis. The operating level

determinations shall be based on knowledge

of the unit, operating experience with the

unit, and actual stack gas velocity

measurements using EPA Method 2 in

appendix A to part 60 of this chapter (or its

allowable alternatives).

(e) 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 or ft/sec (as applicable), in the

electronic quarterly report required under

§ 75.64. * * *

* * * * *

6.5.6 Reference Method Traverse Point

Selection

* * * * *

(b) * * *

(5) If Method 7E is used as the reference

method for the RATA of a NOX CEMS

installed on a combustion turbine, the

reference method measurements may be

made at the sampling points specified in

section 6.1.2 of Method 20 in appendix A to

part 60 of this chapter.

* * * * *

6.5.7 Sampling Strategy

(a) * * * Also, allow sufficient

measurement time to ensure that stable

temperature readings are obtained at each

traverse point, particularly at the first

measurement point at each sample port,

when a probe is moved sequentially from

port-to-port. * * * Alternatively, moisture

measurements for molecular weight

determination may be performed before and

after a series of RATA runs at a particular

load level (low, mid, or high), provided that

the time interval between the two moisture

measurements does not exceed three hours.

If this option is selected, the results of the

two moisture determinations shall be

averaged arithmetically and applied to all

RATA runs in the series. * * *

* * * * *

6.5.10 Reference Methods

* * * Notwithstanding these

requirements, Method 20 may be used as the

reference method for relative accuracy test

audits of NOX monitoring systems installed

on combustion turbines.

Appendix A to Part 75 [Amended]

52. Section 7 of Appendix A to Part

75 is amended by:

a. In section heading 7.3 by revising

the words ‘‘SO2–Diluent Continuous

Emission’’ to read ‘‘O2 Monitors, NOX

Concentration’’;

b. Revising the first sentence of

section 7.3;

c. Revising the variable

" "

i l

n

=

∑

in the list of defined variables for Eq. A–

7 to be

" " di

i

n

=

∑

1

and removing the final sentence of

section 7.3.1;

d. In the section heading and text of

section 7.4 by revising the word ‘‘ NOX’’

to read ‘‘ NOX-diluent’’;

e. In section heading 7.4.2 by

removing the words ‘‘(Monitoring

System)’’;

f. In the second sentence of section

7.6.1 by adding the words ‘‘or NOX’’

after both occurrences of the word

‘‘SO2’’ and the third sentence by

revising the word ‘‘ NOX’’ to read

‘‘NOXdiluent’’;

g. In paragraph (a) of section 7.7 by

removing the fourth sentence;

h. In paragraph (b) of section 7.7 by

removing the first two sentences and

adding four new sentences;

i. In the variable ‘‘(Heat Input)avg’’

under Eq. A–13a in paragraph (c) of

section 7.7 by adding a second and third

sentence to the definition;

j. In paragraph (d) of section 7.7 by

adding the words ‘‘(i.e., the arithmetic

average of the diluent gas

concentrations for all clock hours in

which a RATA run was performed)’’ to

the end of the sentence;

k. In section 7.8 by designating the

existing text as paragraph (a), removing

Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules 32033

the first sentence, adding the words

‘‘and section 2.2.5 of appendix B to this

part’’ to the end of the second sentence,

and adding a new paragraph (b); and

l. Revising Figure 6.

The revisions and additions read as

follows:

7. Calculations

* * * * *

7.3 Relative Accuracy for SO2 and CO2

Pollutant Concentration Monitors, O2

Monitors, NOX Concentration Monitoring

Systems, and Flow Monitors

Analyze the relative accuracy test audit

data from the reference method tests for SO2

and CO2 pollutant concentration monitors,

O2 monitors used only for heat input rate

determination, NOX concentration

monitoring systems, and flow monitors using

the following procedures. * * *

* * * * *

7.7 Reference Flow-to-Load Ratio or

Gross Heat Rate

* * * * *

(b) In Equation A–13, for a common stack,

determine Lavg by summing, for each RATA

run, the operating loads of all units

discharging through the common stack, and

then taking the arithmetic average of the

summed loads. For a unit that discharges its

emissions through multiple stacks, either

determine a single value of Qref for the unit

or a separate value of Qref for each stack. In

the former case, calculate Qref by summing,

for each RATA run, the volumetric flow rates

through the individual stacks and then taking

the arithmetic average of the summed RATA

run flow rates. In the latter case, calculate the

value of Qref for each stack by taking the

arithmetic average, for all RATA runs, of the

flow rates through the stack. * * *

(c) * * *

(Heat Input)avg = * * * For multiple stack

configurations, if the reference GHR value is

determined separately for each stack, use the

hourly heat input measured at each stack. If

the reference GHR is determined at the unit

level, sum the hourly heat inputs measured

at the individual stacks.

* * * * *

7.8 Flow-to-Load Test Exemptions

* * * * *

(b) Units that do not produce electrical

output (in megawatts) or thermal output (in

klb of steam per hour) are exempted from the

flow-to-load ratio test requirements of section

7.7 of this appendix and section 2.2.5 of

appendix B to this part.

* * * * *

* * * * *

53. Section 1 of Appendix B to Part

75 is amended by:

a. Adding a fourth sentence to section

1; and

b. Removing the word ‘‘and’’ before the

words ‘‘section 2.1.5.1’’ in the second

sentence of section 1.3.1.

The revisions and additions read as

follows:

Appendix B to Part 75—Quality Assurance

and Quality Control Procedures

1. Quality Assurance/Quality Control

Program

* * * Electronic storage of the information

in the QA/QC plan is permissible, provided

that the information can be made available in

hardcopy upon request during an audit.

* * * * *

54. Section 2 of Appendix B to Part

75 is amended by:

a. In paragraph (a) of section 2.1.4 by

revising the words ‘‘< 200 ppm’’ in the

first sentence to read ‘‘> 50.0 ppm but

≤ 200 ppm, or exceeds 5.0 ppm for span

values ≤ 50.0 ppm’’;

b. In the first sentence of section 2.2.1

by revising the word ‘‘Perform’’ to read

‘‘Unless a particular monitor (or

monitoring range) is exempted under

this paragraph or under section 6.2 of

appendix A to this part, perform’’;

c. In paragraph (c) of section 2.2.3 by

adding a third sentence;

d. In the second sentence of paragraph

(e) of section 2.2.3 by removing the

words ‘‘or SO2-diluent’’;

e. In the second sentence of paragraph

(f) of section 2.2.3 by revising the words

‘‘168 unit operating hour or stack

operating hour grace period’’ to read

‘‘grace period of 168 cumulative unit or

stack operating hours’’;

f. In paragraph (a) of section 2.2.4 by

revising both occurrences of the word

‘‘consecutive’’ to read ‘‘cumulative’’;

g. In the first sentence of paragraph (b)

of section 2.2.4 by adding the word

‘‘cumulative’’ after the number ‘‘168’’

and the words ‘‘first unit operating’’

before the words ‘‘hour following’’;

h. In paragraph (a) of section 2.2.5 by

removing the first sentence, revising the

words ‘‘by an approved petition in

accordance with’’ in the second

sentence to read ‘‘from the flow-to-load

ratio test under’’, and by adding a final

sentence before Eq. B–1;

i. Revising the third sentence of

paragraph (a)(1) of section 2.2.5;

j. In paragraph (a)(3) of section 2.2.5

by adding the word ‘‘rate’’ after the

words ‘‘heat input’’;

k. In paragraph (a)(4) of section 2.2.5

by adding the word ‘‘acceptable’’ after

each occurrence of the number ‘‘168’’,

and by adding in the third sentence the

words ‘‘(i.e., at loads within ± 10

percent of Lavg)’’ after the word ‘‘rates’’;

l. Revising the last sentence of

paragraph (b) of section 2.2.5;

m. Revising the introductory text of

paragraph (c) of section 2.2.5;

n. Adding a new third sentence in

paragraph (c)(1) of section 2.2.5;

32034 Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules

o. In paragraph (c)(8) of section 2.2.5

by removing the second sentence and

adding two new sentences in its place;

p. In the first sentence of the

introductory paragraph to section

2.2.5.1 by revising the words ‘‘two

weeks’’ to read ‘‘14 unit operating

days’’;

q. Revising paragraph (b) of section

2.2.5.1;

r. Revising section 2.2.5.2;

s. Revising the second and third

sentences of paragraph (a) of section

2.2.5.3;

t. In the second sentence of paragraph

(b) of section 2.2.5.3 by changing the

number ‘‘5.0’’ to ‘‘10.0’’;

u. In paragraph (c) of section 2.2.5.3

by adding the words ‘‘(if applicable)’’

after the words ‘‘flow-to-load test’’ in

the second sentence and after the words

‘‘flow monitor’’ in the third sentence;

v. In the fourth sentence of paragraph

(a) of section 2.3.1.1 by revising the

words ‘‘720 unit (or stack) operating

hour grace period’’ to read ‘‘grace period

of 720 cumulative unit or stack

operating hours’’;

w. Removing and reserving paragraph

(b) of section 2.3.1.2;

x. Removing the words ‘‘On and after

January 1, 2000,’’ and capitalizing the

letter ‘‘t’’ in the first instance of ‘‘the’’

in paragraph (c) of section 2.3.1.2;

y. In paragraph (d) of section 2.3.1.2

by adding the words ‘‘, as measured by

the reference method during the RATA’’

after the words ‘‘≤10.0 fps’’ and by

removing the words ‘‘(10.0 percent if

prior to January 1, 2000)’’;

z. In paragraph (e) of section 2.3.1.2

by adding the words ‘‘reference

method’’ before the word

‘‘concentrations’’, and by adding the

words ‘‘) during the RATA’’ after the

words ‘‘250 ppm’’;

aa. In paragraph (f) of section 2.3.1.2

by adding the words ‘‘measured by the

reference method during the RATA’’

after the words ‘‘average NOX emission

rate’’;

bb. Removing and reserving paragraph

(g) of section 2.3.1.2;

cc. In section heading 2.3.1.3 by

adding the words ‘‘(or Operating)’’ after

the words ‘‘RATA Load’’;

dd. In paragraph (a) of section 2.3.1.3

by adding the words ‘‘(or operating

level)’’ after each instance of the words

‘‘load level’’, adding the words ‘‘(or

operating levels)’’ after the words ‘‘load

levels’’, and by revising the words

‘‘section 6.5.2.1’’ to read ‘‘section

6.5.2.1(d)’’;

ee. In paragraph (b) of section 2.3.1.3

by revising the words ‘‘section 6.5.2.1’’

to read ‘‘section 6.5.2.1(d)’’;

ff. Revising paragraphs (c)(1) through

(c)(6) of section 2.3.1.3;

gg. In paragraph (c) of section 2.3.2 by

adding a new third sentence;

hh. In paragraphs (d) and (f) of section

2.3.2 by adding the words ‘‘(or operating

level)’’ after each occurrence of the

words ‘‘load level’’, the words ‘‘(or

single-level)’’ after the word ‘‘singleload’’, the words ‘‘(or multiple-level)’’

after the word ‘‘multiple-load’’, the

words ‘‘(or operating level(s))’’ after the

words ‘‘load level(s)’’, and the words

‘‘(or 3-level)’’ after the words ‘‘3-load’’;

ii. Revising paragraph (e) of section

2.3.2;

jj. In paragraph (a) of section 2.3.3 by

revising the first two instances of the

word ‘‘consecutive’’ to read

‘‘cumulative’’, removing the word ‘‘or’’

after the first two semicolons, and by

removing the words ‘‘consecutive

calendar’’ after the word ‘‘five’’;

kk. In the first sentence of paragraph

(c) of section 2.3.3 by adding the word

‘‘cumulative’’ after the number ‘‘720’’;

ll. Revising paragraph (b) of section

2.4;

mm. Revising footnote 2 of Figure 1

to Appendix B of Part 75; and

nn. In Figure 2 to Appendix B of Part

75 by removing the row for ‘‘Flow

(Phase I)’’, renaming the row for ‘‘Flow

(Phase II)’’ as ‘‘Flow’’, by revising the

word ‘‘H2O2’’ in the final row to read

‘‘H2O2’’, and by adding the word

‘‘cumulative’’ after both occurrences of

the number ‘‘168’’ in footnote 1 to

Figure 2.

The revisions and additions read as

follows:

2. Frequency of Testing

* * * * *

2.2 Quarterly Assessments

* * * * *

2.2.3 Data Validation

* * * * *

(c) * * * If a routine daily calibration error

test is performed and passed just prior to a

linearity test (or during a linearity test

period) and a mathematical correction factor

is automatically applied by the DAHS, the

correction factor shall be applied to all

subsequent data recorded by the monitor,

including the linearity test data.

* * * * *

2.2.5 Flow-to-Load Ratio or Gross Heat Rate

Evaluation

(a) Applicability and methodology. ***

Alternatively, for the reasons stated in

paragraphs (c)(1) through (c)(6) of this

section, the owner or operator may exclude

from the data analysis certain hours within

± 10.0 percent of Lavg and may calculate Rh

values for only the remaining hours. * * *

(1) * * * For a unit that discharges its

emissions through multiple stacks or that

monitors its emissions in multiple

breechings, Qh will be either the combined

hourly volumetric flow rate for all of the

stacks or ducts (if the test is done on a unit

basis) or the hourly flow rate through each

stack individually (if the test is performed

separately for each stack). * * *

* * * * *

(b) * * * If Ef is above these limits, the

owner or operator shall either: implement

Option 1 in section 2.2.5.1 of this appendix;

perform a RATA in accordance with Option

2 in section 2.2.5.2 of this appendix; or (if

applicable) re-examine the hourly data used

for the flow-to-load or GHR analysis and

recalculate Ef, after excluding all nonrepresentative hourly flow rates, as provided

in paragraph (c) of this section.

(c) Recalculation of Ef. If the owner or

operator did not exclude any hours within

±10 percent of Lavg from the original data

analysis and chooses to recalculate Ef, the

flow rates for the following hours are

considered non-representative and may be

excluded from the data analysis:

(1) * * * Also, for units that co-fire

different types of fuels, if the reference RATA

was done while co-firing, then hours in

which a single fuel was combusted may be

excluded from the data analysis as different

fuel hours (and vice-versa for co-fired hours,

if the reference RATA was done while

combusting only one type of fuel);

* * * * *

(8) * * * If, however, Ef is still above the

applicable limit, data from the monitor shall

be declared out-of-control, beginning with

the first unit operating hour following the

quarter in which Ef exceeded the applicable

limit. Alternatively, if a probationary

calibration error test is performed and passed

according to § 75.20(b)(3)(ii), data from the

monitor may be declared conditionally valid

following the quarter in which Ef exceeded

the applicable limit. * * *

2.2.5.1 Option 1

* * * * *

(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 or K factor(s)), data from the

monitor are considered invalid back to the

first unit operating hour after the end of the

calendar quarter for which Ef was above the

applicable limit. If the option to use

conditional data validation was selected

under section 2.2.5(c)(8) of this appendix, all

conditionally valid data shall be invalidated,

back to the first unit operating hour after the

end of the calendar quarter for which Ef was

above the applicable limit. Corrective actions

shall be taken. All corrective actions (e.g.,

non-routine maintenance, repairs, major

component replacements, re-linearization of

the monitor, etc.) shall be documented in the

operation and maintenance records for the

monitor. The owner or operator then shall

either complete the abbreviated flow-to-load

test in section 2.2.5.3 of this appendix, or, if

the corrective action taken has required

relinearization of the flow monitor, shall

perform a 3-load RATA. The conditional data

validation procedures in § 75.20(b)(3) may be

applied to the 3-load RATA.

2.2.5.2 Option 2

Perform a single-load RATA (at a load

designated as normal under section 6.5.2.1 of

Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules 32035

appendix A to this part) of each flow monitor

for which Ef is outside of the applicable limit.

If the RATA is passed hands-off, in

accordance with section 2.3.2(c) of this

appendix, no further action is required and

the out-of-control period for the monitor ends

at the date and hour of completion of a

successful RATA, unless the option to use

conditional data validation was selected

under section 2.2.5(c)(8) of this appendix. In

that case, all conditionally valid data from

the monitor are considered to be qualityassured, back to the first unit operating hour

following the end of the calendar quarter for

which the Ef value was above the applicable

limit. If the RATA is failed, all data from the

monitor shall be invalidated, back to the first

unit operating hour following the end of the

calendar quarter for which the Ef value was

above the applicable limit. Data from the

monitor remain invalid until the required

RATA has been passed. Alternatively,

following a failed RATA and corrective

actions, the conditional data validation

procedures of § 75.20(b)(3) may be used until

the RATA has been passed. If the corrective

actions taken following the failed RATA

included adjustment of the polynomial

coefficients or K-factor(s) of the flow monitor,

a 3-level RATA is required.

2.2.5.3 Abbreviated Flow-to-Load Test

(a) * * * Data from the monitoring system

are considered invalid from the hour of

commencement of the repair, replacement, or

maintenance until either the hour in which

the abbreviated flow-to-load test is passed, or

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. If

the latter option is selected, the abbreviated

flow-to-load test shall be completed within

168 cumulative unit operating hours of the

probationary calibration error test (or, for

peaking units, within 30 unit operating days,

if that is less restrictive). * * *

* * * * *

2.3 Semiannual and Annual Assessments

* * * * *

2.3.1 Relative Accuracy Test Audit (RATA)

* * * * *

2.3.1.3 RATA Load (or Operating) Levels

and Additional RATA Requirements

* * * * *

(c) * * *

(1) An annual 2-load (or 2-level) flow

RATA shall be done at the two most

frequently used load levels (or operating

levels), as determined under section

6.5.2.1(d) of appendix A to this part.

Alternatively, a 3-load (or 3-level) flow

RATA at the low, mid, and high load levels

(or operating levels), as defined under section

6.5.2.1(b) of appendix A to this part, may be

performed in lieu of the 2-load (or 2-level)

annual RATA.

(2) If the flow monitor is on a semiannual

RATA frequency, 2-load (or 2-level) flow

RATAs and single-load (or single-level) flow

RATAs at the normal load level (or normal

operating level) may be performed

alternately.

(3) A single-load (or single-level) annual

flow RATA may be performed in lieu of the

2-load (or 2-level) RATA if the results of an

historical load data analysis show that in the

time period extending from the ending date

of the last annual flow RATA to a date that

is no more than 21 days prior to the date of

the current annual flow RATA, the unit (or

combination of units, for a common stack)

has operated at a single load level (or

operating level) (low, mid, or high), for ≥85.0

percent of the time. Alternatively, a flow

monitor may qualify for a single-load (or

single-level) RATA if the 85.0 percent

criterion is met in the time period extending

from the beginning of the quarter in which

the last annual flow RATA was performed

through the end of the calendar quarter

preceding the quarter of current annual flow

RATA.

(4) A 3-load (or 3-level) RATA, at the

low-, mid-, and high-load levels (or operating

levels), as determined under section 6.5.2.1

of appendix A to this part, shall be performed

at least once every five consecutive calendar

years.

(5) A 3-load (or 3-level) RATA is required

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

when its polynomial coefficients or K

factor(s) are changed, except for flow

monitors installed on peaking units and

bypass stacks. For peaking units and bypass

stacks, a single-load RATA at the normal load

is required.

(6) For all multi-level flow audits, the audit

points at adjacent load levels or at adjacent

operating 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.

* * * * *

2.3.2 Data Validation

* * * * *

(c) * * * If a routine daily calibration error

test is performed and passed just prior to a

RATA (or during a RATA test period) and a

mathematical correction factor is

automatically applied by the DAHS, the

correction factor shall be applied to all

subsequent data recorded by the monitor,

including the RATA test data. * * *

* * * * *

(e) For a RATA performed using the option

in paragraph (b)(1) or (b)(2) of this section,

if the RATA is failed (that is, if the relative

accuracy exceeds the applicable 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 the

CEMS is out-of-control and 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. If the option in paragraph (b)(3) of

this section to use the data validation

procedures and associated timelines in

§§ 75.20(b)(3)(ii) through(b)(3)(ix) has been

selected, the beginning and end of the outof-control period shall be determined in

accordance with § 75.20(b)(3)(vii)(A) and (B).

Note that when a RATA is aborted for a

reason other than monitoring system

malfunction (see paragraph (h) of this

section), this does not trigger an out-ofcontrol period for the monitoring system.

* * * * *

2.4 Recertification, Quality Assurance,

RATA Frequency and Bias Adjustment

Factors (Special Considerations)

* * * * *

(b) Except as provided in section 2.3.3 of

this appendix, whenever a passing RATA of

a gas monitor is performed, or a passing 2-

load (or 2-level) RATA or a passing 3-load (or

3-level) 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 RATA frequency

(semi-annual or annual) shall be established

based upon the date and time of completion

of the RATA and the relative accuracy

percentage obtained. For 2-load (or 2-level)

and 3-load (or 3-level) flow RATAs, use the

highest percentage relative accuracy at any of

the loads (or levels) to determine the RATA

frequency. The results of a single-load (or

single-level) flow RATA may be used to

establish the RATA frequency when 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 when the

single-load (or single-level) RATA is allowed

under section 2.3.1.3(c) of this appendix for

a unit that has operated at one load level (or

operating level) for ≥ 85.0 percent of the time

since the last annual flow RATA. No other

single-load (or single-level) flow RATA may

be used to establish an annual RATA

frequency; however, a 2-load or 3-load (or a

2-level or 3-level) flow RATA may be

performed at any time or in place of any

required single-load (or single-level) RATA,

in order to establish an annual RATA

frequency.

* * * * *

Figure 1 to Appendix B of Part 75—Quality

Assurance Test Requirements

* * * * * 2 For flow monitors installed on peaking

units and bypass stacks, conduct all RATAs

at a single, normal load. For other flow

monitors, conduct annual RATAs at two load

levels (or operating levels). Alternating

single-level and 2-level RATAs may be done

if a monitor is on a semiannual frequency. A

single-level RATA may be done in lieu of a

2-level RATA if, since the last annual flow

RATA, the unit has operated at one load level

(or operating level) for ≥ 85.0 percent of the

time. A 3-level RATA is required at least

once every five calendar years and whenever

a flow monitor is re-linearized.

* * * * *

55. Appendix C to Part 75 is amended

by:

a. Revising the section heading of

section 2;

b. Revising the fifth sentence in

section 2.2.1 and adding a new sentence

after that fifth sentence;

c. Revising in section 2.2.3.9 the

reference ‘‘75.51(a)(2)’’ to read

‘‘75.71(a)(2)’’; and

32036 Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules

d. Adding new sections 3 and 4.

The revisions and additions read as

follows:

Appendix C to Part 75—Missing Data

Estimation Procedures

* * * * *

2. Load-Based Procedure for Missing Flow

Rate, NOX Concentration, and NOX Emission

Rate Data

* * * * *

2.2 Procedure

2.2.1 * * * 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, determine

the maximum hourly average gross load for

the unit by converting the maximum rated

hourly unit heat input (including heat input

from auxiliary firing, if applicable) to an

equivalent gross megawatt value, using the

percentage efficiencies of the main

combustion source and (if applicable) any

auxiliary combustion sources. If the actual

percentage efficiency of a particular

combustion source is unknown, use a default

value of 50 percent for a combustion turbine

and 33 percent for any other type of

combustion source. * * *

* * * * *

3. Non-Load-Based Procedure for Missing

Flow Rate, NOX Concentration, and NOX

Emission Rate Data (Optional)

3.1 Applicability

For affected units that do not produce

electrical output in megawatts or thermal

output in klb/hr of steam, this procedure may

be used in accordance with the provisions of

this part to provide substitute data for

volumetric flow rate (scfh), NOX emission

rate (in lb/mmBtu) from NOX-diluent

continuous emission monitoring systems,

and NOX concentration data (in ppm) from

NOX concentration monitoring systems used

to determine NOX mass emissions.

3.2 Procedure

3.2.1 For each monitored parameter (flow

rate, NOX emission rate, or NOX

concentration), establish at least two, but no

more than ten operational bins,

corresponding to various operating

conditions and parameters (or combinations

of these) that affect volumetric flow rate or

NOX emissions. Include a complete

description of each operational bin in the

hardcopy portion of the monitoring plan

required under § 75.53(e)(2), identifying the

unique combination of parameters and

operating conditions associated with the bin

and explaining the relationship between

these parameters and conditions and the

magnitude of the stack gas flow rate or NOX

emissions. Assign a unique number, 1

through 10, to each operational bin.

Examples of conditions and parameters that

may be used to define operational bins

include unit heat input, type of fuel

combusted, specific stages of an industrial

process, or (for common stacks), the

particular combination of units that are in

operation.

3.2.2 In the electronic quarterly report

required under § 75.64, indicate for each

hour of unit operation the operational bin

associated with the NOX or flow rate data, by

recording the number assigned to the bin

under section 3.2.1 of this appendix.

3.2.3 The data acquisition and handling

system must be capable of properly

identifying and recording the operational bin

number for each unit operating hour. The

DAHS must also be capable of calculating

and recording the following information for

each unit operating hour of missing flow or

NOX data within each identified operational

bin during the shorter of: (a) the previous

2,160 quality assured monitor operating

hours (on a rolling basis), or (b) all previous

quality assured monitor operating hours:

3.2.3.1 Average of the hourly flow rates

reported by a flow monitor (scfh).

3.2.3.2 The 90th percentile value of

hourly flow rates (scfh).

3.2.3.3 The 95th percentile value of

hourly flow rates (scfh).

3.2.3.4 The maximum value of hourly

flow rates (scfh).

3.2.3.5 Average of the hourly NOX

emission rate, in lb/mmBtu, reported by a

NOX-diluent continuous emission monitoring

system.

3.2.3.6 The 90th percentile value of

hourly NOX emission rates (lb/mmBtu).

3.2.3.7 The 95th percentile value of

hourly NOX emission rates (lb/mmBtu).

3.2.3.8 The maximum value of hourly

NOX emission rates, in (lb/mmBtu).

3.2.3.9 Average of the hourly NOX

pollutant concentrations (ppm), reported by

a NOX concentration monitoring system used

to determine NOX mass emissions, as defined

in § 75.51(a)(2).

3.2.3.10 The 90th percentile value of

hourly NOX pollutant concentration (ppm).

3.2.3.11 The 95th percentile value of

hourly NOX pollutant concentration (ppm).

3.2.3.12 The maximum value of hourly

NOX pollutant concentration (ppm).

3.2.4 When a bias adjustment is necessary

for the flow monitor and/or the NOX-diluent

continuous emission monitoring system

(and/or the NOX concentration monitoring

system), apply the bias adjustment factor to

all data values placed in the operational bins.

3.2.5 Calculate all CEMS data averages,

maximum values, and percentile values

determined by this procedure using biasadjusted values.

3.2.6 Use the calculated monitor or

monitoring system data averages, maximum

values, and percentile values to substitute for

missing flow rate and NOX emission rate data

(and where applicable, NOX concentration

data) according to the procedures in subpart

D of this part.

4. Non-Load-Based Procedure for Missing

Fuel Flowmeter Data (Optional)

4.1 Applicability

For affected units that do not produce

electrical output in megawatts or thermal

output in klb/hr of steam, this procedure may

be used in accordance with the provisions of

this part to provide substitute data for fuel

flow rate.

4.2 Procedure

4.2.1 Establish at least two, but no more

than ten operational bins, corresponding to

various operating conditions and parameters

(or combinations of these) related to the fuel

flow rate. Include a complete description of

each operational bin in the hardcopy portion

of the monitoring plan required under

§ 75.53(f)(1)(ii), identifying the parameters

and operating conditions associated with the

bin and explaining the relationship between

these parameters and conditions and the

magnitude of the fuel flow rate. Assign a

unique number, 1 through 10, to each

operational bin.

4.2.2 In the electronic quarterly report

required under § 75.64, indicate for each

hour of unit operation the operational bin

associated with the fuel flow rate data, by

recording the number assigned to the bin

under section 4.2.1 of this appendix.

4.2.3 The data acquisition and handling

system (DAHS) must be capable of properly

identifying and recording the operational bin

number for each unit operating hour. The

DAHS must also be capable of calculating

and recording the following information for

each unit operating hour of missing fuel flow

rate data within each identified operational

bin during the previous 720 operating hours

(on a rolling basis):

4.2.3.1 Arithmetic average of the hourly

fuel flow rates reported by a certified fuel

flowmeter system, in appropriate units of

fuel flow rate.

4.2.3.2 The maximum value of hourly

fuel flow rates reported by a certified fuel

flowmeter system, in appropriate units of

fuel flow rate.

4.2.4 The DAHS shall also be capable of

separating the recorded fuel flow rate data on

the basis of the type of fuel combusted in the

unit. A separate database shall be created and

maintained for each type of fuel when it is

combusted alone in the unit. If different

types of fuel are co-fired in the unit, an

additional database shall be created and

maintained for each type of fuel, for hours in

which it is co-fired with any other type(s) of

fuel(s).

4.3 Use the calculated average and

maximum values to substitute for missing

fuel flow rate data according to the

applicable procedures in sections 2.4.2 and

2.4.3 in appendix D to this part.

Appendix D Section 1 [Amended].

56. Section 1 of Appendix D to Part

75 is amended by removing the final

sentence of section 1.2.

57. Section 2 of Appendix D to Part

75 is amended by:

a. Revising sections 2.1.2, 2.1.2.1, and

2.1.2.2;

b. Revising the first sentence of

section 2.1.4.1;

c. Revising section 2.1.4.3;

d. In section 2.1.5 by revising the

words ‘‘calibrated fuel flow rate’’ to read

‘‘fuel flow rate measurable by the

flowmeter’’ in the first sentence, by

adding the words ‘‘(orifice, nozzle, and

venturi-type flowmeters, only)’’ after the

words ‘‘by design’’ in the second

Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules 32037

sentence, and by revising the words

‘‘measurement against a NIST-traceable

reference method’’ in the third sentence

to read ‘‘in-line comparison against a

reference flowmeter’’;

e. In section 2.1.5.4 by revising the

words ‘‘using the following’’ to read ‘‘in

a manner consistent with’’;

f. In paragraph (c) of section 2.1.6 by

removing the words ‘‘2.1.5.1 or’’;

g. In paragraph (d) of section 2.1.6 by

removing the words ‘‘, where

applicable,’’ before the words ‘‘those

procedures’’ and ‘‘, where applicable’’

after the second occurrence of the words

‘‘element inspection’’, and by adding

‘‘(if applicable)’’ after both occurrences

of the words ‘‘test or’’;

h. Adding new paragraphs (e) and (f)

to section 2.1.6;

i. In the second sentence of paragraph

(a) of section 2.1.6.1 by adding the word

‘‘upscale’’ after the word ‘‘other’’ and by

adding a new third sentence;

j. In section heading 2.1.6.2 by

revising the words ‘‘and Reporting of’’

to read ‘‘for’’;

k. In paragraph (a) of section 2.1.6.2

by removing the second and third

sentences;

l. Removing and reserving sections

2.1.6.2(b) and 2.1.6.2(c);

m. In the final sentence of section

2.1.6.3 by removing the words ‘‘§ 75.56

or’’ and ‘‘, as applicable’’;

n. In the fourth sentence of paragraph

(a) of section 2.1.6.4 by revising the

words ‘‘indicates that’’ to read ‘‘is failed

(if’’ and by adding a closing parenthesis

after the word ‘‘corroded’’;

o. In paragraph (a)(1) of section 2.1.6.4

by adding a new second sentence;

p. In paragraphs (a)(2) and (b)(2) of

section 2.1.6.4 by revising the word

‘‘under’’ to read ‘‘, using’’;

q. In paragraph (b) of section 2.1.6.4

by removing the first sentence;

r. In paragraph (b)(1) of section 2.1.6.4

by adding the words ‘‘and, if applicable,

the transmitters have been successfully

recalibrated’’ to the end of the final

sentence;

s. In paragraph (c) of section 2.1.6.4

by revising the words ‘‘this period’’ to

read ‘‘each period of invalid fuel

flowmeter data described in paragraph

(b) of this section’’;

t. In section 2.1.7 by removing each

occurrence of the words ‘‘where

applicable,’’ and ‘‘as applicable,’’, by

removing the words ‘‘§ 75.54(a) or’’, and

by adding the words ‘‘(if applicable) a’’

and ‘‘(if applicable)’’ after the two

occurrences of ‘‘test or’’, respectively;

u. In paragraph (a) of section 2.1.7.1

by revising the first occurrence of ‘‘i.e.’’

to read ‘‘e.g.’’, by revising the sixth

sentence, and by adding the word

‘‘Arithmetic’’ before the word ‘‘average’’

in the definitions of the variables

‘‘Qbase’’ and ‘‘Lavg’’ under Eq. D–1b;

v. Revising paragraph (b) of section

2.1.7.1;

w. In paragraph (c) of section 2.1.7.1

by adding the words ‘‘average fuel flow

rate and the fuel GCV in the’’ before the

word ‘‘applicable’’ in the definition of

the variable ‘‘(Heat Input)avg’’ under Eq.

D–1c;

x. In paragraph (a) of section 2.1.7.2

by adding a new third sentence;

y. Revising paragraph (b) of section

2.1.7.2;

z. In the variable for ‘‘(Heat Input)h’’

under Eq. D–1e in paragraph (c) of

section 2.1.7.2 by adding the words

‘‘hourly fuel flow rate and the fuel GCV

in the’’ after the words ‘‘using the’’;

aa. In paragraph (d) of section 2.1.7.2

by revising the third sentence and by

adding a new fourth sentence;

bb. Revising the first sentence of

paragraph (a) of section 2.1.7.3;

cc. Adding a second sentence to

paragraph (b) of section 2.1.7.3;

dd. In the first sentence of paragraph

(a) of section 2.1.7.4 by revising the

reference to ‘‘section 2.1.7.2’’ to read

‘‘section 2.1.7.2(h)’’;

ee. In the final sentence of paragraph

(b) of section 2.1.7.4 by adding the word

‘‘fuel’’ after the word ‘‘two’’ and by

adding the words ‘‘(as defined in § 72.2

of this chapter)’’ after the word

‘‘quarters’’;

ff. Revising Table D–4 in section 2.2;

gg. In section 2.2.4.2 introductory text

by adding the words ‘‘and GCV value’’

after the words ‘‘Use the sulfur content’’

in the fourth sentence, and by revising

the reference to ‘‘section 2.2.4.3’’ to read

‘‘section 2.2.4.3(c)’’;

hh. Revising paragraph (b) of section

2.2.4.2;

ii. In the second sentence of

paragraph (c) of section 2.2.4.3 by

revising the first and second

occurrences of the words ‘‘two

following values’’ with, respectively, the

words ‘‘following conservative, assumed

values’’ and ‘‘assumed values’’;

jj. Revising paragraph (d) of section

2.2.4.3;

kk. Revising Table D–5 in section

2.3(b);

ll. Revising all of section 2.3.1.4

except for the section heading and

paragraph (a)(1);

mm. In section 2.3.2.1.1 by adding a

new second sentence and by revising

Equation D–1h and the definitions of

variables for Equation D–1h;

nn. Revising sections 2.3.2.1.2 and

2.3.2.4;

oo. In section 2.3.3.2 by revising the

third sentence and adding a new fourth

sentence;

pp. In section 2.3.4.3 by adding a new

second sentence;

qq. Revising the fourth sentence of

section 2.3.4.3.1;

rr. Revising section 2.3.4.3.2 and

paragraph (a) of section 2.3.5;

ss. In paragraph (a) of section 2.3.6 by

revising the first, second, fourth, and

fifth sentences and by adding a new

sentence after the second sentence;

tt. In the first sentence of paragraph

(b) of section 2.3.6 by removing the

words ‘‘(and hydrogen sulfide content,

if applicable)’’;

uu. In the first sentence of section

2.4.1 by removing the reference

‘‘2.3.3.1.2,’’;

vv. Revising Table D–6 in section

2.4.1 and sections 2.4.2, 2.4.2.1(b) and

heading, 2.4.2.2, and 2.4.2.3; and

ww. In section 2.4.3 by adding a new

sentence to the end of that section.

The revisions and additions read as

follows:

2. Procedure

2.1 Fuel Flowmeter Measurements

* * * * *

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

(as defined in § 72.2 of this chapter).

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

shall not apply 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, unless both of

the following are true: all of the units served

by the common pipe are affected units, and

all of the units have similar efficiencies. For

the purposes of this section, units served by

a common pipe have similar efficiencies (e.g.,

if all of the units are boilers or if all of the

units are combustion turbines). When a fuel

flowmeter is installed in a common pipe

header, proceed as follows:

2.1.2.1 Measure the fuel flow rate in the

common pipe, and combine SO2 mass

emissions (Acid Rain Program units only) for

the affected units for recordkeeping and

compliance purposes; and

2.1.2.2 Apportion the heat input rate

measured at the common pipe to the

individual units, using Equation F–21a, F–

21b, or F–21d in appendix F to this part.

* * * * *

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, a gas-fired unit

that uses oil solely for start-up or burner

ignition, or an oil-fired unit that uses a

different grade of oil solely for start-up or

burner ignition, a fuel flowmeter for the startup fuel is permitted but not required.***

* * * * *

2.1.4.3 Emergency Fuel

The designated representative of a unit that

is restricted by a federally-enforceable permit

32038 Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules

to combusting a particular fuel only during

emergencies where the primary fuel is not

available is exempt from certifying a fuel

flowmeter for use during combustion of the

emergency fuel. During any hour in which

the emergency fuel is combusted, report the

hourly heat input to be the maximum rated

heat input of the unit for the fuel. Use the

maximum potential sulfur content for the

fuel (from Table D–6 of this appendix) and

the fuel flow rate corresponding to the

maximum hourly heat input to calculate the

hourly SO2 mass emission rate, using

Equations D–2 through D–4 of this appendix

(as applicable). Alternatively, if a certified

fuel flowmeter is available for the emergency

fuel, you may use the measured hourly fuel

flow rates in the calculations. Also, if daily

samples or weekly composite samples (fuel

oil, only) of the fuel’s total sulfur content,

GCV, and (if applicable) density are taken

during the combustion of the emergency fuel,

as described in section 2.2 or 2.3 of this

appendix, the sample results may be used to

calculate the hourly SO2 emissions and heat

input rates, in lieu of using maximum

potential values. The designated

representative shall also provide notice

under § 75.61(a)(6) for each period when the

emergency fuel is combusted.

* * * * *

2.1.6 Quality Assurance

* * * * *

(e) When accuracy testing of the orifice,

nozzle, or venturi meter is performed

according to section 2.1.5.2 of this appendix,

record the information displayed in Table D–

1 in this section. At a minimum, record the

overall accuracy results for the fuel

flowmeter at the three flow rate levels

specified in section 2.1.5.2 of this appendix.

(f) Report the results of all fuel flowmeter

accuracy tests, transmitter or transducer

accuracy tests, and primary element

inspections, as applicable, in the emissions

report for the quarter in which the quality

assurance tests are performed, using the

electronic format specified by the

Administrator under § 75.64.

2.1.6.1 Transmitter or Transducer Accuracy

Test for Orifice-, Nozzle-, and Venturi-Type

Flowmeters

(a) * * * For temperature transmitters, the

zero and upscale levels may correspond to

fixed reference points, such as the freezing

point or boiling point of water.

* * * * *

2.1.6.4 Primary Element Inspection

(a) * * *

(1) * * * If the primary element size is

changed, also calibrate the transmitters or

transducers, consistent with the new primary

element size;

* * * * *

2.1.7 Fuel Flow-to-Load Quality Assurance

Testing for Certified Fuel Flowmeters

* * * * *

2.1.7.1 Baseline Flow Rate-to-Load Ratio or

Heat Input-to-Load Ratio

(a) * * * For orifice-, nozzle-, and venturitype fuel flowmeters, if the fuel flow-to-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 2.1.6.4 of

this appendix, then the baseline data must be

obtained after both procedures are completed

and no later than the end of the fourth

calendar quarter following the calendar

quarter in which both procedures were

completed.***

* * * * *

(b) In Equation D–1b, for a fuel flowmeter

installed on a common pipe header, Lavg is

the sum of the operating loads of all units

that received fuel through the common pipe

header during the baseline period, divided by

the total number of hours of fuel flow rate

data collected during the baseline period. For

a unit that receives the same type of fuel

through multiple pipes, Qbase is the sum of

the fuel flow rates during the baseline period

from all of the pipes, divided by the total

number of hours of fuel flow rate data

collected during the baseline period. Round

off the value of Rbase to the nearest tenth.

* * * * *

2.1.7.2 Data Preparation and Analysis

(a) * * * Alternatively, the owner or

operator may exclude non-representative

hours from the data analysis, as described in

section 2.1.7.3 of this appendix, prior to

calculating the values of Rh.

* * * * *

(b) For a fuel flowmeter installed on 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 the same type

of fuel through multiple pipes, Qh will be the

sum of the fuel flow rates from all of the

pipes. Round off each value of Rh to the

nearest tenth.

* * * * *

(d) * * * If, for a particular fuel flowmeter,

fewer than 168 hourly flow-to-load ratios (or

GHR values) are available, or, if the baseline

data collection period is still in progress at

the end of the quarter and fewer than four

calendar quarters have elapsed since the

quarter in which the last successful fuel

flowmeter accuracy test was performed, a

flow-to-load (or GHR) evaluation is not

required for that flowmeter for that calendar

quarter. A one-quarter extension of the

deadline for the next fuel flowmeter accuracy

test may be claimed for a quarter in which

there is insufficient hourly data available to

analyze or a quarter that ends with the

baseline data collection period still in

progress.

* * * * *

2.1.7.3 Optional Data Exclusions

(a) If Ef is outside the limits in section

2.1.7.2(h) 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 may identify and

exclude fuel flow-to-load ratios or GHR

values for any non-representative hours,

provided that such data exclusions were not

previously made under section 2.1.7.2(a) of

this appendix.***

(b) * * * If fewer than 168 hourly fuel

flow-to-load ratio or GHR values remain after

the allowable data exclusions, a fuel flow-toload ratio or GHR analysis is not required for

that quarter, and a one-quarter extension of

the fuel flowmeter accuracy test deadline

may be claimed.

* * * * *

2.2 Oil Sampling and Analysis

* * * * *

TABLE D–4.—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 .................................................... 1. Highest sulfur content from previous 30 daily samples; or

2. Actual daily value.

Flow proportional/weekly composite ............................... Actual measured value.

In storage tank (after addition of fuel to tank) ................ 1. Actual measured value; or

2. Highest of all sampled values in previous calendar

year, unless a higher sample value is obtained; 1 or

3. Maximum value allowed by contract, unless a higher

sample value is obtained.1

As delivered (in delivery truck or barge).1 1. Highest of all sampled values in previous calendar

year, unless a higher sample value is obtained; 1 or

2. Maximum value allowed by contract, unless a higher

sample value is obtained.1

Oil Density ............................ Daily manual sampling .................................................... 1. Use the highest density from the previous 30 daily

samples; or

2. Actual measured value.

Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules 32039

TABLE D–4.—OIL SAMPLING METHODS AND SULFUR, DENSITY AND GROSS CALORIFIC VALUE USED IN CALCULATIONS—

Continued

Parameter Sampling technique/frequency Value used in calculations

Flow proportional/weekly composite ............................... Actual measured value.

In storage tank (after addition of fuel to tank) ................ 1. Actual measured value; or

2. Highest of all sampled values in previous calendar

year, unless a higher sample value is obtained; 1 or

3. Maximum value allowed by contract, unless a higher

sample value is obtained.1

As delivered (in delivery truck or barge).1 1. Highest of all sampled values in previous calendar

year, unless a higher sample value is obtained; 1 or

2. Maximum value allowed by contract, unless a higher

sample value is obtained.1

Oil GCV ................................ Daily manual sampling .................................................... 1. Highest fuel GCV from the previous 30 daily samples; or

2. Actual measured value.

Flow proportional/weekly composite ............................... Actual measured value.

In storage tank (after addition of fuel to tank) ................ 1. Actual measured value; or

2. Highest of all sampled values in previous calendar

year, unless a higher sample value is obtained; 1 or

3. Maximum value allowed by contract, unless a higher

sample value is obtained.1

As delivered (in delivery truck or barge).1 1. Highest of all sampled values in previous calendar

year, unless a higher sample value is obtained; 1 or

2. Maximum value allowed by contract, unless a higher

sample value is obtained.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. If a higher sample value is obtained, use the results of that sample analysis as the new assumed

value.

* * * * *

2.2.4 Manual Sampling

* * * * *

2.2.4.2 Sampling from a Unit’s Storage Tank

* * * * *

(b) One of the conservative assumed values

described in section 2.2.4.3(c) of this

appendix. Follow the applicable provisions

in section 2.2.4.3(d) of this appendix,

regarding the use of assumed values.

2.2.4.3 Sampling from Each Delivery

* * * * *

(d) Continue using the assumed value(s), so

long as the sample results do not exceed the

assumed value(s). However, 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,

beginning on the date of receipt of the results

of the sample analysis, 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.

Consider the sampled value to be the new

assumed sulfur content, gross calorific value,

or density. Continue using this new assumed

value to calculate SO2 mass emission rate or

heat input rate unless and until: it is

superseded by a higher value from an oil

sample; or (if applicable) it is superseded by

a new contract in which case the new

contract value becomes the assumed value at

the time the fuel specified under the new

contract begins to be combusted in the unit;

or (if applicable) both the calendar year in

which the sampled value exceeded the

assumed value and the subsequent calendar

year have elapsed.

2.3 SO2 Emissions from Combustion of

Gaseous Fuels

* * * * *

TABLE D–5.—GAS SULFUR AND GCV VALUES USED IN CALCULATIONS FOR VARIOUS FUEL TYPES

Parameter Fuel type and sampling frequency Value used in calculations (except for missing data

hours)

Gas Sulfur Content .............. Pipeline Natural Gas with total sulfur content less than

or equal to 0.5 grains/100scf (when using the provisions of section 2.3.1 to determine SO2 mass emissions)—Sample semiannually and whenever fuel

composition changes significantly.

0.0006 lb/mmBtu.

Natural Gas with total sulfur content less than or equal

to 20.0 grains/100scf (when using the provisions of

section 2.3.2 to determine SO2 mass emissions)—

Sample semiannually and whenever fuel composition

changes significantly.

Default SO2 emission rate calculated from Eq. D–1h,

using either:

1. The fuel contract maximum total sulfur content, unless a higher value is obtained in a semiannual sample;1

2. The maximum total sulfur content from the previous

year’s samples, unless a higher value is obtained in

a semiannual sample;1 or

3. The actual total sulfur content from the most recent

semiannual sample.

32040 Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules

TABLE D–5.—GAS SULFUR AND GCV VALUES USED IN CALCULATIONS FOR VARIOUS FUEL TYPES—Continued

Parameter Fuel type and sampling frequency Value used in calculations (except for missing data

hours)

Any gaseous fuel delivered in shipments or lots—Sample each lot or shipment.1. Actual total sulfur content from most recent shipment;

2. Highest total sulfur content from previous year’s

samples, unless a higher value is obtained in a sample;1 or

3. Maximum total sulfur content value allowed by contract, unless a higher value is obtained in a sample.1

Any gaseous fuel transmitted by pipeline and having a

demonstrated ‘‘low sulfur variability’’ using the provisions of section 2.3.6—Sample daily.

1. Actual total sulfur content from daily sample; or

2. Highest total sulfur content from previous 30 daily

samples.

Any gaseous fuel—Sample hourly .................................. Actual hourly total sulfur content of the gas.

Gas GCV .............................. Pipeline Natural Gas—Sample monthly ......................... 1. GCV from most recent monthly sample (with ≥ 48

operating hours in the month);

2. Maximum GCV from contract, unless a higher value

is obtained in a monthly sample;1 or

3. Highest GCV from previous year’s samples, unless a

higher value is obtained in a monthly sample.1

Natural Gas—Sample monthly ....................................... 1. GCV from most recent monthly sample (with ≥ 48

operating hours in the month);

2. Maximum GCV from contract;1 or

3. Highest GCV from previous year’s samples.1

Any gaseous fuel delivered in shipments or lots—Sample each lot or shipment.1. Actual GCV from most recent shipment or lot;

2. Highest GCV from previous year’s samples, unless a

higher value is obtained in a sample;1 or

3. Maximum GCV value allowed by contract, unless a

higher value is obtained in a sample.1

Any gaseous fuel transmitted by pipeline and having a

demonstrated ‘‘low GCV variability’’ using the provisions of section 2.3.5—Sample monthly.

1. GCV from most recent monthly sample (with ≥ 48

operating hours in the month); or

2. Highest GCV from previous year’s samples, unless a

higher value is obtained in a monthly sample.1

Any other gaseous fuel not having a ‘‘low GCV variability’’—Sample daily or hourly. (Note that the use of

an on-line GCV calorimeter or gas chromatograph is

allowed).

Actual daily or hourly GCV of the gas.

1Assumed sulfur content and GCV values (i.e., contract values or highest values from previous year) may only continue to be used if the sulfur content or GCV of each sample is no greater than the assumed value used to calculate SO2 emissions or heat input. If a higher sample value

is obtained, use the results of that sample analysis as the new assumed value.

2.3.1 Pipeline Natural Gas Combustion

* * * * *

2.3.1.4 Documentation that a Fuel is

Pipeline Natural Gas

(a) A fuel may initially qualify as pipeline

natural gas, if information is provided in the

monitoring plan required under § 75.53,

demonstrating that the definition of pipeline

natural gas in § 72.2 of this chapter has been

met. The information must demonstrate that

the fuel meets either the percent methane or

GCV requirement and has a total sulfur

content of less than or equal to 0.5 grains/

100scf. The demonstration must be made

using one of the following sources of

information:

* * * * *

(2) The results of all available fuel sample

analyses from the past 12 months,

documenting the total sulfur content of the

fuel and the percentage by weight of methane

and/or GCV of the fuel. The fuel samples may

be obtained and analyzed by the owner or

operator, by an independent laboratory, or by

the supplier of the gaseous fuel;

(3) Data from a 720-hour demonstration

conducted using the procedures of sections

2.3.5 and 2.3.6 of this appendix,

documenting the total sulfur content of the

fuel and the percentage by weight of methane

and/or the GCV of the fuel, and using

comparable procedures to document the

percentage by weight of methane; or

(4) If historical fuel sampling results or

data from a 720-hour demonstration are not

available, a fuel may initially qualify as

pipeline natural gas if a sample of the fuel

is obtained and analyzed for total sulfur

content and for percent methane or GCV, and

if the results of the sample analysis show that

the total sulfur content and percentage

methane or GCV meet the definition of

pipeline natural gas in § 72.2 of this chapter.

(b) After a fuel initially qualifies as

pipeline natural gas under paragraph (a) of

this section, the owner or operator shall

sample the fuel for total sulfur content at

least semiannually and whenever it is

reasonable to believe that the fuel

composition has changed significantly. The

owner or operator shall also sample the GCV

of the fuel at the frequency specified in

section 2.3.4.1 of this appendix.

(c) If the results of a sample under

paragraph (b) of this section show that the

total sulfur content of the fuel exceeds 0.5gr/

100 scf, the fuel no longer qualifies as

pipeline natural gas. When this occurs:

(1) If the sample results show that the fuel

still qualifies as natural gas under section

2.3.2.4 of this appendix, discontinue using

the 0.0006 lb/mmBtu default SO2 emission

rate under 2.3.1.1, as of the date on which

the sample results are received. Determine a

new default SO2 emission rate according to

section 2.3.2.1.1 of this appendix and use the

new SO2 emission rate, beginning with the

date of receipt of the sample results; or

(2) If the sample results show that the fuel

no longer qualifies either as pipeline natural

gas or natural gas, the owner or operator shall

implement the procedures of section 2.3.3.1

of this appendix (for sulfur content

determination) and section 2.3.4.3 of this

appendix (for GCV determination), no later

than 90 days after the end of the quarter in

which the sample results are received.

2.3.2 Natural Gas Combustion

* * * * *

2.3.2.1 SO2 Emission Rate

* * * * *

2.3.2.1.1 * * * In Equation D–1h, the total

sulfur content and GCV values shall be

determined in accordance with the allowable

options shown in Table D–5 of this appendix.

***

Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules 32041

ER S

GCV

total = 



 



 ×[ ] × 



 



 ( ) − 2 0

7000

106 . Eq. D 1h

Where:

ER = Default SO2 emission rate for natural

gas combustion, lb/mmBtu.

Stotal = Total sulfur content of the natural

gas, gr/100scf.

GCV = Gross calorific value of the natural

gas, Btu/100scf.

7000 = Conversion of grains/100scf to lb/

100scf.

2.0 = Ratio of lb SO2/lb S.

106 = Conversion factor (Btu/mmBtu).

2.3.2.1.2 For reporting purposes, apply

the results of the required periodic fuel

samples described in Table D–5 of this

appendix as follows. Use Equation D–1h to

recalculate the SO2 emission rate, as

necessary.

(a) For daily samples of total sulfur content

or GCV:

(1) If the actual value is to be used in the

calculations, apply the results of each daily

sample to all hours in the day on which the

sample is taken; or

(2) If the highest value in the previous 30

daily samples is to be used in the

calculations, apply that value to all hours in

the current day. If, for a particular unit, fewer

than 30 daily samples have been collected,

use the highest value from all available

samples until 30 days of historical sampling

results have been obtained.

(b) For semiannual samples of total sulfur

content:

(1) If the actual value is to be used in the

calculations, apply the results of the most

recent sample, until the date on which the

results of the next sample are received; or

(2) If an assumed value (contract maximum

or highest value from previous year’s

samples) is to be used in the calculations,

apply the assumed value to all hours in the

quarter unless a higher value is obtained in

a semiannual fuel sample. In that case, use

the sampled value, beginning with the date

of receipt of the sample results. Consider the

sample results to be the new assumed value.

Continue using the new assumed value

unless and until it is superseded by a higher

value from a subsequent quarterly sample; or

(if applicable) it is superseded by a new

contract in which case the new contract

value becomes the assumed value at the time

the fuel specified under the new contract

begins to be combusted in the unit; or (if

applicable) both the calendar year in which

the sampled value exceeded the assumed

value and the subsequent calendar year have

elapsed.

(c) For monthly samples of the fuel GCV:

(1) If the actual value is to be used in the

calculations, apply the results of the most

recent sample, until the date on which the

results of the next sample are received; or

(2) If an assumed value (contract maximum

or highest value from previous year’s

samples) is to be used in the calculations,

apply the assumed value to all hours in each

month of the quarter unless a higher value is

obtained in a monthly GCV sample. In that

case, use the sampled value, beginning with

the date of receipt of the sample results.

Consider the sample results to be the new

assumed value. Continue using the new

assumed value unless and until it is

superseded by a higher value from a

subsequent monthly sample; or (if

applicable) it is superseded by a new contract

in which case the new contract value

becomes the assumed value at the time the

fuel specified under the new contract begins

to be combusted in the unit; or (if applicable)

both the calendar year in which the sampled

value exceeded the assumed value and the

subsequent calendar year have elapsed.

(d) For samples of gaseous fuel delivered

in shipments or lots:

(1) If the actual value for the most recent

shipment is to be used in the calculations,

apply the results of the most recent sample,

until the date on which the results of the next

sample are received; or

(2) If an assumed value (contract maximum

or highest value from previous year’s

samples) is to be used in the calculations,

apply the assumed value unless a higher

value is obtained in a sample of a shipment.

In that case, use the sampled value,

beginning with the date of receipt of the

sample results. Consider the sample results

to be the new assumed value. Continue using

the new assumed value unless and until: it

is superseded by a higher value from a

sample of a subsequent shipment; or (if

applicable) it is superseded by a new contract

in which case the new contract value

becomes the assumed value at the time the

fuel specified under the new contract begins

to be combusted in the unit; or (if applicable)

both the calendar year in which the sampled

value exceeded the assumed value and the

subsequent calendar year have elapsed.

* * * * *

2.3.2.4 Documentation that a Fuel is a

Natural Gas

(a) A fuel may initially qualify as natural

gas if information is provided in the

monitoring plan required under § 75.53,

demonstrating that the definition of natural

gas in § 72.2 of this chapter has been met.

The information must demonstrate that the

fuel meets either the percent methane or GCV

requirement and has a total sulfur content of

less than or equal to 20.0 grains/100 scf. 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 transportation

contract;

(2) The results of all available fuel sample

analyses from the past 12 months,

documenting the total sulfur content of the

fuel and the percentage by weight of methane

and/or GCV of the fuel. The fuel samples may

be obtained and analyzed by the owner or

operator, by an independent laboratory, or by

the supplier of the gaseous fuel;

(3) Data from a 720-hour demonstration

conducted using the procedures of section

2.3.6 of this appendix, documenting the total

sulfur content of the fuel and the percentage

by weight of methane and/or the GCV of the

fuel, and using comparable procedures to

document the percentage by weight of

methane; or

(4) If historical fuel sampling results or

data from a 720-hour demonstration are not

available, a fuel may initially qualify as

natural gas if a sample of the fuel is obtained

and analyzed for total sulfur content and for

percent methane or GCV, and if the results

of the sample analyses show that the total

sulfur content and percentage methane or

GCV meet the definition of natural gas in

§ 72.2 of this chapter.

(b) After a fuel initially qualifies as natural

gas under paragraph (a) of this section, the

owner or operator shall sample the fuel for

total sulfur content at least semiannually and

whenever it is reasonable to believe that the

fuel composition has changed significantly.

The owner or operator shall also sample the

GCV of the fuel at the frequency specified in

section 2.3.4.2 of this appendix.

(c) If the results of a periodic sample

required under paragraph (b) of this section

show that the total sulfur content of the fuel

exceeds 20.0 gr/100 scf, the fuel no longer

qualifies as natural gas. In that case, the

owner or operator shall implement the

procedures of section 2.3.3.1 of this appendix

(for sulfur content determination) and section

2.3.4.3 of this appendix (for GCV

determination), no later than 90 days after

the end of the quarter in which the sample

results are received.

2.3.3 SO2 Mass Emissions From Any

Gaseous Fuel

* * * * *

2.3.3.2 SO2 Mass Emission Rate

* * * That is, for fuels delivered by

pipeline which demonstrate a low sulfur

variability (under section 2.3.6 of this

appendix) use either the daily sample value

or the highest value in the previous 30 daily

samples or for fuels requiring hourly sulfur

content sampling with a gas chromatograph

use the actual hourly sulfur content). For

fuels delivered in shipments or lots, use

either the actual sulfur content from the most

recent shipment or an assumed value

(contract maximum or highest value from the

previous year’s samples). In all cases, for

reporting purposes, apply the results of the

required periodic total sulfur samples in

accordance with the provisions of section

2.3.2.1.2 of this appendix.

* * * * *

2.3.4 Gross Calorific Values for Gaseous

Fuels

* * * * *

2.3.4.3 GCV of Other Gaseous Fuels

* * * For reporting purposes, apply the

results of the required periodic GCV samples

in accordance with the provisions of section

2.3.2.1.2 of this appendix.

2.3.4.3.1 * * * For sampling from the tank

after each delivery, use either the most recent

GCV sample, the maximum GCV specified in

the fuel contract, or the highest GCV from the

previous year’s samples.

32042 Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules

2.3.4.3.2 For any gaseous fuel that does

not qualify as pipeline natural gas or natural

gas, which is not delivered in shipments or

lots, and which performs the required 720

hour test under section 2.3.5 of this

appendix, if the results of the test

demonstrate that the gaseous fuel has a low

GCV variability, determine the GCV at least

monthly. In calculations of hourly heat input

for a unit, use either the most recent monthly

sample, the maximum GCV specified in the

fuel contract, or the highest fuel GCV from

the previous year’s samples.

* * * * *

2.3.5 Demonstration of Fuel GCV

Variability

(a) This optional demonstration may be

made for any fuel which does not qualify as

pipeline natural gas or natural gas, and is not

delivered only in shipments or lots. The

demonstration data may be used to show that

monthly sampling of the GCV of the gaseous

fuel or blend is sufficient, in lieu of daily

GCV sampling. The procedures in this

section may also be used to demonstrate that

the GCV of a particular gaseous fuel is within

the range of GCV values for pipeline natural

gas or natural gas, as defined in § 72.2 of this

chapter.

* * * * *

2.3.6 Demonstration of Fuel Sulfur

Variability

(a) This optional demonstration may be

made for any fuel which does not qualify as

pipeline natural gas or natural gas, and is not

delivered only in shipments or lots. The

results of the demonstration may be used to

show that daily sampling for sulfur in the

fuel is sufficient, rather than hourly

sampling. The procedures in this section may

also be used to demonstrate that the total

sulfur content of a particular gaseous fuel is

within the limits for pipeline natural gas or

natural gas, as defined in § 72.2 of this

chapter. * * * Provide a minimum of 720

hours of data, indicating the total sulfur

content of the gaseous fuel or blend (in gr/

100 scf). The demonstration data shall be

obtained using either manual hourly

sampling or an on-line gas chromatograph

capable of determining fuel total sulfur

content on an hourly basis. * * *

* * * * *

2.4 Missing Data Procedures

* * * * *

2.4.1 Missing Data for Oil and Gas Samples

* * * * *

TABLE D–6.—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 Total Sulfur Content .................................... 1. 0.002 lb/mmBtu for pipeline natural gas;

2. For natural gas for which semiannual sampling is performed, a default emission rate calculated from Equation D–1h, using the lesser of: (a) The maximum total sulfur content specified in the fuel contract; or (b) 1.5 times the highest total sulfur content from the previous

year’s samples;

3. For any gaseous fuel sampled daily, 1.5 times the highest total sulfur content value from the

previous 30 days on which valid samples were obtained; or

4. For any gaseous fuel sampled hourly, the highest total sulfur content value from the previous 720 hourly samples

Gas GCV/Heat Content ...................................... 1100 Btu/scf for pipeline natural gas, natural gas or landfill gas.

1500 for butane or refinery gas.

2100 Btu/scf for propane or any other gaseous fuel.

2.4.2 Missing Data Procedures for Fuel

Flow Rate. Whenever data are missing from

any primary fuel flowmeter system (as

defined in § 72.2 of this chapter) and there

is no backup system available to record the

fuel flow rate, 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. Alternatively, for a fuel

flowmeter system used to measure the fuel

combusted by a peaking unit, the simplified

fuel flow missing data procedure in section

2.4.2.1 of this appendix may be used. Before

using the procedures in sections 2.4.2.2 and

2.4.2.3 of this appendix, establish load ranges

for the unit using the procedures of section

2 in appendix C to this part, except for units

that do not produce electrical output

(megawatts) or thermal output (e.g., klb of

steam per hour). The owner or operator of a

unit that does not produce electrical or

thermal output may either establish

operational bins for the unit, as described in

section 4 of appendix C to this part, or may

perform missing data substitution without

segregating the fuel flow rate data into bins.

When load ranges or operational bins are

used for fuel flow rate missing data purposes,

separate, fuel-specific databases shall be

created and maintained. A database shall be

kept for each type of fuel combusted in the

unit, for the hours in which the fuel is

combusted alone in the unit. An additional

database shall be kept for each type of fuel,

for the hours in which it is co-fired with any

other type(s) of fuel(s).

2.4.2.1 Simplified Fuel Flow Rate Missing

Data Procedure for Peaking Units * * *

(b) The maximum flow rate that the fuel

flowmeter can measure (i.e, the upper range

value of the flowmeter).

2.4.2.2 Missing Data Procedures for Nonpeaking Units—Single Fuel Hours. For

missing data periods that occur when only

one type of fuel is being combusted, provide

substitute data for each hour in the missing

data period as follows.

2.4.2.2.1 If load-based missing data

procedures are used, substitute the arithmetic

average of the hourly fuel flow rate(s)

measured and recorded by a certified fuel

flowmeter system at the corresponding

operating unit load range during the previous

720 operating hours in which the unit

combusted only that same fuel. If no fuel

flow rate data are available at the

corresponding load range, apply the same

mathematical algorithm to, and use the same

lookback period for, the data from the next

higher load range, if such data are available.

If no quality-assured fuel flow rate data are

available at either the corresponding load

range or a higher load range, substitute the

maximum potential fuel flow rate (as defined

in section 2.4.2.1 of this appendix) for each

hour of the missing data period.

2.4.2.2.2 For units that do not produce

electrical or thermal output and therefore

cannot use load-based missing data

procedures, provide substitute data for each

hour of the missing data period as follows.

2.4.2.2.2.1 If operational bins (as defined

in section 4 of appendix C to this part) are

used, substitute the arithmetic average of the

hourly fuel flow rates measured and recorded

by a certified fuel flowmeter system at the

corresponding operational bin during the

previous 720 operating hours in which the

unit combusted only that same fuel. If no

quality-assured fuel flow rate data are

available at the corresponding operational

bin, or, if essential operating or parametric

data are unavailable and the operational bin

cannot be determined, substitute the

maximum potential fuel flow rate (as defined

in section 2.4.2.1 of this appendix) for each

hour of the missing data period.

2.4.2.2.2.2 If operational bins are not

used, substitute the arithmetic average of the

hourly fuel flow rates measured and recorded

by a certified fuel flowmeter system during

the previous 720 operating hours in which

the unit combusted only that same fuel. If no

quality-assured fuel flow rate data are

available, substitute the maximum potential

fuel flow rate (as defined in section 2.4.2.1

Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules 32043

of this appendix) for each hour of the missing

data period.

2.4.2.3 Missing Data Procedures for Nonpeaking Units—Multiple Fuel Hours. For

missing data periods that occur when two or

more different types of fuel are being cofired, provide substitute fuel flow rate data

for each hour of the missing data period as

follows.

2.4.2.3.1 If load-based missing data

procedures are used, substitute the maximum

hourly fuel flow rate measured and recorded

by a certified fuel flowmeter system at the

corresponding load range during the previous

720 operating hours when the fuel for which

the flow rate data are missing was co-fired

with any other type of fuel. If no such

quality-assured fuel flow rate data are

available at the corresponding load range,

apply the same mathematical algorithm to,

and use the same lookback period for, the

data from the next higher load range (if

available). If no quality-assured fuel flow rate

data are available for co-fired hours, either at

the corresponding load range or a higher load

range, substitute the maximum potential fuel

flow rate (as defined in section 2.4.2.1 of this

appendix) for each hour of the missing data

period.

2.4.2.3.2 For units that do not produce

electrical or thermal output and therefore

cannot use load-based missing data

procedures, provide substitute fuel flow rate

data for each hour of the missing data period

as follows.

2.4.2.3.2.1 If operational bins (as defined

in section 4 of appendix C to this part) are

used, substitute the maximum hourly fuel

flow rate measured and recorded by a

certified fuel flowmeter system at the

corresponding operational bin, during the

previous 720 operating hours in which the

unit for which the flow rate data are missing

was co-fired with any other type of fuel. If

no quality-assured fuel flow rate data for cofired hours are available at the corresponding

operational bin, or, if essential operating or

parametric data are unavailable and the

operational bin cannot be determined,

substitute the maximum potential fuel flow

rate (as defined in section 2.4.2.1 of this

appendix) for each hour of the missing data

period.

2.4.2.3.2.2 If operational bins are not

used, substitute the maximum hourly fuel

flow rate measured and recorded by a

certified fuel flowmeter system during the

previous 720 operating hours in which the

fuel for which the flow rate data are missing

was co-fired with any other type of fuel. If

no quality-assured fuel flow rate data for cofired hours are available, substitute the

maximum potential fuel flow rate (as defined

in section 2.4.2.1 of this appendix) for each

hour of the missing data period.

2.4.2.3.3 If, during an hour in which

different types of fuel are co-fired, qualityassured fuel flow rate data are missing for

two or more of the fuels being combusted,

apply the procedures in section 2.4.2.3.1 or

2.4.2.3.2 of this appendix (as applicable)

separately for each type of fuel.

2.4.2.3.4 If the missing data substitution

required in section 2.4.2.3.1 or 2.4.2.3.2

causes the reported hourly heat input rate

based on the combined fuel usage to exceed

the maximum rated hourly heat input of the

unit, adjust the substitute fuel flow rate

value(s) so that the reported heat input rate

equals the unit’s maximum rated hourly heat

input. Manual entry of the adjusted

substitute data values is permitted.

2.4.3 * * * In addition, if there is at least

one hour, but fewer than 720 hours of

quality-assured fuel flowmeter data available

for the lookback periods described in

sections 2.4.2.2 and 2.4.2.3 of this appendix,

use all of the available fuel flowmeter data

to determine the appropriate substitute data

values.

Appendix D to Part 75 [Amended]

58. Section 3 of Appendix D to Part

75 is amended by:

a. In the definition of the variable

‘‘%Soil’’ in Equation D–2 in section 3.1.1

by removing the word ‘‘measured’’, and

by revising the word ‘‘sample’’ to read

‘‘oil’’;

b. In the numerator of Equation D–4

in section 3.3.1 by revising the number

‘‘2’’ with the number ‘‘2.0’’;

c. In the definition of the variable

‘‘GCVgas’’ in Equation D–6 in section

3.4.1 by revising the word ‘‘Btu/hr’’ to

read ‘‘Btu/100 scf’’;

d. In the definition of the variable

‘‘GCVoil’’ in Equation D–8 in section

3.4.2 by adding the word ‘‘or’’ after the

word ‘‘Btu/ton,’’;

e. In paragraph (b) in section 3.4.3 by

revising the words ‘‘Equation D–10 or

D–11’’ to read ‘‘Equation F–21a or F–

21b in appendix F to this part’’ in the

third sentence and by removing

equations and variable definitions for

Equations D–10 and D–11;

f. In paragraph (c) of section 3.4.3 by

revising the words ‘‘Equation D–10 or

D–11’’ to read ‘‘Equation F–21a or F–

21b’’;

g. Revising the section heading of

section 3.5;

h. In section heading 3.5.4 by adding

the words ‘‘Rate and Heat Input’’ after

the word ‘‘Input’’; and

i. In section 3.5.4 by adding the

subsection number ‘‘3.5.4.1’’ before the

existing text of the section and adding

new subsection 3.5.4.2 following the

variable definitions for Equation D–15.

The revisions and additions read as

follows:

3. Calculations

* * * * *

3.5 Conversion of Hourly Rates to Hourly,

Quarterly, and Year-to-Date Totals

* * * * *

3.5.4 Hourly Total Heat Input Rate and Heat

Input from the Combustion of all Fuels

* * * * *

3.5.4.2 For reporting purposes, determine

the heat input rate to each unit, in mmBtu/

hr, for each hour from the combustion of all

fuels using Equation D–15a:

HI

t

a rate

i

all

-hr

rate-i

-fuels

u

HI

t = − (Eq. D

∑

15 )

Where:

HIrate-hr = Total heat input rate from all fuels

combusted during the hour, mmBtu/hr.

HIrate-i = Heat input rate for each type of gas

or oil combusted during the hour,

mmBtu/hr.

ti = Time each gas or oil fuel was combusted

for the hour (fuel usage time), 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).

tu = Unit operating time

* * * * *

59. Section 1 of Appendix E to Part

75 is amended by revising the second

sentence of section 1.1 and adding two

sentences after that second sentence to

read as follows:

Appendix E to Part 75—Optional NOX

Emissions Estimation Protocol for Gas-Fired

Peaking Units and Oil-Fired Peaking Units

1. Applicability

1.1 Unit Operation Requirements

* * * If a unit’s operations exceed the

levels required to be a peaking unit, the

owner or operator shall install and certify a

NOX-diluent continuous emission monitoring

system no later than December 31 of the

following calendar year. If the required

CEMS has not been installed and certified by

that date, the owner or operator shall report

the maximum potential NOX emission rate

(MER) (as defined in § 72.2 of this chapter)

for each unit operating hour, starting with the

first unit operating hour after the deadline

and continuing until the CEMS has been

provisionally certified. For each unit

operating hour in which the MER is reported,

the MER shall be specific to the type of fuel

being combusted in the unit. * * *

* * * * *

60. Section 2 of Appendix E to Part

75 is amended by:

a. Revising sections 2.1.4, 2.2 and

2.5.2;

b. In the second sentence of section

2.1.5 by revising the words ‘‘nearest

0.01 lb/mm/Btu’’ to read ‘‘nearest 0.001

lb/mmBtu’’;

c. In section 2.3 by revising the words

‘‘10 unit’’ to read ‘‘30 unit’’ and the

words ‘‘section 2.1 of appendix B of this

part’’ with ‘‘§ 72.2 of this chapter,’’ and

by revising the reference to ‘‘§ 75.60(a)’’

to read ‘‘§ 75.60’’;

d. In sections 2.3.1 and 2.3.2 by

revising the first sentence of each

section, adding a new sentence after

each first sentence, and revising each

occurrence of the words

32044 Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules

‘‘manufacturer’s recommended’’ to read

‘‘acceptable’’;

e. Revising the third sentence of 2.4.2;

f. Adding a new second sentence in

section 2.5; and

g. Adding sections 2.5.2.1, 2.5.2.1.1,

2.5.2.1.2, 2.5.2.2, and 2.5.2.3.

The revisions and additions read as

follows:

Appendix E to Part 75—Optional NOX

Emissions Estimation Protocol for GasFired Peaking Units and Oil-Fired

Peaking Units

* * * * *

2. Procedure

2.1 Initial Performance Testing

* * * * *

2.1.4 Emergency Fuel

The designated representative of a

unit that has a federally-enforceable

permit restricting the combustion of a

particular fuel to emergencies where the

primary fuel is not available is

exempted from the requirements of this

appendix for testing the NOX emission

rate during combustion of the

emergency fuel. The designated

representative shall include in the

monitoring plan for the unit

documentation that the permit restricts

use of the fuel to emergencies only.

When emergency fuel is combusted,

report the maximum potential NOX

emission rate for the unit, in accordance

with section 2.5.2.3 of this appendix.

The designated representative shall also

provide notice under § 75.61(a)(6) for

each period when the emergency fuel is

combusted.

* * * * *

2.2 Periodic NOX Emission Rate

Testing

Retest the NOX emission rate of the

gas-fired peaking unit or the oil-fired

peaking unit while combusting each

type of fuel (or fuel mixture) for which

a NOX emission rate versus heat input

rate correlation curve was derived, at

least once every 20 calendar quarters. If

a required retest is not completed by the

end of the 20th calendar quarter

following the quarter of the last test, use

the missing data substitution procedures

in section 2.5 of this appendix,

beginning with the first unit operating

hour after the end of the 20th calendar

quarter. Continue using the missing data

procedures until the required retest has

been passed. Note that missing data

substitution is fuel-specific (i.e., the use

of substitute data is required only when

combusting a fuel (or fuel mixture) for

which the retesting deadline has not

been met). Each time that a new fuelspecific correlation curve is derived

from retesting, the new curve shall be

used to report NOX emission rate,

beginning with the first operating hour

in which the fuel is combusted,

following the completion of the retest.

2.3 Other Quality Assurance/Quality

Control-Related NOX Emission Rate

Testing

* * * * *

2.3.1 For a stationary gas turbine,

select at least four operating parameters

indicative of the turbine’s NOX

formation characteristics, and define in

the QA plan for the unit the acceptable

ranges for these parameters at each

tested load-heat input point. The

acceptable parametric ranges should be

based upon the turbine manufacturer’s

recommendations. * * *

2.3.2 For a diesel or dual-fuel

reciprocating engine, select at least four

operating parameters indicative of the

engine’s NOX formation characteristics,

and define in the QA plan for the unit

the acceptable ranges for these

parameters at each tested load-heat

input point. The acceptable parametric

ranges should be based upon the engine

manufacturer’s recommendations.

***

* * * * *

2.4 Procedures for Determining Hourly

NOX Emission Rate

* * * * *

2.4.2 * * * Linearly interpolate to

0.1 mmBtu/hr heat input rate and 0.001

lb/mmBtu NOX. * * *

* * * * *

2.5 Missing Data Procedures

* * * For the purpose of providing

substitute data, calculate the maximum

potential NOX emission rate (as defined

in § 72.2 of this chapter) for each type

of fuel combusted in the unit.

* * * * *

2.5.2 Substitute missing NOX

emission rate data using the highest

NOX emission rate tabulated during the

most recent set of baseline correlation

tests for the same fuel or, if applicable,

combination of fuels, except as provided

in paragraphs 2.5.2.1, 2.5.2.2, and

2.5.2.3 of this section.

2.5.2.1 If the measured heat input

rate during any unit operating hour is

higher than the highest heat input rate

from the baseline correlation tests, the

NOX emission rate for the hour is

considered to be missing. Provide

substitute data for each such hour, as

follows.

2.5.2.1.1 Substitute the higher of: the

NOX emission rate obtained by linear

extrapolation of the correlation curve, or

the maximum potential NOX emission

rate (MER) (as defined in § 72.2 of this

chapter), specific to the type of fuel

being combusted. (For fuel mixtures,

substitute the highest NOX MER value

for any fuel in the mixture.) For units

with NOX emission controls, the option

to report the extrapolated NOX emission

rate may only be used if the controls are

documented (e.g., by parametric data) to

be operating properly during the

missing data period (see section 2.5.2.2

of this appendix); or 2.5.2.1.2 Substitute

1.25 times the highest NOX emission

rate from the baseline correlation tests

for the fuel (or fuel mixture) being

combusted in the unit, not to exceed the

MER for that fuel (or mixture). For units

with NOX emission controls, the option

to report 1.25 times the highest emission

rate from the correlation curve may only

be used if the controls are documented

(e.g., by parametric data) to be operating

properly during the missing data period

(see section 2.5.2.2 of this appendix).

2.5.2.2 For a unit with add-on NOX

emission controls (e.g., steam or water

injection, selective catalytic reduction),

if, for any unit operating hour, the

emission controls are either not in

operation or if appropriate parametric

data are unavailable to ensure proper

operation of the controls, the NOX

emission rate for the hour is considered

to be missing. Substitute the fuelspecific MER (as defined in § 72.2 of

this chapter) for each such hour.

2.5.2.3 When emergency fuel (as

defined in § 72.2) is combusted in the

unit, report the fuel-specific NOX MER

for each hour that the fuel is combusted.

* * * * *

61. Section 2 of Appendix F to Part

75 is amended by revising Equation F–

3 in section 2.3 to read as follows:

Appendix F to Part 75—Conversion

Procedures

* * * * *

2. Procedures for SO 2 Emissions

* * * * *

2.3 * * *

E

E t

q Eq

h h

h

n

= − =

∑

1

2000 ( . F 3)

where: * * *

* * * * *

Appendix F Section 3 [Amended]

62. Section 3 of Appendix F to Part

75 is amended by removing the third

sentence from section 3.3.5.

63. Section 5 of Appendix F to Part

75 is amended by:

Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules 32045

a. In the definition of the variable

‘‘Qg’’ of Equation F–20 in section 5.5.2

by revising the words ‘‘hundred cubic

feet’’ to read ‘‘hundred standard cubic

feet per hour’’;

b. In the first sentence of sections

5.6.1, 5.6.2, and 5.7 by revising the word

‘‘should’’ to read ‘‘shall.’’

c. In the definitions for the variables

‘‘ti,’’ and ‘‘tcs,’’ and ‘‘n’’ of Equations F–

21a and F–21b in sections 5.6.1 and

5.6.2 by revising the words ‘‘Operating

time at a particular unit’’ in the

definition of ‘‘variable ti’’ to read ‘‘Unit

operating time’’, by revising the words

‘‘Operating time at common stack’’ in

the definition of ‘‘variable tcs’’ with

‘‘Common stack or common pipe

operating time’’, and by adding the

words ‘‘or pipe’’ to the end of the

definition of variable ‘‘n’’.

d. Revising the definitions of variables

‘‘HIs’’, ‘‘tunit’’, and ‘‘ts’’, and adding a

new definition for ‘‘s’’ in the definition

of variables of Equation F–21c in section

5.7; and

e. Adding section 5.6.3.

The revisions and additions read as

follows:

5. Procedures for Heat Input

* * * * *

5.6 Heat Input Rate Apportionment for

Units Sharing a Common Stack or Pipe

* * * * *

5.6.3 As an alternative to using Equation

F–21a or F–21b, the owner or operator may

apportion the heat input rate at a common

pipe to the individual units served by the

common pipe based on the fuel flow rate to

the individual units, as measured by

uncertified fuel flowmeters. This option may

only be used if a fuel flowmeter system that

meets the requirements of appendix D to this

part is installed on the common pipe. If this

option is used, determine the unit heat input

rates using the following equation:

HI HI t

t

FF t

FF t

i CP d CP

i

i i

i i

i

n = 



 

































−

=

∑

1

(Eq. F ) 21

Where:

HIi = Heat input rate for a unit, mmBtu/hr.

HICP = Heat input rate at the common pipe,

mmBtu/hr.

FFi = Fuel flow rate to a unit, gal/min, 100

scfh, or other appropriate units

ti = 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).

tCP = Common pipe 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 = Total number of units using the common

pipe.

i = Designation of a particular unit.

5.7 Heat Input Rate Summation for Units

with Multiple Stacks or Pipes

* * * * *

HIs = Heat input rate for the individual stack,

duct, or pipe, mmBtu/hr.

tUnit = Unit operating time, 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 for the individual stack

or pipe, 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).

s = Designation for a particular stack, duct,

or pipe.

Appendix F to Part 75 [Amended]

64. Section 7 of Appendix F to Part

75 is amended by revising the

definitions of variables ‘‘Eh’’ and ‘‘HI’’ of

Equation F–23 in section 7 to read as

follows:

7. Procedures for SO2 Mass Emissions at

Units with SO2 Continuous Emission

Monitoring Systems During the Combustion

of Pipeline Natural Gas or Natural Gas

* * * * *

Eh = Hourly SO2 mass emission rate, lb/hr.

HI = Hourly heat input rate, as determined

using the procedures of section 5.2 of

this appendix, mmBtu/hr.

Appendix F to Part 75 [Amended]

65. Section 8 of Appendix F to Part

75 is amended by:

a. In the first sentence of section 8.1.1

by adding the word ‘‘rate’’ after each

occurrence of the words ‘‘heat input’’;

b. Revising the definition of the

variable ‘‘tcs’’ of Equation F–25 in

section 8.1.2; and

c. Adding definitions of the variables

‘‘p’’ and ‘‘u’’ to Equation F–25 of section

8.1.2.

The revisions and additions read as

follows:

8. Procedures for NOX Mass Emissions

* * * * *

8.1 * * *

8.1.2 * * *

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). (For

each hour, tcs is the total time during

which one or more of the units which

exhaust through the common stack

operate.)

* * * * *

p = Number of units that exhaust through the

common stack.

u = Designation of a particular unit.

* * * * *

66. Section 2 of Appendix G to Part

75 is amended by:

a. Amending section 2.1 to designate

the first two sentences following the

variables in Equation G–1 as section

2.1.1, the third sentence as section 2.1.2,

and the remaining text as section 2.1.3;

b. Revising the first sentence of

section 2.3; and

c. Revising the definition of variable

‘‘Fc’’ of Equation G–4 in section 2.3.

The revisions read as follows:

Appendix G to Part 75—Determination of

CO2 Emissions

* * * * *

2. Procedures for Estimating CO2 Emissions

from Combustion

* * * * *

2.3 In lieu of using the procedures,

methods, and equations in section 2.1 of this

appendix, the owner or operator of an

affected gas-fired (or oil-fired) unit (as

defined under § 72.2 of this chapter) may use

the following equation and records of hourly

heat input to estimate hourly CO2 mass

emissions (in tons). * * *

(Eq. G–4) * * *

FC = Carbon based F-factor, 1040 scf/mmBtu

for natural gas; 1,420 scf/mmBtu for

crude, residual, or distillate oil; and

calculated according to the procedures in

section 3.3.5 of appendix F to this part

for other gaseous fuels.

* * * * *

Appendix G to Part 75 [Amended]

67. Section 5 of Appendix G to Part

75 is amended by:

32046 Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules

a. Removing and reserving sections

5.1 and 5.1.1;

b. Revising the section heading and

introductory text of section 5.2; and

c. Revising Table G–1 in section 5.2.2.

The revisions read as follows:

5. Missing Data Substitution Procedures for

Fuel Analytical Data

* * * * *

5.2 Missing Carbon Content Data

Use the procedures of this section to

substitute for missing carbon content data.

* * * * *

TABLE G–1.—MISSING DATA SUBSTITUTION PROCEDURES FOR MISSING CARBON CONTENT DATA

Parameter Missing data value

Oil and coal carbon content ............................... Most recent, previous carbon content value available for that type of coal, grade of oil, or default value, in this table.

Gas carbon content ............................................ Most recent, previous carbon content value available for that type of gaseous fuel, or default

value, in this table.

Default coal carbon content ................................ Anthracite: 90.0 percent.

Bituminous: 85.0 percent.

Sub-bituminous/Lignite: 75.0 percent.

Default oil carbon content ................................... 90.0 percent.

Default gas carbon content ................................ Natural gas: 75.0 percent.

Other gaseous fuels: 90.0 percent.

* * * * *

PART 78—APPEAL PROCEDURES

FOR ACID RAIN PROGRAM

68. The authority citation for part 78

continues to read as follows:

Authority: 42 U.S.C. 7401, 7403, 7410,

7426, 7601, and 7651, et seq.

69. Section 78.1 is amended by

removing from paragraph (a)(1) the

words ‘‘parts 72, 73, 74, 75, 76, and 77

of this chapter’’ and adding in their

place ‘‘parts 72, 73, 74, 75, 76, or 77 of

this chapter or part 97 of this chapter’’;

and adding a new paragraph (b)(6) to

read as follows:

§ 78.1 Purpose and scope.

(b) * * *

(6) Under part 97 of this chapter,

(i) The adjustment of the information

in a compliance certification or other

submission and the deduction or

transfer of NOX allowances based on the

information, as adjusted, under § 97.31;

(ii) The decision on the allocation of

NOX allowances to a NOX Budget unit

under § 97.41(b), (c), (d), or (e);

(iii) The decision on the allocation of

NOX allowances to a NOX Budget unit

from the compliance supplement pool

under § 97.43;

(iv) The decision on the deduction of

NOX allowances under § 97.54;

(v) The decision on the transfer of

NOX allowances under § 97.61;

(vi) The decision on a petition for

approval of an alternative monitoring

system;

(vii) The approval or disapproval of a

monitoring system certification or

recertification under § 97.71;

(viii) The finalization of control

period emissions data, including

retroactive adjustment based on audit;

(ix) The approval or disapproval of a

petition under § 97.75;

(x) The determination of the

sufficiency of the monitoring plan for a

NOX Budget opt-in unit;

(xi) The decision on a request for

withdrawal of a NOX Budget opt-in unit

from the NOX Budget Trading Program

under § 97.86;

(xii) The decision on the deduction of

NOX allowances under § 97.87; and

(xiii) The decision on the allocation of

NOX allowances to a NOX Budget optin unit under § 97.88.

* * * * *

§ 78.2 [Amended].

70. Section 78.2 is amended by

removing the words ‘‘shall apply to this

part’’ and adding to their place ‘‘shall

apply to appeals of any final decision of

the Administrator under parts 72, 73,

74, 75, 76, 77, or 78 of this chapter’’.

71. Section 78.3 is amended by:

a. Amending paragraph (b)(3)(i) by

adding, after the word ‘‘petitioner)’’, the

words ‘‘or the NOX authorized account

representative under paragraph (a)(3) of

this section (unless the NOX authorized

account representative is the

petitioner)’’;

b. In paragraph (c)(7) by adding, after

the words ‘‘title IV of the Act’’, the

words ‘‘or part 97 of this chapter, as

appropriate’’;

c. In paragraph (d)(2) by adding, after

the words ‘‘Acid Rain Program’’ the

words ‘‘or on an account certificate of

representation submitted by a NOX

authorized account representative or an

application for a general account

submitted by a NOX authorized account

representative under the NOX Budget

Trading Program’’;

d. Redesignating paragraphs (d)(2)

and (d)(3) as paragraphs (d)(3) and (d)(4)

respectively; and

e. Adding new paragraphs (a)(3) and

(d)(2).

The additions and revisions read as

follows:

§ 78.3 Petition for administrative review

and request for evidentiary hearing.

(a) * * *

(3) The following persons may

petition for administrative review of a

decision of the Administrator that is

made under part 97 of this chapter and

that is appealable under § 78.1(a) of this

part:

(i) The NOX authorized account

representative for the unit or any NOX

Allowance Tracking System account

covered by the decision; or

(ii) Any interested person.

* * * * *

(d) * * *

(2) Any provision or requirement of

part 97 of this chapter, including the

standard requirements under § 97.6 of

this chapter and any emission

monitoring or reporting requirements

under part 97 of this chapter.

* * * * *

72. Section 78.4 is amended by

adding two new sentences after the

third sentence in paragraph (a) to read

as follows:

§ 78.4 Filings.

(a) * * * Any filings on behalf of

owners and operators of a NOX Budget

unit or source shall be signed by the

NOX authorized account representative.

Any filings on behalf of persons with an

interest in NOX allowances in a general

account shall be signed by the NOX

authorized account representative.

***

* * * * *

§ 78.12 [Amended]

73. Section 78.12 is amended by

adding, after the words ‘‘was properly

issued or should be issued’’ in

paragraph (a)(2), the words ‘‘or that a

Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules 32047

NOX Budget permit or other federally

enforceable permit was properly issued

or should be issued’’.

PART 97—FEDERAL NOX BUDGET

TRADING PROGRAM

74. The authority citation for part 97

continues to read as follows:

Authority: 42 U.S.C. 7401, 7403, 7426, and

7601.

75. Section 97.2 is amended by:

a. Revising the definition of

‘‘continuous emission monitoring

system or CEMS’’;

b. In the definition of ‘‘Most stringent

State or Federal NOX emissions

limitation’’ by removing the words ‘‘,

with regard to a NOX Budget opt-in

unit,’’;

c. In the third sentence of the

definition of ‘‘NOX allowance’’ by

adding the reference ‘‘§ 97.40,’’ after the

word ‘‘except’’;

d. In the definition of ‘‘NOX Budget

unit’’ by removing the words ‘‘Trading

Program’’;

e. In the definition of ‘‘owner’’ by

adding the word ‘‘the’’ before the final

occurrence of the word ‘‘NOX’’ in

paragraph (4) of the definition; and

f. In the definition of ‘‘Percent

monitor data availability’’ by revising

the words ‘‘3,672 hours per’’ to read

‘‘the total number of unit operating

hours in the’’, and by revising the

symbol ‘‘%’’ to read ‘‘percent’’.

The revisions and additions read as

follows:

§ 97.2 Definitions.

* * * * *

Continuous emission monitoring

system or CEMS means the equipment

required under subpart H of this part to

sample, analyze, measure, and provide,

by means of readings taken at least once

every 15 minutes (using an automated

data acquisition and handling system

(DAHS), a permanent record of nitrogen

oxides (NOX) emissions, stack gas

volumetric flow rate or stack gas

moisture content (as applicable), in a

manner consistent with part 75 of this

chapter. The following are the principal

types of continuous emission

monitoring systems required under

subpart H of this part:

(1) A flow monitoring system,

consisting of a stack flow rate monitor

and an automated DAHS. A flow

monitoring system provides a

permanent, continuous record of stack

gas volumetric flow rate, in units of

standard cubic feet per hour (scfh);

(2) A nitrogen oxides concentration

monitoring system, consisting of a NOX

pollutant concentration monitor and an

automated DAHS. A NOX concentration

monitoring system provides a

permanent, continuous record of NOX

emissions in units of parts per million

(ppm);

(3) A nitrogen oxides emission rate (or

NOX-diluent) monitoring system,

consisting of a NOX pollutant

concentration monitor, a diluent gas

(CO2 or O2) monitor, and an automated

DAHS. A NOX concentration monitoring

system provides a permanent,

continuous record of: NOX

concentration in units of parts per

million (ppm), diluent gas concentration

in units of percent O2 or CO2 (% O2 or

CO2), and NOX emission rate in units of

pounds per million British thermal

units (lb/mmBtu); and

(4) A moisture monitoring system, as

defined in § 75.11(b)(2) of this chapter.

A moisture monitoring system provides

a permanent, continuous record of the

stack gas moisture content, in units of

percent H2O (% H2O).

* * * * *

§ 97.4 [Amended]

76. Section 97.4(b) is amended by:

a. Amending the first sentence of

paragraph (b)(1) by adding, after the

words ‘‘federally enforceable permit

that’’, the words ‘‘restricts the unit to

combusting only natural gas or fuel oil

(as defined in § 75.2 of this chapter)

during a control period and’’;

b. In paragraph (b)(4)(i) by adding,

after the words ‘‘with the restriction

on’’, the words ‘‘fuel use and’’; and

c. In paragraph (b)(4)(vi)(B) by adding,

after the words ‘‘the restriction on’’, the

words ‘‘fuel use or’’.

77. Section 97.5 is amended by:

a. In the third sentence of paragraph

(b)(2) by adding, after the word

‘‘submit’’, the words ‘‘such a statement

or’’;

b. In paragraph (c)(6)(ii) by removing

the period and replacing it with ‘‘; or’’;

and

c. Adding a new paragraph (c)(6)(iii).

The revisions and additions read as

follows:

§ 97.5 Retired unit exemption.

* * * * *

(c) * * *

(6) * * *

(iii) The date on which the unit

resumes operation, if the unit is not

required to submit a NOX permit

application.

* * * * *

§ 97.40 [Amended]

78. Section 97.40 is amended by

removing the word ‘‘program’’.

§ 97.43 [Amended]

79. Section 97.43 is amended by

removing paragraph (c)(8).

§ 97.51 [Amended]

80. Section 97.51 is amended by

amending paragraph (b)(1)(i)(D) by

adding, after the words ‘‘with respect

to’’, the word ‘‘ NOX’’.

81. Section 97.54 is amended in

paragraph (f) introductory text by

revising the colon after the words ‘‘as

follows’’ with a period and by adding a

new sentence to the end of the

paragraph to read as follows:

§ 97.54 Compliance.

* * * * *

(f) * * * For each State NOX Budget

Trading Program that is established, and

approved and administered by the

Administrator pursuant to § 51.121 of

this chapter, the terms ‘‘compliance

account’’ or ‘‘compliance accounts’’,

‘‘overdraft account’’ or ‘‘overdraft

accounts’’, ‘‘general account’’ or

‘‘general accounts’’, ‘‘States’’, and

‘‘trading program budgets under

§ 97.40’’ in paragraphs (f)(1) through

(f)(3) of this section shall be read to

include respectively: a compliance

account or compliance accounts

established under such State NOX

Budget Trading Program; an overdraft

account or overdraft accounts

established under such State NOX

Budget Trading Program; a general

account or general accounts established

under such State NOX Budget Trading

Program; the State or portion of a State

covered by such State NOX Budget

Trading Program; and the trading

program budget of the State or portion

of a State covered by such State NOX

Budget Trading Program.

* * * * *

§ 97.61 [Amended]

82. Section 97.61 is amended in

paragraph (b) by revising the words

‘‘same year as’’ to read ‘‘third year after

the year of’’.

83. Section 97.70 is amended by:

a. In paragraph (a)(1) by revising the

words ‘‘§§ 75.72 and §§ 75.76’’ to read

‘‘§§ 75.71 and 75.72’’;

b. Revising paragraph (b)(3);

c. Revising paragraph (b)(4);

d. Removing paragraphs (b)(5) and

(b)(6);

e. Redesignating paragraphs (b)(7),

(b)(8) and (b)(9) as paragraphs (b)(5),

(b)(6), and (b)(7), respectively;

f. Revising newly redesignated

paragraphs (b)(5) and (b)(6); and

g. Revising paragraph (c).

The revisions and additions read as

follows:

§ 97.70 General requirements.

* * * * *

(b) * * *

(3) For the owner or operator of a NOX

Budget unit under § 97.4(a) that

32048 Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules

commences operation on or after

January 1, 2002 and that reports on an

annual basis under § 97.74(d) by the

following dates:

(i) The earlier of 90 unit operating

days after the date on which the unit

commences commercial operation or

180 calendar days after the date on

which the unit commences commercial

operation; or (ii) May 1, 2002, if the

compliance date under paragraph

(b)(3)(i) of this section is before May 1,

2002.

(4) For the owner or operator of a NOX

Budget unit under § 97.4(a) that

commences operation on or after

January 1, 2002 and that reports on a

control period basis under

§ 97.74(d)(2)(ii), by the following dates:

(i) The earlier of 90 unit operating

days or 180 calendar days after the date

on which the unit commences

commercial operation, provided that

this compliance date is during a control

period; or (ii) May 1 immediately

following the compliance date under

paragraph (b)(4)(i) of this section, if

such compliance date is not during a

control period.

(5) For the owner or operator of a NOX

Budget unit that has a new stack or flue

for which construction is completed

after the applicable deadline under

paragraph (b)(1), (b)(2), (b)(3), or (b)(4)

of this section or under subpart I of this

part and that reports on an annual basis

under § 97.74(d), by the earlier of 90

unit operating days or 180 calendar days

after the date on which emissions first

exit to the atmosphere through the new

stack or flue.

(6) For the owner or operator of a NOX

Budget unit that has a new stack or flue

for which construction is completed

after the applicable deadline under

paragraph (b)(1), (b)(2), (b)(3), or (b)(4)

of this section or under subpart I of this

part and that reports on a control period

basis under § 97.74(d)(2)(ii), by the

following dates:

(i) The earlier of 90 unit operating

days or 180 calendar days after the date

on which emissions first exit to the

atmosphere through the new stack or

flue, provided that this compliance date

is during a control period; or

(ii) May 1 immediately following the

compliance date under paragraph

(b)(6)(i) of this section, if such

compliance date is not during a control

period.

* * * * *

(c) Commencement of data reporting.

(1) The owner or operator of NOX

Budget units under paragraph (b)(1) or

(b)(2) of this section shall determine,

record and report NOX mass emissions,

heat input rate, and any other values

required to determine NOX mass

emissions (e.g., NOX emission rate and

heat input rate, or NOX concentration

and stack flow rate) in accordance with

§ 75.70(g) of this chapter, beginning on

the first hour of the applicable

compliance deadline in paragraph (b)(1)

or (b)(2) of this section.

(2) The owner or operator of a NOX

Budget unit under paragraph (b)(3) or

(b)(4) of this section shall determine,

record and report NOX mass emissions,

heat input rate, and any other values

required to determine NOX mass

emissions (e.g., NOX emission rate and

heat input rate, or NOX concentration

and stack flow rate) and electric and

thermal output in accordance with

§ 75.70(g) of this chapter, beginning on:

(i) The date and hour on which the

unit commences operation, if the date

and hour on which the unit commences

operation is during a control period; or

(ii) The first hour on May 1 of the first

control period after the date and hour

on which the unit commences

operation, if the date and hour on which

the unit commences operation is not

during a control period.

(3) Notwithstanding paragraphs

(c)(2)(i) and (c)(2)(ii) of this section, the

owner or operator may begin reporting

NOX mass emission data and heat input

data before the date and hour under

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

section if the unit reports on an annual

basis and if the required monitoring

systems are certified before the

applicable date and hour under

paragraph (c)(1) or (c)(2) of this section.

* * * * *

84. Section 97.71 is amended by:

a. Revising paragraph (a) introductory

text;

b. In paragraphs (b)(1), (b)(2), and

(b)(3)(ii) by adding the word ‘‘emission’’

before the words ‘‘monitoring system’’

in each occurrence in paragraph (b)(1),

in both occurrences in the first sentence

of paragraph (b)(2), and in the one

occurrence in paragraph (b)(3)(ii); and

by revising the word ‘‘a’’ to read ‘‘an’’

after the word ‘‘installs’’ in the second

sentence of paragraph (b)(1);

c. In paragraphs (b)(3)(iii) and

(b)(3)(iv)(C) by removing each

occurrence of the words ‘‘or component

thereof’’; and

d. Revising the second sentence of

paragraph (c), adding two new

sentences to the end of paragraph (c),

and removing paragraphs (c)(i) through

(iii).

The revisions and additions read as

follows:

§ 97.71 Initial certification and

recertification procedures.

(a) The owner or operator of a NOX

Budget unit that is subject to an Acid

Rain emissions limitation shall comply

with the initial certification and

recertification procedures of part 75 of

this chapter for NOX-diluent CEMS,

flow monitors, NOX concentration

CEMS, or excepted monitoring systems

under appendix E of part 75 of this

chapter for NOX, under appendix D for

heat input, or under § 75.19 for NOX and

heat input, except that:

* * * * *

(c) * * * The owner or operator of

such a unit shall also meet the

applicable certification and

recertification procedures of paragraph

(b) of this section, except that the

excepted methodology shall be deemed

provisionally certified for use under the

NOX Budget Trading Program as of the

date on which the certification

application is received by the

Administrator. The methodology shall

be considered to be certified either upon

receipt of a written notice of approval

from the Administrator or, if such notice

is not provided, at the end of the

Administrator’s 120 day review period.

However, a provisionally certified or

certified low mass emissions excepted

methodology shall not be used to report

data under the NOX Budget Trading

Program prior to the applicable

commencement date specified in

§ 75.19(a)(1)(ii) of this chapter.

* * * * *

85. Section 97.72 is amended by:

a. In paragraph (a) by adding the word

‘‘emission’’ before the words

‘‘monitoring system’’ and the words

‘‘subpart H,’’ before ‘‘appendix D’’; and

b. In paragraph (b) by adding the word

‘‘emission’’ before ‘‘monitoring system’’

in the first sentence, by removing each

occurrence of the words ‘‘or

component’’ in the paragraph, and by

adding a new final sentence.

The revisions and additions read as

follows:

§ 97.72 Out of control periods.

* * * * *

(b) * * * The owner or operator shall

follow the initial certification or

recertification procedures in § 97.71 for

each disapproved system.

86. Section 97.74 is amended by

revising paragraphs (a)(1), (d)(1), and

(d)(2)(ii); to read as follows:

§ 97.74 Recordkeeping and reporting.

(a) * * *

(1) The NOX authorized account

representative shall comply with all

recordkeeping and reporting

requirements in this section, with the

Federal Register / Vol. 66, No. 114 / Wednesday, June 13, 2001 / Proposed Rules 32049

recordkeeping and reporting

requirements under § 75.73 of this

chapter, and with the requirements of

§ 97.10(e)(1).

* * * * *

(d) * * *

(1) If a unit is subject to an Acid Rain

emission limitation or if the owner or

operator of the NOX budget unit chooses

to meet the annual reporting

requirements of this subpart H, the NOX

authorized account representative shall

submit a quarterly report, documenting

the NOX mass emissions from the unit,

for each calendar quarter beginning

with:

(i) For a unit for which the owner or

operator intends to apply or applies for

the early reduction credits under

§ 97.43, the calendar quarter that covers

May 1, 2000 through June 30, 2000. NOX

mass emission data shall be recorded

and reported from the first hour on May

1, 2000; or

(ii) For a unit that commences

operation before January 1, 2002 and

that is not subject to paragraph (d)(1)(i)

of this section, the calendar quarter

covering May 1, 2002 through June 30,

2002. NOX mass emission data shall be

recorded and reported from the first

hour on May 1, 2002; or

(iii) For a unit that commences

operation on or after January 1, 2002:

(A) The calendar quarter in which the

unit commences operation, if unit

operation commences during a control

period. NOX mass emission data shall be

recorded and reported from the date and

hour when the unit commences

operation; or

(B) The calendar quarter which

includes May 1 through June 30 of the

first control period following the date

on which the unit commences

operation, if the unit does not

commence operation during a control

period. NOX mass emission data shall be

recorded and reported from the first

hour on May 1 of that control period; or

(iv) A calendar quarter before the

quarter specified in paragraph (d)(1)(i),

(d)(1)(ii), or (d)(1)(iii)(B) of this section,

if the owner or operator elects to begin

reporting early under § 97.70(c)(3).

(2) * * *

(ii) Submit quarterly reports,

documenting NOX mass emissions from

the unit, only for the period from May

1 through September 30 of each year

and including the data described in

§ 75.74(c)(6) of this chapter. The NOX

authorized account representative shall

submit such quarterly reports, beginning

with:

(A) For a unit for which the owner or

operator intends to apply or applies for

early reduction credits under § 97.43,

the calendar quarter covering May 1,

2000 through June 30, 2000. NOX mass

emission data shall be recorded and

reported from first hour on May 1, 2000;

(B) For a unit that commences

operation before January 1, 2002 and

that is not subject to paragraph

(d)(2)(ii)(A)of this section, the calendar

quarter covering May 1 through June 30,

2002. NOX mass emission data shall be

recorded and reported from the first

hour of May 1, 2002;

(C) For a unit that commences

operation on or after January 1, 2002

and during a control period, the

calendar quarter in which the unit

commences operation. NOX mass

emission data shall be reported from the

date and hour corresponding to when

the unit commences operation; or (D)

For a unit that commences operation on

or after January 1, 2002 and not during

a control period, the calendar quarter

which includes May 1 through June 30

of the first control period after the unit

commences operation. NOX mass

emission data shall be recorded and

reported from the first hour on May 1

of the first control period after the unit

commences operation.

* * * * *

§ 97.87 [Amended]

87. Section 97.87 is amended in

second sentence of paragraph

(b)(1)(iii)(A) by adding the word ‘‘be’’

after the words ‘‘shall not’’.

88. Subpart J consisting of § 97.90 is

added to read as follows:

Subpart J—Appeal Procedures

§ 97.90 Appeal Procedures.

The appeal procedures for the NOX

Budget Trading Program are set forth in

part 78 of this chapter.

[FR Doc. 01–13142 Filed 6–12–01; 8:45 am]

BILLING CODE 6560–50–P