.—.

TITLE

35:

ENVIRONMENTAL

PROTECTION

SUBTITLE B:

AIR

POLLUTION

CHAPTER

POLLUTION

CONTROL BOARD

SUBCHAPTER

EMISSION

STANDARDS

AND LIMITATIONS

FOR

STATIONARY SOURCES

PART 225

CONTROL OF

EMISSIONS FROM LARGE COMBUSTION SOURCES

SUBPART A:

GENERAL PROVISIONS

SUBPART B:

CONTROL OF MERCURY

EMISSIONS

FROM COAL-FIRED ELECTRIC

GENERATING UNITS

Section

225.200

225.202

225.205

225.210

225.220

225.230

225.232

225.233

225.234

225.235

225.237

225.238

225.239

225.240

225.250

Monitoring

225.260

225.261

225.263

225.265

225.270

225.290

225.291

225.292

225.293

225.294

Emissions

225.295

225.296

NOx, S02,

225.297

225.298

225.299

Purpose

Measurement Methods

Applicability

Compliance Requirements

Clean Air Act Permit Program

(CAAPP)

Permit Requirements

Emission

Standards for EGU5 at Existing Sources

Averaging Demonstrations for Existing Sources

Multi-Pollutant Standard

(MPS)

Temporary Technology-Based Standard for EGUs at Existing Sources

Units Scheduled for Permanent Shut Down

Emission Standards for New Sources with EGUs

Temporary Technology-Based Standard for New Sources

with EGU5

Periodic Emissions Testing Alternative

Requirements

General Monitoring and

Reporting Requirements

Initial Certification and Recertification Procedures for Emissions

Out

of Control Periods

and

Data Availability for Emission Monitors

Additional Requirements to Provide Heat Input Data

Monitoring of Gross Electrical Output

Coal Analysis for Input Mercury Levels

Notifications

Recordkeeping and Reporting

Combined Pollutant Standard: Purpose

Applicability of the Combined Pollutant Standard

Combined Pollutant Standard: Notice of Intent

Combined Pollutant Standard: Control Technology Requirements and

Standards for Mercury

Combined Pollutant Standard: Emissions Standards for NOx and S02

Combined Pollutant Standard: Control Technology Requirements for

and PM Emissions

Combined Pollutant Standard:

Permanent

Shut-Downs

Combined Pollutant

Standard:

Requirements

for

NOx and

SO2

Allowances

Combined Pollutant Standard: Clean Air Act Requirements

RECEIVED

CLERKS

OFFICE

DEc

022098

Pojg

STATE

OFControl

ILLINOIS

Board

Section

225.100

225.120

225.130

225.140

225. 150

Severability

Abbreviations and Acronyms

Definitions

Incorporations by

Reference

Commence

Commercial Operation

SUBPART

CLEAN AIR ACT INTERSTATE

RULE

(CAIR)

S02

TRADING PROGRAM

Section

225.300

Purpose

225.305

Applicability

225.310

Compliance Requirements

225.315

Appeal Procedures

225.320

Permit

Requirements

225.325

Trading

Program

SUBPART D:

CAIR NOx ANNUAL

TRADING PROGRAM

Section

225.400

Purpose

225.405

Applicability

225.410

Compliance Requirements

225.415

Appeal

Procedures

225.420

Permit

Requirements

225.425

Annual

Trading Budget

225.430

Timing for

Annual Allocations

225.435

Methodology for

Calculating Annual

Allocations

225.440

Annual Allocations

225.445

New

Unit Set-Aside

(NUSA)

225.450

Monitoring,

Recordkeeping

and Reporting

Requirements for

Gross

Electrical

Output and

Useful Thermal Energy

225.455

Clean Air Set-Aside

(CASA)

225.460

Energy Efficiency

and

Conservation,

Renewable

Energy,

and Clean

Technology

Projects

225.465

Clean

Air

Set-Aside

(CASA)

Allowances

225.470

Clean

Air Set-Aside

(CASA)

Applications

225.475

Agency Action

on Clean

Air Set-Aside

(CASA)

Applications

225.480

Compliance

Supplement Pool

SUBPART E:

CAIR NOx

OZONE

SEASON TRADING

PROGRAM

Section

225.500

Purpose

225.505

Applicability

225.510

Compliance

Requirements

225.515

Appeal

Procedures

225.520

Permit

Requirements

225.525

Ozone

Season Trading Budget

225.530

Timing

for

Ozone

Season Allocations

225.535

Methodology

for

Calculating

Ozone

Season

Allocations

225.540

Ozone Season Allocations

225.545

New

Unit Set-Aside

(NUSA)

225.550

Monitoring,

Recordkeeping

and Reporting

Requirements

for Gross

Electrical Output

and

Useful Thermal Energy

225.555

Clean Air Set-Aside

(CASA)

225.560

Energy Efficiency

and Conservation,

Renewable

Energy,

and Clean

Technology

Projects

225.565

Clean

Air Set-Aside

(CASA)

Allowances

225.570

Clean Air Set-Aside

(CASA) Applications

225.575

Agency

Action on Clean

Air Set-Aside

(CASA)

Applications

SUBPART F:

COMBINED POLLUTANT

STANDARDS

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Section

225.130 Definitions

The following definitions apply for the purposes of this Part. Unless otherwise

defined in this Section or a different meaning for a term is clear

from its

context, the terms used in this Part have the meanings specified in 35

Ill.

Adm.

Code 211.

5/3

.105]

“Agency” means the Illinois Environmental Protection Agency.

[415

ILCS

“Averaging

demonstration”

means,

with regard

Subpart B of

this

Part,

demonstration of compliance that is based on the

combined performance of EGUs

two or more sources.

TBase

Emission Rate”

means, for a

group of EGUs

subject to

emission standards

for NOx and SO2 pursuant to Section

225.233,

the

average emission rate of NOx

S02 from the EGUs, in pounds per

million

Btu heat input,

for calendar years

2003

through 2005

(or, for

seasonal NOx,

the 2003 through 2005 ozone

seasons),

determined

from the

data collected

and quality assured

the USEPA, pursuant

the 40

CFR 72 and

federal Acid Rain and NOx Budget Trading Programs, for the

emissions and heat input of

that

group of EGUs.

year

(Source:

Amended

at 33

Ill. Reg.

effective-

“Board” means the Illinois Pollution Control Board.

[415

ILCS 5/3.130]

“Boiler’

means an enclosed fossil or other

fuel-fired combustion device used

produce

heat and

transfer heat to recirculating

water, steam, or other

medium.

TlBottomingcycle

cogeneration unit” means a

cogeneration unit in which the

energy input to

the

unit is first used to produce

useful thermal energy and

least some of the

reject heat from the useful thermal energy

application or

process is then used

for electricity production.

“CAIF. authorized

account representative’ means, for the purpose of

general

accounts, a

responsible natural person who is authorized, in

accordance with

CFR 96, subparts

BB, FF, BBB, FFF, BBBB, and FFFF to

transfer and otherwise

dispose

of CAIR NOx,

502, and NOx Ozone Season allowances, as applicable, held

in the CAIR NOx,

S02, and NOx Ozone Season general account, and for the purpose

CAIR NOx

compliance account,

CAIR S02 compliance account, or a

CAIR

NOx

Ozone Season compliance

account, the CAIR designated representative of the

source.

“CAIR designated

representative” means, for a CAIR NOx source, a CAIR

S02

source, and a

CAIR NOx Ozone Season source and each CAIR NOx unit,

CAIR S02

unit

and CAIR NOx

Ozone Season unit at the source, the natural person

who is

authorized by the

owners and operators of the source and all such

units

at the

source, in

accordance with 40 CFR 96, subparts BB,

FF, BBB, FFF, BBBB, and FFFF

applicable, to represent and legally

bind each owner and operator in matters

pertaining

the CAIR NOx Annual

Trading Program, CAIR S02 Trading Program, and

CAIR

NOx Ozone Season Trading

Program,

applicable. For any unit that is

subject to

one or more of the

following

programs: CAIR NOx Annual Trading

Program,

CAIR SO2 Trading Program, CAIR

NOx Ozone Season Trading Program, or the

federal Acid

Rain Program, the designated

representative for the unit must

the same

natural person for all programs

applicable

the unit.

“Coal”

means any solid fuel classified as

anthracite, bituminous, subbituminous,

or lignite by

the American Society for

Testing and Materials

(ASTM)

Standard

Specification for Classification of

Coals

Rank D388-77,

90,

91, 95, 98a, or

(Reapproved

2004)

“Coal-derived fuel” means any

fuel

(whether

in a solid, liquid or gaseous

state)

produced

by the mechanical,

thermal, or chemical processing of coal.

TTCoal_firedli

means:

For purposes of

Subparto5ubart B and F, or for purposes of allocating

allowances under

Sections 225.435, 225.445, 225.535, and 225.545, combusting any

amount of coal or

coal-derived fuel, alone or in combination with any

amount

any other fuel,

during

specified year;

Except as

provided above, combusting any amount of

coal

coal-derived fuel,

alone or

in combination with any amount of

any other fuel.

“Cogeneration unit” means, for

the purposes of Subparts

D, and E, a

stationary, fossil fuel-fired

boiler or

stationary, fossil fuel-fired

combustion turbine

which

both of

the

following conditions are true:

It uses equipment to

produce electricity and useful thermal energy for

industrial,

commercial, heating, or cooling purposes through the sequential

use

of energy; and

It produces either of the following during the 12-month period

beginning

on the

date

the unit first produces electricity and during any

subsequent calendar

year

after that in which the unit first produces electricity:

For a topping-cycle cogeneration unit, both of the

following:

Useful thermal energy not less than

five percent

total energy

output; and

Useful power that,

when

added to

one-half of useful thermal energy produced,

not less than 42.5

percent of total energy input, if useful thermal energy

produced is 15

percent or more of total energy output, or not less than 45

percent of

total energy input if useful thermal energy produced is less than 15

percent

of total energy output; or

For a

bottoming-cycle cogeneration unit, useful power not less than 45 percent

of total

energy input.

Combined

cycle system”

means

system comprised of one or more combustion

turbines, heat

recovery steam generators, and steam turbines configured to

improve

overall efficiency of electricity generation or steam production.

“Combustion

turbine” means:

An enclosed

device comprising

compressor,

combustor, and a turbine and in

which the flue gas

resulting from the combustion of fuel in the combustor

passes

through the

turbine, rotating the turbine; and

If the enclosed

device described in the above paragraph of this definition is

combined cycle, any associated duct burner, heat recovery steam generator and

steam turbine.

“Commence commercial operation” means, for the purposes of

SubpartcSuboart

B and

of this Part, with regard to an EGU that

serves

generator,

have

begun to

produce steam, gas, or other heated

medium

used to

generate

electricity for

sale

or use, including test

generation. Such

date

must remain the unit’s date

commencement of

operation even if

the

EGU is subsequently modified,

reconstructed

or repowered. For the purposes of Subparts

D and E, “commence

commercial

operation”

is as

defined in Section 225.150.

“Commence

construction” means, for the purposes of Section

225.460(f),

225.470,

225.560(f),

and

225.570, that the owner or owner’s designee has obtained all

necessary

preconstruction approvals (e.g., zoning) or permits and either has:

Begun, or caused to begin,

continuous program of actual on-site construction

of the source,

be completed within a reasonable time; or

Entered

into binding agreements or contractual obligations, which cannot be

cancelled or modified without substantial loss to the owner or operator, to

undertake a program of actual construction of the source to be

completed

within

reasonable time.

For purposes of this definition:

“Construction” shall be determined as any physical change or change in the

method of operation, including but not limited to fabrication, erection,

installation, demolition, or modification of projects eligible for CASA

allowances, as set forth in Sections 225.460 and 225.560.

“A

reasonable

time”

shall

determined considering

but not limited to the

following

factors:

the

nature

and

size of the project, the extent of design

engineering, the amount of off-site

preparation,

whether equipment can be

fabricated or can be purchased, when the project begins (considering both the

seasonal

nature of the construction activity and the existence of other projects

competing for construction labor at the same time, the place of the

environmental permit in the sequence of corporate and overall governmental

approval), and the nature of the project sponsor (e.g., private, public,

regulated)

“Commence operation”, for purposes of Subparts

ID and E, means:

To have begun any mechanical, chemical, or electronic process, including, for

the purpose of a unit, start-up of a unit’s combustion chamber, except as

provided in 40 CFR 96.105, 96.205, or 96.305, as incorporated

reference in

Section 225.140.

For a unit that undergoes a physical change

(other

than replacement of the unit

by a unit at the same

source)

after the date the unit commences operation as set

forth in the first paragraph of this definition, such date will remain the date

of commencement of operation of the unit, which will continue to be treated as

the same unit.

For a unit that is replaced by a unit at the same source (e.g., repowered),

after the date the unit commences operation as set

forth

in the first

paragraph

of this definition, such date

will remain

the

replaced unit’s

date

commencement

of operation, and the replacement unit will

treated

as a

separate

unit with

separate

date

for commencement of operation

as set

forth

this

definition

appropriate.

“Common stack” means

single flue through which emissions from two or more

units are exhausted.

“Compliance account” means:

For

the purposes of Subparts ID and E, a CAIR NOx Allowance Tracking System

account, established

USEPA for

CAIR NOx source or CAIR NOx Ozone Season

source pursuant

40 CFR

96,

subparts FF and FFFF in which any CAIR NOx

allowance or CAIR NOx Ozone

Season

allowance allocations for the CAIR NOx units

or CAIR NOx Ozone Season units

the source are initially recorded and in which

are held any CAIR NOx or CAIR NOx Ozone Season allowances available for

use

for

control period in order to meet the source’s CAIR NOx or CAIR NOx Ozone Season

emissions limitations in accordance with Sections 225.410 and 225.510, and 40

CFR 96.154 and 96.354,

incorporated

reference in Section 225.140. CAIR

NOx allowances may not be used for compliance with the CAIR NOx Ozone Season

Trading Program

and

CAIR NOx Ozone Season allowances may not be used for

compliance with the

CAIR

NOx Annual Trading Program;

For

the

purposes of Subpart

C, a “compliance account” means

CAIR S02

compliance

account,

established

by the USEPA for a CAIR S02 source pursuant

40 CFR 96, subpart

FFF, in

which any S02 units

the source are initially

recorded and in which are held any S02 allowances available

for use for a

control period in order to meet the source’s CAIR

S02 emissions limitations in

accordance with Section 225.310 and 40 CFR 96.254,

as incorporated by reference

in Section 225.140.

“Control period”

means:

For the CAlF. S02 and

NOx

Annual Trading Programs in

Subparts C and D, the period

beginning January 1 of a calendar year, except

provided

in Sections

225.310

Cd) (3)

and 225.410

Cd) (3),

and ending on December

31 of the same year,

inclusive; or

For the CAIR NOx

Ozone

Season Trading Program in Subpart E, the period

beginning

May 1 of a calendar year, except as provided in Section 225.510

Cd) (3),

and

ending on September 30 of the same year, inclusive.

“Designated

representative”

means, for the purposes of Subpart B

this

Part,

the

natural person as dcfincd in 40

CFR 60.4102, and is thc same natural

person

as the

person who is the

designated representative for the CAIR trading

and Acid

Rain

programs.

“Electric generating unit” or “EGU”

means a fossil fuel-fired stationary boiler,

combustion turbine or combined cycle

system that serves a generator that has

nameplate capacity greater than

25 MWe and produces electricity for sale.

“Flue” means

conduit or

duct

through which

gases or other matter is exhausted

the atmosphere.

“Fossil fuel” means natural

gas,

petroleum,

coal, or any form of solid, liquid,

gaseous

fuel derived from

such material.

“Fossil fuel-fired” means the

combusting of any amount of fossil fuel, alone

in combination with any other fuel

in any calendar year.

“Generator” means

device

that

produces

electricity.

“Gross electrical output” means the total electrical

output from an EGU before

making any deductions for energy output

used

in any

way related to the

production of energy. For an EGU generating only

electricity, the gross

electrical output is the output from the turbine/generator

set.

“Heat input” means, for the purposes of Subparts

and E,

a specified period

of time, the product

(in

mmBtu/hr) of the gross calorific value of the

fuel

(in

Btu/lb) divided

1,000,000

Btu/mmBtu and multiplied by the fuel feed rate

into

combustion device (in lb

of fuel/time), as measured, recorded and reported

USEPA

the CAIR designated representative

and determined by USEPA in

accordance with 40 CFR 96,

subpart

HH,

HHH, or HHHH, if applicable, and

excluding the heat derived from

preheated combustion air, recirculated flue

gases, or exhaust from other

sources.

“Higher heating value” or “HHV” means the total

heat liberated per mass of fuel

burned (Btu/lb), when fuel and

dry

air

standard

conditions undergo complete

combustion

and all resultant products are brought

their

standard states

standard conditions.

“Input

mercury’ means the mass of mercury

that

is contained

in the coal

combusted

within an EGU.

“Integrated gasification combined cycle” or “IGCC” means

coal-fired electric

utility

steam generating unit that burns

synthetic

gas

derived from

coal in a

combined-cycle gas turbine. No coal is directly burned in the unit during

operation.

“Long-term cold storage” means the complete shutdown of

unit intended

to last

for an extended period of time

(at

least two calendar years) where notice

for

long-term cold storage is provided under 40 CFR 75.61

(a) (7).

“Nameplate capacity” means, starting from the initial installation of

generator, the maximum electrical generating

output

(in

MWe)

that the generator

is capable of producing on a steady-state basis and during continuous operation

(when

not restricted by seasonal or other deratings)

of such installation

specified by the manufacturer of the generator or, starting from the completion

of any subsequent physical change in the generator resulting in an increase in

the maximum electrical generating output

(in

MWe)

that the generator is capable

of producing on a steady-state basis and during continuous operation

(when

not

restricted by seasonal or other deratings), such increased maximum amount

completion as specified by the person conducting the physical change.

“NIST traceable elemental mercury standards” means either:

-(-1)

Compressed gas cylinders having known concentrations of elemental mercury,

which have been prepared according to the “EPA Traceability Protocol for Assay

and Certification of

Gaseous

Calibration Standards”; or

-2)

Calibration gases having known concentrations of elemental mercury,

produced

a generator that fully meets the performance requirements of the

“EPA Traceability Protocol for Qualification and Certification of Elemental

Mercury

Gas

Generators.”

“NIST traceable source of oxidized mercury” means a generator that is capable of

providing

known concentrations

of vapor

phase

mercuric chloride (HgC12) , and

that fully meets the performance requirements of the “EPA Traceability Protocol

for Qualification and Certification of Oxidized Mercury

Gas

Generators.”

“Oil-fired unit” means

unit combusting fuel oil for more than 15.0 percent

the annual heat input in

specified year and not qualifying

coal-fired.

“Output-based emission standard” means, for the purposes of Subpart B of this

Part, a maximum allowable rate of emissions of mercury per unit of gross

electrical output from an EGU.

“Potential electrical output capacity” means

percent of

unit’s maximum

design heat input, expressed in mmBtu/hr divided

3.413 mmBtu/MWh, and

multiplied

8,760 hr/yr.

“Project sponsor” means

person or an entity, including

but

not limited

to the

owner or operator of an EGU or

not-for-profit group, that provides the

majority of funding for an energy efficiency and conservation, renewable

energy,

or clean technology project as listed in Sections 225.460 and 225.560, unless

another person or entity is designated by a written agreement as the project

sponsor for the purpose of applying

for NOx allowances or NOx Ozone Season

allowances from the CASA.

“Rated-energy efficiency”

means

the

percentage of thermal energy input that is

recovered as useable

energy in

the

form of gross electrical output, useful

thermal energy, or

both

that is used

for heating, cooling, industrial processes,

or other beneficial uses as

follows:

For electric

generators, rated-energy efficiency is calculated as one kilowatt

hour

(3,413 Btu)

electricity divided by the

unitTs

design heat rate using the

higher heating value

of the fuel, and expressed as a percentage.

For combined heat

and power projects, rated-energy efficiency is calculated

using the following

formula:

REE

((GO

+ UTE)/HT)

--1

100

Where:

REE

Rated-energy

efficiency, expressed

percentage.GO

Gross

electrical output of the

system expressed in Btu/hr.UTE

Useful thermal

output

from the system

that is

used

for heating, cooling, industrial processes

or other beneficial uses,

expressed in Btu/hr.HI

Heat input, based

upon the higher

heating value of fuel, in Btu/hr.

“Repowered” means, for the purposes

of an EGU, replacement of

coal-fired

boiler with one of the following

coal-fired technologies

the same source

the

coal-fired boiler:

Atmospheric

or pressurized fluidized bed combustion;

Integrated gasification combined cycle;

Magnetohydrodynamics;

Direct

and indirect coal-fired turbines;

Integrated

gasification fuel

cells; or

As determined by the USEPA

in consultation with the United States Department of

Energy,

derivative of one or

the technologies under this definition

and

any

other coal-fired technology

capable of controlling multiple combustion

emissions simultaneously with

improved boiler or generation efficiency and with

significantly greater waste reduction

relative

the performance of technology

in widespread

commercial use as of January 1, 2005.

“Rolling

12-month basis” means, for the purposes of

SubpartcSuboart

and

this Part,

determination made on a monthly basis

from the relevant data for

particular calendar month and the preceding

11 calendar months

(total

of 12

months of

data),

with

two

exceptions. For determinations involving one EGU,

calendar months in which

the EGU

does

not operate

(zero

EGU operating

hours)

must not be

included in the determination, and must be replaced by a preceding

month or months in which the EGU does operate, so that the

determination

still

based

on 12 months of data. For

determinations involving two or more

EGUs, calendar months in which none of the

EGUs covered

the determination

operates

(zero

EGU operating

hours)

must

not

included

the determination,

and must be replaced by

preceding months in which

least one of the EGU5

covered by the

determination

does operate, so

that the determination is still

based on 12 months

data.

“Total energy output”

means, with respect

to a

cogeneration unit, the sum of

useful power and

useful thermal energy produced

the cogeneration unit.

“Useful thermal energy”

means, for the purpose of

cogeneration unit,

the

thermal energy that is

made available

an industrial or commercial process,

excluding any heat

contained

condensate return or makeup water:

Used

heating application (e.g., space heating or

domestic

hot

water

heating); or

Used

space cooling application (e.g., thermal energy used by

an absorption

chiller)

(Source:

Amended at 33

Ill. Reg.

effective

Section 225.140

Incorporations

Reference

The following

materials are incorporated by reference. These incorporations do

not include

any later amendments or editions.

Appendix A, Subpart A, and Performance Specifications 2 and 3 of Appendix

B of 40 CFR 60,

60.17, 60.45a,

60.49a(1c) (1)

and (p)

, C0.SOa(h)

, and 60.4170

through 60.4176

(2005)

.60 (2005)

40 CFR 72.2

(2005)

eb)

CFR 75.4, 75.11 through 75.14, 75.16 through 75.19, 75.30, 75.34

through

75.37,

75.40 through 75.48,

75.53(e), 75.57(c) (2) (i)

through

75.57(c)(2)(vi), 75.60 through75.67, 75.71,

75.74(c),

Sections 2.1.1.5,

2.1.1.2, 7.7,

and 7.8 of Appendix A to 40 CFR 75, Appendix C to 40 CFR 75,

Section 3.3.5 of

Appendix F

40 CFR 75

(2006)

.40 CFR 75

(2006).

CFR 78

(2006)

e4)

40 CFR

96,

CAIR SO2Trading Program, subparts AAA (excluding 40 CFR 96.204

and

96.206), BBB, FFF, GGG, and HHH

(2006).

e1)

40 CFR 96, CAIR NOx Annual Trading Program, subparts

(excluding 40 CFR

96.104,

96.105(b) (2),

and

96.106),

BB, FF, GG, and

HH (2006).

40 CFR 96,

CAIR

NOx Ozone Season

Trading Program, subparts AA2A (excluding

40 CFR 96.304,

96.305(b)

(2),

and

96.306),

BBBB, FFFF,

GGGG,

and HHHH

(2006).

hgh)

ASTM. The following methods from the American Society for Testing and

Materials,

100

Barr Harbor Drive, P.O. Box C700, West Conshohocken PA 19428-

2959,

(610) 832-9585:

ASTM D388-77 (approved February 25,

1977),

D388-90 (approved March 30,

1990),

D388-91a (approved April 15,

1991),

D388-95 (approved January 15,

1995),

D388-98a (approved September 10,

1998)

, or D388-99 (approved September 10, 1999,

reapproved in

2004),

Classification of Coals by Rank.

ASTM D3l73-03, Standard Test Method for Moisture in the Analysis Sample of

Coal and Coke (Approved April 10,

2003)

ASTM D3684-0l,

Standard Test Method for Total Mercury in Coal by the

Oxygen Bomb

Combustion/Atomic Absorption Method (Approved October 10,

2001)

ASTM D4840-99,

Standard Guide for Sampling Chain-of-Custody Procedures

(Reapproved

2004)

ASTM D5865-04,

Standard Test Method for Gross Calorific Value of Coal and

Coke (Approved

April 1,

2004)

4&)

ASTM D64l4-01,

Standard Test Method for Total Mercury in Coal and Coal

Combustion Residues by

Acid Extraction or Wet Oxidation/Cold Vapor

Atomic

Absorption

(Approved October 10,

2001)

47j

ASTM

D6784-02, Standard Test Method for Elemental, Oxidized,

Particle-

Bound and Total

Mercury in Flue

Gas

Generated from Coal-Fired

Stationary

Sources

(Ontario

Hydro

Method)

(Approved April 10,

2002)

ASTM D6911-03, Standard Guide for Packaging and Shipping

Environmental

Samples

for Laboratory Analysis.

ASTM D7036-04, Standard Practice for Competence of

Air Emission Testing

Bodies.

-ihi) Federal Energy Management Program, M&V Guidelines:

Measurement and

Verification for

Federal Energy Projects, US Department of Energy,

Office of

Energy Efficiency

and Renewable Energy, Version 2.2, DOE/GO-102000-0960

(September

2000)

(Source:

Amended

at 33

Ill. Reg._______ ,

effective

SUBPART B:

CONTROL OF MERCURY EMISSIONS

FROM

COAL-FIRED ELECTRIC GENERATING UNITS

Section 225.202 Measurement

Methods

Measurement of

mercury must be according to the following:

Continuous

emission monitoring pursuant to Appendix B to this Part

alternative

emissions monitoring system, alternative reference method for

measuring

emissions, or other alternative to the emissions monitoring and

measurement

requirements of Sections 225.240 through 225.290, if such

alternative is

submitted

the Agency in writing and approved in writing by the

Manager

of the

Bureau of Air’s Compliance Section. 40 CFR 75

(2005)

ASTM

D3173-03, Standard Test Method for Moisture in the Analysis Sample of

Coal and Coke

(Approved April 10,

2003),

incorporated by reference in Section

225.140.

ASTM

D3684-01, Standard Test Method for Total Mercury in Coal by

the

Oxygen Bomb

Combustion/Atomic Absorption Method (Approved October 10,

2001),

incorporated by

reference in Section 225.140.

ASTM D5865-04,

Standard

Test

Method for

Gross

Calorific Value of Coal and

Coke (Approved April 1,

2004), incorporated

reference in Section 225.140.

ASTM

D6414-Ol, Standard Test Method

for Total

Mercury

in Coal

and

Coal

Combustion Residues by

Acid Extraction

or Wet Oxidation/Cold Vapor

Atomic

Absorption

(Approved

October

10,

2001),

incorporated by reference in Section

225.140.

ASTM

D6784-02, Standard Test Method

for

Elemental, Oxidized,

Particle-Bound and

Total Mercury

Flue

Gas Generated from

Coal-Fired

Stationary Sources

(Ontario

Hydro Method)

(Approved

April

10,

2002),

incorporated by

reference in Section 225.140.

Emissions testing pursuant

Appendix A of 40

CFR

60.

(Source:

Amended at 33 Ill. Reg.

effective

Section 225.210 Compliance Requirements

Permit Requirements.

The owner or operator of each source with one or more EGU5 subject to this

Subpart B at the source must apply for a CAAPP permit that addresses the

applicable requirements of this Subpart B.

Monitoring

and Testing

Requirements.

The owner or operator of each source and each EGU

the source must

comply

with either the monitoring requirements of Sections 225.240 through

225.290 of this Subpart B, the periodic emissions testing requirements of

Section 225.239 of this Subpart B, or an alternative emissions monitoring

system, alternative reference method for measuring emissions, or other

alternative

the

emissions monitoring and measurement requirements of Sections

225.240

through 225.290, if such alternative is submitted to the Agency in

writing and approved in writing by the Manager of the Bureau of Air’s Compliance

Section.

The compliance of each EGU with the mercury requirements of Sections

225.230 and 225.237 of this Subpart B must be determined by the emissions

measurements recorded and reported in accordance with either Sections 225.240

through

225.290 of this Subpart B, Section 225.239 of this Subpart B, or an

alternative

emissions monitoring system, alternative reference method for

measuring

emissions, or other alternative

the

emissions monitoring and

measurement

requirements of Sections 225.240 through 225.290, if such

alternative is submitted

the Agency in writing and approved in writing

by the

Manager

the Bureau of Air’s Compliance Section.

Mercury Emission Reduction Requirements

The owner or operator of any EGU subject to this Subpart B must comply with

applicable requirements for control of mercury emissions of Section 225.230 or

Section 225.237 of this

Subpart B.

Recordkeeping and Reporting Requirements

Unless

otherwise provided, the owner or operator of

source with one or more

EGUs at the source must keep on site

the source each of the documents listed

in subsections

(d) (1)

through

(d) (3)

of this Section for a period of five years

from the

date

the document is created. This period may

extended, in writing

the Agency, for cause, at any time prior

the end of five years.

All emissions monitoring information gathered in accordance with Sections

225.240 through 225.290 and all periodic emissions testing information gathered

in accordance with Section 225.239.

Copies

all reports, compliance certifications, and other submissions

and all records made or required or documents necessary

demonstrate

compliance

with

the requirements of this Subpart B.

Copies of

all documents used

complete

permit application and

any

other submission

under this Subpart

Liability.

The owner

or operator of each source with

one

more EGUs must

meet

the

requirements of this Subpart B.

Any provision of this Subpart B that applies to a source must also apply

the

owner and operator of such source and to the owner or operator of each

EGU

the source.

Any provision of this Subpart B that applies to an EGU must also

apply

the owner or operator of such EGU.

Effect on Other

Authorities.

No provision of this Subpart B may be

construed as exempting or excluding the owner or operator of a source or EGU

from compliance with any other provision of an approved State Implementation

Plan,

permit, the Act, or the CAA.

(Source:

Amended at 33 Ill. Reg.

effective

Section 225.220 Clean Air Act Permit Program

(CAAPP)

Permit Requirements

Application Requirements.

Each source

with

one or more EGU5

subject to

the requirements

of this

Subpart B is

required

submit

CAAPP permit application

that addresses all

applicable requirements of this Subpart B, applicable

each EGU

the source.

For any EGU that commenced commercial operation:

on or before December 31, 2008, the owner or operator of such EGU5 must

submit an initial permit application or application for CAAPP permit

modification that meets the requirements of this Section on or before December

31, 2008.

after December 31, 2008, the owner or operator of any such EGU must submit

an initial CAAPP permit application or application for CAAPP modification that

meets the requirements of this Section not later than 180 days before initial

startup of the EGU, unless the construction permit issued for the EGU addresses

the

requirements of this Subpart B.

Contents of Permit Applications.

In addition to

other

information required for a complete application for CAAPP

permit or CAAPP permit modification, the application must include the following

information:

The ORIS

(Office

of Regulatory Information Systems) or facility code

assigned to the

source

the

U.S.

Department of Energy, Energy Information

Administration, if applicable.

Identification of each EGU at the source.

The intended approach to the monitoring requirements of Sections 225.240

through 225.290 of this Subpart B, or, in the alternative, the applicant may

include its intended approach to the testing requirement of Section 225.239 of

this Subpart B.

The intended approach to the mercury emission reduction requirements of

Section 225.230 or 225.237 of this Subpart B, as applicable.

Permit Contents.

Each CAAPP permit issued by the Agency for a source with one or more EGU5

subject to the requirements of this Subpart B must contain federally enforceable

conditions addressing all applicable requirements of this Subpart B, which

conditions must be a complete and segregable portion of the

sourceTs

entire

CAAPP

permit.

In addition

conditions related to the applicable requirements of this

Subpart B, each such CAAPP permit must also contain the information specified

under subsection

(b)

of this Section.

(Source:

Amended at 33 Ill. Reg.

effective

Section 225.230 Emission Standards for

EGUs

Existing

Sources

Emission Standards.

Except as

provided in Sections

225.230(b)

and

(d),

225.232 through

225.234,

225.239,

and 225.291 through 225.299 of this Subpart B, beginning

Ecginning

July 1, 2009, the owner or operator of a source with one or more EGU5

subject to

this Subpart B that commenced commercial operation on or before

December 31, 2008,

must

comply with one of the following standards for each

EGU

on a rolling

12-month basis:

An emission standard of 0.0080 lb

mercury/GWh gross

electrical output; or

minimum 90-percent reduction of input mercury.

For

an EGU

complying with subsection

(a) (1) (A)

of this Section, the

actual

mercury emission rate of the EGU for each 12-month rolling period,

monitored

in accordance with this Subpart B and calculated as follows, must not exceed the

applicable emission standard:

Where:

ER = Actual mercury emissions rate of the EGU for the particular 12-month

rolling period, expressed in lb/GWh.Ei = Actual mercury emissions of the EGU,

in lbs, in an individual month in the 12-month rolling period,

determined in

accordance with the emissions

monitoring

provisions of this Subpart B.Oi =

Gross electrical output of the EGU,

in GWh,

in an individual month in the 12-

month rolling period, as determined in accordance with Section 225.263 of this

Subpart B.

For an EGU complying with subsection

(a) (1) (B)

of this Section, the actual

control

efficiency for mercury emissions achieved

the EGU for each 12-month

rolling period, as monitored in accordance with this Subpart B and calculated

follows,

must

meet or exceed the applicable efficiency requirement:

Where:

Actual control efficiency for mercury emissions of the EGU for

the

particular 12-month rolling period, expressed

as a

percent.E± =

Actual

mercury

emissions of the EGU, in lbs, in an individual month in the 12-month rolling

period,

determined in accordance with the emissions monitoring provisions of

this

Subpart B.Ii =

Amount of mercury in the fuel fired in the EGU, in

lbs,

in an individual month in the 12-month rolling period,

determined in

accordance with Section 225.265 of this Subpart B.

Alternative Emission Standards for Single EGU5.

As an

alternative

compliance with

the emission standards in subsection

(a)

of this Section, the

owner

operator

of the EGU may comply with the

emission standards of this Subpart

by demonstrating that the actual emissions

of mercury from the EGU are less

than

the allowable emissions of mercury from

the EGU on a rolling 12-month basis.

For the purpose of demonstrating compliance with the alternative emission

standards of this subsection

(b),

for each rolling 12-month period, the actual

emissions of mercury from the EGU, as monitored in accordance with this Subpart

B, must not exceed the allowable emissions of mercury from the EGU, as further

provided by the following formulas:

Where:

E12 = Actual mercury emissions of the EGU for the particular 12-month

rolling period.A12 = Allowable mercury emissions of the EGU for the particular

12-month rolling period.Ei = Actual mercury emissions of the EGU in an

individual month in the 12-month rolling period.Ai = Allowable mercury emissions

of the EGU in an individual month in the 12-month rolling period, based on

either the input mercury to the unit (Alnput

or the electrical output from

the EGU (AOutput

i),

as selected by the owner or operator of the EGU for that

given month.Alnput i = Allowable mercury emissions of the EGU in an individual

month based on the input mercury to the EGU, calculated as 10.0 percent

(or

0.100)

the input mercury

to the EGU.AOutput i = Allowable mercury emissions

of the EGU in

particular month

based

the electrical output from the EGU,

calculated

the product of the output

based mercury limit, i.e., 0.0080

lb/GWh, and the electrical

output

from the

EGU, in GWh.

If the owner or operator of an EGU does not conduct the necessary

sampling, analysis, and recordkeeping, in accordance with Section 225.265 of

this Subpart B, to determine the mercury input

the

EGU, the allowable

emissions of the EGU must be calculated

based

on the electrical

output of the

EGU.

If two or more EGU5 are served

common

ztack(z)stacks

and the owner

operator conducts monitoring for mercury emissions in the common

ctack(c)

stacks,

as provided for by Sections 1.14 through 1.18 of Appendix B

this Part, 40 CFR

75, Subpart I,such that the mercury emissions of each EGU are not determined

separately, compliance of the EGUs with the applicable emission standards of

this Subpart B must be

determined

as if the EGUs were a single EGU.

Alternative Emission Standards

for Multiple EGUs.

an alternative

compliance

with the emission standards of

subsection

(a)

of this Section, the owner

or operator of a source with multiple

EGUs may comply

with the emission

standards of this Subpart B by demonstrating

that the actual

emissions of mercury

from all EGUs at the source are less than

the allowable

emissions of mercury

from all EGUs at the source on a rolling 12-

month basis.

For the purposes of the alternative emission standard of subsection

(d)

(1)

of this Section, for each rolling 12-month period, the actual emissions of

mercury from all the EGUs at the source, as monitored in accordance with this

Subpart B, must not exceed the sum of the allowable emissions of mercury from

all the EGU5 at the source, as further provided by the following formulas:

Where:

ES = Sum of the actual mercury emissions of the EGU5 at the source.AS = Sum

the allowable mercury emissions of the EGUs at the source.Ei = Actual mercury

emissions of an individual EGU at the source, as determined in accordance with

subsection

(b) (2)

of this Section.Ai = Allowable mercury emissions of an

individual EGU at the source, as determined in accordance with subsection

(b) (2)

of this Section. n = Number of EGU5 covered

the demonstration.

If an owner or operator of a source with two or more EGU5 that is relying

on this subsection

(d)

to demonstrate compliance fails

meet the requirements

of this subsection

Cd)

in a given 12-month rolling period, all EGU5

such

source covered by the compliance demonstration are considered

out

of compliance

with the applicable emission standards of this Subpart B for the entire last

month of that period.

(Source:

Amended

at 33 Ill. Reg._______

Section 225.233 Multi-Pollutant Standards

(MPS)

General.

As an

alternative

compliance with

the

emissions standards of Section

225.230(a),

the

owner of eligible EGUs may elect for those EGUs

demonstrate

compliance

pursuant to this Section, which establishes control requirements and

standards for

emissions of NOx and S02,

well

for emissions of mercury.

For the

purpose of this Section, the following requirements apply:

An eligible

EGU is an EGU that is located in Illinois and which commenced

commercial

operation on or before December 31, 2004; and

Ownership of an eligible EGU is determined

based

on direct ownership, by

the holding of a

majority interest in a company that owns the EGU or EGU5, or by

the common

ownership of the company that owns the EGU, whether through a parent-

subsidiary

relationship,

as a

sister corporation, or

an affiliated

corporation with

the same parent corporation, provided that the owner has the

right or authority to

submit

CA7PP application on behalf of the EGU.

The owner

of one or more EGUs electing

demonstrate compliance with

this

Subpart B pursuant

this Section must submit an application for a CAAPP

permit

modification to the Agency, as provided in Section 225.220, that includes

the

information specified in subsection

(b)

of this Section and which clearly

states

the owners election to demonstrate compliance pursuant to this Section

225.233.

If the owner of one or more EGU5 elects to demonstrate compliance with

this Subpart pursuant to this Section, then all EGU5 it owns in

Illinois

as of

July 1, 2006, as defined in subsection

(a) (2)

(B) of this Section, must

thereafter subject to the

standards and control requirements of this Section,

except as provided in

subsection

(a) (3)

(B) . Such EGUs must

referred

to as a

Multi-Pollutant Standard

(MPS)

Group.

Notwithstanding the foregoing, the owner may exclude

from

MPS Group

any

EGU scheduled for permanent shutdown that the owner so designates

its

CAAPP

application required to be submitted pursuant to

subsection

(a) (3)

of this

Section, with compliance for such units to be

achieved

means of Section

225.235.

When an

EGU is

subject to

the requirements of this Section, the

requirements

apply

all owners or operators of the EGU, and to the designated

representative for the

EGU.

Notice of Intent.

The

owner of one or more EGUs that intends to comply with this Subpart B by

means

of this Section must notify the Agency of its intention by December 31,

2007.

The following information must accompany the notification:

The identification of each EGU that will be complying with this Subpart B

means of the multi-pollutant standards contained in this Section, with

evidence that the owner has identified all EGU5 that it owned in Illinois as of

July 1, 2006 and which commenced commercial

operation

on or before

December

31,

2004;

If an EGU identified in subsection

(b) (1)

of this Section is also owned or

operated by a

person different than the owner submitting the notice of intent,

demonstration that the submitter has the right

commit the EGU or

authorization from

the responsible official for the EGU accepting the

application;

The Base

Emission

Rates

for the EGU5, with copies of supporting data and

calculations;

A summary of the current control

devices

installed and

operating on

each

EGU and identification of the additional control devices that will

likely

needed for the each EGU to comply with emission control

requirements of this

Section, including identification of each EGU in the MPS group

that will

addressed by subsection

Cc) (1) (B)

of this Section,

with information showing that

the eligibility

criteria

for

this subsection

(b)

are

satisfied;

and

Identification of each EGU that is scheduled for permanent shut down,

provided by Section

225.235, which will not

part of the MPS Group and which

will not be

demonstrating compliance with this Subpart B pursuant

this

Section.

Control

Technology Requirements for Emissions of Mercury.

Requirements for EGUs in an MPS Group.

For each EGU

in an MPS Group other than an EGU that is addressed by

subsection

(3)

of this Section for the period beginning July 1, 2009

(or

December 31, 2009

for an EGU for which an S02 scrubber or fabric filter is being

installed to be

in operation

December 31,

2009),

and ending on December 31,

2014

(or

such earlier

date

that the EGU is subject

the mercury emission

standard in

subsection

(d) (1)

of this

Section),

the owner or operator of the EGU

must install, to

the extent not already installed, and properly operate and

maintain one

of the following emission control devices:

A Halogenated

Activated Carbon Injection System, complying with the

sorbent

injection requirements of subsection

of this Section, except as

may be

otherwise provided

subsection

of this Section, and followed by

Cold-Side Electrostatic Precipitator or Fabric Filter; or

ii)

If the boiler fires bituminous coal, a Selective Catalytic Reduction

(SCR)

System and an S02 Scrubber.

An owner of an EGU in an MPS Group has

two options under this subsection

(c)

. For an MPS Group that

contains

EGU5

smaller than

gross MW in capacity,

the owner may designate any

such EGU5

to be

not

subject to

subsection

of this Section. Or, for an

MPS Group that contains EGUs with gross MW capacity

of less than 115

MW,

the

owner may designate any such EGUs

to be

not subject

subsection

Cc) (1) (A)

of this

Section, provided that the aggregate gross MW

capacity of the designated

EGUs

does

not exceed 4% of the total gross MW

capacity of

the MPS

Group.

For any EGU subject

one of these two options,

unless

the EGU

subject to

the emission standards in subsection

(d) (2)

of this

Section,

beginning on January 1, 2013, and continuing until such date that the

owner

or operator of the EGU commits to comply with the mercury emission

standard in subsection

Cd)

(2)

of this Section, the owner or operator of the EGU

must

install and properly operate and maintain a Halogenated Activated Carbon

Injection System that complies with the sorbent injection requirements of

subsection

Cc) (2)

of this Section, except as may be otherwise provided by

subsection

Cc) (4)

of this Section, and followed by either a Cold-Side

Electrostatic Precipitator or

Fabric Filter.

The use of a properly

installed,

operated, and maintained Halogenated Activated Carbon Injection

System

that

meets the sorbent

injection requirements of subsection

Cc) (2)

of this Section is

defined as the

Tprincipal

control technique.”

For each EGU

for which injection of halogenated activated carbon is

required by

subsection

of this Section, the owner or operator of the EGU

must

inject halogenated activated carbon in an optimum manner, which, except as

provided in

subsection

of this Section, is defined as all of the

following:

The

use

of an injection system designed for

effective absorption of

mercury, considering the configuration of the EGU and its

ductwork;

The injection of halogenated activated carbon

manufactured

Aistom,

Norit, or

Sorbent

Technologies, or Calgon T

CarbonsFLUEPAC

MC Plus, or the

injection of any

other halogenated activated carbon or sorbent that

the

owner or

operator of the

EGU has demonstrated to have similar or better

effectiveness

for

control of

mercury emissions; and

The

injection of sorbent at the following minimum rates, as

applicable:

For an EGU

firing subbituminous coal, 5.0 lbs per million

actual

cubic

feet or, for

any cyclone-fired EGU that will install a scrubber and

baghouse

December

31,

2012, and which already meets an emission rate

of 0.020

mercury/GWh

gross electrical output or at least 75 percent

reduction of input

mercury,

2.5 lbs per million actual cubic feet;

ii)

For an EGU firing bituminous coal,

10.0 lbs per million actual cubic feet—

e for any cyclone-fired EGU that

will install

scrubber and baghouse by

December 31, 2012, and which

already meets an emission rate of 0.020 lb

mercury/GWh gross electrical output or at

least 75 percent reduction of input

mercury,

5.0

lbs per million

actual cubic

feet;

iii)

For an EGU firing a

blend of subbituminous and bituminous coal, a rate

that is the weighted average

of the above rates, based on the blend of coal

being

fired; or

iv)

A rate or

rates set lower by the Agency, in writing, than

the rate

specified in

any of subsections

, or

(c)

(2)

of this Section

unit-specific basis, provided that the

owner

or operator of

the EGU has

demonstrated that such rate or rates are needed so

that carbon

injection

will not increase particulate matter emissions

opacity

so as to

threaten noncompliance with applicable requirements for

particulate matter

opacity.

For the purposes of subsection

Cc) (2) (C)

this Section, the flue

gas

flow rate must be determined for the point

of sorbent injection; provided that

this flow rate may be assumed to be

identical

to the

stack flow rate if the

gas

temperatures at the point of injection and

the stack are normally within lOOo—

IF,

or the flue gas flow rate may

otherwise

calculated from the stack flow

rate, corrected for the

difference in

gas

temperatures.

The owner or operator

of an EGU that seeks

operate an EGU with an

activated carbon injection rate or

rates that are

set

on a unit-specific basis

pursuant to

subsection

Cc)

(2)

of this Section must submit an application

to the

Agency proposing such rate or rates, and must meet the requirements of

subsections

Cc)

(3) (A)

and

of this Section, subject to the

limitations

of subsections

and

of this Section:

The

application must

submitted as an application for a new or

revised

federally

enforceable operating permit for the EGU, and it must include a

summary of relevant

mercury emission

data

for the EGU, the unit-specific

injection rate or rates

that are proposed, and detailed information to support

the proposed

injection rate or rates; and

This

application must

submitted no later than the date that activated

carbon must first be

injected. For example, the owner or operator of an EGU

that must inject

activated carbon pursuant

subsection

of this

subsection must apply

for unit-specific injection rate or rates by July 1, 2009.

Thereafter, the owner

or operator of the EGU may supplement its application; and

Any decision of

the Agency denying a permit or granting a permit with

conditions that set a

lower injection rate or rates may be appealed to the Board

pursuant to

Section

of the Act; and

The

owner or operator of an EGU may operate at the injection rate or rates

proposed in its

application until a final decision is made on the application,

including a

final decision on any appeal to the Board.

During

any evaluation of the effectiveness of a listed sorbent,

alternative sorbent, or other technique to control mercury

emissions, the owner

operator of an EGU need not comply with the

requirements of subsection

Cc) (2)

of this

Section for any system needed to carry out

the evaluation,

further

provided as

follows:

The

owner or operator of the EGU must conduct the

evaluation in accordance

with a

formal evaluation program submitted to the Agency at

least

30 days

prior

commencement of the evaluation;

The

duration and scope of the

evaluation may not exceed the duration and

scope

reasonably needed to complete the

desired evaluation of the alternative

control technique, as initially

addressed

the owner or operator in a support

document submitted with the

evaluation program;

The owner or operator

the

EGU

must

submit

report to the Agency no

later than 30 days after the conclusion

of the evaluation that describes the

evaluation conducted and

which provides the results of the evaluation; and

If the evaluation of

the alternative control technique shows less

effective control of mercury

emissions from the EGU than was achieved with the

principal control technique, the

owner

operator of the EGU must resume use of

the

principal control

technique. If the evaluation of the alternative control

technique shows

comparable effectiveness

the principal control technique, the

owner or

operator of the EGU may either continue to use the alternative control

technique

manner that is at least as effective as the principal control

technique,

or it may resume use of the principal control technique.

If the

evaluation of the alternative control technique shows

more effective control of

mercury emissions than the control technique, the

owner or operator of the EGU

must

continue to use the alternative control

technique in

manner that is more

effective than the principal control technique, so

long

it continues

to be

subject to this subsection

(c)

addition

to complying with

the applicable

recordkeeping and

monitoring

requirements in

Sections 225.240

through 225.290,

the owner or

operator

of an

EGU that elects

comply

with

this

Subpart B by

means of this

Section

must also

comply with

the

following

additional requirements:

For the

first 36 months

that

injection of sorbent

is required,

must

maintain

records

of the usage

sorbent, the

exhaust gas flow

rate from the

EGU,

and

the sorbent feed

rate, in pounds

per million actual

cubic feet of

exhaust gas

at the

injection

point, on

a weekly average;

After the

first 36 months

that injection of

sorbent is

required,

it must

monitor activated

sorbent

feed

rate to the EGU,

flue gas

temperature

at the

point of

sorbent

injection,

and exhaust gas

flow

rate from

the

EGU,

automatically

recording

this data and the

sorbent carbon

feed rate,

pounds

per

million

actual

cubic feet

of exhaust

gas at the

injection point,

hourly average;

and

a blend

bituminous

and subbituminous

coal

is fired in the

EGU, it

must

keep records

of the amount

of each

type of

coal

burned and the

required

injection rate

for injection

of activated

carbon,

weekly basis.

As an

alternative

the

CEMS monitoring,

recordkeeping,

and reporting

requirements

in Sections

225.240 through

225.290, the

owner or operator

of an

EGU

may

elect

comply with

the

emissions

testing,

monitoring, recordkeeping,

and

reporting

requirements in

Section

225.239(c),

(d), Ce),

Cf) Cl)

and

C2),

Ch) C2)

, Ci) C3)

and

C4)

, and

Cj)

Cl).

3&i)

In addition

to complying with

the applicable reporting

requirements

Sections 225.240

through 225.290,

the owner or operator

of an EGU

that elects

comply

with

this Subpart B

means of this Section

must also submit

quarterly

reports

for the recordkeeping

and monitoring

conducted pursuant

to subsection

Cc) CS)

this Section.

Emission

Standards for

Mercury.

For

each EGU in an

MPS

Group that is

not addressed by

subsection

Cc)

Cl) CB)

of this

Section,

beginning

January 1, 2015

Cor

such earlier

date

when

the

owner

operator of

the EGU notifies

the

Agency that it

will comply

with these

standards)

and

continuing

thereafter,

the

owner or operator

of the EGU

must

comply

with one of the

following

standards

on a rolling

12-month basis:

An emission

standard of

0.0080

lb mercury/GWh

gross electrical

output;

minimum 90-percent

reduction

input

mercury.

For each EGU

in an

MPS

Group

that has been addressed

under subsection

Cc)

Cl) CB)

of this

Section, beginning

on the date

when the owner or

operator

the

EGU notifies

the Agency

that it will comply

with these standards

and

continuing

thereafter, the

owner or operator

of the EGU must

comply

with one

the

following

standards

on a rolling 12-month

basis:

An emission

standard of 0.0080

lb mercury/GWh

gross

electrical

output; or

minimum

90-percent

reduction of input

mercury.

Compliance

with the mercury

emission

standard or

reduction requirement of

this subsection

(d)

must be calculated in accordance with

Section

225.230(a)

(d).

Until June

30, 2012,

an alternative to

demonstrating compliance with

the

emissions standards in this

subsection

(d),

the

owner or operator of an EGU

may elect

comply with the

emissions testing requirements in Section

225.239(c), Cd), Ce), (f) (1)

and

(2), (h) (2),

Ci)

(3)

and

(4),

and

Ci)

(1)

of this

Subpart.

Emission Standards for

NOx and

S02.

NOx Emission Standards.

Beginning in calendar year 2012 and continuing in

each calendar

thereafter,

for the EGU5 in each MPS Group, the owner and

operator of the EGU5

must

comply with an overall NOx annual emission rate of

no more than 0.11

lb/million Btu

or an emission rate equivalent to 52

percent of the Base Annual

Rate of NOx

emissions, whichever is more stringent.

Beginning in the 2012 ozone

season

and

continuing in each ozone season

thereafter, for the EGUs in each MPS Group, the

owner and operator of the EGU5

must

comply with an overall NOx

seasonal emission rate of no more than 0.11

lb/million Btu or an emission rate

equivalent

to 80

percent of the Base Seasonal

Rate

of NOx emissions,

whichever is more stringent.

S02 Emission

Standards.

Beginning in calendar

year 2013 and continuing in calendar year 2014, for

the

EGU5 in each MPS Group,

the owner and operator of the EGUs must comply with

overall S02 annual

emission rate of

0.33 4beJ.h/million

Btu or a rate

equivalent to 44 percent

of the Base Rate of S02 emissions,

whichever

is more

stringent.

Beginning

in calendar year 2015 and continuing in each

calendar year

thereafter,

for the EGU5 in each MPS Grouping, the

owner and operator of the

EGU5 must

comply with an overall annual emission rate

for S02 of 0.25

lbs/million Btu or a rate

equivalent

to 35

percent of the Base Rate of S02

emissions, whichever is more

stringent.

Compliance with the NOx and S02

emission standards must be demonstrated in

accordance

with Sections 225.310, 225.410, and 225.510.

The owner or operator

of EGUs

must complete the demonstration of compliance

before March 1 of the

following year for annual standards and

before November 1 for seasonal

standards, by

which date

compliance report must be

submitted

the Agency.

Requirements for NOx and S02 Allowances.

The owner or operator of EGUs in an

MPS

Group must not

sell or trade

any

person or otherwise exchange

with

give

any person NOx allowances

allocated to

the

EGUs in the MPS Group for

vintage years 2012 and beyond that

would

otherwise be available for

sale,

trade, or

exchange

a result of actions

taken to comply with the

standards in subsection

Ce)

of this Section. Such

allowances

that are not retired for compliance must be surrendered to

the

Agency

on an

annual basis, beginning in calendar year 2013. This

provision

does not

apply to

the use, sale, exchange, gift, or trade of

allowances among the EGU5 in

an MPS

Group.

The owners or

operators of EGUs in an MPS Group must not sell or

trade

any

person or otherwise

exchange with or give

any person S02

allowances

allocated to the EGU5

in the MPS Group for vintage years 2013 and

beyond

that

would otherwise be

available for sale or trade as a result of

actions taken

comply with the

standards in subsection

(e)

of this

Section.

Such

allowances

that are not

retired for compliance, or otherwise surrendered

pursuant

to a

consent decree to

which the State of Illinois is a party, must be

surrendered

the Agency on an

annual basis, beginning in calendar year 2014.

This provision

does

not apply to

the use, sale, exchange, gift, or trade of

allowances among

the EGU5 in an MPS

Group.

The provisions

of this subsection

(f)

not restrict or

inhibit the sale

or trading of

allowances that become available from one or more EGU5

MPS

Group as a result

of holding allowances that represent

over-compliance with the

NOx or S02

standard in subsection

(e)

of this Section, once such a

standard

becomes

effective, whether such over-compliance results

from control equipment,

fuel changes, changes

in the method of operation, unit shut downs,

or other

reasons.

For purposes

of this subsection

(f),

NOx and S02

allowances mean

allowances

necessary for compliance with Subpart

W of Section 217

(NOx

Trading

Program

for Electrical Generating Units)Scctionz

225.310, 225.410, or 225.5l0,

40 CFP.

72, or cubpartc Subparts

A through IA and

AI\7\AI

of 40 CFR 96, or any

future

federal

NOx or 502

emissions trading programs that include Illinois

sources.

This Section does not

prohibit the owner or operator of EGU5 in an MPS

Group

from purchasing or

otherwise obtaining allowances from other sources as

allowed by

law for purposes of

complying with federal or state requirements,

except as

specifically set

forth in this Section.

Before March 1, 2010,

and continuing each year thereafter, the owner or

operator of EGU5 in an MPS

Group must submit a report to the Agency that

demonstrates compliance with

the requirements of this subsection

(f)

for the

previous calendar year, and

which includes identification of any

allowances

that

have been surrendered to

the USEPA or

the

Agency and any

allowances that were

sold,

gifted, used,

exchanged, or traded because they became

available

due to

over-compliance.

All

allowances that are required to be

surrendered must

surrendered by

August 31, unless USEPA has not yet deducted

the allowances from

the previous

year. A final report must be submitted to the Agency by

August 31

each year, verifying

that the actions described in the initial

report have

taken place or, if

such actions have not taken place, an explanation

of all

changes that have

occurred and the reasons for such changes. If

USEPA has not

deducted the

allowances from the previous year by August 31, the

final report

must be due,

and

all allowances required to be

surrendered

must be

surrendered,

within 30 days

after such deduction occurs.

Notwithstanding 35

Ill. Adm.

Code

201.146(hhh),

until an EGU has complied

with the applicable

emission standards of subsections

(d)

and

(e)

of this

Section for 12 months, the

owner or operator of the EGU must obtain a

construction permit for any

new

modified air pollution control equipment that

proposes to construct

for

control of emissions of mercury, NOx, or S02.

(Source:

Amended

at 33

Ill. Reg.

effective

Section

225.234

Temporary Technology-Based Standard for EGU5 at

Existing

Sources

General.

source

with

EGUs that commenced commercial operation on or before

December 31, 2008,

for

an EGU that meets the eligibility criteria in subsection

(b)

of this Section,

the

owner or operator of the EGU may temporarily comply

with the requirements

this Section through June 30, 2015, as an alternative

to compliance with

the mercury

emission standards in Section 225.230, as

provided in subsections

(c), (d),

and

Ce)

of this Section.

An EGU that is complying with the emission control requirements of this

Subpart B by

operating

pursuant to this Section may not be included in a

compliance

demonstration

involving other EGU5 during the period that is

operating pursuant to

this

Section.

The owner or

operator

of an EGU that is complying with this

Subpart B

means

of the

temporary

alternative emission standards of this

Section is not

excused from any

of the

applicable

monitoring,

recordkeeping,

and

reporting

requirements set

forth in

Sections

225.240 through 225.290.

Until June 30,

2012,

an alternative

the CEMS monitoring,

recordkeeping,

and reporting requirements in Sections 225.240 through 225.290,

the owner or

operator

of an EGU may elect to comply with the

emissions

testing,

monitoring,

recordkeeping,

and reporting requirements in Section

225.239(c),

Cd), Ce), (f) Cl)

and

(2),

(h) (2), Ci) (3)

and

C4)

, and

Ci)

(1)

Eligibility.

To be eligible to operate an EGU

pursuant

this Section, the following

criteria must be met for the EGU:

The EGU is equipped and operated with the air pollution

control

equipment

or systems that include injection of halogenated

activated

carbon and either a

cold-side electrostatic

precipitator or

fabric filter.

The owner or operator of the EGU is injecting halogenated activated carbon

in an optimum manner for control of mercury emissions, which must include

injection of Alstrom, Norit,

Sorbent Technologies,

Calgon

Carbon’s FLUEPAC

Plus, or other halogenated

activated carbon that

the

owner

operator of

the

EGU has demonstrated to

have similar

better effectiveness for control

mercury emissions, at least at

the following

rates set forth

in subsections

(b) (2) (A)

through

(b) (2) CD)

this Section,

unless other

provisions for

injection of halogenated

activated

carbon are established in a

federally

enforceable

operating permit issued for the EGU, using

injection

system

designed for

effective absorption of mercury, considering

the

configuration

the EGU and its ductwork. For the purposes of this subsection

Cb)

(2),

the flue

gas flow rate must be

determined

for the point of sorbent injection

(provided,

however, that this flow rate may be assumed to be identical to the stack flow

rate if the gas temperatures at the point of injection and the stack are

normally within 100°

or may otherwise be calculated from the stack flow rate,

corrected for the difference in gas temperatures.

For

an EGU firing subbituminous coal,

5.0 lbs per

million actual

cubic

feet.

For an EGU firing bituminous coal, 10.0 lbs per million actual cubic feet.

For an EGU firing a blend of subbituminous and bituminous coal, a rate

that

the

weighted average of the above rates, based on the blend of coal

being fired.

A rate or rates set on a unit-specific basis that

are lower than the rate

specified above to the extent that the owner or operator of the

EGU demonstrates

that such rate or rates are needed so that carbon injection

would not increase

particulate matter emissions or opacity so as to threaten compliance

with

applicable regulatory requirements for particulate matter or opacity.

The total capacity of the EGU5 that operate pursuant to this

Section

does

not exceed the applicable of the following values:

For the owner or operator of more than one existing source with

EGUs,

2.5

percent

the total rated capacity, in MW, of all the EGU5 at the existing

sources

that it owns or operates, other than any EGU5 operating pursuant to

Section 225.235 of this Subpart B.

For the owner or operator of only a single existing source

with EGU5

(i.e.,

City, Water, Light & Power, City of Springfield,

ID 167120AA0; Kincaid

Generating Station, ID 021814AAB; and Southern Illinois Power

Cooperative/Marion

Generating Station, ID

199856AAC),

25 percent of the total rated

capacity, in

MW, of the all the EGU5 at the existing sources, other than any

EGU5 operating

pursuant

Section 225.235.

Compliance Requirements.

Emission Control Requirements.

The owner

or operator of an EGU that is operating pursuant to this Section must

continue to

maintain and operate the EGU to comply with the criteria for

eligibility

for operation pursuant to this Section, except during an

evaluation

of the

current sorbent, alternative sorbents or other techniques to control

mercury

emissions, as provided by subsection

(e)

of this Section.

Monitoring and Recordkeeping

Requirements.

addition to complying with all applicable

rcporting monitoring and

recordkeeping

requirements in Sections 225.240 through 225.290 or Section

225.239(c),

(d),

(e),

(f) (1)

and

(2), (h) (2),

and

i(3)

and

(4),

the owner or

operator

of an EGU

operating pursuant

this Section must also:

Through December 31, 2012, it must maintain records of the usage of

activated carbon, the exhaust gas

flow

rate

from the

EGU, and

the activated

carbon feed rate, in pounds per

million

actual

cubic

feet

of exhaust

gas at

the

injection point, on a

weekly average.

Beginning January

1, 2013, it must monitor activated carbon feed rate

the EGU, flue

gas temperature

the point of sorbent injection, and exhaust gas

flow rate from the EGU, automatically recording this data and the activated

carbon feed rate, in pounds per million actual cubic feet of exhaust gas at the

injection point, on an hourly

average.

If a blend of

bituminous

and

subbituminous

coal is

fired in the EGU, it

must maintain records of

the amount of

each

type of coal

burned and the required

injection rate

for injection

halogenated activated carbon, on

weekly basis.

Notification and

Reporting

Requirements.

addition to

complying with all applicable reporting

requirements in Sections

225.240 through 225.290 or Section

225.239(f) (1), (f) (2),

and

(j)

(1),

the owner

operator

an EGU operating pursuant to this Section must also

submit the

following notifications and reports to the Agency:

Written notification prior to the month in which any of the

following

events

will occur:

The EGU

will no longer be eligible to operate under this

Section

due to a

change in

operation;

ii)

The type of

coal fired in the EGU will change; the mercury emission

standard with

which the owner or operator is attempting to comply for the EGU

will change; or

iii)

Operation under this

Section will

terminated.

Quarterly reports

for the recordkeeping and monitoring or emissions

testing conducted

pursuant to subsection

Cc) (2)

of this Section.

Annual reports

detailing activities conducted for the EGU to further

improve control of

mercury emissions, including the measures taken during the

past year and

activities planned for the current year.

Applications

Operate under the Technology-Based Standard

Application Deadlines.

The owner

or operator of an EGU that is seeking to operate the EGU

pursuant to this

Section must submit an application to the Agency no later than

three months prior to

the

date

on which compliance with Section 225.230 of this

Subpart B would

otherwise have

to be

demonstrated. For example, the owner or

operator of an

EGU that is applying to operate the EGU pursuant to this Section

on June 30,

2010, when compliance with applicable mercury emission

standards

must be

first demonstrated, must apply by March 31, 2010 to

operate under

this

Section.

Unless the Agency

finds that

the

EGU is not eligible

operate pursuant

to this

Section or that the application for operation pursuant to this Section

does not meet

the requirements of subsection

Cd) (2)

of this Section, the owner

operator of the EGU is authorized

operate the EGU pursuant to this Section

beginning 60 days

after receipt of the application by the Agency.

The owner or operator of an EGU operating pursuant to this Section must

reapply to

operate pursuant

this Section:

If it operated the EGU pursuant to this Section 225.234 during the period

June 2010 through December 2012 and it seeks to operate the EGU pursuant to

this Section 225.234 during the period from January 2013 through June 2015.

ii)

If it is planning a physical change to or a change in the method of

operation of the EGU, control equipment or practices for injection of activated

carbon that is expected to reduce the level of control of mercury emissions.

Contents of Application.

An application to operate an EGU pursuant to this Section 225.234 must be

submitted as an application for a

new

or revised federally enforceable

operating

permit for the EGU, and it must include the following documents and

information:

A formal request to operate pursuant to this Section showing that the EGU

is eligible to operate pursuant to this Section and describing the reason for

the request, the measures that

have

been taken for control of mercury

emissions,

and factors

preventing

effective

control of mercury

emissions from the EGU.

The

applicable mercury emission standard in Section

225.230(a)

with which

the owner or

operator of the EGU is attempting

comply and

summary of

relevant mercury

emission

data

for the

EGU.

If a

unit-specific rate or rates for carbon injection are proposed

pursuant to

subsection

(b) (2)

of this Section, detailed information

support

the proposed

injection rates.

action plan describing the measures that will

taken while operating

under this

Section to improve control of mercury emissions. This plan must

address

measures such as evaluation of alternative forms or sources of activated

carbon, changes to

the injection system, changes

operation of the unit that

affect the

effectiveness of mercury absorption and collection, changes to the

particulate

matter control device

improve performance, and changes

other

emission control

devices. For

each

measure contained in the plan, the plan

must

provide a

detailed description of the specific actions that are planned, the

reason that the

measure is being pursued and the range of improvement in control

of mercury that

is expected, and the factors that affect the timing for carrying

out the

measure, together with the current schedule for the measure.

Evaluation of Alternative Control Techniques for Mercury Emissions.

During an

evaluation of the effectiveness of the current sorbent,

alternative

sorbent, or other technique

control mercury emissions, the owner

or operator

of an EGU operating pursuant

this Section need not comply with

the

eligibility criteria for operation pursuant

this Section

needed

carry out an

evaluation of the practicality and effectiveness of such technique,

subject to the

following limitations:

The

owner or operator of the EGU must conduct the evaluation in accordance

with a

formal evaluation program

that

it has submitted

the Agency

least

days prior to

beginning the evaluation.

The

duration and

scope

the

formal evaluation program must not exceed

the duration

and

scope

reasonably

needed to

complete the desired evaluation

the

alternative control technique,

initially addressed

the owner or owner

in a support

document that it has submitted with the formal evaluation program

pursuant to

subsection

(e) (1) (A)

of this Section.

Notwithstanding 35 Ill. Adm. Code

20l.146(hhh),

the owner or operator of

the EGU must obtain a construction permit for any new or modified air pollution

control equipment to be constructed as part of the evaluation of the alternative

control technique.

The

owner or operator of the EGU must submit

report

to the

Agency, no

later than

days after the conclusion of the formal evaluation program

describing

the

evaluation that was conducted, and providing the results of the

formal evaluation program.

If the evaluation of the alternative control technique shows less

effective control of mercury emissions from the EGU than achieved with the prior

control technique, the owner or operator of the EGU must resume use of the prior

control technique. If the evaluation of the alternative control technique shows

comparable control effectiveness, the owner or operator of the EGU may either

continue to use

the alternative control technique in an optimum manner or resume

use of the

prior control technique. If the evaluation of the alternative

control technique

shows more effective control of mercury emissions, the owner

or operator of

the EGU must continue

to use

the alternative control technique in

an optimum manner,

if it continues

operate

pursuant

this Section.

(Source:

Amended

at 33

Ill. Reg.

effective

Section 225.235

Units Scheduled for Permanent Shut Down

The emission standards of Section

225.230(a)

are not applicable to an EGU

that will

permanently shut down as described in this Section--:

The owner or operator of an EGU that relies on this Section must complete

the following

actions before

June 30, 2009:

Have notified

the Agency that it is planning

permanently shut down the

EGU by the

applicable

date

specified in subsection

(a) (3)

(4)

of this

Section. This

notification must include

description of the actions that have

already been

taken

allow the shut down of the EGU and

description of the

future actions that

must

accomplished

complete the shut down of the EGU,

with the anticipated

schedule for those actions and the anticipated date of

permanent shut

down of the unit.

Have

applied for

construction permit or

actively pursuing

federally

enforceable

agreement that requires the EGU

to be

permanently shut down in

accordance with

this Section.

Have applied for revisions

the operating permits for the EGU to include

provisions that terminate the authorization to operate the unit in accordance

with this

Section.

The owner or operator of an EGU that relies on this Section must, before

June

30,

2010, complete the following actions:

Have obtained a construction permit or entered into a

federally

enforceable agreement as

described

in subsection

(a) (1) (B)

of this

Section;

Have

obtained revised operating permits in accordance with subsection

(a) (1) (C)

this Section.

The plan for permanent shut down of the EGU must provide for the EGU

to be

permanently

shut down

no later than the applicable

date

specified below:

If the

owner or operator of the EGU is not constructing

new EGU or other

generating

unit

specifically replace the existing EGU,

December 31, 2010.

I’

If the owner or operator of the

EGU

is constructing a new EGU

other

generating

unit

specifically replace the existing EGU, by December 31, 2011.

The

owner or operator of the EGU must permanently shut down the EGU by the

date specified

in subsection

(a) (3)

of this Section, unless the owner or

operator submits a

demonstration to the Agency before the specified date showing

that circumstances

beyond

its

reasonable control

(such

protracted delays in

construction

activity, unanticipated outage of another EGU, or protracted

shakedown of a

replacement

unit)

have occurred that interfere with the plan for

permanent shut

down of the EGU, in which case the Agency may accept the

demonstration as

substantiated and extend the

date

for shut down of the EGU as

follows:

If the owner or operator of the EGU is not constructing a new

EGU or other

generating

unit to specifically replace the existing EGU, for up to

one year,

i.e.,

permanent shut down of the EGU to occur by no later

than December 31,

2011; or

If the owner or operator

of the EGU is constructing

new EGU or other

generating

unit to specifically replace

the

existing

EGU, for

up to

18 months,

i.e.,

permanent shutdown of the EGU to occur by no

later than June

30,

2013;

provided, however, that after December 31, 2012, the

existing EGU must only

operate as a

back-up unit to address periods when the

new generating units

are

not in

service.

Notwithstanding Sections 225.230 and 225.232, any EGU that is not

required

to comply

with Section 225.230 pursuant to this Section must not be included

when

determining whether any other EGU5 at the source or other sources are in

compliance

with Section 225.230.

If an EGU, for which the owner or operator of the

source has relied

upon

this Section in lieu of complying with Section

225.230(a)

is not permanently

shut down as required by this Section,

the

EGU must

considered

be a new

EGU subject to the emission standards

in Section

225.237(a)

beginning in the

month after the EGU was

required

to be

permanently shut down, in addition

to any

other penalties that may be

imposed for failure

permanently shut down the EGU

in accordance

with this Section.

EGU that has completed the requirements of subsection

(a)

of this

Section is

exempt from the monitoring and

testing

requirements in Sections 225.239 and

225.240.

An EGU that is scheduled for permanent shut down

pursuant

Section

225.294(b)

is exempt from the monitoring and testing requirements in Sections

225.239

and 225.240.

(Source:

Amended at 33 111. FLeg.

effective

Section 225.237 Emission Standards for New Sources with

EGU5

Standards.

Except

as provided in Sections 225.238 and 225.239, the

Thc

owner or

operator of

source with one or more EGU5,

but

that previously had not had any

EGUs

that commenced commercial operation before January 1, 2009, must comply

with

one of the

following

emission standards for each EGU

on a

rolling 12-month

basis:

An emission

standard of 0.0080 lb mercury/GWh gross electrical

output; or

A minimum

percent reduction of input mercury.

For this purpose, compliance may be demonstrated using the equations in

Section 225.230

(a) (2), (a) (3),

(b) (2).

The initial 12-month rolling period for which compliance with the emission

standards of subsection

(a) (1)

of this Section must be demonstrated for a new

EGU will commence on the date that the initial performance testing commences

under 40 CFR

60.8.

for thc mercury cmicoion ctandard under 40 CFR 60.45a alco

commcncec. The CEMS required by this Subpart B for mercury emissions from the

EGU must

certified prior to this date. Thereafter, compliance must

demonstrated on a rolling 12-month basis

based

on calendar months.

(Source: Amended at 33 Ill. Reg.

effective

Section

225.238

Temporary Technology-Based Standard for New Sources with EGUs

General.

source with EGUs that previously had not had any EGU5 that commenced

commercial operation before January 1, 2009, for an EGU that meets the

eligibility criteria in subsection

(b)

of this Section, as an alternative to

compliance with the

mercury emission

standards in Section 225.237, the owner or

operator of the

EGU may temporarily

comply

with the requirements

this

Section,

through December 31, 2018,

further provided in subsections

(c), (d),

and

(e)

this Section.

An EGU that

is complying with

the

emission control requirements of

this

Subpart B by

operating pursuant

to this

Section may not

be included in a

compliance

demonstration involving

other

EGUs

the

source during the period

that the

temporary technology-based standard is in effect.

The

owner or operator of an EGU that is complying with this Subpart B

pursuant to

this Section is not excused from applicable monitoring,

recordkeeping,

and reporting requirements of Sections 225.240 through 225.290.

Until June

30,

2012,

an alternative

the

CEMS monitoring,

recordkeeping, and reporting requirements in Sections 225.240 through 225.290,

the

owner or operator of an EGU may elect

comply with the emissions testing,

monitoring, recordkeeping, and reporting requirements in Section

225.239(c),

(d) , (e) , (f) (1)

and

(2), (h) (2), (i) (3)

and

(4),

and

(j)

(1)

Eligibility.

To be eligible to operate an EGU pursuant to this Section, the following

criteria must be met for the EGU:

The

EGU

subject to

Best Available Control Technology

(BACT)

for

emissions

sulfur dioxide, nitrogen oxides, and particulate

matter, and the

EGU is equipped and operated with the air pollution control equipment or

systems

specified below, as applicable

the category of EGU:

For

coal-fired boilers, injection of sorbent

or other mercury control

technique (e.g.,

reagent) approved

by the

Agency.

For an EGU firing fuel gas produced by coal gasification, processing of

the raw fuel gas

prior

to combustion for removal of mercury with a system using

a sorbent or other

mercury

control technique approved by the Agency.

For an EGU for

which

injection of a sorbent or other mercury control

technique is required pursuant to subsection

(b) (1)

of this Section, the owner

or operator of the EGU is injecting sorbent or other mercury control technique

in an optimum manner for control of mercury emissions, which must include

injection of Alstrom, Norit, Sorbent Technologies, Calgon Carbons FLUEPAC MC

Plus, or other sorbent or other mercury control technique that the owner or

operator of the EGU demonstrates to have similar or better effectiveness for

control of mercury emissions, at least at the rate set forth in the appropriate

of subsections

(b) (2)

(A)

through

(b) (2) (C)

of this Section, unless other

provisions for

injection

of sorbent or other mercury control technique are

established in a

federally

enforceable operating permit issued for the EGU, with

an injection

system designed for effective

absorption of mercury. For the

purposes

this subsection

(b) (2),

the flue

gas flow rate must be determined

for

the point of sorbent injection or other mercury control technique (provided,

however, that this flow rate may be assumed

to be

identical

the stack flow

rate

if the

gas

temperatures at the point of injection and the stack are

normally within

1000

, or the flow rate may otherwise

calculated from

the

stack flow rate, corrected for the difference in

gas

temperatures.

For an EGU firing subbituminous coal,

5.0

pounds per million actual

cubic

feet.

For an EGU firing bituminous coal, 10.0

pounds

per million actual

cubic

feet.

For an EGU firing a blend of subbituminous and bituminous coal, a rate

that

is the weighted average of the above rates, based on the blend of coal

being

fired.

A rate

or rates

set

unit-specific

basis that are lower than the rate

specified in

subsections

(b) (2)

(A), (B)

, and

(C)

of this Section, to the extent

that

the owner or operator of the

EGU

demonstrates

that such rate or rates are

needed so

that sorbent injection or other mercury

control

technique would

not

increase particulate matter emissions or opacity

so as to threaten

compliance

with applicable regulatory requirements for particulate

matter or opacity or

cause a safety

issue.

Compliance Requirements

Emission Control Requirements.

The owner or operator of an EGU that is operating pursuant

this Section

must

continue to maintain and operate the EGU to comply with the criteria for

eligibility for operation under this Section, except during an evaluation

the

current sorbent, alternative sorbents, or other techniques

control mercury

emissions, as

provided

by subsection

(e)

of this Section.

Monitoring

and

Recordkeeping

Requirements.

In addition

complying with all

applicable

rcporting

monitoring and

recordkeeping requirements in Sections

225.240 through 225.290 or Section

225.239(c),

(d),

(e), (f) (1)

and

(2), (h)(2),

and

£iI(3)

and (4), the owner or

operator

of a

new EGU operating pursuant

this Section

must

also:

Monitor sorbent feed rate to the EGU, flue

gas

temperature

the point of

sorbent injection or other mercury control technique, and exhaust

gas

flow rate

from the EGU, automatically recording this

data

and the sorbent feed rate, in

pounds per million actual cubic feet of exhaust

gas at

the injection point, on

an hourly average.

blend of

bituminous

and subbituminous coal is fired in the EGU,

maintain records

of the

amount

each

type of coal burned and the required

injection rate for

injection of sorbent,

on a weekly basis.

If a mercury

control technique other

than sorbent injection is approved by

the Agency,

monitor appropriate parameter

for that control technique as

specified by the

Agency.

Notification

and Reporting Requirements.

addition to

complying

with all applicable reporting requirements of Sections

225.240 through 225.290 or Section

225.239(f) (1)

and

(2)

and

(j)

(1),

the owner

or operator of an EGU operating pursuant to this Section must also submit the

following notifications and reports to the Agency:

Written notification prior to the month in which any of the following

events will occur: the EGU will no longer be eligible to operate under this

Section due to a change in operation; the type of coal fired in the EGU will

change; the mercury emission standard with which the owner or operator is

attempting to comply for the EGU will change; or operation under this Section

will be terminated.

Quarterly

reports for the recordkeeping

and monitoring or emissions

testing conducted

pursuant

to subsection

of this Section.

Annual

reports detailing activities

conducted for the EGU to further

improve control of mercury emissions, including the measures taken during

the

past

year and activities planned for the current year.

Applications to Operate under the Technology-Based Standard.

Application Deadlines.

The owner or operator of an EGU that is seeking

operate the EGU

pursuant

this Section must submit an application

the

Agency no later

than

three months prior to the date that compliance with Section 225.237 would

otherwise have to be demonstrated.

Unless the Agency finds that the EGU is not eligible to operate pursuant

to this Section or that the application for operation under this Section does

not meet the

requirements

subsection

(d) (2)

of this Section, the owner or

operator of the

EGU

authorized

to operate the EGU pursuant to this Section

beginning 60 days

after receipt of

the application by the Agency.

The owner or operator of an EGU

operating pursuant to this Section must

reapply

operate pursuant to this Section if

it is

planning

a physical change

change in the method of operation of the

EGU, control equipment, or

practices for injection of sorbent or other mercury control

technique that is

expected to reduce the level of control of mercury emissions.

Contents of

Application.

An application

operate

pursuant to this Section must be submitted

application for a

new or revised federally enforceable operating permit for the

new EGU, and it must

include the following information:

A formal request

to operate pursuant to this Section

showing

that

the EGU

is eligible to

operate pursuant to this Section and

describing

the

reason for

the request, the

measures that have been taken for control

mercury

emissions,

and factors

preventing more

effective

control of mercury

emissions from the EGU.

The

applicable mercury

emission

standard in Section

225.237 with which the

owner or

operator of the EGU is attempting to comply and a

summary of relevant

mercury emission

data for the EGU.

If a

unit-specific rate or rates for sorbent or other mercury

control

technique

injection are proposed pursuant to subsection

(b) (2)

of this Section,

detailed

information to support the proposed injection rates.

An action

plan describing the measures that will be taken while operating

pursuant to

this Section to improve control of mercury

emissions. This plan

must address

measures such as evaluation of alternative forms or sources of

sorbent or

other mercury control technique, changes to the injection system,

changes

operation of the unit that affect the effectiveness of

mercury

absorption and

collection, and changes to other emission control

devices.

For

each measure

contained in the plan, the plan must provide a detailed description

of the

specific actions that are planned, the reason that

the measure is being

pursued

and the range of

improvement

in control

of mercury that is expected, and

the

factors that affect the timing for

carrying

out

the measure, with the

current schedule for the

measure.

Evaluation of

Alternative Control Techniques for Mercury Emissions.

During an evaluation of the

effectiveness of the current sorbent,

alternative sorbent, or

other

technique to

control mercury emissions, the owner

or operator of an EGU

operating

pursuant to

this Section does not need to comply

with the eligibility criteria for operation

pursuant

this Section as needed

carry out an evaluation of the

practicality and effectiveness of such

technique, further subject to the

following limitations:

The owner or

operator of the EGU

must

conduct the evaluation in accordance

with a formal

evaluation program that it has submitted to the Agency at least 30

days

prior to

beginning the evaluation.

The

duration and

scope

of the formal evaluation program must not exceed

the duration

and

scope

reasonably needed to complete the desired evaluation of

the

alternative control technique,

initially addressed by the owner

operator in

support document that it has submitted with the formal

evaluation

program

pursuant to subsection

(e) (1) (A)

of this Section.

Notwithstanding 35 Ill. Adm. Code

20l.146(hhh), the owner or operator of

the EGU must obtain a construction permit

for any new or modified air pollution

control equipment to be constructed as

part of the evaluation of the alternative

control technique.

The

owner or

operator

of the EGU

must

submit a report

to the Agency no

later

than 90 days after

the conclusion

of the formal evaluation

program

describing the

evaluation

that was

conducted and providing

the results

of the

formal evaluation

program.

the

evaluation

the alternative

control technique

shows less

effective

control

of mercury

emissions

from the EGU than

was achieved with

the

prior control

technique,

the owner

or operator of the

EGU must resume

use

of the

prior control

technique.

the

evaluation of the

alternative control

technique

shows comparable

effectiveness,

the owner or operator

of the EGU

may either

continue

use the alternative

control technique

in an optimum

manner or resume

use

of the prior

control

technique. If

the evaluation of

the alternative

control technique

shows

more effective

control of mercury

emissions,

the

owner

operator of

the EGU must continue

use

the alternative

control

technique

optimum

manner,

it continues

operate

pursuant

this

Section.

(Source:

Amended

33 Ill. Reg.

effective

Section 225.239

Periodic Emissions

Testing Alternative

Requirements

General.

As an

alternative

to demonstrating

compliance

with the emissions

standards

of Sections

225.230(a)

225.237(a),

the owner

or operator of

EGU

may elect

demonstrate

compliance

pursuant to the

emission

standards

subsection

(b)

of this

Section

and the use

of quarterly

emissions testing

alternative

the

use of

CEMS;

The

owner or operator

an EGU that elects

demonstrate

compliance

pursuant

this Section

must

comply

with

the testing,

recordkeeping,

and

reporting

requirements

of this

Section

in addition to

other applicable

recordkeeping

and reporting

requirements

in this

Subpart;

The

alternative

method

of compliance

provided under

this subsection

may

only be

used

until

June 30,

2012,

after

which

CEMS

certified in accordance

with

Section 225.250

of this

Subpart

B must

be used.

an owner or operator

of an EGU demonstrating

compliance

pursuant

Section

225.230 or 225.237

discontinues

use

of CEMS before

collecting

full

months

of CEMS data

and elects

demonstrate

compliance

pursuant to this

Section, the data

collected prior

to that point must

be averaged to

determine

compliance

for

such period.

In such case, for

purposes of

calculating

emission

standard

or mercury

control efficiency

using the equations

Section

225.230(a)

(b),

the

“12’

in the equations

will be replaced

by a variable

equal

to the

number of full

and partial

months for which

the

owner

operator

collected CEMS

data.

Emission Limits.

Existing

Units: Beginning

July

1, 2009,

the owner or operator

a source

with one

or more EGtJ5 subject

this

Subpart

B that commenced

commercial

operation

on or before

June

30, 2009, must

comply

with one

of the following

standards

for each

EGU, as

determined

through quarterly

emissions testing

according to subsections

(c),

Cd)

, Ce)

, and

(f)

this Section:

emission

standard

of 0.0080 lb mercury/GWh

gross electrical

output;

A minimum 90-percent

reduction

input

mercury.

New Units:

Beginning within

the first

2,160

hours after the commencement

of commercial

operations, the

owner or

operator of

a source with

one or more

EGUs subject

this Subpart

B that

commenced

commercial operation

after June

30,

2009, must comply

with one of

the following

standards

for each EGU, as

determined

through

quarterly

emissions

testing

accordance

with

subsections

and

(f)

of this

Section:

emission standard

of 0.0080

lb mercury/GWh

gross electrical

output;

minimum 90-percent

reduction

of input

mercury.

Initial Emissions

Testing Requirements

for New

Units. The

owner or

operator

an EGU

that commenced commercial

operation

after

June 30,

2009, and

that is complying

means of this

Section must conduct

an initial

performance

test

in accordance

with the

requirements of subsections

Cd)

and

(e)

of this

Section

within the first

2,160 hours after

the commencement

of commercial

operations.

Emissions

Testing Requirements

Subsequent

the initial

performance

test, emissions

tests

must be

performed

quarterly

calendar basis

in accordance with

the requirements

subsections

Cd), Ce),

and

(f)

of this

Section;

Notwithstanding

the provisions

subparagraph

(1)

of this

subsection

(di (1),

owners or operators

of EGU5 demonstrating

compliance

under Section

225.233

or Sections 225.291

through 225.299

must perform

emissions testing

on a

semi-annual

calendar

basis, where the

periods

consist

of the months of

January

through June and

July through December,

accordance

with the requirements

subsections

Cd) , (e)

, and

Cf) (1)

and

(2)

of this

Section;

Emissions tests

which demonstrate

compliance

with this

Subpart must

performed

at least

45 days apart.

However, if

an emissions

test fails

demonstrate compliance

with

this Subpart or

the emissions

test is being

performed subsequent

to a significant

change

in the

operations

of an EGU under

subsection

(h) C2)

of this

Section,

the

owner or operator

an EGU may perform

additional

emissions

tcst(c)tests

using the same

test

protocol

previously

submitted

the same

period,

with less than 45

days

in between

emissions

tests;

A minimum

of three

and

maximum

of nine emissions

test

runs, lasting

least

one hour

each,

shall

conducted

and averaged

to determine

compliance.

All

test

runs

performed

will

reported.

the EGU shares

common stack with

one or more other

EGU5, the owner

operator

of the EGU will

conduct emissions

testing in the

duct

to the common

stack

from each unit,

unless the owner

or operator

the EGU considers

the

combined emissions

measured at the

common

stack

the mass emissions

of mercury

for the EGUs

for recordkeeping

and compliance

purposes.

If an

owner or

operator of

an EGU demonstrating

compliance

pursuant

this Section

later

elects to

demonstrate compliance

pursuant

the CEMS

monitoring

provisions

Section 225.240 of

this Subpart,

the

owner or operator

must

comply

with the emissions

monitoring

deadlines in

Section

225.240(b)

C4)

this

Subpart.

Emissions Testing

Procedures

The owner or operator must conduct a compliance test in accordance with

Method 29, 30A, or 30B of 40 CFR 60, Appendix A, as incorporated by reference in

Section 225.140;

Mercury emissions or

control

efficiency must be measured while the

affected unit is operating at

or above

90% of peak load;

For units

complying with the control

efficiency

standard

subsection

(b) (1) (B)

(b)

(2)

(B)

of this Section, the

owner or

operator must perform

coal

sampling as

follows:

in accordance with Section 225.265 of this Subpart

least once during

each day

of testing; and

in accordance with Section 225.265 of this Subpart, once each month in

those months

when emissions testing is not performed;

For units complying with the output-based emission standard of subsection

(b) (1) (A)

(b)

(2) (A)

of this Section, the owner or operator must monitor

gross

electrical output

for the duration of the testing.

The

owner or operator of an EGU may use an alternative emissions testing

method

if such alternative is submitted to the Agency in writing and approved

writing by

the Manager of the Bureau of Air’s Compliance Section.

Notification Requirements

The owner or operator of an EGU must submit a testing protocol as

described in USEPA’s Emission Measurement Center’s Guideline Document

#42 to

the

Agency at least 45 days prior to a scheduled emissions test, except as provided

in Section

225.239(h) (2)

and

(h) (3).

Upon written request directed to the

Manager of the Bureau of Air’s Compliance Section, the Agency may, in its sole

discretion, waive the 45-day

requirement.

Such waiver

shall only

be effective if

it is provided

in writing and signed

the Manager of the Bureau of Air’s

Compliance

Section, or his or her designee;

Notification of

scheduled emissions

test

must

submitted

the

Agency

in writing,

directed

the

Manager of the Bureau of Air’s Compliance

Section,

at least 30 days

prior

the expected

date

of the emissions

test. Upon

written

request

directed to the Manager of the Bureau of Air’s Compliance Section,

the

Agency

may, in its sole discretion, waive the 30-day notification requirement.

Such waiver shall only be effective if it is provided in writing and signed

the Manager of the Bureau of Air’s Compliance Section, or his or her designee.

Notification of the actual date and expected time of testing must be submitted

in writing, directed to the Manager of the Bureau of Air’s Compliance Section,

least five working days prior to the actual date of the test;

For an EGU that has elected to demonstrate compliance by use of the

emission standards of subsection

(b)

of this Section, if an emissions test

performed

under the requirements

of this Section

fails

to demonstrate compliance

with the limits

of subsection

(b)

this Section,

the owner or

operator

of an

EGU

may perform

new emissions

test

using

the

same

test

protocol previously

submitted in the same period,

notifying

the

Manager of the Bureau of Air’s

Compliance Section or his or her designee

the actual

date

and expected

time

of testing at

least five working days prior to the actual date of the test. The

Agency may, in

its sole discretion,

waive this five-day notification

requirement.

Such waiver shall only be effective if it is provided in writing

and

signed

the Manager of the Bureau of Air’s Compliance Section, or his or

her

designee;

In addition to the

testing protocol

required by

subsection (f)

(1)

of this

Section, the owner or

operator of an

EGU that has elected to

demonstrate

compliance

use of the

emission

standards of subsection

(b)

of this Section

must

submit

Continuous

Parameter

Monitoring

Plan to the Agency at

least 45

days

prior

a scheduled

emissions

test. Upon written request directed to

the

Manager of the Bureau of Air’s

Compliance

Section,

the

Agency

may, in its sole

discretion, waive the 45-day

requirement.

Such waiver shall

only

effective if

it is

provided in writing and signed by the Manager of the

Bureau

Air’s

Compliance Section, or his or her designee. The Continuous

Parameter Monitoring

Plan

must

detail how the EGU will continue to operate within the

parameters

enumerated in the testing protocol and how those parameters will

ensure

compliance with the applicable mercury limit. For example, the Continuous

Parameter Monitoring Plan must include coal sampling as described in

Section

225.239(e) (3)

of this Subpart and must ensure that an EGU that

performs an

emissions test using a blend of coals continues to

operate using that same blend

coal. If the Agency

disapproves

the Continuous

Parameter Monitoring Plan,

the

owner or operator of the EGU has 30 days from the date of

receipt of the

disapproval to submit more detailed information in

accordance with the Agency’s

request.

Compliance

Determination

Each

quarterly emissions

test

shall determine compliance with this Subpart

for that

quarter, where the quarterly periods consist of the months of January

through

March, April through June, July through September, and October through

December;

emissions testing conducted pursuant to this Section fails to

demonstrate

compliance, the owner or operator of the EGU will be deemed to have

been out of

compliance with this Subpart beginning on the day after the most

recent

emissions test that demonstrated compliance or the last day of certified

CEMS data

demonstrating compliance on a rolling 12-month basis, and the

EGU

will

remain out

of compliance until a subsequent emissions test successfully

demonstrates

compliance with the limits of this Section.

Operation Requirements

The owner or operator of an EGU that has elected to demonstrate

compliance

by use

of the emission standards of subsection

(b)

of this Section must continue

operate the EGU commensurate with the Continuous Parameter

Monitoring Plan

until another Continuous Parameter Monitoring Plan is developed

and submitted

the Agency in conjunction with the next compliance demonstration,

accordance

with subsection

(f) (4)

of this Section.

If the owner or

operator

makes a

significant change

to the

operations of

an EGU subject to

this Section,

such as

changing from bituminous

subbituminous

coal, the owner or operator must submit

testing protocol to the

Agency and

perform an emissions

test

within seven operating days of the

significant change. In addition, the owner or operator of an EGU that has

elected

demonstrate compliance by use of the emission standards of subsection

(b)

this

Section must submit a Continuous Parameter Monitoring Plan within

seven operating days

of the significant change.

blend of bituminous and subbituminous coal is fired in the EGU, the

owner or operator of the EGU must ensure that the EGU continues to operate using

the

same

blend

that was used during the most recent successful emissions test.

If the

blend of coal changes, the owner or operator of the EGU must re-test in

accordance with subsections

(d), (e), Ce),

and (g) of this Section within 30

days

of the change in coal blend, notwithstanding the requirement of subsection

(d) (3)

of this Section that there must be 45 days between emissions tests.

recordkeeping

The owner or operator of an EGU and its designated representative must

comply with all applicable recordkeeping and reporting requirements in this

Section.

Continuous Parameter Monitoring. The owner or operator of an EGU

must

maintain records to substantiate that the EGU is operating in

compliance

with

the parameters listed

in the Continuous Parameter Monitoring Plan, detailing the

parameters that

impact mercury reduction and including the following records

related to the

emissions of mercury:

For

an EGU for which the owner or operator is complying with this

Subpart B pursuant to

Section

225.239(b) (1) (B)

225.239(b) (2) (B),

records of

the daily

mercury content of coal

used

(lbs/trillion

Btu)

and the daily and

quarterly input

mercury

(ibs)

For

an EGU for which the owner or operator of an EGU complying with this

Subpart B

pursuant

Section

225.239(b) (1) (A)

225.239(b) (2) (A),

records of

the daily

and quarterly gross electrical output

(MWh)

on an hourly basis.:

The owner or operator of an EGU using activated carbon injection must also

comply

with the following requirements:

Maintain records of the usage of sorbent, the exhaust gas flow rate from

the EGU,

and the sorbent feed rate, in pounds per million actual cubic feet of

exhaust gas at

the injection point, on a weekly average;

blend of bituminous and subbituminous coal is fired in the EGU, keep

records

of the amount of each type of coal burned and the required injection

rate

for injection of activated carbon, on a weekly basis.

The owner or operator of an EGU must retain all records

required

by this

Section at the source unless

otherwise provided in the CAAPP permit issued for

the source and must make a copy of any

record available

the Agency promptly

upon request.

The

owner or operator of an

EGU

demonstrating compliance pursuant to this

Section must

monitor

and

report the heat input rate

the unit level.

The owner or operator of an EGU demonstrating compliance pursuant to this

Section must perform and report coal sampling in accordance with subsection

225.239

Ce) (3).

Reporting Requirements

An owner or operator

of an EGU shall

submit to the Agency a

Final Source

Test Report for each periodic

emissions

test within 45 days

after the

test

completed. The Final Source

Test

Report will be directed to

the Manager of the

Bureau of Air’s Compliance

Section,

or his or her designee,

and include

minimum:

A summary of results;

description of

test

mcthod(z)methods,

including

description of sampling points,

sampling train,

analysis

equipment, and test

schedule, and a detailed

description

of test conditions,

including:

Process

information,

including but

not limited

modc(s)modes

of operation, process rate, and fuel or raw

material consumption;

ii)

Control equipment information

(i.e.,

equipment condition

and

operating parameters during testing);

iii)

A discussion of any preparatory

actions taken

(i.e.,

inspections, maintenance, and

repair)

;

and

iv)

Data

and calculations, including copies of all raw

data

sheets

and records of laboratory

analyses,

sample

calculations, and data on

equipment calibration.

The owner or

operator of

source with one or more EGUs demonstrating

compliance with

Subpart B in accordance with this Section must submit to the

Agency a Quarterly

Certification of Compliance within 45 days following the end

of each

calendar quarter. Quarterly certifications of compliance must certify

whether compliance

existed for each EGU for the calendar quarter covered by the

certification. If the

EGU failed

comply during the quarter covered by the

certification, the

owner or operator must provide the reasons the EGU or EGU5

failed to comply and a

full description of the noncompliance

(i.e.,

tested

emissions rate,

coal sample

data,

etc.).

In addition, for each EGU, the owner or

operator must

provide the following appropriate data to the Agency as set forth

in this Section.

A list of

all emissions

tests

performed within the calendar quarter

covered by

the Certification and submitted to the Agency for each EGU, including

the dates

on which such tests were performed.

Any deviations or exceptions

each month and discussion of

the

reasons for such deviations or

exceptions.

All

Quarterly Certifications of Compliance required to be

submitted must include

the following certification

by a

responsible official:

I certify

under penalty of law that this document and all attachments were

prepared

under my direction or supervision in accordance with a system designed

assure that

qualified personnel properly gather and evaluate the information

submitted.

Based on my inquiry of the person or persons directly responsible

for gathering

the information, the information submitted is, to the best of my

knowledge and

belief, true, accurate, and complete. I am aware that there are

significant

penalties for submitting false information, including the

possibility

of fine and imprisonment for knowing violations.

Deviation

Reports. For

each EGU, the

owner

or operator must

promptly notify

the Agency

deviations from any of the requirements of this

Subpart B. At a

minimum,

these

notifications must include a description of such

deviations

within 30 days

after discovery

of the deviations, and a discussion of

the possible

cause of such

deviations,

any corrective actions, and any

preventative

measures taken.

(Source:

Added at 33 Ill. Reg.

effective

Section 225.240 General

Monitoring

and Reporting Requirements

The owner or operator

of an EGU must

comply with the

monitoring, recordkeeping,

and

reporting requirements as

provided

in this Section,

Sections 225.250 through

225.290

of this Subpart B, and Sections 1.14 through 1.18

of Appendix B

this

Part.

Subpart I of 40 CFR

(sections

75.80 through

75.94),

incorporated

reference in

Section

225.140.

If the EGU utilizes a

common stack with units

that

are not EGU5 and

the owner or

operator

the EGU does

not conduct

emissions monitoring

in the

duct to the

common stack from each EGU, the owner or

operator of the EGU must

conduct

emissions

monitoring

in accordance with Section

1.16(b)

(2)

of Appendix B to this Part

40 CFR

75.92(b) (2)

and this Section,

including monitoring in the duct to the

common stack from each unit that is not

an EGU,

unless the owner or operator of the EGU counts the

combined emissions

measured at

the common stack as the mass emissions of mercury

for the EGU5

for

recordkeeping and compliance purposes.

Requirements for installation,

certification,

and

data

accounting. The

owner or operator of each EGU must:

Install all monitoring systems required

pursuant

this Section and

Sections 225.250 through 225.290 for

monitoring mercury mass emissions

(including all systems required to

monitor mercury concentration, stack

gas

moisture content, stack gas

flow rate, and C02 or 02 concentration, as

applicable, in

accordance with Sections 1.15 and 1.16 of Appendix B to this

Part. 40 CFR 75.91

and

75.92).

Successfully complete all certification tests required

pursuant

to Section

225.250

and meet all other requirements of this Section,

Sections

225.250

through 225.290, and Sections 1.14 through 1.18

of Appendix B

this Part—

subpart I of 40 CFR Part 75 applicable to

the

monitoring systems required under

subsection

(a) (1)

of this

Section.

Record, report, and

assure

the

quality of the

data

from the monitoring

systems required under

subsection

(a)

(1) of this Section.

If the owner or operator elects to use

the low mass emissions excepted

monitoring methodology for an EGU that emits

no more than 464 ounces

(29

pounds)

of mercury per year pursuant to Section

1.15(b)

of Appendix B

this Part 40

CFR

75.91(b),

it must perform emissions

testing in accordance with Section

1.15(c)

of Appendix B to

this Part 40 CFR

75.91(c)

demonstrate that the EGU

is eligible to use this

excepted emissions monitoring methodology,

well

comply with

all other applicable requirements of Section

1.15(b)

through

(f)

Appendix

this Part. 40 CFR

75.91(b)

through

(f)

. Also, the owner or

operator

must submit

copy of any information required to be submitted to the

USEPA pursuant to these provisions to the Agency. The initial

emissions

testing

demonstrate eligibility of an EGU for the low mass

emissions

excepted

methodology must be conducted by the

applicable of the following dates:

the EGU

has

commenced commercial

operation before

July 1, 2008,

least

by July

January 1, 2009,

or 45 days

prior

relying on the

low

mass

emissions excepted

methodology,

whichever

date

is later.

If the

EGU

has

commenced

commercial

operation

after July

1, 2008, at

least

days

prior

to the

applicable date

specified

pursuant to subsection

(b) (2)

this

Section or 45

days

prior

relying

on the low mass

emissions

excepted

methodology,

whichever

date

is later.

Emissions Monitoring

Deadlines.

The owner or operator

must meet the

emissions monitoring

system certification

and other emissions

monitoring

requirements of

subsections

(a) (1)

and

(a) (2)

this Section on or

before the

applicable

of the following

dates.

The owner

or operator must

record, report,

and

quality-assure

the data

from

the

emissions

monitoring systems

required

under

subsection

(a)

(1)

this Section

on and

after the applicable

of the following

dates:

For

the

owner or operator

an EGU

that

commences commercial

operation

before July

1, 2008, by July

January

2009.

For

the owner

or operator

of an EGU

that commences

commercial operation

or after

July

1, 2008, by 90

unit

operating

days

or 180 calendar days,

whichever

occurs

first,

after the date

which the EGU

commences commercial

operation.

For the owner or

operator of an EGU

for which construction

a new

stack

or flue

or installation

of add-on mercury

emission controls,

a flue

gas

desulfurization

system, a selective

catalytic reduction

system, a

fabric

filter,

compact

hybrid particulate

collector system

is completed

after

the

applicable

deadline pursuant

subsection

(b) (1)

(b)

(2)

of this

Section,

unit

operating days

180 calendar

days,

whichever

occurs first,

after

the

date

on which

emissions

first exit

to the atmosphere

through the

new

stack

flue,

add-on

mercury

emission controls,

flue gas

desulfurization

system,

selective catalytic

reduction

system, fabric filter,

or compact

hybrid

particulate

collector

system.

For an

owner or

operator of an

EGU that

originally elected

demonstrate

compliance

pursuant

the

emissions

testing requirements

Section

225.239,

the first day

the

calendar

quarter following

the last

emissions

test

demonstrating

compliance

with Section 225.239.

Reporting

Data.

Except

provided

subsection

(c)

(2)

of this Section,

the owner

operator

an EGU

that

does

not meet the

applicable

emissions monitoring

date

set

forth

in subsection

(b)

of this

Section for any

emissions monitoring

system

required

pursuant

to subsection

(a) (1)

of this

Section must begin

periodic

emissions

testing in accordance

with Section

225.239., for cach

such monitoring

system,

detcrminc, rccord,

and rcport the

maximum potential

(or,

as appropriate,

the

minimum potential)

values for mercury

concentration,

the stack gas

flow

rate, the

stack

gas

moisture

content,

and any other

parameters

required

determine

mercury mass

emissions

in accordance

with 40

CFR

75.80(g).

225.239.

The

owner

or operator

of an EGU that

does not meet

the applicable

emissions

monitoring

date

set forth

subsection

(b) (3)

of this

Section

for any

emissions

monitoring system

required

pursuant

subsection

(a) (1)

this

Section

must begin periodic

emissions

testing

in accordance

with Section

-4-’

substitutc

data

using the applicabic missing

data

procedurcsas set forth in4O

CFR

75.60(f),

in lieu of thc maximum potcntial

(or,

appropriate,

minimum

potential) values for a paramctcr, if thc owner or opcrator demonstrates

that

there is continuity

between thc

data

streams

for that

parameter before and aftcr

the construction or installation pursuant to subscction

(b)

(3)

of this

Scction.

225.239.

Prohibitions.

No owner or

operator of an EGU may

use

any alternative emissions

monitoring system,

alternative reference method for measuring emissions, or

other alternative to

the emissions monitoring and measurement requirements of

this Section and

Sections 225.250 through 225.290, unless such alternative is

submitted to the

Agency in writing and approved in writing

the Manager of the

Bureau of Air’s

Compliance Section, or his or her designee. promulgated by the

USEPA and approved

in writing by the Agency, or the use of such alternative is

annroved

writing

the

Agency

and USEPA.

owner or operator of an EGU may operate its EGU so as to discharge, or

allow to be

discharged, mercury emissions

the

atmosphere without accounting

for all

such emissions in accordance with the applicable provisions of this

Section,

Sections 225.250 through 225.290, and Sections 1.14 through

1.18

Appendix

this Part, unless demonstrating compliance pursuant to Section

225.239,

applicable,

subpart I of 40 CF’R 75.

owner or operator of an EGU may disrupt the CEMS, any

portion thereof,

or any

other approved emission monitoring method, and thereby

avoid monitoring

and

recording mercury mass emissions discharged into the atmosphere, except for

periods of

recertification or periods when calibration, quality assurance

testing, or

maintenance is performed in accordance with the applicable

provisions of

this Section, Sections 225.250 through 225.290, and Sections 1.14

through

1.18

of Appendix B

this Part.

subpart I of 40 CFR 75.

owner or operator of an EGU may retire or

permanently discontinue

use

the CEMS or any component thereof, or any other

approved monitoring

system

pursuant

this Subpart B, except under any one

of the following circumstances:

The owner

or operator is monitoring emissions from the EGU with another

certified

monitoring system that has been approved, in accordance with the

applicable

provisions of this Section, Sections 225.250 through 225.290 of this

Subpart

and Sections 1.14 through 1.18 of Appendix B to this Part, subpart I

of 40 CFR 75, by

the Agency for use at that EGU and that provides emission data

for the same

pollutant or parameter

the retired or discontinued monitoring

system; or

The owner or operator or designated representative submits notification of

the date of

certification testing of

replacement monitoring system for the

retired or

discontinued monitoring system in accordance with Section

225.250

(a) (3)

(A).

The owner or operator is demonstrating compliance pursuant to the

applicable subsections of Section 225.239.

Long-term Cold Storage.

The owner or operator of an EGU that is

in long-term cold storage is subject

the provisions

CF’R 75.4

and

CFR

75.64, incorporated

reference in

Section 225.140,

relating to monitoring, recordkeeping, and reporting for units

in long-term cold

storage.

(Source:

Amended

at 33

Ill.

Reg._______ ,

effective

Section

225.250 Initial Certification and Recertification Procedures for

Emissions Monitoring

The owner or operator of an EGU must comply with the following initial

certification and recertification procedures for

CEMS

(i.e.,

a CEMS or an

excepted

monitoring system

(sorbent

trap monitoring system) pursuant to Section

1.3

Appendix B to this Part 40 CFR 75.15, incorporated

rcfcrcncc in

Scction

225.140)

required by Section 225.240

(a) (1).

The owner or operator of an

EGU that qualifies for, and for which the owner or operator elects to use, the

low-mass-emissions excepted methodology pursuant to Section

1.15(b)

of Appendix

this Part

40 CFR

75.81(b),

incorporated

rcfcrcncc

Section 225.140,

must

comply

with the procedures set forth in subsection

(c)

of this Section.

Requirements for Initial Certification. The owner or operator of an EGU

must ensure

that, for each CEMS required

Section 225.240

(a) (1)

(including

the

automated data

acquisition and handling system), the owner or operator

successfully completes all of the initial certification testing required

pursuant to

Section 1.4 of Appendix B

this Part 40

CFR

75.80(d),

incorporatcd

reference in

Section

225.140,

the applicable deadline in Section

225.240(b).

In addition, whenever the owner or operator of an EGU installs

monitoring

system to meet the requirements of this Subpart B in a location where

such monitoring system was previously installed, the owner or operator must

successfully complete the initial certification requirements of Section 1.4 of

Appendix

B to this Part4O CFR

78.80(d).

Requirements for Recertification. Whenever the owner or operator

of an

EGU makes a replacement, modification, or change

any

certified CEMS,

or an

excepted

monitoring

system

(sorbent

trap monitoring system) pursuant

to Section

1.3 of

Appendix B

this

Part 40 CFR 75.l5,

and required

Section

225.240(a) (1),

that may significantly affect the ability of the system

accurately

measure or record mercury mass emissions or heat input rate or

meet the

quality-assurance and quality-control requirements of Section 1.5

Appendix B to

this Part 40

CFR 75.21

or Exhibit B

Appendix B

this

PartAppendix B

‘10 CFR 75, cach incorporatcd

ref crence in Scct±on

225.140,Part. the owner or operator of an EGU must recertify the monitoring

system in accordance

with

Section

1.4(b)

Appendix B

to this

Part. 40 CFR

75.20(b),

incorporated by reference in Section 225.140.

Furthermore,

whenever

the owner or

operator

of an EGU makes a

replacement, modification, or change

the flue gas

handling

system or the

EGU’s operation

that may

significantly

change the

stack flow or concentration profile, the owner or operator must

recertify

each CEMS, and each

excepted

monitoring

system

(sorbent

trap

monitoring

system) pursuant

Section 1.3

Appendix B

this Part, 40 CFR

75.15, whose accuracy is potentially affected

the change, all in accordance

with Section

1.4(b)

to Appendix B to this Part. 40 CFR

75.20(b).

Examples of

changes to a CEMS that require recertification include, but are not limited

to,

replacement of the analyzer, complete replacement of an existing CEMS, or change

location or orientation

of the

sampling

probe

or site.

Approval Process for Initial Certification and Recertification.

Subsections

(a) (3) (A)

through

(a)

(3) (D)

of this Section apply

both initial

certification and recertification of

CEMS required

Section 225.240

(a)

(1).

For

recertifications,

the

words

“certification” and

“initial

certificationTT

are

read

the

word

“recertification’,

the

word

“certified”

is to be

read

the

word

“recertified”,

and the

procedures

set

forth

in Section

1.4(b)

(5)

Appendix

this Part 40

CFR

75.20(b)

(5)

are

followed

in lieu

the

procedures

set

forth in

subsection

(a)

(3)

(E)

of this

Section.

Notification

Certification.

The owner

or operator

must

submit written

notice of

the

dates of

certification

testing

to the

Agency-

directed

to the

Manager

the Bureau

of Air’s Compliance

ScctionUSEPA

Region

5, and

thc

Administrator

of the

USEPA writtcn

noticc of thc dates

of certification

testingSection,

in accordance

with

Section 225.270.

Certification

Application.

The owner

operator

must submit

the

Agency a certification

application

for each

monitoring

system.

complete

certification

application

must include the

information

specified

in 40

CFR

75.63,

incorporated by

reference in Section

225.140.

Provisional

Certification

Date. The

provisional

certification

date

for

monitoring

system must be

determined in

accordance with

Section

1.4(a)

(3)

Appendix

to this

Part. 40 CFP. 75.20

(a) (3),

incorporated

by reference

Section 225.140.

A provisionally

certified monitoring

system

may

used

pursuant to

this

Subpart B for

a period not to

exceed 120

days

after receipt by

the Agency

of the

complete

certification

application

for the

monitoring system

pursuant

to subsection

(a) (3) (B)

of this

Section. Data

measured

and recorded

the

provisionally

certified monitoring

system,

accordance

with the

requirements

Appendix B to this

Part 40

CFR 75, will

considered

valid

quality-assured

data

(retroactive

to the date

and time of provisional

certification),

provided

that the Agency does

not

invalidate

the provisional

certification

issuing

notice of disapproval

within

120 days after the

date

receipt

the

Agency of the complete

certification

application.

Certification

Application

Approval Process.

The Agency must

issue a

written

notice of approval

or disapproval

of the certification

application to

the

owner or operator

within 120 days

after receipt

of the

complete

certification

application

required

subsection

(a)

(3) (3)

of this

Section.

the event the Agency

does not issue

written

notice

of approval or

disapproval

within the

120-day period, each

monitoring

system that

meets the

applicable

performance

requirements

Appendix

B to this Part 40

CFR 75 and which

included

the certification

application

will be

deemed certified

for use

pursuant

this Subpart

Approval

Notice.

If the certification

application

complete and shows

that

each monitoring

system meets the

applicable performance

requirements

Appendix

this

Part, 40 CFR

75,

then the

Agency must

issue a written

notice

approval

of the certification

application

within 120

days

after

receipt.

ii)

Incomplete

Application

Notice.

If the certification

application

is not

complete,

then the

Agency must issue

written

notice

of incompleteness

that

sets a reasonable

date by which

the

owner

or operator

must submit the

additional

information

required to complete

the

certification

application.

the owner

operator

does not comply

with the notice of

incompleteness by

the

specified

date,

the Agency may issue

a notice

of disapproval

pursuant

subsection

(a) (3)

(D)

(iii)

this Section. The

120-day review

period

will not

begin before

receipt

a complete

certification

application.

iii)

Disapproval Notice.

If the

certification

application

shows that

any

monitoring

system does

not meet the

performance requirements

Appendix

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the monitoring

system will be exempt from the initial certification requirements

this

Section.

The recertification

provisions

of this Section apply to an emissions

monitoring

system required by Section

225.240(a) (1)

exempt from initial

certification requirements

pursuant

to subsection

(a) (1)

of this Section.

Initial

certification and

recertification procedures

for

EGU5

using the

mercury low mass

emissions excepted

methodology pursuant to

Section

1.15(b)

Appendix B to this

Part. 40 CFR

75.81(b). The owner or

operator that has

elected to

use the

mercury-low-mass-emissions-excepted

methodology

for

qualified EGU pursuant to Section

1.15(b)

to Appendix B to this

Part 40 CFR

75.81(b)

must meet the

applicable

certification and

recertification

requirements in Section

1.15(c)

through

(f)

to Appendix B to this

Part. 40 CFR

75.81(c)

through

(f),

incorporated by rcfcrcncc in Section 225.140.

Certification Applications. The owner or operator of an EGU must submit

application

the Agency within 45 days after completing all initial

certification or recertification tests required pursuant to this Section,

including the information required pursuant to 40 CFR 75.63,

incorporated

reference in Section 225.140.

(Source:

Amended at 33 111. Reg.

effective

Section 225.260 Out

of Control Periods and Data Availability for Emission

Monitors

Out

control periods must be determined in accordance with Section 1.7

Appendix

bab)

Monitor data availability must be determined on a calendar quarter basis

in accordance

with Section 1.8 of Appendix B Whcncvcr any emissions monitoring

systcm fails to

mect thc quality assurancc and quality control rcquircmcntc or

data

validation rcquircmcnts of 40 CFR 75, incorporatcd by rcfcrcncc in Section

225.140, data

must bc substituted using the applicabic missing data proccdurcs

buDpares

ann L Or 4U

‘, cacn incorporacca D rcrcrcncc in

bccelon

225.140. following initial certification of the required C02, 02, flow monitor,

mercury concentration or moisture monitoring system(s) at a particular unit

stack location. Compliance with the percent reduction

standard

in Section

225.230(a) (1) (B)

or 225.237

(a) (1) (B)

or the emissions concentration

standard

Section 225.230

(a) (1) (A)

or 225.237

(a) (1) (A)

can only be

demonstrated if

the

monitor data availability is equal to or greater

than 75 percent; that is,

quality assured data must be recorded by a certified

primary monitor,

certified redundant or non-redundant backup

monitor, or reference method

for

that unit at least 75 percent of the time the

unit is in operation.

eb)

Audit

Decertification. Whenever both an audit of an emissions monitoring

system and a

review of the initial certification or recertification application

reveal that

any emissions monitoring system should not have been certified or

recertified

because it did not meet

particular performance specification or

other requirement pursuant to Section 225.250 or the applicable provisions of

Appendix

this Part, 40 CFR 75, both at the time of the initial

certification or recertification application submission and at the time of the

audit, the Agency must issue a notice of disapproval of the certification status

of such monitoring system. For the purposes of this subsection

(eb),

an audit

must

either a

field

audit or an audit of any information submitted to the

Agency. By

issuing the

notice of disapproval,

the Agency

revokes prospectively

the

certification

status

the emissions

monitoring

system. The data

measured

and

recorded by

the

monitoring

system

must not

considered valid

quality-

assured data

from the date of

issuance of the

notification of the

revoked

certification

status

until

the

date

and time

that the owner

or operator

completes

subsequently

approved initial

certification or

recertification

tests

for

the monitoring

system. The owner

or operator must

follow the applicable

initial

certification

or recertification

procedures

in Section 225.250

for each

disapproved

monitoring system.

(Source:

Amended

33 Ill. Reg._______

effective

Section 225.261

Additional

Requirements

Provide

Heat Input

Data

The owner or

operator

of an

EGU that

monitors

and reports

mercury mass emissions

using a

mercury concentration

monitoring

system and

a flow

monitoring

system

must

also monitor

and report the

heat input rate

at the

EGU

level using

the

procedures

set forth

Appendix

B to this Part.

CFR

75, incorporated

reference

in Scction 225.140.

(Source:

Amended

at 33 Ill.

Reg.

effective

Section

225.265

Coal

Analysis

for Input Mercury

Levels

The owner or

operator

of an EGU

complying

with this Subpart

B by

means of

Section

225.230(a)

(4r-2-1)

(B),

er—using

input mercury

levels

(Ii)

and complying

means

of Section

225.230(b)

(d)

or Section

225.232,

electing

comply

with

the

emissions

testing, monitoring,

and recordkeeping

requirements

under

Section

225.239,

demonstrating

compliance under

Section

225.233 or Sections

225.291

through

225.299 must

fulfill

the following

requirements:

Perform

daily sampling

of the coal combusted

in the

EGU for mercury

content.

The

owner

or operator

of such EGU

must collect

a minimum of

one 2-lb-i-

grab

sample

per

day

of operation

from the

belt feeders

anywhere between

the

crusher

house

or breaker building

and

the boiler.

The sample must

be taken in

manner that

provides a representative

mercury

content for the

coal

burned on

that day. EGU5

complying

means

Section

225.233 or

Sections 225.291

through

225.299

this Subpart

must perform

such coal sampling

at least

once

per month;

EGU5

complying

by means of

the

emissions

testing,

monitoring,

and recordkeeping

requirements

under Section 225.239

must perform

such

coal

sampling

according to

the

schedule

provided in

Section

225.239(e)

(3)

of this

Subpart; all

other EGUs

subject to

this requirement

must

perform

such coal sampling

on a

daily

basis.

Analyze the grab

coal

sample for the

following:

Determine the

heat

content using

ASTM D5865-04

or an

equivalent

method

approved in writing

by the Agency.

Determine

the moisture

content using

ASTM D3l73-03

or an equivalent

method

approved

writing by the

Agency.

Measure the mercury content using ASTM D6414-0l, ASTM 1)3684-01, or an

equivalent method approved in writing by the Agency.

The owner or operator of multiple EGU5

the same source using the same

crusher house or breaker building may take one sample per crusher house or

breaker building, rather than one per EGU.

The owner or operator of an EGU

must

use the data analyzed pursuant to

subsection

(b)

this

Section to

determine

the mercury content in

terms

lbs/trillion Btu.

The owner or

operator

of an EGU

that

must conduct

sampling and analysis

coal pursuant to subsection

(a)

this

Section must begin such

activity

by the

following date:

If the EGU is

daily service, at least 30 days before the

start

of the

month for which such activity will be required.

If the EGU is not in daily service, on the day that the EGU resumes

operation.

(Source:

Amended at 33 Ill. Reg.

effective

Section 225.270 Notifications

The owner or

operator

of a

source with one or more EGUs must submit written

notice to the Agency

according

the provisions in 40 CFR 75.61, incorporated

reference in

Section 225.140

(aD

ccgmcnt of 40 CFR

75)

,225.l40. for

each

EGU or group

of EGU5 monitored

at a

common stack and each non-EGU monitored

pursuant to

Section

1.16(b) (2) (B)

of Appendix B

this Part. 40 CFR

75.82(b) (2)

(ii), incorporatod

rcfcrcnce in Scction 225.140.

(Source:

Amended at 33 Ill. Reg.

effective

Section 225.290 Recordkeeping and Reporting

General Provisions.

The owner or operator of an EGU and its designated

representative must

comply with all applicable recordkeeping and reporting requirements

in this

Section and with all applicable recordkeeping and reporting

requirements

Section 1.18 to Appendix B to this Part.

40 CFR 75.84, ±ncorporatcd by rcfcrcncc

Scction 225.140.

The owner or operator of an EGU must maintain

records

for

each month

identifying the

emission standard in Section

225.230(a)

225.237(a)

of this

Section with

which it is complying

that is applicable for the EGU and the

following

records related

the emissions of mercury that the EGU is allowed

emit:

For an EGU for which the owner or operator is complying with this Subpart

B by

means of Section 225.230

(a)

(i)

(B)

or 225.237

(a) (1) (B)

or using input

mercury levels to determine the allowable emissions of the EGU, records of the

daily mercury content of coal used (lbs/trillion

Btu)

and the daily and monthly

input mercury (lbs), which

must

be kept in the file pursuant to Section

1.18(a)

of Appendix B

this Part. 40 CFR

75.84(a).

For an EGU

for which the owner or operator of an EGU complying with this

Subpart

B by

means of Section 225.230

(a) (1) (A)

or 225.237

(a) (1) (A)

or using

electrical output to

determine the allowable emissions of the EGU, records

the daily and

monthly gross electrical

output

(GWh),

which must

kept in

the

file required

pursuant

Section

1.18(a)

of Appendix

B to

this Part 40 CFR

75.84

(a)

The owner or

operator of an EGU must

maintain records

of the following

data for each EGU:

Monthly emissions

of mercury

from the EGU.

For an EGU for

which the owner

or operator is

complying

means of

Section

225.230(b)

(d)

of this Subpart B, records

the monthly allowable

emissions of

mercury from the EGU.

The owner

or operator of an EGU that is participating in an Averaging

Demonstration

pursuant

Section 225.232 of this Subpart B must maintain

records

identifying all sources and EGU5 covered

the Demonstration for

each

month and,

within

days after the end of each calendar month, calculate and

record

the actual and allowable mercury emissions of the EGU for the month

and

the

applicable 12-month rolling period.

The

owner or operator of an EGU must maintain the following records

related to

quality assurance activities conducted for emissions monitoring

systems:

The results of quarterly assessments conducted pursuant to Section section

2.2 of Exhibit B to Appendix B to this Part Appendix B of 40 CFR 75,

incorporatcd by

refcrcncc in

Scction 225.140; and

Daily/weekly system integrity checks pursuant to Section

section

2.6 of

Exhibit B to Appendix B to this Part

Appendix B of 40 CFR 75, incorporated

reference

Section 225.l40 -

The owner or operator of an EGU must

maintain an electronic

copy

all

electronic submittals to the USEPA pursuant to

Section

1.18(f)

Appendix

B to

this Part.

40 CFR

75.84(f),

incorporated by reference in Section 225.140.

The owner or

operator

of an EGU must

retain all records required

by this

Section at the

source unless otherwise provided in the CAAPP permit issued

for

the source and must make

a copy

of any record available

the Agency upon

request.

Quarterly Reports. The owner or operator of a source with one or more

EGU5 must submit quarterly reports to the Agency as follows:

These reports must include the following information for operation of the

EGU5 during the quarter:

The total

operating

hours of each EGU and the

mercury

CEMS, as

also

reported in

accordance with

Appendix B to this

Part. 40 CFR 75, incorporated

re€rrrnrr- -in §r-rtinn 79 94fl

A discussion of any significant changes in the measures used to control

emissions

mercury from the EGU5 or the coal supply to the EGUs, including

changes in the source

of coal.

Summary

information on the performance of the mercury CEMS. When the

mercury

CEMS was

not inoperative, repaired, or adjusted, except for routine zero

and span

checks, this must be stated in the report.

If the CEMS downtime was more than 5.0 percent of the total

operating

time

for

the EGU: the date and time identifying each period during which the CEMS was

inoperative, except for routine zero and span checks; the nature of CEMS repairs

adjustments and a summary of quality assurance data consistent with Appendix

B to

this Part 40 CFR 7S, i.e., the dates and results of the Linearity

Tests

and

any RATA5 during the quarter; a listing of any days when a

required daily

calibration was not

performed;

and the date and duration

any

periods when

the

CEMS was out-of-control as addressed by Section 225.260.

Recertification

testing

that has been performed

for any CEMS and the

status

of the results.

The owner or operator must submit each quarterly report to the

Agency

within 45 days following the end of the calendar quarter covered by

the report.

Compliance Certification. The owner or operator of a source

with

one or

more EGU5

must submit to the Agency a compliance certification in

support

each quarterly report based on reasonable inquiry of those persons

with

primary

responsibility for ensuring that all of the EGU5’ emissions are

correctly

and

fully monitored. The certification must state:

That the

monitoring

data submitted

were recorded in accordance with the

applicable

requirements of this Section, Sections 225.240 through 225.270 and

Section

225.290

this Subpart B, and Appendix B to this Part

40 CFR 75,

including the

quality assurance procedures and specifications; and

For an EGU with add-on mercury emission controls, a flue gas

desulfurization system, a selective catalytic reduction system, or a compact

hybrid particulate collector system and for all hours where mercury data is

missing

that: arc cubctitutcd in accordancc with 40 CFR

75.34(a) (1): A)

That:

ALA)

The mercury add-on emission controls, flue gas

desulfurization

system,

selective catalytic reduction system, or compact

hybrid particulate collector

system was operating within the range of parameters listed in the

quality

assurance/quality control program pursuant to Exhibit

Appendix B

to this

Part Appcndix B to 40 CFR 75; or

• -i-)

With regard

to a

flue

gas

desulfurization system or

selective

catalytic reduction system, quality-assured S02 emission data recorded in

accordance with Appendix B

this Part 40 CFR 75 document that the flue gas

desulfurization system was operating properly, or quality-assured NGXNQ

emission data recorded in accordance with Appendix B to this Part

40 CFR 75

document that the selective catalytic reduction system was operating properly,

applicable; and

B-)-—

Thc zubotitutc data valuco do not cyztcmatically unu uLi[1Itc mcrcury

emissions.

Annual Certification of Compliance.

The owner or operator of a source with one or more EGUs subject to this

Subpart B must submit to the Agency an Annual Certification of Compliance with

this Subpart B no later than May 1 of each year and must address compliance for

the previous calendar year. Such certification must be submitted to the Agency,

Air Compliance

and

Enforccmcnt Section, and the Air Regional Field Office.

Annual Certifications of Compliance must indicate whether compliance

existed

for each EGU for each month in the year covered by the Certification and

it must

certify

that effect. In addition, for each EGU, the owner or

operator must provide the following appropriate data

as set

forth in subsections

(d) (2) (A)

through

(d) (2) (E)

of this Section, together with the data set forth in

subsection

(d)

(2)

(F)

of this Section:

If complying with this Subpart B by means of Section

225.230(a) (1) (A)

225.237

(a)

(1)

(A):

Actual emissions rate, in lb/GWh, for each 12-month rolling period ending

the year covered by the Certification;

ii)

Actual emissions, in ibs, and gross electrical output, in GWh, for each

12-month rolling period ending in the year covered by the Certification; and

iii) Actual emissions, in lbs, and gross electrical output, in GWh, for each

month in the year covered by the Certification and in the previous year.

If complying with this Subpart B by means of Section 225.230

(a) (1) (B)

225.237

(a) (1) (B):

Actual control efficiency for emissions for each 12-month

rolling

period

ending in the year covered by the Certification, expressed as a percent;

ii)

Actual emissions, in lbs, and mercury content in the

fuel fired in

such

EGU, in lbs, for each 12-month

rolling period ending in

the

year covered

by the

Certification;

and

iii)

Actual emissions, in lbs, and mercury content in the fuel fired in such

EGU, in lbs.

for each month in the year covered

the Certification and in the

year.

If complying with this Subpart B

means of Section

225.230(b):

Actual emissions and allowable emissions for each 12-month rolling period

ending in the year covered

the Certification; and

ii)

Actual emissions and allowable emissions, and which standard of compliance

the

owner or operator was utilizing for each month in the year covered

the

Certification and in the previous year.

If complying with this Subpart B by means of Section

225.230(d):

Actual emissions and allowable emissions for all EGUs

the source for

each

12-month rolling period ending in the year covered

the Certification;

and

ii)

Actual emissions

and allowable emissions,

and which standard of compliance

the owner or operator

was

utilizing for each month in the year covered by the

Certification and in the previous year.

If complying with this Subpart B by means of Section 225.232:

Actual emissions and allowable emissions for all EGUs at the source in an

Averaging Demonstration for each 12-month rolling period ending in the year

covered

the Certification; and

ii)

Actual emissions and allowable emissions, with the standard of compliance

the owner or operator was utilizing for each EGU at the source in an Averaging

Demonstration for each month for all EGU5 at the source in an Averaging

Demonstration in the year

covered

by the Certification and in the previous year.

Any deviations, data

substitutions,

or exceptions each month and

discussion of the

reasons for

such

deviations,

data substitutions, or

exceptions.

All Annual

Certifications of Compliance

required to be

submitted must

include the

following

certification

by a

responsible

official:

I certify under penalty

of law

that this document and all attachments were

prepared under my direction

or supervision

in accordance with a system designed

to assure that qualified

personnel properly

gather and

evaluate the information

submitted. Based

on my inquiry of the person

persons directly responsible

for gathering

the information, the information submitted is,

the

best of my

knowledge

and belief, true, accurate, and complete. I am aware that there

are

significant penalties for submitting false information, including the

possibility of fine and imprisonment for knowing violations.

The owner or operator of an EGU must submit its first Annual Certification

Compliance

address

calendar year 2009 or the calendar year in which

the

EGU

commences commercial operation, whichever is later. Notwithstanding

subsection

(d) (2)

of this Section, in the Annual Certifications of Compliance

that

are required to be submitted by May 1, 2010, and May 1, 2011, to address

calendar years 2009 and 2010, respectively, the owner or operator is not

required

provide

12-month rolling data for any period that ends before

June

30,

2010.

Deviation Reports. For each EGU, the owner or operator must promptly

notify the Agency of deviations from requirements of this Subpart B. At a

minimum, these notifications must

include

a description of such deviations

within 30 days

after discovery of

the

deviations, and

discussion of

the

possible

cause

of such deviations, any corrective actions, and any preventative

measures taken.

Quality Assurance RATA Reports. The owner or operator of an EGU must

submit to the Agency, Air Compliance and Enforcement Section, the quality

assurance RATA report for each EGU or group of EGUs monitored at a common stack

and each non-EGU pursuant to Section

1.16(b) (2) (B)

of Appendix B to this Part 40

CFR

75.82(b) (2)(ii),

incorporatcd by rcfcrcncc in Scction 225.l40,

within 45

days

after completing a quality assurance RATA.

(Source:

Amended

Ill.

Reg.

effecti

Section 225.291

Combined Pollutant

Standard: Purpose

The purpose

Sections

225.291

through 225.299

(hereinafter

referred

to as the

Combined

Pollutant

Standard

(“CPS’))

is to

allow an alternate

means of

compliance

with the

emissions

standards

for mercury in

Section

225.230(a)

for

specified EGU5

through permanent

shut-down,

installation

of ACI,

and

the

application of

pollution

control

technology for

NOx,

PM,

and

S02 emissions

that

also reduce

mercury emissions

as a co-benefit

and

establish

permanent

emissions

standards

for those

specified EGU5.

Unless

otherwise provided

for

the

CPS,

owners

and operators

those specified

EGU5 are not excused

from

compliance with

other applicable

requirements

Subparts B,

and

(Source:

Added

at 33

Ill. Reg.

effective

Section

225.292

Applicability

of the

Combined

Pollutant Standard

As an

alternative

to compliance

with the

emissions

standards of

Section

225.230(a),

the

owner

or operator

of specified

EGU5

in the CPS located

at Fisk,

Crawford,

Joliet,

Powerton, Waukegan,

and

Will

County

power plants

may

elect

for

all

of those EGU5

a group

to demonstrate

compliance

pursuant

to the

CPS,

which

establishes

control

requirements

and

emissions standards

for NOx, PM,

S02,

and mercury.

For this

purpose,

ownership

specified

EGU is determined

based

on direct

ownership,

by holding

a majority

interest in

a company that

owns

the

EGU

or EGU5,

the common

ownership

the company

that owns the

EGU,

whether

through

parent-subsidiary

relationship,

a sister corporation,

or as

an affiliated

corporation

with

the

same parent

corporation,

provided

that the

owner or

operator has

the right

or authority to

submit a

CAAPP application

behalf of

the EGU.

specified

EGU is a coal-fired

EGU listed

in Appendix A,

irrespective

any

subsequent

changes in

ownership of the

EGU or power plant,

the operator,

unit

designation, or

name of unit.

The owner

or operator

of each

of the specified

EGU5 electing

demonstrate

compliance

with

Section

225.230(a)

pursuant

the CPS must

submit

application

for

CAAPP

permit modification

the

Agency, as provided

for

Section

225.220,

that

includes the information

specified

in Section

225.293

that

clearly

states

the owner’s

or operator’s

election

demonstrate

compliance

with

Section

225.230(a)

pursuant

to the

CPS.

owner

or operator

of one or more

specified

EGUs elects to

demonstrate

compliance

with

Section

225.230(a)

pursuant

the CPS,

then

all

specified

EGU5

owned or

operated in

Illinois by

the owner or operator

as of

December 31,

2006,

as defined

subsection

(a)

of this Section,

are thereafter

subject to

the

standards

and

control requirements

of the

CPS. Such EGU5

are

referred

to as a

Combined

Pollutant Standard

(CPS)

group.

If an EGU

is subject

to the requirements

of this Section,

then

the

requirements

apply to all

owners

and operators

of the EGU, and

to the

CAIR

designated

representative

for

the EGU.

(Source:

Added at 33 Ill.

Reg.

effective

Section 225.293 Combined Pollutant Standard: Notice

of Intent

The owner or operator of one or more specified EGUs that

intends to comply

with

Section

225.230(a)

by means of the CPS must notify

the

Agency

of its

intention

on or before December 31, 2007. The following information

must accompany the

notification:

The identification of each EGU that will

complying

with Section

225.230(a)

pursuant to the CPS, with evidence that the owner

or operator has

identified all specified EGUs that it owned or operated

Illinois

as of

December 31, 2006, and which commenced commercial operation

on or

before

December 31, 2004;

If an EGU identified in subsection

(a)

of this Section

also owned

operated by a person different than the owner or operator submitting the notice

of intent, a demonstration that the submitter has the right

commit the

EGU or

authorization from the responsible official for the EGU submitting the

application; and

A summary of the current control devices installed and operating on

each

EGU and identification of the additional control devices that will likely

needed for each EGU to comply with emission control requirements

the

CPS.

(Source:

Added at 33 Ill. Reg.,

effective

Section 225.294

Combined

Pollutant Standard: Control Technology Requirements

and Emissions Standards for Mercury

Control

Technology

Requirements for Mercury.

For

each EGU in

CPS

group other than an EGU that is addressed by

subsection

(b)

of this Section, the owner

or operator of the EGU must install,

not already installed, and properly operate

and maintain, by the dates set

forth in subsection

(a) (2)

of this Section, ACI

equipment complying with

subsections (g),

(h),

(i),

(j),

and

(k)

this Section, as applicable.

By the following

dates,

for the EGUs listed

in subsections

(a) (2) (A)

and

(B), which include hot and cold side ESPs, the owner

or operator must install,

not already installed, and begin

operating ACI equipment or the Agency must

given written notice that

the

EGU will

be shut down on or before the

following dates:

Fisk 19, Crawford 7, Crawford 8, Waukegan 7, and

Waukegan 8 on or before

July 1, 2008; and

Powerton 5, Powerton 6, Will County 3, Will County 4, Joliet

Joliet

and

Joliet

on or before

July 1, 2009.

Notwithstanding subsection

(a)

of this Section,

the following EGUs are not

required to install ACI equipment because they will

be permanently

shut

down, as

addressed by Section 225.297,

the date specified:

EGUs

that

are required

to permanently shut down:

before December

31, 2007, Waukegan 6; and

On or before

December

31, 2010,

Will

County 1 and

Will County 2.

Any other

specified

EGU that

is permanently

shut

down

December

31,

2010.

Beginning on

January

2015, and continuing thereafter, and measured on

rolling 12-month

basis

(the

initial period

January 1, 2015, through December

31, 2015, and,

then, for every 12-month period

thereafter),

each specified EGU,

except Will County 3,

shall achieve one of the following emissions standards:

An emissions

standard of

0.0080

lbs mercury/GWh gross electrical

output;

A minimum 90

percent reduction of input mercury.

Beginning

on January 1, 2016, and continuing thereafter, Will County

shall achieve

the mercury emissions standards of subsection

(C)

of this Section

measured on a

rolling 12-month basis

(the

initial period is January 1, 2016,

through

December 31, 2016, and, then, for every 12-month period

thereafter).

Compliance

with Emission Standards

At any

time prior to the dates required for compliance in subsections

(c)

and

(d)

this Section, the owner or operator of

specified EGU, upon notice

to the Agency,

may elect to comply with the emissions standards of subsection

(c)

this Section measured on either:

rolling 12-month basis, or;

semi-annual calendar basis pursuant to the emissions

testing requirements

Section

225.239(c), (d) , (e) , (f) (1)

and

(2), (h) (2),

and

(i) (3)

and

(4)

this Subpart until June 30, 2012.

Once an EGU is subject to the mercury emissions

standards

of subsection

(c)

of this Section, it shall

not

be subject to

the requirements of

subsections

(g),

(h),

(i),

(j)

and

(k)

of this Section.

Compliance with the

mercury emissions standards or reduction requirement

of this Section must be calculated

in accordance with Section

225.230(a)

(b)

For each EGU

for which injection of halogenated activated carbon is

required by

subsection

(a) (1)

of this Section, the owner or operator of the EGU

must inject

halogenated activated carbon in an optimum manner, which, except as

provided

in subsection

(h)

of this Section, is defined as all of the following:

The use of an injection system for effective

absorption

mercury,

considering the

configuration

of the EGU and its

ductwork;

The injection of

halogenated activated carbon manufactured

Alstom,

Norit, or Sorbent

Technologies, or Calgon

Carbons

FLUEPAC MC Plus, or the

injection of

any other halogenated activated carbon or sorbent that the owner or

operator of

the EGU has demonstrated to have similar or better effectiveness for

control of

mercury emissions; and

The injection of sorbent at the following minimum rates, as applicable:

For an EGU

firing subbituminous coal,

5.0

lbs per million actual cubic

feet or, for any

cyclone-fired EGU that will install

scrubber and baghouse

December 31, 2012,

and which already meets an emission rate of 0.020

mercury/GWh gross

electrical output or at least 75 percent reduction of input

mercury, 2.5 lbs

per million actual cubic

feet;

For an EGU

firing bituminous coal, 10.0 lbs per million actual cubic feet

or, for any

cyclone-fired EGU that will install

scrubber and baghouse by

December 31,

2012, and which already meets an emission rate of 0.020 lb

mercury/GWh

gross electrical output or at least 75 percent reduction of input

mercury, 5.0 lbs

per million actual cubic

feet;

For

an EGU firing a blend of subbituminous and bituminous coal, a rate

that

is the weighted average of the rates specified in subsections (g)

(3) (A)

and

(B),

based

on the blend of coal being fired; or

A rate or rates set lower by the Agency, in writing, than the rate

specified in any of subsection (g)

(3)

(A), (B),

(C)

of this Section on a unit-

specific basis, provided that the owner or operator of the EGU has demonstrated

that

such rate or rates are needed so that carbon injection will not increase

particulate matter emissions or opacity so as to threaten noncompliance

with

applicable requirements for particulate matter or opacity.

For purposes of subsection (g)

(3)

of this Section,

the

flue gas

flow

rate

must be

determined for the point sorbent injection; provided that this flow rate

may be

assumed to be identical to the stack flow rate if the gas temperatures at

the

point of injection and the stack are normally within l00 F, or the

flue

gas

flow rate may otherwise be calculated from the stack flow rate, corrected for

the

difference in gas temperatures.

The owner or operator of an EGU that seeks to operate an EGU with an

activated carbon injection rate or rates that are set on a unit-specific basis

pursuant

to subsection (g)

(3) (D)

of this Section must

submit

application

the

Agency proposing such rate or rates, and must meet the requirements of

subsections

(h) (1)

and

(h) (2)

of this Section, subject to the limitations of

subsections

(h) (3)

and

(h) (4)

of this

Section:

The

application must

submitted

an application for

new or revised

federally

enforceable operation permit for the EGU, and it must include a

summary of

relevant mercury emissions data for the EGU, the unit-specific

injection rate

or rates that are proposed, and detailed information to support

the proposed

injection rate or rates; and

This application must be submitted no later than the date that activated

carbon must first be injected. For example, the owner or operator of an EGU

that

must inject activated carbon pursuant to subsection

(a) (1)

of this Section

must

apply for unit-specific injection rate or rates by July 1, 2008.

Thereafter, the owner or operator may supplement its application; and

Any decision of the Agency denying a permit or granting a permit with

conditions that set a lower injection rate or rates may be appealed to the Board

pursuant

Section 39 of the Act; and

The owner or operator of an EGU may operate at the

injection

rate

or rates

proposed in its

application until

a final

decision is

made

on the application

including a

final decision on any appeal

the Board.

During any evaluation of the effectiveness of

listed sorbent,

alternative sorbent, or other technique

control mercury emissions, the owner

operator of an EGU need not comply with the requirements of subsection (g) of

this Section for any system needed to carry out the evaluation, as further

provided

follows:

The owner or

operator

the

EGU must

conduct

the

evaluation in accordance

with a formal

evaluation

program submitted to the Agency at least 30 days

prior

commencement of

the

evaluation;

The duration

and

scope of

the evaluation may

not

exceed the duration and

scope reasonably needed to

complete

the

desired evaluation of the alternative

control techniques, as

initially addressed

the owner or operator in a support

document submitted

with the evaluation program;

and

The owner or

operator of the EGU must submit

report

the

Agency no

later than 30 days

after the conclusion of the evaluation that describes the

evaluation conducted

and which provides the results

the evaluation; and

If the

evaluation of alternative control techniques shows less effective

control of mercury

emissions from

the

EGU than was achieved with the principal

control techniques,

the owner or operator of the EGU must resume

use

of the

principal

control techniques. If

the

evaluation of the alternative control

technique shows

comparable effectiveness

the

principal control technique, the

owner or operator

of the EGU

may

either continue

to use

the alternative control

technique in a

manner that is

at least as

effective

the principal control

technique or it may

resume

use

of the principal control technique. If the

evaluation

of the alternative control technique shows more effective control of

mercury

emissions than the control technique, the owner or operator of the EGU

must

continue to use the alternative control technique in a manner that is more

effective than the principal control technique, so long as it continues to be

subject to

this Section.

In addition to complying with the applicable recordkeeping and

monitoring

requirements in Sections 225.240 through 225.290, the owner or

operator

of an

EGU

that elects to comply with Section

225.230(a)

by means of the CPS

must

also

comply with the following additional requirements:

For the first 36 months that injection of sorbent is required, it

must

maintain records of the usage of sorbent, the exhaust gas flow rate

from

the

EGU,

and the sorbent feed rate, in pounds per million actual cubic feet of

exhaust gas at the injection point, on a weekly average;

After the first 36 months that injection of sorbent is required, it must

monitor activated sorbent feed rate to the EGU, flue gas temperature at the

point of sorbent injection, and exhaust gas flow rate from

the EGU,

automatically recording this data and

the

sorbent

carbon

feed

rate, in pounds

per million actual

cubic feet

exhaust

gas at

the injection point, on an

hourly

average; and

blend of bituminous and subbituminous coal is fired in the EGU, it

must

keep records of the amount of each type of coal burned and the

required

injection rate for injection of activated carbon on a weekly basis.

addition

complying with

the

applicable reporting requirements in

Sections

225.240 through 225.290, the owner

operator

an EGU that elects

comply

with Section

225.230(a)

means of the CPS must also submit quarterly

reports

for

the recordkeeping and monitoring conducted pursuant to subsection

(j)

of this

Section.

As an alternative to the CEMS monitoring, recordkeeping, and reporting

requirements in Sections 225.240 through 225.290, the owner or operator of an

EGU may

elect to

comply with the emissions testing, monitoring, recordkeeping,

and reporting requirements in Section

225.239(c), (d), (e), (f) (1)

and

(2),

(h) (2), (i) (3)

and

(4),

and

(j)

(1)

(Source:

Added at 33 Iii.

Reg.

effective

Section

225.295

Trcatmcnt of Mercury Allowanccs

Combined

Pollutant

Standard:

Emissions Standards for NOx and S02

Any

mercury allowances allocated to the Agcncy

thc USEDA must be trcatcd as

follows:

a-)-

such allowanccs may

allocated

any owncr or opcrator of an ECU or

othcr sources of

mcrcury emissions into the atmosphcrc or dischargcs into thc

waters of the State.

b4-

The Agency must hold all

allowances

allocated by

the USEPA

the

State.

At the end of each calendar

year,

the Agency must instruct

the USEPA

retire

permanently all such

allowances.

Emissions

Standards for NOx and Reporting Requirements.

Beginning

with calendar year 2012 and continuing in each calendar year

thereafter,

the CPS group, which includes all specified EGUs that have not been

permanently shut

down

December 31 before the applicable calendar year, must

comply with a

CPS group average annual NOx emissions rate of no more than 0.11

lbs/mmBtu.

Beginning with ozone season control period 2012 and continuing in each

ozone

season control period (May 1 through September

30)

thereafter, the CPS

group,

which includes all specified EGU5 that have not been permanently shut

down by

December

31 before the applicable ozone season, must comply with a CPS

group average

ozone season NOx emissions rate of no more than 0.11 lbs/mmBtu.

The owner or operator of the specified EGU5 in the CPS group must

file,

not

later than one year after startup of any selective SNCR on such

EGU,

report with the Agency describing the NOx emissions reductions

that the

SNCR has

been able to achieve.

Emissions

Standards for S02. Beginning in calendar year 2013 and

continuing in

each calendar year thereafter, the CPS group must comply with the

applicable

CPS group average annual S02 emissions rate listed as follows:

year lbs/mmBtu

2013 0.44

2014 0.41

2015 0.28

2016 0.195

2017 0.15

2018 0.13

2019 0.11

Compliance

with the NOx and S02 emissions standards must be demonstrated

in accordance

with Sections 225.310, 225.410, and 225.510. The owner or

operator of the

specified EGUs must complete the demonstration of compliance

pursuant to

Section

225.298(c)

before March 1 of the following year for annual

standards and

before November 30 of the particular year for ozone

season

control

periods (May 1

through September

30)

standards,

which date a compliance

report must be

submitted

the

Agency.

The CPS

group average annual 502 emission rate, annual NOx

emission

rate

and ozone

season NOx emission rates shall be determined as

follows:

ERavg = S

(502± or NOxi

tons),’

(I-Ui)

i=l

Where:

ERavg =

average annual or

ozone season emission rate in lbs/mmBbtu of all

EGUs

in the CPS group.HIi

heat input for the annual or ozone control

period of each EGU, in

mmBtu.

502±

actual annual S02 tons of

each

EGU in the CPS group.

NOxi

actual annual or ozone

season

NOx tons of each EGU in the CPS group.

number

of EGU5

that are in the CPS

group i orouti=

each EGU

in the CPS group.

(Source: Amended at 33 111. Reg.

effective

Section

225.296 Combined Pollutant Standard:

Control Technology Requirements

for

NOx, S02, and PM Emissions

Control

Technology Requirements for NOx and S02.

On or

before December 31, 2013, the owner or operator must either

permanently shut down or install and have operational FGD

equipment on Waukegan

On or before December 31, 2014, the

owner or operator must either

permanently shut down or install and

have operational FGD equipment on Waukegan

On or before December 31, 2015, the

owner or operator must either

permanently shut down or install and have

operational FGD equipment on Fisk 19;

If Crawford 7 will be

operated after December 31, 2018, and not

permanently

shut down by

this

date,

the owner or operator must:

On or

before December 31, 2015, install and have operational SNCR or

equipment

capable of delivering essentially equivalent NOx reductions on

Crawford

7; and

On or before December 31, 2018, install and have operational FGD equipment

on Crawford 7;

If Crawford 8 will be operated after December 31, 2017 and not permanently

shut down

this date, the owner or operator must:

On or before December 31, 2015, install and have operational SNCR or

equipment capable of delivering essentially equivalent NOx emissions reductions

on Crawford 8; and

On or

before December 31, 2017,

install and have operational FGD

equipment

on Crawford 8.

Other

Control Technology

Requirements for SO2. Owners or operators of

specified EGU5 must

either

permanently shut down or install FGD equipment on

each specified EGU

(except

Joliet

5),

on or before December 31, 2018, unless an

earlier date is

specified in

subsection

(a)

of this Section.

Control

Technology

Requirements for PM. The owner or operator of the two

specified EGU5 listed in this subsection that are equipped with a hot-side ESP

must replace the hot-side ESP with a cold-side ESP, install an appropriately

designed fabric filter, or permanently shut down the EGU by the dates specified.

Hot-side ESP means an ESP on a coal-fired boiler that is installed before the

boiler’s air-preheater where the operating temperature is typically at least

5500

F, as distinguished from a cold-side ESP that is installed after the air

pre-heater where

the operating

temperature is typically no more than 350° F.

Waukegan 7 on or before December 31, 2013; and

Will County 3

on or before December

31, 2015.

Beginning on December 31, 2008, and annually thereafter

up to

and

including

December 31, 2015, the owner or operator of the Fisk power plant must

submit in writing to the Agency

report on any technology or equipment designed

affect air quality that has been considered or explored for the Fisk power

plant in the preceding 12 months. This report will not obligate the owner or

operator

install any equipment described in the report.

Notwithstanding 35 Ill. Adm. Code

201.146(hhh),

until an EGU has complied

with the applicable requirements of subsections

225.296(a), (b),

and

(c),

the

owner or operator of the EGU must obtain a construction permit for any new or

modified

air pollution control equipment that it proposes

construct for

control of emissions of mercury, NOx, PM, or S02.

(Source:

Added at 33 Ill. Reg.

effective

Section

225.297 Combined Pollutant Standard: Permanent Shut Downs

The owner

operator of the following EGU5 must permanently shut down the

EGU by the dates

specified:

Waukegan

on or before December 31, 2007; and

Will County 1 and Will County 2 on or before December 31, 2010.

No later than 8 months before the date that a specified EGU will be

permanently shut down, the owner or operator must submit a report to the

Agency

that includes

description of the actions that have already been taken to

allow

the shutdown of the EGU and a description of the future actions that must be

accomplished

complete the shutdown of the EGU, with the anticipated schedule

for those actions and the anticipated date of permanent shutdown of the unit.

No later than six months before a specified EGU will be permanently shut

down, the owner or operator shall apply for revisions to the operating permits

for the EGU

include provisions that terminate the authorization to operate

the unit on that date.

If after applying for or obtaining a construction permit to install

required control equipment, the owner or operator decides

permanently shut

down a

Specified EGU rather than install the required control technology, the

owner

or operator must immediately notify the Agency in writing and thereafter

submit

the information required by subsections

(b)

and

(c)

of this Section.

Failure

permanently shut down a specified EGU by the required date

shall

considered separate violations of the applicable emissions standards

and control technology requirements of the CPS for NOx, PM, S02, and mercury.

(Source:

Added at 33

Ill. Reg.

effective

Section 225.298

Combined Pollutant Standard: Requirements for NOx and S02

Allowances

The following

requirements apply

the

owner, the operator, and the

designated

representative

with

respect

to S02 and NOx

allowances:

The owner, operator, and designated representative of

specified EGUs

in a

CPS group is permitted to

sell,

trade, or transfer S02 and

NOx emissions

allowances of any

vintage owned, allocated

to,

earned by

the specified EGU5

(the

“CPS al1owances’) to

its affiliated Homer City, Pennsylvania, generating

station for as

long

the Homer City Station needs the CPS allowances for

compliance.

When and if the Homer City Station no longer requires all of the CPS

allowances, the owner, operator, or designated representative of specified EGU5

in a

CPS group may sell any and all remaining CPS allowances, without

restriction, to any person or entity located anywhere, except that the owner or

operator may not directly sell, trade, or transfer CPS allowances to a unit

located in Ohio, Indiana, Illinois, Wisconsin, Michigan, Kentucky, Missouri,

Iowa, Minnesota, or Texas.

In no

event

shall this

subsection

(a)

require or be

interpreted

require

any

restriction whatsoever on the sale,

trade,

or exchange of the CPS allowances

by persons

or entities who have acquired

the

CPS allowances from the owner,

operator, or designated

representative

of specified EGU5 in a CPS

group.

The

owner, operator, and designated representative

EGU5 in

specified

CPS group

is prohibited from purchasing

or using

S02 and NOx allowances for

the

purposes of meeting the S02 and NOx emissions standards

set

forth in Section

225.295.

Before March 1, 2010, and continuing

each year thereafter, the designated

representative of

the EGUs

in a

CPS

group must submit a report to the Agency

that demonstrates compliance with the requirements of this Section for the

previous calendar year and ozone season control period (May 1 through September

30),

and includes identification of any NOx or S02 allowances that have been

used

for compliance with any NOx or 502 trading programs, and any NOx or S02

allowances that were sold, gifted, used, exchanged, or traded. A final report

must be submitted to the Agency by August 31 of each year, providing either

verification that

the

actions

described

the initial report have taken place,

or, if such actions

have not taken

place, an explanation of the changes that

have occurred and

the reasons for

such changes.

(Source:

Added

at 33

Ill. Reg.

effective

Section

225.299

Combined Pollutant Standard: Clean Air Act Requirements

The

S02 emissions rates

set

forth in the CPS shall

deemed

to be best

available

retrofit technology

)

(BART’

under the Visibility Protection

provisions of

the CAA

(42

USC

7491),

reasonably available control technology

(?!pCTTI)

and

reasonably available control measures (“RACM”) for achieving

fine

particulate

matter

(“PM2.5”)

requirements

under

NAAQS

in effect on

August

31,

2007, as

required

the CAA

(42

USC

7502).

The

Agency may use

the S02

and NOx

emissions

reductions required under the CPS in developing attainment

demonstrations

and demonstrating reasonable

further progress for

PM2.5

and 8

hour ozone

standards,

required under

the CAA. Furthermore, in

developing

rules,

regulations, or

State

Implementation Plans

designed to

comply with

PM2.5

and 8 hour

ozone NAAQS, the Agency, taking into account all emission reduction

efforts and

other appropriate factors, will

use best

efforts

seek

S02 and NOx

emissions rates

from other EGU5 that are equal

less

than the rates

applicable to

the

CPS group and will seek S02 and NOx reductions from other

sources

before seeking additional emissions reductions from any EGU in the

CPS

group.

(Source:

Added at 33 Ill. Reg.

, effective

SUBPART F:

COMBINED POLLUTANT

STANDARDS

Section 225.600

Purpose (Repealed)

22fl(n - thr nmr1

opcrator of specif±

Waukcgan,

“-“

County

power

p’

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group

acmonstrauc

comp±iance

pursuant

The purpooc of this Subpart F is

allow an altcrnatc mcans of compliance

with

the

emissions standards for mercury in Section

225.230(a)

for specified

ECUs

through permanent shut down, installation of CI, and the application of

pollution control technology for NOx, PM, and S02 emissions that also reduce

mercury emissions as a co benefit and to establish permanent emissions standards

for those

specified

ECUs. Unless otherwise provided for in this Subpart F,

owners

and operators of those specified ECU5

are

not

excused from compliance

with other applicable requirements of Subparts B,

P. and E.

(Source: Repealed

at 33

Ill. Reg.

effective

Section 225.605 Applicability (Repealed)

a-)-

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(Source:

Amended at 33

Ill. Reg.

effective

Section

225.APPENDIX B

Continuous Emission Monitoring Systems for Mercury

Section 1.1

Applicability

The

provisions of this Appendix apply to sources subject to 35 Ill Admin.

Adm.

Code

Part 225 mercury (Hg) mass emission reduction program.

Section

1.2 General opcrating rcquircmcntzOoeratin Reauirements

Primary Equipment Performance Requirements. The

owner or operator must

ensure that each continuous mercury emission monitoring

system required

by this

Appendix

meets the equipment, -

installation- and performance specifications in

Exhibit

this Appendix and is maintained according to the quality assurance

and quality

control procedures in Exhibit B to this Appendix.

Heat Input

Rate Measurement Requirement. The owner or operator must

determine and

record the heat input rate, in units of mmBtu/hr, to each affected

unit for every

hour or part of an hour any fuel is combusted following the

procedures

in Exhibit

to this Appendix.

Primary

cquipmcnt

hourly

opcrating rcquircmcntcEiment

Hourly

Ooeratin

Reouirements. The owner or

operator must ensure that all continuous mercury

emission

monitoring

systems

required

this Appendix are in operation and

monitoring unit

emissions

all times that the affected unit combusts any fuel

except

during periods of calibration, quality assurance, or preventive

maintenance, performed pursuant to Section 1.5 of this Appendix and

Exhibit

B to

this

Appendix, periods of repair, periods of backups of data from the data

acquisition and handling system, or recertification performed pursuant to

Section

1.4 of this Appendix.

The owner or operator must ensure that each continuous emission

monitoring system is capable of completing a minimum of one cycle of operation

(sampling,

analyzing-

7-and

data

recording) for each

successive

15-minute

interval. The owner or operator must reduce all volumetric flow, C02

concentration,

02 concentration-

4-and mercury concentration data collected by the

monitors

hourly averages. Hourly averages must be computed using at least one

data

point in each

fiftccnl5

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

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

Section

1.5 of

this Appendix and Exhibit

B to this Appendix, or backups

data

from

the

data

acquisition and handling

system, or recertification,

pursuant

Section

1.4

eof

this Appendix. The

owner or operator must use all valid

measurements or data

points collected

during an hour to calculate the

hourly

averages. All data

points collected

during an hour

must

be, to the

extent

practicable, evenly spaced over the hour.

Failure of a C02 or 02 emissions concentration monitor, mercury

concentration

monitor, flow monitor-- or a moisture monitor to acquire the

minimum number of data points for calculation of an hourly average in

paragraphsubsection

of this Section must result in the failure to obtain

valid hour of data and the loss of such component data for the entire hour.

For

moisture monitoring system consisting of one or more oxygen analyzers

capable of measuring 02 on a wet-basis and a dry-basis, an hourly average

percent moisture value is valid only if the minimum number of data points is

acquired for both the wet-and dry-basis measurements.

Optional

backup monitor rcquircmcntoBackuo Monitor Reauirements.

the owner or operator chooses to use two or more continuous mercury 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

common stack, then

the

owner or operator must designate one monitoring system

the primary

monitoring system, and must record this information in the monitoring plan,

provided for in Section 1.10 of this Appendix. The owner or operator must

designate the other monitoring

cystcm(c) systems

as backup monitoring

zyctcm(z)

systems

in the monitoring plan. The backup monitoring

zystcm(s)

systems

must be

designated as redundant backup monitoring

syztcm(z)svstems,

non-

redundant backup monitoring

zyztcm(s)svstems,

or reference method backup

cyctcm(z)svstems,

as described in Section

1.4(d)

of this Appendix. When the

certified

primary monitoring

system is operating and not

out-of-control

defined in

Section

1.7 of this Appendix, only

data

from the certified primary

monitoring

system must be reported

valid, quality-assured

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 Section

1.7

this Appendix

(or

in the applicable reference method in appendix A of 40

CFR

60,

incorporated by reference in Section

225.140)

and when the certified

primary monitoring system is not operating

(or

is operating but out-of-control)

particular monitor may be designated both as a certified primary monitor for

one

unit and as a certified redundant backup monitor for another unit.

Minimum mcaourcmcnt capability

rcquircmcntMeasurement Canabilitv

Reauirement.

The owner or operator must ensure that each continuous emission

monitoring system is capable of accurately measuring, recording-

7and reporting

data,

and must not incur an exceedance of the full scale range, except as

provided in Section 2.1.2.3 of Exhibit A

this Appendix.

Minimum

rccording and rccordkccping rcquircmcntzRecordin

and

Recordkeeoina

Reauirements.

The owner or operator must record and the designated

representative must report the

hourly, daily, quarterly-

7and annual information

collected

under the requirements

as specified in subpart G of 40 CFR 75,

incorporated

reference in Section 225.140, and Section

1.11 through

1.13

this Appendix.

Section 1.3 Special

cxccptcd

oorbcnt

trap monitoring methodologyProvisions for Measuring Mercury

Mass Emissions Using the Excented Sorbent

Trao

Monitoring Methodoloav

For an affected coal-fired unit

under

35 Ill Admin.

Adm.

Code Part 225225. if

the owner or operator elects to use sorbent trap monitoring systems

(as

defined

in Section

225.130)

to quantify mass emissions, the guidelines in

paragraphosubsections

(a)

through

(1)

of this Section must be followed for this

excepted monitoring methodology:

For each sorbent trap monitoring system

(whether

primary or redundant

backup), the use of paired sorbent traps, as described in Exhibit U to this

Appendix, is required;

Each sorbent trap must have

main section,

backup

section-r

and

a third

eet-ioRtiQn to

allow spiking with a calibration

gas of

known mercury

concentration,

described in Exhibit ID

this

Appendix;

A certified flow monitoring

system is

required;

Correction for stack gas moisture content is required, and in some

cases,

certified 02 or C02 monitoring system is required

(see

Section

1.15(a)

(4));

Each sorbent

trap

monitoring system must be installed and operated in

accordance

with Exhibit U

to this Appendix. The automated data acquisition and

handling

system must ensure that the sampling

rate is proportional to

the

stack

gas

volumetric flow rate.

At the

beginning and end of

each

sample

collection period, and at

least

once in each

unit operating hour during the

collection period, the gas

flow

meter

reading must

recorded.

After

each sample collection

period, the mass of mercury adsorbed in each

sorbent trap

(in

all three

sections)

must be determined according to the

applicable

procedures in Exhibit

U to

this

Appendix.

The hourly mercury mass emissions

for each

collection

period are

determined using the results of the analyses in conjunction with contemporaneous

hourly

data

recorded

a certified stack flow monitor, corrected for the

stack

gas

moisture content. For each pair of sorbent traps analyzed, the average

the

-t-we2.

mercury concentrations must

used for reporting purposes under

Section

1.18(f)

-eQi

this Appendix. Notwithstanding this requirement, if,

due to

circumstances beyond the control of the owner or operator, one of the paired

traps is accidentally lost,

damaged-r

or broken and cannot

analyzed, the

results of the analysis of the other trap may be used for reporting purposes,

provided

that the other trap has met all of the applicable quality-assurance

requirements

of this

partPart.

All

unit operating hours for which valid

mercury concentration data are

obtained with the primary sorbent trap monitoring

system

(as

verified

using the

quality assurance procedures in Exhibit U

to this Appendix) must be reported in

the

electronic quarterly report under

Section

1.18(f)

-o this Appendix. For

hours in

which

data

from

the

primary

monitoring system are invalid, the owner or

operator may, in accordance with

Section

1.4(d)

-e this Appendix, report valid

mercury concentration

data

from: A certified

redundant backup CEMS or sorbent

trap

monitoring system;

certified non-redundant

backup CEMS or sorbent trap

monitoring

system; or an

applicable reference

method under Section 1.6

-o.i

this

Appendix.

Initial certification requirements and

additional quality-assurance

requirements

for

the sorbent trap monitoring

systems are found in Section

1.4(c) (7),

Section

6.5.6

of Exhibit A

to this Appendix, in Sections 1.3 and

2.3 of Exhibit B to this

Appendix, and

in Exhibit D to this Appendix.

During each RATA of

sorbent trap

monitoring system, the type of sorbent

material

used by

the traps must be the

same as for daily operation of the

monitoring

system.

A new pair of traps must

be used for each RATA run. However,

the size

the

traps

used

for the RATA

may be smaller than the traps used for

daily operation

of the system.

Whenever the type of sorbent material

used by

the

traps is changed, the

owner or operator must conduct a diagnostic RATA of the modified sorbent

trap

monitoring system within 720 unit or stack operating hours after the

date and

hour when the new sorbent material is first

used.

If the diagnostic RATA is

passed, data from the modified system may be reported

quality-assured,

back

the

date and hour when the new sorbent material was first used. If the RATA

is failed, all data from the modified system must

invalidated, back

to the

date

and hour when the new sorbent material was first

used,

and

data

from

the

system must remain invalid until a subsequent RATA is

passed.

If the required

RATA is not completed within 720 unit or stack operating hours, but is

passed on

the first attempt, Data

data

from the modified

system

must

invalidated

beginning with the first operating hour after the 720 unit or stack operating

hour window expires and data from the

system

must remain invalid until

the date

and

hour of completion of the successful RATA.

Section 1.4 Initial

certification

anu reccLLLiaLion

and

Recertification Procedures

Initial

certification approval proccaccertification Aooroval Process.

The

owner or operator must ensure that each continuous mercury emission monitoring

system required by this Appendix meets the initial certification requirements

this Section.

In addition, whenever

the owner or operator installs a continuous

mercury

emission monitoring

system

order to meet the requirements of

ScctionsSection

1.3 of this Appendix and 40 CFR Scctionzsections

75.11 through

75.14 and 75.16 through 75.18, incorporated

reference in Section 225.140,

where no continuous emission monitoring system was previously installed,

initial

certification is required.

Notification of initial certification

test dates.

The owner

or operator or

designated representative must submit

written notice

of the dates of initial

ef4ea-4-oncetifi.cation

testing

the unit

as specified in 40 CFR

75.61(a)

(1),

incorporated

reference in Section 225.140.

Certification application. The owner or operator must apply for

certification of each continuous mercury emission monitoring system. The

owner

operator must submit the certification application in accordance with 40

CFR

75.60, incorporated by reference in Section 225.140, and each complete

certification application must include the information specified in 40 CFR

75.63, incorporated by reference in Section 225.140.

Provisional approval

of certification

(or recertification)

applications.

Upon the successful completion

of the

required

certification

(or

recertification)

procedures of

this

Section,

each

continuous mercury

emission

monitoring system must be

deemed

provisionally certified (or recertified) for

use

for

period not to

exceed

120 days following receipt

the

Agency of

the

complete certification

(or

recertification) application under

(a)

(4)

this Section. Data measured and recorded

by a

provisionally certified

(or

recertified)

continuous emission monitoring system,

operated in accordance

with the

requirements of Exhibit B to this Appendix, will

be considered valid

quality-assured

data

(retroactive

to the date and time of

provisional

certification or recertification),

provided that the Agency does not

invalidate the

provisional certification

(or

recertification)

by issuing a

notice of

disapproval within 120

days of receipt by the Agency of the complete

certification

(or

recertification)

application. Note that when the conditional

data validation

procedures of

paragraphsubsection

(b) (3)

of this Section are

used for the initial

certification

(or recertification)

of a continuous

emissions

monitoring

system, the

date and time of provisional certification

(or

recertification)

of the CEMS may be earlier than the date and time of completion

of the required certification

(or recertification)

tests.

Certification

(or recertification)

application formal approval process.

The

AgcncywillAaencv

will issue a notice of approval or disapproval of the

certification

(or recertification)

application to the owner or operator within

120

days

e-after receipt of the complete certification

(or recertification)

application. In the event the Agency does not issue such a notice within 120

days e-after receipt, each continuous emission monitoring system

whichthat

meets

the performance

requirements

of this

partPart

and is included in the

certification

(or

recertification)

application will be deemed certified

(or

recertified)

for

use

under

Code

Part

225.

Approval notice. If the certification

(or recertification)

application is

complete

and shows that each continuous emission monitoring

system meets the

performance

requirements of this partPart, then the

Agency

will

issue a notice

approval of the certification

(or

recertification)

application

within

120

days

oafter receipt.

Incomplete application notice. A certification

(or

recertification)

application will be considered complete when all of the applicable information

required to be

submitted in 40 CFR 75.63, incorporated

reference in

Section

225.140,

has been received

the Agency. If the certification

(or

recertification)

application is not complete, then the Agency will issue

notice of incompleteness that provides

reasonable timeframe for the designated

representative to submit the additional information required

complete the

certification

(or recertification)

application. If the designated representative

has

not complied with the notice of incompleteness

by a

specified

due date, then

the

Agency may issue a notice of disapproval specified under

paaaphuhatiQn

(a)

(4) (C)

of this Section. The 120-day review period will not begin prior

receipt of a complete application.

Disapproval

notice. If the certification

(or recertification)

application

shows that any

continuous

emission

monitoring system does not meet the

performance

requirements

of this

partPart,

or if the certification

(or

recertification)

application is incomplete and the requirement for disapproval

under

paragraphsubsection

(a) (4) (B)

of this Section has been met, the Agency

must issue a

written notice

disapproval

of the certification

(or

recertification)

application within 120

days

e&after receipt.

By issuing the

notice of disapproval, the provisional certification

(or

recertification)

invalidated by the Agency, and the data measured and recorded

each

uncertified continuous emission or opacity monitoring system must not

considered valid quality-assured data as follows: from the hour of the

probationary calibration

error

test

that began the initial certification

(or

recertification)

test

period

(if

the conditional

data

validation procedures of

paragraphsubsection

(b)

(3)

of this Section were

used to

retrospectively validate

data);

or from the date

and time of completion of

the

invalid certification or

recertification tests (if

the conditional

data

validation procedures of

paragraphsubsection

(b) (3)

of this Section were not

used)

. The owner or operator

must follow the procedures

for

loss

of initial certification in

paragraphsubsection

(a) (5)

of this

Section

for each continuous

emission

opacity monitoring system

wh4-ehtli.a.t

is disapproved

for

initial certification.

For

each disapproved recertification, the owner or

operator

must

follow the

procedures

paragraphsubsection

(b) (5)

of this Section.

Procedures

for loss of certification. When the Agency issues a

notice of

disapproval of a

certification application or a notice of

disapproval of

certification

status

(as

specified in paa*aph

section (a)

(4) of this

Section),

then:

Until such time,

date-r

and

hour

the continuous mercury emission

monitoring system can be adjusted,

repaired- or replaced and certification tests

successfully completed

(or,

the conditional

data

validation procedures in

paragraphcsubsections

(b) (3)

(B)

through

(b) (3) (I)

of this Section are used,

until a

probationary calibration error test is passed following

corrective

actions in

accordance with paragraphsu.bsection

(b) (3) (B)

of this

Section),

the

owner or operator must

perform emissions testing pursuant to Section 225.239.

The designated

representative must submit

notification of certification

retest dates as

specified in Section

225.250

(a) (3)

(A)

and

new certification

application according to the procedures

in Section

225.250(a)

(3)(B); and

The owner or operator must

repeat all certification tests or other

requirements that were failed by

the continuous mercury emission monitoring

system, as

indicated in the Agency’s

notice of disapproval, no later than 30

unit

operating days after the date

of issuance of the notice of disapproval.

Recertification approval proccssAooroval

Process.

Whenever the

owner

operator makes a

replacement, modification-

7or change in a

certified continuous

mercury

emission monitoring system that may significantly affect

the ability of

the system to

accurately measure or record the gas

volumetric flow rate, mercury

concentration,

percent

moisture, or to meet the requirements

of Section 1.5 of

this

Appendix or Exhibit B

this Appendix, the owner or

operator must

recertify the

continuous mercury emission monitoring system,

according

the

procedures

in this

paragraph.suhsection.

Examples of changes wh-ehtha.t

require

recertification include: replacement of the analyzer;

change in location or

orientation

of the sampling probe or site; and complete

replacement of an

existing

continuous mercury emission

monitoring system. The owner or operator

must

also recertify the continuous

emission monitoring

systems for a unit that

has

recommenced commercial operation

following

period of long-term cold

storage

defined

Section 225.130.

Any change

a flow monitor or gas

monitoring system

for

which a RATA

is not necessary will not be considered a

recertification

event.

In addition,

changing the polynomial coefficients or K

factor(s)factors

a flow

monitor will require

3-load RATA, but is not

considered to be a

recertification event; however, records of the

polynomial

coefficients

or K factor(z)

factors

currently

in use must be

maintained on-site

in a

format suitable for inspection. Changing the coefficient

or K

factor(c)factors

of a moisture monitoring system will

require

RATA,

but

is not

considered

to be a recertification event; however,

records of the coefficient or

factor(c)

factors

currently

in use by

the

moisture

monitoring system must be

maintained on-site

format suitable for inspection. In such cases,

any other

tests that are

necessary

ensure continued proper operation of the

monitoring

system (e.g., 3-load

flow RATAs following changes to flow monitor

polynomial

coefficients,

linearity checks, calibration error tests, DAHS

verifications,

etc.)

must be

performed as diagnostic tests, rather than as

recertification

tests.

The

data

validation procedures in paapIthectiQn

(b) (3)

this

Section

must

applied to RATA5 associated with changes to flow or

moisture

monitor coefficients, and to linearity checks, 7-day

calibration error

tests-r

and

cycle time tests-;- when these are required as diagnostic tests.

When the

data

validation procedures of

paragraphsubsection

(b) (3)

this Section are applied

in this

manner, replace the word ‘recertification” with the word “diagnostic--’L

Tests required. For all

recertification testing, the owner or operator

must

complete all initial

certification

tests

in paragraphsubsection

Cc)

of this

Section that are applicable to

the

monitoring system, except

otherwise

approved

the Agency. For

diagnostic

testing after

changing the flow rate

monitor polynomial coefficients, the owner or

operator must complete a 3-level

RATA.

For diagnostic testing after changing the

K factor or mathematical

algorithm of

moisture monitoring system, the

owner or operator must complete

RATA.

Notification of

recertification

test dates.

The owner,

operator-r

designated

representative must

submit notice of testing

dates

for

recertification

under this

paragraphsubsection

specified in 40 CFR

75.61(a)

(1) (ii),

incorporated by

reference in Section 225.140, unless all of the

tests

paragraphsubsection

Cc)

this Section are required for

recertification, in which case the

owner or operator must provide notice in

accordance with the notice

provisions for initial certification testing in 40

CFR

75.61

(a) (1) (i),

incorporated by

reference in Section 225.140.

Recertification test

period requirements and data validation. The data

validation

provisions in

paragraphssubsections

(b) (3) (A)

through

(b) (3) (I)

this

Section will apply to

all mercury CEMS recertifications and diagnostic

testing.

The

provisions in paragraphcsubsections

Cb) (3) (B)

through

(b) (3) (I)

this Section may

also

applied

initial certifications

(see

Sections

6.2(a),

6.3.1(a), 6.3.2(a),

6.4(a)

and

6.5(f)

of Exhibit A to this

Appendix) and may

used to

supplement the linearity check and RATA data

validation procedures in

Sections

2.2.3(b)

and

2.3.2(b)

of Exhibit B to this

Appendix.

The

owner or operator must report emission data using a

reference method

or another

monitoring system that has been certified or

approved for

use

under

this partPart,

in the period extending from the hour of the

replacement,

modification--

or change made

to a

monitoring system that

triggers the need

perform

recertification testing, until either: the hour

successful completion

of all of

the required recertification tests; or the

hour in which a

probationary

calibration error test

(according

ag-aph

ectJn

Cb) (3) (B)

of this

Section)

is performed and passed,

following all necessary repairs,

adjustments-i-

or reprogramming of the

monitoring system. The first hour of

quality-assured data for the

recertified monitoring system must either be the

hour

after all recertification tests

have been completed or, if conditional data

validation is used, the first

quality-assured hour must

determined in

accordance with

paragraphcsubsections

(b) (3) (B)

through

(b) (3)

(I)

of this

Section.

Notwithstanding these requirements, if the replacement, modification-

change

requiring recertification of the CEMS is such that the historical data

stream is no

longer representative

(e.g.,

where the mercury

concentration

and

stack flow rate

change significantly after installation of a wet

scrubber),

the

owner or

operator must estimate the mercury emissions over that

time period

and

notify

the

Agency within 15 days ef-after the replacement,

modification-r

change requiring recertification of the CEMS.

Once the modification or change to the CEMS has been completed and all of

the associated repairs, component replacements, adjustments,

linearization-r

and

reprogramming of the CEMS

have

been completed,

probationary calibration error

test

is required

establish the beginning point of the recertification

test

period. In

this instance, the first successful calibration error

test

of the

monitoring system

following completion of all

necessary

repairs, component

replacements,

adjustments, linearization and reprogramming must

the

probationary

calibration error test. The probationary calibration error

test

must be passed before

any of the required recertification

tests

are commenced.

Beginning

with the hour of commencement

of a

recertification

test

period,

emission data

recorded

the mercury CEMS

are

considered

to be

conditionally

valid, contingent

upon the results of the subsequent recertification

tests.

Each

required recertification test must

completed no later than the

following

number of unit operating hours

(or

unit operating days) after the

probationary

calibration error test that initiates the test period:

For

linearity check and/or cycle time test, 168 consecutive unit

operating hours, as defined in 40 CFR 72.2, incorporated by reference in Section

225.140,

or, for CEMS installed on common stacks or bypass stacks, 168

consecutive stack operating hours, as defined in 40 CFR 72.2;

ii)

For

RATA

(whether

normal-load or multiple-load), 720 consecutive unit

operating hours, as defined in 40 CFR 72.2, incorporated by reference in Section

225.140, or, for CEMS installed on common stacks or bypass stacks, 720

consecutive stack operating hours, as defined in 40 CFR 72.2; and

iii)

For

7-day calibration error test, 21 consecutive unit operating days, as

defined

in 40 CFR 72.2, incorporated by reference in Section 225.140.

All

recertification

tests

must be

performed hands-off.

adjustments

the calibration

of the mercury CEMS, other than the routine calibration

adjustments

following daily calibration error

tests as

described in Section

2.1.3 of

Exhibit B

this Appendix, are permitted during the recertification

test period.

Routine

daily

calibration error

tests

must

performed throughout

the

recertification

test period,

in accordance with Section 2.1.1 of Exhibit

this

Appendix. The additional calibration error

test

requirements in

Section

2.1.3 of Exhibit

to this Appendix, must

also

apply

during the recertification

test

period.

If all of

the required recertification

tests

and required daily

calibration

error

tests

are successfully completed in succession with no

failures, and

if each

recertification test is

completed within the time period

specified in paagap.ihaectiQn

(b)

(3)

(0) (i) (u)-

7-or

(iii)

of this Section,

then all of

the conditionally

valid

emission

data

recorded

the mercury CEMS

will be

considered quality assured, from the hour of commencement of the

recertification test period until the hour of completion of the required

tcst(z)tests.

If a

required recertification

test is

failed or aborted

due to a

problem

with the

mercury CEMS,

or if a

daily calibration error

test

is failed during

recertification

test period,

data

validation must

done

follows:

any

required recertification test is failed, it must be repeated. If

any

recertification test other than a 7-day calibration error test is failed or

aborted due to a

problem with the mercury CEMS, the original recertification

test

period is

ended, and a new recertification test period must be commenced

with a

probationary calibration error

test.

The tests that are required in the

new

recertification test period will include any tests that were required for

the

initial recertification event whichthat were not successfully completed and

any

recertification or diagnostic tests that are required as a result of changes

made to the

monitoring system

correct the problems that caused the failure of

the

recertification

test.

For

2- or 3-load flow RATA, if the relative accuracy

test is passed at

one or more load levels, but is failed

a subsequent load

level,

provided that the problem that caused the RATA failure is corrected

without

re-linearizing the instrument, the length of the new recertification

test period

must

equal to the number of unit operating hours remaining in the

original

recertification test period, as of the hour of failure of the RATA.

However, if re-linearization of the flow monitor is required after a flow RATA

failed

at a

particular load level, then a subsequent 3-load RATA is required,

and

the new recertification test period must be 720 consecutive unit

(or stack)

operating hours. The new recertification test sequence must not be

commenced

until all necessary maintenance activities,

adjustments,

lincarizptioric,linearization

and reprogramming of the CEMS have

been completed;

ii)

If a

linearity check, RATA-

7 or cycle time test is failed or aborted due to

a problem

with the mercury CEMS, all conditionally valid emission data recorded

by the CEMS

are invalidated, from the hour of commencement of the

recertification test period to the hour in which the test is failed or aborted,

except

for the case in which a multiple-load flow RATA is passed at one

load

levels, failed at a subsequent load level, and the problem that caused the

RATA failure is corrected without re-linearizing the instrument.

In that

case,

data

invalidation will be prospective, from the hour of failure

of the RATA

until the commencement of the new recertification test period. Data

from

the

CEMS remain invalid until the hour in

which

a new

recertification

test

period

commenced, following corrective action, and a probationary

calibration error

test

is passed, at which time the conditionally valid status of

emission

data

from the CEMS begins again;

iii)

If a 7-day

calibration error

test

is failed within the recertification

test

period,

previously-recorded conditionally valid emission

data

from the

mercury CEMS are not invalidated. The

conditionally valid

data status

unaffected, unless the calibration

error

the

day

the

failed

7-day

calibration error test exceeds twice

the performance specification in Section

of Exhibit A to this Appendix, as

described in

apithection (b) (3) (G)

(iv)

this Section.

iv)

If a

daily calibration error test is failed during a

recertification

test

period

(i.e.,

the results of the test exceed twice the performance

specification

Section

of Exhibit A to this Appendix), the CEMS is

out-of-control

as of

the hour in which the calibration error test is failed. Emission data

from

the

CEMS will be invalidated prospectively from the hour of the failed

calibration

error test until the hour of completion of a subsequent

successful calibration

error test

following

corrective action, at

which

time the

conditionally valid

status of data

from

the

monitoring

system

resumes. Failure

perform a required

daily calibration

error

test during a

recertification

test

period will also

cause data

from the

CEMS to be

invalidated prospectively, from the hour in which

the

calibration error

test

was

due

until the hour of completion of a subsequent

successful

calibration error

test.

Whenever

calibration error

test

is failed

or missed during a

recertification

test

period, no further recertification tests

must be performed until the required subsequent calibration error test has been

passed, re-establishing the conditionally valid status of data from the

monitoring system. If a calibration error test failure occurs while a linearity

check or RATA is still in progress, the linearity check or RATA must be re

started.

Trial

gas

injections and trial RATA runs are permissible during the

recertification test period, prior to commencing a linearity check or RATA, for

the purpose of

optimizing

the

performance of the CEMS. The results of such gas

injections and trial runs will not affect the status of previously-recorded

conditionally valid data or result in termination of the recertification test

period, provided that they meet the following specifications and conditions: for

gas

injections, the stable, ending monitor response is within -1-—5 percent or

within

ppm of the tag value of the reference gas; for RATA trial runs, the

average reference method reading and the average CEMS reading for the run differ

by no

more than -f--—lO% of the average reference method value or +—l5

ppm, or

—l.56

H20-

7-or ÷—O.O2

lb/mmBtu from the average reference method value, as

applicable; no adjustments to the calibration of the CEMS are made following the

trial

injcction(c)iniections

run(s)runs,

other than the adjustments permitted

under Section 2.1.3 of Exhibit B to this Appendix and the CEMS is not repaired,

re-linearized or reprogrammed (e.g., changing flow monitor polynomial

coefficients, linearity

constants-r

K-factors)

after the trial

injcction(c) iniections

run(o)runs.

vi)

If the results of any trial gas

injcction(c)iniections

or RATA

run(z)runs

are outside the limits in

paragraphcsubsection

(b) (3) (G) Cv)

of this Section or

if the CEMS is repaired,

re-linearized-r

or reprogrammed after the trial

injcction(c)iniections

run(z)runs,

the trial

injcction(c)iniections

run(z)runs

will be counted as a failed linearity check or RATA attempt. If this

occurs, follow the procedures pertaining to failed and aborted recertification

tests

paragraphosubsections

(b) (3) (G) Ci)

and

(b) (3) (C) (ii)

of this Section.

If any required recertification test is not completed within its allotted

time period, data

validation

must be

done

follows.

For a

late linearity

test,

RATA-

7-or cycle

time

test

that is

passed

on the first attempt,

data

from the

monitoring

system will

invalidated from the hour of expiration of the

recertification test period until the hour of completion of the late test. For

late 7-day

calibration error

test,

whether or not it is passed on the first

attempt, data

from the monitoring system will also

invalidated from the hour

expiration of the recertification test period until the hour of completion of

the late test.

For a late linearity test,

RATA-r

or cycle time test that is

failed on the first attempt or aborted on the first attempt due to a problem

with the monitor, all conditionally valid data from the monitoring system will

considered invalid back to the hour of the first probationary calibration

error

test

h4-e1that initiated the recertification test period. Data from the

monitoring system will remain invalid until the hour of successful completion of

the

late recertification test and any additional recertification or diagnostic

tests

that are required as a result of changes made

the monitoring system

correct problems that caused failure of the late recertification test.

If any required recertification test of a monitoring system has not been

completed by the end of a calendar quarter and if data contained in the

quarterly

report

are

conditionally valid pending the results of

tczt(z)tests

completed in a subsequent quarter, the owner or operator must

indicate

this

means

suitable conditionally valid

data

flag in

the

electronic

quarterly

report,

and notification within the quarterly report pursuant to

Section

225.290(b) (1) CE),

for that quarter. The owner or operator must resubmit the

report for that

quarter

the required recertification

test is

subsequently

failed. If any required

recertification

test is not completed by

the

end

particular

calendar quarter but is

completed

no later than 30 days after the end

of that

quarter

(i.e.,

prior to the deadline for submitting the quarterly report

under 40

CFR 75.64, incorporated by reference in Section

225.140),

the test data

and results may be

submitted with the earlier quarterly report even though the

test

datc(c)dates

are from the next calendar quarter. In such instances, if the

recertification

tcct(c)tests

are passed in accordance with the provisions of

paragraphsubsection

(b) (3)

of this Section, conditionally valid data may be

reported as

quality-assured, in lieu of reporting

conditional data flag. In

addition, if the

owner or operator uses a conditionally valid data flag in any

of the four

quarterly reports for a given year, the owner or operator must

indicate the

final status of the conditionally valid data

(i.e.,

resolved or

unresolved)

in the annual compliance certification report required under 40 CFR

72.90

for that year. The Agency may invalidate any conditionally valid data that

remains

unresolved at the end of a particular calendar year.

Recertification application. The designated representative must apply for

recertification of each continuous mercury emission monitoring system. The owner

operator must submit the recertification application in accordance with 40

CFR 75.60,

incorporated by reference in Section 225.140, and each complete

recertification application must include the information specified in 40 CFR

75.63,

incorporated

reference in Section 225.140.

Approval or disapproval of request for recertification. The procedures for

provisional

certification in paragraphsubsection

(a) (3)

of this Section

apply to

recertification applications. The Agency will issue a

notice of approval,

disapproval-7-or incompleteness according to the

procedures in

paragraphsubsection

(a) (4)

of this Section. Data

from the monitoring system

remain invalid until all required

recertification

tests

have been

passed or

until

subsequent

probationary calibration error

test

passed,

beginning

new recertification test

period. The owner or operator must repeat all

recertification tests

or other requirements,

indicated in the Agencys

notice of

disapproval, no later than

unit operating days after the date of

issuance of the

notice of disapproval. The designated representative must submit

notification of the recertification retest dates, as specified in 40 CFR

75.61(a) (1)

(ii), incorporated

reference in Section 225.140, and must submit

new

recertification application according

the procedures in

paaaphithact..iQn

(b) (4)

of this Section.

Initial

ccrtification and rcccrtification

proccdurcsCertification

and

Recertification

Procedures.

Prior

the applicable deadline in 35 Ill—d-n

An.

Code

225.240(b),

the

owner or operator must conduct initial certification

tests and in

accordance with 40 CFR

75.63,

incorporated

reference in Section

225.140, the

designated representative must submit an application to demonstrate

that the

continuous emission monitoring system and components

thcrcofof the

system

meet

the specifications in Exhibit A to this Appendix. The owner or

operator

must compare reference method values with output from the automated

data

acquisition

and

handling system that is part of

the continuous mercury

emission monitoring system being tested. Except as

otherwise specified in

paragraphzsubsections

(b) (1), (d)--

and

(e)

this Section, and in Sections

6.3.1 and 6.3.2

of Exhibit

A to

this Appendix, the owner or operator must

perform the

following

tests

for initial certification or recertification of

continuous

emission monitoring systems or components according to the

requirements

of Exhibit B

this Appendix:

For each mercury concentration monitoring system:

A 7-day

calibration error

test;

A linearity

check, for mercury monitors, perform this check with

elemental

mercury standards;

relative accuracy

test

audit must

done on

rig/scm basis;

A bias test;

A cycle

time test;

For mercury

monitors a 3-level system integrity check, using a NIST

traceable source

of oxidized mercury,

described in Section 6.2 of Exhibit A

this Appendix.

This

test

is not required for

mercury monitor that does not

have a converter.

For each

flow monitor:

A 7-day

calibration error

test;

Relative accuracy test audits, as follows:

single-load

(or

single-level) RATA at the normal load

(or

level),

defined in

Section

6.5.2.1(d)

of Exhibit A to this Appendix, for a

flow monitor

installed

peaking unit or bypass stack, or for a

flow monitor exempted from

multiple-level RATA testing under Section

6.5.2(e)

of Exhibit A to

this

Appendix;

ii)

For

all other flow monitors, a RATA at each of the three load

levels

(or

operating

levels)

corresponding to the three flue gas velocities

described in

Section

6.5.2(a)

of Exhibit A to this Appendix;

A bias test

for the single-load

(or

single-level) flow RATA

described

paaapnhactiQn

of this Section; and

A bias test

(or

bias

tests)

for the

3-level flow RATA described in

pa-ag-r-aphiihaecJJ..Qn

of this

Section,

the following load or

operational lcvcl

(c)

levels:

At each load

level designated

normal under Section

6.5.2.1(d)

Exhibit A to

this Appendix, for units that produce electrical or

thermal

output,

ii)

the operational level identified as

normal

in Section

6.5.2.1(d)

Exhibit A

this Appendix, for units that do not produce

electrical or thermal

output.

For each diluent gas monitor used only to monitor heat input

rate:

7-day

calibration error test;

A linearity check;

A relative accuracy test audit,

where,

for

an 02 monitor used to determine

C02 concentration,

the

C02 reference

method must

be used

for the RATA; and

A cycle-time test.

For each continuous moisture monitoring system consisting of wet- and dry-

basis 02 analyzers:

7-day

calibration error test of each 02 analyzer;

A cycle time test of each 02 analyzer;

A linearity test of each 02 analyzer; and

A RATA-

7 directly comparing the percent moisture measured

the monitoring

system

to a

reference method.

For each continuous moisture sensor: A

RATAT

directly comparing the

percent moisture measured by the monitor sensor to a reference method.

For a continuous moisture monitoring system consisting of a temperature

sensor

and a data acquisition and handling system

(DAHS)

software component

programmed with a moisture lookup table: A demonstration that the correct

moisture value for each hour is being taken from the moisture lookup tables and

applied

the emission calculations. At a minimum, the demonstration must be

made

three different temperatures covering the normal range of stack

temperatures from low to high.

For each sorbent trap monitoring system, perform a RATA, on a ag/dscm

basis, and

bias

test.

For the automated data acquisition and handling system, tests designed

verify the proper computation of hourly averages for pollutant concentrations,

flow rate, pollutant emission

ratesT

and pollutant mass emissions.

The owner or operator must

provide

adequate

facilities for initial

certification or recertification

testing that include:

Sampling

ports

adequate

for

test

methods applicable

such facility, such

that:

Volumetric flow rate, pollutant concentration-

7and pollutant emission

rates

can

accurately determined by applicable test methods and procedures;

and

ii)

A stack or duct free of cyclonic flow during performance tests is

available,

demonstrated

applicable

test

methods and procedures.

Basic facilities

(e.g.,

electricity) for sampling and testing equipment.

4-)--

Initial

ccrtification

and rcccrtification and quality assurancc

proccdurcc

for optional backup continuous cmission monitoring systcms.

Initial Certification

and Recertification and

Quality Assurance

Procedures

for Optional Backun

Continuous

Emission Monitoring Systems.

Redundant backups. The owner or operator of an optional redundant backup

CEMS must comply with all the requirements for initial certification and

recertification according to the procedures specified in paragraphssubsections

(a) , (b)--

and

(c)

of this Section. The owner or operator must operate the

redundant

backup CEMS

during all periods of unit operation, except for periods

calibration, quality assurance, maintenance-;- or repair. The owner or operator

must

perform upon the redundant backup CEMS all quality assurance and quality

control

procedures

specified in Exhibit B to this Appendix, except that the

daily assessments

in Section 2.1 of Exhibit B to this Appendix are optional for

days

on which the redundant backup CEMS is not used to report emission data

under this

partPart.

For any day on which a redundant backup CEMS is used to

report emission data, the system must meet all of the applicable daily

assessment criteria in Exhibit B to this Appendix.

Non-redundant backups. The owner or operator of an optional non-redundant

backup CEMS or like-kind replacement analyzer must comply with all of the

following requirements for initial certification, quality assurance,

recertification--

and data reporting:

Except as

provided in

pang÷aph

ib ctjan

Cd) (2) (E)

of this Section, for a

regular

non-redundant backup CEMS

(i.e.,

a non-redundant backup CEMS that has

its own separate

probe, sample

interfaceT

and analyzer), or a non-redundant

backup flow

monitor, all of the tests in

pea ap4axthaection

(c)

of this Section

are required for

initial certification of the system, except for the 7-day

calibration

error

test.

For

like-kind replacement non-redundant backup analyzer

(i.e.,

a non-

redundant

backup analyzer that uses the same probe and sample interface as a

primary

monitoring system), no initial certification of the analyzer

required.

Each non-redundant backup CEMS or like-kind replacement

analyzer must

comply with the daily and quarterly quality assurance and

quality control

requirements in Exhibit B to this Appendix for

each

day

and quarter that

the

non-redundant backup CEMS or

like-kind replacement analyzer is

used to

report

data,

and must meet the additional linearity

and calibration error

test

requirements

specified in this pa*ag-r-apbaubaaction. The

owner or operator

must

ensure that each non-redundant backup CEMS or like-kind

replacement analyzer

passes a

linearity check

(for

mercury concentration and

diluent

gas

monitors)

calibration error test

(for

flow

monitors)

prior to each use

for recording

and

reporting

emissions. When a non-redundant backup CEMS or like-kind

replacement

analyzer is brought into service, prior to conducting the

linearity

test, a

probationary

calibration error test

(as

described in pa-rag-r-aphmabaaction

(b) (3)

(B)

of this

Section),

which will begin a period of

conditionally valid

data,

may be performed in

order

allow the

validation of

data

retrospectively,

follows.

Conditionally valid

data

from the CEMS or like-kind replacement

analyzer are

validated back

the hour of completion of the probationary

calibration

error

test

if the following conditions are met: if no adjustments

are made to

the CEMS or like-kind replacement analyzer other than the allowable

calibration adjustments specified in Section 2.1.3 of Exhibit B to this Appendix

between the probationary calibration error test and the

successful completion

the

linearity test; and if the linearity test

passed

within 168 unit

(or

stack)

operating hours of the probationary

calibration error

test.

However,

the

linearity test is performed

within

168 unit

or stack operating hours

but is

either failed or aborted due to a

problem with the CEMS or like-kind replacement

analyzer, then all of the

conditionally valid

data

are invalidated back

to the

hour of the

probationary calibration

error test,

and

data

from the non-redundant

backup CEMS or

from the primary monitoring system of which the like-kind

replacement

analyzer is a part

remain invalid until the hour of completion

of a

successful linearity test.

Notwithstanding this requirement, the conditionally

valid data status

may

re-established after

failed or aborted linearity

check, if

corrective action

taken

and a

calibration error

test

subsequently passed.

However,

in no case will the

use of conditional data

validation extend for more than 168 unit or stack

operating hours beyond the

date

and

time of

the original probationary

calibration error test when the

analyzer

was

brought into service.

For

each

parameter monitored (i.e.,

C02, 02, Hg-

7- or flow

rate)

at each

unit or

stack, a

regular non-redundant

backup CEMS may not be used to report

data at that affected

unit

or common

stack for more than 720 hours in any one

calendar

year

(in accordance with

40 CFR

75.74(c),

incorporated

by reference in

Section

225.140),

unless the CEMS

passes a RATA at that unit or stack. For each

parameter monitored at each unit or stack,

the use of a like-kind replacement

non-redundant

backup analyzer

(or

analyzers)

is restricted to 720 cumulative

hours per calendar year, unless the owner or operator redesignates

the like-kind

replacement

analyzcr(c)

componcnt(s)analvzers

as components

of regular

non-

redundant backup CEMS and each redesignated CEMS

passes a

RATA

that unit

stack.

For each regular non-redundant backup CEMS, no more than eight

successive

calendar

quarters must elapse following the quarter in which the last RATA

the CEMS was done at a particular unit or stack, without performing

a subsequent

RATA. Otherwise, the CEMS may not be used to report data from that unit

or stack

until the hour of completion of a passing RATA at that location.

Each regular non-redundant backup CEMS must

represented in the

monitoring plan required under Section 1.10 of this Appendix

as a

separate

monitoring system, with unique system and component identification numbers.

When

like-kind replacement non-redundant backup analyzers are

used,

the owner

operator must represent each like-kind replacement analyzer

used

during

particular calendar quarter in the monitoring plan required

under Section 1.10

of this Appendix

a component of

primary monitoring system. The owner

operator must also assign

unique component identification number

to each like

kind replacement analyzer, beginning with the letters T

LK’

(e.g.,

-“-LK1,

—-”-

LK2,-”-

etc.)

and must specify the manufacturer, model and serial number of the like-

kind replacement analyzer. This information may

added, deleted or

updated as

necessary, from quarter to quarter. The owner or operator must also report

data

from the like-kind replacement analyzer using the system identification number

of the

primary monitoring

system

and

the assigned

component

identification

number of the like-kind replacement analyzer. For the purposes

of the electronic

quarterly

report required under 40 CFR 75.64, incorporated

reference in

Section

225.140, the owner or operator may manually enter the

appropriate

component identification numbcr(c)numbers of any like-kind replacement

analyzcr(s)analvzers

used

for

data

reporting during the quarter.

When reporting

data

from

certified regular non-redundant

backup CEMS,

use a

method of determination code (MODC)

codc

‘G2—-fll’L.

When

reporting data

from

like-kind replacement

non-redundant backup analyzer, use a MODC of

!l7TI

(see

Table 4a under

Section 1.11 of

this

Appendix) . For the purposes of the

electronic quarterly report

required under 40 CFR 75.64, incorporated by

reference in Section 225.140, the owner

operator may

manually enter the

required MOOC of “17” for

like-kind replacement analyzer.

For non-redundant backup mercury CEMS and sorbent trap monitoring

systems,

and for like-kind replacement mercury analyzers, the following provisions apply

addition

to,

or, in

some cases, in lieu of, the general requirements in

paragraphssubsections

(d) (2) (A)

through

(d) (2)

(H)

of this Section:

When a certified

sorbent trap monitoring system

brought into service as

regular non-redundant backup monitoring system, the system must be

operated

according

the

procedures in Section 1.3 of this Appendix and

Exhibit ID to

this Appendix;

ii)

When a regular

non-redundant backup mercury CEMS or

like-kind

replacement mercury

analyzer is brought into service,

linearity check with

elemental

mercury

standards,

described in paragraphsubsection

this Section and

Section 6.2 of Exhibit A to this Appendix, and a single-point

system integrity

check,

described in Section 2.6 of Exhibit B to this

Appendix, must be

performed. Alternatively, a 3-level system integrity check, as

described in

paragraphsu.bsection

of this Section and

paaaph.suhaectiQn

(g) of Section 6.2 in Exhibit A to this Appendix, may be

performed in lieu

of these two tests.

iii)

The weekly

single-point system integrity checks described in Section 2.6

of Exhibit B to

this Appendix are required

long

as a

non-redundant backup

mercury CEMS or like-kind

replacement mercury analyzer remains in service,

unless the daily

calibrations of

the

mercury analyzer are done using a NIST

traceable source or other

approved source of oxidized mercury.

Reference method

backups. A monitoring system that is operated as a

reference method

backup system pursuant

the reference method requirements of

Methods

2, 3A, 30A--nd

30B in appendix A of 40 CFR

60,

incorporated by

reference in

Section 225.140, need not perform and pass the certification tests

required by paag&phbIec.ti..Qn

(c)

of this Section prior to its use

pursuant

this

paaphectiQn.

Certification/rcccrtification proccdurcs for cithcr pcaking unit

pass stack/duct

continuous omission monitoring systcmsRecertification Procedures

for

Either Peaking

Unit or

Bv-ass Stack/Duct Continuous

Emission Monitoring

Systems. The owner or operator of either a peaking unit or by-pass

stack/duct

continuous

emission

monitoring system must comply with all the

requirements

for

certification or recertification according to the procedures

specified in

paragraphssubsections

(a), (b)--

and

(c)

of this Section, except as

follows:

the

owner

or operator need only perform one Nine-run

relative accuracy

test

audit

for

certification or recertification of a flow monitor

installed on the by-pass

stack/duct

or on the stack/duct used only by affected

peaking unit(s)units.

The

relative accuracy test audit must be performed during normal

operation of

the

peaking

unit(s)units

or the by-pass stack/duct.

Certification/rcccrtification

proccdurcs for altcrnativc

monitoring

systcmsRecertification

Procedures

for

Alternative Monitoring Systems.

The

designated representative representing the

owner or operator of each alternative

monitoring system approved by the

Agency

equivalent

or better than a

continuous emission

monitoring system according

the criteria in subpart E of

CFR 75,

incorporated

reference in Section 225.140, must apply for

certification to

the Agency prior

to use

of the system under Part 225, Subpart B

of this

Part,

and must apply for recertification to the Agency following a

replacement, modification, or change according to the procedures in

paragraphsubsection

(c)

of this Section.

The owner

operator

an alternative

monitoring system must comply with the

notification

and

application requirements

for certification or recertification

according

to the

procedures specified in

paragraphssubsections

(a)

and

(b)

this Section.

Section 1.5 Quality assurancc

and

quality

rontrn] rmiromontAssiirance arid

Quality

Control Reauirements

Continuous cmizzion monitoring

DyztcmzEmission

Monitoring

Systems. The

owner or operator of an

affected

unit

must

operate, calibrate and

maintain

each

continuous mercury emission monitoring system used to report mercury

emission

data as

follows:

The owner or operator must operate, calibrate and maintain each

primary

and redundant backup continuous emission monitoring system according to the

quality assurance and quality control procedures in Exhibit B to this Appendix.

The owner or operator must ensure that each non-redundant backup CEMS

meets

the

quality assurance requirements of Section

1.4(d)

of this Appendix for

each day

and

quarter that the system is used to report data.

The owner or operator must perform quality assurance upon a

reference

method backup monitoring system according to the requirements

me--hodMetli

or 3A in appendix A of 40 CFR 60, incorporated by

reference in Section 225.140

(supplemented, as

necessary,

guidance from the Administrator or the Agency),

or one of the mercury

reference methods in Section 1.6 of this Appendix,

applicable, instead

of the procedures specified

Exhibit B of this Appendix.

Calibration gacccGases. The owner or operator must ensure that all

calibration gases used to

quality assure the operation of the instrumentation

required

by this

Appendix must meet the definition in 40 CFR 72.2, incorporated

by reference in

Section 225.140.

Section

1.6 Reference tcct

mcthodoTest Methods

The

owner or operator

must

use the

following methods, which are found

appendix A-4 to 40 CFR 60, incorporated by reference

in Section 225.140, or

have

been published by ASTM, to conduct the following tests:

monitoring system

tests

for certification or recertification of continuous

mercury emission monitoring

systems; the emission tests required under Section

1.15(c) and

(d)

of this

Appendix; and required quality assurance

and quality control tests:

Methods 1

or 1A are the reference methods for selection of sampling site

and sample

traverses.

Method

2 or its allowable alternatives, as provided in appendix A to 40

CFR

60,

incorporated by reference in Section 225.140, except

for Methods 2B

and

2E,

are the reference methods for

determination

volumetric flow.

Methods 3,

3A-r

or 3B

are

the

reference methods for the determination of

the dry molecular weight 02

and C02 concentrations in the emissions.

Method 4

(either

the standard procedure described

in Section 8.1 of

the

method or the moisture approximation procedure

described

Section 8.2 of

the

method)

must be used to correct pollutant concentrations

from

dry basis

to a

wet

basis

(or

from a wet basis to a dry

basis)

and must be used

when relative

accuracy test audits of continuous moisture

monitoring systems are conducted.

For the purpose of determining the stack gas

molecular weight, however,

the

alternative wet bulb-dry bulb technique

for approximating the stack gas moisture

content described in Section 2.2 of

Method 4 may

be used

in lieu of the

procedures in

Sections

8.1 and 8.2 of

the method.

ASTM

D6784-02, Standard Test Method for Elemental, Oxidized, Particle

Bound and Total Mercury in Flue Gas Generated from Coal-Fired Stationary Sources

I-

(Ontario

Hydro

Method)

(incorporated

reference under Section

225.140)

is the

reference method for

determining mercury concentration.

Alternatively,

Method 29

appendix A-8

40 CFR 60, incorporated by

reference in Section

225.140,

may be used,

with these caveats: The procedures

for

preparation of

mercury standards and sample analysis in Sections 13.4.1.1

through 13.4.1.3 ASTM

D6784-02 (incorporated by reference

under Section

225.140)

must be followed instead

of the procedures in Sections 7.5.33

and 11.1.3 of

Method 29 in

appendix A-8 to 40 CFR 60, and the QA/QC

procedures in Section

13.4.2 of

ASTM D6784-02 (incorporated by reference

under Section

225.140)

must

be performed instead

of the procedures in Section 9.2.3

of Method 29 in appendix

A-8 to 40

CFP.

60.

The tester may also opt to use the

sample recovery and

preparation

procedures in ASTM D6784-02 (incorporated by

reference under Section

225.140)

instead

of the Method 29 in appendix A-8 to 40

CFR

procedures,

follows: Sections

8.2.8 and 8.2.9.1 of Method 29 in appendix

A-8

40 CFR

may be replaced

with Sections 13.2.9.1 through 13.2.9.3

of ASTM D6784-02

(incorporated by

reference under Section 225.140);

Sections 8.2.9.2 and 8.2.9.3

of Method 29 in

appendix A-S to 40 CFR 60 may be replaced

with Sections

13.2.10.1 through

13.2.10.4 of ASTM D6784-02 (incorporated by

reference under

Section 225.140);

Section 8.3.4 of Method 29 in appendix

A-8

40 CFR

may

replaced with

Section 13.3.4 or 13.3.6 of ASTM D6784-02

(as

appropriate)

(incorporated

reference under Section 225.140); and

Section

8.3.5

of Method

in appendix A-8 to

40 CFR

may be replaced with Section 13.3.5

or 13.3.6 of

ASTM D6784-02

(as

appropriate) (incorporated by reference

under Section

225.140)

Whenever

ASTM D6784-02 (incorporated by

reference under Section

225.140)

or Method 29 in

appendix A-8 to 40 CFR 60, incorporated by

reference in Section

225.140,225.140

used,

paired sampling trains are

required. To validate

RATA

run or an

emission

test

run, the relative deviation

(RD), calculated according

Section 11.6

of Exhibit D to this Appendix, must

not exceed 10 percent-

7when

the average

concentration is greater than 1.0

pg/m3. If the average

concentration is less than or equal to 1.0

pg/m3, the RD must not exceed 20

percent.

The RD results are also

acceptable if the absolute difference between

the

mercury concentrations

measured

the paired trains does not exceed 0.03

ig/m3.

If the RD criterion is

met, the run is valid. For each valid

run, average

the

mercury concentrations

measured

the two trains (vapor phase-

only)

Two additional reference

methods that may be used to measure

mercury

concentration

are: Method

30A,

1!Determination

of Total Vapor Phase

Mercury

Emissions from Stationary Sources

(Instrumental

Analyzer

Procedure)11

and

Method

30B,

!!Determination

of Total

Vapor Phase Mercury Emissions from

Coal-Fired

Combustion

Sources Using Carbon

Sorbent Traps-’

When Method 29 in appendix A-8 to

40 CFR 60, incorporated by

reference

Section

225.140,

or ASTM D6784- 02 (incorporated by

reference under Section

225.140)

is used

for

the

mercury emission testing required

under Section 1.15(c)

and

(d)

of this

Appendix,

locate

the reference method test

points according

Section

8.1 of

Method 30A, and if mercury

stratification testing is part of the

test

protocol, follow the procedures in Sections 8.1.3

through 8.1.3.5 of Method

30A.

The

owner or operator may use any

of the following methods, which are

found

in appendix A to 40 CFR 60,

incorporated

reference in Section 225.140,

have been published by ASTM, as a

reference method backup monitoring system

provide quality-assured

monitor

data:

Method 3A for

determining

02 or

C02 concentration;

Method 2, or its

allowable alternatives,

as provided in appendix

CFR 60, incorporated by

reference

in Section 225.140, except for

Methods 2B and

2E, for determining

volumetric

flow. The sample point(c)ooints for reference

methods must

located

according

to the provisions of Section 6.5.4 of Exhibit

this Appendix.

ASTM D6784-02,

Standard

Test

Method for Elemental, Oxidized,

Particle-

Bound and Total Mercury in Flue Gas Generated from Coal-Fired Stationary Sources

(Ontario

Hydro

Method)

(incorporated by reference under Section

225.140)

for

determining mercury concentration;

Method 29 in appendix A-8

40 CFR

60,

incorporated by reference in

Section

225.140, for determining mercury concentration;

Method 30A for determining mercury concentration; and

Method 30B for determining mercury concentration.

Instrumental EPA Reference Method 3A in appendices A-2 and A-4 of

CFR

60,

incorporated by reference in Section 225.140, must be conducted

using

calibration gases as

defined

in Section 5 of Exhibit A to this

Appendix.

Otherwise,

performance

tests

must

be conducted

and

data

reduced in accordance

with the test

methods and procedures of this partPart unless the Agency:

Specifies or

approves, in specific

cases,

the

use

reference method

with minor changes

methodology;

Approves the use of an equivalent method;

Approves shorter sampling times and smaller sample volumes

when

necessitated by process variables or other factors.

Section 1.7

Out-of-control

cm biac tcztingControl

Periods

and

System

Bias Testing

If an

out-of-control period occurs

to a

monitor or continuous emission

monitoring system, the owner or operator must take corrective action and repeat

the tests

applicable

the

-“-out-of-control parameter-”- as described in Exhibit B

this Appendix.

For daily calibration error tests, an out-of-control period occurs when

the

calibration error of

pollutant concentration monitor exceeds the

applicable specification in Section 2.1.4 of Exhibit B to this

Appendix.

For quarterly linearity checks, an out-of-control period

occurs when

the

error in linearity at any of three gas

concentrations (low,

mid-range-r

and

high)

exceeds the

applicable specification in Exhibit A

this Appendix.

For relative accuracy test

audits,

out-of-control

period

occurs when

the relative accuracy exceeds the applicable

specification

Exhibit A

to this

Appendix.

When

monitor or continuous emission monitoring system is out-of-control,

any data

recorded by the monitor or monitoring system are not quality-assured

and must not be used in

calculating monitor

data

availabilities pursuant to

Section

1.8 of this Appendix.

When a monitor or continuous

emission

monitoring system is out-of-control,

the owner or operator must take one of the

following

actions until the monitor

or monitoring system has successfully met the

relevant criteria in Exhibits A

and B of

this Appendix as demonstrated by subsequent tests:

Use a certified

backup monitoring system or a

reference method for

measuring

and recording emissions from

the

affected

unit(o)units; or

Adjust the

gas

discharge paths

from

the

affected

unit(s)units

with

emissions normally observed by the

out-of-control monitor or monitoring system

that all exhaust gases are

monitored

by a

certified monitor or monitoring

system meeting the requirements

of Exhibits A and B

this Appendix.

When the bias test

indicates that a flow monitor, a diluent

monitoring

system, a mercury

concentration monitoring system or a sorbent trap

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 Exhibit A

this Appendix), the

owner or operator must

adjust

the monitor or continuous

emission

monitoring system to

eliminate the

cause

of bias such that it passes

the

bias

test.

Section

1.8 Determination of

monitor nata avg

Monitor Data Availability

Following initial certification of

the required

C02-r2.

-rZ

flow monitoring

cyctcm(z)svstems,

concentration-r

or moisture monitoring

oyztcm(z) systems

at a

particular unit or stack location

(i.e.,

the

date

and time at which quality

assured

data begins to be

recorded

CEr”IS(c)CEMSs

that

location),

the owner

operator must begin

calculating the percent monitor data

availability

described

in parag*aphha.t1Qn

(a) (1)

of this Section, by means of

the

automated data acquisition

and handling system, and the percent

monitor

data

availability for

each monitored parameter.

Following

initial certification, the owner or

operator must

use

Equation

to calculate,

hourly, percent monitor data

availability for each calendar

quarter.

Total unit operating hours

for which quality-assured

data Percent

was recorded for the calendar

quarter monitor data =

_____________________________

X 100 (Eq.8)

Availability

Total

unit operating

hours

for the calendar quarter

When

calculating percent monitor data

availability using Equation 8, the

owner or

operator must include all

unit operating hours, and all monitor

operating

hours for which

quality-assured

data

were recorded by a certified

primary monitor; a certified

redundant or non-redundant backup monitor or a

reference method for that unit.

Section

1.9 Determination of

zorbcnt trap monitoring zystcmz data

availabilitySorbent Trao Monitorina

Systems Data

Availability

If a

primary sorbent trap monitoring system has not

been certified

the

applicable

compliance

date

specified under

3S Ill Admin. Codc

Part 225,

Subpart

of this Part,

and if quality-assured mercury

concentration data from a

certified

backup

mercury monitoring system, reference

method-r

or approved

alternative monitoring

system are unavailable, the owner or operator must

perform quarterly

emissions testing in accordance with Section 225.239 until

such time the primary

sorbent trap monitoring system has been certified.

For a

certified sorbent trap system, a missing data period will occur in

the

following

circumstances, unless quality-assured mercury concentration data

from a

certified backup mercury CEMS, sorbent trap system, reference

method-7

approved alternative monitoring system are available:

A gas sample

is not extracted from the stack during unit operation (e.g.,

during a monitoring

system malfunction or when the system undergoes

maintenance)

;

The results of

the mercury analysis for the paired sorbent traps are

missing or invalid

(as

determined using the quality assurance procedures in

Exhibit D to this

Appendix). The missing

data

period begins with the hour in

which the paired sorbent

traps for which the mercury analysis is missing or

invalid were put

into service. The missing

data

period ends at the first hour in

which valid mercury

concentration

data

are obtained with another pair of sorbent

traps

(i.e.,

the

hour

which this pair of traps was placed in

service),

with

a certified

backup mercury CEMS, reference

method

or approved

alternative

monitoring

system.

Following initial certification of the sorbent trap monitoring system,

begin reporting

the percent monitor data availability in accordance with Section

1.8 of this

Appendix.

Section

1.10 Monitoring

planPlan

The owner or operator of an affected unit must

prepare and maintain

mercury

emissions monitoring plan.

Whenever the owner or operator makes a

replacement, modification-

change in

the certified CEMS, including a change in the

automated

data

acquisition and handling system or in the flue gas

handling system, that affects

information reported in the

monitoring plan

(e.g., a

change

to a

serial number

for

component of a monitoring

system), then the owner or operator must update

the

monitoring plan, by the

applicable deadline specified in 40 CFR 75.62,

incorporated by reference in

Section 225.140, or elsewhere in this Appendix.

Contents of

monitoring plan for cpccific

cituationcMonitorin

Plan

for

Specific Situations.

The following

additional information must be included in

the monitoring

plan for

the

specific situations described. For each monitoring

system

recertification, maintenance-7or other event, the designated

representative

must include the following additional information in electronic

format in the

monitoring plan:

Component/system identification code;

Event

code

for required test;

Event begin date and hour;

Conditionally

valid

data period begin date

and hour

(if

applicable);

Date

and hour that last

test

is successfully completed; and

Indicator of whether conditionally valid data were reported at the end of

the quarter.

Contents

of the mere v—me

e-ig—p4-aMercury

Monitoring Plan.

The

requirements of

paragrphsubsection

Cd)

of this Section must be met on and after

July 1, 2009.

Each monitoring plan must contain the information in

paaaphti.n (d) (1)

of this Section in electronic format and the

information in

agaphi.1hti.Qn

(d)

(2)

of this Section in hardcopy format.

Electronic storage

of all monitoring

plan information,

including the hardcopy

portions, is

permissible provided

that a paper copy

of the information can be

furnished upon request

for audit purposes.

Electronic

The

facility ORISPL number developed

the Department of Energy and used

in the

National Allowance Data Base

(or

equivalent facility ID number assigned

USEPA, if the facility does not have an ORISPL

number).

Also

provide

the

following information for each unit and

(as

applicable) for each

common

stack

and/or pipe, and each multiple stack and/or pipe involved in

the monitoring

plan:

A representation of the exhaust configuration for the

units in the

monitoring plan. Provide the ID number of each unit and assign a

unique ID

number to

each common stack, common pipe, multiple

stack-r

and/or multiple pipe

associated with

the

unit(s)units

represented in the monitoring plan. For common

and multiple

stacks and/or pipes, provide the activation date and

deactivation

date

(if

applicable) of each stack and/or pipe;

ii)

Identification of the monitoring system

location(c)locations

(e.g., at the

unit-level, on the common stack, at each multiple stack,

etc.).

Provide

indicator

(h1flagu)

if the monitoring location is at a bypass stack or

the

ductwork (breeching);

iii)

The stack exit height

(f t)

above

ground

level and ground level elevation

above sea level, and the inside

cross-sectional area

(ft2)

the flue exit and

the flow

monitoring location

(for

units with flow

monitors-r

only) . Also use

appropriate codes to

indicate the

matcrial(s)materials

of construction and the

chapc(c)shaoes

of the stack or

duct

cross-scction(c)sections at the flue exit

and

(if

applicable)

at the

flow monitor location;

iv)

The

typc(s)tvoes

of fucl(z)fuels

fired

each unit. Indicate the start

and

(if

applicable) end

date

of combustion for each type of fuel, and whether

the fuel is the

primary, secondary,

emergency-r

or startup fuel;

The

typc(s)tvoes of emission controls that are used to reduce mercury

emissions

from each unit. Also provide the installation date, optimization

date-r

and

retirement date

(if

applicable) of the emission controls, and indicate

whether the controls are an original installation; and

vi)

Maximum hourly heat input capacity of each unit.

For each

monitored parameter

(i.e.,

mercury concentration, diluent

concentratiom-

or flow)

each monitoring location, specify the monitoring

methodology

for the parameter. If the unmonitored

bypass

stack approach is

used

for a

particular parameter, indicate this

means of an appropriate code.

Provide the activation

date/hour, and deactivation date/hour (if

applicable) for

each monitoring

methodology.

For each

required continuous emission monitoring

system-7-and each sorbent

trap monitoring

system

(as

defined in Section

225.130),

identify and describe

the major

monitoring components in the monitoring system (e.g.,

gas analyzer,

flow monitor,

moisture sensor, DAHS software,

etc.).

Other important components

in the system (e.g.,

sample probe, PLC, data

logger,

etc.)

may also be

represented in

the monitoring plan, if necessary.

Provide the following specific

information about

each component and

monitoring

system:

For each required monitoring

system, assign

unique, 3-character

alphanumeric identification code to

the

system; indicate the parameter monitored

by the

system; designate the system as a

primary, redundant backup, non

redundant

backup, data backup-

7-or

reference method backup system, as

provided

Section

1.2(d)

of this Appendix; and indicate the

system activation date/hour

and

deactivation date/hour

(as

applicable)

ii)

For

each component of each monitoring

system represented in the monitoring

plan, assign a

unique, 3-character

alphanumeric identification code to the

component;

indicate the manufacturer, model

and serial number; designate the

component type;

for gas analyzers, indicate

the moisture basis of measurement;

indicate

the method of sample

acquisition or operation, (e.g.,

extractive

pollutant

concentration monitor or

thermal flow monitor); and indicate the

component

activation date/hour and deactivation

date/hour

(as

applicable)

Explicit formulas, using the

component and system identification codes for

the primary

monitoring system, and

containing all constants and factors required

to derive

the required emission rates,

heat input rates, etc. from the

hourly

data recorded

by the monitoring

systems. Formulas using the system and component

ID codes

for backup monitoring

systems are required only if different

formulas

for the

same parameter are used

for the primary and backup monitoring

systems

(e.g.,

if the primary system

measures pollutant concentration on a

different

moisture

basis from the backup

system)

. Provide the equation number

other

appropriate

code for each

emissions formula

(e.g.,

use code F-i if

Equation F-l

Exhibit

C to this

Appendix is

used to

calculate S02 mass

emissions)

. Also

identify each emissions

formula with a unique three

character

alphanumeric

code.

The

formula

effective

start

date/hour and inactivation

date/hour

(as

applicable)

must be

included for each

formula.

For each parameter

monitored with CEMS, provide the

following information:

Measurement

scale;

ii)

Maximum

potential value

(and

method

calculation);

iii)

Maximum expected value

(if

applicable) and

method of calculation;

iv)

Span

valuc(c)values

and full-scale

measurement

rangc(c)ranoes;

Daily calibration units of

measure;

vi)

Effective date/hour, and

(if

applicable) inactivation date/hour

each

span

value;

vii)

The default high range

value

(if

applicable) and the

maximum allowable

low-range

value for

this

option.

the

monitoring system

or excepted

methodology provides

for the

use of a

constant,

assumed-- or

default value for

a parameter

under

specific

circumstances,

then

include

the

following

information

for each such value

for

each

parameter:

Identification

of the

parameter;

ii)

Default,

maximum,

minimum,

or constant

value, and units

of measure

for the

value;

iii)

Purpose of

the

value;

iv)

Indicator

of use,

i.e.,

during controlled

hours,

uncontrolled

hours-;- or

all

operating hours;

Type of fuel;

vi)

Source

of the

value;

vii)

Value

effective date

and hour;

viii)

Date

and

hour value

no longer

effective

(if

applicable);

and

Unless

otherwise

specified

in Section

6.5.2.1 of

Exhibit A

this

Appendix,

for

each unit or

common stack

on which

hardware CEMS

are

installed:

Maximum

hourly gross

load

(in

MW, rounded

the nearest

MW, or

steam load

in 1000

lb/hr

(i.e.,

klb/hr),

rounded to the

nearest

klb/hr, or thermal

output

in mmBtu/hr,

rounded

the

nearest mmBtu/hr),

for

units that produce

electrical

thermal

output;

ii)

The

upper and lower

boundaries

of the

range of operation

(as

defined

Section

6.5.2.1 of

Exhibit

A to this

Appendix), expressed

in megawatts,

thousands

of lb/hr

of steam, mmBtu/hr

of thermal

output- or ft/sec

(as

applicable);

iii)

Except for peaking

units, identify

the most frequently

and

second most

frequently

used load

(or

operating)

levels

(i.e.,

low,

mid-r

high)

accordance with

Section 6.5.2.1

of Exhibit A to this

Appendix, expressed

megawatts,

thousands of lb/hr

of steam, mmBtu/hr

of thermal output--

ft/sec

(as

applicable);

iv)

An indicator

of whether the second

most frequently

used load

(or

operating) level

is designated

normal in Section

6.5.2.1 of Exhibit

this

Appendix;

The date of the

data analysis

used

to determine the

normal load

(or

operating)

lcvcl(z)levels

and the two

most frequently-used

load

(or

operating)

levels

(as

applicable); and

vi)

Activation and

deactivation

dates

and hours, when

the maximum hourly

gross

load,

boundaries

of the range

of operation,

normal

load

(or

operating)

lcvcl(s)levels

or two most frequently-used

load

(or

operating)

levels

change and

are

updated.

For each unit

for which CEMS are

not

installed,

the

maximum hourly gross

load

(in

MW, rounded to

the

nearest MW,

or steam load in klb/hr, rounded to

the

nearest

klb/hr-

7-or steam load in

mmBtu/hr,

rounded to the nearest

mmBtu/hr);

For each unit

with

flow monitor installed on

rectangular

stack

duct, if

wall effects

adjustment factor (WAF) is determined and applied

the

hourly flow rate data:

Stack or duct

width

the

test location, ft;

ii)

Stack or duct

depth

the

test

location,

ft;

iii)

Wall effects

adjustment factor (WAF),

the

nearest 0.0001;

iv)

Method of

determining the WAF;

WAF

Effcctivceffective

date

and hour;

vi)

WAF no

longer effective

date

and hour

(if

applicable);

vii)

WAF

determination

date;

viii)

Number of WAF test

runs;

ix)

Number of

Method 1 traverse points in the WAF test;

Number of test

ports in the WAF

test;

and

xi)

Number

of Method 1 traverse points in the reference flow RATA.

Hardcopy

Information, including

(as

applicable)

Identification of the test

strategy;

protocol for the relative accuracy test audit; other relevant test

information;

calibration

gas

levels (percent of span) for the calibration error

test and

linearity check and span; and apportionment strategies under Sections

1.2 and 1.3

of this Appendix.

Description of site locations for each monitoring component in the

continuous emission monitoring systems, including schematic diagrams

and

engineering drawings specified in 40 CFR

75.53(e) (2) (iv)

and

(v),

incorporated by reference in Section

225.140,225.140 and any other documentation

that demonstrates each monitor

location meets the appropriate siting criteria.

A data

flow diagram denoting the complete information handling path from

output signals

of CEMS

components to

final reports.

For units monitored

a continuous emission monitoring system, a

schematic

diagram identifying entire gas handling system from boiler to stack

for

all affected units, using identification numbers for units,

monitoring

systems

and

components-r

and stacks corresponding to the identification numbers

provided

in paragraphssubsections

(d) (1) (A)

and

(d) (1)

(C)

of this Section. The

schematic

diagram must depict stack height and the height of any monitor

locations. Comprehensive and/or separate schematic diagrams must be used to

describe

groups of units using a common stack.

For units

monitored

by a

continuous emission 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-r

and other

equipment

that

affects

the

monitoring

system

location,

performance-- or

quality control checks.

Section

1.11

General

rccordkccping

provizionzRecordkeeninc Provisions

The owner or

operator must meet all

the applicable recordkeeping requirements

of Section 225.290

and of this Section.

Recordkeeping rcquircmcntcRecniirements

for

affcctcd

aourcczAffected

Sources.

The owner or operator of any affected source subject to

the

requirements

of this

Appendix

must

maintain for

each

affected unit a file of all

measurements, data,

reports-r

and

other information required

Part 225, Subpart

this

Part

the source

in a

form suitable for inspection for at least

thrcc

(3-)-

years

from the

date

each

record. The file must contain the

following

information:

The data and

information required in

paragraphDsubsections

(b)

through

(h)

of this Section,

beginning with the earlier of the

date

of provisional

certification or

July 1, 2009;

The

supporting

data

and information

used to

calculate values required in

paragraphsubsections

(b)

through

(g)

of this Section, excluding the subhourly

data

points used to

compute hourly averages under Section

1.2(c)

of this

Appendix, beginning

with

the

earlier

the

date

of provisional certification or

July 1, 2009;

The data and

information required in Section 1.12 of this Appendix for

specific situations, beginning

with

the

earlier of the

date

of provisional

certification or

July

1, 2009;

The

certification test data and information required in

Section 1.13

this

Appendix for tests required under Section 1.4 of this Appendix,

beginning

with the date

of the first certification test performed, the

quality assurance

and quality

control data and information required in Section 1.13

of this

Appendix

for tests, and the quality assurance/quality control plan

required

under

Section 1.5 of this Appendix and Exhibit B to this

Appendix, beginning

with the

date

of provisional certification;

The current monitoring plan as specified

Section

1.10 of this Appendix,

beginning with the initial submission required by

40 CFR 75.62, incorporated

reference in Section 225.140; and

The quality control plan as described in

Section 1 of Exhibit B

this

Appendix, beginning with the date of provisional certification.

Operating

paramctcr record

provizioneParameter Record Provisions.

The

owner or operator must record for each hour the

following information on unit

operating

time, heat input rate-i- and

load, separately for each affected unit and

also for each

group of units utilizing

common stack and

common monitoring

system:

Date and hour;

Unit operating time

(rounded

up to

the

nearest

fraction of an hour

(in

equal increments

that can range

from one hundredth

to one

quarter of an hour, at

the option of the

owner or operator));

Hourly gross

unit load

(rounded

to nearest MWge)

Steam load in

1000 lbs/hr at stated temperatures and

pressures, rounded

the nearest 1000

lbs/hr.

Operating

load range corresponding to hourly gross

load of 1

10, except

for units using a

common stack, which may use up to 20 load

ranges

for stack or

fuel flow, as

specified in the

monitoring plan;

Hourly

heat input rate (mmBtu/hr,

rounded

to the

nearest tenth);

Identification code for

formula

used

for

heat input-i-

provided in

Section 1.10

of this Appendix; and

For

Mercury

CEMS units only, F-factor for heat

input calculation and

indication of

whether the diluent cap was used for heat

input

calculations for

the hour.

Diluent rccord

provicioncRecord Provisions. The owner or operator of a

unit

using a flow monitor and

02 diluent monitor to determine heat input, in

accordance with

Equation F-17 or F-lB of Exhibit

to this Appendix, or a unit

that

accounts for heat

input using

flow monitor and a C02 diluent

monitor

(which is used only

for heat input determination and is not used as a

C02

pollutant

concentration

monitor)

must keep the following records for the 02 or

C02

diluent monitor:

Component-system

identification

code-p

as provided in

Section 1.10 of

this

Appendix;

Date and hour;

Hourly

average diluent gas

(02

C02)

concentration

(in percent, rounded

the nearest

tenth);

Percent

monitor

data

availability for the diluent

monitor

(recorded

the

nearest

tenth of a

percent)-- calculated pursuant to Section 1.8

this

Appendix; and

Method

of determination code for diluent gas

(02

C02)

concentration

data using Codes

l-&-- in Table 4a of this Section.

Missing data rccordsData

Records. The owner or operator must record the

causes

of any missing data periods

and the actions taken by the owner or

operator to correct

such

causes.

Mercury cmiscion rccord

provizionsEmission Record Provisions

(CEMS)

. The

owner or

operator must record for each hour the information

required

this

paragraphsubsection

for each affected unit using mercury

CEMS in combination

with flow rate,

and

(in

certain

cases)

moisture, and diluent gas

monitors,

determine

mercury concentration and

(if

applicable) unit

heat input under Part

225, Subpart

B of this Part.

For mercury

concentration during unit operation, as measured and reported

from each certified

primary monitor, certified back-up monitor-;- or other

approved method of

emissions determination:

Component-system

identification

code-;- as

provided in Section 1.10 of this

Appendix;

Date and hour;

Hourly mercury concentration (jig/scm, rounded to the nearest

tenth)

. For

particular pair of sorbent traps, this will be the

flow-proportional average

concentration for the data collection period;

Method of

determination for hourly mercury concentration using Codes 1-55

in Table 4a of this

Section; and

The percent

monitor

data

availability

(to

the nearest tenth of a

percent)T

calculated pursuant to

Section 1.8 of this Appendix.

For flue gas

moisture content during unit operation

(if

required), as

measured and

reported from each certified primary monitor, certified back-up

monitor--

other approved method of emissions determination (except where a

default moisture

value

is approved under 40 CFR 75.66, incorporated by reference

in Section

225.140)

Component-system

identification

code-- as

provided in Section 1.10 of this

Appendix;

Date and

hour;

Hourly average

moisture content of flue

gas

(percent, rounded to the

nearest

tenth)

. If the

continuous moisture monitoring system consists of wet-and

dry-basis oxygen

analyzers, also record both the wet- and dry-basis oxygen

hourly averages (in

percent 02, rounded

the

nearest tenth);

Percent

monitor data availability

(recorded

to the nearest tenth

percent)

for the moisture monitoring

system-r

calculated

pursuant to

Section

1.8

of this

Appendix; and

Method of

determination for hourly average moisture percentage-- using

Codes

1-55 in

Table 4a of this Section.

For

diluent

gas

(02

C02)

concentration during unit operation

(if

required), as

measured and reported from each certified primary monitor,

certified

back-up

monitor-r

or other approved method of emissions determination:

Component-system identification

code-r

as provided in Section 1.10 of this

Appendix;

Date and hour;

Hourly average

diluent

gas

(02

C02)

concentration

(in

percent, rounded

the nearest

tenth)

Method

of determination code for diluent gas

(02

C02)

concentration

data

using Codes

l-&S--

in Table 4a of this Section; and

The percent

monitor data

availability

(to

the nearest tenth

percent)

for the 02 or

C02

monitoring

system

(if

a separate

02 or C02

monitoring

system

is used for

heat

input

determination)--

calculated

pursuant

Section

1.8 of

this Appendix.

For stack gas

volumetric

flow

rate during

unit operation,

as measured

and

reported

from

each certified

primary

monitor,

certified back-up

monitor-

other approved

method

of emissions determination,

record

the information

required

under

CFR

75.57(c) (2)

(i)

through

(c)

(2)

(vi),

incorporated

reference

Section

225.140.

For

mercury mass emissions

during unit

operation, as measured

and reported

from

the certified primary

monitoring syztcm(c)svstems,

certified redundant

non-redundant

back-up

monitoring systcm(s)svstems,

other approved

mcthod(z)methods

emissions determination:

Date

and hour;

Hourly

mercury

mass emissions

(ounces,

rounded

to three decimal

places);

Identification

code for

emissions formula

used

derive

hourly mercury

mass

emissions

from mercury

concentration,

flow rate and moisture

data,

provided in

Section 1.10

this

Appendix.

Mercury

smission

rccord provisions

(sorbcnt

trap

systcmsEmission

Record

Provisions

(Sorbent

Tran

Systems)

The

owner or

operator must record

for each

hour the

information required

this

paragraphsubsection,

for each affected

unit

using sorbent trap

monitoring systems

in combination

with

flow

rate,

moisture,

and

(in

certain

cases)

diluent

gas monitors,

determine

mercury

mass

emissions and

(if

required)

unit

heat input under

this Part—2-2-5.

For

mercury concentration

during unit

operation,

measured and

reported

from

each

certified

primary

monitor,

certified

back-up

monitor-

other

approved

method

emissions determination:

Component-system

identification

code-

7- as

provided

in Section 1.10

of this

Appendix;

Date and

hour;

Hourly

mercury

concentration

(ig/dscm,

rounded

the

nearest tenth)

. For

particular

pair

of sorbent

traps, this

will

the

flow-proportional

average

concentration

for

the

data collection period;

Method

of determination

for

hourly

average

mercury concentration

using

Codes 1- 55

in Table

4a of

this

Section;

and

Percent monitor

data availability

(recorded

to the nearest

tenth

percent)-

calculated

pursuant

Section 1.8 of

this Appendix;

For flue gas

moisture

content during

unit operation,

measured

and

reported

from

each certified

primary

monitor,

certified back-up

monitor-

other approved

method of

emissions determination

(except where

a default

moisture

value

is approved

under 40 CFR

75.66, incorporated

by reference

Section

225.140),

record

the information

required under

paragraphssubsections

(e)

(2) (A)

through

Cc) (-2-)-(E)

this

Section;

For diluent

gas

(02

C02

)

concentration

during unit

operation

(if

required

for heat

input

determination),

record

the information

required under

paragraphcsubsections

(e) (3)

(A)

through

(E)

of this Section.

For

stack gas

volumetric

flow

rate during unit

operation, as measured

and

reported

from

each certified primary

monitor,

certified

back-up monitor-;-

other approved

method of emissions

determination,

record the information

required

under

40 CFR

75.57(c)

(2)(i)

through

incorporated

reference in

Section

225.140.

For

mercury

mass emissions

during unit operation,

as measured

and reported

from the certified

primary

monitoring

zyztcm(z)svstems,

certified

redundant or

non-redundant

back-up monitoring

cyctom(s)

,svstems or other

approved

mcthod(c)methods

emissions

determination,

record the

information

required

under

paa apithection

(e) (5)

this Section.

Record the

average flow

rate

stack

gas

through each sorbent

trap

(in

appropriate units,

e.g.,

liters/mm, cc/mm,

dscm/min)

Record

the gas

flow

meter reading

(in

dscm, rounded

the

nearest

hundredth)

the beginning and

end of the collection

period

and at least

once

in each

unit

operating

hour

during the collection

period.

Calculate and record

the ratio of

the bias-adjusted

stack gas

flow

rate

the

sample flow rate,

as described

Section 11.2 of

Exhibit D

to this

Appendix.

Table 4a.

- Codes for Method

of Emissions

and Flow

Determination

Codc

Code Hourly

emissions/flow measurement

estimation method

iCertified

primary

emission/flow monitoring

system.2

2Certified backup

emission/flow

monitoring

system.3

3Approved

alternative

monitoring

system.4

Reference

method:17. .

..J.lLike-kind

replacement

non-redundant

bac]cupanalyzcr.32.

. . .backuo analvzer.32Hourly

concentration

determined

from

analysis

of a

single trap

multiplied by

a factor

of 1.111 when

one of the

paired traps

invalidated

or damaged

(See

Appendix

K, 6ee4eç,j

.33...

.Hourly Hg

concentration determined

from

the trap resulting

the

higher

Hg concentration

when

the relative

deviation

criterion for

the

paired

traps is

not met

(See

Appendix

zcctionSection

.40...

.jQFuel

specific

default value

(or

prorated

default

value)

used

for the

hour.54.

.540ther

quality

assured

methodologies approved

through petition.

These

hours are included

missing

data

lookback and are

treated

unavailable

hours for percent

monitor availability

calculations..5S.

.0ther

substitute

data approved

through petition.

These hours

are not

included

in missing

data lookback

and

are

treated

as unavailable

hours

for

percent

monitor availability

calculations.

Section

1.12 General rccordkccping

provisions

for

spocific

cituptionzRcordkeeoino

Provisions

for

Specific

Situations

The

owner or operator

must meet

all of the applicable

recordkeeping

requirements

this Section.

In accordance

with

40 CFR 75.34,

incorporated

by reference

Section

225.140, the

owner

or operator of

an affected

unit

with add-on

emission

controls

must

record

the

applicable

information

this Section for

each hour of

missing mercury concentration data. Except as otherwise provided in 40 CFR

75.34(d),

incorporated by reference in Section 225.140, for units with

add-on

mercury emission controls, the owner or operator must record:

Parametric data

wh4-eth

demonstrate, for each

hour

missing mercury

emission

data, the

proper

operation of the add-on emission controls,

described

in the

quality assurance/quality control program for the unit. The

parametric

data

must be maintained on site and must

submitted, upon request,

the Agency. Alternatively, for units equipped with flue

gas

desulfurization

(FGD)

systems, the owner or operator may use quality-assured data from

certified S02 monitor to demonstrate proper operation of the emission controls

during periods of

missing mercury

data;

A flag

indicating, for each

hour of missing mercury emission data, either

that the add-on

emission controls

are operating properly, as evidenced by all

parameters being

within the ranges

specified in the quality assurance/quality

control program, or

that the

add-on emission controls are not operating

properly.

Section 1.13

Certification, quality azcurancc,

and

quality control record

provicioncOualitv

Assurance and

Quality Control Record Provisions

The owner or operator must meet all of the applicable recordkeeping requirements

of this Section.

Continuous

cmiocion monitoring cyctcmcEmission Monitorinc Systems.

The

owner or operator must 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.

For each

flow

monitor, mercury

monitor-r

or diluent gas monitor (including

wet- and

dry-basis 02 monitors

used to

determine percent

moisture)

, the owner or

operator must

record the following for all daily and

7-day

calibration error

tests, all

daily system integrity checks-- and all off-line calibration

demonstrations, including any follow-up tests after corrective action:

Component-system identification code

(on

and after January 1, 2009, only

the

component identification code is required);

Instrument span and span scale;

Date and hour;

Reference value

(i.e.,

calibration

gas

concentration or reference signal

value,

in ppm or other appropriate

units)

Observed value

(monitor

response during calibration, in ppm or other

appropriate units);

Percent

calibration

error

(rounded

to the nearest tenth of a percent)

(flag if using

alternative

performance specification for low emitters or

differential

pressure flow monitors)

Reference signal or calibration

gas

level;

For 7-day

calibration

error tests, a test number and reason for test;

For

7-day

calibration tests for certification or recertification, a

certification from the cylinder gas vendor or CEMS vendor that

calibration

gas,

defined in 40 CFR 72.2, incorporated by reference in Section

225.140, and

Exhibit A

this Appendix, was used to conduct calibration error

testing;

Description

any adjustments,

corrective

actions-p

maintenance prior

to a passed test

or following

failed test; and

Indication of whether the unit is off-line or on-line.

For each flow

monitor,

the

owner or

operator must

record the following for

all daily interference checks,

including

any follow-up tests after

corrective

action.

Component-system identification code

(after

January 1, 2009, only the

component

identification

code

is required);

Date and hour;

Code indicating whether monitor passes or fails the interference

check;

and

Description of any adjustments, corrective actions-

7or

maintenance prior

to a

passed test or following a failed test.

For

each mercury concentration -

monitor or diluent

gas

monitor (including

wet- and

dry-basis 02 monitors

used to

determine percent

moisture),

the owner or

operator must

record the following for the initial and all subsequent linearity

chcck(o)checks

and 3-level system integrity checks (mercury monitors with

converters-7only),

including any follow-up

tests

after corrective action:

Component-system identification

code

(on

and after July 1, 2009, only the

component

identification

code

is required);

Instrument span

and span scale (only span scale is required on and after

July 1,

2009)

Calibration

gas

level;

Date

and time

(hour

and

minute)

of each gas injection at each calibration

gas

level;

Reference value

(i.e.,

reference gas concentration for each gas

injection

each calibration gas level, in ppm or other appropriate units);

Observed value

(monitor

response to each

reference

gas

injection

each

calibration gas

level,

in ppm or

other appropriate units);

Mean

reference values and mean of measured values

each calibration

gas

level;

Linearity error

each of the reference gas concentrations

(rounded

nearest

tenth of

percent) (flag if using alternative performance

specification)

Test number and reason for test (flag if aborted test); and

Description of any adjustments, corrective

action-i-

or maintenance prior to

a passed test

or following

failed test.

For each

differential pressure

type

flow monitor, the owner or operator

must record

items in paragraphssubsections

(a) (4) (A)

through

(E)

of this

Section, for all

quarterly leak checks, including any follow-up

tests

after

corrective action.

For each flow monitor,

the

owner

or operator

must record

items in

paragraphzsubsections

(a)

(4)

(F)

and

(G)

of this Section for all flow-

to-load ratio and

gross heat rate

tests:

Component-system identification

code

(on

and after July 1, 2009, only the

system

identification code is required)

Date

and

hour.

Reason for test.

Code

indicating whether monitor

passes or

fails

the

quarterly leak check.

Description of

any

adjustments, corrective actions-i- or maintenance prior

a passed test or

following

a failed test.

Test data from the flow-to-load ratio or gross heat rate

(GHR) evaluation,

including:

Monitoring system identification code;

ii)

Calendar year and quarter;

iii)

Indication of whether the test is a flow-to-load ratio or gross heat rate

evaluation;

iv)

Indication of whether bias adjusted flow rates were used;

Average absolute percent

difference between reference ratio

(or GHR)

and

hourly ratios

(or

GHR values);

vi)

Test

result;

vii)

Number of hours used in final quarterly average;

viii) Number of hours exempted for use of a different fuel type;

ix)

Number of hours exempted for load ramping

or down;

Number of hours exempted for scrubber

bypass;

xi)

Number of hours exempted for hours preceding a normal-load flow RATA;

xii)

Number of hours exempted for hours preceding a successful

diagnostic

test,

following a documented monitor

repair

or major component replacement;

xiii)

Number of

hours

excluded

for

flue gases

discharging simultaneously

thorough a main

stack

and a bypass stack;

and

xiv)

Test number.

Reference data for the flow-to-load ratio or gross heat rate evaluation,

including

(as

applicable):

Reference flow RATA end date and time;

ii)

Test number of the reference RATA;

iii)

Reference

RATA load

and

load level;

iv)

Average

reference method flow rate

during reference

flow

RATA;

Reference flow/load ratio;

vi)

Average reference method diluent gas concentration during flow RATA and

diluent

gas

units of measure;

vii)

Fuel specific Fd-or Fc-factor during flow RATA and F-factor units of

measure;

viii)

Reference gross heat rate value;

ix)

Monitoring system identification code;

Average hourly heat input rate during RATA;

xi)

Average gross unit load;

xii)

Operating load level; and

xiii)

An indicator

(-‘1-flag-’1-) if

separate

reference

ratios are calculated for each

multiple stack.

For

each flow monitor, each diluent

gas

(02

C02)

monitor

used to

determine heat

input, each moisture monitoring system, mercury concentration

monitoring

system,

each sorbent trap monitoring

system-r

and each approved

alternative

monitoring system, the owner or operator must record the following

information for the

initial and

all

subsequent relative accuracy

test audits:

Reference

mcthod(c)methods

used.

Individual

test

run data from the relative accuracy

test

audit for

the

flow

monitor, C02 emissions concentration monitor-diluent continuous emission

monitoring system, diluent gas

(02

C02)

monitor

used to

determine heat

input,

moisture monitoring system, mercury concentration monitoring system, sorbent

trap

monitoring

system-r

or approved alternative monitoring system, including:

Date,

hour-r

and minute of beginning of test run;

ii)

Date,

hour-r

and minute of end of test run;

iii)

Monitoring system identification code;

iv)

Test number and reason for

test;

Operating level

(low,

mid, -

high- or normal,

appropriate) and number

operating levels comprising test;

vi)

Normal load

(or

operating

level)

indicator for flow RATAs (except for

peaking

units);

vii)

Units of measure;

viii)

Run number;

ix)

Run value

from CEMS being tested, in the appropriate units of measure;

Run value

from reference method, in the appropriate units of measure;

xi)

Flag value

(0, --1

9, as appropriate)

indicating whether run has

been

used

in calculating

relative accuracy

and bias

values

whether

the test was

aborted prior to

completion;

xii)

Average

gross unit load, expressed

as a

total gross unit load, rounded

the

nearest MWe, or as steam load, rounded

the nearest

thoucandl000

lb/hr-)-,

except

for units that do not produce electrical or thermal output; and

xiii)

Flag to indicate whether an alternative performance specification has been

used.

Calculations and tabulated results, as follows:

Arithmetic mean of the monitoring system measurement

values-r

of the

reference method values, and of their differences, as specified in Equation A-7

in Exhibit

this Appendix;

ii)

Standard deviation, as specified in Equation A-S in Exhibit A to this

Appendix;

iii)

Confidence coefficient, as specified in Equation A-9 in Exhibit A to this

Appendix;

iv)

Statistical -‘-t-- value used

in calculations;

Relative accuracy

test

results,

specified in Equation A-b in Exhibit

to this

Appendix. For multi-level flow monitor tests the relative accuracy

test

results

must

recorded at each load

(or

operating) level tested. Each load

(or

operating) level must

expressed as a total gross unit load, rounded to the

nearest

MWe, or

steam load, rounded

the nearest

he-s-an4IQjQ.

lb/hr, or

otherwise

specified

the Agency, for units that

not produce electrical or

thermal

output;

vi)

Bias test results as specified in Section 7.4.4 in Exhibit A to this

Appendix; and

Description of any adjustment, corrective action-

7-or maintenance prior to

a passed

test or following a failed or aborted test.

For flow monitors, the equation used to linearize the

flow monitor

and the

numerical

values

the

polynomial coefficients

or K

factor(s)

factors

of that

equation.

For moisture monitoring systems,

the

coefficient or

1LK!L

factor or other

mathematical algorithm used to adjust the monitoring system with

respect

the

reference method.

For each

mercury concentration monitor, and each C02 or 02

monitor

used to

determine heat input,

the owner or operator must record the

following

information for the cycle time test:

Component-system identification code

(on

and after

July 1, 2009, only the

component identification code is required);

Date;

Start and end

times;

Upscale and

downscale cycle times for each component;

Stable start

monitor value;

Stable end

monitor value;

Reference value

of calibration

gas(ez)

;ases:

Calibration gas

level;

Total cycle time;

Reason

for test; and

Test number.

addition

the

information in pa ag phi1hactiQn

(a) (5)

this

Section, the

owner or operator must record, for each relative accuracy test

audit,

supporting information sufficient to substantiate compliance

with

all

applicable

ccctionoSections and

appcndicczAoendices

in this partPart.

Unless

otherwise

specified in this partPart or in an applicable test

method, the

information in paragraphssubsections

(a) (7) (A)

through

(a) (7)

(H) of this Section

may be

recorded either in hard copy format,

electronic format or

combination

of the

two, and the owner or operator must

maintain this information in a format

suitable

for inspection and audit purposes. This

RATA supporting information

must include,

but must not be limited to, the following data

elements:

For each RATA using Reference Method 2

(or

its

allowable

alternatives)

appendix A to 40 CFR 60, incorporated by

reference in Section 225.140, to

determine volumetric flow rate:

Information indicating

whether or not the location meets requirements of

Method 1 in appendix A to 40

CFR

60,

incorporated

reference in Section

225.140; and

ii)

Information indicating whether or not the equipment passed the required

leak checks.

For each run of each RATA using Reference Method 2

(or

its

allowable

alternatives

in appendix A to 40 CFR 60, incorporated by reference in

Section

225.140)

determine volumetric flow rate, record the following data

elements

(as

applicable to the measurement method

used)

Operating level

(low,

mid,

high-r

or normal,

appropriate);

ii)

Number of

reference method traverse

points;

iii)

Average stack

gas

temperature (°F);

iv)

Barometric

pressure

at test port

(inches

of mercury);

Stack static pressure

(inches

of H20);

vi)

Absolute stack gas pressure

(inches

of mercury)

vii)

Percent C02 and 02 in the stack gas, dry basis;

viii)

CO2 and 02 reference method used;

ix)

Moisture

content

stack

gas (percent H20);

Molecular

weight

of stack gas, dry basis (lb/lb-mole);

xi)

Molecular weight of stack

gas,

wet

basis

(lb/lb-mole);

xii)

Stack

diameter

(or

equivalent diameter)

at the test

port

(ft);

xiii)

Average

square root of velocity

head of stack gas

(inches

H20)

for the

run;

xiv)

Stack

or duct

cross-sectional area

at test

port (ft2);

xv)

Average

velocity

(ft/sec);

xvi)

Average

stack flow rate, adjusted, if applicable, for wall effects

(scfh,

wet

basis)

xvii)

Flow rate reference method used;

xviii)

Average velocity, adjusted for wall effects;

xix)

Calculated (site-specific) wall effects adjustment factor determined

during the run, and, if different, the wall effects adjustment factor used in

the

calculations; and

xx)

Default wall effects adjustment factor used.

For each traverse point of each run of each RATA using Reference Method 2

(or its allowable alternatives in appendix A to 40 CFR 60, incorporated by

reference in Section

225.140)

to determine volumetric flow rate, record the

following data elements

(as

applicable to the measurement method

used)

Reference method probe type;

ii)

Pressure measurement device type;

iii)

Traverse point ID;

iv)

Probe or pitot tube calibration coefficient;

Date of latest probe

or pitot

tube calibration;

vi)

Average velocity differential pressure

traverse

point

(inches

H20)

or the

average of the square roots of the velocity differential pressures at the

traverse point

((inches

of H20)l/2);

vii)

TS, stack temperature at the traverse point (°F);

viii)

Composite

(wall effects)

traverse point identifier;

ix)

Number of points included in composite traverse point;

Yaw angle of flow at traverse point (degrees);

xi)

Pitch angle of flow at traverse point (degrees);

xii)

Calculated velocity at

traverse

point both accounting and not accounting

for wall effects (ft/sec)

;

and

xiii)

Probe

identification number.

For each RATA using eMethod 3A in appendix A to 40 CFR 60, incorporated

reference in Section 225.140, to determine-i- C02, or 02 concentration:

Pollutant or diluent gas being measured;

ii)

Span

of reference method analyzer;

iii)

Type of reference method system (e.g., extractive or dilution type);

iv)

Reference method dilution factor

(dilution

type

systems-r

only);

Reference gas concentrations

(zero,

mid-

and high

gas

levels)

used for the

3-point pre-test analyzer

calibration

error test

(or,

for

dilution

type

reference method

systems, for

the 3-point

pre-test system calibration error

test)

and for any subsequent

recalibrations;

vi)

Analyzer

responses

the

zero-, mid--

and high-level calibration

gases

during the 3-point

pre-test

analyzer

(or

system)

calibration error

test and

during any

subsequent rccalibration(z)recalibrations;

vii)

Analyzer calibration error

each

gas

level

(zero,

mid-

7 and high) for the

3-point

pre-test analyzer

(or

system) calibration error test and for any

subsequent

rccalibration(z)recalibrations (percent of span value);

viii)

Upscale gas concentration

(mid

or high gas

level)

used for each pre-run or

post-run system bias check or

(for

dilution type reference method systems) for

each pre-run or post-run system calibration error check;

ix)

Analyzer response

the calibration

gas

for each pre-run or post-run

system bias

(or

system calibration error) check;

The

arithmetic average of the analyzer responses

the zero-level

gas,

for

each

pair of pre- and post-run

system

bias

(or

system calibration

error)

checks;

xi)

The arithmetic average of the analyzer responses

to the upscale

calibration

gas-

for each pair of pre- and

post-run system bias

(or

system

calibration

error)

checks;

xii)

The results of each pre-run and each post-run

system bias

(or

system

calibration

error)

check using the zero-level

gas (percentage of span

value);

xiii)

The results of each pre-run and each post-run

system bias

(or

system

calibration

error)

check using the upscale calibration

gas (percentage of span

value);

xiv)

Calibration drift and zero drift of analyzer during each RATA run

(percentage of span

value)

xv)

Moisture basis of the reference method analysis;

xvi)

Moisture

content of stack gas, in percent, during each

test

run

(if

needed

convert to moisture basis of CEMS being tested);

xvii)

Unadjusted

(raw)

average pollutant or diluent gas concentration for each

run;

xviii)

Average pollutant or diluent gas concentration for each run,

corrected for calibration bias

(or

calibration

error)

and, if applicable,

corrected for moisture;

xix)

The F-factor used to convert reference method data to units of lb/mmBtu

(if

applicable);

xx)

Datc(c)Dates

of the latest analyzer interference

tcst(z)tests;

xxi)

Results of the latest analyzer interference

tczt(s);tests: and

xxii)

For each calibration gas cylinder used during each RATA, record the

cylinder gas

vendor,

cylinder number, expiration date, pollutant(z)ollutants in

the cylinder-

and certified

gas

conccntrat±on(z)concentrations.

For each

test

run of each moisture determination using Method 4 in

appendix A

40 CFR

60,

incorporated

reference in Section 225.140,

(or

its

allowable

alternatives),

whether the determination is made

support

a gas

RATA,

support a flow RATA-

7 or

quality assure the

data

from

continuous

moisture monitoring system, record the following data elements

(as

applicable

the

moisture measurement method

used)

Test number;

ii)

Run number;

iii)

The beginning date, 7

hour- and minute of the run;

iv)

The ending date, hour-i- and minute of the run;

Unit operating level

(low,

mid,

high-- or normal, as appropriate);

vi)

Moisture measurement method;

vii)

Volume of H20 collected in the impingers (ml);

viii)

Mass

H20 collected in the silica gel

(g);

ix)

Dry

gas

meter calibration factor;

Average dry gas

meter temperature (°F);

xi)

Barometric

pressure

(inches

of mercury);

xii)

Differential

pressure across the orifice meter

(inches

H20)

xiii)

Initial and

final dry

gas

meter readings

(ft3

);

xiv)

Total sample gas

volume, corrected

standard conditions

(dscf)

;

and

xv)

Percentage

of moisture in the stack

gas

(percent

H20)

The raw data

and calculated results for any stratification tests performed

in accordance

with Sections 6.5.5.1 through 6.5.5.3 of Exhibit A to this

Appendix.

For each

RATA run using the Ontario Hydro Method

determine mercury

concentration:

Percent

C02 and 02 in the stack

gas,

dry basis;

ii)

Moisture

content of the stack

gas

(percent H20);

iii)

Average

stack temperature (°F);

iv)

Dry gas

volume metered

(dscm)

Percent

isokinetic;

vi)

Particle-bound mercury collected by the filter,

biank-

and probe rinse

(igm);

vii)

Oxidized mercury collected by the KCl impingers (igm);

viii)

Elemental mercury collected in the HNO3/H202 impinger and

in the

KMnO4/H2S04

impingers (igm);

ix)

Total

mercury, including particle-bound mercury (igm); and

Total

mercury, excluding particle-bound mercury

(agm)

All appropriate data elements for Methods 30A

and 30B.

For a

unit with

flow monitor installed on a rectangular stack

duct,

if a

site-specific default or measured wall effects adjustment

factor (WAF)

used to

correct the stack gas volumetric flow rate data to

account for velocity

decay near

the stack or duct wall, the owner or operator must

keep records of

the

following for each

flow

RATA performed with EPA Method

2 in appendices A-i

and

A-2

40 CFR 60, incorporated by reference in

Section 225.140, subsequent

the WAF

determination:

Monitoring

system

ID;

ii)

Test number;

iii)

Operating

level;

iv)

RATA

end date

and time;

Number of Method 1 traverse points;

and

vi)

Wall effects adjustment factor

(WAF),

to the nearest 0.0001.

For each RATA run using Method 29 in

appendix A-8 to 40 CFR 60,

incorporated

reference in Section 225.140,

to determine mercury

concentration:

Percent CO2 and 02 in the stack

gas, dry basis;

ii)

Moisture content of the stack

gas (percent H2O);

iii)

Average stack gas temperature (°F);

iv)

Dry gas volume metered (dscm);

Percent isokinetic;

vi)

Particulate mercury collected in the front half of the sampling train,

corrected

for the

front-half

blank value (ig); and

vii)

Total

vapor

phase

mercury collected in the back half of the sampling

train, corrected for the back-half blank value (ig-)---om)

For each certified continuous emission monitoring system, excepted

monitoring system-- or alternative monitoring system, the

date

and

description of

each event

w4-eh,h

requires certification,

recertification-r

or certain

diagnostic testing of the system and the

date

and

type

of each

test performed.

If the conditional data validation procedures of Section

1.4(b)

(3)

this

Appendix are to be used to validate and report data prior

the

completion

the required

certification,

recertification-- or diagnostic testing, the

date

and

hour of the

probationary calibration

error test must be reported to mark

the

beginning of conditional

data

validation.

Hardcopy relative accuracy

test

reports,

certification reports,

recertification

reports-r

or semiannual

annual

reports for gas or flow rate

CEMS, mercury CEMS-- or sorbent trap monitoring systems

are required or requested

under 40 CFR

75.60(b) (6)

or 75.63, incorporated

reference in

Section 225.140,

the

reports must include, at

minimum, the following

elements

-(-as

applicable

the

typc(c)tvoes of

tcct(s)tests

performed:

Summarized test results.

DAHS printouts of the CEMS data generated during the calibration error,

linearity,

cycle

time-r

and relative accuracy

tests.

For pollutant concentration monitor or diluent monitor relative

accuracy

tests

at normal operating load:

The raw

reference method data from each run, i.e., the data under

par-a--aphibsection

(a) (7) (D) (xvii)

of this Section (usually in the form

computerized printout,

showing

series of one-minute readings and the run

average);

ii)

The raw data and

results for all required pre-test, post-test, pre-run and

post-run quality

assurance checks

(i.e.,

calibration gas injections) of the

reference method

analyzers,

i.e.,

the

data

under paragraphzsulDsections

(a)

(7) (D) (v)

through

(a)

(7) (D)

(xiv) of this Section;

iii) The raw data

and results for any moisture measurements made

during the

relative accuracy

testing, i.e., the

data

under paragraphzsubsections

(a)

(7) (E) (i)

through

(a) (7) (E)

(xv)

of this Section; and

iv)

Tabulated,

final, corrected reference method run data

(i.e.,

the actual

values used in

the relative accuracy

calculations),

along with the

equations

used

convert the raw data to the final values and example

calculations

demonstrate

how the test data were reduced.

For

relative accuracy tests for flow monitors:

The raw

flow rate reference method data, from Reference Method

2 (or

its

allowable

alternatives)

under appendix A to 40 CFR 60, incorporated by

reference

in Section

225.140, including auxiliary moisture data

(often

the

form of

handwritten data

sheets),

i.e., the

data

under

paragraphzsubsections

(a)

(7) (B) (i)

through

(a) (7) (3) (xx),

paragraphcsubsections

(a) (7) (C) (i)

through

(a) (7) (C) (xiii),

and, if applicable,

paragraphssubsections

(a) (7) (E)

(i) through

(a) (7) (E) (xv)

this Section; and

ii)

The

tabulated, final volumetric flow rate

values

used

in the relative

accuracy

calculations

(determined

from the

flow rate reference method data and

other

necessary measurements, such as moisture,

stack temperature and pressure)

along

with the equations used to

convert

the

raw

data to

the

final values and

example

calculations to demonstrate

how

the test data

were reduced.

Calibration gas certificates

for the

gases

used in the linearity,

calibration

error-r

and

cycle time

tests

and for the calibration gases used to

quality assure

the

gas

monitor reference method data during the

relative

accuracy test

audit.

Laboratory

calibrations of the source sampling equipment.

For sorbent trap

monitoring

systems, the

laboratory analyses of all sorbent traps-7

and

information documenting the

results of all leak checks and other

applicable

quality control procedures.

copy

of the test

protocol

used

for the CEMS certifications or

recertifications, including

narrative that explains any testing

abnormalities,

problematic

sampling,

and

analytical conditions that required a

change

the

test

protocol,

and/or solutions

technical problems encountered

during the

testing

program.

Diagrams illustrating test locations and

sample

point

locations

(to

verify

that

locations are consistent with

information in the monitoring plan) . Include

discussion of any special

traversing

measurement scheme. The discussion

must

also confirm that

sample points satisfy applicable acceptance criteria.

Names of key

personnel involved in the

test program, including test

team

members, plant contacts,

agency representatives

and test observers on

site.

10)

Whenever

reference methods are

used as backup monitoring systems

pursuant

to Section

1.4(d) (3)

of this Appendix, the owner

operator

must

record the

following

information:

For each test run using Reference Method 2

(or

its allowable alternatives

appendix A

40 CFR

60,

incorporated

reference in Section

225.140)

determine volumetric flow rate, record the following

data

elements

(as

applicable

the

measurement method

used)

Unit

or stack identification number;

ii)

Reference method system and component identification numbers;

iii)

Run date

and hour;

iv)

The data

ahction (a)

(7) (B) of

this

Section, except for

paragraphcsubsections

(a) (7) (B) (i), (vi), (viii),

(xii)T

and

(xvii)

through

(xx); and

The data in

(a) (7) (C),

except on a run basis.

For each reference method test run using Method

6C,

7E-

7- or 3A in appendix

A to

40 CFR 60, incorporated by reference in Section 225.140, to determine S02,

NOx,

C02--2.

or 02 concentration:

Unit or stack identification number;

ii)

The reference method system and component identification numbers;

iii)

Run number;

iv)

Run start date and hour;

Run

end

date

and hour;

vi)

The

data

paragraphosuiDsections

(a) (7) CD) (ii)

through

(ix)

and

(xii)

through (xv); and

(vii)

Stack gas density adjustment factor

(if

applicable)

For each hour of each

reference

method test run using

Method

6C,

7E-

or 3A

appendix A to 40 CFR 60,

incorporated

reference

Section 225.140,

determine S02, NOx,

C02,

02 concentration:

Unit or stack identification number;

ii)

The reference method system and component identification numbers;

iii)

Run number;

iv)

Run date and hour;

Pollutant or

diluent

gas being measured;

vi)

Unadjusted

(raw)

average pollutant or diluent gas

concentration for

the

hour; and

vii)

Average

pollutant or

diluent gas concentration for the hour, adjusted as

appropriate

for moisture,

calibration bias

(or

calibration

error)

and stack gas

density.

11)

For each

other quality-assurance test or other

quality assurance activity,

the owner or

operator must record

the following

(as

applicable)

Component/system identification code;

Parameter;

Test

or activity

completion

date

and hour;

Test

activity

description;

Test

result;

Reason for test; and

Test code.

12)

For each request

for

quality assurance test

extension or exemption, for

any loss

of exempt status,

and for each single-load flow RATA

claim pursuant

Section

2.3.1.3(c) (3)

Exhibit B

this Appendix, the

owner

operator

must

record

the following

(as

applicable)

For a

RATA deadline

extension or exemption request:

Monitoring system identification code;

ii)

Date

of last RATA;

iii)

RATA

expiration date without

extension;

iv)

RATA expiration date

with extension;

Type

of RATA extension of exemption

claimed or lost;

vi)

Year

date hours of usage of

fuel other than very low sulfur

fuel;

vii)

Year to

date hours of non-redundant

back-up CEMS usage at the unit/stack;

and

viii)

Quarter and year.

For a

linearity test or flow-to-load

ratio

test

quarterly exemption:

Component-system identification code;

ii)

Type

of test;

iii)

Basis for exemption;

iv)

Quarter

and

year;

and

Span

scale.

For

fuel

flowmeter accuracy

test extension:

Component-system

identification

code;

ii)

Date of last

accuracy test;

iii)

Accuracy test

expiration date without extension;

iv)

Accuracy test

expiration date with extension;

Type of

extension; and

vi)

Quarter and year.

For a

single-load

(or

single-level) flow RATA claim:

Monitoring

system identification

code;

ii)

Ending date

of last annual flow RATA;

iii)

The

relative frequency (percentage) of unit or stack operation at each

load

(or

operating)

level

(low, mid-r

and high) since the previous annual flow

RATA, to the

nearest 0.1 percent;

iv)

End date

of the historical load

(or

operating

level)

data collection

period;

and

Indication

of the load (or operating) level

(low,

mid or high) claimed for

the single-load

flow RATA.

13)

For the sorbent traps used in sorbent

trap monitoring systems

quantify

mercury concentration under Sections 1.14

through 1.18

this Appendix

(including sorbent traps used for relative

accuracy

testing),

the owner or

operator must keep records of the following:

The ID number

the monitoring

system in which each sorbent trap was

used

collect mercury;

The unique identification

number

each sorbent

trap;

The beginning and ending dates

and hours of the

data

collection period for

each sorbent trap;

The

average mercury concentration

(in

igm/dscm) for the data collection

period;

Information documenting the results of the required leak checks;

The analysis of the mercury collected by each sorbent trap; and

Information documenting

the

results of the other applicable quality

control

procedures in Section

1.3

of this Appendix and in Exhibits B and D to

this

Appendix.

Except

otherwise provided in Section

1.12(a)

of this Appendix, for

units

with add-on mercury emission controls, the owner or operator must keep the

following records on-site in the quality

assurance/quality control plan required

by Section 1 of

Exhibit B

this Appendix:

A list of operating parameters

for

the add-on emission

controls, including

parameters in

Section

1.12 of this Appendix, appropriate to the

particular

installation

of add-on emission controls; and

The range

of each operating parameter in the list that

indicates the add-

on emission

controls are properly operating.

Excepted

monitoring for mcrcury low macc emiccion unitcMonitorine

for

Mercury

Low

Mass

Emission Units

under Section

1.15(b)

of this

Appendix. For

qualifying

coal-fired units using the alternative low mass

emission methodology

under Section

1.15(b),

the owner or operator must record the data

elements

described

Section

1.13(a) (7) (G),

Section

1.13(a) (7)

(H)-;- or

Section

1.13(a) (7) (J)

of this Appendix, as applicable, for each run of

each mercury

emission test

and re-test required under Section

1.15(c) (1)

or Section

1.15(d) (4) (C)

of this Appendix.

DAHS

Verification.

For each

DAHS (missing

data

and

formula)

verification

that

is required

for initial certification, recertification-;- or for certain

diagnostic testing of a

monitoring system, record the

date

and hour that the

DAHS

verification is

successfully completed.

(This

requirement only applies to

units

that report monitoring plan data

in accordance with Section

1.10(d)

this

Appendix.)

Section

1.14 General

provicioncProvisions

Applicability. The owner or

operator of

unit must comply with the

requirements of this Appendix to the extent

that compliance is required by this

Part

225. For purposes of this Appendix, the

term “affected unit” means any

coal-fired

unit

(as

defined in 40 CFR 72.2, incorporated by

reference)

that is

subject

this

Part

225..

The term “non-affected

unit”

means any unit that is

not subject to

such a program, the term

“permitting authority” means the Agency,

and

the term

TTdesignated

representative” means the responsible party under

this

Part

225.

Compliance datecDates.

The owner or operator of an affected

unit

must

meet

the compliance

deadlines established

Part 225, Subpart B

of this Part.

Prohibitions.

owner or operator of an affected unit or a

non-affected unit under

Section

1.16(b) (2) (B)

of this Appendix will use any

alternative monitoring

system,

alternative reference method-7-or any

other alternative for the required

continuous

emission monitoring system without

having obtained prior written

approval

accordance with

paa ap

bedJQn

(f)

of this

Section.

owner or operator of an affected unit or a non-affected

unit under

Section

1.16(b) (2) (B)

of this Appendix will operate the unit so as to

discharge,

or allow to be

discharged. emissions of mercury to the

atmosphere without

accounting

for all such emissions in accordance with the

applicable provisions

this Appendix.

No owner or operator

of an affected unit or

non-affected unit under

Section

1.16(b) (2)

(B)

this Appendix will disrupt the continuous

emission

monitoring

system,

any

portion

thereofof the system,

or any other

approved

emission

monitoring method,

and

thereby

avoid monitoring

and recording mercury

mass emissions

discharged

into

the

atmosphere,

except

for periods of

recertification

periods

when calibration,

quality

assurance

testingT

maintenance

performed in

accordance

with the

provisions

this

Appendix

applicable

monitoring

systems

under Section 1.15

of this

Appendix.

owner or

operator

of an affected

unit

non-affected

unit

under

Section

1.16(b)

(2)

(B)

will

retire or

permanently

discontinue

use

the

continuous

emission monitoring

system, any component

thcrcofof

the

system,

any

other

approved emission

monitoring system

under this Appendix,

except under

any

one of the following

circumstances:

During the

period that

the

unit is covered

by a retired

unit

exemption

that

is in

effect

under

this

Part 225; or

The owner or

operator

is monitoring

mercury mass emissions

from

the

affected

unit

with

another certified

monitoring system

approved,

accordance

with

the

provisions

of Section 225.250;

or250 of

this

Part:

The

designated representative

submits

notification of

the date of

certification

testing

of a replacement

monitoring system

in accordance with

Section

240(d)

of this

Part

225.240

Cd).

Quality

aczurancc

and

quality

control

rcquircmcntsAssurance

and Quality

Control

Recuirements. For

units that

use

continuous

emission

monitoring

systems

to account

for mercury

mass emissions,

the owner or operator

must meet

the

applicable

quality

assurance and quality

control requirements

Section

1.5

and

Exhibit B

to this Appendix for

the flow monitoring

systems,

mercury

concentration

monitoring

systems,

moisture monitoring

systems-

and diluent

monitors

required

under

Section

1.15 of this

Appendix.

Units using

sorbent trap

monitoring

systems

must

meet

the applicable

quality

assurance requirements

Section

1.3 of this

Appendix,

Exhibit

D to this

Appendix, and Sections

1.3 and

2.3

Exhibit

B to

this

Appendix.

Reporting data—p

e—Ee-—in

ial—eer-t-i-f-i-eat

ata Prior

Initial

Certification.

If, by the applicable

compliance date

under

this

Part

225,

the

owner

operator

of an affected

unit has not

successfully completed

all

required

certification tests

for

any monitoring

cystcm(c)svstems,

she

must

determine,

record, and

report

data

prior

initial certification

in accordance

with

Section

225.239231

this Part.

Petitions.

The

designated representative

of an

affected unit

that is also

subject to

the

Acid

Rain Program

may submit

petition

the

Agency

requesting an

alternative

any requirement

of Sections

1.14 through

1.18 of this

Appendix.

Such

petition

must meet the

requirements

40 CFR 75.66, incorporated

reference

in Section 225.140,

and

any

additional

requirements

established

Part

225, Subpart B

of this

Part.

Use

an alternative

to any requirement

Sections

1.14 through

1.18 of this

Appendix is in accordance

with

Sections

1.14

through

1.18 of

this

Appendix

and

with

Part

225,

Subpart

of this

Part

only

the

extent

that the

petition

is approved in writing

by the

Agency.

Notwithstanding

paragraphsu.bsection

(f)

(1)

of this Section, petitions

requesting

an alternative to

a requirement

concerning

any additional

CEMS

required

solely to meet the

common

stack

provisions

of Section

1.16 of this

Appendix

must be submitted

the Agency

and will

governed

paragraphsubsection

(f) (3)

of this

Section.

Such

a petition must meet

the

requirements

of 40

CFR 75.66,

incorporated

reference in Section

225.140, and

any

additional

requirements

established

Part 225, Subpart

this

Part.

The designated

representative

of an affected

unit

that is not subject

the Acid Rain

Program may

submit

petition

the

Agency requesting

alternative

to any

requirement

Sections

1.14

through 1.18 of

this Appendix.

Such a petition

must

meet

the

requirements

of 40 CFR 75.66,

incorporated by

reference

in Section

225.140,

and

any

additional

requirements

established

Part

225, Subpart

of this

Part.

Use

of an alternative

any requirement

Sections 1.14

through 1.18 of this

Appendix is in

accordance with Sections

1.14

through

1.18 of this

Appendix

only to the extent

that

is approved

in writing

by the Agency.

Section

1.15 Monitoring

of mcrcury

mass cmissions and

hcat input at thc

unit

lcvclMercurv Mass

Emissions and

Heat Inout

at the

Unit

Level

The owner

or operator of

the affected coal-fired

unit must:

Meet

the

general

operating

requirements

in Section

1.2 of this Appendix

for the following

continuous emission

monitors

(except

provided

in accordance

with subpart

of 40 CFR 75,

incorporated by reference

in Section

225.140):

A mercury concentration

monitoring

system

(consisting

of a

mercury

pollutant

concentration

monitor and

automated

DAHS,

which provides

permanent, continuous

record of

mercury emissions

units of

micrograms

per

standard

cubic

meter (rig/scm))

or a

sorbent

trap monitoring

system-r

measure

the mass

concentration of

total vapor

phase

mercury in

the flue

gas,

including

the

elemental and oxidized

forms of

mercury,

in micrograms

per standard cubic

meter

(jig/scm)

;

and

A flow

monitoring system;

A continuous moisture

monitoring

system

(if

correction

of mercury

concentration

for

moisture is required),

described

in 40 CFR

75.11(b),

incorporated

reference in Section

225.140.

Alternatively,

the

owner or

operator may

use the appropriate

fuel-specific

default

moisture

value provided

in 40

CFR

75.11, incorporated

reference

Section

225.140,

site-

specific

moisture value

approved

petition under

CFR

75.66,

incorporated

reference

Section

225.140; and

If heat

input is

required

to be

reported

under

this

Part 225, the owner

operator

must meet the

general operating

requirements

for

flow monitoring

system and

02 or C02

monitoring

system to measure

heat

input

rate.

For

affected

unit

that emits 464 ounces

(29 lb)

mercury per year

less,

use the following

excepted monitoring

methodology.

To implement this

methodology

for

qualifying unit,

the owner

operator

must meet the

general

operating requirements

in Section

1.2 of this

Appendix

for the continuous

emission

monitors

described

in paragraphssubsections

(a) (2)

and

(a) (4)

of this

Section,

and perform mercury

emission testing

for initial

certification

and on

going

quality-assurance,

as described in

paragraphssubsections

(c)

through

(e)

this Section.

To determine

whether an

affected

unit

is eligible

to use

the

monitoring

provisions

in paragraphsubsections

(b)

of this Section:

The owner or operator must perform mercury emission testing within 18

months

before

the

compliance date in Section

1.14(b)

of this Appendix-7to

determine

the

mercury concentration

(i.e.,

total vapor phase mercury) in the

effluent.

The testing must be

performed using one of

the

mercury reference methods

listed in Section

1.6(a) (5)

of this Appendix, and must consist of a minimum of 3

runs at the

normal unit operating load, while combusting coal. The coal

combusted during

the testing must

representative of the coal that will be

combusted at the

start of the mercury mass emissions reduction program

(preferably

from the same

courcc(z)sources

of supply).

The minimum time per run must be 1 hour if Method 30A is used.

If either

Method

29 in appendix A-8 to 40 CFR 60, incorporated by reference,

ASTM D6784-02

(the

Ontario Hydro

method)

(incorporated by reference under

Section 225.l40)-

Method 30B is used, paired samples are required for each test

run and the runs

must be long enough to

ensure

that

sufficient mercury is collected

analyze.

When Method 29 in

appendix

A-8 to 40

CFR

60,

incorporated

reference, or the

Ontario Hydro method is used, the test

results must

be based

on the vapor phase

mercury collected in

the back-half

of the

sampling trains

(i.e.,

the non-

filterable impinger

catches)

. For each

Method 29 in appendix A-8

40 CFR

60,

incorporated

by reference, Method 30B-7 or

Ontario T-{ydro method

test

run, the

paired

trains must meet the relative

deviation (ED) requirement specified in

Section

1.6(a) (5)

of this Appendix or Method 30B, as

applicable. If the RD

specification is met, the results of the two samples must be

averaged

arithmetically.

the unit is equipped with flue gas desulfurization

or add-on mercury

emission controls, the controls must be operating

normally during the testing,

and, for

the purpose of establishing proper

operation

the controls, the owner

operator must record parametric data or S02

concentration

data

in accordance

with

Section

1.12(a)

of this

Appendix.

If two or

more of units of the same

type

qualify as a group of identical

units in

accordance with 40 CFR

75.19(c) (1) (iv) (B),

incorporated by reference in

Section

225.140, the owner or operator may test a subset of these

units in

lieu

of testing

each unit individually. If this option is selected,

the number

units

required to be tested must be determined from Table LM-4

in 40 CFR

75.19,

incorporated

reference in Section 225.140. For

the

purposes

of the required

retests

under

aaphuhactiQn

(d) (4)

of this Section, it

is strongly

recommended that

(to

the extent practicable)

the same

subset

of the units not

tested

in two successive retests, and that every effort be

made

ensure that

each unit in

the group of identical units is tested in a timely

manner.

Based

on the results of the emission

testing,

Equation 1

of this Section

must be used

to provide a conservative estimate

the annual

mercury mass

emissions

from the unit:

(Equation

Where:

= Estimated

annual mercury mass emissions from the affected unit,

(ounces/year)

K = Units conversion constant, 9.978 x 10-10

oz-scm/ig-zcfN

scfN= Either 8,760

(the

number of hours in a year) or the maximum

number

operating

hours

per year

(if

less than

8,760)

allowed

by the unit’s

Federally-

enforceable

operating permit.

The

highest mercury

concentration

(pg/scm)

from any

of the test

runs

0.50 pg/scm,

whichever is

grcatcr

creatermax=

Maximum

potential

flow

rate,

determined

according

to Section

2.1.2.1

of Exhibit

this Appendix,

(scfh)

Equation

of this

Section assumes that

the unit operates

its maximum

potential

flow

rate,

either

year-round

or for the maximum

number of hours

allowed

the

operating

permit

(if unit

operation is

restricted to less

than

8,760 hours

per

year) . If the permit

restricts the

annual unit heat

input

but

not the number

annual unit

operating hours,

the owner or operator

may divide

the allowable

annual heat

input

(mmBtu)

the design

rated heat

input

capacity

of the

unit (mmBtu/hr)

determine the

value of “N”

in Equation

1. Also,

note

that

if the

highest

mercury concentration

measured in

any test

run is

less than

0.50

pg/scm,

a default

value of

0.50 pg/scm must

used

in the

calculations.

the

estimated

annual

mercury mass

emissions

from

paragrciphsubsection

this

Section are

464 ounces per

year or

less, then the

unit is

eligible

use

the

monitoring provisions

in paragraphsubsection

(b)

this

Section,

and continuous

monitoring

of the mercury

concentration is

not required

(except

as otherwise

provided

in paragraphosubsections

(e)

and

(f)

of this

Section)

If the

owner

or operator of an

eligible unit under

paragraphsubsection

of this

Section elects not

to continuously

monitor mercury concentration,

then the following

requirements

must be met:

The results of the

mercury emission

testing performed

under

paragraphsubsection

(c)

of this Section

must be submitted

certification

application

the permitting authority,

no later

than 45

days

after

the testing

is completed.

The calculations

demonstrating that

the

unit emits

464 ounces

(or

less)

per

year of mercury

must also be

provided, and

the default

mercury

concentration

that will

be used for

reporting under

Section

1.18 of

this

Appendix

must

specified

in both

the

electronic

and

hard copy

portions

of the

monitoring plan

for the unit. The

methodology

considered to be

provisionally

certified as

of the date and

hour of

completion

the mercury

emission testing.

Following initial

certification,

the

same default

mercury concentration

value

that was used

to estimate the

unit’s annual

mercury

mass

emissions

under

paragraphsubsection

(c)

of this

Section must

reported

for

each

unit

operating

hour,

except

as otherwise

provided in

paragraphsubsection

Cd)

(4)

(IJ)

Cd) (6)

this

Section.

The default

mercury concentration

value

must be

updated as

appropriate-

according

paragraphsubsection

(d) (5)

this Section.

The

hourly mercury

mass emissions must

be calculated according

to Section

4.1.3

in Exhibit

C to this

Appendix.

The mercury

emission testing

described in

aphhac.t.iQn

Cc)

of this

Section must

be repeated

periodically,

for the

purposes

quality-assurance,

follows:

If the results

of the certification

testing under

paragraphsubsection

Cc)

this Section

show that the unit

emits 144 ounces

ib)

of mercury

per year

or less, the

first retest is

required by the end

of the fourth

QA operating

quarter

(as

defined in 40

CFR 72.2, incorporated

reference)

following the

calendar

quarter of the

certification testing;

If the

results of the certification testing under paragraphsubsection

(C)

of this Section

show that the unit emits more than 144 ounces of mercury per

year, but less

than or equal to 464 ounces per year, the first retest is

required

the

end of the second QA operating quarter

(as

defined in 40 CFR

72.2, incorporated by

reference)

following the calendar quarter of the

certification

testing; and

Thereafter,

retesting must be required either semiannually or annually

(i.e.,

by the end of

the second or fourth QA operating quarter following the

quarter of the previous

test),

depending

on the

results of the previous

test.

determine whether the next

retest is

due

within two or four QA operating

quarters, substitute the

highest mercury concentration from the current

test

0.50

ig/scm

(whichever

greater) into

the equation

paragraphsubsection

(c)

(2) of this Section. If

the estimated

annual

mercury mass emissions exceeds

144 ounces, the next test

due

within two QA operating quarters. If the

estimated annual

mercury mass emissions is 144 ounces or less, the next test is

due within four

QA operating quarters.

additional retest is required when there is a change in the coal rank

of the primary

fuel (e.g., when the primary fuel is switched from bituminous

coal to

lignite) . Use ASTM D388-99 (incorporated by reference under Section

225.140)

determine the coal rank. The four principal coal ranks are

anthracitic,

bituminous,

subbituminous-r

and lignitic. The ranks of anthracite

coal refuse

(culm) and bituminous coal refuse (gob) must be anthracitic and

bituminous,

respectively. The retest must

performed within 720 unit operating

hours of the change.

The default

mercury concentration

used

for reporting under Section 1.18 of

this Appendix must be updated

after each required retest. This includes retests

that are

required prior

the compliance date in Section

1.14(b)

this

Appendix. The

updated value must either be the highest mercury

concentration

measured in

any of the test runs or 0.50 fig/scm, whichever is greater.

The

updated value

must be applied beginning with the first unit operating

hour

which

mercury emissions data are required to be reported

after completion

of the

retest,

except as provided in

paapihetion

(d)

(4)

(D)

of this Section,

where the

need to retest is triggered by a

change in the coal rank of the

primary

fuel. In that case, apply the updated

default mercury concentration

beginning with the first unit operating

hour in which mercury emissions are

required to

be reported after the date and

hour of the fuel switch.

If the unit is equipped with a flue gas

desulfurization system or add-on

mercury

controls, the owner or operator must

record the information required

under Section 1.12 of this Appendix for

each unit operating hour,

document

proper operation of the emission controls.

For units with

common

stack and

multiple stack exhaust configurations, the

•

use

of the

monitoring

methodology described in paragraphcsubsections

(b)

through

(d)

of this

Section is restricted

follows:

The

methodology may not

used for reporting mercury mass

emissions

at a

common

stack unless all of the units using the common stack are affected units

and the

units’ combined potential to emit does not exceed

464

ounces

of mercury

per

year

times the number of units sharing the

stack, in

accordance

with

paragraphzsubsections

(c)

and

Cd)

of this

Section. If the

test

results

demonstrate

that

the units

sharing the

common stack qualify

low mass

emitters,

the

default mercury concentration

used

for reporting mercury mass

emissions

at the

common stack must either

the highest value obtained in any

test

run

or 0.50

pg/scm, whichever is greater.

The

initial

emission testing required under

paragraphsubsection

Cc)

this

Section

may be

performed at the common stack if the following conditions

are met. Otherwise, testing of the individual units

(or

a subset of the units,

if identical,

described in

pa-gp

i.baection (c) (1) CD)

of this

Section)

required:

The testing must be done at a combined load corresponding to the

designated normal load level

(low,

mid-

7 or high) for the units sharing

the

common stack-

7-in accordance

with

Section 6.5.2.1 of Exhibit A to

this Appendix;

ii)

All of the units that

the stack must be operating in a

normal,

stable manner and at

typical load

levels during

the

emission

testing. The coal

combusted in each unit during the testing must be representative of

the coal

that

will

combusted in that unit at the start of the mercury mass

emission

reduction

program (preferably from the same

ourcc(z)sources

of supply);

iii)

If flue

gas

desulfurization and/or add-on mercury emission

controls

are

used to

reduce the

leveloI

the emissions exiting from the common

stack, these

emission controls must be operating normally during the emission

testing and,

for the purpose of establishing proper operation of the controls,

the owner

operator must record parametric data or 502 concentration data in

accordance

with

Section

1.12(a)

of this Appendix;

iv)

When calculating E, the estimated maximum potential annual

mercury

mass

emissions from the stack, substitute the maximum potential flow rate

through

the

common stack

(as

defined in the monitoring plan) and the highest

concentration

from any

test

run

(or

0.50 pg/scm, if greater) into

Equation 1;

The calculated value of E must be divided by the number of

units sharing

the

stack. If the result, when rounded to the

nearest ounce,

does

not exceed 464

ounces, the units qualify to use the low mass

emission methodology; and

vi)

If the units

qualify

to use the

methodology, the default mercury

concentration used

for reporting

the common stack must

the highest value

obtained in any test

run or

0.50

pg/scm, whichever is greater; or

The retests

required under

par-a ap

hction

(d) (4)

of this Section may

also be done at

the common stack. If this testing option is chosen, the testing

must be done at a

combined load corresponding to the designated normal load

level

(low,

mid-

or high) for the units sharing the common stack, in accordance

with

Section 6.5.2.1 of Exhibit A

this Appendix. Provided that the required

load

level is attained and that all of the units sharing the stack are fed from

the

same on-site coal supply during normal operation, it is not

necessary

for

all

of the units sharing the stack to be in operation during a retest.

However,

two or more of the units that share the stack are fed from different

on-site

coal supplies

(e.g.,

one unit burns low-sulfur coal for compliance and

the

other

combusts

higher-sulfur

coal),

then either:

Perform the retest with all units in normal operation; or

ii)

If this is not possible, due to

circumstances

beyond the

control of the

owner or operator (e.g., a forced unit outage),

perform

the retest

with the

available units

operating

and assess the test

results

as follows. Use

the

mercury

concentration

obtained in the retest for

reporting purposes under this

partPart

if the

concentration is greater than or equal

the value obtained in

the

most

recent

test. If the retested value is lower than the mercury

concentration from the previous test, continue using the higher value from the

test

for reporting purposes and use that same higher mercury

concentration value in Equation 1 to determine the

due

date for the next retest,

described in

(e) (1) (C)

of this Section.

testing

is done

the common stack, the

due date

for the next

scheduled retest

must

determined

follows:

Substitute

the maximum potential flow rate for the common stack

(as

defined in the

monitoring

plan)

and

the

highest mercury concentration from any

test run

(or

0.50

pg/scm,

greater)

into

Equation

1; and

ii)

If the value

of E obtained from Equation 1, rounded

the nearest ounce,

is greater than

144 times the number of units sharing the common stack, but less

than or equal to

464 times the number of units sharing the stack, the next

retest is due

in two QA operating

quarters;Qr

iii)

If the

value

of E obtained from Equation 1, rounded to the nearest ounce,

is less

than or equal to 144 times the number of units sharing the

common

stack,

the next

retest is due in four QA operating quarters.

For

units with multiple stack or duct configurations, mercury

emission

testing must be

performed separately on each stack or duct, and the sum of the

estimated

annual mercury mass emissions from the stacks or ducts must not exceed

464 ounces

of mercury per year. For reporting purposes, the default mercury

concentration

used

for each stack or duct must either be the highest

value

obtained

in any test run for that stack or 0.50 pg/scm,

whichever

greater.

For units with a main stack and bypass stack configuration,

mercury

emission testing must be performed only on the main stack.

For reporting

purposes,

the default mercury concentration used for the

main stack must

either

be the

highest value obtained in any test run for that

stack or

0.50

pg/scm,

whichever is greater. Whenever the main stack is bypassed,

the maximum

potential

mercury concentration, as defined in

Section

2.1.3

of Exhibit A

this

Appendix, must be

reported.

At the

end of each calendar year, if the cumulative annual mercury mass

emissions

from an affected unit have exceeded 464 ounces, then the owner must

install,

certify,

operate-r

and maintain a mercury concentration monitoring

system or a

sorbent trap monitoring system no later than 180 days after the end

of the calendar

year

which the annual mercury mass emissions exceeded 464

ounces. For

common stack and multiple stack configurations, installation and

certification of a

mercury concentration or sorbent trap monitoring system on

each stack (except

for

bypass

stacks)

is likewise required within 180 days after

the end of the

calendar year, if:

The

annual mercury mass emissions

the common stack have exceeded 464

ounces times

the number of affected units using the common stack; or

The sum of the annual mercury mass emissions from all of

the multiple

stacks or ducts has exceeded

464 ounces; or

The

sum of the annual mercury mass emissions from the main and bypass

stacks

has exceeded 464 ounces.

For an affected

unit that

using a mercury

concentration

CEMS

sorbent trap system

under Section

1.15(a)

of this Appendix to continuously

monitor the mercury

mass emissions, the owner or operator may switch to the

methodology in

Section

1.15(b)

this Appendix, provided that the

applicable

conditions

paragraphssubsections

(c)

through

(f)

of this Section

are met.

Section 1.16

Monitoring of

mercury mass

emissions

and heat input

common and

multiple stacksMercurv

Mass Emissions

and

Heat Innut at Common

and

Multiple

Stacks

Unit

utilizing

common stack with other affected unit(s)Utilizina

Common

Stack

with Other Affected Units.

When an affected unit utilizes a

common

stack

with one

or more affected units, but no non-affected units,

the owner or

operator must

either:

Install, certify,

operate-r

and maintain the monitoring

systems described

Section

1.15(a)

of this Appendix at the common

stack-r

record the combined

mercury mass

emissions for the units exhausting to

the

common stack.

Alternatively, if, in accordance

with

Section

1.15(e)

of this Appendix, each of

the

units using the common

stack is demonstrated

emit less than 464 ounces of

mercury

per year, the owner or operator may

install, certify, operate and

maintain

the

monitoring systems and perform the

mercury emission testing

described

under Section

1.15(b)

this Appendix.

If reporting of the unit heat

input

rate

is required, determine the hourly unit heat

input rates either

by:

Apportioning the common stack heat input rate to

the

individual units

according

the

procedures in 40 CFR

75.16(e)

(3),

incorporated by reference in

Section 225.140; or

)

Installing, certifying,

operating-

7and maintaining a flow monitoring

system and diluent monitor in the duct to

the common stack from each unit; or

Install, certify,

operate

and maintain the monitoring systems and

(if

applicable) perform the

mercury emission testing described in Section

1.15(a)

Section

1.15(b)

of this

Appendix in the

duct to

the common stack from each unit.

Unit

ta-il4-z-ing-—eemmen-—s-haeklJtilizing

CQTnTSQZi

Stack with

nonaffected

unit(s)Nonaffected

Units.

When

one or more affected units utilizes a common

stack

with one or more nonaffected units,

the owner or operator must either:

Install, certify, operate-

7and

maintain the monitoring systems and

(if

applicable)

perform

the

mercury emission testing described in Section

1.15(a)

Section

1.15(b)

of this Appendix in the duct to the common stack

from

each

affected unit;

Install, certify,

operate

and maintain the

monitoring systems described

Section

1.15(a)

of this Appendix in the

common stack; and

Install, certify, operate,- and

maintain the monitoring systems and

(if

applicable)

perform

the mercury

emission testing described in Section

1.15(a)

Section

1.15(b)

this Appendix in the

duct to

the common stack from each non-

affected unit. The

designated representative must submit a petition to the

Agency to allow a

method of calculating and reporting the mercury mass emissions

from the affected

units

as the

difference between mercury mass emissions

measured in the

common stack

and

mercury mass emissions measured in the ducts of

the

non-affected

units, not

to be

reported as an hourly value less than

zero.

The

Agency may

approve such

a method

whenever the designated

representative

demonstrates, to the

satisfaction of the Agency, that the method ensures that

the mercury mass

emissions from the affected units are not underestimated; or

Count the

combined emissions measured

the common stack as the mercury

mass emissions for the

affected units, for recordkeeping and compliance

purposes,

in accordance

with

pa ag-rap

uhsctiQn

(a)

of this Section; or

Submit a

petition

the

Agency

allow use of

method for apportioning

mercury mass

emissions measured in the common stack to each of the units using

the common stack and

for reporting the mercury mass emissions. The Agency

may

approve such a method

whenever the designated representative demonstrates, to

the satisfaction of

the Agency, that the method ensures that the

mercury

mass

emissions from the

affected units are not underestimated.

If the monitoring

option in

para aphhsection (b) (2)

of this Section is

selected, and if heat

input is required

to be

reported under

this

Part 22S, the

owner or operator must

either:

Apportion

the common stack heat input rate to the

individual units

according to the

procedures in 40 CFR

75.16(e) (3),

incorporated by

reference

Section 225.140;

Install

flow monitoring system and a diluent gas

(02

C02)

monitoring

system in the duct

leading from each affected unit to the

common stack, and

measure the heat

input

rate in each duct, according to Section

2.2 of Exhibit

this Appendix.

Unit w4-hWith a

main stackMain Stack

and a

bypass

stackBvoass

Stack.

Whenever any

portion of the flue gases from an affected unit

can

routed

through

a bypass

stack

avoid the mercury monitoring

syztcm(s)svstems

installed on the

main stack, the owner and operator must

either:

Install,

certify,

operate-r

and maintain the

monitoring systems described

Section

1.15(a)

of this Appendix on both the

main stack and the bypass stack

and

calculate mercury mass emissions for

the unit

the sum of the mercury mass

emissions measured at the two

stacks;

Install,

certify, operate-- and maintain the monitoring systems

described

Section

1.15(a)

this

Appendix at the main stack and measure

mercury

mass

emissions at the bypass

stack using the appropriate reference

methods in

Section

1.6(b)

of this

Appendix. Calculate mercury mass emissions for the

unit

as the

sum of the

emissions recorded

the installed monitoring

systems on the main

stack and the

emissions measured

the reference

method monitoring systems;

Install,

certify, operate-v- and maintain the monitoring

systems and

(if

applicable)

perform the mercury emission testing described in

Section 1.15(a) or

Scction

1.15(b) of this Appendix only on the main stack. If

this option is

chosen, it is not necessary to

designate the exhaust

configuration

as a

multiple

stack

configuration in the

monitoring plan required under Section 1.10

this

Appendix, since only the main

stack is monitored; or

If the

monitoring option in

paragraphsubsection

(e-42)

of this

Section is

selected, and if heat input is required to be

reported under

this

Part

225, the owner or operator must:

Use the installed

flow and

diluent

monitors

to determine the

hourly heat

input rate

each stack (mmBtu/hr),

according

to Section 2.2 of

Exhibit

C to

this Appendix;

and

Calculate

the

hourly heat input

at each stack

(in mmBtu)

by multiplying

the

measured

stack

heat input rate

by the corresponding

stack operating

time;

and

Determine the hourly

unit heat input

by summing the

hourly stack heat

input

values.

Unit

with multiplc stack

duct

configurationWith

Multinle

Stack or

Duct

Configuration.

When the flue

gases from an

affected unit discharge

to the

atmosphere

through more

than one stack,

or when the flue

gases

from an

affected

unit

utilize two or

more ducts feeding

into a

single

stack and the

owner or

operator chooses

monitor in the

ducts rather

than

in the stack,

the

owner

operator must

either:

Install, certify,

operate-

and maintain

the

monitoring

systems

and

(if

applicable)

perform

the mercury emission

testing described

in Section

1.15(a)

Scction

1.15(b)

of this Appendix

in each of the multiple

stacks and

determine

mercury mass

emissions from

the affected unit

the

sum of the

mercury

mass

emissions

recorded for each

stack. If another

unit also exhausts

flue gases into

one of

the

monitored

stacks, the owner

or operator must

comply with the

applicable

requirements

paragraphzsulsections

(a)

and

(b)

of this

Section,

order to properly

determine the

mercury

mass

emissions

from the units

using that

stack;

Install, certify,

operate-

and maintain the

monitoring systems

and

(if

applicable)

perform

the

mercury

emission testing

described in Section

1.15(a)

Scction

1.15(b)

of this

Appendix

in each of

the ducts that feed

into the stack,

and

determine

mercury mass

emissions from

the affected unit

using the sum

of the

mercury

mass

emissions

measured

each duct, except

that where another

unit

also

exhausts

flue gases

one

or more of the stacks,

the owner or

operator

must

also comply

with the applicable

requirements

of paragraphcsubsections

(a)

and

(b)

this

Section

determine and record

mercury

mass

emissions from the

units

using

that

stack;

If the monitoring

option in

paragraphsubsection

(d) (1)

(4442)

of this

Section

selected,

and

if heat

input is required

reported

under this

Part

225,

the

owner

operator

must:

Use

the installed flow

and diluent

monitors to

determine the hourly

heat

input

rate at each stack

duct

(mmBtu/hr), according

Section 2.2

of Exhibit

this Appendix;

and

Calculate the hourly

heat input at

each

stack

or duct

(in

mmBtu)

multiplying

the

measured

stack

(or

duct)

heat

input

rate

by the

corresponding

stack

(or duct)

operating time;

and

Determine

the hourly

unit heat

input by summing

the

hourly

stack

(or duct)

heat

input values.

Section

1.17 Calculation

mercury mass

emissions and heat

input

rate

The owner or

operator must calculate mercury mass emissions and heat input rate

in accordance with the

procedures

in Sections 4.1 through 4.3 of Exhibit F to

this Appendix.

Section 1.18

Recordkeeping and reporting

General

recordkeeping provisions. The owner or operator of any affected

unit must maintain

for each affected unit and

each

non-affected unit under

Section

1.16(b) (2) (B)

of this Appendix

file of all measurements, data,

reports, and other

information required

this part

the source in a form

suitable for

inspection for

least

years from the

date

of each record.

Except for the

certification

data

required in Section

1.11(a) (4)

of this

Appendix and the initial

submission of the monitoring plan required in Section

1.11(a) (5)

of this Appendix,

the

data

must

collected beginning with the

earlier of the date

of provisional certification or the compliance deadline in

Section

1.14(b)

this Appendix. The certification

data

required in Section

1.11(a) (4)

this Appendix must be collected beginning with the date of the

first

certification test performed. The file must contain the following

information:

The

information required in Sections

1.11(a) (2), (a) (4), (a) (5), (a) (6),

(b),

applicable),

(d),

and

(e)

(f)

of this Appendix

(as

applicable);

The

information required in Section 1.12 of this Appendix, for units with

flue gas

desulfurization systems or add-on mercury emission controls;

For affected units using mercury CEMS or sorbent trap

monitoring

systems,

for each

hour when the unit is operating, record the mercury mass

emissions,

calculated

in accordance with Section 4 of Exhibit C to this

Appendix.

Heat

input and mercury methodologies for the hour; and

Formulas from

the

monitoring plan for total mercury mass

emissions

and

heat input rate

(if

applicable);

Certification, quality assurance and quality

control record provisions.

The

owner or operator of any affected unit must

record the applicable

information in Section 1.13 of this

Appendix for each affected unit or group

units monitored at a common

stack and each non-affected unit under Section

1.16(b) (2) (B)

this Appendix.

Monitoring plan recordkeeping provisions.

General provisions. The owner or operator of an affected

unit

must

prepare

and

maintain a monitoring plan for each affected unit

or group of units

monitored at a

common stack and each non-affected unit under Section

1.16(b)

(2) (B)

of this Appendix. The monitoring plan must

contain sufficient

information on the continuous monitoring systems and the use of data

derived

from these

systems to demonstrate that all the unit’s mercury emissions

are

monitored

and reported.

Updates.

Whenever the owner or operator makes a replacement,

modification,

change in

certified continuous monitoring system or

alternative monitoring

system under 40 CFR 75, subpart E, incorporated by

reference in Section 225.140,

including a change in the automated data acquisition

and handling system or

the

flue gas handling system, that affects

information reported in the

monitoring

plan

(e.g.,

a change

serial number

for a component

monitoring system),

then

the owner or

operator must

update

the monitoring plan.

Contents

of the

monitoring

plan. Each

monitoring

plan must contain

the

information

in Section

1.10(d)

(1)

of this

Appendix

in electronic format

and

the

information in Section

1.10(d)

(2)

hardcopy format.

General

reporting

provisions.

The designated

representative

for

affected

unit must comply

with all

reporting requirements

in this

Section

and

with

any additional

requirements

set

forth in

Ill.

Adm.

Code

Part

225.

The

designated

representative

for an

affected unit

must submit the

following

for

each affected unit

or group of units

monitored at a

common stack

and each

non-affected

unit

under

Section

1.16(b)

(2) (B)

of this

Appendix:

Monitoring

plans

accordance

with paa

aph

haetiQn (e)

this

Section;

and

Quarterly

reports in

accordance

with

paragraphsubsection

(f)

of this

Section.

Other

petitions

and

communications.

The

designated

representative

for

affected

unit must

submit

petitions,

correspondence,

application forms,

and

petition-related

test

results

in accordance

with

the provisions

in Section

1.14(f)

of this

Appendix.

Quality

assurance

RATA

reports. If

requested by

the Agency,

the

designated

representative

of an affected

unit must

submit the

quality

assurance

RATA report

for

each affected

unit

group of

units

monitored

at a common

stack

and each

non-affected

unit under Section

1.16(b)

(2) (B)

of this

Appendix

the

later of

days

after completing

a quality assurance

RATA

according

Section

2.3

Exhibit

B to

this

Appendix

days

eafter

receiving the request.

The

designated

representative

must report

the hardcopy

information

required

Section

1.13(a) (9)

of this Appendix

to the Agency.

Notifications. The

designated

representative

for an affected

unit

must

submit

written

notice

to the Agency

according to

the

provisions

in 40 CFR

75.61,

incorporated by

reference

Section

225.140,

for each affected

unit or group

units

monitored

at a common

stack and each

non-affected

unit under Section

1.16(b) (2)

(B)

of this Appendix.

Monitoring plan

reporting.

Electronic

submission.

The designated

representative

for an affected

unit

must

submit

to the Agency

and USEPA, or an

alternate

Agency designee if

one

specified,

a complete,

electronic, up-to-date

monitoring

plan file

format

specified

by the

Agency for

each affected

unit

or group of units

monitored

at a

common

stack

and each

non-affected

unit

under

Section

1.16(b)

(2) (B)

of this

Appendix, as

follows:

No later

than 21 days

prior to the

commencement

initial

certification

testing;

at the

time of a

certification

recertification

application

submission;

and whenever

an update of

the

electronic

monitoring

plan

required,

either under Section

1.10 of this

Appendix

or elsewhere in

this

Appendix.

Hardcopy submission.

The designated

representative

of an affected unit

must

submit

all

the hardcopy information

required

under Section 1.10

of this

Appendix,

for

each affected unit

group of units

monitored at a

common stack

and

each non-affected

unit under

Section

1.16(b)

(2) (B)

of this

Appendix,

the

Agency

prior

initial certification.

Thereafter,

the designated

representative

must

submit hardcopy

information only if

that portion of

the

monitoring

plan

revised. The designated

representative

must submit the

required hardcopy

information

follows: no

later

than 21 days prior

to the commencement

initial certification

testing;

with any certification

or recertification

application,

if a hardcopy

monitoring plan

change is associated

with

the

recertification

event;

and within

30 days

o-after

any other

event

with

which

hardcopy

monitoring

plan change is

associated, pursuant

Section

1.10(b)

this

Appendix.

Electronic submittal

of all monitoring

plan

information,

including hardcopy

portions,

is permissible provided

that a paper

copy of the

hardcopy

portions can be

furnished upon request.

Quarterly reports.

Electronic

submission.

Electronic quarterly

reports must

be submitted,

beginning

with

the calendar

quarter

containing

the compliance

date in Section

1.14(b)

of this Appendix,

unless otherwise

specified in

35 Ill.

Adffi4im. Code

Part

225. The designated

representative

for an affected

unit must report

the

data

and information

this

paagaphhaectiQn

(f) (1)

and

the applicable

compliance

certification

information

paragraphsubsection

(f) (2)

this

Section

to the Agency

and

USEPA, or an alternate

Agency

designee if one

specified,

quarterly

format

specified

by the

Agency, except as

otherwise

provided

in 40

CFR

75.64(a),

incorporated

reference

Section

225.140,

for

units in

long-term cold

storage.

Each electronic

report must

submitted

to the

Agency within

45 days

following

the

end of each

calendar

quarter. Except

otherwise

provided

in 40 CFR

75.64(a) (4)

and

(a)(5),

incorporated by

reference

Section

225.140,

each electronic

report

must

include

the date of

report

generation

and the

following

information

for each

affected unit

or group

units monitored

at a

common

stack:

The

facility information

in 40 CFR 75.64

(a) (3),

incorporated by

reference

Section

225.140; and

The

information and

hourly

data required

paragraphasubections

(a)

and

(b)

of this

Section,

except

for:

Descriptions

of adjustments,

corrective action,

and maintenance;

ii)

Information

which is

incompatible with

electronic

reporting

(e.g., field

data

sheets, lab analyses,

quality control

plan);

iii)

For units

with flue

gas

desulfurization

systems or with

add-on

mercury

emission

controls, the

parametric information

in Section

1.12 of this Appendix;

iv)

Information

required by

Section

1.11(d)

this Appendix concerning

the

causes

of any

missing data

periods

and the

actions

taken to cure

&ueh

causes;

Hardcopy

monitoring

plan

information

required by

Section 1.10 of

this

Appendix

and hardcopy

test

data and

results required

by Section 1.13

of this

Appendix;

vi)

Records

of flow

polynomial

equations and

numerical

values required

Section

1.13(a) (5)

(E)

of this

Appendix;

vii)

Stratification

test results required

as part of

the

RATA

supplementary

records under

Section 1.13(a)

(7)

of this Appendix;

viii)

Data

and

results

RATAs that are aborted

or invalidated

due to problems

with

the reference

method

or operational

problems with the

unit and

data

and

results of linearity

checks

that are

aborted or invalidated

due to operational

problems with

the unit;

ix)

Supplementary

RATA information

required

under

Section

1.13(a)

(7)

of this

Appendix,

except

that: the

applicable data

elements

under Section

1.13(a)

(7) (B)

(i)

through

(xx)

of this

Appendix

and under Section

1.13(a)

(7)

through

(xiii)

of this Appendix

must

reported

for flow RATAs

circular

or rectangular

stacks

(or

ducts)

in which angular

compensation

for

yaw

and/or pitch angles

used

(i.e.,

Method 2F or 2G

in appendices A-i

and

A—2

to 40

CFR 60,

incorporated

reference

in Section

225.140),

with

or without

wall

effects

adjustments; the

applicable

data

elements under Section

1.13(a)

(7)

(B) (i)

through

(xx)

this Appendix

and under Section

1.13(a)

(7)

through

(xiii)

of this

Appendix must

reported

for

any

flow

RATA run

at a

circular

stack

which

Method 2 in appendices

A-i and A-2

to 40

CFR

60,

incorporated

by reference

Section 225.140,

is used and

a wall

effects

adjustment

factor is determined

direct

measurement;

the data

under

Section

1.13(a) (7) (B)

(xx)

of this

Appendix

must be

reported for all

flow RATAS

circular

stacks in which

Method

2 in appendices

A-i

and

A-2

40 CFR

60,

incorporated

reference

Section 225.140,

is used

and

default wall

effects

adjustment

factor

is applied;

and the data

under

Section

1.13(a)

(7) (I)

(i)

through

(vi)

must

reported for all

flow RATAs at

rectangular

stacks

or ducts

in which Method

2 in

appendices

A-i and A-2 to 40

CFR

60,

incorporated

reference in

Section

225.140,

is used and a wall

effects

adjustment factor

applied.

For

units

using sorbent

trap

monitoring

systems, the hourly

gas flow

meter

readings

taken between the

initial

and

final

meter readings

for the data

collection

period; and

Ounces of

mercury

emitted

during quarter and

cumulative

ounces

of mercury

emitted in

the

year-to-date

(rounded

to the

nearest thousandth);

and

Unit or

stack

operating

hours for

quarter,

cumulative unit or

stack

operating

hours

for

year-to-date; and

Reporting

period

heat

input

(if

applicable)

and

cumulative,

year-to-date

heat

input.

Compliance certification.

The designated

representative

must certify

that the

monitoring

plan

information

each

quarterly

electronic

report

(i.e.,

component and

system

identification

codes,

formulas,

etc.)

represent current

operating

conditions

for

the

affected

unit

()units.

The designated representative

must

submit and sign

compliance

certification

support of

each

quarterly

emissions

monitoring

report

based

reasonable

inquiry of those

persons

with primary

responsibility

for ensuring

that

all of

the

unit’s

emissions

are

correctly and fully

monitored. The

certification

must

state that:

The

monitoring data

submitted

were recorded

accordance

with the

applicable

requirements

of this

Appendix, including

the

quality assurance

procedures

and specifications;

and

ii)

With

regard to a

unit with an FGD

system or with

add-on mercury

emission

controls,

that for all

hours where

mercury

data

is missing

accordance with

Section

1.13(b)

of this

Appendix,

the add-on emission

controls

were

operating

within the

range of

parameters

listed in the quality-assurance

plan for

the unit

(or

that quality-assured

S02 CEMS data were

available

document

proper

operation of

the

emission

controls)

Additional reporting

requirements.

The designated

representative must

also

comply

with all of

the

quarterly

reporting

requirements

in 40 CFR

75.64(d),

(f),

and (g), incorporated

by reference

in Section

225.140.

Exhibit

A to Appendix

B -— Specifications

and Test Procedures

1. Installation

and Measurement

Location

1.1 Gas

and Mercury Monitors

Following

the

procedures in

Section 8.1.1 of Performance

Specification

2 in

Appendix

to 40

CFR

60,

incorporated by reference

in Section

225.140, install

the

pollutant concentration

monitor or

monitoring system

at a

location where

the

pollutant

concentration

and emission

rate measurements

are directly

representative

of the total emissions

from the affected

unit. Select

representative

measurement point

or path for the

monitor

probc(c)orobes

(or

for

the

path

from the transmitter

to the

receiver)

such

that the

C02, 02,

concentration

monitoring

system, mercury

concentration

monitoring

system,

sorbent

trap monitoring

system will

pass the relative

accuracy

test

(see

Section

of this

Exhibit)

is recommended

that monitor

measurements

be made at locations

where the

exhaust gas

temperature

is above the dew-point

temperature.

If the cause of

failure

to meet

the

relative accuracy

tests is determined

the measurement

location, relocate

the monitor probc(c)

.orobes.

1.1.1 Point

Monitors

Locate

the measurement

point

(1)

within

the

centroidal

area of the stack

or duct

cross section,

(2)

no less than

1.0

meter

from the

stack or duct

wall.

1.2

Flow Monitors

Install

the

flow

monitor

in a

location that provides

representative

volumetric

flow over

all

operating

conditions.

Such a

location is one

that

provides

average

velocity of the

flue

gas

flow over

the stack or

duct

cross section

and

representative

of the pollutant

concentration monitor

location. Where

the

moisture content

of the flue

gas

affects

volumetric

flow

measurements,

use the

procedures

both Reference

Methods 1 and 4

Appcndixaooendix

A to 40 CFR 60,

incorporated

reference

Section 225.140,

to establish a

proper location

for

the

flow monitor. The

Illinois EPA recommends

(but

does

not require) performing

flow profile study

following the

procedures

in 40

CFR

part

60,

appendix

Method-;-

1, Sections

11.5 or 11.4, incorporated

reference in Section 225.140,

for each of the three

operating or

load

levels indicated in Section 6.5.2.1 of

this Exhibit to

determine the acceptability of the potential flow monitor

location and to

determine the number and location of flow sampling points

required

obtain a

representative flow value. The

procedure

in 40 CFR part

60,

Appcndixaooendix A, Test Method 1, Section 11.5, incorporated by reference

Section 225.140, may be used even if the flow measurement location is

greater

than or equal

2 equivalent stack or duct diameters downstream or

greater than

equal

1/2 duct diameter upstream from a flow disturbance. If a flow

profile study

shows that cyclonic

(or

swirling) or stratified flow conditions

exist at the

potential flow monitor location that are likely to prevent the

monitor from meeting the performance specifications of this part, then

the

Agency

recommends

either

(1)

selecting another location where there is no

cyclonic

(or

swirling) or stratified flow condition, or

(2)

eliminating

the

cyclonic

(or

swirling) or stratified flow condition by straightening

the flow,

e.g., by

installing straightening vanes. The Agency also recommends

selecting

flow monitor locations to minimize the effects of condensation,

coating,

erosion, or other conditions that could adversely affect flow

monitor

performance.

1.2.1

Acceptability of Monitor Location

The

installation of

flow monitor is acceptable if either

(1)

the location

satisfies

the

minimum siting criteria of Method 1 in Appcndixaooendix A to 40

CFR

60,

incorporated by reference in

Section 225.140

(i.e.,

the location is

greater than or equal to

eight

stack

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

flow

disturbance),

(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

this part. If the flow monitor is

installed in

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

this Section.

1.2.2

Alternative Monitoring Location

Whenever the owner or operator successfully demonstrates that

modifications

the

exhaust duct or stack

(such

as installation of straightening

vanes,

modifications of ductwork, and the

like)

are necessary for the flow

monitor

meet

the performance specifications, the Agency may approve

an interim

alternative flow monitoring methodology and an

extension

the

required

certification date

for

the flow monitor.

Where no location exists that satisfies the physical

siting criteria in

Section

1.2.1,

where the results of flow profile studies performed at two

or more

alternative

flow monitor locations are unacceptable, or where

installation

of a

flow monitor in either the stack or the ducts is demonstrated to be

technically

infeasible, the owner or operator may petition the Agency for an

alternative

method for monitoring flow.

Equipment

Specifications

2.1

Instrument Span and

Range

In implementing

Sections 2.1.1 through 2.1.2 of this Exhibit, set the

measurement range

for

each

parameter

(C02,

02,

flow

rate)

high enough to

prevent full-scale exceedances

from occurring,

yet

low enough

ensure good

measurement accuracy

and

maintain

high signal-to-noise ratio. To meet these

objectives, select

the range such that the majority of the readings obtained

during typical

unit operation are kept, to the extent practicable, between 20.0

and 80.0 percent

of the full-scale range of the instrument.

2.1.1

C02 and 02 Monitors

For an 02 monitor

(including 02 monitors

used to

measure C02 emissions or

percentage

moisture),

select

span value between 15.0 and 25.0 percent 02. For

C02 monitor installed on a

boiler, select

span value between 14.0 and 20.0

percent

C02. For a C02 monitor installed on a combustion

turbine, an alternative

span

value between 6.0 and 14.0 percent C02 may be used.

An alternative C02 span

value

below

6.0

percent may be used if an appropriate

technical justification is

included in

the hardcopy monitoring plan. An alternative 02

span value below

15.0 percent

02 may be used if an appropriate technical

justification is

included in the

monitoring plan (e.g., 02 concentrations

above

certain level

create an

unsafe operating

condition)

. Select the full-scale

range of the

instrument to be

consistent with Section 2.1 of this Exhibit

and

to be

greater

than or equal to

the

span value. Select the calibration gas

concentrations

for

the daily

calibration error tests and linearity checks in

accordance with

Section 5.1

of this Exhibit, as percentages of the span

value. For 02 monitors

with span

values ->= 21.0 percent 02, purified instrument

air containing 20.9

percent 02

may be used as the high-level calibration

material. If

dual-range

autoranging diluent analyzer is installed, the

analyzer may

represented in

the

monitoring plan as a single component, using a

special component type

code

specified by

the USEPA to satisfy the

requirements of 40 CFR

75.53(e) (1) (iv)

(D),

incorporated by reference in Section 225.140.

2.1.2 Flow Monitors

Select the

full-scale range of the flow monitor so that it is consistent with

Section 2.1 of

this Exhibit and can accurately measure all

potential volumetric

flow rates at

the flow monitor installation site.

2.1.2.1

Maximum Potential Velocity and Flow Rate

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

(wet basis)

from

velocity traverse

testing using

Reference Method 2

(or

its allowable

alternatives)

in appendix

40 CFR 60,

incorporated

reference in Section 225.140. If

using

test

values, use

the highest average velocity

(determined

from the

Method 2

traverses)

measured

or near the maximum unit operating load

(or, for

units

that do

not produce electrical or thermal output, at the

normal process

operating conditions corresponding to the maximum

stack

gas

flow

rate)

. Express

the

MPV in units of wet standard feet per minute (fpm).

For the purpose of

providing substitute data

during periods of missing flow rate data in accordance

with ee40

CFR 75.31

and 75.33

of 40 CFR Part 75

and

required elsewhere in

this part, calculate the

maximum potential stack

gas

flow rate

(MPF)

in units of

standard

cubic

feet

per

hour

(scfh),

the product of the MPV

(in

units of wet,

standard fpm)

times

60,

times the cross-sectional area of the stack or duct

(in

ff2)

at the

flow monitor location.

(Equation

A-3a)

(Equation

A-3b)

Where:

MPV

= maximum

potential velocity

(fpm, standard

wet

basis)

.Fd

= dry-basis F

factor

(dscf/mmBtu)

from Table

1, Section

3.3.5 of

, 40

CFR

Part

75.Fc = carbon-based

factor

(scf

C02/mmBtu) from

Table

Section

3.3.5

Appe-f4*ADDendj

F , 40 CFR Part

75.Hf = maximum

heat input (mmBtu/minute)

for all

units,

combined, exhausting

the stack

or duct where

the flow monitor

is located.A

= inside cross

sectional area

(ft2)

of the flue

at the flow

monitor

location.%02d=

maximum

oxygen concentration,

percent dry

basis, under normal

operating

conditions.%C02d=

minimum

carbon dioxide concentration,

percent

dry

basis,

under

normal

operating conditions.%H20=

maximum

percent flue

gas moisture

content under

normal operating

conditions.

2.1.2.2

Span Values and Range

Determine

the span

and range of the

flow monitor as

follows.

Convert

the

MPV,

determined in

Section

2.1.2.1

this Exhibit, to

the same measurement

units of

flow rate that

are used

for

daily calibration

error tests (e.g.,

scfh,

kscfh,

kacfm, or

differential

pressure

(inches

water))

. Next,

determine

the

“calibration

span

value by

multiplying

the

MPV

(converted

equivalent

daily

calibration

error

units)

a factor

no less

than

1.00

and no greater

than 1.25,

and rounding up

the

result

to at

least two

significant figures.

For

calibration

span values

inches

of water,

retain at least

two

decimal

places.

Select

appropriate

reference signals

for the daily

calibration

error

tests

percentages

of the calibration

span value,

as specified

Section

2.2.2.1

this

Exhibit. Finally,

calculate the

flow rate span

valueTT

(in

scfh) as

the

product

of the

MPF, as determined

in Section 2.1.2.1

of this

Exhibit,

times

the

same

factor

(between

1.00 and

1.25)

that was used

to calculate

the calibration

span

value.

Round off the

flow rate span value

to the nearest

1000

scfh. Select

the

full-scale range

of the flow monitor

that it is

greater than

or equal

the

span value and

is consistent with

Section 2.1 of

this

Exhibit.

Include

the

monitoring

plan for the

unit:

calculations of

the

MPV, MPF,

calibration

span

value,

flow

rate

span

value,

and full-scale range

(expressed

both in

scfh and,

if different,

in the

measurement

units of

calibration).

2.1.2.3

Adjustment

of Span

and Range

For each

affected unit

or common

stack, the

owner or operator

must make

periodic

evaluation

of the

MPV, span, and

range values

for each flow

rate

monitor

(at

minimum,

an annual

evaluation

is required)

and must

make any

necessary

span

and range adjustments

with

corresponding

monitoring

plan

updates,

described

in paragraph3subsections

(a)

through

(c)

of this

Section

2.1.2.3.

Span

and range

adjustments

may

be required,

for

example,

as a result

of changes

in the fuel

supply,

changes

in the

stack or ductwork

configuration, changes

the

manner of

operation of

the unit,

or installation

or removal of

emission

controls.

implementing the

provisions in paragraphssubsections

(a)

and

(b)

this

Section

2.1.2.3, note

that

flow rate

data recorded during

short-term, non

representative

operating

conditions

(e.g.,

a trial burn

of a different type

fuel)

must be

excluded

from consideration.

The owner

operator

must

keep the

results of the

most

recent

span

and range evaluation

on-site,

format

suitable

for

inspection.

Make

each required span

or range

adjustment

no later

than 45

days

after

the end

of the quarter

which the

need to adjust

the span

range is identified.

-(-a)

If the

fuel

supply,

stack

or ductwork configuration,

operating

parameters,

other

conditions

change

such that the maximum

potential

flow rate

changes

significantly,

adjust

the

span and range

assure the continued

accuracy

of the

flow monitor. A

significant

change

in the MPV means

that the

guidelines

Section 2.1 of

this

Exhibit

can

no longer be met,

determined

either

periodic evaluation

the

owner

or operator or

from the

results of

an audit by

the

Agency.

The

owner

operator should evaluate

whether

any planned

changes

operation

of the

unit may

affect the flow

of the unit

or stack and

should

plan

any

necessary span

and

range changes

needed to account

for these

changes,

that they are made

timely

a manner as

practicable

coordinate

with

the

operational

changes.

Calculate

the adjusted

calibration

span and flow

rate span

values using

the

procedures

in Section 2.1.2.2

of this

Exhibit.

-(-b)

Whenever

the full-scale

range

is exceeded

during

quarter,

provided that

the exceedance

is not caused

a monitor

out-of-control period,

report 200.0

percent of

the

current

full-scale

range as

the hourly flow

rate for each

hour of

the

full-scale exceedance.

the range

is exceeded,

make appropriate

adjustments

the flow rate

span-- and

range

prevent

future full-scale

exceedances.

Calculate the

new calibration

span

value

converting

the new flow

rate span value

from units

of scfh

to units

of daily calibration.

A calibration

error test

must be performed

and passed to

validate

data

on the new range.

-(-C)

Whenever

changes are

made to the

MPV, full-scale

range, or span

value

the

flow

monitor,

as described

paragrciphcsubsections

(a)

and

(b)

of this

Section, record

and report

(as

applicable)

the new full-scale

range setting,

calculations

of the flow

rate

span value,

calibration span

value, and MPV

updated

monitoring

plan for

the unit. The

monitoring

plan update must

made

the

quarter

which the changes

become

effective.

Record and report

the

adjusted

calibration

span and

reference

values

parts of the

records for the

calibration

error test required

Exhibit

B to this Appendix.

Whenever the

calibration

span value

is adjusted,

use

reference values

for the calibration

error test

that meet

the requirements

of Section 2.2.2.1

this

Exhibit,

based

on the

most

recent

adjusted calibration

span value.

Perform a

calibration

error

test

according

to Section 2.1.1

of Exhibit B to

this Appendix

whenever

making

change to

the flow

monitor

span or range,

unless the range

change also

triggers

recertification

under

Section 1.4 of

this

Appendix.

2.1.3

Mercury

Monitors

Determine

the

appropriate

span and range

valuc(c)values

for each mercury

pollutant

concentration

monitor,

so that

all

expected

mercury concentrations

can

determined

accurately.

2.1.3.1 Maximum

Potential

Concentration

The

maximum

potential

concentration

depends upon

the type of coal

combusted

the

unit.

For

the initial MPC

determination, there

are three options:

-(-1)

Use

one of the following

default

values: 9 ig/scm

for bituminous coal;

rig/scm

for sub-bituminous

coal;

jig/scm for lignite,

and 1

pg/scm

for

waste

coal,

i.e., anthracite

culm

bituminous

gob. If

different coals

are

blended,

use

the highest

MPC for

any

fuel in the blend;

-(-2)

You may base

the MPC

on the results

of site-specific

emission

testing

using

tIic

one of

the mercury

reference

methods

in Section 1.6 of

this

Appendix,

the unit does

not have

add-on

mercury

emission

controls or

flue

gas

desulfurization

system,

if you

test upstream

of these

control

devices.

minimum

of 3 test

runs are

required-r

at the

normal

operating

load.

Use

the

highest

total

mercury

concentration

obtained

any of

the tests

as the

MPC;

-3)

You

may base

the MPC

720 or

more hours

of historical

CEMS

data

from a sorbent

trap monitoring

system,

if the

unit

does

not

have

add-on

mercury

emission

controls

or a

flue

gas

desulfurization

system

(or

if the CEMS

sorbent

trap

system

is located

upstream

these

control

devices)

and if the

mercury

CEMS or sorbent

trap

system

has

been tested

for

relative

accuracy

against

one of

the mercury

reference

methods

in Section

1.6 of

this Appendix

and

has met

relative

accuracy

specification

20.0% or

less.

2.1.3.2

Maximum

Expected

Concentration

For

units

with

FGD

systems

that significantly

reduce

mercury

emissions

(including

fluidized

bed units

that

use

limestone

injection)

and

for

units

equipped

with add-on

mercury

emission

controls

(e.g.,

carbon

injection),

determine

the

maximum

expected

mercury concentration

(MEC)

during

normal,

stable

operation

the unit

and emission

controls.

calculate

the

MEC,

substitute

the

MPC value

from

Section

2.1.3.1 of

this Exhibit

into

Equation

A-2 in

Section

2.1.1.2

AppcndixalDoendix A to 40

CFR 75,

incorporated

reference

Section

225.140.

For

units

with

add-on

mercury

emission

controls,

base

the

percent

removal

efficiency

design

engineering

calculations.

For

units

with

FGD

systems,

use

the

best

available

estimate

of the

mercury

removal

efficiency

the

FGD system.

2.1.3.3

Span

and

Range

Valuc(c)

Values

-(-a)

For

each mercury

monitor,

determine

high

span value,

rounding

the MPC

value

from

Section

2.1.3.1 of

this Exhibit

upward

the next

highest multiple

of 10

rag/scm.

-(-b)

For an

affected

unit

equipped

with

an FGD

system or

a unit with

add-on

mercury

emission

controls,

the

MEC

value from

Section

2.1.3.2

of this

Exhibit

less

than 20

percent

of the

high

span value

from paragraphsubsection

(a)

this

Section,

and

if the

high span

value

20 ‘ag/scm

greater,

define

second,

low

span value

of 10

jig/scm.

-(-c)

only a

high

span

value is

required,

set

the

full-scale

range

the

mercury

analyzer

greater

than

or equal

the

span value.

-(-d)

If two

span

values

are

required,

you

may

either:

-(-1)

Use

two separate

(high

and

low)

measurement

scales,

setting

the

range

each scale

to be

greater

than or

equal

the high

or low span

value, as

appropriate;

Quality-assure

two

segments

of a single

measurement

scale.

2.1.3.4

Adjustment

of Span

and Range

For

each affected

unit

or common

stack,

the owner

or operator

must

make

periodic

evaluation

of the MPC,

MEC,

span,

and

range values

for

each mercury

monitor

(at

minimum,

annual

evaluation

is required)

and

must make

any

necessary

span

and range

adjustments,

with corresponding

monitoring

plan

updates.

Span

and range

adjustments

may

required,

for

example,

as a result

changes in

the

fuel

supply,

changes

in the

manner of

operation

the

unit,

installation or

removal of emission controls. In implementing the provisions in

paragraphzsubsections

(a)

and

(b)

of this Section,

data

recorded during short-

term, non-representative process

operating conditions

(e.g.,

a trial burn of a

different

type

fuel)

must be

excluded from consideration. The owner or

operator must keep the results

of the

most

recent

span and

range evaluation on-

site,

format suitable

for inspection. Make

each

required span or range

adjustment no later than 45 days after

the end

of the

quarter in which the need

to adjust

the span or range is identified,

except

that up to

days

after the

end

of that quarter may be taken to

implement

a span

adjustment if the

calibration

gas

concentrations currently

being

used for

calibration error

tests,

system

integrity checks, and linearity checks are

unsuitable for

use

with the

new

span value and new

calibration materials

must be

ordered.

-(-a)

The guidelines of Section 2.1 of

this Exhibit

not apply

mercury

monitoring systems.

-(-b)

Whenever a

full-scale range exceedance occurs during a quarter and is not

caused by

a monitor

out-of-control period, proceed

follows:

-(-1)

For monitors

with

single measurement scale, report that the system was

out

of range and

invalid

data

was obtained until the readings come

back

on-scale

and, if appropriate,

make adjustments

the MPC, span, and range to

prevent

future full-scale

exceedances; or

-(-2)

For units with

two separate measurement scales, if the low range

exceeded,

no further

action is required, provided that the high range is

available and is not

out-of-control or out-of-service for any reason.

However,

if the high range

is not able

provide quality assured data at the

time

of the

low range exceedance

any time during the continuation of the

exceedance,

report that the

system was out-of-control until the readings return to the low

range or until

the high range is able to provide quality assured data

(unless

the reason that

the high-scale range is not able to provide quality

assured

data

because the

high-scale range has been exceeded; if the high-scale range is

exceeded

the procedures in

pciragraphsubsection

(b) (1)

of this

Section).

-(-c)

Whenever changes are made to the MPC, MEC,

full-scale range, or

span value

of the

mercury monitor, record and report

(as

applicable) the new full-scale

range setting,

the new MPC or MEC and calculations

of the

adjusted

span value

an updated

monitoring plan. The monitoring plan update

must

made in the

quarter in

which the changes become effective. In

addition, record and report

the adjusted

span as part of the records for the

daily calibration error

test

and linearity

check specified by Exhibit B to this Appendix.

Whenever the

span

value is adjusted,

use calibration gas concentrations that

meet the requirements

of Section

5.1 of this Exhibit, based on the adjusted

span value. When a span

adjustment

is so significant that the

calibration

gas

concentrations currently

being used

for calibration

error

tests,

system integrity checks and linearity

checks are

unsuitable for

use

with the new span value, then a diagnostic

linearity or

3-level system integrity check using the new calibration gas

concentrations must be

performed and passed. Use the data validation procedures

Section

1.4(b)

(3)

of this Appendix, beginning with the hour in

which

the span

changed.

2.2 Design

for Quality Control Testing

2.2.1 Pollutant

Concentration

and C02 or 02

Monitors

-(-a)

Design and

equip each

pollutant concentration

and

C02

02 monitor

with

calibration gas

injection

port that

allows a check of

the

entire

measurement

system when

calibration gases

are

introduced. For

extractive

and

dilution

type

monitors, all

monitoring

components

exposed to

the sample gas,

(e.g., sample

lines,

filters,

scrubbers,

conditioners, and

as much of

the probe

practicable)

are

included

the measurement

system.

For in

zsitu type monitors,

the calibration

must check

against

the injected gas

for

the performance

of all

active

electronic and optical

components

(e.g..

transmitter,

receiver,

analyzer)

-(-b)

Design

and

equip each

pollutant concentration

C02 or 02 monitor

allow

daily

determinations

of calibration

error

(positive or negative)

at the

zero- and mid-

or high-level

concentrations

specified

in Section

5.2

this

Exhibit.

2.2.2

Flow

Monitors

Design all

flow monitors

meet

the applicable

performance

specifications.

2.2.2.1

Calibration

Error Test

Design

and

equip each flow

monitor

allow

for a

daily calibration

error

test

consisting

least two

reference

values:

Zero

20 percent

of span

or an

equivalent

reference

value

(e.g.,

pressure

pulse or electronic

signal)

and 50 to

70 percent

of span.

Flow monitor

response,

both before

and after any

adjustment,

must

capable

of being recorded

by the

data

acquisition

and handling

system.

Design

each

flow monitor to

allow a

daily

calibration

error test

of the

entire

flow

monitoring

system, from

and

including the

probe tip

(or

equivalent)

through

and

including the data

acquisition

and

handling system,

or the flow monitoring

system

from and including

the

transducer

through and

including the data

acquisition and

handling

system.

2.2.2.2

Interference

Check

-(-a)

Design and equip

each

flow

monitor

with

means

to ensure that

the

moisture expected

to occur

the

monitoring location

does not interfere

with

the

proper

functioning

of the

flow monitoring

system. Design and

equip

each flow

monitor

with a

means

to detect,

least

a daily basis,

pluggage

of each

sample

line and

sensing

port, and malfunction

of each

resistance

temperature

detector

(RTD),

transceiver

or equivalent.

-(-b)

Design

and

equip

each

differential

pressure

flow monitor

to provide an

automatic,

periodic

back

purging (simultaneously

on both

sides of the

probe)

equivalent

method

of sufficient

force and

frequency to

keep the probe

and

lines

sufficiently

free of obstructions

at least a

daily basis

prevent

velocity

sensing

interference, and

means

for detecting

leaks in the

system on

at least

quarterly

basis

(manual

check

is acceptable)

-(-c)

Design and

equip each

thermal

flow monitor

with

means to ensure

least

daily

basis that the

probe

remains

sufficiently

clean

prevent

velocity

sensing

interference.

-(-d)

Design and equip

each

ultrasonic flow

monitor with

means to ensure

least

daily basis

that the

transceivers

remain

sufficiently clean

(e.g.,

backpurgingback

urcxina

system) to

prevent velocity

sensing interference.

2.2.3

Mercury

Monitors-

Design

and

equip

each mercury monitor

permit

the

introduction of

known

concentrations

of elemental

mercury

and

HgC12

separately,

at a

point

immediately

preceding

the sample extraction

filtration

system,

such that

the entire

measurement

system can

be checked.

If the mercury

monitor

does not have a

converter,

the HgC12

injection

capability is not

required.

Performance

Specifications

3.1

Calibration Error

-f-a)

The calibration

error performance

specifications

in this Section

apply

only

to 7-day

calibration error

tests under

Sections

6.3.1 and

6.3.2 of this

Exhibit

and

the off line

calibration

demonstration

described

Section

2.1.1.2

of Exhibit B

to this Appendix.

The

calibration

error

limits for daily

operation

of the continuous

monitoring

systems required

under this part

are

found in Section

2.1.4(a)

of Exhibit

B to this

Appendix.

-(-b)

The

calibration error

of a mercury

concentration

monitor

must not deviate

from

the reference value

of either the

zero or

upscale calibration

gas by

than

5.0 percent of

the span value,

calculated

using

Equation A-S of

this

Exhibit. Alternatively,

if the span

value is

pg/scm,

the calibration

error

test results

are also acceptable

if the

absolute

value of the difference

between

the monitor

response value

and the reference

value, R-A

in Equation

A-5 of this

Exhibit,

is .= 1.0 pg/scm.

(Equation

A-5)

whcrc,

Where:

= Calibration

error as a

percentage of

the span of

the

instrument.R

Reference

value

zero

or upscale (high-level

or mid-level,

applicable)

calibration

gas introduced

into the

monitoring

system.A

= Actual monitoring

system response

the calibration

gas.S = Span of

the instrument,

as specified

in Section

of this Exhibit.

3.2

Linearity Check

For C02 or

monitors

(including

02 monitors used

to measure C02 emissions

percent

moisture)

-(-a)

The error in linearity

for each calibration

gas concentration

(low-,

mid-,

and

high-levels) must

not exceed or

deviate from the

reference value by

than 5.0 percent

calculated using

Equation

A-4 of

this Exhibit;

-(-b)

The

absolute value

of the difference

between

the average

of the monitor

response

values and the

average of the

reference

values,

R-A in Equation A-4

this

Exhibit, must

be less than or

equal

to 0.5

percent

C02 or 02,

whichever

less

restrictive.

-(-c)

For the linearity

check and the

3-level system

integrity check of

mercury monitor,

which are required,

respectively,

under Section

1.4(c) (1) (B)

and

(C)

(1)

(E)

of this Appendix,

the

measurement

error

must not

exceed 10.0

percent

the reference

value at any

of the three

gas levels.

calculate

the

measurement

error at each

level, take

the

absolute

value

of the difference

between

the

reference

value

and

mean CEM response,

divide

the result by

the

reference

value,

and then multiply by

100.

Alternatively, the results at

any

gas

level are acceptable if the absolute

value

of the difference between the

average

monitor

response and the average

reference

value, i.e., R-A

Equation

A-4 of

this

Exhibit,

does

not exceed 0.8

jig/m3.

The principal and alternative

performance specifications in this Section also apply to the

single-level

system

integrity check described in Section 2.6 of Exhibit B to this Appendix.

(Equation

A-4)

whcrc,

Where:

= Percentage

Lincaritylinearitv

error, based upon the

reference value.R =

Reference value of ew1Qw-, mid-, or high-level calibration gas introduced into

the

monitoring system.A = Average of the monitoring system responses.

3.3

Relative Accuracy

3.3.1 Relative Accuracy for C02 and 02 Monitors

The relative accuracy for C02 and 02 monitors must not

exceed 10.0 percent.

The

relative accuracy test results are also acceptable if the

difference between

the

mean value of the C02 or 02 monitor measurements and the

corresponding reference

method measurement mean value, calculated using equation

A-7 of this Exhibit,

does

not exceed

±—±

1.0 percent C02 or 02.

(Equation

A-7)

whcrc,

Where:

= Number of data points.di

= The

difference

between

reference method value

and

the corresponding continuous emission monitoring

system value

(RMi-

CEMi)

given point in time i.

3.3.2 Relative Accuracy for Flow Monitors

-+a)

The relative accuracy

of flow monitors must not exceed 10.0 percent

any

load

(or

operating)

level

which

RATA is performed

(i.e.,

the low, mid, or

high level, as defined in

Section

6.5.2.1

of this

Exhibit)

-(-b)

For affected

units where the average of the flow reference method

measurements

gas

velocity at

particular load

(or

operating) level of the

relative accuracy test audit is less than or equal to 10.0 fps,

the difference

between the mean value of the flow monitor velocity measurements

and the

reference

method mean value in fps at that level must not exceed -f----j

2.0

fps,

wherever the 10.0 percent relative accuracy specification is not

achieved.

3.3.3

Relative Accuracy for

Moisture

Monitoring Systems

The

relative accuracy of a

moisture monitoring system must not exceed 10.0

percent. The

relative accuracy

test

results are also acceptable if the

difference

between

the

mean value

the reference method measurements

(in

percent

H20)

and

the corresponding mean value of

the

moisture monitoring system

measurements

(in

percent

H20),

calculated

using

Equation A-7 of this Exhibit

does

not exceed

---—

1.5 percent

I-{20.

3.3.4 Relative

Accuracy for Mercury Monitoring Systems

The

relative

accuracy

mercury

concentration

monitoring

system or

sorbent

trap monitoring

system

must

not exceed 20.0 percent.

Alternatively,

for affected

units where the

average

the reference method

measurements

mercury

concentration

during

the

relative accuracy

test audit is

less

than

5.0 jig/scm,

the test

results

are

acceptable if

the difference between

the

mean

value

of the

monitor

measurements

and the reference

method mean

value does

not

exceed 1.0

ig/scm,

in cases

where

the

relative

accuracy

specification of

20.0

percent is

not

achieved.

3.4 Bias

3.4.1

Flow

Monitors

Flow

monitors must not

be biased low as

determined by

the

test

procedure

Section

7.4 of this

Exhibit.

The bias

specification

applies

all flow

monitors

including those

measuring

average

gas velocity

10.0

fps

or less.

3.4.2

Mercury

Monitoring

Systems

Mercury

concentration

monitoring

systems

and

sorbent trap monitoring

systems

must

not be

biased

low as determined

by the test

procedure

in Section 7.4

this

Exhibit.

3.5 Cycle

Time

The

cycle time

for

mercury

concentration

monitors,

oxygen monitors

used

determine

percent

moisture,

and any other monitoring

component

of a continuous

emission

monitoring system

that is required

perform

cycle time test

must

not exceed

15 minutes.

4. Data

Acquisition

and

Handling

Systems

Automated

data

acquisition

and handling

systems must

read and

record

the

full

range

pollutant

concentrations

and volumetric

flow from

zero through

span and

provide

continuous,

permanent

record of all

measurements

and required

information

as an ASCII flat

file capable

transmission

both

direct

computer-to-computer

electronic transfer

via modem and

EPA-provided

software

and

IBM-compatible

personal computer

diskette. These

systems

also must

have

the

capability

of interpreting and

converting the

individual

output

signals from

flow

monitor,

a C02 monitor,

an 02 monitor,

moisture

monitoring

system, a

mercury

concentration monitoring

system, and

a sorbent

trap monitoring

system,

produce

continuous

readout of pollutant

emission rates

pollutant

mass

emissions

(as

applicable)

in the appropriate

units (e.g.,

lb/hr.

lb/MNBtummBtu,

ounces/hr,

tons/hr)

. These systems

also must have

the

capability

interpreting

and

converting

the individual

output

signals

from a flow

monitor

to produce

continuous

readout of pollutant

mass

emission

rates in the

units

the

standard.

Where C02 emissions

are

measured

with a continuous

emission

monitoring

system,

the

data acquisition

and

handling

system must

also produce

readout

C02

mass

emissions

in tons.

Data

acquisition

and

handling

systems must

also

compute

and record monitor

calibration

error--

any

bias adjustments

mercury

pollutant concentration

data,

flow rate

data, or mercury

emission

rate data.

Calibration

Gas

5.1

Reference

Gases

For

the

purposes

of this Appendix,

calibration

gases include

the

following:

5.1.1

Standard

Reference

Materials

(SRM)

These

calibration

gases

may

obtained

from the

National

Institute

Standards

and

Technology

(NIST)

at the

following

address:

Quince

Orchard and

Cloppers

Road,

Gaithersburg,

MD 20899-0001.

5.1.2

SRM-Equivalent

Compressed

Gas Primary

Reference

Material

(PRM)

Contact

the Gas Metrology

Team, Analytical

Chemistry

Division,

Chemical

Science

and

Technology

Laboratory

of NIST,

the address

in Section

5.1.1,

for

list

vendors

and

cylinder

gases.

5.1.3

NIST

Traceable

Reference

Materials

Contact

the Gas

Metrology

Team, Analytical

Chemistry

Division,

Chemical

Science

and

Technology

Laboratory

of NIST,

the address

Section

5.1.1, for

a list

vendors and

cylinder

gases

that meet

the

definition

for

NIST Traceable

Reference

Material

(NTRM)

provided

CFR 72.2,

incorporated

reference

Section

225.140.

5.1.4

EPA Protocol

Gases

-(-a)

EPA Protocol

Gas is

a calibration

gas

mixture

prepared

and analyzed

according

Section

2 of

the

“EPA

Traceability

Protocol

for

Assay and

Certification

of Gaseous

Calibration

Standards-

-”

September

1997, EPA-600/R-

97/121

such revised

procedure

as approved

the Administrator

(EPA

Traceability

Protocol)

-(-b)

EPA Protocol

Gas

must

have

a specialty

gas

producer-certified

uncertainty

(95—

percent

confidence

interval)

that

must not

greater

than

2.0

percent

the certified

concentration (tag

value)

of the

gas

mixture.

The

uncertainty

must

calculated

using the

statistical

procedures

(or

equivalent

statistical

techniques)

that

are listed

in Section

2.1.8

the

EPA Traceability

Protocol.

-(-c)

A copy

of EPA-600/R-97/121 is available

from

the National

Technical

Information

Service,

5285 Port

Royal

Road,

Springfield-r

VA, 703-605-6585

http://www.ntis.gov,

and from

http://www.epa.gov/ttn/emc/news.html

or http://

www. epa.

gov/appcdwww/t

sb/index.

html.

5.1.5

Research

Gas

Mixtures

Research

gas

mixtures

must

vendor-certified to

be within

2.0

percent

of the

concentration

specified

on the

cylinder

label (tag

value),

using

the

uncertainty

calculation

procedure

in Section

2.1.8

of the

“EPA Traceability

Protocol

for

Assay

and

Certification

of Gaseous

Calibration

Standards-r”,

September

1997,

EPA

600/R-97/121.

Inquiries

about

the

RGM

program

should

be directed

to:

National

Institute

Standards

and

Technology,

Analytical

Chemistry

Division,

Chemical

Science

and

Technology

Laboratory,

B-324

Chemistry,

Gaithersburg-r

MD 20899.

5.1.6

Zero

Air Material

Zero

air material is defined in 40

CFR

72.2, incorporated by reference in

Section 225.140.

5.1.7

NIST/EPA-Approved Certified Reference Materials

Existing certified

reference materials

(CRM5)

that are still within their

certification period

may

be used as

calibration

gas.

5.1.8 Gas

Manufacturer’s Intermediate Standards

Gas

manufacturer’s intermediate

standards

is defined in

40 CFR 72.2,

incorporated by reference

in Section 225.140.

5.1.9 Mercury Standards

For 7-day

calibration error tests of mercury concentration monitors and

for

daily

calibration error tests of mercury monitors, either

NIST-traceable

elemental mercury standards

(as

defined in Section

225.130)

or a

NIST-traceable

source

of oxidized mercury

(as

defined in Section

225.130)

may be used.

For

linearity checks, NIST-traceable elemental mercury standards must be used. For

level and single-point system integrity checks under

Section 1.4(c)

(1)

(E)

this

Appendix, Sections 6.2(g) and 6.3.1 of this Exhibit, and

Sections 2.1.1,

2.2.1

and

2.6

of Exhibit B to this Appendix, a NIST-traceable

source of

oxidized

mercury must be used.

Alternatively, other NIST-traceable standards may be used

for the required

checks, subject to the approval of the Agency. Notwithstanding

these

requirements, mercury calibration standards that are not NIST-traceable

may be used for the tests

described in this Section until December 31, 2009.

However, on and

after January 1, 2010, only NIST-traceable calibration standards

must be used for

these

tests.

. 2 Concentrations

Four concentration

levels are required

follows.

5.2.1

Zero-level Concentration

0.0 to 20.0

percent of span, including span for high-scale

or both low-

and

high-scale for C02 and 02 monitors, as appropriate.

5.2.2 Low-level

Concentration

20.0 to 30.0

percent of span, including span for high-scale or

both low-

and

high-scale for

C02 and 02 monitors, as appropriate.

5.2.3

Mid-level Concentration

50.0 to 60.0

percent of span, including span for high-scale or both

low-

and

high-scale for

C02 and 02 monitors, as appropriate.

5.2.4

High-level

Concentration

80.0 to 100.0

percent of span, including span for high-scale or both

low-and

high-scale for C02 and 02 monitors, as appropriate.

Certification Tests and

Procedures

6.1

General

Requirements

6.1.1 Pretest

Preparation

Install the

components of the continuous emission monitoring system

(i.e.,

pollutant

concentration monitors, C02 or 02 monitor, and flow

monitor)

specified in

Sections 1, 2, and 3 of this Exhibit, and prepare each system

component

and

the combined system for operation in accordance with the

manufacturers

written instructions. Operate the

unit(c)units

during each period

when

measurements are made. Units may be tested on

non-consecutive

days.

To the

extent

practicable, test the DABS software prior to testing the

monitoring

hardware.

6.1.2 Requirements for Air Emission Testing Bodies

-(-a)

On and after January 1, 2009, any Air Emission

Testing Body

(AETB)

conducting relative accuracy test audits of CEMS and sorbent

trap monitoring

systems

under Part 225, Subpart B, must conform to the requirements

of ASTM

D7036-04

(incorporated by reference

undcrin.

Section

225.140)

. This Section

not

applicable

daily operation, daily calibration error checks,

daily

flow

interference

checks, quarterly linearity checks or routine maintenance

CEMS.

-(-b)

The AETB

must provide

the affected

courcc(c)sources

certification that

the AETB operates

in conformance with, and that data submitted to the

Agency

has

been collected

in accordance with, the requirements of ASTM D7036-04

(incorporated

reference

undcrin

Section

225.140)

. This

certification may

provided in

the form of:

-(-1)

certificate of accreditation of relevant scope issued by a

recognized,

national accreditation body; or

-(-2)

letter of

certification signed

by a

member of the senior management

staff of the AETB.

-(-c)

The AETB must

either provide

Qualified Individual on-site to conduct or

must

oversee all

relative accuracy testing carried out by the AETB as required

ASTM 07036-04 (incorporated by reference

underin

Section

225.140)

. The

Qualified

Individual

must

provide the affected

zourcc(c)sources

with copies of

the

qualification

credentials relevant

the scope of the testing conducted.

6.2

Linearity Check

(General

Procedures)

Check the linearity of each C02, Hg, and

02 monitor while the unit, or group of

units

for a common stack, is combusting

fuel

conditions of typical stack

temperature and pressure; it is not

necessary for the unit to be generating

electricity during this test.

For

units

with two measurement ranges (high and

low)

for a

particular parameter, perform

linearity check on both the low scale

and

the

high scale. For on-going quality assurance of the CEMS, perform

linearity

checks, using the procedures in this Section, on the

rangc(o)ranaes

and at

the frequency specified in Section 2.2.1 of Exhibit

to this

Appendix.

Challenge

each monitor with calibration gas, as defined

Section 5.1 of

this

Exhibit,

at the low-, mid-, and high-range

concentrations specified in Section

5.2

this Exhibit.

Introduce

the

calibration

gas at

the gas injection port,

specified in

Section 2.2.1 of this Exhibit. Operate each monitor at its normal

operating

temperature and conditions. For extractive and dilution type monitors,

pass the

calibration

gas

through all filters, scrubbers, conditioners, and other

monitor

components used during normal sampling and through as much of

the

sampling

probe

is practical. For in-situ type monitors, perform

calibration

checking

all

active electronic and optical components, including the

transmitter, receiver, and analyzer. Challenge the monitor three times with each

reference

gas

(see

example

data

sheet in Figure 1) . Do

not use the

same

gas

twice in succession. To the extent practicable,

the

duration of each linearity

test,

from

the

hour of the first injection

the hour of the last injection,

must

not

exceed

24 unit operating hours. Record

the

monitor response from the

data acquisition

and handling system. For each concentration,

use

the average of

the

responses

determine the error in linearity

using

Equation A-4 in this

Exhibit.

Linearity

checks are

acceptable for monitor or monitoring

system

certification, recertification, or

quality assurance if none of the test

results

exceed the

applicable performance

specifications in Section 3.2 of

this Exhibit.

The status of

emission

data from a CEMS prior to and during a linearity test

period must be

determined

as follows:

-4-a)

For the initial certification of a CEMS, data from the monitoring system

are considered invalid until all certification tests, including the linearity

test, have been

successfully

completed, unless the conditional data

validation

procedures in Section

1.4(b)

(3)

of this Appendix are used. When the procedures

in Section

1.4(b) (3)

of this Appendix

are followed, the words

Tlinitial

certification”

apply instead of

“recertification-”..

and complete all of the

initial

certification

tests by

January 1, 2009, rather than within the time

periods

specified in Section

1.4(b) (3) (0)

of this Appendix for the individual

tests.

-4-b)

For the routine quality assurance linearity checks required by Section

2.2.1 of Exhibit B to this Appendix, use the data validation procedures in

Section 2.2.3 of Exhibit B to this Appendix.

-4-c)

When

linearity test is required as a diagnostic test or for

recertification, use the data validation procedures in Section 1.4

(b) (3)

this

Appendix.

-(-d)

For

linearity

tests

of non-redundant backup monitoring systems, use the

data

validation procedures in Section

1.4(d) (2) (C)

of this Appendix.

-(-e)

For linearity tests performed during a grace period and after the

expiration of a grace period, use the data validation procedures in Sections

2.2.3 and 2.2.4, respectively, of Exhibit B to this Appendix.

-4-i)

For all

other linearity checks,

use the data

validation procedures in

Section 2.2.3 of

Exhibit

B to

this Appendix.

-4-g)

For mercury monitors, follow the guidelines in Section 2.2.3 of this

Exhibit in addition

the applicable procedures in Section 6.2 when performing

the

system integrity checks described in Section

1.4(c) (1) (E)

and in Sections

2.1.1, 2.2.1, and 2.6 of Exhibit B to this Appendix.

-4-h)

For mercury concentration monitors, if moisture is added to the

calibration gas during the required linearity checks or system integrity checks,

the

moisture

content of the calibration gas must be accounted for. Under these

circumstances,

the dry basis concentration of the calibration gas must be used

calculate the linearity error or measurement error

(as

applicable)

6.3

7-Day Calibration Error Test

6.3.1 Gas Monitor 7-day Calibration Error Test

Measure

the

calibration error of each mercury concentration

monitor-r

and each

C02 or 02 monitor

while

the unit is

combusting fuel

(but

not necessarily

generating electricity) once each day

for

7 consecutive

operating

days

according

the following procedures. For

mercury

monitors, you may

perform this

test

using either elemental mercury

standards

or a NIST-traceable

source of oxidized

mercury. Also for mercury monitors,

if moisture

is added to

the calibration gas,

the added moisture must be accounted

for

and the dry-basis

concentration of the

calibration

gas

must be used to

calculate

the calibration

error.

(In

the event

that unit outages occur after the

commencement

of the test,

the 7 consecutive

unit operating days need not be 7

consecutive calendar

days.)

Units using dual

span monitors must

perform the calibration error

test

on both high- and low-

scales of the

pollutant concentration monitor. The calibration error test

procedures in this

Section and in Section 6.3.2 of this Exhibit must also be

used to perform

the daily assessments and additional calibration error tests

required under

Sections 2.1.1 and 2.1.3 of Exhibit B

this Appendix. Do not

make manual or

automatic adjustments

the monitor settings until after taking

measurements at

both zero and high concentration levels for that day during the

7-day test. If

automatic adjustments are made following both injections, conduct

the calibration

error

test

such that the magnitude of the adjustments can be

determined and

recorded. Record and report

test

results for each day using the

unadjusted

concentration measured in the calibration error test prior to making

any manual or automatic

adjustments (i.e., resetting the

calibration).

The

calibration error tests

should

approximately 24 hours apart,

(unless

the 7-

day test

is performed over

non-consecutive

days)

. Perform calibration error

tests at

both the zero-level

concentration and high-level concentration, as

specified in Section 5.2 of

this Exhibit. Alternatively,

mid-level

concentration gas

(50.0

to 60.0 percent

of the span

value)

may be used in lieu

of the high-level gas,

provided that the mid-level

gas

is more representative of

the actual stack gas

concentrations.

Use

only calibration gas, as specified in

Section

5.1 of this

Exhibit. Introduce the calibration

gas

at the gas injection

port, as

specified in Section 2.2.1 of this Exhibit. Operate each monitor in its

normal

sampling mode. For extractive and dilution type monitors, pass the

calibration gas

through all filters, scrubbers, conditioners, and other monitor

components used

during normal sampling and through as much of the

sampling

probe

practical. For in-situ type monitors, perform

calibration, checking all

active electronic and optical components,

including the transmitter, receiver,

and

analyzer. Challenge the

pollutant concentration monitors and C02 or 02

monitors once with each

calibration

gas.

Record the monitor response from the

data

acquisition and handling system. Using

Equation A-5 of this Exhibit,

determine the calibration error at each

concentration once each day

(at

approximately 24-hour

intervals)

for 7

consecutive

days

according

the

procedures given in this Section. The results of a 7-day

calibration error

test

are

acceptable for monitor or monitoring system

certification, recertification

diagnostic testing if none of these daily

calibration error

test

results

exceed

the applicable performance

specifications

Section 3.1 of this

Exhibit. The status of emission data from a gas

monitor prior

and during

day

calibration error test period must be

determined

follows:

-(-a)

For initial certification, data

from the monitor are considered invalid

until all

certification

tests,

including the

7-day

calibration error test, have

been

successfully

completed,

unless the conditional data validation procedures

Section

1.4(b) (3)

this Appendix are used. When the procedures in Section

1.4(b)

(3)

of this Appendix are followed, the words

TTinitial

certification” apply

instead

of recertification-

-”and complete all of the initial

certification

tests

by January 1, 2009, rather than within the time periods

specified in

Section

1.4(b) (3) CD)

of this Appendix for the individual tests.

-(-b)

When

7-day calibration

error

test

required as a

diagnostic

test

for recertification, use the data

validation procedures in Section

1.4(b) (3)

this

Appendix.

6.3.2 Flow Monitor 7-day

Calibration Error Test

Flow monitors

installed on peaking units

(as

defined in 40 CFR 72.2,

incorporated by

reference in Section

225.140)

are exempted from the 7-day

calibration

error test requirements of this part. In all other cases,

perform

the 7-day

calibration error test of a flow monitor, when required for

certification,

recertification or diagnostic testing, according to the

following

procedures. Introduce

the reference signal corresponding to the values

specified

in Section 2.2.2.1

of this Exhibit to the probe tip

(or

equivalent), or to the

transducer. During

the

7-day

certification

test

period, conduct the calibration

error

test

while the

unit

operating once each unit operating day

(as

close to

24-hour intervals as

practicable) . In the event that unit outages occur after

the

commencement of the test,

the 7 consecutive operating days need not be 7

consecutive calendar days.

Record the flow monitor responses by means of the

data

acquisition and handling

system. Calculate the calibration error using

Equation A-6 of this

Exhibit. Do not perform any corrective maintenance, repair,

or replacement

upon the flow monitor during the 7-day test period

other

than

that required

in the quality assurance/quality control plan

required

Exhibit

this

Appendix. Do not make adjustments between the zero and

high reference

level

measurements on any day during the 7-day test. If the flow

monitor

operates

within the calibration error performance

specification (i.e., less

than

equal to 3.0

percent error each day and requiring no

corrective maintenance,

repair, or

replacement during the 7-day test period),

the flow monitor passes

the

calibration error test. Record all maintenance

activities and the magnitude

of any

adjustments. Record output readings from the data

acquisition and

handling

system before and after all adjustments. Record

and report all

calibration

error test results using the unadjusted

flow rate measured in the

calibration

error

test

prior to resetting the

calibration. Record all

adjustments made

during the 7-day period at the time the

adjustment is made,

and

report them

in the certification or recertification application.

The

status of

emissions data

from a flow monitor prior to and during a 7-day

calibration

error

test period

must be determined as follows:

-f-a)

For initial certification, data from

the monitor are considered invalid

until

all certification tests, including the 7-day

calibration error test, have

been

successfully completed, unless the

conditional

data

validation procedures

Section

1.4(b) (3)

of this Appendix

are

used.

When the procedures in Section

1.4(b)

(3)

of this Appendix are followed, the

words

ITinitial

certification” apply

instead

of “recertification” and

complete all of the initial certification

tests

by January 1,

2009, rather than within the time periods specified in

Section

1.4(b) (3)

(D) of this Appendix for the individual tests.

-{-b)

When a 7-day

calibration error test is required as a diagnostic test or

for

recertification,

use

the

data

validation procedures in Section

1.4

(b)

(3).

(Equation

A-6)

whcrc:

Where:

= Calibration error as a percentage of span.R

= Low or high level reference

value specified

Section

2.2.2.1 of this Exhibit.A = Actual flow monitor

response

to the

reference

value.S =

Flow monitor calibration

span value as

determined

under

Section 2.1.2.2

of this Exhibit.

6.3.3

For gas or

flow monitors

installed

on peaking

units,

the exemption

from

performing

the

7-day calibration

error test

applies

as long

the unit

continues

meet

the

definition of a peaking

unit in 40

CFR 72.2, incorporated

reference

Section

225.140. However,

if at the end

particular

calendar

year

or ozone

season, it is determined

that peaking

unit

status

has

been lost,

the owner or

operator must perform

a diagnostic

7-day calibration

error test of

each monitor

installed on

the unit, by no

later than December

31 of the

following

calendar year.

6.4 Cycle Time

Test

Perform

cycle time tests

for each pollutant

concentration monitor

and continuous

emission

monitoring system

while the

unit

operating,

according to

the

following

procedures.

Use a

zero-level and

a high-level

calibration gas

(as

defined

Section

5.2 of

this

Exhibit)

alternately.

For mercury

monitors, the

calibration

gas used

for this

test

may

either be the

elemental

or oxidized

form

mercury.

determine

the downscale

cycle time, measure

the

concentration

the

flue

gas emissions

until the

response stabilizes.

Record

the

stable

emissions

value. Inject

zero-level

concentration

calibration

gas

into the

probe tip

(or

injection

port leading

the

calibration

cell, for

situ

systems

with

no probe) . Record

the time

the zero

gas injection,

using the

data acquisition

and handling

system

(DAHS) . Next, allow

the

monitor to

measure

the

concentration of

the zero gas until

the

response

stabilizes.

Record the

stable

ending calibration

gas reading.

Determine

the

downscale cycle time

as the

time it takes for

95.0 percent of

the step

change

to be achieved between

the

stable stack

emissions value

and the stable

ending

zero

gas reading.

Then repeat

the procedure,

starting with

stable stack

emissions and

injecting

the

high-level

gas,

to determine the

upscale

cycle time,

which is

the

time

it takes

for

95.0

percent

of the step

change to be

achieved between

the

stable stack

emissions

value and the stable

ending

high-level

gas

reading. Use

the

following criteria

to assess

when

a stable

reading of stack

emissions or calibration

gas

concentration

has been

attained. A

stable value is equivalent

to a

reading

with

change of

less

than 2.0 percent

of the span value

for 2 minutes,

or a reading

with

change

of less than

6.0

percent from the

measured average

concentration

over

minutes.

Alternatively,

the reading

is considered stable

if it changes

than

0.5

ppm,

0.5 ig/m3

(for

mercury)

for

two

minutes.

(Owners

operators

of systems

whi-eIt1iat

do not

record data

1-minute or 3-minute

intervals may petition

the Agency

for

alternative

stabilization

criteria).

For

monitors or

monitoring systems

that perform a

series

of operations

(such

purge, sample,

and analyze),

time the injections

the calibration

gases so

they

will

produce

the

longest possible

cycle time. Refer

Figures 6a and

6b in

this

Exhibit for example

calculations

of upscale

and

downscale cycle times.

Report the slower

of the two cycle

times (upscale

downscale)

the cycle

time

for the

analyzer. On and

after January 1,

2009, record the

cycle time for

each component

analyzer separately.

For

time-shared

systems,

perform the cycle

time

tests at each

the probe

locations that will

polled

within

the

same

15-minute

period during

monitoring

system operations.

To determine the

cycle

time

for

time-shared

systems, at

each monitoring

location,

report the

sum

of the

cycle

time observed

that monitoring

location plus

the sum of

the

time

required

for

all

purge

cycles

(as

determined

by the continuous

emission

monitoring system

manufacturer)

each of the probe

locations of the

time

shared

systems.

For monitors

with

dual ranges,

report

the test

results for each

range separately.

Cycle time

test

results

are acceptable for

monitor or

monitoring system certification,

recertification

or diagnostic

testing if none

the cycle times exceed 15 minutes.

The

status of emissions data

from

monitor prior

and during

cycle

time

test period must be

determined

follows:

-(-a)

For initial

certification,

data

from

the monitor are

considered invalid

until all certification tests,

including

the cycle

time

test,

have been

successfully completed, unless the

conditional

data

validation procedures in

Section

1.4(b) (3)

of this Appendix are used. When the procedures in Section

1.4(b) (3)

of this

Appendix are followed, the words “initial

certificationTl

apply

instead

TIrecertificationyT

and complete all of the initial certification

tests by January 1,

2009,

rather than

within the time periods specified in

Section

1.4(b) (3) (D)

of this

Appendix

for

the

individual

tests.

-(-b)

When

cycle time test is required as a diagnostic test

or for

recertification, use the data validation procedures

in Section

1.4(b) (3)

of this

Appendix.

6.5

Relative Accuracy and Bias Tests

(General

Procedures)

Perform the required relative accuracy test

audits (RATA5)

follows for each

flow monitor, each 02 or C02 diluent

monitor

used to

calculate heat input, each

mercury concentration monitoring

system, each sorbent trap monitoring system,

and

each moisture monitoring system--.

-(-a)

Except as

otherwise provided in this paag*aphuhetiQn, perform each

RATA while the

unit (or units, if more than one unit exhausts into the

flue)

combusting the

fuel that is

normal primary or backup fuel for that unit

(for

some units, more

than one

type

of fuel may

considered normal, e.g., a unit

that combusts gas

or oil on

seasonal

basis)

. For units that co-fire fuels as

the predominant

mode of operation, perform the RATAs while co-firing. For

mercury

monitoring systems, perform the RATA5 while the unit is

combusting

coal.

When

relative accuracy test audits are performed on CEMS installed

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.

-(-b)

Perform each RATA at the load

(or

operating)

lcvcl(z)levels specified

Section

6.5.1

or 6.5.2 of this Exhibit or in Section

2.3.1.3 of Exhibit B

this

Appendix, as applicable.

-(-c)

For monitoring systems with dual ranges,

perform the relative accuracy

test on

the range normally used for

measuring emissions. For units with add-on

mercury

controls that operate

continuously rather than seasonally, or for units

that

need a dual range to record high

concentration spikes” during startup

conditions, the

low

range is considered

normal. However, for some dual span

units (e.g.,

for

units

that use

fuel switching or for which the emission

controls are

operated seasonally), provided that both monitor ranges are

connected to a

common probe and sample interface, either of the two measurement

ranges may be

considered normal; in such cases, perform the RATA on the

range

that

is in use at

the time of the scheduled test. If the low and high

measurement

ranges are connected

separate sample probes and interfaces, RATA

testing on

both ranges is required.

-(-d)

Record

monitor or monitoring system output from the data

acquisition

and

handling system.

-(-e)

Complete each

single-load relative

accuracy test

audit within a

period

168

consecutive

unit operating hours,

as defined

40 CFR 72.2, incorporated

reference in

Section

225.140

(or, for CEMS installed

on common

stacks

or bypass

stacks,

168 consecutive stack

operating hours,

defined in

40 CFR 72.2,

incorporated

reference

in Section

225.140)

. Notwithstanding

this requirement,

up to 336

consecutive

unit

stack

operating

hours

may

taken

complete

the

RATA of

mercury

monitoring system,

when ASTM 6784-02

(incorporated

reference

undcrin

Section

225.140)

or Method 29

appendix A-8

to 40

CFR 60,

incorporated

reference

in Section 225.140,

used as

the

reference

method.

For 2-level

and

3-level

flow

monitor RATA5, complete

all

of the RATAs

at all

levels,

to the

extent

practicable,

within

a period of 168

consecutive

unit

(or

stack)

operating

hours; however,

if this

is not possible,

up to

720

consecutive

unit

(or stack)

operating hours

may

be taken to complete

a multiple-load

flow

RATA.

-f)

The

status

emission

data from the

CEMS prior to

and during

the RATA

test

period must

be determined

as follows:

-(-1)

For

the initial certification

CEMS,

data

from the

monitoring

system

are

considered invalid

until all certification

tests,

including

the RATA,

have

been

successfully

completed, unless

the conditional data

validation

procedures

Section

1.4(b) (3)

of this Appendix

are

used.

When

the procedures

Section

1.4(b) (3)

this

Appendix

are

followed, the words

Tlinitial

certification”

apply

instead

“recertification-

-”

and complete

all of the initial

certification

tests by

January 1,

2009,

rather than within

the time periods

specified in

Section

1.4(b)

(3) (ID)

of this Appendix

for the individual

tests.

-(-2)

For

the

routine quality

assurance RATA5

required

Section

2.3.1

Exhibit B to

this Appendix,

use

the data

validation

procedures

in Section

2.3.2

of Exhibit

this

Appendix.

-(-3)

For recertification

RATA5,

use

the

data

validation

procedures

Section

1.4(b) (3).

-(-4)

For quality

assurance

RATA5 of non-redundant

backup

monitoring

systems,

use

the data

validation

procedures

ScctioncSection

1.4(d) (2)

(ID)

and

(E)

this Appendix.

-(-5)

For

RATA5 performed

during

and after

the

expiration

grace

period,

use

the

data

validation

procedures

in Sections

2.3.2 and

2.3.3, respectively,

Exhibit

B to

this Appendix.

-(-6)

For all

other RATA5,

use

the data validation

procedures

Section 2.3.2

Exhibit

B to

this

Appendix.

-(-g)

For

each

flow monitor,

each C02

or 02 diluent

monitor

used to determine

heat input,

each moisture

monitoring

system,

each mercury concentration

monitoring

system, and

each

sorbent trap

monitoring system,

calculate

the

relative

accuracy,

in accordance with

Section 7.3 of

this Exhibit, as

applicable.

6.5.1

Gas

and

Mercury

Monitoring

System RATA5

(Special

Considerations)

-(-a)

Perform

the required

relative

accuracy test audits

for each

C02

or 02

diluent

monitor used

determine

heat input, each

mercury concentration

monitoring

system, and

each

sorbent trap monitoring

system at

the normal

load

level

or normal operating

level

for the unit

(or

combined

units, if common

stack),

defined

in Section 6.5.2.1 of this Exhibit. If two load levels

operating levels

have been designated as normal, the RATAs may be done at

either

load

level.

-(-b)

For the

initial certification of a gas or mercury monitoring

system and

for recertifications

in which, in addition to

RATA, one or more other tests

are required

(i.e.,

a linearity test, cycle time test, or 7-day

calibration

error

test),

the

Agency recommends that the RATA not be commenced

until the

other required

tests of the CEMS have been passed.

6.5.2 Flow

Monitor RATAs (Special

Considerations)

-a)

Except as

otherwise provided in

paagaphi.ihaestiQn

(b)

(e)

of this

Section,

perform relative accuracy test audits for the

initial certification of

each

flow

monitor at three different exhaust gas

velocities

(low,

mid, and

high),

corresponding to three different load

levels or operating levels within

the range of

operation, as defined in Section

6.5.2.1 of this Exhibit. For

common stack/duct,

the three different exhaust gas

velocities may be obtained

from frequently

used unit/load or operating level

combinations for the units

exhausting to

the

common stack. Select the three exhaust gas

velocities such

that the audit

points at adjacent load or operating levels

(i.e.,

low and mid or

mid and high),

megawatts

(or

in thousands of lb/hr

of steam production or in

ft/sec, as

applicable), are separated by no less than

25.0 percent of the range

of operation, as

defined in Section 6.5.2.1 of this Exhibit.

-(-b)

For

flow monitors on bypass stacks/ducts and

peaking units, the flow

monitor

relative accuracy test audits for initial

certification and

recertification

must be single-load tests,

performed

the normal load, as

defined in

Section

6.5.2.1(d)

of this Exhibit.

-(-c)

Flow

monitor recertification RATAs must be

done

three load

lcvcl(c)levels

(or

three operating

levels),

unless otherwise specified in

p&a-r-ap1ahetiQn

(b)

(e)

of this

Section or unless otherwise specified or

approved by

the Agency.

-(-d)

The semiannual and annual

quality assurance flow monitor RATAs required

under Exhibit B to this

Appendix must

done at the load

lcvcl(c)levels

(or

operating

levels)

specified in Section 2.3.1.3 of Exhibit B to this

Appendix.

-fe)

For flow

monitors installed on units that do not produce

electrical

thermal output,

the

flow RATA5 for initial certification or

recertification

may

done at

fewer than three operating levels, if:

-(-1)

The

owner or operator provides a technical

justification in the hardcopy

portion of

the monitoring plan for the unit required

under 40 CFR

75.53(e) (2),

incorporated

by reference in Section 225.140,

demonstrating that the unit

operates at

only one level or two levels

during normal operation (excluding unit

startup

and

shutdown)

. Appropriate

documentation and

data

must be provided to

support

the claim of single-level or

two-level operation; and

-(-2)

The justification

provided

paragraphsubsection

(e) (1)

of this Section

deemed to be acceptable by the

permitting authority.

6.5.2.1

Range of Operation and Normal Load

(or Operating)

Lcvcl(z)Levels

-(-a)

The owner or

operator must determine the upper and lower boundaries of the

TTrange

operation”

follows for each unit

(or

combination of units, for

common stack

configurations)

-(-1)

For affected

units that produce electrical output

(in

megawatts) or

thermal

output

(in

klblh/hr

of steam production or mmBtu/hr), the lower boundary

the range of operation of a unit must be the minimum safe, stable loads for

any

the

units discharging through the stack. Alternatively, for a group of

frequently—

operated units that serve

common stack, the sum of the minimum

safe, stable loads

for the individual units may

be used as

the lower boundary of

the range of

operation. The upper boundary of the range of operation of a unit

must be the maximum sustainable

load. The “maximum sustainable load” is the

higher of either:

the nameplate or rated capacity of the unit, less any physical

or regulatory

limitations or other deratings; or the highest sustainable load,

based on at least

four quarters of representative historical operating data. For

common stacks, the

maximum sustainable load is the sum of all of the maximum

sustainable loads

of the individual units discharging through the stack, unless

this load is

unattainable in practice, in which

case

use the highest sustainable

combined load

for the units that discharge through the stack. Based on at least

four quarters

of representative historical operating data. The load values for

the

unit(c)units

must

expressed either in units of megawatts of thousands of

lb/hr of steam

load or mmBtu/hr of thermal output; or

-(-2)

For

affected units that do not produce electrical or thermal output, the

lower

boundary of

the range of operation must

the minimum expected flue gas

velocity

(in

ft/sec)

during normal, stable operation of the unit. The upper

boundary of

the

range of operation must

the maximum potential flue gas

velocity

(in

ft/sec) as

defined in Section 2.1.2.1 of this Exhibit. The minimum

expected and

maximum potential velocities may

derived from the results of

reference

method testing or

using Equation A-3a or A-3b

(as

applicable) in

Section

2.1.2.1 of this Exhibit. If Equation A-3a or A-3b is used to determine

the minimum

expected velocity, replace the word “maximum” with the word

“minimum”

in the definitions of “MPV,” “Hf,”

“T%O2d”

and

,-“%H20”.

and replace

the word

“minimum” with the word “maximum” in the definition of “CO2d--”

Alternatively, 0.0 ft/sec may be used as the lower boundary of the range of

operation.

-(-b)

The operating levels for

relative accuracy

test

audits will, except for

peaking units, be defined as

follows: the “low” operating level will

the

first 30.0 percent of the range of

operation; the “mid” operating level will

the middle portion

30.0 percent, but

-t=

60.0

percent) of the range of

operation; and the “high” operating

level will

the

upper

end

60.0

percent)

the range of operation. For

example, if

the upper

and lower boundaries of the

range of operation are 100 and 1100

megawatts, respectively, then the low, mid,

and

high operating levels would be 100 to 400

megawatts,

400 to 700

megawatts,

and

700 to 1100 megawatts,

respectively.

-(-c)

Units that do not produce

electrical

thermal

output

are exempted from

the

requirements

this

paragraph,subsection

(c)

. The owner or operator must

identify, for

each

affected unit

or common stack, the “normal” load level or

levels

(low,

mid

or high),

based

on the operating history of the

unit(c)units.

identify the normal load

lcvcl(c)levels,

the owner or operator must, at a

minimum, determine the relative number of operating hours at each of the three

load

levels, low, mid and high over the past four representative

operating

quarters. The

owner

or operator must

determine,

the

nearest 0.1 percent, the

percentage

of the time that each load level

(low,

mid, high) has been used

during

that time period. A summary of the

data used

for this determination and

the

calculated

results

must

kept on-site

format

suitable for inspection.

For

new units or

newly—

affected units,

the data analysis

in this

pa-r-ag--aphsj.ection

may be

based on

fewer than four

quarters of data

fewer

than four representative

quarters

of historical

load

data

are available.

Or,

historical

load data are

available, the

owner or operator

may designate the

normal

load based on

the expected or projected

manner of

operating the

unit.

However, in either

case, once four

quarters of representative

data become

available, the

historical load analysis

must be repeated.

-(-d)

Determination

normal

load

(or operating

level)

-(-1)

Based on the

analysis

the

historical load

data

described in

paragraphsubsection

(C)

of this

Section, the owner

or operator must,

for

units

that produce

electrical

or thermal

output,

designate

the most frequently

used

load

level

as the

normal

load level for the

unit

(or

combination

of units,

for

common

stacks)

. The owner

or operator may

also designate

the second most

frequently used load

level

an additional

normal load

level for

the

unit or

stack. If the

manner of

operation

of the unit changes

significantly,

such

that

the designated

normal

load(s)

loads or the two

most frequently used

load levels

change,

the owner

operator

must repeat

the historical load

analysis and must

redesignate

the

normal

load(s)

loads and

the two most frequently

used load

levels,

appropriate. A

minimum of

two representative

quarters

historical

load data are

required to

document

that a change

in the

manner

of unit

operation

has occurred.

Update

the

electronic

monitoring

plan

whenever

the normal

load

lcvcl(s)levels

and

the two

most frequently—

used load levels

are

redesignated.

-(-2)

For units

that

not

produce

electrical or thermal

output,

the

normal

operating

lcvcl(s)

levels

must

determined using

sound

engineering

judgment,

based on

knowledge of

the unit

and operating experience

with the industrial

process.

-(-e)

The

owner

or operator

must report

the upper

and lower boundaries

of the

range of

operation for each

unit

(or

combination

of units,

for common

stacks),

in units of

megawatts

or thousands

of lb/hr or

mmBtu/hr of

steam

production or

ft/sec

(as

applicable),

the electronic

monitoring

plan required under

Section

1.10

of this

Appendix.

6.5.2.2

Multi-Load

(or

Multi-Level)

Flow

RATA

Results

For each

multi-load

(or

multi-level)

flow

RATA, calculate

the flow monitor

relative

accuracy

at each operating

level.

If a

flow

monitor relative

accuracy

test

failed

or aborted due

to a

problem

with

the monitor on

any level

of a 2-

level

(or

3-level)

relative

accuracy

test

audit, the RATA must

repeated

that

load

(or

operating)

level. However,

the entire 2-level

(or 3-level)

relative

accuracy

test audit

does

not

have to be repeated

unless

the flow

monitor

polynomial

coefficients

K-factor(s)factors

are changed,

which

case

level

RATA is

required

(or,

2-level RATA,

for units demonstrated

operate

only two

levels,

under Section

6.5.2(e)

of this

Exhibit).

.5 .3

Calculations

Using

the data from the

relative

accuracy test

audits, calculate

relative

accuracy

and bias

accordance with

the procedures and

equations specified

Section

7 of this

Exhibit.

6.5.4

Reference

Method Measurement

Location

Select a

location for

reference

method measurements that is

(1)

accessible;

(2)

in the same

proximity

the monitor or monitoring system location; and

(3)

meets

the requirements of

Performance Specification

in appendix B of 40

CFR

60,

incorporated by

reference in Section 225.140, for C02 or 02 monitors, or

Method 1

(or 1A)

in appendix A of 40 CFR

60,

incorporated by reference in

Section 225.140,

for volumetric flow, except

otherwise indicated in this

Section or

approved

the Agency.

6.5.5

Reference

Method Traverse Point Selection

Select

traverse

points that ensure acquisition of representative samples of

pollutant and

diluent concentrations, moisture content, temperature, and flue

gas

flow

rate over

the flue cross Section. To achieve this, the

reference method

traverse points must

meet

the requirements of Section 8.1.3 of

Performance

Specification 2

(“PS No.

2”)

in appendix B

40 CFR 60, incorporated by

reference in

Section 225.140

(for

moisture monitoring system

RATA5),

Performance

Specification 3 in

appendix B

40 CFR

60,

incorporated by reference

Section

225.140

(for

02 and

C02 monitor

RATA5),

Method 1

(or 1A) (for

volumetric

flow

rate monitor

RATA5),

Method 3

(for

molecular weight), and

Method 4

(for

moisture

determination)

in appendix A to 40 CFR 60, incorporated by

reference in Section

225.140. The

following alternative reference method traverse

point locations

are

permitted for

moisture and gas monitor RATA5:

-(-a)

For

moisture determinations where the moisture data

are

used

only

determine

stack

gas

molecular weight, a single reference

method point, located

least 1.0 meter

from the stack wall, may be used. For moisture

monitoring

system RATAs and

for

gas

monitor RATA5 in which moisture data

are

used to

correct pollutant

or diluent concentrations from a dry basis to a

wet basis

(or

vice-versa),

single-point moisture sampling may only be used if

the 12-point

stratification test

described in Section 6.5.5.1 of this Exhibit is

performed

prior

the RATA

for

least one pollutant or diluent gas, and if

the

test is

passed

according

the

acceptance

criteria in Section

6.5.5.3(b)

this

Exhibit.

-(-b)

For gas

monitoring system RATAs, the owner or

operator may

use

any of

the

following

options:

-(-1)

At any

location (including locations

where stratification is expected),

use a

minimum of six traverse points along a

diameter, in the direction of any

expected

stratification. The points must be

located in accordance with Method 1

appendix A to 40 CFR 60, incorporated by

reference in Section 225.140.

-(-2)

locations where Section 8.1.3 of

PS No. 2 allows the use of a short

reference method measurement line

(with

three points located at 0.4, 1.2, and

2.0 meters

from the stack

wall),

the

owner or operator may use an alternative 3-

point

measurement line, locating the

three points at 4.4, 14.6, and 29.6 percent

of the way

across the stack, in

accordance with Method 1 in appendix A to 40 CFR

60,

incorporated by reference in

Section 225.140.

-(-3)

locations where

stratification

likely

occur (e.g., following a

wet

scrubber or when dissimilar gas

streams are

combined)

, the short measurement

line

from Section 8.1.3 of

No.

(or

the

alternative line described in

paragraphsubsection

(b) (2)

of this Section) may be used in lieu of the

prescribed

“long” measurement line in Section 8.1.3 of PS No. 2,

provided that

the

12-point

stratification

test

described in Section 6.5.5.1 of this

Exhibit

performed

and passed one time at the location

(according

the acceptance

criteria

of Section

6.5.5.3(a)

of this

Exhibit)

and provided that either the 12-

point stratification test

or the alternative (abbreviated) stratification

test

Section 6.5.5.2 of this

Exhibit is

performed

and

passed prior to

each

subsequent RATA at the

location (according

to the acceptance

criteria

Section

6.5.5.3(a)

of this

Exhibit).

-(-4)

A single

reference

method measurement point, located no less than 1.0

meter from the

stack wall and situated along

one

of the measurement lines used

for the stratification test,

may

be used at any

sampling location if the 12-

point stratification test

described

in Section

6.5.5.1 of this Exhibit is

performed and passed

prior

each RATA

at the

location (according

the

acceptance criteria of

Section

6.5.5.3(b)

of this

Exhibit).

-(-c)

For mercury monitoring systems, use the same basic

approach for traverse

point

selection that is used

for

the other gas

monitoring system RATA5, except

that

the stratification test

provisions

in Sections 8.1.3

through 8.1.3.5 of

Method 30A must apply, rather than the provisions of

Sections 6.5.5.1 through

6.5.5.3

of this Exhibit.

6.5.5.1 Stratification Test

-(-a)

With the

unit(z)units

operating under

steady-state

conditions at the

normal load level

(or

normal operating

level),

defined in Section 6.5.2.1 of

this Exhibit, use a

traversing

gas

sampling probe

measure diluent

(C02

02)

concentrations

at a

minimum of twclvc

(12-)-

points, located according to Method 1

in appendix A to

40 CFR

60,

incorporated

reference in Section 225.140.

-(-b)

Use Method

3A in appendix A

40 CFR

60,

incorporated by reference in

Section 225.140, to

make the measurements. Data from the reference method

analyzers must be

quality assured

performing analyzer calibration

error

and

system bias

checks before the series of measurements and by conducting system

bias and

calibration drift checks after the measurements, in accordance

with

the

procedures of

Method 3A.

-(-c)

Measure for a

minimum

minutes

each traverse point. To the extent

practicable,

complete the traverse within

2-hour period.

-(-d)

the load has remained constant

(-—3.0

percent) during

the traverse

and

if the reference method analyzers have passed all of the

required quality

assurance checks, proceed with the data analysis.

-(-e)

Calculate the average C02

(or 02)

concentrations

each of the individual

traverse points. Then, calculate the arithmetic

average C02 (or

02)

concentrations for all traverse points.

6.5.5.2 Alternative

(Abbreviated)

Stratification

Test

-(-a)

With the

unit()units

operating under steady-state

conditions

the

normal load level

(or

normal operating

level),

defined in Section 6.5.2.1 of

this

Exhibit, use a traversing gas sampling probe to measure the

diluent

(C02

02)

concentrations at three points. The points must be

located according to the

specifications

for

the

long

measurement

line in Section 8.1.3 of PS No. 2

(i.e.,

locate the

points 16.7 percent,

50.0

percent, and

83.3

percent of the way across

the

stack)

. Alternatively, the concentration measurements may be made at six

traverse

points along

diameter. The six points must be located in

accordance

with Method 1 in appendix A to 40 CFR 60, incorporated by reference

in Section

225.140.

-(-b)

Use

Method 3A

appendix

A to

40 CFR

60, incorporated

by reference

Section

225.140, to make

the

measurements.

Data from

the

reference

method

analyzers

must

quality assured by

performing

analyzer

calibration

error and

system bias checks

before the series

of measurements

and

conducting

system

bias and calibration

drift checks

after

the

measurements,

in accordance

with

the

procedures

Method 3A.

-(-c)

Measure for

a minimum of 2 minutes

at each traverse

point. To the

extent

practicable, complete

the traverse

within

1-hour

period.

-(-d)

the load has remained

constant

(±—j3.O

percent) during

the

traverse

and

the

reference

method analyzers

have passed

all

the required

quality

assurance

checks,

proceed with the

data

analysis.

-(-e)

Calculate

the

average

C02

(or

02)

concentrations

at each

the individual

traverse

points. Then, calculate

the

arithmetic

average C02

(or 02)

concentrations

for all

traverse points.

6.5.5.3 Stratification

Test

Results and Acceptance

Criteria

-(-a)

For

each

diluent

gas,

the short

reference method

measurement line

described

Section 8.1.3

of PS

No. 2 may

used

lieu

the long

measurement

line prescribed

Section 8.1.3 of

PS No.

2 if the

results of

stratification

test,

conducted in

accordance

with

Section 6.5.5.1

or 6.5.5.2

this Exhibit

(as

appropriate;

see

Section

6.5.5(b) (3)

of this

Exhibit),

show

that the

concentration at

each individual

traverse point

differs

more than

-—-io.0

percent

from the arithmetic

average concentration

for

all

traverse

points.

The

results

are also

acceptable if the

concentration

each individual

traverse

point

differs

no more than -f----j5ppm

-+----,0.5

percent

C02

(or

02)

from

the arithmetic average

concentration

for

all traverse

points.

-(-b)

For

each

diluent

gas, a

single

reference method

measurement point,

located

least

1.0

meter

from the

stack wall and situated

along one of

the measurement

lines used for

the

stratification

test, may

be used for that

diluent gas if the

results

stratification

test,

conducted

in accordance

with Section 6.5.5.1

this Exhibit, show

that the concentration

at each

individual traverse

point

differs

by no

than -f-—5.0

percent from the

arithmetic average

concentration

for

all traverse

points. The results

are also acceptable

if the

concentration

each individual

traverse

point differs

more than

-i----3

ppm

÷-0.3

percent

C02

(or 02)

from

the arithmetic average

concentration

for

all

traverse points.

-(-c)

The owner

or operator must

keep the results

all stratification

tests

on-site,

format suitable

for inspection,

part

of the

supplementary

RATA

records

required under

Section

1.13(a)

(7)

of this

Appendix.

6.5.6 Sampling

Strategy

-(-a)

Conduct

the

reference method

tests so

they will

yield

results

representative

the pollutant

concentration, emission

rate,

moisture,

temperature,

and

flue

gas

flow

rate from the unit

and

can be

correlated

with the

pollutant

concentration monitor,

C02 or 02

monitor, flow monitor,

and mercury

CEMS

measurements. The

minimum acceptable

time for a

gas

monitoring system

RATA

run

for

moisture

monitoring

system

RATA run is

minutes. For each

run of

gas monitoring

system RATA, all

necessary

pollutant

concentration

measurements,

diluent concentration

measurements,

and

moisture

measurements

(if

applicable) must,

the

extent practicable,

be made within

60-minute period.

For flow

monitor RATAs, the

minimum time per run must

5 minutes. Flow rate

reference method measurements

may be made either sequentially from port to

port

simultaneously at two or

more sample ports.

The

velocity measurement probe

may be

moved from

traverse point to traverse point either manually or

automatically. If,

during

flow RATA, significant pulsations in the

reference

method readings are

observed, be sure to allow enough measurement time at each

traverse point

obtain

an accurate average reading when a manual readout

method is

used (e.g.,

“sight-weighted” average from

manometer)

. Also, allow

sufficient measurement

time

ensure that stable temperature

readings are

obtained

each

traverse point, particularly

the first

measurement point

each

sample port,

when

probe is moved sequentially from

port-to-port. A

minimum of one set of

auxiliary measurements for stack gas

molecular weight

determination

(i.e.,

diluent gas

data and moisture

data)

is required

for

every

clock

hour of

flow RATA or

for every three

test

runs

(whichever

is less

restrictive) . Alternatively,

moisture measurements for molecular weight

determination may be performed

before

and after a

series of flow RATA runs at a

particular load level

(low,

mid, or high), provided that the time

interval

between the two

moisture measurements

does

not exceed three hours. If

this

option is selected,

the results of the two moisture

determinations must

averaged arithmetically

and applied to all RATA runs in the

series. Successive

flow RATA runs may be

performed without waiting in-between runs.

If an 02-

diluent monitor is used as a

C02 continuous emission monitoring

system, perform

C02 system RATA

(i.e., measure C02, rather than 02, with

the reference

method)

. For

moisture monitoring systems, an appropriate

coefficient, “K” factor

or other suitable

mathematical algorithm may be developed

prior

the

RATA,

adjust

the monitoring

system readings with respect to the

reference method.

such

coefficient,

K-factor or algorithm is developed, it must be

applied

the

CEMS readings during

the RATA and

(if

the RATA is passed), to

the

subsequent

CEMS

data,

by means of

the automated

data

acquisition and

handling system.

The

owner or operator must

keep records of the current coefficient,

K factor

algorithm, as specified

in Section

1.13(a) (5) (F)

of this

Appendix. Whenever

the

coefficient, K

factor or algorithm is changed, a RATA of

the moisture monitoring

system is required.

For the RATA of a mercury CEMS

using the Ontario Hydro

Method, or for

the RATA of a sorbent trap system

(irrespective of the reference

method

used),

the time per run must be long

enough

collect a sufficient mass

of mercury to

analyze. For the RATA of a

sorbent trap monitoring system, the

type of

sorbent material used by the

traps must

the same as for daily

operation of the monitoring system;

however, the size of the traps used

for

the

RATA

may

smaller than the traps used

for daily operation of the

system.

Spike

the

third section of each

sorbent trap with elemental mercury, as

described

Section

7.1.2 of Exhibit

this Appendix. Install a new pair of

sorbent

traps

prior

each test run. For

each run, the sorbent trap data must be

validated

according to the quality

assurance criteria in Section 8 of Exhibit

this

Appendix.

-(-b)

To properly

correlate individual mercury CEMS data

(in

lb/MMEtummBtu) and

volumetric flow rate data

with

the

reference method data, annotate

the

beginning

and

end of each reference method test

run (including the exact time of day) on

the

individual chart

rccordcr(o)recorders or other permanent recording

dcvicc

(z)

devices.

6.5.7 Correlation

of Reference

Method

and Continuous Emission

Monitoring System

Confirm that the

monitor or monitoring system and

reference method

test

results

are on

consistent moisture, pressure, temperature, and

diluent concentration

basis (e.g.,

since the flow monitor measures

flow rate on

wet basis, Method 2

test

results must also be

a wet

basis)

. Compare flow-monitor and reference

method results

on a

scfh

basis. Also, consider

the response

times of the

pollutant concentration

monitor, the continuous

emission

monitoring system,

and

the flow

monitoring

system

ensure

comparison of simultaneous

measurements.

For each relative

accuracy

test audit

run,

compare

the measurements

obtained

from the monitor

continuous

emission

monitoring

system

(in

ppm, percent C02,

lb/mmBtu, or

other

units)

against

the

corresponding

reference

method values.

Tabulate

the paired

data in

a table such as

the one shown

in Figure 2.

6.5.8

Number of

Reference Method

Tests

Perform a minimum

nine sets

of paired

monitor

(or

monitoring

system) and

reference

method test

data

for every required

(i.e.,

certification,

recertification,

diagnostic,

semiannual,

annual)

relative accuracy

test

audit.

For 2-level

and 3-level

relative

accuracy test

audits of

flow monitors,

perform

minimum

nine

sets at

each of the

operating levels.

6.5.9

Reference

Methods

The

following methods

are from

appendix

A to

CFR

60,

incorporated

reference in

Section

225.140, or

have been

published

ASTM,

and

are

the

reference methods

for

performing

relative

accuracy

test

audits under this

part:

Method

1 or 1A in

appendix

A-l

40 CFR 60

for

siting;

Method 2 in appendices

A-i and

A-2 to 40

CFR

its allowable

alternatives

in appendix

40 CFR

60 (except

for Methods

and 2E in

appendix

A-l

40 CFR

60)

for stack

gas

velocity and

volumetric flow

rate;

Methods 3,

3A or 3B in appendix

A-2

CFR

for 02 and

C02; Method

in appendix A-3 to

40 CFR 60

for

moisture;

and

for

mercury,

either

ASTM

06784-02

(the

Ontario Hydro

Method)

(incorporated

reference

under

Section 225.140),

Method

29 in appendix

A-8 to 40

CFR

60,

Method

30A,

or Method

30B.

Calculations

7.1

Linearity

Check

Analyze the

linearity data

for pollutant concentration

monitors as follows.

Calculate

the percentage

error in linearity

based

upon the reference

value

the

low-level, mid-level,

and high-level

concentrations

specified

Section

6.2

this

Exhibit.

Perform this calculation

once during

the certification

test.

Use

the

following

equation

calculate the error

linearity

for each

reference

value.

(Equation

A-4)

whcrc,

Where:

LE=Percentage

Lincaritylinearitv

error,

based

upon the reference

value.R=Reference

value of

i,ewj-,

mid-, or

high-level calibration

gas

introduced

into

the monitoring

system.A=Average

of the monitoring

system

responses.

7.2

Calibration

Error

7.2.1

Pollutant

Concentration

and

Diluent

Monitors

For

each reference

value,

calculate

the percentage

calibration

error

based

upon

instrument

span

for

daily calibration

error tests

using the

following

equation:

(Equation

A-5)

whcrc,

Where:

= Calibration error

as a percentage

of the span of

the instrument.R

Reference value

zero or

upscale

(high-level or

mid-level,

applicable)

calibration gas

introduced into

the monitoring

system.A

= Actual monitoring

system

response to the calibration

gas.S

Span of the

instrument,

as specified

in Section

of this

Exhibit.

7.2.2 Flow

Monitor

Calibration Error

For each

reference

value, calculate

the percentage

calibration

error

based upon

span using the

following

equation:

(Equation

A-6)

whcrc,

Where:

= Calibration

error

percentage

span.R = Low or high

level

reference

value

specified

Section

2.2.2.1

of this

Exhibit.A = Actual

flow monitor

response to

the

reference

value.S = Flow monitor

calibration

span value

determined

under

Section 2.1.2.2

of this

Exhibit.

7.3

Relative Accuracy

for

02 Monitors,

Mercury

Monitoring Systems,

and Flow

Monitors

Analyze

the

relative

accuracy

test audit data

from the

reference method

tests

for C02

or 02

monitors

used only for heat

input

rate

determination,

mercury

monitoring

systems

used to determine

mercury mass

emissions under

Sections 1.14

through

1.18 of

Appendix

and

flow monitors using

the following

procedures.

Summarize

the

results on a

data

sheet. An example

shown

in Figure 2.

Calculate

the mean of the

monitor or monitoring

system

measurement values.

Calculate

the mean of

the

reference method

values.

Using data from

the

automated

data

acquisition and

handling

system,

calculate

the arithmetic

differences

between the

reference method

and

monitor measurement

data sets.

Then

calculate

the

arithmetic

mean of

the

difference,

the standard deviation,

the

confidence

coefficient,

and the

monitor

monitoring

system relative

accuracy

using

the

following

procedures

and equations.

7.3.1

Arithmetic

Mean

Calculate

the arithmetic

mean of the

differences, d,

data

set as follows.

(Equation

A-7)

whcrc,

Where:

= Number

of data points.di

= The difference

between a

reference method

value

and

the

corresponding

continuous

emission

monitoring

system value

(RMi-

CEMi)

given

point in

time

7.3.2

Standard

Deviation

Calculate

the standard

deviation,

Sd,

data set as follows:

-IC

-I

)

-I

-IC

Lxi

)

.I.

•1-

U)H

SiC)flII

<0CD

OOCD

tj)L1U)

iIi

CtF--ct

MiCt

CDCf

WH-H-

H-

3’(1I

Orf

H-0Cl-

PJCDH-W

(DCD

U)0Mi

Lxi

O[-t,CD

I-ti

‘-CDU)CDrf

H-

U’

H-RH

U)C)(DCDO

CDH

Cr0

H-

It-Q

(DH-fl

HiU)CDCD

CfH-

F-till)

D’

JMLx

H-H-bLx

CDk<

C)OCD

H-LxCfO

H-

[IOCD

LxSCD

0LxF-

CfOCDrf

flop)

CDCDrf

H-

LxH-

Cfrf

irf

0Lx[1

I-I-D

[ICDCD

CUD)

H-

I-ti

‘1

CflCfP)

jl-(D

H-fl

LC(DF-

0CC)

l-tiCD

(fl(D3

F-

‘-<fl

HDJ

UICD(D

H-CO

LxLx<

(DOs

(DH-

CDCD

$lrtcf

OCD

H-MU)

UJCDO

LxH-Cf

l-ctQ

C!)LU)

(D0

CII

UICU)

OU)

çt

Cf<H

H-(J)Cf

IIDJCD

Oct

HI))

LxCDQ

F-tj.

U)$p)

WCD

(Oct

CDU)Il

—I--

)

•

P)D),-

U)(O

•

LxCD

Cn0CD

HCcf

(C)

F-CfP)

CtU)

Lx0F-tt

ctCD(j)

OtYI1

0t3

IC)Lxb

p)c1-

JrtH-

HCD

IC)

—IrtU)

CD(n

iU’U)

OOH

•dHi

M,3

C)CD

CtH-

WLxO

I-tii

CDIC)Mi

H-

rfrt

H-F

IC)

‘-I

3-’

-I

—-I

F’

F-’

0’,

3-’

-J

3-’

‘3

Lii

I.)

3’

-‘

-iUii

-‘

WLflC)ll

-H

-Li

wrtZ

1U—I

3-,

C)LxCDE

-‘

ci-

SiI

I..

Lx’COCD

M,O0F

ci-

H-H-F-(

-‘

Lx0

CDctCDfrt,

Lxi

‘—3

flH-’dC)

Ui—

CDLxOU)

3U)

Lxcf

HCD

flctC)Ui

CDCD

H-

OH-H

a’

Mi(DIC)0

Cii

H-

H-H-fli

‘

C)•

Qct

—)

ctCD

H-

LxID

DII

Ci-’

H-C)

-‘‘U)’

ci-

LxH

—ii

Si’

—

I-ti

Oil

‘CD’

F-’.

-‘I

3)’

CDCD

Si’I

Di’

Si’

(OH

(JIM,

0’

H-Mi

3)1

OCD

Di’

,j,

0Crn)

-‘I

H-

LxCD

‘3’

F—’

H-

Sill

Cfb

OCD

Di’

—

F-Cf

LxCD

-‘,

IC)CD

Di’

J1’

If)

Si’’

‘<U)

Cl)

Sill

CfF-(

CDCD

SI-ti

,i’

DII

<F-I

Dii

U)CD

Si’I

HLx

—I’l

CDCD

Si’’

3)’

—S

H’’

ci-

Lii’’

Si’’

)

Lx)

F-h

Lx1<

H-H

(F)

Exhibit.

For

multiple-load flow RATAs, perform

bias test

at each load

level

designated

normal under Section 6.5.2.1

this Exhibit.

7.4.1 Arithmetic Mean

Calculate the arithmetic mean of the difference,

d”,

of the

data set

using

Equation A-7 of this Exhibit. To calculate bias for

flow monitor,

‘d

T’

is, for

each

paired data

point, the difference between the flow rate values (in

scfh)

obtained from the reference method and the monitor. To calculate

bias

for

mercury monitoring system when using the Ontario Hydro Method or Method

29 in

appendix

A-8 to

40 CFR 60, incorporated

reference in Section 225.140,

“d” is,

for each data

point, the difference between

the

average mercury concentration

value

(in

ig/m3)

from the paired Ontario

Hydro or

Method 29 in

appendix A-S to

40 CFR 60 sampling

trains and the concentration

measured by the monitoring

system. For sorbent

trap monitoring

systems, use the

average mercury

concentration

measured

the paired traps

in the calculation of

ITdTT.

7.4.2 Standard

Deviation

Calculate the standard

deviation,

Sd, of the data set using Equation A-8.

7.4.3

Confidence Coefficient

Calculate the confidence coefficient,

cc,

of the

data set

using Equation A-9.

7.4.4 Bias Test

If,

for the relative accuracy test audit data

set

being tested, the mean

difference, d, is less than or equal to the absolute value of the confidence

coefficient, , the monitor or monitoring system has passed the bias test. If the

mean difference, d, is greater than the absolute value of the confidence

coefficient, , the monitor or monitoring system has failed to meet the bias

test

requirement.

7.5

Reference Flow-to-Load Ratio or Gross Heat Rate

-(-a)

Except

provided in Section 7.6 of this Exhibit, the owner or operator

must

determine Rref, the reference value of the ratio of flow rate to unit load,

each time that a passing flow RATA is performed at a load level designated

normal in Section 6.5.2.1 of this Exhibit. The owner or operator must report

the

current

value of Rref in the electronic quarterly report required under 40 CFR

75.64, incorporated by reference in Section 225.140, and must also report the

completion date of the associated RATA. If two load levels have been designated

normal under Section 6.5.2.1 of this Exhibit, the owner or operator must

determine

separate Rref

value for each of the normal load levels. The

reference

flow-to-load

ratio must be

calculated

follows:

(Equation

A-13)

whcrc,

Where:

Rref=

Reference value of the flow-to-load ratio, from the most recent normal

load

flow RATA, scfh/megawatts, scfh/l000 lb/hr of steam, or scfh/ (mmBtu/hr of

steam output)

. Oref=

Average stack gas volumetric flow rate measured by the

reference method during the normal-load RATA, scth.

Lavc=

Average unit load

during

the

normal-load

flow RATA, megawatts,

1000 lb/hr

of steam,

or mmBtu/hr

thermal

output.

-(-b)

In Equation

A-13, for a

common stack, determine

Lavp by summing,

for each

RATA run, the

operating loads

of all units

discharging

through the

common stack,

and then taking

the arithmetic

average

the summed

loads. For

a unit

that

discharges

its

emissions

through multiple

stacks,

either determine

single

value

for the

unit or a separate

value of

Oref

for each

stack.

In the

former

case, calculate

Oref by summing,

for

each

RATA

run, the

volumetric flow

rates

through

the

individual stacks

and then taking

the arithmetic

average of

the

summed

RATA

run flow rates.

In the latter

case, calculate the

value of

Oref

for

each

stack

by taking

the arithmetic average,

for

all

RATA

runs, of the flow

rates

through

the stack.

For

unit with

a multiple stack

discharge

configuration

consisting

of a main

stack and a bypass

stack

(e.g.,

a unit

with a

wet 502 scrubber),

determine Oref

separately

for

each stack

the

time of the

normal load

flow

RATA. Round

off the value

of Rref

to two decimal

places.

-(-c)

In addition

determining

Rref

or as

alternative

determine

Rref,

reference value

of the gross

heat

rate

(GHR)

may be

determined.

In order

use this option,

quality assured

diluent gas

(C02

02)

must be

available for

each hour of

the most recent

normal-load

flow RATA. The

reference

value of

the

GHR must

determined as

follows:

(Equation

A-13a)

whcrc,

Where:

(GHR)ref=

Reference

value of the gross

heat

rate at the

time of the most

recent

normal-load

flow RATA,

Btu/kwh,

Btu/lb steam load,

or Btu heat input/mmBtu

steam

output.

(Heatlnout)avg=

Average

hourly heat input

during

the normal-load

flow

RATA,

determined using

the applicable equation

Exhibit

to this

Appendix,

mmBtu/hr.

For multiple

stack configurations,

if the reference

GHR value

determined

separately

for each stack,

use the

hourly

heat input

measured

at each

stack. If the reference

GHR is determined

the unit

level,

sum

the hourly

heat

inputs measured

at the individual

stacks.

Lavo=

Average

unit load

during the

normal-load

flow RATA, megawatts,

1000

lb/hr of steam,

mmBtu/hr thermal

output.

-(-d)

In the

calculation

(Heatlnput)avg, use

Oref, the average

volumetric

flow

rate

measured

the

reference method

during the RATA,

and use the

average

diluent

gas

concentration

measured during

the flow

RATA

(i.e.,

the

arithmetic

average

the diluent gas

concentrations

for

all clock

hours in which

a RATA

run

was performed)

7.6

Flow-to-Load

Test

Exemptions

-(-a)

For complex

stack

configurations

(e.g., when the

effluent from a

unit

divided

and

discharges

through multiple

stacks

such

manner that

the flow

rate

in the

individual

stacks

cannot

be correlated

with unit

load),

the owner or

operator

may

petition

the

USEPA under 40 CFR

75.66, incorporated

by reference

Section

225.140,

for an

exemption from

the requirements

of Section 7.7 to

Appendix

to 40 CFR Part

and

Section

2.2.5 of Exhibit

Appendix

B. The

petition

must include

sufficient

information and

data

demonstrate

that a

flow-to-load

or gross

heat

rate

evaluation is

infeasible for the

complex

stack

configuration.

-(-b)

Units

that do

not produce

electrical

output

(in

megawatts) or

thermal

output

(in

of steam per

hour)

are

exempted

from

the

flow-to-load

ratio

test

requirements

of Section

7.5 of this

Exhibit and Section

2.2.5

Exhibit

Appendix B.

aurpo

7’.nncndix

Figure 1.—

Linearity

Error

Peter-m4naH4onDieterrninatinn

Day

Datc

and

Rcfcrcnce

Monitor

Diffcrcncc

Pcrccnt

DavDate

and

timeReference

valueMonitor

valueDifferencePercent

timc

valuc

reference

value

Low-level:

Mid-level:

High-level:

Figure

2.—

Relative

Accuracy Determination

(Pollutant

Concentration Monitors)

S02 (ppm

[FNc])

C02

(Pollutant)

(ppm

[FNcJ)

ULL

Run

and RM

[FNa]

[Rib]

Diff

and

[FNa]

Diff No.

L±LL.

Run

No.Date

and

timeRM

[FNa1M

IFNbTDiffDate and

timeRM

rFNaTM rnmlDiffl

ArithmcticArthmetic

Mean

Difference (Eq.

A-7)

Confidence Cocff±cicntCoeffecient

(Eq.

A-9)

Relative

Accuracy

(Eq. A-b).

[FNa]

RM means

“reference method

data-r’L..JFNb]

means “monitor

data-r”[FNc]

Make sure the RM

and M data are on a

consistent basis, either wet or dry.

Figure 3.—

Relative Accuracy Determination

(Flow

Monitors)

Flow

rate

(Low)

Flow rate

(Normal)

Flow

rate

(High)

(scf/hr)

[FNa]

(scf/hr)

[FNa]

(scf/hr)

[FNa]

DatcRun and

and

No.

timc

Diff timc

RTi

Diff

timc

Diff

Run

timeDate and

timeRMMDiffflate and

timeRMlvlDiffflate

and timeRMMDiff

Mean

Difference (Eq.

A-7)

Confidence

Cocfficicnt Coeffecient

(Eq.

A-9)

Relative

Accuracy

(Eq.

A-b).

[FNa]

Make sure the RM

and M data

are on a consistent basis,

either wet or dry.

Figure 4.—

Relative

Accuracy

Determination

(NOX/DilucntNox/Dilent Combined

System)

Reference

method

data

NOX NOx system (lb/mmBtu)

Run No.

Date and

4me—NOXtjmNQc(

)

[FNa]

02/C02%

DiffcrcnccRMMDifference

ArithmcticArthmetic

Mean

Difference (Eq.

A-7)

Componcnt.5

Cycle TimeDate

testComoonent/system

ID#:—

typc

Scrial Numbcr

HightvoeSerial

NuntherHiah

level gas concentration:

ppm/%

(circle one)

Zero level gas

concentration:

ppm/%

(circle

one)Analyzer span setting:

ppm/%

(circle

one)Upscale:Stable starting monitor value:

ppm/%

(circle

one)Stable ending monitor reading:

ppm/%

(circle

one)Elapsed time:

cccondcDownccalcSecondsDownscale : Stable starting monitor value:

ppm/%

(circle

one)Stable ending monitor valuc:

readin:ppm/%

(circle

one)Elapsed

time:

secondsComoonent cycle time =secondsSvstem cycle time

.seconds

Componcnt cycic timc

Syctcm cyclc

timc=

zccondz

A. To

determine the upscale cycle time (Figure

Ga),

measure the flue gas

emissions

until the response stabilizes. Record the stabilized value

(see

Section

6.4 of this Exhibit for the stability

criteria)

B. Inject a

high-level calibration gas into the port leading to the calibration

cell

or thimble

(Point

. Allow the analyzer to stabilize. Record the

stabilized value.

Determine the step change. The step

change is equal

the difference

between

the

final stable

calibration

gas

value (Point D) and the stabilized stack

emissions value

(Point A)

Take 95% of the step change value and add the result to the

stabilized

stack

emissions value

(Point A)

. Determine the time at which 95%-

the step

change

occurred

(Point C).

Calculate the upscale cycle time by subtracting the time at

which the

calibration gas was injected

(Point B)

from

the

time at

which

95%

of the

step

change

occurred (Point

. In this example, upscale

cycle time

= (11-5)

= 6

minutes.

determine the downscaie

cycle

time (Figure

6b)

repeat the procedures

above, except

that a zero

gas

is injected when the flue

gas

emissions have

stabilized,

and 95% of the

step

change in concentration is subtracted from the

stabilized

stack emissions value.

Compare the upscale and downscale cycle time values. The longer of

these

two

times

is the cycle time for the analyzer.

Confidence Cocffic±cntCoeffecient (Eq.

A-9)

Relative

Accuracy

(Eq.

A-ic).

[FNaI

Specify

units: ppm,

lb/dscf, mg/dscm.

Figure 5 Cyc

Datc of tcst

Exhibit

B to Appendix

B -— Quality Assurance

and Quality

Control Procedures

1. Quality

Assurance/Quality Control Program

Develop and implement a

quality assurance/quality

control (QA/QC)

program for

the continuous

emission monitoring

systems-r

and

their

components.

minimum,

include in each QA/QC

program

written

plan that describes

in detail

(or

that

refers

separate

documents containing)

complete, step-by-step

procedures and

operations for each

of the following activities.

Upon request

from regulatory

authorities, the

source must make all procedures,

maintenance

records, and

ancillary supporting

documentation from the

manufacturer (e.g.,

software

coefficients and

troubleshooting diagrams)

available for

review during an audit.

Electronic storage of the information in the QA/QC plan is

permissible,

provided

that the

information can be made available in hardcopy upon request during an

audit.

1.1 Requirements

for All Monitoring Systems

1.1.1

Preventive Maintenance

Keep a

written record of procedures needed to maintain the monitoring system in

proper

operating condition and a schedule for those procedures. This must, at a

minimum,

include procedures specified by the manufacturers of the equipment and,

if applicable, additional or alternate procedures developed for the

equipment.

1.1.2 Recordkeeping

and Reporting

Keep a written

record describing procedures that will

be used to

implement the

recordkeeping and

reporting requirements in subparts E and

of 40 CFR 75,

incorporated by reference in

Section 225.140,

and

Sections 1.10 through 1.13

Appendix B, as applicable.

1.1.3

Maintenance Records

Keep a

record of all testing, maintenance, or repair

activities performed

on any

monitoring system

component

location and format suitable for inspection.

A maintenance

log may

be used

for this purpose. The following records should

maintained: date,

time, and description of any testing, adjustment, repair,

replacement,

or preventive maintenance action performed on any monitoring system

and records

of any corrective actions associated with a monitor’s outage period.

Additionally,

any adjustment that recharacterizes

system’s ability to record

and report

emissions

data

must

recorded

(e.g.,

changing of flow monitor or

moisture

monitoring

system polynomial coefficients, K factors or mathematical

algorithms,

changing of temperature and pressure coefficients and dilution ratio

settings),

and a written explanation of the procedures used to make the

adjuctmcnt(c)adiustments

must be kept.

1.1.4

The requirements in Section 6.1.2 of Exhibit A to this

Appendix must

met

any

Air Emissions Testing Body

(AETB)

performing the

semiannual/annual RATAs

described in Section 2.3 of this Exhibit and the mercury

emission

tests

described in Sections

1.15(c)

and

1.15(d) (4)

of Appendix B.

1.2 Specific

Requirements

for Continuous

Emissions Monitoring Systems

1.2.1

Calibration Error Test and Linearity Check Procedures

Keep

a written

record

the

procedures

used for

daily

calibration

error

tests

and

linearity

checks

(e.g.,

how

gases

are

to be

injected,

adjustments

flow

rates and

pressure,

introduction

reference

values,

length

time

for

injection

of calibration

gases,

steps for

obtaining

calibration

error

or error

linearity,

determination

interferences,

and

when calibration

adjustments

should

made)

. Identify

any

calibration

error

test

and

linearity

check

procedures

specific

the

continuous

emission

monitoring

system

that

vary

from

the

procedures

Exhibit

A to this

Appendix.

1.2.2

Calibration

and

Linearity

Adjustments

Explain

how

each component

of the continuous

emission

monitoring

system

will

adjusted

to provide

correct

responses

calibration

gases,

reference

values,

and/or

indications

interference

both initially

and after

repairs

corrective

action.

Identify

equations,

conversion

factors

and other

factors

affecting

calibration

each

continuous

emission

monitoring

system.

1.2.3 Relative

Accuracy

Test

Audit

Procedures

Keep a

written

record

procedures

and

details

peculiar

to the installed

continuous

emission

monitoring

systems

that are

to be used

for relative

accuracy

test

audits,

such

sampling

and analysis

methods.

1.2.4 Parametric

Monitoring

for Units

With

Add-on

Emission

Controls

The

owner or

operator

shall keep

a written

(or

electronic)

record

including

list

of operating

parameters

for the

add-on mercury

emission

controls,

applicable,

and the

range

of each

operating

parameter

that indicates

the add-on

emission

controls

are operating

properly.

The owner

or operator

shall

keep

written

(or

electronic)

record

of the parametric

monitoring

data

during

each

mercury

missing

data

period.

1.3

Requirements

for

Sorbent

Trap

Monitoring

Systems

1.3.1

Sorbent

Trap

Identification

and

Tracking

Include

procedures

for

inscribing

otherwise

permanently

marking

a unique

identification

number

each sorbent

trap-

for

tracking

purposes.

Keep

records

of the

ID of

the monitoring

system

which

each

sorbent

trap

is used-

and

the

dates

and

hours of

each

mercury

collection

period.

1.3.2

Monitoring

System

Integrity

and

Data Quality

Explain

the

procedures

used

perform

the

leak

checks

when

sorbent

traps

are

placed

service and

removed

from

service.

Also

explain

the

other

QA procedures

used

ensure

system

integrity

and

data quality,

including,

but

not

limited

to,

gas

flow

meter

calibrations,

verification

of moisture

removal,

and

ensuring

air

tight

pump

operation.

In addition,

the QA

plan must

include

the

data

acceptance

and

quality

control

criteria

Section

of Exhibit

to this Appendix.

All

reference

meters

used

to calibrate

the

gas

flow

meters

(e.g.,

wet test

meters)

must be

periodically

recalibrated.

Annual,

or more frequent,

recalibration

recommended.

If a

NIST-traceable

calibration

device

is used

as a reference

flow

meter,

the

QA plan

must include

protocol

for

ongoing

maintenance

and periodic

recalibration

maintain

the accuracy

and

NIST-traceability

the calibrator.

1.3.3

Mercury

Analysis

Explain the chain of

custody employed in packing, transporting, and analyzing

the sorbent traps

(see

Sections 7.2.8

and

7.2.9 in Exhibit D

this Appendix.).

Keep records of all

mercury analyses.

The analyses

must

performed in

accordance with the

procedures described in Section 10 of Exhibit D to this

Appendix.

1.3.4 Laboratory Certification

The QA Plan must include documentation that the laboratory performing the

analyses

on the carbon sorbent traps is certified by the International

Organization for Standardization

(ISO)

have

proficiency that meets the

requirements

of ISO 17025. Alternatively, if the laboratory performs the spike

recovery study

described in Section 10.3 of Exhibit D to this Appendix and

repeats that

procedure annually, ISO certification is not required.

1.3.5 Data

Collection Period

State, and provide

the rationale for, the minimum acceptable

data

collection

period (e.g., one day,

one week,

etc.)

for the size of

the

sorbent

trap selected

for the monitoring.

Include in the discussion such factors

the mercury

concentration in

the

stack gas, the

capacity of the sorbent trap, and the

minimum mass of

mercury required for the analysis.

1.3.6

Relative Accuracy Test Audit Procedures

Keep records

of the procedures and details peculiar to the sorbent trap

monitoring

systems that are

to be

followed for relative accuracy test audits,

such as

sampling and analysis methods.

2. Frequency

of Testing

A summary

chart showing each quality assurance test and the

frequency

at which

each test is

required is located at the end of this Exhibit in Figure

2.1 Daily

Assessments

Perform the following daily assessments to quality-assure the

hourly

data

recorded

the monitoring systems during each period of

unit operation, or,

for

a bypass

stack or duct, each period in which

emissions

pass

through the

bypass

stack or duct. These requirements are effective as of the date

when the monitor

continuous emission monitoring system completes certification

testing.

2.1.1 Calibration

Error

Test

Except as

provided in Section 2.1.1.2 of this

Exhibit, perform the daily

calibration

error

test of each gas monitoring system

(including moisture

monitoring

systems consisting of wet- and dry-basis

02 analyzers) according

the

procedures

in Section 6.3.1 of Exhibit A to

this Appendix, and perform the

daily

calibration error

test of each

flow monitoring system according to the

procedure in

Section

6.3.2 of Exhibit A to

this Appendix. When two measurement

ranges

(low

and

high)

are required

for

particular parameter, perform

sufficient

calibration error

tests

on each range

validate the data recorded

that range,

according

to the

criteria in Section 2.1.5 of this Exhibit.

For

units with add-on emission controls and dual-span or auto-ranging

monitors,

and

other units

that

use the maximum expected concentration to

determine

calibration gas

values, perform the daily calibration error

tests

on each scale

that has been used

since

the

previous calibration

error test.

For example,

the pollutant concentration has not exceeded the low-scale value

(based

the

maximum expected

concentration)

since the previous calibration

error

test, the

calibration error test may be performed on the low-scale only. If,

however,

the

concentration has exceeded the low-scale span value for one hour or longer since

the previous calibration error test, perform the calibration error test on both

the

low- and high-scales.

2.1.1.1

On-line Daily Calibration Error Tests-

Except as

provided in Section 2.1.1.2 of this Exhibit, all daily calibration

error

tests

must be

performed while

the

unit is in operation at normal, stable conditions

(i.e. on-line’)

2.1.1.2

Off-line Daily Calibration Error Tests-s

Daily calibrations may be performed while the unit is not operating

(i.e.,

“off-

line”)

and may be used

to validate data for a monitoring system

that

meets

the

following conditions:

-(-1)

An initial demonstration test of the monitoring system is

successfully

completed and the results are reported

the quarterly

report required under

CFR 75.64, incorporated by reference

in Section 225.140. The initial

demonstration test, hereafter called the “off-line

calibration demonstration”,

consists of an off-line calibration error test

followed

an on-line

calibration error test. Both the off-line and on-line

portions of the off-line

calibration demonstration must meet the calibration error

performance

specification in Section 3.1 of Exhibit A to Appendix B. Upon

completion

of the

off-line portion of the demonstration, the zero and upscale

monitor responses

may be

adjusted, but only toward the true values of the

calibration

gases or

reference signals used to perform the test and only in

accordance with the

routine calibration adjustment

procedures specified in the quality control

program required under Section 1 of this

Exhibit. Once these adjustments are

made,

no further adjustments may be made to the

monitoring system until after

completion of the

on-line

portion

of the off-line calibration demonstration.

Within 26 clock hours

eafter the completion hour of the off-line portion of the

demonstration, the monitoring

system must successfully complete the first

attempted

calibration error

test,

i.e., the on-line portion of the

demonstration.

-2)

For each

monitoring system that has

passed

the off-line calibration

demonstration,

off-line calibration error

tests

may be

used

on a limited basis

validate data,

accordance with

(2)

in Section 2.1.5.1

this Exhibit.

2.1.2 Daily

Flow Interference Check

Perform

the daily flow monitor interference checks specified in Section

2.2.2.2

Exhibit A to this Appendix while the unit is in operation at normal, stable

conditions.

2.1.3

Additional

Calibration

Error Tests and Calibration

Adjustments

-f-a)

addition

the daily calibration error

tests

required under Section

2.1.1 of this

Exhibit,

calibration error

test

monitor must be performed

accordance

with Section 2.1.1 of this Exhibit,

follows: whenever a daily

calibration error test

is failed; whenever

monitoring system is returned

service following

repair or corrective maintenance

that

could affect the

monitor’s ability to

accurately measure and record emissions

data;

or after

making certain

calibration

adjustments,

described

this Section. Except in

the case of the

routine calibration

adjustments described

this Section,

data

from the monitor are

considered invalid until the

required

additional

calibration error test

has been successfully completed.

-(-b)

Routine

calibration adjustments of

monitor

are

permitted after any

successful

calibration error

test.

These routine adjustments must

made

so as

bring the

monitor readings

practicable

the

known

tag

values of

the

calibration gases

the actual value

the flow monitor reference

signals. An

additional calibration error

test

is required following routine

calibration

adjustments where the monitor’s calibration has been physically

adjusted (e.g., by

turning

potentiometer)

verify that the adjustments have

been made properly.

An additional calibration error

test

is not required,

however, if the

routine calibration adjustments are made

means of

mathematical

algorithm programmed

into the data

acquisition and handling system.

It is

recommended that routine calibration adjustments be

made,

at a

minimum,

whenever the daily calibration error exceeds the limits of

the applicable

performance specification in Exhibit A to this Appendix

for the pollutant

concentration

monitor,

C02 or 02 monitor, or flow

monitor.

-(-c)

Additional

(non-routine) calibration adjustments of

monitor are

permitted prior to

(but

not during) linearity checks and RATAs and at other

times, provided

that an appropriate technical justification is included in the

quality control

program required under Section 1 of this Exhibit. The allowable

non-routine

adjustments are

follows. The owner or operator may physically

adjust

the

calibration of

monitor

(e.g., by

means of

potentiometer),

provided that the

post-adjustment zero and upscale responses of the monitor are

within the performance

specifications of the instrument given in Section

3.1 of

Exhibit A to this

Appendix. An additional calibration error test is required

following such

adjustments

verify

that

the monitor is operating within the

performance specifications at both the zero and

upscale calibration levels.

2.1.4 Data

Validation

-(-a)

out-of-control period occurs when the calibration error of a

C02

or 02

monitor

(including 02 monitors used to measure C02 emissions or

percent

moisture)

exceeds 1.0 percent C02 or 02, or when the

calibration error of

a flow

monitor or

moisture sensor exceeds 6.0 percent of the span

value, which

twice

the applicable specification of Exhibit A to this

Appendix.

Notwithstanding, a differential pressure-type flow monitor

for which the

calibration error exceeds 6.0 percent of the span

value will not

considered

out-of-control if , the absolute

value of

the

difference between the monitor

response and the

reference value

Equation A-6 of Exhibit A

this Appendix,

< 0.02 inches

water. For a

mercury monitor, an out-of-control period

occurs when the

calibration

error

exceeds

5.0%

of the span value.

Notwithstanding,

the mercury monitor will

not be

considered out-of-control if

Equation A-6 does not exceed 1.0

rig/scm. The out-of-control period begins

upon failure

of the calibration error

test

and ends upon completion of a

successful

calibration error

test.

Note,

that

failed calibration,

corrective

action,

and successful

calibration error

test

occur within the same

hour, emission data for that

hour recorded

by the

monitor after the successful

calibration

error

test may be used

for reporting purposes, provided that two

more valid

readings are obtained

required

Section 1.2 of this Appendix.

Emission data

must not

reported from an out-of-control monitor.

-(-b)

An out-of-control period also occurs whenever interference of a flow

monitor

identified. The out-of-control period begins with the hour of

completion

the failed interference check and ends with the hour of completion

of an

interference check that is passed.

2.1.5

Quality

Assurance of Data

With

Respect to Daily Assessments

When

monitoring system passes a daily assessment

(i.e.,

daily calibration

error test or

daily flow interference

check),

data from that monitoring system

are

prospectively validated for 26 clock hours

(i.e.,

24 hours plus a 2-hour

grace

period) beginning with the hour in which the test is passed, unless

another

assessment

(i.e.

a daily calibration error test, an interference check

of a flow

monitor, a quarterly linearity check, a quarterly leak check, or a

relative

accuracy

test

audit)

is failed within the 26-hour period.

2.1.5.1

Data

Invalidation with Respect

Daily Assessments-i

The following

specific rules apply to the invalidation of data with respect to

daily

assessments:

-(-1)

Data

from a monitoring system are invalid, beginning with the

first

hour

following the

expiration of a 26-hour data validation period or

beginning

with

the first hour

following the expiration of an S-hour start-up grace period

(as

provided

under Section 2.1.5.2 of this

Exhibit),

if the required subsequent

daily

assessment has not been conducted.

-(-2)

For

monitor that has passed the off-line calibration demonstration, a

combination of on-line and off-line calibration error tests may be used to

validate data

from the monitor, as follows. For a particular unit

(or stack)

operating

hour, data from a monitor may be validated using a

successful

off-line

calibration

error test if: -

An on-line calibration error test has been passed

within the previous

unit

(or stack)

operating hours; and -

the 26 clock

hour

data

validation window for the off-line calibration

error test has

not expired. If either of these conditions is not met, then the

data from the

monitor are invalid with respect

the daily calibration error

test requirement.

Data from the monitor must remain invalid until the

appropriate

on-line or off-line calibration error test is successfully completed

that both

conditions

subsections

(a)

and

(b)

are met.

-(-3)

For units

with

two measurement

ranges

(low

and high) for

particular

parameter, when

separate

analyzers

are

used

for the low and high ranges, a

failed or expired

calibration

on one

the

ranges

does

not affect the quality-

assured data status on the other range.

For

dual-range analyzer

(i.e.,

single analyzer

with

two measurement

scales),

failed calibration error

test

either the low or

high

scale results

out-of-control period for the

monitor. Data

from the monitor remain invalid until corrective actions are taken

and

hands-off calibration error tests have been passed on both ranges.

However, if the most recent calibration error test on the high scale was passed

but

has expired, while the low scale is up-to-date on its

calibration error

test

requirements

(or

vice-versa),

the expired

calibration error

test

does not affect

the

quality-assured

status of the data

recorded on the other scale.

2.1.5.2

Daily Assessment

Start-Up

Grace Period-i

For

the purpose of

quality

assuring data

with respect to

a daily assessment

(i.e.

daily

calibration

error

test

or a flow interference

check),

start-up

grace period may

apply when

unit

begins

operate

after a period

of non-

operation.

The

start-up

grace

period for a daily

calibration

error

test is

independent

the

start-up

grace period for

a daily flow

interference

check.

qualify

for a

start-up grace

period for

a daily assessment,

there

are

two

requirements:

-(-1)

The unit

must

have

resumed

operation after

being in outage

for

1 or more

hours

(i.e.,

the

unit

must

be in

start-up

condition)

evidenced

by a change

in unit

operating

time from

zero in one

clock hour to an

operating

time

greater

than zero in the

next clock

hour.

-(-2)

For the

monitoring

system

used to

validate data

during

the grace

period,

the previous

daily

assessment of the

same kind must

have

been

passed

line

within 26

clock hours

prior

the

last hour in which

the

unit

operated

before

the outage.

addition, the

monitoring system

must be

in-control

with

respect

quarterly and

semi-annual

or annual assessments.

both

of the

above

conditions

are met, then

a start-up

grace period

of up

to 8

clock

hours applies,

beginning

with the

first hour of unit

operation

following

the outage.

During

the

start-up grace

period, data generated

the

monitoring

system are

considered

quality-assured.

For each monitoring

system, a

start-up

grace period

for

calibration

error test or flow

interference

check

ends when

either:

(1)

daily

assessment

of the same

kind

(i.e.,

calibration error

test

flow

interference

check)

performed;

(2)

clock

hours have elapsed

(starting with

the first hour

unit

operation

following the outage),

whichever

occurs first.

2.1.6 Data

Recording

Record

and tabulate

all

calibration

error test data

according

month,

day,

clock-hour, and

magnitude

either

ppm, percent

volume,

scfh. Program

monitors that

automatically

adjust data to the

corrected

calibration

values

(e.g.,

microprocessor

control)

to record either:

(1)

Thet.h

unadjusted

concentration

flow rate

measured in

the

calibration

error

test

prior

resetting

the

calibration,

(2)

the

magnitude of any

adjustment.

Record

the

following

applicable flow

monitor

interference check

data:

(1) Samplcsamnle

line/sensing

port

pluggage,

and

(2)

malfunction

of each RTD,

transceiver,

equivalent.

2.2

Quarterly

Assessments

For

each primary and

redundant backup monitor

or monitoring

system, perform

the

following

quarterly

assessments. This

requirement—4-e

applies as of the

calendar

quarter

following

the

calendar quarter

in which the

monitor or continuous

emission

monitoring

system

provisionally certified.

2.2.1

Linearity

Check

Unless a

particular monitor

(or

monitoring range)

is exempted

under

this

paragraphsubsection

under

Section 6.2 of Exhibit

A to this

Appendix,

perform

linearity

check,

accordance

with

the

procedures

Section 6.2 of

Exhibit

this

Appendix,

for each

primary and

redundant backup,

mercury, pollutant

concentration

monitor and

each primary

and redundant

backup C02

or 02

monitor

(including 02

monitors

used to measure

C02 emissions

or to

continuously

monitor

moisture)

least

once

during

each

QA operating

quarter, as

defined

in 40 CFR

72.2, incorporated

by reference

in Section 225.140.

For

mercury

monitors,

perform

the

linearity checks

using elemental

mercury standards.

Alternatively,

you

may perform 3-level

system integrity

checks at the same

three

calibration

gas

levels

(i.e.,

low, mid,

and high),

using a NIST-traceable

source

oxidized

mercury. If

you

choose

this

option,

the performance

specification

Section

3.2(c)

of Exhibit

A to

this

partPart must be met

at each gas

level.

For units

using both

low and

high

span value, a linearity

check is

required

only on the

rangc(s)ranes

used to

record and report

emission

data

during

the

operating

quarter.

Conduct the

linearity checks

no less than 30

days

apart,

to the

extent

practicable. The

data validation

procedures in Section

2.2.3(e)

this Exhibit

must

followed.

2.2.2 Leak

Check

For

differential

pressure

flow monitors,

perform

a leak check

of all

sample

lines

manual

check

acceptable)

at least

once during

each QA

operating

quarter.

For this test,

the

unit does not

have to be in

operation.

Conduct the

leak

checks no less

than

30 days apart,

to the extent

practicable.

a leak

check

is failed,

follow the

applicable

data validation

procedures

Section

2.2.3(g) of this

Exhibit.

2.2.3 Data

Validation

-(-a)

A linearity

check must not

commenced if the

monitoring system

operating

out-of-control

with respect

any of the

daily or semiannual

quality

assurance

assessments

required

Sections 2.1

and 2.3 of this

Exhibit or with

respect to

the additional

calibration error

test

requirements

in Section 2.1.3

of this

Exhibit.

-(-b)

Each

required

linearity

check

must

done

according to

par-ag-r-aphsi.ilaactism

(b) (1)

, (b)

(2)

(b) (3)

this Section:

-(-1)

The linearity

check may

done

“coldT”

i.e.,

with no corrective

maintenance,

repair, calibration

adjustments,

re-linearization

or reprogramming

of the

monitor

prior to the

test.

-(-2)

The

linearity

check may

be done

after performing

only the routine

or non-

routine

calibration

adjustments

described

in Section

2.1.3 of this

Exhibit

the

various

calibration gas

levels

(zero,

low,

mid or high), but

no other

corrective

maintenance, repair,

re-linearization

or reprogramming

the

monitor.

Trial gas injection

runs

may be

performed after

the calibration

adjustments

and additional

adjustments

within the allowable

limits

Section

2.1.3

this Exhibit

may be

made prior

the linearity

check, as

necessary,

optimize

the

performance of

the

monitor. The trial

gas

injections

need not

reported,

provided that they

meet

the

specification

for trial

gas injections

Section

1.4(b)

(3) (G)

(v)

this

Appendix.

However, if, for

any trial injection,

the

specification

in Section

1.4(b) (3)

(G)

(v)

not met,

the trial injection

must

counted as

an aborted

linearity

check.

The

linearity check

may

done

after

repair, corrective

maintenance

reprogramming

of the monitor.

In this case, the

monitor

must be considered

out

of-control

from the

hour in which the

repair, corrective

maintenance

reprogramming is

commenced

until

the linearity check

has been passed.

Alternatively,

the data validation

procedures

and associated timelines

Sections

1.4(b)

(3) (B)

through

(I)

of this

Appendix may be

followed

upon

completion

of the

necessary

repair, corrective

maintenance,

or reprogramming.

the procedures

in Section

1.4(b) (3)

are

used, the

words

“quality

assuranceT

apply

instead

the word

TTrecertificationT.

-(-c)

Once

linearity check has been commenced,

the test must be done hands-

off. That is, no

adjustments of the monitor

are permitted during

the

linearity

test

period, other than the routine calibration

adjustments following daily

calibration error tests,

described in

Section 2.1.3 of this

Exhibit.

If a

routine daily

calibration error

test

is performed

and passed just

prior

to a

linearity

test

(or

during

linearity

test period) and a

mathematical

correction

factor

is automatically applied

the DAHS,

the correction

factor must

applied to all

subsequent

data

recorded

by the monitor, including the linearity

test data.

--d)

If a daily

calibration

error test is failed during a linearity test

period, prior to

completing

the test, the linearity test must be repeated. Data

from the monitor

are invalidated

prospectively from the hour of the failed

calibration

error test until the hour of completion of a subsequent successful

calibration error test. The linearity test must not be commenced until the

monitor has

successfully

completed a calibration error test.

--e)

out-of-control

period occurs when a linearity test is failed

(i.e.,

when the error in linearity at any of the three concentrations in the quarterly

linearity check

(or

any of the six concentrations, when both ranges of a single

analyzer with a dual range are

tested)

exceeds the applicable specification in

Section 3.2 of Exhibit A to this Appendix) or when a linearity test is aborted

due to a

problem with

the monitor or monitoring system. The out-of-control

period begins

with the hour

the failed or aborted linearity check and ends

with the

hour of completion of

a satisfactory linearity check following

corrective

action and/or monitor

repair, unless the option in

p&g-aphubaectin

(b) (3)

of this Section to use the data

validation

procedures

and associated

timelines in

Section

1.4(b) (3) (B)

through

(I)

of this Appendix

has been

selected, in which

case the beginning and

end

of the

out-of-control

period must be

determined in accordance with Sections 1.4(b)

(3) (G)

(i) and

(ii).

For a

dual-range analyzer, ‘hands-off” linearity checks must

be passed

both

measurement scales to end the out-of-control period.

-(-f)

No more than four successive calendar quarters must elapse after the

quarter

in which a linearity check of

monitor or monitoring system

(or

range

of a

monitor or monitoring system) was last performed without

subsequent

linearity test

having been

conducted.

linearity

test

has not been

completed

the end of

the fourth

calendar quarter since the

last

linearity

test, then

the linearity test

must

be completed within a 168

unit

operating hour

stack

operating

hour “grace

periodTT

(as

provided in

Section

2.2.4 of this

Exhibit)

following

the end of the fourth

successive elapsed

calendar

quarter,

data

from the

CEMS

(or

range)

will become invalid.

-(-g)

An out-of-control period also occurs when

flow monitor sample line

leak

detected. The out-of-control period begins with the hour of the failed leak

check and ends

with

the hour of a satisfactory leak check following corrective

action.

-h)

For

each monitoring

system, report the results of all completed

and

partial

linearity tests that

affect data validation

(i.e.,

all completed, passed

linearity checks; all completed, failed linearity checks; and all linearity

checks

aborted due to

problem

with the monitor, including trial gas injections

counted

failed test attempts

under

paragraphsubsection

(b) (2)

this

Section

under Section

1.4(b) (3) (G) (vi)

of Appendix

B),

in the quarterly report

required under 40 CFR

75.64, incorporated

reference in Section 225.140. Note

that linearity attempts

wh-ehtiiat

are aborted

or invalidated due to

problems

with the reference

calibration

gases or due to operational

problems with the

affected

un±t(z)units need not

be reported. Such

partial

tests do

not affect the

validation status of

emission

data recorded by the monitor. A

record of all

linearity

tests,

trial gas

injections

and test attempts

(whether reported or

not)

must

kept

on-site

as part of the official test log for

each monitoring

system.

2.2.4 Linearity and

Leak Check

Grace Period

-(-a)

When

required linearity test or flow monitor leak check has not been

completed by

the end of the QA operating quarter in which it is due or

if,

due

infrequent operation of a unit or infrequent use of a required high range of

a monitor

or monitoring system, four successive calendar quarters have elapsed

after the

quarter in which a linearity check of a monitor or monitoring system

(or

range)

was last performed without a subsequent linearity test

having

been

done, the owner or operator has a grace period of 168

consecutive unit operating

hours, as defined in

40 CFR 72.2, incorporated

reference in Section 225.140

(or, for monitors

installed

on common

stacks

or bypass

stacks, 168 consecutive

stack operating hours, as defined in 40 CFR

72.2)

which

perform

linearity test or leak check of that monitor or

monitoring system

(or

range)

The grace period begins with the first unit

or stack operating hour following

the calendar quarter in

which

the linearity test

was

due.

Data validation during

linearity or leak check

grace

period must be

done

in accordance with the

applicable provisions in Section 2.2.3 of this

Exhibit.

-(-b)

If, at the end of the 168 unit

(or

stack)

operating hour grace period, the

required linearity testor leak check has not

been completed,

data

from the

monitoring system

(or

range) will be invalid,

beginning with the first unit

operating

hour following the expiration of the grace

period. Data from the

monitoring

system

(or

range)

remain invalid until the

hour

completion of

subsequent

successful hands-off linearity test or leak check of

the monitor

monitoring

system

(or

range)

. Note that when a linearity test or a

leak check

conducted

within a grace period for the purpose of

satisfying

the

linearity

test

leak check requirement from a previous

operating quarter, the results

that

linearity test or leak check may

only

be used to

meet the linearity check

or leak check

requirement

the previous quarter, not the quarter in which the

missed linearity test or leak

check is completed.

2.2.5

Flow-to-Load Ratio or Gross Heat Rate Evaluation

-(-a)

Applicability and methodology. Unless exempted from the

flow-to-load

ratio

test

under Section 7.8

Appendix A to 40 CFR Part 75 , the

owner or operator

must,

for each flow rate monitoring system installed on

each

unit,

common

stack

or multiple

stack, evaluate the flow-to-load ratio quarterly, i.e.,

for each

operating

quarter

(as

defined in 40 CFR 72.2, incorporated by

reference in

Section

225.140)

. At the end of each QA operating quarter,

the owner or operator

must use

Equation B-l to calculate the flow-to-load ratio

for every hour during

the

quarter in which: the unit

(or

combination

of units,

for

common

stack)

operated

within -f----l0.0 percent of Lava, the average load

during the most

recent normal-load flow RATA; and a quality assured hourly

average flow rate was

obtained

with a certified flow rate monitor. Alternatively,

for the reasons

stated

paragraphssubsections

Cc) (1)

through

(e-)—(-6)

of this

Section, the owner

operator may exclude from the data

analysis

certain hours

within ±—10.0

percent

Lava

and may calculate Lava

values for only the remaining hours.

(Equation

B-i)

whcrc,

Where:

Rh=

Hourly value of the flow-to-load ratio, scfh/megawatts, scfh/1000 lb/hr of

steam, or scfh/(mmBtu/hr thermal output). = Hourly stack gas volumetric flow

rate,

measured by the flow rate monitor, scfh.

Lh=

Hourly unit load,

megawatts, 1000 lb/hr of steam, or mmBtu/hr thermal output; must be

within +

10.0 percent of

Lava

during the most recent normal-load flow

RATA.

-(-1)

In Equation B-l, the owner or operator may use either bias-adjusted

flow

rates or unadjusted flow rates, provided that all of the ratios are

calculated

the same way. For a common stack,

J.h

will be the sum of the hourly

operating

loads of all units that discharge through the stack. For a unit that

discharges

its emissions through multiple stacks or that monitors its

emissions in multiple

breechings,

will be either the combined hourly volumetric flow

rate for

all

of the stacks or ducts

(if

the test is done on a unit

basis)

the

hourly

flow

rate through each stack individually

(if

the test is

performed separately for

each

stack)

. For a unit with a multiple stack discharge

configuration consisting

of a

main stack and a bypass stack, each of which has a

certified flow monitor

(e.g., a

unit with a wet S02

scrubber),

calculate the hourly

flow-to-load

ratios

separately

for each stack. Round off each value of

to two

decimal places.

-(-2)

Alternatively, the owner or operator may calculate the hourly gross heat

rates

(GHR)

lieu of the hourly flow-to-load ratios. The hourly GHR must

determined only for

those hours in which quality assured flow rate data and

diluent gas

(C02 or

02)

concentration

data

are both available from a certified

monitor or

monitoring system or reference method. If this option is selected,

calculate each

hourly GHR value

follows:

(Equation

B-la)

Where:

(GHR)h=Hourly value of

the

gross heat

rate, Btu/kwh, Btu/lb steam

load,

1000 mmBtu heat

input/mmBtu thermal

output.

(Heatlnout)h=Hourly

heat

input,

determined from the

quality assured flow rate and

diluent

data, using

the applicable equation in

Exhibit

C to this

Appendix, mmBtu/hr.

= LhHourly

unit load,

megawatts, 1000 lb/hr of steam,

mmBtu/hr thermal output; must be

within

+ 10.0

percent of

Lava

during the most

recent normal-load flow RATA.

-(-3)

In Equation B-la, the owner or operator may either use

bias-adjusted

flow

rates

or unadjusted flow rates in the calculation of

(HeatInut)h, provided

that

all of the heat input values are determined in the

same manner.

-(-4)

The owner or

operator

must

evaluate the calculated hourly flow-to-load

ratios

(or

gross

heat

rates)

follows. A separate

data

analysis must be

performed

for each primary and each redundant backup flow rate monitor used

record and

report data during the quarter. Each analysis must be based on a

minimum of 168 acceptable recorded hourly average flow rates

(i.e.,

at loads

within ---- 10 percent of

Lava).

When two RATA load levels are

designated

normal, the analysis must be performed at the higher load

level, unless there

are fewer than 168

acceptable

data points available at

that

load level, in which

case the

analysis must

performed

the lower load level. If, for a

particular

flow monitor, fewer than 168 acceptable hourly flow-to-load ratios

(or

GHR

values)

are

available

any of the load levels designated as normal, a

flow-to-load

(or

GHR)

evaluation

is not

required for that monitor for that

calendar quarter.

-(-5)

For each

flow

monitor,

use

Equation

B-2 in this Exhibit to calculate

Rh,

the absolute

percentage

difference

between each

hourly

_Rh

value and

Rref,

the

reference value

of the

flow-to-load

ratio, as

determined in accordance with

Section 7.7 to

Appendix

to 40 CFR

Part

75.

Note that

Rref

must always be

based upon the most

recent normal-load RATA,

even if that RATA was performed in

the

calendar

quarter being evaluated.

(Equation

B-2)

Where:

RhaJDsolute

percentage difference between the

hourly

average f low-

to-load ratio and

the reference value of the flow-to-load

ratio

normal load.

= RhaThe

hourly average flow-to-load ratio,

for each flow

rate

recorded at a

load level within +l0.0 percent of

- Lava.Rref=The

reference value

of the flow-to-load ratio

from the most

recent normal-load flow RATA,

determined in accordance with

Section 7.7 to

Appendix A to 40 CFR Part 75.

-(-6)

Equation B-2 must be used in a

consistent manner. That is, use

Rref

and

if the

flow-to-load ratio is being

evaluated, and use

(GHR)ref

and

(GHR)

h if

the gross heat

rate is being evaluated.

Finally, calculate

Ri,

the

arithmetic

average of

all of the hourly

_Eh

values.

The owner or operator must

report

the

results of

each quarterly flow-to-load

(or

gross

heat

rate)

evaluation, as

determined

from Equation B-2, in the electronic

quarterly

report required under

40 CFR 75.64.

-(-b)

Acceptable results. The results of a

quarterly flow-to-load

(or

gross heat

rate)

evaluation are acceptable, and no further

action is required, if the

calculated value

of is less than or equal to:

(1)

15.0 percent, if

Lava

for

the

most recent

normal-load flow RATA is

megawatts

(or

->= 500 klb/hr of

steam)

and if

unadjusted flow rates were used in

the calculations; or

(2)

10.0

percent, if

Lava for the most recent

normal-load flow RATA is >= 60 megawatts

(or ->= 500

klb/hr of

steam)

and if bias-adjusted

flow rates were used in the

calculations;

(3)

20.0 percent, if

Lava for the most recent normal-load flow

RATA is < 60

megawatts

(or

< 500 klb/hr of

steam)

and if unadjusted

flow

rates

were used

in the calculations; or

(4)

15.0

percent, if

Lava

for the most recent

normal-load

flow RATA is < 60 megawatts

(or

< 500

klb/hr of

steam)

and

bias

adjusted

flow rates were used in the

calculations. If

is above these limits,

the

owner or operator must either:

implement Option 1 in Section

2.2.5.1

of this

Exhibit;

perform

RATA in accordance with Option 2 in

Section 2.2.5.2 of

this Exhibit;

or re-examine the hourly data used

for the flow-to-load or GHR

analysis and

recalculate

after excluding all

non-representative hourly flow

rates.

above these limits, the owner or

operator must either:

implement

Option 1 in Section 2.2.5.1 of this

Exhibit; perform a RATA in

accordance

with Option 2 in Section 2.2.5.2 of this

Exhibit; or

(if

applicable)

re-examine the

hourly data used for the flow-to-load

or GHR analysis and

recalculate

El,

after excluding all

non-representative hourly flow rates, as

provided in

paragraphsubsection

(c)

of this Section.

-(-c)

Recalculation of

Ri.

If the owner or

operator did not exclude any hours

within

-f---j10 percent of Lava from the

original data analysis and chooses to

recalculate

El,

the

flow

rates for the following

hours

are considered

non

representative

and may

be excluded from

the data analysis:

-(-1)

Any hour in

which the

type of

fuel combusted

was different

from

the fuel

burned

during the

most recent

normal-load

RATA.

For purposes of

this

determination,

the

type of

fuel

different

if the fuel is

in a different state

of matter

(i.e.,

solid,

liquid,

or gas)

than

the fuel

burned

during

the

RATA

if the

fuel is a

different

classification

coal

(e.g.,

bituminous

versus

sub-bituminous)

. Also,

for

units that co-fire

different

types

of fuels,

if the

reference

RATA was

done

while co-firing,

then hours in

which a

single fuel was

combusted

may

excluded

from the

data analysis

different

fuel hours

(and

vice-versa

for

co-fired

hours,

if the reference

RATA was

done while combusting

only

one

type of

fuel);

-(-2)

For a unit

that is equipped

with

S02

scrubber and

which always

discharges its

flue gases

the

atmosphere

through a single

stack, any

hour

which the

S02 scrubber

was

bypassed;

-(-3)

Any hour

in which “ramping’

occurred, i.e.,

the hourly

load differed

than

--—l5.O

percent from

the load during

the

preceding

hour or

the

subsequent

hour;

-4)

For

unit with

a multiple stack

discharge

configuration

consisting

of a

main

stack and a

bypass stack,

any

hour in which

the flue gases

were

discharged

through

both

stacks;

-(-5)

normal-load

flow

RATA

was performed

and passed

during the quarter

being

analyzed,

any

hour

prior to completion

that

RATA; and

-(-6)

problem

with the

accuracy

of the

flow

monitor was discovered

during

the

quarter and

was

corrected

(as

evidenced by

passing the abbreviated

f low-to-

load

test in

Section

2.2.5.3

of this

Exhibit),

any hour

prior to completion

the

abbreviated

flow-to-load

test.

-(-7)

After

identifying and

excluding

all

non-representative

hourly

data in

accordance

with paragraphsubsections

through

(6)

this Section,

the

owner or

operator may

analyze the remaining

data a second

time. At

least

168

representative

hourly

ratios or GHR

values must be

available

perform

the

analysis;

otherwise,

the flow-to-load

(or GHR)

analysis is not

required for

that

monitor for

that

calendar

quarter.

-(-8)

If, after

re-analyzing

the data,

meets

the applicable limit

p&ag-r-aphbseot.iQxi

(b)

(1)

, (b)

(2) , (b) (3)

, or

(b)

(4) of this Section,

further

action

is required. If,

however,

still above

the applicable

limit,

data

from the

monitor

will be declared

out-of-control,

beginning with

the

first

unit

operating hour

following the quarter

which

exceeded

the

applicable

limit. Alternatively,

probationary

calibration error

test

performed

and passed

according

Section

1.4(b) (3)

(B) of this

Appendix,

data

from

the monitor

may be declared

conditionally valid

following

the quarter

which

exceeded

the applicable

limit. The owner

or operator

must then

either

implement

Option

Section

2.2.5.1 of this

Exhibit

or Option 2 in

Section

2.2.5.2

of this

Exhibit.

2.2.5.1 Option

Within

14 unit operating

days of the

end of the calendar

quarter

for

which

the

value is above

the applicable

limit, investigate

and

troubleshoot

the

applicable

flow

monitor(z)monitors.

Evaluate

the

results of

each

investigation

follows:

-(-a)

the

investigation

fails to

uncover

problem

with the

flow

monitor,

RATA

must

performed in accordance

with

Option

2 in Section

2.2.5.2

of this

Exhibit.

-(-b)

problem

with the

flow monitor

is identified

through

the

investigation

(including

the

need to re-linearize

the monitor by

changing the polynomial

coefficients

or K

factor(s)factors),

data

from

the monitor are

considered

invalid back to

the

first

unit operating hour

after the end

the

calendar

quarter

for which

was above the applicable

limit. If

the

option

to use

conditional

data validation

was selected

under Section

2.2.5(c) (8)

this

Exhibit,

all

conditionally

valid

data

will

invalidated,

back to

the first

unit

operating

hour after the

end of the calendar

quarter for

which

.._ was

above the

applicable limit.

Corrective actions

must be taken.

All corrective

actions (e.g.,

non-routine

maintenance,

repairs, major component

replacements,

re-linearization

the monitor,

etc.)

must

documented

in the operation

and

maintenance

records

for the

monitor. The

owner or

operator then must

either

complete

the

abbreviated flow-to-load

test in

Section 2.2.5.3 of

this Exhibit,

or, if the

corrective action

taken

has required

relinearization

of the flow

monitor, must

perform

a 3-load

RATA. The

conditional

data

validation procedures

in Section

1.4(b)

(3)of

this

Appendix may be

applied

the 3-load RATA.

2.2.5.2

Option

Perform a

single-load

RATA

(at

load designated

as normal

under

Section

6.5.2.1

Exhibit A to this

Appendix) of each

flow monitor for

which

outside

the

applicable

limit. If the RATA

is passed hands-off,

accordance

with

Section

2.3.2(c)

this

Exhibit,

no further action

is required

and the

out-of-

control

period for

the

monitor

ends at the

date and

hour

of completion

of a

successful

RATA,

unless the

option to use

conditional

data

validation

was

selected

under

Section

2.2.5(c)

(8)

of this Exhibit.

In that case,

all

conditionally valid

data from the

monitor are

considered

be quality-assured,

back

the

first

unit

operating

hour following

the

end

of the calendar

quarter

for

which

the

EI.

value was

above the applicable

limit.

If the RATA is

failed,

all data

from the

monitor will

be invalidated,

back to

the

first unit

operating

hour

following the

end of the calendar

quarter for which

the

value

was above

the

applicable

limit. Data from

the monitor remain

invalid

until

the

required

RATA

has

been

passed. Alternatively,

following

a failed

RATA and

corrective

actions,

the conditional

data validation procedures

Section

1.4(b)

(3)

of this

Appendix

may be used until

the RATA has

been passed. If

the corrective

actions

taken

following the

failed RATA included

adjustment

of the polynomial

coefficients

factor(s)

factors

of the flow

monitor,

3-level RATA

required, except

as otherwise

specified in Section

2.3.1.3

of this Exhibit.

2.2.5.3

Abbreviated

Flow-to-Load

Test

-(-a)

The

following abbreviated

flow-to-load

test

may be performed

after

any

documented

repair, component

replacement,

or other corrective

maintenance

to a

flow

monitor (except

for changes affecting

the linearity

of the

flow

monitor,

such

adjusting

the flow monitor

coefficients or

factor(s)factors)

demonstrate

that

the repair,

replacement, or other

maintenance

has not

significantly

affected

the

monitor’s

ability

accurately

measure the

stack

gas

volumetric

flow

rate. Data

from the monitoring

system

are

considered

invalid

from

the hour of commencement

of the

repair, replacement,

or maintenance

until

either

the hour

in which

the abbreviated

flow-to-load

test

passed,

or the

hour in which a

probationary

calibration error

test is

passed following

completion of the

repair,

replacement, or

maintenance and

any

associated

adjustments to the

monitor. If

the latter

option is

selected, the abbreviated

flow-to-load test

must be

completed within

168 unit

operating hours of the

probationary

calibration error test

(or,

for peaking units,

within

unit

operating days,

if that is less

restrictive)

. Data from the

monitor

are

considered

conditionally valid

(as

defined in 40 CFR

72.2, incorporated

reference in Section

225.140),

beginning with the hour of the probationary

calibration error test.

-b)

Operate

the

unit(c)units

in such

way

as to

reproduce, as closely as

practicable,

the exact

conditions

the time of the most recent normal-load

flow

RATA. To achieve this,

it is recommended that the load be held constant to

within -----l0.0 percent

of the average load during the RATA and that the diluent

gas

(C02 or

02)

concentration

maintained within

-f----j0.5

percent C02 or 02 of

the

average diluent

concentration during the RATA. For common stacks, to the

extent

practicable, use

the same combination of units and load levels that were

used

during the

RATA. When the process parameters have been set, record a

minimum of six and a

maximum of 12 consecutive hourly average flow rates, using

the flow

monitor(c)monitors

for which

was outside the

applicable limit.

For

peaking units, a

minimum of three and a maximum of 12

consecutive hourly average

flow rates are

required. Also record the corresponding hourly load

values

and,

if applicable, the

hourly diluent gas concentrations. Calculate the

flow-to-load

ratio

(or GHR)

for each hour in the test hour period, using Equation

B-l

or B

la.

Determine

Eh for each hourly flow- to-load ratio

(or GHR),

using Equation

B-2

of this Exhibit

and then calculate , the arithmetic average

of the

values.

-(-c)

The results

of the abbreviated flow-to-load test will be

considered

acceptable, and no further

action is required if the value of ... does not

exceed

the applicable limit specified in

Section 2.2.5 of this Exhibit. All

conditionally valid data recorded by the flow

monitor will be considered quality

assured,

beginning with the

hour

the probationary calibration error test that

preceded

the abbreviated

flow-to-load

test

(if

applicable). However,

outside

the applicable limit,

all conditionally valid data recorded by

the

flow

monitor

(if

applicable) will

considered invalid back to the hour

of the

probationary

calibration error test that preceded the

abbreviated flow-to-load

test, and a

single-load RATA is required in accordance

with Section 2.2.5.2

this Exhibit.

If the flow monitor must be

re-linearized, however,

3-load RATA

is required.

2.3

Semiannual and Annual Assessments

For

each primary and redundant backup

monitoring system, perform relative

accuracy

assessments either semiannually or

annually, as specified in Section

2.3.1.1 or 2.3.1.2 of this Exhibit

for

the type

of test and the performance

achieved.

This requirement applies as of the

calendar

quarter following the

calendar

quarter in which the monitoring

system is provisionally certified. A

summary

chart showing the frequency with

which

relative accuracy test audit

must be

performed, depending on the accuracy

achieved,

is located at the end of

this Exhibit in Figure 2.

2.3.1 Relative

Accuracy

Test

Audit (RATA)

2.3.1.1

Standard RATA Frequencies

-(-a)

Except for mercury monitoring systems, and as otherwise specified in

Section 2.3.1.2 of this Exhibit, perform relative accuracy

test

audits

semiannually, i.e., once every two successive QA operating quarters

(as

defined

in 40 CFR 72.2, incorporated by reference in Section

225.140)

for each primary

and redundant backup flow monitor, C02 or 02 diluent monitor

used to

determine

heat input, moisture monitoring system. For each primary and redundant backup

mercury concentration monitoring system and each sorbent trap monitoring system,

RATA5 must

performed annually, i.e., once every four successive QA operating

quarters

(as

defined in 40 CFR

72.2)

. A calendar quarter that

does

not qualify

as a

QA operating quarter must be excluded in determining the deadline for the

next RATA. No more than eight successive calendar quarters must elapse after the

quarter in which a RATA was last performed without a subsequent RATA having been

conducted. If a

RATA

has

not

been completed by the end of the eighth calendar

quarter since the quarter of the last RATA, then the RATA must be completed

within

720 unit

(or stack)

operating hour grace period

(as

provided in Section

2.3.3 of this

Exhibit)

following

the end of the eighth successive elapsed

calendar quarter, or data from the CEMS will become invalid.

-(-b)

The relative accuracy test audit frequency of a CEMS may be reduced, as

specified in Section 2.3.1.2 of this Exhibit, for primary or redundant backup

monitoring

systems which qualify for less frequent testing. Perform all required

RATAs in

accordance with the applicable procedures and provisions in Sections

6.5 through

6.5.2.2 of Exhibit A

this Appendix and Sections 2.3.1.3 and

2.3.1.4 of

this Exhibit.

2.3.1.2 Reduced

RATA Frequencies

Relative accuracy test audits of primary and redundant backup C02 or 02 diluent

monitors

used

to determine heat input, moisture monitoring systems, flow

monitors may be performed annually

(i.e.,

once every four successive QA

operating quarters, rather than once every two successive QA operating quarters)

any of the following conditions are met for the specific monitoring system

involved:

-(-a)

The relative accuracy during the audit of a C02 or 02 diluent monitor used

determine heat input is --= 7.5 percent;

-(-b)

The

relative

accuracy during the audit of a

flow

monitor

is -= 7.5

percent

each operating

level

tested;

-(-c)

For low flow

(<-=

10.0 fps), as measured by the reference method

during

the

RATA stacks/ducts,

when

the flow monitor fails to

achieve

relative

accuracy =

7.5 percent

during the

audit, but the monitor

mean value, calculated using

Equation A-7

in Exhibit A

this

Appendix and

converted back

an equivalent

velocity

standard

feet

per

second

(fps), is

within

+—j 1.5 fps

of the

reference

method mean value, converted

to an

equivalent velocity in

fps;

-(-d)

For

C02 or 02 monitor, when the mean difference between the reference

method

values from the RATA and the corresponding monitor values is within --—

0.7

percent C02 or 02; and

-(-e)

When the relative accuracy of a continuous moisture monitoring system is

*= 7.5 percent or when the mean difference between the reference method values

from the RATA and the corresponding monitoring system values is within --—jl.0

percent H20.

2.3.1.3

RATA Load

(or

Operating) Levels

and

Additional RATA Requirements

-(-a)

For C02 or 02

diluent

monitors used to determine heat input, mercury

concentration

monitoring

systems, sorbent trap monitoring systems, moisture

monitoring

systems,

the

required semiannual or annual RATA tests must be done at

the load level

(or

operating

level)

designated as normal under Section

6.5.2.1(d)

of Exhibit A to this Appendix. If two load levels

(or

operating

levels)

are designated as normal, the required

RATA(s)RATAs

may

be done at

either load level

(or

operating

level)

-(-b)

For flow monitors installed and bypass stacks, and for flow monitors that

qualify

perform only single-level RATAs under Section

6.5.2(e)

of Exhibit A

to this

Appendix, all required semiannual or annual relative accuracy test

audits must be

single-load

(or

single-level) audits

the normal load

(or

operating

level),

defined in

Section

6.5.2.1(d)

of Exhibit A to

this

Appendix.

-(-c)

For all

other flow monitors, the RATAs must

performed

follows:

-(-1)

annual 2-load

(or 2-level)

flow RATA must

done

the two most

frequently used

load levels

(or

operating

levels),

determined under Section

6.5.2.1(d)

of Exhibit A

this Appendix, or

(if

applicable)

the operating

levels determined under Section

6.5.2(e)

of Exhibit A

this Appendix.

Alternatively,

3-load

(or 3-level)

flow RATA

the low, mid, and high load

levels

(or operating

levels),

defined under Section

6.5.2.1(b)

of Exhibit A

to this

Appendix, may be performed in lieu of the 2-load

(or 2-level)

annual

RATA.

-(-2)

If the flow monitor is on a semiannual RATA frequency, 2-load

(or 2-level)

flow RATAs and single-load

(or

single-level) flow RATA5 at the normal load level

(or

normal operating

level)

may

performed alternately.

-(-3)

single-load

(or

single-level) annual flow RATA may be performed in lieu

of the 2-load

(or 2-level)

RATA if the results of an historical load data

analysis

show that in the time period extending from the ending date of the last

annual flow RATA to a date that is no more than 21 days prior to the date of the

current annual flow RATA, the unit

(or

combination of units, for a common

stack)

has

operated at a single load level

(or

operating

level) (low,

mid, or

high),

for

->= 85.0

percent of the time. Alternatively, a flow monitor may

qualify

for

single-load

(or

single-level) RATA if the 85.0 percent criterion is met in the

time

period extending from the beginning of the quarter in which the last annual

flow RATA was performed through the end of the calendar quarter

preceding

the

quarter of current annual flow RATA.

-(-4)

A 3-load

(or 3-level)

RATA, at the low-, mid-, and high-load

levels

(or

operating

levels),

as determined under Section 6.5.2.1 of Exhibit A to this

Appendix, must be performed at least once every twenty consecutive

calendar

quarters, except for flow monitors that are exempted from 3-load

(or

3-level)

RATA testing under Section

6.5.2(b)

6.5.2(e)

of Exhibit A to this

Appendix.

-(-5)

A 3-load

(or

3-level)

RATA

required whenever

flow monitor is re

linearized,

i.e., when

its

polynomial coefficients or K

factor(s)

factors are

changed, except

for flow monitors that are exempted from 3-load

(or

3-level)

RATA

testing under Section

6.5.2(b)

6.5.2(e)

of Exhibit A

this Appendix.

For monitors so exempted under Section

6.5.2(b),

single-load flow RATA is

required. For monitors

exempted under Section

6.5.2(e),

either a single-level

RATA or

2-level RATA is required, depending on the number of operating levels

documented in the monitoring plan for the unit.

-(-6)

For all multi-level flow audits,

the

audit points at

adjacent

load

levels

or at adjacent

operating levels (e.g., mid and high) must be separated by

less than 25.0

percent of the “range of

operation,TT

defined in Section

6.5.2.1 of Exhibit

A to this Appendix.

-(-d)

A RATA of a

moisture monitoring system must

performed whenever the

coefficient, K

factor or mathematical algorithm determined under Section 6.5.6

of Exhibit A to

this Appendix is changed.

2 .3 .1.4

Number of RATA Attempts

The owner or

operator may perform as many RATA attempts as are necessary to

achieve the

desired relative accuracy test audit frequencies. However, the data

validation

procedures in Section 2.3.2 of this Exhibit must be followed.

2.3.2 Data

Validation

-(-a)

RATA must not commence if the monitoring system is

operating out-of-

control

with respect to any of the daily and quarterly quality

assurance

assessments

required by Sections 2.1 and 2.2 of this Exhibit or

with

respect

the additional

calibration error test requirements in Section 2.1.3 of this

Exhibit.

-(-b)

Each

required RATA must be done according to

paragraphzsubsection

(b) (1),

(b) (2)

(b) (3)

of this Section:

-(-1)

The

RATA may be done

coldTT.

i.e., with no

corrective maintenance,

repair,

calibration adjustments, re-linearization or reprogramming of

the

monitoring

system prior to the test.

-(-2)

The

RATA may be done after performing only the routine

or non-routine

calibration adjustments described in Section 2.1.3 of this Exhibit at

the

zero

and/or

upscale

calibration gas levels, but no other

corrective maintenance,

repair,

re-linearization or reprogramming of the

monitoring system. Trial

RATA

runs may be

performed after the calibration

adjustments and additional

adjustments within the allowable limits in Section

2.1.3 of this Exhibit may

made

prior to the RATA, as necessary, to

optimize the performance of the CEMS.

The trial RATA runs need

not

reported, provided that they meet the

specification for

trial RATA runs in Section

1.4(b) (3) (G) (v)

of this Appendix.

However, if,

for any trial run, the specification in Section

(b) (3) (G) (v)

this Appendix is

not

met,

the trial run must

counted as an aborted RATA

attempt.

-3)

The RATA

may

done after repair, corrective maintenance, re

linearization

or reprogramming of the monitoring system. In this case, the

monitoring

system will

considered out-of-control from the hour in which the

repair,

corrective maintenance, re-linearization or reprogramming is commenced

until the

RATA has been passed. Alternatively, the data validation procedures

and

associated timelines in Sections

1.4(b) (3) (B)

through

(I)

this Appendix

may be

followed upon completion of the necessary repair,

corrective maintenance,

re-linearization or reprogramming. If the procedures in

Section 1.4(b)

(3)

this

Appendix are used, the words “quality assurance”

apply instead of the

word

-(-c)

Once a RATA is commenced, the test must be done

hands-off. No adjustment

the

monitorTs

calibration

is permitted

during the RATA

test

period, other

than the routine

calibration

adjustments following

daily calibration error

tests, as

described

Section 2.1.3 of this Exhibit.

routine

daily

calibration

error test is performed and passed just prior to a RATA

(or

during a

EATA test period)

and a mathematical correction factor is automatically applied

by the DABS,

the correction factor must be applied to all subsequent data

recorded by the

monitor, including the RATA test data. For 2-level and 3- level

flow

monitor audits,

no linearization

or reprogramming

of the

monitor is

permitted

between

load

levels.

-(-d)

For single-load

(or

single-level) RATA5, if a daily

calibration error

test

failed during a

RATA

test period, prior to completing

the

test,

the RATA

must

be repeated. Data

from the monitor are invalidated prospectively from the hour

of the failed

calibration

error test until the hour of completion of a

subsequent

successful calibration error

test.

The subsequent RATA must not be

commenced

until the monitor has successfully passed a calibration error test in

accordance

with Section 2.1.3 of this Exhibit. Notwithstanding these

requirements,

when ASTM D6784-02 (incorporated by reference under Section

225.140)

Method 29 in appendix A-8

40 CFR

60,

incorporated by reference in

Section

225.140,

is used

the reference method for the RATA of a mercury CEMS,

if a

calibration error

test

of the CEMS is failed during a RATA test period, any

test

run(z)runs

completed prior

the

failed calibration error test need not be

repeated;

however, the RATA may not continue until

subsequent calibration

error test of

the mercury CEMS has been

passed.

For multiple-load

(or

multiple-

level)

flow

PATAs, each load level

(or

operating

level)

is treated as a separate

RATA

(i.e.,

when

calibration error

test

is failed prior to completing the RATA

particular load level

(or

operating

level),

only the RATA at that load

level

(or

operating

level)

must

repeated; the results of any previously-

passed

RATA(o)RATAs

the other load

lcvcl(z)levels

(or

operating

lcvcl(z)levels) are unaffected, unless re-linearization of the monitor is

required to

correct the problem that caused the calibration failure,

in which

case a subsequent

3-load

(or 3-level)

RATA is required), except as

otherwise

provided

Section

2.3.1.3(c) (5)

of this Exhibit.

-fe)

For a

RATA performed using the option in

apuhtjQn

(b)

(1)

(b) (2)

this Section, if the RATA is failed

(that

is, if the

relative

accuracy

exceeds the

applicable specification in Section 3.3 of Exhibit A to

this

Appendix)

or if the RATA is aborted prior to completion due to a

problem with

the

CEMS, then the CEMS is out-of-control and

all emission

data

from the CEMS

are

invalidated

prospectively

from the

hour in which the RATA is failed or

aborted. Data from the CEMS remain

invalid until the hour of completion of

subsequent RATA that meets the applicable

specification in Section 3.3 of

Exhibit

A to this Appendix.

If the

option

(b) (3)

of this

Section

use the data

validation procedures and associated timelines in

Sections

1.4(b) (3)

(B)

through(b)

(3) (I)

of this Appendix has been selected, the

beginning and

end of

the

out-of-control period must be determined in accordance

with Section

1.4(b) (3) (G) (i)

and

(ii)

this Appendix. Note that when a RATA is

aborted for a reason other than monitoring

system malfunction

(see

paaaphuhtin

(g) of

this Section), this

does

not trigger an out-of-

control

period

for the monitoring system.

-(-f)

For a

2-level

3-level flow RATA, if,

any load level

(or

operating

level),

RATA

failed or aborted

due to a

problem with the flow monitor, the

RATA at that

load level (or operating

level)

must be repeated. The flow monitor

considered

out-of-control and

data

from the monitor are invalidated from the

hour in

which the test is failed or aborted and remain invalid until the passing

of a

RATA at the failed load level

(or

operating

level),

unless

the option

paragraphsubsection

(b) (3)

this Section to use the data

validation procedures

and

associated

timelines in Section

1.4(b)

(3)

(B) through

(b) (3) (I)

of this

Appendix has

been selected, in which case

the

beginning

and end of the out-of-

control period must

be determined in accordance with

Section

1.4(b)

(3) (G) (i)

and

(ii)

of this

Appendix. Flow

RATA(s)

that were previously passed at

the other

load

lcvcl(o)levels

(or

operating

lcvcls(s)levelss)

do not

have

to be

repeated

unless the flow

monitor must be re-linearized following the

failed or aborted

test. If the

flow monitor is re-linearized, a subsequent

3-load (or

3-level)

RATA is required,

except as otherwise provided in Section

2.3.1.3(c)

(5)

of this

Exhibit.

-(-g)

For each

monitoring system, report the results of

all completed and

partial RATA5

that affect data validation

(i.e.,

all

completed, passed RATA5;

all completed,

failed RATA5; and all RATA5 aborted due to a

problem with the

CEMS, including

trial RATA runs counted as failed test

attempts under

p-ag-apiae

ion (b) (2)

of this Section or under

Section

1.4(b) (3) (G) (vi))

the quarterly

report required under 40 CFR 75.64,

incorporated

reference in

Section 225.140.

Note that RATA attempts that are aborted

or invalidated due to

problems with

the reference method or due to

operational problems with the

affected

unit(D)units need not be reported. Such runs do

not affect the

validation status

of emission data recorded by the

CEMS. However, a record of

all RATA5,

trial RATA runs and RATA attempts

(whether reported or

not)

must be

kept on-site as

part of the official test log

for each monitoring system.

-(-h)

Each

time that a hands-off RATA of a

mercury concentration monitoring

system, a

sorbent trap monitoring system, or a

flow monitor is passed, perform a

bias test in

accordance with Section 7.4.4 of

Exhibit

A to

this Appendix.

-(-i)

Failure

of the bias test does not result in the

monitoring system being

out-of-control.

2.3.3 RATA Grace

Period

-(-a)

The

owner or operator has a grace period

of 720 consecutive unit operating

hours, as

defined in 40 CFR 72.2, incorporated by

reference in Section 225.140

(or,

for

CEMS installed on common stacks or bypass

stacks, 720

consecutive

stack

operating

hours, as defined in 40

CFR

72.2),

in which to complete the

required

RATA

for

particular CEMS

whenever:

-€1)

A required RATA has not

been performed by the end of the

QA operating

quarter

in which it is due; or

-(-2)

required 3-load flow

RATA has not been performed by the end

of the

calendar

quarter in which it is due.

-(-b)

The grace period will

begin with the first unit

(or

stack)

operating hour

following the

calendar quarter in which the required RATA

was

due.

Data

validation

during a RATA grace period must be

done

in accordance with the

applicable

provisions in Section 2.3.2 of

this Exhibit.

-(-c)

If, at

the end of the 720 unit

(or stack)

operating hour grace period, the

RATA has not

been completed, data from the

monitoring system will be invalid,

beginning

with the first unit

operating hour following the expiration

of the

grace

period. Data from the CEMS

remain invalid until the hour of

completion

subsequent hands-off RATA.

The deadline for the next test will be

either

two

operating

quarters

(if

semiannual RATA frequency is

obtained)

or four QA

operating quarters

(if

annual RATA frequency is

obtained)

after the quarter

which the

RATA is completed, not to exceed eight calendar

quarters.

-(-d)

When a RATA

done during a

grace

period in order to satisfy a RATA

requirement from a

quarter, the deadline for the next RATA must be

determined

follows:

-€1)

If the grace

period

RATA qualifies for a reduced,

(i.e., annual),

RATA

frequency the

deadline

for the next

RATA

will be set

three QA operating

quarters after the quarter in which the grace period test is completed.

-(-2)

If the grace

period

RATA qualifies for the standard,

(i.e., semiannual),

RATA frequency the deadline for the next RATA will be set at two QA operating

quarters after the quarter in which the grace period test is completed.

-(-3)

Notwithstanding

these

requirements,

no more than eight successive calendar

quarters must

elapse after

the

quarter in

which the grace period test is

completed, without a subsequent RATA having been conducted.

2.4 Recertification, Quality Assurance, and RATA Frequency (Special

Considerations)

-(-a)

When a

significant change

is made to a monitoring system such that

recertification of the monitoring system

is required in accordance with Section

1.4(b)

of this

Appendix,

recertification

test

(or tests)

must be performed

ensure that

the CEMS continues

generate

valid data. In all recertifications,

a RATA will be

one of the

required tests; for some recertifications, other tests

will also be

required.

A recertification test may be used to satisfy the quality

assurance test

requirement of

this Exhibit. For example, if, for a particular

change made to a

CEMS, one

of the required recertification tests is a linearity

check and the

linearity check

is successful, then, unless another

such

recertification

event

occurs in that same QA operating quarter, it would not

necessary to perform an additional linearity test of the CEMS in that quarter

meet the quality assurance requirement of Section 2.2.1 of this Exhibit. For

this reason, EPA recommends that owners or operators coordinate component

replacements, system upgrades, and other events that may require

recertification, to the extent practicable, with the periodic quality assurance

testing required by this Exhibit. When a quality assurance test is done for the

dual purpose

of recertification and routine

quality assurance,

the

applicable

data

validation procedures in Section 1.4(b)

(3)

must

followed.

-(-b)

Except as provided in Section 2.3.3 of this Exhibit, whenever a passing

RATA of

a gas

monitor is performed, or

passing 2-load

(or 2-level)

RATA or

passing 3-load

(or 3-level)

RATA of

flow monitor is performed (irrespective

whether the RATA is done to satisfy a recertification requirement or to meet

the

quality

assurance requirements of this Exhibit, or

both),

the RATA frequency

(semi-annual or

annual)

must be established

based

upon the date and time of

completion of the RATA and the relative accuracy percentage obtained. For 2-load

(or

2-level)

and 3-load

(or 3-level)

flow RATA5, use the highest percentage

relative accuracy at any of the loads

(or levels)

determine the EATA

frequency. The results of a single-load

(or

single-level) flow RATA may

be used

establish the RATA frequency when the single-load

(or

single-level) flow

RATA

specifically required under Section

2.3.1.3(b)

of this Exhibit or when the

single-load

(or

single-level) RATA is allowed under Section

2.3.1.3(c)

of this

Exhibit for a unit that has operated

one load level

(or

operating

level)

for

85.0

percent of the time since the last annual flow RATA. No other single

load

(or

single-level) flow RATA may be used

establish an annual RATA

frequency;

however,

a 2-load or 3-load

(or

a 2-level or

3-level)

flow RATA may

performed

any time or in place of any required single-load

(or

single-

level)

RATA, in

order

establish an annual

RATA frequency.

2.5

Other

Audits

Affected

units

may be subject to relative accuracy

test

audits at any time. If a

monitor

continuous emission monitoring system fails the relative accuracy

test during the

audit, the monitor or continuous emission monitoring

system

will

be considered to be

out-of-control beginning

with the date

and time

completion of the

audit, and continuing until

successful audit

test is

completed

following corrective action.

2.6 System

Integrity Checks for Mercury Monitors

For each mercury

concentration monitoring

system (except for a

mercury

monitor

that does not have a

converter),

perform a single-point system integrity check

weekly, i.e., at

least once every 168 unit

or stack

operating hours, using

NIST-traceable

source of oxidized mercury. Perform this check using

mid-

high-level gas

concentration,

defined in

Section 5.2 of

Exhibit A

to this

Appendix.

The

performance specifications in

paragraphsubsection

(3)

Section

3.2 of Exhibit

this Appendix must

be met, otherwise

the monitoring

system

is considered

out-of-control, from

the hour of the failed

check until

subsequent system

integrity check is

passed. If a

required

system

integrity

check is not

performed and

passed

within

168 unit or stack operating

hours

last successful

check,

the monitoring system will also be considered out of

control, beginning

with

the

169th

unit or stack operating hour after the last

successful check,

and continuing

until a subsequent system integrity check is

passed. This

weekly check

is not

required

if the daily

calibration

assessments

in Section 2.1.1

of this Exhibit

are performed using a

NIST-traceable

source of

oxidized mercury.

[Note:

The

following TABLE/FORM is

too

wide

to be

displayed on one screen.

You

must print it

for a meaningful review of its contents. The table has been

divided into

multiple pieces with each piece containing information

help

you

assemble a

printout of the table. The information for each piece includes:

(1)

three line message preceding the tabular data showing by line

and character

the position of the upper left-hand corner of the piece and the position of

the piece within the entire table; and

(2)

a numeric scale following the tabular

data

displaying the character positions.]

This is picce 1.

bcgins

charactcr 1 of tablc linc 1.

Figure 1 for Exhibit B of Appendix B

Tc s t

—Part

75.

- Opulity Assurance Test Rea-uirements

TestBasic

OA test freciuencv reauirements

IFN*1

Daily

FFN*1

WeeklvOuarterlv

[FN*1

Semiannual

Calibration

rFN*lAnnualCalibration

Error Test

pt.)—-Llnterference

Check

(f low)—

LFlow-to-Load

Ratio

Leak Check

(DP

flow

monitors)—

---LLinearity Check or System Integrity Check

[FN**]

pt.)Single-point System

Integrity Check

[FN**] .

.LRATA

(802,

NOXfl, C02, 0-

H20)

[FN1]

LRATA

(All

Hg monitoring systems)RATA

(flow)

[FN1]

[FN2I—

+++****++++ttttt+++++++++++t+t*++++++++t++++++++++++++++++÷+÷+++++÷++++++tt*++÷

This is piecc

begins

character

33 of

table line 1.

*+++++ttt+ttt+*+++++++++++++++++++÷+++++++++++++++++++++++÷÷+÷++++++++÷+*t÷+++

Part 75. Quality Assurance

Test

Requirements

Basic QA test frequency requirements

[FIT

Daily

Weekly

Quartcrly

Semiannual

Annual

[FIT

[FIT]

[FIT

33....40....i...5O....i...60....i...70....i...80....i.

4*+++44444++++***++*+++4++4*+++*4*44+++++++**+*++++*+*****+4444+4+44+44444444++

.L4L-Z--Z-3

piece 3.

It begins

cnara

—4—-—-—,

tanie ne

+*444+44444+******44 *4 4 +4+4+4+4*4* +4+4+4+ +4-4 +4+

*4 *4+

4 4+4+

+4+4+ 4+4+4 4+4+4 +4+44+

[FN*]

“Daily”

means operating days, only. “Weekly” means once every 168 unit or

stack

operating hours. “Quarterly” means once every QA operating

quarter.

“Semiannual”

means once every two QA operating quarters. “Annual”

means

once

every four

QA operating quarters.

[FN**]

The system integrity check

applies

only

to Hg

monitors with converters. The single-point weekly system

integrity

check

is not

required if daily calibrations are performed using a

NIST-traceable

source

of oxidized Hg. The 3-point quarterly system integrity

check is not

required if a linearity check is performed.

[FN1] Conduct RATA annually

(i.e.,

once every four QA operating

quarters), if

monitor meets accuracy requirements to qualify for less frequent

testing.

[FN2]

For flow monitors installed on peaking units, bypass stacks, or

units that

qualify

for single-level RATA testing under Section

6.5.2(e)

this part,

conduct

all RATA5 at a single, normal load

(or

operating

level)

. For other flow

monitors, conduct

annual RATA5 at two load levels

(or

operating

levels)

Alternating single-load

and 2-load

(or

single-level and

2-level) RATAs may be

done

if a monitor is

semiannual frequency. A single-load

(or

single-level)

RATA may

done

lieu of

2-load

(or 2-level)

RATA if,

since the last annual

flow RATA, the unit

has operated at one load level

(or

operating

level)

for >=

85.0 percent of the

time. A 3-level RATA is required at least once

every five

calendar years and

whenever

flow monitor is re-linearized, except

for flow

monitors exempted

from 3-level RATA testing under Section

6.5.2(b)

6.5.2(e)

of Exhibit A to

this Appendix.

1... I . . .10.... I . . .20...

.1 .

.30.... I . . .0. . . . I .

.50.

Figure 2 for

Exhibit B of Appendix B -— Relative Accuracy Test

Frequency

Incentive

System

RATA

Semiannual

[FNW]

----RATASemipanual FFNW1

(oercent)Annual

[FNW]

(pcrccntj

S02 or

NOX

[FNY]

7.5%

< RA -= 10.0% or -f---j15.0

ppm

[FNXI

7.5% or

-1—l2.0

ppm

[FNX]

.S02-diluent

7.5% < RA -.= 10.0% or ÷—0.030

lb/mmBtu

[FNX]

RA = 7.5% or

-f—0.025

lb/mmBtu

=GSX.NOX-diluent

7.5% < RA <-= 10.0% or

-f-—0.020

lb/mmBtu

[FNX]

RA -= 7.5% or -----0. 015

lb/mmBtu

[FNX]

.Flow

7.5% < RA -= 10.0% or

±—2.0

fps

[FNX]

7.5% or

-f----l.5

fps

[FNXJ

.C02 or 02

7.527.5% < RA --= 10.0% or

-i----l.0

C02/02

[FNX]

RA = 7.5%

or ----0.7%

C02/02

[FNXI .Hg

[FNX]

N/A

A<.cmu>>c/scmN/ARA

< 20.0%

or +—

1.0

<.mu>>g/zcm

[FNX]

.Moisture

7.5% < RA <-= 10.0% or

+—j1.5%

H20

[FNX]

RA <-= 7.5% or

±—l.0%

H20

[FNX] .

[FNWI

The

deadline for the next

RATA is the end of the second

(if

semiannual)

or fourth

(if annual)

successive QA operating quarter following

the quarter in

which

the CEMS was last tested.

Exclude calendar quarters with

fewer than 168

unit

operating hours

(or,

for

common stacks and bypass stacks,

exclude quarters

with

fewer than 168 stack

operating

hours)

in determining the

RATA deadline. For

S02

monitors, QA operating

quarters in which only very low

sulfur fuel as

defined

40 CFR 72.2,

incorporated

reference in Section

225.140, is

combusted

may also be excluded.

However, the exclusion of

calendar quarters

limited as

follows: the deadline for

the next RATA will be no more

than

calendar

quarters after the quarter in

which

RATA was last

performed. [FNX]

The

difference between monitor and

reference method mean values

applies

moisture

monitors,

C02, and 02

monitors, low emitters of S02, NOX,

or Hg, or

and

low

flow, only. The

specifications for Hg monitors also apply to

sorbent trap

monitoring systems.

[FNY]

A NOX concentration monitoring

system used to

determine

NOX mass

emissions under 40 CFR 75.71, incorporated by

reference in

Section 225.140.

Exhibit C to

Appendix B--Conversion Procedures

1. Applicability

Use the

procedures

in this

Exhibit to

convert

measured data

from

a monitor or

continuous

emission

monitoring

system

into

the appropriate

units of

the

standard.

2. Procedures

for Heat

Input

Use

the

following

procedures

compute heat input

rate

an affected

unit

(in

mmBtu/hr

mmBtu/day):

2.1

Calculate

and

record

heat

input

rate to

an affected unit

an hourly

basis.

The

owner

operator

may choose

to use

the provisions specified

40 CFR

75.16(e),

incorporated by

reference

Section

225.140, in

conjunction

with the

procedures

provided

Sections

2.4 through

2.4.2 to apportion

heat input

among

each unit

using the

common

stack

common pipe header.

2.2

For an affected

unit

that has

a flow monitor

(or

approved

alternate

monitoring

system under

subpart

E of 40

CFR 75, incorporated

by reference

Section

225.140,

for

measuring

volumetric

flow

rate)

and a

diluent

gas

(02

C02)

monitor,

use

the recorded data

from

these monitors and

one of the

following

equations to

calculate hourly

heat

input

rate

(in

mmBtu/hr).

2.2.1

When

measurements

of C02 concentration

are on a wet

basis,

use

the following

equation:

(Equation

F - 15)

Where:

Hourly heat input

rate

during unit

operation, mmBtu/hr.

= Hourly

average

volumetric

flow rate

during

unit operation,

wet basis,

scfh.

Carbon-based

F-

factor,

listed

in Section 3.3.5

Appcndixaooendix

40 CFR 75

for

each

fuel,

scf/mmstu.

C02w= Hourly

concentration

of C02

during unit

operation,

percent C02 wet

basis.

2.2.2

When

measurements

of C02 concentration

are on a

dry basis, use

the following

equation:

(Equation

F-16)

Where:

= Hourly heat

input rate

during unit

operation,

mmBtu/hr. = Hourly

average

volumetric

flow rate during

unit operation,

wet

basis, scfh.

Ec=

Carbon-based

Factorfactor,

listed in Section

3.3.5 of

Appcndixaooendix

40 CFR 75

for

each

fuel, scf/mmBtu.

%C02d=

Hourly

concentration

of C02

during unit

operation,

percent

C02 d-ry

basis.%H20= Moisture

content of

gas

in the stack,

percent.

2.2.3

When measurements

of 02 concentration

are on a wet

basis, use

the following

equation:

(Equation

F-17)

Where:

HI = Hourly

heat input

rate

during unit operation,

mmBtu/hr.

Hourly

average

volumetric

flow rate

during

unit operation,

wet

basis,

scfh.F

= Dry

basis=Carbon-based

F-factor,

listed

in Section 3.3.5

F to

CFR

75 for

each

fuel,

dsefacL/mmBtu.%02w=

Hourly

concentration

of 02

during unit

operation,

percent 02 wet basisi6H2o=

Hourly average

stack

moisture content,

percent by

volume.

For

any operating

hour whcre

Equation

F 17

results

in an hourly

heat

innut

that is

0.0

mmBtu/hr,

1.0

mmEtu/hr

must be

recordcd ann

renortea

as the heat

rate

for unac

nour.

2.2.4

When

measurements

of 02

concentration

are on a

dry basis, use the

following

equation:

(Equation

F-l8)

Where:

= Hourly

heat input

rate

during unit

operation, mmBtu/hr.

= Hourly

average

volumetric

flow during

unit

operation, wet

basis,

scfh.F

= Dry basis F-factor,

listed in

Section 3.3.5

Appendixaooendix

F to

40 CFR 75 for each

fuel,

dscf/mmBtu.%H20=

Moisture

content of

the stack gas,

percent.02d=

Hourly

concentration

02 during unit

operation, percent

dry basis.

2.3

Heat Input

Summation

(for

Heat Input

Determined Using

Flow

Monitor

and Diluent

Monitor)

2.3.1

Calculate

total

quarterly heat input

for a unit or

common stack

using

flow

monitor

and

diluent monitor

calculate heat

input,

using

the

following

equation:

(Equation

F-lSa)

Where:

jjjg=

Total heat input

for the quarter,

mmBtu.

jj=

Hourly heat input

rate

during unit

operation,

using Equation

F-l5, F-lG,

F-17,

or F-l8,

mmBtu/hr. j=

Hourly

operating

time for the unit

or common stack,

hour or

fraction of an

hour

(in equal

increments

that can

range from one hundredth

one quarter of

hour, at

the option

the

owner or operator)

2.3.2

Calculate

total

cumulative

heat

input for a

unit or common stack

using

a flow

monitor and

diluent monitor

to calculate

heat input, using

the

following

equation:

(Equation F-l8b

Where:

Total

heat

input for th

IiI=

Total heat input for the quarter, mmBtu.HIp=Total

heat

input

for

the

auarter. mmBtu.

2.4 Heat Input Rate Apportionment for Units Sharing a Common Stack or Pipe

2.4.1

Where applicable,

the

owner or operator of an affected unit that determines heat

input rate at the

unit

level by apportioning the heat input monitored at a

common stack or

common

pipe using megawatts must apportion the heat input rate

using the following equation:

Where:

(Equation

F-21a)

Hui=

Heat

input rate for

unit, mmBtu/hr.

HIcs=

Heat

stack or

pipe, mmBtu/hr.

NWi=

Gross electrical

output,

time,

hour or fraction of an hour

(in

equal increments

hundredth

one quarter of an hour, at the option of

La=

Common stack or common pipe operating time, hour

equal

increments that can range from one hundredth to

the

option of the owner or operator) .n = Total number

stack or pipe.i = Designation of a particular unit.

2.4.2

input rate at the common

MWe. = Unit operating

that can range from one

the owner or operator)

or fraction of an hour

(in

one quarter of an hour,

of units using the common

Where applicable, the owner or operator of an affected unit that

determines

the

heat

input rate at the unit level by apportioning the heat input rate monitored

a common stack or

common

pipe using steam load

must apportion the heat input

rate using the

following equation:

Where

(Equation

F-21b)

EIi=

Heat input rate for a unit, mmBtu/hr. HIcs= Heat input rate at

the

common

stack or pipe,

mmBtu/hr.SF

= Gross steam load, lb/hr, or mmBtu/hr.tj=

Unit

operating time,

hour or fraction

of an

hour

(in

equal increments that can range

from one

hundredth

one quarter of

hour,

the option of the owner or

operator)

tça=

Common stack or common

pipe

operating time, hour or fraction

an hour

(in

equal increments that can range from one hundredth

one quarter

an hour, at

the option of the owner or operator) .n = Total number of units using

the

common stack or pipe.i = Designation of

particular unit.

2.5

Heat Input Rate Summation for Units with Multiple Stacks or Pipes

The

owner or operator of an affected unit that determines the heat input rate at

the unit level by

summing

the

heat input

rates monitored at

multiple stacks

multiple

pipes must sum the heat input

rates

using the following equation:

(Equation

F-2lc)

Where:

HIUnit=

Heat

input rate for

unit, mmBtu/hr.

HI=

Heat input rate for the

individual stack, duct, or pipe, mmBtu/hr. tllnit=

Unit operating time,

hour

fraction

the hour

(in

equal increments that can range from one hundredth

one quarter

an hour, at the option of the owner or operator) .

.tE=

Operating

time for

the

individual stack or pipe, hour or fraction

of the hour

(in

equal

increments

that

can range from one hundredth

to one quarter of an hour, at the

option of the

owner or operator)

= Designation

for a particular stack, duct,

or pipe.

3. Procedure for

Converting Volumetric

Flow to STP

Use

the following equation to convert volumetric flow at actual temperature and

pressure

standard temperature and pressure.

(Equation F-22)

Where:

FSTP=Flue

gas

volumetric flow rate

standard temperature and pressure,

scfh.

FActual=Flue

gas

volumetric flow rate

actual temperature and pressure,

acfh.

TStd=Standard temperature = 528 degreesR. TStack=Flue

gas

temperature

flow

monitor

location, degreesR, where degreesR = 460 + degreesF. PStack=The

absolute

flue gas

pressure = barometric pressure

the flow monitor location + flue

gas

static

pressure, inches of mercury.

=Standard

prcccurc=29.92PStd=The

absolute

flue as pressure = barometric pressure at the flow monitor location

flue

gas

static pressure. inches of mercury.

4. Procedures

for Mercury Mass Emissions.

4.1

Use the

procedures in

this Section to calculate the hourly mercury mass

emissions

(in ounces)

at each monitored

locatiom-

for the affected unit or group

of units that

discharge through

a common stack.

4.1.1

determine the hourly mercury mass emissions when using

mercury

concentration monitoring system that measures on

wet basis and

flow monitor,

use

the following equation:

(Equation

F-28)

Where:

Nh=

Mercury

mass emissions for the

hour- rounded

off

three decimal places-

(ounces)

= Units conversion constant,

9.978 x 10-10

oz-scm/ag--scf

..Ch=

Hourly

mercury

concentration, wet basis,

adjusted for bias if the bias-test procedures

in Exhibit A to

this Appendix show

that a bias-adjustment factor is necessary,

(ig/wscm)

= Hourly stack

gas

volumetric

flow rate, adjusted for bias, where

the bias-test

procedures in Exhibit

A to this Appendix shows a bias-adjustment

factor

is necessary,

(scfh)

th=

Unit

or stack operating

time,

as defined in 40

CFR

72.2, (hr)

4.1.2

To determine the

hourly mercury mass emissions

when

using

mercury

concentration

monitoring system that measures

on a dry basis

a sorbent trap

monitoring system and a

flow monitor,

use the following equation:

(Equation

F-29)

Where:

Nh=

mercury mass emissions for the -

hour rounded of f to three decimal places-

(ounces)

.K = Units

conversion

constant, 9.978 x 10-10

oz-scm/<<mu>>g-scf

.Sh=

Hourly mercury

concentration,

dry basis, adjusted for bias if the bias-test

procedures in Exhibit

to this Appendix show that a bias-adjustment factor is

necessary, (pg/dscm)

. For sorbent

trap systems, a single value of

fla

(i.e.,

flow-proportional

average concentration

for the data collection period)

7- is

applied to each

hour in the

data

collection

period

7-for a

particular

pair of

traps.

Q2,=

Hourly

stack

gas

volumetric

flow rate, adjusted for

bias,

where the

bias-test procedures

in Exhibit A

to this Appendix shows a bias-adjustment

factor is necessary,

(scfh)

.Bws= Moisture fraction of the stack gas

7- expressed

as a decimal (equal to

%H20

100)

th=

Unit or stack operating time-- as defined in

40 CFR 72.2,

(hrj

4.1.3

For units that are demonstrated under Section

1.15(d)

of this Appendix to emit

less than 464 ounces of mercury per year, and for which the owner or operator

elects not

continuously monitor the mercury concentration, calculate the

hourly mercury mass emissions using Equation F-28 in Section 4.1.1 of this

Exhibit,

except that

£h”

will

the applicable default mercury concentration

from

Section

1.15(c), (d),

(e)

of this Appendix, expressed in pg/scm.

Correction for the stack

gas

moisture content is not required when this

methodology is used.

4.2

Use

the following equation to calculate quarterly and year-to-date mercury mass

emissions in ounces:

(Equation

F-30)

Where:

Mtimeoeriod=

Mercury

mass emissions for the

given

time perio i.e., quarter or

year-to-date

rounded

to the nearest thousandth,

(ounces)

. Nh=

Mercury mass

emissions for

the

hour-- rounded to three decimal places

(ounces)

.n = The number

of hours in

the given

time period (quarter or

year-to-date)

4.3 If heat

input rate monitoring

is required,

follow the applicable

procedures

for heat input

apportionment

and summation

Sections

2.3,

2.4

and

2.5 of this

Exhibit.

Moisture

Determination From

Wet and

Dry 02 Readings

If a

correction for the stack

gas

moisture content is required in any of the

emissions or heat input calculations described in this Exhibit, and if the

hourly moisture content is determined from wet- and dry-basis 02 readings,

use

Equation F-31 to

calculate

the percent moisture, unless a

TTKII

factor or other

mathematical

algorithm

developed

as described in Section

6.5.6(a)

of Exhibit

to this

Appendix:

(Equation

F-31)

Where:

%H20= Hourly average stack gas moisture content, percent H20 002d= Dry-basis

hourly average oxygen concentration, percent 02

QZw=

Wet-basis hourly average

oxygen

concentration, percent 02

Exhibit

D to

Appendix B -— Quality Assurance and Operating Procedures for

Sorbent Trap

Monitoring Systems

1.0 Scope and

Application

This Exhibit

specifies sampling, and analytical, and quality-assurance criteria

and procedures

for the performance-based monitoring of vapor-phase mercury (Hg)

emissions in

combustion flue

gas

streams, using

sorbent trap monitoring system

(as

defined in

Section

225.130).

The

principle employed is continuous sampling

using in-stack

sorbent media

coupled with analysis

of the integrated samples.

The performance-based

approach

of this

Exhibit allows

for use

of various

suitable sampling

and analytical

technologies

while maintaining

specified and

documented

level of

data

quality through performance criteria. Persons using

this Exhibit

should have

thorough working knowledge of Methods 1, 2, 3, 4 and

in appendices

A-i through A-3

CFR 60,

incorporated

reference in

Section 225.140, as

well

the determinative technique selected for analysis.

1.1 Analytes-

The analyte

measured by these procedures and specifications is total vapor-phase

mercury

in the flue gas, which represents the sum of elemental mercury (HgO, CAS

Number

7439-97-6)

and oxidized forms of mercury, in mass concentration units of

micrograms per dry standard cubic meter (ig/dscm)

1.2

App1icability--

These

performance criteria and procedures are applicable

monitoring of vapor-

phase mercury

emissions under relatively low-dust conditions

(i.e.,

sampling

the stack

after all pollution control

devices),

from coal-fired electric utility

steam

generators which are

subject to

Sections 1.14 through 1.18 of Appendix B.

Individual

sample collection times can range from

minutes to several days

duration,

depending on the mercury concentration in the stack. The monitoring

system must

achieve the performance criteria specified in Section 8 of this

Exhibit

and the sorbent media capture ability must not be exceeded. The sampling

rate must be

maintained at

constant proportion to the total stack flow rate

ensure

representativeness of the sample collected. Failure to achieve certain

performance criteria will result in invalid mercury emissions monitoring data.

2.0

Principle-s

Known volumes of

flue

gas are extracted from a stack or duct

through paired,

stack, pre-spiked

sorbent

media traps at an appropriate

nominal flow rate.

Collection of

mercury

the sorbent media in the stack

mitigates potential

loss

of mercury

during transport

through a

probe/sample line. Paired train sampling

required

determine measurement precision and verify acceptability of the

measured emissions data.

The

sorbent traps are recovered from the sampling system, prepared for analysis,

needed, and analyzed by any suitable determinative technique that can meet

the

performance criteria. A section of each sorbent trap is spiked with HgO

prior to sampling.

This section is analyzed

separately and the recovery value is

used to correct the

individual mercury

sample for measurement bias.

3.0 Clean Handling

and Contamination-

To avoid mercury contamination of the samples, special attention should be paid

cleanliness during transport, field handling, sampling, recovery, and

laboratory analysis, as well

during preparation of

the

sorbent cartridges.

Collection

and

analysis of blank samples (field, trip,

lab)

is useful in

verifying

the

absence of contaminant mercury.

4.0

Safety-i

4.1 Site hazards-i

Site hazards must be thoroughly considered in advance of applying these

procedures/specifications in the field; advance coordination with the site is

critical

understand the

conditions and applicable safety policies. At a

minimum, portions

the sampling system will be hot, requiring appropriate

gloves, long

sleeves,

and caution in handling this equipment.

4.2 Laboratory safety policies-

Laboratory safety policies should be in place to minimize risk of chemical

exposure and to properly handle waste disposal. Personnel must wear appropriate

laboratory attire according to a Chemical Hygiene Plan established by the

laboratory.

4.3 Toxicity or carcinogenicity-

The toxicity or carcinogenicity of any reagents used must be considered.

Depending upon the sampling and analytical technologies selected, this

measurement may

involve

hazardous materials, operations, and equipment and this

Exhibit does not address all of the safety problems associated with implementing

this approach. It is the responsibility of the user to establish appropriate

safety and health practices and determine the applicable regulatory limitations

prior to performance.

Any chemical

should be regarded as a potential health

hazard and

exposure

these

compounds should be

minimized.

Chemists

should

refer to the

Material

Safety Data Sheet

(MSDS)

for each chemical used.

4.4

Any wastes

generated

this procedure must

disposed of according

to a

hazardous

materials management plan

that

details and tracks various waste

streams and

disposal procedures.

5.0 Equipment

and Supplies-i

The

following list is presented

as an

example of key equipment and supplies

likely required to perform vapor-phase mercury monitoring using

sorbent

trap

monitoring system. It is recognized that additional equipment and supplies may

needed. Collection of paired samples is required. Also required are a

certified stack gas volumetric flow monitor that meets the requirements of

Section 1.2 to this Appendix and an acceptable means of correcting for the

stack

gas

moisture content, i.e., either by using data from a certified continuous

moisture

monitoring

system or by using an approved default moisture value

(see

CFR

75.11(b),

incorporated

reference

in Section

225.140).

5.1 Sorbent Trap

Monitoring System-

A typical sorbent

trap monitoring system is shown in Figure K-i. The

monitoring

system must

include the following components:

5.1.1 Sorbent

Traps-

The sorbent

media used to collect mercury must be

configured

in a

trap with

three

distinct and identical segments or sections, connected in

series, that are

amenable to

separate analyses. Section 1 is designated

for primary capture of

gaseous

mercury. Section 2 is

designated

as a backup

section for determination

vapor-phase mercury breakthrough. Section 3 is

designated for QA/QC purposes

where

this section must be spiked with a known amount of gaseous

HgO prior

sampling

and later analyzed to determine recovery efficiency. The

sorbent media

may be any

collection material (e.g., carbon, chemically-treated

filter,

etc.)

capable of

quantitatively capturing and recovering for subsequent

analysis,

all

gaseous forms

of mercury for the intended application. Selection of the sorbent

media must be based

on the material’s ability

achieve the performance

criteria contained

in Section

of this Exhibit

well as the sorbent’s vapor-

phase mercury

capture efficiency for the emissions matrix and the expected

sampling

duration

the

test

site. The sorbent media must be obtained

from

source that can

demonstrate the quality assurance and control necessary to

ensure consistent

reliability. The paired sorbent traps are supported on a probe

(or

probes) and

inserted directly into the flue gas stream.

5.1.2

Sampling Probe Assemb1y--

Each probe

assembly must have a leak-free Exhibit to the sorbent

trap(z)traos.

Each sorbent

trap must be mounted at the entrance of or within the

probe

such

that the gas

sampled

enters the trap directly. Each probe/sorbent

trap

assembly

must be heated to a

temperature sufficient to prevent liquid

condensation

in the

sorbent

trap(z)traos. Auxiliary heating is required

only where the stack

temperature is too low to prevent condensation. Use a

calibrated thermocouple

monitor

the stack temperature. A single probe

capable of operating the paired

sorbent

traps may be used. Alternatively,

individual probe/sorbent trap

assemblies

may be used, provided that the

individual sorbent traps are co

located to

ensure representative mercury

monitoring and are sufficiently

separated to

prevent aerodynamic interference.

5.1.3 Moisture

Removal Device

robust moisture

removal device

system, suitable for continuous duty

(such

as a

Peltier

cooler)

, must be used to

remove water vapor from the gas stream

prior to entering the gas flow meter.

5.1.4 Vacuum

Pump-i

Use a

leak-tight, vacuum pump capable of operating within the candidate system’s

flow range.

5.1.5 Gas

Flow Meter

A gas

flow meter

(such

as a dry gas meter, thermal mass flow meter,

or other

suitable

measurement

device)

must be used to determine the

total sample volume

on a

dry basis, in units of standard cubic meters.

The meter must

sufficiently accurate to

measure

the total sample

volume

within 2 percent and

must

calibrated

selected flow

rates across the

range

of sample flow

rates

which

the

sorbent trap monitoring

system typically

operates.

The gas

flow

meter must

equipped with any necessary

auxiliary

measurement

devices (e.g.,

temperature sensors,

pressure measurement

devices)

needed to correct the sample

volume to standard

conditions.

5.1.6 Sample Flow Rate Meter and Controller-

Use a flow rate indicator and controller for maintaining necessary sampling flow

rates.

5.1.7 Temperature Sensor-

Same

Section 6.1.1.7 of Method

in appendix A-3

40 CFR

60,

incorporated

reference in Section 225.140.

5.1.8 Barometer-

Same

Section 6.1.2 of Method 5 in appendix A-3 to 40 CFR

60,

incorporated

reference in Section 225.140.

5.1.9 Data Logger (Optiona1)--

Device for recording associated and necessary ancillary information (e.g.,

temperatures,

pressures,

flow, time,

etc.).

5.2 Gaseous HgO Sorbent Trap Spiking System-i

known mass of gaseous Hg0 must be spiked onto section

of each sorbent trap

prior to sampling. Any approach capable of quantitatively delivering known

masses of HgO onto sorbent traps is acceptable. Several technologies or devices

are available to meet this objective. Their practicality is a function of

mercury mass

spike levels.

For low levels, NIST-certified or NIST-traceable

gas

generators or tanks may be suitable, but will likely require long preparation

times. A more

practical,

alternative system, capable of delivering almost any

mass required,

makes

use of NIST-certified or NIST-traceable mercury salt

solutions (e.g.,

Hg(N03)2).

With this system, an aliquot of known volume and

concentration

added to a reaction vessel containing a reducing agent (e.g.,

stannous

chloride); the mercury

salt

solution is

reduced to HgO and

purged

onto

section 3 of

the sorbent trap

using an

impinger sparging

system.

5.3

Sample Analysis Equipment-

Any

analytical system capable

quantitatively recovering

and

quantifying

total

gaseous

mercury from sorbent media

acceptable provided that the analysis

can

meet

the performance criteria in Section

of this procedure. Candidate recovery

techniques

include leaching, digestion, and thermal desorption. Candidate

analytical techniques include ultraviolet atomic fluorescence

(UV

AF);

ultraviolet

atomic absorption (tAT

AA),

with and without gold trapping; and in

situ X-ray fluorescence

(XRF)

analysis.

6.0 Reagents

and Standards-

Only

NIST-certified

NIST-traceable

calibration gas standards and reagents

must be used

for the

tests

and

procedures

required

under this

Exhibit.

7.0

Sample Collection and Transport-

7.1 Pre-Test Procedures-i

7.1.1 Selection of Sampling Site-

Sampling site information should be obtained in accordance with Method 1 in

appendix A-l to 40

CFR

60, incorporated by reference in Section 225.140.

Identify a monitoring location representative of source mercury emissions.

Locations shown to be free of

stratification

through measurement traverses for

gases such as SO2 and

NOx

may be one such approach. An estimation of the

expected stack

mercury concentration is

required to establish a target sample

flow rate, total gas sample

volume, and

the mass of HgO to be spiked onto

section 3 of each

sorbent

trap.

7.1.2 Pre-sampling

Spiking

Sorbent

Traps-

Based on

the estimated mercury concentration

in the stack, the

target sample

rate and the

target sampling duration,

calculate the expected mass loading for

section 1 of each

sorbent

trap

(for

an example calculation, see Section 11.1 of

this

Exhibit)

. The pre-sampling spike to be added to section 3 of each sorbent

trap must be within ----- 50 percent of the expected section 1 mass loading. Spike

section 3 of each sorbent trap at this level, as described in Section 5.2 of

this Exhibit. For

each

sorbent

trap, keep

an official record of the mass of HgO

added to section 3.

This

record must include, at a minimum, the ID number of the

trap, the date and

time

of the spike, the name of the analyst performing the

procedure,

the mass

of HgO

added to

section

3 of the trap

(jig),

and the

supporting

calculations.

This record must be maintained in a format suitable for

inspection and audit and must be made available to the regulatory agencies upon

request.

7.1.3 Pre-test Leak Check

Perform a leak

check

with the sorbent traps in place. Draw a vacuum in each

sample train. Adjust the

vacuum

in the sample train to mercury. Using the gas

flow meter,

determine

leak

rate. The

leakage rate must not exceed

4 percent

the target

sampling rate. Once the

leak check passes this

criterion, carefully

release the vacuum

the sample train then seal the sorbent trap inlet until

the probe is ready

for insertion

into the stack or duct.

7.1.4

Determination of Flue

Gas

Characteristics-i

Determine or measure the flue gas measurement environment characteristics

(gas

temperature, static pressure, gas velocity, stack moisture,

etc.)

in order

determine

ancillary requirements such

probe

heating requirements

(if

any),

initial sample rate, proportional sampling conditions, moisture management,

etc.

7.2 Sample Collection-i

7.2.1

Remove the plug

from

the end

each

sorbent trap and store each plug in a clean

sorbent trap

storage container. Remove

the stack or duct port cap and insert the

probc(z)orobes.

Secure the

probc(s)orobes

and ensure that no leakage occurs

between the duct

and environment.

7.2.2

Record initial data

including the sorbent

trap ID, start time, starting dry gas

meter readings,

initial temperatures,

set-points, and any other appropriate

information.

7.2.3

Flow Rate

Control

Set the initial

sample flow rate

the

target value from Section 7.1.1 of this

Exhibit. Record the

initial

gas

flow

meter

reading, stack

temperature

(if

needed

to convert to

standard

conditions),

meter temperatures

(if

needed),

etc. Then,

for every operating hour

during

the sampling period, record the date and time,

the sample flow rate, the gas flow meter reading, the stack temperature

(if

needed),

the flow meter temperatures

(if needed),

temperatures of heated

equipment such

the vacuum lines and the probes

(if heated),

and the sampling

system vacuum readings. Also, record the stack gas flow rate, as measured

the

certified flow monitor, and the ratio of the stack gas flow rate to the sample

flow rate. Adjust the sampling flow rate to maintain proportional sampling,

i.e.,

keep the ratio of the stack gas flow rate

sample flow rate constant,

within -----25 percent of the reference ratio from the first hour of the data

collection period

(see

Section 11 of this

Exhibit)

. The sample flow rate through

sorbent trap monitoring system during any hour

(or

portion of an

hour)

which the unit is not operating must be zero.

7.2.4

Stack Gas Moisture Determination-c

Determine stack gas moisture using a continuous moisture monitoring system, as

described in 40 CFR

75.11(b),

incorporated by reference in Section 225.140.

Alternatively, the owner or operator may use the appropriate fuel-specific

moisture default value provided in 40 CFR 75.11, incorporated by reference in

Section

225.140, or a site-specific moisture default value approved by the

Agency.

7.2.5

Essential Operating Data

Obtain and record any essential operating data for the facility during the test

period,

e.g.,

the barometric pressure for correcting the sample volume measured

by a

dry

gas

meter to standard conditions. At the end of the data collection

period, record the

final

gas flow meter reading

and the final values of

all

other

essential parameters.

7.2.6 Post Test

Leak Check-

When sampling is

completed, turn

off the sample

pump, remove the probe/sorbent

trap from the port and

carefully

re-plug the

end of each sorbent trap. Perform

leak check

with the sorbent traps in

place,

the maximum vacuum reached

during

the sampling period. Use

the

same general approach

described in Section 7.1.3

this Exhibit.

Record

the

leakage rate

and

vacuum. The leakage rate must not

exceed 4 percent

the

average sampling

rate

for

the data

collection period.

Following the

leak

check,

carefully

release the

vacuum

in the

sample train.

7.2.7 Sample

Recovery-c-

Recover

each sampled sorbent trap

removing it from the probe, sealing

both

ends.

Wipe any deposited material from the outside of the sorbent trap. Place

the

sorbent

trap into an appropriate sample storage container and store/preserve

appropriate manner.

7.2.8 Sample

Preservation, Storage,

and

Transport-

While the

performance criteria

this approach

provide for verification of

appropriate sample

handling, it is still important that

the user consider,

determine, and

plan for

suitable

sample preservation, storage,

transport, and

holding times for

these measurements. Therefore, procedures

ASTM

D69l1-03

Standard Guide

for Packaging and Shipping Environmental

Samples for Laboratory

Analysis”

(incorporated by reference under Section

225.140)

must be

followed for

all samples.

7.2.9 Sample Custody-

Proper

procedures

and documentation for sample chain of custody

are critical

ensuring data

integrity. The chain of custody procedures in ASTM

D4840-99

(reapproved

2004)

“Standard Guide for Sample Chain-of-Custody

Procedures”

(incorporated by

reference under Section

225.140)

must be followed

for all

samples (including

field samples and

blanks).

8.0

Quality

Assurance and Quality Control-i

Table K-l

summarizes the QA/QC performance criteria that are used to

validate

the mercury

emissions

data

from sorbent trap monitoring systems,

including the

relative accuracy test

audit

(RATA)

requirement

(see

Section

1.4(c) (7),

Section

6.5.6 of

Exhibit A to this Appendix, and Section 2.3 of

Exhibit B

this

Appendix). Except

as provided in Section

1.3(h)

of this

Appendix and as

otherwise indicated

in Table K-l, failure to achieve these

performance criteria

will result in

invalidation of mercury emissions data.

Table IC-l.—

Quality Assurance/Quality Control Criteria

for Sorbent Trap

Monitoring

Systems

QA,’QC test

Acceptance

criteria

Frequency

Consequences

QA/OC

test

or snecificationAcceotance

criteriaFrec-uencvConseouences if

specification

not met

Pre-test

leak check

-= 4% of

target sampling

uaLLLllng

Sampling ratePrior

to samolinaSamnlin

must not

commence

until

the leak

check

passed.Post-test leak check

<= 4% of average

sampling

rate

AftcrrateAfter

sampling__[FN**]

See

Note,

below.Ratio

of stack gas flow rate torateto

sample flow rate

rateNo

more than 5% of the

hourly

ratios or 5

hourly ratios

(whichever

is less

restrictive)

may

deviate from the

reference

ratio

more than

jEvery hour

throughout

data

collection

period

See Note,

below.Sorbent

trap section 2 break-through ..

of Section 1 Hg—

macc

Every massEverv sample

... [FN**]

See Note,

below.Paired

sorbent trap agreement .

<= 10% Relative

Deviation

(RD)

the

average concentration

> 1.0 <<mu>>g/m3 .

. .Every sample ... Either invalidate

thc data from

the paircd trapc

or rcport the

rczultc from

the

trap

with the

higher Hg

on.

20% RD if the

average

concentration

is <-= 1.0

<<mu>>g/m

Results are also

acceptable if

absolute difference

between

concentrations

from

paired traps

is =

0.03

<<mu>>g/m3

Spi]tc

Recovery Study

AvcragcEverv samoleEither invalidate

the data

from

the

paired traos

report

the results from the trao

with

the

higher

concentration.Soike

Recovery

StudvAveraae

recovery

between 85% and

115%

for

each of the

spike

concentration

leveisPrior to

analyzing

field

samples

and prior

use of

new

sorbent

me44a—Fe-l4mdi.Ei1d

samples

must not be

analyzed

until

the

percent

recovery

criteria has

been met

Multipoint

been metMultipoint

ana1yzer—e±

&±en—---..—r&eh

ca1ibrationach

analyzer reading

within ÷—l0%

of true

value and

->=

the day

analysis,

before

analyzing

any

zamplcci

Rccalibratc

samolesRecalibrate until

successful.Analysis

independent calibration otandard

Within

of true

value

Foiiowing

standardWithin

+ 10% of true valueFollowina daily

calibration,

prior

analyzing

field zamplc

Recalibrate

field samplesRecalibrate and

repeat

independent

standard

analysis until

successful.Spike recovery

from

zcctionSection

of sorbent trap

75-125% of

spike

amount EvcryamountEverv sample .

.. [FN**]

See Note,

below.R2\Ti

7’

<RATARA

= 20.0% or Mean

difference

= 1.0

<<mu>>g/dscm for

low

cmittcrz

For emittersFor initial

certification

and

annually

hcrcaftcr ...

Data

thereafterData

from the

system are

invalidated

until

a RATA is

passed.Gas

flow

factor

(Y)

within

----j

average

value

from

the most recent

3-point

calibration ..

AtcalibrationAt three

settings

prior

initial use

and at least

quarterly at

one

setting

thereafter.

For

mass flow

meters,

initial

calibration

with

stack

gas is

rcquircd

Rccalibratc rea-uiredRecalibrate

the

meter at

three

orifice settings

determine a

new value of

Y.Temperature sensor caILaLion . . . . Abzolutc

calibrationAbsolute temperature

measured

sensor

within +— 1.5%

of a

reference zcnzor

PriorsensorPrior to

initial use

and

at least

quarterly

thcrcaftcr thereafterRecalibrate...

Rccalibratc.

Sensor may

not

be used

until

specification is

met.Barometer calibration .... Absolute

calibrationAbsolute pressure

measured by

instrument within -i-—

10 mm Hg of

reading

with

mercury

baromctcr

Prior

barometerPrior to

initial use

and at

least

quarterly

thcrcaftcr thereat terRecalibrate...

ratc.

Instrument may

not be

used

until

specification is

met.

[FN**]

Note:

If both

traps

fail

meet the acceptance criteria, the data from

the

pair of traps are invalidated. However, if only one of the paired traps

fails

meet this particular acceptance criterion and the other sample meets

all of the applicable QA criteria, the results of the valid trap may be used for

reporting under this part, provided that the measured Hg

concentration is

multiplied by a

factor

of 1.111. When the data from

both

traps are

invalidated

and

quality-assured

data from a certified

backup monitoring system, reference

method, or

approved

alternative

monitoring system are unavailable, missing data

substitution

must

used. 9.0 Calibration and Standardization.

9.1

Only NIST-certified and

NIST-traceable

calibration standards

(i.e.,

calibration

gases,

solutions,

etc.)

must

be used for the spiking and analytical procedures

this Exhibit.

9.2 Gas

Flow Meter Calibration

9.2.1

Preliminaries-i—

The manufacturer

or supplier of the

gas

flow meter should perform all necessary

set-up, testing,

programming,

etc.,

and should provide the end user with any

necessary

instructions,

ensure that the meter will give an accurate readout

of dry gas volume

in standard cubic

meters

for the

particular field application.

9.2.2 Initial

Ca1ibration-—

Prior to

its initial use, a calibration of the flow meter must be performed. The

initial

calibration may be done by the manufacturer, by the equipment supplier,

or by the

end user. If the flow meter is volumetric in nature (e.g., a dry gas

meter),

the

manufacturer, equipment supplier, or end user may perform a direct

volumetric

calibration using any

gas.

For

mass flow meter, the manufacturer,

equipment

supplier, or end user may calibrate the meter using a bottled gas

mixture

containing 12 -f---j 0.5% C02, 7 ----- 0.5% 02, and balance N2, or these same

gases in

proportions more representative of the expected stack gas composition.

Mass flow

meters may also

initially calibrated on-site, using actual stack

gas.

9.2.2.1

Initial Calibration Procedures-i—

Determine an

average calibration factor

(Y)

for the

gas

flow

meter, by

calibrating it at

three sample flow rate settings covering the range of sample

flow rates at

which the sorbent trap monitoring system typically operates. You

may

either follow the procedures in Section 10.3.1 of Method 5 in appendix A-3

to 40

CFR

60,

incorporated

reference in Section 225.140, or the procedures in

Section

16 of Method

in appendix A-3

40 CFR 60. If a dry gas meter is being

calibrated, use

at least five revolutions of the meter at each flow rate.

9.2.2.2

Alternative Initial Calibration Procedures-i—

Alternatively, you

may

perform the initial

calibration of the

gas

flow meter

using a reference gas flow

meter

(RGFM)

. The RGFM may either

be:

(1)

A wet

test

meter calibrated according to Section

10.3.1 of Method

in appendix A-3

CFR 60,

incorporated

reference

Section 225.140;

(2)

a gas flow metering

device

calibrated

multiple flow

rates

using the procedures in Section 16 of

Method 5 in

appendix A-3

40 CFR

60;

(3)

NIST-traceable calibration

device

capable of measuring volumetric flow

an accuracy of 1 percent. To

calibrate

the

gas

flow meter using the RGFM, proceed

follows: While the

sorbent trap

monitoring system is sampling the actual stack

gas

or a compressed

gas

mixture that simulates the

stack gas

composition

(as

applicable), connect

the RGFM to

the

discharge of the

system.

Care should

taken

minimize the

dead

volume between the sample flow meter being

tested

and the RGFM.

Concurrently

measure dry

gas

volume with the RGFM and the flow meter being

calibrated

the for a minimum of 10 minutes

each of three flow rates covering

the typical range of

operation

of the sorbent trap monitoring system. For each

10-minute

(or

longer) data collection period, record the total sample

volume,

units of dry standard cubic meters

(dscm),

measured by the RGFM and the gas flow

meter being

tested.

9.2.2.3

Initial Calibration Factor-—

Calculate

an individual calibration factor Yi at each tested flow rate from

Section 9.2.2.1 or 9.2.2.2 of this Exhibit

(as

applicable),

taking the ratio

of the reference sample volume to the sample volume recorded by the gas flow

meter. Average the

three Yi

values, to determine Y, the calibration

factor for

the flow meter.

Each of the

three individual

values

of Yi must be

within ÷—

0.02

of Y. Except as otherwise provided in Sections 9.2.2.4 and 9.2.2.5 of this

Exhibit,

use

the average Y value from the three level calibration to adjust all

subsequent

gas

volume measurements made with the gas flow meter.

9.2.2.4

Initial On-Site Calibration Check-—

For

mass flow

meter

that was initially calibrated using a compressed gas

mixture, an on-site calibration check must be performed before using

the flow

meter

provide data for this part. While sampling stack gas,

check the

calibration of the flow meter at one intermediate flow rate typical

of normal

operation of the monitoring system. Follow the basic procedures in Section

9.2.2.1

or 9.2.2.2 of this Exhibit. If the on-site calibration

check shows

that

the

value of Yi, the calibration factor at the tested flow rate,

differs

by more

than 5

percent from the value of Y obtained in the initial calibration of the

meter, repeat

the full 3-level calibration of the meter using stack gas to

determine a

new value of Y, and apply the new Y value

all subsequent gas

volume

measurements made with the

gas

flow meter.

9.2.2.5

Ongoing Quality Assurance-—

Recalibrate the gas flow meter quarterly at one intermediate flow rate setting

representative of normal operation of the monitoring system.

Follow the

basic

procedures in Section 9.2.2.1 or 9.2.2.2 of this

Exhibit. If

quarterly

recalibration

shows that

the

value

of Yi, the calibration factor at the tested

flow rate,

differs from the current value of Y

more than 5 percent, repeat

the full

3-level calibration of the meter to determine a new value of Y, and

apply the

new Y value

all subsequent

gas

volume measurements made with the

gas flow

meter.

9.3

Thermocouples and Other Temperature Sensors-

Use the

procedures and criteria in Section 10.3 of Method 2 in appendix A-l

40 CFR 60,

incorporated

reference in Section 225.140,

calibrate in-stack

temperature

sensors

and

thermocouples. Dial thermometers must

calibrated

against

mercury-in-glass

thermometers. Calibrations

must

performed prior

initial use and at

least

quarterly thereafter. At

each calibration point,

the

absolute

temperature

measured by the

temperature sensor

must

agree

within

÷—j

1.5 percent

of the temperature measured with the reference sensor, otherwise

the

sensor may

not continue

to be used.

Calibrate against a mercury barometer. Calibration must be

performed prior

initial use

and

at least quarterly thereafter. At each

calibration point,

the

absolute

pressure measured

the barometer must agree

within

÷—j

10 mm

mercury of the

pressure measured by the mercury

barometer,

otherwise

the

barometer

may not

continue

to be

used.

9.5

Other Sensors and Gauges-i

Calibrate

all

other sensors and gauges according

to the

procedures

specified by

the

instrument

manufacturcr(s)

.manufacturers.

9.6

Analytical

System

Calibration-i

See Section 10.1

of this Exhibit.

10.0 Analytical

Procedures-

The analysis of

the mercury samples may

be conducted using any instrument or

technology capable

of quantifying

total mercury from the sorbent media and

meeting the

performance

criteria in Section 8 of this Exhibit.

10.1 Analyzer System Calibration-i

Perform a multipoint calibration of the analyzer at three or more upscale points

over the desired quantitative range (multiple calibration ranges must be

calibrated, if necessary) . The field samples analyzed must fall within a

calibrated,

quantitative

range and meet the necessary performance criteria. For

samples that

are suitable for

aliquotting, a series of dilutions may be needed

to ensure that

the samples fall within

a calibrated range. However, for sorbent

media samples

that are consumed during

analysis (e.g., thermal desorption

techniques),

extra care must

be taken to ensure that the analytical system is

appropriately calibrated prior

sample analysis.

The

calibration

curve

rangc(D)ranes

should

determined

based

the

anticipated level

of mercury

mass on

the sorbent media. Knowledge of

estimated

stack mercury

concentrations

and

total sample volume may

required prior

analysis. The calibration

curve

for use

with the various analytical techniques

(e.g.,

t.JV AA, UV AF, and XRF)

can

generated by directly introducing standard solutions into the analyzer

or by

spiking the standards onto the sorbent media and then introducing into the

analyzer after preparing the sorbent/standard according

the particular

analytical technique. For each calibration curve, the value

of the square of the

linear

correlation

coefficient, i.e., r2,

must be >= 0.99,

and

the

analyzer

response must be within ----- 10 percent of reference value

each upscale

calibration point. Calibrations must

performed on the

day of the analysis,

before

analyzing any of the samples. Following calibration, an independently

prepared standard

(not

from same calibration stock

solution)

must

analyzed.

The

measured value of the independently prepared standard must

within

+—j

percent of the expected value.

10.2 Sample Preparation-i

Carefully

separate the three

sections of each sorbent trap. Combine for analysis

all

materials associated with

each section, i.e., any supporting substrate that

the

sample

gas

passes through prior

entering

a media section (e.g., glass

wool, polyurethane foam,

etc.)

must

analyzed

with

that segment.

10.3

Spike Recovery Study-

Before analyzing any field samples,

the laboratory must demonstrate the ability

recover

and quantify mercury from the sorbent

media by

performing

the

following spike

recovery

study for sorbent media traps spiked with

elemental

mercury.

Using the procedures

described in Sections 5.2 and 11.1 of this Exhibit, spike

the third section of

nine sorbent traps with

gaseous

HgO, i.e., three traps at

each of three different

mass loadings, representing the range of masses

anticipated in the

field samples. This will yield

a 3

sample matrix. Prepare

and analyze the third

section of each

spiked

trap, using the techniques that

will

be used to

prepare

and analyze

the field

samples. The average recovery for

each

spike concentration

must

be between 85 and

115 percent. If multiple types

of sorbent

media are to be

analyzed,

a separate spike

recovery

study

is required

for each

sorbent material. If multiple ranges are

calibrated,

separate spike

recovery study

is required for each range.

10.4

Field Sample Analysis

Analyze the sorbent

trap samples following the same procedures that were used

for conducting the

spike recovery

study.

The three sections of each sorbent trap

must be analyzed

separately

(i.e.,

section 1, then section 2, then

section

Quantify the

total mass of mercury for each section based on analytical system

response and the

calibration curve from Section 10.1 of this Exhibit. Determine

the spike recovery

from sorbent trap section

The spike recovery must be no

less than 75 percent

and no greater than 125 percent. To report the final

mercury mass for

each trap,

add

together the mercury masses collected in trap

sections 1 and 2.

11.0

Calculations and Data Analysis-s

11.1

Calculation of Pre-Sampling Spiking

Level-

Determine

sorbent trap section 3 spiking level using

estimates of the stack

mercury

concentration, the target sample flow rate,

and the expected sample

duration.

First, calculate the expected mercury

mass that will

collected in

section

of the trap. The pre-sampling

spike must

within --—-j 50 percent of

this mass.

Example calculation: For an

estimated stack mercury concentration of

5 pg/m3, a

target sample rate of 0.30

L/min, and

sample duration of 5 days:

(0.30

L/min)

(1440 mm/day)

days)

(10-3

m3/liter) (5ig/m3) = 10.8

pre-sampling spike of 10.8

-----

percent is, therefore,

appropriate.

11.2

Calculations for Flow-Proportional Sampling-i

For the

first hour of the data collection period,

determine the reference ratio

of the

stack gas volumetric flow rate to the sample flow rate, as

follows:

(Equation

K-l)

Where:

Rref=

Reference ratio of hourly stack gas flow rate to

hourly sample flow

raterateOref= Average stack gas volumetric

flow rate for first hour of

collection

pcriod oeriodFref=

Average

sample flow rate for first hour of the

collection period,

in appropriate

units (e.g.,

liters/mm, cc/mi

dscm/min)K =

Power of ten

multiplier,

to keep the

value of

Rref

between 1 and 100. The

appropriate K

value will depend on the selected units of measure for the sample

flow rate.

Then,

for each

subsequent hour of

the data collection period, calculate ratio of

the

stack gas flow

rate to the sample

flow rate using the equation K-2:

(Equation

K-2)

Where:

Rh=

Ratio of

hourly stack

gas

flow rate

to hourly sample flow rate rateph=

Average

stack gas

volumetric flow rate

for the hourhourFh= Average sample flow

rate for the hour,

in appropriate units

(e.g., liters/mm, cc/mm, dscm/min)K =

Power of ten

multiplier,

keep

the value of

between 1 and 100. The

appropriate K value

will depend

on the selected units of measure for the sample

flow rate and the

range of expected

stack gas flow rates.

Maintain

the

value

within

----- 25 percent of

Rref

throughout

the

data

collection period.

11.3

Calculation of Spike Recovery-

Calculate the percent recovery of each section 3 spike, as follows:

(Equation

K-3)

Where:

%R=Percentage

recovery

of the pre-sampling

spike

soikeM3= Mass of mercury

recovered from section 3 of the sorbent trap, (zig) = Calculated mercury

mazs%R=Percentace recovery

of the pre-sampling spike, from Section 7.1.2 of this

Exhibit, (zig)

11.4 Calculation

of Breakthrough-i

Calculate the

percent

breakthrough to the

second

section of the

sorbent

trap, as

follows:

Where:

(Equation

K-4)

Where:

Percent

breakthrough

- Mass of mercury recovered from section 2 of thc sorbcnt trap, (pg)

breakthrouohM2= Mass of mercury recovered from

section

the sorbent

trap,

(

ig)Ml=Mass

of mercury

recovered from section 1

of the

sorbent

trap.

(ua)

11.5

Calculation of Mercury Concentration

Calculate the mercury concentration for each sorbent trap, using the following

equation:

(Equation

K-5)

Where:

= Concentration of mercury for the collection period, igm/dscm)M= Total

mass

mercury recovered from sections 1 and 2 of

the

sorbent

trap,

pg)

3Lt=

Total

volume of dry gas metered during the collection period,

(dscm)

. For the purposes

of this Exhibit, standard temperature

and pressure

are defined as

and 760

mm mercury, respectively.

11.6 Calculation of Paired Trap Agreement

Calculate the relative deviation

(RD)

between

the mercury

concentrations

measured with the paired sorbent traps:

(Equation

K-6)

Where:

P.12=

Relative

deviation between the mercury concentrations from traps

and

TTbTT

(percent)

= Concentration

mercury for the collection period, for

sorbent trap

alT

(igm/dscm)

Ch=

Concentration of mercury for the collection

period, for sorbent

trap

“b’

(igm/dscm)

11.7 Calculation

of Mercury Mass Emissions-i

To calculate

mercury mass emissions, follow the procedures in

Section 4.1.2

Exhibit C to this

Appendix.

Use

the average of the two mercury concentrations

from the paired

traps in the calculations, except as provided in Section

2.2.3(h)

Exhibit B

this Appendix or in Table K-i.

12.0 Method

Performance-i

These

monitoring criteria and procedures have been applied to

coal-fired

utility

boilers

(including units with post-combustion emission

controls),

having vapor

phase mercury

concentrations ranging from 0.03 ig/dscm to 100

ig/dscm.

(Source:

Added

at 33

Ill. Reg.

effective

ILLINOIS

(TmtD

POLLUTION

CONTROL BOD

NOTICE OF PROPOSED 4ENDMENTS

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