26510 Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations

ENVIRONMENTAL PROTECTION

AGENCY

40 CFR Parts 9, 72, and 75

[FRL–5203–3]

Acid Rain Program: Permits

Regulation General Provisions and

Continuous Emission Monitoring Rule

Technical Revisions

AGENCY: Environmental Protection

Agency (EPA).

ACTION: Direct final rule.

SUMMARY: Title IV of the Clean Air Act

(the Act), as amended by the Clean Air

Act Amendments of 1990, authorizes

the Environmental Protection Agency

(EPA or Agency) to establish the Acid

Rain Program. The program sets

emissions limitations to reduce acidic

deposition and its serious, adverse

effects on natural resources, ecosystems,

materials, visibility, and public health.

On January 11, 1993, the Agency

promulgated final rules under title IV.

Several parties filed petitions for review

of the rules. On April 17, 1995, the EPA

and the parties signed a settlement

agreement addressing continuous

emission monitoring (CEM) issues.

This direct final rule would amend

the Continuous Emission Monitoring

(CEM) provisions and the General

Provisions of the Acid Rain Program for

the purpose of making the

implementation of the program simpler,

streamlined, and more efficient for both

the EPA and industry. The rule

amendment is being issued as a direct

final rule because the corrections are

technical in nature and address various

implementation issues without major

changes in policy. Furthermore, the rule

amendments are consistent with the

April 17, 1995 settlement agreement.

Therefore, EPA believes these

amendments are noncontroversial and

has provided for the amendments to be

effective 60 days after publication in the

Federal Register.

DATES: Effective Dates. This final rule

will be effective July 17, 1995. However,

if significant adverse comments on

portions of the rule are received by June

16, 1995, then the effective date of those

provisions will be delayed, EPA will

withdraw those portions of the rule, and

timely notice will be published in the

Federal Register. Sections 75.50, 75.51

and 75.52; redesignated section 2.4.3.1

of appendix D of part 75; and sections

4.3.1, 4.3.2, 4.3.3, 4.4.3, 5.3. and 5.4 of

appendix F of part 75 are effective

through December 31, 1995. The

incorporation by reference of certain

publications listed in the regulation is

approved by the Director of the Federal

Register as of July 17, 1995.

Compliance Dates. Information on

compliance dates is in the

Supplementary Information section of

this preamble and in appendix J of part

75.

ADDRESSES: Any written comments

must be identified with Docket No. A–

94–16, must be identified as comments

on the direct final rule and companion

proposal, and must be submitted in

duplicate to: EPA Air Docket (6102),

Environmental Protection Agency, 401

M Street SW, Washington, DC 20460.

The docket is available for public

inspection and copying between 8:30

a.m. and 3:30 p.m., Monday through

Friday, at the address given above. A

reasonable fee may be charged for

copying. A detailed rationale for the

revisions is set forth in the technical

support document for the direct final

rule, which can be obtained by writing

to the Air Docket at the address given

above.

FOR FURTHER INFORMATION CONTACT:

Margaret Sheppard, Acid Rain Division

(6204J), U.S. Environmental Protection

Agency, 401 M Street SW, Washington,

DC 20460, telephone number (202) 233–

9180.

SUPPLEMENTARY INFORMATION: The EPA

is revising the CEM provisions as a

direct final rule without prior proposal

because the Agency views these

revisions as noncontroversial and

anticipates no significant adverse

comments. The EPA is also publishing

a companion proposed rule to this

direct final rule in this issue of the

Federal Register in order to take

comment on provisions of the direct

final rule. If EPA does receive

significant adverse comments, EPA will

publish a document in the Federal

Register withdrawing portions of the

direct final rule. In addition, EPA is

publishing an interim final rule in

today’s Federal Register to address

other monitoring issues that may be

controversial. The EPA will not institute

a second comment period on the

proposed rule, on the interim final rule,

or on any subsequent final rule. Any

parties interested in commenting on

these revisions to parts 72 and 75

should do so at this time.

Significant adverse comment will be

addressed in a subsequent final

rulemaking document. If EPA

withdraws portions of the direct final

rule, EPA will accept comments for 15

days after publication of the notice of

withdrawal in order to receive

additional comments on withdrawn

portions of the rule. If the effective date

is delayed, timely notice will be

published in the Federal Register.

The owner or operator shall comply

with the following requirements from

July 17, 1995 through December 31,

1995: for the recordkeeping

requirements of subpart F of part 75, by

following either §§ 75.50, 75.51 and

75.52 or §§ 75.54, 75.55 and 75.56; for

the missing data substitution

requirements for carbon dioxide (CO2)

and heat input, by following either

§§ 75.35 and 75.36 or sections 4.3.1

through 4.3.3, section 4.4.3 and section

5.3 and 5.4 of appendix F of part 75; and

for the missing data substitution

requirements for fuel flowmeters by

following either section 2.4.3.1 or

sections 2.4.3.2 and 2.4.3.3 of appendix

D of part 75.

On or after January 1, 1996, the owner

or operator shall comply with the

following requirements: for the

recordkeeping requirements of subpart F

of part 75, by meeting the requirements

of §§ 75.54, 75.55, and 75.56; and for the

missing data substitution requirements

for CO2 concentration, heat input and

fuel flowmeters by meeting the

requirements of §§ 75.35 and 75.36 and

sections 2.4.3.2 through 2.4.3.3 of

appendix D of part 75.

The EPA has been engaged in

settlement discussions with several

parties who challenged certain

provisions of the Acid Rain CEM rules

promulgated on January 11, 1993. [See

Environmental Defense Fund v.

Browner, No. 93–1203 and consolidated

cases, ‘‘Complex’’ (D.C. Cir. filed March

12, 1993).] Although the parties have

been able to reach agreement on a

number of issues, which are addressed

in this direct final rulemaking, some

additional issues remain outstanding.

The outstanding issues, unlike the

noncontroversial and routine technical

corrections and other amendments

addressed by this direct final rule, may

not be considered noncontroversial and

therefore are being addressed separately

in an interim final rule, published

elsewhere in this Federal Register.

I. Acid Rain Program Background

A. Rulemaking Background

On January 11, 1993, EPA

promulgated the ‘‘core’’ regulations that

implemented the major provisions of

title IV of the Clean Air Act (CAA or the

Act), as amended November 15, 1990,

including the General Provisions of the

Permits Regulation (40 CFR part 72) and

the CEM regulation at 40 CFR part 75

authorized under Sections 412 and 821

of the Act. The CEM rule specifies how

each affected utility unit must install a

system to continuously monitor the
Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations 26511

emissions and to collect, record, and

report emissions data to ensure that the

mandated reductions in sulfur dioxide

(SO2) and nitrogen dioxide (NOX)

emissions are achieved, that opacity and

CO2 emissions are measured, and that

SO2 emissions are accurately measured

so that the allowance system functions

in an orderly manner. Technical

corrections were published on June 23,

1993 and July 30, 1993. An amendment

to the certification deadline for NOX and

CO2 monitoring for oil-fired units and

gas-fired units was published on August

18, 1994.

Since the CEM rule was promulgated,

the operation of Phase I utility units

have essentially completed the first

stage of implementation of the rule,

having submitted monitoring plans,

conducted certification testing,

submitted certification applications, and

submitted their first quarterly reports. In

addition, many Phase II utility units

also have begun implementation. During

early implementation, many technical

issues have been raised, including many

minor issues which could be addressed

by technical corrections. The preamble

discussion that follows outlines the

changes that are contained in today’s

direct final rulemaking that will make

these technical corrections.

B. Implementation Background

The EPA held three Acid Rain

Implementation Conferences (January

5–6, 1993; January 25–26, 1993; and

March 16–17, 1993). In these public

meetings, EPA staff presented an

overview of the Acid Rain Program and

Acid Rain core rules. Some of the

changes in today’s revised rule resulted

from issues raised by the public at these

conferences.

In order to respond to a multitude of

questions raised by industry, EPA

instituted a new ‘‘Acid Rain

monitoring’’ section on the Agency’s

computerized Technology Transfer

Network Bulletin Board System

(TTNBBS). This bulletin board can be

accessed by computer modem at (919)

541–5742. The EPA’s Acid Rain

Division periodically updates this

section of the bulletin board with

notices of meetings, interpretations of

part 75, policy determinations, and

other information relevant to State

environmental regulators and the

regulated community. In particular, EPA

has published three installments of

commonly asked questions and their

answers in the ‘‘Acid Rain CEM (Part

75) Policy Manual’’ (Docket Item I–D–

54). Many of these policy

determinations and clarifications of part

75 are incorporated into today’s revised

rule.

Some standard forms have been

revised to be consistent with the

changes in this rulemaking. Packages of

revised standard forms, with

instructions, will contain revised

monitoring plan forms, certification

forms, and electronic data reporting

format, and will be available from EPA

in electronic form from the TTNBBS by

using computer modem at (919) 541–

5742 or on paper by calling the Acid

Rain Hotline at (202) 233–9620.

II. Changes to Parts 72 and 75—General

Provisions of the Permits Regulation

and Continuous Emission Monitoring

Several of the definitions in § 72.2

related to monitoring have been revised.

As explained below, EPA edited these

definitions and added a few definitions

to explain or clarify new or existing

terms in part 75.

The changes to part 75 are

clarifications intended to ease

implementation, and do not constitute

major policy changes. The most

significant changes in today’s revised

part 75 concern deadlines for

completing certification testing, the

procedures for exceptions to the use of

CEMS found in appendices D and E,

and the provisions for determining the

span of NOX pollutant concentration

monitors. The EPA has added to the list

of certification testing deadlines to

apply to more types of units that might

require certification after the statutory

deadline for installation of CEMS. In

addition, the Agency rewrote major

portions of appendices D and E to make

them easier to understand and to

implement. Changes to appendix E also

substantially reduce the time and

difficulty of testing required to obtain

NOX emission rate data. Finally, the

procedures for determining NOX span

have been revised so that utilities with

units having low NOX emission rates

may select a single span representative

of the situation at their plant, rather

than being required to use both a high

scale and a low scale measurement

range. A list of compliance dates for the

revised recordkeeping requirements and

missing data substitution procedures are

included in the new appendix J.

The rationale and effect of the

revisions to parts 72 and 75 are

discussed in detail in a technical

support document. This document may

be obtained from the EPA Air Docket as

Docket Item II–F–2, ‘‘Technical Support

Document (Attachment A),’’ in Docket

No. A–94–16. In addition, EPA is

publishing this document under the

CAA Title IV portion of EPA’s TTNBBS.

This bulletin board can be accessed by

computer modem at (919) 541–5742.

The topics in the rule revisions

discussed in the Technical Support

Document are as follows:

I. Glossary of Terms and Abbreviations

II. Acid Rain Program Background

A. Rulemaking Background

B. Implementation Background

III. Changes to Part 72—Permits Regulation

General Provisions

A. Fuel-related Definitions

B. Operating Hour Definitions

C. Calibration Gas Definitions

D. Bypass Operating Quarter, Unit

Operating Quarter

E. Ozone Nonattainment Area, Ozone

Transport Region

F. Other Definitions

IV. Changes to Part 75—Continuous Emission

Monitoring

A. General Revisions

B. Changes to Subpart A, General

1. Certification Deadlines

a. Shutdown Units

b. New Stacks or Flue Gas Desulfurization

Systems

c. Backup Fuel and Emergency Fuel

d. Newly Affected Units

e. EIA Forms

f. Emissions Accounting Prior to

Certification

2. Incorporation by Reference

3. Relative Accuracy and Availability

Performance Analysis

C. Changes to Subpart B, Monitoring

Provisions

1. Calculation of Average Emissions and

Opacity Data

2. Peaking Unit Definition and

Applicability of Appendix E

3. SO2 Monitoring During Combustion of

Gas for Units With SO2 CEMS

4. Monitoring Common Stacks, Bypass

Stacks, and Multiple Stacks

a. Common Stack Monitoring

b. Multiple Stacks—NOXMonitoring

c. Bypass Stack Monitoring

5. Determining Emissions From Qualifying

Phase I Technologies

D. Changes to Subpart C, Operation and

Maintenance Requirements

1. Certification Procedures for CEMS

a. Initial Certification and Recertification

b. Loss of Certification Procedures

c. Submission and Retesting Deadlines

d. Audit Decertification

e. Monitoring Systems To Be Certified

f. Use of Backup or Portable Monitoring

Systems

2. Certification Procedures for Alternative

Monitoring Systems

3. Certification Procedures for Excepted

Monitoring Systems

E. Changes to Subpart D, Missing Data

Procedures

1. Missing Data Procedures for Peaking

Units

2. Addition to NOX and Flow Missing Data

Procedures

3. Changes to CO2 and Heat Input

Procedures

4. Missing Data Procedures for Units With

Add-on Emission Controls

5. SO2 Concentration Missing Data During

Gas Combustion

F. Changes to Subpart E, Alternative

Monitoring Systems
26512 Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations

G. Changes to Subpart F, Recordkeeping

Requirements

1. Additional Sections 75.54, 75.55 and

75.56

2. Changes to Emission Data Records

3. Certification Records

4. Monitoring Plans

5. Records File

H. Changes to Subpart G, Reporting

Requirements

1. Notifications to EPA and State Agencies

2. Information Not Reported to EPA

3. Effective Date of Revised Reporting

Requirements

4. Petitions to the Administrator

5. Confidentiality of Data

6. Reporting Addresses

I. Changes to Appendix A, Specifications

and Testing Procedures

1. Changes to Span Requirements

a. Span for SO2 Pollutant Concentration

Monitors

b. Span for NOX Pollutant Concentration

Monitors

c. Changes to Span

2. Clarification of Certification Test

Procedures

a. Calibration Error Test

b. Cycle Time Test

c. Relative Accuracy Test for NOX

d. RATAs for CO2 and O2

3. Calibration Gases

4. Changes to Appendix B, Quality

Assurance and Quality Control

Procedures

5. Periodic RATAs for Monitors on Peaking

Units and Bypass Stacks

6. Incentive Standard and Out-of-Control

for CO2 Monitors

7. Incentive Standard for NOX Low

Emitters

8. Quality Assurance of Data Following

Daily Calibration Error Test

9. Recalibration

10. Calibration Gas for Linearity Checks

J. Changes to Appendix C, Missing Data

Statistical Estimation Procedures

1. Changes to Parametric Monitoring

Procedure for Missing Data

2. Clarifications of Load-Based Procedure

for Missing Flow Rate and NOX Emission

Rate Data

K. Changes to Appendix D, Optional SO2

Emission Protocol for Gas-fired and Oilfired Units

1. Gaseous Fuels Other Than Natural Gas

2. SO2 Emissions From Natural Gas

3. Fuel Flowmeter Installation

Requirements

4. Gas Flowmeter Accuracy

5. Fuel Flowmeter Calibration and Quality

Assurance Requirements

6. Fuel Sampling for Diesel Fuel

7. Turnaround Time for Fuel Analysis

8. Missing Data Procedures

9. Heat Input

L. Changes to Appendix E, Optional NOX

Emission Estimation Protocol for Gasfired Peaking Units and Oil-fired Peaking

Units

1. Testing by Fuel

2. Heat Input as Unit Operating Load

3. Number of Load Levels

4. Tests by Excess O2 Level

5. Efficiency Testing

6. Stack Testing Procedures

7. Quality Assurance and Quality Control

Parameters

8. Emergency Fuel Provisions

M. Changes to Appendix F, Conversion

Procedures

1. Heat Input

2. Diluent Cap Values

3. NOX and SO2 Conversion Procedures

N. Changes to Appendix G, Determination

of CO2 Emissions

III. Impact Analyses

A. Paperwork Reduction Act

The information collection

requirements in this rule have been

approved by the Office of Management

and Budget (OMB) under the Paperwork

Reduction Act, 44 U.S.C. 3501 et seq.

and have been assigned control number

2060–0258.

This collection of information has an

estimated reporting burden averaging 40

hours per response and an estimated

annual recordkeeping burden averaging

160 hours per respondent. These

estimates include time for reviewing

instructions, searching existing data

sources, gathering and maintaining the

data needed, and completing and

reviewing the collection of information.

The control numbers assigned to

collections of information in certain

EPA regulations by the OMB have been

consolidated under 40 CFR part 9. The

EPA finds there is ‘‘good cause’’ under

Sections 553(b)(B) and 553(d)(3) of the

Administrative Procedure Act to amend

the applicable table in 40 CFR part 9 to

display the OMB control number for

this rule without prior notice and

comment. Due to the technical nature of

the table, further notice and comment

would be unnecessary. For additional

information, see 58 FR 18014, April 7,

1993, and 58 FR 27472, May 10, 1993.

Send comments regarding the burden

estimate or any other aspect of this

collection of information, including

suggestions for reducing this burden to

Chief, Information Policy Branch; EPA;

401 M St., SW (Mail Code 2136);

Washington, DC 20460; and to the

Office of Information and Regulatory

Affairs, Office of Management and

Budget, Washington, DC 20503, marked

‘‘Attention: Desk Officer for EPA.’’

B. Executive Order Requirements

1. Executive Order 12866

Under Executive Order 12866 (58 FR

51735, October 4, 1993), the Agency

must determine whether the regulatory

action is ‘‘significant’’ and therefore

subject to 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.

Pursuant to the terms of Executive

Order 12866, OMB has notified EPA

that it considers this a ‘‘significant

regulatory action’’ within the meaning

of the Executive Order. The EPA has

submitted this action to OMB for

review. Changes made in response to

OMB suggestions or recommendations

will be documented in the public

record.

The revisions to part 75 slightly

decrease the overall cost of compliance

for the regulated community. Therefore,

the Agency did not prepare a Regulatory

Impact Analysis (RIA). Revisions to

appendix D of part 75, ‘‘Optional SO2

Emissions Data Protocol for Gas-Fired

and Oil-Fired Units,’’ reduce the

frequency of sampling and analysis of

diesel fuel, reducing the cost of SO2

monitoring for units using No. 2 fuel oil

as a backup fuel. Revisions to appendix

E of part 75, ‘‘Optional NOX Emission

Estimation Protocol for Gas-Fired

Peaking Units and Oil-Fired Peaking

Units,’’ reduce the amount of testing for

gas-fired peaking units and oil-fired

peaking units using this optional

procedure. A small gas-fired or oil-fired

peaking unit using appendix D or

appendix E would have monitoring

costs reduced by 10 to 40 percent from

the cost of the promulgated rule of

January 11, 1993.

2. Executive Order 12875

Executive Order 12875 generally

prohibits Agencies from issuing

regulations not required by statute that

impose mandates on State, local, and

tribal governments unless federal

funding is provided for the direct costs

of compliance or the Agency, after

consultation with the affected entities,

justifies the need for an unfunded

mandate. Clean Air Act Section 412(a)

required EPA to issue regulations

specifying requirements for CEMS and

alternative monitoring systems, as well

as for recordkeeping and reporting of
Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations 26513

information from such systems. This

direct final rule revises the regulation

required under Section 412(a) in order

to address various issues that have come

to light during early implementation

and is therefore a statutorily-required

regulation. In addition, as discussed

above, the revisions to the regulation do

not impose additional costs, but rather

slightly decrease the overall cost of

compliance for the regulated

community. Therefore, the revisions

meet the requirements of Executive

Order 12875.

C. Regulatory Flexibility Act

Pursuant to Section 605(b) of the

Regulatory Flexibility Act, 5 U.S.C.

605(b), the Administrator certifies on

April 28, 1995 that this rule revision

will not have a significant economic

impact on a substantial number of small

entities.

The EPA performed an analysis of the

effects upon small utilities of the Acid

Rain core rules (58 FR 3649, January 11,

1993), including permitting, allowances,

and continuous emission monitoring.

The earlier document concluded that

significant costs would occur to small

utilities as a result of statutory

requirements. For example, based upon

a worst case for model utilities, total

regulatory costs could represent as

much as 6 to 7 percent of the average

value of electricity produced in the year

2000. About one-third of the 105 small

utilities currently affected could face

impacts of up to this magnitude.

Today’s revisions to part 75 have a

beneficial impact on small entities by

reducing the burden of complying with

the Acid Rain Program monitoring

requirements for approximately 800

small utility units. Revisions to

appendix D of part 75 reduce the

frequency of sampling and analysis of

diesel fuel, reducing the cost of SO2

monitoring for units using diesel fuel

(No. 2 fuel oil) as a backup fuel. The

EPA estimates that this will reduce the

cost of complying with monitoring

requirements by 15 percent per year for

SO2 monitoring for units using diesel

fuel. Revisions to appendix E of part 75

reduce the amount of testing for gasfired peaking units and oil-fired peaking

units. The EPA estimates that these

changes will reduce the cost of

appendix E testing by one-third for

boilers and by one-tenth for stationary

gas turbines and diesel reciprocating

engines. A small gas-fired or oil-fired

peaking unit monitoring using appendix

D or appendix E would have monitoring

costs reduced by 10 to 40 percent from

the cost of the promulgated rule of

January 11, 1993.

D. Unfunded Mandates Act

Section 202 of the Unfunded

Mandates Reform Act of 1995

(‘‘Unfunded Mandates Act’’) (signed

into law on March 22, 1995) requires

that the Agency prepare a budgetary

impact statement before promulgating a

rule that includes a Federal mandate

that may result in expenditure by State,

local, and tribal governments, in

aggregate, or by the private sector, of

$100 million or more in any one year.

Section 203 requires the Agency to

establish a plan for obtaining input from

and informing, educating, and advising

any small governments that may be

significantly or uniquely affected by the

rule.

Under section 205 of the Unfunded

Mandates Act, the Agency must identify

and consider a reasonable number of

regulatory alternatives before

promulgating a rule for which a

budgetary impact statement must be

prepared. The Agency must select from

those alternatives the least costly, most

cost-effective, or least burdensome

alternative that achieves the objectives

of the rule, unless the Agency explains

why this alternative is not selected or

why the selection of this alternative is

inconsistent with law.

Because this direct final rule and its

associated proposed and interim final

rules are estimated to have an impact of

less than $100 million in any one year,

the Agency has not prepared a

budgetary impact statement or

specifically addressed the selection of

the least costly, most cost-effective, or

least burdensome alternative. Because

small governments will not be

significantly or uniquely affected by the

revisions to parts 72 and 75, the Agency

is not required to develop a plan with

regard to small governments. However,

as discussed in this preamble, the rule

revisions have the net effect of reducing

the burden of part 75 of the Acid Rain

regulations on regulated entities,

including both investor-owned and

State and municipally-owned utilities.

List of Subjects in 40 CFR Parts 9, 72,

and 75

Environmental protection, Air

pollution control, Carbon dioxide,

Continuous emission monitors, Electric

utilities, Incorporation by reference,

Nitrogen oxides, Reporting and

recordkeeping requirements, Sulfur

dioxide.

Dated: April 28, 1995.

Carol M. Browner,

Administrator.

For the reasons set out in the

preamble, parts 9, 72, and 75 of title 40,

chapter I, of the Code of Federal

Regulations are amended as follows:

PART 9—OMB APPROVALS UNDER

THE PAPERWORK REDUCTION ACT

1. The authority citation for part 9

continues to read as follows:

Authority: 7 U.S.C. 135 et seq., 136–136y;

15 U.S.C. 2001, 2003, 2005, 2006, 2601–2671;

21 U.S.C. 331j, 346a, 348; 31 U.S.C. 9701; 33

U.S.C. 1251 et seq., 1311, 1313d, 1314, 1321,

1326, 1330, 1344, 1345 (d) and (e), 1361; E.O.

11735, 58 FR 21243, 3 CFR, 1971–1975

Comp. p. 973; 42 U.S.C. 241, 242b, 243, 246,

300f, 300g, 300g-1, 300g-2, 300g-3, 300g-4,

300g-5, 300g-6, 300j-1, 300j-2, 300j-3, 300j-4,

300j-9, 1857 et seq., 6901–6992k, 7401–

7767q, 7542, 9601–9657, 11023, 11048.

2. The table in § 9.1 under the heading

‘‘Continuous Emission Monitoring’’ by

removing the entries for ‘‘§§ 75.50

through 75.53’’ and by adding entries

for ‘‘§§ 75.50 through 75.52’’ and

‘‘§§ 75.53 through 75.56’’ to read as

follows:

§ 9.1 OMB approvals under the Paperwork

Reduction Act.

* * * * *

40 CFR Citation OMB Control No.

* * * * *

Continuous Emission Monitoring

* * * * *

75.50–75.52 .............................. 2060–0258

75.53–75.56 .............................. 2060–0258

* * * * *

PART 72—PERMITS REGULATION

3. The authority citation for part 72

continues to read as follows:

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

Subpart A—Acid Rain Program

General Provisions

4. Section 72.2 is amended by revising

the definitions of ‘‘Calibration gas’’,

‘‘Capacity factor’’, ‘‘Diesel fuel’’, ‘‘Gasfired’’, ‘‘Maximum potential NOx

emission rate’’, ‘‘Monitor operating

hour’’, ‘‘Natural gas’’, ‘‘Oil-fired’’,

‘‘Peaking unit’’, ‘‘Quality assured

monitoring operating hour’’, ‘‘Stationary

gas turbine’’ and ‘‘Unit operating

hours’’, and by adding, in alphabetical

order, new definitions for ‘‘Backup

fuel’’, ‘‘By-pass operating quarter’’,

‘‘Diesel-fired unit’’, ‘‘Emergency fuel’’,

‘‘Excepted monitoring system’’, ‘‘Flue

gas desulfurization system’’, ‘‘Gaseous

fuel’’, ‘‘Hour before and after’’, ‘‘NIST

traceable reference material’’, ‘‘Ozone

nonattainment area’’, ‘‘Ozone transport

region’’, ‘‘Pipeline natural gas’’,
26514 Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations

‘‘Research gas material’’, ‘‘Unit

operating day’’, and ‘‘Unit operating

quarter’’; and by removing the definition

of ‘‘zero ambient air material’’ and

adding a definition of ‘‘zero air

material’’ to read as follows:

§ 72.2 Definitions.

* * * * *

Backup fuel means a fuel for a unit

where: (1) For purposes of the

requirements of the monitoring

exception of appendix E of part 75 of

this chapter, the fuel provides less than

10.0 percent of the heat input to a unit

during the three calendar years prior to

certification testing for the primary fuel

and the fuel provides less than 15.0

percent of the heat input to a unit in

each of those three calendar years; or

the Administrator approves the fuel as

a backup fuel; and (2) For all other

purposes under the Acid Rain Program,

a fuel that is not the primary fuel

(expressed in mmBtu) consumed by an

affected unit for the applicable calendar

year.

* * * * *

Bypass operating quarter means a

calendar quarter during which

emissions pass through a stack, duct or

flue that bypasses add-on emission

controls.

* * * * *

Calibration gas means: (1) a standard

reference material; (2) a NIST traceable

reference material; (3) a Protocol 1 gas;

(4) a research gas material; or (5) zero air

material.

Capacity factor means either: (1) the

ratio of a unit’s actual annual electric

output (expressed in MWe-hr) to the

unit’s nameplate capacity times 8760

hours, or (2) the ratio of a unit’s annual

heat input (in million British thermal

units or equivalent units of measure) to

the unit’s maximum design heat input

(in million British thermal units per

hour or equivalent units of measure)

times 8,760 hours.

* * * * *

Diesel-fired unit means, for the

purposes of part 75 of this chapter, an

oil-fired unit that combusts diesel fuel

as its fuel oil, where the supplementary

fuel, if any, shall be limited to natural

gas or gaseous fuels containing no more

sulfur than natural gas.

Diesel fuel means a low sulfur fuel oil

of grades 1–D or 2–D, as defined by the

American Society for Testing and

Materials standard ASTM D975–91,

‘‘Standard Specification for Diesel Fuel

Oils,’’ grades 1–GT or 2–GT, as defined

by ASTM D2880–90a, ‘‘Standard

Specification for Gas Turbine Fuel

Oils,’’ or grades 1 or 2, as defined by

ASTM D396–90, ‘‘Standard

Specification for Fuel Oils’’

(incorporated by reference in § 72.13).

* * * * *

Emergency fuel means either:

(1) For purposes of the requirements

for a fuel flowmeter used in an excepted

monitoring system under appendix D or

E of part 75 of this chapter, the fuel

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; or

(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 the State, local, or Federal

permit for a plant and is 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,

as established in a petition under

§ 75.66 of this chapter.

* * * * *

Excepted monitoring system means a

monitoring system that follows the

procedures and requirements of

appendix D or E of part 75 of this

chapter for approved exceptions to the

use of continuous emission monitoring

systems.

* * * * *

Flue gas desulfurization system

means a type of add-on emission control

used to remove sulfur dioxide from flue

gas, commonly referred to as a

‘‘scrubber.’’

* * * * *

Gaseous fuel means a material that is

in the gaseous state at standard

atmospheric temperature and pressure

conditions and that is combusted to

produce heat.

* * * * *

Gas-fired means:

(1) The combustion of:

(i) Natural gas or other gaseous fuel

(including coal-derived gaseous fuel),

for at least 90.0 percent of the unit’s

average annual heat input during the

previous three calendar years and for at

least 85.0 percent of the annual heat

input in each of those calendar years;

and

(ii) Any fuel other than coal or coalderived fuel (other than coal-derived

gaseous fuel) for the remaining heat

input, if any; provided that for purposes

of part 75 of this chapter, any fuel used

other than natural gas, shall be limited

to:

(A) Gaseous fuels containing no more

sulfur than natural gas; or

(B) Fuel oil.

(2) For purposes of part 75 of this

chapter, a unit may initially qualify as

gas-fired under the following

circumstances:

(i) If the designated representative

provides fuel usage data for the unit for

the three calendar years immediately

prior to submission of the monitoring

plan, and if the unit’s fuel usage is

projected to change on or before January

1, 1995, the designated representative

submits a demonstration satisfactory to

the Administrator that the unit will

qualify as gas-fired under the first

sentence of this definition using the

years 1995 through 1997 as the three

calendar year period; or

(ii) If a unit does not have fuel usage

data for one or more of the three

calendar years immediately prior to

submission of the monitoring plan, the

designated representative submits:

(A) The unit’s designed fuel usage;

(B) Any fuel usage data, beginning

with the unit’s first calendar year of

commercial operation following 1992;

(C) The unit’s projected fuel usage for

any remaining future period needed to

provide fuel usage data for three

consecutive calendar years; and

(D) Demonstration satisfactory to the

Administrator that the unit will qualify

as gas-fired under the first sentence of

this definition using those three

consecutive calendar years as the three

calendar year period.

* * * * *

Hour before and 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, or hourly NOX emission rate

recorded by a certified monitor during

the unit operating hour immediately

before and the unit operating hour

immediately after a missing data period.

Maximum potential NOX emission

rate means the emission rate of nitrogen

oxides (in lb/mmBtu) calculated in

accordance with section 3 of appendix

F of part 75 of this chapter, using the

maximum potential nitrogen oxides

concentration as defined in section 2 of

appendix A of 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.

* * * * *

Monitor operating hour means any

unit operating hour or portion thereof

over which a CEMS, or other monitoring

system approved by the Administrator

under part 75 of this chapter is

operating, regardless of the number of

measurements (i.e., data points)
Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations 26515

collected during the hour or portion of

an hour.

* * * * *

Natural gas means a naturally

occurring fluid mixture of hydrocarbons

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

containing 1 grain or less hydrogen

sulfide per 100 standard cubic feet, and

20 grains or less total sulfur per 100

standard cubic feet), produced in

geological formations beneath the

Earth’s surface, and maintaining a

gaseous state at standard atmospheric

temperature and pressure under

ordinary conditions.

* * * * *

NIST traceable reference material

(NTRM) means a calibration gas mixture

tested by and certified by the National

Institutes of Standards and

Technologies (NIST) to have a certain

specified concentration of gases. NTRMs

may have different concentrations from

those of standard reference materials.

* * * * *

Oil-fired means:

(1) The combustion of:

(i) Fuel oil for more than 10.0 percent

of the average annual heat input during

the previous three calendar years or for

more than 15.0 percent of the annual

heat input during any one of those

calendar years; and

(ii) Any solid, liquid, or gaseous fuel

(including coal-derived gaseous fuel),

other than coal or any other coal derived

fuel, for the remaining heat input, if

any; provided that for purposes of part

75 of this chapter, any fuel used other

than fuel oil shall be limited to gaseous

fuels containing no more sulfur than

natural gas.

(2) For purposes of part 75 of this

chapter, a unit that does not have fuel

usage data for one or more of the three

calendar years immediately prior to

submission of the monitoring plan may

initially qualify as oil-fired under the

following circumstances: the designated

representative submits:

(i) Unit design fuel usage,

(ii) The unit’s designed fuel usage,

(iii) Any fuel usage data, beginning

with the unit’s first calendar year of

commercial operation following 1992,

(iv) The unit’s projected fuel usage for

any remaining future period needed to

provide fuel usage data for three

consecutive calendar years, and

(v) A demonstration satisfactory to the

Administrator that the unit will qualify

as oil-fired under the first sentence of

this definition using those three

consecutive calendar years as the three

calendar year period.

* * * * *

Ozone nonattainment area means an

area designated as a nonattainment area

for ozone under subpart C of part 81 of

this chapter.

Ozone transport region means the

ozone transport region designated under

Section 184 of the Act.

* * * * *

Peaking unit means:

(1) A unit that has:

(i) An average capacity factor of no

more than 10.0 percent during the

previous three calendar years and

(ii) A capacity factor of no more than

20.0 percent in each of those calendar

years.

(2) For purposes of part 75 of this

chapter, a unit may initially qualify as

a peaking unit under the following

circumstances:

(i) If the designated representative

provides capacity factor data for the unit

for the three calendar years immediately

prior to submission of the monitoring

plan and if the unit’s capacity factor is

projected to change on or before the

certification deadline for NOX

monitoring in § 75.4 of this chapter, the

designated representative submits a

demonstration satisfactory to the

Administrator that the unit will qualify

as a peaking unit under the first

sentence of this definition using the

three calendar years beginning with the

year of the certification deadline for

NOX monitoring in § 75.4 of this chapter

(either 1995 or 1996) as the three year

period; or

(ii) If the unit does not have capacity

factor data for any one or more of the

three calendar years immediately prior

to submission of the monitoring plan,

the designated representative submits:

(A) Any capacity factor data,

beginning with the unit’s first calendar

year of commercial operation following

the first year of the three calendar years

immediately prior to the certification

deadline for NOX monitoring in § 75.4 of

this chapter (either 1992 or 1993),

(B) Capacity factor information for the

unit for any remaining future period

needed to provide capacity factor data

for three consecutive calendar years,

and

(C) A demonstration satisfactory to

the Administrator that the unit will

qualify as a peaking unit under the first

sentence of this definition using the

three consecutive calendar years

specified in (2) (ii) (A) and (B) as the

three calendar year period.

* * * * *

Pipeline natural gas means natural

gas that is provided by a supplier

through a pipeline.

* * * * *

Quality-assured monitor operating

hour means any unit operating hour or

portion thereof over which a certified

CEMS, or other monitoring system

approved by the Administrator under

part 75 of this chapter, is operating:

(1) Within the performance

specifications set forth in part 75,

appendix A of this chapter and the

quality assurance/quality control

procedures set forth in part 75,

appendix B of this chapter, without

unscheduled maintenance, repair, or

adjustment; and

(2) In accordance with § 75.10(d), (e),

and (f) of this chapter.

* * * * *

Research gas material (RGM) means a

calibration gas mixture developed by

agreement of a requestor and the

National Institutes for Standards and

Technologies (NIST) that NIST analyzes

and certifies as ‘‘NIST traceable.’’ RGMs

may have concentrations different from

those of standard reference materials.

* * * * *

Stationary gas turbine means a

turbine that is not self-propelled and

that combusts natural gas, other gaseous

fuel with a sulfur content no greater

than natural gas, or fuel oil in order to

heat inlet combustion air and thereby

turn a turbine, in addition to or instead

of producing steam or heating water.

* * * * *

Unit operating day means a calendar

day in which a unit combusts any fuel.

Unit operating hour means any hour

(or fraction of an hour) during which a

unit combusts any fuel.

Unit operating quarter means a

calendar quarter in which a unit

combusts any fuel.

* * * * *

Zero air material means either: (1) a

calibration gas certified by the gas

vendor not to contain concentrations of

either SO2, NOΧ, or total hydrocarbons

above 0.1 parts per million (ppm); a

concentration of CO above 1 ppm; and

a concentration of CO2 above 400 ppm,

or (2) ambient air conditioned and

purified by a continuous emission

monitoring system for which the

continuous emission monitoring system

manufacturer or vendor certifies that the

particular continuous emission

monitoring system model produces

conditioned gas that does not contain

concentrations of either SO2 or NOΧ

above 0.1 ppm or CO2 above 400 ppm;

and that does not contain

concentrations of other gases that

interfere with instrument readings or

cause the instrument to read

concentrations of SO2, NOΧ, or CO2 for

a particular continuous emission

monitoring system model.

* * * * *

5. Section 72.13 is amended by

redesignating paragraphs (a)(8) and
26516 Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations

(a)(9) as (a)(9) and (a)(10), and by adding

paragraph (a)(8), and by revising newly

designated paragraphs (a)(9) and (a)(10)

to read as follows:

§ 72.13 Incorporation by reference.

* * * * *

(8) ASTM D2880–90a, Standard

Specification for Gas Turbine Fuel Oils,

for § 72.2 of this part.

(9) ASTM D4057–88, Standard

Practice for Manual Sampling of

Petroleum and Petroleum Products, for

§ 72.7 of this part.

(10) ASTM D4294–90, Standard Test

Method for Sulfur in Petroleum

Products by Energy-Dispersive X-Ray

Fluorescence Spectroscopy, for § 72.7 of

this part.

* * * * *

PART 75—CONTINUOUS EMISSIONS

MONITORING

6–7. The authority citation for part 75

is revised to read as follows:

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

§ 75.2 [Amended]

8. Section 75.2 is amended by

removing paragraph (b)(4).

9. Section 75.4 is amended by revising

the last sentence of paragraph (a)

introductory text and by revising

paragraphs (a)(1), (a)(2), (a)(3), (a)(4), (b),

(c), and (d), by redesignating and

revising paragraph (e) as paragraph (h)

and by adding new paragraphs (e), (f),

and (g) to read as follows:

§ 75.4 Compliance dates.

(a) * * * In accordance with § 75.20,

the owner or operator of each existing

affected unit shall ensure that all

monitoring systems required by this part

for monitoring SO2, NOΧ, CO2, opacity,

and volumetric flow are installed and

all certification tests are completed not

later than the following dates (except as

provided in paragraphs (d) through (h)

of this section):

(1) For a unit listed in Table 1 of

§ 73.10(a) of this chapter, November 15,

1993.

(2) For a substitution or a

compensating unit that is designated

under an approved substitution plan or

reduced utilization plan pursuant to

§ 72.41 or § 72.43 of this chapter, or for

a unit that is designated an early

election unit under an approved NOΧ

compliance plan pursuant to part 76 of

this chapter, that is not conditionally

approved and that is effective for 1995,

the earlier of the following dates:

(i) January 1, 1995; or

(ii) 90 days after the issuance date of

the Acid Rain permit (or date of

approval of permit revision) that

governs the unit and contains the

approved substitution plan, reduced

utilization plan, or NOΧ compliance

plan.

(3) For either a Phase II unit, other

than a gas-fired unit or an oil-fired unit,

or a substitution or compensating unit

that is not a substitution or

compensating unit under paragraph

(a)(2) of this section: January 1, 1995.

(4) For a gas-fired Phase II unit or an

oil-fired Phase II unit, January 1, 1995,

except that installation and certification

tests for continuous emission

monitoring systems for NOΧ and CO2 or

excepted monitoring systems for NOΧ

under appendix E or CO2 estimation

under appendix G of this part shall be

completed as follows:

(i) For an oil-fired Phase II unit or a

gas-fired Phase II unit located in an

ozone nonattainment area or the ozone

transport region, not later than July 1,

1995; or

(ii) For an oil-fired Phase II unit or a

gas-fired Phase II unit not located in an

ozone nonattainment area or the ozone

transport region, not later than January

1, 1996.

(5) * * *

(b) In accordance with § 75.20, the

owner or operator of each new affected

unit shall ensure that all monitoring

systems required under this part for

monitoring of SO2, NOΧ, CO2, opacity,

and volumetric flow are installed and

all certification tests are completed on

or before the later of the following dates:

(1) January 1, 1995, except that for a

gas-fired unit or oil-fired unit located in

an ozone nonattainment area or the

ozone transport region, the date for

installation and completion of all

certification tests for NOΧ and CO2

monitoring systems shall be July 1, 1995

and for a gas-fired unit or an oil-fired

unit not located in an ozone

nonattainment area or the ozone

transport region, the date for installation

and completion of all certification tests

for NOΧ and CO2 monitoring systems

shall be January 1, 1996; or

(2) Not later than 90 days after the

date the unit commences commercial

operation, notice of which date shall be

provided under subpart G of this part.

(c) In accordance with § 75.20, the

owner or operator of any unit affected

under any paragraph of § 72.6(a)(3) (ii)

through (vii) of this chapter shall ensure

that all monitoring systems required

under this part for monitoring of SO2,

NOΧ, CO2, opacity, and volumetric flow

are installed and all certification tests

are completed on or before the later of

the following dates:

(1) January 1, 1995, except that for a

gas-fired unit or oil-fired unit located in

an ozone nonattainment area or the

ozone transport region, the date for

installation and completion of all

certification tests for NOΧ and CO2

monitoring systems shall be July 1, 1995

and for a gas-fired unit or an oil-fired

unit not located in an ozone

nonattainment area or the ozone

transport region, the date for installation

and completion of all certification tests

for NOΧ and CO2 monitoring systems

shall be January 1, 1996; or

(2) Not later than 90 days after the

date the unit becomes subject to the

requirements of the Acid Rain Program,

notice of which date shall be provided

under subpart G of this part.

(d) In accordance with § 75.20, the

owner or operator of an existing unit

that is shutdown and is not yet

operating by the applicable dates listed

in paragraph (a) of this section, shall

ensure that all monitoring systems

required under this part for monitoring

of SO2, NOΧ, CO2, opacity, and

volumetric flow are installed and all

certification tests are completed not

later than the earlier of 45 unit operating

days or 180 calendar days after the date

that the unit recommences commercial

operation of the affected unit, notice of

which date shall be provided under

subpart G of this part. The owner or

operator shall determine and report SO2

concentration, NOΧ emission rate, CO2

concentration, and flow data for all unit

operating hours after the applicable

compliance date in paragraph (a) of this

section until all required certification

tests are successfully completed using

either:

(1) The maximum potential

concentration of SO2, the maximum

potential NOΧ emission rate, the

maximum potential flow rate, as defined

in section 2.1 of appendix A of this part,

or the maximum CO2 concentration

used to determine the maximum

potential concentration of SO2 in

section 2.1.1.1 of appendix A of this

part; or

(2) Reference methods under

§ 75.22(b); or

(3) Another procedure approved by

the Administrator pursuant to a petition

under § 75.66.

(e) In accordance with § 75.20, if the

owner or operator of an existing unit

completes construction of a new stack,

flue, or flue gas desulfurization system

after the applicable deadline in

paragraph (a) of this section, then the

owner or operator shall ensure that all

monitoring systems required under this

part for monitoring SO2, NOΧ, CO2,

opacity, and volumetric flow are

installed on the new stack or duct and

all certification tests are completed not

later than 90 calendar days after the date

that emissions first exit to the
Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations 26517

atmosphere through the new stack, flue,

or flue gas desulfurization system,

notice of which date shall be provided

under subpart G of this part. Until

emissions first pass through the new

stack, flue or flue gas desulfurization

system, the unit is subject to the

appropriate deadline in paragraph (a) of

this section. The owner or operator shall

determine and report SO2 concentration,

NOΧ emission rate, CO2 concentration,

and flow data for all unit operating

hours after emissions first pass through

the new stack, flue, or flue gas

desulfurization system until all required

certification tests are successfully

completed using either:

(1) The appropriate value for

substitution of missing data upon

recertification pursuant to § 75.20(b)(3);

or

(2) Reference methods under

§ 75.22(b) of this part; or

(3) Another procedure approved by

the Administrator pursuant to a petition

under § 75.66.

(f) In accordance with § 75.20, the

owner or operator of a gas-fired or oilfired 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

by no later than the later of: 30 unit

operating days after the date that the

unit first combusted that backup fuel

after the certification testing of the

primary fuel; or The deadline in

paragraph (a) of this section. The owner

or operator shall determine and report

NOΧ emission rate data for all unit

operating hours that the backup fuel is

combusted after the applicable

compliance date in paragraph (a) of this

section until all required certification

tests are successfully completed using

either:

(1) The maximum potential NOΧ

emission rate; or

(2) Reference methods under

§ 75.22(b) of this part; or

(3) Another procedure approved by

the Administrator pursuant to a petition

under § 75.66.

(g) In accordance with § 75.20,

whenever the owner or operator of a

gas-fired or oil-fired unit uses an

excepted monitoring system under

appendix D or E of this part and

combusts emergency fuel as defined in

§ 72.2 of this chapter, then the owner or

operator shall ensure that a fuel

flowmeter measuring emergency fuel is

installed and the required certification

tests for excepted monitoring systems

are completed by no later than 30 unit

operating days after the first date after

January 1, 1995 that the unit combusts

emergency fuel. For all unit operating

hours that the unit combusts emergency

fuel after January 1, 1995 until the

owner or operator installs a flowmeter

for emergency fuel and successfully

completes all required certification

tests, the owner or operator shall

determine and report SO2 mass

emission data using either:

(1) The maximum potential fuel flow

rate, as described in appendix D of this

part, and the maximum sulfur content of

the fuel, as described in section 2.1.1.1

of appendix A of this part;

(2) Reference methods under

§ 75.22(b) of this part; or

(3) Another procedure approved by

the Administrator pursuant to a petition

under § 75.66.

(h) In accordance with § 75.20, the

owner or operator of a unit with a

qualifying Phase I technology shall

ensure that all certification tests for the

inlet and outlet SO2-diluent continuous

emission monitoring systems are

completed no later than January 1, 1997

if the unit with a qualifying Phase I

technology requires the use of an inlet

SO2-diluent continuous emission

monitoring system for the purpose of

monitoring SO2 emissions removal from

January 1, 1997 through December 31,

1999.

10. Section 75.5 is amended by

revising paragraph (e) and by adding

paragraph (f) to read as follows:

§ 75.5 Prohibitions.

* * * * *

(e) No owner or operator of an

affected unit shall disrupt the

continuous emission monitoring system,

any portion thereof, or any other

approved emission monitoring method,

and thereby avoid monitoring and

recording SO2, NOX, or CO2 emissions

discharged to the atmosphere, except for

periods of recertification, or periods

when calibration, quality assurance, or

maintenance is performed pursuant to

§ 75.21 and appendix B of this part.

(f) No owner or operator of an affected

unit shall retire or permanently

discontinue use of the continuous

emission monitoring system, any

component thereof, the continuous

opacity monitoring system, or any other

approved emission monitoring system

under this part, except under any one of

the following circumstances:

(1) During the period that the unit is

covered by an approved retired unit

exemption under § 72.8 of this chapter

that is in effect; or

(2) The owner or operator is

monitoring emissions from the unit with

another certified monitoring system that

provides emission data for the same

pollutant or parameter as the retired or

discontinued monitoring system; or

(3) The designated representative

submits notification of the date of

recertification testing of a replacement

monitoring system in accordance with

§§ 75.20 and 75.61, and the owner or

operator recertifies thereafter a

replacement monitoring system in

accordance with § 75.20.

11. Section 75.6 is amended by

revising paragraphs (a), (b)(1) through

(b)(6); by removing paragraphs (b)(7)

through (b)(9); and by adding

paragraphs (c), (d), and (e) to read as

follows:

§ 75.6 Incorporation by reference.

* * * * * *

(a) The following materials are

available for purchase from the

following addresses: American Society

for Testing and Material (ASTM), 1916

Race Street, Philadelphia, Pennsylvania

19103; and the University Microfilms

International 300 North Zeeb Road, Ann

Arbor, Michigan 48106.

(1) ASTM D129–91, Standard Test

Method for Sulfur in Petroleum

Products (General Bomb Method), for

appendices A and D of this part.

(2) ASTM D240–87 (Reapproved

1991), Standard Test Method for Heat of

Combustion of Liquid Hydrocarbon

Fuels by Bomb Calorimeter, for

appendices A, D and F of this part.

(3) ASTM D287–82 (Reapproved

1987), Standard Test Method for API

Gravity of Crude Petroleum and

Petroleum Products (Hydrometer

Method), for appendix D of this part.

(4) ASTM D388–92, Standard

Classification of Coals by Rank,

incorporation by reference for appendix

F of this part.

(5) ASTM D941–88, Standard Test

Method for Density and Relative Density

(Specific Gravity) of Liquids by Lipkin

Bicapillary Pycnometer, for appendix D

of this part.

(6) ASTM D1072–90, Standard Test

Method for Total Sulfur in Fuel Gases,

for appendix D of this part.

(7) ASTM D1217–91, Standard Test

Method for Density and Relative Density

(Specific Gravity) of Liquids by

Bingham Pycnometer, for appendix D of

this part.

(8) ASTM D1250–80 (Reapproved

1990), Standard Guide for Petroleum

Measurement Tables, for appendix D of

this part.

(9) ASTM D1298–85 (Reapproved

1990), Standard Practice for Density,

Relative Density (Specific Gravity) or

API Gravity of Crude Petroleum and

Liquid Petroleum Products by

Hydrometer Method, for appendix D of

this part.
26518 Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations

(10) ASTM D1480–91, Standard Test

Method for Density and Relative Density

(Specific Gravity) of Viscous Materials

by Bingham Pycnometer, for appendix D

of this part.

(11) ASTM D1481–91, Standard Test

Method for Density and Relative Density

(Specific Gravity) of Viscous Materials

by Lipkin Bicapillary Pycnometer, for

appendix D of this part.

(12) ASTM D1552–90, Standard Test

Method for Sulfur in Petroleum

Products (High Temperature Method),

for appendices A and D of the part.

(13) ASTM D1826–88, Standard Test

Method for Calorific (Heating) Value of

Gases in Natural Gas Range by

Continuous Recording Calorimeter, for

appendix F of this part.

(14) ASTM D1945–91, Standard Test

Method for Analysis of Natural Gas by

Gas Chromatography, for appendices F

and G of this part.

(15) ASTM D1946–90, Standard

Practice for Analysis of Reformed Gas

by Gas Chromatography, for appendices

F and G of this part.

(16) ASTM D1989–92, Standard Test

Method for Gross Calorific Value of Coal

and Coke by Microprocessor Controlled

Isoperibol Calorimeters, for appendix F

of this part.

(17) ASTM D2013–86, Standard

Method of Preparing Coal Samples for

Analysis, for § 75.15 and appendix F of

this part.

(18) ASTM D2015–91, Standard Test

Method for Gross Calorific Value of Coal

and Coke by the Adiabatic Bomb

Calorimeter, for § 75.15 and appendices

A, D and F of this part.

(19) ASTM D2234–89, Standard Test

Methods for Collection of a Gross

Sample of Coal, for § 75.15 and

appendix F of this part.

(20) ASTM D2382–88, Standard Test

Method for Heat of Combustion of

Hydrocarbon Fuels by Bomb

Calorimeter (High-Precision Method),

for appendices D and F of this part.

(21) ASTM D2502–87, Standard Test

Method for Estimation of Molecular

Weight (Relative Molecular Mass) of

Petroleum Oils from Viscosity

Measurements, for appendix G of this

part.

(22) ASTM D2503–82 (Reapproved

1987), Standard Test Method for

Molecular Weight (Relative Molecular

Mass) of Hydrocarbons by

Thermoelectric Measurement of Vapor

Pressure, for appendix G of this part.

(23) ASTM D2622–92, Standard Test

Method for Sulfur in Petroleum

Products by X-Ray Spectrometry, for

appendices A and D of this part.

(24) ASTM D3174–89, Standard Test

Method for Ash in the Analysis Sample

of Coal and Coke From Coal, for

appendix G of this part.

(25) ASTM D3176–89, Standard

Practice for Ultimate Analysis of Coal

and Coke, for appendices A and F of

this part.

(26) ASTM D3177–89, Standard Test

Methods for Total Sulfur in the Analysis

Sample of Coal and Coke, for § 75.15

and appendix A of this part.

(27) ASTM D3178–89, Standard Test

Methods for Carbon and Hydrogen in

the Analysis Sample of Coal and Coke,

for appendix G of this part.

(28) ASTM D3238–90, Standard Test

Method for Calculation of Carbon

Distribution and Structural Group

Analysis of Petroleum Oils by the n-dM Method, for appendix G of this part.

(29) ASTM D3246–81 (Reapproved

1987), Standard Test Method for Sulfur

in Petroleum Gas By Oxidative

Microcoulometry, for appendix D of this

part.

(30) ASTM D3286–91a, Standard Test

Method for Gross Calorific Value of Coal

and Coke by the Isoperibol Bomb

Calorimeter, for appendix F of this part.

(31) ASTM D3588–91, Standard

Practice for Calculating Heat Value,

Compressibility Factor, and Relative

Density (Specific Gravity) of Gaseous

Fuels, for appendix F of this part.

(32) ASTM D4052–91, Standard Test

Method for Density and Relative Density

of Liquids by Digital Density Meter, for

appendix D of this part.

(33) ASTM D4057–88, Standard

Practice for Manual Sampling of

Petroleum and Petroleum Products, for

appendix D of this part.

(34) ASTM D4177–82 (Reapproved

1990), Standard Practice for Automatic

Sampling of Petroleum and Petroleum

Products, for appendix D of this part.

(35) ASTM D4239–85, Standard Test

Methods for Sulfur in the Analysis

Sample of Coal and Coke Using High

Temperature Tube Furnace Combustion

Methods, for § 75.15 and appendix A of

this part.

(36) ASTM D4294–90, Standard Test

Method for Sulfur in Petroleum

Products by Energy-Dispersive X-Ray

Fluorescence Spectroscopy, for

appendices A and D of this part.

(37) ASTM D4468–85 (Reapproved

1989), Standard Test Method for Total

Sulfur in Gaseous Fuels by

Hydrogenolysis and Rateometric

Colorimetry, for appendix D of this part.

(38) ASTM D4891–89, Standard Test

Method for Heating Value of Gases in

Natural Gas Range by Stoichiometric

Combustion, for appendix F of this part.

(39) ASTM D5291–92, Standard Test

Methods for Instrumental Determination

of Carbon, Hydrogen, and Nitrogen in

Petroleum Products and Lubricants, for

appendix G of this part.

(40) ASTM D5504–94, Standard Test

Method for Determination of Sulfur

Compounds in Natural Gas and Gaseous

Fuels by Gas Chromatography and

Chemiluminescence, for appendix D of

this part.

(b) * * *

(1) ASME MFC–3M–1989 with

September 1990 Errata, Measurement of

Fluid Flow in Pipes Using Orifice,

Nozzle, and Venturi, for § 75.20 and

appendix D of this part.

(2) ASME MFC–4M–1986 (Reaffirmed

1990), Measurement of Gas Flow by

Turbine Meters, for § 75.20 and

appendix D of this part.

(3) ASME-MFC–5M–1985,

Measurement of Liquid Flow in Closed

Conduits Using Transit-Time Ultrasonic

Flowmeters, for § 75.20 and appendix D

of this part.

(4) ASME MFC–6M–1987 with June

1987 Errata, Measurement of Fluid Flow

in Pipes Using Vortex Flow Meters, for

§ 75.20 and appendix D of this part.

(5) ASME MFC–7M–1987 (Reaffirmed

1992), Measurement of Gas Flow by

Means of Critical Flow Venturi Nozzles,

for § 75.20 and appendix D of this part.

(6) ASME MFC–9M–1988 with

December 1989 Errata, Measurement of

Liquid Flow in Closed Conduits by

Weighing Method, for § 75.20 and

appendix D of this part.

(c) The following materials are

available for purchase from the

American National Standards Institute

(ANSI), 11 W. 42nd Street, New York

NY 10036: ISO 8316: 1987(E)

Measurement of Liquid Flow in Closed

Conduits—Method by Collection of the

Liquid in a Volumetric Tank, for § 75.20

and appendices D and E of this part.

(d) The following materials are

available for purchase from the

following address: Gas Processors

Association (GPA), 6526 East 60th

Street, Tulsa, Oklahoma 74145:

(1) GPA Standard 2172–86,

Calculation of Gross Heating Value,

Relative Density and Compressibility

Factor for Natural Gas Mixtures from

Compositional Analysis, for appendices

D, E, and F of this part.

(2) GPA Standard 2261–90, Analysis

for Natural Gas and Similar Gaseous

Mixtures by Gas Chromatography, for

appendices D, F, and G of this part.

(e) The following materials are

available for purchase from the

following address: American Gas

Association, 1515 Wilson Boulevard,

Arlington VA 22209: American Gas

Association Report No. 3: Orifice

Metering of Natural Gas and Other

Related Hydrocarbon Fluids, Part 1:

General Equations and Uncertainty
Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations 26519

Guidelines (October 1990 Edition), Part

2: Specification and Installation

Requirements (February 1991 Edition)

and Part 3: Natural Gas Applications

(August 1992 Edition), for § 75.20 and

appendices D and E of this part.

12. Section 75.8 is added to Subpart

A to read as follows:

§ 75.8 Relative accuracy and availability

analysis.

(a) The Agency will conduct an

analysis of monitoring data submitted to

EPA under this part between November

15, 1993 and December 31, 1996 to

evaluate the appropriateness of the

current performance specifications for

relative accuracy and availability trigger

conditions for missing data substitution

for SO2 and CO2 pollutant concentration

monitors, flow monitors, and NOX

continuous emission monitoring

systems.

(b) Prior to July 1, 1997, the Agency

will prepare a report evaluating

quarterly report data for the period

between January 1, 1994 and December

31, 1996 and initial certification test

data. Based upon this evaluation, the

Administrator will sign for publication

in the Federal Register, either:

(1) A notice that the Agency has

completed its analysis and has

determined that retaining the current

performance specifications for relative

accuracy and availability trigger

conditions are appropriate; or

(2) A notice that the Agency will

develop a proposed rule, based on the

results of the study, proposing

alternatives to the current performance

specifications for relative accuracy and

availability trigger conditions.

(c) If the Administrator signs a notice

that the Agency will develop a proposed

rule, the Administrator will:

(1) Sign a notice of proposed

rulemaking by October 31, 1997; and

(2) Sign a notice of final rulemaking

by October 31, 1998.

Subpart B—Monitoring Provisions

13. Section 75.10 is amended by

revising paragraphs (a)(1), (a)(2), (a)(3),

(d), (e), and (f) to read as follows:

§ 75.10 General operating requirements.

(a) * * *

(1) The owner or operator shall

install, certify, operate, and maintain, in

accordance with all the requirements of

this part, a SO2 continuous emission

monitoring system and a flow

monitoring system with the automated

data acquisition and handling system

for measuring and recording SO2

concentration (in ppm), volumetric gas

flow (in scfh), and SO2 mass emissions

(in lb/hr) discharged to the atmosphere,

except as provided in §§ 75.11 and

75.16 and subpart E of this part;

(2) The owner or operator shall

install, certify, operate, and maintain, in

accordance with all the requirements of

this part, a NOX continuous emission

monitoring system (consisting of a NOX

pollutant concentration monitor and an

O2 or CO2 diluent gas monitor) with the

automated data acquisition and

handling system for measuring and

recording NOX concentration (in ppm),

O2 or CO2 concentration (in percent O2

or CO2) and NOX emission rate (in lb/

mmBtu) discharged to the atmosphere,

except as provided in §§ 75.12 and

75.17 and subpart E of this part. The

owner or operator shall account for total

NOX emissions, both NO and NO2,

either by monitoring for both NO and

NO2 or by monitoring for NO only and

adjusting the emissions data to account

for NO2;

(3) The owner or operator shall

determine CO2 emissions by using one

of the following options, except as

provided in § 75.13 and subpart E of this

part:

(i) The owner or operator shall install,

certify, operate, and maintain, in

accordance with all the requirements of

this part, a CO2 continuous emission

monitoring system and a flow

monitoring system with the automated

data acquisition and handling system

for measuring and recording CO2

concentration (in ppm or percent),

volumetric gas flow (in scfh), and CO2

mass emissions (in tons/hr) discharged

to the atmosphere;

(ii) The owner or operator shall

determine CO2 emissions based on the

measured carbon content of the fuel and

the procedures in appendix G of this

part to estimate CO2 emissions (in ton/

day) discharged to the atmosphere; or

(iii) The owner or operator shall

install, certify, operate, and maintain, in

accordance with all the requirements of

this part, a flow monitoring system and

a CO2 continuous emission monitoring

system using an O2 concentration

monitor in order to determine CO2

emissions using the procedures in

appendix F of this part with the

automated data acquisition and

handling system for measuring and

recording O2 concentration (in percent),

CO2 concentration (in percent),

volumetric gas flow (in scfh), and CO2

mass emissions (in tons/hr) discharged

to the atmosphere; and

* * * * *

(d) Primary equipment hourly

operating requirements. The owner or

operator shall ensure that all continuous

emission and opacity monitoring

systems required by this part are in

operation and monitoring unit

emissions or opacity at all times that the

affected unit combusts any fuel except

as provided in § 75.11(e) and during

periods of calibration, quality assurance,

or preventive maintenance, performed

pursuant to § 75.21 and appendix B of

this part, periods of repair, periods of

backups of data from the data

acquisition and handling system, or

recertification performed pursuant to

§ 75.20. The owner or operator shall also

ensure, subject to the exceptions above

in this paragraph, that all continuous

opacity monitoring systems required by

this part are in operation and

monitoring opacity during the time

following combustion when fans are

still operating, unless fan operation is

not required to be included under any

other applicable Federal, State, or local

regulation, or permit. The owner or

operator shall ensure that the following

requirements are met:

(1) The owner or operator shall ensure

that each continuous emission

monitoring system and component

thereof is capable of completing a

minimum of one cycle of operation

(sampling, analyzing, and data

recording) for each successive 15-min

interval. The owner or operator shall

reduce all SO2 concentrations,

volumetric flow, SO2 mass emissions,

SO2 emission rate in lb/mmBtu (if

applicable), CO2 concentration, O2

concentration, CO2 mass emissions (if

applicable), NOX concentration, and

NOX emission rate data collected by the

monitors to hourly averages. Hourly

averages shall be computed using at

least one data point in each fifteen

minute quadrant of an hour, where the

unit combusted fuel during that

quadrant of an hour. Notwithstanding

this requirement, an hourly average may

be computed from at least two data

points separated by a minimum of 15

minutes (where the unit operates for

more than one quadrant of an hour) if

data are unavailable as a result of the

performance of calibration, quality

assurance, or preventive maintenance

activities pursuant to § 75.21 and

appendix B of this part, backups of data

from the data acquisition and handling

system, or recertification, pursuant to

§ 75.20. The owner or operator shall use

all valid measurements or data points

collected during an hour to calculate the

hourly averages. All data points

collected during an hour shall be, to the

extent practicable, evenly spaced over

the hour.

(2) The owner or operator shall ensure

that each continuous opacity monitoring

system is capable of completing a

minimum of one cycle of sampling and

analyzing for each successive 10-sec
26520 Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations

period and one cycle of data recording

for each successive 6-min period. The

owner or operator shall reduce all

opacity data to 6-min averages

calculated in accordance with the

provisions of part 51, appendix M of

this chapter, except where the

applicable State implementation plan or

operating permit requires a different

averaging period, in which case the

State requirement shall satisfy this Acid

Rain Program requirement.

(3) Failure of an SO2, CO2 or O2

pollutant concentration monitor, flow

monitor, or NOX continuous emission

monitoring system, to acquire the

minimum number of data points for

calculation of an hourly average in

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

result in the failure to obtain a valid

hour of data and the loss of such

component data for the entire hour. An

hourly average NOX or SO2 emission

rate in lb/mmBtu is valid only if the

minimum number of data points are

acquired by both the pollutant

concentration monitor (NOX or SO2) and

the diluent monitor (CO2 or O2). Except

for SO2 emission rate data in lb/mmBtu,

if a valid hour of data is not obtained,

the owner or operator shall estimate and

record emission or flow data for the

missing hour by means of the automated

data acquisition and handling system, in

accordance with the applicable

procedure for missing data substitution

in subpart D of this part.

(e) Optional backup monitor

requirements. If the owner or operator

chooses to use two or more continuous

emission monitoring systems, each of

which is capable of monitoring the same

stack or duct at a specific affected unit,

or group of units using a common stack,

then the owner or operator shall

designate one monitoring system as the

primary monitoring system, and shall

record this information in the

monitoring plan, as provided for in

§ 75.53. The owner or operator shall

designate the other monitoring system(s)

as backup monitoring system(s) in the

monitoring plan. The backup

monitoring system(s) shall be

designated as redundant backup

monitoring system(s), non-redundant

backup monitoring system(s), or

reference method backup system(s), as

described in § 75.20(d). When the

certified primary monitoring system is

operating and not out-of-control as

defined in § 75.24, only data from the

certified primary monitoring system

shall be reported as valid, qualityassured data. Thus, data from the

backup monitoring system may be

reported as valid, quality-assured data

only when the backup is operating and

not out-of-control as defined in § 75.24

(or in the applicable reference method

in appendix A of part 60 of this chapter)

and when the certified primary

monitoring system is not operating (or is

operating but out-of-control). A

particular monitor may be designated

both as a certified primary monitor for

one unit and as a certified redundant

backup monitor for another unit.

(f) Minimum measurement capability

requirement. The owner or operator

shall ensure that each continuous

emission monitoring system and

component thereof is capable of

accurately measuring, recording, and

reporting data, and shall not incur a full

scale exceedance, except as provided in

sections 2.1.1.4, 2.1.2.4, and 2.1.4 of

appendix A of this part.

* * * * *

14. Section 75.11 is amended by

revising paragraphs (c) and (d),

redesignating paragraph (e) as paragraph

(f), and reserving paragraph (e) to read

as follows:

§ 75.11 Specific provisions for monitoring

SO2 emissions (SO2 and flow monitors).

* * * * *

(c) Unit with no location for a flow

monitor meeting siting requirements.

Where no location exists that satisfies

the minimum physical siting criteria in

appendix A to this part for installation

of a flow monitor in either the stack or

the ducts serving an affected unit or

installation of a flow monitor in either

the stack or ducts is demonstrated to the

satisfaction of the Administrator to be

technically infeasible, either:

(1) The designated representative

shall petition the Administrator for an

alternative method for monitoring

volumetric flow in accordance with

§ 75.66; or

(2) The owner or operator shall

construct a new stack or modify existing

ductwork to accommodate the

installation of a flow monitor, and the

designated representative shall petition

the Administrator for an extension of

the required certification date given in

§ 75.4 and approval of an interim

alternative flow monitoring

methodology in accordance with

§ 75.66. The Administrator may grant

existing Phase I affected units an

extension to January 1, 1995, and

existing Phase II affected units an

extension to January 1, 1996 for the

submission of the certification

application for the purpose of

constructing a new stack or making

substantial modifications to ductwork

for installation of a flow monitor; or

(3) The owner or operator shall install

a flow monitor in any existing location

in the stack or ducts serving the affected

unit at which the monitor can achieve

the performance specifications of this

part.

(d) Gas-fired units and oil-fired units.

The owner or operator of an affected

unit that qualifies as a gas-fired or oilfired unit, as defined in § 72.2 of this

chapter, based on information submitted

by the designated representative in the

monitoring plan, shall measure and

record SO2 emissions using one of the

following methods:

(1) Meet the general operating

requirements in § 75.10 for an SO2

continuous emission monitoring system

and flow monitoring system except as

provided in paragraph (e) of this

section. When the owner or operator

uses an SO2 continuous emission

monitoring system and flow monitoring

system to monitor SO2 mass emissions

from an affected unit, the owner or

operator shall comply with applicable

monitoring provisions in paragraph (a)

of this section; or

(2) Provide other information

satisfactory to the Administrator using

the procedure specified in appendix D

to this part for estimating hourly SO2

mass emissions.

(e) [Reserved]

* * * * *

15. Section 75.12 is amended by

revising paragraph (c) to read as follows:

§ 75.12 Specific provisions for monitoring

NOX emissions (NOX and diluent gas

monitors).

* * * * *

(c) Gas-fired peaking units or oil-fired

peaking units. The owner or operator of

an affected unit that qualifies as a gasfired peaking unit or oil-fired peaking

unit, as defined in § 72.2 of this chapter,

based on information submitted by the

designated representative in the

monitoring plan shall comply with one

of the following:

(1) Meet the general operating

requirements in § 75.10 for a NOX

continuous emission monitoring system;

or

(2) Provide information satisfactory to

the Administrator using the procedure

specified in appendix E of this part for

estimating hourly NOX emission rate.

However, if in the years after

certification of an excepted monitoring

system under appendix E of this part, a

unit’s operations exceed a capacity

factor of 20 percent in any calendar year

or exceed a capacity factor of 10.0

percent averaged over three years, the

owner or operator shall install, certify,

and operate a NOX continuous emission

monitoring system no later than

December 31 of the following calendar

year.

* * * * *
Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations 26521

16. Section 75.13 is amended by

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

follows:

§ 75.13 Specific provisions for monitoring

CO2 emissions.

(a) CO2 continuous emission

monitoring system. If the owner or

operator chooses to use the continuous

emission monitoring method, then the

owner or operator shall meet the general

operating requirements in § 75.10 for a

CO2 continuous emission monitoring

system and flow monitoring system for

each affected unit. The owner or

operator shall comply with the

applicable provisions specified in

§ 75.11 (a) through (e) or § 75.16, except

that the phrase ‘‘SO2 continuous

emission monitoring system’’ is

replaced with ‘‘CO2 continuous

emission monitoring system,’’ the term

‘‘maximum potential concentration for

SO2’’ is replaced with ‘‘maximum CO2

concentration,’’ and the phrase ‘‘SO2

mass emissions’’ is replaced with ‘‘CO2

mass emissions.’’

* * * * *

(c) Determination of CO2 mass

emissions using an O2 monitor

according to appendix F. If the owner or

operator chooses to use the appendix F

method, then the owner or operator may

determine hourly CO2 concentration

and mass emissions with a flow

monitoring system, a continuous O2

concentration monitor, fuel F and Fc

factors, and where O2 concentration is

measured on a dry basis, hourly

corrections for the moisture content of

the flue gases, using the methods and

procedures specified in appendix F to

this part. For units using a common

stack, multiple stack, or by-pass stack,

the owner or operator may use the

provisions of § 75.16, except that the

phrase ‘‘SO2 continuous emission

monitoring system’’ is replaced with

‘‘CO2 continuous emission monitoring

system,’’ the term ‘‘maximum potential

concentration of SO’’ is replaced with

‘‘maximum CO2 concentration,’’ and the

phrase ‘‘SO2 mass emissions’’ is

replaced with ‘‘CO2 mass emissions.’’

17. Section 75.14 is amended by

revising paragraph (c) to read as follows:

§ 75.14 Specific provisions for monitoring

opacity.

* * * * *

(c) Gas-fired units. The owner or

operator of an affected unit that

qualifies as gas-fired, as defined in

§ 72.2 of this chapter, based on

information submitted by the designated

representative in the monitoring plan is

exempt from the opacity monitoring

requirements of this part.

* * * * *

18. Section 75.15 is amended by

revising paragraphs (a) introductory

text, (a)(1), (a)(2), and Equations 5 and

7 in paragraph (b)(1) to read as follows:

§ 75.15 Specific provisions for monitoring

SO2 emissions removal by qualifying Phase

I technology.

(a) Additional monitoring provisions.

In addition to the SO2 monitoring

requirements in § 75.11 or § 75.16, for

the purposes of adequately monitoring

SO2 emissions removal by qualifying

Phase I technology operated pursuant to

§ 72.42 of this chapter, the owner or

operator shall, except where specified

below, use both an inlet SO2-diluent

continuous emission monitoring system

and an outlet SO2-diluent continuous

emission monitoring system, consisting

of an SO2 pollutant concentration

monitor and a diluent CO2 or O2

monitor. (The outlet SO2-diluent

continuous emission monitoring system

may consist of the same SO2 pollutant

concentration monitor that is required

under § 75.11 or § 75.16 for the

measurement of SO2 emissions

discharged to the atmosphere and the

diluent monitor used as part of the NOΧ

continuous emission monitoring system

that is required under § 75.12 or § 75.17

for the measurement of NOΧ emissions

discharged into the atmosphere.) During

the period when required to measure

emissions removal efficiency, from

January 1, 1997 through December 31,

1999, the owner or operator shall meet

the general operating requirements in

§ 75.10 for both the inlet and the outlet

SO2-diluent continuous emission

monitoring systems, and in addition, the

owner or operator shall comply with the

monitoring provisions in this section.

On January 1, 2000, the owner or

operator may cease operating and/or

reporting on the inlet SO2-diluent

continuous emission monitoring system

results for the purposes of the Acid Rain

Program.

(1) Pre-combustion technology. The

owner or operator of an affected unit for

which a precombustion technology has

been employed for the purpose of

meeting qualifying Phase I technology

requirements shall use sections 4 and 5

of Method 19 in appendix A of part 60

of this chapter to estimate, daily, for the

purposes of this part, the percentage

SO2 removal efficiency from such

technology, and shall substitute the

following ASTM methods for sampling,

preparation, and analysis of coal for

those cited in Method 19: ASTM

D2234–89, Standard Test Method for

Collection of a Gross Sample of Coal

(Type I, Conditions A, B, or C and

systematic spacing), ASTM D2013–86,

Standard Method of Preparing Coal

Samples for Analysis, ASTM D2015–91,

Standard Test Method for Gross

Calorific Value of Coal and Coke by the

Adiabatic Calorimeter, and ASTM

D3177–89, Standard Test Methods for

Total Sulfur in the Analysis Sample of

Coal and Coke, or ASTM D4239–85,

Standard Test Method for Sulfur in the

Analysis Sample of Coal and Coke

Using High Temperature Tube Furnace

Combustion Methods. Each of the

preceding ASTM methods is

incorporated by reference in § 75.6.

(2) Combustion technology. The

owner or operator of an affected unit for

which a combustion technology has

been installed and operated for the

purpose of meeting qualifying Phase I

technology requirements shall use the

coal sampling and analysis procedures

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

Equation 5 in paragraph (b) of this

section to estimate the percentage SO2

removal efficiency from such

technology.

* * * * *

(b) * * *

(1) * * *

% . ( . ) R

E

E

Eq c

co

ci

= − 













 100 1 0 5

where,

Eco=Average hourly SO2 emission rate in

lb/mmBtu, measured at the outlet of

the combustion emission controls

during the calendar year, calculated

from Equation 6.

Eci=Average hourly SO2 emission rate in

lb/mmBtu, determined by coal

sampling and analysis according to

the methods and procedures in

paragraph (a)(1) of this section,

calculated from Equation 7.

(Eq. 6) * * *

E E Eq ci icj

j

p

=

=

∑

1

( . ) 7

where,

Eicj=Each average hourly SO2 emission

rate in lb/mmBtu, determined by

the coal sampling and analysis

methods and procedures in

paragraph (a)(1) of this section and

calculated using appendix A,

Method 19 of part 60 of this

chapter, performed once a day.

p=Total unit operation hours during

which coal sampling and analysis is

performed to determine SO2

emissions at the inlet to the

combustion controls.

* * * * *

19. Section 75.16 is revised to read as

follows:
26522 Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations

§ 75.16 Special provisions for monitoring

emissions from common, by-pass, and

multiple stacks for SO2 emissions and heat

input determinations.

(a) Phase I common stack procedures.

Prior to January 1, 2000, the following

procedures shall be used when more

than one unit utilize a common stack:

(1) Only Phase I units or only Phase

II units using common stack. When a

Phase I unit uses a common stack with

one or more other Phase I units, but no

other units, or when a Phase II unit uses

a common stack with one or more Phase

II units, but no other units, the owner

or operator shall either:

(i) Install, certify, operate, and

maintain an SO2 continuous emission

monitoring system and flow monitoring

system in the duct to the common stack

from each affected unit; or

(ii) Install, certify, operate, and

maintain an SO2 continuous emission

monitoring system and flow monitoring

system in the common stack; and

(A) Combine emissions for the

affected units for recordkeeping and

compliance purposes; or

(B) Provide information satisfactory to

the Administrator on methods for

apportioning SO2 mass emissions

measured in the common stack to each

of the affected units. The designated

representative shall provide the

information to the Administrator

through a petition submitted under

§ 75.66. The Administrator may approve

such substitute methods for

apportioning SO2 mass emissions

measured in a common stack whenever

the method ensures complete and

accurate accounting of all emissions

regulated under this part.

(2) Phase I unit using common stack

with non-Phase I unit(s). When one or

more Phase I units uses a common stack

with one or more Phase II or nonaffected

units, the owner or operator shall either:

(i) Install, certify, operate, and

maintain an SO2 continuous emission

monitoring system and flow monitoring

system in the duct to the common stack

from each affected unit; or

(ii) Install, certify, operate, and

maintain an SO2 continuous emission

monitoring system and flow monitoring

system in the common stack; and

(A) Designate any Phase II unit(s) as

a substitution or compensating unit(s)

accordance with part 72 of this chapter

and any nonaffected unit(s) as opt-in

units in accordance with part 74 of this

chapter and combine emissions for

recordkeeping and compliance

purposes; or

(B) Install, certify, operate, and

maintain an SO2 continuous emission

monitoring system and flow monitoring

system in the duct from each Phase II or

nonaffected unit; calculate SO2 mass

emissions from the Phase I units as the

difference between SO2 mass emissions

measured in the common stack and SO2

mass emissions measured in the ducts

of the Phase II and nonaffected units;

record and report the calculated SO2

mass emissions from the Phase I units;

and combine emissions for the Phase I

units for compliance purposes; or

(C) Install, certify, operate, and

maintain an SO2 continuous emission

monitoring system and flow monitoring

system in the duct from each Phase I or

nonaffected unit; calculate SO2 mass

emissions from the Phase II units as the

difference between SO2 mass emissions

measured in the common stack and SO2

mass emissions measured in the ducts

of the Phase I and nonaffected units;

and combine emissions for the Phase II

units for recordkeeping and compliance

purposes; or

(D) Record the combined emissions

from all units as the combined SO2 mass

emissions for the Phase I units for

recordkeeping and compliance

purposes; or

(E) Provide information satisfactory to

the Administrator on methods for

apportioning SO2 mass emissions

measured in the common stack to each

of the units using the common stack.

The designated representative shall

provide the information to the

Administrator through a petition

submitted under § 75.66. The

Administrator may approve such

substitute methods for apportioning SO2

mass emissions measured in a common

stack whenever the method ensures

complete and accurate accounting of all

emissions regulated under this part.

(3) Phase II unit using common stack

with non-affected unit(s). When one or

more Phase II units uses a common

stack with one or more nonaffected

units, the owner or operator shall follow

the procedures in paragraph (b)(2) of

this section.

(b) Phase II common stack

procedures. On or after January 1, 2000,

the following procedures shall be used

when more than one unit uses a

common stack:

(1) Unit utilizing common stack with

other affected unit(s). When a Phase I or

Phase II affected unit utilizes a common

stack with one or more other Phase I or

Phase II affected units, but no

nonaffected units, the owner or operator

shall either:

(i) Install, certify, operate, and

maintain an SO2 continuous emission

monitoring system and flow monitoring

system in the duct to the common stack

from each affected unit; or

(ii) Install, certify, operate, and

maintain an SO2 continuous emission

monitoring system and flow monitoring

system in the common stack; and

(A) Combine emissions for the

affected units for recordkeeping and

compliance purposes; or

(B) Provide information satisfactory to

the Administrator on methods for

apportioning SO2 mass emissions

measured in the common stack to each

of the Phase I and Phase II affected

units. The designated representative

shall provide the information to the

Administrator through a petition

submitted under § 75.66. The

Administrator may approve such

substitute methods for apportioning SO2

mass emissions measured in a common

stack whenever the method ensures

complete and accurate accounting of all

emissions regulated under this part.

(2) Unit utilizing common stack with

nonaffected unit(s). When one or more

Phase I or Phase II affected units utilizes

a common stack with one or more

nonaffected units, the owner or operator

shall either:

(i) Install, certify, operate, and

maintain an SO2 continuous emission

monitoring system and flow monitoring

system in the duct to the common stack

from each Phase I and Phase II unit; or

(ii) Install, certify, operate, and

maintain an SO2 continuous emission

monitoring system and flow monitoring

system in the common stack; and

(A) Designate the nonaffected units as

opt-in units in accordance with part 74

of this chapter and combine emissions

for recordkeeping and compliance

purposes; or

(B) Install, certify, operate, and

maintain an SO2 continuous emission

monitoring system and flow monitoring

system in the duct from each

nonaffected unit; determine SO2 mass

emissions from the affected units as the

difference between SO2 mass emissions

measured in the common stack and SO2

mass emissions measured in the ducts

of the nonaffected units; and combine

emissions for the Phase I and Phase II

affected units for recordkeeping and

compliance purposes; or

(C) Record the combined emissions

from all units as the combined SO2 mass

emissions for the Phase I and Phase II

affected units for recordkeeping and

compliance purposes; or

(D) Petition through the designated

representative and provide information

satisfactory to the Administrator on

methods for apportioning SO2 mass

emissions measured in the common

stack to each of the units using the

common stack. The Administrator may

approve such demonstrated substitute

methods for apportioning SO2 mass

emissions measured in a common stack

whenever the demonstration ensures
Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations 26523

complete and accurate accounting of all

emissions regulated under this part.

(c) Unit with bypass stack. Whenever

any portion of the flue gases from an

affected unit can be routed 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 an SO2 continuous emission

monitoring system or flow monitoring

system on the bypass flue, duct, or stack

gas stream and calculate SO2 mass

emissions for the unit as the sum of the

emissions recorded by all required

monitoring systems; or

(2) Monitor SO2 mass emissions on

the bypass flue, duct, or stack gas stream

using the reference methods in

§ 75.22(b) for SO2 and flow 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) Where a Federal, State, or local

regulation or permit prohibits operation

of the bypass stack or duct or limits

operation of the bypass stack or duct to

emergency situations resulting from the

malfunction of a flue gas desulfurization

system record the following values for

each hour during which emissions pass

through the bypass stack or duct: the

maximum potential concentration for

SO2 as determined under section 2 of

appendix A of this part, and the hourly

volumetric flow value that would be

substituted for the flow monitor

installed on the main stack or flue under

the missing data procedures in subpart

D of this part if data from the flow

monitor installed on the main stack or

flue were missing for the hour. Calculate

SO2 mass emissions for the unit as the

sum of the emissions calculated with

the substitute values and the emissions

recorded by the SO2 and flow

monitoring systems installed on the

main stack.

(d) Unit with multiple stacks or ducts.

When the flue gases from an affected

unit utilize two or more ducts feeding

into two or more stacks (that may

include flue gases from other affected or

nonaffected units), or when the flue

gases 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 either:

(1) Install, certify, operate, and

maintain an SO2 continuous emission

monitoring system and flow monitoring

system in each duct feeding into the

stack or stacks and determine SO2 mass

emissions from each affected unit as the

sum of the SO2 mass emissions recorded

for each duct; or

(2) Install, certify, operate, and

maintain an SO2 continuous emission

monitoring system and flow monitoring

system in each stack. Determine SO2

mass emissions from each affected unit

as the sum of the SO2 mass emissions

recorded for each stack, except that

where another unit also exhausts flue

gases to one or more of the stacks, the

owner or operator shall also comply

with the applicable common stack

requirements of this section to

determine and record SO2 mass

emissions from the units using that

stack.

(e) Heat input. The owner or operator

of an affected unit using a common

stack, bypass stack, or multiple stacks

shall account for heat input according to

the following:

(1) The owner or operator of an

affected unit using a common stack,

bypass stack, or multiple stack with a

diluent monitor and a flow monitor on

each stack may choose to determine the

heat input for the affected unit,

wherever flow and diluent monitor

measurements are used to determine the

heat input, using the procedures

specified in paragraphs (a) through (d)

of this section, except that the terms

‘‘SO2 mass emissions’’ and ‘‘emissions’’

are replaced with the term ‘‘heat input’’

and the phrase ‘‘SO2 continuous

emission monitoring system and flow

monitoring system’’ is replaced with the

phrase ‘‘a diluent monitor and a flow

monitor’’.

(2) Notwithstanding paragraph (e)(1)

of this section, for any common stack

where any unit utilizing the common

stack has a NOX emission limitation

pursuant to Section 407(b) of the Act,

the owner or operator shall not combine

heat input for compliance purposes and

shall determine heat input for that unit

separately.

(3) Notwithstanding paragraph (e)(1)

of this section, during the period prior

to January 1, 2000, the owner or

operator shall not combine heat input

for units utilizing a common stack in

order to determine heat input for each

unit for purposes of § 75.10.

(4) In the event that an owner or

operator of a unit with a bypass stack

does not install and certify a diluent

monitor and flow monitoring system in

a bypass stack, the owner or operator

shall determine total heat input to the

unit for each unit operating hour during

which the bypass stack is used

according to the missing data provisions

for heat input under § 75.36 or the

procedures for calculating heat input

from fuel sampling and analysis in

section 5.5 of appendix F of this part.

20. Section 75.17 is amended by

revising paragraph (a)(2)(i)(B), adding

paragraph (a)(2)(i)(C), removing

paragraph (c), redesignating paragraph

(d) as paragraph (c), and revising the

newly designated paragraph (c) to read

as follows:

§ 75.17 Specific provisions for monitoring

emissions from common, by-pass, and

multiple stacks for NOX emission rate.

(a) * * *

(2) * * *

(i) * * *

(B) Each unit will comply with the

applicable NOX emission limitation by

averaging its emissions with the other

unit(s) utilizing the common stack,

pursuant to the emissions averaging

plan submitted under part 76 of this

chapter; or

(C) Each unit’s compliance with the

applicable NOX emission limit will be

determined by a method satisfactory to

the Administrator for apportioning to

each of the units the combined NOX

emission rate (in lb/mmBtu) measured

in the common stack, as provided in a

petition submitted by the designated

representative. The Administrator may

approve such demonstrated substitute

methods for apportioning NOX emission

rate measured in a common stack

whenever the demonstration ensures

complete and accurate estimation of all

emissions regulated under this part.

* * * * *

(c) Unit with multiple stacks or bypass

stack. When the flue gases from an

affected unit utilize two or more ducts

feeding into two or more stacks (that

may include flue gases from other

affected or nonaffected units), or when

flue gases 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 representative of

each affected unit. Where another unit

also exhausts flue gases to one or more

of the stacks where monitoring systems

are installed, the owner or operator shall

also comply with the applicable

common stack monitoring requirements

of this section. The owner or operator

shall either:

(1) Install, certify, operate, and

maintain a NOX continuous emission

monitoring system in each stack or duct

and determine the NOX emission rate

for the unit as the Btu-weighted sum of

the NOX emission rates measured in the

stacks or ducts using the heat input

estimation procedures in appendix F of

this part; or

(2) Install, certify, operate, and

maintain a NOX continuous emission

monitoring system in one stack or duct
26524 Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations

from each 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.

21. Section 75.18 is amended by

revising paragraph (b) to read as follows:

§ 75.18 Specific provisions for monitoring

emissions from common and by-pass

stacks for opacity.

(a) * * *

(b) Unit using bypass stack. Where

any portion of the flue gases from an

affected unit can be routed so as to

bypass the installed continuous opacity

monitoring system, the owner or

operator shall install, certify, operate,

and maintain a certified continuous

opacity monitoring system on each

bypass stack flue, duct, or stack gas

stream unless either:

(1) An applicable Federal, State, or

local opacity regulation or permit

exempts the unit from a requirement to

install a continuous opacity monitoring

system in the bypass stack; or

(2) A continuous opacity monitoring

system is already installed and certified

at the inlet of the add-on emissions

controls; or

(3) The owner or operator monitors

opacity using Method 9 of appendix A,

part 60 of this chapter whenever

emissions pass through the bypass

stack.

Subpart C—Operation and

Maintenance Requirements

22. Section 75.20 is amended by

revising paragraphs (a) introductory

text, (a)(1), (a)(2), (a)(3), (a)(4)

introductory text, (a)(4)(iii), (a)(4)(iv),

(a)(5), (b), the last sentence of paragraph

(c) introductory text, (c)(1)(v), (c)(2)(ii),

(c)(2)(iii), (c)(4), (c)(5) introductory text,

(c)(5)(iv), (c)(6)(i), (c)(8), (d), (f)

introductory text, (f)(1), the last

sentence of paragraph (f)(2), (f)(3) and

(g), by adding a new sentence at the end

of paragraph (f)(2), and by removing

paragraph (c)(9) to read as follows:

§ 75.20 Certification and recertification

procedures.

(a) Initial certification approval

process. The owner or operator shall

ensure that each continuous emission or

opacity monitoring system required by

this part, which includes the automated

data acquisition and handling system,

and, where applicable, the CO2

continuous emission monitoring system,

meets the initial certification

requirements of this section and shall

ensure that all applicable certification

tests under paragraph (c) of this section

are completed by the deadlines

specified in § 75.4 and prior to use in

the Acid Rain Program. In addition,

whenever the owner or operator installs

a continuous emission or opacity

monitoring system in order to meet the

requirements of §§ 75.13 through 75.18

where no continuous emission or

opacity monitoring system was

previously installed, initial certification

is required.

(1) Notification of initial certification

test dates. The owner or operator or

designated representative shall submit a

written notice of the dates of initial

certification testing at the unit as

specified in § 75.60 and § 75.61(a)(1)(i).

(2) Certification application. The

owner or operator shall apply for

certification of each continuous

emission or opacity monitoring system

used under the Acid Rain Program. The

owner or operator shall submit the

certification application in accordance

with § 75.60 and each complete

certification application shall include

the information specified in § 75.63.

(3) Provisional approval of

certification applications. Upon the

successful completion of the required

certification procedures of this section

for each continuous emission or opacity

monitoring system or component

thereof, each continuous emission or

opacity monitoring system or

component thereof shall be deemed

provisionally certified for use under the

Acid Rain Program for a period not to

exceed 120 days following receipt by

the Administrator of the complete

certification application under

paragraph (a)(4) of this section;

provided that no continuous emission

or opacity monitor systems for a

combustion source seeking to enter the

Opt-in Program in accordance with part

74 of this chapter shall be deemed

provisionally certified for use under the

Acid Rain Program. Data measured and

recorded by a provisionally certified

continuous emission or opacity

monitoring system or component

thereof, in accordance with the

requirements of appendix B of this part,

will be considered valid quality-assured

data (retroactive to the date and time of

successful completion of all certification

tests), provided that the Administrator

does not invalidate the provisional

certification by issuing a notice of

disapproval within 120 days of receipt

of the complete certification

application.

(4) Certification application formal

approval process. The Administrator

will issue a written notice of approval

or disapproval of the certification

application to the owner or operator

within 120 days of receipt of the

complete certification application. In

the event the Administrator does not

issue such a written notice within 120

days of receipt, each continuous

emission or opacity monitoring system

which meets the performance

requirements of this part and is

included in the certification application

will be deemed certified for use under

the Acid Rain Program.

* * * * *

(iii) Disapproval notice. If the

certification application is complete but

shows that any continuous emission or

opacity monitoring system or

component thereof does not meet the

performance requirements of this part,

the Administrator shall issue a written

notice of disapproval of the certification

application within 120 days of receipt.

By issuing the notice of disapproval, the

provisional certification is invalidated

by the Administrator, and the data

measured and recorded by each

uncertified continuous emission or

opacity monitoring system or

component thereof shall not be

considered valid quality-assured data

from the date and time of completion of

the invalid certification tests until the

date and time that the owner or operator

completes subsequently approved initial

certification tests. The owner or

operator shall follow the procedures for

loss of certification in paragraph (a)(5)

of this section for each continuous

emission or opacity monitoring system

or component thereof which was

disapproved.

(iv) Audit decertification. The

Administrator may issue a notice of

disapproval of the certification status of

a continuous emission or opacity

monitoring system or component

thereof, in accordance with § 75.21.

(5) Procedures for loss of certification.

When the Administrator issues a notice

of disapproval of a certification

application or a notice of disapproval of

certification status (as specified in

paragraph (a)(4) of this section), then:

(i) The owner or operator shall

substitute the following values, as

applicable, for each hour of unit

operation during the period of invalid

data specified in paragraph (a)(4)(iii) of

this section or in § 75.21: the maximum

potential concentration of SO2 as

defined in section 2.1 of appendix A of

this part to report SO2 concentration;

the maximum potential NOX emission

rate, as defined in § 72.2 of this chapter

to report NOX emissions, the maximum

potential flow rate, as defined in section

2.1 of appendix A of this part to report

volumetric flow, or the maximum CO2

concentration used to determine the

maximum potential concentration of

SO2 in section 2.1.1.1 of appendix A of
Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations 26525

this part to report CO2 concentration

data until such time, date, and hour as

the continuous emission monitoring

system or component thereof can be

adjusted, repaired, or replaced and

certification tests successfully

completed; and

(ii) The designated representative

shall submit a notification of

certification retest dates as specified in

§ 75.61(a)(1)(ii) and a new certification

application according to the procedures

in paragraph (a)(2) of this section; and

(iii) The owner or operator shall

repeat all certification tests or other

requirements that were failed by the

continuous emission or opacity

monitoring system, as indicated in the

Administrator’s notice of disapproval,

no later than 30 unit operating days

after the date of issuance of the notice

of disapproval.

(b) Recertification approval process.

Whenever the owner or operator makes

a replacement, modification, or change

in the certified continuous emission

monitoring system or continuous

opacity monitoring system (which

includes the automated data acquisition

and handling system, and, where

applicable, the CO2 continuous

emission monitoring system), that

significantly affects the ability of the

system to measure or record the SO2

concentration, volumetric gas flow, SO2

mass emissions, NOX emission rate, CO2

concentration, or opacity, or to meet the

requirements of § 75.21 or appendix B of

this part, the owner or operator shall

recertify the continuous emission

monitoring system, continuous opacity

monitoring system, or component

thereof according to the procedures in

this paragraph. Examples of changes

which require recertification include:

replacement of the analytical method,

including the analyzer; change in

location or orientation of the sampling

probe or site; rebuilding of the analyzer

or all monitoring system equipment;

and replacement of an existing

continuous emission monitoring system

or continuous opacity monitoring

system. In addition, if a continuous

emission monitoring system is not

operating for more than two calendar

years, then the owner or operator shall

recertify the continuous emission

monitoring system. The Administrator

may determine whether a replacement,

modification or change in a monitoring

system significantly affects the ability of

the monitoring system to measure or

record the SO2 concentration,

volumetric gas flow, SO2 mass

emissions, NOX emission rate, CO2

concentration, or opacity. Furthermore,

whenever the owner or operator makes

a replacement, modification, or change

to the flue gas handling system or the

unit operation that significantly changes

the flow or concentration profile or

opacity of monitored emissions, the

owner or operator shall recertify the

continuous emission or opacity

monitoring system or component

thereof according to the procedures in

this paragraph. Recertification is not

required prior to use of a non-redundant

backup continuous emission monitoring

system in cases where all of the

following conditions have been met: the

non-redundant backup continuous

emission monitoring system has

previously been certified at the same

sampling location; all components of

the non-redundant backup continuous

emission monitoring system have

previously been certified; and

component monitors of the nonredundant backup continuous emission

monitoring system pass a linearity

check (for pollutant concentration

monitors) or a calibration error test (for

flow monitors) prior to their use for

monitoring of emissions or flow. In

addition, changes resulting from routine

or normal corrective maintenance and/

or quality assurance activities do not

require recertification, nor do software

modifications in the automated data

acquisition and handling system, where

the modification is only for the purpose

of generating additional or modified

reports for the State Implementation

Plan or for reporting requirements under

subpart G of this part.

(1) Tests required. For recertification

testing, the owner or operator shall

complete all certification tests in

paragraph (c) of this section applicable

to the monitoring system, except as

approved by the Administrator. Such

approval may be obtained by petition

under § 75.66 or may be provided in

written guidance from the

Administrator.

(2) Notification of recertification test

dates. The owner or operator or

designated representative shall submit

notice of testing dates for recertification

under this paragraph as specified in

§ 75.61(a)(1)(ii), unless such testing is

required as a result of a change in the

flue gas handling system, a change in

location or orientation of the sampling

probe or site, or the planned

replacement of a continuous emission or

opacity monitoring system or

component thereof. In such cases, the

owner or operator shall provide notice

in accordance with the notice

provisions for initial certification testing

in § 75.61(a)(1)(i).

(3) Substitution of missing data. (i)

The owner or operator shall substitute

for missing data during the period

following the replacement,

modification, or change to the

monitoring system up to the time of

successful completion of all

recertification testing according to the

standard missing data procedures in

§§ 75.33 through 75.36, and shall use

the standard missing data substitution

procedures for all missing data periods

following the recertification, except as

provided below.

(ii) If the replacement, modification,

or change is such that the data collected

by the prior certified monitoring system

are no longer representative, such as

after a change to the flue gas handling

system or unit operation that requires

changing the span value to be consistent

with Section 2.1 of appendix A of this

part, the owner or operator must also

substitute the appropriate one of the

following values: 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 during the period following

the replacement, modification, or

change up to the time of the successful

completion of all recertification testing;

or for a change that results in a

significantly lower concentration or

flow rate, substitute data using the

standard missing data procedures

during the period following the

replacement, modification, or change up

to the time of the successful completion

of all recertification testing. The owner

or operator shall then use the initial

missing data procedures in § 75.31

following provisional certification,

unless otherwise provided by § 75.34 for

units with add-on emission controls.

(4) Recertification application. The

designated representative shall apply for

recertification of a continuous emission

or opacity monitoring system used

under the Acid Rain Program according

to the procedures in paragraph (a)(2) of

this section. Each complete

recertification application shall include

the information specified in § 75.63 of

this part.

(5) Approval/disapproval of request

for recertification. The procedures for

provisional certification in paragraph

(a)(3) of this section shall apply. The

Administrator will issue a written

notice of approval or disapproval

according to the procedures in

paragraph (a)(4) of this section, except

that the period for the Administrator’s

review provided under paragraph (a)(4)

of this section shall not exceed 60 days

following receipt of the complete

recertification application by the

Administrator. The missing data

substitution procedures under

paragraph (b)(3) of this section shall
26526 Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations

apply in the event of a loss of

recertification.

(c) * * * Except as specified in

paragraphs (b)(1), (d) and (e) of this

section, the owner or operator shall

perform the following tests for initial

certification or recertification of

continuous emission or opacity

monitoring systems or components

according to the requirements of

appendix A of this part:

(1) * * *

(v) A cycle time test.

(2) * * *

(ii) Relative accuracy test audits at

three flue gas velocities; and

(iii) A bias test (at normal operating

load).

(3) * * *

(4) The certification test data from an

O2 or a CO2 diluent gas monitor certified

for use in a NOX continuous emission

monitoring system may be submitted to

meet the requirements of § 75.20(c)(5).

(5) For each CO2 pollutant

concentration monitor or O2 monitor

which is part of a CO2 continuous

emission monitoring system or is used

to monitor heat input and for each SO2-

diluent continuous emission monitoring

system:

* * * * *

(iv) A cycle-time test.

(6) * * *

(i) Performance of the tests for

certification or recertification, according

to the requirements of Performance

Specification 1 in appendix B to part 60

of this chapter.

* * * * *

(8) The owner or operator shall

provide, or cause to be provided,

adequate facilities for certification or

recertification testing that include:

(i) Sampling ports adequate for test

methods applicable to such facility,

such that:

(A) Volumetric flow rate, pollutant

concentration, and pollutant emission

rates can be accurately determined by

applicable test methods and procedures;

and

(B) A stack or duct free of cyclonic

flow during performance tests is

available, as demonstrated by applicable

test methods and procedures.

(ii) Basic facilities (e.g., electricity) for

sampling and testing equipment.

(d) Certification/recertification

procedures for optional backup

continuous emission monitoring

systems—(1) Redundant backups. The

owner or operator of an optional

redundant backup continuous emission

monitoring system shall comply with all

the requirements for initial certification

and recertification according to the

procedures specified in paragraphs (a),

(b), and (c) of this section. The owner

or operator shall operate the redundant

backup continuous emission monitoring

system during all periods of unit

operation, except for periods of

calibration, quality assurance,

maintenance, or repair. The owner or

operator shall perform upon the

redundant backup continuous emission

monitoring system all quality assurance

and quality control procedures specified

in appendix B of this part.

(2) Non-redundant backups. The

owner or operator of an optional nonredundant backup continuous emission

monitoring system shall comply with all

the requirements for initial certification

and recertification according to the

procedures specified in paragraphs (a),

(b) and (c) of this section for each nonredundant backup continuous emission

monitoring system, except that: the

owner or operator of a non-redundant

backup continuous emission monitoring

system may omit the 7-day calibration

error test for certification or

recertification of an SO2 pollutant

concentration monitor, flow monitor,

NOX pollutant concentration monitor, or

diluent gas monitor, provided the nonredundant backup system is not used for

reporting on any affected unit for more

than 720 hours in any calendar year. In

addition, the owner or operator shall

ensure that the certified non-redundant

backup continuous emission monitoring

system passes a linearity check (for

pollutant concentration monitors) or a

calibration error test (for flow monitors)

prior to each use for recording and

reporting emissions and complies with

the daily and quarterly quality

assurance and quality control

requirements in appendix B of this part

for each day and quarter that the nonredundant backup monitoring system is

used to report data. If the owner or

operator does not perform semi-annual

or annual relative accuracy test audits

upon the non-redundant backup

continuous emission monitoring system,

then the owner or operator shall

recertify the non-redundant continuous

emission monitoring system once every

two calendar years, performing all

certification tests applicable under this

paragraph. However, if a non-redundant

backup system is used for reporting data

from any affected unit or common stack

for more than 720 hours in any one

calendar year, then reported data after

the first 720 hours is not valid, qualityassured data unless the owner or

operator has ensured that the nonredundant backup monitoring system

has also passed the 7-day calibration

error test, before data is recorded for any

period in excess of 720 hours for that

calendar year for that monitoring

system.

(3) Reference method backups. A

monitoring system that is operated as a

reference method backup system

pursuant to the reference method

requirements of Methods 2, 6C, 7E, or

3A in appendix A of part 60 of this

chapter need not perform and pass the

certification tests required by paragraph

(c) of this section prior to its use

pursuant to this paragraph.

* * * * *

(f) Certification/recertification

procedures for alternative monitoring

systems. The designated representative

representing the owner or operator of

each alternative monitoring system

approved by the Administrator as

equivalent to or better than a continuous

emission monitoring system according

to the criteria and procedures in subpart

E of this part shall apply for certification

to the Administrator prior to use of the

system under the Acid Rain Program,

and shall apply for recertification to the

Administrator following a replacement,

modification, or change by performing

all of the tests under paragraph (c) of

this section that can be applied to the

alternative monitoring system. The

owner or operator of an alternative

monitoring system shall comply with

the notification and application

requirements for certification or

recertification according to the

procedures specified in paragraphs

(f)(1), (f)(2), and (f)(3) of this section.

(1) Each alternative monitoring

system shall be certified by the

Administrator before it may be

authorized for use under the Acid Rain

Program.

(i) Certification testing notification.

The designated representative shall

provide certification testing notification

according to the procedures in

subparagraph (a)(1) of this section prior

to conducting certification testing.

(ii) Monitoring plan. The designated

representative shall submit an initial

monitoring plan at least 45 days prior to

the first day of certification testing.

(iii) Certification application. The

designated representative shall submit a

certification application for the

alternative monitoring system prior to

use in the Acid Rain Program. Each

complete certification application shall

include:

(A) Information and test results for the

relative accuracy test and any other

applicable tests in paragraph (c) of this

section;

(B) A revised monitoring plan; and

(C) Results of the tests for verification

of the accuracy of emissions

calculations and missing data
Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations 26527

procedures performed by the automated

data acquisition and handling system.

(2) * * * The procedures for

provisional certification under

paragraph (a)(3) of this section and for

a 120-day EPA review period for initial

certification under paragraph (a)(4) of

this section shall apply to alternative

monitoring systems, provided that the

Administrator has already approved the

petition or petitions required under

subpart E of this part. The designated

representative shall report no data from

an alternative monitoring system in a

quarterly report from a period prior to

both Administrator approval of the

petition or petitions under subpart E of

this part and also successful completion

of certification testing.

(3) The recertification requirements of

paragraph (b) of this section shall apply

to alternative monitoring systems,

except that the owner or operator shall

perform the tests specified under

paragraph (f)(1)(iii) of this section.

(g) Certification procedures for

excepted monitoring systems under

appendices D and E. The owner or

operator of a gas-fired unit, oil-fired

unit, or diesel-fired unit using the

optional protocol under appendix D or

E of this part shall ensure that an

excepted monitoring system under

appendix D or E of this part meets the

applicable general operating

requirements of § 75.10, the applicable

requirements of appendices D and E to

this part, and the certification

requirements of this paragraph.

(1) Certification testing. The owner or

operator shall use the following

procedures for certification of an

excepted monitoring system under

appendix D or E of this part.

(i) When the optional SO2 mass

emissions estimation procedure in

appendix D of this part or the optional

NOX emissions estimation protocol in

appendix E of this part is used, the

owner or operator shall provide data

from a calibration test for each fuel

flowmeter according to the appropriate

calibration procedures using one of the

following standard methods: ASME

MFC–3M–1989 with September 1990

Errata, ‘‘Measurement of Fluid Flow in

Pipes Using Orifice, Nozzle, and

Venturi’’, ASME MFC–4M–1986

(Reaffirmed 1990) ‘‘Measurement of Gas

Flow by Turbine Meters’’, ASME MFC–

5M–1985 ‘‘Measurement of Liquid Flow

in Closed Conduits Using Transit-Time

Ultrasonic Flowmeters’’, ASME MFC–

6M–1987 with June 1987 Errata,

‘‘Measurement of Fluid Flow in Pipes

Using Vortex Flow Meters’’, ASME

MFC–7M–1987 (Reaffirmed 1992),

‘‘Measurement of Gas Flow by Means of

Critical Flow Venturi Nozzles’’, ASME

MFC–9M–1988 with December 1989

Errata, ‘‘Measurement of Liquid Flow in

Closed Conduits by Weighing Method’’,

ISO 8316: 1987(E) ‘‘Measurement of

Liquid Flow in Closed Conduits—

Method by Collection of the Liquid in

a Volumetric Tank’’, or American Gas

Association Report No. 3: Orifice

Metering of Natural Gas and Other

Related Hydrocarbon Fluids Part 1:

General Equations and Uncertainty

Guidelines (October 1990 Edition), Part

2: Specification and Installation

Requirements (February 1991 Edition)

and Part 3: Natural Gas Applications

(August 1992 Edition), excluding the

modified calculation procedures of Part

3, as required by appendices D and E of

this part (all methods incorporated by

reference under § 75.6). The

Administrator may also approve other

procedures that use equipment traceable

to National Institute of Standards of

Technology (NIST) standards. The

designated representative shall

document the procedure and the

equipment used in the monitoring plan

for the unit and in a petition submitted

in accordance with § 75.66(c).

(ii) For the automated data acquisition

and handling system used under either

the optional SO2 mass emissions

estimation procedure in appendix D of

this part or the optional NOX emissions

estimation protocol in appendix E of

this part, the owner or operator shall

perform tests designed to verify:

(A) The proper computation of hourly

averages for pollutant concentrations,

fuel flow rates, emission rates, heat

input, and pollutant mass emissions;

and

(B) Proper computation and

application of the missing data

substitution procedures in appendix D

or E of this part.

(iii) When the optional NOX

emissions protocol in appendix E is

used, the owner or operator shall

complete all initial performance testing

under section 2.1 of appendix E.

(2) Certification testing notification.

The designated representative shall

provide initial certification testing

notification and periodic retesting

notification for an excepted monitoring

system under appendix E of this part as

specified in § 75.61. The designated

representative shall submit

recertification testing notification as

specified in § 75.61 for quality

assurance/quality control-related NOX

emission rate testing under section 2.3

of appendix E of this part for an

excepted monitoring system under

appendix E of this part. Certification

testing notification or periodic retesting

notification is not required for testing of

a fuel flowmeter or testing for an

excepted monitoring system under

appendix D of this part.

(3) Monitoring plan. The designated

representative shall submit an initial

monitoring plan in accordance with

§ 75.62(a).

(4) Certification application. The

designated representative shall submit a

certification application in accordance

with §§ 75.60 and 75.63.

(5) Provisional approval of

certification applications. Upon the

successful completion of the required

certification procedures for each

excepted monitoring system under

appendix D or E of this part, each

excepted monitoring system under

appendix D or E of this part shall be

deemed provisionally certified for use

under the Acid Rain Program during the

period for the Administrator’s review.

The provisions for the certification

application formal approval process in

paragraph (a)(4) of this section shall

apply. Data measured and recorded by

a provisionally certified excepted

monitoring system under appendix D or

E of this part, will be considered

quality-assured data from the date and

time of completion of the final

certification test, provided that the

Administrator does not revoke the

provisional certification by issuing a

notice of disapproval within 120 days of

receipt of the complete certification

application in accordance with the

provisions in paragraph (a)(4) of this

section.

23. Section 75.21 is amended by

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

follows:

§ 75.21 Quality assurance and quality

control requirements.

* * * * *

(d) Notification for periodic relative

accuracy test audits. The owner or

operator or the designated

representative shall submit a written

notice of the dates of relative accuracy

testing as specified in § 75.61.

(e) Consequences of audits. The

owner or operator shall invalidate data

from a continuous emission monitoring

system or continuous opacity

monitoring system upon failure of an

audit under paragraph (a)(1)(iv) of

§ 75.20, under appendix B of this part,

or any other audit, beginning with the

unit operating hour of completion of a

failed audit as determined by the

Administrator. The owner or operator

shall not use invalidated data for

reporting emissions or heat input, nor

for calculations of monitor data

availability.

(1) Audit decertification. Whenever

both: an audit (including audits

required under appendix B of this part)
26528 Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations

of a continuous emission or opacity

monitoring system or component

thereof, including the data acquisition

and handling system, and a review of

the initial certification application or

recertification application, reveal that

any continuous emission or opacity

monitoring system or component should

not have been certified because it did

not meet a particular performance

specification or other requirement of

this part both at the time of the

certification application submission and

at the time of the audit, the

Administrator will issue a notice of

disapproval of the certification status of

such system or component. By issuing

the notice of disapproval, the

certification status is revoked,

prospectively, by the Administrator.

The data measured and recorded by

each continuous emission or opacity

monitoring system shall not be

considered valid quality-assured data

from the date of issuance of the

notification of the revoked certification

status until the date and time that the

owner or operator completes

subsequently approved certification

tests. The owner or operator shall follow

the procedures for loss of certification in

§ 75.20(a)(5) for initial certification or

§ 75.20(b)(3) for recertification to

replace, prospectively, all of the invalid,

non-quality-assured data for each

disapproved continuous emission or

opacity monitoring system.

(2) Out-of-control period. Whenever a

continuous emission monitoring system

or continuous opacity monitoring

system fails a periodic quality assurance

audit, an audit under § 75.20(a)(1)(iv), a

field audit from EPA personnel or other

audit, the system is out-of-control. The

owner or operator shall follow the

procedures for out-of-control periods in

§ 75.24.

24. Section 75.22 is amended by

revising paragraphs (a) introductory

text, (a)(5), and (a)(6) and by adding

paragraphs (b) and (c) to read as follows:

§ 75.22 Reference test methods.

(a) The owner or operator shall use

the following methods included in

appendix A to part 60 of this chapter to

conduct monitoring system tests for

certification or recertification of

continuous emission monitoring

systems and excepted monitoring

systems under appendix E of this part

and quality assurance and quality

control procedures.

* * * * *

(5) Methods 6, 6A, 6B or 6C, and 7,

7A, 7C, 7D or 7E, as applicable, are the

reference methods for determining SO2

and NOX pollutant concentrations.

(Methods 6A and 6B may also be used

to determine SO2 emission rate in lb/

mmBtu. Methods 7, 7A, 7C, 7D, or 7E

must be used to measure total NOX

emissions, both NO and NO2, for

purposes of this part. The owner or

operator shall not use the exception in

section 5.1.2 of Method 7E.)

(6) Method 20 is the reference method

for determining NOX and diluent

emissions from stationary gas turbines

for testing under appendix E of this part.

(b) The owner or operator may use the

following methods in Appendix A of

part 60 of this chapter as a reference

method backup monitoring system to

provide quality-assured monitor data:

(1) Method 3A for determining O2 or

CO2 concentration;

(2) Method 6C for determining SO2

concentration;

(3) Method 7E for determining total

NOX concentration (both NO and NO2);

and

(4) Method 2 for determining

volumetric flow. The sample point(s) for

reference methods shall be located

according to the provisions of section

6.5.5 of appendix A of this part.

(c) (1) Performance tests shall be

conducted and data reduced in

accordance with the test methods and

procedures of this part unless the

Administrator:

(i) Specifies or approves, in specific

cases, the use of a reference method

with minor changes in methodology;

(ii) Approves the use of an equivalent

method; or

(iii) Approves shorter sampling times

and smaller sample volumes when

necessitated by process variables or

other factors.

(2) Nothing in this paragraph shall be

construed to abrogate the

Administrator’s authority to require

testing under Section 114 of the Act.

25. Section 75.23 is revised to read as

follows:

§ 75.23 Alternatives to standards

incorporated by reference.

(a) The designated representative of a

unit may petition the Administrator for

an alternative to any standard

incorporated by reference and

prescribed in this part in accordance

with § 75.66(c).

(b) (reserved)

26. Section 75.24 is amended by

revising paragraphs (d) and (e)

introductory text to read as follows:

§ 75.24 Out-of-control periods.

* * * * *

(d) When the bias test indicates that

an SO2 monitor, volumetric flow

monitor, or NOX continuous emission

monitoring system is biased low (i.e.,

the arithmetic mean of the differences

between the reference method value and

the monitor or monitoring system

measurements in a relative accuracy test

audit exceed the bias statistic in section

7 of appendix A to this part), the owner

or operator shall adjust the monitor or

continuous emission monitoring system

to eliminate the cause of bias such that

it passes the bias test or calculate and

use the bias adjustment factor as

specified in section 2.3.3 of appendix B

to this part and in accordance with

§ 75.7.

(e) The owner or operator shall

determine if a continuous opacity

monitoring system is out-of-control and

shall take appropriate corrective actions

according to the procedures specified

for State Implementation Plans,

pursuant to appendix M of part 51 of

this chapter. The owner or operator

shall comply with the monitor data

availability requirements of the State. If

the State has no monitor data

availability requirements for continuous

opacity monitoring systems, then the

owner or operator shall comply with the

monitor data availability requirements

as stated in the data capture provisions

of appendix M, part 51 of this chapter.

Subpart D—Missing Data Substitution

Procedures

27. Section 75.30 is revised to read as

follows:

§ 75.30 General provisions.

(a) Except as provided in § 75.34, the

owner or operator shall provide

substitute data for each affected unit

using a continuous emission monitoring

system according to the missing data

procedures in this subpart whenever the

unit combusts any fuel and:

(1) A valid, quality-assured hour of

SO2 concentration data (in ppm) has not

been measured and recorded for an

affected unit by a certified SO2 pollutant

concentration monitor, or by an

approved alternative monitoring method

under subpart E of this part, except as

provided in paragraph (d) of this

section; or

(2) A valid, quality-assured hour of

flow data (in scfh) has not been

measured and recorded for an affected

unit from a certified flow monitor, or by

an approved alternative monitoring

system under subpart E of this part; or

(3) A valid, quality-assured hour of

NOX emission rate data (in lb/mmBtu)

has not been measured and recorded for

an affected unit by a certified NOX

continuous emission monitoring system,

or by an approved alternative

monitoring system under subpart E of

this part; or

(4) A valid, quality-assured hour of

CO2 concentration data (in percent CO2,
Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations 26529

or percent O2 converted to percent CO2

using the procedures in appendix F of

this part) has not been measured and

recorded for an affected unit by a

certified CO2 continuous emission

monitoring system, or by an approved

alternative monitoring method under

subpart E of this part.

(b) However, the owner or operator

shall have no need to provide substitute

data according to the missing data

procedures in this subpart if the owner

or operator uses SO2 or CO2 (or O2)

concentration, flow, or NOX emission

rate data recorded from either a certified

redundant or non-redundant backup

continuous emission monitor or a

backup reference method monitoring

system when the certified primary

monitor is not operating or out-ofcontrol. A redundant or non-redundant

backup continuous emission monitoring

system must have been certified

according to the procedures in § 75.20

prior to the missing data period. Nonredundant backup continuous emission

monitoring system must pass a linearity

check (for pollutant concentration

monitors) or a calibration error test (for

flow monitors) prior to each period of

use of the certified backup monitor for

recording and reporting emissions. Use

of a certified backup monitoring system

or backup reference method monitoring

system is optional and at the discretion

of the owner or operator.

(c) When the certified primary

monitor is not operating or out-ofcontrol, then data recorded for an

affected unit from a certified backup

continuous emission monitor or backup

reference method monitoring system are

used, as if such data were from the

certified primary monitor, to calculate

monitor data availability in § 75.32, and

to provide the quality-assured data used

in the missing data procedures in

§§ 75.31 and 75.33, such as the ‘‘hour

after’’ value.

(d) [Reserved]

(e) [Reserved]

28. Section 75.31 is amended by

revising paragraphs (a), (b) and (c)(3) to

read as follows:

§ 75.31 Initial missing data procedures.

(a) During the first 720 qualityassured monitor operating hours

following initial certification (i.e.,

following the date and time of

completion of successful certification

tests), of the SO2 and CO2 (or O2)

pollutant concentration monitor and

during the first 2,160 quality-assured

monitor operating hours following

initial certification of the flow monitor

and NOX continuous emission

monitoring system(s), the owner or

operator shall provide substitute data

required under this subpart according to

the procedures in paragraphs (b) and (c)

of this section. The owner or operator of

a unit shall use these procedures for no

longer than three years (26,280 clock

hours) following initial certification.

(b) SO2 or CO2 (or O2) concentration

data. For each hour of missing SO2 or

CO2 concentration data (including CO2

data converted from O2 data using the

procedures in appendix F of this part)

or O2 concentration data used to

calculate heat input, the owner or

operator shall calculate the substitute

data as follows:

(1) Whenever prior quality-assured

data exist, the owner or operator shall

substitute, by means of the data

acquisition and handling system, the

average of the hourly SO2 or CO2 (or O2)

concentrations recorded for an affected

unit by a certified monitor for the unit

operating hour immediately before and

the unit operating hour immediately

after the missing data period for each

hour of missing data.

(2) Whenever no prior quality-assured

SO2 or CO2 (or O2) concentration data

exist, the owner or operator shall

substitute the maximum potential

concentration for SO2 or CO2 (or

minimum O2 concentration, for

determination of heat input), as

specified in section 2.1 of appendix A

of this part, for each hour of missing

data.

(c) * * *

(3) Whenever no prior quality-assured

flow or NOX emission rate data exist for

the corresponding load range, or any

higher load range, the owner or operator

shall calculate and substitute the

maximum potential flow rate or shall

substitute the maximum potential NOX

emission rate, as specified in § 72.2 of

this chapter and section 2.1 of appendix

A, for each hour of missing data.

29. Section 75.32 is amended by

revising paragraphs (a) introductory

text, the first sentence of paragraphs

(a)(1) and (a)(2) and paragraph (b) to

read as follows:

§ 75.32 Determination of monitor data

availability for standard missing data

procedures.

(a) Following initial certification,

upon completion of the first 720 qualityassured monitor operating hours of the

SO2 or CO2 (or O2) pollutant

concentration monitor or the first 2,160

quality-assured monitor operating hours

of the flow monitor or NOX continuous

emission monitoring system, the owner

or operator shall calculate and record,

by means of the automated data

acquisition and handling system, the

percent monitor data availability for the

SO2 and CO2 (or O2) pollutant

concentration monitor, the flow

monitor, the NOX continuous emission

monitoring system as follows:

(1) Prior to completion of 8,760 unit

operating hours following initial

certification, the owner or operator

shall, for the purpose of applying the

standard missing data procedures of

§ 75.33, use Equation 8 to calculate,

hourly, percent monitor data

availability. * * *

(2) Upon completion of 8,760 unit

operating hours following initial

certification (or, for a unit with less than

8,760 unit operating hours three years

(26,280 clock hours) after initial

certification, upon completion of three

years (26,280 clock 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. * * *

(3) * * *

(b) The monitor data availability need

not be calculated during the missing

data period. The owner or operator shall

record the percent monitor data

availability for the last hour of each

missing data period as the monitor

availability used to implement the

missing data substitution procedures.

30. Section 75.33 is amended by

adding a sentence to the end of

paragraph (a) and by adding paragraph

(c)(5) to read as follows:

§ 75.33 Standard missing data procedures.

(a) * * * The owner or operator of a

unit shall substitute for missing data

using only quality-assured monitor

operating hours of data from the three

years (26,280 clock hours) prior to the

date and time of the missing data

period. * * *

* * * * *

(c) * * *

(5) Whenever no proper qualityassured flow or NOX emission rate data

exist for either the corresponding load

range or a higher load range, the owner

or operator shall substitute the

maximum potential NOX emission rate

or the maximum potential flow rate, as

defined in section 2.1 of appendix A of

this part.

* * * * *

31. Section 75.35 is added as follows:

§ 75.35 Missing data procedures for CO2

data.

(a) On or after January 1, 1996, the

owner or operator of a unit with a CO2

continuous emission monitoring system

shall substitute for missing CO2

concentration data using the procedures

of this section. Prior to January 1, 1996,

the owner or operator of a unit with a
26530 Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations

CO2 continuous emission monitoring

system may substitute for missing CO2

concentration data using the procedures

of this section.

(b) During the first 720 qualityassured monitor operating hours

following initial certification (i.e.,

following the date and time of

completion of successful certification

tests), of the CO2 continuous emission

monitoring system, the owner or

operator shall provide substitute data

required under this subpart according to

the procedures in paragraph (b) of

§ 75.31.

(c) Upon completion of the first 720

quality-assured monitor operating hours

following initial certification of the CO2

continuous emission monitoring system,

the owner or operator shall provide

substitute data for CO2 concentration or

CO2 mass emissions required under this

subpart according to the procedures in

paragraphs (c)(1), (c)(2), or (c)(3) of this

section, including CO2 data calculated

from O2 measurements using the

procedures in appendix F of this part.

(1) Whenever a quality-assured

monitoring operating hour of CO2

concentration data has not been

obtained and recorded for a period less

than or equal to 72 hours or for a

missing data period where the percent

monitor data availability for the CO2

continuous emission monitoring system

as of the last unit operating hour of the

previous calendar quarter was greater

than or equal to 90.0 percent, then the

owner or operator shall substitute the

average of the recorded CO2

concentration for the hour before and

the hour after the missing data period

for each hour in each missing data

period.

(2) Whenever no quality-assured CO2

concentration data are available for a

period of 72 consecutive unit operating

hours or more, the owner or operator

shall begin substituting CO2 mass

emissions calculated using the

procedures in appendix G of this part

beginning with the seventy-third hour of

the missing data period until qualityassured CO2 concentration data are

again available. The owner or operator

shall use the CO2 concentration from the

hour before the missing data period to

substitute for hours 1 through 72 of the

missing data period.

(3) Whenever no quality-assured CO2

concentration data are available for a

period where the percent monitor data

availability for the CO2 continuous

emission monitoring system as of the

last unit operating hour of the previous

calendar quarter was less than 90.0

percent, the owner or operator shall

substitute CO2 mass emissions

calculated using the procedures in

appendix G of this part for each hour of

the missing data period until qualityassured CO2 concentration data are

again available.

32. Section 75.36 is added as follows:

§ 75.36 Missing data procedures for heat

input.

(a) On or after January 1, 1996, the

owner or operator of a unit monitoring

heat input with a CO2 or O2 pollutant

concentration monitor and a flow

monitoring system shall substitute for

missing heat input data using the

procedures of this section. Prior to

January 1, 1996, the owner or operator

of a unit monitoring heat input with a

CO2 or O2 pollutant concentration

monitor and a flow monitoring system

may substitute for missing heat input

data using the procedures of this

section.

(b) During the first 720 qualityassured monitor operating hours

following initial certification (i.e.,

following the date and time of

completion of successful certification

tests), of the CO2 or O2 pollutant

concentration monitor and during the

first 2,160 quality-assured monitoring

operating hours following initial

certification of the flow monitor, the

owner or operator shall provide

substitute data for heat input calculated

under section 5.2 of appendix F of this

part by substituting the CO2 or O2

concentration measured or substituted

according to paragraph (b) of § 75.31,

and by substituting the flow rate

measured or substituted according to

§ 75.31.

(c) Upon completion of the first 720

quality-assured monitor operating hours

following initial certification of the CO2

(or O2) pollutant concentration monitor,

the owner or operator shall provide

substitute data for CO2 or O2

concentration to calculate heat input or

shall substitute heat input determined

under appendix F of this part according

to the procedures in paragraphs (c)(1),

(c)(2), or (c)(3) of this section. Upon

completion of 2,160 quality-assured

monitor operating hours following

initial certification of the flow monitor,

the owner or operator shall provide

substitute data for volumetric flow

according to the procedures in § 75.33

in order to calculate heat input, unless

required to determine heat input using

the fuel sampling procedures in

appendix F of this part under

paragraphs (c)(1), (c)(2) or (c)(3) of this

section.

(1) Whenever a quality-assured

monitor operating hour of CO2 or O2

concentration data has not been

obtained and recorded for a period less

than or equal to 72 hours or for a

missing data period where the percent

monitor data availability for the CO2 or

O2 pollutant concentration monitor as of

the last unit operating hour of the

previous calendar quarter was greater

than or equal to 90.0 percent, the owner

or operator shall substitute the average

of the recorded CO2 or O2 concentration

for the hour before and the hour after

the missing data period for each hour in

each missing data period to calculate

heat input.

(2) Whenever a quality-assured

monitor operating hour of CO2 or O2

concentration data has not been

obtained and recorded for a period of 72

consecutive unit operating hours or

more, the owner or operator shall begin

substituting heat input calculated using

the procedures in section 5.5 of

appendix F of this part beginning with

the seventy-third hour of the missing

data period until quality-assured CO2 or

O2 concentration data are again

available. The owner or operator shall

use the CO2 or O2 concentration from

the hour before the missing data period

to substitute for hours 1 through 72 of

the missing data period.

(3) Whenever no quality-assured CO2

or O2 concentration data are available

for a period where the percent monitor

data availability for the CO2 continuous

emission monitoring system (or O2

diluent monitor) as of the last unit

operating hour of the previous calendar

quarter was less than 90.0 percent, the

owner or operator shall substitute heat

input calculated using the procedures in

section 5.5 of appendix F of this part for

each hour of the missing data period

until quality-assured CO2 or O2

concentration data are again available.

(d) For a unit that has no diluent

monitor certified during the period

between the certification deadline in

§ 75.4(a) for flow monitoring systems

and the certification deadline in

§ 75.4(a) for NOX and CO2 continuous

emission monitoring systems, the owner

or operator shall calculate heat input

using the procedures in section 5.5 of

appendix F of this part until qualityassured data are available from both a

flow monitor and a diluent monitor.

Subpart E—Alternative Monitoring

Systems

33. Section 75.41 is amended by

adding a sentence to the end of

paragraph (a)(1), revising paragraphs

(b)(1)(i), (b)(2)(iv)(A), (b)(2)(iv)(C),

(c)(1)(i), (c)(1)(ii) and (c)(2)(ii) to read as

follows:

§ 75.41 Precision criteria.

(a) * * *
Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations 26531

(1) * * * For the purposes of this

subpart, each reference method run

shall be 30 to 60 minutes in duration.

* * * * *

(b) * * *

(1) * * *

(i) Apply the log transformation to

each measured value of either the

certified continuous emissions

monitoring system, certified flow

monitor or reference method, using the

following equation:

lv = ln ev (Eq. 11)

Where:

ev= Hourly value generated by the

certified continuous emissions

monitoring system, certified flow

monitoring system, or reference

method.

* * * * *

(2) * * *

(iv) * * *

(A) The set of measured hourly

values, ev, generated by the certified

continuous emissions monitoring

system, certified flow monitoring

system, or reference method.

* * * * *

(C) The set of hourly differences, ev ¥

ep, between the hourly values, ev,

generated by the certified continuous

emissions monitoring system, certified

flow monitoring system, or reference

method and the hourly values, ep,

generated by the proposed alternative

monitoring system.

* * * * *

(c) * * *

(1) * * *

(i) Calculate the variance of the

certified continuous emission

monitoring system, certified flow

monitor, or reference method as

applicable, Sv

2, and the proposed

method, Sp

2, using the following

equation.

S

e e

n

Eq

i m

i

n

2

2

1

1 = 23

( ) −

−

=

∑

( . )

(Eq. 23)

Where:

ei = Measured values of either the

certified continuous emission

monitoring system, certified flow

monitor, or reference method, as

applicable, or proposed method.

em = Mean of either the certified

continuous emission monitoring

system or certified flow monitor, or

reference method, as applicable, or

proposed method values.

n = Total number of paired samples.

(ii) Determine if the variance of the

proposed method is significantly

different from that of the certified

continuous emission monitoring system,

certified flow monitor, or reference

method, as applicable, by calculating

the F-value using the following

equation.

F

S

S

Eq p

v

=

2

2 ( . ) 24

(Eq. 24)

Compare the experimental F-value

with the critical value of F at the 95-

percent confidence level with n-1

degrees of freedom. The critical value is

obtained from a table for F-distribution.

If the calculated F-value is greater than

the critical value, the proposed method

is unacceptable.

(2) * * *

(ii) Use the following equation to

calculate the coefficient of correlation, r,

between the emissions data from the

alternative monitoring system and the

continuous emission monitoring system

using all hourly data for which paired

values were available from both

monitoring systems.

r

e e e e n

e e n e e n

Eq p v p v

p p v v

= ∑ − ∑( )( ) ∑

∑ − ∑( ) 



 



[ ] ∑ − ∑( ) 



 





/

/ /

( . ) /

2 2 2 2

1 2 27

(Eq. 27)

Where:

ep = Hourly value generated by the

alternative monitoring system.

ev = Hourly value generated by the

continuous emission monitoring

system.

n = Total number of hours for which

data were generated for the tests.

* * * * *

34. Section 75.47 is revised to read as

follows:

§ 75.47 Criteria for a class of affected

units.

(a) The owner or operator of an

affected unit that is determined by the

Administrator to be representative of a

class of affected units may petition the

Administrator under § 75.48 for

approval of an alternative monitoring

system that may be used at any unit in

that class based on testing performed

only at the representative unit.

(b) The owner or operator of an

affected unit representing a class of

affected units shall provide the

following information to obtain class

status:

(1) A description of the affected unit

at which the demonstration will be

performed and how it appropriately

represents the class of affected units;

and

(2) A description and listing of the

class of affected units, including a

listing of all units and data describing

all the affected units which will

comprise the class; and

(3) A demonstration that the

magnitude of emissions for all units

which will comprise the class of

affected units are de minimis.

(c) If the Administrator determines

that the emissions from all affected

units which will comprise the class of

units are de minimis, then the

Administrator shall publish notice in

the Federal Register of each request for

approval of class status and shall

provide a 30-day period for public

comment, prior to granting approval.

(d) The designated representative

shall provide the information required

in § 75.48 based on testing at the

representative unit when petitioning for

approval of the alternative monitoring

system for members of the class. A

request for class status under this

section may be submitted

simultaneously with a petition under

§ 75.48, or following approval of a

petition under § 75.48.

35. Section 75.48 is amended by

revising paragraphs (a) introductory

text, and (a)(1), and by adding

paragraphs (b) and (c) to read as follows:

§ 75.48 Petition for an alternative

monitoring system.

(a) The designated representative

shall submit the following information

in the petition for approval of an

alternative monitoring system for an

affected unit, or a class of affected units

approved pursuant to § 75.47.

(1) Source identification information

for the affected unit at which testing

was performed.

* * * * *

(b) The Administrator will publish a

notice of receipt of each petition for

approval of an alternative monitoring
26532 Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations

system in the Federal Register and,

following a public comment period of

30 days, will issue a notice of approval

or disapproval of the alternative

monitoring system.

(c) No alternative monitoring system

approved under this section shall be

used under the Acid Rain Program prior

to successful completion of all

certification tests under § 75.20(f).

Subpart F—Recordkeeping

Requirements

36. Section 75.50 is amended by

revising paragraph (a) to read as follows:

§ 75.50 General recordkeeping provisions.

(a) Recordkeeping requirements for

affected sources. The provisions of this

section shall remain in effect prior to

January 1, 1996. The owner or operator

shall meet the requirements of either

§§ 75.50 or 75.54 prior to January 1,

1996. On or after January 1, 1996, the

owner or operator shall meet the

requirements of § 75.54 only.

* * * * *

37. Section 75.51 is amended by

adding paragraph (e) to read as follows:

§ 75.51 General recordkeeping provisions

for specific situations.

* * * * *

(e) The provisions of this section shall

remain in effect prior to January 1, 1996.

The owner or operator shall meet the

requirements of either §§ 75.51 or 75.55

prior to January 1, 1996. On or after

January 1, 1996, the owner or operator

shall meet the requirements of § 75.55

only.

38. Section 75.52 is amended by

adding paragraph (b) to read as follows:

§ 75.52 Certification, quality assurance

and quality control record provisions.

(a) * * *

(b) The provisions of this section shall

remain in effect prior to January 1, 1996.

The owner or operator shall meet the

requirements of either §§ 75.52 or 75.56

prior to January 1, 1996. On or after

January 1, 1996, the owner or operator

shall meet the requirements of § 75.56

only.

39. Section 75.53 is amended by

revising paragraphs (a), (b), (c)

introductory text, (c)(1), (c)(2)(ii), (c)(4)

introductory text, (c)(4)(ii), (c)(4)(vi),

(c)(5)(ii), (c)(6), (c)(7), (c)(8), (c)(9),

(d)(1), and (d)(2) and by adding

paragraphs (c)(10), and (d)(3) to read as

follows:

§ 75.53 Monitoring plan.

(a) General provisions. The owner or

operator of an affected unit shall

prepare and maintain a monitoring plan.

Except as provided in paragraph (d) of

this section, a monitoring plan shall

contain sufficient information on the

continuous emission or opacity

monitoring systems or excepted

monitoring systems under appendix D

or E of this part and the use of data

derived from these systems to

demonstrate that all unit SO2 emissions,

NOX emissions, CO2 emissions, and

opacity are monitored and reported.

(b) Whenever the owner or operator

makes a replacement, modification, or

change, either in the certified

continuous emission monitoring system

or continuous opacity monitoring

system or excepted monitoring systems

under appendix D or E of this part,

including a change in the automated

data acquisition and handling system or

in the flue gas handling system, that

requires recertification, then the owner

or operator shall update the monitoring

plan.

(c) Contents of the monitoring plan.

Each monitoring plan shall contain the

following:

(1) Precertification information,

including, as applicable, the

identification of the test strategy,

protocol for the relative accuracy test

audit, other relevant test information,

span calculations, and apportionment

strategies under §§ 75.13 through 75.17

of this part.

(2) * * *

(ii) Classification of unit as one of the

following: Phase I (including

substitution or compensating units),

Phase II, new, or nonaffected;

* * * * *

(4) Monitoring component table.

Identification and description of each

monitoring component (including each

monitor and its identifiable components

such as analyzer and/or probe) in the

continuous emission monitoring

systems (i.e., SO2 pollutant

concentration monitor, flow monitor,

moisture monitor; NOX pollutant

concentration monitor and diluent gas

monitor) the continuous opacity

monitoring system, or excepted

monitoring system (i.e., fuel flowmeter,

data acquisition and handling system),

including:

* * * * *

(ii) Component/system identification

code assigned by the utility to each

identifiable monitoring component

(such as the analyzer and/or probe). The

code shall use a six-digit format, unique

to each monitoring component, where

the first three digits indicate the number

of the component and the second three

digits indicate the system to which the

component belongs;

* * * * *

(vi) A designation of the system as a

primary, redundant backup, nonredundant backup or reference method

backup system, as provided for in

§ 75.10(e).

(5) * * *

(ii) For software components,

identification of the provider and a brief

description of features;

* * * * *

(6) Emissions formula table. A table

giving explicit formulas for each

reported unit emission parameter, using

component/system identification codes

to link continuous emission monitoring

system or excepted monitoring system

observations with reported

concentrations, mass emissions, or

emission rates, according to the

conversions listed in appendix D, E, or

F to this part. The formulas must

contain all constants and factors

required to derive mass emissions or

emission rates from component/system

code observations, and each emissions

formula is identified with a unique

three digit code.

(7) Schematic stack diagrams. For

units monitored by a continuous

emission or opacity monitoring system,

a schematic diagram identifying entire

gas handling system from boiler to stack

for all affected units, using

identification numbers for units,

monitor components, and stacks

corresponding to the identification

numbers provided in paragraphs (c)(2),

(c)(4), (c)(5), and (c)(6) of this section.

The schematic diagram must depict

stack height and the height of any

monitor locations. Comprehensive and/

or separate schematic diagrams shall be

used to describe groups of units using

a common stack.

(8) Stack and duct engineering

diagrams. For units monitored by a

continuous emission or opacity

monitoring system, stack and duct

engineering diagrams showing the

dimensions and location of fans, turning

vanes, air preheaters, monitor

components, probes, reference method

sampling ports and other equipment

which affects the monitoring system

location, performance or quality control

checks.

(9) Inside crosssectional area (ft 2) at

flue exit and at flow monitoring

location.

(10) Span and calibration gas. A table

or description identifying maximum

potential concentration, maximum

expected concentration (if applicable),

maximum potential flow rate, maximum

potential NOX emission rate, span value,

and full-scale range for each SO2, NOX,

CO2, O2, or flow component monitor. In

addition, the table must identify
Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations 26533

calibration gas levels for the calibration

error test and the linearity check, and

calculations made to determine each

span value.

(d) * * *

(1) For each gas-fired unit or oil-fired

unit for which the owner or operator

uses the optional protocol in appendix

D of this part for estimating SO2 mass

emissions or appendix E of this part for

estimating NOX emission rate (using a

fuel flow meter), the designated

representative shall include in the

monitoring plan:

(i) A description of the fuel flowmeter

(and data demonstrating its flow meter

accuracy, when available);

(ii) The installation location of each

fuel flowmeter;

(iii) The fuel sampling location(s); and

(iv) Procedures used for calibrating

each fuel flowmeter.

(2) For each gas-fired peaking unit

and oil-fired peaking unit for which the

owner or operator uses the optional

procedures in appendix E of this part for

estimating NOX emission rate, the

designated representative shall include

in the monitoring plan:

(i) A protocol containing methods

used to perform the baseline or periodic

NOX emission test, and a copy of initial

performance test results (when such

results are available);

(ii) Unit operating and capacity factor

information demonstrating that the unit

qualifies as a peaking unit, as defined in

§ 72.2 of this chapter; and

(iii) Unit operating parameters related

to NOX formation by the unit.

(3) For each gas-fired unit and dieselfired unit or unit with a wet flue gas

pollution control system for which the

designated representative claims an

opacity monitoring exemption under

§ 75.14, the designated representative

shall include in the monitoring plan

information demonstrating that the unit

qualifies for the exemption.

40. Section 75.54 is added to read as

follows:

§ 75.54 General recordkeeping provisions.

(a) Recordkeeping requirements for

affected sources. On or after January 1,

1996, the owner or operator shall meet

the requirements of this section. The

owner or operator of any affected source

subject to the requirements of this part

shall maintain for each affected unit a

file of all measurements, data, reports,

and other information required by this

part at the source in a form suitable for

inspection for at least three (3) years

from the date of each record. Unless

otherwise provided, throughout this

subpart the phrase ‘‘for each affected

unit’’ also applies to each group of

affected or nonaffected units utilizing a

common stack and common monitoring

systems, pursuant to §§ 75.13 through

75.18, or utilizing a common pipe

header and common fuel flowmeter,

pursuant to section 2.1.2 of appendix D

of this part. The file shall contain the

following information:

(1) The data and information required

in paragraphs (b) through (f) of this

section, beginning with the earlier of the

date of provisional certification, or the

deadline in § 75.4(a), (b) or (c);

(2) The supporting data and

information used to calculate values

required in paragraphs (b) through (f) of

this section, excluding the subhourly

data points used to compute hourly

averages under § 75.10(d), beginning

with the earlier of the date of

provisional certification, or the deadline

in § 75.4(a), (b) or (c);

(3) The data and information required

in § 75.55 of this part for specific

situations, as applicable, beginning with

the earlier of the date of provisional

certification, or the deadline in § 75.4(a),

(b) or (c);

(4) The certification test data and

information required in § 75.56 for tests

required under § 75.20, beginning with

the date of the first certification test

performed, and the quality assurance

and quality control data and

information required in § 75.56 for tests

and the quality assurance/quality

control plan required under § 75.21 and

appendix B of this part, beginning with

the date of provisional certification;

(5) The current monitoring plan as

specified in § 75.53, beginning with the

initial submission required by § 75.62;

and

(6) The quality control plan as

described in appendix B to this part,

beginning with the date of provisional

certification.

(b) Operating parameter record

provisions. The owner or operator shall

record for each hour the following

information on unit operating time, heat

input, and load separately for each

affected unit, and also for each group of

units utilizing a common stack and a

common monitoring system or utilizing

a common pipe header and common

fuel flowmeter, except that separate heat

input data for each unit shall not be

required after January 1, 2000 for any

unit, other than an opt-in source, that

does not have a NOX emission

limitation under part 76 of this chapter.

(1) Date and hour;

(2) Unit operating time (rounded up to

nearest 15 minutes);

(3) Total hourly gross unit load

(rounded to nearest MWge) (or steam

load in lb/hr at stated temperature and

pressure, rounded to the nearest 1000

lb/hr, if elected in the monitoring plan);

(4) Operating load range

corresponding to total gross load of 1–

10, except for units using a common

stack or common pipe header, which

may use the number of unit load ranges

up to 20 for flow, as specified in the

monitoring plan; and

(5) Total heat input (mmBtu, rounded

to the nearest tenth).

(c) SO2 emission record provisions.

The owner or operator shall record for

each hour the information required by

this paragraph for each affected unit or

group of units using a common stack

and common monitoring systems,

except as provided under § 75.11(e) or

for a gas-fired or oil-fired unit for which

the owner or operator is using the

optional protocol in appendix D to this

part for estimating SO2 mass emissions:

(1) For SO2 concentration, as

measured and reported from each

certified primary monitor, certified

back-up monitor, or other approved

method of emissions determination:

(i) Component-system identification

code as provided for in § 75.53;

(ii) Date and hour;

(iii) Hourly average SO2 concentration

(ppm, rounded to the nearest tenth);

(iv) Hourly average SO2 concentration

(ppm, rounded to the nearest tenth)

adjusted for bias, if bias adjustment

factor is required as provided for in

§ 75.24(d);

(v) Percent monitor data availability

(recorded to the nearest tenth of a

percent) calculated pursuant to § 75.32;

and

(vi) Method of determination for

hourly average SO2 concentration using

Codes 1–15 in Table 4 of this section.

(2) For flow as measured and reported

from each certified primary monitor,

certified back-up monitor or other

approved method of emissions

determination:

(i) Component/system identification

code as provided for in § 75.53;

(ii) Date and hour;

(iii) Hourly average volumetric flow

rate (in scfh, rounded to the nearest

thousand);

(iv) Hourly average volumetric flow

rate (in scfh, rounded to the nearest

thousand) adjusted for bias, if bias

adjustment factor required as provided

for in § 75.24(d);

(v) Hourly average moisture content of

flue gases (percent, rounded to the

nearest tenth) where SO2 concentration

is measured on dry basis;

(vi) Percent monitor data availability

(recorded to the nearest tenth of a

percent), calculated pursuant to § 75.32;

and

(vii) Method of determination for

hourly average flow rate using Codes 1–

15 in Table 4.
26534 Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations

(3) For SO2 mass emissions as

measured and reported from the

certified primary monitoring system(s),

certified redundant or non-redundant

back-up monitoring system(s), or other

approved method(s) of emissions

determination:

(i) Date and hour;

(ii) Hourly SO2 mass emissions (lb/hr,

rounded to the nearest tenth);

(iii) Hourly SO2 mass emissions (lb/

hr, rounded to the nearest tenth)

adjusted for bias, if bias adjustment

factor required, as provided for in

§ 75.24(d); and

(iv) Identification code for emissions

formula used to derive hourly SO2 mass

emissions from SO2 concentration and

flow data in paragraphs (c)(1) and (c)(2)

of this section as provided for in § 75.53.

TABLE 4.—CODES FOR METHOD OF

EMISSIONS AND FLOW DETERMINATION

[Amended]

Code Hourly emissions/flow measurement or estimation method

1 ........ Certified primary emission/flow

monitoring system.

2 ........ Certified back-up emission/flow

monitoring system.

3 ........ Approved alternative monitoring

system.

4 ........ Reference method:

SO2: Method 6C.

Flow: Method 2.

NOX: Method 7E.

CO2 or O2: Method 3A.

5 ........ For units with add-on SO2 and/or

NOX emission controls: SO2 concentration or NOX emission rate

estimate from Agency

preapproved parametric monitoring method.

6 ........ Average of the hourly SO2 concentrations, CO2 concentrations,

flow, or NOX emission rate for

the hour before and the hour following a missing data period.

7 ........ Hourly average SO2 concentration,

CO2 concentration, flow rate, or

NOX emission rate using initial

missing data procedures.

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

emission rate.

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

emission rate.

10 ........ Maximum hourly SO2 concentration, flow rate, or NOX emission

rate.

11 ........ Hourly average flow rate or NOX

emission rate in corresponding

load range.

12 ........ Maximum potential concentration of

SO2, maximum potential flow

rate, or maximum potential NOX

emission rate, as determined

using section 2.1 of appendix A

of this part, or maximum CO2

concentration.

TABLE 4.—CODES FOR METHOD OF

EMISSIONS AND FLOW DETERMINATION—Continued

[Amended]

Code Hourly emissions/flow measurement or estimation method

13 ........ Other data (specify method).

14 ........ Minimum CO2 concentration of 5.0

percent CO2 or maximum O2

concentration of 14.0 percent to

be substituted optionally for

measured diluent gas concentrations during unit startup, for NOX

emission rate or SO2 emission

rate in lb/mmBtu or for CO2 concentration.

15 ........ Fuel analysis data from appendix G

of this part for CO2 mass emissions.

(d) NOX emission record provisions.

The owner or operator shall record the

information required by this paragraph

for each affected unit for each hour,

except for a gas-fired peaking unit or oilfired peaking unit for which the owner

or operator is using the optional

protocol in appendix E to this part for

estimating NOX emission rate. For each

NOX emission rate as measured and

reported from the certified primary

monitor, certified back-up monitor, or

other approved method of emissions

determination:

(1) Component/system identification

code as provided for in § 75.53;

(2) Date and hour;

(3) Hourly average NOX concentration

(ppm, rounded to the nearest tenth);

(4) Hourly average diluent gas

concentration (percent O2 or percent

CO2, rounded to the nearest tenth);

(5) Hourly average NOX emission rate

(lb/mmBtu, rounded to nearest

hundredth);

(6) Hourly average NOX emission rate

(lb/mmBtu, rounded to nearest

hundredth) adjusted for bias, if bias

adjustment factor is required as

provided for in § 75.24(d);

(7) Percent monitoring system data

availability, (recorded to the nearest

tenth of a percent), calculated pursuant

to § 75.32;

(8) Method of determination for

hourly average NOX emission rate using

Codes 1–15 in Table 4; and

(9) Identification code for emissions

formula used to derive hourly average

NOX emission rate, as provided for in

§ 75.53.

(e) CO2 emission record provisions.

The owner or operator shall record or

calculate CO2 emissions for each

affected unit using one of the following

methods specified in this section:

(1) If the owner or operator chooses to

use a CO2 continuous emission

monitoring system (including an O2

monitor and flow monitor as specified

in appendix F of this part), then the

owner or operator shall record for each

hour the following information for CO2

mass emissions, as measured and

reported from the certified primary

monitor, certified back-up monitor, or

other approved method of emissions

determination:

(i) Component/system identification

code as provided for in § 75.53;

(ii) Date and hour;

(iii) Hourly average CO2 concentration

(in percent, rounded to the nearest

tenth);

(iv) Hourly average volumetric flow

rate (scfh, rounded to the nearest

thousand scfh);

(v) Hourly CO2 mass emissions (tons/

hr, rounded to the nearest tenth);

(vi) Percent monitor data availability

(recorded to the nearest tenth of a

percent); calculated pursuant to § 75.32;

(vii) Method of determination for

hourly CO2 mass emissions using Codes

1–15 in Table 4; and

(viii) Identification code for emissions

formula used to derive average hourly

CO2 mass emissions, as provided for in

§ 75.53.

(2) As an alternative to § 75.54(e)(1),

the owner or operator may use the

procedures in § 75.13 and in appendix

G to this part, and shall record daily the

following information for CO2 mass

emissions:

(i) Date;

(ii) Daily combustion-formed CO2

mass emissions (tons/day, rounded to

the nearest tenth);

(iii) For coal-fired units, flag

indicating whether optional procedure

to adjust combustion-formed CO2 mass

emissions for carbon retained in flyash

has been used and, if so, the adjustment;

(iv) For a unit with a wet flue gas

desulfurization system or other controls

generating CO2, daily sorbent-related

CO2 mass emissions (tons/day, rounded

to the nearest tenth); and

(v) For a unit with a wet flue gas

desulfurization system or other controls

generating CO2, total daily CO2 mass

emissions (tons/day, rounded to the

nearest tenth) as sum of combustionformed emissions and sorbent-related

emissions.

(f) Opacity records. The owner or

operator shall record opacity data as

specified by the State or local air

pollution control agency. If the State or

local air pollution control agency does

not specify recordkeeping requirements

for opacity, then record the information

required by paragraphs (f) (1) through

(5) of this section for each affected unit,

except as provided for in § 75.14 (b), (c),

and (d). The owner or operator shall
Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations 26535

also keep records of all incidents of

opacity monitor downtime during unit

operation, including reason(s) for the

monitor outage(s) and any corrective

action(s) taken for opacity, as measured

and reported by the continuous opacity

monitoring system:

(1) Component/system identification

code;

(2) Date, hour, and minute;

(3) Average opacity of emissions for

each six minute averaging period (in

percent opacity);

(4) If the average opacity of emissions

exceeds the applicable standard, then a

code indicating such an exceedance has

occurred; and

(5) Percent monitor data availability,

recorded to the nearest tenth of a

percent, calculated according to the

requirements of the procedure

recommended for State Implementation

Plans in appendix M of part 51 of this

chapter.

41. Section 75.55 is added to read as

follows:

§ 75.55 General recordkeeping provisions

for specific situations.

(a) Specific SO2 emission record

provisions for units with qualifying

Phase I technology. In addition to the

SO2 emissions information required in

§ 75.54(c), from January 1, 1997, through

December 31, 1999, the owner or

operator shall record the applicable

information in this paragraph for each

affected unit on which SO2 emission

controls have been installed and

operated for the purpose of meeting

qualifying Phase I technology

requirements pursuant to § 72.42 of this

chapter and § 75.15.

(1) For units with post-combustion

emission controls:

(i) Component/system identification

codes for each inlet and outlet SO2-

diluent continuous emission monitoring

system;

(ii) Date and hour;

(iii) Hourly average inlet SO2

emission rate (lb/mmBtu, rounded to

nearest hundredth);

(iv) Hourly average outlet SO2

emission rate (lb/mmBtu, rounded to

nearest hundredth);

(v) Percent data availability for both

inlet and outlet SO2-diluent continuous

emission monitoring systems (recorded

to the nearest tenth of a percent),

calculated pursuant to Equation 8 of

§ 75.32 (for the first 8,760 unit operating

hours following initial certification) and

Equation 9 of § 75.32, thereafter; and

(vi) Identification code for emissions

formula used to derive hourly average

inlet and outlet SO2 mass emissions

rates for each affected unit or group of

units using a common stack.

(2) For units with combustion and/or

pre-combustion emission controls:

(i) Component/system identification

codes for each outlet SO2-diluent

continuous emission monitoring system;

(ii) Date and hour;

(iii) Hourly average outlet SO2

emission rate (lb/mmBtu, rounded to

nearest hundredth);

(iv) For units with combustion

controls, average daily inlet SO2

emission rate (lb/mmBtu, rounded to

nearest hundredth), determined by coal

sampling and analysis procedures in

§ 75.15; and

(v) For units with pre-combustion

controls (i.e., fuel pretreatment), fuel

analysis demonstrating the weight,

sulfur content, and gross calorific value

of the product and raw fuel lots.

(b) [Reserved]

(c) Specific SO2 emission record

provisions for gas-fired or oil-fired units

using optional protocol in appendix D

of this part. In lieu of recording the

information in § 75.54(c) of this section,

the owner or operator shall record the

applicable information in this paragraph

for each affected gas-fired or oil-fired

unit for which the owner or operator is

using the optional protocol in appendix

D of this part for estimating SO2 mass

emissions.

(1) For each hour when the unit is

combusting oil:

(i) Date and hour;

(ii) Hourly average flow rate of oil

with the units in which oil flow is

recorded, (gal/hr, lb/hr, m3/hr, or bbl/hr,

rounded to the nearest tenth)(flag value

if derived from missing data

procedures);

(iii) Sulfur content of oil sample used

to determine SO2 mass emissions,

rounded to nearest hundredth for diesel

fuel or to the nearest tenth of a percent

for other fuel oil (flag value if derived

from missing data procedures);

(iv) Method of oil sampling (flow

proportional, continuous drip, as

delivered or manual);

(v) Mass of oil combusted each hour

(lb/hr, rounded to the nearest tenth);

(vi) SO2 mass emissions from oil (lb/

hr, rounded to the nearest tenth);

(vii) For units using volumetric oil

flowmeters, density of oil (flag value if

derived from missing data procedures);

(viii) Gross calorific value (heat

content) of oil, used to determine heat

input (Btu/mass unit) (flag value if

derived from missing data procedures);

(ix) Hourly heat input rate from oil

according to procedures in appendix F

of this part (mmBtu/hr, to the nearest

tenth); and

(x) Fuel usage time for combustion of

oil during the hour, rounded up to the

nearest 15 min.

(2) For gas-fired units or oil-fired

units using the optional protocol in

appendix D of this part of daily manual

oil sampling, when the unit is

combusting oil, the highest sulfur

content recorded from the most recent

30 daily oil samples rounded to nearest

tenth of a percent.

(3) For each hour when the unit is

combusting gaseous fuel,

(i) Date and hour;

(ii) Hourly heat input rate from

gaseous fuel according to procedures in

appendix F to this part (mmBtu/hr,

rounded to the nearest tenth);

(iii) Sulfur content or SO2 emission

rate, in one of the following formats, in

accordance with the appropriate

procedure from appendix D of this part:

(A) Sulfur content of gas sample,

(rounded to the nearest 0.1 grains/100

scf) (flag value if derived from missing

data procedures); or

(B) SO2 emission rate of 0.0006 lb/

mmBtu for pipeline natural gas;

(iv) Hourly flow rate of gaseous fuel,

in 100 scfh (flag value if derived from

missing data procedures);

(v) Gross calorific value (heat content)

of gaseous fuel, used to determine heat

input (Btu/scf) (flag value if derived

from missing data procedures);

(vi) Heat input rate from gaseous fuel

(mmBtu/hr, rounded to the nearest

tenth);

(vii) SO2 mass emissions due to the

combustion of gaseous fuels, lb/hr; and

(viii) Fuel usage time for combustion

of gaseous fuel during the hour,

rounded up to the nearest 15 min.

(4) For each oil sample or sample of

diesel fuel:

(i) Date of sampling;

(ii) Sulfur content (percent, rounded

to the nearest hundredth for diesel fuel

and to the nearest tenth for other fuel

oil) (flag value if derived from missing

data procedures);

(iii) Gross calorific value or heat

content (Btu/lb) (flag value if derived

from missing data procedures); and

(iv) Density or specific gravity, if

required to convert volume to mass (flag

value if derived from missing data

procedures).

(5) For each daily sample of gaseous

fuel:

(i) Date of sampling;

(ii) Sulfur content (grains/100 scf,

rounded to the nearest tenth) (flag value

if derived from missing data

procedures);

(6) For each monthly sample of

gaseous fuel:

(i) Date of sampling;

(ii) Gross calorific value or heat

content (Btu/scf) (flag value if derived

from missing data procedures).

(d) Specific NOX emission record

provisions for gas-fired peaking units or
26536 Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations

oil-fired peaking units using optional

protocol in appendix E of this part. In

lieu of recording the information in

paragraph § 75.54(d), the owner or

operator shall record the applicable

information in this paragraph for each

affected gas-fired peaking unit or oilfired peaking unit for which the owner

or operator is using the optional

protocol in appendix E of this part for

estimating NOX emission rate.

(1) For each hour when the unit is

combusting oil,

(i) Date and hour;

(ii) Hourly average fuel flow rate of oil

with the units in which oil flow is

recorded (gal/hour, lb/hr or bbl/hour)

(flag value if derived from missing data

procedures);

(iii) Gross calorific value (heat

content) of oil, used to determine heat

input (Btu/lb) (flag value if derived from

missing data procedures);

(iv) Hourly average NOX emission rate

from combustion of oil (lb/mmBtu);

(v) Heat input rate of oil (mmBtu/hr,

rounded to the nearest tenth); and

(vi) Fuel usage time for combustion of

oil during the hour, rounded to the

nearest 15 min.

(2) For each hour when the unit is

combusting gaseous fuel,

(i) Date and hour;

(ii) Hourly average fuel flow rate of

gaseous fuel (100 scfh) (flag value if

derived from missing data procedures);

(iii) Gross calorific value (heat

content) of gaseous fuel, used to

determine heat input (Btu/scf) (flag

value if derived from missing data

procedures);

(iv) Hourly average NOX emission rate

from combustion of gaseous fuel (lb/

mmBtu, rounded to nearest hundredth);

(v) Heat input rate from gaseous fuel

(mmBtu/hr, rounded to the nearest

tenth); and

(vi) Fuel usage time for combustion of

gaseous fuel during the hour, rounded

to the nearest 15 min.

(3) For each hour when the unit

combusts any fuel:

(i) Date and hour;

(ii) Total heat input from all fuels

(mmBtu, rounded to the nearest tenth);

(iii) Hourly average NOX emission rate

for the unit for all fuels;

(iv) For stationary gas turbines and

diesel or dual-fuel reciprocating

engines, hourly averages of operating

parameters under section 2.3 of

appendix E (flag if value is outside of

manufacturer’s recommended range);

(v) For boilers, hourly average boiler

O2 reading (percent, rounded to the

nearest tenth) (flag if value exceeds by

more than 2 percentage points the O2

level recorded at the same heat input

during the previous NOX emission rate

test).

(4) For each fuel sample:

(i) Date of sampling;

(ii) Gross calorific value (heat content)

(Btu/lb for oil, Btu/scf for gaseous fuel);

and

(iii) Density or specific gravity, if

required to convert volume to mass.

(e) [Reserved]

(f) The owner or operator shall meet

the requirements of this section on or

after January 1, 1996.

42. Section 75.56 is added to read as

follows:

§ 75.56 Certification, quality assurance

and quality control record provisions.

(a) Continuous emission or opacity

monitoring systems. The owner or

operator shall record the applicable

information in this section for each

certified monitor or certified monitoring

system (including certified backup

monitors) measuring and recording

emissions or flow from an affected unit.

(1) For each SO2 or NOX pollutant

concentration monitor, flow monitor,

CO2 monitor, or diluent gas monitor, the

owner or operator shall record the

following for all daily and 7-day

calibration error tests, including any

follow-up tests after corrective action:

(i) Component/system identification

code;

(ii) Instrument span;

(iii) Date and hour;

(iv) Reference value, (i.e., calibration

gas concentration or reference signal

value, in ppm or other appropriate

units);

(v) Observed value (monitor response

during calibration, in ppm or other

appropriate units);

(vi) Percent calibration error (rounded

to nearest tenth of a percent); and

(vii) For 7-day calibration tests for

certification or recertification, a

certification from the cylinder gas

vendor or CEMS vendor, that calibration

gas as defined in § 72.2 and appendix A

of this part, were used to conduct

calibration error testing; and

(viii) Description of any adjustments,

corrective actions, or maintenance

following test.

(2) For each flow monitor, the owner

or operator shall record the following

for all daily interference checks,

including any follow-up tests after

corrective action:

(i) Code indicating whether monitor

passes or fails the interference check;

and

(ii) Description of any adjustments,

corrective actions, or maintenance

following test.

(3) For each SO2 or NOX pollutant

concentration monitor, CO2 monitor, or

diluent gas monitor, the owner or

operator shall record the following for

the initial and all subsequent linearity

check(s), including any follow-up tests

after corrective action:

(i) Component/system identification

code;

(ii) Instrument span;

(iii) Date and hour;

(iv) Reference value (i.e., reference gas

concentration, in ppm or other

appropriate units);

(v) Observed value (average monitor

response at each reference gas

concentration, in ppm or other

appropriate units);

(vi) Percent error at each of three

reference gas concentrations (rounded to

nearest tenth of a percent); and

(vii) Description of any adjustments,

corrective action, or maintenance

following test.

(4) For each flow monitor, where

applicable, the owner or operator shall

record the following for all quarterly

leak checks, including any follow-up

tests after corrective action:

(i) Code indicating whether monitor

passes or fails the quarterly leak check;

and

(ii) Description of any adjustments,

corrective actions, or maintenance

following test.

(5) For each SO2 pollutant

concentration monitor, flow monitor,

CO2 pollutant concentration monitor;

NOX continuous emission monitoring

system, SO2-diluent continuous

emission monitoring system, and

approved alternative monitoring system,

the owner or operator shall record the

following information for the initial and

all subsequent relative accuracy tests

and test audits:

(i) Date and hour;

(ii) Reference method(s) used;

(iii) Individual test run data from the

relative accuracy test audit for the SO2

concentration monitor, flow monitor,

CO2 pollutant concentration monitor,

NOX continuous emission monitoring

system, SO2-diluent continuous

emission monitoring system, or

approved alternative monitoring

systems, including:

(A) Date, hour, and minute of

beginning of test run,

(B) Date, hour, and minute of end of

test run,

(C) Component/system identification

code,

(D) Run number,

(E) Run data for monitor;

(F) Run data for reference method;

and

(G) Flag value (0 or 1) indicating

whether run has been used in

calculating relative accuracy and bias

values.

(iv) Calculations and tabulated

results, as follows:
Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations 26537

(A) Arithmetic mean of the

monitoring system measurement values,

reference method values, and of their

differences, as specified in Equation A–

7 in appendix A to this part.

(B) Standard deviation, as specified in

Equation A–8 in appendix A to this

part.

(C) Confidence coefficient, as

specified in Equation A–9 in appendix

A to this part.

(D) Relative accuracy test results, as

specified in Equation A–10 in appendix

A to this part. (For the 3-level flow

monitor test only, relative accuracy test

results should be recorded at each of

three gas velocities. Each of these three

gas velocities shall be expressed as a

total gross unit load, rounded to the

nearest MWe or as steam load, rounded

to the nearest thousand lb/hr.)

(E) Bias test results as specified in

section 7.6.4 in appendix A to this part.

(F) Bias adjustment factor from

Equations A–11 and A–12 in appendix

A to this part for any monitoring system

or component that failed the bias test

and 1.0 for any monitoring system or

component that passed the bias test.

(For flow monitors only, bias

adjustment factors should be recorded at

each of three gas velocities).

(v) Description of any adjustment,

corrective action, or maintenance

following test.

(vi) F-factor value(s) used to convert

NOX pollutant concentration and

diluent gas (O2 or CO2) concentration

measurements into NOX emission rates

(in lb/mmBtu), heat input or CO2

emissions.

(6) [Reserved]

(7) Results of all trial runs and

certification tests and quality assurance

activities and measurements (including

all reference method field test sheets,

charts, records of combined system

responses, laboratory analyses, and

example calculations) necessary to

substantiate compliance with all

relevant appendices in this part. This

information shall include, but shall not

be limited to, the following reference

method data:

(i) For each run of each test using

Method 2 in appendix A of part 60 of

this chapter to determine volumetric

flow rate:

(A) Pitot tube coefficient;

(B) Date of pitot tube calibration;

(C) Average square root of velocity

head of stack gas (inches of water) for

the run;

(D) Average absolute stack gas

temperature, °R;

(E) Barometric pressure at test port,

inches of mercury;

(F) Stack static pressure, inches of

H2O;

(G) Absolute stack gas pressure,

inches of mercury;

(H) Moisture content of stack gas,

percent;

(I) Molecular weight of stack gas, wet

basis (lb/lb-mole);

(J) Number of reference method

measurements during the run; and

(K) Total volumetric flowrate (scfh,

wet basis).

(ii) For each test using Method 2 in

appendix A of part 60 of this chapter to

determine volumetric flow rate:

(A) Information indicating whether or

not the location meets requirements of

Method 1 in appendix A of part 60 of

this chapter;

(B) Information indicating whether or

not the equipment passed the leak check

after every run included in the relative

accuracy test;

(C) Stack inside diameter at test port

(ft);

(D) Duct side height and width at test

port (ft);

(E) Stack or duct cross-sectional area

at test port (ft2); and

(F) Designation as to the load level of

the test.

(iii) For each run of each test using

Method 6C, 7E, or 3A in appendix A of

part 60 of this chapter to determine SO2,

NOX, CO2, or O2 concentration:

(A) Run start date;

(B) Run start time;

(C) Run end date;

(D) Run end time;

(E) Span of reference method

analyzer;

(F) Reference gas concentration (low,

mid-, and high gas levels);

(G) Initial and final analyzer

calibration response (low, mid- and high

gas levels);

(H) Analyzer calibration error (low,

mid-, and high gas levels);

(I) Pre-test and post-test analyzer bias

(zero and upscale gas levels);

(J) Calibration drift and zero drift of

analyzer;

(K) Indication as to which data are

from a pretest and which are from a

posttest;

(L) Calibration gas level (zero, midlevel, or high); and

(M) Moisture content of stack gas, in

percent, if needed to convert to moisture

basis of CEMS being tested.

(iv) For each test using Method 6C,

7E, or 3A in appendix A of part 60 of

this chapter to determine SO2, NOX CO2,

or O2 concentration:

(A) Pollutant being measured;

(B) Test number;

(C) Date of interference test;

(D) Results of interference test;

(E) Date of NO2 to NO conversion test

(Method 7E only);

(F) Results of NO2 to NO conversion

test (Method 7E only).

(v) For each calibration gas cylinder

used to test using Method 6C, 7E, or 3A

in appendix A of part 60 of this chapter

to determine SO2, NOX, CO2, or O2

concentration:

(A) Cylinder gas vendor name from

certification;

(B) Cylinder number;

(C) Cylinder expiration date;

(D) Pollutant(s) in cylinder; and

(E) Cylinder gas concentration(s).

(b) Excepted monitoring systems for

gas-fired and oil-fired units. The owner

or operator shall record the applicable

information in this section for each

excepted monitoring system following

the requirements of appendix D of this

part or appendix E of this part for

determining and recording emissions

from an affected unit.

(1) For each oil-fired unit or gas-fired

unit using the optional procedures of

appendix D of this part for determining

SO2 mass emissions and heat input or

the optional procedures of appendix E

of this part for determining NOX

emission rate, for certification and

quality assurance testing of fuel

flowmeters:

(i) Date of test,

(ii) Upper range value of the fuel

flowmeter,

(iii) Flowmeter measurements during

accuracy test,

(iv) Reference flow rates during

accuracy test,

(v) Average flowmeter accuracy as a

percent of upper range value,

(vi) Fuel flow rate level (low, midlevel, or high); and

(vi) Description of fuel flowmeter

calibration specification or procedure

(in the certification application, or

periodically if a different method is

used for annual quality assurance

testing).

(2) For gas-fired peaking units or oilfired peaking units using the optional

procedures of appendix E of this part,

for each initial performance, periodic, or

quality assurance/quality control-related

test:

(i) For each run of emissions data;

(A) Run start date and time;

(B) Run end date and time;

(C) Fuel flow (lb/hr, gal/hr, scf/hr,

bbl/hr, or m3/hr);

(D) Gross calorific value (heat content)

of fuel (Btu/lb or Btu/scf);

(E) Density of fuel (if needed to

convert mass to volume);

(F) Total heat input during the run

(mmBtu);

(G) Hourly heat input rate for run

(mmBtu/hr);

(H) Response time of the O2 and NOX

reference method analyzers;

(I) NOX concentration (ppm);

(J) O2 concentration (percent O2);
26538 Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations

(K) NOX emission rate (lb/mmBtu);

and

(L) Fuel or fuel combination (by heat

input fraction) combusted.

(ii) For each unit load and heat input;

(A) Average NOX emission rate (lb/

mmBtu);

(B) F-factor used in calculations;

(C) Average heat input rate (mmBtu/

hr);

(D) Unit operating parametric data

related to NOX formation for that unit

type (e.g., excess O2 level, water/fuel

ratio); and

(E) Fuel or fuel combination (by heat

input fraction) combusted.

(iii) For each test report;

(A) Graph of NOX emission rate

against heat input rate;

(B) Results of the tests for verification

of the accuracy of emissions

calculations and missing data

procedures performed by the automated

data acquisition and handling system,

and the calculations used to produce

NOX emission rate data at different heat

input conditions; and

(C) Results of all certification tests

and quality assurance activities and

measurements (including reference

method field test sheets, charts,

laboratory analyses, example

calculations, or other data as

appropriate), necessary to substantiate

compliance with the requirements of

appendix E of this part.

(c) The owner or operator shall meet

the requirements of this section on or

after January 1, 1996.

Subpart G—Reporting Requirements

43. Section 75.60 is amended by

revising paragraphs (b)(1) and (b)(2),

and by adding paragraph (c) to read as

follows:

§ 75.60 General provisions.

* * * * *

(b) * * *

(1) All initial certification or

recertification testing notifications,

initial certification or recertification

applications, monitoring plans,

petitions for alternative monitoring

systems, notifications, electronic

quarterly reports, and other

communications required by this

subpart shall be submitted to the

Administrator.

(2) Copies of initial certification or

recertification testing notifications,

certification or recertification

applications and monitoring plans shall

be submitted to the appropriate

Regional office of the U.S.

Environmental Protection Agency and

appropriate State or local air pollution

control agency.

(c) Confidentiality of data. The

following provisions shall govern the

confidentiality of information submitted

under this part.

(1) All emission data reported in

quarterly reports under § 75.64 shall

remain public information.

(2) For information submitted under

this part other than emission data

submitted in quarterly reports, the

designated representative must assert a

claim of confidentiality at the time of

submission for any information he or

she wishes to have treated as

confidential business information (CBI)

under subpart B of part 2 of this chapter.

Failure to assert a claim of

confidentiality at the time of submission

may result in disclosure of the

information by EPA without further

notice to the designated representative.

(3) Any claim of confidentiality for

information submitted in quarterly

reports under § 75.64 must include

substantiation of the claim. Failure to

provide substantiation may result in

disclosure of the information by EPA

without further notice.

(4) As provided under subpart B of

part 2 of this chapter, EPA may review

information submitted to determine

whether it is entitled to confidential

treatment even when confidentiality

claims are initially received. The EPA

will contact the designated

representative as part of such a review

process.

44. Section 75.61 is revised to read as

follows:

§ 75.61 Notifications.

(a) Submission. The designated

representative for an affected unit (or

owner or operator, as specified) shall

submit notice to the Administrator, to

the appropriate EPA Regional Office,

and to the applicable State air pollution

control agency for the following

purposes, as required by this part.

(1) Initial certification and

recertification test notifications. The

owner or operator or designated

representative for an affected unit shall

submit written notification of initial

certification tests, recertification tests,

and revised test dates as specified in

§ 75.20 for continuous emission

monitoring systems, for alternative

monitoring systems under subpart E of

this part, or for excepted monitoring

systems under appendix E of this part,

except as provided in paragraph (a)(4) of

this section and except for testing only

of the data acquisition and handling

system.

(i) Notification of initial certification

testing. Initial certification test

notifications shall be submitted not later

than 45 days prior to the first scheduled

day of initial certification testing.

Testing may be performed on a date

other than that already provided in a

notice under this subparagraph as long

as notice of the new date is provided

either in writing or by telephone or

other means at least 7 days prior to the

original scheduled test date or the

revised test date, whichever is earlier.

(ii) Notification of certification

retesting and recertification testing. For

retesting following a loss of certification

under § 75.20(a)(5) or for recertification

under § 75.20(b), notice of testing shall

be submitted either in writing or by

telephone at least 7 days prior to the

first scheduled day of testing; except

that in emergency situations when

testing is required following an

uncontrollable failure of equipment that

results in lost data, notice shall be

sufficient if provided within 2 business

days following the date when testing is

scheduled. Testing may be performed

on a date other than that already

provided in a notice under this

subparagraph as long as notice of the

new date is provided by telephone or

other means at least 2 business 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 test

immediately, without advance

notification, whenever the owner or

operator has determined during the

certification testing that a test was failed

or that a second test is necessary in

order to attain a reduced relative

accuracy test frequency.

(2) New unit, newly affected unit, new

stack, or new flue gas desulfurization

system operation notification. The

designated representative for an affected

unit shall submit written notification:

For a new unit or a newly affected unit,

of the planned date when a new unit or

newly affected unit will commence

commercial operation or, for new stack

or flue gas desulfurization system, of the

planned date when a new stack or flue

gas desulfurization system will be

completed and emissions will first exit

to the atmosphere.

(i) Notification of the planned date

shall be submitted not later than 45 days

prior to the date the unit commences

commercial operation, or not later than

45 days prior to the date when a new

stack or flue gas desulfurization system

exhausts emissions to the atmosphere.

(ii) If the date when the unit

commences commercial operation or the

date when the new stack or flue gas

desulfurization system exhausts

emissions to the atmosphere, whichever
Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations 26539

is applicable, changes from the planned

date, a notification of the actual date

shall be submitted not later than 7 days

following: The date the unit commences

commercial operation or, the date when

a new stack or flue gas desulfurization

system exhausts emissions to the

atmosphere.

(3) Unit shutdown and

recommencement of commercial

operation. The designated

representative for an affected unit that

will be shutdown on the relevant

compliance date in § 75.4(a) and that is

relying on the provisions in § 75.4(d) to

postpone certification testing shall

submit notification of unit shutdown

and recommencement of commercial

operation as follows:

(i) For planned unit shutdowns,

written notification of the planned

shutdown date and planned date of

recommencement of commercial

operation shall be submitted 45

calendar days prior to the deadline in

§ 75.4(a). For unit shutdowns that are

not planned 45 days prior to the

deadline in § 75.4(a), written

notification of the planned shutdown

date and planned date of

recommencement of commercial

operation shall be submitted no later

than 7 days after the date the owner or

operator is able to schedule the

shutdown date and date of

recommencement of commercial

operation. If the actual shutdown date

or the actual date of recommencement

of commercial operation differs from the

planned date, written notice of the

actual date shall be submitted no later

than 7 days following the actual date of

shutdown or of recommencement of

commercial operation, as applicable;

(ii) For unplanned unit shutdowns,

written notification of actual shutdown

date and the expected date of

recommencement of commercial

operation shall be submitted no later

than 7 days after the shutdown. If the

actual date of recommencement of

commercial operation differs from the

expected date, written notice of the

actual date shall be submitted no later

than 7 days following the actual date of

recommencement of commercial

operation.

(4) Use of backup fuels for appendix

E procedures. The designated

representative for an affected oil-fired or

gas-fired peaking unit that is using an

excepted monitoring system under

appendix E of this part and that is

relying on the provisions in § 75.4(f) to

postpone testing of a fuel shall submit

written notification of that fact no later

than 45 days prior to the deadline in

§ 75.4(a). The designated representative

shall also submit a notification that such

a fuel has been combusted no later than

7 days after the first date of combustion

of any fuel for which testing has not

been performed under appendix E after

the deadline in § 75.4(a). Such notice

shall also include notice that testing

under Appendix E either was performed

during the initial combustion or notice

of the date that testing will be

performed.

(5) Periodic relative accuracy test

audits. 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 appendix B of this part

no later than 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

subparagraph as long as notice of the

new date is provided either in writing

or by telephone or other means at least

7 days prior to the original scheduled

test date or the revised test date,

whichever is earlier. Notwithstanding

these notice requirements, the owner or

operator may elect to repeat a periodic

relative accuracy test immediately,

without additional notification

whenever the owner or operator has

determined that a test was failed, or that

a second test is necessary in order to

attain a reduced relative accuracy test

frequency.

(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 provide notice of

the combustion of emergency fuel

according to the following:

(i) For an affected oil-fired or gas-fired

unit that is using an excepted

monitoring system under appendix D or

E of this part, where the owner or

operator is postponing installation or

testing of a fuel flowmeter for

emergency fuel under § 75.4(g), the

designated representative shall submit

written notification of postponement of

installation or testing no later than 45

days prior to the deadline in § 75.4(a).

The designated representative shall also

submit a notification that emergency

fuel has been combusted no later than

7 days after the first date of combustion

of the emergency fuel after the deadline

in § 75.4(a).

(ii) The designated representative of a

unit that has received approval of a

petition under § 75.66 for exemption

from one or more of the requirements of

appendix E of this part for certification

of an excepted monitoring system under

appendix E of this part for a unit

combusting emergency fuel shall submit

written notice of each period of

combustion of the emergency fuel with

the next quarterly report submitted

under § 75.64 for each calendar quarter

in which emergency fuel is combusted,

including notice specifying the exact

dates and hours during which the

emergency fuel was combusted.

(b) The owner or operator or

designated representative shall submit

notification of certification tests and

recertification tests for continuous

opacity monitoring systems, as specified

in § 75.20(c)(6) to the State or local air

pollution control agency.

(c) If the Administrator determines

that notification substantially similar to

that required in this section is required

by any other State or local agency, the

owner or operator or designated

representative may send the

Administrator a copy of that notification

to satisfy the requirements of this

section, provided the ORISPL unit

identification number(s) is denoted.

45. Section 75.62 is amended by

revising paragraph (a) and adding

paragraph (c) to read as follows:

§ 75.62 Monitoring plan.

(a) Submission. The designated

representative for an affected unit shall

submit the monitoring plan to the

Administrator no later than 45 days

prior to the first scheduled certification

test, other than testing of a fuel

flowmeter or an excepted monitoring

system under appendix D of this part.

The designated representative shall

submit the monitoring plan for a Phase

II unit using an excepted monitoring

system under appendix D of this part to

the Administrator no later than

November 15, 1994.

* * * * *

(c) Format. Each monitoring plan

shall be submitted in a format specified

by the Administrator, including

information in electronic format and on

paper.

46. Section 75.63 is revised to read as

follows:

§ 75.63 Initial certification or recertification

application.

(a) Submission. The designated

representative for an affected unit or a

combustion source seeking to enter the

Opt-in Program in accordance with part

74 of this chapter shall submit the

application to the Administrator within

45 days after completing all initial

certification tests or recertification tests.

(b) Contents. Each application for

initial certification or recertification

shall contain the following information:

(1) A copy of the monitoring plan (or

any modifications to the monitoring

plan) for the unit, or units, or

combustion sources seeking to enter the

Opt-in Program in accordance with part
26540 Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations

74 of this chapter, if not previously

submitted.

(2) The results of the test(s) required

by § 75.20, including the type of test

conducted, testing date, and field data

sheets required by § 75.52 (or § 75.56, no

later than January 1, 1996), and

including the results of any failed tests

that had been repeated pursuant to the

requirements in § 75.20.

(3) Results of the tests for verification

of the accuracy of emissions and

volumetric flow calculations performed

by the automated data acquisition and

handling system, including a summary

of equations used to convert component

data to units of the standard and to

calculate substitute data for missing

data periods, including sample

calculations.

(c) Format. Each certification

application shall be submitted in a

format to be specified by the

Administrator, including test results in

electronic format and field data sheets

required by § 75.52 (or § 75.56, no later

than January 1, 1996) on paper where

the information required under

§ 75.56(a)(7) shall be submitted on

paper.

47. Section 75.64 is amended by

revising the first two sentences of

paragraph (a) introductory text, by

revising paragraphs (a)(5), (b) and (d), by

revising the last sentence of paragraph

(e) introductory text and by removing

paragraphs (e)(1) and (2) to read as

follows:

§ 75.64 Quarterly reports.

(a) Electronic submission. The

designated representative for an affected

unit shall electronically report the data

and information in paragraphs (a), (b),

and (c) of this section to the

Administrator quarterly, beginning with

the data from the later of: the last

(partial) calendar quarter of 1993 (where

the calendar quarter data begins at

November 15, 1993); or the calendar

quarter corresponding to the relevant

deadline for certification in § 75.4(a),

(b), or (c). For any provisionallycertified monitoring system, some or all

of the quarterly data may be invalidated,

if the Administrator subsequently issues

a notice of disapproval within 120 days

of receipt of the complete initial

certification application or within 60

days of receipt of the complete

recertification application for the

monitoring system. * * *

(5) Total heat input (mmBtu) for

quarter and cumulative heat input for

calendar year.

* * * * *

(b) The designated representative

shall affirm that the component/system

identification codes and formulas in the

quarterly electronic reports, submitted

to the Administrator pursuant to

§ 75.53, represent current operating

conditions.

* * * * *

(d) Electronic format. Each quarterly

report shall be submitted in a format to

be specified by the Administrator,

including both electronic submission of

data and paper submission of

compliance certifications.

(e) * * * Each report shall include all

measurements and calculations

necessary to substantiate that the

qualifying technology achieves the

overall percentage reduction in SO2

emissions.

48. Section 75.65 is revised to read as

follows:

§ 75.65 Opacity reports.

The owner or operator or designated

representative shall report excess

emissions of opacity recorded under

§§ 75.50(f) or 75.54(f) to the applicable

State or local air pollution control

agency, in a format specified by the

applicable State or local air pollution

control agency.

49. Section 75.66 is amended by

redesignating paragraphs (a), (b), (c), (d),

(e) and (f) as paragraphs (b), (c), (d), (e),

(f) and (i), by adding new paragraphs (a),

(g), and (h), and by revising newly

designated paragraphs (b), (c), and (i), to

read as follows:

§ 75.66 Petitions to the Administrator.

(a) General. The designated

representative for an affected unit

subject to the requirements of this part

may submit petitions to the

Administrator. Any petitions shall be

submitted in accordance with the

requirements of this section. The

designated representative shall comply

with the signatory requirements of

§ 72.21 of this chapter for each

submission.

(b) Alternative flow monitoring

method petition. In cases where no

location exists for installation of a flow

monitor in either the stack or the ducts

serving an affected unit that satisfies the

minimum physical siting criteria in

appendix A of this part or where

installation of a flow monitor in either

the stack or duct is demonstrated to the

satisfaction of the Administrator to be

technically infeasible, the designated

representative for the affected unit may

petition the Administrator for an

alternative method for monitoring

volumetric flow. The petition shall, at a

minimum, contain the following

information:

(1) Identification of the affected

unit(s);

(2) Description of why the minimum

siting criteria cannot be met within the

existing ductwork or stack(s). This

description shall include diagrams of

the existing ductwork or stack, as well

as documentation of any attempts to

locate a flow monitor; and

(3) Description of proposed

alternative method for monitoring flow.

(c) Alternative to standards

incorporated by reference. The

designated representative for an affected

unit may apply to the Administrator for

an alternative to any standard

incorporated by reference and

prescribed in this part. The designated

representative shall include the

following information in an application:

(1) A description of why the

prescribed standard is not being used;

(2) A description and diagram(s) of

any equipment and procedures used in

the proposed alternative;

(3) Information demonstrating that the

proposed alternative produces data

acceptable for use in the Acid Rain

Program, including accuracy and

precision statements, NIST traceability

certificates or protocols, or other

supporting data, as applicable to the

proposed alternative.

* * * * *

(g) Petitions for emissions or heat

input apportionments. The designated

representative of an affected unit shall

provide information to describe a

method for emissions or heat input

apportionment under §§ 75.13, 75.16,

75.17, or appendix D of this part. This

petition may be submitted as part of the

monitoring plan. Such a petition shall

contain, at a minimum, the following

information:

(1) A description of the units,

including their fuel type, their boiler

type, and their categorization as Phase

I units, substitution units, compensating

units, Phase II units, new units, or nonaffected units;

(2) A formula describing how the

emissions or heat input are to be

apportioned to which units;

(3) A description of the methods and

parameters used to apportion the

emissions or heat input; and

(4) Any other information necessary

to demonstrate that the apportionment

method accurately measures emissions

or heat input and does not

underestimate emissions or heat input

from affected units.

(h) Partial recertification petition. The

designated representative of an affected

unit may provide information and

petition the Administrator to specify

which of the certification tests required

by § 75.20 apply for partial

recertification of the affected unit. Such
Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations 26541

a petition shall include the following

information:

(1) Identification of the monitoring

system(s) being changed;

(2) A description of the changes being

made to the system;

(3) An explanation of why the

changes are being made; and

(4) A description of the possible effect

upon the monitoring system’s ability to

measure, record, and report emissions.

(i) Any other petitions to the

Administrator under this part. The

designated representative for an affected

unit shall include sufficient information

for the evaluation of any other petition

submitted to the Administrator under

this part.

50. Section 75.67 is amended by

revising paragraph (a) to read as follows:

§ 75.67 Retired units petitions.

(a) For units that will be permanently

retired prior to January 1, 1995, if the

designated representative submits a

complete petition, as required in § 72.8

of this chapter, to the Administrator

prior to the deadline in § 75.4 by which

the continuous emission or opacity

monitoring systems must complete the

required certification tests, the

Administrator will issue an exemption

from the requirements of this part,

including the requirement to install and

certify continuous emission monitoring

systems.

* * * * *

Appendix A to Part 75—Specifications

and Test Procedures

51. Appendix A to part 75, section 1

is amended by revising section 1.1.2, by

revising the fourth sentence in section

1.2; and by revising section 1.2.1 and by

revising the first sentence of section

1.2.2 to read as follows:

1. Installation and Measurement Location

1.1 * * *

1.1.1 * * *

1.1.2 Path Pollutant Concentration and CO2

or O2 Gas Monitors

Locate the measurement path (1) totally

within the inner area bounded by a line 1.0

meter from the stack or duct wall, or (2) such

that at least 70.0 percent of the path is within

the inner 50.0 percent of the stack or duct

cross-sectional area, or (3) such that the path

is centrally located within any part of the

centroidal area.

1.2 Flow Monitors

* * * The EPA recommends (but does not

require) performing a flow profile study

following the procedures in 40 CFR part 60,

appendix A, Method, 1, section 2.5 or 2.4 for

each of the three operating or load levels

indicated in section 6.5.2 of this appendix to

determine the acceptability of the potential

flow monitor location and to determine the

number and location of flow sampling points

required to obtain a representative flow

value. * * *

1.2.1 Acceptability of Monitor Location

The installation of a flow monitor is

acceptable if either (1) the location satisfies

the minimum siting criteria of Method 1 in

Appendix A to part 60 of this chapter (i.e.,

the location is greater than or equal to eight

stack or duct diameters downstream and two

diameters upstream from a flow disturbance;

or, if necessary, two stack or duct diameters

downstream and one-half stack or duct

diameter upstream from a flow disturbance),

or (2) the results of a flow profile study, if

performed, are acceptable (i.e., there are no

cyclonic (or swirling) or stratified flow

conditions), and the flow monitor also

satisfies the performance specifications of

this part. If the flow monitor is installed in

a location that does not satisfy these physical

criteria, but nevertheless the monitor

achieves the performance specifications of

this part, then the location is acceptable,

notwithstanding the requirements of this

section.

1.2.2 Flow Monitor Certification Date

Extension

Whenever the designated representative

successfully demonstrates that modifications

to the exhaust duct or stack (such as

installation of straightening vanes,

modifications of ductwork, and the like) are

necessary for the flow monitor to meet the

performance specifications, the

Administrator may approve an interim

alternative flow monitoring methodology and

an extension to the required certification date

for the flow monitor. * * *

* * * * *

52. Appendix A to part 75, section 2

is amended by revising sections 2.1.1;

revising the first paragraph of section

2.1.1.1, and by revising sections 2.1.1.2,

2.1.1.4, 2.1.2, 2.1.2.1, 2.1.2.2, 2.1.2.4,

2.1.3 and 2.1.4 to read as follows:

2. Equipment Specifications

2.1 * * *

2.1.1 SO2 Pollutant Concentration Monitors

Determine, as indicated below, the span

value for an SO2 pollutant concentration

monitor so that all expected concentrations

can be accurately measured and recorded.

2.1.1.1 Maximum Potential Concentration

The monitor must be capable of accurately

measuring up to 125 percent of the maximum

potential concentration (MPC) as calculated

using Equation A–1a or A–1b. Calculate the

maximum potential concentration by using

Equation A–1a or A–1b and the maximum

percent sulfur and minimum gross calorific

value (GCV) for the highest sulfur fuel to be

burned, using daily fuel sample data if they

are available. If an SO2 CEMS is already

installed, the owner or operator may

determine an MPC based upon the maximum

concentration observed during the previous

30 unit operating days when using the type

of fuel to be burned. For initial certification,

base the maximum percent sulfur and

minimum GCV on the results of all available

fuel sampling and analysis data from the

previous 12 months (where such data exists).

If the unit has not been operated during that

period, use the maximum sulfur content and

minimum GCV from the fuel contract for fuel

that will be combusted by the unit. Whenever

the fuel supply changes such that these

maximum sulfur and minimum GCV values

may change significantly, base the maximum

percent sulfur and minimum GCV on the

new fuel with the highest sulfur content. Use

the one of the two following methods that

results in a higher MPC: (1) results of

samples representative of the new fuel

supply, or (2) maximum sulfur and minimum

GCV from the fuel contract for fuel that will

be combusted by the unit. Whenever

performing fuel sampling to determine the

MPC, use ASTM Methods ASTM D3177–89,

‘‘Standard Test Methods for Total Sulfur in

the Analysis Sample of Coal and Coke,’’

ASTM D4239–85, ‘‘Standard Test Methods

for Sulfur in the Analysis Sample of Coal and

Coke Using High Temperature Tube Furnace

Combustion Methods,’’ ASTM D4294–90,

‘‘Standard Test Method for Sulfur in

Petroleum Products by Energy-Dispersive XRay Fluorescence Spectroscopy,’’ ASTM

D1552–90, ‘‘Standard Test Method for Sulfur

in Petroleum Products (High Temperature

Method),’’ ASTM D129–91, ‘‘Standard Test

Method for Sulfur in Petroleum Products

(General Bomb Method),’’ or ASTM D2622–

92, ‘‘Standard Test Method for Sulfur in

Petroleum Products by X-Ray Spectrometry’’

for sulfur content of solid or liquid fuels, or

ASTM D3176–89, ‘‘Standard Practice for

Ultimate Analysis of Coal and Coke’’, ASTM

D240–87 (Reapproved 1991), ‘‘Standard Test

Method for Heat of Combustion of Liquid

Hydrocarbon Fuels by Bomb Calorimeter’’, or

ASTM D2015–91, ‘‘Standard Test Method for

Gross Calorific Value of Coal and Coke by the

Adiabatic Bomb Calorimeter’’ for GCV

(incorporated by reference under § 75.6).

Multiply the maximum potential

concentration by 125 percent, and round up

the resultant concentration to the nearest

multiple of 100 ppm to determine the span

value. The span value will be used to

determine the concentrations of the

calibration gases. Include the full-scale range

setting and calculations of the span and MPC

in the monitoring plan for the unit. Select the

full-scale range of the instrument to be

consistent with section 2.1 of this appendix,

and to be greater than or equal to the span

value. This selected monitor range with a

span rounded up from 125 percent of the

maximum potential concentration will be the

‘‘high-scale’’ of the SO2 pollutant

concentration monitor.
26542 Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations

MPC

S

GCV

O

Eq A a

or

MPC

S

GCV

CO

Eq A b

w

w

= × 



 





 −



 



 −

= × 



 









 



 −

11 32 10

20 9

20 9

1

66 93 10

100

1

6 2

6 2

. % . %

. ( . )

. % %( . )

2.1.1.2 Maximum Expected Concentration

If the majority of SO2 concentration values

are predicted to be less than 25 percent of the

full-scale range of the instrument selected

under section 2.1.1.1 of this appendix, (e.g.,

where an SO2 add-on emission control is

used or where fuel with different sulfur

contents are blended), use an additional

(lower) measurement range. For this second

range, use Equation A–2 to calculate the

maximum expected concentration (MEC) for

units with emission controls. For units

blending fuels, calculate the MEC using a

best estimate of the highest sulfur content

and lowest gross calorific value expected for

the blend and inserting these values into

Equation A–1. If an SO2 CEMS is already

installed, the owner or operator may

calculate an MEC based upon the maximum

concentration measured by the CEMS over a

thirty-day period, provided that there have

been no full-scale exceedances since the

range was last selected. Multiply the

maximum expected concentration by 125

percent, and round up the resultant

concentration to the nearest multiple of 10

ppm to determine the span value for the

additional (lower) range. The span value of

this additional range will also be used to

determine concentrations of the calibration

gases for this additional range. Report the

full-scale range setting and calculations of

the MEC and span in the monitoring plan for

the unit. Select the full-scale range of the

instrument of this additional (lower) range to

be consistent with section 2.1 of this

appendix, and to be greater than or equal to

the lower range span value. This selected

monitor range with a span rounded up from

125 percent of the MEC will be the ‘‘lowscale’’ of the SO2 pollutant concentration

monitor. Units using a low-scale range must

also be capable of accurately measuring the

anticipated concentrations up to and

including 125 percent of the maximum

potential concentration. If an existing State,

local, or Federal requirement for span of an

SO2 pollutant concentration monitor requires

a span other than that required in this

section, but less than that required for the

high-scale by this appendix, the State, local

or Federal span value may be approved,

where a satisfactory explanation is included

in the monitoring plan.

MEC=MPC[(100–RE)/100] (Eq. A–2)

Where:

MEC=Maximum expected concentration

(ppm).

MPC=Maximum potential concentration

(ppm), as determined by Eq. A–1a or A–

1b.

RE = Expected average design removal

efficiency of control equipment (%).

2.1.1.3 * * *

2.1.1.4 Adjustment of Span

Wherever the SO2 concentration exceeds

the maximum potential concentration but

does not exceed the full-scale range during

more than one clock-hour and the monitor

can measure and record the SO2

concentration accurately, it may be reported

for use in the Acid Rain Program. If the

concentration exceeds the monitor’s ability to

measure and record values accurately during

a clock hour, and the full-scale exceedance

is not during an out-of-control period, report

the full-scale value as the SO2 concentration

for that clock hour. If full-scale exceedances

occur during more than one clock hour since

the last adjustment of the full-scale range

setting, adjust the full-scale range setting to

prevent future exceedances.

Whenever the fuel supply or emission

controls change such that the maximum

expected or potential concentration may

change significantly, adjust the span and

range setting to assure the continued proper

operation of the monitoring system.

Determine the adjusted span using the

procedures in sections 2.1.1.1 or 2.1.1.2 of

this appendix. Select the full scale range of

the instrument to be greater than or equal to

the new span value and to be consistent with

the guidelines of section 2.1 of this appendix.

Record and report the new full-scale range

setting, calculations of the span, MPC, and

MEC (if appropriate), and the adjusted span

value, in an updated monitoring plan. In

addition, record and report the adjusted span

as part of the records for the daily calibration

error test and linearity check specified by

appendix B of this part. Whenever the span

value is adjusted, use calibration gas

concentrations based on the most recent

adjusted span value. Perform a linearity

check according to section 6.2 of this

appendix whenever making a change to the

monitor span or range. Recertification under

§ 75.20(b) is required whenever a significant

change in the monitor’s range also requires

an internal modification to the monitor (e.g.,

a change of measurement cell length).

2.1.2 NOX Pollutant Concentration Monitors

Determine, as indicated below, the span

value(s) for the NOX pollutant concentration

monitor so that all expected NOX

concentrations can be determined and

recorded accurately including both the

maximum expected and potential

concentration.

2.1.2.1 Maximum Potential Concentration

The monitor must be capable of accurately

measuring up to 125 percent of the maximum

potential concentration (MPC) as determined

below in this section. Use 800 ppm for coalfired and 400 ppm for oil- or gas-fired units

as the maximum potential concentration of

NOx, unless a more representative MPC is

determined by one of the following methods

(If an MPC of 1600 ppm for coal-fired units

or 480 ppm for oil- or gas-fired units was

previously selected under this part, that

value may still be used.): (1) NOX emission

test results, (2) historical CEM data over the

previous 30 unit operating days; or (3)

specific values based on boiler-type and fuel

combusted, listed in Table 2–1 or Table 2–

2 if other data under (1) or (2) were not

available. Multiply the MPC by 125 percent

and round up to the nearest multiple of 100

ppm to determine the span value. The span

value will be used to determine the

concentrations of the calibration gases.

Report the full-scale range setting, and

calculations of the MPC, maximum potential

NOX emission rate, and span in the

monitoring plan for the unit. Select the fullscale range of the instrument to be consistent

with section 2.1 of this appendix, and to be

greater than or equal to the span value. This

selected monitor range with a span rounded

up from 125 percent of the maximum

potential concentration will be the ‘‘highscale’’ of the NOX pollutant concentration

monitor.

If NOX emission testing is used to

determine the maximum potential NOX

concentration, use the following guidelines:

Use Method 7E from appendix A of part 60

of this chapter to measure total NOX

concentration. Operate the unit, or group of

units sharing a common stack, at the

minimum safe and stable load, the normal

load, and the maximum load. If the normal

load and maximum load are identical, an

intermediate level need not be tested.

Operate at the highest excess O2 level

expected under normal operating conditions.

Make at least three runs with three traverse

points of at least 20 minutes duration at each

operating condition. Select the highest NOX

concentration from all measured values as

the maximum potential concentration for

NOx. If historical CEM data are used to

determine the MPC, the data must represent

various operating conditions, including the

minimum safe and stable load, normal load,

and maximum load. Calculate the MPC and

span using the highest hourly NOX

concentration in ppm. If no test data or

historical CEM data are available, use Table

2–1 or Table 2–2 to estimate the maximum

potential concentration based upon boiler

type and fuel used.
Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations 26543

TABLE 2–1.—MAXIMUM POTENTIAL CONCENTRATION FOR NOX—Coal-Fired Units

Unit type Maximum potential concentration for

NOX (ppm)

Tangentially-fired dry bottom and fluidized bed ............................................................................................. 460

Wall-fired dry bottom, turbo-fired dry bottom, stokers ................................................................................... 675

Roof-fired (vertically-fired) dry bottom, cell burners, arch-fired ..................................................................... 975

Cyclone, wall-fired wet bottom, wet bottom turbo-fired ................................................................................. 1200

Others ............................................................................................................................................................. As approved by the Administrator.

TABLE 2–2.—MAXIMUM POTENTIAL CONCENTRATION FOR NOX—Gas- And 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 or combined cycle turbine ................................................................................ 200

New stationary gas turbine/combustion turbine ............................................................................................. 50

Others ............................................................................................................................................................. As approved by the Administrator.

2.1.2.2 Maximum Expected Concentration

If the majority of NOX concentrations are

expected to be less than 25 percent of the

full-scale range of the instrument selected

under section 2.1.2.1 of this appendix (e.g.,

where a NOX add-on emission control is

used) use a ‘‘low-scale’’ measurement range.

For units with add-on emission controls,

determine the maximum expected

concentration (MEC) of NOX using Equation

A–2, 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

appropriate, set the MEC, either (1) by

measuring the NOX concentration using the

testing procedures in section 2.1.2.1 of this

appendix, or (2) by using historical CEM data

over the previous 30 unit operating days.

Other methods for determining the MEC may

be accepted if they are satisfactorily

explained in the monitoring plan. If an

existing State, local, or Federal requirement

for span of an NOX pollutant concentration

monitor requires a span other than that

required in this section, but less than that

required for the high scale by this appendix,

the State, local, or Federal span value may be

approved, where a satisfactory explanation is

included in the monitoring plan. Calculate

the span for the additional (lower) range by

multiplying the maximum expected

concentration by 125 percent and by

rounding up the resultant concentration to

the nearest multiple of 10 ppm. The span

value of this additional (lower) range will

also be used to determine the concentrations

of the calibration gases. Include the full-scale

range setting and calculations of the MEC

and span in the monitoring plan for the unit.

Select the full-scale range of the instrument

to be consistent with section 2.1 of this

appendix, and to be greater or equal to the

lower range span value. This selected

monitor range with a span rounded up from

125 percent of the maximum expected

concentration is the ‘‘low-scale’’ of NOX

pollutant concentration monitors. NOX

pollutant concentration monitors on affected

units with NOX emission controls, or on

other units with monitors using a low-scale

range, must also be capable of accurately

measuring up to 125 percent of the maximum

potential concentration. For dual-span NOX

pollutant concentration monitors, determine

the concentration of calibration gases based

on both span values.

2.1.2.3 * * *

2.1.2.4 Adjustment of Span

Wherever the actual NOX concentration

exceeds the maximum potential

concentration but does not exceed the fullscale range for more than one clock-hour and

the monitor can measure and record the NOX

concentration values accurately, the NOX

concentration values may be reported for use

in the Acid Rain Program. If the

concentration exceeds the monitor’s ability to

measure and record values accurately during

a clock hour, and the full-scale exceedance

is not during an out-of-control period, report

the full-scale value as the NOX concentration

for that clock hour. If full-scale exceedances

occur during more than one clock hour since

the last adjustment of the full-scale range

setting, adjust the full-scale range setting to

prevent future exceedances.

Whenever the fuel supply, emission

controls, or other process parameters change

such that the maximum expected

concentration or the maximum potential

concentration may change significantly,

adjust the NOX pollutant concentration span

and monitor range to assure the continued

accuracy of the monitoring system.

Determine the adjusted span value using the

procedures in sections 2.1.2.1 or 2.1.2.2 of

this appendix. Select the new full scale range

of the instrument to be greater than or equal

to the adjusted span value and to be

consistent with the guidelines of section 2.1

of this appendix. Record and report the new

full-scale range setting, calculations of the

span value, MPC, and MEC (if appropriate),

maximum potential NOX emission rate and

the adjusted span value in an updated

monitoring plan for the unit. In addition,

record and report the adjusted span as part

of the records for the daily calibration error

test and linearity check required by appendix

B of this part. Whenever the span value is

adjusted, use calibration gas concentrations

based on the most recent adjusted span

value. Perform a linearity check according to

section 6.2 of this appendix whenever

making a change to the monitor span or

range. Recertification under § 75.20(b) is

required whenever a significant change is

made in the monitor’s range that requires an

internal modification to the monitor (e.g., a

change of measurement cell length).

2.1.3 CO2 and O2 Monitors

Define the ‘‘high scale’’ span value as 20

percent O2 or 20 percent CO2. All O2 and CO2

analyzers must have ‘‘high-scale’’

measurement capability. Select the full-scale

range of the instrument to be consistent with

section 2.1 of this appendix, and to be greater

than or equal to the span value. If the O2 or

CO2 concentrations are expected to be

consistently low, a ‘‘low scale’’ measurement

range may be used for increased accuracy,

provided that it is consistent with section 2.1

of this appendix. Include a span value for the

low-scale range in the monitoring plan.

Select the calibration gas concentrations as

percentages of the span value.

2.1.4 Flow Monitors

Select the full-scale range of the flow

monitor so that it is consistent with section

2.1 of this appendix, and can accurately

measure all potential volumetric flow rates at

the flow monitor installation site. For this

purpose, determine the span value of the

flow monitor using the following procedure.

Calculate the maximum potential velocity

(MPV) using Equation A–3a or A–3b or

determine the MPV or maximum potential

flow rate (MPF) in scfh (wet basis) from

velocity traverse testing. If using test values,

use the highest velocity measured at or near

the maximum unit operating load. Calculate

the MPV in units of wet standard fpm. Then,

if necessary, convert the MPV to equivalent

units of flow rate (e.g., scfh or kscfh) or

differential pressure (inches of water),

consistent with the measurement units used

for the daily calibration error test to calculate

the span value. Multiply the MPV (in
26544 Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations

equivalent units) by 125 percent, and round

up the result to no less than 2 significant

figures. Report the full-scale range setting,

and calculations of the span value, MPV and

MPF in the monitoring plan for the unit.

MPV

F H

A O H O

Eq A a

or

MPV

F H

A CO H O

Eq A b

d f

d

d f

d

= 



 



 −











 −















 −

= 



 















 −















 −

20 9

20 9

100

100

3

100 100

100

3

2 2

2 2

.

. % %

( . )

% %

( . )

Where:

MPV=maximum potential velocity (fpm,

standard wet basis),

Fd=dry-basis F factor (dscf/mmBtu) from

Table 1, Appendix F of this part,

Fc=carbon-based F factor (scfCO2/mmBtu)

from Table 1, Appendix F of this part,

Hf=maximum heat input (mmBtu/minute) for

all units, combined, exhausting to the

stack or duct where the flow monitor is

located,

A=inside cross sectional area (ft2) of the flue

at the flow monitor location,

%O2d=maximum oxygen concentration,

percent dry basis, under normal

operating conditions,

%CO2d=minimum carbon dioxide

concentration, percent dry basis, under

normal operating conditions,

%H2O = maximum percent flue gas moisture

content under normal operating

conditions.

If the volumetric flow rate exceeds the

maximum potential flow calculated from the

maximum potential velocity but does not

exceed the full scale range during more than

one clock hour and the flow monitor can

accurately measure and record values, the

flow rate may be reported for use in the Acid

Rain Program. If the volumetric flow rate

exceeds the monitor’s ability to measure and

record values accurately during a clock hour,

and the full-scale exceedance is not during

an out-of-control period, report the full-scale

value as the flow rate for that clock hour. If

full-scale exceedance occurs during more

than one hour since the last adjustment of the

full-scale range setting, adjust the full-scale

range setting to prevent future exceedances.

If the fuel supply, process parameters or

other conditions change such that the

maximum potential velocity may change

significantly, adjust the range to assure the

continued accuracy of the flow monitor.

Calculate an adjusted span using the

procedures in this section. Select the fullscale range of the instrument to be greater

than or equal to the adjusted span value.

Record and report the new full-scale range

setting, calculations of the span value, MPV,

and MPF, and the adjusted span value in an

updated monitoring plan for the unit. Record

and report the adjusted span and reference

values as parts of the records for the

calibration error test required by appendix B

of this part. Whenever the span value is

adjusted, use reference values for the

calibration error test based on the most recent

adjusted span value.

Perform a calibration error test according to

section 2.1.2 of this appendix whenever

making a change to the flow monitor span or

range. Recertification under § 75.20(b) is

required whenever making a significant

change in the flow monitor’s range that

requires an internal modification to the

monitor.

* * * * *

53. Appendix A to part 75, section 3

is amended by revising sections 3.3.3

and 3.5 to read as follows:

3. Performance Specifications

* * * * *

3.3 * * *

3.3.1 * * *

3.3.2 * * *

3.3.3 Relative Accuracy for CO2 and O2

Pollutant Concentration Monitors

The relative accuracy for CO2 and O2

monitors shall not exceed 10.0 percent. The

relative accuracy test results are also

acceptable if the mean difference of the CO2

or O2 monitor measurements and the

corresponding reference method

measurement, calculated using Equation A–

7 of this appendix, is within 1.0 percent CO2

or O2.

* * * * *

3.5 Cycle Time

The cycle time for pollutant concentration

monitors, and continuous emission

monitoring systems shall not exceed 15 min.

* * * * *

54. Appendix A to part 75, section 4

is amended by adding a third paragraph

to read as follows:

4. Data Acquisition and Handling Systems

* * * * *

For an excepted monitoring system under

appendix D or E of this part, data acquisition

and handling systems shall:

(1) Read and record the full range of fuel

flowrate through the upper range value;

(2) Calculate and record intermediate

values necessary to obtain emissions, such as

mass fuel flowrate and heat input rate;

(3) Calculate and record emissions in units

of the standard (lb/hr of SO2, lb/mmBtu of

NOX);

(4) Predict and record NOX emission rate

using the heat input rate and the NOX/heat

input correlation developed under appendix

E of this part;

(5) Calculate and record all missing data

substitution values specified in appendix D

or E of this part; and

(6) Provide a continuous, permanent record

of all measurements and required

information as an ASCII flat file capable of

transmission via an IBM-compatible personal

computer diskette or other electronic media.

* * * * *

55. Appendix A to part 75, section 5

is amended by revising section 5.1.2 and

by adding sections 5.1.4, 5.1.5, and 5.1.6

to read as follows:

5. Calibration Gas

5.1 Reference Gases

5.1.1 * * *

5.1.2 NIST Traceable Reference Materials

Contact the Quality Assurance Division

(MD 77), Environmental Monitoring System

Laboratory, U.S. Environmental Protection

Agency, Research Triangle Park, North

Carolina 27711 or the Organic Analytical

Research Division of NIST at the above

address for Standard Reference Materials for

a list of vendors and cylinder gases.

5.1.3 * * *

5.1.4 Research Gas Mixtures

Contact the Quality Assurance Division

(MD 77), Environmental Monitoring System

Laboratory, U.S. Environmental Protection

Agency, Research Triangle Park, North

Carolina 27711 or the Organic Analytical

Research Division of NIST at the above

address for Standard Reference Materials for

a list of vendors and cylinder gases.

5.1.5 Zero Air Material

Use zero air material for calibrating at zerolevel concentrations only. Zero air material

shall be certified by the gas vendor or

instrument manufacturer or vendor not to

contain concentrations of SO2 or NOX above

0.1 ppm or CO2 above 400 ppm, and not to

contain concentrations of other gases that

will interfere with instrument readings or

cause the instrument to read concentrations

of SO2, NOX, or CO2.
Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations 26545

5.1.6 NIST/EPA-approved Certified

Reference Materials

Existing certified reference materials as

previously certified under EPA’s former

certified reference material program may be

used for the remainder of the cylinder’s shelf

life.

* * * * *

56. Appendix A to part 75, section 6

is amended by adding a sentence to the

end of section 6.1; by revising the first

sentence in the second paragraph of

section 6.2; and by revising sections 6.5,

6.5.1, 6.5.2, 6.5.5, 6.5.6, 6.5.7, and 6.5.10

to read as follows:

6. Certification Tests and Procedures

6.1 Pretest Preparation

* * * To the extent practicable, test the

DAHS software prior to testing the

monitoring hardware.

6.2 Linearity Check

* * * * *

Challenge each pollutant concentration or

CO2 or O2 monitor with NIST/EPA-approved

certified reference material, NIST traceable

reference material, standard reference

material, or Protocol 1 calibration gases

certified to be within 2 percent of the

concentration specified on the label at the

low-, mid-, or high-level concentrations

specified in section 5.2 of this appendix.

* * *

* * * * *

6.5 Relative Accuracy and Bias Tests

Perform relative accuracy test audits for

each CO2 and SO2 pollutant concentration

monitor, each O2 monitor used to calculate

heat input or CO2 concentration, each SO2-

diluent continuous emission monitoring

system (lb/mmBtu) used by units with a

qualifying Phase I technology for the period

during which the units are required to

monitor SO2 emission removal efficiency,

from January 1, 1997 through December 31,

1999, flow monitor, and NOX continuous

emission monitoring system. For monitors or

monitoring systems with dual ranges,

perform the relative accuracy test on one

range measuring emissions in the stack at the

time of testing. Record monitor or monitoring

system output from the data acquisition and

handling system. Perform concurrent relative

accuracy test audits for each SO2 pollutant

concentration monitor and flow monitor, at

least once a year (see section 2.3.1 of

appendix B of this part), during the flow

monitor test at the normal operating level

specified in section 6.5.2 of this appendix.

Concurrent relative accuracy test audits may

be performed by conducting simultaneous

SO2 and flow relative accuracy test audit

runs, or by alternating an SO2 relative

accuracy test audit run with a flow relative

accuracy test audit run until all relative

accuracy test audit runs are completed.

Where two or more probes are in the same

proximity, care should be taken to prevent

probes from interfering with each other’s

sampling. For each SO2 pollutant

concentration monitor, each flow monitor,

and each NOX continuous emission

monitoring system, calculate bias, as well as

relative accuracy, with data from the relative

accuracy test audits.

Complete each relative accuracy test audit

within a 7-day period while the unit (or

units, if more than one unit exhausts into the

flue) is combusting the fuel that is normal for

that unit. When relative accuracy test audits

are performed on continuous emission

monitoring systems or component(s) on

bypass stacks/ducts, use the fuel normally

combusted by the unit (or units, if more than

one unit exhausts into the flue) when

emissions exhaust through the bypass stack/

ducts. Do not perform corrective

maintenance, repairs, replacements or

adjustments during the relative accuracy test

audit other than as required in the operation

and maintenance manual.

6.5.1 SO2, O2 and CO2 Pollutant

Concentration Monitors and SO2-Diluent and

NOX Continuous Emission Monitoring

Systems

Perform relative accuracy test audits for

each SO2, O2 or CO2 pollutant concentration

monitor or NOX continuous emission

monitoring system or SO2-diluent continuous

emission monitoring system (lb/mmBtu) used

by units with a qualifying Phase I technology

for the period during which the units are

required to monitor SO2 emission removal

efficiency, from January 1, 1997 through

December 31, 1999, at a normal operating

level for the unit (or combined units, if

common stack).

6.5.2 Flow Monitors

Except for flow monitors on bypass stacks/

ducts and peaking units, perform relative

accuracy test audits for each flow monitor at

three different exhaust gas velocities,

expressed in terms of percent of flow monitor

span, or different operating or load levels.

For a common stack/duct, the three different

exhaust gas velocities may be obtained from

frequently used unit/load combinations for

units exhausting to the common stack. Select

the operating levels as follows: (1) A

frequently used low operating level selected

within the range between the minimum safe

and stable operating level and 50 percent

load, (2) a frequently used high operating

level selected within the range between 80

percent of the maximum operating level and

the maximum operating level, and (3) the

normal operating level. If the normal

operating level is within 10.0 percent of the

maximum operating level of either (1) or (2)

above, use a level that is evenly spaced

between the low and high operating levels

used. The maximum operating level shall be

equal to the nameplate capacity less any

physical or regulatory limitations or other

deratings. Calculate flow monitor relative

accuracy at each of the three operating levels.

If a flow monitor fails the relative accuracy

test on any of the three levels of a three-level

relative accuracy test audit, the three-level

relative accuracy test audit must be repeated.

For flow monitors on bypass stacks/ducts

and peaking units, the flow monitor relative

accuracy test audit is required only at the

normal operating level.

6.5.3 * * *

6.5.4 * * *

6.5.5 Reference Method Measurement

Location

Select a location for reference method

measurements that is (1) accessible; (2) in the

same proximity as the monitor or monitoring

system location; and (3) meets the

requirements of Performance Specification 2

in appendix B of part 60 of this chapter for

SO2 and NOX continuous emission

monitoring systems, Performance

Specification 3 in appendix B of part 60 of

this chapter for CO2 or O2 monitors, or

Method 1 (or 1A) in appendix A of part 60

of this chapter for volumetric flow, except as

otherwise indicated in this section or as

approved by the Administrator.

6.5.6 Reference Method Traverse Point

Selection

Select traverse points that (1) ensure

acquisition of representative samples of

pollutant and diluent concentrations,

moisture content, temperature, and flue gas

flow rate over the flue cross section; and (2)

meet the requirements of Performance

Specification 2 in appendix B of part 60 of

this chapter (for SO2 and NOX), Performance

Specification 3 in appendix B of part 60 of

this chapter (for O2 and CO2), Method 1 (or

1A) (for volumetric flow), Method 3 (for

molecular weight), and Method 4 (for

moisture determination) in appendix A of

part 60 of this chapter.

6.5.7 Sampling Strategy

Conduct the reference method tests so they

will yield results representative of the

pollutant concentration, emission rate,

moisture, temperature, and flue gas flow rate

from the unit and can be correlated with the

pollutant concentration monitor, CO2 or O2

monitor, flow monitor, and SO2 or NOX

continuous emission monitoring system

measurements. Conduct the diluent (O2 or

CO2) measurements and any moisture

measurements that may be needed

simultaneously with the pollutant

concentration and flue gas flow rate

measurements. If an O2 monitor is used as a

CO2 continuous emission monitoring system,

but not as a diluent monitor, measure CO2

with the reference method. To properly

correlate individual SO2 and CO2 pollutant

concentration monitor data, O2 monitor data,

SO2 or NOX continuous emission monitoring

system data (in lb/mmBtu), and volumetric

flow rate data with the reference method

data, mark the beginning and end of each

reference method test run (including the

exact time of day) on the individual chart

recorder(s) or other permanent recording

device(s).

6.5.8 * * *

6.5.9 * * *

6.5.10 Reference Methods

The following methods from appendix A to

part 60 of this chapter or their approved

alternatives are the reference methods for

performing relative accuracy test audits:

Method 1 or 1A for siting; Method 2 (or 2A,

2C, or 2D) for velocity; Methods 3, 3A, or 3B

for O2 or CO2; Method 4 for moisture;
26546 Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations

Methods 6, 6A, or 6C for SO2; Methods 7, 7A,

7C, 7D, 7E for NOX, excluding the exception

in section 5.1.2 of Method 7E. When using

Method 7E for measuring NOX concentration,

total NOX, both NO and NO2, must be

measured.

* * * * *

58. Appendix A to part 75, section 7

is amended by revising section 7.2.2; by

revising the section heading for section

7.3; and by revising sections 7.6.4 and

7.6.5 to read as follows:

7. Calculations

* * * * *

7.2.2 Flow Monitor Calibration Error

For each reference value, calculate the

percentage calibration error based upon span

using the following equation:

CE

R A

S = Eq A − × − 100 6 ( . )

where:

CE=Calibration error;

R=Low or high level reference value

specified in section 2.2.2.1 of this

appendix;

A=Actual flow monitor response to the

reference value; and

S=Flow monitor span or equivalent reference

value (e.g., pressure pulse or electronic

signal).

7.3 Relative Accuracy for SO2 and CO2

Pollutant Concentration Monitors, SO2-

Diluent Continuous Emission Monitoring

Systems, and Flow Monitors

* * * * *

7.6.4 Bias Test

If the mean difference, d , is greater than

the absolute value of the confidence

coefficient, |cc|, the monitor or monitoring

system has failed to meet the bias test

requirement. For flow monitor bias tests, if

the mean difference, d ̄, is greater than |cc| at

the operating level closest to normal

operating level during the 3-level RATA, the

monitor has failed to meet the bias test

requirement. For flow monitors, apply the

bias test at the operating level closest to

normal operating level during the 3-level

RATA.

7.6.5 Bias Adjustment

If the monitor or monitoring system fails to

meet the bias test requirement, adjust the

value obtained from the monitor using the

following equation:

CEM CEM BAF Eq A i

Adjusted

i

Monitor = × − ( . ) 11

Where:

CEMi Adjusted=Data (measurement) provided

by the monitor at time i.

CEMi Monitor=Data value, adjusted for bias, at

time i.

BAF=Bias adjustment factor, defined by

BAF

d

CEM

= + − 1 12 ( . ) Eq A

Where:

BAF=Bias adjustment factor, calculated to

the nearest thousandth.

d=Arithmetic mean of the difference

obtained during the failed bias test using

Equation A–7.

CEM=Mean of the data values provided by

the monitor during the failed bias test.

If the bias test is failed by a flow monitor

at the operating level closest to normal on a

3-level relative accuracy test audit, calculate

the bias adjustment factor for each of the

three operating levels. Apply the largest of

the three bias adjustment factors to

subsequent flow monitor data using Equation

A–11.

Apply this adjustment prospectively to all

monitor or monitoring system data from the

date and time of the failed bias test until the

date and time of a relative accuracy test audit

that does not show bias. Use the adjusted

values in computing substitution values in

the missing data procedure, as specified in

subpart D of this part, and in reporting the

concentration of SO2, the flow rate, and the

average NOΧ emission rate and calculated

mass emissions of SO2 and CO2 during the

quarter and calendar year, as specified in

subpart G of this part.

* * * * *

APPENDIX B TO PART 75—QUALITY

ASSURANCE AND QUALITY CONTROL

PROCEDURES

59. Appendix B to part 75, section 2

is amended by revising sections 2.1.4,

2.2, 2.2.1, 2.2.2, 2.3, 2.3.1, and 2.3.2;

and by amending Figure 2 at the end of

the appendix to read as follows:

* * * * *

2. Frequency of Testing

2.1 Daily Assessments * * *

2.1.1 * * *

2.1.2 * * *

2.1.3 * * *

2.1.4 Recalibration

The EPA recommends adjusting the

calibration, at a minimum, whenever the

daily calibration error exceeds the limits of

the applicable performance specification for

the pollutant concentration monitor, CO2, or

O2 monitor, or flow monitor in appendix A

of this part.

* * * * *

2.2 Quarterly Assessments

For each monitor or continuous emission

monitoring system, perform the following

assessments during each unit operating

quarter, or for monitors or monitoring

systems on bypass ducts or bypass stacks,

during each bypass operating quarter to be

performed not less than once every 2

calendar years. This requirement is effective

as of the calendar quarter following the

calendar quarter in which the monitor or

continuous emission monitoring system is

provisionally certified.

2.2.1 Linearity Check

Perform a linearity check for each SO2 and

NOΧ pollutant concentration monitor and

each CO2 or O2 monitor at least once during

each unit operating quarter or each bypass

operating quarter, in accordance with the

procedures in appendix A, section 6.2 of this

part. For units using emission controls and

other units using a low-scale span value to

determine calibration gases, perform a

linearity check on both the low- and highscales. Conduct the linearity checks no less

than 2 months apart, to the extent

practicable.

2.2.2 Leak Check

For differential pressure flow monitors,

perform a leak check of all sample lines (a

manual check is acceptable) at least once

during each unit operating quarter or each

bypass operating quarter. Conduct the leak

checks no less than 2 months apart, to the

extent practicable.

2.2.3 * * *

2.3 Semiannual and Annual Assessments

For each monitor or continuous emission

monitoring system, perform the following

assessments once semiannually (within two

calendar quarters) or once annually (within

four calendar quarters) after the calendar

quarter in which the monitor or monitoring

system was last tested, as specified below for

the type of test and the performance

achieved, except as provided below in

section 2.3.1 of this appendix for monitors or

continuous emission monitoring systems on

bypass ducts or stacks or on peaking units.

This requirement is effective as of the

calendar quarter, unit operating quarter (for

peaking units), or bypass operating quarter

(for bypass stacks or ducts) following the

calendar quarter in which the monitor or

continuous emission monitoring system is

provisionally certified. A summary chart

showing the frequency with which a relative

accuracy test audit must be performed,

depending on the accuracy achieved, is

located at the end of this appendix in Figure

2.

2.3.1 Relative Accuracy Test Audit

Perform relative accuracy test audits

semiannually and, to the extent practicable,

no less than 4 months apart for each SO2 or

CO2 pollutant concentration monitor, flow

monitor, NOΧ continuous emission

monitoring system, or SO2-diluent

continuous emission monitoring systems

used by units with a Phase I qualifying

technology for the period during which the

units are required to monitor SO2 emission

removal efficiency, from January 1, 1997

through December 31, 1999, except as

provided for monitors or continuous
Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations 26547

emission monitoring systems on peaking

units or bypass stacks or ducts. For monitors

on bypass stacks/ducts, perform relative

accuracy test audits no less than once every

two successive bypass operating quarters, or

once every two calendar years, whichever

occurs first, in accordance with the

procedures in section 6.5 of Appendix A of

this part. For monitors on peaking units,

perform relative accuracy test audits no less

than once every two successive unit

operating quarters, or once every two

calendar years, whichever occurs first.

Audits required under this section shall be

performed no less than 4 months apart, to the

extent practicable. The audit frequency may

be reduced, as specified below for monitors

or monitoring systems which qualify for less

frequent testing.

For flow monitors, one-level and threelevel relative accuracy test audits shall be

performed alternately (when a flow RATA is

conducted semiannually), such that the

three-level relative accuracy test audit is

performed at least once annually. The threelevel audit shall be performed at the three

different operating or load levels specified in

appendix A, section 6.5.2 of this part, and the

one-level audit shall be performed at the

normal operating or load level.

Notwithstanding that requirement, relative

accuracy test audits need only be performed

at the normal operating or load level for

monitors and continuous emission

monitoring systems on peaking units and

bypass stacks/ducts.

Relative accuracy test audits may be

performed on an annual basis rather than on

a semiannual basis (or for monitors on

peaking units and bypass ducts or bypass

stacks, no less than (1) once every four

successive unit or bypass operating quarters,

or (2) every two calendar years, whichever

occurs first) under any of the following

conditions: (1) The relative accuracy during

the previous audit for an SO2 or CO2

pollutant concentration monitor (including

an O2 pollutant monitor used to measure CO2

using the procedures in appendix F of this

part), or for a NOΧ or SO2-diluent continuous

emissions monitoring system is 7.5 percent

or less; (2) prior to January 1, 2000, the

relative accuracy during the previous audit

for a flow monitor is 10.0 percent or less at

each operating level tested; (3) on and after

January 1, 2000, the relative accuracy during

the previous audit for a flow monitor is 7.5

percent or less at each operating level tested;

(4) on low flow (≤10.0 fps) stacks/ducts,

when the monitor mean, calculated using

Equation A–7 in appendix A of this part is

within ±1.5 fps of the reference method mean

or achieves a relative accuracy of 7.5 percent

(10 percent if prior to January 1, 2000) or less

during the previous audit; (5) on low SO2

emitting units (SO2 concentrations ≤250.0

ppm, or equivalent lb/mmBtu value for SO2-

diluent continuous emission monitoring

systems), when the monitor mean is within

±8.0 ppm (or equivalent in lb/mmBtu for

SO2-diluent continuous emission monitoring

systems) of the reference method mean or

achieves a relative accuracy of 7.5 percent or

less during the previous audit; or (6) on low

NOX emitting units (NOX emission rate ≤0.20

lb/mmBtu), when the NOΧ continuous

emission monitoring system achieves a

relative accuracy of 7.5 percent or less or

when the monitoring system mean,

calculated using Equation A–7 in appendix A

of this part is within ±0.01 lb/mmBtu of the

reference method mean.

A maximum of two relative accuracy test

audit trials may be performed for the purpose

of achieving the results required to qualify

for less frequent relative accuracy test audits.

Whenever two trials are performed, the

results of the second (later) trial must be used

in calculating both the relative accuracy and

bias.

2.3.2 Out-of-Control Period

An out-of-control period occurs under any

of the following conditions: (1) The relative

accuracy of an SO2, CO2, or O2 pollutant

concentration monitor or a NOX or SO2-

diluent continuous emission monitoring

system exceeds 10.0 percent; (2) prior to

January 1, 2000, the relative accuracy of a

flow monitor exceeds 15.0 percent; (3) on

and after January 1, 2000, the relative

accuracy of a flow monitor exceeds 10.0

percent; (4) for low flow situations (≤10.0

fps), the flow monitor mean value (if

applicable) exceeds ±2.0 fps of the reference

method mean whenever the relative accuracy

is greater than 15.0 percent for Phase I or 10

percent for Phase II; (5) for low SO2 emitter

situations, the monitor mean values exceeds

±15.0 ppm (or ± 0.03 lb/mmBtu for SO2-

diluent continuous emission monitoring

systems from January 1, 1997 through

December 31, 1999) of the reference method

mean whenever the relative accuracy is

greater than 10.0 percent; or (6) for low NOX

emitting units (NOX emission rate ≤0.2 lb/

mmBtu), the NOX continuous emission

monitoring system mean values exceed ±0.02

lb/mmBtu of the reference method mean

whenever the relative accuracy is greater

than 10.0 percent. For SO2, CO2, O2, NOX

emission rate, and flow relative accuracy test

audits performed at only one level, the outof-control period begins with the hour of

completion of the failed relative accuracy test

audit and ends with the hour of completion

of a satisfactory relative accuracy test audit.

For a flow relative accuracy test audit at 3

operating levels, the out-of-control period

begins with the hour of completion of the

first failed relative accuracy test audit at any

of the three operating levels, and ends with

the hour of completion of a satisfactory threelevel relative accuracy test audit.

Failure of the bias test does not result in

the system or monitor being out-of-control.

* * * * *

FIGURE 2.—RELATIVE ACCURACY TEST FREQUENCY INCENTIVE SYSTEM

RATA Semiannually 1

(percent) Annual 1

SO2 ......................................................................................................................................... RA ≤ 10 RA ≤ 7.5% or ±8.0 ppm.2

NOX ........................................................................................................................................ RA ≤ 10 RA ≤ 7.5% or ±0.01 lb/mmBtu.2

Flow (Phase I) 3 ...................................................................................................................... RA ≤ 15 RA ≤ 10% or ± 1.5 fps.2

Flow (Phase II) 3 ..................................................................................................................... RA ≤ 10 RA ≤ 7.5% or ± 1.5 fps.2

CO2/O2 ................................................................................................................................... RA ≤ 10 RA ≤ 7.5%.

1For monitors on bypass stack/duct, bypass operating quarters, not to exceed two calendar years. For monitors on peaking units, unit operating quarters, not to exceed two calendar years. 2The difference between monitor and reference method mean values; low emitters or low flow, only.

3 Conduct 3-load RATAs annually, if requirements to qualify for less frequent testing are met.

Appendix C to Part 75—Missing Data

Estimation Procedures

60. Appendix C to part 75, section 1

is amended by revising the section

heading and the first paragraph of

section 1.2 and by revising the first

paragraph of section 1.3 to read as

follows:

1. Parametric Monitoring Procedure for

Missing SO2 Concentration or NOX Emission

Rate Data

* * * * *

1.2 Petition Requirements

Continuously monitor, determine, and

record hourly averages of the estimated SO2

or NOX removal efficiency and of the

parameters specified below, at a minimum.

The affected facility shall supply additional

parametric information where appropriate.

Measure the SO2 concentration or NOX

emission rate, removal efficiency of the addon emission controls, and the parameters for

at least 2160 unit operating hours. Provide

information for all expected operating

conditions and removal efficiencies. At least

4 evenly spaced data points are required for

a valid hourly average, except during periods

of calibration, maintenance, or quality

assurance activities, during which 2 data

points per hour are sufficient. The
26548 Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations

Administrator will review all applications on

a case-by-case basis.

* * * * *

1.3 Correlation of Emissions With

Parameters

Establish a method for correlating hourly

averages of the parameters identified above

with the percent removal efficiency of the

SO2 or post-combustion NOX emission

controls under varying unit operating loads.

Equations 1–7 in § 75.15 may be used to

estimate the percent removal efficiency of the

SO2 emission controls on an hourly basis.

* * * * *

61. Appendix C to part 75, section 2

is amended by revising section 2.2.1,

Table C–1, and sections 2.2.3, 2.2.3.1,

2.2.3.5, and 2.2.5 to read as follows:

* * * * *

2. Procedure

2.2.1 For a single unit, establish 10

operating load ranges defined in terms of

percent of the maximum hourly gross load of

the unit, in gross megawatts (MWge), as

shown in Table C–1. For units sharing a

common stack monitored with a single flow

monitor, the load ranges for flow (but not for

NOX) may be broken down into 20 equallysized operating load ranges in increments of

5 percent of the combined maximum hourly

gross load of all units utilizing the common

stack. 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 gross load in MWge is not

recorded separately, use the hourly gross

steam load of the unit, in pounds of steam

per hour at the measured temperature (°F)

and pressure (psia) instead of MWge. Indicate

a change in the number of load ranges or the

units of loads to be used in the

precertification section of the monitoring

plan.

TABLE C–1.—DEFINITION OF OPERATING LOAD RANGES FOR LOAD-BASED

SUBSTITUTION DATA PROCEDURES

Operating load range

Percent of

maximum

hourly gross

load (%)

1 ............................................ 0–10

2 ............................................ 10–20

3 ............................................ 20–30

4 ............................................ 30–40

5 ............................................ 40–50

6 ............................................ 50–60

7 ............................................ 60–70

8 ............................................ 70–80

9 ............................................ 80–90

10 .......................................... 90–100

2.2.2 * * *

2.2.3 Beginning with the first hour of unit

operation after installation and certification

of the flow monitor or the NOX continuous

emission monitoring system and continuing

thereafter, the data acquisition and handling

system must be capable of calculating and

recording the following information for each

unit operating hour of missing flow or NOX

data within each identified load range during

the shorter of: (1) the previous 2,160 quality

assured monitor operating hours (on a rolling

basis), or (2) all previous quality assured

monitor operating hours.

2.2.3.1 Average of the hourly flow rates

reported by a flow monitor, in scfh.

2.2.3.2 * * *

2.2.3.3 * * *

2.2.3.4 * * *

2.2.3.5 Average of the hourly NOX

emission rate, in lb/mmBtu, reported by a

NOX continuous emission monitoring

system.

2.2.3.6 * * *

2.2.3.7 * * *

2.2.3.8 * * *

2.2.4 * * *

2.2.5 When a bias adjustment is necessary

for the flow monitor and/or the NOX

continuous emission monitoring system,

apply the adjustment factor to all monitor or

continuous emission monitoring system data

values placed in the load ranges.

2.2.6 * * *

Appendix D to Part 75—Optional SO2

Emissions Data Protocol for Gas-Fired

and Oil-Fired Units

62. Appendix D to part 75, section 1

is amended by revising section 1.1; by

removing section 1.2 and revising and

redesignating section 1.3 as section 1.2;

and by removing section 1.4 to read as

follows:

1. Applicability

1.1 This protocol may be used in lieu of

continuous SO2 pollutant concentration and

flow monitors for the purpose of determining

hourly SO2 emissions and heat input from:

(1) gas-fired units as defined in § 72.2 of this

chapter; or (2) oil-fired units as defined in

§ 72.2 of this chapter. This optional SO2

emissions data protocol contains procedures

for conducting oil sampling and analysis in

section 2.2 of this appendix; the procedures

for flow proportional oil sampling and the

procedures for manual daily oil sampling

may be used for any gas-fired unit or oil-fired

unit. In addition, this optional SO2 emissions

data protocol contains two procedures for

determining SO2 emissions due to the

combustion of gaseous fuels; these two

procedures may be used for any gas-fired unit

or oil-fired unit.

1.2 Pursuant to the procedures in § 75.20,

complete all testing requirements to certify

use of this protocol in lieu of a flow monitor

and an SO2 continuous emission monitoring

system. Complete all testing requirements no

later than the applicable deadline specified

in § 75.4. Apply to the Administrator for

initial certification to use this protocol no

later than 45 days after the completion of all

certification tests. Whenever the monitoring

method is to be changed, reapply to the

Administrator for recertification of the new

monitoring method.

63. Appendix D to part 75, section 2

is revised to read as follows:

2. Procedure

2.1 Flowmeter Measurements

For each hour when the unit is combusting

fuel, measure and record the flow of fuel

combusted by the unit, except as provided

for gas in section 2.1.4 of this appendix.

Measure the flow of fuel with an in-line fuel

flowmeter and automatically record the data

with a data acquisition and handling system,

except as provided in section 2.1.4 of this

appendix.

2.1.1 Measure the flow of each fuel

entering and being combusted by the unit. If

a portion of the flow is diverted from the unit

without being burned, and that diversion

occurs downstream of the fuel flowmeter, an

additional in-line fuel flowmeter is required

to account for the unburned fuel. Record the

flow of each fuel combusted by the unit as

the difference between the flow measured in

the pipe leading to the unit and the flow in

the pipe diverting fuel away from the unit.

2.1.2 Install and use fuel flowmeters

meeting the requirements of this appendix in

a pipe going to each unit, or install and use

a fuel flowmeter in a common pipe header

(i.e., a pipe carrying fuel for multiple units).

If the flowmeter is installed in a common

pipe header, do one of the following:

2.1.2.1 Measure the fuel flow in the

common pipe and combine SO2 mass

emissions for the affected units for

recordkeeping and compliance purposes; or

2.1.2.2 Provide information satisfactory to

the Administrator on methods for

apportioning SO2 mass emissions and heat

input to each of the affected units

demonstrating that the method ensures

complete and accurate accounting of all

emissions regulated under this part. The

information shall be provided to the

Administrator through a petition submitted

by the designated representative under

§ 75.66. Satisfactory information includes

apportionment using fuel flow

measurements, the ratio of load (in MWe) in

each unit to the total load for all units

receiving fuel from the common pipe header,

or the ratio of steam flow (in 1000 lb/hr) at

each unit to the total steam flow for all units

receiving fuel from the common pipe header.

2.1.3 For a gas-fired unit or an oil-fired

unit that continuously or frequently

combusts a supplemental fuel for flame

stabilization or safety purposes, measure the

flow of the supplemental fuel with a fuel

flowmeter meeting the requirements of this

appendix.

2.1.4 For an oil-fired unit that uses gas

solely for start-up or burner ignition or a gasfired unit that uses oil solely for start-up or

burner ignition a flowmeter for the start-up

fuel is not required. Estimate the volume of

oil combusted for each start-up or ignition,

either by using a fuel flowmeter or by using

the dimensions of the storage container and

measuring the depth of the fuel in the storage

container before and after each start-up or

ignition. A fuel flowmeter used solely for

start-up or ignition fuel is not subject to the

calibration requirements of section 2.1.5 and

2.1.6 of this appendix. Gas combusted solely

for start-up or burner ignition does not need

to be measured separately.

2.1.5 Each fuel flowmeter used to meet

the requirements of this protocol shall meet
Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations 26549

a flowmeter accuracy of ±2.0 percent of the

upper range value (i.e, maximum calibrated

fuel flow rate), either by design or as

calibrated and as measured under laboratory

conditions by the manufacturer, by an

independent laboratory, or by the owner or

operator. The flowmeter accuracy must

include all error from all parts of the fuel

flowmeter being calibrated based upon the

contribution to the error in the flowrate.

2.1.5.1 Use the procedures in the

following standards for flowmeter calibration

or flowmeter design, as appropriate to the

type of flowmeter: ASME MFC–3M–1989

with September 1990 Errata (‘‘Measurement

of Fluid Flow in Pipes Using Orifice, Nozzle,

and Venturi’’), ASME MFC–4M–1986

(Reaffirmed 1990), ‘‘Measurement of Gas

Flow by Turbine Meters,’’ American Gas

Association Report No. 3, ‘‘Orifice Metering

of Natural Gas and Other Related

Hydrocarbon Fluids Part 1: General

Equations and Uncertainty Guidelines’’

(October 1990 Edition), Part 2: ‘‘Specification

and Installation Requirements’’ (February

1991 Edition) and Part 3: ‘‘Natural Gas

Applications’’ (August 1992 edition),

(excluding the modified flow-calculation

method in Part 3) ASME MFC–5M–1985

(‘‘Measurement of Liquid Flow in Closed

Conduits Using Transit-Time Ultrasonic

Flowmeters’’), ASME MFC–6M–1987 with

June 1987 Errata (‘‘Measurement of Fluid

Flow in Pipes Using Vortex Flow Meters’’),

ASME MFC–7M–1987 (Reaffirmed 1992),

‘‘Measurement of Gas Flow by Means of

Critical Flow Venturi Nozzles,’’ ISO 8316:

1987(E) ‘‘Measurement of Liquid Flow in

Closed Conduits—Method by Collection of

the Liquid in a Volumetric Tank,’’ or MFC–

9M–1988 with December 1989 Errata

(‘‘Measurement of Liquid Flow in Closed

Conduits by Weighing Method’’) for all other

flow meter types (incorporated by reference

under § 75.6 of this part). The Administrator

may also approve other procedures that use

equipment traceable to National Institute of

Standards and Technology (NIST) standards.

Document other procedures, the equipment

used, and the accuracy of the procedures in

the monitoring plan for the unit and a

petition submitted by the designated

representative under § 75.66(c). If the

flowmeter accuracy exceeds ±2.0 percent of

the upper range value, the flowmeter does

not qualify for use under this part.

2.1.5.2 Alternatively, a fuel flowmeter

used for the purposes of this part may be

calibrated or recalibrated at least annually

(or, for fuel flowmeters measuring emergency

fuel, bypass fuel or fuel usage of peaking

units, every four calendar quarters when the

unit combusts the fuel measured by the fuel

flowmeter) by comparing the measured flow

of a flowmeter to the measured flow from

another flowmeter which has been calibrated

or recalibrated during the previous 365 days

using a standard listed in section 2.1.5 of this

appendix or other procedure approved by the

Administrator under § 75.66. Any secondary

elements, such as pressure and temperature

transmitters, must be calibrated immediately

prior to the comparison. Perform the

comparison over a period of no more than

seven consecutive unit operating days.

Compare the average of three fuel flow

readings for each meter at each of three

different flow levels, corresponding to (1)

normal full operating load, (2) normal

minimum operating load, and (3) a load point

approximately equally spaced between the

full and minimum operating loads. Calculate

the flowmeter accuracy at each of the three

flow levels using the following equation:

ACC

R A

URV = Eq D − × − 100 1 ( . )

Where:

ACC=Flow meter accuracy as a percentage of

the upper range value, including all error

from all parts of both flowmeters.

R=Average of the three flow measurements of

the reference flow meter.

A=Average of the three measurements of the

flow meter being tested.

URV=Upper range value of fuel flow meter

being tested (i.e. maximum measurable

flow).

If the flow meter accuracy exceeds ±2.0

percent of the upper range value at any of the

three flow levels, either recalibrate the flow

meter until the accuracy is within the

performance specification, or replace the

flow meter with another one that is within

the performance specification.

Notwithstanding the requirement for annual

calibration of the reference flowmeter, if a

reference flowmeter and the flowmeter being

tested are within ±1.0 percent of the flowrate

of each other during all in-place calibrations

in a calendar year, then the reference

flowmeter does not need to be calibrated

before the next in-place calibration. This

exception to calibration requirements for the

reference flowmeter may be extended for

periods up to five calendar years.

2.1.6 Quality Assurance

2.1.6.1 Recalibrate each fuel flowmeter to

a flowmeter accuracy of ±2.0 percent of the

upper range value prior to use under this part

at least annually (or, for fuel flowmeters

measuring emergency fuel, bypass fuel or

fuel usage of peaking units, every four

calendar quarters when the unit combusts the

fuel measured by the fuel flowmeter), or

more frequently if required by manufacturer

specifications. Perform the recalibration

using the procedures in section 2.1.5 of this

appendix. For orifice-, nozzle-, and venturitype flowmeters, also recalibrate the

flowmeter the following calendar quarter

using the procedures in section 2.1.6.2 of this

appendix, whenever the fuel flowmeter

accuracy during a calibration or test is greater

than ±1.0 percent of the upper range value,

or whenever a visual inspection of the

orifice, nozzle, or venturi identifies corrosion

since the previous visual inspection.

2.1.6.2 For orifice-, nozzle-, and venturitype flowmeters that are designed according

to the standards in section 2.1.5 of this

appendix, satisfy the calibration

requirements of this appendix by calibrating

the differential pressure transmitter or

transducer, static pressure transmitter or

transducer, and temperature transmitter or

transducer, as applicable, using equipment

that has a current certificate of traceability to

NIST standards. In addition, conduct a visual

inspection of the orifice, nozzle, or venturi at

least annually.

2.2 Oil Sampling and Analysis

Perform sampling and analysis of as-fired

oil to determine the percentage of sulfur by

weight in the oil.

2.2.1 When combusting diesel fuel,

sample the diesel fuel either (1) every day the

unit combusts diesel fuel, or (2) upon receipt

of a shipment of diesel fuel.

2.2.1.1 If the diesel fuel is sampled every

day, use either the flow proportional method

described in section 2.2.3 of this appendix or

the daily manual method described in

section 2.2.4 of this appendix.

2.2.1.2 If the diesel fuel is sampled upon

delivery, calculate SO2 emissions using the

highest sulfur content of any oil supply

combusted in the previous 30 days that the

unit combusted oil. Diesel fuel sampling and

analysis may be performed either by the

owner or operator of an affected unit, an

outside laboratory, or a fuel supplier,

provided that sampling is performed

according to ASTM D4057–88, ‘‘Standard

Practice for Manual Sampling of Petroleum

and Petroleum Products’’ (incorporated by

reference under § 75.6 of this part).

2.2.2 Perform oil sampling every day the

unit is combusting oil except as provided for

diesel fuel. Use either the flow proportional

method described in section 2.2.3 of this

appendix or the daily manual method

described in section 2.2.4 of this appendix.

2.2.3 Conduct flow proportional oil

sampling or continuous drip oil sampling in

accordance with ASTM D4177–82

(Reapproved 1990), ‘‘Standard Practice for

Automatic Sampling of Petroleum and

Petroleum Products’’ (incorporated by

reference under § 75.6), every day the unit is

combusting oil. Extract oil at least once every

hour and blend into a daily composite

sample. The sample composite period may

not exceed 24 hr.

2.2.4 Representative as-fired oil samples

may be taken manually every day that the

unit combusts oil according to ASTM D4057–

88, ‘‘Standard Practice for Manual Sampling

of Petroleum and Petroleum Products’’

(incorporated by reference under § 75.6),

provided that the highest fuel sulfur content

recorded at that unit from the most recent 30

daily samples is used for the purposes of

calculating SO2 emissions under section 3 of

this appendix. Use the gross calorific value

measured from that day’s sample to calculate

heat input. If oil supplies with different

sulfur contents are combusted on the same

day, sample the highest sulfur fuel

combusted that day.

Note: For units with pressurized fuel flow

lines such as some diesel and dual-fuel

reciprocating internal combustion engine

units, a manual sample may be taken from

the point closest to the unit where it is safe

to take a sample (including back to the oil

tank), rather than just prior to entry to the

boiler or combustion chamber. As-delivered

manual samples of diesel fuel need not be asfired.

2.2.5 Split and label each oil sample.

Maintain a portion (at least 200 cc) of each

sample throughout the calendar year and in

all cases for not less than 90 calendar days
26550 Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations

after the end of the calendar year allowance

accounting period. Analyze oil samples for

percent sulfur content by weight in

accordance with ASTM D129–91, ‘‘Standard

Test Method for Sulfur in Petroleum

Products (General Bomb Method),’’ ASTM

D1552–90, ‘‘Standard Test Method for Sulfur

in Petroleum Products (High Temperature

Method),’’ ASTM D2622–92, ‘‘Standard Test

Method for Sulfur in Petroleum Products by

X-Ray Spectrometry,’’ or ASTM D4294–90,

‘‘Standard Test Method for Sulfur in

Petroleum Products by Energy-Dispersive XRay Fluorescence Spectroscopy’’

(incorporated by reference under § 75.6).

2.2.6 Where the flowmeter records

volumetric flow rather than mass flow,

analyze oil samples to determine the density

or specific gravity of the oil. Determine the

density or specific gravity of the oil sample

in accordance with ASTM D287–82

(Reapproved 1991), ‘‘Standard Test Method

for API Gravity of Crude Petroleum and

Petroleum Products (Hydrometer Method),’’

ASTM D941–88, ‘‘Standard Test Method for

Density and Relative Density (Specific

Gravity) of Liquids by Lipkin Bicapillary

Pycnometer,’’ ASTM D1217–91, ‘‘Standard

Test Method for Density and Relative Density

(Specific Gravity) of Liquids by Bingham

Pycnometer,’’ ASTM D1481–91, ‘‘Standard

Test Method for Density and Relative Density

(Specific Gravity) of Viscous Materials by

Lipkin Bicapillary,’’ ASTM D1480–91,

‘‘Standard Test Method for Density and

Relative Density (Specific Gravity) of Viscous

Materials by Bingham Pycnometer,’’ ASTM

D1298–85 (Reapproved 1990), ‘‘Standard

Practice for Density, Relative Density

(Specific Gravity) or API Gravity of Crude

Petroleum and Liquid Petroleum Products by

Hydrometer Method,’’ or ASTM D4052–91,

‘‘Standard Test Method for Density and

Relative Density of Liquids by Digital Density

Meter’’ (incorporated by reference under

§ 75.6).

2.2.7 Analyze oil samples to determine

the heat content of the fuel. Determine oil

heat content in accordance with ASTM

D240–87 (Reapproved 1991), ‘‘Standard Test

Method for Heat of Combustion of Liquid

Hydrocarbon Fuels by Bomb Calorimeter,’’

ASTM D2382–88, ‘‘Standard Test Method for

Heat or Combustion of Hydrocarbon Fuels by

Bomb Calorimeter (High-Precision Method)’’,

or ASTM D2015–91, ‘‘Standard Test Method

for Gross Calorific Value of Coal and Coke by

the Adiabatic Bomb Calorimeter’’

(incorporated by reference under § 75.6) or

any other procedures listed in section 5.5 of

appendix F of this part.

2.2.8 Results from the oil sample analysis

must be available no later than thirty

calendar days after the sample is composited

or taken. However, during an audit, the

Administrator may require that the results of

the analysis be available within 5 business

days, or sooner if practicable.

2.3 SO2 Emissions from Combustion of

Gaseous Fuels

Account for the hourly SO2 mass emissions

due to combustion of gaseous fuels for each

day when gaseous fuels are combusted by the

unit using the procedures in either section

2.3.1 or 2.3.2.

2.3.1 Sample the gaseous fuel daily.

2.3.1.1 Analyze the sulfur content of the

gaseous fuel in grain/100 scf using ASTM

D1072–90, ‘‘Standard Test Method for Total

Sulfur in Fuel Gases’’, ASTM D4468–85

(Reapproved 1989) ‘‘Standard Test Method

for Total Sulfur in Gaseous Fuels by

Hydrogenolysis and Rateometric

Colorimetry,’’ ASTM D5504–94 ‘‘Standard

Test Method for Determination of Sulfur

Compounds in Natural Gas and Gaseous

Fuels by Gas Chromatography and

Chemiluminescence,’’ or ASTM D3246–81

(Reapproved 1987) ‘‘Standard Test Method

for Sulfur in Petroleum Gas By Oxidative

Microcoulometry’’ (incorporated by reference

under § 75.6). The test may be performed by

the owner or operator, an outside laboratory,

or the gas supplier.

2.3.1.2 Results from the analysis must be

available on-site no later than thirty calendar

days after the sample is taken.

2.3.1.3 Determine the heat content or

gross calorific value for at least one sample

each month and use the procedures of

section 5.5 of appendix F of this part to

determine the heat input for each hour the

unit combusted gaseous fuel.

2.3.1.4 Multiply the sulfur content by the

hourly metered volume of gas combusted in

100 scf, using Equation D–4 of this appendix.

2.3.2 If the fuel is pipeline natural gas,

calculate SO2 emissions using a default SO2

emission rate of 0.0006 lb/mmBtu.

2.3.2.1 Use the default SO2 emission rate

of 0.0006 lb/mmBtu and the hourly heat

input from pipeline natural gas in mmBtu/hr,

as determined using the procedures in

section 5.5 of appendix F of this part.

Calculate SO2 emissions using Equation D–5

of this appendix.

2.3.2.2 Provide information on the

contractual sulfur content from the pipeline

gas supplier in the monitoring plan for the

unit, demonstrating that the gas has a

hydrogen sulfide content of 1 grain/100 scf

or less, and a total sulfur content of 20 grain/

100 scf or less.

2.4 Missing Data Procedures.

When data from the procedures of this part

are not available, provide substitute data

using the following procedures.

2.4.1 When sulfur content or oil density

data from the analysis of an oil sample or

when sulfur content data from the analysis of

a gaseous fuel sample are missing or invalid,

substitute, as applicable, the highest

measured sulfur content or oil density (if

using a volumetric oil flowmeter) recorded

during the previous 30 days when the unit

burned that fuel. If no previous sulfur

content data are available, substitute the

maximum potential sulfur content of that

fuel.

2.4.2 When gross calorific value data

from the analysis of an oil sample are missing

or invalid, substitute the highest measured

gross calorific value recorded during the

previous 30 days that the unit burned oil.

When gross calorific value data from the

analysis of a monthly gaseous fuel sample are

missing or invalid, substitute the highest

measured gross calorific value recorded

during the previous three months that the

unit burned gaseous fuel.

2.4.3 Whenever data are missing from any

fuel flowmeter that is part of an excepted

monitoring system under appendix D or E of

this part, where the fuel flowmeter data are

required to determine the amount of fuel

combusted by the unit, use the procedures in

either section 2.4.3.1 or sections 2.4.3.2 and

2.4.3.3 prior to January 1, 1996 and use the

procedures in sections 2.4.3.2 and 2.4.3.3 but

do not use the procedures in section 2.4.3.1

on or after January 1, 1996 to account for the

flow rate of fuel combusted at the unit for

each hour during the missing data period.

2.4.3.1 When data from the fuel

flowmeter are missing, substitute for each

hour in the missing data period the average

hourly oil flow rate measured and recorded

by the fuel flowmeter at the closest unit load

(in MWe) greater than the load recorded for

the missing data period for which oil flow

rate data are available during the previous

720 hours during which the unit combusted

oil. If no oil flow rate data are available at

a load greater than the load recorded during

the missing data period, substitute the

maximum flow rate that the flowmeter can

measure.

2.4.3.2 For hours where only one fuel is

combusted, substitute for each hour in the

missing data period the average of the hourly

fuel flow rate(s) measured and recorded by

the fuel flowmeter (or flowmeters, where fuel

is recirculated) at the corresponding

operating unit load range recorded for each

missing hour during the previous 720 hours

during which the unit combusted that same

fuel only. Establish load ranges for the unit

using the procedures of section 2 in appendix

C of this part for missing volumetric flow rate

data. If no fuel flow rate data are available

at the corresponding load range, use data

from the next higher load range where data

are available. If no fuel flow rate data are

available at either the corresponding load

range or a higher load range during any hour

of the missing data period for that fuel,

substitute the maximum potential fuel flow

rate. The maximum potential fuel flow rate

is the lesser of the following: (1) the

maximum fuel flow rate the unit is capable

of combusting or (2) the maximum flow rate

that the flowmeter can measure.

2.4.3.3 For hours where two or more fuels

are combusted, substitute the maximum

hourly fuel flow rate measured and recorded

by the flowmeter (or flowmeters, where fuel

is recirculated) for the fuel for which data are

missing at the corresponding load range

recorded for each missing hour during the

previous 720 hours when the unit combusted

that fuel with any other fuel. For hours where

no previous recorded fuel flow rate data are

available for that fuel during the missing data

period, calculate and substitute the

maximum potential flow rate of that fuel for

the unit as defined in section 2.4.3.2 of this

appendix.

2.4.4. In any case where the missing data

provisions of this section require substitution

of data measured and recorded more than

three years (26,280 clock hours) prior to the

date and time of the missing data period, use

three years (26,280 clock hours) in place of

the prescribed lookback period.

* * * * *
Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations 26551

64. Appendix D to part 75, section 3

is amended by revising the introductory

paragraph; by revising the section

heading of section 3.1; by revising the

definition of the variable ‘‘MSO2’’ in

Equation D–2 in section 3.1.1; by

revising section 3.1.2; by revising the

section heading of section 3.2; by

revising section 3.2.1; and by adding

sections 3.3, 3.3.1, 3.3.2, 3.3.3, and 3.4

to read as follows:

3. Calculations

Use the calculation procedures in section

3.1 of this appendix to calculate SO2 mass

emissions. Where an oil flowmeter records

volumetric flow, use the calculation

procedures in section 3.2 of this appendix to

calculate mass flow of oil. Calculate hourly

SO2 mass emissions from gaseous fuel using

the procedures in section 3.3 of this

appendix. Calculate hourly heat input for oil

and for gaseous fuel using the equations in

section 5.5 of Appendix F of this part.

Calculate total SO2 mass emissions and heat

input as provided under section 3.4 of this

appendix.

3.1 SO2 Mass Emissions Calculation for Oil

3.1.1 * * *

Where:

MSO2=Hourly mass of SO2 emitted from

combustion of oil, lb/hr.

* * * * *

3.1.2 Record the SO2 mass emissions

from oil for each hour that oil is combusted.

3.2 Mass Flow Calculation for Oil Using

Volumetric Flow

3.2.1 Where the oil flowmeter records

volumetric flow rather than mass flow,

calculate and record the oil mass flow for

each hourly period using hourly oil flow

measurements and the density or specific

gravity of the oil sample.

* * * * *

3.3 SO2 Mass Emissions Calculation for

Gaseous Fuels

3.3.1 Use the following equation to

calculate the SO2 emissions using the gas

sampling and analysis procedures in section

2.3.1 of this appendix:

M Q S Eq D SO g g g 2

2 0

7000 = 4 



 



 × × − . ( . )

Where:

MSO2g=Hourly mass of SO2 emitted due to

combustion of gaseous fuel, lb/hr.

Qg=Hourly metered flow or amount of

gaseous fuel combusted, 100 scf/hr.

Sg=Sulfur content of gaseous fuel, in grain/

100 scf.

2.0=Ratio of lb SO2/lb S.

7000=Conversion of grains/100 scf to lb/100

scf.

3.3.2 Use the following equation to

calculate the SO2 emissions using the 0.0006

lb/mmBtu emission rate in section 2.3.2 of

this appendix:

M ER HI Eq D SO g g 2 = × − ( . ) 5

Where:

MSO2g=Hourly mass of SO2 emissions from

combustion of pipeline natural gas, lb/

hr.

ER=SO2 emission rate of 0.0006 lb/mmBtu

for pipeline natural gas.

HIg=Hourly heat input of pipeline natural

gas, calculated using procedures in

appendix F of this part, in mmBtu/hr.

3.3.3 Record the SO2 mass emissions for

each hour when the unit combusts gaseous

fuel.

3.4 Records and Reports

Calculate and record quarterly and

cumulative SO2 mass emissions and heat

input for each calendar quarter and for the

calendar year by summing the hourly values.

Calculate and record SO2 emissions and heat

input data using a data acquisition and

handling system. Report these data in a

standard electronic format specified by the

Administrator.

* * * * *

Appendix E to Part 75—Optional NOX

Emissions Estimation Protocol for GasFired Peaking Units and Oil-Fired

Peaking Units

65. Appendix E to part 75, section 1

is amended by revising section 1.1; by

removing section 1.2, redesignating

sections 1.3, 1.3.1 and 1.3.2 as sections

1.2, 1.2.1 and 1.2.2 and revising new

sections 1.2, 1.2.1 and 1.2.2 to read as

follows:

1. Applicability

1.1 Unit Operation Requirements

This NOX emissions estimation procedure

may be used in lieu of a continuous NOX

emission monitoring system (lb/mmBtu) for

determining the average NOX emission rate

and hourly NOX rate from gas-fired peaking

units and oil-fired peaking units as defined

in § 72.2 of this chapter. If a unit’s operations

exceed the levels required to be a peaking

unit, install and certify a continuous NOX

emission monitoring system no later than

December 31 of the following calendar year.

The provisions of § 75.12 apply to excepted

monitoring systems under this appendix.

1.2 Certification

1.2.1 Pursuant to the procedures in

§ 75.20, complete all testing requirements to

certify use of this protocol in lieu of a NOX

continuous emission monitoring system no

later than the applicable deadline specified

in § 75.4. Apply to the Administrator for

certification to use this method no later than

45 days after the completion of all

certification testing. Whenever the

monitoring method is to be changed, reapply

to the Administrator for certification of the

new monitoring method.

1.2.2 If the owner or operator has already

successfully completed certification testing

of the unit using the protocol of appendix E

of part 75 and submitted a certification

application under § 75.20(g) prior to llll

July 17, 1995, the unit’s monitoring system

does not need to repeat initial certification

testing using the revised procedures

published llll May 17, 1995.

* * * * *

66. Appendix E to part 75, section 2

is amended by revising sections 2.1,

2.1.1, 2.1.2, 2.1.2.1, and 2.1.2.2; by

removing section 2.1.2.3 and

redesignating section 2.1.2.4 as 2.1.2.3;

by revising sections 2.1.3, 2.1.3.1, and

2.1.3.2; by revising sections 2.1.4, 2.1.5,

2.1.6, 2.1.6.1, and 2.1.6.2; by revising

sections 2.3, 2.3.1 and 2.3.2; by

removing sections 2.1.4.1, 2.1.4.2,

2.1.4.3, 2.1.4.4, 2.3.3, 2.3.3.1 and 2.3.3.3;

by redesignating section 2.3.3.2 as

section 2.3.3 and revising new section

2.3.3; by revising section 2.4.1; by

revising section 2.4.2 and adding

sections 2.4.3 and 2.4.4; by revising

section 2.5 and adding sections 2.5.1,

2.5.2, 2.5.3, 2.5.4, and 2.5.5 to read as

follows:

2. Procedure

2.1 Initial Performance Testing

Use the following procedures for:

measuring NOX emission rates at heat input

rate levels corresponding to different load

levels; measuring heat input rate; and

plotting the correlation between heat input

rate and NOX emission rate, in order to

determine the emission rate of the unit(s).

2.1.1 Load Selection

Establish at least four approximately

equally spaced operating load points, ranging

from the maximum operating load to the

minimum operating load. Select the

maximum and minimum operating load from

the operating history of the unit during the

most recent two years. (If projections indicate

that the unit’s maximum or minimum

operating load during the next five years will

be significantly different from the most

recent two years, select the maximum and

minimum operating load based on the

projected dispatched load of the unit.) For

new gas-fired peaking units or new oil-fired

peaking units, select the maximum and

minimum operating load from the expected

maximum and minimum load to be

dispatched to the unit in the first five

calendar years of operation.

2.1.2 NOX and O2 Concentration

Measurements

Use the following procedures to measure

NOX and O2 concentration in order to

determine NOX emission rate.

2.1.2.1 For boilers, select an excess O2

level for each fuel (and, optionally, for each

combination of fuels) to be combusted that is

representative for each of the four or more

load levels. If a boiler operates using a single,

consistent combination of fuels only, the

testing may be performed using the

combination rather than each fuel. If a fuel

is combusted only for the purpose of testing

ignition of the burners for a period of five

minutes or less per ignition test or for startup, then the boiler NOX emission rate does

not need to be tested separately for that fuel.

Operate the boiler at a normal or

conservatively high excess oxygen level in
26552 Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations

conjunction with these tests. Measure the

NOX and O2 at each load point for each fuel

or consistent fuel combination (and,

optionally, for each combination of fuels) to

be combusted. Measure the NOX and O2

concentrations according to Method 7E and

3A in appendix A of part 60 of this chapter.

Select sampling points as specified in section

5.1, Method 3 in appendix A of part 60 of

this chapter. The designated representative

for the unit may also petition the

Administrator under § 75.66 to use fewer

sampling points. Such a petition shall

include the proposed alternative sampling

procedure and information demonstrating

that there is no concentration stratification at

the sampling location.

2.1.2.2 For stationary gas turbines, select

sampling points and measure the NOX and

O2 concentrations at each load point for each

fuel or consistent combination of fuels (and,

optionally, each combination of fuels)

according to appendix A, Method 20 of part

60 of this chapter. For diesel or dual fuel

reciprocating engines, measure the NOX and

O2 concentrations according to Method 20,

but modify Method 20 by selecting a

sampling site to be as close as practical to the

exhaust of the engine.

2.1.2.3 Allow the unit to stabilize for a

minimum of 15 minutes (or longer if needed

for the NOX and O2 readings to stabilize)

prior to commencing NOx, O2, and heat input

measurements. Determine the average

measurement system response time

according to section 5.5 of Method 20 in

appendix A, part 60 of this chapter. When

inserting the probe into the flue gas for the

first sampling point in each traverse, sample

for at least one minute plus twice the average

measurement system response time (or

longer, if necessary to obtain a stable

reading). For all other sampling points in

each traverse, sample for at least one minute

plus the average measurement response time

(or longer, if necessary to obtain a stable

reading). Perform three test runs at each load

condition and obtain an arithmetic average of

the runs for each load condition. During each

test run on a boiler, record the boiler excess

oxygen level at 5 minute intervals.

2.1.3 Heat Input

Measure the total heat input (mmBtu) and

heat input rate during testing (mmBtu/hr) as

follows:

2.1.3.1 When the unit is combusting fuel,

measure and record the flow of fuel

consumed. Measure the flow of fuel with an

in-line flowmeter(s) and automatically record

the data. If a portion of the flow is diverted

from the unit without being burned, and that

diversion occurs downstream of the fuel

flowmeter, an in-line flowmeter is required to

account for the unburned fuel. Install and

calibrate in-line flow meters using the

procedures and specifications contained in

sections 2.1.2, 2.1.3, 2.1.4, and 2.1.5 of

appendix D of this part. Correct any gaseous

fuel flow rate measured at actual temperature

and pressure to standard conditions of 68°F

and 29.92 inches of mercury.

2.1.3.2 For liquid fuels, analyze fuel

samples taken according to the requirements

of section 2.2 of appendix D of this part to

determine the heat content of the fuel.

Determine heat content of liquid or gaseous

fuel in accordance with the procedures in

appendix F of this part. Calculate the heat

input rate during testing (mmBtu/hr)

associated with each load condition in

accordance with Equations F–19 or F–20 in

appendix F of this part and total heat input

using Equation E–1 of this appendix. Record

the heat input rate at each heat input/load

point.

2.1.4 Emergency Fuel

The designated representative of a unit that

is restricted by its Federal, State or local

permit to combusting a particular fuel only

during emergencies where the primary fuel is

not available may petition the Administrator

pursuant to the procedures in § 75.66 for an

exemption 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 petition a procedure for determining

the NOX emission rate for the unit when the

emergency fuel is combusted, and a

demonstration that the permit restricts use of

the fuel to emergencies only. The designated

representative shall also provide notice

under § 75.61(a) for each period when the

emergency fuel is combusted.

2.1.5 Tabulation of Results

Tabulate the results of each baseline

correlation test for each fuel or, as applicable,

combination of fuels, listing: time of test,

duration, operating loads, heat input rate

(mmBtu/hr), F-factors, excess oxygen levels,

and NOX concentrations (ppm) on a dry basis

(at actual excess oxygen level). Convert the

NOX concentrations (ppm) to NOX emission

rates (to the nearest 0.01 lb/mm/Btu)

according to Equation F–5 of appendix F of

this part or 19–3 in Method 19 of appendix

A of part 60 of this chapter, as appropriate.

Calculate the NOX emission rate in lb/mmBtu

for each sampling point and determine the

arithmetic average NOX emission rate of each

test run. Calculate the arithmetic average of

the boiler excess oxygen readings for each

test run. Record the arithmetic average of the

three test runs as the NOX emission rate and

the boiler excess oxygen level for the heat

input/load condition.

2.1.6 Plotting of Results

Plot the tabulated results as an x–y graph

for each fuel and (as applicable) combination

of fuels combusted according to the following

procedures.

2.1.6.1 Plot the heat input rate (mmBtu/

hr) as the independent (or x) variable and the

NOX emission rates (lb/mmBtu) as the

dependent (or y) variable for each load point.

Construct the graph by drawing straight line

segments between each load point. Draw a

horizontal line to the y-axis from the

minimum heat input (load) point.

2.1.6.2 Units that co-fire gas and oil may

be tested while firing gas only and oil only

instead of testing with each combination of

fuels. In this case, construct a graph for each

fuel.

2.2 * * *

2.3 Other Quality Assurance/Quality

Control-Related NOx Emission Rate Testing

When the operating levels of certain

parameters exceed the limits specified below,

or where the Administrator issues a notice

requesting retesting because the NOX

emission rate data availability for when the

unit operates within all quality assurance/

quality control parameters in this section

since the last test is less than 90.0 percent,

as calculated by the Administrator, complete

retesting of the NOX emission rate by the

earlier of: (1) 10 unit operating days (as

defined in section 2.1 of appendix B of this

part) or (2) 180 calendar days after exceeding

the limits or after the date of issuance of a

notice from the Administrator to re-verify the

unit’s NOX emission rate. Submit test results

in accordance with § 75.60(a) within 45 days

of completing the retesting.

2.3.1 For a stationary gas turbine, obtain

a list of at least four operating parameters

indicative of the turbine’s NOX formation

characteristics, and the recommended ranges

for these parameters at each tested load-heat

input point, from the gas turbine

manufacturer. If the gas turbine uses water or

steam injection for NOX control, the water/

fuel or steam/fuel ratio shall be one of these

parameters. During the NOx-heat input

correlation tests, record the average value of

each parameter for each load-heat input to

ensure that the parameters are within the

manufacturer’s recommended range.

Redetermine the NOX emission rate-heat

input correlation for each fuel and (optional)

combination of fuels after continuously

exceeding the manufacturer’s recommended

range of any of these parameters for one or

more successive operating periods totaling

more than 16 unit operating hours.

2.3.2 For a diesel or dual-fuel

reciprocating engine, obtain a list of at least

four operating parameters indicative of the

engine’s NOX formation characteristics, and

the recommended ranges for these

parameters at each tested load-heat input

point, from the engine manufacturer. Any

operating parameter critical for NOX control

shall be included. During the NOX heat-input

correlation tests, record the average value of

each parameter for each load-heat input to

ensure that the parameters are within the

manufacturer’s recommended range.

Redetermine the NOX emission rate-heat

input correlation for each fuel and (optional)

combination or fuels after continuously

exceeding the manufacturer’s recommended

range of any of these parameters for one or

more successive operating periods totaling

more than 16 unit operating hours.

2.3.3 For boilers using the procedures in

this appendix, the NOX emission rate heat

input correlation for each fuel and (optional)

combination of fuels shall be redetermined if

the excess oxygen level at any heat input rate

(or unit operating load) continuously exceeds

by more than 2 percentage points O2 from the

boiler excess oxygen level recorded at the

same operating heat input rate during the

previous NOX emission rate test for one or

more successive operating periods totaling

more than 16 unit operating hours.

2.4 Procedures for Determining Hourly NOX

Emission Rate

2.4.1 Record the time (hr. and min.), load

(MWge or steam load in 1000 lb/hr), fuel flow

rate and heat input rate (using the procedures

in section 2.1.3 of this appendix) for each
Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations 26553

hour during which the unit combusts fuel.

Calculate the total hourly heat input using

Equation E–1 of this appendix. Record the

heat input rate for each fuel to the nearest 0.1

mmBtu/hr. During partial unit operating

hours or during hours where more than one

fuel is combusted, heat input must be

represented as an hourly rate in mmBtu/hr,

as if the fuel were combusted for the entire

hour at that rate (and not as the actual, total

heat input during that partial hour or hour)

in order to ensure proper correlation with the

NOX emission rate graph.

2.4.2 Use the graph of the baseline

correlation results (appropriate for the fuel or

fuel combination) to determine the NOX

emissions rate (lb/mmBtu) corresponding to

the heat input rate (mmBtu/hr). Input this

correlation into the data acquisition and

handling system for the unit. Linearly

interpolate to 0.1 mmBtu/hr heat input rate

and 0.01 lb/mmBtu NOX.

2.4.3 To determine the NOX emission rate

for a unit co-firing fuels that has not been

tested for that combination of fuels,

interpolate between the NOX emission rate

for each fuel as follows. Determine the heat

input rate for the hour (in mmBtu/hr) for

each fuel and select the corresponding NOX

emission rate for each fuel on the appropriate

graph. (When a fuel is combusted for a partial

hour, determine the fuel usage time for each

fuel and determine the heat input rate from

each fuel as if that fuel were combusted at

that rate for the entire hour in order to select

the corresponding NOX emission rate.)

Calculate the total heat input to the unit in

mmBtu for the hour from all fuel combusted

using Equation E–1. Calculate a Btu-weighted

average of the emission rates for all fuels

using Equation E–2 of this appendix.

2.4.4 For each hour, record the critical

quality assurance parameters, as identified in

the monitoring plan, and as required by

section 2.3 of this appendix.

2.5 Missing Data Procedures

Provide substitute data for each unit

electing to use this alternative procedure

whenever a valid quality-assured hour of

NOX emission rate data has not been

obtained according to the procedures and

specifications of this appendix.

2.5.1 Use the procedures of this section

whenever any of the quality assurance/

quality control parameters exceeds the limits

in section 2.3 of this appendix or whenever

any of the quality assurance/quality control

parameters are not available.

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.

2.5.3 Maintain a record indicating which

data are substitute data and the reasons for

the failure to provide a valid quality-assured

hour of NOX emission rate data according to

the procedures and specifications of this

appendix.

2.5.4 Substitute missing data from a fuel

flowmeter using the procedures in section

2.4.3 of appendix D of this part.

2.5.5 Substitute missing data for gross

calorific value of fuel using the procedures in

section 2.4.2 of appendix D of this part.

* * * * *

67. Appendix E to part 75, section 3

is amended by revising section 3.1; by

removing section 3.2, redesignating

section 3.3 as 3.2, and revising new

section 3.2; by redesignating sections

3.4, 3.4.1, 3.4.2, 3.4.3 as 3.3, 3.3.1, 3.3.2,

and 3.3.3; and by removing sections

3.4.4 and 3.5 and adding section 3.3.4

to read as follows:

3. Calculations

3.1 Heat Input

Calculate the total heat input by summing

the product of heat input rate and fuel usage

time of each fuel, as in the following

equation:

HT = HIfuel1 t1 + HIfuel2 t2 + HIfuel3 t3 + . . .

+ HIlastfuel tlast (Eq. E–1)

Where:

HT =Total heat input of fuel flow or a

combination of fuel flows to a unit,

mmBtu;

HIfuel 1,2,3,...last= Heat input rate from each fuel

during fuel usage time, in mmBtu/hr, as

determined using equation F–19 or F–20

in section 5.5 of appendix F of this part,

mmBtu/hr;

t1,2,3....last= Fuel usage time for each fuel,

rounded up to the nearest .25 hours.

Note: For hours where a fuel is combusted

for only part of the hour, use the fuel flow

rate or mass flow rate during the fuel usage

time, instead of the total fuel flow during the

hour, when calculating heat input rate using

Equation F–19 or F–20.

3.2 F-factors

Determine the F-factors for each fuel or

combination of fuels to be combusted

according to section 3.3 of appendix F of this

part.

3.3 NOX Emission Rate

3.3.1 Conversion from Concentration to

Emission Rate [Amended]

Convert the NOX concentrations (ppm) and

O2 concentrations to NOX emission rates (to

the nearest 0.01 lb/mmBtu) according to the

appropriate one of the following equations:

F–5 in appendix F of this part for dry basis

concentration measurements, or 19–3 in

Method 19 of appendix A of part 60 of this

chapter for wet basis concentration

measurements.

3.3.2 Quarterly Average NOX Emission Rate

Report the quarterly average emission rate

(lb/mmBtu) as required in subpart G of this

part. Calculate the quarterly average NOX

emission rate according to Equation F–9 in

Appendix F of this part.

3.3.3 Annual Average NOX Emission Rate

Report the average emission rate (lb/

mmBtu) for the calendar year as required in

subpart G of this part. Calculate the average

NOX emission rate according to equation F–

10 in appendix F of this part.

3.3.4 Average NOX Emission Rate During

Co-firing of Fuels [Amended] (Eq. E–2)

Where:

Eh=NOX emission rate for the unit for the

hour, lb/mmBtu;

E

E HI t

H

h

f

all fuels

f f f

T

=

( ) ×

=

∑

1

Ef=NOX emission rate for the unit for a given

fuel at heat input rate HIf, lb/mmBtu;

HIf=Heat input rate for a given fuel during

the fuel usage time, as determined using

equation F–19 or F–20 in section 5.5 of

appendix F of this part, mmBtu/hr;

HT=Total heat input for all fuels for the hour

from Equation E–1;

tt=Fuel usage time for each fuel, rounded to

the nearest .25 hour.

Note: For hours where a fuel is combusted

for only part of the hour, use the fuel flow

rate or mass flow rate during the fuel usage

time, instead of the total fuel flow or mass

flow during the hour, when calculating heat

input rate using Equation F–19 or F–20.

* * * * *

68. Appendix E to part 75, section 4

is amended by revising the introductory

paragraph and section 4.1 to read as

follows:

4. Quality Assurance/Quality Control Plan

Include a section on the NOX emission rate

determination as part of the monitoring

quality assurance/quality control plan

required under § 75.21 and appendix B of

this part for each gas-fired peaking unit and

each oil-fired peaking unit. In this section

present information including, but not

limited to, the following: (1) a copy of all

data and results from the initial NOX

emission rate testing, including the values of

quality assurance parameters specified in

Section 2.3 of this appendix; (2) a copy of all

data and results from the most recent NOX

emission rate load correlation testing; (3) a

copy of the unit manufacturer’s

recommended range of quality assuranceand quality control-related operating

parameters.

4.1 Submit a copy of the unit

manufacturer’s recommended range of

operating parameter values, and the range of

operating parameter values recorded during

the previous NOX emission rate test that

determined the unit’s NOX emission rate,

along with the unit’s revised monitoring plan

submitted with the certification application.

* * * * *

Appendix F to Part 75—Conversion

Procedures

69. Appendix F to part 75, section 2

is amended by revising section 2.4 to

read as follows:

* * * * *

2. Procedures for SO2 Emissions

* * * * *

2.4 Round all SO2 mass emissions to the

number of decimal places identified in

§ 75.50(c) or § 75.54(c) of this part (in lb/hr).

* * * * *

70. Appendix F to part 75, section 3 is

amended by revising the equation in section

3.2, by adding a sentence to the end of 3.3.4.

and by revising sections 3.3.6.1, 3.3.6.2, and

3.4 to read as follows:
26554 Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations

3. Procedures for NOX Emission Rate

* * * * *

3.2 When the NOX continuous emission

monitoring system uses CO2 as the diluent,

use the following conversion procedure:

E K C F

CO

Eq F h c = − 1006

% 2

( . )

where:

K, E, Ch, Fc, and %CO2 are defined in section

3.3 of this appendix.

Where CO2 and NOX measurements are

performed on a different moisture basis,

use the equations in Method 19 in

Appendix A of part 60 of this chapter.

* * * * *

3.3.4 * * * A minimum concentration of

5.0 percent CO2 and a maximum

concentration of 14.0 percent O2 may be

substituted for measured diluent gas

concentration values during unit start-up.

3.3.5 * * *

3.3.6 * * *

3.3.6.1 H, C, S, N, and O are content by

weight of hydrogen, carbon, sulfur, nitrogen,

and oxygen (expressed as percent),

respectively, as determined on the same basis

as the gross calorific value (GCV) by ultimate

analysis of the fuel combusted using ASTM

D3176–89, ‘‘Standard Practice for Ultimate

Analysis of Coal and Coke’’ (solid fuels),

ASTM D5291–92, ‘‘Standard Test Methods

for Instrumental Determination of Carbon,

Hydrogen, and Nitrogen in Petroleum

Products and Lubricants’’ (liquid fuels) or

computed from results using ASTM D1945–

91, ‘‘Standard Test Method for Analysis of

Natural Gas by Gas Chromatography’’ or

ASTM D1946–90, ‘‘Standard Practice for

Analysis of Reformed Gas by Gas

Chromatography’’ (gaseous fuels) as

applicable. (These methods are incorporated

by reference under § 75.6 of this part.)

3.3.6.2 GCV is the gross calorific value

(Btu/lb) of the fuel combusted determined by

ASTM D2015–91, ‘‘Standard Test Method for

Gross Calorific Value of Coal and Coke by the

Adiabatic Bomb Calorimeter’’, ASTM D1989–

92 ‘‘Standard Test Method for Gross Calorific

Value of Coal and Coke by Microprocessor

Controlled Isoperibol Calorimeters,’’ or

ASTM D3286–91a ‘‘Standard Test Method for

Gross Calorific Value of Coal and Coke by the

Isoperibol Bomb Calorimeter’’ for solid and

liquid fuels, and ASTM D240–87

(Reapproved 1991) ‘‘Standard Test Method

for Heat of Combustion of Liquid

Hydrocarbon Fuels by Bomb Calorimeter’’, or

ASTM D2382–88 ‘‘Standard Test Method for

Heat of Combustion of Hydrocarbon Fuels by

Bomb Calorimeter (High-Precision Method)’’

for oil; and ASTM D3588–91 ‘‘Standard

Practice for Calculating Heat Value,

Compressibility Factor, and Relative Density

(Specific Gravity) of Gaseous Fuels,’’ ASTM

D4891–89 ‘‘Standard Test Method for

Heating Value of Gases in Natural Gas Range

by Stoichiometric Combustion,’’ GPA

Standard 2172 86 ‘‘Calculation of Gross

Heating Value, Relative Density and

Compressibility Factor for Natural Gas

Mixtures from Compositional Analysis,’’

GPA Standard 2261–90 ‘‘Analysis for Natural

Gas and Similar Gaseous Mixtures by Gas

Chromatography,’’ or ASTM D1826–88,

‘‘Standard Test Method for Calorific

(Heating) Value of Gases in Natural Gas

Range by Continuous Recording Calorimeter’’

for gaseous fuels, as applicable. (These

methods are incorporated by reference under

§ 75.6).

3.3.6.3 * * *

3.3.6.4 * * *

3.4 Use the following equations to

calculate the average NOX emission rate for

each calendar quarter (Eq. F–9) and the

average emission rate for the calendar year

(Eq. F–10) in lb/mmBtu.

E

E

n

Eq F q

i

i

n

= −

=

∑ ( . ) 9

1

where:

Eq=Quarterly average NOX emission rate, lb/

mmBtu.

Ei=Hourly average Nox emission rate, lb/

mmBtu.

n=Number of hourly rates during calendar

quarter.

E

E

m

Eq F a

i

i

n

= −

=

∑ ( . ) 10

1

where:

Ea=Average NOX emission rate for the

calendar year, lb/mmBtu.

Ei=Hourly average NOX emission rate, lb/

mmBtu.

m=Number of hours for which Ei is available

in the calendar year.

3.5 * * *

* * * * *

71. Appendix F to part 75, section 4

is amended by revising the introductory

paragraph, by revising the definition of

the variable ‘‘Ch’’ in Equation F–11 in

section 4.1, by revising sections 4.4.1

and 4.4.2. and by adding two sentences

to the beginning of sections 4.3.1, 4.3.2,

4.3.3, and 4.4.3 to read as follows:

4. Procedures for CO2 Mass Emissions

Use the following procedures to convert

continuous emission monitoring system

measurements of CO2 concentration

(percentage) and volumetric flow rate (scfh)

into CO2 mass emissions (in tons/day) when

the owner or operator uses a CO2 continuous

emission monitoring system (consisting of a

CO2 or O2 pollutant monitor) and a flow

monitoring system to monitor CO2 emissions

from an affected unit.

4.1 * * *

(Eq. F–11)

Where:

* * * * *

Ch=Hourly average CO2 concentration, stack

moisture basis, %CO2. A minimum

concentration of 5.0 percent CO2 may be

substituted for the measured

concentration during unit start-up.

* * * * *

4.2 * * *

4.3 * * *

4.3.1 On or after January 1, 1996, use the

missing data provisions of § 75.35 and do not

use the provisions of this section. Prior to

January 1, 1996, use either the provisions of

this section or the provisions

of

§ 75.35. * * *

4.3.2 On or after January 1, 1996, use the

missing data provisions of § 75.35 and do not

use the provisions of this section. Prior to

January 1, 1996, use either the provisions of

this section or the provisions

of

§ 75.35. * * *

4.3.3 On or after January 1, 1996, use the

missing data provisions of § 75.35 and do not

use the provisions of this section. Prior to

January 1, 1996, use either the provisions of

this section or the provisions

of

§ 75.35. * * *

4.4 For an affected unit, when the owner

or operator is continuously monitoring O2

concentration (in percent by volume) of flue

gases using an O2 monitor, use the equations

and procedures in section 4.4.1 through 4.4.3

of this appendix to determine hourly CO2

mass emissions (in tons).

4.4.1 Use appropriate F and Fc factors

from section 3.3.5 of this appendix in the

following equation to determine hourly

average CO2 concentration of flue gases (in

percent by volume).
Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations 26555

CO

F

F

O

Eq F a d

c d

2

2 100

20 9

20 9

= 14 − − .

. ( . )

(Eq. F–14a)

Where:

CO2d=Hourly average CO2 concentration,

percent by volume, dry basis.

F, Fc=F-factor or carbon-based Fc-factor from

section 3.3.5 of this appendix.

20.9=Percentage of O2 in ambient air.

O2d=Hourly average O2 concentration,

percent by volume, dry basis. A

maximum concentration of 14.0 percent

O2 may be substituted for the measured

concentration during unit start-up.

or

(Eq. F–14b)

Where:

CO2w=Hourly average CO2 concentration,

percent by volume, wet basis.

O2w=Hourly average O2 concentration,

percent by volume, wet basis. A

maximum concentration of 14.0 percent

O2 may be substituted for the measured

concentration during unit start-up.

F, Fc=F-factor or carbon-based Fc-factor from

section 3.3.5 of this appendix.

20.9=Percentage of O2 in ambient air.

%H2O=Moisture content of gas in the stack,

percent.

4.4.2 Determine CO2 mass emissions (in

tons) from hourly average CO2 concentration

(percent by volume) using Equation F–11 and

the procedure in section 4.1, where O2

measurements are on a wet basis, or using the

procedures in section 4.2 of this appendix,

where O2 measurements are on a dry basis.

4.4.3 On or after January 1, 1996, use the

missing data provisions of § 75.35 and do not

use the provisions of this section. Prior to

January 1, 1996, either use the provisions of

§ 75.35 or use the provisions

of this

section. * * *

* * * * *

72. Appendix F to part 75, section 5

is amended by revising section 5.1 and

by revising the definition of the variable

‘‘%CO2w’’ in Equation F–15 in section

5.2.1, by revising the definition of the

variable ‘‘%CO2d’’ in Equation F–16 in

section 5.2.2, by revising the definition

of the variable ‘‘%O2w’’ in Equation F–

17 in section 5.2.3, and by revising the

definition of the variable ‘‘%O2d’’ in

Equation F–18 in section 5.2.4, by

revising seciton 5.5.1, by adding two

sentences to the beginning of sections

5.3, and 5.4; by revising section 5.5; by

revising section 5.5.2; by revising

section 5.5.3.1; by revising section

5.5.3.2;by revising section 5.5.3.3; and

by adding new sections 5.5.4, 5.5.5,

5.5.6, and 5.5.7 to read as follows:

5. Procedures for Heat Input

* * * * *

5.1 Calculate and record heat input to an

affected unit on an hourly basis, except as

provided below. The owner or operator may

choose to use the provisions specified in

§ 75.16(e) or in section 2.1.2 of appendix D

of this part in conjunction with the

procedures provided below to apportion heat

input among each unit using the common

stack or common pipe header.

5.2 * * *

5.2.1 * * *

(Eq. F–15)

Where:

%CO2w=Hourly concentration of CO2,

percent CO2 wet basis. A minimum

concentration of 5.0 percent CO2 may be

substituted for the measured

concentration during unit startup.

5.2.2 * * *

(Eq. F–16)

Where:

%CO2d=Hourly concentration of CO2, percent

CO2 dry basis. A minimum concentration

of 5.0 percent CO2 may be substituted for

the measured concentration during unit

startup.

* * * * *

5.2.3 * * *

(Eq. F–17)

Where:

%O2w=Hourly concentration of O2, percent

O2 wet basis. A maximum concentration

of 14.0 percent O2 may be substituted for

the measured concentration during unit

startup.

* * * * *

5.2.4 * * *

(Eq. F–18)

Where:

%O2d=Hourly concentration of O2, percent

O2 dry basis. A maximum concentration

of 14.0 percent O2 may be substituted for

the measured concentration during unit

startup.

* * * * *

5.3 On or after January 1, 1996, use the

missing data provisions of § 75.36 and do not

use the provisions of this section. Prior to

January 1, 1996, use either the missing data

provisions of this section or the provisions of

§ 75.36. * * *

5.4 On or after January 1, 1996, use the

missing data provisions of § 75.36 and do not

use the provisions of this section. Prior to

January 1, 1996, use either the missing data

provisions of this section or the provisions of

§ 75.36. * * *

5.5 For a gas-fired or oil-fired unit that

does not have a flow monitor and is using the

procedures specified in appendix D to this

part to monitor SO2 emissions or for any

affected unit using a common stack for which

the owner or operator chooses to determine

heat input by fuel sampling and analysis, use

the following procedures to calculate hourly

heat input in mmBtu/hr.

5.5.1 When the unit is combusting oil,

use the following equation to calculate

hourly heat input.

(Eq. F–19)

HI M

GCV

Eq F o o

o = − 10

19 6 ( . )

Where:

HIo=Hourly heat input from oil, mmBtu/hr.

Mo=Mass of oil consumed per hour, as

determined using procedures in

appendix D of this part, in lb, tons, or

kg.

GCVo=Gross calorific value of oil, as

measured daily by ASTM D240–87

(Reapproved 1991), ASTM D2015–91, or

ASTM D2382–88, Btu/unit mass

(incorporated by reference under § 75.6

of this part).

106=Conversion of Btu to mmBtu.

When performing oil sampling and

analysis solely for the purpose of the missing

data procedures in § 75.36, oil samples for

measuring GCV may be taken weekly and the

procedures specified in appendix D of this

part for determining the mass of oil

consumed per hour are optional.

5.5.2 When the unit is combusting

gaseous fuels, use the following equation to

calculate heat input from gaseous fuels for

each hour.

(Eq. F–20)

HI

Q GCV

Eq F g

g g = × − 10 000

20 , ( . )

Where:

HIg=Hourly heat input from gaseous fuel,

mmBtu/hour.

Qg=Metered flow or amount of gaseous fuel

combusted during the hour, hundred

cubic feet.

GCVg=Gross calorific value of gaseous fuel,

as determined by sampling at least every

month the gaseous fuel is combusted, or

as verified by the contractual supplier at

least once every month the gaseous fuel

is combusted using ASTM D1826–88,

ASTM D3588–91, ASTM D4891–89, GPA

Standard 2172–86 ‘‘Calculation of Gross

Heating Value, Relative Density and

Compressibility Factor for Natural Gas

Mixtures from Compositional Analysis,’’

or GPA Standard 2261–90 ‘‘Analysis for

Natural Gas and Similar Gaseous

Mixtures by Gas Chromatography,’’ Btu/

cubic foot (incorporated by reference

under § 75.6 of this part).

10,000=Conversion factor, (Btu-100 scf)/

(mmBtu-scf).

5.5.3 * * *

5.5.3.1 Perform coal sampling daily

according to section 5.3.2.2 in Method 19 in

appendix A to part 60 of this chapter and use
26556 Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations

ASTM Method D2234–89, ‘‘Standard Test

Methods for Collection of a Gross Sample of

Coal,’’ (incorporated by reference under

§ 75.6) Type I, Conditions A, B, or C and

systematic spacing for sampling. (When

performing coal sampling solely for the

purposes of the missing data procedures in

§ 75.36, use of ASTM D2234–89 is optional,

and coal samples may be taken weekly.)

5.5.3.2 Use ASTM D2013–86, ‘‘Standard

Method of Preparing Coal Samples for

Analysis,’’ for preparation of a daily coal

sample and analyze each daily coal sample

for gross calorific value using ASTM D2015–

91, ‘‘Standard Test Method for Gross

Calorific Value of Coal and Coke by the

Adiabatic Bomb Calorimeter’’, ASTM 1989–

92 ‘‘Standard Test Method for Gross Calorific

Value of Coal and Coke by Microprocessor

Controlled Isoperibol Calorimeters,’’ or

ASTM 3286–91a ‘‘Standard Test Method for

Gross Calorific Value of Coal and Coke by the

Isoperibol Bomb Calorimeter.’’ (All ASTM

methods are incorporated by reference under

§ 75.6 of this part.)

On-line coal analysis may also be used if

the on-line analytical instrument has been

demonstrated to be equivalent to the

applicable ASTM methods under §§ 75.23

and 75.66.

5.5.3.3 Calculate the heat input from coal

using the following equation:

HI M

GCV

Eq F c c

c = − 500

( . ) 21

(Eq. F–21)

Where:

HIc=Daily heat input from coal, mmBtu/day.

Mc=Mass of coal consumed per day, as

measured and recorded in company

records, tons.

GCVc=Gross calorific value of coal sample, as

measured by ASTM D3176–89, D1989–

92, D3286–91a, or D2015–91, Btu/lb.

500=Conversion of Btu/lb to mmBtu/ton.

5.5.4 For units obtaining heat input

values daily instead of hourly, apportion the

daily heat input using the fraction of the

daily steam load or daily unit operating load

used each hour in order to obtain HIi for use

in the above equations. Alternatively, use the

hourly mass of coal consumed in equation F–

21.

5.5.5 If a daily fuel sampling value for

gross calorific value is not available,

substitute the maximum gross calorific value

measured from the previous 30 daily

samples. If a monthly fuel sampling value for

gross calorific value is not available,

substitute the maximum gross calorific value

measured from the previous 3 monthly

samples.

5.5.6 If a fuel flow value is not available,

use the fuel flowmeter missing data

procedures in section 2.4 of appendix D of

this part. If a daily coal consumption value

is not available, substitute the maximum fuel

feed rate during the previous thirty days

when the unit burned coal.

5.5.7 Results for samples must be

available no later than thirty calendar days

after the sample is composited or taken.

However, during an audit, the Administrator

may require that the results be available in

five business days, or sooner if practicable.

* * * * *

73. Appendix F to part 75, section 6 is

amended by revising the definitions for

Equation F–22 to read as follows:

6. Procedure for Converting Volumetric Flow

to STP

* * * * *

(Eq. F–22)

Where:

FSTP=Flue gas volumetric flow rate at

standard temperature and pressure, scfh.

FActual=Flue gas volumetric flow rate at actual

temperature and pressure, acfh.

TStd=Standard temperature=528 °R.

TStack=Flue gas temperature at flow monitor

location, °R, where °R=460+°F.

PStack=The absolute flue gas

pressure=barometric pressure at the flow

monitor location + flue gas static

pressure, inches of mercury.

PStd=Standard pressure=29.92 inches of

mercury.

74. Appendix F to part 75 is amended

by reserving section 7:

7. [Reserved]

* * * * *

Appendix G to Part 75—Determination

of CO2 Emissions

75. Appendix G to part 75, section 2

is amended by revising sections 2.1, 2.2

and 2.3 to read as follows:

* * * * *

2. Procedures for Estimating CO2 Emissions

From Combustion

* * * * *

2.1 Use the following equation to

calculate daily CO2 mass emissions (in tons/

day) from the combustion of fossil fuels.

Where fuel flow is measured in a common

pipe header (i.e., a pipe carrying fuel for

multiple units), the owner or operator may

use the procedures in section 2.1.2 of

appendix D of this part for combining or

apportioning emissions, except that the term

‘‘SO2 mass emissions’’ is replaced with the

term ‘‘CO2 mass emissions.’’

W

MW MW W

MW

CO Eq G

C O C

C

2

2

2 000 = 1 ( ) + ×

− , ( . )
Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations 26557

Where:

Wco2=CO2 emitted from combustion, tons/

day.

MWc=Molecular weight of carbon (12.0).

MWo2=Molecular weight of oxygen (32.0)

WC=Carbon burned, lb/day, determined

using fuel sampling and analysis and

fuel feed rates. Collect at least one fuel

sample during each week that the unit

combusts coal or oil, one sample per

each shipment for diesel fuel, and one

fuel sample each month the unit

combusts gaseous fuels. Collect coal

samples from a location in the fuel

handling system that provides a sample

representative of the fuel bunkered or

consumed during the week. Determine

the carbon content of each fuel sampling

using one of the following methods:

ASTM D3178–89 for coal; ASTM D5291–

92 ‘‘Standard Test Methods for

Instrumental Determination of Carbon,

Hydrogen, and Nitrogen in Petroleum

Products and Lubricants,’’ ultimate

analysis of oil, or computations based

upon ASTM D3238–90 and either ASTM

D2502–87 or ASTM D2503–82

(Reapproved 1987) for oil; and

computations based on ASTM D1945–91

or ASTM D1946–90 for gas. Use daily

fuel feed rates from company records for

all fuels and the carbon content of the

most recent fuel sample under this

section to determine tons of carbon per

day from combustion of each fuel. (All

ASTM methods are incorporated by

reference under § 75.6). Where more than

one fuel is combusted during a calendar

day, calculate total tons of carbon for the

day from all fuels.

2.2 For an affected coal-fired unit, the

estimate of daily CO2 mass emissions given

by Equation G–1 may be adjusted to account

for carbon retained in the ash using the

procedures in either section 2.2.1 through

2.2.3 or section 2.2.4 of this appendix.

* * * * *

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 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).

W

F H U MW

CO Eq G C f CO

2

2

2000 = 4  × × ×









 ( . ) −

(Eq.G–4)

Where:

WCO2=CO2 emitted from combustion, tons/

hr.

Fc=Carbon-based F-factor, 1,040 scf/mmBtu

for natural gas; 1,420 scf/mm/btu for

crude, residual, or distillate oil.

H = Hourly heat input in mmBtu, as

calculated using the procedures in

section 5 of appendix F of this part.

Uf=1/385 scf CO2/lb-mole at 14.7 psia and 68

°F.

* * * * *

76. Appendix G to part 75, section 3

is amended by revising the introductory

paragraph; by revising section 3.1.2

before the equation and the definition of

the variable ‘‘WS02’’; and by adding

Equation G–7 and definitions to section

3.1.2 to read as follows:

3. Procedures for Estimating CO2 Emissions

From Sorbent

When the affected unit has a wet flue gas

desulfurization system, is a fluidized bed

boiler, or uses other emission controls with

sorbent injection, use either a CO2

continuous emission monitoring system or an

O2 monitor and a flow monitor, or use the

procedures, methods, and equations in

sections 3.1 through 3.2 of this appendix to

determine daily CO2 mass emissions from the

sorbent (in tons).

3.1 * * *

3.1.1 * * *

3.1.2 In lieu of using Equation G–5, any

owner or operator who operates and

maintains a certified SO2-diluent continuous

emission monitoring system (consisting of an

SO2 pollutant concentration monitor and an

O2 or CO2 diluent gas monitor), for measuring

and recording SO2 emission rate (in lb/

mmBtu) at the outlet to the emission controls

and who uses the applicable procedures,

methods, and equations in § 75.15 of this part

to estimate the SO2 emissions removal

efficiency of the emission controls, may use

the following equations to estimate daily CO2

mass emissions from sorbent (in tons).

(Eq. G–6)

where:

* * * * *

WSO2=Sulfur dioxide removed, lb/day, as

calculated below using Eq. G–7.

* * * * *

and

W SO

R

R

SO o Eq G 2 2

100 = 7 − − %( % )

( . )

(Eq. G–7)

where:

WSO2=Weight of sulfur dioxide removed, lb/

day.

SO20=SO2 mass emissions monitored at the

outlet, lb/day, as calculated using the

equations and procedures in section 2 of

appendix F of this part.

%R=Overall percentage SO2 emissions

removal efficiency, calculated using

Equations 1 through 7 in § 75.15 using

daily instead of annual average emission

rates.

* * * * *

Appendix J to Part 75—Compliance

Dates for Revised Recordkeeping

Requirements and Missing Data

Procedures

77. Appendix J to part 75 is added to

read as follows:

1. Recordkeeping Requirements

The owner or operator shall meet the

recordkeeping requirements of subpart F of

this part by following either §§ 75.50, 75.51

and 75.52 or §§ 75.54, 75.55 and 75.56, from

July 17, 1995 through December 31, 1995. On

or after January 1, 1996, the owner or

operator shall meet the recordkeeping

requirements of subpart F of this part by
26558 Federal Register / Vol. 60, No. 95 / Wednesday, May 17, 1995 / Rules and Regulations

meeting the requirements of §§ 75.54, 75.55,

and 75.56.

2. Missing Data Substitution Procedures

The owner or operator shall meet the

missing data substitution requirements for

carbon dioxide (CO2) and heat input by

following either §§ 75.35 and 75.36 or

sections 4.3.1 through 4.3.3, section 4.4.3 and

sections 5.3 through 5.4 of appendix F of this

part from July 17, 1995 through December 31,

1995. The owner or operator shall meet the

missing data substitution requirements for

fuel flowmeters in appendix D of this part by

following either section 2.4.3.1 or sections

2.4.3.2 and 2.4.3.3 of appendix D of this part

from July 17, 1995 through December 31,

1995. On or after January 1, 1996, the owner

or operator shall meet the missing data

substitution requirements for CO2

concentration, that input and fuel flowmeters

by meeting the requirements of §§ 75.35 and

75.36 and sections 2.4.3.2 through 2.4.3.3 of

appendix D of this part.

[FR Doc. 95–11498 Filed 5–10–95; 3:40 pm]

BILLING CODE 6560–50–P